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1

Heat pipe with hot gas reservoir  

NASA Technical Reports Server (NTRS)

Heat pipe can reverse itself with gas reservoir acting as evaporator, leading to rapid recovery from liquid in reservoir. Single layer of fine-mesh screen is included inside reservoir to assure uniform liquid distribution over hottest parts of internal surface until liquid is completely removed.

Marcus, B. D.

1974-01-01

2

Effect of Hydrates on Sustaining Reservoir Pressure in a Hydrate-Capped Gas Reservoir  

Microsoft Academic Search

A hydrate-capped gas reservoir is defined here as a reservoir that consists of a hydrate-bearing layer underlain by a two-phase zone involving mobile gas. In such a reservoir, hydrates at the top contribute to the produced gas stream once the reservoir pressure is reduced by gas production from the free-gas zone. Large gas reservoirs of this type are known to

S. Gerami; M. Pooladi-Darvish

2007-01-01

3

Optimizing Development Strategies to Increase Reserves in Unconventional Gas Reservoirs  

E-print Network

, approximate reservoir simulation model to match and predict production performance in unconventional gas reservoirs. Simulation results were then fit with decline curves to enable direct integration of the reservoir model into a Bayesian decision model...

Turkarslan, Gulcan

2011-10-21

4

Type Curves for Pressure Transient Analysis of Composite Double-Porosity Gas Reservoirs.  

E-print Network

??Economic production from unconventional gas reservoirs require horizontal drilling with multistage fracturing. These unconventional gas reservoirs include shale, tight gas reservoirs. Since there has been… (more)

Rana, Sachin

2011-01-01

5

Mechanisms of Liquid Buildup in Gas Condensate Reservoirs  

Microsoft Academic Search

Gas condensate reservoirs are different from dry and wet gas reservoirs in many cases, and these differences lead to weird and wonderful properties. When reservoir pressure falls below dew point, liquid dropout and its saturation may increase to a point that could flow. Therefore, in a reservoir three different regions are developed with different effects on well productivity. The authors

M. Qassamipour; A. Hashemi

2011-01-01

6

Impes modeling of volumetric dry gas reservoirs with mobile water  

E-print Network

program specifically designed to model two-phase flow of gas and water in these reservoirs. Since fluid compression and viscous forces are the dominant parameters that control fluid movement in a dry gas reservoir, we used the Implicit Pressure...

Forghany, Saeed

2004-09-30

7

ELASTIC ROCK PROPERTIES OF TIGHT GAS SANDSTONES FOR RESERVOIR CHARACTERIZATION  

E-print Network

ELASTIC ROCK PROPERTIES OF TIGHT GAS SANDSTONES FOR RESERVOIR CHARACTERIZATION AT RULISON FIELD, and lithology changes on tight gas sandstones. The rock physics of tight gas sandstones (low permeability sandstone reservoirs. However, very little work has been done in tight gas sandstones. In this work, rock

8

Gas-in-place determination for coal gas reservoirs  

SciTech Connect

The Upper Cretaceous Fruitland Formation of the San Juan Basin has been a very active natural gas play in recent years. Case studies of coal natural gas- in-place reassessments have revealed that gains of up to 74% are possible based upon methods recently developed by the Gas Research Institute. The greater gas-in-place estimates were consistent with production history and provide a new geologic perspective upon the producible coal gas resources. Coal gas-in-place is proportional to the thickness, average density, and average gas content. The GRI procedure evaluates each of these properties with a combination of core and density log data for specific reservoirs. The procedure follows eight steps. (1) Perform desorption measurements at reservoir temperature on conventional core samples. (2) Estimate total gas content of each sample using the Direct Method lost gas content procedure. (3) Relate, total gas content to sample composition. (4) Relate sample composition to density. (5) Determine the in-situ moisture content from equilibrium moisture content measurements. (6) Determine the gross thickness and average in-situ density from log data. (7) Estimate the in-situ gas content at the average reservoir density and moisture content. (8) Compute the gas-in-place volume. Quantitative errors and causes of errors in the three parameters have been determined. Errors are often caused by determining gross thickness with low density cut-off limits, by basing average density estimates upon {open_quotes}rules of thumb{close_quotes} or bounding rock density, by performing desorption measurements at ambient temperature, and by the use of drill cuttings rather than core samples.

Mavor, M.J. [Tesseract Corp., Park City, UT (United States); Pratt, T.J. [TICORA Geosciences, Inc., Arvda, CO (United States); Nelson, C.R. [Gas Research Inst., Chicago, IL (United States)] [and others

1996-12-31

9

Gas-in-place determination for coal gas reservoirs  

SciTech Connect

The Upper Cretaceous Fruitland Formation of the San Juan Basin has been a very active natural gas play in recent years. Case studies of coal natural gas- in-place reassessments have revealed that gains of up to 74% are possible based upon methods recently developed by the Gas Research Institute. The greater gas-in-place estimates were consistent with production history and provide a new geologic perspective upon the producible coal gas resources. Coal gas-in-place is proportional to the thickness, average density, and average gas content. The GRI procedure evaluates each of these properties with a combination of core and density log data for specific reservoirs. The procedure follows eight steps. (1) Perform desorption measurements at reservoir temperature on conventional core samples. (2) Estimate total gas content of each sample using the Direct Method lost gas content procedure. (3) Relate, total gas content to sample composition. (4) Relate sample composition to density. (5) Determine the in-situ moisture content from equilibrium moisture content measurements. (6) Determine the gross thickness and average in-situ density from log data. (7) Estimate the in-situ gas content at the average reservoir density and moisture content. (8) Compute the gas-in-place volume. Quantitative errors and causes of errors in the three parameters have been determined. Errors are often caused by determining gross thickness with low density cut-off limits, by basing average density estimates upon [open quotes]rules of thumb[close quotes] or bounding rock density, by performing desorption measurements at ambient temperature, and by the use of drill cuttings rather than core samples.

Mavor, M.J. (Tesseract Corp., Park City, UT (United States)); Pratt, T.J. (TICORA Geosciences, Inc., Arvda, CO (United States)); Nelson, C.R. (Gas Research Inst., Chicago, IL (United States)) (and others)

1996-01-01

10

Shale Gas reservoirs characterization using neural network  

NASA Astrophysics Data System (ADS)

In this paper, a tentative of shale gas reservoirs characterization enhancement from well-logs data using neural network is established. The goal is to predict the Total Organic carbon (TOC) in boreholes where the TOC core rock or TOC well-log measurement does not exist. The Multilayer perceptron (MLP) neural network with three layers is established. The MLP input layer is constituted with five neurons corresponding to the Bulk density, Neutron porosity, sonic P wave slowness and photoelectric absorption coefficient. The hidden layer is forms with nine neurons and the output layer is formed with one neuron corresponding to the TOC log. Application to two boreholes located in Barnett shale formation where a well A is used as a pilot and a well B is used for propagation shows clearly the efficiency of the neural network method to improve the shale gas reservoirs characterization. The established formalism plays a high important role in the shale gas plays economy and long term gas energy production.

Ouadfeul, Sid-Ali; Aliouane, Leila

2014-05-01

11

Evaluation of Devonian shale gas reservoirs  

SciTech Connect

The evaluation of predominantly shale reservoirs presents a problem for engineers traditionally educated either to correct for or to ignore such lithologic zones. Currently accepted evaluation techniques and their applicability are discussed to determine the best way to forecast remaining recoverable gas reserves from the Devonian shales of the Appalachian basin. This study indicates that rate/time decline-curve analysis is the most reliable technique and presents typical decline curves based on production data gathered from 508 shale wells in a three-state study area. The resultant type curves illustrate a dual- (or multiple-) porosity mechanism that violates standard decline-curve analysis guidelines. The results, however, are typical not only for the Devonian shales but for all naturally fractured, multilayered, or similar shale reservoirs.

Vanorsdale, C.R.

1987-05-01

12

Naturally fractured tight gas reservoir detection optimization  

SciTech Connect

The goal of the work this quarter has been to partition and high-grade the Greater Green River basin for exploration efforts in the Upper Cretaceous tight gas play and to initiate resource assessment of the basin. The work plan for the quarter of July 1-September 30, 1998 comprised three tasks: (1) Refining the exploration process for deep, naturally fractured gas reservoirs; (2) Partitioning of the basin based on structure and areas of overpressure; (3) Examination of the Kinney and Canyon Creek fields with respect to the Cretaceous tight gas play and initiation of the resource assessment of the Vermilion sub-basin partition (which contains these two fields); and (4) Initiation analysis of the Deep Green River Partition with respect to the Stratos well and assessment of the resource in the partition.

NONE

1998-11-30

13

Naturally fractured tight gas reservoir detection optimization  

SciTech Connect

Building upon the partitioning of the Greater Green River Basin (GGRB) that was conducted last quarter, the goal of the work this quarter has been to conclude evaluation of the Stratos well and the prototypical Green River Deep partition, and perform the fill resource evaluation of the Upper Cretaceous tight gas play, with the goal of defining target areas of enhanced natural fracturing. The work plan for the quarter of November 1-December 31, 1998 comprised four tasks: (1) Evaluation of the Green River Deep partition and the Stratos well and examination of potential opportunity for expanding the use of E and P technology to low permeability, naturally fractured gas reservoirs, (2) Gas field studies, and (3) Resource analysis of the balance of the partitions.

NONE

1999-06-01

14

De Wijk gas field: Reservoir mapping with amplitude anomalies  

SciTech Connect

De Wijk field, discovered in 1949, is located in the northeastern part of Netherlands. The main gas accumulation is contained in cretaceous and Triassic sandstone reservoirs trapped in a broad salt-induced structure of around 80 km[sup 2] areal extent. The field contains gas in the tertiary, Chalk, Zechstein 2 Carbonate, and Carboniferous reservoirs as well. De Wijk field is unique in the Netherlands as most gas-producing reservoirs in the Cretaceous/Triassic are of no commercial interest. Post-depositional leaching has positively affected the reservoir properties of the Triassic formations subcropping below the Cretaceous unconformity. Optimum, interpretation of 3-D seismic data acquired in 1989 resulted in spectacular displays highlighting the uniqueness of the field. Most gas-bearing reservoirs are expressed on seismic by amplitude anomalies. Various attribute-measurement techniques show the effect of gas fill, leaching, and sand distribution in the various reservoirs.

Bruijn, B. (Nederlandse Aardolie Maatshappij, Assen (Netherlands))

1993-09-01

15

Naturally fractured tight gas reservoir detection optimization  

SciTech Connect

During this quarter, work began on the regional structural and geologic analysis of the greater Green River basin (GGRB) in southwestern Wyoming, northwestern Colorado and northeastern Utah. The ultimate objective of the regional analysis is to apply the techniques developed and demonstrated during earlier phases of the project to sweet-spot delineation in a relatively new and underexplored play: tight gas from continuous-type Upper Cretaceous reservoirs of the GGRB. The primary goal of this work is to partition and high-grade the greater Green River basin for exploration efforts in the Cretaceous tight gas play. The work plan for the quarter of January 1, 1998--March 31, 1998 consisted of three tasks: (1) Acquire necessary data and develop base map of study area; (2) Process data for analysis; and (3) Initiate structural study. The first task and second tasks were completed during this reporting period. The third task was initiated and work continues.

NONE

1998-09-30

16

Reservoir Engineering for Unconventional Gas Reservoirs: What Do We Have to Consider?  

SciTech Connect

The reservoir engineer involved in the development of unconventional gas reservoirs (UGRs) is required to integrate a vast amount of data from disparate sources, and to be familiar with the data collection and assessment. There has been a rapid evolution of technology used to characterize UGR reservoir and hydraulic fracture properties, and there currently are few standardized procedures to be used as guidance. Therefore, more than ever, the reservoir engineer is required to question data sources and have an intimate knowledge of evaluation procedures. We propose a workflow for the optimization of UGR field development to guide discussion of the reservoir engineer's role in the process. Critical issues related to reservoir sample and log analysis, rate-transient and production data analysis, hydraulic and reservoir modeling and economic analysis are raised. Further, we have provided illustrations of each step of the workflow using tight gas examples. Our intent is to provide some guidance for best practices. In addition to reviewing existing methods for reservoir characterization, we introduce new methods for measuring pore size distribution (small-angle neutron scattering), evaluating core-scale heterogeneity, log-core calibration, evaluating core/log data trends to assist with scale-up of core data, and modeling flow-back of reservoir fluids immediately after well stimulation. Our focus in this manuscript is on tight and shale gas reservoirs; reservoir characterization methods for coalbed methane reservoirs have recently been discussed.

Clarkson, Christopher R [ORNL

2011-01-01

17

Mid-continent natural gas reservoirs and plays  

SciTech Connect

Natural gas reservoirs of the mid-continent states of Oklahoma, Kansas, and Arkansas (northern part) have produced 103 trillion cubic ft (tcf) of natural gas. Oklahoma has produced the most, having a cumulative production of 71 tcf. The major reservoirs (those that have produced more than 10 billion ft[sup 3]) have been identified and organized into 28 plays based on geologic age, lithology, and depositional environment. The Atlas of Major Midcontinent Gas Reservoirs, published in 1993, provides the documentation for these plays. This atlas was a collaborative effort of the Gas Research Institute; Bureau of Economic Geology. The University of Texas at Austin; Arkansas Geological Commission; Kansas Geological survey; and Oklahoma Geological Survey. Total cumulative production for 530 major reservoirs is 66 tcf associated and nonassociated gas. Oklahoma has the highest production with 39 tcf from 390 major reservoirs, followed by Kansas with 26 tcf from 105 major reservoirs. Most of the mid-continent production is from Pennsylvanian (46%) and Permian (41%) reservoirs; Mississippian reservoirs account for 10% production, and lower Paleozoic reservoirs, 3%. The largest play by far is the Wolfcampian Shallow Shelf Carbonate-Hugoton Embayment play with 25 tcf cumulative production, most of which is from the Hugoton and Panoma fields in Kansas and Guymon-Hugoton gas area in Oklahoma. A total of 53% of the mid-continent gas production is from dolostone and limestone reservoirs; 39% is from sandstone reservoirs. The remaining 8% is from chert conglomerate and granite-wash reservoirs. Geologically based plays established from the distribution of major gas reservoirs provide important support for the extension of productive trends, application of new resource technology to more efficient field development, and further exploration in the mid-continent region.

Bebout, D.G. (Univ. of Texas, Austin, TX (United States))

1993-09-01

18

Using multi-layer models to forecast gas flow rates in tight gas reservoirs  

E-print Network

The petroleum industry commonly uses single-layer models to characterize and forecast long-term production in tight gas reservoir systems. However, most tight gas reservoirs are layered systems where the permeability and porosity of each layer can...

Jerez Vera, Sergio Armando

2007-04-25

19

Petrophysical and mineralogical evaluation of shale gas reservoirs: a Cooper Basin case study.  

E-print Network

??Unconventional shale gas reservoirs are over-mature potential source rocks and possess commercial quantities of hydrocarbons in a mechanism which is different from conventional gas reservoirs.… (more)

Maqsood Ahmad

2014-01-01

20

General inflow performance relationship for solution-gas reservoir wells  

SciTech Connect

Two equations are developed to describe the inflow performance relationship (IPR) of wells producing from solution-gas drive reservoirs. These are general equations (extensions of the currently available IPR's) that apply to wells with any drainage-area shape at any state of completion flow efficiency and any stage of reservoir depletion. 7 refs.

Dias-Couto, L.E.; Golan, M.

1982-02-01

21

Some modern notions on oil and gas reservoir production regulation  

SciTech Connect

The historic rhetoric of oil and gas reservoir production regulations has been burdened with misconceptions. One was that most reservoirs are rate insensitive. Another was that a reservoir's decline is primarily a function of reservoir mechaism rather than a choice unconstrained by the laws of physics. Relieved of old notions like these, we introduce some modern notions, the most basic being that production regulation should have the purpose of obtaining the highest value from production per irreversible diminution of thermodynamically available energy. The laws of thermodynamics determine the available energy. What then is value. Value may include contributions other than production per se and purely monetary economic outcomes.

Lohrenz, J.; Monash, E.A.

1980-05-21

22

Gas condensate reservoir characterisation for CO2 geological storage  

NASA Astrophysics Data System (ADS)

During oil and gas production hydrocarbon recovery efficiency is significantly increased by injecting miscible CO2 gas in order to displace hydrocarbons towards producing wells. This process of enhanced oil recovery (EOR) might be used for the total CO2 storage after complete hydrocarbon reservoir depletion. This kind of potential storage sites was selected for detailed studies, including generalised development study to investigate the applicability of CO2 for storages. The study is focused on compositional modelling to predict the miscibility pressures. We consider depleted gas condensate field in Kazakhstan as important target for CO2 storage and EOR. This reservoir being depleted below the dew point leads to retrograde condensate formed in the pore system. CO2 injection in the depleted gas condensate reservoirs may allow enhanced gas recovery by reservoir pressurisation and liquid re-vaporisation. In addition a number of geological and petrophysical parameters should satisfy storage requirements. Studied carbonate gas condensate and oil field has strong seal, good petrophysical parameters and already proven successful containment CO2 and sour gas in high pressure and high temperature (HPHT) conditions. The reservoir is isolated Lower Permian and Carboniferous carbonate platform covering an area of about 30 km. The reservoir contains a gas column about 1.5 km thick. Importantly, the strong massive sealing consists of the salt and shale seal. Sour gas that filled in the oil-saturated shale had an active role to form strong sealing. Two-stage hydrocarbon saturation of oil and later gas within the seal frame were accompanied by bitumen precipitation in shales forming a perfect additional seal. Field hydrocarbon production began three decades ago maintaining a strategy in full replacement of gas in order to maintain pressure of the reservoir above the dew point. This was partially due to the sour nature of the gas with CO2 content over 5%. Our models and calculations demonstrate that injection of produced and additional gas (CO2 and sour gases) is economically viable and ecologically safe. Gas injection monitoring using surface injection well head pressures and measured injected volumes demonstrates a highly effective gas injection process. Injection well head pressure response shows no increase, indicating absence of compartmentalization close to the near well bore gas injection region in reservoir. And injector pulse study shows interconnectivity across the injection region highlighting good quality reservoir across the potential CO2 injection zones. Preliminary CO2 storage potential was also estimated for this type of geological site.

Ivakhnenko, A. P.

2012-04-01

23

Characterization of oil and gas reservoir heterogeneity  

SciTech Connect

The ultimate oojective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization--determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis--source rock identification; and the study of asphaltene precipitation for Alaskan crude oils. This report presents a summary of technical progress of the well log analysis of Kuparuk Field, Northslope, Alaska.

Sharma, G.D.

1992-01-01

24

Horizontal Well Placement Optimization in Gas Reservoirs Using Genetic Algorithms  

E-print Network

HORIZONTAL WELL PLACEMENT OPTIMIZATION IN GAS RESERVOIRS USING GENETIC ALGORITHMS A Thesis by TREVOR HOWARD GIBBS Submitted to the Office of Graduate Studies of Texas A&M University in partial fulfillment of the requirements... for the degree of MASTER OF SCIENCE May 2010 Major Subject: Petroleum Engineering HORIZONTAL WELL PLACEMENT OPTIMIZATION IN GAS RESERVOIRS USING GENETIC ALGORITHMS A Thesis by TREVOR HOWARD GIBBS Submitted to the Office of Graduate...

Gibbs, Trevor Howard

2011-08-08

25

Analysis of a geopressured gas reservoir using solution plot method  

E-print Network

by decreasing formation compressibility values as the pore pressure declines. Geopressured gas reservoirs are characterized by partially compacted rocks with major support of the overburden being provided by the abnormal pore pressures. Decline in the pore... permeability and compressibility treated as a function of pressure can be used to match geopressured gas reservoir performance behavior. Ambasthat5 used Bourgoyne's general material balance equation to develop a graphical matching technique based on a...

Hussain, Syed Muqeedul

2012-06-07

26

US production of natural gas from tight reservoirs  

SciTech Connect

For the purposes of this report, tight gas reservoirs are defined as those that meet the Federal Energy Regulatory Commission`s (FERC) definition of tight. They are generally characterized by an average reservoir rock permeability to gas of 0.1 millidarcy or less and, absent artificial stimulation of production, by production rates that do not exceed 5 barrels of oil per day and certain specified daily volumes of gas which increase with the depth of the reservoir. All of the statistics presented in this report pertain to wells that have been classified, from 1978 through 1991, as tight according to the FERC; i.e., they are ``legally tight`` reservoirs. Additional production from ``geologically tight`` reservoirs that have not been classified tight according to the FERC rules has been excluded. This category includes all producing wells drilled into legally designated tight gas reservoirs prior to 1978 and all producing wells drilled into physically tight gas reservoirs that have not been designated legally tight. Therefore, all gas production referenced herein is eligible for the Section 29 tax credit. Although the qualification period for the credit expired at the end of 1992, wells that were spudded (began to be drilled) between 1978 and May 1988, and from November 5, 1990, through year end 1992, are eligible for the tax credit for a subsequent period of 10 years. This report updates the EIA`s tight gas production information through 1991 and considers further the history and effect on tight gas production of the Federal Government`s regulatory and tax policy actions. It also provides some high points of the geologic background needed to understand the nature and location of low-permeability reservoirs.

Not Available

1993-10-18

27

Predicting horizontal well performance in solution-gas drive reservoirs  

E-print Network

PREDICTING HORIZONTAL WELL PERFORMANCE IN SOLUTION-GAS DRIVE RESERVOIRS A Thesis by. SliELDON VON PI. AHN Submitted to the Graduate College of Texas ARM Unifier ity in part al fulfillment of the requirements for the degree of MASTER... OF SCIENCE August 1986 Medor Subdect Petroleum Engineering PREDICTING HORIZONTAL WELL PERFORMANCE IN SOL(JTION-GAS DRIVE RESERVOIRS A Thesis by SHELDON VON PLAHN Approved as to style and content by. R&chard A. Startzman (Chair of Corn 'ttee) Tabor...

Plahn, Sheldon Von

2012-06-07

28

Gas reservoir identification by seismic AVO attributes on fluid substitution  

NASA Astrophysics Data System (ADS)

Traditionally, fluid substitutions are often conducted on log data for calculating reservoir elastic properties with different pore fluids. Their corresponding seismic responses are computed by seismic forward modeling for direct gas reservoir identification. The workflow provides us with the information about reservoir and seismic but just at the well. For real reservoirs, the reservoir parameters such as porosity, clay content, and thickness vary with location. So the information from traditional fluid substitution just at the well is limited. By assuming a rock physics model linking the elastic properties to porosity and mineralogy, we conducted seismic forward modeling and AVO attributes computation on a three-layer earth model with varying porosity, clay content, and formation thickness. Then we analyzed the relations between AVO attributes at wet reservoirs and those at the same but gas reservoirs. We arrived at their linear relations within the assumption framework used in the forward modeling. Their linear relations make it possible to directly conduct fluid substitution on seismic AVO attributes. Finally, we applied these linear relations for fluid substitution on seismic data and identified gas reservoirs by the cross-plot between the AVO attributes from seismic data and those from seismic data after direct fluid substitution.

Li, Jing-Ye

2012-06-01

29

30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?  

Code of Federal Regulations, 2013 CFR

...approval to produce gas-cap gas from an oil reservoir with an associated gas cap? 250...approval to produce gas-cap gas from an oil reservoir with an associated gas cap? (a...gas-cap gas from each completion in an oil reservoir that is known to have an associated...

2013-07-01

30

30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?  

...approval to produce gas-cap gas from an oil reservoir with an associated gas cap? 250...approval to produce gas-cap gas from an oil reservoir with an associated gas cap? (a...gas-cap gas from each completion in an oil reservoir that is known to have an associated...

2014-07-01

31

30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?  

Code of Federal Regulations, 2012 CFR

...approval to produce gas-cap gas from an oil reservoir with an associated gas cap? 250...approval to produce gas-cap gas from an oil reservoir with an associated gas cap? (a...gas-cap gas from each completion in an oil reservoir that is known to have an associated...

2012-07-01

32

Characterization of oil and gas reservoir heterogeneity  

SciTech Connect

Research described In this report addresses the internal architecture of two specific reservoir types: restricted-platform carbonates and fluvial-deltaic sandstones. Together, these two reservoir types contain more than two-thirds of the unrecovered mobile oil remaining ill Texas. The approach followed in this study was to develop a strong understanding of the styles of heterogeneity of these reservoir types based on a detailed outcrop description and a translation of these findings into optimized recovery strategies in select subsurface analogs. Research targeted Grayburg Formation restricted-platform carbonate outcrops along the Algerita Escarpment and In Stone Canyon In southeastern New Mexico and Ferron deltaic sandstones in central Utah as analogs for the North Foster (Grayburg) and Lake Creek (Wilcox) units, respectively. In both settings, sequence-stratigraphic style profoundly influenced between-well architectural fabric and permeability structure. It is concluded that reservoirs of different depositional origins can therefore be categorized Into a heterogeneity matrix'' based on varying intensity of vertical and lateral heterogeneity. The utility of the matrix is that it allows prediction of the nature and location of remaining mobile oil. Highly stratified reservoirs such as the Grayburg, for example, will contain a large proportion of vertically bypassed oil; thus, an appropriate recovery strategy will be waterflood optimization and profile modification. Laterally heterogeneous reservoirs such as deltaic distributary systems would benefit from targeted infill drilling (possibly with horizontal wells) and improved areal sweep efficiency. Potential for advanced recovery of remaining mobile oil through heterogeneity-based advanced secondary recovery strategies In Texas is projected to be an Incremental 16 Bbbl. In the Lower 48 States this target may be as much as 45 Bbbl at low to moderate oil prices over the near- to mid-term.

Tyler, N.; Barton, M.D.; Bebout, D.G.; Fisher, R.S.; Grigsby, J.D.; Guevara, E.; Holtz, M.; Kerans, C.; Nance, H.S.; Levey, R.A.

1992-10-01

33

Characterization of oil and gas reservoir heterogeneity  

SciTech Connect

The objective of the cooperative research program is to characterize Alaskan reservoirs in terms of their reserves, physical and chemical properties, geologic configuration and structure, and the development potential. The tasks completed during this period include: (1) geologic reservoir description of Endicott Field; (2) petrographic characterization of core samples taken from selected stratigraphic horizons of the West Sak and Ugnu (Brookian) wells; (3) development of a polydispersed thermodynamic model for predicting asphaltene equilibria and asphaltene precipitation from crude oil-solvent mixtures, and (4) preliminary geologic description of the Milne Point Unit.

Not Available

1991-01-01

34

Integrated Hydraulic Fracture Placement and Design Optimization in Unconventional Gas Reservoirs  

E-print Network

Unconventional reservoir such as tight and shale gas reservoirs has the potential of becoming the main source of cleaner energy in the 21th century. Production from these reservoirs is mainly accomplished through engineered hydraulic fracturing...

Ma, Xiaodan

2013-12-10

35

Improved Upscaling & Well Placement Strategies for Tight Gas Reservoir Simulation and Management  

E-print Network

, with opportunities for improved reservoir simulation & management, such as simulation model design, well placement. Our work develops robust and efficient strategies for improved tight gas reservoir simulation and management. Reservoir simulation models are usually...

Zhou, Yijie

2013-07-29

36

Gas hydrate reservoir characteristics and economics  

SciTech Connect

The primary objective of the DOE-funded USGS Gas Hydrate Program is to assess the production characteristics and economic potential of gas hydrates in northern Alaska. The objectives of this project for FY-1992 will include the following: (1) Utilize industry seismic data to assess the distribution of gas hydrates within the nearshore Alaskan continental shelf between Harrison Bay and Prudhoe Bay; (2) Further characterize and quantify the well-log characteristics of gas hydrates; and (3) Establish gas monitoring stations over the Eileen fault zone in northern Alaska, which will be used to measure gas flux from destabilized hydrates.

Collett, T.S.; Bird, K.J.; Burruss, R.C.; Lee, Myung W.

1992-01-01

37

Gas hydrate reservoir characteristics and economics  

SciTech Connect

The primary objective of the DOE-funded USGS Gas Hydrate Program is to assess the production characteristics and economic potential of gas hydrates in northern Alaska. The objectives of this project for FY-1992 will include the following: (1) Utilize industry seismic data to assess the distribution of gas hydrates within the nearshore Alaskan continental shelf between Harrison Bay and Prudhoe Bay; (2) Further characterize and quantify the well-log characteristics of gas hydrates; and (3) Establish gas monitoring stations over the Eileen fault zone in northern Alaska, which will be used to measure gas flux from destabilized hydrates.

Collett, T.S.; Bird, K.J.; Burruss, R.C.; Lee, Myung W.

1992-06-01

38

30 CFR 250.121 - What happens when the reservoir contains both original gas in place and injected gas?  

Code of Federal Regulations, 2011 CFR

...2011-07-01 false What happens when the reservoir contains both original gas in place...250.121 What happens when the reservoir contains both original gas in place and injected gas? If the reservoir contains both original gas in...

2011-07-01

39

30 CFR 250.121 - What happens when the reservoir contains both original gas in place and injected gas?  

Code of Federal Regulations, 2013 CFR

...2013-07-01 false What happens when the reservoir contains both original gas in place...250.121 What happens when the reservoir contains both original gas in place and injected gas? If the reservoir contains both original gas in...

2013-07-01

40

30 CFR 250.121 - What happens when the reservoir contains both original gas in place and injected gas?  

...2014-07-01 false What happens when the reservoir contains both original gas in place...250.121 What happens when the reservoir contains both original gas in place and injected gas? If the reservoir contains both original gas in...

2014-07-01

41

30 CFR 250.121 - What happens when the reservoir contains both original gas in place and injected gas?  

Code of Federal Regulations, 2012 CFR

...2012-07-01 false What happens when the reservoir contains both original gas in place...250.121 What happens when the reservoir contains both original gas in place and injected gas? If the reservoir contains both original gas in...

2012-07-01

42

Reservoir characterization of the underground gas storage "Banatski Dvor"  

NASA Astrophysics Data System (ADS)

The area of the "Banatski Dvor" gas field is located in the eastern Vojvodina, Srednji Banat. It is built up of Mesozoic, Tertiary and Quaternary sediments. Pontian sandstones and sands are the main gas bearing formations of the "Banatski Dvor" structure. The Lower Pontian sandstone horizon bears gas reservoir "A" (gas storage). Petrophysical properties of the reservoir rocks are very important for development of the underground gas storage project. In the area of the underground gas storage 3D seismic survey was designed to get detailed stuctural model of the reservoir "A" and petrophysical parameters. 3D seismic data were inverted in acustic impedance on the basis of the well logging data. One of the most important procedure in reservoir characterization is seismic to well tie. Accurate synthetic seismograms were created using elastic modeling from P, S and density logs. Wavelet was extracted from seismic data near the well. A background model is required and very involved in the amplitude inversion process. A good and detailed background model can largely enhance the accuracy of the inversion results. Data from eighteen wells were used to create density and P-wave velocity model. 3D ordinary kriging method was used to create well based background models. Amplitude inversion is a procedure that converts seismic traces to impedances. Constrained Inversion in Eigenvectors basis was used as a method for the amplitude inversion. Petrophysical parameters of the reservoir "A" were estimated based on the interpretation of the acustic impedance volume and the well logging data. Results of the interpretation the acustic impedance volume and the well logging data served to estimate following petrophysical parameters: porosity, permeability, water saturation and volume of shale content. The results were very satisfactory and were used for the volume estimation of the gas storage.

Nicic Jorovic, V.

2009-04-01

43

Prediction of Gas Injection Performance for Heterogeneous Reservoirs  

SciTech Connect

This report describes research carried out in the Department of Petroleum Engineering at Stanford University from September 1998 - September 1998 under the third year of a three-year Department of Energy (DOE) grant on the ''Prediction of Gas Injection Performance for Heterogeneous Reservoirs''. The research effort is an integrated study of the factors affecting gas injection, from the pore scale to the field scale, and involves theoretical analysis, laboratory experiments and numerical simulation. The research is divided into four main areas: (1) Pore scale modeling of three-phase flow in porous media; (2) Laboratory experiments and analysis of factors influencing gas injection performance at the core scale with an emphasis on the fundamentals of three-phase flow; (3) Benchmark simulations of gas injection at the field scale; and (4) Development of streamline-based reservoir simulator.

Blunt, Martin J.; Orr, Jr., Franklin M.

1999-12-20

44

Petrophysical rock classification in the Cotton Valley tight-gas sandstone reservoir with a clustering  

E-print Network

Petrophysical rock classification in the Cotton Valley tight-gas sandstone reservoir in complex reservoirs. Tight-gas sandstones exhibit large variability in all petrophysical properties due classification method with field data acquired in the Cotton Valley tight-gas sandstone reservoir located

Torres-Verdín, Carlos

45

3D multi-scale imaging of experimental fracture generation in shale gas reservoirs.  

E-print Network

3D multi-scale imaging of experimental fracture generation in shale gas reservoirs. Supervisory-grained organic carbon-rich rocks (shales) are increasingly being targeted as shale gas "reservoirs". Due in real time during rock loading. Fig 1. Fractures in an outcropping shale gas reservoir (Woodford Shale

Henderson, Gideon

46

Gas hydrate-filled fracture reservoirs on continental margins  

NASA Astrophysics Data System (ADS)

Many scientists predicted that gas hydrate forms in fractures or lenses in fine-grained sediments, but only in the last decade were gas hydrates found in complex fracture systems on continental margins. Gas hydrate-filled fractures were captured on both in situ borehole images and in x-ray imaged pressure cores. These new discoveries of gas hydrate as fill in fractures have been a boon to the gas hydrate community, yet, very little is known about the features and dimensions of a gas hydrate-filled fracture reservoir. Geophysical prospecting techniques, such as exploration seismic and controlled source electromagnetic surveys have not been able to detect a gas hydrate-filled fracture reservoir. In this dissertation, I aim to define the marine gas hydrate-filled fracture reservoir. Three offshore drilling expeditions, known as the gas hydrate Joint Industry Project Expeditions 1 and 2 in the Gulf of Mexico and the Indian National Gas Hydrate Program Expedition 1 on the Indian continental margins, are the sources of the geophysical well log and core data used in this dissertation. In the following five chapters, I show that gas hydrate often forms in shallow, unconsolidated, fine-grained sediments in near-vertical fractures. Gas hydrate-filled fractures are planar features, but likely only extend a few meters in breath. Gas hydrate-filled fracture systems are likely controlled by in situ methanogenesis and or methane solubility. The near-vertical nature of the gas hydrate-filled fractures causes anisotropic conditions in geophysical logging measurements made in vertical boreholes. Measured resistivity is most affected by the anisotropy, producing high resistivities in near-vertical gas hydrate-filled fracture systems. Thus, using measured resistivity to calculate gas hydrate saturation produces unreliable results. Gas hydrate-filled fractures in the same hole usually have similar strike orientations. The fracture orientations are used to determine the shallow stress directions in hole. The stress directions orient with bathymetric contour lines showing shallow stress is chiefly affected by changes in seafloor topography.

Cook, Ann Elizabeth

47

Earthquakes and depleted gas reservoirs: which comes first?  

NASA Astrophysics Data System (ADS)

While scientists are paying increasing attention to the seismicity potentially induced by hydrocarbon exploitation, little is known about the reverse problem, i.e. the impact of active faulting and earthquakes on hydrocarbon reservoirs. The recent 2012 earthquakes in Emilia, Italy, raised concerns among the public for being possibly human-induced, but also shed light on the possible use of gas wells as a marker of the seismogenic potential of an active fold-and-thrust belt. Based on the analysis of over 400 borehole datasets from wells drilled along the Ferrara-Romagna Arc, a large oil and gas reserve in the southeastern Po Plain, we found that the 2012 earthquakes occurred within a cluster of sterile wells surrounded by productive ones. Since the geology of the productive and sterile areas is quite similar, we suggest that past earthquakes caused the loss of all natural gas from the potential reservoirs lying above their causative faults. Our findings have two important practical implications: (1) they may allow major seismogenic zones to be identified in areas of sparse seismicity, and (2) suggest that gas should be stored in exploited reservoirs rather than in sterile hydrocarbon traps or aquifers as this is likely to reduce the hazard of triggering significant earthquakes.

Mucciarelli, M.; Donda, F.; Valensise, G.

2014-12-01

48

Reservoir and stimulation analysis of a Devonian Shale gas field  

E-print Network

similar t. o the Huron; both are dark, highly radioactive shales. The Rhinestreet unconformably overlies the Onondaga Limestone in the study area. The older Devonian rocks (Sonyea, Genessee, Tully, Hamilton, and Marcellus) which are present to the east...RESERVOIR AND STIMULATION ANALYSIS OF A DEVONIAN SHALE GAS FIELD A Thesis by JAMES STANLEY SHAW Submitted to the Graduate College of Texas A&M University in partial fulfillment of the requirements for the degree of MASTER OF SCIENCE...

Shaw, James Stanley

1986-01-01

49

Performance of fractured horizontal well with stimulated reservoir volume in unconventional gas reservoir  

NASA Astrophysics Data System (ADS)

This paper extended the conventional multiple hydraulic fractured horizontal (MFH) well into a composite model to describe the stimulated reservoir volume (SRV) caused by hydraulic fracturing. Employing the Laplace transform, Source function, and Dirac delta function methods, the continuous linear source function for general composite dual-porosity is derived, and the solution of the MFH well in a composite gas reservoir is obtained with the numerical discrete method. Through the Stehfest numerical algorithm and Gauss elimination method, the transient pressure responses for well producing at a constant production rate and the production rate vs. time for constant bottomhole pressure are analyzed. The effects of related parameters such as natural permeability and radial of the SRV region, formation permeability and interporosity coefficient on transient pressure and production performance are analyzed as well. The presented model and obtained results in this paper not only enrich the well testing models of such unconventional reservoir, but also can use to interpret on-site data which have significance on efficient reservoir development.

Zhao, Yu-Long; Zhang, Lie-Hui; Luo, Jian-Xin; Zhang, Bo-Ning

2014-05-01

50

A Numerical Study of Microscale Flow Behavior in Tight Gas and Shale Gas Reservoir Systems  

Microsoft Academic Search

Various attempts have been made to model flow in shale gas systems. However, there is currently little consensus regarding\\u000a the impact of molecular and Knudsen diffusion on flow behavior over time in such systems. Direct measurement or model-based\\u000a estimation of matrix permeability for these “ultra-tight” reservoirs has proven unreliable. The composition of gas produced\\u000a from tight gas and shale gas

C. M. Freeman; G. J. Moridis; T. A. Blasingame

51

Effect of the reservoir size on gas adsorption in inhomogeneous porous media E. Kierlik,1  

E-print Network

Effect of the reservoir size on gas adsorption in inhomogeneous porous media E. Kierlik,1 J: September 12, 2008) We study the influence of the relative size of the reservoir on the adsorption isotherms matter with a reservoir of gas that is at the same temperature and chemical potential and whose relative

Paris-Sud XI, Université de

52

MathematicalGeology, Vol. 11,No. I,1979 Modeling and Optimizing a Gas-Water Reservoir  

E-print Network

MathematicalGeology, Vol. 11,No. I,1979 Modeling and Optimizing a Gas-Water Reservoir: I Enhanced dictates that waterfloodingof gas reservoirsshould commence,ifever. only when the reservoir pressure has in the literature however. Thispaper considersa modelfor agas-water reservoir with a variableproduction rate

Waterman, Michael S.

53

SHEAR WAVE TIME-LAPSE SEISMIC MONITORING OF A TIGHT GAS SANDSTONE RESERVOIR, RULISON FIELD, COLORADO  

E-print Network

SHEAR WAVE TIME-LAPSE SEISMIC MONITORING OF A TIGHT GAS SANDSTONE RESERVOIR, RULISON FIELD sandstone reservoir in western Colorado. The objective of these highly repeatable seismic surveys of shear wave data as a tool for monitoring 4D changes. The basin centered tight gas sandstone reservoir

54

Seismic Modeling Of Reservoir Heterogeneity Scales: An Application To Gas Hydrate Reservoirs  

NASA Astrophysics Data System (ADS)

Natural gas hydrates, a type of inclusion compound or clathrate, are composed of gas molecules trapped within a cage of water molecules. The occurrence of gas hydrates in permafrost regions has been confirmed by core samples recovered from the Mallik gas hydrate research wells located within Mackenzie Delta in Northwest Territories of Canada. Strong vertical variations of compressional and shear sonic velocities and weak surface seismic expressions of gas hydrates indicate that lithological heterogeneities control the distribution of hydrates. Seismic scattering studies predict that typical scales and strong physical contrasts due to gas hydrate concentration will generate strong forward scattering, leaving only weak energy captured by surface receivers. In order to understand the distribution of hydrates and the seismic scattering effects, an algorithm was developed to construct heterogeneous petrophysical reservoir models. The algorithm was based on well logs showing power law features and Gaussian or Non-Gaussian probability density distribution, and was designed to honor the whole statistical features of well logs such as the characteristic scales and the correlation among rock parameters. Multi-dimensional and multi-variable heterogeneous models representing the same statistical properties were constructed and applied to the heterogeneity analysis of gas hydrate reservoirs. The petrophysical models provide the platform to estimate rock physics properties as well as to study the impact of seismic scattering, wave mode conversion, and their integration on wave behavior in heterogeneous reservoirs. Using the Biot-Gassmann theory, the statistical parameters obtained from Mallik 5L-38, and the correlation length estimated from acoustic impedance inversion, gas hydrate volume fraction in Mallik area was estimated to be 1.8%, approximately 2x108 m3 natural gas stored in a hydrate bearing interval within 0.25 km2 lateral extension and between 889 m and 1115 m depth. With parallel 3-D viscoelastic Finite Difference (FD) software, we conducted a 3D numerical experiment of near offset Vertical Seismic Profile. The synthetic results implied that the strong attenuation observed in the field data might be caused by the scattering.

Huang, J.; Bellefleur, G.; Milkereit, B.

2008-12-01

55

Naturally fractured tight gas reservoir detection optimization. Final report  

SciTech Connect

This DOE-funded research into seismic detection of natural fractures is one of six projects within the DOE`s Detection and Analysis of Naturally Fractured Gas Reservoirs Program, a multidisciplinary research initiative to develop technology for prediction, detection, and mapping of naturally fractured gas reservoirs. The demonstration of successful seismic techniques to locate subsurface zones of high fracture density and to guide drilling orientation for enhanced fracture permeability will enable better returns on investments in the development of the vast gas reserves held in tight formations beneath the Rocky Mountains. The seismic techniques used in this project were designed to capture the azimuthal anisotropy within the seismic response. This seismic anisotropy is the result of the symmetry in the rock fabric created by aligned fractures and/or unequal horizontal stresses. These results may be compared and related to other lines of evidence to provide cross-validation. The authors undertook investigations along the following lines: Characterization of the seismic anisotropy in three-dimensional, P-wave seismic data; Characterization of the seismic anisotropy in a nine-component (P- and S-sources, three-component receivers) vertical seismic profile; Characterization of the seismic anisotropy in three-dimensional, P-to-S converted wave seismic data (P-wave source, three-component receivers); and Description of geological and reservoir-engineering data that corroborate the anisotropy: natural fractures observed at the target level and at the surface, estimation of the maximum horizontal stress in situ, and examination of the flow characteristics of the reservoir.

NONE

1997-11-19

56

Reservoir and stimulation analysis of a Devonian shale gas field  

SciTech Connect

This paper presents a study of a shallow, low-productivity Devonian shale gas field consisting of 48 wells in Mason County, WV. Gas production from wells in the field was found to be associated with zones of substantial free-gas porosity in the presence of high kerogen (organic) content. Most wells are poor producers; the best wells are located in the northwest portion of the field, which corresponds to an area of natural fracturing identified by remote sensing imagery. The authors identified and mapped quality reservoir areas and predicted performance for all wells in the field. The stimulation treatments conducted on all wells in the field successfully initiated gas production from the shales, but these treatments generally failed to achieve the degree of stimulation expected from such jobs.

Shaw, J.S.; Gatens, J.M. III (Eastern Reservoir Services, Kingsport, TN (US)); Lancaster, D.E. (S.A. Holditch and Associates (US)); Terry, D.P. (Equitable Resources Exploration Inc. (US)); Lee, W.J. (Petroleum Engineering at Texas A and M Univ. (US)); Avary, K.L. (West Virginia Geological and Economics Survey (US))

1989-11-01

57

KPIM of Gas\\/Condensate Productivity: Prediction of Condensate\\/Gas Ratio Using Reservoir Volumetric Balance  

Microsoft Academic Search

A new approach for forecasting viability of gas condensate wells and calculating Condensate Gas Ratio (CGR), using simpler techniques is presented. The calculation uses a volumetric balance model for reservoir system, standardized and modified correlations, equation of state and a vapor-liquid equilibrium technique. The technique has been extended to include mass transfer and also to allow for the changes in

A. F. Olaberinjo; M. O. Oyewola; O. A. Obiyemi; O. A. Adeyanju; M. S. Adaramola

2006-01-01

58

Application of Fast Marching Method in Shale Gas Reservoir Model Calibration  

E-print Network

and reservoir heterogeneity but also is time consuming. In this thesis, we propose and apply an efficient technique, fast marching method (FMM), to analyze the shale gas reservoirs. Our proposed approach stands midway between analytic techniques and numerical...

Yang, Changdong

2013-07-26

59

A Novel Approach For the Simulation of Multiple Flow Mechanisms and Porosities in Shale Gas Reservoirs  

E-print Network

The state of the art of modeling fluid flow in shale gas reservoirs is dominated by dual porosity models that divide the reservoirs into matrix blocks that significantly contribute to fluid storage and fracture networks which principally control...

Yan, Bicheng

2013-07-15

60

Prediction of Gas Injection Performance for Heterogeneous Reservoirs  

SciTech Connect

This report describes research carried out in the Department of Petroleum Engineering at Stanford University from September 1996 - September 1997 under the first year of a three-year Department of Energy grant on the Prediction of Gas Injection Performance for Heterogeneous Reservoirs. The research effort is an integrated study of the factors affecting gas injection, from the pore scale to the field scale, and involves theoretical analysis, laboratory experiments and numerical simulation. The original proposal described research in four main areas; (1) Pore scale modeling of three phase flow in porous media; (2) Laboratory experiments and analysis of factors influencing gas injection performance at the core scale with an emphasis on the fundamentals of three phase flow; (3) Benchmark simulations of gas injection at the field scale; and (4) Development of streamline-based reservoir simulator. Each stage of the research is planned to provide input and insight into the next stage, such that at the end we should have an integrated understanding of the key factors affecting field scale displacements.

Blunt, Michael J.; Orr, Franklin M.

1999-05-26

61

30 CFR 250.121 - What happens when the reservoir contains both original gas in place and injected gas?  

Code of Federal Regulations, 2010 CFR

...What happens when the reservoir contains both original gas in place and injected gas? 250.121 Section 250.121 Mineral Resources...SERVICE, DEPARTMENT OF THE INTERIOR OFFSHORE OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL...

2010-07-01

62

A coupled reservoir-geomechanical simulation study of CO 2 storage in a nearly depleted natural gas reservoir  

Microsoft Academic Search

Atzbach–Schwanenstadt natural gas field located in Upper Austria Molasse Foreland basin was one of the four European sites selected for subsurface CO2 storage feasibility\\/performance evaluation in the recently completed EU-funded research project CASTOR. The objectives of the coupled reservoir-geomechanical modelling effort at Aztbach-Schwanenstadt gas field were: 1) evaluation of the hydro-mechanical response of the reservoir rock and overburden formations to

Ji-Quan Shi; Sevket Durucan

2009-01-01

63

Predicting gas, oil, and water intervals in Niger delta reservoirs using gas chromatography  

SciTech Connect

Formation evaluation experts usually have little difficulty in interpreting wireline logs to assess the type of reservoir fluid (oil/gas/water) in sand-shale sequences. This assessment is usually accomplished by a combination neutron-density tool that detects low hydrogen and low electron densities typical of gas zones, and the repeat formation tester (RFT), which uses both the pressure gradient and sample acquisition techniques to evaluate reservoir fluid. In the Niger Delta, however, many of the sands exhibit a poor neutron-density response to gas, and RFT testing has been largely eliminated because poor hole conditions commonly result in stuck tools. Oil fingerprinting of residual hydrocarbons from sidewall core extracts can provide an independent means of identifying reservoir fluid type.

Baskin, D.K.; Hwang, R.J. [Chevron Petroleum Technology Co., La Habra, CA (United States); Purdy, R.K. [Chevron Overseas Petroleum, Inc., San Ramon, CA (United States)

1995-03-01

64

A New Type Curve Analysis for Shale Gas/Oil Reservoir Production Performance with Dual Porosity Linear System.  

E-print Network

??With increase of interest in exploiting shale gas/oil reservoirs with multiple stage fractured horizontal wells, complexity of production analysis and reservoir description have also increased.… (more)

Abdulal, Haider Jaffar

2012-01-01

65

Approaches for reservoir geological modelling of the Maui Gas Field, New Zealand  

Microsoft Academic Search

The Maui field currently supplies 90 % of New Zealand`s gas and a significant proportion of the country`s total energy requirement. The management of the gas reserves uses an ECLIPSE simulation model based upon the input of reservoir properties from STRATAMODEL. This is a deterministic reservoir geological modelling system suitable for the generally continuous C Sands gas-condensate reservoir, and oil

C. Greenstreet; R. The; J. Cohen

1995-01-01

66

Data assimilation for fractured shale gas reservoirs using ensemble Kalman filter.  

E-print Network

??Production of shale gas reservoirs depends on natural and hydraulic fractures, which represent a significant challenge in numerical simulation. Unknown fracture characteristics such as location,… (more)

Ghods, Parham

2012-01-01

67

Geological controls on gas accumulation in a unique Zechstein carbonate reservoir  

E-print Network

Geological controls on gas accumulation in a unique Zechstein carbonate reservoir Craig Duguid clastic reservoir systems. Within the region, the Upper Permian Zechstein Supergroup ­ present across much hydrocarbons as an effective reservoir seal. Deep in the palaeo-basin centre, salts (anhydrite and halite

68

Importance of Low Permeability Natural Gas Reservoirs (released in AEO2010)  

EIA Publications

Production from low-permeability reservoirs, including shale gas and tight gas, has become a major source of domestic natural gas supply. In 2008, low-permeability reservoirs accounted for about 40% of natural gas production and about 35% of natural gas consumption in the United States. Permeability is a measure of the rate at which liquids and gases can move through rock. Low-permeability natural gas reservoirs encompass the shale, sandstone, and carbonate formations whose natural permeability is roughly 0.1 millidarcies or below. (Permeability is measured in darcies.)

2010-01-01

69

Atlas of Northern Gulf of Mexico Gas and Oil Reservoirs: Procedures and examples of resource distribution  

SciTech Connect

The objective of the program is to produce a reservoir atlas series of the Gulf of Mexico that (1) classifies and groups offshore oil and gas reservoirs into a series of geologically defined reservoir plays, (2) compiles comprehensive reservoir play information that includes descriptive and quantitative summaries of play characteristics, cumulative production, reserves, original oil and gas in place, and various other engineering and geologic data, (3) provides detailed summaries of representative type reservoirs for each play, and (4) organizes computerized tables of reservoir engineering data into a geographic information system (GIS). The primary product of the program will be an oil and gas atlas series of the offshore Northern Gulf of Mexico and a computerized geographical information system of geologic and engineering data linked to reservoir location.

Seni, S.J.; Finley, R.J.

1995-06-01

70

Advanced Hydraulic Fracturing Technology for Unconventional Tight Gas Reservoirs  

SciTech Connect

The objectives of this project are to develop and test new techniques for creating extensive, conductive hydraulic fractures in unconventional tight gas reservoirs by statistically assessing the productivity achieved in hundreds of field treatments with a variety of current fracturing practices ranging from 'water fracs' to conventional gel fracture treatments; by laboratory measurements of the conductivity created with high rate proppant fracturing using an entirely new conductivity test - the 'dynamic fracture conductivity test'; and by developing design models to implement the optimal fracture treatments determined from the field assessment and the laboratory measurements. One of the tasks of this project is to create an 'advisor' or expert system for completion, production and stimulation of tight gas reservoirs. A central part of this study is an extensive survey of the productivity of hundreds of tight gas wells that have been hydraulically fractured. We have been doing an extensive literature search of the SPE eLibrary, DOE, Gas Technology Institute (GTI), Bureau of Economic Geology and IHS Energy, for publicly available technical reports about procedures of drilling, completion and production of the tight gas wells. We have downloaded numerous papers and read and summarized the information to build a database that will contain field treatment data, organized by geographic location, and hydraulic fracture treatment design data, organized by the treatment type. We have conducted experimental study on 'dynamic fracture conductivity' created when proppant slurries are pumped into hydraulic fractures in tight gas sands. Unlike conventional fracture conductivity tests in which proppant is loaded into the fracture artificially; we pump proppant/frac fluid slurries into a fracture cell, dynamically placing the proppant just as it occurs in the field. From such tests, we expect to gain new insights into some of the critical issues in tight gas fracturing, in particular the roles of gel damage, polymer loading (water-frac versus gel frac), and proppant concentration on the created fracture conductivity. To achieve this objective, we have designed the experimental apparatus to conduct the dynamic fracture conductivity tests. The experimental apparatus has been built and some preliminary tests have been conducted to test the apparatus.

Stephen Holditch; A. Daniel Hill; D. Zhu

2007-06-19

71

The construction and use of aquifer influence functions in determining original gas in place for water-drive gas reservoirs  

E-print Network

THE CONSTRUCTION AND USE OF AQUIFER INFLUENCE FUNCTIONS IN DETERMINING ORIGINAL GAS IN PLACE FOR WATER-DRIVE GAS RESERVOIRS A Thesis by RONALD JOSEPH GAJDICA Submitted to the Graduate College of Texas A&M University in partial fulfillment... of the requirements for the degree of MASTER OF SCIENCE December 1986 Major Subject: Petroleum Engineering THE CONSTRUCTION AND USE OF AQUIFER INFLUENCE FUNCTIONS IN DETERMINING ORIGINAL GAS IN PLACE FOR MATER-DRIVE GAS RESERVOIRS A Thesis by RONALD JOSEPH...

Gajdica, Ronald Joseph

2012-06-07

72

a Review of Hydropower Reservoir and Greenhouse Gas Emissions  

NASA Astrophysics Data System (ADS)

Like most manmade projects, hydropower dams have multiple effects on the environment that have been studied in some depth over the past two decades. Among their most important effects are potential changes in water movement, flowing much slower than in the original river. This favors the appearance of phytoplankton as nutrients increase, with methanogenesis replacing oxidative water and generating anaerobic conditions. Although research during the late 1990s highlighted the problems caused by hydropower dams emitting greenhouse gases, crucial aspects of this issue still remain unresolved. Similar to natural water bodies, hydropower reservoirs have ample biota ranging from microorganisms to aquatic vertebrates. Microorganisms (bacteria) decompose organic matter producing biogenic gases under water. Some of these biogenic gases cause global warming, including methane, carbon dioxide and nitrous oxide. The levels of GHG emissions from hydropower dams are a strategic matter of the utmost importance, and comparisons with other power generation options such as thermo-power are required. In order to draw up an accurate assessment of the net emissions caused by hydropower dams, significant improvements are needed in carbon budgets and studies of representative hydropower dams. To determine accurately the net emissions caused by hydro reservoir formation is required significant improvement of carbon budgets studies on different representatives' hydro reservoirs at tropical, boreal, arid, semi arid and temperate climate. Comparisons must be drawn with emissions by equivalent thermo power plants, calculated and characterized as generating the same amount of energy each year as the hydropower dams, burning different fuels and with varying technology efficiency levels for steam turbines as well as coal, fuel oil and natural gas turbines and combined cycle plants. This paper brings to the scientific community important aspects of the development of methods and techniques applied as well as identifying the main players and milestones to this subject.

Rosa, L. P.; Dos Santos, M. A.

2013-05-01

73

Modeling and optimizing a gas-water reservoir: Enhanced recovery with waterflooding  

USGS Publications Warehouse

Accepted practice dictates that waterflooding of gas reservoirs should commence, if ever, only when the reservoir pressure has declined to the minimum production pressure. Analytical proof of this hypothesis has yet to appear in the literature however. This paper considers a model for a gas-water reservoir with a variable production rate and enhanced recovery with waterflooding and, using an initial dynamic programming approach, confirms the above hypothesis. ?? 1979 Plenum Publishing Corporation.

Johnson, M.E.; Monash, E.A.; Waterman, M.S.

1979-01-01

74

OPTIMIZATION OF INFILL DRILLING IN NATURALLY-FRACTURED TIGHT-GAS RESERVOIRS  

Microsoft Academic Search

A major goal of industry and the U.S. Department of Energy (DOE) fossil energy program is to increase gas reserves in tight-gas reservoirs. Infill drilling and hydraulic fracture stimulation in these reservoirs are important reservoir management strategies to increase production and reserves. Phase II of this DOE\\/cooperative industry project focused on optimization of infill drilling and evaluation of hydraulic fracturing

Lawrence W. Teufel; Her-Yuan Chen; Thomas W. Engler; Bruce Hart

2004-01-01

75

OPTIMIZATION OF INFILL DRILLING IN NATURALLY-FRACTURED TIGHT-GAS RESERVOIRS  

SciTech Connect

A major goal of industry and the U.S. Department of Energy (DOE) fossil energy program is to increase gas reserves in tight-gas reservoirs. Infill drilling and hydraulic fracture stimulation in these reservoirs are important reservoir management strategies to increase production and reserves. Phase II of this DOE/cooperative industry project focused on optimization of infill drilling and evaluation of hydraulic fracturing in naturally-fractured tight-gas reservoirs. The cooperative project involved multidisciplinary reservoir characterization and simulation studies to determine infill well potential in the Mesaverde and Dakota sandstone formations at selected areas in the San Juan Basin of northwestern New Mexico. This work used the methodology and approach developed in Phase I. Integrated reservoir description and hydraulic fracture treatment analyses were also conducted in the Pecos Slope Abo tight-gas reservoir in southeastern New Mexico and the Lewis Shale in the San Juan Basin. This study has demonstrated a methodology to (1) describe reservoir heterogeneities and natural fracture systems, (2) determine reservoir permeability and permeability anisotropy, (3) define the elliptical drainage area and recoverable gas for existing wells, (4) determine the optimal location and number of new in-fill wells to maximize economic recovery, (5) forecast the increase in total cumulative gas production from infill drilling, and (6) evaluate hydraulic fracture simulation treatments and their impact on well drainage area and infill well potential. Industry partners during the course of this five-year project included BP, Burlington Resources, ConocoPhillips, and Williams.

Lawrence W. Teufel; Her-Yuan Chen; Thomas W. Engler; Bruce Hart

2004-05-01

76

Feasibility of waterflooding Soku E7000 gas-condensate reservoir  

E-print Network

. To achieve this recovery, the reservoir should return to natural depletion after four years of water injection, before water invades the producing wells. Factors that affect the effectiveness of water injection in this reservoir include aquifer strength...

Ajayi, Arashi

2012-06-07

77

Performance of multiple fractured horizontal wells in shale gas reservoirs with consideration of multiple mechanisms  

NASA Astrophysics Data System (ADS)

Gas flow in shales is believed to result from a combination of several mechanisms, including desorption, diffusion, viscous flow and the effect of stress-sensitivity of reservoir permeability. However, little work has been done in literature to simultaneously incorporate all these mechanisms in well testing models for shale gas reservoirs. This paper presents a new well testing model for multiple fractured horizontal wells (MFHW) in shale gas reservoirs with consideration of desorption, diffusive flow, viscous flow and stress-sensitivity of reservoir permeability. Comparing with current well testing models for MFHW, the model presented here takes into consideration more mechanisms controlling shale gas flow, which is more in line with the actual reservoir situation. Laplace transformation, point source function, perturbation method, numerical discrete method and Gaussian elimination method are employed to solve the well testing model. The pressure transient responses are then inverted into real time space with Stehfest numerical inversion algorithm. Type curves are plotted, and different flow regimes in shale gas reservoirs are identified. The effects of relevant parameters are analyzed as well. The presented model can be used to interpret pressure data more accurately for shale gas reservoirs and provide more accurate dynamic parameters which are important for efficient reservoir development.

Wang, Hai-Tao

2014-03-01

78

The importance of shale composition and pore structure upon gas storage potential of shale gas reservoirs  

Microsoft Academic Search

The effect of shale composition and fabric upon pore structure and CH4 sorption is investigated for potential shale gas reservoirs in the Western Canadian Sedimentary Basin (WCSB). Devonian–Mississippian (D–M) and Jurassic shales have complex, heterogeneous pore volume distributions as identified by low pressure CO2 and N2 sorption, and high pressure Hg porosimetry. Thermally mature D–M shales (1.6–2.5%VRo) have Dubinin–Radushkevich (D–R)

Daniel J. K. Ross; R. Marc Bustin

2009-01-01

79

Characterization of oil and gas reservoirs and recovery technology deployment on Texas State Lands  

SciTech Connect

Texas State Lands oil and gas resources are estimated at 1.6 BSTB of remaining mobile oil, 2.1 BSTB, or residual oil, and nearly 10 Tcf of remaining gas. An integrated, detailed geologic and engineering characterization of Texas State Lands has created quantitative descriptions of the oil and gas reservoirs, resulting in delineation of untapped, bypassed compartments and zones of remaining oil and gas. On Texas State Lands, the knowledge gained from such interpretative, quantitative reservoir descriptions has been the basis for designing optimized recovery strategies, including well deepening, recompletions, workovers, targeted infill drilling, injection profile modification, and waterflood optimization. The State of Texas Advanced Resource Recovery program is currently evaluating oil and gas fields along the Gulf Coast (South Copano Bay and Umbrella Point fields) and in the Permian Basin (Keystone East, Ozona, Geraldine Ford and Ford West fields). The program is grounded in advanced reservoir characterization techniques that define the residence of unrecovered oil and gas remaining in select State Land reservoirs. Integral to the program is collaboration with operators in order to deploy advanced reservoir exploitation and management plans. These plans are made on the basis of a thorough understanding of internal reservoir architecture and its controls on remaining oil and gas distribution. Continued accurate, detailed Texas State Lands reservoir description and characterization will ensure deployment of the most current and economically viable recovery technologies and strategies available.

Tyler, R.; Major, R.P.; Holtz, M.H. [Univ. of Texas, Austin, TX (United States)] [and others

1997-08-01

80

CO2 Utilization and Storage in Shale Gas Reservoirs  

NASA Astrophysics Data System (ADS)

Surging natural gas production from fractured shale reservoirs and the emerging concept of utilizing anthropogenic CO2 for secondary recovery and permanent storage is driving the need for understanding fundamental mechanisms controlling gas adsorption and desorption processes, mineral volume changes, and impacts to transmissivity properties. Early estimates indicate that between 10 and 30 gigatons of CO2 storage capacity may exist in the 24 shale gas plays included in current USGS assessments. However, the adsorption of gases (CO2, CH4, and SO2) is not well understood and appears unique for individual clay minerals. Using specialized experimental techniques developed at PNNL, pure clay minerals were examined at relevant pressures and temperatures during exposure to CH4, CO2, and mixtures of CO2-SO2. Adsorbed concentrations of methane displayed a linear behavior as a function of pressure as determined by a precision quartz crystal microbalance. Acid gases produced differently shaped adsorption isotherms, depending on temperature and pressure. In the instance of kaolinite, gaseous CO2 adsorbed linearly, but in the presence of supercritical CO2, surface condensation increased significantly to a peak value before desorbing with further increases in pressure. Similarly shaped CO2 adsorption isotherms derived from natural shale samples and coal samples have been reported in the literature. Adsorption steps, determined by density functional theory calculations, showed they were energetically favorable until the first CO2 layer formed, corresponding to a density of ~0.35 g/cm3. Interlayer cation content (Ca, Mg, or Na) of montmorillonites influenced adsorbed gas concentrations. Measurements by in situ x-ray diffraction demonstrate limited CO2 diffusion into the Na-montmorillonite interlayer spacing, with structural changes related to increased hydration. Volume changes were observed when Ca or Mg saturated montmorillonites in the 1W hydration state were exposed to supercritical CO2. Additional experiments were conducted with pressurized attenuated total reflectance infrared spectroscopy technique that tracked clay hydration, gas adsorption, and water concentrations in the fluids during exposure to CO2 and CH4. These fundamental physico-chemical data are being collected into a database for parameterization of multiphase flow and reactive transport simulations of the CO2 injection, trapping, and secondary methane in fractured shales.

Schaef, T.; Glezakou, V.; Owen, T.; Miller, Q.; Loring, J.; Davidson, C.; McGrail, P.

2013-12-01

81

AVO in North of Paria, Venezuela: Gas methane versus condensate reservoirs  

SciTech Connect

The gas fields of North of Paria, offshore eastern Venezuela, present a unique opportunity for amplitude variations with offset (AVO) characterization of reservoirs containing different fluids: gas-condensate, gas (methane) and water (brine). AVO studies for two of the wells in the area, one with gas-condensate and the other with gas (methane) saturated reservoirs, show interesting results. Water sands and a fluid contact (condensate-water) are present in one of these wells, thus providing a control point on brine-saturated properties. The reservoirs in the second well consist of sands highly saturated with methane. Clear differences in AVO response exist between hydrocarbon-saturated reservoirs and those containing brine. However, it is also interesting that subtle but noticeable differences can be interpreted between condensate-and methane-saturated sands. These differences are attributed to differences in both in-situ fluid density and compressibility, and rock frame properties.

Regueiro, J. [Univ. Simon Bolivar, Sartenejas (Venezuela)] [Univ. Simon Bolivar, Sartenejas (Venezuela); Pena, A. [Lagoven S.A., Caracas (Venezuela)] [Lagoven S.A., Caracas (Venezuela)

1996-07-01

82

Naturally fractured tight gas reservoir detection optimization. Quarterly report, January--March 1995  

SciTech Connect

This report describes progress in the following five projects: (1) Geologic assessment of the Piceance Basin; (2) Regional stratigraphic studies, Upper Cretaceous Mesaverde Group, southern Piceance Basin, Colorado; (3) Structurally controlled and aligned tight gas reservoir compartmentalization in the San Juan and Piceance Basins--Foundation for a new approach to exploration and resource assessments of continuous type deposits; (4) Delineation of Piceance Basin basement structures using multiple source data--Implications for fractured reservoir exploration; and (5) Gas and water-saturated conditions in the Piceance Basin, western Colorado--Implications for fractured reservoir detection in a gas-centered coal basin.

NONE

1995-05-01

83

Impact of relative permeability models on fluid flow behavior for gas condensate reservoirs  

E-print Network

and on the quantification of their impact on reservoir fluid flow and well performance. We selected three relative permeability models to compare the results obtained in the modeling of relative permeabilities for a published North Sea gas condensate reservoir. The models...

Zapata Arango, Jose? Francisco

2012-06-07

84

CO 2 sequestration in depleted oil and gas reservoirs—caprock characterization and storage capacity  

Microsoft Academic Search

CO2 storage in depleted oil and gas reservoirs is considered to be one of the most practical options for reducing CO2 emissions in the atmosphere and has been practiced in different locations worldwide. It is commonly believed that the sealing capacity of the caprock, which had successfully sealed the original hydrocarbon in the reservoirs for a geological time, is sufficient

Zhaowen Li; Mingzhe Dong; Shuliang Li; Sam Huang

2006-01-01

85

Shale we look for gas?............................................................................. 1 The Marcellus shale--An old "new" gas reservoir in Pennsylvania ............ 2  

E-print Network

#12;CONTENTS Shale we look for gas?............................................................................. 1 The Marcellus shale--An old "new" gas reservoir in Pennsylvania ............ 2 Meet the staff, the contour interval should be 6 inches. #12;STATE GEOLOGIST'S EDITORIAL Shale We Look For Gas? Recently, you

Boyer, Elizabeth W.

86

Time-Lapse Depletion Modeling Sensitivity Study: Gas-Filled Gulf of Mexico Reservoir.  

E-print Network

??Time-lapse seismic allows oil/gas reservoir monitoring during production, highlighting compaction and water movement. Time-lapse modeling, using a stress-dependent rock physics model, helps determine the need… (more)

Gautre, Christy

2010-01-01

87

Application of the Stretched Exponential Production Decline Model to Forecast Production in Shale Gas Reservoirs  

E-print Network

Production forecasting in shale (ultra-low permeability) gas reservoirs is of great interest due to the advent of multi-stage fracturing and horizontal drilling. The well renowned production forecasting model, Arps? Hyperbolic Decline Model...

Statton, James Cody

2012-07-16

88

Comparison of Various Deterministic Forecasting Techniques in Shale Gas Reservoirs with Emphasis on the Duong Method  

E-print Network

There is a huge demand in the industry to forecast production in shale gas reservoirs accurately. There are many methods including volumetric, Decline Curve Analysis (DCA), analytical simulation and numerical simulation. Each one of these methods...

Joshi, Krunal Jaykant

2012-10-19

89

Well-test analysis for solution-gas-drive reservoirs. Part 2; Buildup analysis  

SciTech Connect

This work presents new analysis methods for pressure-buildup data from a well completed in a solution-gas-drive reservoir. New procedures for estimating effective phase permeabilities as functions of pressure and saturation are presented.

Serra, K.V.; Peres, A.M.M. (PETROBRAS, Rio de Janeiro, RJ (Brazil)); Reynolds, A.C. (Tulsa Univ., OK (USA))

1990-06-01

90

A quadratic cumulative production model for the material balance of an abnormally pressured gas reservoir  

E-print Network

The premise of this research is the concept, development, and application of an approximate relation for the material balance of abnormally-pressured gas reservoirs. The approximation is formulated directly from the rigorous material balance...

Gonzalez, Felix Eduardo

2005-02-17

91

Z-99 Rock Physics of Gas Hydrate Reservoir J. DVORKIN 1 AND A. NUR 2  

Microsoft Academic Search

Summary. Enormous amounts of methane gas hydrate are present in sediments under the world's oceans as well as in on-shore sediments in the Arctic. These hydrates are a potential future energy resource. The most well-developed geophysical tool for exploring large volumes of the subsurface where gas hydrate is found is seismic reflection profiling. To characterize a natural gas hydrate reservoir

S. Gessner

92

Underground natural gas storage reservoir management: Phase 2. Final report, June 1, 1995--March 30, 1996  

SciTech Connect

Gas storage operators are facing increased and more complex responsibilities for managing storage operations under Order 636 which requires unbundling of storage from other pipeline services. Low cost methods that improve the accuracy of inventory verification are needed to optimally manage this stored natural gas. Migration of injected gas out of the storage reservoir has not been well documented by industry. The first portion of this study addressed the scope of unaccounted for gas which may have been due to migration. The volume range was estimated from available databases and reported on an aggregate basis. Information on working gas, base gas, operating capacity, injection and withdrawal volumes, current and non-current revenues, gas losses, storage field demographics and reservoir types is contained among the FERC Form 2, EIA Form 191, AGA and FERC Jurisdictional databases. The key elements of this study show that gas migration can result if reservoir limits have not been properly identified, gas migration can occur in formation with extremely low permeability (0.001 md), horizontal wellbores can reduce gas migration losses and over-pressuring (unintentionally) storage reservoirs by reinjecting working gas over a shorter time period may increase gas migration effects.

Ortiz, I.; Anthony, R.V.

1996-12-31

93

Determining tight gas reservoir parameters with an automatic history matching model  

E-print Network

DETERMINING TIGHT GAS RESERVOIR PARAMETERS WITH AN AUTOMATIC HISTORY MATCHING MODEL A Thesis by SAMUEL ROBERT AYDELOTTE, II Submitted to the Graduate College of Texas A&M University in partial fulfillment of the requirement for the degree... of MASTER OF SCIENCE August 1977 Major Subject: Petroleum Engineering DETERMINING TIGHT GAS RESERVOIR PARAMETERS WITH AN AUTOMATIC HISTORY MATCHING MODEL A Thesis by SAMUEL ROBERT AYDELOTTE, II Approved as to style and content by: Chairman...

Aydelotte, Samuel Robert

1977-01-01

94

Electrical anisotropy of gas hydrate-bearing sand reservoirs in the Gulf of Mexico  

Microsoft Academic Search

We present new results and interpretations of the electrical anisotropy and reservoir architecture in gas hydrate-bearing sands using logging data collected during the Gulf of Mexico Gas Hydrate Joint Industry Project Leg II. We focus specifically on sand reservoirs in Hole Alaminos Canyon 21 A (AC21-A), Hole Green Canyon 955 H (GC955-H) and Hole Walker Ridge 313 H (WR313-H). Using

Ann E. Cook; Barbara I. Anderson; John Rasmus; Keli Sun; Qiming Li; Timothy S. Collett; David S. Goldberg

95

Stochastic Modeling of a Fracture Network in a Hydraulically Fractured Shale-Gas Reservoir  

E-print Network

are the main contributors to the domestic dry gas production (Figure 1), and this contribution is projected to increase steadily until 2040. Understanding the performance potential and nature of reserves for unconventional reservoirs remains a significant... challenge, and the economic impact of inaccurate reserves estimation may be significant. Figure 1 — U.S. dry natural gas production (Reproduced with data from EIA (2014)). In the context of unconventional reservoirs, we are faced an increasing...

Mhiri, Adnene

2014-08-10

96

The effects of production rate and gravitational segregation on gas injection performance of oil reservoirs  

E-print Network

THE EFFECTS OF PRODUCTION RATE AND GRAVITATIONAL SEGREGATION ON GAS INJECTION PERFORMANCE OF OIL RESERVOIRS A Thesis by ED MARTIN FERGUSON Submitted to the Graduate College of Texas A&M University in partial fulfillment of the requirements... for the degree of MASTER OF SCIENCE August 1972 Major Subject: PETROLEUM ENGINEERING THE EFFECTS OF PRODUCTION RATE AND GRAVITATIONAL SEGREGATION ON GAS INJECTION PERFORMANCE OF OIL RESERVOIRS A Thesis by ED MARTIN FERGUSON Approved as. to style...

Ferguson, Ed Martin

1972-01-01

97

Modeling Performance of Horizontal Wells with Multiple Fractures in Tight Gas Reservoirs  

E-print Network

MODELING PERFORMANCE OF HORIZONTAL WELLS WITH MULTIPLE FRACTURES IN TIGHT GAS RESERVOIRS A Thesis by GUANGWEI DONG Submitted to the Office of Graduate Studies of Texas A&M University in partial fulfillment... Guangwei Dong MODELING PERFORMANCE OF HORIZONTAL WELLS WITH MULTIPLE FRACTURES IN TIGHT GAS RESERVOIRS A Thesis by GUANGWEI DONG Submitted to the Office of Graduate Studies of Texas A&M University in partial fulfillment...

Dong, Guangwei

2011-02-22

98

Production of Natural Gas and Fluid Flow in Tight Sand Reservoirs  

SciTech Connect

This document reports progress of this research effort in identifying relationships and defining dependencies between macroscopic reservoir parameters strongly affected by microscopic flow dynamics and production well performance in tight gas sand reservoirs. These dependencies are investigated by identifying the main transport mechanisms at the pore scale that should affect fluids flow at the reservoir scale. A critical review of commercial reservoir simulators, used to predict tight sand gas reservoir, revealed that many are poor when used to model fluid flow through tight reservoirs. Conventional simulators ignore altogether or model incorrectly certain phenomena such as, Knudsen diffusion, electro-kinetic effects, ordinary diffusion mechanisms and water vaporization. We studied the effect of Knudsen's number in Klinkenberg's equation and evaluated the effect of different flow regimes on Klinkenberg's parameter b. We developed a model capable of explaining the pressure dependence of this parameter that has been experimentally observed, but not explained in the conventional formalisms. We demonstrated the relevance of this, so far ignored effect, in tight sands reservoir modeling. A 2-D numerical simulator based on equations that capture the above mentioned phenomena was developed. Dynamic implications of new equations are comprehensively discussed in our work and their relative contribution to the flow rate is evaluated. We performed several simulation sensitivity studies that evidenced that, in general terms, our formalism should be implemented in order to get more reliable tight sands gas reservoirs' predictions.

Maria Cecilia Bravo

2006-06-30

99

GEOLOGIC ASPECTS OF TIGHT GAS RESERVOIRS IN THE ROCKY MOUNTAIN REGION.  

USGS Publications Warehouse

The authors describe some geologic characteristics of tight gas reservoirs in the Rocky Mountain region. These reservoirs usually have an in-situ permeability to gas of 0. 1 md or less and can be classified into four general geologic and engineering categories: (1) marginal marine blanket, (2) lenticular, (3) chalk, and (4) marine blanket shallow. Microscopic study of pore/permeability relationships indicates the existence of two varieties of tight reservoirs. One variety is tight because of the fine grain size of the rock. The second variety is tight because the rock is relatively tightly cemented and the pores are poorly connected by small pore throats and capillaries.

Spencer, Charles W.

1985-01-01

100

A New Technology for the Exploration of Shale Gas Reservoirs  

Microsoft Academic Search

Energy consumption in the world increases 5.6% every year, and alternative resources like shale gas, coal-bed methane (CBM), tar sand, and so on are strongly needed. Shale gas is an unconventional natural gas of enormous potential. Abundant shale gas resides in the form of adsorption gas. Desorption of shale gas is an important mechanism and power source of shale gas

W. Jing; L. Huiqing; G. Rongna; K. Aihong; Z. Mi

2011-01-01

101

Effect of connate water on miscible displacement of reservoir oil by flue gas  

E-print Network

of Reservoir Fluid Before Adding Natural Gas Page 2. Reservoir Fluid Characteristics 14 3. Production History 18 4. Distribution of Carbon Dioxide Between Hydrocarbons and Salt Solution at 40 C 0 5. Solubility of Carbon Dioxide in Water in the Presence... hydrocarbons. In this work flue gas, composed of 88 mole per cent nitrogen and 12 mole per cent carbon dioxide, was substituted for natural gas as the displacing medium in the high-pressure gas drive. Because of the decrease in solubility of carbon dioxide...

Maxwell, H. D.

1960-01-01

102

Evaluation of in situ stress changes with gas depletion of coalbed methane reservoirs  

NASA Astrophysics Data System (ADS)

sound knowledge of the stress path for coalbed methane (CBM) reservoirs is critical for a variety of applications, including dynamic formation stability evaluation, long-term gas production management, and carbon sequestration in coals. Although this problem has been extensively studied for traditional oil and gas reservoirs, it is somewhat unclear for CBM reservoirs. The difference between the stress paths followed in the two reservoir types is expected to be significant given the unique sorption-induced deformation phenomenon associated with gas production from coal. This results in an additional reservoir volumetric strain, which induces a rather "abnormal" loss of horizontal stress with depletion, leading to continuous changes in the subsurface formation stresses, both effective as well as total. It is suspected that stress changes within the reservoir triggers formation failure after significant depletion. This paper describes an experimental study, carried out to measure the horizontal stress under in situ depletion conditions. The results show that the horizontal stress decreases linearly with depletion under in situ conditions. The dynamic stress evolution is theoretically analyzed, based on modified poroelasticity associated with sorption-induced strain effect. Additionally, the failure tendency of the reservoir under in situ conditions is analyzed using the traditional Mohr-Coulomb failure criterion. The results indicate that depletion may lead to coal failure, particularly in deeper coalbeds and ones exhibiting large matrix shrinkage.

Liu, Shimin; Harpalani, Satya

2014-08-01

103

Fractured Shale Gas Reservoir Performance Study-An Offset Well Interference Field Test  

Microsoft Academic Search

Gas-production characteristics of naturally fractured Devonian shale have been quantified through a three-well interference field test by use of an established producing well and two offsets placed on the primary and secondary regional fracture trends relative to the producer. Three individual shale zones were evaluated simultaneously by buildup, drawdown, and pulse tests to investigate reservoir gas flow characteristics, natural fracture

Karl-Heinz Frohne; James Mercer

1984-01-01

104

DEVELOPMENT OF MORE-EFFICIENT GAS FLOODING APPLICABLE TO SHALLOW RESERVOIRS  

Microsoft Academic Search

The objective of this research is to widen the applicability of gas flooding to shallow oil reservoirs by reducing the pressure required for miscibility using gas enrichment and increasing sweep efficiency with foam. Task 1 examines the potential for improved oil recovery with enriched gases. Subtask 1.1 examines the effect of dispersion processes on oil recovery and the extent of

William R. Rossen; Russell T. Johns; Gary A. Pope

2003-01-01

105

Factors affecting the development of the pressure differential in Upper Paleozoic gas reservoirs in the Sulige and Yulin areas of the Ordos Basin, China  

Microsoft Academic Search

The Sulige gas field and the Yulin gas field are located in the north of the Ordos Basin. Reservoir pressure in the Sulige area is subnormal, whereas reservoirs in the Yulin area have normal hydrostatic pressure. This paper provides an explanation of this difference. The characteristics of reservoir sediment and formation water chemistry in the gas reservoirs of these two

Hao Xu; Dazhen Tang; Junfeng Zhang; Wei Yin; Wenzhong Zhang; Wenji Lin

2011-01-01

106

CO2-Driven Enhanced Gas Recovery and Storage in Depleted Shale Reservoir-A Numerical Simulation Study  

E-print Network

1 CO2-Driven Enhanced Gas Recovery and Storage in Depleted Shale Reservoir- A Numerical Simulation for storage and enhanced gas recovery may be organic-rich shales, which CO2 is preferentially adsorbed comprehensive simulation studies to better understand CO2 injection process in shale gas reservoir. This paper

Mohaghegh, Shahab

107

Characterization of oil and gas reservoir heterogeneity. Final report  

SciTech Connect

Research described In this report addresses the internal architecture of two specific reservoir types: restricted-platform carbonates and fluvial-deltaic sandstones. Together, these two reservoir types contain more than two-thirds of the unrecovered mobile oil remaining ill Texas. The approach followed in this study was to develop a strong understanding of the styles of heterogeneity of these reservoir types based on a detailed outcrop description and a translation of these findings into optimized recovery strategies in select subsurface analogs. Research targeted Grayburg Formation restricted-platform carbonate outcrops along the Algerita Escarpment and In Stone Canyon In southeastern New Mexico and Ferron deltaic sandstones in central Utah as analogs for the North Foster (Grayburg) and Lake Creek (Wilcox) units, respectively. In both settings, sequence-stratigraphic style profoundly influenced between-well architectural fabric and permeability structure. It is concluded that reservoirs of different depositional origins can therefore be categorized Into a ``heterogeneity matrix`` based on varying intensity of vertical and lateral heterogeneity. The utility of the matrix is that it allows prediction of the nature and location of remaining mobile oil. Highly stratified reservoirs such as the Grayburg, for example, will contain a large proportion of vertically bypassed oil; thus, an appropriate recovery strategy will be waterflood optimization and profile modification. Laterally heterogeneous reservoirs such as deltaic distributary systems would benefit from targeted infill drilling (possibly with horizontal wells) and improved areal sweep efficiency. Potential for advanced recovery of remaining mobile oil through heterogeneity-based advanced secondary recovery strategies In Texas is projected to be an Incremental 16 Bbbl. In the Lower 48 States this target may be as much as 45 Bbbl at low to moderate oil prices over the near- to mid-term.

Tyler, N.; Barton, M.D.; Bebout, D.G.; Fisher, R.S.; Grigsby, J.D.; Guevara, E.; Holtz, M.; Kerans, C.; Nance, H.S.; Levey, R.A.

1992-10-01

108

Atlas of selected oil and gas reservoir rocks from North America: A color guidebook to the petrology of selected oil and gas reservoir rocks from the United States and Canada  

SciTech Connect

A collection of color photomicrographs of oil and gas reservoir rocks. It discusses reservoirs that have experienced secondary and tertiary recovery projects, their failures and successes. It provides photographs of a broad range of reservoir rock types. It helps in assessing legislation dealing with U.S. petroleum resources.

Biederman, E.W.

1986-01-01

109

NMR relaxation measurements on partially water saturated rocks (from a tight gas reservoir)  

NASA Astrophysics Data System (ADS)

Low permeability natural gas reservoirs are called tight gas reservoirs. In these reservoirs, permeability is the crucial parameter for an economical production. Unfortunately, rock permeability is difficult to determine at least in situ. We improve the prediction of tight gas reservoir properties, such as gas and water content and relative permeability (i.e. the permeability of a fluid phase at partial saturation) using Nuclear Magnetic Resonance (NMR) measurements. To this end, we carried out longitudinal (T1) and transversal (T2) relaxation time NMR measurements under variable saturations with air and water on 22 rock samples from a North Sea natural gas reservoir kindly provided by Wintershall Holding. Porosity of these samples varies between 1.6 % and 9.7 %. Negative pressures between 0 hPa and 4000 hPa were applied to drain the originally water saturated samples. At each pressure, a T1- and T2- NMR relaxation time measurement was performed. From the obtained desaturation curves, i.e. pressure dependent saturations, we estimated the relative permeability using the van Genuchten-Mualem model. We will introduce the obtained relations between the NMR properties on the one hand and water saturation and relative permeability on the other hand.

Jorand, R.; Klitzsch, N.; Clauser, C.; de Wijn, B.

2010-12-01

110

Variations in dissolved gas compositions of reservoir fluids from the Coso geothermal field  

SciTech Connect

Gas concentrations and ratios in 110 analyses of geothermal fluids from 47 wells in the Coso geothermal system illustrate the complexity of this two-phase reservoir in its natural state. Two geographically distinct regions of single-phase (liquid) reservoir are present and possess distinctive gas and liquid compositions. Relationships in soluble and insoluble gases preclude derivation of these waters from a common parent by boiling or condensation alone. These two regions may represent two limbs of fluid migration away from an area of two-phase upwelling. During migration, the upwelling fluids mix with chemically evolved waters of moderately dissimilar composition. CO{sub 2} rich fluids found in the limb in the southeastern portion of the Coso field are chemically distinct from liquids in the northern limb of the field. Steam-rich portions of the reservoir also indicate distinctive gas compositions. Steam sampled from wells in the central and southwestern Coso reservoir is unusually enriched in both H{sub 2}S and H{sub 2}. Such a large enrichment in both a soluble and insoluble gas cannot be produced by boiling of any liquid yet observed in single-phase portions of the field. In accord with an upflow-lateral mixing model for the Coso field, at least three end-member thermal fluids having distinct gas and liquid compositions appear to have interacted (through mixing, boiling and steam migration) to produce the observed natural state of the reservoir.

Williams, Alan E.; Copp, John F.

1991-01-01

111

Geology, reservoir engineering and methane hydrate potential of the Walakpa Gas Field, North Slope, Alaska  

SciTech Connect

The Walakpa Gas Field, located near the city of Barrow on Alaska's North Slope, has been proven to be methane-bearing at depths of 2000--2550 feet below sea level. The producing formation is a laterally continuous, south-dipping, Lower Cretaceous shelf sandstone. The updip extent of the reservoir has not been determined by drilling, but probably extends to at least 1900 feet below sea level. Reservoir temperatures in the updip portion of the reservoir may be low enough to allow the presence of in situ methane hydrates. Reservoir net pay however, decreases to the north. Depths to the base of permafrost in the area average 940 feet. Drilling techniques and production configuration in the Walakpa field were designed to minimize formation damage to the reservoir sandstone and to eliminate methane hydrates formed during production. Drilling development of the Walakpa field was a sequential updip and lateral stepout from a previously drilled, structurally lower confirmation well. Reservoir temperature, pressure, and gas chemistry data from the development wells confirm that they have been drilled in the free-methane portion of the reservoir. Future studies in the Walakpa field are planned to determine whether or not a component of the methane production is due to the dissociation of updip in situ hydrates.

Glenn, R.K.; Allen, W.W.

1992-12-01

112

Gross greenhouse gas fluxes from hydro-power reservoir compared to thermo-power plants  

Microsoft Academic Search

This paper presents the findings of gross carbon dioxide and methane emissions measurements in several Brazilian hydro-reservoirs, compared to thermo power generation.The term ‘gross emissions’ means gas flux measurements from the reservoir surface without natural pre-impoundment emissions by natural bodies such as the river channel, seasonal flooding and terrestrial ecosystems. The net emissions result from deducting pre-existing emissions by the

Marco Aurelio dos Santos; Luiz Pinguelli Rosa; Bohdan Sikar; Elizabeth Sikar; Ednaldo Oliveira dos Santos

2006-01-01

113

Approaches for reservoir geological modelling of the Maui Gas Field, New Zealand  

SciTech Connect

The Maui field currently supplies 90 % of New Zealand`s gas and a significant proportion of the country`s total energy requirement. The management of the gas reserves uses an ECLIPSE simulation model based upon the input of reservoir properties from STRATAMODEL. This is a deterministic reservoir geological modelling system suitable for the generally continuous C Sands gas-condensate reservoir, and oil bearing F Sands. Reservoir correlations within this lower Eocene coastal plain and shallow marine depositional environment are consistent with reservoir pressure and palaeomagneto-stratigraphic data, supported by a sequence stratigaphic framework and outcrop analogues from the Book Cliffs, Utah. Certain reservoir dis-continuities were interpreted and digitized from seismic amplitude displays and include offlapping shoreface sequences, images of shoreline positions and discrete large-scale valley fills. Along with gas condensate, the remaining D Sand reservoir contains multiple stacked, but marginal, oil accumulations in fluvial and estuarine barrel sands, trapped by extensive intraformational seals caused by base level fluctuations. It is generally a low permeability reservoir, with discontinuous sediment bodies and possibly sealing, small-scale faults, In contrast with the more predictable C Sands, a combined deterministic-stochastic modelling procedure using Shell`s GEOCAP system was found to be most appropriate. The D Sand property modelling is based on frequency distributions of a large minipermeameter dataset integrated with digital sedimentological core descriptions and supported by systematic mineralogical and petrographic analyses. Some of the potentially productive high permeability meandering fluvial and estuarine channel sands are identified by seismic amplitudes, together with core interpretations and supported by palynofacies data.

Greenstreet, C.; The, R.; Cohen, J. [Shell Todd Oil Services, New Plymouth (New Zealand)

1995-08-01

114

Long-term greenhouse gas emissions from hydroelectric reservoirs in tropical forest regions  

Microsoft Academic Search

The objective of this work is to quantify long-term emissions of two major greenhouse gases, CO2 and CH4, produced by the decomposition of the flooded organic matter in tropical artificial reservoirs. In a previous paper [Galy-Lacaux et al., 1997], gas emissions from the tropical reservoir of Petit Saut (French Guiana) were quantified over the first two years after impounding. This

Corinne Galy-Lacaux; Robert Delmas; Georges Kouadio; Sandrine Richard; Philippe Gosse

1999-01-01

115

CONCEPTUAL MODEL FOR ORIGIN OF ABNORMALLY PRESSURED GAS ACCUMULATIONS IN LOW-PERMEABILITY RESERVOIRS.  

USGS Publications Warehouse

The paper suggests that overpressured and underpressured gas accumulations of this type have a common origin. In basins containing overpressured gas accumulations, rates of thermogenic gas accumulation exceed gas loss, causing fluid (gas) pressure to rise above the regional hydrostatic pressure. Free water in the larger pores is forced out of the gas generation zone into overlying and updip, normally pressured, water-bearing rocks. While other diagenetic processes continue, a pore network with very low permeability develops. As a result, gas accumulates in these low-permeability reservoirs at rates higher than it is lost. In basins containing underpressured gas accumulations, rates of gas generation and accumulation are less than gas loss. The basin-center gas accumulation persists, but because of changes in the basin dynamics, the overpressured accumulation evolves into an underpressured system.

Law, B.E.; Dickinson, W.W.

1985-01-01

116

30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?  

Code of Federal Regulations, 2010 CFR

...Resources 2 2010-07-01 2010-07-01 false How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap? 250.1157 Section 250.1157 Mineral Resources MINERALS MANAGEMENT SERVICE,...

2010-07-01

117

Two Kinds of Gas Hydrate Reservoirs: Pore-filling Sand vs. Fractured Clay  

Microsoft Academic Search

Recent marine gas hydrate expeditions, such as the Indian National Gas Hydrate Program Expedition 01 (NGHP-01) on the Indian continental margin and the Chevron\\/Department of Energy Joint Industry Project Legs 1 & 2 (JIP1 and JIP2) in the Gulf of Mexico, revealed both fine-grained sediments containing near-vertical gas hydrate filled fractures and sand reservoirs which are likely containing pore filling

A. Cook; D. Goldberg

2009-01-01

118

Geomechanical Development of Fractured Reservoirs During Gas Production  

E-print Network

and utilized in a finite element model to coupled gas diffusion and rock mass deformation. The dual permeability method (DPM) is implemented into the Finite Element Model (FEM) to investigate fracture deformation and closure and its impact on gas flow...

Huang, Jian

2013-04-05

119

Analyzing aquifers associated with gas reservoirs using aquifer influence functions  

E-print Network

. and analytically by Ysxley for interference testing. Even more recently, the effects of a partially sealing fault in a composite reservoir were considered analytically by Ambastha et al. for transient pressure testing. This present research focused on obtaining... between the calcu- lated pressure change Apk. This deviation may be either positive or negative. Two variables are needed to represent this deviation because the LP method will not accept negative variables. Thus, the equation becomes: k E Acl Pj...

Targac, Gary Wayne

1988-01-01

120

Gas hydrate-filled fracture reservoirs on continental margins  

Microsoft Academic Search

Many scientists predicted that gas hydrate forms in fractures or lenses in fine-grained sediments, but only in the last decade were gas hydrates found in complex fracture systems on continental margins. Gas hydrate-filled fractures were captured on both in situ borehole images and in x-ray imaged pressure cores. These new discoveries of gas hydrate as fill in fractures have been

Ann Elizabeth Cook

2010-01-01

121

Reservoir and Stimulation Analysis of a Devonian Shale Gas Field  

Microsoft Academic Search

This paper presents a study of a shallow, low-productivity Devonian shale gas field consisting of 48 wells in Mason County, WV. Gas production from wells in the field was found to be associated with zones of substantial free-gas porosity in the presence of high kerogen (organic) content. Most wells are poor producers; the best wells are located in the northwest

J. S. Shaw; D. E. Lancaster; W. J. Lee; K. L. Avary; D. P. Terry

1989-01-01

122

Coal natural gas reservoir properties and formation evaluation techniques. Topical report  

SciTech Connect

The report summarizes coal natural gas reservoir and fluid properties and the techniques required to obtain quantitative estimates of the properties. The first section discusses the properties of the coal matrix that affect the volume of gas in place, the gas recovery as a function of pressure, and the rate of mass transfer from the coal matrix to the natural fracture system. The second section discusses the properties of the natural fracture system that control the production rates of gas and water from wells. The third section discusses the effect of these properties upon predicted rates and recovery factors of gas and water.

Mavor, M.

1995-05-01

123

Radon in unconventional natural gas from gulf coast geopressured-geothermal reservoirs  

USGS Publications Warehouse

Radon-222 has been measured in natural gas produced from experimental geopressured-geothermal test wells. Comparison with published data suggests that while radon activity of this unconventional natural gas resource is higher than conventional gas produced in the gulf coast, it is within the range found for conventional gas produced throughout the U.S. A method of predicting the likely radon activity of this unconventional gas is described on the basis of the data presented, methane solubility, and known or assumed reservoir conditions of temperature, fluid pressure, and formation water salinity.

Kraemer, T.F.

1986-01-01

124

Developing a tight gas sand advisor for completion and stimulation in tight gas reservoirs worldwide  

E-print Network

while completing and stimulating TGS reservoirs. The modules include Perforation Selection and Proppant Selection. Based on input well/reservoir parameters these subroutines provide unambiguous recommendations concerning which perforation strategy...

Bogatchev, Kirill Y.

2009-05-15

125

Characterization of Tight Gas Reservoir Pore Structure Using USANS/SANS and Gas Adsorption Analysis  

SciTech Connect

Small-angle and ultra-small-angle neutron scattering (SANS and USANS) measurements were performed on samples from the Triassic Montney tight gas reservoir in Western Canada in order to determine the applicability of these techniques for characterizing the full pore size spectrum and to gain insight into the nature of the pore structure and its control on permeability. The subject tight gas reservoir consists of a finely laminated siltstone sequence; extensive cementation and moderate clay content are the primary causes of low permeability. SANS/USANS experiments run at ambient pressure and temperature conditions on lithologically-diverse sub-samples of three core plugs demonstrated that a broad pore size distribution could be interpreted from the data. Two interpretation methods were used to evaluate total porosity, pore size distribution and surface area and the results were compared to independent estimates derived from helium porosimetry (connected porosity) and low-pressure N{sub 2} and CO{sub 2} adsorption (accessible surface area and pore size distribution). The pore structure of the three samples as interpreted from SANS/USANS is fairly uniform, with small differences in the small-pore range (< 2000 {angstrom}), possibly related to differences in degree of cementation, and mineralogy, in particular clay content. Total porosity interpreted from USANS/SANS is similar to (but systematically higher than) helium porosities measured on the whole core plug. Both methods were used to estimate the percentage of open porosity expressed here as a ratio of connected porosity, as established from helium adsorption, to the total porosity, as estimated from SANS/USANS techniques. Open porosity appears to control permeability (determined using pressure and pulse-decay techniques), with the highest permeability sample also having the highest percentage of open porosity. Surface area, as calculated from low-pressure N{sub 2} and CO{sub 2} adsorption, is significantly less than surface area estimates from SANS/USANS, which is due in part to limited accessibility of the gases to all pores. The similarity between N{sub 2} and CO{sub 2}-accessible surface area suggests an absence of microporosity in these samples, which is in agreement with SANS analysis. A core gamma ray profile run on the same core from which the core plug samples were taken correlates to profile permeability measurements run on the slabbed core. This correlation is related to clay content, which possibly controls the percentage of open porosity. Continued study of these effects will prove useful in log-core calibration efforts for tight gas.

Clarkson, Christopher R [ORNL; He, Lilin [ORNL; Agamalian, Michael [ORNL; Melnichenko, Yuri B [ORNL; Mastalerz, Maria [Indiana Geological Survey; Bustin, Mark [University of British Columbia, Vancouver; Radlinski, Andrzej Pawell [ORNL; Blach, Tomasz P [ORNL

2012-01-01

126

New inflow performance relationships for gas condensate reservoirs  

E-print Network

....................................................................................................(1.5) Similarly, using Eq. 1.2 or Eq. 1.4 to solve for the rate at any time, we have: )1 wf psso pb ? ....................................................................................................................(1.6) Dividing Eq. 1....13 GRACE versus GRACE + polynomial regression (Case 9) ? dry gas...................................... 66 4.14 Example 5 ? gas condensate (? o= 0.22 measured) .................................................................... 68 4.15 Example 5...

Del Castillo Maravi, Yanil

2004-09-30

127

Canyon sand -- S. W. Texas example of a low permeability gas reservoir  

SciTech Connect

Canyon sands are Upper Pennsylvanian deposits found in the Val Verde basin and on the Permian Basin eastern shelf, Texas, and occur in a thick clastic sequence overlying the Strawn limestone. These sandstones are considered to have been deposited during Missourian time and are formally named after the Canyon group deposited on the eastern shelf. The Canyon sand has provided commercial gas production for over 30 years. Canyon gas reservoirs, occurring at depths of 2,000--8,000 ft, have yielded almost 2 tcf of gas. The area of this producing sand covers more than 10 counties in south central Texas. The paper describes the depositional environments and lithology, diagenetic cements, reservoir, stimulation, and geologic traps. Even though the stratigraphy includes coal beds, no commercial gas has been produced from the coal beds.

Trabelsi, A. (Trabelsi (Ali), Lubbock, TX (United States))

1994-05-09

128

HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS  

SciTech Connect

This report outlines progress in the first quarter of the third year of the DOE project ''High Resolution Prediction of Gas Injection Process Performance for Heterogeneous Reservoirs''. In this report we present an application of compositional streamline simulation in modeling enhanced condensate recovery via gas injection. These processes are inherently compositional and detailed compositional fluid descriptions must be use to represent the flow behavior accurately. Compositional streamline simulation results are compared to those of conventional finite-difference (FD) simulation for evaluation of gas injection schemes in condensate reservoirs. We present and compare streamline and FD results for two-dimensional (2D) and three-dimensional (3D) examples, to show that the compositional streamline method is a way to obtain efficiently estimates of reasonable accuracy for condensate recovery by gas injection.

Franklin M. Orr, Jr.

2002-12-31

129

Reservoir compaction and surface subsidence in the Central Luconia gas bearing carbonates, offshore Sarawak, East Malaysia  

Microsoft Academic Search

In the Central Luconia area, offshore Sarawak, substantial gas reserves are present in Miocene carbonate buildups. The carbonates consist of limestones and dolomites with porosities ranging from 0 to 40 percent. From core analysis it became evident that there exists a potential problem with regard to the compaction of the carbonate reservoir matrix as a result of effective stress increase

P. J. D. vanDitzhunzen; J. A. de Waai

1984-01-01

130

Effect of shale-water recharge on brine and gas recovery from geopressured reservoirs  

Microsoft Academic Search

The concept of shale-water recharge has often been discussed and preliminary assessments of its significance in the recovery of geopressured fluids have been given previously. The present study uses the Pleasant Bayou Reservoir data as a base case and varies the shale formation properties to investigate their impact on brine and gas recovery. The parametric calculations, based on semi-analytic solutions

T. D. Riney; S. K. Garg; R. H. Jr. Wallace

1985-01-01

131

Reservoir-Wellbore Coupled Simulation of Liquid Loaded Gas Well Performance  

E-print Network

accurate in predicting onset of liquid loading. In addition, we developed a simple pseudo-steady-state reservoir flow model that was seamlessly connected to a wellbore two-phase flow model. The model is capable of predicting the time a gas well...

Riza, Muhammad Feldy

2013-11-12

132

Naturally fractured tight gas reservoir detection optimization. Quarterly technical progress report, April 1995--June 1995  

SciTech Connect

Research continued on methods to detect naturally fractured tight gas reservoirs. This report contains a seismic survey map, and reports on efforts towards a source test to select the source parameters for a 37 square mile compressional wave 3-D seismic survey. Considerations of the source tests are discussed.

NONE

1995-08-01

133

Impact of mass balance calculations on adsorption capacities in microporous shale gas reservoirs  

Microsoft Academic Search

Determination of the adsorbed reservoir capacity of gas shales by adsorption analyses as done routinely by mass balance maybe in significant error if the effects of pore-size dependent void volume (porosity) is not considered. It is shown here that with increasing pressure, helium, which is invariably used to measure void volume, can access pores that are not available for adsorption

Daniel J. K. Ross; R. Marc Bustin

2007-01-01

134

Spatial and Temporal Variations in Greenhouse Gas Emissions from an Agricultural Reservoir  

EPA Science Inventory

Reservoirs are being built at an increasing rate each year to provide humans with resources such as hydroelectric power and drinking water. These man-made systems have provided society with important services, but these have come at the cost of enhanced greenhouse gas (GHG) emiss...

135

Naturally fractured tight gas reservoir detection optimization. Quarterly report, January 1 - March 31, 1996  

SciTech Connect

The objective is to determine methods for detection and mapping of naturally fractured systems for economic production of natural gas from fractured reservoirs. This report contains: 3D P-wave alternate processing; down hole 3C geophone analysis; fracture pattern analysis of the Fort Union and Wind River Basin; 3D-3C seismic processing; and technology transfer.

NONE

1996-12-31

136

Induced seismicity in the gas reservoirs of the Netherlands  

NASA Astrophysics Data System (ADS)

The Netherlands contains a large number of natural gas fields of various sizes, including the Groningen field, the largest in Western Europe. Gas production started in 1960 and is expected to be continued for more than two decades ahead. In due course, more and more of the smaller fields will become depleted and potentially available for underground gas storage. A number of fields are already being used as buffer storage for natural gas. Plans for CO2 storage in other fields are reaching an advanced stage. Currently, most industrial activity in the gas fields is still related to gas extraction rather than storage. The monitoring and analysis of induced seismicity that is observed today will be crucial for the assessment of storage opportunities in the near future. Induced seismicity due to gas extraction was not observed or recognized until a first widely felt event of magnitude 3.2 (ML) in 1986, only after several decades of production. Since then a steady rate of seismicity is observed, distributed over several fields. The largest events (up to ML=3.5 so far) cause some none-structural damage and much concern to the public. The monitoring network currently consists of 11 shallow (200m) borehole sensors and a pool of 19 accelerometers. The regional location threshold is around ML=1. The induced seismic catalogue contains more than 550 events to date and is growing at a rate of 30-50 events annually. The current work is aimed at improving source location accuracy using 3D velocity models obtained from the gas industry and the association of events with specific fault planes. The observed seismicity pattern provides insight on the behaviour of (compartments of) the gas fields under changing stress conditions.

Kraaijpoel, D.; Goutbeek, F.; Sleeman, R.; Dost, B.

2009-04-01

137

Characterizing Reservoir Properties Using Monitoring Gas Pressure Data after CO2-Injection  

NASA Astrophysics Data System (ADS)

This study evaluate the possibility of characterizing reservoir properties of permeability, porosity and entry pressure using CO2 monitoring data such as spatiotemporal distributions of gas pressure. The injection reservoir was set to be located 1400-1500 m below the ground surface so that CO2 remained in the supercritical state. The reservoir was assumed to contain five homogenous layers with alternating conductive and resistive properties, which is analogous to actual geological formations such as the Mount Simon Sandstone unit. The CO2 injection simulation used a cylindrical grid setting in which the injection well was situated at the center of the domain, which extended up to 8000 m from the injection well. The CO2 migration was simulated using the PNNL-developed simulator STOMP-CO2e (the water-salt-CO2 module). We adopted a nonlinear parameter estimation and optimization modeling software package, PEST, for automated reservoir parameter estimation. We explored the effects of data quality, data worth, and data redundancy on the detectability of reservoir parameters using CO2 pressure monitoring data, by comparing PEST inversion results using data with different levels of noises, various monitoring locations, and different data collection spacing and temporal sampling intervals. This study yielded insight into the use of CO2 monitoring data for reservoir characterization and how to design the monitoring system to optimize data worth and reduce data redundancy.

Fang, Z.; Hou, Z.; Lin, G.; Fang, Y.

2012-12-01

138

The Performance of Fractured Horizontal Well in Tight Gas Reservoir  

E-print Network

of a gas well in Marcellus Shale. .............................................. 85 Fig. 44?Schematic of the formation. .............................................................................. 87 Fig. 45?Vertical well schematic.... ......................................................... 77 Table 12?Cases for non-Darcy flow study. .................................................................... 79 Table 13?Cumulative production results. ...................................................................... 81 Table 14?Marcellus...

Lin, Jiajing

2012-02-14

139

Selection of fracture fluid for stimulating tight gas reservoirs  

E-print Network

..........................................51 6 Water Fracture Fluid Description ..............................................................56 7 Gel Fracture Fluid Description ..................................................................56 8 Proppant Description... Based on Proppant Concentration ........................66 24 Cumulative Frequency Distribution for 3-Year Cumulative Gas Production for Both Groups and Both Treatments (Carthage...

Malpani, Rajgopal Vijaykumar

2007-04-25

140

Greenhouse Gas Emissions from Hydroelectric Reservoirs in Tropical Regions  

Microsoft Academic Search

This paper discusses emissions by power-dams in the tropics. Greenhouse gas emissions from tropical power-dams are produced underwater through biomass decomposition by bacteria. The gases produced in these dams are mainly nitrogen, carbon dioxide and methane. A methodology was established for measuring greenhouse gases emitted by various power-dams in Brazil. Experimental measurements of gas emissions by dams were made to

Luiz Pinguelli Rosa; Marco Aurelio dos Santos; Bohdan Matvienko; Ednaldo Oliveira dos Santos; Elizabeth Sikar

2004-01-01

141

Transport of Gas Phase Radionuclides in a Fractured, Low-Permeability Reservoir  

NASA Astrophysics Data System (ADS)

The U.S. Atomic Energy Commission (predecessor to the Department of Energy, DOE) oversaw a joint program between industry and government in the 1960s and 1970s to develop technology to enhance production from low-permeability gas reservoirs using nuclear stimulation rather than conventional means (e.g., hydraulic and/or acid fracturing). Project Rio Blanco, located in the Piceance Basin, Colorado, was the third experiment under the program. Three 30-kiloton nuclear explosives were placed in a 2134 m deep well at 1780, 1899, and 2039 m below the land surface and detonated in May 1973. Although the reservoir was extensively fractured, complications such as radionuclide contamination of the gas prevented production and subsequent development of the technology. Two-dimensional numerical simulations were conducted to identify the main transport processes that have occurred and are currently occurring in relation to the detonations, and to estimate the extent of contamination in the reservoir. Minor modifications were made to TOUGH2, the multiphase, multicomponent reservoir simulator developed at Lawrence Berkeley National Laboratories. The simulator allows the explicit incorporation of fractures, as well as heat transport, phase change, and first order radionuclide decay. For a fractured two-phase (liquid and gas) reservoir, the largest velocities are of gases through the fractures. In the gas phase, tritium and one isotope of krypton are the principle radionuclides of concern. However, in addition to existing as a fast pathway, fractures also permit matrix diffusion as a retardation mechanism. Another retardation mechanism is radionuclide decay. Simulations show that incorporation of fractures can significantly alter transport rates, and that radionuclides in the gas phase can preferentially migrate upward due to the downward gravity drainage of liquid water in the pores. This project was funded by the National Nuclear Security Administration, Nevada Operations Office, under DOE Contract no. DE-AC08-00NV13609.

Cooper, C. A.; Chapman, J.

2001-12-01

142

Stress change and fault slip in produced gas reservoirs used for storage of natural gas and carbon-dioxide  

NASA Astrophysics Data System (ADS)

Gas extraction and subsequent storage of natural gas or CO2 in produced gas reservoirs will change the state of stress in a reservoir-seal system due to poro-mechanical, thermal and possibly chemical effects. Depletion- and injection-induced stresses can mechanically damage top- and side-seals, re-activate pre-existing sealing faults and create new fractures, allowing fluid migration out of the storage reservoir and causing induced seismicity. The first case study describes a field scale three-dimensional geomechanical numerical modelling of a depleted gas field in the Netherlands, which will be used for underground gas storage (UGS). The field experienced induced seismicity associated with gas production in the past and concerns were raised regarding the risk of future injection-related seismicity. The numerical modelling study aimed at investigating the potential of major faults for reactivation during UGS operations. The geomechanical model was calibrated to match the location and timing of the fault slip on the main central fault, which has most likely caused past seismic events during gas production. Simulation results showed that the part of the central fault most sensitive to slip during reservoir depletion is located at partial juxtaposition of the two main reservoir blocks across the central fault, which is in agreement with the seismological localization of the recorded seismic events. UGS operations with annual cycles of gas injection and production will largely have stabilizing effects on fault stability. The potential for fault slip on the central fault will therefore be low throughout annual operational cycles of this storage facility. The second case study describes a field scale two-dimensional geomechanical modelling of an offshore depleted gas field in the Netherlands, which is being considered for CO2 storage. The geomechanical modelling study aimed at investigating the mechanical impact of induced stress changes, resulting from past gas extraction and future CO2 injection, on the reservoir rock, top- and side-seals as well as faults. The study focused in particular on the potential for induced hydro-fracturing of the reservoir rock and top seals and re-activation of existing faults. In contrast to the first case study of UGS where good calibration data were available, in this case calibration data were largely missing as the field has not experienced (felt) induced seismicity during production period and subsidence of the seabed was not measured. Numerical simulations of CO2 injection into compartmentalized reservoir structures showed that the side seal and boundary faults at the edges of reservoir compartments represent weak spots where production-induced mechanical damage and fault re-activation will first occur. Possible permeability enhancement resulting from local seal damage and fault slip can provide initial pathways for CO2 penetration into the seal enhancing fluid-rock chemical interactions.

Orlic, Bogdan; Wassing, Brecht

2013-04-01

143

Comparison of Gross Greenhouse Gas Fluxes from Hydroelectric Reservoirs in Brazil with Thermopower Generation  

NASA Astrophysics Data System (ADS)

Widespread interest in human impacts on the Earth has prompted much questioning in fields of concern to the general public. One of these issues is the extent of the impacts on the environment caused by hydro-based power generation, once viewed as a clean energy source. From the early 1990s onwards, papers and studies have been challenging this assumption through claims that hydroelectric dams also emit greenhouse gases, generated by the decomposition of biomass flooded by filling these reservoirs. Like as other freshwater bodies, hydroelectric reservoirs produce gases underwater by biology decomposition of organic matter. Some of these biogenic gases are effective in terms of Global Warming. The decomposition is mainly due by anaerobically regime, emitting methane (CH4), nitrogen (N2) and carbon dioxide (CO2). This paper compare results obtained from gross greenhouse fluxes in Brazilian hydropower reservoirs with thermo power plants using different types of fuels and technology. Measurements were carried in the Manso, Serra da Mesa, Corumbá, Itumbiara, Estreito, Furnas and Peixoto reservoirs, located in Cerrado biome and in Funil reservoir located at Atlantic forest biome with well defined climatologically regimes. Fluxes of carbon dioxide and methane in each of the reservoirs selected, whether through bubbles and/or diffusive exchange between water and atmosphere, were assessed by sampling. The intensity of emissions has a great variability and some environmental factors could be responsible for these variations. Factors that influence the emissions could be the water and air temperature, depth, wind velocity, sunlight, physical and chemical parameters of water, the composition of underwater biomass and the operational regime of the reservoir. Based in this calculations is possible to conclude that the large amount of hydro-power studied is better than thermopower source in terms of atmospheric greenhouse emissions. The comparisons between the reservoirs studied shown a large variation in the data on greenhouse gas emissions, which would suggest that more care, should be taken in the choice of future projects by the Brazilian electrical sector. The emission of CH4 by hydroelectric reservoirs is always unfavorable, since even if the carbon has originated with natural sources, it is part of a gas with higher GWP in the final calculation. Emissions of CO2 can be attributed in part to the natural carbon cycle between the atmosphere and the water of the reservoir. Another part could be attributed to the decomposition of organic material, caused by the hydroelectric dam.

Rogerio, J. P.; Dos Santos, M. A.; Matvienko, B.; dos Santos, E.; Rocha, C. H.; Sikar, E.; Junior, A. M.

2013-05-01

144

Criteria for displacement by gas versus water in oil reservoirs  

E-print Network

of Model for Base Case Gas Injection Runs. . Capillary Pressure Functions 3 Oil -Water Relative Permeability . 10 Gas-Oil Relative Permeability, Correlation of Oil Recovery with Dimensionless Rate and Time. 17 Comparison of Oil Recovery from Base... the Buckley-Leverett and Dietz displacement theories and found that the former more accu- rately described their thin tube exper1ments due to capillary ef- fects, a f1nd1ng which corfirmed conclusions reached by DietzT con- cerning his sharp interface...

Piper, Larry Dean

2012-06-07

145

Variation of galactic cold gas reservoirs with stellar mass  

NASA Astrophysics Data System (ADS)

The stellar and neutral hydrogen (H I) mass functions at z ˜ 0 are fundamental benchmarks for current models of galaxy evolution. A natural extension of these benchmarks is the two-dimensional distribution of galaxies in the plane spanned by stellar and H I mass, which provides a more stringent test of simulations, as it requires the H I to be located in galaxies of the correct stellar mass. Combining H I data from the Arecibo Legacy Fast ALFA survey, with optical data from Sloan Digital Sky Survey, we find a distinct envelope in the H I-to-stellar mass distribution, corresponding to an upper limit in the H I fraction that varies monotonically over five orders of magnitude in stellar mass. This upper envelope in H I fraction does not favour the existence of a significant population of dark galaxies with large amounts of gas but no corresponding stellar population. The envelope shows a break at a stellar mass of ˜109 M?, which is not reproduced by modern models of galaxy populations tracing both stellar and gas masses. The discrepancy between observations and models suggests a mass dependence in gas storage and consumption missing in current galaxy evolution prescriptions. The break coincides with the transition from galaxies with predominantly irregular morphology at low masses to regular discs at high masses, as well as the transition from cold to hot accretion of gas in simulations.

Maddox, Natasha; Hess, Kelley M.; Obreschkow, Danail; Jarvis, M. J.; Blyth, S.-L.

2015-02-01

146

Prediction of Gas Injection Performance for Heterogeneous Reservoirs  

SciTech Connect

This report was an integrated study of the physics and chemistry affecting gas injection, from the pore scale to the field scale, and involved theoretical analysis, laboratory experiments and numerical simulation. Specifically, advances were made on streamline-based simulation, analytical solutions to 1D compositional displacements, and modeling and experimental measures of three-phase flow.

Blunt, M.J.; Orr, F.M. Jr.

2001-03-26

147

Diagenesis and reservoir quality of Bhuban sandstones (Neogene), Titas Gas Field, Bengal Basin, Bangladesh  

NASA Astrophysics Data System (ADS)

This study deals with the diagenesis and reservoir quality of sandstones of the Bhuban Formation located at the Titas Gas Field of Bengal Basin. Petrographic study including XRD, CL, SEM and BSE image analysis and quantitative determination of reservoir properties were carried out for this study. The sandstones are fine to medium-grained, moderately well to well sorted subfeldspathic arenites with subordinate feldspathic and lithic arenites. The diagenetic processes include clay infiltration, compaction and cementation (quartz overgrowth, chlorite, kaolinite, calcite and minor amount of pyrite, dolomite and K-feldspar overgrowth). Quartz is the dominant pore occluding cement and generally occurred as small euhedral crystals, locally as large pyramidal crystals in the primary pores. Pressure solution derived from grain contact is the main contributor of quartz overgrowths. Chlorite occurs as pore-lining and pore filling cement. In some cases, chlorite helps to retain porosity by preventing quartz overgrowth. In some restricted depth interval, pore-occlusion by calcite cement is very much intense. Kaolinite locally developed as vermiform and accelerated the minor porosity loss due to pore-occlusion. Kaolinite/chlorite enhances ineffective microporosity. Kaolinite is a by-product of feldspar leaching in the presence of acidic fluid produced during the maturation of organic matter in the adjacent Miocene or deeper Oligocene source rocks. The relation between diagenesis and reservoir quality is as follows: the initial porosity was decreased by compaction and cementation and then increased by leaching of the metastable grains and dissolution of cement. Good quality reservoir rocks were deposited in fluvial environment and hence quality of reservoir rocks is also environment selective. Porosity and permeability data exhibit good inverse correlation with cement. However, some data points indicate multiple controls on permeability. Reservoir quality is thus controlled by pore occluding cement, textural parameters (grain size, pore size and sorting) and depositional environment. The reservoir finally resumed partly its pre-cementation quality after development of secondary porosity.

Aminul Islam, M.

2009-06-01

148

Tight gas reservoir simulation: Modeling discrete irregular strata-bound fracture network flow, including dynamic recharge from the matrix  

SciTech Connect

The US Department of Energy, Federal Energy Technology Center, has sponsored a project to simulate the behavior of tight, fractured, strata-bound gas reservoirs that arise from irregular discontinuous, or clustered networks of fractures. New FORTRAN codes have been developed to generate fracture networks, or simulate reservoir drainage/recharge, and to plot the fracture networks and reservoirs pressures. Ancillary codes assist with raw data analysis.

McKoy, M.L., Sams, W.N.

1997-10-01

149

Reservoir geometry and trapping mechanisms, Lindsey Slough Gas field, southern Sacramento basin  

SciTech Connect

Multiple reservoir units, numerous unconformities and stratigraphic pinch-outs, and extensive faulting make the Lindsey Slough field area (T5N, R2E, MDBM) geologically intriguing and economically attractive. The petroleum geology class of California State University, Northridge, undertook a group mapping project in November 1985, to delineate producing pools, determine reservoir geometries and trapping mechanisms, and identify potential exploration and development locations. More than 12 separate pools, producing from at least one of the 13 reservoir zones, are present. Reservoirs are of two main types: (1) extensive sheet sandstones deposited in delta-front and shelf(.) environments, and (2) lenticular channel sandstones deposited in submarine canyon, slope, and submarine fan environments. Among the sheet sandstones, the upper and lower Petersen members of the Upper Cretaceous Starkey formation are especially productive, with pay zones exceeding 100 ft. Both members pinch out to the southwest, along the paleoshelf edge. Of the lenticular sandstones, reservoir quality and thickness appear to be greatest in delta-mouth slope channels that fed sand basinward to submarine fans. Net pay in the K-1 and related upper Cretaceous channels exceeds 200 ft in some wells. Middle-fan channels of the Upper Cretaceous channels exceeds 200 ft in some wells. Middle-fan channels of the Upper Cretaceous Winters Fan are locally productive, and a small amount of gas has been produced from thin, poorly sorted sandstones within the Paleocene Martinez Submarine Canyon.

Cherven, V.; Fischer, P.; Frick, E.; Grunberg, A.; Ipswitch, S.; Menzie, R.; Pierotti, R.; Russell, P.; Schwartzbart, D.

1986-04-01

150

Diagenetic controlled reservoir quality of South Pars gas field, an integrated approach  

NASA Astrophysics Data System (ADS)

The Dalan-Kangan Permo-Triassic aged carbonates were deposited in the South Pars gas field in the Persian Gulf Basin, offshore Iran. Based on the thin section studies from this field, pore spaces are classified into three groups including depositional, fabric-selective and non-fabric selective. Stable isotope studies confirm the role of diagenesis in reservoir quality development. Integration of various data show that different diagenetic processes developed in two reservoir zones in the Kangan and Dalan formations. While dolomitisation enhanced reservoir properties in the upper K2 and lower K4 units, lower part of K2 and upper part of K4 have experienced more dissolution. Integration of RQI, porosity-permeability values and pore-throat sizes resulted from mercury intrusion tests shows detailed petrophysical behavior in reservoir zones. Though both upper K2 and lower K4 are dolomitised, in upper K2 unit non-fabric selective pores are dominant and fabric destructive dolomitisation is the main cause of high reservoir quality. In comparison, lower K4 has more fabric-selective pores that have been connected by fabric retentive to selective dolomitisation.

Tavakoli, Vahid; Rahimpour-Bonab, Hossain; Esrafili-Dizaji, Behrooz

2011-01-01

151

Simulation study to determine the feasibility of injecting hydrogen sulfide, carbon dioxide and nitrogen gas injection to improve gas and oil recovery oil-rim reservoir  

NASA Astrophysics Data System (ADS)

This study is combining two important and complicated processes; Enhanced Oil Recovery, EOR, from the oil rim and Enhanced Gas Recovery, EGR from the gas cap using nonhydrocarbon injection gases. EOR is proven technology that is continuously evolving to meet increased demand and oil production and desire to augment oil reserves. On the other hand, the rapid growth of the industrial and urban development has generated an unprecedented power demand, particularly during summer months. The required gas supplies to meet this demand are being stretched. To free up gas supply, alternative injectants to hydrocarbon gas are being reviewed to support reservoir pressure and maximize oil and gas recovery in oil rim reservoirs. In this study, a multi layered heterogeneous gas reservoir with an oil rim was selected to identify the most optimized development plan for maximum oil and gas recovery. The integrated reservoir characterization model and the pertinent transformed reservoir simulation history matched model were quality assured and quality checked. The development scheme is identified, in which the pattern and completion of the wells are optimized to best adapt to the heterogeneity of the reservoir. Lateral and maximum block contact holes will be investigated. The non-hydrocarbon gases considered for this study are hydrogen sulphide, carbon dioxide and nitrogen, utilized to investigate miscible and immiscible EOR processes. In November 2010, re-vaporization study, was completed successfully, the first in the UAE, with an ultimate objective is to examine the gas and condensate production in gas reservoir using non hydrocarbon gases. Field development options and proces schemes as well as reservoir management and long term business plans including phases of implementation will be identified and assured. The development option that maximizes the ultimate recovery factor will be evaluated and selected. The study achieved satisfactory results in integrating gas and oil reservoir management methodology to maximize both fluid recovery and free up currently injected HC gases for domestic consumption. Moreover, this study identified the main uncertainty parameters impacting the gas and oil production performance with all proposed alternatives. Maximizing both fluids oil and gas in oil rim reservoir are challenging. The reservoir heterogeneity will have a major impact on the performance of non hydrocarbon gas flooding. Therefore, good reservoir description is a key to achieve acceptable development process and make reliable prediction. The lab study data were used successfully to as a tool to identify the range of uncertainty parameters that are impacting the hydrocarbon recovery.

Eid, Mohamed El Gohary

152

Joule-Thomson Cooling Due to CO2 Injection into Natural GasReservoirs  

SciTech Connect

Depleted natural gas reservoirs are a promising target for Carbon Sequestration with Enhanced Gas Recovery (CSEGR). The focus of this study is on evaluating the importance of Joule-Thomson cooling during CO2 injection into depleted natural gas reservoirs. Joule-Thomson cooling is the adiabatic cooling that accompanies the expansion of a real gas. If Joule-Thomson cooling were extreme, injectivity and formation permeability could be altered by the freezing of residual water,formation of hydrates, and fracturing due to thermal stresses. The TOUGH2/EOS7C module for CO2-CH4-H2O mixtures is used as the simulation analysis tool. For verification of EOS7C, the classic Joule-Thomson expansion experiment is modeled for pure CO2 resulting in Joule-Thomson coefficients in agreement with standard references to within 5-7 percent. For demonstration purposes, CO2 injection at constant pressure and with a large pressure drop ({approx}50 bars) is presented in order to show that cooling by more than 20 C can occur by this effect. Two more-realistic constant-rate injection cases show that for typical systems in the Sacramento Valley, California, the Joule-Thomson cooling effect is minimal. This simulation study shows that for constant-rate injections into high-permeability reservoirs, the Joule-Thomson cooling effect is not expected to create significant problems for CSEGR.

Oldenburg, Curtis M.

2006-04-21

153

Potential hazards of compressed air energy storage in depleted natural gas reservoirs.  

SciTech Connect

This report is a preliminary assessment of the ignition and explosion potential in a depleted hydrocarbon reservoir from air cycling associated with compressed air energy storage (CAES) in geologic media. The study identifies issues associated with this phenomenon as well as possible mitigating measures that should be considered. Compressed air energy storage (CAES) in geologic media has been proposed to help supplement renewable energy sources (e.g., wind and solar) by providing a means to store energy when excess energy is available, and to provide an energy source during non-productive or low productivity renewable energy time periods. Presently, salt caverns represent the only proven underground storage used for CAES. Depleted natural gas reservoirs represent another potential underground storage vessel for CAES because they have demonstrated their container function and may have the requisite porosity and permeability; however reservoirs have yet to be demonstrated as a functional/operational storage media for compressed air. Specifically, air introduced into a depleted natural gas reservoir presents a situation where an ignition and explosion potential may exist. This report presents the results of an initial study identifying issues associated with this phenomena as well as possible mitigating measures that should be considered.

Cooper, Paul W.; Grubelich, Mark Charles; Bauer, Stephen J.

2011-09-01

154

Merging basic science and applied reservoir characterization research: An effective approach for assisting industry in field optimization for incremental recovery of oil and gas  

Microsoft Academic Search

Using a dual approach of basic research and applied field-optimization studies, Bureau geoscientists are helping industry maximize the recovery of oil and gas in stratigraphically complex reservoirs. Basic research on reservoir architecture is supported by two industrial associates programs that are evaluating siliciclastic reservoirs (Characterization of Heterogeneity Style and Permeability Structure in a Sequence Stratigraphic Framework in Fluvial-Deltaic Reservoirs) and

R. A. Levey; T. Noel; S. P. Dutton

1995-01-01

155

A modeling framework for CO2-storage in depleted gas reservoirs  

NASA Astrophysics Data System (ADS)

This work performs a complete framework of numerical simulation of CO2-Injection into depleted gas reservoirs against the background of enhanced gas recovery and CO2-Storage. This framework ranges from model development to site-specific scenario simulations and result interpretation. Numerical simulations of gas related applications such as CO2 sequestration, geothermal energy production, or natural gas storage have to consider non-isothermal effects caused by gas compression or expansion. This mathematical approach results in a system of coupled non-linear PDEs, which have been implemented into the open-source software platform OpenGeoSys. For model verification purposes, a number of well-known benchmark tests and analytical solutions of simplified or adapted conditions has been utilized to prove the validity of the developed simulation tool. Fluid material parameters are obtained by applying highly accurate and state-of-the-art property correlations. However, the accuracy of these correlations is strongly depending on the precision of the chosen equation of state, which provides a relation between the system state variables pressure, temperature, and composition. To guarantee a high level of accuracy, four commonly used equations of state (EOS) have been chosen from literature and have been evaluated by comparison using a large number of measurement datasets. Complex EOS reach a much better precision than simple ones, but lead to expansive computing times. Therefore, comparative simulations have been performed to investigate the effects of EOS differences on numerical simulation results. The comparison shows, that little differences in the density determination may lead to significant discrepancies in simulation results. Applying a compromise among precision and computational effort, a cubic EOS has been chosen to simulate the continuous injection of carbon dioxide into a depleted natural gas reservoir. This simulation allows to investigate physical phenomena which appear during injection and to predict the evolution of reservoir pressures and temperatures. Investigating multiple scenarios, this model helps to find the best injection strategy for enhanced gas recovery applications.

Böttcher, N.; Taron, J.; Park, C.; Singh, A. K.; Görke, U.; Liedl, R.; Kolditz, O.

2012-12-01

156

FMS/FMI borehole imaging of carbonate gas reservoirs, Central Luconia Province, offshore Sarawak, Malaysia  

SciTech Connect

The Central Luconia Province, offshore Sarawak, is a significant gas province characterized by extensive development of late Miocene carbonate buildups. Some 200 carbonate structures have been seismically mapped of which 70 have been drilled. FMS/FMI borehole images were obtained from three appraisal wells drilled in the [open quotes]M[close quotes] cluster gas fields situated in the northwestern part of the province. The [open quotes]M[close quotes] cluster fields are currently part of an upstream gas development project to supply liquefied natural gas. Log facies recognition within these carbonate gas reservoirs is problematic due mainly to the large gas effect. This problem is being addressed by (1) application of neural network techniques and (2) using borehole imaging tools. Cores obtained from the M1, M3, and M4 gas fields were calibrated with the FMS/FMI images. Reservoir characterization was obtained at two different scales. The larger scale (i.e., 1:40 and 1:200) involved static normalized images where the vertical stacking pattern was observed based on recognition of bed boundaries. In addition, the greater vertical resolution of the FMS/FMI images allowed recognition of thin beds. For recognition of specific lithofacies, dynamically normalized images were used to highlight lithofacies-specific sedimentary features, e.g., clay seams/stylolites, vugs, and breccia zones. In general, the FMS/FMI images allowed (1) easier recognition of reservoir features, e.g., bed boundaries, and (2) distinction between lithofacies that are difficult to characterize on conventional wireline logs.

Singh, U.; Van der Baan, D. (Sarawak Shell Berhad (Malaysia))

1994-07-01

157

The noble gas geochemistry of natural CO 2 gas reservoirs from the Colorado Plateau and Rocky Mountain provinces, USA  

NASA Astrophysics Data System (ADS)

Identification of the source of CO 2 in natural reservoirs and development of physical models to account for the migration and interaction of this CO 2 with the groundwater is essential for developing a quantitative understanding of the long term storage potential of CO 2 in the subsurface. We present the results of 57 noble gas determinations in CO 2 rich fields (>82%) from three natural reservoirs to the east of the Colorado Plateau uplift province, USA (Bravo Dome, NM., Sheep Mountain, CO. and McCallum Dome, CO.), and from two reservoirs from within the uplift area (St. John's Dome, AZ., and McElmo Dome, CO.). We demonstrate that all fields have CO 2/ 3He ratios consistent with a dominantly magmatic source. The most recent volcanics in the province date from 8 to 10 ka and are associated with the Bravo Dome field. The oldest magmatic activity dates from 42 to 70 Ma and is associated with the McElmo Dome field, located in the tectonically stable centre of the Colorado Plateau: CO 2 can be stored within the subsurface on a millennia timescale. The manner and extent of contact of the CO 2 phase with the groundwater system is a critical parameter in using these systems as natural analogues for geological storage of anthropogenic CO 2. We show that coherent fractionation of groundwater 20Ne/ 36Ar with crustal radiogenic noble gases ( 4He, 21Ne, 40Ar) is explained by a two stage re-dissolution model: Stage 1: Magmatic CO 2 injection into the groundwater system strips dissolved air-derived noble gases (ASW) and accumulated crustal/radiogenic noble gas by CO 2/water phase partitioning. The CO 2 containing the groundwater stripped gases provides the first reservoir fluid charge. Subsequent charges of CO 2 provide no more ASW or crustal noble gases, and serve only to dilute the original ASW and crustal noble gas rich CO 2. Reservoir scale preservation of concentration gradients in ASW-derived noble gases thus provide CO 2 filling direction. This is seen in the Bravo Dome and St. John's Dome fields. Stage 2: The noble gases re-dissolve into any available gas stripped groundwater. This is modeled as a Rayleigh distillation process and enables us to quantify for each sample: (1) the volume of groundwater originally 'stripped' on reservoir filling; and (2) the volume of groundwater involved in subsequent interaction. The original water volume that is gas stripped varies from as low as 0.0005 cm 3 groundwater/cm 3 gas (STP) in one Bravo Dome sample, to 2.56 cm 3 groundwater/cm 3 gas (STP) in a St. John's Dome sample. Subsequent gas/groundwater equilibration varies within all fields, each showing a similar range, from zero to ˜100 cm 3 water/cm 3 gas (at reservoir pressure and temperature).

Gilfillan, Stuart M. V.; Ballentine, Chris J.; Holland, Greg; Blagburn, Dave; Lollar, Barbara Sherwood; Stevens, Scott; Schoell, Martin; Cassidy, Martin

2008-02-01

158

Recovery of oil from fractured reservoirs by gas displacement  

E-print Network

po oy D 0 (18) gas equation: A ds + C ds +B ds +E ds i F ds sg OX sg ox sg 0 sg oy sg oy +AP+CP+BP+EP+FP pg ox pg ox pg o pg oy pg oy D g These equations are solved simultaneously for oil saturation change and oil pressure using a modified... 18 19 20 21 Effect of Fracture Capillary Pressure on GOR vs N for C =10 p R Effect of Fracture Capillary Pressure on GOR vs N for C =1 P GOR vs N for C =. I p R GOR vs N for C =I P R GOR vs N for C =10 P Oil Saturation Distribution...

Unneberg, Arild

2012-06-07

159

A method for evaluating a gas reservoir using a digital computer  

E-print Network

RESERVOIR USING A DIGITAL COMPUTER A THESIS By FORREST ALLAN GARB Approv as to style and conten by: (Chairman of Committee) May, 1963 TABLE OF CONTENTS Page 1. INTRODUCTION 2. DEVELOPMENT OF PROGRAM 3. DISCUSSION OF RESULTS 4. PROGRAM OPERATIONS... . 16 19 5. CONC LUSIONS 6. REFERENCES 22 7. AC KNOW LEDGE MENTS 23 8. APPENDIX 24 LIST OF TABLES Table Page Static Bottom Hole Pressures Calculated from Closed- In Wellhead Pressure A- I 2 -10 Predicted Performance for Sample Gas Field...

Garb, Forrest Allan

2012-06-07

160

Insights and contributions from the Multiwell Experiment: A field laboratory in tight gas sandstone reservoirs  

Microsoft Academic Search

The U.S. Department of Energy's Multiwell Experiment (MWX) has led to insights and contributions into the technology for natural gas production from low permeability sandstones reservoirs in the western United States. Three wells, between 110 and 215 ft (34-66 m) apart at depth, have been drilled in the piceance Basin of Colorado, where the cretaceous-age Mesaverde, the formation of interest,

D. A. Northrop; K. H. Frohne

1988-01-01

161

Depositional environment and reservoir morphology of the Upper Wilcox sandstones, Katy gas field, Waller County, Texas  

E-print Network

of the requirements for the degree of MASTER OF SCIENCE August 1979 Major Subject: Geology DEPOSITIONAL ENVIRONMENT AND RESERVOIR MORPHOLOGY OF THE UPPER WILCOX SANDSTONES, KATY GAS FIELD WALLER COUNTY, TEXAS A Thesis by GILBERT JOHN DePAUL Approved... is predominantly shale, a Middle Massive Wilcox, equivalent to the Rockdale delta system, and Upper Wilcox sandstone and shale. The Wilcox fault zone lies about 30 miles downdip from the Sabinian shoreline in East Texas (Fisher and McGowan, 1969). Katy field...

DePaul, Gilbert John

2012-06-07

162

The production characteristics of a solution gas-drive reservoir as measured on a centrifugal model  

E-print Network

LIBRARY A 8I M COLLEGE OF TEXAS THE PRODUCTION CHARACTERISTICS OF A SOLUTION GAS-DRIVE RESERVOIR AS MEASURED ON A CENTRIFUGAL MIODEL A Thesis Robert J. Goodwin Submitted to the Graduate School of the Agricultural and Mechanical College... by Robert J. Goodwin Approved as to style and content by: Chairman of Co ttee Head of Department TABLE OF CONTENTS 1. ABSTRACT 2. INTRODUCTION 3. EQUIPMENT AND MATERIALS 4, PROCEDURE RESULTS AND DISCUSSION 6. CONCLUSIONS 7. ACKNOWLEDGEMENTS 8...

Goodwin, Robert Jennings

2012-06-07

163

E ect of the reservoir size on gas adsorption in inhomogeneous porous media E. Kierlik, 1 J. Puibasset, 2 and G. Tarjus 1  

E-print Network

E#11;ect of the reservoir size on gas adsorption in inhomogeneous porous media E. Kierlik, 1 J of the reservoir on the adsorption isotherms of a uid in disordered or inhomogeneous mesoporous solids. We, the uid inside the porous solid exchanges matter with a reservoir of gas that is at the same temperature

Recanati, Catherine

164

Hydrocarbon transfer pathways from Smackover source rocks to younger reservoir traps in the Monroe gas field, NE Louisiana  

SciTech Connect

The Monroe gas field contained more than 7 tcf of gas in its virgin state. Much of the original gas reserves have been produced through wells penetrating the Upper Cretaceous Monroe Gas Rock Formation reservoir. Other secondary reservoirs in the field area are Eocene Wilcox, the Upper Cretaceous Arkadelphia, Nacatoch, Ozan, Lower Cretaceous, Hosston, Jurassic Schuler, and Smackover. As producing zones, these secondary producing zones reservoirs have contributed an insignificant amount gas to the field. The source of much of this gas appears to have been in the lower part of the Jurassic Smackover Formation. Maturation and migration of the hydrocarbons from a Smackover source into Upper Cretaceous traps was enhanced and helped by igneous activity, and wrench faults/unconformity conduits, respectively. are present in the pre-Paleocene section. Hydrocarbon transfer pathways appear to be more vertically direct in the Jurassic and Lower Cretaceous section than the complex pattern present in the Upper Cretaceous section.

Zimmerman, R.K. (Louisiana State Univ., Baton Rouge, LA (United States))

1993-09-01

165

Tritium Transport at the Rulison Site, a Nuclear-stimulated Low-permeability Natural Gas Reservoir  

SciTech Connect

The U.S. Department of Energy (DOE) and its predecessor agencies conducted a program in the 1960s and 1970s that evaluated technology for the nuclear stimulation of low-permeability natural gas reservoirs. The second project in the program, Project Rulison, was located in west-central Colorado. A 40-kiltoton nuclear device was detonated 2,568 m below the land surface in the Williams Fork Formation on September 10, 1969. The natural gas reservoirs in the Williams Fork Formation occur in low permeability, fractured sandstone lenses interbedded with shale. Radionuclides derived from residual fuel products, nuclear reactions, and activation products were generated as a result of the detonation. Most of the radionuclides are contained in a cooled, solidified melt glass phase created from vaporized and melted rock that re-condensed after the test. Of the mobile gas-phase radionuclides released, tritium ({sup 3}H or T) migration is of most concern. The other gas-phase radionuclides ({sup 85}Kr, {sup 14}C) were largely removed during production testing in 1969 and 1970 and are no longer present in appreciable amounts. Substantial tritium remained because it is part of the water molecule, which is present in both the gas and liquid (aqueous) phases. The objectives of this work are to calculate the nature and extent of tritium contamination in the subsurface from the Rulison test from the time of the test to present day (2007), and to evaluate tritium migration under natural-gas production conditions to a hypothetical gas production well in the most vulnerable location outside the DOE drilling restriction. The natural-gas production scenario involves a hypothetical production well located 258 m horizontally away from the detonation point, outside the edge of the current drilling exclusion area. The production interval in the hypothetical well is at the same elevation as the nuclear chimney created by the detonation, in order to evaluate the location most vulnerable to tritium migration.

C. Cooper; M. Ye; J. Chapman

2008-04-01

166

Factors Influencing Greenhouse Gas Emissions from Three Gorges Reservoir of China  

NASA Astrophysics Data System (ADS)

Three gorges reservoir (TGR) of China located in a subtropical climate region. It has attracted tremendous attentions on greenhouse gas (GHG) emissions from TGR, including carbon dioxide (CO2), methane (CH4) and nitrous Oxide (N2O). Results on monthly fluxes and their spatial and seasonal variations have been determined by a static chamber method and have published elsewhere recently. Here we made further discussions on the factors influencing GHG emissions from TGR. We conclude that the hydrodynamic situation was the key parameter controlling the fluxes. TGR was a typical valley-type reservoir and with a complex terrain in the surrounding catchment, where almost 94% of the region was occupied by mountainous, this situation made the reservoir had sufficient allochthonous organic carbon input origin from eroded soil. But no significant relationship between organic carbon (both dissolved and particulate form) and GHG fluxes, we thought that TGR was not a carbon-limited reservoir on the GHG issue. In the mainstream of the reservoir, dissolved CO2 and CH4 were supersaturation in the water, the relative high flow together with the narrow-deep channel result in great disturbance, which would promote more dissolved gas escape into the atmosphere. This could also approved by the differences in CO2 and CH4 fluxes in different reach from up to downstream of the reservoir. In the reservoir tail water, the mainstream remained the high flow rate, both CO2 and CH4 fluxes is relative high, while downwards, the fluxes were gradually dropped, as after the impoundment of the reservoir, flow rate have greatly decreased. Another evidence was the relative higher CO2 and CH4 fluxes in the rainy season. As the rainy season approaches, TGR would empty the storage to prepare for retention and mitigation. The interplay between water inflows and outflows produced marked variations in the water residence times. During the rainy season times, this could be as short as 6 days with higher water flow rate which would also cause higher disturbance, while for other periods of a year, the reservoir would act more like a lake and residence times could exceed 30 days. Meanwhile the manipulate of the reservoir made the water column not only well mixed top to bottom for most of the year, but also the complete water column has high dissolved oxygen concentrations (> 6 mg/L). Only in April and May is there substantial temperature stratification in mainstream and tributaries. The high dissolved oxygen concentrations even in the deepest parts of the TGR storage minimize the scope for sediment anoxia and less GHG was produced, especially for CH4. In the tributaries, the totally different hydrodynamic situation made these regions a different GHG emission dynamics. After the impoundment, water velocity had greatly decreased, these regions showed more Limnology characteristics compared to the mainstream. This made the tributaries prone to algal blooms which would great affect the surface GHG fluxes, especially for CO2, which would consume the dissolved CO2 in water and cause the intake of atmospheric CO2.

Zhao, Y.; Zhao, X.; Wu, B.; Zeng, Y.

2013-05-01

167

Paving the road for hydraulic fracturing in Paleozoic tight gas reservoirs in Abu Dhabi  

NASA Astrophysics Data System (ADS)

This study contributes to the ongoing efforts of Abu Dhabi National Oil Company (ADNOC) to improve gas production and supply in view of increasing demand and diminishing conventional gas reservoirs in the region. The conditions of most gas reservoirs with potentially economical volumes of gas in Abu Dhabi are tight abrasive deep sand reservoirs at high temperature and pressures. Thus it inevitably tests the limit of both conventional thinking and technology. Accurate prediction of well performance is a major challenge that arises during planning phase. The primary aim is to determine technical feasibility for the implementation of the hydraulic fracture technology in a new area. The ultimate goal is to make economical production curves possible and pave the road to tap new resource of clean hydrocarbon energy source. The formation targeted in this study is characterized by quartzitic sandstone layers and variably colored shale and siltstones with thin layers of anhydrites. It dates back from late Permian to Carboniferous age. It forms rocks at the lower reservoir permeability ranging from 0.2 to less than 1 millidarcy (mD). When fractured, the expected well flow in Abu Dhabi offshore deep gas wells will be close to similar tight gas reservoir in the region. In other words, gas production can be described as transient initially with high rates and rapidly declining towards a pseudo-steady sustainable flow. The study results estimated fracturing gradient range from 0.85 psi/ft to 0.91 psi/ft. In other words, the technology can be implemented successfully to the expected rating without highly weighted brine. Hence, it would be a remarkable step to conduct the first hydraulic fracturing successfully in Abu Dhabi which can pave the road to tapping on a clean energy resource. The models predicted a remarkable conductivity enhancement and an increase of production between 3 to 4 times after fracturing. Moreover, a sustainable rate above 25 MMSCFD between 6 to 10 years is predicted based on a single well model. The forecasts also show that most of the contribution will come from one zone and therefore optimized operational cost can be achieved in future. Once pressures during a diagnostic injection test are known prior to the main hydraulic fracturing treatment, precise calibration will enable accurate design of fracture geometry and containment for full field development. The feasibility of hydraulic fracture is based on available offset well data. The biggest two challenges in Abu-Dhabi at this stage are high depths and high temperatures as well as offshore conditions. For this reason, a higher well pressure envelop and fracturing string installation is envisaged as a necessity in a future well where unknown tectonic stress could result in higher fracturing load. Finally the study recommends drilling a candidate well designed for the implementation of hydraulic fracturing. This well should consider required pressure rating for the fracturing string. Thermal design considerations will also play a role during production due to high temperature. A dipole or multi pole sonic log from the same well is essential to confirm in situ stresses. The planned well will be in the crest at close proximity to studied offset wells to minimize uncertainty where tested wells produced dry gas and to avoid drilling to watered zones down the flank of the reservoir.

Alzarouni, Asim

168

Numerical Modeling of Fractured Shale-Gas and Tight-Gas Reservoirs Using Unstructured Grids  

E-print Network

reservoirs. These simulations utilized up to a half-million grid-blocks and consider a period of up to 3,000 years in some cases. The aim is to provide very high-definition reference numerical solutions that will exhibit virtually all flow regimes we can...

Olorode, Olufemi Morounfopefoluwa

2012-02-14

169

Drilling and production statistics for major US coalbed methane and gas shale reservoirs. Topical report, June-August 1995  

SciTech Connect

The objective of this work is to provide GRI with a review and analysis of the oil and gas industry`s activity level and associated production from the major coalbed methane and gas shale reservoirs in the U.S. The authors specifically focused on the pre- and post-Section 29 qualifying deadline of December 1992 for unconventional gas Tax Credits. The primary plays investigated include the coalbed methane reservoirs in the San Juan, Warrier, Appalachian, Uinta, Powder River, and Pieceance basins and the gas shale plays in the Michigan, Fort Worth, Appalachian, Denver, and Illinois basins. A projection for future activity and production levels is made based on historic trends for each of the reservoir types. Telephone surveys were conducted with numerous operators to determine current activity status and to assist in projecting future activity of the two gas resources.

Kelso, B.S.; Lombardi, T.E.; Kuuskraa, J.A.

1995-12-01

170

Naturally fractured tight gas reservoir detection optimization. Quarterly report, July--September 1994  

SciTech Connect

This report details the field work undertaken by Coleman Energy and Environmental Systems--Blackhawk Geosciences Division (CEES-BGD) and Lynn, Inc. during the summer of 1994 at a gas field in the Wind River Basin in central Wyoming. The field work described herein consisted of two parts: multicomponent feasibility studies during the 3D P-wave survey on the site, and 9C VSP in a well at the site. The objectives of both surveys were to characterize the nature of anisotropy in the reservoir. With the 9C VSP, established practices were used to achieve this objective in the immediate vicinity of the well. With the multicomponent studies, tests were conducted to establish the feasibility of surface recording of the anisotropic reservoir rocks.

NONE

1994-11-01

171

Reservoir Characterization using geostatistical and numerical modeling in GIS with noble gas geochemistry  

NASA Astrophysics Data System (ADS)

The integration of precise geochemical analyses with quantitative engineering modeling into an interactive GIS system allows for a sophisticated and efficient method of reservoir engineering and characterization. Geographic Information Systems (GIS) is utilized as an advanced technique for oil field reservoir analysis by combining field engineering and geological/geochemical spatial datasets with the available systematic modeling and mapping methods to integrate the information into a spatially correlated first-hand approach in defining surface and subsurface characteristics. Three key methods of analysis include: 1) Geostatistical modeling to create a static and volumetric 3-dimensional representation of the geological body, 2) Numerical modeling to develop a dynamic and interactive 2-dimensional model of fluid flow across the reservoir and 3) Noble gas geochemistry to further define the physical conditions, components and history of the geologic system. Results thus far include using engineering algorithms for interpolating electrical well log properties across the field (spontaneous potential, resistivity) yielding a highly accurate and high-resolution 3D model of rock properties. Results so far also include using numerical finite difference methods (crank-nicholson) to solve for equations describing the distribution of pressure across field yielding a 2D simulation model of fluid flow across reservoir. Ongoing noble gas geochemistry results will also include determination of the source, thermal maturity and the extent/style of fluid migration (connectivity, continuity and directionality). Future work will include developing an inverse engineering algorithm to model for permeability, porosity and water saturation.This combination of new and efficient technological and analytical capabilities is geared to provide a better understanding of the field geology and hydrocarbon dynamics system with applications to determine the presence of hydrocarbon pay zones (or other reserves) and improve oil field management (e.g. perforating, drilling, EOR and reserves estimation)

Vasquez, D. A.; Swift, J. N.; Tan, S.; Darrah, T. H.

2013-12-01

172

Characteristics and genesis of the Feixianguan Formation oolitic shoal reservoir, Puguang gas field, Sichuan Basin, China  

NASA Astrophysics Data System (ADS)

The Lower Triassic Feixianguan Formation at the well-known Puguang gasfield in the northeastern Sichuan Basin of southwest China produces a representative oolitic reservoir, which has been the biggest marine-sourced gasfield so far in China (discovered in 2003 with proven gas reserves greater than 350×108 m3). This study combines core, thin section, and scanning electron microscopy observations, and geochemical analysis (C, O, and Sr isotopes) in order to investigate the basic characteristics and formation mechanisms of the reservoir. Observations indicate that platform margin oolitic dolomites are the most important reservoir rocks. Porosity is dominated by intergranular and intragranular solution, and moldic pore. The dolomites are characterized by medium porosity and permeability, averaging at approximately 9% and 29.7 mD, respectively. 87Sr/86Sr (0.707536-0.707934) and ?13CPDB (1.8‰-3.5‰) isotopic values indicate that the dolomitization fluid is predominantly concentrated seawater by evaporation, and the main mechanism for the oolitic dolomite formation is seepage reflux at an early stage of eodiagenesis. Both sedimentation and diagenesis (e.g., dolomitization and dissolution) have led to the formation of high-quality rocks to different degrees. Dolomite formation may have little contribution, karst may have had both positive and negative influences, and burial dissolution-TSR (thermochemical sulfate reduction) may not impact widely. The preservation of primary intergranular pores and dissolution by meteoric or mixed waters at the early stage of eogenesis are the main influences. This study may assist oil and gas exploration activities in the Puguang area and in other areas with dolomitic reservoirs.

Chen, Peiyuan; Tan, Xiucheng; Yang, Huiting; Tang, Ming; Jiang, Yiwei; Jin, Xiuju; Yu, Yang

2014-06-01

173

Integration of water and gas chemistry in an unconventional Devonian black shale gas reservoir: Microbial vs. thermogenic origin  

SciTech Connect

The upper Devonian Antrim Shale is a self-sourced, fractured gas reservoir that has been the target of intensive exploitation around the margin of the Michigan Basin. Significant amounts of water are commonly produced with methane in regions adjacent to subcrop of the Antrim Shale. Chemical and isotopic properties measured in the formation waters show significant regional variations and probably delineate zones of increased flow controlled by the fracture network within the Antrim Shale. The isotopic composition of Antrim methane ({gamma}{sup 13}C = -49 to -59{per_thousand}) was used to suggest that the gas is of thermtogenic origin. However, the highly {sup 13}C-enriched carbon of co-produced CO{sub 2} gas ({gamma}{sup 13}C {approx} +22{per_thousand}) and DIC in associated Antrim brines ({gamma}{sup 13}C = +19 to +31{per_thousand}) are consistent with bacterially mediated fractionation. Deuterium values in the methane ({gamma}D = -200 to -260{per_thousand}) also support a bacterial origin for methane. Preliminary correlation of deuterium in methane with that of the Antrim waters implies that methane is being generated via CO{sub 2} reduction within the reservoir.

Martini, A.M.; Budai, J.M.; Walter, L.M. [Univ. of Michigan, Ann Arbor, MI (United States)] [and others

1995-12-31

174

Gas hydrate saturations estimated from fractured reservoir at Site NGHP-01-10, Krishna-Godavari Basin, India  

USGS Publications Warehouse

During the Indian National Gas Hydrate Program Expedition 01 (NGHP-Ol), one of the richest marine gas hydrate accumulations was discovered at Site NGHP-01-10 in the Krishna-Godavari Basin. The occurrence of concentrated gas hydrate at this site is primarily controlled by the presence of fractures. Assuming the resistivity of gas hydratebearing sediments is isotropic, th?? conventional Archie analysis using the logging while drilling resistivity log yields gas hydrate saturations greater than 50% (as high as ???80%) of the pore space for the depth interval between ???25 and ???160 m below seafloor. On the other hand, gas hydrate saturations estimated from pressure cores from nearby wells were less than ???26% of the pore space. Although intrasite variability may contribute to the difference, the primary cause of the saturation difference is attributed to the anisotropic nature of the reservoir due to gas hydrate in high-angle fractures. Archie's law can be used to estimate gas hydrate saturations in anisotropic reservoir, with additional information such as elastic velocities to constrain Archie cementation parameters m and the saturation exponent n. Theory indicates that m and n depend on the direction of the measurement relative to fracture orientation, as well as depending on gas hydrate saturation. By using higher values of m and n in the resistivity analysis for fractured reservoirs, the difference between saturation estimates is significantly reduced, although a sizable difference remains. To better understand the nature of fractured reservoirs, wireline P and S wave velocities were also incorporated into the analysis.

Lee, M.W.; Collett, T.S.

2009-01-01

175

Western Greece unconventional hydrocarbon potential from oil shale and shale gas reservoirs  

NASA Astrophysics Data System (ADS)

It is clear that we are gradually running out of new sedimentary basins to explore for conventional oil and gas and that the reserves of conventional oil, which can be produced cheaply, are limited. This is the reason why several major oil companies invest in what are often called unconventional hydrocarbons: mainly oil shales, heavy oil, tar sand and shale gas. In western Greece exist important oil and gas shale reservoirs which must be added to its hydrocarbon potential1,2. Regarding oil shales, Western Greece presents significant underground immature, or close to the early maturation stage, source rocks with black shale composition. These source rock oils may be produced by applying an in-situ conversion process (ICP). A modern technology, yet unproven at a commercial scale, is the thermally conductive in-situ conversion technology, developed by Shell3. Since most of western Greece source rocks are black shales with high organic content, those, which are immature or close to the maturity limit have sufficient thickness and are located below 1500 meters depth, may be converted artificially by in situ pyrolysis. In western Greece, there are several extensive areas with these characteristics, which may be subject of exploitation in the future2. Shale gas reservoirs in Western Greece are quite possibly present in all areas where shales occur below the ground-water level, with significant extent and organic matter content greater than 1%, and during their geological history, were found under conditions corresponding to the gas window (generally at depths over 5,000 to 6,000m). Western Greece contains argillaceous source rocks, found within the gas window, from which shale gas may be produced and consequently these rocks represent exploitable shale gas reservoirs. Considering the inevitable increase in crude oil prices, it is expected that at some point soon Western Greece shales will most probably be targeted. Exploration for conventional petroleum reservoirs, through the interpretation of seismic profiles and the surface geological data, will simultaneously provide the subsurface geometry of the unconventional reservoirs. Their exploitation should follow that of conventional hydrocarbons, in order to benefit from the anticipated technological advances, eliminating environmental repercussions. As a realistic approach, the environmental consequences of the oil shale and shale gas exploitation to the natural environment of western Greece, which holds other very significant natural resources, should be delved into as early as possible. References 1Karakitsios V. & Rigakis N. 2007. Evolution and Petroleum Potential of Western Greece. J.Petroleum Geology, v. 30, no. 3, p. 197-218. 2Karakitsios V. 2013. Western Greece and Ionian Sea petroleum systems. AAPG Bulletin, in press. 3Bartis J.T., Latourrette T., Dixon L., Peterson D.J., Cecchine G. 2005. Oil Shale Development in the United States: Prospect and Policy Issues. Prepared for the National Energy Tech. Lab. of the U.S. Dept Energy. RAND Corporation, 65 p.

Karakitsios, Vasileios; Agiadi, Konstantina

2013-04-01

176

Gas reservoirs in Stuart City trend along lower Cretaceous shelf margin in south Texas  

SciTech Connect

A complex of reefs, banks, tidal bars, channel fills, and stabilized grainflats accumulated along the Lower Cretaceous shelf margin in S. Texas. The wide range of energy levels along this shelf-margin complex resulted in deposition of numerous facies, some with initial porosities as great as 30 to 40%. Subsequent marine cementation, meteoric phreatic diagenesis, and deep subsurface cementation have generally filled pore spaces and blocked permeability within the limestone. Only 4 facies commonly have greater than 5% porosity and 5 md permeability--the algae encrusted miliolid-coral- caprinid packstone, mollusk grainstone, rudist grainstone, and coral-stromatoporoid boundstone. Stuart City gas fields are facies-controlled stratigraphic traps. Gas is present within common intraparticle and moldic porosities, which are best preserved in the 4 depositional facies listed above. Fractures provide the effective gas collecting network in the Stuart City reservoirs. 11 referernces.

Schatzinger, R.A.; Bebout, D.G.; Loucks, R.G.; Reid, A.M. III

1980-01-01

177

HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS  

SciTech Connect

This report outlines progress in the second quarter of the second year of the DOE project ''High Resolution Prediction of Gas Injection Process Performance for Heterogeneous Reservoirs''. A three-dimensional streamline simulator, developed at Stanford University, has been modified in order to use analytical one-dimensional dispersion-free solutions to multicomponent gas injection processes. The use of analytical one-dimensional solutions in combination with streamline simulation is demonstrated to speedup compositional simulations of miscible gas injection processes by orders of magnitude compared to a conventional finite difference simulator. Two-dimensional and three-dimensional examples are reported to demonstrate the potential of this technology. Finally, the assumptions of the approach and possible extensions to include the effects of gravity are discussed.

Franklin M. Orr, Jr.

2002-03-31

178

Simulating the gas hydrate production test at Mallik using the pilot scale pressure reservoir LARS  

NASA Astrophysics Data System (ADS)

LARS, the LArge Reservoir Simulator, allows for one of the few pilot scale simulations of gas hydrate formation and dissociation under controlled conditions with a high resolution sensor network to enable the detection of spatial variations. It was designed and built within the German project SUGAR (submarine gas hydrate reservoirs) for sediment samples with a diameter of 0.45 m and a length of 1.3 m. During the project, LARS already served for a number of experiments simulating the production of gas from hydrate-bearing sediments using thermal stimulation and/or depressurization. The latest test simulated the methane production test from gas hydrate-bearing sediments at the Mallik test site, Canada, in 2008 (Uddin et al., 2011). Thus, the starting conditions of 11.5 MPa and 11°C and environmental parameters were set to fit the Mallik test site. The experimental gas hydrate saturation of 90% of the total pore volume (70 l) was slightly higher than volumes found in gas hydrate-bearing formations in the field (70 - 80%). However, the resulting permeability of a few millidarcy was comparable. The depressurization driven gas production at Mallik was conducted in three steps at 7.0 MPa - 5.0 MPa - 4.2 MPa all of which were used in the laboratory experiments. In the lab the pressure was controlled using a back pressure regulator while the confining pressure was stable. All but one of the 12 temperature sensors showed a rapid decrease in temperature throughout the sediment sample, which accompanied the pressure changes as a result of gas hydrate dissociation. During step 1 and 2 they continued up to the point where gas hydrate stability was regained. The pressure decreases and gas hydrate dissociation led to highly variable two phase fluid flow throughout the duration of the simulated production test. The flow rates were measured continuously (gas) and discontinuously (liquid), respectively. Next to being discussed here, both rates were used to verify a model of gas hydrate dissociation applying the foamy oil approach, a method earlier adopted to model the Mallik production test (see abstract Abendroth et al., this volume). Combined with a dense set of data from a cylindrical electrical resistance tomography (ERT) array (see abstract Priegnitz et al., this volume), very valuable information were gained on the spatial as well as temporal formation and dissociation of gas hydrates as well as changes in permeability and resulting pathways for the fluid flow. Here we present the set-up and execution of the experiment and discuss the results from temperature and flow measurements with respect to the gas hydrate dissociation and characteristics of resulting fluid flow. Uddin, M., Wright, F., and Coombe, D. 2011. Numerical Study of Gas Evolution and Transport Behaviours in Natural Gas-Hydrate Reservoirs. Journal of Canadian Petroleum Technology 50, 70-89.

Heeschen, Katja; Spangenberg, Erik; Schicks, Judith M.; Priegnitz, Mike; Giese, Ronny; Luzi-Helbing, Manja

2014-05-01

179

Reservoir characterization of marine and permafrost associated gas hydrate accumulations with downhole well logs  

USGS Publications Warehouse

Gas volumes that may be attributed to a gas hydrate accumulation depend on a number of reservoir parameters, one of which, gas-hydrate saturation, can be assessed with data obtained from downhole well-logging devices. This study demonstrates that electrical resistivity and acoustic transit-time downhole log data can be used to quantify the amount of gas hydrate in a sedimentary section. Two unique forms of the Archie relation (standard and quick look relations) have been used in this study to calculate water saturations (S(w)) [gas-hydrate saturation (S(h)) is equal to (1.0 - S(w))] from the electrical resistivity log data in four gas hydrate accumulations. These accumulations are located on (1) the Blake Ridge along the Southeastern continental margin of the United States, (2) the Cascadia continental margin off the pacific coast of Canada, (3) the North Slope of Alaska, and (4) the Mackenzie River Delta of Canada. Compressional wave acoustic log data have also been used in conjunction with the Timur, modified Wood, and the Lee weighted average acoustic equations to calculate gas-hydrate saturations in all four areas assessed.

Collett, T.S.; Lee, M.W.

2000-01-01

180

Geophysical assessments of renewable gas energy compressed in geologic pore storage reservoirs.  

PubMed

Renewable energy resources can indisputably minimize the threat of global warming and climate change. However, they are intermittent and need buffer storage to bridge the time-gap between production (off peak) and demand peaks. Based on geologic and geochemical reasons, the North German Basin has a very large capacity for compressed air/gas energy storage CAES in porous saltwater aquifers and salt cavities. Replacing pore reservoir brine with CAES causes changes in physical properties (elastic moduli, density and electrical properties) and justify applications of integrative geophysical methods for monitoring this energy storage. Here we apply techniques of the elastic full waveform inversion FWI, electric resistivity tomography ERT and gravity to map and quantify a gradually saturated gas plume injected in a thin deep saline aquifer within the North German Basin. For this subsurface model scenario we generated different synthetic data sets without and with adding random noise in order to robust the applied techniques for the real field applications. Datasets are inverted by posing different constraints on the initial model. Results reveal principally the capability of the applied integrative geophysical approach to resolve the CAES targets (plume, host reservoir, and cap rock). Constrained inversion models of elastic FWI and ERT are even able to recover well the gradual gas desaturation with depth. The spatial parameters accurately recovered from each technique are applied in the adequate petrophysical equations to yield precise quantifications of gas saturations. Resulting models of gas saturations independently determined from elastic FWI and ERT techniques are in accordance with each other and with the input (true) saturation model. Moreover, the gravity technique show high sensitivity to the mass deficit resulting from the gas storage and can resolve saturations and temporal saturation changes down to ±3% after reducing any shallow fluctuation such as that of groundwater table. PMID:24936391

Al Hagrey, Said Attia; Köhn, Daniel; Rabbel, Wolfgang

2014-01-01

181

HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS  

SciTech Connect

This final technical report describes and summarizes results of a research effort to investigate physical mechanisms that control the performance of gas injection processes in heterogeneous reservoirs and to represent those physical effects in an efficient way in simulations of gas injection processes. The research effort included four main lines of research: (1) Efficient compositional streamline methods for 3D flow; (2) Analytical methods for one-dimensional displacements; (3) Physics of multiphase flow; and (4) Limitations of streamline methods. In the first area, results are reported that show how the streamline simulation approach can be applied to simulation of gas injection processes that include significant effects of transfer of components between phases. In the second area, the one-dimensional theory of multicomponent gas injection processes is extended to include the effects of volume change as components change phase. In addition an automatic algorithm for solving such problems is described. In the third area, results on an extensive experimental investigation of three-phase flow are reported. The experimental results demonstrate the impact on displacement performance of the low interfacial tensions between the gas and oil phases that can arise in multicontact miscible or near-miscible displacement processes. In the fourth area, the limitations of the streamline approach were explored. Results of an experimental investigation of the scaling of the interplay of viscous, capillary, and gravity forces are described. In addition results of a computational investigation of the limitations of the streamline approach are reported. The results presented in this report establish that it is possible to use the compositional streamline approach in many reservoir settings to predict performance of gas injection processes. When that approach can be used, it requires substantially less (often orders of magnitude) computation time than conventional finite difference compositional simulation.

Franklin M. Orr, Jr.

2004-05-01

182

Analysis of the Development of Messoyakha Gas Field: A Commercial Gas Hydrate Reservoir  

E-print Network

230 gas-hydrate deposits have been discovered globally. Several production technologies have been tested; however, the development of the Messoyakha field in the west Siberian basin is the only successful commercial gas-hydrate field to date. Although...

Omelchenko, Roman 1987-

2012-12-11

183

Developing a tight gas sand advisor for completion and stimulation in tight gas reservoirs worldwide  

E-print Network

consolidations with adequate strengths after being exposed to extended pump times in water-based fracturing fluids and high temperatures.44 TABLE 2 - TYPICAL PROPPANT PROPERTIES Proppant type Sand Precured Resin Coated Sand Partially Cured Resin.... The modules include Perforation Selection and Proppant Selection. Based on input well/reservoir parameters these subroutines provide unambiguous recommendations concerning which perforation strategy(s) and what proppant(s) are applicable for a given well...

Bogatchev, Kirill Y

2008-10-10

184

Natural and Induced Fracture Diagnostics from 4-D VSP Low Permeability Gas Reservoirs  

SciTech Connect

Tight gas sand reservoirs generally contain thick gas-charged intervals that often have low porosity and very low permeability. Natural and induced fractures provide the only means of production. The objective of this work is to locate and characterize natural and induced fractures from analysis of scattered waves recorded on 4-D (time lapse) VSP data in order to optimize well placement and well spacing in these gas reservoirs. Using model data simulating the scattering of seismic energy from hydraulic fractures, we first show that it is possible to characterize the quality of fracturing based upon the amount of scattering. In addition, the picked arrival times of recorded microseismic events provide the velocity moveout for isolating the scattered energy on the 4-D VSP data. This concept is applied to a field dataset from the Jonah Field in Wyoming to characterize the quality of the induced hydraulic fractures. The time lapse (4D) VSP data from this field are imaged using a migration algorithm that utilizes shot travel time tables derived from the first breaks of the 3D VSPs and receiver travel time tables based on the microseismic arrival times and a regional velocity model. Four azimuthally varying shot tables are derived from picks of the first breaks of over 200 VSP records. We create images of the fracture planes through two of the hydraulically fractured wells in the field. The scattered energy shows correlation with the locations of the microseismic events. In addition, the azimuthal scattering is different from the azimuthal reflectivity of the reservoir, giving us more confidence that we have separated the scattered signal from simple formation reflectivity. Variation of the scattered energy along the image planes suggests variability in the quality of the fractures in three distinct zones.

Mark E. Willis; Daniel R. Burns; M. Nafi Toksoz

2008-09-30

185

The formation of magnetic ferric oxides in soils over underground gas storage reservoirs  

NASA Astrophysics Data System (ADS)

The concepts of the specific mechanisms responsible for the formation of magnetic ferric oxides in soils over artificial gas storage reservoirs are considered for the first time. Upon the interaction of technogenic allochthonous methane with soil, some biogeochemical barriers are formed that are characterized by the accumulation of solid products resulting from the functioning and development of the soil. The pedogenic new formations are represented by fine magnetic ferric oxides of specific shape. They are the result of an elementary soil-forming process—oxidogenesis composed of a complex of microprocesses of biogenic and abiogenic nature.

Mozharova, N. V.; Pronina, V. V.; Ivanov, A. V.; Shoba, S. A.; Zagurskii, A. M.

2007-06-01

186

Geology, reservoir engineering and methane hydrate potential of the Walakpa Gas Field, North Slope, Alaska. Final report  

SciTech Connect

The Walakpa Gas Field, located near the city of Barrow on Alaska`s North Slope, has been proven to be methane-bearing at depths of 2000--2550 feet below sea level. The producing formation is a laterally continuous, south-dipping, Lower Cretaceous shelf sandstone. The updip extent of the reservoir has not been determined by drilling, but probably extends to at least 1900 feet below sea level. Reservoir temperatures in the updip portion of the reservoir may be low enough to allow the presence of in situ methane hydrates. Reservoir net pay however, decreases to the north. Depths to the base of permafrost in the area average 940 feet. Drilling techniques and production configuration in the Walakpa field were designed to minimize formation damage to the reservoir sandstone and to eliminate methane hydrates formed during production. Drilling development of the Walakpa field was a sequential updip and lateral stepout from a previously drilled, structurally lower confirmation well. Reservoir temperature, pressure, and gas chemistry data from the development wells confirm that they have been drilled in the free-methane portion of the reservoir. Future studies in the Walakpa field are planned to determine whether or not a component of the methane production is due to the dissociation of updip in situ hydrates.

Glenn, R.K.; Allen, W.W.

1992-12-01

187

Matrix Heterogeneity Effects on Gas Transport and Adsorption in Coalbed and Shale Gas Reservoirs  

Microsoft Academic Search

In coalbeds and shales, gas transport and storage are important for accurate prediction of production rates and for the consideration\\u000a of subsurface greenhouse gas sequestration. They involve coupled fluid phenomena in porous medium including viscous flow,\\u000a diffusive transport, and adsorption. Standard approach to describe gas–matrix interactions is deterministic and neglects the\\u000a effects of local spatial heterogeneities in porosity and material

Ebrahim Fathi; I. Yücel Akkutlu

2009-01-01

188

Gulf of Mexico Oil and Gas Atlas Series: Play analysis of oligocene and miocene reservoirs from Texas State Offshore Waters  

SciTech Connect

The objective of the Offshore Northern Gulf of Mexico Oil and Gas Resource Atlas Series is to define hydrocarbon plays by integrating geologic and engineering data for oil and gas reservoirs with large-scale patterns of depositional basin fill and geologic age. The primary product of the program will be an oil and gas atlas set for the offshore northern Gulf of Mexico and a computerized geographical information system of geologic and engineering data linked to reservoir location. The oil and gas atlas for the Gulf of Mexico will provide a critically compiled, comprehensive reference that is needed to more efficiently develop reservoirs, to extend field limits, and to better assess the opportunities for intrafield exploration. The play atlas will provide an organizational framework to aid development in mature areas and to extend exploration paradigms from mature areas into frontier areas deep below the shelf and into deep waters of the continental slope. In addition to serving as a model for exploration and education, the offshore atlas will aid resource assessment efforts of State, Federal, and private agencies by allowing for greater precision in the extrapolation of variables within and between plays. Classification and organization of reservoirs into plays have proved to be effective in previous atlases produced by the Bureau, including the Texas oil and gas atlases, the Midcontinent gas atlas, and Central and Eastern Gulf Coast gas atlas.

Seni, S.J.; Finley, R.J.

1993-12-31

189

Accounting for Adsorbed gas and its effect on production bahavior of Shale Gas Reservoirs  

E-print Network

?.............................................................................................. 14 3.4 SGPA results on decline curve for free, desorbed and total gas ............... 15 3.5 SGPA results on log qg / [m(pi) ?m(pwf)] vs log time plot for free, desorbed and total gas (SGPA.................................................................................... 23 4.4 Plot of [m(pi )? m(pwf )(t)] / qg vs pseudo time tn* constant rate gas BDF including adsorbed gas with slope mBDF to calculate G............................ 25 4.5 Plot of [m(pi )? m(pwf )(t)] / qg vs pseudo time tn...

Mengal, Salman Akram

2010-10-12

190

Geologic, technical, and economic sensitivity analysis in support of the GRI (Gas Research Institute) Tight Gas Reservoirs Project area. Annual report, November 1984October 1985  

Microsoft Academic Search

During 1984-1985, Lewin and Associates, Inc., used the Tight Gas Analysis System (TGAS) as a planning and assessment tool for GRI. During this period TGAS was used to support the GRI Tight Gas Reservoirs Program: (1) evaluation of the benefits of the entire program and its subcomponents; (2) detailed analysis of a single formation (the Travis Peak); and (3) fine

J. P. Brashear; M. Haas; F. Morra

1985-01-01

191

Numerical simulations of the Macondo well blowout reveal strong control of oil flow by reservoir permeability and exsolution of gas.  

PubMed

In response to the urgent need for estimates of the oil and gas flow rate from the Macondo well MC252-1 blowout, we assembled a small team and carried out oil and gas flow simulations using the TOUGH2 codes over two weeks in mid-2010. The conceptual model included the oil reservoir and the well with a top boundary condition located at the bottom of the blowout preventer. We developed a fluid properties module (Eoil) applicable to a simple two-phase and two-component oil-gas system. The flow of oil and gas was simulated using T2Well, a coupled reservoir-wellbore flow model, along with iTOUGH2 for sensitivity analysis and uncertainty quantification. The most likely oil flow rate estimated from simulations based on the data available in early June 2010 was about 100,000 bbl/d (barrels per day) with a corresponding gas flow rate of 300 MMscf/d (million standard cubic feet per day) assuming the well was open to the reservoir over 30 m of thickness. A Monte Carlo analysis of reservoir and fluid properties provided an uncertainty distribution with a long tail extending down to 60,000 bbl/d of oil (170 MMscf/d of gas). The flow rate was most strongly sensitive to reservoir permeability. Conceptual model uncertainty was also significant, particularly with regard to the length of the well that was open to the reservoir. For fluid-entry interval length of 1.5 m, the oil flow rate was about 56,000 bbl/d. Sensitivity analyses showed that flow rate was not very sensitive to pressure-drop across the blowout preventer due to the interplay between gas exsolution and oil flow rate. PMID:21730177

Oldenburg, Curtis M; Freifeld, Barry M; Pruess, Karsten; Pan, Lehua; Finsterle, Stefan; Moridis, George J

2012-12-11

192

Numerical simulations of the Macondo well blowout reveal strong control of oil flow by reservoir permeability and exsolution of gas  

PubMed Central

In response to the urgent need for estimates of the oil and gas flow rate from the Macondo well MC252-1 blowout, we assembled a small team and carried out oil and gas flow simulations using the TOUGH2 codes over two weeks in mid-2010. The conceptual model included the oil reservoir and the well with a top boundary condition located at the bottom of the blowout preventer. We developed a fluid properties module (Eoil) applicable to a simple two-phase and two-component oil-gas system. The flow of oil and gas was simulated using T2Well, a coupled reservoir-wellbore flow model, along with iTOUGH2 for sensitivity analysis and uncertainty quantification. The most likely oil flow rate estimated from simulations based on the data available in early June 2010 was about 100,000 bbl/d (barrels per day) with a corresponding gas flow rate of 300 MMscf/d (million standard cubic feet per day) assuming the well was open to the reservoir over 30 m of thickness. A Monte Carlo analysis of reservoir and fluid properties provided an uncertainty distribution with a long tail extending down to 60,000 bbl/d of oil (170 MMscf/d of gas). The flow rate was most strongly sensitive to reservoir permeability. Conceptual model uncertainty was also significant, particularly with regard to the length of the well that was open to the reservoir. For fluid-entry interval length of 1.5 m, the oil flow rate was about 56,000 bbl/d. Sensitivity analyses showed that flow rate was not very sensitive to pressure-drop across the blowout preventer due to the interplay between gas exsolution and oil flow rate. PMID:21730177

Oldenburg, Curtis M.; Freifeld, Barry M.; Pruess, Karsten; Pan, Lehua; Finsterle, Stefan; Moridis, George J.

2012-01-01

193

A combined saline formation and gas reservoir CO2 injection pilotin Northern California  

SciTech Connect

A geologic sequestration pilot in the Thornton gas field in Northern California, USA involves injection of up to 4000 tons of CO{sub 2} into a stacked gas and saline formation reservoir. Lawrence Berkeley National Laboratory (LBNL) is leading the pilot test in collaboration with Rosetta Resources, Inc. and Calpine Corporation under the auspices of the U.S. Department of Energy and California Energy Commission's WESTCARB, Regional Carbon Sequestration Partnership. The goals of the pilot include: (1) Demonstrate the feasibility of CO{sub 2} storage in saline formations representative of major geologic sinks in California; (2) Test the feasibility of Enhanced Gas Recovery associated with the early stages of a CO{sub 2} storage project in a depleting gas field; (3) Obtain site-specific information to improve capacity estimation, risk assessment, and performance prediction; (4) Demonstrate and test methods for monitoring CO{sub 2} storage in saline formations and storage/enhanced recovery projects in gas fields; and (5) Gain experience with regulatory permitting and public outreach associated with CO{sub 2} storage in California. Test design is currently underway and field work begins in August 2006.

Trautz, Robert; Myer, Larry; Benson, Sally; Oldenburg, Curt; Daley, Thomas; Seeman, Ed

2006-04-28

194

System-level modeling for economic evaluation of geological CO2storage in gas reservoirs  

SciTech Connect

One way to reduce the effects of anthropogenic greenhousegases on climate is to inject carbon dioxide (CO2) from industrialsources into deep geological formations such as brine aquifers ordepleted oil or gas reservoirs. Research is being conducted to improveunderstanding of factors affecting particular aspects of geological CO2storage (such as storage performance, storage capacity, and health,safety and environmental (HSE) issues) as well as to lower the cost ofCO2 capture and related processes. However, there has been less emphasisto date on system-level analyses of geological CO2 storage that considergeological, economic, and environmental issues by linking detailedprocess models to representations of engineering components andassociated economic models. The objective of this study is to develop asystem-level model for geological CO2 storage, including CO2 capture andseparation, compression, pipeline transportation to the storage site, andCO2 injection. Within our system model we are incorporating detailedreservoir simulations of CO2 injection into a gas reservoir and relatedenhanced production of methane. Potential leakage and associatedenvironmental impacts are also considered. The platform for thesystem-level model is GoldSim [GoldSim User's Guide. GoldSim TechnologyGroup; 2006, http://www.goldsim.com]. The application of the system modelfocuses on evaluating the feasibility of carbon sequestration withenhanced gas recovery (CSEGR) in the Rio Vista region of California. Thereservoir simulations are performed using a special module of the TOUGH2simulator, EOS7C, for multicomponent gas mixtures of methane and CO2.Using a system-level modeling approach, the economic benefits of enhancedgas recovery can be directly weighed against the costs and benefits ofCO2 injection.

Zhang, Yingqi; Oldenburg, Curtis M.; Finsterle, Stefan; Bodvarsson, Gudmundur S.

2006-03-02

195

The effect of reservoir heterogeneity on gas production from hydrate accumulations in the permafrost  

SciTech Connect

The quantity of hydrocarbon gases trapped in natural hydrate accumulations is enormous, leading to significant interest in the evaluation of their potential as an energy source. Large volumes of gas can be readily produced at high rates for long times from methane hydrate accumulations in the permafrost by means of depressurization-induced dissociation combined with conventional technologies and horizontal or vertical well configurations. Initial studies on the possibility of natural gas production from permafrost hydrates assumed homogeneity in intrinsic reservoir properties and in the initial condition of the hydrate-bearing layers (either due to the coarseness of the model or due to simplifications in the definition of the system). These results showed great promise for gas recovery from Class 1, 2, and 3 systems in the permafrost. This work examines the consequences of inevitable heterogeneity in intrinsic properties, such as in the porosity of the hydrate-bearing formation, or heterogeneity in the initial state of hydrate saturation. Heterogeneous configurations are generated through multiple methods: (1) through defining heterogeneous layers via existing well-log data, (2) through randomized initialization of reservoir properties and initial conditions, and (3) through the use of geostatistical methods to create heterogeneous fields that extrapolate from the limited data available from cores and well-log data. These extrapolations use available information and established geophysical methods to capture a range of deposit properties and hydrate configurations. The results show that some forms of heterogeneity, such as horizontal stratification, can assist in production of hydrate-derived gas. However, more heterogeneous structures can lead to complex physical behavior within the deposit and near the wellbore that may obstruct the flow of fluids to the well, necessitating revised production strategies. The need for fine discretization is crucial in all cases to capture dynamic behavior during production.

Reagan, M. T.; Kowalsky, M B.; Moridis, G. J.; Silpngarmlert, S.

2010-05-01

196

Study of Multi-scale Transport Phenomena in Tight Gas and Shale Gas Reservoir Systems  

E-print Network

. In this work we contribute a numerical model which captures multicomponent desorption, diffusion, and phase behavior in ultra-tight rocks. We also describe a workflow for incorporating measured gas composition data into modern production analysis....

Freeman, Craig Matthew

2013-11-25

197

Helium and neon isotope systematics in carbon dioxide-rich and hydrocarbon-rich gas reservoirs  

NASA Astrophysics Data System (ADS)

The isotopic compositions and elemental abundances of helium and neon were measured in three natural gas reservoirs in the Pannonian sedimentary basin of Hungary. Kismarja (a CO 2-rich reservoir) and Szeghalom-South and Szeghalom-North (both CH 4-dominated reservoirs) are located on topographic basement highs close to the Derecske Sub-Basin in eastern Hungary. Mantle-derived neon has been identified in mixed CH 4-CO 2 reservoirs in the Vienna Basin, Austria. This study establishes that mantle-derived neon and helium are a characteristic feature of gas reservoirs throughout the Neogene extensional basins of Hungary and Austria regardless of the dominant active gas composition. 3He /4He ratios within these samples are attributable to a two-component mixing between mantlederived and crustal-radiogenic helium. The percent contribution of mantle-derived 4He varies from 2.3 to 17%. In contrast, neon isotopic ratios indicate that the gases contain a significant component of atmosphere-derived neon in addition to the mantle- and crustal-derived components. 20Ne, 21Ne and 22Ne abundances can be corrected for this atmospheric contribution. Calculated contributions of mantle- and crustal-derived 21Ne are between 3.6-21% and 1-37%, respectively. 20Ne /22Ne c and 21Ne /22Ne c ratios derived for these atmosphere-corrected components correlate with measured R/Ra values and plot along a single two-component mixing line between crustal and mantle isotopic endmembers. This is consistent with a model in which simple mixing occurs between crustal and mantle endmembers with fixed He/Ne ratios. The mixing line is defined by a hyperbolic constant K (where K = ( 4He /22Ne ) rad/( 4 He /22Ne ) mntl) with a mean value of 67.3 ± 11.8. Based on estimated values of 0.47 for 21Ne /22Ne rad and (1.62 ± 0.03)× 10 7 for ( 4He /21Ne ) rad (Kennedy et al., 1990), values of 7.61 × 10 6 for ( He/22Ne ) rad and 11.3 × 10 4 for ( 4He /22Ne ) mntl can be calculated for the Pannonian Basin gases. This ( 4He /22Ne ) mntl value is indistinguishable within error from the value of 8.04 × 10 4 calculated for rare gases in natural gases from the Vienna Basin. These results clearly establish that the continental expression of mantle-derived rare gases in continental extensional systems in Austria and Hungary is distinct and consistently different from that of gases discharging at the spreading ridges where best estimates of ( 4He /22Ne ) mntl are 8.1-11.3 times higher (9.10 × 10 5; Staudacher et al., 1989). Given the remarkable agreement in the continental expression of mantle-derived gases throughout the Pannonian and Vienna Basins, it is difficult to attribute the observed neon enrichment/helium depletion with respect to MORB gases to fractionation related to lithospheric transport processes. Kinetic fraction ation processes involved in transport through the crust might be expected to produce a much wider variation in the observed He/Ne elemental ratios. The consistent, order-of-magnitude neon enrichment observed throughout these gas fields instead implies that mantle-derived fluids in these continental extensional systems may be sourced in a region of the mantle distinct from that supplying the mid-ocean spreading ridges.

Lollar, B. Sherwood; O'Nions, R. K.; Ballentine, C. J.

1994-12-01

198

An evaluation of the deep reservoir conditions of the Bacon-Manito geothermal field, Philippines using well gas chemistry  

SciTech Connect

Gas chemistry from 28 wells complement water chemistry and physical data in developing a reservoir model for the Bacon-Manito geothermal project (BMGP), Philippines. Reservoir temperature, THSH, and steam fraction, y, are calculated or extrapolated from the grid defined by the Fischer-Tropsch (FT) and H2-H2S (HSH) gas equilibria reactions. A correction is made for H2 that is lost due to preferential partitioning into the vapor phase and the reequilibration of H2S after steam loss.

D'Amore, Franco; Maniquis-Buenviaje, Marinela; Solis, Ramonito P.

1993-01-28

199

Galaxy stellar mass assembly: supernova feedback, photo-ionization and no-star-forming gas reservoir.  

NASA Astrophysics Data System (ADS)

Semi-analytical models are currently the best way to understand the formation of galaxies within the cosmic dark-matter structures. While they fairly well reproduce the local stellar mass functions, they fail to match observations at high redshift. The inconsistency indicates that the gas accretion in galaxies and the transformation of gas into stars, are not well followed. With a new SAM: eGalICS, we explore the impacts of classical mechanisms (supernova feedback, photo-ionization) onto the stellar mass assembly. Even with a strong efficiency, these two processes cannot explain the observed stellar mass function and star formation rate distribution. We introduce an ad-hoc modification of the standard paradigm, based on the presence of a no-star-forming gas component in galaxy discs. We introduce this reservoir to generate a delay between the accretion of the gas and the star formation process. The new stellar mass function and SFR distributions are in good agreement with observations.

Cousin, M.

2014-12-01

200

Numerical simulations of depressurization-induced gas production from gas hydrate reservoirs at the Walker Ridge 312 site, northern Gulf of Mexico  

SciTech Connect

In 2009, the Gulf of Mexico (GOM) Gas Hydrates Joint-Industry-Project (JIP) Leg II drilling program confirmed that gas hydrate occurs at high saturations within reservoir-quality sands in the GOM. A comprehensive logging-while-drilling dataset was collected from seven wells at three sites, including two wells at the Walker Ridge 313 site. By constraining the saturations and thicknesses of hydrate-bearing sands using logging-while-drilling data, two-dimensional (2D), cylindrical, r-z and three-dimensional (3D) reservoir models were simulated. The gas hydrate occurrences inferred from seismic analysis are used to delineate the areal extent of the 3D reservoir models. Numerical simulations of gas production from the Walker Ridge reservoirs were conducted using the depressurization method at a constant bottomhole pressure. Results of these simulations indicate that these hydrate deposits are readily produced, owing to high intrinsic reservoir-quality and their proximity to the base of hydrate stability. The elevated in situ reservoir temperatures contribute to high (5–40 MMscf/day) predicted production rates. The production rates obtained from the 2D and 3D models are in close agreement. To evaluate the effect of spatial dimensions, the 2D reservoir domains were simulated at two outer radii. The results showed increased potential for formation of secondary hydrate and appearance of lag time for production rates as reservoir size increases. Similar phenomena were observed in the 3D reservoir models. The results also suggest that interbedded gas hydrate accumulations might be preferable targets for gas production in comparison with massive deposits. Hydrate in such accumulations can be readily dissociated due to heat supply from surrounding hydrate-free zones. Special cases were considered to evaluate the effect of overburden and underburden permeability on production. The obtained data show that production can be significantly degraded in comparison with a case using impermeable boundaries. The main reason for the reduced productivity is water influx from the surrounding strata; a secondary cause is gas escape into the overburden. The results dictate that in order to reliably estimate production potential, permeability of the surroundings has to be included in a model.

Myshakin, Evgeniy M.; Gaddipati, Manohar; Rose, Kelly; Anderson, Brian J.

2012-06-01

201

GHG Emissions from Hydropower Reservoirs The role of hydropower reservoirs in contributing to greenhouse gas (GHG) emissions is poorly  

E-print Network

to greenhouse gas (GHG) emissions is poorly understood, but recent studies have indicated that GHG emissions inverted funnels for ebullitive gas emissions (24 hours), floating dome for diffusive gas emissions (10 minutes), and water sample analysis for dissolved gas concentrations. Findings CO2 emissions from

202

Electrical anisotropy of gas hydrate-bearing sand reservoirs in the Gulf of Mexico  

USGS Publications Warehouse

We present new results and interpretations of the electricalanisotropy and reservoir architecture in gashydrate-bearingsands using logging data collected during the Gulf of MexicoGasHydrate Joint Industry Project Leg II. We focus specifically on sandreservoirs in Hole Alaminos Canyon 21 A (AC21-A), Hole Green Canyon 955 H (GC955-H) and Hole Walker Ridge 313 H (WR313-H). Using a new logging-while-drilling directional resistivity tool and a one-dimensional inversion developed by Schlumberger, we resolve the resistivity of the current flowing parallel to the bedding, R| and the resistivity of the current flowing perpendicular to the bedding, R|. We find the sandreservoir in Hole AC21-A to be relatively isotropic, with R| and R| values close to 2 ? m. In contrast, the gashydrate-bearingsandreservoirs in Holes GC955-H and WR313-H are highly anisotropic. In these reservoirs, R| is between 2 and 30 ? m, and R| is generally an order of magnitude higher. Using Schlumberger's WebMI models, we were able to replicate multiple resistivity measurements and determine the formation resistivity the gashydrate-bearingsandreservoir in Hole WR313-H. The results showed that gashydrate saturations within a single reservoir unit are highly variable. For example, the sand units in Hole WR313-H contain thin layers (on the order of 10-100 cm) with varying gashydrate saturations between 15 and 95%. Our combined modeling results clearly indicate that the gashydrate-bearingsandreservoirs in Holes GC955-H and WR313-H are highly anisotropic due to varying saturations of gashydrate forming in thin layers within larger sand units.

Cook, Anne E.; Anderson, Barbara I.; Rasmus, John; Sun, Keli; Li, Qiming; Collett, Timothy S.; Goldberg, David S.

2012-01-01

203

Scale-dependent gas hydrate saturation estimates in sand reservoirs in the Ulleung Basin, East Sea of Korea  

USGS Publications Warehouse

Through the use of 2-D and 3-D seismic data, several gas hydrate prospects were identified in the Ulleung Basin, East Sea of Korea and thirteen drill sites were established and logging-while-drilling (LWD) data were acquired from each site in 2010. Sites UBGH2–6 and UBGH2–10 were selected to test a series of high amplitude seismic reflections, possibly from sand reservoirs. LWD logs from the UBGH2–6 well indicate that there are three significant sand reservoirs with varying thickness. Two upper sand reservoirs are water saturated and the lower thinly bedded sand reservoir contains gas hydrate with an average saturation of 13%, as estimated from the P-wave velocity. The well logs at the UBGH2–6 well clearly demonstrated the effect of scale-dependency on gas hydrate saturation estimates. Gas hydrate saturations estimated from the high resolution LWD acquired ring resistivity (vertical resolution of about 5–8 cm) reaches about 90% with an average saturation of 28%, whereas gas hydrate saturations estimated from the low resolution A40L resistivity (vertical resolution of about 120 cm) reaches about 25% with an average saturation of 11%. However, in the UBGH2–10 well, gas hydrate occupies a 5-m thick sand reservoir near 135 mbsf with a maximum saturation of about 60%. In the UBGH2–10 well, the average and a maximum saturation estimated from various well logging tools are comparable, because the bed thickness is larger than the vertical resolution of the various logging tools. High resolution wireline log data further document the role of scale-dependency on gas hydrate calculations.

Lee, Myung Woong; Collett, Timothy S.

2013-01-01

204

Control of water coning in gas reservoirs by injecting gas into the aquifer  

E-print Network

of water in the producing well. fiost research on water coning has been directed toward minimizing water production by reduced well penetration or production rate con- tro1. An alternative method for gas wells with water coning problems, is to inject.... This gives high water cuts in the early stages of the succeeding production, when gas is injected deep in the aquifer. This was not a significant problem for the high permeability ratio. When the well is put on production, the established cone overrides...

Haugen, Sigurd Arild

2012-06-07

205

Carbon dioxide and helium emissions from a reservoir of magmatic gas beneath Mammoth Mountain, California  

SciTech Connect

Carbon dioxide and helium with isotopic compositions indicative of a magmatic source ({delta}thinsp{sup 13}C={minus}4.5 to {minus}5{per_thousand}, {sup 3}He/{sup 4}He=4.5 to 6.7 R{sub A}) are discharging at anomalous rates from Mammoth Mountain, on the southwestern rim of the Long Valley caldera in eastern California. The gas is released mainly as diffuse emissions from normal-temperature soils, but some gas issues from steam vents or leaves the mountain dissolved in cold groundwater. The rate of gas discharge increased significantly in 1989 following a 6-month period of persistent earthquake swarms and associated strain and ground deformation that has been attributed to dike emplacement beneath the mountain. An increase in the magmatic component of helium discharging in a steam vent on the north side of Mammoth Mountain, which also began in 1989, has persisted until the present time. Anomalous CO{sub 2} discharge from soils first occurred during the winter of 1990 and was followed by observations of several areas of tree kill and/or heavier than normal needlecast the following summer. Subsequent measurements have confirmed that the tree kills arc associated with CO{sub 2} concentrations of 30{endash}90{percent} in soil gas and gas flow rates of up to 31,000 gthinspm{sup {minus}2}thinspd{sup {minus}1} at the soil surface. Each of the tree-kill areas and one area of CO{sub 2} discharge above tree line occurs in close proximity to one or more normal faults, which may provide conduits for gas flow from depth. We estimate that the total diffuse CO{sub 2} flux from the mountain is approximately 520 t/d, and that 30{endash}50 t/d of CO{sub 2} are dissolved in cold groundwater flowing off the flanks of the mountain. Isotopic and chemical analyses of soil and fumarolic gas demonstrate a remarkable homogeneity in composition, suggesting that the CO{sub 2} and associated helium and excess nitrogen may be derived from a common gas reservoir whose source is associated with some combination of magmatic degassing and thermal metamorphism of metasedimentary rocks. Furthermore, N{sub 2}/Ar ratios and nitrogen isotopic values indicate that the Mammoth Mountain gases are derived from sources separate from those that supply gas to the hydrothermal system within the Long Valley caldera. Various data suggest that the Mammoth Mountain gas reservoir is a large, low-temperature cap over an isolated hydrothermal system, that it predates the 1989 intrusion, and that it could remain a source of gas discharge for some time. {copyright} 1998 American Geophysical Union

Sorey, M.L.; Evans, W.C. [U.S. Geological Survey, Menlo Park, California (United States)] Kennedy, B.M. [Lawrence Berkeley National Laboratory, Berkeley, California (United States)] Farrar, C.D. [U.S. Geological Survey, Carnelian Bay, California (United States)] Hainsworth, L.J. [Chemistry Department, Emory and Henry College, Emory, Virginia (United States)] Hausback, B. [Geology Department, California State University, Sacramento

1998-07-01

206

Eos modeling and reservoir simulation study of bakken gas injection improved oil recovery in the elm coulee field, Montana  

NASA Astrophysics Data System (ADS)

The Bakken Formation in the Williston Basin is one of the most productive liquid-rich unconventional plays. The Bakken Formation is divided into three members, and the Middle Bakken Member is the primary target for horizontal wellbore landing and hydraulic fracturing because of its better rock properties. Even with this new technology, the primary recovery factor is believed to be only around 10%. This study is to evaluate various gas injection EOR methods to try to improve on that low recovery factor of 10%. In this study, the Elm Coulee Oil Field in the Williston Basin was selected as the area of interest. Static reservoir models featuring the rock property heterogeneity of the Middle Bakken Member were built, and fluid property models were built based on Bakken reservoir fluid sample PVT data. By employing both compositional model simulation and Todd-Longstaff solvent model simulation methods, miscible gas injections were simulated and the simulations speculated that oil recovery increased by 10% to 20% of OOIP in 30 years. The compositional simulations yielded lower oil recovery compared to the solvent model simulations. Compared to the homogeneous model, the reservoir model featuring rock property heterogeneity in the vertical direction resulted in slightly better oil recovery, but with earlier CO2 break-through and larger CO2 production, suggesting that rock property heterogeneity is an important property for modeling because it has a big effect on the simulation results. Long hydraulic fractures shortened CO2 break-through time greatly and increased CO 2 production. Water-alternating-gas injection schemes and injection-alternating-shut-in schemes can provide more options for gas injection EOR projects, especially for gas production management. Compared to CO2 injection, separator gas injection yielded slightly better oil recovery, meaning separator gas could be a good candidate for gas injection EOR; lean gas generated the worst results. Reservoir simulations also indicate that original rock properties are the dominant factor for the ultimate oil recovery for both primary recovery and gas injection EOR. Because reservoir simulations provide critical inputs for project planning and management, more effort needs to be invested into reservoir modeling and simulation, including building enhanced geologic models, fracture characterization and modeling, and history matching with field data. Gas injection EOR projects are integrated projects, and the viability of a project also depends on different economic conditions.

Pu, Wanli

207

Application of coiled-tubing-drilling technology on a deep underpressured gas reservoir  

SciTech Connect

The Upper-Mississippian Elkton formation is a dolomitized shallow-water carbonate consisting of dense limestones and porous dolomites. The Elkton was deposited in an open-shelf environment as crinoid grainstones, coral packstones, and lime muds. Deposition of impermeable shales and siltstones of the Lower Cretaceous created the lateral and updip seals. Reservoir thickness can be up to 20 m, with porosities reaching 20% and averaging 10%. The reservoir gas contains approximately 0.5% hydrogen sulfide. Well 11-18 was to be completed in the Harmatten Elkton pool. The pool went on production in 1967 at an initial pressure of 23,500 kPa. At the current pressure of 16,800 kPa, the remaining reserves are underpressured at 6.5 kPa/m, and underbalanced horizontal drilling was selected as the most suitable technique for exploiting remaining reserves. Coiled-tubing (CT) technology was selected to ensure continuous underbalanced conditions and maintain proper well control while drilling. The paper describes the equipment, CT drilling summary, and drilling issues.

NONE

1997-06-01

208

Simulation of Geomechanically Coupled IOR Processes in Unconventional Oil and Gas Reservoirs  

NASA Astrophysics Data System (ADS)

Fracture network creation has been shown to be a key factor in facilitating economic production of oil and gas from unconventional reservoirs. These networks provide highly permeable flow paths that allow access to tight matrix blocks. A recent water injection study in Bakken has illustrated how stress changes during water injection could induce micro-fractures that further extend the fracture network into the matrix. To capture such physics, we present a coupled flow and geomechanics model for dual porosity reservoirs. The tight matrix is refined into multiple continua to capture the stress change on the matrix surface. This stress change is calculated using equivalent mechanical properties for fractured rock. These properties are based on the assumption that the deformation of fractured rock is the sum of the deformation of intact rock and fractures. In addition, Hoek-Brown failure criterion is used to calculate when matrix rock fails. Once induced stress exceeds rock strength, matrix block failure is assumed and the transfer function between fracture and matrix is improved. Our simulation results indicate viscous displacement and spontaneous imbibition processes are negligible because they cannot penetrate into the tight matrix block. However, once matrix blocks are cracked due to thermally induced stresses on the matrix surface, these processes become more pronounced and can improve oil production from the cracked tight matrix. These positive effects are particularly important farther away from the immediate vicinity of the hydraulic fracture where much of the undrained oil resides.

Wu, Y.; Winterfeld, P. H.; Fakcharoenphol, P.

2012-12-01

209

Gas hydrate saturations estimated from fractured reservoir at Site NGHP-01-10, Krishna-Godavari Basin, India  

NASA Astrophysics Data System (ADS)

During the Indian National Gas Hydrate Program Expedition 01 (NGHP-01), one of the richest marine gas hydrate accumulations was discovered at Site NGHP-01-10 in the Krishna-Godavari Basin. The occurrence of concentrated gas hydrate at this site is primarily controlled by the presence of fractures. Assuming the resistivity of gas hydrate-bearing sediments is isotropic, the conventional Archie analysis using the logging while drilling resistivity log yields gas hydrate saturations greater than 50% (as high as ˜80%) of the pore space for the depth interval between ˜25 and ˜160 m below seafloor. On the other hand, gas hydrate saturations estimated from pressure cores from nearby wells were less than ˜26% of the pore space. Although intrasite variability may contribute to the difference, the primary cause of the saturation difference is attributed to the anisotropic nature of the reservoir due to gas hydrate in high-angle fractures. Archie's law can be used to estimate gas hydrate saturations in anisotropic reservoir, with additional information such as elastic velocities to constrain Archie cementation parameters m and the saturation exponent n. Theory indicates that m and n depend on the direction of the measurement relative to fracture orientation, as well as depending on gas hydrate saturation. By using higher values of m and n in the resistivity analysis for fractured reservoirs, the difference between saturation estimates is significantly reduced, although a sizable difference remains. To better understand the nature of fractured reservoirs, wireline P and S wave velocities were also incorporated into the analysis.

Lee, M. W.; Collett, T. S.

2009-07-01

210

On the physics multimechanistic gas-water flow in fractured reservoirs  

SciTech Connect

Multimechanistic flow occurs in reservoirs when the fluid transport is influenced by both, pressure and concentration gradients. In this research, we investigate the dynamics of multi-mechanistic gas-water transport in fractured systems. To achieve this objective, we have developed a two-phase, two-dimensional dual-porosity, dual-permeability simulator. The details of the simulator development are presented in a previous paper. Our studies indicate the presence of higher flowrates and cumulative production at early times in systems experiencing multimechanistic flow. This is attributed to the higher draw- downs experienced by such systems. At late times, a {open_quotes}choking effect{close_quotes} is hypothesized to be responsible for higher cumulative production. In this paper, we investigate the physics underlying this multimechanistic flow behavior. We do this by carefully analyzing a fractured system which clearly displays multi-mechanistic flow characteristics.

Chawathe, A.; Grader, A.; Ertekin, T.

1996-09-01

211

Star formation, quenching, black hole feedback and the fate of gas reservoirs  

NASA Astrophysics Data System (ADS)

Massive galaxies are broadly split into those forming stars on the main sequence, and those which are quiescent. The physical processes by which galaxies quench their star formation remain poorly understood. I analyze the properties of galaxies and track their evolutionary trajectories as they migrate from the blue cloud of star forming galaxies to the red sequence of quiescent galaxies via the `green valley'. I show that there must be two fundamentally star formation quenching pathways associated with early- and late-type galaxies which are intricately linked to how hydrogen gas reservoirs are destroyed or shut off. In the quenching of late-type galaxies, environment (or halo mass) is a key parameter, while for early-types, an internal mechanism such as black hole feedback is more likely. I will present recent HI observations supporting this picture.

Schawinski, Kevin; Wong, Ivy; Urry, C. Megan; Willett, Kyle; Simmons, Brooke D.; Galaxy Zoo team

2015-01-01

212

Pore-scale mechanisms of gas flow in tight sand reservoirs  

SciTech Connect

Tight gas sands are unconventional hydrocarbon energy resource storing large volume of natural gas. Microscopy and 3D imaging of reservoir samples at different scales and resolutions provide insights into the coaredo not significantly smaller in size than conventional sandstones, the extremely dense grain packing makes the pore space tortuous, and the porosity is small. In some cases the inter-granular void space is presented by micron-scale slits, whose geometry requires imaging at submicron resolutions. Maximal Inscribed Spheres computations simulate different scenarios of capillary-equilibrium two-phase fluid displacement. For tight sands, the simulations predict an unusually low wetting fluid saturation threshold, at which the non-wetting phase becomes disconnected. Flow simulations in combination with Maximal Inscribed Spheres computations evaluate relative permeability curves. The computations show that at the threshold saturation, when the nonwetting fluid becomes disconnected, the flow of both fluids is practically blocked. The nonwetting phase is immobile due to the disconnectedness, while the permeability to the wetting phase remains essentially equal to zero due to the pore space geometry. This observation explains the Permeability Jail, which was defined earlier by others. The gas is trapped by capillarity, and the brine is immobile due to the dynamic effects. At the same time, in drainage, simulations predict that the mobility of at least one of the fluids is greater than zero at all saturations. A pore-scale model of gas condensate dropout predicts the rate to be proportional to the scalar product of the fluid velocity and pressure gradient. The narrowest constriction in the flow path is subject to the highest rate of condensation. The pore-scale model naturally upscales to the Panfilov's Darcy-scale model, which implies that the condensate dropout rate is proportional to the pressure gradient squared. Pressure gradient is the greatest near the matrix-fracture interface. The distinctive two-phase flow properties of tight sand imply that a small amount of gas condensate can seriously affect the recovery rate by blocking gas flow. Dry gas injection, pressure maintenance, or heating can help to preserve the mobility of gas phase. A small amount of water can increase the mobility of gas condensate.

Silin, D.; Kneafsey, T.J.; Ajo-Franklin, J.B.; Nico, P.

2010-11-30

213

The model of the oil-gas bearing molasse reservoirs in the Peri-Adriatic depression, Albania  

SciTech Connect

The Peri-Adriatic Depression (PAD) represents the eastern extension of the Cenozoic Adriatic basin into onshore Albania. Several oil, gas condensate, dry gas fields have been discovered in this basin. Dry gas fields occur mainly in the western sector of the basin, whereas the oil fields are found in the eastern one. Reservoir rocks are well sorted to poorly, fine grained to pebbly sandstones and silstones of Miocene (Serravalian) to Pliocene age, deposited in deep water (turbidite), deltaic and littoral environments. Reservoir beds range in thickness from I to 40 in and are generally regionally distributed. The porosity varies from 3 to 37%, the permeability ranges from low values up to 2200-2500 mD. The minimal value of the porosity measured from oil flowing reservoirs varies from 12% to 16% and for the dry gas 12-21%. Geothermal gradient range from 1.4-2 C/100m. The dimensions of the reservoirs are very different and its geometric shape differs from beds to irregular shape. The types of the traps are also different : lithologo-stratigraphic, lithologic, structural-lithologic ones, etc. The upper part of the Pliocene basin belongs to the delta deposits. The deltaic sandstones are coarse grain to conglomeratic ones, of barriers type, saturated with fresh water and have vast distribution.

Hysen, K.N.; Skender, T.G. (Albpetrol Co., Fier (Albania))

1996-01-01

214

The model of the oil-gas bearing molasse reservoirs in the Peri-Adriatic depression, Albania  

SciTech Connect

The Peri-Adriatic Depression (PAD) represents the eastern extension of the Cenozoic Adriatic basin into onshore Albania. Several oil, gas condensate, dry gas fields have been discovered in this basin. Dry gas fields occur mainly in the western sector of the basin, whereas the oil fields are found in the eastern one. Reservoir rocks are well sorted to poorly, fine grained to pebbly sandstones and silstones of Miocene (Serravalian) to Pliocene age, deposited in deep water (turbidite), deltaic and littoral environments. Reservoir beds range in thickness from I to 40 in and are generally regionally distributed. The porosity varies from 3 to 37%, the permeability ranges from low values up to 2200-2500 mD. The minimal value of the porosity measured from oil flowing reservoirs varies from 12% to 16% and for the dry gas 12-21%. Geothermal gradient range from 1.4-2 C/100m. The dimensions of the reservoirs are very different and its geometric shape differs from beds to irregular shape. The types of the traps are also different : lithologo-stratigraphic, lithologic, structural-lithologic ones, etc. The upper part of the Pliocene basin belongs to the delta deposits. The deltaic sandstones are coarse grain to conglomeratic ones, of barriers type, saturated with fresh water and have vast distribution.

Hysen, K.N.; Skender, T.G. [Albpetrol Co., Fier (Albania)

1996-12-31

215

Enhanced gas-phase hydrogen-deuterium exchange of oligonucleotide and protein ions stored in an external multipole ion reservoir.  

PubMed

Rapid gas-phase hydrogen-deuterium (H-D) exchange from D(2)O and ND(3) into oligonucleotide and protein ions was achieved during storage in a hexapole ion reservoir. Deuterated gas is introduced through a capillary line that discharges directly into the low-pressure region of the reservoir. Following exchange, the degree of H-D exchange is determined using Fourier transform ion cyclotron resonance mass spectrometry. Gas-phase H-D exchange experiments can be conducted more than 100 times faster than observed using conventional in-cell exchange protocols that require lower gas pressures and additional pump-down periods. The short experimental times facilitate the quantitation of the number of labile hydrogens for less reactive proteins and structured oligonucleotides. For ubiquitin, we observe approximately 65 H-D exchanges after 20 s. Exchange rates of > 250 hydrogens s(-1) are observed for oligonucleotide ions when D(2)O or ND(3) is admitted directly into the external ion reservoir owing to the high local pressure in the hexapole. Partially deuterated oligonucleotide ions have been fragmented in the reservoir using infrared multiphoton dissociation (IRMPD). The resulting fragment ions show that exchange predominates at charged sites on the 5'- and 3'-ends of the oligonucleotide, whereas exchange is slower in the core. This hardware configuration is independent of the mass detector and should be compatible with other mass spectrometric platforms including quadrupole ion trap and time-of-flight mass spectrometers. PMID:10633235

Hofstadler, S A; Sannes-Lowery, K A; Griffey, R H

2000-01-01

216

Simulation of fracture fluid cleanup and its effect on long-term recovery in tight gas reservoirs  

E-print Network

proppants have been placed at a high enough concentration to “prop open” the fracture. The “effective length” is the portion of the propped fracture that cleans up and allows gas flow from the reservoir into the fracture then down the fracture...

Wang, Yilin

2009-05-15

217

Naturally fractured tight gas: Gas reservoir detection optimization. Quarterly report, January 1--March 31, 1997  

SciTech Connect

Economically viable natural gas production from the low permeability Mesaverde Formation in the Piceance Basin, Colorado requires the presence of an intense set of open natural fractures. Establishing the regional presence and specific location of such natural fractures is the highest priority exploration goal in the Piceance and other western US tight, gas-centered basins. Recently, Advanced Resources International, Inc. (ARI) completed a field program at Rulison Field, Piceance Basin, to test and demonstrate the use of advanced seismic methods to locate and characterize natural fractures. This project began with a comprehensive review of the tectonic history, state of stress and fracture genesis of the basin. A high resolution aeromagnetic survey, interpreted satellite and SLAR imagery, and 400 line miles of 2-D seismic provided the foundation for the structural interpretation. The central feature of the program was the 4.5 square mile multi-azimuth 3-D seismic P-wave survey to locate natural fracture anomalies. The interpreted seismic attributes are being tested against a control data set of 27 wells. Additional wells are currently being drilled at Rulison, on close 40 acre spacings, to establish the productivity from the seismically observed fracture anomalies. A similar regional prospecting and seismic program is being considered for another part of the basin. The preliminary results indicate that detailed mapping of fault geometries and use of azimuthally defined seismic attributes exhibit close correlation with high productivity gas wells. The performance of the ten new wells, being drilled in the seismic grid in late 1996 and early 1997, will help demonstrate the reliability of this natural fracture detection and mapping technology.

NONE

1997-12-31

218

Rapid Prediction of CO2 Movement in Aquifers, Coal Beds, and Oil and Gas Reservoirs  

NASA Astrophysics Data System (ADS)

Predictions of the mix of future primary energy sources often include significant use of fossil fuels, and scenarios envisioning a switch to renewable and/or nuclear primary energy sources rely on fossil fuels for the extended period required to install large-scale systems. Effective means of sequestering CO2 will be required to reduce emissions of CO2 in these scenarios. The earth's crust presents three major classes of geologic formation that appear suitable for long-term storage: deep formations containing salt water, unmineable coalbeds, and depleted oil and gas reservoirs. With injection into oil and gas reservoirs and coalbeds, it may be possible to recover net energy in concert with CO2 storage. If CO2 injection into geologic formations is undertaken on a large scale, high-resolution, but low computational cost, numerical methods will be needed. Such simulations may be used to predict where CO2 is likely to flow, interpret the volume and spatial distribution of the subsurface contacted by injectant, and optimize injection operations. These elements will certainly be necessary if geological sequestration is proven feasible and public acceptance is to be gained. In this paper, we present research on developing ultra-fast computational methods and tools applicable to the suite of geologic formations suitable for CO2 storage. The underpinnings of these methods are streamline-based computations. The flow field in 3D is decoupled into a series of 1D flow problems linked by common injection and boundary conditions. Periodically, streamline trajectories are updated as the pressure field in the volume under consideration evolves. The advantages of this approach are a reduction in the dimensionality of the numerical problem, the possibility to employ analytical solutions along each streamline, and a significant reduction in the effects of numerical dispersion. In contrast, conventional finite-difference based numerical techniques suffer from excessive numerical dispersion and long computation times. Finally, we demonstrate by calculation examples the different mechanisms controlling the displacement behavior of CO2 sequestration schemes, the interaction between flow and phase equilibrium and how proper design of injection gas composition and well completion are required to co-optimize oil production and CO2 storage.

Orr, F. M.; Jessen, K.; Kovscek, A.

2003-12-01

219

HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS  

SciTech Connect

This report outlines progress in the second quarter of the third year of the DOE project ''High Resolution Prediction of Gas Injection Process Performance for Heterogeneous Reservoirs''. This report presents results of an investigation of the effects of variation in interfacial tension (IFT) on three-phase relative permeability. We report experimental results that demonstrate the effect of low IFT between two of three phases on the three-phase relative permeabilities. In order to create three-phase systems, in which IFT can be controlled systematically, we employed analog liquids composing of hexadecane, n-butanol, isopropanol, and water. Phase composition, phase density and viscosity, and IFT of three-phase system were measured and are reported here. We present three-phase relative permeabilities determined from recovery and pressure drop data using the Johnson-Bossler-Naumann (JBN) method. The phase saturations were obtained from recovery data by the Welge method. The experimental results indicate that the wetting phase relative permeability was not affected by IFT variation whereas the other two-phase relative permeabilities were clearly affected. As IFT decreases the ''oil'' and ''gas'' phases become more mobile at the same phase saturations.

Franklin M. Orr, Jr.

2003-03-31

220

Surface-bounded reservoir compartmentalization in the Caddo Conglomerate, Boonsville (Bend Conglomerate) Gas Field, Fort Worth Basin, Texas  

SciTech Connect

Interpretation of cores and logs from 222 wells and a 26 mi[sup 2] 3-D seismic survey in the Boonsville (Bend Conglomerate) Gas Field indicates the Caddo Conglomerate zone (Atoka) contains two reservoir sandstone bodies which are physically separated by a key chronostratigraphic erosion surface. The oil-productive Lower Caddo sandstone represents a southward-prograding, strike-oriented highstand delta system. Downdip wells have encountered both oil and gas in a younger valley-fill sandstone complex comprising the Upper Caddo lowstand systems tract. Abandoned delta-platform limestones at the top of the Lower Caddo highstand tract were truncated during lowstand valley incision prior to Upper Caddo sandstone deposition. The limestones do not occur above the sharp-based, blocky to upward-fining Upper Caddo valley-fill sandstones, and underlying Lower Caddo sandstones typically display upward-coarsening, progradational patterns. Significant gas reserves in Upper Caddo wells located structurally downdip to the Lower Caddo oil accumulation indicate the two units are hydraulically separate reservoir compartments. Both reservoir compartments have been successfully imaged using 3-D seismic attributes analysis, confirming the original, log-based interpretation and providing a powerful infill drilling and reservoir management tool.

Carr, D.L. (Consulting Geologist, Austin, TX (United States)); Oliver, K.L. (Consulting Geophysicist, Houston, TX (United States))

1996-01-01

221

Surface-bounded reservoir compartmentalization in the Caddo Conglomerate, Boonsville (Bend Conglomerate) Gas Field, Fort Worth Basin, Texas  

SciTech Connect

Interpretation of cores and logs from 222 wells and a 26 mi{sup 2} 3-D seismic survey in the Boonsville (Bend Conglomerate) Gas Field indicates the Caddo Conglomerate zone (Atoka) contains two reservoir sandstone bodies which are physically separated by a key chronostratigraphic erosion surface. The oil-productive Lower Caddo sandstone represents a southward-prograding, strike-oriented highstand delta system. Downdip wells have encountered both oil and gas in a younger valley-fill sandstone complex comprising the Upper Caddo lowstand systems tract. Abandoned delta-platform limestones at the top of the Lower Caddo highstand tract were truncated during lowstand valley incision prior to Upper Caddo sandstone deposition. The limestones do not occur above the sharp-based, blocky to upward-fining Upper Caddo valley-fill sandstones, and underlying Lower Caddo sandstones typically display upward-coarsening, progradational patterns. Significant gas reserves in Upper Caddo wells located structurally downdip to the Lower Caddo oil accumulation indicate the two units are hydraulically separate reservoir compartments. Both reservoir compartments have been successfully imaged using 3-D seismic attributes analysis, confirming the original, log-based interpretation and providing a powerful infill drilling and reservoir management tool.

Carr, D.L. [Consulting Geologist, Austin, TX (United States); Oliver, K.L. [Consulting Geophysicist, Houston, TX (United States)

1996-12-31

222

Influence of environmental variables on diffusive greenhouse gas fluxes at hydroelectric reservoirs in Brazil.  

PubMed

For almost two decades, studies have been under way in Brazil, showing how hydroelectric reservoirs produce biogenic gases, mainly methane (CH4) and carbon dioxide (CO2), through the organic decomposition of flooded biomass. This somewhat complex phenomenon is due to a set of variables with differing levels of interdependence that directly or indirectly affect greenhouse gas (GHG) emissions. The purpose of this paper is to determine, through a statistical data analysis, the relation between CO2, CH4 diffusive fluxes and environmental variables at the Furnas, Itumbiara and Serra da Mesa hydroelectric reservoirs, located in the Cerrado biome on Brazil's high central plateau. The choice of this region was prompted by its importance in the national context, covering an area of some two million square kilometers, encompassing two major river basins (Paraná and Tocantins-Araguaia), with the largest installed power generation capacity in Brazil, together accounting for around 23% of Brazilian territory. This study shows that CH4 presented a moderate negative correlation between CO2 and depth. Additionally, a moderate positive correlation was noted for pH, water temperature and wind. The CO2 presented a moderate negative correlation for pH, wind speed, water temperature and air temperature. Additionally, a moderate positive correlation was noted for CO2 and water temperature. The complexity of the emission phenomenon is unlikely to occur through a simultaneous understanding of all the factors, due to difficulties in accessing and analyzing all the variables that have real, direct effects on GHG production and emission. PMID:24789391

Rogério, J P; Santos, M A; Santos, E O

2013-11-01

223

Investigation of gas hydrate-bearing sandstone reservoirs at the "Mount Elbert" stratigraphic test well, Milne Point, Alaska  

SciTech Connect

In February 2007, the U.S. Department of Energy, BP Exploration (Alaska), Inc., and the U.S. Geological Survey conducted an extensive data collection effort at the "Mount Elbert #1" gas hydrates stratigraphic test well on the Alaska North Slope (ANS). The 22-day field program acquired significant gas hydrate-bearing reservoir data, including a full suite of open-hole well logs, over 500 feet of continuous core, and open-hole formation pressure response tests. Hole conditions, and therefore log data quality, were excellent due largely to the use of chilled oil-based drilling fluids. The logging program confirmed the existence of approximately 30 m of gashydrate saturated, fine-grained sand reservoir. Gas hydrate saturations were observed to range from 60% to 75% largely as a function of reservoir quality. Continuous wire-line coring operations (the first conducted on the ANS) achieved 85% recovery through 153 meters of section, providing more than 250 subsamples for analysis. The "Mount Elbert" data collection program culminated with open-hole tests of reservoir flow and pressure responses, as well as gas and water sample collection, using Schlumberger's Modular Formation Dynamics Tester (MDT) wireline tool. Four such tests, ranging from six to twelve hours duration, were conducted. This field program demonstrated the ability to safely and efficiently conduct a research-level openhole data acquisition program in shallow, sub-permafrost sediments. The program also demonstrated the soundness of the program's pre-drill gas hydrate characterization methods and increased confidence in gas hydrate resource assessment methodologies for the ANS.

Boswell, R.M.; Hunter, R. (ASRC Energy Services, Anchorage, AK); Collett, T. (USGS, Denver, CO); Digert, S. (BP Exploration (Alaska) Inc., Anchorage, AK); Hancock, S. (RPS Energy Canada, Calgary, Alberta, Canada); Weeks, M. (BP Exploration (Alaska) Inc., Anchorage, AK); Mt. Elbert Science Team

2008-01-01

224

Full field reservoir modelling of Central Oman gas/condensate fields  

SciTech Connect

Gas reserves sufficient for a major export scheme have been found in Central Oman. To support appraisal and development planning of the gas/condensate fields, a dedicated, multi-disciplinary study team comprising both surface and subsurface engineers was assembled. The team fostered a high level of awareness of cross-disciplinary needs and challenges, resulting in timely data acquisition and a good fit between the various work-activities. The foundation of the subsurface contributions was a suite of advanced full-field reservoir models which: (1) provided production and well requirement forecasts; (2) quantified the impact of uncertainties on field performance and project costs; (3) supported the appraisal campaign; (4) optimised the field development plan; and (5) derived recovery factor ranges for reserves estimates. Geological/petrophysical uncertainties were quantified using newly-developed, 3-D probabilistic modelling tools. An efficient computing environment allowed a large number of sensitivities to be run in a timely, cost-effective manner. The models also investigated a key concern in gas/condensate fields: well impairment due to near-well condensate precipitation. Its impact was assessed using measured, capillary number-dependent, relative permeability curves. Well performance ranges were established on the basis of Equation of State single-well. simulations, and translated into the volatile oil full-field models using pseudo relative permeability curves for the wells. The models used the sparse available data in an optimal way and, as part of the field development plan, sustained confidence in the reserves estimates and the project, which is currently in the project specification phase.

Leemput, L.E.C. van de; Bertram, D.A.; Bentley, M.R. [and others

1995-12-31

225

Time-dependent deformation of gas shales - role of rock framework versus reservoir fluids  

NASA Astrophysics Data System (ADS)

Hydraulic fracturing operations are generally performed to achieve a fast, drastic increase of permeability and production rates. Although modeling of the underlying short-term mechanical response has proven successful via conventional geomechanical approaches, predicting long-term behavior is still challenging as the formation interacts physically and chemically with the fluids present in-situ. Recent experimental work has shown that shale samples subjected to a change in effective stress deform in a time-dependent manner ("creep"). Although the magnitude and nature of this behavior is strongly related to the composition and texture of the sample, also the choice of fluid used in the experiments affects the total strain response - strongly adsorbing fluids result in more, recoverable creep. The processes underlying time-dependent deformation of shales under in-situ stresses, and the long-term impact on reservoir performance, are at present poorly understood. In this contribution, we report triaxial mechanical tests, and theoretical/thermodynamic modeling work with the aim to identify and describe the main mechanisms that control time-dependent deformation of gas shales. In particular, we focus on the role of the shale solid framework versus the type and pressure of the present pore fluid. Our experiments were mainly performed on Eagle Ford Shale samples. The samples were subjected to cycles of loading and unloading, first in the dry state, and then again after equilibrating them with (adsorbing) CO2 and (non-adsorbing) He at fluid pressures of 4 MPa. Stresses were chosen close to those persisting under in-situ conditions. The results of our tests demonstrate that likely two main types of deformation mechanisms operate that relate to a) the presence of microfractures as a dominating feature in the solid framework of the shale, and b) the adsorbing potential of fluids present in the nanoscale voids of the shale. To explain the role of adsorption in the observed compaction creep, we postulate a serial coupling between 1) stress-driven desorption of the fluid species, 2) diffusion of the desorbed species out of the solid, and 3) consequent shrinkage. We propose a model in which the total shrinkage of the solid (Step 3) that is measured as bulk compaction, is driven by a change in stress state (Step 1), and evolves in time controlled by the diffusion characteristics of the system (Step 2). Our experimental and modeling study shows that both the nature of the solid framework of the shale, as well as the type and pressure of pore fluids affect the long-term in-situ mechanical behavior of gas shale reservoirs.

Hol, Sander; Zoback, Mark

2013-04-01

226

Monitoring of a gas reservoir in Western Siberia through SqueeSAR  

NASA Astrophysics Data System (ADS)

The success of surface movement monitoring using InSAR is critically dependent on the coherence of the radar signal though time and over space. As a result, rural areas are more difficult to monitor with this technology than are areas with a lot of infrastructure. The development of advanced algorithms exploiting distributed scatterers, such as SqueeSAR, has improved these possibilities considerably. However, in rural areas covered with varying quantities of snow and ice, it had not yet been possible to demonstrate the applicability of the technology. We performed a study to assess the applicability of InSAR for assessing land movement is Western Siberia, where we chose the area of the Yuznho Russkoye field for a detailed analysis, after a screening using data that involved a number of fields in the vicinity of the Yuznho Russkoye Field. A first evaluation with C-band data ranging from 2004 - 2010 was unsuccessful due to the small number of images. Therefore we investigated the applicability of X-band data. 75 images were available spanning a period spanning May 2012 until July 2013. Within the summer periods when there was no snow coverage, the X-band data showed good coherence. The subsidence during a summer season, however, was not sufficient to make a quantitative comparison between geomechanical predictions and geodetic observations. Including the winter season in the analysis, however, destroyed the coherence and no subsidence signal could be derived. Quite unexpectedly, however, by cutting out the winter season and using the two disconnected summer seasons simultaneously, the coherence re-appeared and a subsidence estimate was established covering the full period. This way, the temporal surface movement could be established as a function of the position in the field. The spatial subsidence distribution was subsequently compared with the expected pattern expected from the location of producing wells and was found to be show a good correlation. Subsidence was clearly concentrated in the areas with the most producing wells and therefore where the gas production was assumed to be the largest. The potential of the technology is to use the distribution of the subsidence pattern in combination with the gas production characteristics to better assess the flow properties of the reservoir. These characteristics include the sealing behavior of faults causing reservoir compartments and possible activity of connected aquifers.

Rucci, Alessio; Ferretti, Alessandro; Fokker, Peter A.; Jager, Johan; Lou, Sten

2014-05-01

227

DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS  

SciTech Connect

Borehole seismology is the highest resolution geophysical imaging technique available to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This proposal takes direct aim at this shortcoming. P/GSI is developing a 400 level 3C clamped downhole seismic receiver array for borehole seismic 3D imaging. This array will remove the acquisition barrier to record the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for economic use of 3D borehole seismic imaging for reservoir characterization and monitoring. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore facilitate 9C reservoir imaging. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

Bjorn N.P. Paulsson

2002-09-01

228

DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS  

SciTech Connect

Borehole seismology is the highest resolution geophysical imaging technique available to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This proposal takes direct aim at this shortcoming. P/GSI is developing a 400 level 3C clamped downhole seismic receiver array for borehole seismic 3D imaging. This array will remove the acquisition barrier to record the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for economic use of 3D borehole seismic imaging for reservoir characterization and monitoring. By using 3C surface seismic or borehole seismic sources the 400 level receiver array will furthermore facilitate 9C reservoir imaging. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

Bjorn N.P Paulsson

2002-05-01

229

A MASSIVE MOLECULAR GAS RESERVOIR IN THE z = 5.3 SUBMILLIMETER GALAXY AzTEC-3  

SciTech Connect

We report the detection of CO J = 2{yields}1, 5{yields}4, and 6{yields}5 emission in the highest-redshift submillimeter galaxy (SMG) AzTEC-3 at z = 5.298, using the Expanded Very Large Array and the Plateau de Bure Interferometer. These observations ultimately confirm the redshift, making AzTEC-3 the most submillimeter-luminous galaxy in a massive z {approx_equal} 5.3 protocluster structure in the COSMOS field. The strength of the CO line emission reveals a large molecular gas reservoir with a mass of 5.3 x 10{sup 10}({alpha}{sub CO}/0.8) M {sub sun}, which can maintain the intense 1800 M {sub sun} yr{sup -1} starburst in this system for at least 30 Myr, increasing the stellar mass by up to a factor of six in the process. This gas mass is comparable to 'typical' z {approx} 2 SMGs and constitutes {approx_gt}80% of the baryonic mass (gas+stars) and 30%-80% of the total (dynamical) mass in this galaxy. The molecular gas reservoir has a radius of <4 kpc and likely consists of a 'diffuse', low-excitation component, containing (at least) 1/3 of the gas mass (depending on the relative conversion factor {alpha}{sub CO}), and a 'dense', high-excitation component, containing {approx}2/3 of the mass. The likely presence of a substantial diffuse component besides highly excited gas suggests different properties between the star-forming environments in z > 4 SMGs and z > 4 quasar host galaxies, which perhaps trace different evolutionary stages. The discovery of a massive, metal-enriched gas reservoir in an SMG at the heart of a large z = 5.3 protocluster considerably enhances our understanding of early massive galaxy formation, pushing back to a cosmic epoch where the universe was less than 1/12 of its present age.

Riechers, Dominik A.; Scoville, Nicholas Z. [Astronomy Department, California Institute of Technology, MC 249-17, 1200 East California Boulevard, Pasadena, CA 91125 (United States); Capak, Peter L.; Yan, Lin [Spitzer Science Center, California Institute of Technology, MC 220-6, 1200 East California Boulevard, Pasadena, CA 91125 (United States); Carilli, Christopher L. [National Radio Astronomy Observatory, P.O. Box O, Socorro, NM 87801 (United States); Cox, Pierre; Neri, Roberto [Institut de RadioAstronomie Millimetrique, 300 Rue de la Piscine, Domaine Universitaire, 38406 Saint Martin d'Heres (France); Schinnerer, Eva [Max-Planck-Institut fuer Astronomie, Koenigstuhl 17, D-69117 Heidelberg (Germany); Bertoldi, Frank, E-mail: dr@caltech.ed [Argelander-Institut fuer Astronomie, Universitaet Bonn, Auf dem Huegel 71, Bonn, D-53121 (Germany)

2010-09-10

230

Confirming the Discovery of Massive 10^6 K Gas Reservoirs in Spiral-Rich Galaxy Groups  

NASA Astrophysics Data System (ADS)

Due to the unprecedented quality of far-UV spectra now being delivered by the Cosmic Origins Spectrograph on HST, we have discovered several examples of broad, shallow Ly-alpha and OVI absorption lines which appears to be 10^6 K gas in the vicinity of small groups of spiral galaxies. Because COS observations provide only pencil-beam probes through this gas, its full extent is not known by direct observation. But if this gas is >600 kpc in extent it contains >10^11 solar masses of gas and is a major reservoir of baryons and metals surrounding spiral galaxies. If this inference is correct, the presence of the hot gas in spiral-rich groups like the Local Group has significant implications for the cosmic baryon census ( 20% of the total) and galactic chemical evolution modeling (accretion reservoir for low metallicity gas). Here we propose to use GEMINI-N/GMOS multi-object spectroscopy to confirm this interpretation by verifying the presence of small spiral-rich groups around each absorber and determining if the velocity dispersion of the group matches the Ly -alpha and OVI thermal line widths. We propose our four best sight lines, containing seven OVI absorbers at z=0.06-0.14 based on COS and FUSE spectroscopy.

Keeney, Brian; Stocke, John; Syphers, David; Danforth, Charles; Wakker, Bart; Savage, Blair; Morris, Simon

2014-02-01

231

Well-test analysis for solution-gas-drive reservoirs: Part 1; Determination of relative and absolute permeabilities  

SciTech Connect

For transient radial flow to a well producing a solution-gas-drive reservoir, it is shown that estimates of effective phase permeabilities as functions of pressure can be obtained directly from the measured flowing wellbore pressure and the flow rates. Rough estimates of effective permeabilities as functions of oil saturation also can be obtained. It is also shown that a semilog plot of pressure squared vs. time can be used to estimate effective permeabilities and the skin factor.

Serra, K.V.; Peres, A.M.M. (PETROBRAS, Rio de Janeiro, RJ (Brazil)); Reynolds, A.C. (Tulsa Univ., OK (USA))

1990-06-01

232

Secondary natural gas recovery: Targeted applications for infield reserve growth in midcontinent reservoirs, Boonsville Field, Fort Worth Basin, Texas. Topical report, May 1993--June 1995  

SciTech Connect

The objectives of this project are to define undrained or incompletely drained reservoir compartments controlled primarily by depositional heterogeneity in a low-accommodation, cratonic Midcontinent depositional setting, and, afterwards, to develop and transfer to producers strategies for infield reserve growth of natural gas. Integrated geologic, geophysical, reservoir engineering, and petrophysical evaluations are described in complex difficult-to-characterize fluvial and deltaic reservoirs in Boonsville (Bend Conglomerate Gas) field, a large, mature gas field located in the Fort Worth Basin of North Texas. The purpose of this project is to demonstrate approaches to overcoming the reservoir complexity, targeting the gas resource, and doing so using state-of-the-art technologies being applied by a large cross section of Midcontinent operators.

Hardage, B.A.; Carr, D.L.; Finley, R.J.; Tyler, N.; Lancaster, D.E.; Elphick, R.Y.; Ballard, J.R.

1995-07-01

233

Implementation of the Ensemble Kalman Filter in the Characterization of Hydraulic Fractures in Shale Gas Reservoirs by Integrating Downhole Temperature Sensing Technology  

E-print Network

Multi-stage hydraulic fracturing in horizontal wells has demonstrated successful results for developing unconventional low-permeability oil and gas reservoirs. Despite being vastly implemented by different operators across North America, hydraulic...

Moreno, Jose A

2014-08-12

234

Characterization of oil and gas reservoir heterogeneity. Technical progress report, July 1, 1992--September 30, 1992  

SciTech Connect

The ultimate oojective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization--determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis--source rock identification; and the study of asphaltene precipitation for Alaskan crude oils. This report presents a summary of technical progress of the well log analysis of Kuparuk Field, Northslope, Alaska.

Sharma, G.D.

1992-12-01

235

Sedimentology and permeability architecture of Atokan Valley-Fill natural gas reservoirs, Boonsville Field, North-Central Texas  

SciTech Connect

The Boonsville {open_quotes}Bend Conglomerate{close_quotes} gas field in Jack and Wise Counties comprises numerous thin (10-20 ft) conglomeratic sandstone reservoirs within an approximately 1,000-ft-thick section of Atokan strata. Reservoir sandstone bodies commonly overlie sequence-boundary unconformities and exhibit overall upward-fining grain-size trends. Many represent incised valley-fill deposits that accumulated during postunconformity base-level rise. This stratal architectures is repeated at several levels throughout the Bend Conglomerate, suggesting that sediment accumulation occurred in a moderate- to low-accommodation setting and that base level fluctuated frequently. The reservoir units were deposited by low-sinuosity fluvial processes, causing a hierarchy of bed forms and grain-avalanche bar-front processes to produce complex grain-size variations. Permeability distribution is primarily controlled by depositional factors but may also be affected by secondary porosity created by the selective dissolution of chert clasts. High-permeability zones ({approximately}2.8 darcys) are characterized by macroscopic vugs composed of clast-shaped moldic voids ({approximately}5 mm in diameter). Tight (low-permeability) zones are heavily cemented by silica, calcite, dolomite, and ankerite and siderate cements. Minipermeameter, x-radiography, and petrographic studies and facies analysis conducted on cores from two Bend Conglomerate reservoirs (Threshold Development Company, I.G. Yates 33, and OXY U.S.A. Sealy {open_quotes}C{close_quotes} 2) illustrate the hierarchy of sedimentological and diagenetic controls on permeability architecture.

Burn, M.J.; Carr, D.L. [Univ. of Texas, Austin, TX (United States); Stuede, J. [Scientific Measurement Systems, Inc., Austin, TX (United States)

1994-12-31

236

Sedimentology and permeability architecture of Atokan Valley-fill natural gas reservoirs, Boonsville Field, north-central Texas  

SciTech Connect

The Boonsville {open_quotes}Bend Conglomerate{close_quotes} gas field in Jack and Wise counties comprises numerous thin (10-20 ft) conglomerate sandstone reservoirs within an approximately 1000-ft-thick section of Atokan strata. Reservoir sandstone bodies commonly overlie sequence-boundary unconformities and exhibit overall upward-fining grain-size trends. Many represent incised valleyfill deposits that accumulated during postunconformity baselevel rise. This stratal architecture is repeated at several levels throughout the Bend Conglomerate, suggesting that sediment accumulation occurred in a moderate-to low-accommodation setting and that base level fluctuated frequently. The reservoir units were deposited by low-sinuosity fluvial processes, causing a hierarchy of bed forms and grain-avalanche bar-front processes to produce complex grain-size variations. Permeability distribution is primarily controlled by depositional factors but may also be affected by secondary porosity created by the selective dissolution of chert clasts. High-permeability zones (up to 2.8 darcys) are characterized by macroscopic vugs comprised of clast-shaped moldic voids (up to 5 mm in diameter). Tight (low-permeability) zones are heavily cemented by silica, calcite, dolomite, and ankerite and siderite cements. Minipermeameter, x-radiograph, and petrographic studies and facies analysis conducted on cores from two Bend Conglomerate reservoirs illustrate the hierarchy of sedimentological and diagenetic controls on permeability architecture.

Burn, M.J.; Carr, D.L. [Univ. of Texas, Austin, TX (United States); Stuede, J. [Scientific Measurement Systems, Inc., Austin, TX (United States)

1994-09-01

237

A reservoir of ionized gas in the galactic halo to sustain star formation in the Milky Way.  

PubMed

Without a source of new gas, our Galaxy would exhaust its supply of gas through the formation of stars. Ionized gas clouds observed at high velocity may be a reservoir of such gas, but their distances are key for placing them in the galactic halo and unraveling their role. We have used the Hubble Space Telescope to blindly search for ionized high-velocity clouds (iHVCs) in the foreground of galactic stars. We show that iHVCs with 90 ? |v(LSR)| ? 170 kilometers per second (where v(LSR) is the velocity in the local standard of rest frame) are within one galactic radius of the Sun and have enough mass to maintain star formation, whereas iHVCs with |v(LSR)| ? 170 kilometers per second are at larger distances. These may be the next wave of infalling material. PMID:21868626

Lehner, Nicolas; Howk, J Christopher

2011-11-18

238

Detection of gas in sandstone reservoirs using AVO analysis: A 3-D seismic case history using the Geostack technique  

SciTech Connect

The Geostack technique is a method of analyzing seismic amplitude variation with offset (AVO) information. One of the outputs of the analysis is a set of direct hydrocarbon indicator traces called fluid factor traces. The fluid factor trace is designed to be low amplitude for all reflectors in a clastic sedimentary sequence except for rocks that lie off the mudrock line. The mudrock line is the line on a crossplot of P-wave velocity against S-wave velocity on which water-saturated sandstones, shales, and siltstones lie. Some of the rock types that lie off the mudrock line are gas-saturated sandstones, carbonates, and igneous rocks. In the absence of carbonates and igneous rocks, high amplitude reflections on fluid factor traces would be expected to represent gas-saturated sandstones. Of course, this relationship does not apply exactly in nature, and the extent to which the mudrock line model applies varies from area to area. However, it is a useful model in many basins of the world, including the one studied here. Geostack processing has been done on a 3-D seismic data set over the Mossel Bay gas field on the southern continental shelf of South Africa. The authors found that anomalously high amplitude fluid factor reflections occurred at the top and base of the gas-reservoir sandstone. Maps were made of the amplitude of these fluid factor reflections, and it was found that the high amplitude values were restricted mainly to the gas field area as determined by drilling. The highest amplitudes were found to be located roughly in the areas of best reservoir quality (i.e., highest porosity) in areas where the reservoir is relatively thick.

Fatti, J.L.; Smith, G.C.; Vail, P.J.; Strauss, P.J.; Levitt, P.R. (Soekor, Parow (South Africa))

1994-09-01

239

Preliminary formation analysis for compressed air energy storage in depleted natural gas reservoirs : a study for the DOE Energy Storage Systems Program.  

SciTech Connect

The purpose of this study is to develop an engineering and operational understanding of CAES performance for a depleted natural gas reservoir by evaluation of relative permeability effects of air, water and natural gas in depleted natural gas reservoirs as a reservoir is initially depleted, an air bubble is created, and as air is initially cycled. The composition of produced gases will be evaluated as the three phase flow of methane, nitrogen and brine are modeled. The effects of a methane gas phase on the relative permeability of air in a formation are investigated and the composition of the produced fluid, which consists primarily of the amount of natural gas in the produced air are determined. Simulations of compressed air energy storage (CAES) in depleted natural gas reservoirs were carried out to assess the effect of formation permeability on the design of a simple CAES system. The injection of N2 (as a proxy to air), and the extraction of the resulting gas mixture in a depleted natural gas reservoir were modeled using the TOUGH2 reservoir simulator with the EOS7c equation of state. The optimal borehole spacing was determined as a function of the formation scale intrinsic permeability. Natural gas reservoir results are similar to those for an aquifer. Borehole spacing is dependent upon the intrinsic permeability of the formation. Higher permeability allows increased injection and extraction rates which is equivalent to more power per borehole for a given screen length. The number of boreholes per 100 MW for a given intrinsic permeability in a depleted natural gas reservoir is essentially identical to that determined for a simple aquifer of identical properties. During bubble formation methane is displaced and a sharp N2methane boundary is formed with an almost pure N2 gas phase in the bubble near the borehole. During cycling mixing of methane and air occurs along the boundary as the air bubble boundary moves. The extracted gas mixture changes as a function of time and proximity of the bubble boundary to the well. For all simulations reported here, with a formation radius above 50 m the maximum methane composition in the produced gas phase was less than 0.5%. This report provides an initial investigation of CAES in a depleted natural gas reservoir, and the results will provide useful guidance in CAES system investigation and design in the future.

Gardner, William Payton

2013-06-01

240

Petrophysical Analysis and Geographic Information System for San Juan Basin Tight Gas Reservoirs  

SciTech Connect

The primary goal of this project is to increase the availability and ease of access to critical data on the Mesaverde and Dakota tight gas reservoirs of the San Juan Basin. Secondary goals include tuning well log interpretations through integration of core, water chemistry and production analysis data to help identify bypassed pay zones; increased knowledge of permeability ratios and how they affect well drainage and thus infill drilling plans; improved time-depth correlations through regional mapping of sonic logs; and improved understanding of the variability of formation waters within the basin through spatial analysis of water chemistry data. The project will collect, integrate, and analyze a variety of petrophysical and well data concerning the Mesaverde and Dakota reservoirs of the San Juan Basin, with particular emphasis on data available in the areas defined as tight gas areas for purpose of FERC. A relational, geo-referenced database (a geographic information system, or GIS) will be created to archive this data. The information will be analyzed using neural networks, kriging, and other statistical interpolation/extrapolation techniques to fine-tune regional well log interpretations, improve pay zone recognition from old logs or cased-hole logs, determine permeability ratios, and also to analyze water chemistries and compatibilities within the study area. This single-phase project will be accomplished through four major tasks: Data Collection, Data Integration, Data Analysis, and User Interface Design. Data will be extracted from existing databases as well as paper records, then cleaned and integrated into a single GIS database. Once the data warehouse is built, several methods of data analysis will be used both to improve pay zone recognition in single wells, and to extrapolate a variety of petrophysical properties on a regional basis. A user interface will provide tools to make the data and results of the study accessible and useful. The final deliverable for this project will be a web-based GIS providing data, interpretations, and user tools that will be accessible to anyone with Internet access. During this project, the following work has been performed: (1) Assimilation of most special core analysis data into a GIS database; (2) Inventorying of additional data, such as log images or LAS files that may exist for this area; (3) Analysis of geographic distribution of that data to pinpoint regional gaps in coverage; (4) Assessment of the data within both public and proprietary data sets to begin tuning of regional well logging analyses and improve payzone recognition; (5) Development of an integrated web and GIS interface for all the information collected in this effort, including data from northwest New Mexico; (6) Acquisition and digitization of logs to create LAS files for a subset of the wells in the special core analysis data set; and (7) Petrophysical analysis of the final set of well logs.

Martha Cather; Robert Lee; Robert Balch; Tom Engler; Roger Ruan; Shaojie Ma

2008-10-01

241

HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS  

SciTech Connect

This report outlines progress in the first quarter of the extension of the DOE project ''High Resolution Prediction of Gas Injection Process Performance for Heterogeneous Reservoirs''. This report presents experimental results that demonstrate combined scaling effects of viscous, capillary, and gravity crossflow mechanisms that apply to the situations in which streamline models are used. We designed and ran a series of experiments to investigate combined effects of capillary, viscous, and gravity forces on displacement efficiency in layered systems. Analog liquids (isooctane, isopropanol, and water) were employed to control scaling parameters by changing interfacial tension (IFT), flow rate, and density difference. The porous medium was a two-dimensional (2-D) 2-layered glass bead model with a permeability ratio of about 1:4. In order to analyze the combined effect of only capillary and viscous forces, gravity effects were eliminated by changing the orientation of the glass bead model. We employed a commercial simulator, Eclipse100 to calculate displacement behavior for comparison with the experimental data. Experimental results with minimized gravity effects show that the IFT and flow rate determine how capillary and viscous forces affect behavior of displacement. The limiting behavior for scaling groups for two-phase displacement was verified by experimental results. Analysis of the 2-D images indicates that displacements having a capillary-viscous equilibrium give the best sweep efficiency. Experimental results with gravity effects, but with low IFT fluid systems show that slow displacements produce larger area affected by crossflow. This, in turn, enhances sweep efficiency. The simulation results represent the experimental data well, except for the situations where capillary forces dominate the displacement.

Franklin M. Orr, Jr.

2003-09-30

242

Evaluating reservoir production strategies in miscible and immiscible gas-injection projects  

E-print Network

, comprehensive reservoir engineering and project monitoring are necessary for typical miscible flood projects than for other recovery methods. This project evaluated effects of important factors such as injection pressure, vertical-to-horizontal permeability...

Farzad, Iman

2004-11-15

243

Layered Pseudo-Steady-State Models for tight commingled gas reservoirs  

E-print Network

follows the style of the Jouma1 of PerroIeurn Technology, In 1945, Arps' presented empirical equations for decline curves (exponential, hyperbolic, and harmonic). Although his work was mainly based on observation and analysis, it furnished... the foundation of decline curve analysis techniques. In his work, Arps found that if we are dealing with ideal reservoirs where water drive is absent and reservoir pressure is proportional to the amount of remaining oil and also if the productivity indexes...

El-Banbi, Ahmed

1995-01-01

244

Characterization of gas hydrate reservoirs by integration of core and log data in the Ulleung Basin, East Sea  

USGS Publications Warehouse

Examinations of core and well-log data from the Second Ulleung Basin Gas Hydrate Drilling Expedition (UBGH2) drill sites suggest that Sites UBGH2-2_2 and UBGH2-6 have relatively good gas hydrate reservoir quality in terms of individual and total cumulative thicknesses of gas-hydrate-bearing sand (HYBS) beds. In both of the sites, core sediments are generally dominated by hemipelagic muds which are intercalated with turbidite sands. The turbidite sands are usually thin-to-medium bedded and mainly consist of well sorted coarse silt to fine sand. Anomalies in infrared core temperatures and porewater chlorinity data and pressure core measurements indicate that “gas hydrate occurrence zones” (GHOZ) are present about 68–155 mbsf at Site UBGH2-2_2 and 110–155 mbsf at Site UBGH2-6. In both the GHOZ, gas hydrates are preferentially associated with many of the turbidite sands as “pore-filling” type hydrates. The HYBS identified in the cores from Site UBGH2-6 are medium-to-thick bedded particularly in the lower part of the GHOZ and well coincident with significant high excursions in all of the resistivity, density, and velocity logs. Gas-hydrate saturations in the HYBS range from 12% to 79% with an average of 52% based on pore-water chlorinity. In contrast, the HYBS from Site UBGH2-2_2 are usually thin-bedded and show poor correlations with both of the resistivity and velocity logs owing to volume averaging effects of the logging tools on the thin HYBS beds. Gas-hydrate saturations in the HYBS range from 15% to 65% with an average of 37% based on pore-water chlorinity. In both of the sites, large fluctuations in biogenic opal contents have significant effects on the sediment physical properties, resulting in limited usage of gamma ray and density logs in discriminating sand reservoirs.

Bahk, J.-J.; Kim, G.-Y.; Chun, J.-H.; Kim, J.-H.; Lee, J.Y.; Ryu, B.-J.; Lee, J.-H.; Son, B.-K.; Collett, Timothy S.

2013-01-01

245

Detailed evaluation of gas hydrate reservoir properties using JAPEX/JNOC/GSC Mallik 2L-38 gas hydrate research well downhole well-log displays  

USGS Publications Warehouse

The JAPEX/JNOC/GSC Mallik 2L-38 gas hydrate research well project was designed to investigate the occurrence of in situ natural gas hydrate in the Mallik area of the Mackenzie Delta of Canada. Because gas hydrate is unstable at surface pressure and temperature conditions, a major emphasis was placed on the downhole logging program to determine the in situ physical properties of the gas-hydrate-bearing sediments. Downhole logging tool strings deployed in the Mallik 2L-38 well included the Schlumberger Platform Express with a high resolution laterolog, Array Induction Imager Tool, Dipole Shear Sonic Imager, and a Fullbore Formation Microlmager. The downhole log data obtained from the log- and core-inferred gas-hydrate-bearing sedimentary interval (897.25-1109.5 m log depth) in the Mallik 2L-38 well is depicted in a series of well displays. Also shown are numerous reservoir parameters, including gas hydrate saturation and sediment porosity log traces, calculated from available downhole well-log and core data. The gas hydrate accumulation delineated by the Mallik 2L-38 well has been determined to contain as much as 4.15109 m3 of gas in the 1 km2 area surrounding the drill site.

Collett, T.S.

1999-01-01

246

Greenhouse Gas Emissions from U.S. Hydropower Reservoirs: FY2011 Annual Progress Report  

SciTech Connect

The primary objective of this study is to quantify the net emissions of key greenhouse gases (GHG) - notably, CO{sub 2} and CH{sub 4} - from hydropower reservoirs in moist temperate areas within the U.S. The rationale for this objective is straightforward: if net emissions of GHG can be determined, it would be possible to directly compare hydropower to other power-producing methods on a carbon-emissions basis. Studies of GHG emissions from hydropower reservoirs elsewhere suggest that net emissions can be moderately high in tropical areas. In such areas, warm temperatures and relatively high supply rates of labile organic matter can encourage high rates of decomposition, which (depending upon local conditions) can result in elevated releases of CO{sub 2} and CH{sub 4}. CO{sub 2} and CH{sub 4} emissions also tend to be higher for younger reservoirs than for older reservoirs, because vegetation and labile soil organic matter that is inundated when a reservoir is created can continue to decompose for several years (Galy-Lacaux et al. 1997, Barros et al. 2011). Water bodies located in climatically cooler areas, such as in boreal forests, could be expected to have lower net emissions of CO{sub 2} and CH{sub 4} because their organic carbon supplies tend to be relatively recalcitrant to microbial action and because cooler water temperatures are less conducive to decomposition.

Stewart, Arthur J [ORNL; Mosher, Jennifer J [ORNL; Mulholland, Patrick J [ORNL; Fortner, Allison M [ORNL; Phillips, Jana Randolph [ORNL; Bevelhimer, Mark S [ORNL

2012-05-01

247

Diagenesis and fluid evolution of deeply buried Permian (Rotliegende) gas reservoirs, Northwest Germany  

SciTech Connect

Depositional environment and tectonic setting were important in the diagenesis and evolution of reservoir properties in the Rotliegende sequence of the North German Basin. Facies belts paralleling the edge of a central saline lake controlled the distribution of early and shallow burial cements. Lake shoreline sands with radial chlorite cement show the best reservoir properties in the study area. Juxtaposition of Rotliegende deposits against either Carboniferous Coal Measures or Late Permian (Zechstein) evaporites by faulting resulted in cross-formational fluid exchange. The introduction of fluids from Carboniferous Coal Measures into Rotliegende reservoirs produced intense clay cementation, significantly reducing rock permeabilities. Influx of Zechstein fluids favored precipitation of late carbonate and anhydrite cements. Cross-formational and fault-related fluid flow was enhanced during periods of fault activity. 50 refs., 15 figs., 1 tab.

Gaupp, R. (Johannes Gutenberg Universitaet, Mainz (Germany)); Matter, A.; Ramseyer, K.; Platt, J. (Geologisches Institute der Universitaet, Bern (Switzerland)); Walzebuck, J. (NAM Nederlands Aardolie Maatschappij, Assen (Netherlands))

1993-07-01

248

Characterization of oil and gas reservoir heterogeneity. Annual report, November 1, 1990--October 31, 1991  

SciTech Connect

The objective of the cooperative research program is to characterize Alaskan reservoirs in terms of their reserves, physical and chemical properties, geologic configuration and structure, and the development potential. The tasks completed during this period include: (1) geologic reservoir description of Endicott Field; (2) petrographic characterization of core samples taken from selected stratigraphic horizons of the West Sak and Ugnu (Brookian) wells; (3) development of a polydispersed thermodynamic model for predicting asphaltene equilibria and asphaltene precipitation from crude oil-solvent mixtures, and (4) preliminary geologic description of the Milne Point Unit.

Not Available

1991-12-31

249

Development of a 400 Level 3C Clamped Downhole Seismic Receiver Array for 3D Borehole Seismic Imaging of Gas Reservoirs  

SciTech Connect

Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently hampered by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. Massive 3D VSP{reg_sign} and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver arrays will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

Bjorn N.P. Paulsson

2005-08-21

250

DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS  

SciTech Connect

Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. Massive 3D VSP{reg_sign} and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver arrays will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

Bjorn N.P. Paulsson

2004-09-30

251

DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS  

SciTech Connect

Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

Bjorn N.P Paulsson

2003-07-01

252

DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS  

SciTech Connect

Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

Bjorn N.P Paulsson

2003-09-01

253

DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS.  

SciTech Connect

Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

Bjorn N.P Paulsson

2003-01-01

254

DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS  

SciTech Connect

Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

Bjorn N.P. Paulsson

2002-12-01

255

Development of a 400 Level 3C Clamped Downhole Seismic Receiver Array for 3D Borehole Seismic Imaging of Gas Reservoirs  

SciTech Connect

Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently hampered by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. Massive 3D VSP{reg_sign} and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver arrays will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

Bjorn N. P. Paulsson

2005-09-30

256

DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS  

SciTech Connect

Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

Bjorn N.P. Paulsson

2004-05-31

257

DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS  

SciTech Connect

Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

Bjorn N.P. Paulsson

2004-06-30

258

Development of a 400 Level 3C Clamped Downhole Seismic Receiver Array for 3D Borehole Seismic Imaging of Gas Reservoirs  

SciTech Connect

Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently hampered by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. Massive 3D VSP{reg_sign} and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver arrays will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

Bjorn N.P Paulsson

2006-05-05

259

DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS  

SciTech Connect

Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

Bjorn N.P. Paulsson

2003-12-01

260

DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS  

SciTech Connect

Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

Bjorn N.P. Paulsson

2004-05-01

261

DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS  

SciTech Connect

Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently hampered by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. Massive 3D VSP{reg_sign} and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver arrays will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

Bjorn N.P. Paulsson

2005-03-31

262

DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS  

SciTech Connect

Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. Massive 3D VSP{reg_sign} and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver arrays will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

Bjorn N.P. Paulsson

2004-12-31

263

FRACTURE MODELING AND FAULT ZONE CHARACTERISTICS APPLIED TO RESERVOIR CHARACTERIZATION OF THE RULISON GAS FIELD,  

E-print Network

FRACTURE MODELING AND FAULT ZONE CHARACTERISTICS APPLIED TO RESERVOIR CHARACTERIZATION the interpretation of three dimensional seismic. Shale Gouge Ratios along the seismically mapped fault surfaces have the dilation tendency of faults and fractures within the field to be calculated and analyzed. The mapped faults

264

Numerical Simulation and Multiple Realizations for Sensitivity Study of Shale Gas Reservoir  

E-print Network

SPE 141058 Numerical Simulation and Multiple Realizations for Sensitivity Study of Shale Gas. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Shale gas in the United States the largest conventional gas accumulations in the world. Shale gas success is directly the result

Mohaghegh, Shahab

265

The interplay of fractures and sedimentary architecture: Natural gas from reservoirs in the Molina sandstones, Piceance Basin, Colorado  

SciTech Connect

The Molina Member of the Wasatch Formation produces natural gas from several fields along the Colorado River in the Piceance Basin, northwestern Colorado. The Molina Member is a distinctive sandstone that was deposited in a unique fluvial environment of shallow-water floods. This is recorded by the dominance of plane-parallel bedding in many of the sandstones. The Molina sandstones crop out on the western edge of the basin, and have been projected into the subsurface and across the basin to correlate with thinner sandy units of the Wasatch Formation at the eastern side of the basin. Detailed study, however, has shown that the sedimentary characteristics of the type-section Molina sandstones are incompatible with a model in which the eastern sandstones are its distal facies equivalent. Rather, the eastern sandstones represent separate and unrelated sedimentary systems that prograded into the basin from nearby source-area highlands. Therefore, only the subsurface {open_quotes}Molina{close_quotes} reservoirs that are in close proximity to the western edge of the basin are continuous with the type-section sandstones. Reservoirs in the Grand Valley and Rulison gas fields were deposited in separate fluvial systems. These sandstones contain more typical fluvial sedimentary structures such as crossbeds and lateral accretion surfaces. Natural fractures play an important role in enhancing the conductivity and permeability of the Molina and related sandstones of the Wasatch Formation.

Lorenz, J.C.

1997-03-01

266

The Influence of Local and Large-Scale Environment on Galaxy Gas Reservoirs in the RESOLVE Survey  

NASA Astrophysics Data System (ADS)

There is growing evidence to suggest galaxy gas reservoirs have been replenished over time, but a clear picture of how this process depends on local and large-scale environment is still an active area of research. I will present an analysis of galaxy gas content with respect to environment using the ~90% complete 21cm census for the volume-limited RESOLVE survey, which yields an unbiased inventory of HI masses (or strong upper limits < 5-10% of the stellar mass) for ~1550 galaxies with baryonic mass greater than 109 M? in >50,000 cubic Mpc of the z=0 universe. We quantify large-scale environment via identification of cosmic web filaments and walls using a modified friends-of-friends technique, while also using photometric redshifts to identify additional potential companions around each galaxy. Combining this powerful data set with estimates of HI profile asymmetries and star formation histories, we examine whether there are local or large-scale environments where cold gas accretion is more effective. Specifically, we investigate whether galaxy interactions can induce enhanced HI content. We also explore whether galaxies residing in large-scale filaments or walls, where simulations show large-scale gas flows, display signatures of enhanced gas accretion relative to other large-scale environments. This project is supported by NSF funding for the RESOLVE survey (AST-0955368), the GBT Student Observing Support program, and a UNC Royster Society of Fellows Dissertation Completion Fellowship.

Stark, David V.; Kannappan, Sheila; Baker, Ashley; Berlind, Andreas A.; Burchett, Joseph; Eckert, Kathleen D.; Florez, Jonathan; Hall, Kirsten; Haynes, Martha P.; Giovanelli, Riccardo; Gonzalez, Roberto; Guynn, David; Hoversten, Erik A.; Leroy, Adam K.; Moffett, Amanda J.; Pisano, Daniel J.; Watson, Linda C.; Wei, Lisa H.; Resolve Team

2015-01-01

267

Effect of flue gas impurities on the process of injection and storage of carbon dioxide in depleted gas reservoirs  

E-print Network

sequestration. In this thesis, I report my findings on the effect of flue gas ??impurities?? on the displacement of natural gas during CO2 sequestration, and results on unconfined compressive strength (UCS) tests to carbonate samples. In displacement experiments...

Nogueira de Mago, Marjorie Carolina

2005-11-01

268

Nonassociated gas resources in low-permeability sandstone reservoirs, lower tertiary Wasatch Formation, and upper Cretaceous Mesaverde Group, Uinta Basin, Utah  

SciTech Connect

The US Geological Survey recognizes six major plays for nonassociated gas in Tertiary and Upper Cretaceous low-permeability strata of the Uinta Basin, Utah. For purposes of this study, plays without gas/water contacts are separated from those with such contacts. Continuous-saturation accumulations are essentially single fields, so large in areal extent and so heterogeneous that their development cannot be properly modeled as field growth. Fields developed in gas-saturated plays are not restricted to structural or stratigraphic traps and they are developed in any structural position where permeability conduits occur such as that provided by natural open fractures. Other fields in the basin have gas/water contacts and the rocks are water-bearing away from structural culmination`s. The plays can be assigned to two groups. Group 1 plays are those in which gas/water contacts are rare to absent and the strata are gas saturated. Group 2 plays contain reservoirs in which both gas-saturated strata and rocks with gas/water contacts seem to coexist. Most units in the basin that have received a Federal Energy Regulatory Commission (FERC) designation as tight are in the main producing areas and are within Group 1 plays. Some rocks in Group 2 plays may not meet FERC requirements as tight reservoirs. However, we suggest that in the Uinta Basin that the extent of low-permeability rocks, and therefore resources, extends well beyond the limits of current FERC designated boundaries for tight reservoirs. Potential additions to gas reserves from gas-saturated tight reservoirs in the Tertiary Wasatch Formation and Cretaceous Mesaverde Group in the Uinta Basin, Utah is 10 TCF. If the potential additions to reserves in strata in which both gas-saturated and free water-bearing rocks exist are added to those of Group 1 plays, the volume is 13 TCF.

Fouch, T.D.; Schmoker, J.W.; Boone, L.E.; Wandrey, C.J.; Crovelli, R.A.; Butler, W.C.

1994-08-01

269

Fundamentals of numericl reservoir simulation  

Microsoft Academic Search

Computers are being widely used for numerical simulations of oil and gas reservoirs. This book is intended for the reservoir engineer. The first chapter reviews the basic reservoir mechanics and derives the differential equations that reservoir simulators are designed to solve. The next four chapters provide basic theory on the numerical solution of simple partial differential equations. The final chapter

D. W. Peaceman

1977-01-01

270

Naturally fractured tight gas reservoir detection optimization. Quarterly report, January--March 1996  

SciTech Connect

This progress report covers field performance test plan and three- dimensional basins simulator. The southern portion of the Rulison Field was originally selected as the location for the seismic program. Due to permitting problems the survey was unable to go forward. The northern Rulison Field has been modeled to determine suitability for the seismic program. The survey has been located over an area that contains the best producing, most intensively fractured wells and the worst, least fractured wells. Western Geophysical surveyed in the 564 vibrator points and 996 receiver stations. Maps displaying the survey design and modeled offset ranges can be found in Appendix A. The seismic acquisition crew is scheduled to arrive on location by April 7th. The overall development of the fracture prediction simulator has led to new insights into the nature of fractured reservoirs. In particular, the investigators have placed them within the context of recent idea on basin compartments. These concepts an their overall view of the physico-chemical dynamics of fractured reservoir creation are summarized in the report included as Appendix B entitled ``Prediction of Fractured Reservoir Location and Characteristics: A Basin Modeling Approach.`` The full three dimensional, multi-process basin simulator, CIRF.B, is operational and is being tested.

NONE

1996-04-01

271

Conference on the topic: {open_quotes}Exploration and production of petroleum and gas from chalk reservoirs worldwide{close_quotes}  

SciTech Connect

More than 170 delegates from 14 countries in Europe, North America, Africa, and Asia took part in a conference on the topic: Exploration and Production of Petroleum and Gas from Chalk Reservoirs Worldwide. The conference was held in Copenhagen, Denmark in September,1994, and was a joint meeting of the American Association of Petroleum Geologists (AAPG), and the European Association of Petroleum Geoscientists and Engineers (EAPG). In addition to the opening remarks, 25 oral and nine poster reports were presented. The topics included chalk deposits as reservoir rocks, the occurrence of chalk deposits worldwide, the North Sea oil and gas fields, and other related topics.

Kuznetsov, V.G.

1995-07-01

272

Using Carbon Dioxide to Enhance Recovery of Methane from Gas Hydrate Reservoirs: Final Summary Report  

SciTech Connect

Carbon dioxide sequestration coupled with hydrocarbon resource recovery is often economically attractive. Use of CO2 for enhanced recovery of oil, conventional natural gas, and coal-bed methane are in various stages of common practice. In this report, we discuss a new technique utilizing CO2 for enhanced recovery of an unconventional but potentially very important source of natural gas, gas hydrate. We have focused our attention on the Alaska North Slope where approximately 640 Tcf of natural gas reserves in the form of gas hydrate have been identified. Alaska is also unique in that potential future CO2 sources are nearby, and petroleum infrastructure exists or is being planned that could bring the produced gas to market or for use locally. The EGHR (Enhanced Gas Hydrate Recovery) concept takes advantage of the physical and thermodynamic properties of mixtures in the H2O-CO2 system combined with controlled multiphase flow, heat, and mass transport processes in hydrate-bearing porous media. A chemical-free method is used to deliver a LCO2-Lw microemulsion into the gas hydrate bearing porous medium. The microemulsion is injected at a temperature higher than the stability point of methane hydrate, which upon contacting the methane hydrate decomposes its crystalline lattice and releases the enclathrated gas. Small scale column experiments show injection of the emulsion into a CH4 hydrate rich sand results in the release of CH4 gas and the formation of CO2 hydrate

McGrail, B. Peter; Schaef, Herbert T.; White, Mark D.; Zhu, Tao; Kulkarni, Abhijeet S.; Hunter, Robert B.; Patil, Shirish L.; Owen, Antionette T.; Martin, P F.

2007-09-01

273

Characterization of Gas-Hydrate Reservoirs in the Ulleung Basin, East Sea, by Integration of Core-Log Data  

NASA Astrophysics Data System (ADS)

Examinations of core and well-log data from the UBGH2 drill sites suggest that the sites UBGH2-2_2 and UBGH2-6 have relatively good gas-hydrate reservoir quality in terms of individual and total cumulative thicknesses of gas-hydrate-bearing sand (HYBS) beds. In both of the sites, core sediments are generally dominated by hemipelagic muds which are frequently intercalated with turbidite sands. The turbidite sands are usually thin-to-medium bedded and mainly consist of well sorted coarse silt to fine sand. Anomalies in infrared core temperatures and porewater chlorinity data and pressure core measurements indicate that gas hydrate occurrence zones (GHOZ) occur about 65-155 mbsf in the site UBGH2-2_2 and 112-154 mbsf in the site UBGH2-6, above the base of gas hydrate stability zones (BGHSZ) at 180.5 mbsf and 167 mbsf, respectively. In both the GHOZ, gas hydrates are preferentially associated with many of the turbidite sands as "pore-filling" types. The HYBS identified in the cores from the site UBGH2-6 are usually medium-to-thick bedded and well coincident with significant high excursions in all of the log resistivity, density, and velocity curves. Gas-hydrate saturations in the HYBS range from 12 to 79% with an average of 55% based on porewater chlorinity and pressure core depressurizations. In contrast, the HYBS from the site UBGH2-2_2 are usually thin-bedded and roughly correlated with high excursions in both of the log resistivity and velocity curves due to the difference in resolutions of core and log data and the uncertainty in the log-to-core depth calibration. Gas-hydrate saturations in the HYBS range from 7 to 65% with an average of 31%. In both of the sites, there are intervals without gas hydrates between the GHOZ and the BGHSZ despite frequent occurrence of turbidite sands, suggesting limitations in methane supply by vertical gas diffusion or water migration. Since neither inclined permeable beds nor faults are identified in the core and log data, further examination of seismic data seems necessary to reveal migration pathways of methane.

Bahk, J.; Kim, G.; Chun, J.; Kim, J.; Lee, J.; Ryu, B.; Lee, J.; Collett, T. S.; Riedel, M.

2012-12-01

274

Modelling of stress development and fault slip in and around a producing gas reservoir  

Microsoft Academic Search

Many gas fields are currently being produced in the northern Netherlands. Induced seismicity related to gas production has become a growing problem in the Netherlands in the past two decades. To date, a few hundred induced seismic events occurred. Induced seismicity is generally assumed to be the result of induced reactivation of discontinuities in the subsurface. Field data of the

F. M. M. Mulders

2003-01-01

275

Anisotropic Velocities of Gas Hydrate-Bearing Sediments in Fractured Reservoirs  

USGS Publications Warehouse

During the Indian National Gas Hydrate Program Expedition 01 (NGHP-01), one of the richest marine gas hydrate accumulations was discovered at drill site NGHP-01-10 in the Krishna-Godavari Basin, offshore of southeast India. The occurrence of concentrated gas hydrate at this site is primarily controlled by the presence of fractures. Gas hydrate saturations estimated from P- and S-wave velocities, assuming that gas hydrate-bearing sediments (GHBS) are isotropic, are much higher than those estimated from the pressure cores. To reconcile this difference, an anisotropic GHBS model is developed and applied to estimate gas hydrate saturations. Gas hydrate saturations estimated from the P-wave velocities, assuming high-angle fractures, agree well with saturations estimated from the cores. An anisotropic GHBS model assuming two-component laminated media - one component is fracture filled with 100-percent gas hydrate, and the other component is the isotropic water-saturated sediment - adequately predicts anisotropic velocities at the research site.

Lee, Myung W.

2009-01-01

276

Study of Flow Regimes in Multiply-Fractured Horizontal Wells in Tight Gas and Shale Gas Reservoir Systems  

E-print Network

Various analytical, semi-analytical, and empirical models have been proposed to characterize rate and pressure behavior as a function of time in tight/shale gas systems featuring a horizontal well with multiple hydraulic fractures. Despite a small...

Freeman, Craig M.

2010-07-14

277

Numerical modeling of self-limiting and self-enhancing caprock alteration induced by CO2 storage in a depleted gas reservoir  

Microsoft Academic Search

This paper presents numerical simulations of reactive transport which may be induced in the caprock of an on-shore depleted gas reservoir by the geological sequestration of carbon dioxide. The objective is to verify that CO geological disposal activities currently being planned for the study area are safe and do not induce any undesired environmental impact. In our model, fluid flow

Tianfu Xu; Fabrizio Gherardi; Karsten Pruess

2007-01-01

278

A workflow for building and calibrating 3-D geomechanical models &ndash a case study for a gas reservoir in the North German Basin  

NASA Astrophysics Data System (ADS)

The optimal use of conventional and unconventional hydrocarbon reservoirs depends, amongst other things, on the local tectonic stress field. For example, wellbore stability, orientation of hydraulically induced fractures and - especially in fractured reservoirs - permeability anisotropies are controlled by the present-day in situ stresses. Faults and lithological changes can lead to stress perturbations and produce local stresses that can significantly deviate from the regional stress field. Geomechanical reservoir models aim for a robust, ideally "pre-drilling" prediction of the local variations in stress magnitude and orientation. This requires a numerical modelling approach that is capable to incorporate the specific geometry and mechanical properties of the subsurface reservoir. The workflow presented in this paper can be used to build 3-D geomechanical models based on the finite element (FE) method and ranging from field-scale models to smaller, detailed submodels of individual fault blocks. The approach is successfully applied to an intensively faulted gas reservoir in the North German Basin. The in situ stresses predicted by the geomechanical FE model were calibrated against stress data actually observed, e.g. borehole breakouts and extended leak-off tests. Such a validated model can provide insights into the stress perturbations in the inter-well space and undrilled parts of the reservoir. In addition, the tendency of the existing fault network to slip or dilate in the present-day stress regime can be addressed.

Fischer, K.; Henk, A.

2013-10-01

279

Method for identifying subsurface fluid migration and drainage pathways in and among oil and gas reservoirs using 3-D and 4-D seismic imaging  

DOEpatents

The invention utilizes 3-D and 4-D seismic surveys as a means of deriving information useful in petroleum exploration and reservoir management. The methods use both single seismic surveys (3-D) and multiple seismic surveys separated in time (4-D) of a region of interest to determine large scale migration pathways within sedimentary basins, and fine scale drainage structure and oil-water-gas regions within individual petroleum producing reservoirs. Such structure is identified using pattern recognition tools which define the regions of interest. The 4-D seismic data sets may be used for data completion for large scale structure where time intervals between surveys do not allow for dynamic evolution. The 4-D seismic data sets also may be used to find variations over time of small scale structure within individual reservoirs which may be used to identify petroleum drainage pathways, oil-water-gas regions and, hence, attractive drilling targets. After spatial orientation, and amplitude and frequency matching of the multiple seismic data sets, High Amplitude Event (HAE) regions consistent with the presence of petroleum are identified using seismic attribute analysis. High Amplitude Regions are grown and interconnected to establish plumbing networks on the large scale and reservoir structure on the small scale. Small scale variations over time between seismic surveys within individual reservoirs are identified and used to identify drainage patterns and bypassed petroleum to be recovered. The location of such drainage patterns and bypassed petroleum may be used to site wells. 22 figs.

Anderson, R.N.; Boulanger, A.; Bagdonas, E.P.; Xu, L.; He, W.

1996-12-17

280

Method for identifying subsurface fluid migration and drainage pathways in and among oil and gas reservoirs using 3-D and 4-D seismic imaging  

DOEpatents

The invention utilizes 3-D and 4-D seismic surveys as a means of deriving information useful in petroleum exploration and reservoir management. The methods use both single seismic surveys (3-D) and multiple seismic surveys separated in time (4-D) of a region of interest to determine large scale migration pathways within sedimentary basins, and fine scale drainage structure and oil-water-gas regions within individual petroleum producing reservoirs. Such structure is identified using pattern recognition tools which define the regions of interest. The 4-D seismic data sets may be used for data completion for large scale structure where time intervals between surveys do not allow for dynamic evolution. The 4-D seismic data sets also may be used to find variations over time of small scale structure within individual reservoirs which may be used to identify petroleum drainage pathways, oil-water-gas regions and, hence, attractive drilling targets. After spatial orientation, and amplitude and frequency matching of the multiple seismic data sets, High Amplitude Event (HAE) regions consistent with the presence of petroleum are identified using seismic attribute analysis. High Amplitude Regions are grown and interconnected to establish plumbing networks on the large scale and reservoir structure on the small scale. Small scale variations over time between seismic surveys within individual reservoirs are identified and used to identify drainage patterns and bypassed petroleum to be recovered. The location of such drainage patterns and bypassed petroleum may be used to site wells.

Anderson, Roger N. (New York, NY); Boulanger, Albert (New York, NY); Bagdonas, Edward P. (Brookline, MA); Xu, Liqing (New Milford, NJ); He, Wei (New Milford, NJ)

1996-01-01

281

Soft computing for reservoir characterization and management  

Microsoft Academic Search

Reservoir characterization plays a crucial role in modern reservoir management. It helps to make sound reservoir decisions and improves the asset value of the oil and gas companies. It maximizes integration of multi-disciplinary data and knowledge and improves the reliability of the reservoir predictions. The ultimate product is a reservoir model with realistic tolerance for imprecision and uncertainty. Soft computing

Masoud Nikravesh

2005-01-01

282

Petrophysical Characterization and Reservoir Simulator for Methane Gas Production from Gulf of Mexico Hydrates  

SciTech Connect

Gas hydrates are crystalline, ice-like compounds of gas and water molecules that are formed under certain thermodynamic conditions. Hydrate deposits occur naturally within ocean sediments just below the sea floor at temperatures and pressures existing below about 500 meters water depth. Gas hydrate is also stable in conjunction with the permafrost in the Arctic. Most marine gas hydrate is formed of microbially generated gas. It binds huge amounts of methane into the sediments. Estimates of the amounts of methane sequestered in gas hydrates worldwide are speculative and range from about 100,000 to 270,000,000 trillion cubic feet (modified from Kvenvolden, 1993). Gas hydrate is one of the fossil fuel resources that is yet untapped, but may play a major role in meeting the energy challenge of this century. In this project novel techniques were developed to form and dissociate methane hydrates in porous media, to measure acoustic properties and CT properties during hydrate dissociation in the presence of a porous medium. Hydrate depressurization experiments in cores were simulated with the use of TOUGHFx/HYDRATE simulator. Input/output software was developed to simulate variable pressure boundary condition and improve the ease of use of the simulator. A series of simulations needed to be run to mimic the variable pressure condition at the production well. The experiments can be matched qualitatively by the hydrate simulator. The temperature of the core falls during hydrate dissociation; the temperature drop is higher if the fluid withdrawal rate is higher. The pressure and temperature gradients are small within the core. The sodium iodide concentration affects the dissociation pressure and rate. This procedure and data will be useful in designing future hydrate studies.

Kishore Mohanty; Bill Cook; Mustafa Hakimuddin; Ramanan Pitchumani; Damiola Ogunlana; Jon Burger; John Shillinglaw

2006-06-30

283

Discovery of Large Molecular Gas Reservoirs in Post-Starburst Galaxies  

E-print Network

Post-starburst (or "E+A") galaxies are characterized by low H$\\alpha$ emission and strong Balmer absorption, suggesting a recent starburst, but little current star formation. Although many of these galaxies show evidence of recent mergers, the mechanism for ending the starburst is not yet understood. To study the fate of the molecular gas, we search for CO (1-0) and (2-1) emission with the IRAM 30m and SMT 10m telescopes in 32 nearby ($0.01gas masses of $M(H_2)=10^{8.6}$-$10^{9.8} M_\\odot$ and molecular gas mass to stellar mass fractions of $\\sim10^{-2}$-$10^{-0.5}$, comparable to those of star-forming galaxies. The large amounts of molecular gas rule out complete gas consumption, expulsion, or starvation as the primary mechanism that ends the starburst in these galaxies. The upper limits on $M(H_2)$ for th...

French, K Decker; Zabludoff, Ann; Narayanan, Desika; Shirley, Yancy; Walter, Fabian; Smith, John-David; Tremonti, Christy A

2015-01-01

284

Reservoir sedimentology  

SciTech Connect

Collection of papers focuses on sedimentology of siliclastic sandstone and carbonate reservoirs. Shows how detailed sedimentologic descriptions, when combined with engineering and other subsurface geologic techniques, yield reservoir models useful for reservoir management during field development and secondary and tertiary EOR. Sections cover marine sandstone and carbonate reservoirs; shoreline, deltaic, and fluvial reservoirs; and eolian reservoirs. References follow each paper.

Tillman, R.W.; Weber, K.J.

1987-01-01

285

Increasing Production from Low-Permeability Gas Reservoirs by Optimizing Zone Isolation for Successful Stimulation Treatments  

SciTech Connect

Maximizing production from wells drilled in low-permeability reservoirs, such as the Barnett Shale, is determined by cementing, stimulation, and production techniques employed. Studies show that cementing can be effective in terms of improving fracture effectiveness by 'focusing' the frac in the desired zone and improving penetration. Additionally, a method is presented for determining the required properties of the set cement at various places in the well, with the surprising result that uphole cement properties in wells destined for multiple-zone fracturing is more critical than those applied to downhole zones. Stimulation studies show that measuring pressure profiles and response during Pre-Frac Injection Test procedures prior to the frac job are critical in determining if a frac is indicated at all, as well as the type and size of the frac job. This result is contrary to current industry practice, in which frac jobs are designed well before the execution, and carried out as designed on location. Finally, studies show that most wells in the Barnett Shale are production limited by liquid invasion into the wellbore, and determinants are presented for when rod or downhole pumps are indicated.

Fred Sabins

2005-03-31

286

Characterization of lithology and reservoir rock for deep gas drilling in Siljan Impact Structure, Sweden  

SciTech Connect

The Gravberg 1 well in the Siljan impact structure in Sweden has been drilled entirely in granite and dolerite intrusions of Precambrian age to a present depth of 6.6 km. Study of the cuttings at the well site included a lithologic description, with emphasis on quantifying mineralogical, textural, and pore-space parameters that affect porosity and permeability and that can indicate the potential presence of a fractured reservoir. Important mineral parameters are epidote, reddish feldspar, chlorite, and other alteration products. Textural parameters include the presence of fractures, cataclastic and brecciated graikns, vugs, and drusy crystals. Although rare, the presence of drusy crystals clearly shows that open fractures are present. The study is also geared to identify minerals that affect wireline logs (e.g., alteration products such as chlorite,sericite, and illite, and heavy minerals such as pyritic and magnetite4). Cuttings examination is crucial as relatively few cores or sidewalls have been recovered. Laboratory studies incorporating capillary pressure tests, SEM, and thin-section petrography (in polarized and fluorescent light) reveal that the samples contain a bimodal pore structure composed of larger pores representing the microfractures and smaller pores representing the intercrystalline microporosity developed within altered grains. Porosity in the granites averages 0.96% (typical Swedish granite is 0.5%), and the permeability is 0.003-0.027 md.

Castano, J.R.; Sneider, R.M.; Bolger, G.W.

1988-01-01

287

Application of geo-microbial prospecting method for finding oil and gas reservoirs  

NASA Astrophysics Data System (ADS)

Microbial prospecting of hydrocarbons is based on the detection of anomalous population of hydrocarbon oxidizing bacteria in the surface soils, indicates the presence of subsurface oil and gas accumulation. The technique is based on the seepage of light hydrocarbon gases such as C1-C4 from the oil and gas pools to the shallow surface that provide the suitable conditions for the development of highly specialized bacterial population. These bacteria utilize hydrocarbon gases as their only food source and are found enriched in the near surface soils above the hydrocarbon bearing structures. The methodology involves the collection of soil samples from the survey area, packing, preservation and storage of samples in pre-sterilized sample bags under aseptic and cold conditions till analysis and isolation and enumeration of hydrocarbon utilizing bacteria such as methane, ethane, propane, and butane oxidizers. The contour maps for the population density of hydrocarbon oxidizing bacteria are drawn and the data can be integrated with geological, geochemical, geophysical methods to evaluate the hydrocarbon prospect of an area and to prioritize the drilling locations thereby reducing the drilling risks and achieve higher success in petroleum exploration. Microbial Prospecting for Oil and Gas (MPOG) method success rate has been reported to be 90%. The paper presents details of microbial prospecting for oil and gas studies, excellent methodology, future development trends, scope, results of study area, case studies and advantages.

Rasheed, M. A.; Hasan, Syed Zaheer; Rao, P. L. Srinivasa; Boruah, Annapurna; Sudarshan, V.; Kumar, B.; Harinarayana, T.

2014-07-01

288

Evaluation of Travis Peak gas reservoirs, west margin of the East Texas Basin  

E-print Network

for basinward extension of Travis Peak gas production along the west margin of the East Texas Basin. Along the west margin of the East Texas Basin, southeast-trending Travis Peak sandstones belts were deposited by the Ancestral Red River fluvial-deltaic system...

Li, Yamin

2009-05-15

289

Geological implications and controls on the determination of water saturation in shale gas reservoirs  

NASA Astrophysics Data System (ADS)

A significant challenge to the petrophysical evaluation of shale gas systems can be attributed to the conductivity behaviour of clay minerals and entrained clay bound waters. This is compounded by centimetre to sub-millimetre vertical and lateral heterogeneity in formation composition and structure. Where despite significant variation in formation geological and therefore petrophysical properties, we routinely rely on conventional resistivity methods for the determination of water saturation (Sw), and hence the free gas saturation (Sg) in gas bearing mudstones. The application of resistivity based methods is the subject of continuing debate, and there is often significant uncertainty in both how they are applied and the saturation estimates they produce. This is partly a consequence of the view that "the quantification of the behaviour of shale conductivity....has only limited geological significance" (Rider 1986). As a result, there is a separation between our geological understanding of shale gas systems and the petrophysical rational and methods employed to evaluate them. In response to this uncertainty, many petrophysicists are moving away from the use of more complex 'shaly-sand' based evaluation techniques and returning to traditional Archie methods for answers. The Archie equation requires various parameter inputs such as porosity and saturation exponents (m and n), as well as values for connate fluid resistivity (Rw). Many of these parameters are difficult to determine in shale gas systems, where obtaining a water sample, or carrying out laboratory experiments on recovered core is often technically impractical. Here we assess the geological implications and controls on variations in pseudo Archie parameters across two geological formations, using well data spanning multiple basinal settings for a prominent shale gas play in the northern Gulf of Mexico basin. The results, of numerical analysis and systematic modification of parameter values to minimise the error between core derived Sw (Dean Stark analysis) and computed Sw, links sample structure with composition, highlighting some unanticipated impacts of clay minerals on the effective bulk fluid resistivity (Rwe) and thus formation resistivity (Rt). In addition, it highlights simple corrective empirical adaptations that can significantly reduce the error in Sw estimation for some wells. Observed results hint at the possibility of developing a predictive capability in selecting Archie parameter values based on geological facies association and log composition indicators (i.e. V Clay), establishing a link between formation depositional systems and their petrophysical properties in gas bearing mudstones. Rider, M.H., 1986. The Geological Interpretation of Well Logs, Blackie.

Hartigan, David; Lovell, Mike; Davies, Sarah

2014-05-01

290

Characterization of Roabiba Sandstones Reservoir in Bintuni Field, Papua, Indonesia  

E-print Network

Bintuni Field has two Middle Jurassic gas reservoirs, Upper and Lower Roabiba Sandstone reservoirs, with the estimated reserve from eight appraisal drilled wells of 6.08 tcf. The field has not been producing commercially. The main gas reservoir...

Vera, Riene

2011-02-22

291

Gas reservoir of a hyper-luminous quasar at z = 2.6  

NASA Astrophysics Data System (ADS)

Context. Understanding the relationship between the formation and evolution of galaxies and their central super-massive black holes (SMBH) is one of the main topics in extragalactic astrophysics. Links and feedback may reciprocally affect both black hole and galaxy growth. Aims: Observations of the CO line at the main epoch of galaxy and SMBH assembly (z = 2-4) are crucial to investigating the gas mass, star formation, and accretion onto SMBHs, and the effect of AGN feedback. Potential correlations between AGN and host galaxy properties can be highlighted by observing extreme objects. Methods: We targeted CO(3-2) in ULAS J1539+0557, a hyper-luminous quasar (Lbol > 1048 erg/s) at z = 2.658, selected through its unusual red colour in the UKIDSS Large Area Survey (ULAS). Results: We find a molecular gas mass of 4.1 ± 0.8 × 1010 M?, by adopting a conversion factor ? = 0.8 M? K-1 km s-1 pc2, and a gas fraction of ~0.4-0.1, depending mostly on the assumed source inclination. We also find a robust lower limit to the star-formation rate (SFR = 250-1600 M?/yr) and star-formation efficiency (SFE = 25-350 L?/(K km s-1 pc2) by comparing the observed optical-near-infrared spectral energy distribution with AGN and galaxy templates. The black hole gas consumption timescale, M(H2) /?acc, is ~160 Myr, similar to or higher than the gas consumption timescale. Conclusions: The gas content and the star formation efficiency are similar to those of other high-luminosity, highly obscured quasars, and at the lower end of the star-formation efficiency of unobscured quasars, in line with predictions from AGN-galaxy co-evolutionary scenarios. Further measurements of the (sub)mm continuum in this and similar sources are mandatory to obtain a robust observational picture of the AGN evolutionary sequence. Based on observations carried out with the IRAM Plateau de Bure Interferometer. IRAM is supported by INSU/CNRS (France), MPG (Germany), and IGN (Spain).

Feruglio, C.; Bongiorno, A.; Fiore, F.; Krips, M.; Brusa, M.; Daddi, E.; Gavignaud, I.; Maiolino, R.; Piconcelli, E.; Sargent, M.; Vignali, C.; Zappacosta, L.

2014-05-01

292

Appraisal of heavy hydrocarbons in coal seam gas reservoirs. Annual report, September 1991-August 1992  

SciTech Connect

Five wax samples from coal-bed methane sites within the San Juan Basin were analyzed using adsorption chromatography, gas chromatography, and gas chromatography linked to mass spectrometry. The largest of the chemical classes was the aliphatic with the n-alkanes as the predominant aliphatic series. Branched and cyclic alkanes, alkyl substituted cyclohexane series, and several biomarker compounds were also found in aliphatic fractions of the waxes. Aromatic and polar compounds were present in the waxes, but at much lower concentrations than the aliphatics. The extracts of wax, shale, and coal samples from two of the coal-bed methane sites (Hamilton No. 3 and SUT H-1) were analyzed, and some interesting observations were made. The most striking finding was that the coal extracts of both wax-producing sites were completely devoid of n-alkanes. The wax and shale aliphatic, aromatic, and polar gas chromatograms were quite similar for samples from both sites. Extracts of coal samples obtained from a nearby non-wax-producing coal-bed methane site contained similar n-alkane distributions as observed in the five wax and two shale samples examined. The above data support the hypothesis that the waxes are coal derived.

Vorkink, W.P.; Lee, M.L.

1993-02-01

293

Geophysical investigations of the methane reservoir and gas escape mechanisms on the west Svalbard margin  

NASA Astrophysics Data System (ADS)

In 2008, over 250 bubble plumes were discovered close to the landward limit of methane hydrate stability on the west Svalbard continental margin, and sampling of ocean water in the vicinity of some of these plumes showed anomalously high methane concentrations. Many of the plumes occur in the region over which the hydrate stability field has receded during the last three decades due to ocean warming and such thermal erosion of the hydrate stability field may provide a positive feedback effect in global climate change. The presence of hydrate beneath the seabed is evidenced by the presence of a widespread bottom-simulating reflector (BSR) on the lower continental slope and by direct sampling with cores. More limited plume activity was found in deeper water at pockmark features that reach several hundred metres in diameter. During cruises in 2011 and 2012, we conducted further geophysical surveys both in the region of hydrate stability field recession on the continental slope and over a large pockmark on the nearby Vestnesa Ridge sediment drift. We conducted high-resolution seismic reflection surveys using a 90 cu. in. GI gun source and a 60-m, 60-channel hydrophone streamer, and deep-towed seismic surveys using Ifremer's SYSIF vehicle and chirp sources with 220-1050 Hz and 580-2200 Hz sweeps. We recorded both the GI-gun and the lower-frequency Chirp sources on ocean bottom seismometers to determine the velocity structure with high vertical resolution at both sites. We obtained controlled source electromagnetic (CSEM) data from both sites using a deep-towed frequency domain electromagnetic source recorded at 14 seafloor receivers with orthogonal electrodes and a towed three-component electric field receiver. At the slope site, our CSEM profile extends into deep water where a BSR is present. High-resolution and Chirp seismic reflection data show evidence for the widespread presence of subsurface gas at the slope site, both within and beneath the region of hydrate stability field recession. Here, numerous sub-vertical fractures provide conduits for gas transport to the ocean floor. Deeply sourced gas also appears to migrate along stratigraphic horizons. At some locations, gas appears to pond beneath a thin veneer of glacial and post-glacial sediments. At the Vestnesa pockmark site, strong scattering in Chirp images suggests the presence of localised pockets of subsurface gas within the hydrate stability field, and local increases in seismic velocity above the BSR provide evidence for a concentration of hydrate beneath the pockmark. We present initial results and interpretations from both cruises.

Minshull, T. A.; Westbrook, G. K.; Sinha, M. C.; Weitemeyer, K. A.; Henstock, T.; Chabert, A.; Vardy, M. E.; Sarkar, S.; Goswami, B.; Marsset, B.; Ker, S.; Thomas, Y.; Best, A. I.; Rajan, A.

2012-12-01

294

Scientific Challenges of Producing Natural Gas from Organic-Rich Shales - From the Nano-Scale to the Reservoir Scale (Louis Néel Medal Lecture)  

NASA Astrophysics Data System (ADS)

In this talk I will discuss several on-going research projects with the PhD students and post-Docs in my group that are investigating the wide variety of factors affecting the success of stimulating gas production from extremely low permeability organic-rich shales. First, I will present laboratory measurements of pore structure, adsorption and nano-scale fluid transport on samples of the Barnett, Eagle Ford, Haynesville, Marcellus and Horn River shale (all in North America). I will also discuss how these factors affect ultimate gas recovery. Second, I present several lines of evidence that indicate that during hydraulic fracturing stimulation of shale gas reservoirs there is pervasive slow slip occurring on pre-existing fractures and faults that are not detected by standard microseismic monitoring. I will also present laboratory and modeling studies that demonstrate why slowly slipping faults are to be expected. In many cases, slow slip on faults may be the most important process responsible for stimulating gas production in the reservoirs. Finally, I discuss our research on the viscoplastic behavior of the shales and what viscoplasticity implies for the evolution of the physical properties of the reservoir and in situ stress magnitudes.

Zoback, Mark D.

2013-04-01

295

GAS RESERVOIRS AND STAR FORMATION IN A FORMING GALAXY CLUSTER AT zbsime0.2  

SciTech Connect

We present first results from the Blind Ultra-Deep H I Environmental Survey of the Westerbork Synthesis Radio Telescope. Our survey is the first direct imaging study of neutral atomic hydrogen gas in galaxies at a redshift where evolutionary processes begin to show. In this Letter we investigate star formation, H I content, and galaxy morphology, as a function of environment in Abell 2192 (at z = 0.1876). Using a three-dimensional visualization technique, we find that Abell 2192 is a cluster in the process of forming, with significant substructure in it. We distinguish four structures that are separated in redshift and/or space. The richest structure is the baby cluster itself, with a core of elliptical galaxies that coincides with (weak) X-ray emission, almost no H I detections, and suppressed star formation. Surrounding the cluster, we find a compact group where galaxies pre-process before falling into the cluster, and a scattered population of 'field-like' galaxies showing more star formation and H I detections. This cluster proves to be an excellent laboratory to understand the fate of the H I gas in the framework of galaxy evolution. We clearly see that the H I gas and the star formation correlate with morphology and environment at z {approx} 0.2. In particular, the fraction of H I detections is significantly affected by the environment. The effect starts to kick in in low-mass groups that pre-process the galaxies before they enter the cluster. Our results suggest that by the time the group galaxies fall into the cluster, they are already devoid of H I.

Jaffe, Yara L.; Poggianti, Bianca M. [INAF-Osservatorio Astronomico di Padova, vicolo dell' Osservatorio 5, I-35122 Padova (Italy); Verheijen, Marc A. W.; Deshev, Boris Z. [Kapteyn Astronomical Institute, Landleven 12, 9747-AD Groningen (Netherlands); Van Gorkom, Jacqueline H., E-mail: yara.jaffe@oapd.inaf.it [Department of Astronomy, Columbia University, Mail Code 5246, 550 W 120th Street, New York, NY 10027 (United States)

2012-09-10

296

The design of an efficient and reliable streamline simulator for gas injection processes in oil reservoirs  

NASA Astrophysics Data System (ADS)

For reliable performance prediction of gas injection processes it is essential to properly account for the effects of heterogeneity through the use of fine grids, and accurately represent component transfer between phases. Because of the required high grid density and the costly phase behavior calculations (aka flashes), gas injection processes are computationally intensive. Streamline methods, akin to Euler-Lagrangian methods, are attractive for these advection dominated processes because they alleviate time-step restrictions, are inherently parallel, and easily combined with adaptive mesh refinement strategies to reduce flashing costs. In streamline methods, the pressure equation is solved on a 3D grid, whereas the mass balance equations for each of the components are solved along streamlines, generated from the pressure field using Darcy's law. We show that accurate modeling of phase behavior can be achieved if high-order upwind schemes are used along streamlines. The high order of the schemes allows the use of coarser grids along streamlines, thus reducing flash calculations. Also, the longitudinal numerical diffusion is reduced which is especially important in compositional problems because it can significantly affect the predicted displacement efficiencies. Numerical smoothing is still present as a result of mapping solution values between streamlines and pressure grid at pressure updates. We designed a high order mapping algorithm that greatly reduces these mapping errors.

Gerritsen, Margot; Mallison, Bradley

2003-11-01

297

Numerical Model Representation Of Multi-stage Hydrualically Fractured Horizontal Wells Located In Shale Gas Reservoirs Using Neural Networks.  

E-print Network

??Numerical representation of hydrocarbon reservoirs has seen increase usage and sophistication due to recent surge in demands for unconventional hydrocarbon resources. Unlike the conventional fields… (more)

Bodipat, Kanin

2012-01-01

298

CHARACTERIZATION OF CONDITIONS OF NATURAL GAS STORAGE RESERVOIRS AND DESIGN AND DEMONSTRATION OF REMEDIAL TECHNIQUES FOR DAMAGE MECHANISMS FOUND THEREIN  

SciTech Connect

The underground gas storage (UGS) industry uses over 400 reservoirs and 17,000 wells to store and withdrawal gas. As such, it is a significant contributor to gas supply in the United States. It has been demonstrated that many UGS wells show a loss of deliverability each year due to numerous damage mechanisms. Previous studies estimate that up to one hundred million dollars are spent each year to recover or replace a deliverability loss of approximately 3.2 Bscf/D per year in the storage industry. Clearly, there is a great potential for developing technology to prevent, mitigate, or eliminate the damage causing deliverability losses in UGS wells. Prior studies have also identified the presence of several potential damage mechanisms in storage wells, developed damage diagnostic procedures, and discussed, in general terms, the possible reactions that need to occur to create the damage. However, few studies address how to prevent or mitigate specific damage types, and/or how to eliminate the damage from occurring in the future. This study seeks to increase our understanding of two specific damage mechanisms, inorganic precipitates (specifically siderite), and non-darcy damage, and thus serves to expand prior efforts as well as complement ongoing gas storage projects. Specifically, this study has resulted in: (1) An effective lab protocol designed to assess the extent of damage due to inorganic precipitates; (2) An increased understanding of how inorganic precipitates (specifically siderite) develop; (3) Identification of potential sources of chemical components necessary for siderite formation; (4) A remediation technique that has successfully restored deliverability to storage wells damaged by the inorganic precipitate siderite (one well had nearly a tenfold increase in deliverability); (5) Identification of the types of treatments that have historically been successful at reducing the amount of non-darcy pressure drop in a well, and (6) Development of a tool that can be used by operators to guide treatment selection in wells with significant non-darcy damage component. In addition, the effectiveness of the remediation treatment designed to reduce damage caused by the inorganic precipitate siderite was measured, and the benefits of this work are extrapolated to the entire U.S. storage industry. Similarly the potential benefits realized from more effective identification and treatment of wells with significant nondarcy damage component are also presented, and these benefits are also extrapolated to the entire U.S. storage industry.

J.H. Frantz Jr; K.G. Brown; W.K. Sawyer; P.A. Zyglowicz; P.M. Halleck; J.P. Spivey

2004-12-01

299

Sweet spots discrimination in shale gas reservoirs using seismic and well-logs data. A case study from the Worth basin in the Barnett shale  

NASA Astrophysics Data System (ADS)

Here, we present a case study of sweet spots discrimination in shale gas reservoirs located in the Worth basin of the Barnett shale using seismic and well-logs data. Seismic attributes such the Chaos and the ANT-Tracking are used for natural fractures system identification from seismic data, the maps of the stress and the Poisson ratio obtained from the upscaling of well-logs data of a horizontal well are able to provide an information about the drilling direction which is usually in the minimum horizontal stress profile, the map of the Poisson ratio can provide an information hardness of the source rock. The set of well logs data is used for geo-mechanical and petrophysical discrimination of the sweet spots, after discrimination the identified zones are useful for reserves estimation from unconventional shale gas reservoir.

Aliouane, Leila; Ouadfeul, Sid-Ali; Boudella, Amar

2014-05-01

300

Radon-222 content of natural gas samples from Upper and Middle Devonian sandstone and shale reservoirs in Pennsylvania—preliminary data  

USGS Publications Warehouse

Samples of natural gas were collected as part of a study of formation water chemistry in oil and gas reservoirs in the Appalachian Basin. Nineteen samples (plus two duplicates) were collected from 11 wells producing gas from Upper Devonian sandstones and the Middle Devonian Marcellus Shale in Pennsylvania. The samples were collected from valves located between the wellhead and the gas-water separator. Analyses of the radon content of the gas indicated 222Rn (radon-222) activities ranging from 1 to 79 picocuries per liter (pCi/L) with an overall median of 37 pCi/L. The radon activities of the Upper Devonian sandstone samples overlap to a large degree with the activities of the Marcellus Shale samples.

Rowan, E.L.; Kraemer, T.F.

2012-01-01

301

Seismic attenuation analysis of vertical seismic profiles for gas-bearing sedimentary reservoirs  

NASA Astrophysics Data System (ADS)

Quality factor (Q) estimation of vertical seismic profiles requires precise computation of seismic energy or amplitude over a certain frequency band width of a propagating wave field through the earth media. It is a big challenge to have the correct amplitude spectra over a frequency band for reliable estimation of anelastic attenuation factor in seismic data. Q is a very useful petrophysical parameter in the characterization of different layered earth media. Estimation of Q in this study is for both numerically generated zero-offset vertical seismic profiles and field VSP. A finite difference technique has been applied to model wave propagation in elastic isotropic layered media. In finite difference modeling a staggered grid scheme is implemented in second-order in time and second-order in space that provides a convenient way to define model boundaries. For forward 2D Q analysis of model VSP and field VSP data, spectral ratio (SR) and centroid frequency down shift (CFD) methods have been used in this study. Validity and sensitivity studies of SR and CFD methods, has been done on synthetically generated model VSP data prior to attenuation analysis of field VSP data. The use of two different methods (SR and CFD methods) provides an opportunity to validate attenuation measurements. The results of the synthetic modeling studies with and without intrinsic attenuation in different models shows very close agreement with model values and validates these methods. The Q analysis of total field VSP over the 30m depth interval, illustrates that the Q estimation is satisfactory, however a few shows a physically unrealizable phenomenon of negative values. The formation wise average Q analysis result of the field VSP indicates that the Bhuban formation is more attenuative than Tipam and Bokabil formations and the gas bearing zone (2420--2460m) has a low Q value (SR=28 and CFD=23). This highly attenuative thin gas bearing layer alters the seismic signal both in shape and size. The spectral analysis and estimated Q values of the total VSP section indicates that amplitude spectra drastically losses energy when the signal passes through the gas bearing zone.

Talukder, Md. Waheduzzaman

302

Numerical modeling of self-limiting and self-enhancing caprock alteration induced by CO 2 storage in a depleted gas reservoir  

Microsoft Academic Search

This paper presents numerical simulations of reactive transport which may be induced in the caprock of an on-shore depleted gas reservoir by the geological sequestration of carbon dioxide. The objective is to verify that CO2 geological disposal activities currently being planned for the study area are safe and do not induce any undesired environmental impact.In our model, fluid flow, mass

Fabrizio Gherardi; Tianfu Xu; Karsten Pruess

2007-01-01

303

Gas geochemistry of the magmatic-hydrothermal fluid reservoir in the Copahue-Caviahue Volcanic Complex (Argentina)  

NASA Astrophysics Data System (ADS)

Copahue volcano is part of the Caviahue-Copahue Volcanic Complex (CCVC), which is located in the southwestern sector of the Caviahue volcano-tectonic depression (Argentina-Chile). This depression is a pull-apart basin accommodating stresses between the southern Liquiñe-Ofqui strike slip and the northern Copahue-Antiñir compressive fault systems, in a back-arc setting with respect to the Southern Andean Volcanic Zone. In this study, we present chemical (inorganic and organic) and isotope compositions (?13C-CO2, ?15N, 3He/4He, 40Ar/36Ar, ?13C-CH4, ?D-CH4, and ?D-H2O and ?18O-H2O) of fumaroles and bubbling gases of thermal springs located at the foot of Copahue volcano sampled in 2006, 2007 and 2012. Helium isotope ratios, the highest observed for a Southern American volcano (R/Ra up to 7.94), indicate a non-classic arc-like setting, but rather an extensional regime subdued to asthenospheric thinning. ?13C-CO2 values (from - 8.8‰ to - 6.8‰ vs. V-PDB), ?15N values (+ 5.3‰ to + 5.5‰ vs. Air) and CO2/3He ratios (from 1.4 to 8.8 × 109) suggest that the magmatic source is significantly affected by contamination of subducted sediments. Gases discharged from the northern sector of the CCVC show contribution of 3He-poor fluids likely permeating through local fault systems. Despite the clear mantle isotope signature in the CCVC gases, the acidic gas species have suffered scrubbing processes by a hydrothermal system mainly recharged by meteoric water. Gas geothermometry in the H2O-CO2-CH4-CO-H2 system suggests that CO and H2 re-equilibrate in a separated vapor phase at 200°-220 °C. On the contrary, rock-fluid interactions controlling CO2, CH4 production from Sabatier reaction and C3H8 dehydrogenation seem to occur within the hydrothermal reservoir at temperatures ranging from 250° to 300 °C. Fumarole gases sampled in 2006-2007 show relatively low N2/He and N2/Ar ratios and high R/Ra values with respect to those measured in 2012. Such compositional and isotope variations were likely related to injection of mafic magma that likely triggered the 2000 eruption. Therefore, changes affecting the magmatic system had a delayed effect on the chemistry of the CCVC gases due to the presence of the hydrothermal reservoir. However, geochemical monitoring activities mainly focused on the behavior of inert gas compounds (N2 and He), should be increased to investigate the mechanism at the origin of the unrest started in 2011.

Agusto, M.; Tassi, F.; Caselli, A. T.; Vaselli, O.; Rouwet, D.; Capaccioni, B.; Caliro, S.; Chiodini, G.; Darrah, T.

2013-05-01

304

EOS7C Version 1.0: TOUGH2 Module for Carbon Dioxide or Nitrogen inNatural Gas (Methane) Reservoirs  

SciTech Connect

EOS7C is a TOUGH2 module for multicomponent gas mixtures in the systems methane carbon dioxide (CH4-CO2) or methane-nitrogen (CH4-N2) with or without an aqueous phase and H2O vapor. EOS7C uses a cubic equation of state and an accurate solubility formulation along with a multiphase Darcy s Law to model flow and transport of gas and aqueous phase mixtures over a wide range of pressures and temperatures appropriate to subsurface geologic carbon sequestration sites and natural gas reservoirs. EOS7C models supercritical CO2 and subcritical CO2 as a non-condensible gas, hence EOS7C does not model the transition to liquid or solid CO2 conditions. The components modeled in EOS7C are water, brine, non-condensible gas, gas tracer, methane, and optional heat. The non-condensible gas (NCG) can be selected by the user to be CO2 or N2. The real gas properties module has options for Peng-Robinson, Redlich-Kwong, or Soave-Redlich-Kwong equations of state to calculate gas mixture density, enthalpy departure, and viscosity. Partitioning of the NCG and CH4 between the aqueous and gas phases is calculated using a very accurate chemical equilibrium approach. Transport of the gaseous and dissolved components is by advection and Fickian molecular diffusion. We present instructions for use and example problems to demonstrate the accuracy and practical application of EOS7C.

Oldenburg, Curtis M.; Moridis,George J.; Spycher, Nicholas; Pruess, Karsten

2004-06-29

305

Drill Cuttings-based Methodology to Optimize Multi-stage Hydraulic Fracturing in Horizontal Wells and Unconventional Gas Reservoirs  

NASA Astrophysics Data System (ADS)

Horizontal drilling and hydraulic fracturing techniques have become almost mandatory technologies for economic exploitation of unconventional gas reservoirs. Key to commercial success is minimizing the risk while drilling and hydraulic fracturing these wells. Data collection is expensive and as a result this is one of the first casualties during budget cuts. As a result complete data sets in horizontal wells are nearly always scarce. In order to minimize the data scarcity problem, the research addressed throughout this thesis concentrates on using drill cuttings, an inexpensive direct source of information, for developing: 1) A new methodology for multi-stage hydraulic fracturing optimization of horizontal wells without any significant increases in operational costs. 2) A new method for petrophysical evaluation in those wells with limited amount of log information. The methods are explained using drill cuttings from the Nikanassin Group collected in the Deep Basin of the Western Canada Sedimentary Basin (WCSB). Drill cuttings are the main source of information for the proposed methodology in Item 1, which involves the creation of three 'log tracks' containing the following parameters for improving design of hydraulic fracturing jobs: (a) Brittleness Index, (b) Measured Permeability and (c) An Indicator of Natural Fractures. The brittleness index is primarily a function of Poisson's ratio and Young Modulus, parameters that are obtained from drill cuttings and sonic logs formulations. Permeability is measured on drill cuttings in the laboratory. The indication of natural fractures is obtained from direct observations on drill cuttings under the microscope. Drill cuttings are also the main source of information for the new petrophysical evaluation method mentioned above in Item 2 when well logs are not available. This is important particularly in horizontal wells where the amount of log data is almost non-existent in the vast majority of the wells. By combining data from drill cuttings and previously available empirical relationships developed from cores it is possible to estimate water saturations, pore throat apertures, capillary pressures, flow units, porosity (or cementation) exponent m, true formation resistivity Rt, distance to a water table (if present), and to distinguish the contributions of viscous and diffusion-like flow in the tight gas formation. The method further allows the construction of Pickett plots using porosity and permeability obtained from drill cuttings, without previous availability of well logs. The method assumes the existence of intervals at irreducible water saturation, which is the case of the Nikanassin Group throughout the gas column. The new methods mentioned above are not meant to replace the use of detailed and sophisticated evaluation techniques. But the proposed methods provide a valuable and practical aid in those cases where geomechanical and petrophysical information are scarce.

Ortega Mercado, Camilo Ernesto

306

Reservoir microfacies and their logging response of gas hydrate in the Qilian Mountain permafrost in Northwest China  

NASA Astrophysics Data System (ADS)

The Qilian Mountain permafrost is located in the north margin of the Qinghai-Tibet Plateau in northwest China. The permafrost area is about 10×104 Km2, and dominated by mountain permafrost. The mean annual ground temperature is 1.5 to 2.4 centigrade and the thickness of permafrost is generally 50 to 139 m. The gas hydrate was sampled successfully in the 133-396m interval from holes DK-1, DK-2 and DK-3 and tested by microRaman spectroscopy in the hydrate laboratory of the Qingdao Institute of Marine Geology during June to September in 2009. The exploratory drilling indicated that gas hydrate and its abnormal occurrence are mainly developed 130-400 m beneath permafrost. The strata belong to the Jiangcang Formation of middle Jurassic. Based on lithology, sedimentary structure and sequence and other facies markers, reservoir microfacies of gas hydrate are identified as underwater distributary channel and interdistributary bay in delta front of delta and deep lake mudstone facies in lacustrine. The underwater distributary channel in delta front of delta is dominated by fine sandstone. It has little mudstone. The grain size generally becomes finer, and scour-filling structure, parallel bedding, cross bedding and wavy bedding develop successively from bottom to top in one phase of channel. In vertical multi-period distributary channels superimpose, forming thick sandstone, and sometimes a thin mudstone develop between two channels. The interdistributaty bay is characterized by mudstone with little siltstone and fine sandstone. The lithology column shows mudstone interbedded with thin sandstone. Horizon bedding and lenticular bedding are the main structure. The gas hydrate usually presents visible white (smoky gray when mixing with mud) ice-like lamina in fissures or invisible micro disseminated occurrence in pores of sandstone. Honeycomb pores formed by the decomposition of gas hydrate are usually found in sandstone. The deep lake is dominated by thick dark grey mudstone and oil shale with horizon bedding. Some plant clasts can be found in mudstone. The gas hydrate generally presents white ice-like lamina in fissures of mudstone and oil shale. Underwater distributary channel and interdistributary bay have big variation amplitude on the logging curves. The extend of gamma (Gr) logging curve is 30 to 140 API, the acoustic (AC) logging curve is 300 to 400?s/m and the apparent resistivity (Rt) logging curve is 20-60?×m. The sandstone layer has characteristics of low Gr and AC value and high Rt value, whereas the mudstone layer has characteristics of high Gr and AC value and low Rt value. In shape, the underwater distributary channel shows tooth-like funnel-shaped pattern on Gr logging curve and bell-shaped pattern on Rt curve, whereas the underwater distributary bay presents tooth-like box-shaped pattern on both Gr and Rt curves. Deep lake mudstone has a relatively small variation amplitude on the logging curves. The extend of Gr logging curve is 45-80 API, the AC logging curve is 280-325?s/m, and the Rt logging curve is 25-50?×m. In the Gr and Rt logging curves, it generally presents box-shaped or tooth-like box-shaped pattern.

Liu, H.; Lu, Z.; Zhang, Y.; Sun, Z.

2012-12-01

307

Pore- and fracture-filling gas hydrate reservoirs in the Gulf of Mexico Gas Hydrate Joint Industry Project Leg II Green Canyon 955 H well  

USGS Publications Warehouse

High-quality logging-while-drilling (LWD) downhole logs were acquired in seven wells drilled during the Gulf of MexicoGasHydrateJointIndustryProjectLegII in the spring of 2009. Well logs obtained in one of the wells, the GreenCanyon Block 955Hwell (GC955-H), indicate that a 27.4-m thick zone at the depth of 428 m below sea floor (mbsf; 1404 feet below sea floor (fbsf)) contains gashydrate within sand with average gashydrate saturations estimated at 60% from the compressional-wave (P-wave) velocity and 65% (locally more than 80%) from resistivity logs if the gashydrate is assumed to be uniformly distributed in this mostly sand-rich section. Similar analysis, however, of log data from a shallow clay-rich interval between 183 and 366 mbsf (600 and 1200 fbsf) yielded average gashydrate saturations of about 20% from the resistivity log (locally 50-60%) and negligible amounts of gashydrate from the P-wave velocity logs. Differences in saturations estimated between resistivity and P-wave velocities within the upper clay-rich interval are caused by the nature of the gashydrate occurrences. In the case of the shallow clay-rich interval, gashydrate fills vertical (or high angle) fractures in rather than fillingpore space in sands. In this study, isotropic and anisotropic resistivity and velocity models are used to analyze the occurrence of gashydrate within both the clay-rich and sand dominated gas-hydrate-bearing reservoirs in the GC955-Hwell.

Lee, M.W.; Collett, T.S.

2012-01-01

308

Paleozoic oil/gas shale reservoirs in southern Tunisia: An overview  

NASA Astrophysics Data System (ADS)

During these last years, considerable attention has been given to unconventional oil and gas shale in northern Africa where the most productive Paleozoic basins are located (e.g. Berkine, Illizi, Kufra, Murzuk, Tindouf, Ahnet, Oued Mya, Mouydir, etc.). In most petroleum systems, which characterize these basins, the Silurian played the main role in hydrocarbon generation with two main 'hot' shale levels distributed in different locations (basins) and their deposition was restricted to the Rhuddanian (Lllandovery: early Silurian) and the Ludlow-Pridoli (late Silurian). A third major hot shale level had been identified in the Frasnian (Upper Devonian). Southern Tunisia is characterized by three main Paleozoic sedimentary basins, which are from North to South, the southern Chotts, Jeffara and Berkine Basin. They are separated by a major roughly E-W trending lower Paleozoic structural high, which encompass the Mehrez-Oued Hamous uplift to the West (Algeria) and the Nefusa uplift to the East (Libya), passing by the Touggourt-Talemzane-PGA-Bou Namcha (TTPB) structure close to southern Tunisia. The forementioned major source rocks in southern Tunisia are defined by hot shales with elevated Gamma ray values often exceeding 1400 API (in Hayatt-1 well), deposited in deep water environments during short lived (c. 2 Ma) periods of anoxia. In the course of this review, thickness, distribution and maturity maps have been established for each hot shale level using data for more than 70 wells located in both Tunisia and Algeria. Mineralogical modeling was achieved using Spectral Gamma Ray data (U, Th, K), SopectroLith logs (to acquire data for Fe, Si and Ti) and Elemental Capture Spectroscopy (ECS). The latter technique provided data for quartz, pyrite, carbonate, clay and Sulfur. In addition to this, the Gamma Ray (GR), Neutron Porosity (?N), deep Resistivity (Rt) and Bulk Density (?b) logs were used to model bulk mineralogy and lithology. Biostratigraphic and complete geochemical review has been undertaken from published papers and unpublished internal reports to better assess these important source intervals.

Soua, Mohamed

2014-12-01

309

A New Type Curve Analysis for Shale Gas/Oil Reservoir Production Performance with Dual Porosity Linear System  

E-print Network

in the Reservoir Modeling Consortium; Anas Almarzooq, Ahmad Alkouh, Orkhan Samandarli, Ammar Agnia, Tan Tran, Hassan Al-Ahmadi, Hassan Hamam, Pahala Sinurat, Salman Mengal, Wahaj Khan, and Vartit Tivayanonda, for their support and friendship. vi TABLE...

Abdulal, Haider Jaffar

2012-02-14

310

Bachaquero study: a composite analysis of the behavior of a compaction drive\\/solution-gas drive reservoir  

Microsoft Academic Search

With some 18 billion bbl of oil initially in place, the Bachaquero post-Eocene reservoir is one of the largest heavy-oil fields at the Bolivar Coast in Venezuela. The most typical feature of Bachaquero is the occurrence of substantial surface subsidence, locally exceeding 12 ft and indicating appreciable compaction of the reservoir. A study was made to analyze the subsidence\\/compaction phenomena

H. A. Merle; C. J. P. Kentie; G. van Opstal; G. M. G. Schneider

1975-01-01

311

Chemical, mineralogical and molecular biological characterization of the rocks and fluids from a natural gas storage deep reservoir as a baseline for the effects of geological hydrogen storage  

NASA Astrophysics Data System (ADS)

Planned transition to renewable energy production from nuclear and CO2-emitting power generation brings the necessity for large scale energy storage capacities. One possibility to store excessive energy produced is to transfer it to chemical forms like hydrogen which can be subsequently injected and stored in subsurface porous rock formations like depleted gas reservoirs and presently used gas storage sites. In order to investigate the feasibility of the hydrogen storage in the subsurface, the collaborative project H2STORE ("hydrogen to store") was initiated. In the scope of this project, potential reactions between microorganism, fluids and rocks induced by hydrogen injection are studied. For the long-term experiments, fluids of natural gas storage are incubated together with rock cores in the high pressure vessels under 40 bar pressure and 40° C temperature with an atmosphere containing 5.8% He as a tracer gas, 3.9% H2 and 90.3% N2. The reservoir is located at a depth of about 2 000 m, and is characterized by a salinity of 88.9 g l-1 NaCl and a temperature of 80° C and therefore represents an extreme environment for microbial life. First geochemical analyses showed a relatively high TOC content of the fluids (about 120 mg l-1) that were also rich in sodium, potassium, calcium, magnesium and iron. Remarkable amounts of heavy metals like zinc and strontium were also detected. XRD analyses of the reservoir sandstones revealed the major components: quartz, plagioclase, K-feldspar, anhydrite and analcime. The sandstones were intercalated by mudstones, consisting of quartz, plagioclase, K-feldspar, analcime, chlorite, mica and carbonates. Genetic profiling of amplified 16S rRNA genes was applied to characterize the microbial community composition by PCR-SSCP (PCR-Single-Strand-Conformation Polymorphism) and DGGE (Denaturing Gradient Gel Electrophoresis). First results indicate the presence of microorganisms belonging to the phylotypes alfa-, beta- and gamma-Proteobacteria and Actinobacteria. Sequences of these organisms have been found in subsurface environments before, e.g. in saline, hot, anoxic, and deep milieus. Due to the saline and hyperthermophilic reservoir conditions, the quantification of those microorganisms by DAPI staining revealed very low cell numbers of about 102 cells ml-1. Investigations of the microbial community composition, mineralogy and fluid chemistry after 6 months of incubation are in progress to determine to what extent hydrogen injection may contribute to a shift in the microbial community structure and abundance, microbial-mineral interactions and hydrogen-based methanogenesis.

Morozova, Daria; Kasina, Monika; Weigt, Jennifer; Merten, Dirk; Pudlo, Dieter; Würdemann, Hilke

2014-05-01

312

Soft computing-based computational intelligent for reservoir characterization  

Microsoft Academic Search

Reservoir characterization plays a crucial role in modern reservoir management. It helps to make sound reservoir decisions and improves the asset value of the oil and gas companies. It maximizes integration of multi-disciplinary data and knowledge and improves the reliability of the reservoir predictions. The ultimate product is a reservoir model with realistic tolerance for imprecision and uncertainty. Soft computing

Masoud Nikravesh

2004-01-01

313

Reservoir limnology  

SciTech Connect

This book addresses reservoirs as unique ecological systems and presents research indicating that reservoirs fall into two or three highly concatenated, interactive ecological systems ranging from riverine to lacustrine or hybrid systems. Includes some controversial concepts about the limnology of reservoirs.

Thornton, K.W.; Kimmel, B.L.; Payne, F.E.

1990-01-01

314

Uncertainty quantification of volumetric and material balance analysis of gas reservoirs with water influx using a Bayesian framework  

E-print Network

be used to estimate initial hydrocarbon volumes in place, predict future reservoir performance, and predict ultimate hydrocarbon recovery under various types of primary-drive mechanisms. The equation for the material balance method is structured... and the BB sand, are known to have water-drive. The synthetic field has a strong water drive, while the BB sand has a very weak water drive. 3 For simplicity, and without significant sacrifice of accuracy, I will use a two-parameter aquifer model...

Aprilia, Asti Wulandari

2007-04-25

315

Gas hydrate saturations estimated from fractured reservoir at Site NGHP-01-10, Krishna-Godavari Basin, India  

Microsoft Academic Search

[1] During the Indian National Gas Hydrate Program Expedition 01 (NGHP-01), one of the richest marine gas hydrate accumulations was discovered at Site NGHP-01-10 in the Krishna-Godavari Basin. The occurrence of concentrated gas hydrate at this site is primarily controlled by the presence of fractures. Assuming the resistivity of gas hydrate– bearing sediments is isotropic, the conventional Archie analysis using

M. W. Lee; T. S. Collett

2009-01-01

316

Gas hydrate saturations estimated from fractured reservoir at Site NGHP-01-10, Krishna-Godavari Basin, India  

Microsoft Academic Search

During the Indian National Gas Hydrate Program Expedition 01 (NGHP-01), one of the richest marine gas hydrate accumulations was discovered at Site NGHP-01-10 in the Krishna-Godavari Basin. The occurrence of concentrated gas hydrate at this site is primarily controlled by the presence of fractures. Assuming the resistivity of gas hydrate-bearing sediments is isotropic, the conventional Archie analysis using the logging

M. W. Lee; T. S. Collett

2009-01-01

317

Gas hydrate saturations estimated from fractured reservoir at Site NGHP-01-10, Krishna-Godavari Basin, India  

Microsoft Academic Search

During the Indian National Gas Hydrate Program Expedition 01 (NGHP-01), one of the richest marine gas hydrate accumulations was discovered at Site NGHP-01-10 in the Krishna-Godavari Basin. The occurrence of concentrated gas hydrate at this site is primarily controlled by the presence of fractures. Assuming the resistivity of gas hydrate–bearing sediments is isotropic, the conventional Archie analysis using the logging

M. W. Lee; T. S. Collett

2009-01-01

318

Reservoir characterization of tight gas sand: Taylor sandstone (upper Cotton Valley group, upper Jurassic), Rusk County, Texas  

SciTech Connect

An integrated petrographic, sedimentologic, and log analysis study of the Taylor sandstone in Rusk County, Texas, was conducted to understand the geologic controls on reservoir performance and to identify pay zones for reserves calculations. The Taylor sandstone interval consists of tightly cemented, fine-grained quartzose sandstones interbedded with mudstones, siltstones, and carbonates that occur in upward-coarsening sequences. Helium permeability rarely exceeds 0.1 md, and porosity is rarely greater than 10%. Relationships between porosity and permeability are diffuse because of a string diagenetic overprint. Six major rock types or petrofacies are distinguished on the basis of pore type and dominant cement mineralogy. Three sandstone petrofacies - primary macroporous quartz cemented, moldic macroporous quartz cemented, and microporous clay cemented - have reservoir potential. Although these petrofacies have similar porosities and permeabilities, fluid saturations differ considerably due to differences in pore geometry as indicated by petrographic and capillary pressure analyses. These three reservoir-quality petrofacies can each be identified directly on wireline logs by applying cutoffs to the porosity and normalized gamma-ray logs.

Vavra, C.L.; Scheihing, M.H.; Klein, J.D.

1989-03-01

319

Acoustic Velocity Log Numerical Simulation and Saturation Estimation of Gas Hydrate Reservoir in Shenhu Area, South China Sea  

PubMed Central

Gas hydrate model and free gas model are established, and two-phase theory (TPT) for numerical simulation of elastic wave velocity is adopted to investigate the unconsolidated deep-water sedimentary strata in Shenhu area, South China Sea. The relationships between compression wave (P wave) velocity and gas hydrate saturation, free gas saturation, and sediment porosity at site SH2 are studied, respectively, and gas hydrate saturation of research area is estimated by gas hydrate model. In depth of 50 to 245?m below seafloor (mbsf), as sediment porosity decreases, P wave velocity increases gradually; as gas hydrate saturation increases, P wave velocity increases gradually; as free gas saturation increases, P wave velocity decreases. This rule is almost consistent with the previous research result. In depth of 195 to 220?mbsf, the actual measurement of P wave velocity increases significantly relative to the P wave velocity of saturated water modeling, and this layer is determined to be rich in gas hydrate. The average value of gas hydrate saturation estimated from the TPT model is 23.2%, and the maximum saturation is 31.5%, which is basically in accordance with simplified three-phase equation (STPE), effective medium theory (EMT), resistivity log (Rt), and chloride anomaly method. PMID:23935407

Xiao, Kun; Zou, Changchun; Xiang, Biao; Liu, Jieqiong

2013-01-01

320

Acoustic velocity log numerical simulation and saturation estimation of gas hydrate reservoir in Shenhu area, South China Sea.  

PubMed

Gas hydrate model and free gas model are established, and two-phase theory (TPT) for numerical simulation of elastic wave velocity is adopted to investigate the unconsolidated deep-water sedimentary strata in Shenhu area, South China Sea. The relationships between compression wave (P wave) velocity and gas hydrate saturation, free gas saturation, and sediment porosity at site SH2 are studied, respectively, and gas hydrate saturation of research area is estimated by gas hydrate model. In depth of 50 to 245?m below seafloor (mbsf), as sediment porosity decreases, P wave velocity increases gradually; as gas hydrate saturation increases, P wave velocity increases gradually; as free gas saturation increases, P wave velocity decreases. This rule is almost consistent with the previous research result. In depth of 195 to 220?mbsf, the actual measurement of P wave velocity increases significantly relative to the P wave velocity of saturated water modeling, and this layer is determined to be rich in gas hydrate. The average value of gas hydrate saturation estimated from the TPT model is 23.2%, and the maximum saturation is 31.5%, which is basically in accordance with simplified three-phase equation (STPE), effective medium theory (EMT), resistivity log (Rt), and chloride anomaly method. PMID:23935407

Xiao, Kun; Zou, Changchun; Xiang, Biao; Liu, Jieqiong

2013-01-01

321

Seismic investigation and attribute analysis of faults and fractures within a tight-gas sandstone reservoir: Williams Fork Formation, Mamm Creek Field, Piceance Basin, Colorado  

NASA Astrophysics Data System (ADS)

The seismic-reflection characteristics, distribution and orientation of faults, and fracture intensity of the Williams Fork Formation at Mamm Creek Field vary stratigraphically and with lithology and depositional setting. The fluvial, marsh, and shallow marine deposits of the Williams Fork Formation were deposited within alluvial-plain, coastal-plain, and shallow-marine environments. The deposits produce significant amounts of natural gas from Cretaceous-age tight-gas-sandstone reservoirs that are moderately porous but exhibit low matrix permeability. Faults and fractures provide conduits for gas migration and enhance permeability and reservoir productivity. Key stratigraphic units, fault and fracture characteristics, fracture intensity, and the controls on fracture distribution were evaluated by using p-wave seismic data and derived seismic attributes in conjunction with well logs, borehole-image logs, and core data. Amplitude dimming, poor amplitude coherency, and offset reflections characterize the alluvial-plain and coastal-plain deposits. More continuous and moderate-to-high amplitude reflections are present in the lower Williams Fork Formation, which is characterized by coastal-plain and shallowmarine deposits. An ant-tracking workflow and interpreted seismic-amplitude data and curvature attributes indicate that fault characteristics are complex and vary stratigraphically; the lowermost lower Williams Fork Formation is characterized by north-northwest- and east-west-trending small scale thrust and normal faults. The uppermost lower Williams Fork Formation and the middle and upper Williams Fork formations exhibit north-northeast- and east-west-trending arrays of fault splays that terminate upward and do not appear to displace the upper Williams Fork Formation. In the uppermost Williams Fork Formation and Ohio Creek Member, north-northeast-trending discontinuities are displaced by east-west-trending events and the east-west-trending events dominate. Fracture analysis based on ant-track and t* attenuation seismic attributes suggests a nonuniform spatial distribution of fractures. In general, higher fracture intensity occurs within the southern, southwestern, and western portions of the area, and fracture intensity is greater within the fluvial reservoirs of the middle and upper Williams Fork formations. Greater than 90% of natural fractures occur in sandstones and siltstones. In-situ stress analysis, based on induced-tensile fractures and borehole breakouts, indicates a north-northwest orientation of present-day maximum horizontal stress, an approximate 20-degree rotation in the orientation of Shmax with depth, and a sudden stress shift in the Rollins Sandstone Member.

Baytok, Sait

322

SMALL, GEOLOGICALLY COMPLEX RESERVOIRS CAN BENEFIT FROM RESERVOIR SIMULATION  

SciTech Connect

The Cascade Sand zone of the Mission-Visco Lease in the Cascade Oil field of Los Angeles County, California, has been under water flood since 1970. Increasing water injection to increase oil production rates was being considered as an opportunity to improve oil recovery. However, a secondary gas cap had formed in the up-dip portion of the reservoir with very low gas cap pressures, creating concern that oil could be displaced into the gas cap resulting in the loss of recoverable oil. Therefore, injecting gas into the gas cap to keep the gas cap pressurized and restrict the influx of oil during water injection was also being considered. Further, it was recognized that the reservoir geology in the gas cap area is very complex with numerous folding and faulting and thus there are potential pressure barriers in several locations throughout the reservoir. With these conditions in mind, there were concerns regarding well to well continuity in the gas cap, which could interfere with the intended repressurization impact. Concerns about the pattern of gas flow from well to well, the possibilities of cycling gas without the desired increased pressure, and the possible loss of oil displaced into the gas cap resulted in the decision to conduct a gas tracer survey in an attempt to better define inter-well communication. Following the gas tracer survey, a reservoir model would be developed to integrate the findings of the gas tracer survey, known geologic and reservoir data, and historic production data. The reservoir model would be used to better define the reservoir characteristics and provide information that could help optimize the waterflood-gas injection project under consideration for efficient water and gas injection management to increase oil production. However, due to inadequate gas sampling procedures in the field and insufficiently developed laboratory analytical techniques, the laboratory was unable to detect the tracer in the gas samples taken. At that point, focus on, and an expansion of the scope of the reservoir simulation and modeling effort was initiated, using DOE's BOAST98 (a visual, dynamic, interactive update of BOAST3), 3D, black oil reservoir simulation package as the basis for developing the reservoir model. Reservoir characterization, modeling, and reservoir simulation resulted in a significant change in the depletion strategy. Information from the reservoir characterization and modeling effort indicate that in-fill drilling and relying on natural water influx from the aquifer could increase remaining reserves by 125,000 barrels of oil per well, and that up to 10 infill wells could be drilled in the field. Through this scenario, field production could be increased two to three times over the current 65 bopd. Based on the results of the study, permits have been applied for to drill a directional infill well to encounter the productive zone at a high angle in order to maximize the amount of pay and reservoirs encountered.

Richard E. Bennett

2002-06-24

323

Hydrologic and geochemical data collected near Skewed Reservoir, an impoundment for coal-bed natural gas produced water, Powder River Basin, Wyoming  

USGS Publications Warehouse

The Powder River Structural Basin is one of the largest producers of coal-bed natural gas (CBNG) in the United States. An important environmental concern in the Basin is the fate of groundwater that is extracted during CBNG production. Most of this produced water is disposed of in unlined surface impoundments. A 6-year study of groundwater flow and subsurface water and soil chemistry was conducted at one such impoundment, Skewed Reservoir. Hydrologic and geochemical data collected as part of that study are contained herein. Data include chemistry of groundwater obtained from a network of 21 monitoring wells and three suction lysimeters and chemical and physical properties of soil cores including chemistry of water/soil extracts, particle-size analyses, mineralogy, cation-exchange capacity, soil-water content, and total carbon and nitrogen content of soils.

Healy, Richard W.; Rice, Cynthia A.; Bartos, Timothy T.

2012-01-01

324

Gas seepage as an indicator of deeper prospective reservoirs. A study based on exploration 3D seismic data  

Microsoft Academic Search

Three periods of sustained gas seepage in geological time have been revealed in Danish block 5604\\/26 in the North Sea by the use of exploration 3D seismic data. The most recent period is indicated by a cluster of seismic chimneys which ties in to buried craters near the seabed, and possible present gas escape through the seabed, along with amplitude

Roar Heggland

1998-01-01

325

Migration Depths of Juvenile Chinook Salmon and Steelhead Relative to Total Dissolved Gas Supersaturation in a Columbia River Reservoir  

Microsoft Academic Search

The in situ depths of juvenile salmonids Oncorhynchus spp. were studied to determine whether hydrostatic compensation was sufficient to protect them from gas bubble disease (GBD) during exposure to total dissolved gas (TDG) supersaturation from a regional program of spill at dams meant to improve salmonid passage survival. Yearling Chinook salmon O. tshawytscha and juvenile steelhead O. mykiss implanted with

John W. Beeman; Alec G. Maule

2006-01-01

326

Carbonate petroleum reservoirs  

SciTech Connect

This book presents papers on the geology of petroleum deposits. Topics considered include diagenesis, porosity, dolomite reservoirs, deposition, reservoir rock, reefs, morphology, fracture-controlled production, Cenozoic reservoirs, Mesozoic reservoirs, and Paleozoic reservoirs.

Roehl, P.O.; Choquette, P.W.

1985-01-01

327

Analysis of active microorganisms and their potential role in carbon dioxide turnover in the natural gas reservoirs Altmark and Schneeren (Germany)  

NASA Astrophysics Data System (ADS)

RECOBIO-2, part of the BMBF-funded Geotechnologien consortium, investigates the presence of active microorganisms and their potential role in CO2 turnover in the formation waters of the Schneeren and Altmark gas fields, which are both operated by GDF SUEZ E&P Germany GmbH. Located to the north west of Hannover the natural gas reservoir Schneeren is composed of compacted Westfal-C sandstones that have been naturally fractured into a subsalinar horst structure. This gas field is characterized by a depth of 2700 to 3500m, a bottom-hole temperature between 80 and 110° C as well as a moderate salinity (30-60g/l) and high sulfate contents (~1000mg/l). During RECOBIO-1 produced formation water collected at wells in Schneeren was already used to conduct long term laboratory experiments. These served to examine possible microbial processes of the autochthonous biocenosis induced by the injection of CO2 (Ehinger et al. 2009 submitted). Microorganisms in particular sulfate-reducing bacteria and methanogens were able to grow in the presence of powdered rock material, CO2 and H2 without any other added nutrients. The observed development of DOC was now proven in another long term experiment using labelled 13CO2. In contrast to Schneeren, the almost depleted natural gas reservoir Altmark exhibits an average depth of 3300m, a higher bottom-hole temperature (111° C to 120° C), a higher salinity (275-350g/l) but sulfate is absent. This Rotliegend formation is located in the southern edge of the Northeast German Basin and is of special interest for CO2 injection because of favourable geological properties. Using molecular biological techniques two types of samples are analyzed: formation water collected at the well head (November 2008) and formation water sampled in situ from a depth of around 3000m (May 2009). Some of the wells are treated frequently with a foaming agent while others are chemically untreated. Despite the extreme environmental conditions in the Altmark gas field, RNA of apparently active microorganisms was successfully extracted from all samples. Sequence analysis of 16S rRNA revealed mainly fermentative bacteria belonging to the phylogenetic group of Actinobacteria (e.g. Propionibacterium spp.) and ?-Proteobacteria (e.g. Hyphomicrobium spp.) possibly involved in the nitrogen cycle. Cell numbers were determined using a PCR-independent molecular detection method (CARD-FISH) with universal 16S rRNA-specific probes (EUB338, ARCH915). The fraction of bacterial cells comprised up to 104 cells per milliliter, which corresponds to the cell numbers obtained with a generic DNA stain (DAPI). Archaeal cells could not be detected by CARD-FISH, though archaeal 16S rRNA gene fragments were amplified from DNA extracts using PCR. So far differences have neither been observed between treated and untreated formation waters nor between well head and in situ sampled formation waters. Further investigations are underway to elucidate whether particular metabolic pathways are present in the microbial assemblage of the Altmark gas field fluids. In addition, microbe-mineral interactions will be assessed using electron microscopic approaches. Ehinger, S., Kassahun, A., Muschlle, T., Gniese, C., Schlömann, M., Hoth, N., Seifert, J. (2009 submitted) Sulfate reduction by novel Thermoanaerobacteriaceae in bioreactor inoculated with gas-field brine. Environmental Microbiology

Gniese, Claudia; Muschalle, Thomas; Mühling, Martin; Frerichs, Janin; Krüger, Martin; Kassahun, Andrea; Seifert, Jana; Hoth, Nils

2010-05-01

328

Geologic factors controlling CO2 storage capacity and permanence: case studies based on experience with heterogeneity in oil and gas reservoirs applied to CO2 storage  

NASA Astrophysics Data System (ADS)

A variety of structural and stratigraphic factors control geological heterogeneity, inferred to influence both sequestration capacity and effectiveness, as well as seal capacity. Structural heterogeneity factors include faults, folds, and fracture intensity. Stratigraphic heterogeneity is primarily controlled by the geometry of depositional facies and sandbody continuity, which controls permeability structure. The permeability structure, in turn, has implications for CO2 injectivity and near-term migration pathways, whereas the long-term sequestration capacity can be inferred from the production history. Examples of Gulf Coast oil and gas reservoirs with differing styles of stratigraphic heterogeneity demonstrate the impact of facies variability on fluid flow and CO2 sequestration potential. Beach and barrier-island deposits in West Ranch field in southeast Texas are homogeneous and continuous. In contrast, Seeligson and Stratton fields in south Texas, examples of major heterogeneity in fluvial systems, are composed of discontinuous, channel-fill sandstones confined to narrow, sinuous belts. These heterogeneous deposits contain limited compartments for potential CO2 storage, although CO2 sequestration effectiveness may be enhanced by the high number of intraformational shale beds. These field examples demonstrate that areas for CO2 storage can be optimized by assessing sites for enhanced oil and gas recovery in mature hydrocarbon provinces.

Ambrose, W. A.; Lakshminarasimhan, S.; Holtz, M. H.; Núñez-López, V.; Hovorka, S. D.; Duncan, I.

2008-06-01

329

Successful reservoir prediction through integration of 3-D seismic coherency and sequence stratigraphy, East Mayaro giant gas field, offshore eastern Trinidad  

SciTech Connect

Stratigraphy in the Columbus Basin, as in most clastic basins, is characterized by episodes of shelf progradation and retrogradation in response to relative shoreline translations. Tectonic activity strongly influences accommodation space at the shelfbreak causing very rapid facies changes in a depositional dip direction. Using sparse well-data alone makes it difficult to accurately predict the shelfbreak separating sand-prone shelfal versus shale-prone deeper marine facies at any one time in the basin's history. Regional sequence stratigraphic analysis was integrated with a new 3-D discontinuity algorithm that was used for delineating faults and stratigraphic features Density-driven impedance differences between sand and shale, in the Columbus Basin, generate 3-D coherency variations that can be horizon-slice mapped to illustrate shelfbreak mitigation through time. Regional sequence stratigraphic analysis in the Columbus Basin indicate a diachronous eastward facies transition from shallow to deep marine facies throughout the Plio-Pleistocene, with a shoreline consistently oriented NW-SE. Horizon-based slices of 3D seismic data were taken in the East Mayaro area, which showed a boundary between high and low 3-D coherence areas that occurred progressively more westard with increasing depth in the section. Well data within the study area reflected deep marine, laminated sands and shales associated with the more eastward low coherency value areas. These observations were combined with regional sequence stratigraphic analysis results to predict the presence to time-equivalent, higher quality sands located on a paleo-shelf to the west. Predictions were accurate with subsequent exploration wells encountering high quality reservoir sands >450 feet (150 meters) at deeper horizons previously unseen across the area. Reservoir presence, and favorable structure and migration history, combined to result in the discovery of a giant gas/condensate field.

Ortmann, K.A.; Wood, L.J. (Amoco Production Co., Houston, TX (United States))

1996-01-01

330

Successful reservoir prediction through integration of 3-D seismic coherency and sequence stratigraphy, East Mayaro giant gas field, offshore eastern Trinidad  

SciTech Connect

Stratigraphy in the Columbus Basin, as in most clastic basins, is characterized by episodes of shelf progradation and retrogradation in response to relative shoreline translations. Tectonic activity strongly influences accommodation space at the shelfbreak causing very rapid facies changes in a depositional dip direction. Using sparse well-data alone makes it difficult to accurately predict the shelfbreak separating sand-prone shelfal versus shale-prone deeper marine facies at any one time in the basin`s history. Regional sequence stratigraphic analysis was integrated with a new 3-D discontinuity algorithm that was used for delineating faults and stratigraphic features Density-driven impedance differences between sand and shale, in the Columbus Basin, generate 3-D coherency variations that can be horizon-slice mapped to illustrate shelfbreak mitigation through time. Regional sequence stratigraphic analysis in the Columbus Basin indicate a diachronous eastward facies transition from shallow to deep marine facies throughout the Plio-Pleistocene, with a shoreline consistently oriented NW-SE. Horizon-based slices of 3D seismic data were taken in the East Mayaro area, which showed a boundary between high and low 3-D coherence areas that occurred progressively more westard with increasing depth in the section. Well data within the study area reflected deep marine, laminated sands and shales associated with the more eastward low coherency value areas. These observations were combined with regional sequence stratigraphic analysis results to predict the presence to time-equivalent, higher quality sands located on a paleo-shelf to the west. Predictions were accurate with subsequent exploration wells encountering high quality reservoir sands >450 feet (150 meters) at deeper horizons previously unseen across the area. Reservoir presence, and favorable structure and migration history, combined to result in the discovery of a giant gas/condensate field.

Ortmann, K.A.; Wood, L.J. [Amoco Production Co., Houston, TX (United States)

1996-12-31

331

High-resolution geostatistical inversion of a seismic data set acquired in a Gulf of Mexico gas reservoir.  

E-print Network

High-resolution geostatistical inversion of a seismic data set acquired in a Gulf of Mexico gas, UNOCAL Corporation Summary Geostatistical inversion is applied on a Gulf-of-Mexico, 3D post-stack seismic in this paper is located in the Gulf of Mexico, off the coast of Louisiana. Existing development wells reach two

Torres-Verdín, Carlos

332

Greenhouse Gas Emissions from a Hydroelectric Reservoir (Brazil’s Tucuruí Dam) and the Energy Policy Implications  

Microsoft Academic Search

Greenhouse gas emissions from hydroelectric dams are oftenportrayed as nonexistent by the hydropower industry, and havebeen largely ignored in global calculations of emissions fromland-use change. Brazil’s Tucuruí Dam provides an example with important lessons for policy debates on Amazonian development and on how to assess the global warming impact ofdifferent energy options. Tucuruí is better from the pointof view of

Philip M. Fearnside

2002-01-01

333

Use of Two-Phase Pseudo Pressure Method to Calculate Condensate Bank Size and Well Deliverability in Gas Condensate Reservoirs  

Microsoft Academic Search

This paper introduces a novel approach in the use of two-phase pseudo pressures for the calculation of condensate bank radius and productivity index of wells and the interpretation of gas condensate well test data. It is shown that knowledge of the relationship between condensate saturation and pressure is necessary for the integration of pseudo pressure in all regions of the

Jalal Mazloom; Fariborz Rashidi

2006-01-01

334

Large gas reservoirs and free-free emission in two lensed star-forming galaxies at z = 2.7  

NASA Astrophysics Data System (ADS)

We report the detection of CO(1-0) line emission in the bright, lensed star-forming galaxies SPT-S 233227-5358.5 (z = 2.73) and SPT-S 053816-5030.8 (z = 2.78), using the Australia Telescope Compact Array. Both galaxies were discovered in a large-area millimetre survey with the South Pole Telescope (SPT) and found to be gravitationally lensed by intervening structures. The measured CO intensities imply galaxies with molecular gas masses of (3.2 ± 0.5) × 1010(?/15)-1(XCO/0.8) and (1.7 ± 0.3) × 1010(?/20)-1(XCO/0.8) M?, and gas depletion time-scales of 4.9 × 107(XCO/0.8) and 2.6 × 107(XCO/0.8) yr, respectively, where ? corresponds to the lens magnification and XCO is the CO luminosity to gas mass conversion factor. In the case of SPT-S 053816-5030.8, we also obtained significant detections of the rest-frame 115.7 and 132.4 GHz radio continuum. Based on the radio-to-infrared spectral energy distribution and an assumed synchrotron spectral index, we find that 42 ± 10 and 55 ± 13 per cent of the flux at rest-frame 115.7 and 132.4 GHz arises from free-free emission. We find a radio-derived intrinsic star formation rate of 470 ± 170 M? yr-1, consistent within the uncertainties with the infrared estimate. Based on the morphology of this object in the source plane, the derived gas mass and the possible flattening of the radio spectral index towards low frequencies, we argue that SPT-S 053816-5030.8 exhibits properties compatible with a scaled-up local ultraluminous infrared galaxy.

Aravena, M.; Murphy, E. J.; Aguirre, J. E.; Ashby, M. L. N.; Benson, B. A.; Bothwell, M.; Brodwin, M.; Carlstrom, J. E.; Chapman, S. C.; Crawford, T. M.; de Breuck, C.; Fassnacht, C. D.; Gonzalez, A. H.; Greve, T. R.; Gullberg, B.; Hezaveh, Y.; Holder, G. P.; Holzapfel, W. L.; Keisler, R.; Malkan, M.; Marrone, D. P.; McIntyre, V.; Reichardt, C. L.; Sharon, K.; Spilker, J. S.; Stalder, B.; Stark, A. A.; Vieira, J. D.; Weiß, A.

2013-07-01

335

Factors that affect fracture fluid clean-up and pressure buildup test results in tight gas reservoirs  

E-print Network

and Water Permeability . . . 21 Fracture Relative Gas and Water Permeability . . . . . . 24 Created and Propped Fracture Lengths as a Function of Treatment Volume Based on FRACDIM ZI One Quarter of a Square Pattern with Wellbore Centered in Middle... Simulation of the Water Distribution Around the Fracture - Grid Breakup - 20 x 14 Saturation Distribution for a 250 ft. Fracture - Just After Injection has Stopped Base Case, Lc = 378 A. Saturation Distribution for a 750 ft. Fracture - Just After...

Montgomery, Kevin Todd

2012-06-07

336

30 CFR 250.407 - What tests must I conduct to determine reservoir characteristics?  

Code of Federal Regulations, 2013 CFR

...What tests must I conduct to determine reservoir characteristics? 250.407 Section...What tests must I conduct to determine reservoir characteristics? You must determine the presence, quantity, quality, and reservoir characteristics of oil, gas,...

2013-07-01

337

30 CFR 250.407 - What tests must I conduct to determine reservoir characteristics?  

...What tests must I conduct to determine reservoir characteristics? 250.407 Section...What tests must I conduct to determine reservoir characteristics? You must determine the presence, quantity, quality, and reservoir characteristics of oil, gas,...

2014-07-01

338

30 CFR 250.407 - What tests must I conduct to determine reservoir characteristics?  

Code of Federal Regulations, 2010 CFR

...What tests must I conduct to determine reservoir characteristics? 250.407 Section...What tests must I conduct to determine reservoir characteristics? You must determine the presence, quantity, quality, and reservoir characteristics of oil, gas,...

2010-07-01

339

30 CFR 250.407 - What tests must I conduct to determine reservoir characteristics?  

Code of Federal Regulations, 2012 CFR

...What tests must I conduct to determine reservoir characteristics? 250.407 Section...What tests must I conduct to determine reservoir characteristics? You must determine the presence, quantity, quality, and reservoir characteristics of oil, gas,...

2012-07-01

340

30 CFR 250.407 - What tests must I conduct to determine reservoir characteristics?  

Code of Federal Regulations, 2011 CFR

...What tests must I conduct to determine reservoir characteristics? 250.407 Section...What tests must I conduct to determine reservoir characteristics? You must determine the presence, quantity, quality, and reservoir characteristics of oil, gas,...

2011-07-01

341

PHYSICS OF A PARTIALLY IONIZED GAS RELEVANT TO GALAXY FORMATION SIMULATIONS-THE IONIZATION POTENTIAL ENERGY RESERVOIR  

SciTech Connect

Simulation codes for galaxy formation and evolution take on board as many physical processes as possible beyond the standard gravitational and hydrodynamical physics. Most of this extra physics takes place below the resolution level of the simulations and is added in a ''sub-grid'' fashion. However, these sub-grid processes affect the macroscopic hydrodynamical properties of the gas and thus couple to the ''on-grid'' physics that is explicitly integrated during the simulation. In this paper, we focus on the link between partial ionization and the hydrodynamical equations. We show that the energy stored in ions and free electrons constitutes a potential energy term which breaks the linear dependence of the internal energy on temperature. Correctly taking into account ionization hence requires modifying both the equation of state and the energy-temperature relation. We implemented these changes in the cosmological simulation code GADGET2. As an example of the effects of these changes, we study the propagation of Sedov-Taylor shock waves through an ionizing medium. This serves as a proxy for the absorption of supernova feedback energy by the interstellar medium. Depending on the density and temperature of the surrounding gas, we find that up to 50% of the feedback energy is spent ionizing the gas rather than heating it. Thus, it can be expected that properly taking into account ionization effects in galaxy evolution simulations will drastically reduce the effects of thermal feedback. To the best of our knowledge, this potential energy term is not used in current simulations of galaxy formation and evolution.

Vandenbroucke, B.; De Rijcke, S.; Schroyen, J. [Department of Physics and Astronomy, Ghent University, Krijgslaan 281, S9, B-9000 Gent (Belgium); Jachowicz, N. [Department of Physics and Astronomy, Ghent University, Proeftuinstraat 86, B-9000 Gent (Belgium)

2013-07-01

342

Pore and fracture-filling gas hydrate reservoirs in the Gulf of Mexico Gas Hydrate Joint Industry Project Leg II Green Canyon 955 H well  

Microsoft Academic Search

High-quality logging-while-drilling (LWD) downhole logs were acquired in seven wells drilled during the Gulf of Mexico Gas Hydrate Joint Industry Project Leg II in the spring of 2009. Well logs obtained in one of the wells, the Green Canyon Block 955 H well (GC955-H), indicate that a 27.4-m thick zone at the depth of 428 m below sea floor (mbsf; 1404 feet

M. W. Lee; T. S. Collett

343

Fractured gas well analysis: evaluation of in situ reservoir properties of low permeability gas wells stimulated by finite conductivity hydraulic fractures  

E-print Network

gas well. The Wellbore Fracture DEY (I) DEX (J) FIG. 1 - GRID PATTERN FOR SINULATION OF A VERTICALLY FRACTURED NELL fracture is placed in the I = 1 row of the grid pattern. When running the model with this plan view grid pattern, the well... made in this study, DEX (1) was set equal to . 001 feet. DEY (1) is always set equal to one-half the fracture width. Exception cards were used to read in high permeability and porosity in the cells containing the fracture. The dimensionless fracture...

Makoju, Charles Adoiza

2012-06-07

344

Use of multi-drain wells to more effectively extract natural gas from lenticular sand reservoirs: a feasibility study  

SciTech Connect

The purpose of this study was to determine the feasibility of the multi-drain well method in tight, lenticular formations. Although directional drilling is more costly than conventional vertical drilling, this practice could triple well production. The proposed drilling plan may be more cost efficient than drilling three separate wells with less than 320-acre spacing because it would save the costs of site surveys, rig setup, purchase of the surface lease area, and gas pipeline hookups for two additional well sites. This feasibility study was conducted on the Piceance Basin area, mainly because of the availability of geological information. The results of this study will generally apply to other regions with tight, lenticular sand, depending upon the similarity in the total percentage of sand lenses in the area and the lens dimensions and orientations. Appendix A discusses the geology of the eastern Uinta Basin in eastern Utah, and the applicability of this study to the area. Appendix B provides calculation of expected production increase due to angle of drilling. 18 refs., 30 figs., 14 tabs.

Regenhardt, C.; Dean, J.; Hancock, J.

1986-01-01

345

An overview of advanced cesium reservoir technology  

NASA Astrophysics Data System (ADS)

The cesium reservoir is a critical component pacing development of a long life thermionic power system. A variety of cesium reservoirs have been researched during the existence of thermionics technology. Cesium is the ionization medium of choice and reservoir research is directed at containing and controlling this material. Historically, reservoirs of interest have included porous tungsten, highly oriented pyrolytic graphite (HOPG), charcoal, POCO graphite, binary compounds, and gas buffered reservoirs. Russian researchers are also working on a variety of reservoirs and cesiation techniques which are generically referred to as interelectrode medium maintenance systems. Russian work follows the general thrust of US work (heat pipe based concepts, graphite reservoir concepts, and chemical compounds of cesium.) This paper discusses the merits of several of these cesiation techniques which are in various stages of development in the United States. Russian work will be addressed only as a matter of historical record.

Lamp, Thomas R.

1993-01-01

346

High-temperature quartz cement and the role of stylolites in a deep gas reservoir, Spiro Sandstone, Arkoma Basin, USA  

USGS Publications Warehouse

The Spiro Sandstone, a natural gas play in the central Arkoma Basin and the frontal Ouachita Mountains preserves excellent porosity in chloritic channel-fill sandstones despite thermal maturity levels corresponding to incipient metamorphism. Some wells, however, show variable proportions of a late-stage, non-syntaxial quartz cement, which post-dated thermal cracking of liquid hydrocarbons to pyrobitumen plus methane. Temperatures well in excess of 150°C and possibly exceeding 200°C are also suggested by (i) fluid inclusions in associated minerals; (ii) the fact that quartz post-dated high-temperature chlorite polytype IIb; (iii) vitrinite reflectance values of the Spiro that range laterally from 1.9 to ? 4%; and (iii) the occurrence of late dickite in these rocks. Oxygen isotope values of quartz cement range from 17.5 to 22.4‰ VSMOW (total range of individual in situ ion microprobe measurements) which are similar to those of quartz cement formed along high-amplitude stylolites (18.4–24.9‰). We favour a model whereby quartz precipitation was controlled primarily by the availability of silica via deep-burial stylolitization within the Spiro Sandstone. Burial-history modelling showed that the basin went from a geopressured to a normally pressured regime within about 10–15 Myr after it reached maximum burial depth. While geopressure and the presence of chlorite coats stabilized the grain framework and inhibited nucleation of secondary quartz, respectively, stylolites formed during the subsequent high-temperature, normal-pressured regime and gave rise to high-temperature quartz precipitation. Authigenic quartz growing along stylolites underscores their role as a significant deep-burial silica source in this sandstone.

Worden, Richard H.; Morad, Sadoon; Spötl, C.; Houseknecht, D.W.; Riciputi, L.R.

2000-01-01

347

New tools for modeling fracture networks and simulating gas flow in low-permeability sand and shale reservoirs  

SciTech Connect

The U.S. Department of Energy, Morgantown Energy Technology Center, has an on-going project to model and simulate gas flow in low-permeability sands and shales that contain irregular, sometimes discontinuous, fracture networks (i.e., the types of networks not adequately represented by existing models/simulators). A FORTRAN code and methodology for modeling and simulating flow in these fracture networks has been developed. The goal was to convert the locations and orientations of fractures, as observed along a horizontal well bore, into two-dimensional, geometrically and hydraulically equivalent networks, which can be used to study variability in yield and drainage pattern. The fracture network generator implements four models of increasing complexity through a Monte Carlo process of selecting fracture network attributes from fitted statistical distributions. A process of shifting fracture end-point locations along the axes of fractures provides a partial control of fracture intersection/termination frequencies. Output consists of fracture end-points and apertures. The flow simulator divides each fracture-bounded matrix block into subregions that drain to the midpoint of the adjacent fracture segment in accordance with a one-dimensional, unsteady idealization. The idealization approximates both the volume and the mean flow path length of each subregion. Volumetric flow rate in the fractures is modeled as a linear function of the pressure difference between the recharge points and the fracture intersections. The requirement of material balance between all intersections couples the individual recharge models together, and the resulting equations are solved by a Newton-Raphson technique.

McKoy, M.L.; Sams, W.N. [EG& G Technical Services of West Virginia, Inc., Morgantown, WV (United States)

1996-09-01

348

Pore-throat radius and tortuosity estimation from formation resistivity data for tight-gas sandstone reservoirs  

NASA Astrophysics Data System (ADS)

A new model is proposed for estimation of pore-throat aperture size from formation resistivity factor and permeability data. The model is validated with data from the Mesaverde sandstone using brine salinities ranging from 20,000 to 200,000 ppm. The data analyzed includes various basins such as Green River, Piceance, Sand Wash, Powder River, Uinta, Washakie and Wind River, available in the literature. For pore-throat radii analysis the methodology involves the use of log-log plots of pore-throat radius versus the product of formation resistivity factor and permeability (rT = a(FK)b + c). The model fits over 280 samples from the Mesaverde formation with coefficients of determination varying between 0.95 and 0.99 depending primarily on the type of model used for pore throat radius calculation. The brine salinity has some minor effects on the results. The model can provide better estimates of pore-throat radii if it is calibrated with experimental techniques such as mercury porosimetry. The results show pore-throat radii varying between 0.001 and 5 ?m for the Mesaverde tight sandstone; however, most of the samples fall in a range between 0.01 and 1 ?m. For tortuosity analysis, the calculation involves the use of product of formation factor and porosity data. Results indicate that the estimated tortuosity values range mainly between 1 and 5. For samples with lower porosities (< 5%), tortuosity values show a wider scatter (between 1 and 8); whereas for samples with larger porosities (> 15%), the scattering in tortuosity decreases significantly. In general, for tortuosity calculation in tight gas sandstone formations, a square root model with a parameter (bf) representing various types of connecting pores, i.e., sheet-like and tubular pores, is recommended.

Ziarani, Ali S.; Aguilera, Roberto

2012-08-01

349

Analysis of real-time reservoir monitoring : reservoirs, strategies, & modeling.  

SciTech Connect

The project objective was to detail better ways to assess and exploit intelligent oil and gas field information through improved modeling, sensor technology, and process control to increase ultimate recovery of domestic hydrocarbons. To meet this objective we investigated the use of permanent downhole sensors systems (Smart Wells) whose data is fed real-time into computational reservoir models that are integrated with optimized production control systems. The project utilized a three-pronged approach (1) a value of information analysis to address the economic advantages, (2) reservoir simulation modeling and control optimization to prove the capability, and (3) evaluation of new generation sensor packaging to survive the borehole environment for long periods of time. The Value of Information (VOI) decision tree method was developed and used to assess the economic advantage of using the proposed technology; the VOI demonstrated the increased subsurface resolution through additional sensor data. Our findings show that the VOI studies are a practical means of ascertaining the value associated with a technology, in this case application of sensors to production. The procedure acknowledges the uncertainty in predictions but nevertheless assigns monetary value to the predictions. The best aspect of the procedure is that it builds consensus within interdisciplinary teams The reservoir simulation and modeling aspect of the project was developed to show the capability of exploiting sensor information both for reservoir characterization and to optimize control of the production system. Our findings indicate history matching is improved as more information is added to the objective function, clearly indicating that sensor information can help in reducing the uncertainty associated with reservoir characterization. Additional findings and approaches used are described in detail within the report. The next generation sensors aspect of the project evaluated sensors and packaging survivability issues. Our findings indicate that packaging represents the most significant technical challenge associated with application of sensors in the downhole environment for long periods (5+ years) of time. These issues are described in detail within the report. The impact of successful reservoir monitoring programs and coincident improved reservoir management is measured by the production of additional oil and gas volumes from existing reservoirs, revitalization of nearly depleted reservoirs, possible re-establishment of already abandoned reservoirs, and improved economics for all cases. Smart Well monitoring provides the means to understand how a reservoir process is developing and to provide active reservoir management. At the same time it also provides data for developing high-fidelity simulation models. This work has been a joint effort with Sandia National Laboratories and UT-Austin's Bureau of Economic Geology, Department of Petroleum and Geosystems Engineering, and the Institute of Computational and Engineering Mathematics.

Mani, Seethambal S.; van Bloemen Waanders, Bart Gustaaf; Cooper, Scott Patrick; Jakaboski, Blake Elaine; Normann, Randy Allen; Jennings, Jim (University of Texas at Austin, Austin, TX); Gilbert, Bob (University of Texas at Austin, Austin, TX); Lake, Larry W. (University of Texas at Austin, Austin, TX); Weiss, Chester Joseph; Lorenz, John Clay; Elbring, Gregory Jay; Wheeler, Mary Fanett (University of Texas at Austin, Austin, TX); Thomas, Sunil G. (University of Texas at Austin, Austin, TX); Rightley, Michael J.; Rodriguez, Adolfo (University of Texas at Austin, Austin, TX); Klie, Hector (University of Texas at Austin, Austin, TX); Banchs, Rafael (University of Texas at Austin, Austin, TX); Nunez, Emilio J. (University of Texas at Austin, Austin, TX); Jablonowski, Chris (University of Texas at Austin, Austin, TX)

2006-11-01

350

AUTOMATED TECHNIQUE FOR FLOW MEASUREMENTS FROM MARIOTTE RESERVOIRS.  

USGS Publications Warehouse

The mariotte reservoir supplies water at a constant hydraulic pressure by self-regulation of its internal gas pressure. Automated outflow measurements from mariotte reservoirs are generally difficult because of the reservoir's self-regulation mechanism. This paper describes an automated flow meter specifically designed for use with mariotte reservoirs. The flow meter monitors changes in the mariotte reservoir's gas pressure during outflow to determine changes in the reservoir's water level. The flow measurement is performed by attaching a pressure transducer to the top of a mariotte reservoir and monitoring gas pressure changes during outflow with a programmable data logger. The advantages of the new automated flow measurement techniques include: (i) the ability to rapidly record a large range of fluxes without restricting outflow, and (ii) the ability to accurately average the pulsing flow, which commonly occurs during outflow from the mariotte reservoir.

Constantz, Jim; Murphy, Fred

1987-01-01

351

Exploring the effects of data quality, data worth, and redundancy of CO2 gas pressure and saturation data on reservoir characterization through PEST Inversion  

SciTech Connect

This study examined the impacts of reservoir properties on CO2 migration after subsurface injection and evaluated the possibility of characterizing reservoir properties using CO2 monitoring data such as saturation distribution. The injection reservoir was assumed to be located 1400-1500 m below the ground surface such that CO2 remained in the supercritical state. The reservoir was assumed to contain layers with alternating conductive and resistive properties, which is analogous to actual geological formations such as the Mount Simon Sandstone unit. The CO2 injection simulation used a cylindrical grid setting in which the injection well was situated at the center of the domain, which extended up to 8000 m from the injection well. The CO2 migration was simulated using the PNNL-developed simulator STOMP-CO2e (the water-salt-CO2 module). We adopted a nonlinear parameter estimation and optimization modeling software package, PEST, for automated reservoir parameter estimation. We explored the effects of data quality, data worth, and data redundancy on the detectability of reservoir parameters using CO2 saturation monitoring data, by comparing PEST inversion results using data with different levels of noises, various numbers of monitoring wells and locations, and different data collection spacing and temporal sampling intervals. This study yielded insight into the use of CO2 saturation monitoring data for reservoir characterization and how to design the monitoring system to optimize data worth and reduce data redundancy.

Fang, Zhufeng; Hou, Zhangshuan; Lin, Guang; Engel, David W.; Fang, Yilin; Eslinger, Paul W.

2014-04-01

352

Development of Reservoir Characterization Techniques and Production Models for Exploiting Naturally Fractured Reservoirs  

SciTech Connect

This research was directed toward developing a systematic reservoir characterization methodology which can be used by the petroleum industry to implement infill drilling programs and/or enhanced oil recovery projects in naturally fractured reservoir systems in an environmentally safe and cost effective manner. It was anticipated that the results of this research program will provide geoscientists and engineers with a systematic procedure for properly characterizing a fractured reservoir system and a reservoir/horizontal wellbore simulator model which can be used to select well locations and an effective EOR process to optimize the recovery of the oil and gas reserves from such complex reservoir systems.

Wiggins, Michael L.; Brown, Raymon L.; Civan, Faruk; Hughes, Richard G.

2003-02-11

353

Pockmarks on either side of the Strait of Gibraltar: formation from overpressured shallow contourite gas reservoirs and internal wave action during the last glacial sea-level lowstand?  

NASA Astrophysics Data System (ADS)

Integrating novel and published swath bathymetry (3,980 km2), as well as chirp and high-resolution 2D seismic reflection profiles (2,190 km), this study presents the mapping of 436 pockmarks at water depths varying widely between 370 and 1,020 m on either side of the Strait of Gibraltar. On the Atlantic side in the south-eastern Gulf of Cádiz near the Camarinal Sill, 198 newly discovered pockmarks occur in three well localized and separated fields: on the upper slope ( n=14), in the main channel of the Mediterranean outflow water (MOW, n=160), and on the huge contourite levee of the MOW main channel ( n=24) near the well-known TASYO field. These pockmarks vary in diameter from 60 to 919 m, and are sub-circular to irregularly elongated or lobate in shape. Their slope angles on average range from 3° to 25°. On the Mediterranean side of the strait on the Ceuta Drift of the western Alborán Basin, where pockmarks were already known to occur, 238 pockmarks were identified and grouped into three interconnected fields, i.e. a northern ( n=34), a central ( n=61) and a southern field ( n=143). In the latter two fields the pockmarks are mainly sub-circular, ranging from 130 to 400 m in diameter with slope angles averaging 1.5° to 15°. In the northern sector, by contrast, they are elongated up to 1,430 m, probably reflecting MOW activity. Based on seismo-stratigraphic interpretation, it is inferred that most pockmarks formed during and shortly after the last glacial sea-level lowstand, as they are related to the final erosional discontinuity sealed by Holocene transgressive deposits. Combining these findings with other existing knowledge, it is proposed that pockmark formation on either side of the Strait of Gibraltar resulted from gas and/or sediment pore-water venting from overpressured shallow gas reservoirs entrapped in coarse-grained contourites of levee deposits and Pleistocene palaeochannel infillings. Venting was either triggered or promoted by hydraulic pumping associated with topographically forced internal waves. This mechanism is analogous to the long-known effect of tidal pumping on the dynamics of unit pockmarks observed along the Norwegian continental margin.

León, Ricardo; Somoza, Luis; Medialdea, Teresa; González, Francisco Javier; Gimenez-Moreno, Carmen Julia; Pérez-López, Raúl

2014-06-01

354

Reservoir Heterogeneities between structural positions in the anticline: A case study from Kela-2 gas field in the Kuqa Depression, Tarim Basin, NW China  

Microsoft Academic Search

There are strong heterogeneous characteristics of reservoir property between the core and limbs of the Kela-2 anticline, although they are in the same structure. The reservoir heterogeneity mode of “small-scale and east-west” cannot be explained by the distribution mode of compressional stress “large-scale and south-north” proposed by previous scholars. Statistical result of petrographic composition and diagenetic characteristics shows that the

Han Denglin; Li Zhong; Shou Jianfeng; Li Weifeng

2011-01-01

355

Brine reservoirs in the Castile Formation, Waste Isolation Plant Plant (WIPP) project, southeastern New Mexico  

SciTech Connect

The analysis and interpretations by three disciplines - geology, hydrology, and chemistry - have been integrated to form a model of brine reservoir genesis, and to assess the current and future status of brine reservoirs as they relate to the WIPP site. In summary, the brine reservoirs appear to be local, isolated features that have reached equilibrium with their environment. Evidence for long-term hydraulic and chemical isolation includes: Hydraulic heads that are substantially different from reservoir to reservoir and higher than the heads of local ground waters. The containment of gas by the reservoirs. Brine and associated gas chamistries that differ from reservoir to reservoir. Geographic separation and nonuniform distribution of reservoirs, i.e., extensive drilling has taken place in this area, but only a few wells have intercepted pressurized brines. There is no evidence for a continuous, extensive aquifer in the Castile. Bulk chemical equilibrium between the brine, gas, and reservoir rock in the ERDA-6 and WIPP-12 reservoirs.

Popielak, R.S.; Beauheim, R.L.; Black, S.R.; Coons, W.E.; Ellingson, C.T.; Olsen, R.L.

1983-03-01

356

Installation of a Devonian Shale Reservoir Testing Facility and acquisition of reservoir property measurements. Final report  

SciTech Connect

In October, a contract was awarded for the Installation of a Devonian Shale Reservoir Testing Facility and Acquisition of Reservoir Property measurements from wells in the Michigan, Illinois, and Appalachian Basins. Geologic and engineering data collected through this project will provide a better understanding of the mechanisms and conditions controlling shale gas production. This report summarizes the results obtained from the various testing procedures used at each wellsite and the activities conducted at the Reservoir Testing Facility.

Locke, C.D.; Salamy, S.P.

1991-09-01

357

Geologic aspects of horizontal drilling in self-sourcing reservoirs  

SciTech Connect

Horizontal drilling techniques provide a way to exploit hydrocarbon reserves that are either noneconomic or only marginally economic using vertical drilling techniques. A significant fraction of these reserves is contained in reservoirs that are self-sourcing or in reservoirs that are closely associated with their resources. Most formations drilled as horizontal targets are self-sourcing. The Austin Chalk, Niobrara, Mesaverde, and Bakken are examples of horizontally drilled, self-sourcing reservoir systems. In formations like the Bakken or Austin Chalk, the close relationship between reservoir and source makes risks associated with migration and accumulation less important. Reservoirs of this kind can contain oil or gas and often have little or no associated water. They can be matrix-dominated reservoirs, dual-porosity reservoirs (Mesaverde), or fractured reservoirs (Austin Chalk, Bakken, and Niobrara). Fractured, self-sourcing reservoirs also can possess matrix characteristics that contribute increased recovery efficiency. Most reservoirs drilled horizontally possess matrix characteristics that contribute increased recovery efficiency. Most reservoirs drilled horizontally possess highly heterogeneous reservoir systems. Characterization of the style of reservoir heterogeneity in self-sourcing systems is important if the favorable properties of horizontally oriented bore holes are to be realized. Production data and rock mechanics considerations are important in horizontal drilling ventures. Examples of the use of these data for the purpose of defining reservoir characteristics are discussed. Knowledge of lateral changes in reservoir properties is essential if we are to recover known reserves efficiently.

Illich, H.A. (Oryx Energy Co., Dallas, TX (United States))

1991-03-01

358

Improved Recovery from Gulf of Mexico Reservoirs, Volume 4, Comparison of Methane, Nitrogen and Flue Gas for Attic Oil. February 14, 1995 - October 13, 1996. Final Report  

SciTech Connect

Gas injection for attic oil recovery was modeled in vertical sandpacks to compare the process performance characteristics of three gases, namely methane, nitrogen and flue gas. All of the gases tested recovered the same amount of oil over two cycles of gas injection. Nitrogen and flue gas recovered oil more rapidly than methane because a large portion of the methane slug dissolved in the oil phase and less free gas was available for oil displacement. The total gas utilization for two cycles of gas injection was somewhat better for nitrogen as compared to methane and flue gas. The lower nitrogen utilization was ascribed to the lower compressibility of nitrogen.

Wolcott, Joanne; Shayegi, Sara

1997-01-13

359

Impact of coal seam as interlayer on CO 2 storage in saline aquifers: A reservoir simulation study  

Microsoft Academic Search

Geological storage of CO2 is a viable option for the mitigation of greenhouse gas emissions. Two main reservoir types exist; porous formations such as saline aquifers or depleted oil or gas reservoirs and, of lesser importance in terms of storage capacity, coal or shale reservoirs. These reservoirs have distinct storage mechanisms; in the porous formations the CO2 is stored within

Zhejun Pan; Luke D. Connell

2011-01-01

360

Sharing Reservoirs  

E-print Network

Large reservoirs such as oil fields are typically split into exploratory blocks for different consortia. Although space demarcation at the surface level is a standard process, finding the corresponding effective extents of the shares is not simple. We introduce a theoretical framework to identify the effectively exploitable volumes and characterize their boundaries, based on the number of consortia. For three consortia, we show that in an uncorrelated medium the set of shared regions is a fractal of dimension $d_\\text{tot}=1.69\\pm0.02$. The subset of these shared sites spanning the entire medium has fractal dimension $d_\\text{lc}=1.55\\pm0.03$. The peculiar topological properties of the emerging clusters of shared sites are analyzed and the model is shown to exhibit a tricritical crossover involving also a negative exponent at criticality.

Schrenk, K J; Herrmann, H J

2012-01-01

361

A New Method for History Matching and Forecasting Shale Gas/Oil Reservoir Production Performance with Dual and Triple Porosity Models  

E-print Network

, at the top of the list for valuable courses that are taught at Texas A&M University. I also want to acknowledge my colleagues in the Reservoir Modeling Consortium: Hasan Al-Ahmadi, Hassan Hamam, Anas Almarzooq, Pahala Sinurat, vii Salman Mengal, Haider...

Samandarli, Orkhan

2012-10-19

362

Seismic characteristics of sandstone hydrocarbon reservoirs  

Microsoft Academic Search

In seismic terms, three distinct zones of sandstone reservoirs can be defined (Neidell, SEG Distinguished Lecture, 1986): Zone I sands with low acoustic impedance when wet and, in contrast with contemporary aged shales, gas presence is signaled with Bright Spots; Zone III sands have impedance values higher than associated shales (The Compacted Zone) and indicate gas presence with subtle amplitude

N. S. Neidell; W. C. Lefler; W. R. Landwer; M. Smith

1993-01-01

363

Comprehensive Analysis of Enhanced CBM Production via CO2 Injection Using a Surrogate Reservoir Model Jalal Jalali, Shahab D. Mohaghegh, Dept. of Petroleum & Natural Gas Engineering, West Virginia University  

E-print Network

Comprehensive Analysis of Enhanced CBM Production via CO2 Injection Using a Surrogate Reservoir University 8th Annual Conference on Carbon Capture & Sequestration, May 4th ­ 7th 2009, Pittsburgh, PA Reservoir simulation is the industry standard for reservoir management. Complex reservoir models usually

Mohaghegh, Shahab

364

Production-induced changes in reservoir geomechanics  

NASA Astrophysics Data System (ADS)

Sand production remains a source of concern in both conventional and heavy oil production. Porosity increase and changes in local stress magnitude, which often enhance permeability, have been associated with severe sanding. On the other hand, sand production has been linked to a large number of field incidences involving loss of well integrity, casing collapse and corrosion of down-hole systems. It also poses problems for separators and transport facilities. Numerous factors such as reservoir consolidation, well deviation angle through the reservoir, perforation size, grain size, capillary forces associated with water cut, flow rate and most importantly reservoir strain resulting from pore pressure depletion contribute to reservoir sanding. Understanding field-specific sand production patterns in mature fields and poorly consolidated reservoirs is vital in identifying sand-prone wells and guiding remedial activities. Reservoir strain analysis of Forties Field, located in the UK sector of the North Sea, shows that the magnitude of the production-induced strain, part of which is propagated to the base of the reservoir, is of the order of 0.2 %, which is significant enough to impact the geomechanical properties of the reservoir. Sand production analysis in the field shows that in addition to poor reservoir consolidation, a combined effect of repeated perforation, high well deviation, reservoir strain and high fluid flow rate have contributed significantly to reservoir sanding. Knowledge of reservoir saturation variation is vital for in-fill well drilling, while information on reservoir stress variation provides a useful guide for sand production management, casing design, injector placement and production management. Interpreting time-lapse difference is enhanced by decomposing time-lapse difference into saturation, pressure effects and changes in rock properties (e.g. porosity) especially in highly compacting reservoirs. Analyzing the stress and saturation sensitivity of the reservoir and overburden shale of Forties Field, I observe that while pore pressure variations have not been significant in most parts of the field, a relatively higher decrease in pore pressure in a region of the reservoir has affected the geomechanical properties of both reservoir and overlying rock strata . I found that strain development in the field accounts, in part, for increased reservoir sand production and a negative velocity change in the overburden, which provides an indication of dilation. I use changes in the AVO intercept and gradient calibrated with laboratory measurements to decouple the time-lapse (4D) difference into saturation and pressure changes. Furthermore, I propose a new modification to time-lapse AVO inversion workflows to account for the effect of porosity change in measurements of time-lapse difference. This is particularly crucial in highly-compacting chalk and poorly consolidated clastic reservoirs. Rock-physics-driven inversion of 3D pre-stack seismic data plays a prominent role in the characterization of both reservoir and overburden rocks. Understanding the rock physics of the overburden rock is required for efficient production of the reservoir and to safeguard wellbore, down-hole assembly and supporting surface facilities. Taking Forties Field as a case study, I observe that while instability and subsequent failure of the overburden in the field can be linked to the rapid decrease of the unconfined compressive strength (UCS) at inclinations close to 45 degrees to the bedding plan, some zones in the overburden are characterized by extreme weakness regardless of the well angle through the rock. I use the correlation between unconfined compressive strength and elastic moduli (Young's and Bulk moduli), coupled with the results of simultaneous inversion to derive 3D elastic moduli, calibrated to laboratory measurements, to characterize the zones of extreme weakness. Time-lapse gravimetry continues to find increasing application in reservoir monitoring, typically in gas reservoirs and reservoirs used for CO2 sequestration.

Amoyedo, Sunday O.

365

Gas  

MedlinePLUS

... swallow and the breakdown of undigested food by bacteria in the large intestine. Certain foods may cause gas. Foods that produce gas in one person may not cause gas in another. You can reduce the amount of gas you have by Drinking lots of water and non-fizzy drinks Eating more slowly so ...

366

Prediction of reservoir compaction and surface subsidence  

Microsoft Academic Search

A new loading-rate-dependent compaction model for unconsolidated clastic reservoirs is presented that considerably improves the accuracy of predicting reservoir rock compaction and surface subsidence resulting from pressure depletion in oil and gas fields. The model has been developed on the basis of extensive laboratory studies and can be derived from a theory relating compaction to time-dependent intergranular friction. The procedure

J. A. De Waal; R. M. M. Smits

1988-01-01

367

Carbon emission from global hydroelectric reservoirs revisited.  

PubMed

Substantial greenhouse gas (GHG) emissions from hydropower reservoirs have been of great concerns recently, yet the significant carbon emitters of drawdown area and reservoir downstream (including spillways and turbines as well as river reaches below dams) have not been included in global carbon budget. Here, we revisit GHG emission from hydropower reservoirs by considering reservoir surface area, drawdown zone and reservoir downstream. Our estimates demonstrate around 301.3 Tg carbon dioxide (CO2)/year and 18.7 Tg methane (CH4)/year from global hydroelectric reservoirs, which are much higher than recent observations. The sum of drawdown and downstream emission, which is generally overlooked, represents 42 % CO2 and 67 % CH4 of the total emissions from hydropower reservoirs. Accordingly, the global average emissions from hydropower are estimated to be 92 g CO2/kWh and 5.7 g CH4/kWh. Nonetheless, global hydroelectricity could currently reduce approximate 2,351 Tg CO2eq/year with respect to fuel fossil plant alternative. The new findings show a substantial revision of carbon emission from the global hydropower reservoirs. PMID:24943886

Li, Siyue; Zhang, Quanfa

2014-12-01

368

Reservoir CharacterizationReservoir Characterization Research LaboratoryResearch Laboratory  

E-print Network

Reservoir CharacterizationReservoir Characterization Research LaboratoryResearch Laboratory at Austin Austin, Texas 78713Austin, Texas 78713--89248924 #12;Reservoir Characterization Research Platform, The Dolomites, Italy. #12;iii Reservoir Characterization Research Laboratory Research Plans

Texas at Austin, University of

369

High-resolution reservoir characterization of midcontinent sandstones using wireline resistivity imaging, Boonsville (Bend Conglomerate) Gas Field, Fort Worth Basin, TX  

SciTech Connect

In the absence of abundant core data, Formation MicroScanner* (FMS) and Fullbore Formation Microlmager* (FMI) wireline logs from 3 wells in Boonsville Field provided continuous geologic information in a 1000-foot thick, Pennsylvanian (Atoka) interval. Cores provided the most detailed sequence-stratigraphic information, but only 358 ft of core from 4 wells was available to evaluate the 30 mi{sup 2} project area. The FMS and FMI logs thus served as continuous, oriented {open_quote}virtual cores{close_quote} that expanded our stratigraphic database and improved our interpretations, which included the identification of key chronostratigraphic surfaces, lithofacies, sedimentary structures, faults, and fractures. Paleocurrents inferred from the FMS and FMI images suggest that most Bend Conglomerate sandstones are lowstand valley-fill deposits derived from the Muenster and Red River Uplifts, rather than Ouachita-derived deltas. Combined analysis of cores and wireline resistivity imaging technology enabled the development of a fine-scale, sequence-stratigraphic framework which formed the basis for correlation and mapping of the major Bend Conglomerate reservoir zones, and helped us to identify compartmentalization mechanisms within these complex reservoirs.

Carr, D.L. [Consulting Geologist, Austin, TX (United States); Elphick, R.Y. [Scientific Software-Intercomp, Denver, CO (United States); Foulk, L.S. [Schlumberger Well Services, Englewood, CO (United States)

1996-12-31

370

High-resolution reservoir characterization of midcontinent sandstones using wireline resistivity imaging, Boonsville (Bend Conglomerate) Gas Field, Fort Worth Basin, TX  

SciTech Connect

In the absence of abundant core data, Formation MicroScanner* (FMS) and Fullbore Formation Microlmager* (FMI) wireline logs from 3 wells in Boonsville Field provided continuous geologic information in a 1000-foot thick, Pennsylvanian (Atoka) interval. Cores provided the most detailed sequence-stratigraphic information, but only 358 ft of core from 4 wells was available to evaluate the 30 mi[sup 2] project area. The FMS and FMI logs thus served as continuous, oriented [open quote]virtual cores[close quote] that expanded our stratigraphic database and improved our interpretations, which included the identification of key chronostratigraphic surfaces, lithofacies, sedimentary structures, faults, and fractures. Paleocurrents inferred from the FMS and FMI images suggest that most Bend Conglomerate sandstones are lowstand valley-fill deposits derived from the Muenster and Red River Uplifts, rather than Ouachita-derived deltas. Combined analysis of cores and wireline resistivity imaging technology enabled the development of a fine-scale, sequence-stratigraphic framework which formed the basis for correlation and mapping of the major Bend Conglomerate reservoir zones, and helped us to identify compartmentalization mechanisms within these complex reservoirs.

Carr, D.L. (Consulting Geologist, Austin, TX (United States)); Elphick, R.Y. (Scientific Software-Intercomp, Denver, CO (United States)); Foulk, L.S. (Schlumberger Well Services, Englewood, CO (United States))

1996-01-01

371

Application of integrated reservoir management and reservoir characterization to optimize infill drilling  

SciTech Connect

This project has used a multi-disciplinary approach employing geology, geophysics, and engineering to conduct advanced reservoir characterization and management activities to design and implement an optimized infill drilling program at the North Robertson (Clearfork) Unit in Gaines County, Texas. The activities during the first Budget Period consisted of developing an integrated reservoir description from geological, engineering, and geostatistical studies, and using this description for reservoir flow simulation. Specific reservoir management activities were identified and tested. The geologically targeted infill drilling program currently being implemented is a result of this work. A significant contribution of this project is to demonstrate the use of cost-effective reservoir characterization and management tools that will be helpful to both independent and major operators for the optimal development of heterogeneous, low permeability shallow-shelf carbonate (SSC) reservoirs. The techniques that are outlined for the formulation of an integrated reservoir description apply to all oil and gas reservoirs, but are specifically tailored for use in the heterogeneous, low permeability carbonate reservoirs of West Texas.

NONE

1997-04-01

372

Reservoir Operation in Texas  

E-print Network

demands being placed upon the surface water resources. The climate of the state is characterized by floods and droughts. Reservoirs are necessary to control and utilize the highly variable streamflow. Numerous reservoirs have been constructed to facilitate...

Wurbs, Ralph A.

373

Integration of reservoir simulation and geomechanics  

NASA Astrophysics Data System (ADS)

Fluid production from tight and shale gas formations has increased significantly, and this unconventional portfolio of low-permeability reservoirs accounts for more than half of the gas produced in the United States. Stimulation and hydraulic fracturing are critical in making these systems productive, and hence it is important to understand the mechanics of the reservoir. When modeling fractured reservoirs using discrete-fracture network representation, the geomechanical effects are expected to have a significant impact on important reservoir characteristics. It has become more accepted that fracture growth, particularly in naturally fractured reservoirs with extremely low permeability, cannot be reliably represented by conventional planar representations. Characterizing the evolution of multiple, nonplanar, interconnected and possibly nonvertical hydraulic fractures requires hydraulic and mechanical characterization of the matrix, as well as existing latent or healed fracture networks. To solve these challenging problems, a reservoir simulator (Advanced Reactive Transport Simulator (ARTS)) capable of performing unconventional reservoir simulation is developed in this research work. A geomechanical model has been incorporated into the simulation framework with various coupling schemes and this model is used to understand the geomechanical effects in unconventional oil and gas recovery. This development allows ARTS to accept geomechanical information from external geomechanical simulators (soft coupling) or the solution of the geomechanical coupled problem (hard coupling). An iterative solution method of the flow and geomechanical equations has been used in implementing the hard coupling scheme. The hard coupling schemes were verified using one-dimensional and two-dimensional analytical solutions. The new reservoir simulator is applied to learn the influence of geomechanical impact on unconventional oil and gas production in a number of practical recovery scenarios. A commercial simulator called 3DEC was the geomechanical simulator used in soft coupling. In a naturally fractured reservoir, considering geomechanics may lead to an increase or decrease in production depending on the relationship between the reservoir petrophysical properties and mechanics. Combining geomechanics and flow in multiphase flow settings showed that production decrease could be caused by a combination of fracture contraction and water blockage. The concept of geomechanical coupling was illustrated with a complex naturally fractured system containing 44 fractures. Development of the generalized framework, being able to study multiphase flow reservoir processes with coupled geomechanics, and understanding of complex phenomena such as water blocks are the major outcomes from this research. These new tools will help in creating strategies for efficient and sustainable production of fluids from unconventional resources.

Zhao, Nan

374

Reservoir management applications to oil reservoirs  

SciTech Connect

Winnipegosis and Red River oil production in the Bainville North Field in Roosevelt County, Montana began in 1979. The Red River is at 12,500 ft and one well is completed in the Nisku formation at 10,200 ft. This well produced 125,000 bbl from the Nisku during its first 41 months. Since operating conditions inhibit dual completions and Nisku wells cost $900,000, the need for a Nisku development plan is apparent. The size of the reservoir and optimum well density are the key unknowns. Recognizing the need for additional Nisku data, a 5000 acre 3-D seismic survey was processed and the results used to map the top of the Nisku. The reservoir thickness, porosity, and water saturation were known from the openhole logs at eight well locations on an average of 320 acres spacing. The thickness of the thin pay limited the seismic information to areal extent of reservoir depth. Static reservoir pressure from drillstem test was available at two wells. Additional reservoir pressure data in the form of transient tests were available at two wells. Under Los Alamos National Laboratory Basic Ordering Agreement 9-XU3-0402J-1, the New Mexico Petroleum Recovery Research Center (PRRC) characterized the Nisku to develop a reservoir management plan. Nance Petroleum provided all available field and laboratory data for characterizing the Nisku formation. Due to sparse well coverage, and the lack of producing wells, the PRRC had to develop a new reservoir description approach to reach an acceptable characterization of the entire reservoir. This new approach relies on the simultaneous use of 3-D seismic and reservoir simulation to estimate key reservoir properties.

Martin, F.D.; Ouenes, A.; Weiss, W.W.; Chawathe, A.

1996-02-01

375

Reservoir Characterization Research Laboratory  

E-print Network

Reservoir Characterization Research Laboratory for Carbonate Studies Executive Summary/Al 0.00 0.02 0.04 Eagle Ford Fm #12;#12; Reservoir Characterization Research Laboratory Research Plans for 2014 Outcrop and Subsurface Characterization of Carbonate Reservoirs for Improved Recovery of Remaining

Texas at Austin, University of

376

SEISMIC ATTENUATION FOR RESERVOIR CHARACTERIZATION  

SciTech Connect

We have developed and tested technology for a new type of direct hydrocarbon detection. The method uses inelastic rock properties to greatly enhance the sensitivity of surface seismic methods to the presence of oil and gas saturation. These methods include use of energy absorption, dispersion, and attenuation (Q) along with traditional seismic attributes like velocity, impedance, and AVO. Our approach is to combine three elements: (1) a synthesis of the latest rock physics understanding of how rock inelasticity is related to rock type, pore fluid types, and pore microstructure, (2) synthetic seismic modeling that will help identify the relative contributions of scattering and intrinsic inelasticity to apparent Q attributes, and (3) robust algorithms that extract relative wave attenuation attributes from seismic data. This project provides: (1) Additional petrophysical insight from acquired data; (2) Increased understanding of rock and fluid properties; (3) New techniques to measure reservoir properties that are not currently available; and (4) Provide tools to more accurately describe the reservoir and predict oil location and volumes. These methodologies will improve the industry's ability to predict and quantify oil and gas saturation distribution, and to apply this information through geologic models to enhance reservoir simulation. We have applied for two separate patents relating to work that was completed as part of this project.

Joel Walls; M.T. Taner; Naum Derzhi; Gary Mavko; Jack Dvorkin

2003-12-01

377

Status of Cherokee Reservoir  

SciTech Connect

This is the first in a series of reports prepared by Tennessee Valley Authority (TVA) for those interested in the conditions of TVA reservoirs. This overviews of Cherokee Reservoir summarizes reservoir and watershed characteristics, reservoir uses and use impairments, water quality and aquatic biological conditions, and activities of reservoir management agencies. This information was extracted from the most current reports, publications, and data available, and interviews with water resource professionals in various Federal, state, and local agencies and in public and private water supply and wastewater treatment facilities. 11 refs., 4 figs., 1 tab.

Not Available

1990-08-01

378

Improved methodology for determining total gas content. Volume 2. Comparative evaluation of the accuracy of gas-in-place estimates and review of lost gas models. Topical report, November 16, 1993-October 31, 1995  

SciTech Connect

This report provides exploration geologists and reservoir engineers with insights into the accuracy and reliability of the procedures commonly used to acquire and analyze canister gas desorption data and estimate coal seam gas reservoir gas content values.

Mavor, M.J.; Pratt, T.J.

1996-03-01

379

MULTIDISCIPLINARY IMAGING OF ROCK PROPERTIES IN CARBONATE RESERVOIRS FOR FLOW-UNIT TARGETING  

SciTech Connect

Despite declining production rates, existing reservoirs in the US contain large quantities of remaining oil and gas that constitute a huge target for improved diagnosis and imaging of reservoir properties. The resource target is especially large in carbonate reservoirs, where conventional data and methodologies are normally insufficient to resolve critical scales of reservoir heterogeneity. The objectives of the research described in this report were to develop and test such methodologies for improved imaging, measurement, modeling, and prediction of reservoir properties in carbonate hydrocarbon reservoirs. The focus of the study is the Permian-age Fullerton Clear Fork reservoir of the Permian Basin of West Texas. This reservoir is an especially appropriate choice considering (a) the Permian Basin is the largest oil-bearing basin in the US, and (b) as a play, Clear Fork reservoirs have exhibited the lowest recovery efficiencies of all carbonate reservoirs in the Permian Basin.

Stephen C. Ruppel

2005-02-01

380

Acoustic properties of reservoir fluids  

NASA Astrophysics Data System (ADS)

Both water and hydrocarbons are important resources in reservoir exploration. These real reservoirs behave as mixtures or solutions including dissolved gases, and the properties of a solvent can be significantly affected by the type and concentration of gas dissolved in it. A crucial part of any reservoir monitoring research program must experimentally determine the acoustic velocities, compressibilities, and densities of various gas-fluid solutions at varying temperatures, pressures, and concentrations. A phase-interference method was developed for velocity measurement, where double impulses and double reflectors were combined to fulfill the interference requirements. A robust system and a reliable protocol to measure velocity of gas-fluid solutions were accomplished with high accuracy of 0.05%. Measurement of pure fluids is the first step in obtaining robust and reliable results for unknown gas-fluid solutions. Typical gas solutes, CO2,/ CH4,/ N2 and NH3, and solvents, water and decane, were selected as the samples for the solution study. We discovered that the two solvents showed reverse trends in velocity when gas was dissolved into them. For gas aqueous solution, the velocity of the solution increases with increasing concentration. Velocity increases up to 50 m/s (?3%) and 140 m/s (?9%) for CO2 aqueous solution and NH3 aqueous solution respectively. These results were obtained at room temperature ([/approx]22oC) with CO2 saturated vapor pressure of 400 psi, and NH3 saturated vapor pressure of 70 psi. Velocity increases only slightly (?0.1%) for CH4 and N2 aqueous solutions. Conversely, for gases dissolved in decane, the velocity of the solution decreases with increasing concentration. Velocity decreases about 100 m/s for CH4 (?8%), 130 m/s for CO2 (?10%), and 47 m/s for N2 (?4%) at saturated vapor pressures of 500 psi, 400 psi, and 600 psi, respectively. Water yielded anomalous properties while decane gave normal results. A mechanism was proposed based on the interstitial structure of water to interpret the anomalous properties during gas dissolution. Water behaves abnormally because of its hydrogen bonds and special lattice structure, where a vacancy exists in each bonded unit. Free solute molecules can occupy the vacancies in some of the units to strengthen the entire system.

Liu, Yuguang

381

A committee machine with intelligent systems for estimation of total organic carbon content from petrophysical data: An example from Kangan and Dalan reservoirs in South Pars Gas Field, Iran  

NASA Astrophysics Data System (ADS)

Total organic carbon (TOC) content present in reservoir rocks is one of the important parameters, which could be used for evaluation of residual production potential and geochemical characterization of hydrocarbon-bearing units. In general, organic-rich rocks are characterized by higher porosity, higher sonic transit time, lower density, higher ?-ray, and higher resistivity than other rocks. Current study suggests an improved and optimal model for TOC estimation by integration of intelligent systems and the concept of committee machine with an example from Kangan and Dalan Formations, in South Pars Gas Field, Iran. This committee machine with intelligent systems (CMIS) combines the results of TOC predicted from intelligent systems including fuzzy logic (FL), neuro-fuzzy (NF), and neural network (NN), each of them has a weight factor showing its contribution in overall prediction. The optimal combination of weights is derived by a genetic algorithm (GA). This method is illustrated using a case study. One hundred twenty-four data points including petrophysical data and measured TOC from three wells of South Pars Gas Field were divided into 87 training sets to build the CMIS model and 37 testing sets to evaluate the reliability of the developed model. The results show that the CMIS performs better than any one of the individual intelligent systems acting alone for predicting TOC.

Kadkhodaie-Ilkhchi, Ali; Rahimpour-Bonab, Hossain; Rezaee, Mohammadreza

2009-03-01

382

1-Nearwell local space and time refinement in reservoir simulation.  

E-print Network

1-Nearwell local space and time refinement in reservoir simulation. 2- Applying of the Two. Dirichlet Neumann Interface Conditions (IC). Windowing (Eclipse): Two grid levels: full coarse grid and LGR;Simplified two phase flow model Injection of a phase 2 (gas) in a 3D reservoir initially saturated

Ribot, Magali

383

Wellbore stability analysis in carbonate reservoir considering anisotropic behaviour  

Microsoft Academic Search

Carbonate reservoirs represent a major part of the world oil and gas reserves. In particular, recent discoveries in the pre-salt offshore Brazil place big challenges to exploration and production under high temperatures and pressures (HTHP). During production, the extraction of hydrocarbons reduces pore pressure and thus causes an increase in the effective stress and mechanical compaction in the reservoir. The

José Alves; Nestor Guevara; Lucia Coelho; Patrick Baud

2010-01-01

384

Dolomite reservoirs: Porosity evolution and reservoir characteristics  

SciTech Connect

Systematic analyses of the published record of dolomite reservoirs worldwide reveal that the majority of hydrocarbon-producing dolomite reservoirs occurs in (1) peritidal-dominated carbonate, (2) subtidal carbonate associated with evaporitic tidal flat/lagoon, (3) subtidal carbonate associated with basinal evaporite, and (4) nonevaporitic carbonate sequence associated with topographic high/unconformity, platform-margin buildup or fault/fracture. Reservoir characteristics vary greatly from one dolomite type to another depending upon the original sediment fabric, the mechanism by which dolomite was formed, and the extent to which early formed dolomite was modified by post-dolomitization diagenetic processes (e.g., karstification, fracturing, and burial corrosion). This paper discusses the origin of dolomite porosity and demonstrates the porosity evolution and reservoir characteristics of different dolomite types.

Sun, S.Q. [Masera International Ltd., London (United Kingdom)

1995-02-01

385

APPLICATION OF INTEGRATED RESERVOIR MANAGEMENT AND RESERVOIR CHARACTERIZATION  

Microsoft Academic Search

Reservoir performance and characterization are vital parameters during the development phase of a project. Infill drilling of wells on a uniform spacing, without regard to characterization does not optimize development because it fails to account for the complex nature of reservoir heterogeneities present in many low permeability reservoirs, especially carbonate reservoirs. These reservoirs are typically characterized by: (1) large, discontinuous

Jack Bergeron; Tom Blasingame; Louis Doublet; Mohan Kelkar; George Freeman; Jeff Callard; David Moore; David Davies; Richard Vessell; Brian Pregger; Bill Dixon; Bryce Bezant

2000-01-01

386

Optimising hydraulic fracture treatments in reservoirs under complex conditions.  

E-print Network

??Growing global energy demand has prompted the exploitation of non-conventional resources such as Coal Bed Methane (CBM) and conventional resources such as gas-condensate reservoirs. Exploitation… (more)

Valencia, Karen Joy

2005-01-01

387

Hydrophobic liquid/gas separator for heat pipes  

NASA Technical Reports Server (NTRS)

Perforated nonwetting plug of material such as polytetrafluoroethylene is mounted in gas reservoir feed tube, preferably at end which extends into heat pipe condenser section, to prevent liquid from entering gas reservoir of passively controlled heat pipe.

Marcus, B. D.

1972-01-01

388

Reservoir Simulation and Uncertainty Analysis of Enhanced CBM Production Using Artificial Neural Networks  

E-print Network

SPE 125959 Reservoir Simulation and Uncertainty Analysis of Enhanced CBM Production Using Coalbed methane is becoming one of the major natural gas resources. CO2 injection into CBM reservoirs2 (CO2Seq). Reservoir simulation is used regularly for building representative ECBM and CO2Seq

Mohaghegh, Shahab

389

Optimization of condensing gas drive  

E-print Network

- cal, undersaturated reservoir with gas being injected into the crest and oil being produced from the base of the structure. Fractional oil re- covery at gas breakthrough proved to be less sensitive to changes in oil withdrawal rates as the gas... of gravity will result when gas is injected into the crest and oil produced from the base of a vertical reservoir. 4 Terwilliger, et al. demonstrated that fractional oil recovery at gas breakthrough is inversely proportional to the oil withdrawal rate...

Lofton, Larry Keith

1977-01-01

390

CFD Modeling of Methane Production from Hydrate-Bearing Reservoir  

SciTech Connect

Methane hydrate is being examined as a next-generation energy resource to replace oil and natural gas. The U.S. Geological Survey estimates that methane hydrate may contain more organic carbon the the world's coal, oil, and natural gas combined. To assist in developing this unfamiliar resource, the National Energy Technology Laboratory has undertaken intensive research in understanding the fate of methane hydrate in geological reservoirs. This presentation reports preliminary computational fluid dynamics predictions of methane production from a subsurface reservoir.

Gamwo, I.K.; Myshakin, E.M.; Warzinski, R.P.

2007-04-01

391

95. BOUQUET RESERVOIR LOOKING UP VALLEY TO RESERVOIR LOOKING EAST ...  

Library of Congress Historic Buildings Survey, Historic Engineering Record, Historic Landscapes Survey

95. BOUQUET RESERVOIR LOOKING UP VALLEY TO RESERVOIR LOOKING EAST - Los Angeles Aqueduct, From Lee Vining Intake (Mammoth Lakes) to Van Norman Reservoir Complex (San Fernando Valley), Los Angeles, Los Angeles County, CA

392

Volume 3: Characterization of representative reservoirs -- South Marsh Island 73, B35K and B65G Reservoirs  

SciTech Connect

This report documents the results of a detailed study of two Gulf of Mexico salt dome related reservoirs and the application of a publicly available PC-based black oil simulator to model the performances of gas injection processes to recover attic oil. The overall objective of the research project is to assess the oil reserve potential that could result from the application of proven technologies to recover bypassed oil from reservoirs surrounding piercement salt domes in the Gulf of Mexico. The specific study objective was to simulate the primary recovery and attic gas injection performance of the two subject reservoirs to: (1) validate the BOAST model; (2) quantify the attic volume; and (3) predict the attic oil recovery potential that could result from additional updip gas injection. The simulation studies were performed on the B-35K Reservoir and the B-65G Reservoir in the South Marsh Island Block 73 Field using data provided by one of the field operators. A modified PC-version of the BOAST II model was used to match the production and injection performances of these reservoirs in which numerous gas injection cycles had been conducted to recover attic oil. The historical performances of the gas injection cycles performed on both the B-35K Reservoir and B-65G Reservoir were accurately matched, and numerous predictive runs were made to define additional potential for attic oil recovery using gas injection. Predictive sensitivities were conducted to examine the impact of gas injection rate, injection volume, post-injection shut-in time, and the staging of gas injection cycles on oil recovery.

Young, M.A.; Salamy, S.P.; Reeves, T.K. [BDM-Oklahoma, Inc., Bartlesville, OK (United States); Kimbrell, W.C. [Louisiana State Univ., Baton Rouge, LA (United States). Dept. of Petroleum Engineering; Sawyer, W.K. [Mathematical and Computer Services, Inc., Danville, VA (United States)

1998-07-01

393

CO2 storage resources, reserves, and reserve growth: Toward a methodology for integrated assessment of the storage capacity of oil and gas reservoirs and saline formations  

USGS Publications Warehouse

Geologically based methodologies to assess the possible volumes of subsurface CO2 storage must apply clear and uniform definitions of resource and reserve concepts to each assessment unit (AU). Application of the current state of knowledge of geologic, hydrologic, geochemical, and geophysical parameters (contingencies) that control storage volume and injectivity allows definition of the contingent resource (CR) of storage. The parameters known with the greatest certainty are based on observations on known traps (KTs) within the AU that produced oil, gas, and water. The aggregate volume of KTs within an AU defines the most conservation volume of contingent resource. Application of the concept of reserve growth to CR volume provides a logical path for subsequent reevaluation of the total resource as knowledge of CO2 storage processes increases during implementation of storage projects. Increased knowledge of storage performance over time will probably allow the volume of the contingent resource of storage to grow over time, although negative growth is possible. ?? 2009 Elsevier Ltd. All rights reserved.

Burruss, R.C.

2009-01-01

394

Reservoir Characterization Using Intelligent Seismic Inversion  

E-print Network

Reservoir Characterization Using Intelligent Seismic Inversion Emre Artun, WVU Shahab D. Mohaghegh, W.V. SPE Paper # 98012 #12;motivation > Reservoir Modeling Workflow Exploration: Seismic Surveys Exploration Drilling Reservoir Characterization Reservoir Simulation A structural model of the reservoir can

Mohaghegh, Shahab

395

Prediction of reservoir compaction and surface subsidence  

SciTech Connect

A new loading-rate-dependent compaction model for unconsolidated clastic reservoirs is presented that considerably improves the accuracy of predicting reservoir rock compaction and surface subsidence resulting from pressure depletion in oil and gas fields. The model has been developed on the basis of extensive laboratory studies and can be derived from a theory relating compaction to time-dependent intergranular friction. The procedure for calculating reservoir compaction from laboratory measurements with the new model is outlined. Both field and laboratory compaction behaviors appear to be described by one single normalized, nonlinear compaction curve. With the new model, the large discrepancies usually observed between predictions based on linear compaction models and actual (nonlinear) field behavior can be explained.

De Waal, J.A.; Smits, R.M.M.

1988-06-01

396

Reservoir characterization of Pennsylvanian sandstone reservoirs. Final report  

SciTech Connect

This final report summarizes the progress during the three years of a project on Reservoir Characterization of Pennsylvanian Sandstone Reservoirs. The report is divided into three sections: (i) reservoir description; (ii) scale-up procedures; (iii) outcrop investigation. The first section describes the methods by which a reservoir can be described in three dimensions. The next step in reservoir description is to scale up reservoir properties for flow simulation. The second section addresses the issue of scale-up of reservoir properties once the spatial descriptions of properties are created. The last section describes the investigation of an outcrop.

Kelkar, M.

1995-02-01

397

Directly imaging damped Ly ? galaxies at z > 2 - III. The star formation rates of neutral gas reservoirs at z ˜ 2.7  

NASA Astrophysics Data System (ADS)

We present results from a survey designed to probe the star formation properties of 32 damped Lyman ? systems (DLAs) at z ˜ 2.7. By using the `double-DLA' technique that eliminates the glare of the bright background quasars, we directly measure the rest-frame far-ultraviolet flux from DLAs and their neighbouring galaxies. At the position of the absorbing gas, we place stringent constraints on the unobscured star formation rates (SFRs) of DLAs to 2? limits of dot{? }<0.09-0.27M? yr-1, corresponding to SFR surface densities ?sfr < 10-2.6-10-1.5M? yr-1 kpc-2. The implications of these limits for the star formation law, metal enrichment, and cooling rates of DLAs are examined. By studying the distribution of impact parameters as a function of SFRs for all the galaxies detected around these DLAs, we place new direct constraints on the bright end of the UV luminosity function of DLA hosts. We find that ?13 per cent of the hosts have dot{? }?2M? yr-1 at impact parameters b_dla ? (dot{? }/{M_{?} yr^{-1}})^{0.8}+6 kpc, differently from current samples of confirmed DLA galaxies. Our observations also disfavour a scenario in which the majority of DLAs arise from bright Lyman-break galaxies at distances 20 ? bdla < 100 kpc. These new findings corroborate a picture in which DLAs do not originate from highly star-forming systems that are coincident with the absorbers, and instead suggest that DLAs are associated with faint, possibly isolated, star-forming galaxies. Potential shortcomings of this scenario and future strategies for further investigation are discussed.

Fumagalli, Michele; O'Meara, John M.; Prochaska, J. Xavier; Rafelski, Marc; Kanekar, Nissim

2015-01-01

398

Integrated reservoir study of the 8 reservoir of the Green Canyon 18 field  

E-print Network

the hydrocarbon bearing reservoir, quantified the different resource categories as STOIIP/GIIP = 19.8/26.2 mmstb/Bscf, ultimate recovery = 9.92/16.01 mmstb/Bscf, and reserves (as of 9/2001) = 1.74/5.99 mmstb/Bscf of oil and gas, respectively. There does not appear...

Aniekwena, Anthony Udegbunam

2004-11-15

399

Reservoir Aspects of Ekofisk Subsidence  

Microsoft Academic Search

In Nov. 1984, Phillips Petroleum Co. discovered subsidence of the seabed overlying the Ekofisk oil reservoirs offshore Norway. This phenomenon is the result of the compaction of the porous chalk reservoirs and the transmission of this compaction through the overburden to the seafloor. This paper describes the geolgoic- and reservoir-related aspects of subsidence, including the mechanism leading to reservoir compaction

R. M. Sulak; J. Danielsen

1989-01-01

400

The Svartsengi Reservoir in Iceland  

SciTech Connect

The Svartsengi geothermal reservoir in Iceland is described and its production history presented. Lumped-parameter models for confined and unconfined reservoirs are derived, and a conceptual model of the reservoir suggested. Using depletion analysis, the dominant production mechanism is identified as drainage of an unconfined reservoir.

Gudmundsson, J.S.; Thorhallsson, S.

1986-01-01

401

Microseismic monitoring: a tool for reservoir characterization.  

NASA Astrophysics Data System (ADS)

Characterization of fluid-transport properties of rocks is one of the most important, yet one of most challenging goals of reservoir geophysics. There are some fundamental difficulties related to using active seismic methods for estimating fluid mobility. However, it would be very attractive to have a possibility of exploring hydraulic properties of rocks using seismic methods because of their large penetration range and their high resolution. Microseismic monitoring of borehole fluid injections is exactly the tool to provide us with such a possibility. Stimulation of rocks by fluid injections belong to a standard development practice of hydrocarbon and geothermal reservoirs. Production of shale gas and of heavy oil, CO2 sequestrations, enhanced recovery of oil and of geothermal energy are branches that require broad applications of this technology. The fact that fluid injection causes seismicity has been well-established for several decades. Observations and data analyzes show that seismicity is triggered by different processes ranging from linear pore pressure diffusion to non-linear fluid impact onto rocks leading to their hydraulic fracturing and strong changes of their structure and permeability. Understanding and monitoring of fluid-induced seismicity is necessary for hydraulic characterization of reservoirs, for assessments of reservoir stimulation and for controlling related seismic hazard. This presentation provides an overview of several theoretical, numerical, laboratory and field studies of fluid-induced microseismicity, and it gives an introduction into the principles of seismicity-based reservoir characterization.

Shapiro, S. A.

2011-12-01

402

Application of integrated reservoir management and reservoir characterization to optimize infill drilling. Annual report, June 13, 1994--June 12, 1995  

SciTech Connect

This project has used a multi-disciplinary approach employing geology, geophysics, and engineering to conduct advanced reservoir characterization and management activities to design and implement an optimized infill drilling program at the North Robertson (Clearfork) Unit in Gaines County, Texas. The activities during the first Budget Period have consisted of developing an integrated reservoir description from geological, engineering, and geostatistical studies, and using this description for reservoir flow simulation. Specific reservoir management activities are being identified and tested. The geologically targeted infill drilling program will be implemented using the results of this work. A significant contribution of this project is to demonstrate the use of cost-effective reservoir characterization and management tools that will be helpful to both independent and major operators for the optimal development of heterogeneous, low permeability shallow-shelf carbonate (SSC) reservoirs. The techniques that are outlined for the formulation of an integrated reservoir description apply to all oil and gas reservoirs, but are specifically tailored for use in the heterogeneous, low permeability carbonate reservoirs of West Texas.

Pande, P.K.

1996-11-01

403

Cacti at Amistad Reservoir  

USGS Multimedia Gallery

Amistad National Recreation Area includes the Amistad Reservoir, a man-made lake along the Texas and Mexico border. It is fed by the Rio Grande, Devils River, and the Pecos River, among others.    ...

404

Panorama of Amistad Reservoir  

USGS Multimedia Gallery

Amistad National Recreation Area includes the Amistad Reservoir, a man-made lake along the Texas and Mexico border. It is fed by the Rio Grande, Devils River, and the Pecos River, among others.    ...

405

Use of Cutting-Edge Horizontal and Underbalanced Drilling Technologies and Subsurface Seismic Techniques to Explore, Drill and Produce Reservoired Oil and Gas from the Fractured Monterey Below 10,000 ft in the Santa Maria Basin of California  

SciTech Connect

This project was undertaken to demonstrate that oil and gas can be drilled and produced safely and economically from a fractured Monterey reservoir in the Santa Maria Basin of California by employing horizontal wellbores and underbalanced drilling technologies. Two vertical wells were previously drilled in this area with heavy mud and conventional completions; neither was commercially productive. A new well was drilled by the project team in 2004 with the objective of accessing an extended length of oil-bearing, high-resistivity Monterey shale via a horizontal wellbore, while implementing managed-pressure drilling (MPD) techniques to avoid formation damage. Initial project meetings were conducted in October 2003. The team confirmed that the demonstration well would be completed open-hole to minimize productivity impairment. Following an overview of the geologic setting and local field experience, critical aspects of the application were identified. At the pre-spud meeting in January 2004, the final well design was confirmed and the well programming/service company requirements assigned. Various design elements were reduced in scope due to significant budgetary constraints. Major alterations to the original plan included: (1) a VSP seismic survey was delayed to a later phase; (2) a new (larger) surface hole would be drilled rather than re-enter an existing well; (3) a 7-in. liner would be placed into the top of the Monterey target as quickly as possible to avoid problems with hole stability; (4) evaluation activities were reduced in scope; (5) geosteering observations for fracture access would be deduced from penetration rate, cuttings description and hydrocarbon in-flow; and (6) rather than use nitrogen, a novel air-injection MPD system was to be implemented. Drilling operations, delayed from the original schedule by capital constraints and lack of rig availability, were conducted from September 12 to November 11, 2004. The vertical and upper curved sections were drilled and lined through the problematic shale member without major stability problems. The top of the targeted Monterey was thought to be seen at the expected TVD of 10,000 ft where the 7-in. liner was set at a 60{sup o} hole angle. Significant oil and gas shows suggested the fractured interval anticipated at the heel location had been penetrated. A total of 2572 ft of 6{Delta}-in. near-horizontal interval was placed in the shale section, extending planned well length by approximately 470 ft. Very little hydrocarbon in-flow was observed from fractures along the productive interval. This may be a result of the well trajectory falling underneath the Monterey fractured zone. Hydrocarbon observations, cuttings analysis and gamma-ray response indicated additional fractured intervals were accessed along the last {+-}900 ft of well length. The well was completed with a 2 and 7/8-in. tubing string set in a production packer in preparation for flow and swab tests to be conducted later by a service rig. The planned well time was estimated as 39 days and overall cost as $2.4 million. The actual results are 66 days at a total cost of $3.4 million. Well productivity responses during subsequent flow and swabbing tests were negative. The well failed to inflow and only minor amounts (a few barrels) of light oil were recovered. The lack of production may suggest that actual sustainable reservoir pressure is far less than anticipated. Temblor attempted in July, 2006, to re-enter and clean out the well and run an Array Induction log (primarily for resistivity and correlation purposes), and an FMI log (for fracture detection). Application of surfactant in the length of the horizontal hole, and acid over the fracture zone at 10,236 was also planned. This attempt was not successful in that the clean out tools became stuck and had to be abandoned.

George Witter; Robert Knoll; William Rehm; Thomas Williams

2006-06-30

406

Use of Cutting-Edge Horizontal and Underbalanced Drilling Technologies and Subsurface Seismic Techniques to Explore, Drill and Produce Reservoired Oil and Gas from the Fractured Monterey Below 10,000 ft in the Santa Maria Basin of California  

SciTech Connect

This project was undertaken to demonstrate that oil and gas can be drilled and produced safely and economically from a fractured Monterey reservoir in the Santa Maria Basin of California by employing horizontal wellbores and underbalanced drilling technologies. Two vertical wells were previously drilled in this area with heavy mud and conventional completions; neither was commercially productive. A new well was drilled by the project team in 2004 with the objective of accessing an extended length of oil-bearing, high-resistivity Monterey shale via a horizontal wellbore, while implementing managed-pressure drilling (MPD) techniques to avoid formation damage. Initial project meetings were conducted in October 2003. The team confirmed that the demonstration well would be completed open-hole to minimize productivity impairment. Following an overview of the geologic setting and local field experience, critical aspects of the application were identified. At the pre-spud meeting in January 2004, the final well design was confirmed and the well programming/service company requirements assigned. Various design elements were reduced in scope due to significant budgetary constraints. Major alterations to the original plan included: (1) a VSP seismic survey was delayed to a later phase; (2) a new (larger) surface hole would be drilled rather than re-enter an existing well; (3) a 7-in. liner would be placed into the top of the Monterey target as quickly as possible to avoid problems with hole stability; (4) evaluation activities were reduced in scope; (5) geosteering observat