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1

Open fracture prediction and detection at the Bluebell-Altamont field, Uinta Basin, Utah  

SciTech Connect

Production in the Bluebell-Altamont field is controlled by fracture permeability, and to date, intersecting open fractures has been a hit-or-miss process. By integrating knowledge of basin formation, structural history, and specific geophysical characteristics, we will show that the fractures in the producing region of the Uinta Basin occur systematically, and that the open fractures can be defined using reflection seismic AVO anomalies. The Uinta basin is markedly asymmetrical, reaching its deepest point of -20,000 feet bsl. The interpreted mechanism of basin formation is left-lateral strike-slip faulting in the basement along the Duschesne and South Flank fault systems, created by the indentation of the Colorado Plateau into the North American craton during the Laramide orogeny. Fracture directions in the sedimentary reservoir rocks predicted using this concept are N15[degrees]-50[degrees]W, which agree with core and joint analyses. Blackhawk Geosciences shot two orthogonal 3C reflection seismic lines, and a 9C VSP at the Bluebell-Altamont field under DOE Contract No. DE-RP21-91MC28135; the 9C VSP defined N35[degrees]W as the open fracture direction. Amplitudes at far offsets on the N70[degrees]E line were significantly greater than amplitudes on the N30[degrees]W line, which shows that the N70[degrees]E crosses open fractures at approximately right angles, while the N30[degrees]W line is approximately parallel to the open fractures. These AVO anomalies are consistent with the results of the 9C VSP, surface shear wave seismic anomalies, and geologic structural analysis.

Harthill, N.; Bates, C.R. (Blackhawk Geosciences, Golden, CO (United States))

1996-01-01

2

Identifying compartmentalization in gas reservoirs  

SciTech Connect

Compartmentalization as a function of depositional systems is now recognized as a common type of reservoir heterogeneity that limits recovery from oil and gas reservoirs. US Department of Energy (DOE) estimates indicate that substantial quantities of gas resources will not be recovered from presently identified reservoirs under historic development practices. The Secondary Natural Gas Recovery (SGR) project sponsored by the Gas Research Institute (GRI), state of Texas and DOE quantified compartmentalization over intervals as large as 2,000 feet in several different fluvial deltaic reservoirs. Early recognition of compartmentalized behavior can be used to pursue a more rapid development plan including efficient well spacing and elimination of redundant wells. Three classes of reservoir compartment sizes were delineated in the SGR project using methods discussed in this article. Forward stochastic modeling of gas recovery from these compartment-size classes established well spacing requirements that would yield maximum gas contact efficiency. The presence of reservoir compartmentalization was also shown to correlate with reserve growth. Also, those reservoirs classified as having smaller compartment sizes exhibited the greatest reserve growth potential. Utilization of tools, such as personal computer-based methods discussed, enables better engineering interpretation of actual field behavior. Some of these tools require minimal production data, which is readily available on CD-ROM or via modem at very low cost.

Junkin, J.; Cooper, K. [Petrotek Engineering Corp., Englewood, CO (United States); Sippel, M. [Sippel (Mark), Englewood, CO (United States)

1997-01-01

3

EXCEPTIONAL ENHANCED GEOTHERMAL SYSTEMS FROM OIL AND GAS RESERVOIRS  

Microsoft Academic Search

A lot of oil and gas reservoirs have been or will be abandoned in petroleum industry. In this study, we pointed out that these oil and gas reservoirs might be transferred into exceptional enhanced geothermal reservoirs with very high temperatures by oxidizing the residual oil with injected air. A concept to generate power from these exceptional enhanced geothermal reservoirs by

Kewen Li; Lingyu Zhang

4

Tight gas reservoirs: A visual depiction  

SciTech Connect

Future gas supplies in the US will depend on an increasing contribution from unconventional sources such as overpressured and tight gas reservoirs. Exploitation of these resources and their conversion to economically producible gas reserves represents a major challenge. Meeting this challenge will require not only the continuing development and application of new technologies, but also a detailed understanding of the complex nature of the reservoirs themselves. This report seeks to promote understanding of these reservoirs by providing examples. Examples of gas productive overpressured tight reservoirs in the Greater Green River Basin, Wyoming are presented. These examples show log data (raw and interpreted), well completion and stimulation information, and production decline curves. A sampling of wells from the Lewis and Mesaverde formations are included. Both poor and good wells have been chosen to illustrate the range of productivity that is observed. The second section of this document displays decline curves and completion details for 30 of the best wells in the Greater Green River Basin. These are included to illustrate the potential that is present when wells are fortuitously located with respect to local stratigraphy and natural fracturing, and are successfully hydraulically fractured.

Not Available

1993-12-01

5

Stimulation of the Tight Western Gas Reservoirs.  

National Technical Information Service (NTIS)

Hydraulic fracturing and high-explosive stimulation are the two principal methods that have been used to stimulate production of oil and gas reservoirs in the United States. Since the late 1940s, hydraulic fracturing has become the primary well-completion...

M. E. Hanson

1977-01-01

6

RESERVOIR ANALYSIS AND RECOVERY PREDICTION FOR CYCLING GAS-CONDENSATE RESERVOIRS  

Microsoft Academic Search

This paper demonstrates techniques for determining gas reserves and for predicting performance of gas- condensate reservoirs where cycling is employed. Calculation of original gas in place is accomplished through the application of a simple transient gas energy balance equation. The volumetric gas balance utilizes past production data and bottomhole pressures taken over the life of the project. Reservoir and fluid

O. R. Butterfield; J. D. Clark; E. B. Brauer

1965-01-01

7

Carbon sequestration in natural gas reservoirs: Enhanced gas recovery and natural gas storage  

SciTech Connect

Natural gas reservoirs are obvious targets for carbon sequestration by direct carbon dioxide (CO{sub 2}) injection by virtue of their proven record of gas production and integrity against gas escape. Carbon sequestration in depleted natural gas reservoirs can be coupled with enhanced gas production by injecting CO{sub 2} into the reservoir as it is being produced, a process called Carbon Sequestration with Enhanced Gas Recovery (CSEGR). In this process, supercritical CO{sub 2} is injected deep in the reservoir while methane (CH{sub 4}) is produced at wells some distance away. The active injection of CO{sub 2} causes repressurization and CH{sub 4} displacement to allow the control and enhancement of gas recovery relative to water-drive or depletion-drive reservoir operations. Carbon dioxide undergoes a large change in density as CO{sub 2} gas passes through the critical pressure at temperatures near the critical temperature. This feature makes CO{sub 2} a potentially effective cushion gas for gas storage reservoirs. Thus at the end of the CSEGR process when the reservoir is filled with CO{sub 2}, additional benefit of the reservoir may be obtained through its operation as a natural gas storage reservoir. In this paper, we present discussion and simulation results from TOUGH2/EOS7C of gas mixture property prediction, gas injection, repressurization, migration, and mixing processes that occur in gas reservoirs under active CO{sub 2} injection.

Oldenburg, Curtis M.

2003-04-08

8

Seismic imaging of gas hydrate reservoir heterogeneities  

NASA Astrophysics Data System (ADS)

Natural gas hydrate, a type of inclusion compound or clathrate, are composed of gas molecules trapped within a cage of water molecules. The presence of gas hydrate has been confirmed by core samples recovered from boreholes. Interests in the distribution of natural gas hydrate stem from its potential as a future energy source, geohazard to drilling activities and their possible impact on climate change. However the current geophysical investigations of gas hydrate reservoirs are still too limited to fully resolve the location and the total amount of gas hydrate due to its complex nature of distribution. The goal of this thesis is twofold, i.e., to model (1) the heterogeneous gas hydrate reservoirs and (2) seismic wave propagation in the presence of heterogeneities in order to address the fundamental questions: where are the location and occurrence of gas hydrate and how much is stored in the sediments. Seismic scattering studies predict that certain heterogeneity scales and velocity contrasts will generate strong scattering and wave mode conversion. Vertical Seismic Profile (VSP) techniques can be used to calibrate seismic characterization of gas hydrate expressions on surface seismograms. To further explore the potential of VSP in detecting the heterogeneities, a wave equation based approach for P- and S-wave separation is developed. Tests on synthetic data as well as applications to field data suggest alternative acquisition geometries for VSP to enable wave mode separation. A new reservoir modeling technique based on random medium theory is developed to construct heterogeneous multi-variable models that mimic heterogeneities of hydrate-bearing sediments at the level of detail provided by borehole logging data. Using this new technique, I modeled the density, and P- and S-wave velocities in combination with a modified Biot-Gassmann theory and provided a first order estimate of the in situ volume of gas hydrate near the Mallik 5L-38 borehole. Our results suggest a range of 528 to 768x10 6 m3/km2 of natural gas trapped within hydrate, nearly an order of magnitude lower than earlier estimates which excluded effects of small-scale heterogeneities. Further, the petrophysical models are combined with a 3-D Finite Difference method to study seismic attenuation. Thus a framework is built to further tune the models of gas hydrate reservoirs with constraints from well logs other disciplinary data.

Huang, Jun-Wei

9

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

10

Coarse scale simulation of tight gas reservoirs  

NASA Astrophysics Data System (ADS)

It is common for field models of tight gas reservoirs to include several wells with hydraulic fractures. These hydraulic fractures can be very long, extending for more than a thousand feet. A hydraulic fracture width is usually no more than about 0.02 ft. The combination of the above factors leads to the conclusion that there is a need to model hydraulic fractures in coarse grid blocks for these field models since it may be impractical to simulate these models using fine grids. In this dissertation, a method was developed to simulate a reservoir model with a single hydraulic fracture that passes through several coarse gridblocks. This method was tested and a numerical error was quantified that occurs at early time due to the use of coarse grid blocks. In addition, in this work, rules were developed and tested on using uniform fine grids to simulate a reservoir model with a single hydraulic fracture. Results were compared with the results from simulations using non-uniform fine grids.

El-Ahmady, Mohamed Hamed

11

Gas in tight reservoirs - an emerging major source of energy  

SciTech Connect

Low-permeability (tight) gas reservoirs are gas-bearing rocks that usually have an in-situ permeability to gas, exclusive of fracture permeability, of less than 0.1 milli-darcy (mD). In the United States these reservoirs are estimated to contain in-place gas resources of at least 420 trillion cubic feet (Tcf) and possibly more than 5,000 Tcf. Estimates of recoverable gas in the United States range from less than 200 to more than 550 Tcf. Tight gas reservoirs occur in nearly all petroleum provinces. They occur at virtually all depths and in a variety of rock types that include sandstone, siltstone, shale, sandy carbonate rocks, limestone, dolomite, and chalk. Tight gas reservoirs may be thick and areally extensive or thin and areally limited. In contrast to normal (conventional) gas accumulations where the gas is concentrated in structural or stratigraphic traps, gas in tight reservoirs occurs as regionally pervasive accumulations that are usually abnormally pressured and are mostly independent of structural and stratigraphic traps. Artificial stimulation, such as hydraulic fracturing, is usually needed in order to produce the gas unless extensive fracturing is present. As a consequence of an improved understanding of tight gas reservoirs and improved drilling and completion practices, gas from these reservoirs is rapidly emerging as a major source of energy. 64 refs., 17 figs., 1 tab.

Law, B.E.; Spencer, C.W. (Geological Survey, Denver, CO (United States))

1993-01-01

12

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

13

Mantle Reservoirs From a Noble Gas Perspective  

NASA Astrophysics Data System (ADS)

The noble gases provide unique insight into mantle structure and the origin of the different mantle reservoirs. Many OIBs, such as Hawaii and Iceland, have 3He/4He ratios that are a factor of 4 to 6 higher than the canonical MORB value of 8±1 RA. The high 3He/4He ratios in OIBs are conventionally viewed as evidence for the existence of a primitive mantle reservoir. Such a view, however, is frequently challenged on the grounds that noble gas abundances in OIBs are an order of magnitude lower than in MORBs, an observation that traditional models of magmatic degassing cannot explain. The apparent concentration paradox has been resolved by incorporating kinetic fractionation of the noble gases during magmatic degassing of the erupting magma and it can be shown that higher CO2 and H2O content of OIBs, compared to MORBs, leads to more extensive degassing of He in OIB magmas (Gonnermann and Mukhopadhyay, 2007). In contrast to Hawaii and Iceland, some ocean islands, such as the Cook-Austral Islands and Canary Islands (HIMU ocean islands) have 3He/4He ratios of 4-7 RA, lower than the MORB range. The low 3He/4He ratios are attributed to the addition of radiogenic 4He from recycled slabs. Surprisingly, recent high-precision neon isotopic measurements made at Harvard in olivine phenocrysts from the Cook-Austral Islands indicate that HIMU neon is less nucleogenic than the MORB source. The He and Ne systematics from the Cook-Austral's demonstrate that the noble gas signature of HIMU basalts cannot arise either from simple diffusive equilibration of a recycled slab with a MORB source, or result from mixing of melts that are derived from recycled slabs and the MORB mantle. The He-Ne systematics, however, can be quantitatively modeled as a mixture of recycled slab and a primitive mantle reservoir. The scenario is consistent with He-Os and He- Nd correlations seen in the Cook-Austral basalts. Thus, both low and high 3He/4He OIBs incorporate the same primitive mantle reservoir, although in varying proportions. The notion of a reservoir that is primitive in its volatile content and sampled at ocean islands is very much alive. In spite of whole mantle convection, it appears that part of the Earth's mantle has remained largely undegassed. While significant progress has been made with respect to understanding the geochemical implications of He and Ne isotopic composition measured in MORBs and OIBs, our knowledge of Xenon in the mantle remains poor. Since 129Xe and 136Xe have been produced by the now extinct nuclides, 129I and 244Pu respectively, Xe isotopic composition of the mantle can be used to test models of atmosphere formation and provide unique clues to the volatile history of the Earth's mantle. Some of the outstanding issues that still need to be resolved are whether the Earth's mantle has solar or chondritic heavy noble gases, whether OIBs and MORB have the same Xe isotopic composition, and what fraction of the 136Xe is from 244Pu vs. 238U fission. Addressing these issues will require not only high precision measurements but also innovative experimental techniques to reduce air contamination that is ubiquitous in mantle-derived samples. High precision Xe isotopic measurements made at Harvard indicates that Samoa (a high 3He/4He ocean island) and MORBs have exactly the same proportion of radiogenic 129Xe to 136Xe. Although this result needs to be verified from other OIBs, it suggests that a single mantle reservoir supplies the excess 129Xe and 136Xe to both the MORB and OIB mantle source. The primitive mantle reservoir is the most likely carrier of the xenon isotopic anomaly.

Mukhopadhyay, S.

2007-12-01

14

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

15

Delta 37Cl and Characterisation of Petroleum-gas Reservoirs  

Microsoft Academic Search

The geochemical characterisation of formation waters from oil\\/gas fields is used to detect fluid-flow barriers in reservoirs and to reconstruct the system dynamic. During the progression of the reservoir filling, the aquifer waters are pushed by hydrocarbons toward the reservoir bottom and their compositions evolve due to several parameters such as water-rock interactions, mixing with oil-associated waters, physical processes etc.

V. Woulé Ebongué; N. Jendrzejewski; F. Walgenwitz; F. Pineau; M. Javoy

2003-01-01

16

The Optimization of Underground Gas Storage in a Partially Depleted Gas Reservoir  

Microsoft Academic Search

Underground gas storage (UGS) is a well-known technology to supply variable demand of natural gas market. The objective of this work is to demonstrate the feasibility of UGS development in an Iranian depleted fractured gas reservoir. For this purpose, gas demand analysis was conducted based on yearly consumption, and the peak condition demand was obtained. Then, a full-field multicomponent reservoir

R. Malakooti; R. Azin

2011-01-01

17

Fluid and Heat Flow In Gas-Rich Geothermal Reservoirs  

Microsoft Academic Search

Numerical simulation techniques are used to study the effects of noncondensable gases (COâ) on geothermal reservoir behavior in the natural state and during exploitation. It is shown that the presence of COâ has a large effect on the thermodynamic conditions of a reservoir in the natural state, especially on temperature distributions and phase compositions. The gas will expand two-phase zones

M. J. OSullivan; G. S. Bodvarsson; K. Pruess; M. R. Blakeley

1985-01-01

18

Frequency-dependent seismic reflection coefficient for discriminating gas reservoirs  

NASA Astrophysics Data System (ADS)

The asymptotic equation of wave propagation in fluid-saturated porous media is available for calculating the normal reflection coefficient within a seismic frequency band. This frequency-dependent reflection coefficient is expressed in terms of a dimensionless parameter ?, which is the product of the reservoir fluid mobility (i.e. inverse viscosity), fluid density and the frequency of the signal. In this paper, we apply this expression to the Xinchang gas field, China, where reservoirs are in super-tight sands with very low permeability. We demonstrate that the variation in the reflection coefficient at a gas-water contact as a transition zone within a sand formation is observable within the seismic frequency band. Then, we conduct seismic inversion to generate attributes which first indicate the existence of fluid (either gas or water), and then discriminate a gas reservoir from a water reservoir.

Xu, Duo; Wang, Yanghua; Gan, Qigan; Tang, Jianming

2011-12-01

19

Naturally fractured tight gas reservoir detection optimization. Final report.  

National Technical Information Service (NTIS)

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...

1997-01-01

20

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

21

Gas-well production decline in multiwell reservoirs  

SciTech Connect

This paper introduces a pseudosteady-state constant-pressure solution for gas wells. The solution was used to develop a type-curve-based method to history match and predict multiwell gas reservoir production. Good agreements between the predicted and actual gas well production rates were obtained.

Aminian, K.; Ameri, S. (West Virginia Univ., WV (US)); Stark, J.J. (Exxon Co. U.S.A. (US)); Yost, A.B. II (US DOE (US))

1990-12-01

22

Characterization of oil and gas reservoir heterogeneity  

SciTech Connect

The ultimate objective 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. Results are discussed.

Sharma, G.D.

1992-01-01

23

Characterization of oil and gas reservoir heterogeneity  

SciTech Connect

The ultimate objective 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.

Sharma, G.D.

1992-01-01

24

Characterization of oil and gas reservoir heterogeneity  

SciTech Connect

The ultimate objective 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.

Sharma, G.D.

1991-01-01

25

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

26

Naturally fractured tight gas reservoir detection optimization  

SciTech Connect

The work plan for October 1, 1997 to September 30, 1998 consisted of investigation of a number of topical areas. These topical areas were reported in four quarterly status reports, which were submitted to DOE earlier. These topical areas are reviewed in this volume. The topical areas covered during the year were: (1) Development of preliminary tests of a production method for determining areas of natural fracturing. Advanced Resources has demonstrated that such a relationship exists in the southern Piceance basin tight gas play. Natural fracture clusters are genetically related to stress concentrations (also called stress perturbations) associated with local deformation such a faulting. The mechanical explanation of this phenomenon is that deformation generally initiates at regions where the local stress field is elevated beyond the regional. (2) Regional structural and geologic analysis of the Greater Green River Basin (GGRB). Application of techniques developed and demonstrated during earlier phases of the project for sweet-spot delineation were demonstrated in a relatively new and underexplored play: tight gas from continuous-typeUpper Cretaceous reservoirs of the Greater Green River Basin (GGRB). The effort included data acquisition/processing, base map generation, geophysical and remote sensing analysis and the integration of these data and analyses. (3) Examination of the Table Rock field area in the northern Washakie Basin of the Greater Green River Basin. This effort was performed in support of Union Pacific Resources- and DOE-planned horizontal drilling efforts. The effort comprised acquisition of necessary seismic data and depth-conversion, mapping of major fault geometry, and analysis of displacement vectors, and the development of the natural fracture prediction. (4) Greater Green River Basin Partitioning. Building on fundamental fracture characterization work and prior work performed under this contract, namely structural analysis using satellite and potential field data, the GGRB was divided into partitions that will be used to analyze the resource potential of the Frontier and Mesaverde Upper Cretaceous tight gas play. A total of 20 partitions were developed, which will be instrumental for examining the Upper Cretaceous play potential. (5) Partition Analysis. Resource assessment associated with individual partitions was initiated starting with the Vermilion Sub-basin and the Green River Deep (which include the Stratos well) partitions (see Chapter 5). (6) Technology Transfer. Tech transfer was achieved by documenting our research and presenting it at various conferences.

NONE

1998-11-30

27

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

28

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

Microsoft Academic Search

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

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

2010-01-01

29

Reservoir characterization of the giant Hugoton gas field, Kansas  

SciTech Connect

Hugoton field in Kansas is the largest gas field in North America, with cumulative production over 23 Tcf. Infill and deep drilling activity over the last 10 yr have made it possible to build an extensive database of modern wireline log and core data. Such data formed the basis for a wide-ranging reservoir characterization done to obtain critical information for optimum reservoir management of the field. Reservoir heterogeneity and formation-evaluation problems made it difficult to characterize fluid distribution, estimate gas in place, and determine permeability from wireline log data, but few of the problems in this reservoir characterization study are unique to Hugoton. The techniques described here may be applicable to other reservoirs. Technologies employed to solve the formation-evaluation and lateral-variability problems included artificial neural networks, resistivity modeling, geostatistics, and three-dimensional grid manipulation. The application of new technologies to problems in characterizing the Hugoton reservoir yielded both tools for evaluating specific areas of the field and a better understanding of fieldwide pore volume gas in place (PVGIP) and its distribution. Geologic maps that include sealing faults, plus well plots from new applications of formation evaluation techniques, provide valuable tools to operations teams for increasing production and decreasing costs. PVGIP is estimated to be between 34.5 and 37.8 Tcf. The distribution of, and uncertainty in, the PVGIP values are important because they are also used to better manage the reservoir.

Olson, T.M.; Thompson, K.A. [Amoco Production Co., Denver, CO (United States); Babcock, J.A. [Amoco Production Co., Houston, TX (United States)] [and others

1997-11-01

30

Gas content of Gladys McCall reservoir brine  

SciTech Connect

On October 8, 1983, after the first full day of production from Sand No.8 in the Gladys McCall well, samples of separator gas and separator brine were collected for laboratory P-V-T (pressure, volume, temperature) studies. Recombination of amounts of these samples based upon measured rates at the time of sample collection, and at reservoir temperature (290 F), revealed a bubble point pressure of 9200 psia. This is substantially below the reported reservoir pressure of 12,783 psia. The gas content of the recombined fluids was 30.19 SCF of dry gas/STB of brine. In contrast, laboratory studies indicate that 35.84 SCF of pure methane would dissolve in each STB of 95,000 mg/L sodium chloride brine. These results indicate that the reservoir brine was not saturated with natural gas. By early April, 1987, production of roughly 25 million barrels of brine had reduced calculated flowing bottomhole pressure to about 6600 psia at a brine rate of 22,000 STB/D. If the skin factor(s) were as high as 20, flowing pressure drop across the skin would still be only about 500 psi. Thus, some portion of the reservoir volume was believed to have been drawn down to below the bubble point deduced from the laboratory recombination of separator samples. When the pressure in a geopressured geothermal reservoir is reduced to below the bubble point pressure for solution gas, gas is exsolved from the brine flowing through the pores in the reservoir rock. This exsolved gas is trapped in the reservoir until the fractional gas saturation of pore volume becomes large enough for gas flow to commence through a continuous gas-filled channel. At the same time, the gas/brine ratio becomes smaller and the chemistry of the remaining solution gas changes for the brine from which gas is exsolved. A careful search was made for the changes in gas/brine ratio or solution gas chemistry that would accompany pressure dropping below the bubble point pressure. Changes of about the same magnitude as the scatter in the data appear to have occurred in mid-1985 when calculated flowing bottomhole pressure was in the range of 9400 to 9700 psi. After the amount of brine flowing through the rock near to the wellbore has exsolved enough gas for onset of gas mobility through a continuous gas-filled channel, another test for whether the reservoir is below its bubble point becomes possible. This ''bubble test'' consists of suddenly increasing flow rate so that bottomhole pressure drops. Gas expansion then results in a small portion of the free gas from near the wellbore being produced in a short period of time. The resulting ''bubble'' of gas has a higher natural gas liquids content than gas produced before and after the transient. ''Bubble tests'' were performed in February 1986 and April 1987. Neither test liberated enough additional gas to provide a detectable change in produced gas/brine ratio. However, observed small transients in Ethane/Methane and Propane/Methane ratios indicate that some free gas was produced from the near wellbore region. These results suggest that the bubble point pressure must have been in the vicinity of the calculated 9500 psi flowing bottomhole pressure during the second of 1985. They conclude that: (1) Sand No.8 in the Gladys McCall well was not saturated with natural gas at the reported initial reservoir pressure of 12,873 psia; (2) flowing bottomhole pressure became less than the bubble point pressure during 1985; and (3) bubble point pressure was in the range of 9200 to 10,000 psi.

Hayden, C.G.; Randolph, P.L.

1987-05-29

31

Gas Injection Into Fractured Reservoirs Above Bubble Point Pressure  

Microsoft Academic Search

Among all enhanced oil recovery (EOR) scenarios, gas injection seems to be promising for implementation in naturally fractured reservoirs. The use of CO2 has received considerable interest as a method of EOR but a major drawback is its availability and increasing cost. Therefore, an alternative gas like CH4 or N2 must be considered to meet the economic considerations. To investigate

P. Heidari; A. Kordestany

2012-01-01

32

Geological controls on coalbed methane reservoir capacity and gas content  

Microsoft Academic Search

The influence of coal composition and rank on coalbed methane reservoir capacity, gas content and gas saturation have been investigated for a series of Australian, Canadian and United States coals. Globally there is no or little correlation between coal rank and methane adsorption capacity (as commonly assumed), although in particular basins there are general trends with rank and composition. Micropore1Micropores

R. M Bustin; C. R Clarkson

1998-01-01

33

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

34

Numerical modeling of gas recovery from methane hydrate reservoirs  

NASA Astrophysics Data System (ADS)

Class 1 hydrate deposits are characterized by a hydrate bearing layer underlain by a two phase, free-gas and water, zone. A Class 1 hydrate reservoir is more preferable than class 2 and class 3 hydrate accumulations because a small change of pressure and temperature can induce hydrate dissociation. In this study, production characteristics from class 1 methane-hydrate reservoirs by means of conventional depressurization technique are studied. In this work, the production characteristics and efficiency from different production strategies (mainly focused on a constant bottom-hole pressure production scheme) such as well-completion locations, well spacing, and production scheduling are investigated. In the production of conventional gas reservoirs using a constant bottom-hole pressure production scheme, both gas and water production rates exponentially decrease with time. However, for methane-hydrate reservoirs, gas production rate exponentially declines with time whereas water production rate increases with time because methane hydrate dissociation increases water saturation of the reservoir. The effects of well-completion locations on the production performances are examined. The simulation results indicate that the moving well completion location strategy provides better gas production performance than the fixed completion location strategy. The optimum well-completion location (using a moving completion location strategy) is at the middle of free-gas zone. Due to the effects of hydrate saturation on formation permeability, one should not complete a well in the hydrate zone. The effect of well spacing on the production efficiency is also investigated. As expected, smaller well-spacing system yields more total gas production and it can dissociate gas-hydrate more rapidly than the larger well-spacing system. However, the number of wells increases when the well-spacing decreases resulting in the increase of the capital investment of the project. Based on this study, when the well-spacing increased about 100 percent (from 45.0 acres to 74.38 acres) the cumulative gas production decreased about 8.4 percent at 1,000 days of production. Therefore, once the similar simulation study for a particular reservoir has been performed, the optimum well spacing for a specific reservoir can be determined. The effect of well scheduling on the production performance is also examined. In multiple-well systems, starting all production wells at the same time provides faster hydrate dissociation. However, based on this study, starting production wells at different times yields more produced gas (about 10 percent by volume) even though less gashydrate dissociates. Therefore, starting production wells in the multiple-well system at different times could help in improving the gas production efficiency.

Silpngarmlert, Suntichai

35

Horizontal wells enhance development of thin offshore gas reservoirs  

SciTech Connect

Horizontal wells in clastic rocks can reduce water coning problems and increase production rates as much as six-fold. They are now practical to drill for developing Gulf of Mexico gas reservoirs that may be less than 10 ft thick. In 1991, Chevron USA began exploring the feasibility of developing thin gas reservoirs in western Gulf of Mexico (GOM) fields. A critical element that needed to be addressed was the minimum target thickness that is geologically and operationally practical to drill with current horizontal well technology. Chevron`s first GOM horizontal well spudded in February 1992. The target was 31 ft of net effective gas on water in a massive Pleistocene sand at 1,700 ft TVD. Chevron spudded a second horizontal well in the same field during June 1993. This well was geosteered into a 19-ft gas sand with no immediate water contact at 1,650 ft TVD. The entire 1,000-ft horizontal section was interpreted as gas from the MWD tool response. A spinner survey was not run in this hole. At 19 MMcfd of gas, this well also proved to be a major economic success because of its low cost. After the second completion, Chevron`s next proposed well targeted a gas reservoir with a maximum thickness of only 7 ft.

Gidman, B. [Chevron USA, Lafayette, LA (United States); Hammons, L.R.B.; Paulk, M.D. [Baker Hughes INTEQ, Lafayette, LA (United States)

1995-03-01

36

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

37

Gas Hydrate Reservoir Characterization Using Converted Waves  

NASA Astrophysics Data System (ADS)

Geophysical evidence exists for gas hydrates along the northern sidewall of the Storegga Slide. A BSR reflects the base of the Gas Hydrate Stability Zone (GHSZ), and the free gas zone beneath it. Gas hydrates exist outside and inside the slide area of the Storegga Slide. Ocean Bottom Seismometer, Ocean Bottom Cable and geotechni- cal borehole data allow to assess the elastic properties of hydrated and gassy sediments in an integrated approach. The P-S data evaluation requires a special processing pro- cedure, which involves two different approaches to determine the Vp/Vs-ratio and the shear-wave velocity of the sediments. The compressional-wave velocity shows a distinctive increase just above the BSR and a low-velocity zone below the BSR. We in- terpret these zones to be caused by hydrated and gas-charged sediments, respectively. Another low-velocity zone occurs at about 250 m below the BSR, at the base of the Naust Formation. This is the upper termination of a polygonal fault system and the base of a fluid leakage system in the area. The magnitude of the velocity decrease, i.e. 200 U 300 m/s, is caused by free gas. The Vp/Vs-ratio decreases through the whole sediment column from 7 for the uppermost sediments to 5 at the depth of the BSR. It shows a positive deviation from its downward decreasing trend associated with the p-wave low-velocity zone just below the BSR. This indicates the occurrence of gas underneath the hydrates. Further downward, the Vp/Vs-ratio continues to decrease to values of about 3 at a depth of 600 m below seafloor. The second gas-charged layer at about 500 m depth is not detected by the shear waves. One of the premier applications in offshore industry of recording shear waves is to image through gas clouds. Whereas shear waves behave exemplary for the lower gas-charged layer in our case, they do not so for the gas that occurs beneath the BSR. It is therefore concluded that the decrease in shear-wave velocity is caused by overpressure of gas that is trapped underneath the hydrates. Such overpressure would reduce the effective stress and grain coupling leading to low shear modulus and low shear-wave velocity.

Bünz, S.; Mienert, J.; Berndt, C.

38

Shale gas reservoir characterisation: A typical case in the southern Sichuan Basin of China  

Microsoft Academic Search

The Lower Silurian Longmaxi Formation is an organic-rich (black) mudrock that is widely considered to be a potential shale gas reservoir in the southern Sichuan Basin (the Yangtze plate) in Southwest China. A case study is presented to characterise the shale gas reservoir using a workflow to evaluate its characteristics. A typical characterisation of a gas shale reservoir was determined using

Shangbin Chen; Yanming Zhu; Hongyan Wang; Honglin Liu; Wei Wei; Junhua Fang

2011-01-01

39

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

40

Permeability effects on the seismic response of gas reservoirs  

NASA Astrophysics Data System (ADS)

In this work, we analyse the role of permeability on the seismic response of sandstone reservoirs characterized by patchy gas-water saturation. We do this in the framework of Johnson's model, which is a generalization of White's seminal model allowing for patches of arbitrary geometry. We first assess the seismic attenuation and velocity dispersion characteristics in response to wave-induced fluid flow. To this end, we perform an exhaustive analysis of the sensitivity of attenuation and velocity dispersion of compressional body waves to permeability and explore the roles played by the Johnson parameters T and S/V, which characterize the shape and size of the gas-water patches. Our results indicate that, within the typical frequency range of exploration seismic data, this sensitivity may indeed be particularly strong for a variety of realistic and relevant scenarios. Next, we extend our analysis to the corresponding effects on surface-based reflection seismic data for two pertinent models of typical sandstone reservoirs. In the case of softer and more porous formations and in the presence of relatively low levels of gas saturation we observe that the effects of permeability on seismic reflection data are indeed significant. These prominent permeability effects prevail for normal-incidence and non-normal-incidence seismic data and for a very wide range of sizes and shapes of the gas-water patches. For harder and less porous reservoirs, the normal-incidence seismic responses exhibit little or no sensitivity to permeability, but the corresponding non-normal-incidence responses show a clear dependence on this parameter, again especially so for low gas saturations. The results of this study therefore suggest that, for a range of fairly common and realistic conditions, surface-based seismic reflection data are indeed remarkably sensitive to the permeability of gas reservoirs and thus have the potential of providing corresponding first-order constraints.

Rubino, J. Germán.; Velis, Danilo R.; Holliger, Klaus

2012-04-01

41

Geology, distribution, and original gas in place of 1282 large gas reservoirs, onshore Texas Gulf Coast and east Texas basins  

SciTech Connect

Information on more than 1800 onshore Texas gas reservoirs with a cumulative production of at least 10 billion ft/sup 3/ each has been compiled for the first comprehensive atlas of Texas gas reservoirs. Of these, 1282 reservoirs are in the onshore Texas Gulf Coast and east Texas basins. Geology, production statistics, and reservoir-size distribution of important gas plays are analyzed. Hydrocarbon plays are defined by producing stratigraphic unit, depositional system, lithology, and trapping mechanism.

Kosters, E.C.; Banta, N.J.; Luna-Melo, J.; Finley, R.J.

1989-03-01

42

Naturally fractured tight gas reservoir detection optimization  

SciTech Connect

In March, work continued on characterizing probabilities for determining natural fracturing associated with the GGRB for the Upper Cretaceous tight gas plays. Structural complexity, based on potential field data and remote sensing data was completed. A resource estimate for the Frontier and Mesa Verde play was also completed. Further, work was also conducted to determine threshold economics for the play based on limited current production in the plays in the Wamsutter Ridge area. These analyses culminated in a presentation at FETC on 24 March 1999 where quantified natural fracture domains, mapped on a partition basis, which establish ''sweet spot'' probability for natural fracturing, were reviewed. That presentation is reproduced here as Appendix 1. The work plan for the quarter of January 1, 1999--March 31, 1999 comprised five tasks: (1) Evaluation of the GGRB partitions for structural complexity that can be associated with natural fractures, (2) Continued resource analysis of the balance of the partitions to determine areas with higher relative gas richness, (3) Gas field studies, (4) Threshold resource economics to determine which partitions would be the most prospective, and (5) Examination of the area around the Table Rock 4H well.

NONE

1999-04-30

43

Slaughter estate unit tertiary miscible gas pilot reservoir description  

SciTech Connect

A reservoir description for the Slaughter Estate Unit tertiary pilot and surrounding area and the procedure that we used to obtain it are discussed in this paper. The procedure is based on matching waterflood performance prior to pilot miscible gas injection with a black oil reservoir simulator. An initial estimate of the reservoir description is obtained from petrophysical data and single-well pressure transient tests. The initial estimate is then modified by a trial and error procedure until a good match between the actual and calculated waterflood performance is obtained. It was determined that the Slaughter Estate Unit tertiary pilot had an original oil in place (OOIP) of 642,400 STB (102 133 stock-tank m/sup 3/). A waterflood prediction derived from the reservoir description in this paper indicates that a primary-plus-secondary recovery through Sept. 30, 1983, of 49.6% OOIP would have been obtained from the pilot if waterflood operations had been continued. On the basis of this prediction, it was established that the tertiary oil recovery resulting from the miscible gas process was 18.5% OOIP as of Sept. 30, 1983.

Ader, J.C.; Stein, M.H.

1984-05-01

44

PREDICTION OF GAS INJECTION PERFORMANCE FOR HETEROGENEOUS RESERVOIRS  

SciTech Connect

This final report describes research carried out in the Department of Petroleum Engineering at Stanford University from September 1996--May 2000 under a three-year grant from the Department of Energy on the ''Prediction of Gas Injection Performance for Heterogeneous Reservoirs''. The advances from the research include: new tools for streamline-based simulation including the effects of gravity, changing well conditions, and compositional displacements; analytical solutions to 1D compositional displacements which can speed-up gas injection simulation still further; and modeling and experiments that delineate the physics that is unique to three-phase flow.

Martin J. Blunt; Franklin M. Orr Jr

2000-06-01

45

Prediction of Gas Injection Performance for Heterogeneous Reservoirs  

SciTech Connect

This project performs research in four main areas: laboratory experiments to measure three-phase relative permeability; network modeling to predict three-phase relative perme- ability; benchmark simulations of gas injection and waterfl ooding at the field scale; and the development of fast streamline techniques to study field-scale oil. The aim of the work is to achieve a comprehensive description of gas injection processes from the pore to the core to the reservoir scale. In this report we provide a detailed description of our measurements of three-phase relative permeability.

Franklin M. Orr, Jr; Martin J. Blunt

1998-03-31

46

Prediction of Gas Injection Performance for Heterogeneous Reservoirs  

SciTech Connect

This report describes research into gas injection processes in four main areas: laboratory experiments to measure three-phase relative permeability; network modeling to predict three-phase relative permeability; benchmark simulations of gas injection and water flooding at the field scale; and the development of fast streamline techniques to study field-scale ow. The aim of the work is to achieve a comprehensive description of gas injection processes from the pore to the core to the reservoir scale. To this end, measurements of three-phase relative pemeability have been made and compared with predictions from pore scale modeling. At the field scale, streamline-based simulation has been extended to compositional displacements, providing a rapid method to predict oil recovery from gas injection.

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

1998-04-30

47

Case History of Pressure Maintenance by Crestal Gas Injection in the 26R Gravity Drainage Reservoir  

Microsoft Academic Search

This paper is a field case history on the performance of the 26R Reservoir. This is a gravity drainage reservoir under pressure maintenance by crestal gas injection. The 26R Reservoir is a highly layered Stevens turbidite sandstone. The reservoir is located in the Naval Petroleum Reserve No. 1 (NPR{number sign}1) in Elk Hills, Kern County, California. The 26R Reservoir is

M. H. Wei; J. P. Yu; D. M. Moore; Ezekwe Nnaemeka; M. E. Querin; L. L. Williams

1992-01-01

48

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...DEPARTMENT OF THE INTERIOR OFFSHORE OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF Oil and Gas Production Requirements...

2013-07-01

49

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

50

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 1997 - September 1998 under the second year of a three-year grant from the Department of Energy 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 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 state 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, Martin J.; Orr, Franklin M.

1999-05-17

51

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

Code of Federal Regulations, 2013 CFR

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

2013-07-01

52

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

53

Gas injection with radioactive tracer to determine reservoir continuity, East Coalinga field, California  

Microsoft Academic Search

The Temblor Zone II reservoir consists of intervals of movable oil associated with intervals of high gas saturation or desaturated intervals. Natural gas injection into these desaturated intervals, using tritium and krypton as radioactive tracers has served to determine reservoir continuity. In these example cases, the desaturated intervals contained nearly all carbon dioxide gas. The injection tests also have furnished

Tinker

1972-01-01

54

Similarity theory for the physical simulation of natural gas hydrate reservoir development  

Microsoft Academic Search

In order to apply physical simulation results to natural gas hydrate reservoir parameters to provide a theoretical framework for the design of a development plan, an analytical equation method was used to obtain the similarity criteria of natural gas hydrate reservoir development by physical simulation, based on a mathematical model of natural gas hydrate development. Given the approach of numerical

Yaping LIU; Yueming CHEN; Yuhu BAI; Shuxia LI

2010-01-01

55

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 percent of natural gas production and about 35 percent 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.)

Information Center

2010-05-11

56

Advanced reservoir management for independent oil and gas producers  

SciTech Connect

There are more than fifty-two hundred oil and gas producers operating in the United States today. Many of these companies have instituted improved oil recovery programs in some form, but very few have had access to state-of-the-art modeling technologies routinely used by major producers to manage these projects. Since independent operators are playing an increasingly important role in the production of hydrocarbons in the United States, it is important to promote state-of-the-art management practices, including the planning and monitoring of improved oil recovery projects, within this community. This is one of the goals of the Strategic Technologies Council, a special interest group of independent oil and gas producers. Reservoir management technologies have the potential to increase oil recovery while simultaneously reducing production costs. These technologies were pioneered by major producers and are routinely used by them. Independent producers confront two problems adopting this approach: the high cost of acquiring these technologies and the high cost of using them even if they were available. Effective use of reservoir management tools requires, in general, the services of a professional (geoscientist or engineer) who is already familiar with the details of setting up, running, and interpreting computer models.

Sgro, A.G.; Kendall, R.P.; Kindel, J.M.; Webster, R.B.; Whitney, E.M.

1996-11-01

57

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

58

Horizontal drilling in Baldonnel gas reservoirs - a case history of the Jadney - North Bubbles gas pools  

Microsoft Academic Search

The Jedney - North Bubbles gas pools are trapped in anticlinal folds of the host Triassic dolostones against a northern subcrop edge. The pools have been on production since the early 1960`s, with producing wells averaging 45 dam³\\/d and current reserve lives in excess of 10 years. Gross pay thickness of the reservoir is 46m, with the better matrix wells

R. Hill; P. Kubica; G. Tebbutt

1996-01-01

59

Influence of reservoir heterogeneity on gas resource potential for geologically based infill drilling, Brooks and I-92 reservoirs, Frio Formation, south Texas  

Microsoft Academic Search

Gas resource potential for strategic infill drilling or recompletion in a reservoir can be calculated by subtracting gas volumes derived using the material balance (pressure decline) method from volumes derived using a volumetric method. This resource potential represents remaining gas that is not in communication with existing wells. Frio reservoirs in mature, nonassociated gas plays located downdip from the Vicksburg

M. L. W. Jackson; W. A. Ambrose

1989-01-01

60

Delta 37Cl and Characterisation of Petroleum-gas Reservoirs  

NASA Astrophysics Data System (ADS)

The geochemical characterisation of formation waters from oil/gas fields is used to detect fluid-flow barriers in reservoirs and to reconstruct the system dynamic. During the progression of the reservoir filling, the aquifer waters are pushed by hydrocarbons toward the reservoir bottom and their compositions evolve due to several parameters such as water-rock interactions, mixing with oil-associated waters, physical processes etc. The chemical and isotopic evolution of these waters is recorded in irreducible waters that have been progressively "fossilised" in the oil/gas column. Residual salts precipitated from these waters were recovered. Chloride being the most important dissolved anion in these waters and not involved in diagenetic reactions, its investigation should give insights into the different transport or mixing processes taking place in the sedimentary basin and point out to the formation waters origins. The first aim of our study was to test the Cl-RSA technique (Chlorine Residual Salts Analysis) based on the well-established Sr-RSA technique. The main studied area is a turbiditic sandstone reservoir located in the Lower Congo basin in Angola. Present-day aquifer waters, irreducible waters from sandstone and shale layers as well as drilling mud and salt dome samples were analysed. Formation waters (aquifer and irreducible trapped in shale) show an overall increase of chlorinity with depth. Their ?37Cl values range from -1.11 ppm to +2.30 ppm ± 0.05 ppm/ SMOC. Most Cl-RSA data as well as the ?37Cl obtained on a set of water samples (from different aquifers in the same area) are lower than -0.13 ppm with lower ?37Cl values at shallower depths. In a ?37Cl versus chlorinity diagram, they are distributed along a large range of chlorinity: 21 to 139 g/l, in two distinct groups. (1) Irreducible waters from one of the wells display a positive correlation between chlorinity and the ?37Cl values. (2) In contrary, the majority of ?37Cl measured on aquifers and on residual salts from a second well are anti-correlated with chlorinity. The preliminary determinations of ?37Cl values of sandstone irreducible waters seem to match the values obtained on irreducible waters trapped in the shale porosity. ?37Cl values and chlorinities are used to identify the contributions of physico-chemical processes such as ion filtration, diffusion or mixing. The chronology of the events and their relative importance are discussed.

Woulé Ebongué, V.; Jendrzejewski, N.; Walgenwitz, F.; Pineau, F.; Javoy, M.

2003-04-01

61

Evaluating oil, gas opportunities in western Siberia; Reservoir description  

SciTech Connect

In this article, the authors discuss how to use the subsurface data to describe hydrocarbon reservoirs and estimate the original oil in place (OOIP) in western Siberia. The methodology for describing a reservoir and estimating the OOIP in western Siberia is similar to the approach for most reservoirs: Establish stratigraphic correlations across the field; Construct structure maps on key horizons; Construct porosity isopach maps for significant reservoirs; Construct net pay maps; Determine reservoir parameters; and Calculate pore-volume estimates of OOIP.

Connelly, W. (Pangea International Inc., Golden, CO (United States)); Krug, J.A. (Questa Engineering Corp., Golden, CO (United States))

1992-12-07

62

Potential power generation and gas production from Gulf Coast Geopressured Reservoirs  

Microsoft Academic Search

Extensive on-shore and offshore zones of geopressured water reservoirs are found in the Texas and Louisiana Gulf Coast region. Energy in these reservoirs is present in the form of natural gas in solution, thermal energy, and hydraulic, energy. Reservoir depths generally vary from 5000 to 20,000 feet, with corresponding temperatures from below 200°F to above 300°F. Natural gas is presumed

P. A. House; P. M. Johnson; D. F. Towse

1975-01-01

63

Unconventional gas sources. Executive summary. [Coal seams, Devonian shale, geopressured brines, tight gas reservoirs  

SciTech Connect

The long lead time required for conversion from oil or gas to coal and for development of a synthetic fuel industry dictates that oil and gas must continue to supply the United States with the majority of its energy requirements over the near term. In the interim period, the nation must seek a resource that can be developed quickly, incrementally, and with as few environmental concerns as possible. One option which could potentially fit these requirements is to explore for, drill, and produce unconventional gas: Devonian Shale gas, coal seam gas, gas dissolved in geopressured brines, and gas from tight reservoirs. This report addresses the significance of these sources and the economic and technical conditions under which they could be developed.

Not Available

1980-12-01

64

Product gas reservoirs for cyclic char burning engines and gasifiers  

SciTech Connect

A cyclic char fuel burning power reactor (CFR) is described, comprising: at least one combined means for compressing and expanding gases, each comprising: an internal combustion engine (ICE) mechanism comprising a variable volume chamber (VVC) for compressing and expanding gases, and drive means for driving the ICE mechanism and for varying the volume of the chamber through repeated cycles and each the combined means being connected to a separate primary reaction chamber (PRC), within a pressure vessel container, each the PRC comprising: a refuel end with a mechanism for supplying fresh char fuel (CF) particles into the refuel end, an ash collection end, a CF direction of motion from the refuel end toward the ash removal end, a CF preheat zone positioned toward the refuel end, a rapid reaction zone positioned between the CF preheat zone and the ash collection zone, and at least one means for removing ashes; the CFR further comprising a source of supply of reactant gas containing appreciable oxygen gas to each the intake means for admitting reactant gases into the VVC; means for preheating the CF within the PRC to that temperature at which the CF reacts rapidly with oxygen in adjacent compressed reactant gases when the CFR is being started; means for cranking the ICE mechanism when the CFR is being started; an improvement comprising adding to each the PRC a reactant gas manifold comprising an inlet and an outlet; a producer gas reservoir (pgr) wherein all of the reactant gas inlet ports and also all of the outlet ports are smaller in at least one area cross section dimension than the CF particles to be refueled into the PRC; means for gas flow connecting the VVC of the ICE mechanism to the PRC so that during all compression time intervals gas flows from the VVC into the PRC via the reactant gas manifold inlet and gas flows from the PRC into the pgr; and further so that during all expansion time intervals gas flows from the pgr and the PRC into the VVC.

Firey, J.C.

1993-06-08

65

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

66

Gas atomized chemical reservoir ODS ferritic stainless steels  

SciTech Connect

Gas atomization reaction synthesis was used to surface oxidize ferritic stainless steel powders (i.e., Fe-16.0Cr-(0.1-0.2)Y-(0.1-0.5)(Ti or Hf) at.%) during the primary break-up and solidification of the molten alloy. This rapid surface reaction resulted in envelopment of the powders by an ultra thin (i.e., t < 100nm) metastable Cr-enriched oxide shell. This metastable oxide phase was subsequently dissociated, and used as an oxygen reservoir for the formation of more thermodynamically favored Y-(Ti,Hf) nano-metric oxide precipitates during elevated temperature heat treatment of the as-consolidated powders. This oxygen exchange reaction promoted the formation of nano-metric oxide dispersoids throughout the alloy microstructure. The atomization processing parameters were adjusted to tailor the oxygen content in as-atomized powders. Microstructure phase analysis was completed using transmission electron microscopy and X-ray powder diffraction.

Rieken, J.R.; Anderson, I.E.; Kramer, M.J.

2010-06-27

67

Coupling relationship between natural gas charging and deep sandstone reservoir formation: A case from the Kuqa Depression, Tarim Basin  

Microsoft Academic Search

The formation mechanism of deep effective reservoirs is elaborated based on the analysis of the conditions for forming natural gas accumulations in deep Kuqa Depression. Natural gas charging is closely related to the formation of effective sandstone reservoirs in the deep zone: reservoirs which capture oil and gas in the early period are of better quality during the long burial

Zhu Guangyou; Zhang Shuichang; Chen Ling; Yang Haijun; Yang Wenjing; Zhang Bin; Su Jin

2009-01-01

68

Naturally fractured tight gas - gas reservoir detection optimization. Quarterly report, June 1, 1996--September 30, 1996  

SciTech Connect

This document contains the status report for the Naturally Fractured Tight Gas-Gas Reservoir Detection Optimization project for the contract period 9/30/93 to 3/31/97. Data from seismic surveys are analyzed for structural imaging of reflector units. The data were stacked using the new, improved statics and normal moveout velocities. The 3-D basin modeling effort is continuing with code development. The main activities of this quarter were analysis of fluid pressure data, improved sedimentary history, lithologic unit geometry reconstruction algorithm and computer module, and further improvement, verification, and debugging of the basin stress and multi-phase reaction transport module.

Maxwell, J.M.; Ortoleva, P.; Payne, D.; Sibo, W.

1996-11-15

69

Advancing New 3D Seismic Interpretation Methods for Exploration and Development of Fractured Tight Gas Reservoirs  

Microsoft Academic Search

In a study funded by the U.S. Department of Energy and GeoSpectrum, Inc., new P-wave 3D seismic interpretation methods to characterize fractured gas reservoirs are developed. A data driven exploratory approach is used to determine empirical relationships for reservoir properties. Fractures are predicted using seismic lineament mapping through a series of horizon and time slices in the reservoir zone. A

James Reeves

2005-01-01

70

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

71

The urgency of assessing the greenhouse gas budgets of hydroelectric reservoirs in China  

NASA Astrophysics Data System (ADS)

Already the largest generator of hydroelectricity, China is accelerating dam construction to increase the share of hydroelectricity in its primary energy mix to reduce greenhouse gas emissions. Here, we review the evidence on emissions of GHGs, particularly methane, from the Three Gorges Reservoir, and argue that although the hydroelectric reservoirs may release large amounts of methane, they contribute significantly to greenhouse gas reduction by substitution of thermal power generation in China. Nonetheless, more systematic monitoring and modelling studies on greenhouse gas emissions from representative reservoirs are necessary to better understand the climate impact of hydropower development in China.

Hu, Yuanan; Cheng, Hefa

2013-08-01

72

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

73

Feasibility Assessment of CO2 Sequestration and Enhanced Recovery in Gas Shale Reservoirs  

NASA Astrophysics Data System (ADS)

CO2 sequestration and enhanced methane recovery may be feasible in unconventional, organic-rich, gas shale reservoirs in which the methane is stored as an adsorbed phase. Previous studies have shown that organic-rich, Appalachian Devonian shales adsorb approximately five times more carbon dioxide than methane at reservoir conditions. However, the enhanced recovery and sequestration concept has not yet been tested for gas shale reservoirs under realistic flow and production conditions. Using the lessons learned from previous studies on enhanced coalbed methane (ECBM) as a starting point, we are conducting laboratory experiments, reservoir modeling, and fluid flow simulations to test the feasibility of sequestration and enhanced recovery in gas shales. Our laboratory work investigates both adsorption and mechanical properties of shale samples to use as inputs for fluid flow simulation. Static and dynamic mechanical properties of shale samples are measured using a triaxial press under realistic reservoir conditions with varying gas saturations and compositions. Adsorption is simultaneously measured using standard, static, volumetric techniques. Permeability is measured using pulse decay methods calibrated to standard Darcy flow measurements. Fluid flow simulations are conducted using the reservoir simulator GEM that has successfully modeled enhanced recovery in coal. The results of the flow simulation are combined with the laboratory results to determine if enhanced recovery and CO2 sequestration is feasible in gas shale reservoirs.

Vermylen, J. P.; Hagin, P. N.; Zoback, M. D.

2008-12-01

74

Review of Fracture Fluid-Reservoir Interactions in Tight Gas Formations.  

National Technical Information Service (NTIS)

This publication reviews the pertinent literature available on fracture fluid interactions with tight gas formations and other related subjects such as fracture proppants and reservoir characteristics. It deals primarily with the fracture fluids and their...

B. A. Baker H. B. Carroll

1979-01-01

75

Horizontal drilling in Baldonnel gas reservoirs - a case history of the Jadney - North Bubbles gas pools  

SciTech Connect

The Jedney - North Bubbles gas pools are trapped in anticlinal folds of the host Triassic dolostones against a northern subcrop edge. The pools have been on production since the early 1960`s, with producing wells averaging 45 dam{sup 3}/d and current reserve lives in excess of 10 years. Gross pay thickness of the reservoir is 46m, with the better matrix wells averaging 22m of 9.5% porosity. The reservoir is {open_quote}streaky{close_quote} with lenses of primarily moldic porosity, through dissolution of the shell and crinoid components. Petro-Canada drilled seven horizontal wells into the pools in 1993-1994. Flooding surfaces of {open_quote}high gamma{close_quote} phosphate-rich laminae are correlatable, and allow subdivision of the Baldonnel into five distinctly different units. The middle or {open_quote}C{close_quote} unit porosity was successfully targeted by all seven wells. Well length in the {open_quote}C{close_quote} unit averages 800m, approximately 50% of that being porous. All horizontal wells were evaluated with resistivity and nuclear porosity logs. Porosities calculated from the density log compared favourably with the core porosity. However, in porous intervals the neutron log indicated a large gas effect. In some of the wells, resistivity image logs were run to obtain detailed information on structure; particularly fracture density and orientation. In addition, FMI images also provide valuable information on stratigraphy and reservoir continuity. In one of the wells an ARI resistivity log was run. The drilling program has been economically successful and provided a clearer, albeit more complex, picture of the reservoir.

Hill, R.; Kubica, P.; Tebbutt, G. [Petro-Canada Resources, Calgary (Canada)

1996-06-01

76

A practical approach for optimization of infill well placement in tight gas reservoirs  

Microsoft Academic Search

Despite their low production rates, tight gas wells contribute significantly to the Nation's energy supply. Because permeabilities in tight reservoirs can be as low as fractions of a millidarcy, or even in the microdarcy range, drainage areas are small and many more wells are needed to drain tight gas fields than conventional gas fields. Infill drilling has been the most

Yueming Cheng; Duane A. McVay; W. John Lee

2009-01-01

77

Chemical stimulation of gas condensate reservoirs: An experimental and simulation study  

Microsoft Academic Search

Well productivity in gas condensate reservoirs is reduced by condensate banking when the bottom hole flowing pressure drops below the dewpoint pressure. Several methods have been proposed to restore gas production rates after a decline due to condensate blocking. Gas injection, hydraulic fracturing, horizontal wells and methanol injection have been tried with limited success. These methods of well stimulation either

Viren Kumar

2006-01-01

78

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

79

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

Microsoft Academic Search

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 and frequency of expensive repeat seismic acquisition. We simulate a Gulf of Mexico gas reservoir time-lapse response for depletion and water flooding using uncertainty ranges in water saturation, porosity, stress-induced velocity changes, and pore compressibility.

Christy Gautre

2010-01-01

80

Feasibility Assessment of CO2 Sequestration and Enhanced Recovery in Gas Shale Reservoirs  

Microsoft Academic Search

CO2 sequestration and enhanced methane recovery may be feasible in unconventional, organic-rich, gas shale reservoirs in which the methane is stored as an adsorbed phase. Previous studies have shown that organic-rich, Appalachian Devonian shales adsorb approximately five times more carbon dioxide than methane at reservoir conditions. However, the enhanced recovery and sequestration concept has not yet been tested for gas

J. P. Vermylen; P. N. Hagin; M. D. Zoback

2008-01-01

81

Rock Compressibility and Failure as Reservoir Mechanisms in Geopressured Gas Reservoirs  

Microsoft Academic Search

Rock compressibility has long been recognized as an important factor in material-balance calculations of oil in place for closed reservoirs producing above bubble-point pressure. For example, if the pore volume compressibility of the reservoir rock is half of the compressibility of the undersaturated oil, neglect of the rock-compressibility term results in about a 50% overestimation of oil in place. In

David Harville; Murray Hawkins Jr.

1969-01-01

82

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

83

Development of improved technologies and techniques for reducing base gas requirements in underground gas storage facilities: Simulation study of hanson field gas storage reservoir. Final report, May 1989November 1989  

Microsoft Academic Search

Base gas requirements in the U.S. amount to a few trillion cubic feet. The Gas Research Institute has proposed a gas storage operating plan whereby an inert gas or a low BTU gas could be injected to replace part of the hydrocarbon gas. A reservoir simulator has been developed, enhanced and tested to solve gas-water reservoir problems where the gas

Modine

1989-01-01

84

Multiscale rock-physics templates for gas detection in carbonate reservoirs  

NASA Astrophysics Data System (ADS)

The heterogeneous distribution of fluids in patchy-saturated rocks generates significant velocity dispersion and attenuation of seismic waves. The mesoscopic Biot-Rayleigh theory is used to investigate the relations between wave responses and reservoir fluids. Multiscale theoretical modeling of rock physics is performed for gas/water saturated carbonate reservoirs. Comparisons with laboratory measurements, log and seismic data validate the rock physics template. Using post-stack and pre-stack seismic inversion, direct estimates of rock porosity and gas saturation of reservoirs are obtained, which are in good agreement with oil production tests of the wells.

Ba, Jing; Cao, Hong; Carcione, José M.; Tang, Gang; Yan, Xin-Fei; Sun, Wei-tao; Nie, Jian-xin

2013-06-01

85

Surface tension of reservoir crude-oil/gas systems recognizing the asphalt in the heavy fraction  

SciTech Connect

Improvements in predicting surface tensions for crude-oil/gas systems at reservoir conditions has been attributed to new parachors for distillation cuts of crude oil and the recognition that the last fraction or residue of distillation has a parachor not continuous with the distillation cuts. For such reservoir gas/oil systems as condensates, which normally do not contain asphalt materials, the new parachors for the crude cuts would suffice for the surface-tension computation. For a reservoir fluid containing asphaltic substances, the calculation procedure should include a single measurement of the surface tension.

Firoozabadi, A.; Katz, D.L.; Soroosh, H.; Sajjadian, V.A.

1988-02-01

86

Critical Performance Parameters for Horizontal Well Applications in Gas Storage Reservoirs, Final Report, March 1992-March 1993.  

National Technical Information Service (NTIS)

The report identifies, classifies, and illustrates the importance of a number of reservoir, operational, and well design parameters that are likely to strongly influence horizontal well performance in gas storage reservoirs. The technical approach entaile...

J. K. Hall S. D. Joshi W. Ding

1993-01-01

87

Application of facies analysis to improve gas reserve growth in Fluvial Frio Reservoirs, La Gloria Field, South Texas  

Microsoft Academic Search

Geologically based infill-drilling strategies hold great potential for extension of domestic gas resources. Traditional gas-well drilling and development have often assumed homogeneous and continuous reservoirs; uniform gas-well spacing has resulted in numerous untapped reservoirs isolated from other productive sand bodies. Strategically located infill wells drilled into these undrained reservoirs may ultimately contact an additional 20% of original gas in place

W. A. Ambrose; M. L. W. Jackson; R. J. Finley

1988-01-01

88

PP and PS seismic response from fractured tight gas reservoirs: a case study  

NASA Astrophysics Data System (ADS)

In this paper, we present an example of using PP and PS converted-wave data recorded by digital micro-eletro-mechanical-systems (MEMS) to evaluate a fractured tight gas reservoir from the Xinchang gas field in Sichuan, China. For this, we analyse the variations in converted shear-wave splitting, Vp/Vs ratio and PP and PS impedance, as well as other attributes based on absorption and velocity dispersion. The reservoir formation is tight sandstone, buried at a depth of about 5000 m, and the converted-wave data reveal significant shear-wave splitting over the reservoir formation. We utilize a rotation technique to extract the shear-wave polarization and time delay from the data, and a small-window correlation method to build time-delay spectra that allow the generation of a time-delay section. At the reservoir formation, the shear-wave time delay is measured at 20 ms, about 15% shear-wave anisotropy, correlating with the known gas reservoirs. Furthermore, the splitting anomalies are consistent with the characteristics of other attributes such as Vp/Vs ratio and P- and S-wave acoustic and elastic impedance. The P-wave shows consistent low impedance over the reservoir formation, whilst the S-wave impedance shows relatively high impedance. The calculated gas indicator based on absorption and velocity dispersion yields a high correlation with the gas bearing formations. This confirms the benefit of multicomponent seismic data from digital MEMS sensors.

Jianming, Tang; Shaonan, Zhang; Li, Xiang-Yang

2008-03-01

89

Advancing New 3D Seismic Interpretation Methods for Exploration and Development of Fractured Tight Gas Reservoirs  

SciTech Connect

In a study funded by the U.S. Department of Energy and GeoSpectrum, Inc., new P-wave 3D seismic interpretation methods to characterize fractured gas reservoirs are developed. A data driven exploratory approach is used to determine empirical relationships for reservoir properties. Fractures are predicted using seismic lineament mapping through a series of horizon and time slices in the reservoir zone. A seismic lineament is a linear feature seen in a slice through the seismic volume that has negligible vertical offset. We interpret that in regions of high seismic lineament density there is a greater likelihood of fractured reservoir. Seismic AVO attributes are developed to map brittle reservoir rock (low clay) and gas content. Brittle rocks are interpreted to be more fractured when seismic lineaments are present. The most important attribute developed in this study is the gas sensitive phase gradient (a new AVO attribute), as reservoir fractures may provide a plumbing system for both water and gas. Success is obtained when economic gas and oil discoveries are found. In a gas field previously plagued with poor drilling results, four new wells were spotted using the new methodology and recently drilled. The wells have estimated best of 12-months production indicators of 2106, 1652, 941, and 227 MCFGPD. The latter well was drilled in a region of swarming seismic lineaments but has poor gas sensitive phase gradient (AVO) and clay volume attributes. GeoSpectrum advised the unit operators that this location did not appear to have significant Lower Dakota gas before the well was drilled. The other three wells are considered good wells in this part of the basin and among the best wells in the area. These new drilling results have nearly doubled the gas production and the value of the field. The interpretation method is ready for commercialization and gas exploration and development. The new technology is adaptable to conventional lower cost 3D seismic surveys.

James Reeves

2005-01-31

90

Visco-plastic properties of organic-rich shale gas reservoir rocks and its implication for stress variations within reservoirs  

NASA Astrophysics Data System (ADS)

We are studying the time-dependent deformational properties of shale gas reservoir rocks through laboratory creep experiments in a triaxial deformation apparatus under room temperature and room humidity conditions. Samples come from the Barnett shale (TX), Eagle Ford shale (TX), Haynesville shale (LA), and Fort St. John shale (Canada). The clay and carbonate content of these shales vary markedly, as well as the total organic content. To cover effective pressures both below and above in-situ conditions, confining pressures were between 10-60 MPa. In order to examine creep processes unrelated to pre-failure crack growth, differential stresses during creep were kept below 50% of the ultimate rock strength. Time dependent creep at constant differential stress increases with clay content (regardless of the carbonate content) and there is a pronounced increase in amount of creep at around 35-40% clay content. The amount of creep strain is relatively insensitive to both the confining pressure and differential pressure. More creep occurs in the bedding-perpendicular direction than the bedding-parallel direction, which correlates with the sample's elastic anisotropy. The constitutive law governing the time-dependent deformation of these rocks is visco-plastic, and creep strain is well-approximated by a power-law function of time within the time scales of the experiment (maximum of 2 weeks). Also an oven-dried sample exhibited much less creep, which suggests that the physical mechanism of the creep is likely a hydrolytically-assisted plastic deformation process. Interpretation of the results through visco-elastic theory shows that the power law exponents of these rocks, which reflects how rapid a rock creeps or relaxes stress, vary between 0.01-0.07. Based on these numbers, we can roughly calculate the visco-elastic accumulation of differential stresses within these reservoirs, by assuming a constant intraplate tectonic strain rate (10^-19 - 10^-17) and by considering the ages of these rocks (100-350 Ma). Results suggest that the current intra-reservoir contrast of differential stresses can become as high as tens of MPa. Such prediction is consistent with the occurence of drilling-induced tensile fractures (DITFs) observed in a vertical well from Barnett shale where DITFs appear and disappear corresponding to the intra-reservoir lithological variation. It is important to characterize such stress variations within a reservoir since production from shale gas reservoirs heavily relies on reservoir stimulation by hydraulic fracturing and in-situ stress is a major control on the outcomes of such operations.

Sone, H.; Zoback, M. D.

2011-12-01

91

Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity  

SciTech Connect

The objectives of this project are to augment the National Reservoir Database (TORIS database) and to increase our understanding of geologic heterogeneities that affect the recoveries of oil and gas from carbonate reservoirs in the State of Alabama and to identify those resources that are producible at moderate cost. These objectives will be achieved through detailed geological, engineering, and geostatistical characterization of typical Jurassic Smackover Formation hydrocarbon reservoirs in selected productive fields in the State of Alabama. The results of these studies will be used to develop and test mathematical models for prediction of the effects of reservoir heterogeneities in hydrocarbon production. Work to date has focused on the completion of Subtasks 1, 2, and 3. Subtask 1 included the survey and tabulation of available reservoir engineering and geological data relevant to the Smackover reservoir in southwestern Alabama. Subtask 2 comprises the geological and engineering characterization of Smackover reservoir lithofacies. This has been accomplished through detailed examination and analysis of geophysical well logs, core material, well cuttings, and well-test data from wells penetrating Smackover reservoirs in southwestern Alabama. From these data, reservoir heterogeneities, such as lateral and vertical changes in lithology, porosity, permeability, and diagenetic overprint, have been recognized and used to produce maps, cross sections, graphs, and other graphic representations to aid in interpretation of the geologic parameters that affect these reservoirs. Subtask 3 includes the geologic modeling of reservoir heterogeneities for Smackover reservoirs. This research has been based primarily on the evaluation of key geologic and engineering data from selected Smackover fields. 1 fig.

Mancini, E.A.

1990-01-01

92

Analytical Modeling for Gravity Segregation in Gas Improved Oil Recovery of Tilted Reservoirs  

Microsoft Academic Search

Stone’s model for gravity segregation in gas improved oil recovery (IOR) indicates the distance that injected gas and water\\u000a travel together before the segregation being completed (length of complete segregation). This model is very useful for co-injection\\u000a of water and gas into horizontal depleted reservoirs. A proof by Rossen and van Duijn showed that Stone’s model applies to\\u000a steady-state gas–liquid

Mohammad Jamshidnezhad; T. Ghazvian

2011-01-01

93

Reservoir engineering study of low-permeability Western gas sands. Final report  

Microsoft Academic Search

The parameters of formation permeability, porosity, gas saturation net pay thickness, and well spacing were investigated to develop a multiple-well transient test. Long test times were found to be required for interference or pulse testing in low permeability gas reservoirs; however, well spacing has been optimized. The new type curves developed account for the length of time a well was

Bixel

1982-01-01

94

Transport and storage of CO 2 in natural gas hydrate reservoirs  

Microsoft Academic Search

Storage of CO2 in natural gas hydrate reservoirs may offer stable long term deposition of a greenhouse gas while benefiting from methane production, without requiring heat. By exposing hydrate to a thermodynamically preferred hydrate former, CO2, the hydrate may be maintained macroscopically in the solid state and retain the stability of the formation. One of the concerns, however, is the

Geir Ersland; Jarle Husebø; Arne Graue; Bjørn Kvamme

2009-01-01

95

The Niobrara Gas Play: Exploration and Development of a Low-Pressure, Low-Permeability Gas Reservoir  

Microsoft Academic Search

An integrated interdisciplinary exploration\\/exploitation strategy contributed to the successful economic development of the Niobrara gas play, located in eastern Colorado, northwestern Kansas, and western Nebraska. The exploration, development, production, and evaluation data suggest that (1) Niobrara chalk reservoirs have exceptionally high porosities but very low permeabilities, (2) individual reservoirs are low-relief, highly faulted structural traps characterized consistently by extensive water-transition

C. A. Brown; J. W. Crafton; J. G. Golson

1982-01-01

96

Gas-field deliverability forecasting: A coupled reservoir simulator and surface facilities model  

SciTech Connect

To determine if a gas contract can be satisified now and in the future, it is necessary to forecast the performance of the gas reservoir, the gas inflow into the sandface, the multiphase pressure losses in the wellbore and gathering system and the field facilities. Surface production models which rigorously model from the sandface to the plant gate are available. However, these surface packages model reservoirs simply, in most cases as tank-type reservoirs. Comprehensive 3 dimensional reservoir simulators are available, but typically only include simple surface networks which don`t adequately model multiphase flow in complex gathering systems. This paper describes the procedures used in a joint venture by two software vendors to combine an existing reservoir simulator and an existing surface facilities model into a single forecasting tool. Relatively small changes were made to each program. In the new model, the black oil reservoir simulator provides the formation pressure and water to gas ratio for each well. The surface facilities model then calculates the multiphase flow pressure losses in the wellbore and gathering system, plus the corresponding flow rates for each well. The actual production required from each well to satisfy the pipeline contractual requirements, over each time step, is computed by the surface facilities model and relayed back to the reservoir simulator. The time step is determined dynamically according to the requirements of each program. The performance and results from the coupled model are compared to that of running each model separately for a gas storage field in the USA and for a gas production field with bottom-water. It is shown that running each model separately does not account for all the factors affecting the forecast.

Trick, M.D. [Neotechnology Consultants Ltd. (United States); Agarwal, R. [Computer Modelling Group (United States); Ammer, J.R.; Mercer, J.C. [USDOE Morgantown Energy Technology Center, WV (United States); Harris, R.P. [National Fuel Gas Supply Corp. (United States)

1994-08-01

97

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

98

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

99

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

100

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

101

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

102

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

103

Forty-seven years of gas injection in a preferentially oil-wet, low-dip reservoir  

Microsoft Academic Search

The Mauddud is the major oil producing reservoir of the Bahrain field situated in an anticlinal feature of Middle Cretaceous period. This is a highly undersaturated, lowdip and preferentially oil wet reservoir. Crestal gas injection has been employed in the Central area of the reservoir since 1938 for pressure maintenance thus making it the first improved recovery project in the

C. R. K. Murty; B. A. Dakessian; N. A. Saleh

1985-01-01

104

A critical compilation of 1,500 large onshore gas reservoirs in Texas Gulf Coast and East Texas  

Microsoft Academic Search

About 1,500 gas reservoirs in the Texas Gulf Coast and east Texas have a cumulative production of at least 10 bcf. The Gulf Coast contains nearly 90% of these reservoirs. One-third of all reservoirs have produced more than 30 bcf, and another 10% have produced more than 100 bcf. In the Gulf Coast, total production from the greater than 30

E. C. Kosters; R. J. Finley; N. Tyler

1988-01-01

105

Processes affecting greenhouse gas production in experimental boreal reservoirs  

NASA Astrophysics Data System (ADS)

Flooding land for water reservoir creation has many environmental impacts including the production of the greenhouse gases (GHG) carbon dioxide (CO2) and methane (CH4). To assess processes governing GHG emissions from the flooding of terrestrial carbon, three experimental reservoirs were constructed in upland boreal forest areas of differing carbon stores as part of the Flooded Upland Dynamics Experiment (FLUDEX). We calculated process-based GHG budgets for these reservoirs over 5 years following the onset of flooding. Stable isotopic budgets of carbon were necessary to separate community respiration (CR), which produces CO2, from net primary production (NPP), which consumes CO2, and to separate CH4 production from CH4 consumption via oxidation. NPP removed up to 44% of the CO2 produced from CR. CR and NPP exhibited different year-after-year trends. CH4 flux to the atmosphere increased about twofold over 3 years, yet isotopic budgets showed CH4 production in flooded soils increased nearly tenfold. CH4 oxidation near the flooded soil-water interface greatly decreased the CH4 flux from the water column to the atmosphere. Ebullition was the most important conduit of CH4 to the atmosphere after 3 years. Although CH4 production increased with time, the total GHG flux, in CO2 equivalents, declined. Contrary to expectations, neither CR nor total GHG fluxes were directly related to the quantity of organic carbon flooded. Instead, these reservoirs produced a strikingly similar amount of CO2 equivalents over 5 years.

Venkiteswaran, Jason J.; Schiff, Sherry L.; St. Louis, Vincent L.; Matthews, Cory J. D.; Boudreau, Natalie M.; Joyce, Elizabeth M.; Beaty, Kenneth G.; Bodaly, R. Andrew

2013-04-01

106

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

107

Storage of natural gas in a depleted reservoir  

Microsoft Academic Search

El Paso Natural Gas Co. places great faith in the use of underground storage for natural gas. El Paso, because of the geological limitations within its service area, developed the storage it uses on the upstream end of its transmission system. The importance of using storage projects to conserve natural gas cannot be emphasized too strongly. It affords the natural

1967-01-01

108

Prediction of gas injection performance for heterogenous reservoirs, semi-annual technical report, October 1, 1996March 31, 1997  

Microsoft Academic Search

The current project is a systematic research effort that will lead to a new generation of predictive tools for gas injection processes in heterogeneous reservoirs. The project is aimed at quantifying the impact of heterogeneity on oil recovery from pore level to reservoir scales. This research effort is, therefore, divided into four areas: (1) Laboratory Gas Injection Experiments (2) Network

Blunt

1997-01-01

109

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

110

Secondary natural gas recovery in mature fluvial sandstone reservoirs, Frio Formation, Agua Dulce Field, South Texas  

SciTech Connect

An approach that integrates detailed geologic, engineering, and petrophysical analyses combined with improved well-log analytical techniques can be used by independent oil and gas companies of successful infield exploration in mature Gulf Coast fields that larger companies may consider uneconomic. In a secondary gas recovery project conducted by the Bureau of Economic Geology and funded by the Gas Research Institute and the U.S. Department of Energy, a potential incremental natural gas resource of 7.7 bcf, of which 4.0 bcf may be technically recoverable, was identified in a 490-ac lease in Agua Dulce field. Five wells in this lease had previously produced 13.7 bcf from Frio reservoirs at depths of 4600-6200 ft. The pay zones occur in heterogeneous fluvial sandstones offset by faults associated with the Vicksburg fault zone. The compartments may each contain up to 1.0 bcf of gas resources with estimates based on previous completions and the recent infield drilling experience of Pintas Creek Oil Company. Uncontacted gas resources occur in thin (typically less than 10 ft) bypassed zones that can be identified through a computed log evaluation that integrates open-hole logs, wireline pressure tests, fluid samples, and cores. At Agua Dulce field, such analysis identified at 4-ft bypassed zone uphole from previously produced reservoirs. This reservoir contained original reservoir pressure and flowed at rates exceeding 1 mmcf/d. The expected ultimate recovery is 0.4 bcf. Methodologies developed in the evaluation of Agua Dulce field can be successfully applied to other mature gas fields in the south Texas Gulf Coast. For example, Stratton and McFaddin are two fields in which the secondary gas recovery project has demonstrated the existence of thin, potentially bypassed zones that can yield significant incremental gas resources, extending the economic life of these fields.

Ambrose, W.A.; Levey, R.A. (Univ. of Texas, Austin, TX (United States)); Vidal, J.M. (ResTech, Inc., Houston, TX (United States)); Sippel, M.A. (Research and Engineering Consultants, Inc., Englewood, CA (United States)); Ballard, J.R. (Envirocorp Services and Technology, Houston, TX (United States)); Coover, D.M. Jr. (Pintas Creek Oil Company, Corpus Christi, TX (United States)); Bloxsom, W.E. (Coastal Texas Oil and Gas, Houston, TX (United States))

1993-09-01

111

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

Microsoft Academic Search

Identification of the source of CO2 in natural reservoirs and development of physical models to account for the migration and interaction of this CO2 with the groundwater is essential for developing a quantitative understanding of the long term storage potential of CO2 in the subsurface. We present the results of 57 noble gas determinations in CO2 rich fields (>82%) from

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

2008-01-01

112

Influence of deep gas-steam fluids on the composition of reservoir waters of oil and gas fields  

Microsoft Academic Search

In this work the conditions of the formation of low-mineral deep hydrocarbonate sodium waters of oil-and-gas fields are considered.\\u000a Analysis of the boron-bromine ratio of reservoir and condensed waters in several fields of Western Siberia shows that the\\u000a influx of endogenous high-temperature gas-steam fluids into zones containing sedimentogenic brines is a decisive factor in\\u000a the formation of the chemical composition

V. A. Vsevolozhsky; T. A. Kireeva

2010-01-01

113

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

114

Improving Well Productivity in Gas Condensate Reservoirs via Chemical Treatment  

Microsoft Academic Search

Condensate dropout and accumulation along with high water saturation near the wellbore region result in a decrease in the gas relative permeability. This permeability is a function of fluid saturations interfacial tension (IFT and rock wettability between the condensate and gas. The need to mitigate the reduction in well productivity caused by condensate build up below the dew point is

Mukul Sharma; Vishal Bang; Mohabbat Ahmadi; Harry Linnemeyer

115

On the Economics of Improved Oil Recovery: The Optimal Recovery Factor from Oil and Gas Reservoirs  

Microsoft Academic Search

This paper investigates an oil company's optimal depletion of oil and gas reservoirs, taking into account that the depletion policy itself influences the recoverable reserves, i.e. determines the recovery factor. The emphasis is on the role of up-front capital costs. The depletion policy is derived from the amount of investment in production and associated injection projects, represented in a stylized

Arild N. Nystad

1988-01-01

116

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

117

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

SciTech Connect

The objective is to determine methods for detection and mapping of natural fracture systems for economic production of natural gas from fractured reservoirs. This progress report covers: 3D P-wave survey; additional processing of 3D P-wave survey; review of multicomponent recording feasibility tests; minivibrator studies; and modeling of 3D-3C acquisition parameters.

NONE

1995-05-01

118

Optimisation of the wells placement in gas reservoirs using SIMPLEX method  

Microsoft Academic Search

This paper presents novel optimisation model to evaluate the optimal number of wells for underground gas storage operations. More specifically, generalized well-placement scheme has been formulated to minimize the total number of wells required to fulfil prescribed multiple constrains including wells interference. The scheme integrates nonlinear models of reservoir and well performance. The optimization problem has been formulated mathematically and

Jakub Siemek; Jerzy Stopa

2006-01-01

119

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

Microsoft Academic Search

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

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

2008-01-01

120

OIL RECOVERY FROM WATERFLOODED RESERVOIRS BY INJECTING GAS, ALTERNATELY WITH WATER  

Microsoft Academic Search

There are many reservoirs in which water flooding has been implemented, some in a very advanced stage. At the end of waterflood often some 40 to 60% of the original oil-in-place is left behind. Under favourable circumstances, the use of gas injection can result in a better displacement efficiency than waterflooding, but it usually has poorer sweep efficiency and is

M. Sohrabi; G. D. Henderson; D. H. Tehrani; M. I. J. van Dijke; S. R. McDougall; K. S. Sorbie; A. Danesh; B. G. D. Smart

121

Application of oil gas-chromatography in reservoir compartmentalization in a mature Venezuelan oil field  

Microsoft Academic Search

Gas chromatographic oil {open_quotes}fingerprinting{close_quotes} was successfully applied in a multidisciplinary production geology project by Maraven, S.A. to define the extent of vertical and lateral continuity of Eocene and Miocene sandstone reservoirs in the highly faulted Bloque I field, Maracaibo Basin, Venezuela. Seventy-five non-biodegraded oils (20°-37.4° API) were analyzed with gas chromatography. Fifty were produced from the Eocene Misoa C-4, C-5,

N. G. Munoz; L. Mompart; S. C. Talukdar

1996-01-01

122

A Successful Gas-Injection Project in a Heavy Oil Reservoir  

Microsoft Academic Search

Meneven, an affiliate of Petroleos de Venezuela, S.A., has been conducting a natural-gas-injection project in a heavy-oil reservoir (14 to 20 API), located in E. Venezuela, immediately north of the Orinoco oil belt, since 1963. Laboratory tests were made to investigate recovery mechanisms, and a black-oil simulator was used to match performance history and predict future performance under continued gas

F. M. Garcia

1983-01-01

123

Influence of reservoir heterogeneity on gas resource potential for geologically based infill drilling, Brooks and I-92 reservoirs, Frio Formation, south Texas  

SciTech Connect

Gas resource potential for strategic infill drilling or recompletion in a reservoir can be calculated by subtracting gas volumes derived using the material balance (pressure decline) method from volumes derived using a volumetric method. This resource potential represents remaining gas that is not in communication with existing wells. Frio reservoirs in mature, nonassociated gas plays located downdip from the Vicksburg fault zone are characterized by multiple, vertically stacked sandstones. The Brooks reservoir, in La Gloria field, lies in a fluvial-dominated system that contains dip-elongate channel sandstone belts 1-2 mi wide. Within these belts are six or more vertically stacked channel-fill, point-bar and splay deposits. Depositional environments were interpreted from SP logs. Individual sandstones are separated vertically by thin mudstone layers and pinch out laterally into flood-plain deposits.

Jackson, M.L.W.; Ambrose, W.A. (Bureau of Economic Geology, Austin, TX (USA))

1989-09-01

124

Transport of gas-phase radionuclides in a fractured, low-permeability reservoir  

SciTech Connect

The U.S. Atomic Energy Commission (predecessor to the U.S. 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 2,134-m-deep well at 1,780, 1,899, and 2,039 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 principal 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.

Clay Cooper; Jenny Chapman

2001-12-01

125

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

SciTech Connect

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 and finite-difference techniques, show that for vertical shale permeabilities which are at least of the order of 10/sup -5/ md, shale recharge will constitute an important reservoir drive mechanism and will result in much larger fluid recovery than that possible in the absence of shale dewatering.

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

1985-01-01

126

Studies of gas injection into oil reservoirs by a cell-to-cell simulation model  

SciTech Connect

Injection of various gases into two different North Sea reservoir oils has been simulated using a cell to cell model. It is shown that ternary diagrams are insufficient to represent the mixing processes which take place in a petroleum reservoir into which gas is being injected. New criteria for evaluating the results of a cell to cell calculation are suggested. The highest recoveries are obtained when a miscible drive is established. However, also in cases where miscibility is not achieved, a marked enhancement of the oil recovery may be possible.

Pederson, K.S.; Fjellerup, J.; Thomassen, P.; Fredenslund, A.

1986-01-01

127

Application of oil gas-chromatography in reservoir compartmentalization in a mature Venezuelan oil field  

SciTech Connect

Gas chromatographic oil {open_quotes}fingerprinting{close_quotes} was successfully applied in a multidisciplinary production geology project by Maraven, S.A. to define the extent of vertical and lateral continuity of Eocene and Miocene sandstone reservoirs in the highly faulted Bloque I field, Maracaibo Basin, Venezuela. Seventy-five non-biodegraded oils (20{degrees}-37.4{degrees} API) were analyzed with gas chromatography. Fifty were produced from the Eocene Misoa C-4, C-5, C-6 or C-7 horizons, fifteen from the Miocene basal La Rosa and ten from multizone completions. Gas chromatographic and terpane and sterane biomarker data show that all of the oils are genetically related. They were expelled from a type II, Upper Cretaceous marine La Luna source rock at about 0.80-0.90% R{sub o} maturity. Alteration in the reservoir by gas stripping with or without subsequent light hydrocarbons mixing was observed in some oils. Detailed chromatographic comparisons among the oils shown by star plots and cluster analysis utilizing several naphthenic and aromatic peak height ratios, resulted in oil pool groupings. This led to finding previously unknown lateral and vertical reservoir communication and also helped in checking and updating the scaling character of faults. In the commingled oils, percentages of each contributing zone in the mixture were also determined giving Maraven engineers a proven, rapid and inexpensive tool for production allocation and reservoir management The oil pool compartmentalization defined by the geochemical fingerprinting is in very good agreement with the sequence stratigraphic interpretation of the reservoirs and helped evaluate the influence of structure in oil migration and trapping.

Munoz, N.G.; Mompart, L. [Maraven, Caracas (Venezuela); Talukdar, S.C.

1996-08-01

128

Chemical stimulation of gas condensate reservoirs: An experimental and simulation study  

NASA Astrophysics Data System (ADS)

Well productivity in gas condensate reservoirs is reduced by condensate banking when the bottom hole flowing pressure drops below the dewpoint pressure. Several methods have been proposed to restore gas production rates after a decline due to condensate blocking. Gas injection, hydraulic fracturing, horizontal wells and methanol injection have been tried with limited success. These methods of well stimulation either offer only temporary productivity restoration or are applicable only in some situations. Wettability alteration of the rock in the near well bore region is an economic and efficient method for the enhancement of gas-well deliverability. Altering the wettability of porous media from strongly water-wet or oil-wet to intermediate-wet decreases the residual liquid saturations and results in an increase in the relative permeability to gas. Such treatments also increase the mobility and recovery of condensate from the reservoir. This study validates the above hypothesis and provides a simple and cost-efficient solution to the condensate blocking problem. Screening studies were carried out to identify the chemicals based on structure, solubility and reactivity at reservoir temperature and pressure. Experiments were performed to evaluate these chemicals to improve gas and condensate relative permeabilities. The improvement in relative permeability after chemical treatment was quantified by performing high pressure and high temperature coreflood experiments in Berea sandstone, Texas Cream limestone and reservoir cores using synthetic gas mixtures at reservoir conditions. Experiments were done at high flow rates and for long time periods to evaluate the durability of the treatment. Single well simulation studies were conducted to demonstrate the performance of the chemical treatment in the field. The experimental relative permeability data was modeled using a trapping number dependent relative permeability model and incorporated in the simulations. Effect of connate water saturation, drawdown pressure, skin, treatment radius and the timing of the treatment during the life of the reservoir were investigated using a compositional simulator. Spectroscopic studies using a scanning electron microscope, neutron magnetic resonance and time of flight-secondary ion mass spectroscopy were used to determine the structural and reactive chemistry of the chemicals used and to evaluate the extent of treatment on the rock surface. The study allows us to postulate and partly verify a detailed mechanism of interaction between the rock surface and the chemical.

Kumar, Viren

129

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

130

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

131

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

132

Rock assay for predicting oil or gas in target reservoirs  

US Patent & Trademark Office Database

The present invention relates to assays for ascribing catalytic activity to rock samples by virtue of zero-valent transition metals potentially being present within the sample. Embodiments of the present invention are generally directed to novel assays for measuring intrinsic paleocatalytic activities (k) of sedimentary rocks for converting oil to gas and projecting the activities to the subsurface based on the measured linear relationship between ln(k) and temperature (T).

2006-12-26

133

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

134

HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS  

SciTech Connect

Gas injection in oil reservoirs offers huge potential for improved oil recovery. However, successful design of a gas injection process requires a detailed understanding of a variety of different significant processes, including the phase behavior of multicomponent mixtures and the approach to multi-contact miscibility in the reservoir, the flow of oil, water and gas underground, and the interaction of phase behavior reservoir heterogeneity and gravity on overall performance at the field scale. This project attempts to tackle all these issues using a combination of theoretical, numerical and laboratory studies of gas injection. The aim of this work is to develop a set of ultra-fast compositional simulation tools that can be used to make field-scale predictions of the performance of gas injection processes. To achieve the necessary accuracy, these tools must satisfy the fundamental physics and chemistry of the displacement from the pore to the reservoir scales. Thus this project focuses on four main research areas: (1) determination of the most appropriate methods of mapping multicomponent solutions to streamlines and streamtubes in 3D; (2) development of techniques for automatic generation of analytical solutions for one-dimensional flow along a streamline; (3) experimental investigations to improve the representation of physical mechanisms that govern displacement efficiency along a streamline; and (4) Theoretical and experimental investigations to establish the limitations of the streamline/streamtube approach. In this report they briefly review the status of the research effort in each area. They then give a more in depth discussion of the development of a CT scanning technique which can measure compositions in a two-phase, three-component system in-situ.

Thomas A. Hewett; Franklin M. Orr Jr.

2000-12-31

135

Estimating Deliverability in Multi-Layered Gas Reservoirs Using Artificial Intelligence  

NASA Astrophysics Data System (ADS)

In this research, an artificial intelligence (AI) model has been created to estimate the production rate of each layer in a multi-layered gas reservoir using static properties such as those obtained from well logging, in addition to dynamic properties such as pressure. This approach will be helpful in several reservoir engineering applications, such as understanding layers' depletion, or targeting specific layers for workover. It could also be used for PLT analysis where the measured PLT values are compared to the expected values and a variance analysis could be performed. Data were collected from more than 100 wells in a certain reservoir spanning over four fields. They were combined in related input variables and fed to the AI model for learning purposes. To compare different AI methods, the data were fed to 5 methods, namely ANFIS, MLP, RBF, SVM, and GRNN, and results were optimized for each method. Between the tested AI methods, SVM and GRNN performed best as shown by a low mean absolute percentage error and a very high correlation coefficient. This research shows promising use for AI methods in estimating production rate from each layer in a multi-layered gas reservoir.

Al-Arfaj, Malik Khalid

136

A breakthrough of researching reservoir adsorption gas and its significance  

Microsoft Academic Search

GC-C-MS on linear isotope analysis equipment makes it possible to measure the hydrocarbon gases at the level of 10?3–10?2 ?L. By applying this technique the carbon isotopes of C1-C3 of the adsorbed gas from the Triassic oil sand bed of the Aican-l Well in the Turpan-Hami basin were analysed. The ?13C values of C1-C3 are ?55.1‰, ?38.6‰ and ?35.0‰ respectively.

Yongchang Xu; Xiaobao Zhang; Ping Shen; Wenhui Liu

1999-01-01

137

Geologic characterization of tight gas reservoirs: Annual report, FY 1987  

SciTech Connect

The objectives of US Geological Survey (USGS) work are to conduct geologic research characterizing tight gas-bearing sequences in the western United States. Additional critical objects are to provide geologic consulting and research support for ongoing Multiwell Experiment (MWX) engineering, petrophysical, log-analysis, and well-testing research. The USGS research during the last few years has been in the Greater Green River, Piceance, and Uinta basins of Wyoming, Colorado, and Utah. However, beginning in FY-87 our efforts have been restricted for the most part to the Greater Green River basin. 16 refs., 20 figs.

Law, B.E.; Spencer, C.W.; Keighin, C.W.; Lickus, M.R.; Pollastro, R.M.; Johnson, R.C.; Nuccio, V.F.; Charpentier, R.R.; Wandrey, C.J.

1987-10-01

138

Deep microbial life in the Altmark natural gas reservoir: baseline characterization prior CO2 injection  

NASA Astrophysics Data System (ADS)

Within the framework of the CLEAN project (CO2 Largescale Enhanced gas recovery in the Altmark Natural gas field) technical basics with special emphasis on process monitoring are explored by injecting CO2 into a gas reservoir. Our study focuses on the investigation of the in-situ microbial community of the Rotliegend natural gas reservoir in the Altmark, located south of the city Salzwedel, Germany. In order to characterize the microbial life in the extreme habitat we aim to localize and identify microbes including their metabolism influencing the creation and dissolution of minerals. The ability of microorganisms to speed up dissolution and formation of minerals might result in changes of the local permeability and the long-term safety of CO2 storage. However, geology, structure and chemistry of the reservoir rock and the cap rock as well as interaction with saline formation water and natural gases and the injected CO2 affect the microbial community composition and activity. The reservoir located at the depth of about 3500m, is characterised by high salinity fluid and temperatures up to 127° C. It represents an extreme environment for microbial life and therefore the main focus is on hyperthermophilic, halophilic anaerobic microorganisms. In consequence of the injection of large amounts of CO2 in the course of a commercial EGR (Enhanced Gas Recovery) the environmental conditions (e.g. pH, temperature, pressure and solubility of minerals) for the autochthonous microorganisms will change. Genetic profiling of amplified 16S rRNA genes are applied for detecting structural changes in the community by using PCR- SSCP (PCR-Single-Strand-Conformation Polymorphism) and DGGE (Denaturing Gradient Gel Electrophoresis). First results of the baseline survey indicate the presence of microorganisms similar to representatives from other saline, hot, anoxic, deep environments. However, due to the hypersaline and hyperthermophilic reservoir conditions, cell numbers are low, so that the quantification of those microorganisms as well as the determination of microbial activity was not yet possible. Microbial monitoring methods have to be further developed to study microbial activities under these extreme conditions to access their influence on the EGR technique and on enhancing the long term safety of the process by fixation of carbon dioxide by precipitation of carbonates. We would like to thank GDF SUEZ for providing the data for the Rotliegend reservoir, sample material and enabling sampling campaigns. The CLEAN project is funded by the German Federal Ministry of Education and Research (BMBF) in the frame of the Geotechnologien Program.

Morozova, Daria; Shaheed, Mina; Vieth, Andrea; Krüger, Martin; Kock, Dagmar; Würdemann, Hilke

2010-05-01

139

Horizontal-well technology for enhanced recovery in very mature, depletion-drive gas reservoirs  

Microsoft Academic Search

Horizontal-well technology has been applied successfully to exploit reservoirs with thin beds, low-permeability zones, and natural fractures and in high-cost areas and zones with water coming. Horizontal technology has been used to enhance ultimate gas recovery in a very mature, low-pressure zone in the lower Pettit horizon at Carthage field, Panola County, Texas. The Pirkle-2 well was drilled to test

A. W. McCoy; F. A. Davis; J. P. Elrod; S. L. Jr. Rhodes; S. P. Singh

1998-01-01

140

HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS  

SciTech Connect

This report outlines progress in the third 3 quarter of the first year of the DOE project ''High Resolution Prediction of Gas Injection Process Performance for Heterogeneous Reservoirs.'' A simple theoretical formulation of vertical flow with capillary/gravity equilibrium is described. Also reported are results of experimental measurements for the same systems. The results reported indicate that displacement behavior is strongly affected by the interfacial tension of phases that form on the tie line that extends through the initial oil composition.

Franklin M. Orr, Jr.

2001-06-30

141

The big fat LARS - a LArge Reservoir Simulator for hydrate formation and gas production  

NASA Astrophysics Data System (ADS)

Simulating natural scenarios on lab scale is a common technique to gain insight into geological processes with moderate effort and expenses. Due to the remote occurrence of gas hydrates, their behavior in sedimentary deposits is largely investigated on experimental set ups in the laboratory. In the framework of the submarine gas hydrate research project (SUGAR) a large reservoir simulator (LARS) with an internal volume of 425 liter has been designed, built and tested. To our knowledge this is presently a word-wide unique set up. Because of its large volume it is suitable for pilot plant scale tests on hydrate behavior in sediments. That includes not only the option of systematic tests on gas hydrate formation in various sedimentary settings but also the possibility to mimic scenarios for the hydrate decomposition and subsequent natural gas extraction. Based on these experimental results various numerical simulations can be realized. Here, we present the design and the experimental set up of LARS. The prerequisites for the simulation of a natural gas hydrate reservoir are porous sediments, methane, water, low temperature and high pressure. The reservoir is supplied by methane-saturated and pre-cooled water. For its preparation an external gas-water mixing stage is available. The methane-loaded water is continuously flushed into LARS as finely dispersed fluid via bottom-and-top-located sparger. The LARS is equipped with a mantle cooling system and can be kept at a chosen set temperature. The temperature distribution is monitored at 14 reasonable locations throughout the reservoir by Pt100 sensors. Pressure needs are realized using syringe pump stands. A tomographic system, consisting of a 375-electrode-configuration is attached to the mantle for the monitoring of hydrate distribution throughout the entire reservoir volume. Two sets of tubular polydimethylsiloxan-membranes are applied to determine gas-water ratio within the reservoir using the effect of permeability differences between gaseous and dissolved methane (Zimmer et al., 2011). Gas hydrate is formed using a confined pressure of 12-15 MPa and a fluid pressure of 8-11 MPa with a set temperature of 275 K. The duration of the formation process depends on the required hydrate saturation and is usually in a range of several weeks. The subsequent decomposition experiments aiming at testing innovative production scenarios such as the application of a borehole tool for thermal stimulation of hydrate via catalytic oxidation of methane within an autothermal catalytic reactor (Schicks et al. 2011). Furthermore, experiments on hydrate decomposition via pressure reduction are performed to mimic realistic scenarios such as found during the production test in Mallik (Yasuda and Dallimore, 2007). In the near future it is planned to scale up existing results on CH4-CO2 exchange efficiency (e.g. Strauch and Schicks, 2012) by feeding CO2 to the hydrate reservoir. All experiments are due to the gain of high-resolution spatial and temporal data predestined as a base for numerical modeling. References Schicks, J. M., Spangenberg, E., Giese, R., Steinhauer, B., Klump, J., Luzi, M., 2011. Energies, 4, 1, 151-172. Zimmer, M., Erzinger, J., Kujawa, C., 2011. Int. J. of Greenhouse Gas Control, 5, 4, 995-1001. Yasuda, M., Dallimore, S. J., 2007. Jpn. Assoc. Pet. Technol., 72, 603-607. Beeskow-Strauch, B., Schicks, J.M., 2012. Energies, 5, 420-437.

Beeskow-Strauch, Bettina; Spangenberg, Erik; Schicks, Judith M.; Giese, Ronny; Luzi-Helbing, Manja; Priegnitz, Mike; Klump, Jens; Thaler, Jan; Abendroth, Sven

2013-04-01

142

Characteristics of the nuclear magnetic resonance logging response in fracture oil and gas reservoirs  

NASA Astrophysics Data System (ADS)

Fracture oil and gas reservoirs exist in large numbers. The accurate logging evaluation of fracture reservoirs has puzzled petroleum geologists for a long time. Nuclear magnetic resonance (NMR) logging is an effective new technology for borehole measurement and formation evaluation. It has been widely applied in non-fracture reservoirs, and good results have been obtained. But its application in fracture reservoirs has rarely been reported in the literature. This paper studies systematically the impact of fracture parameters (width, number, angle, etc), the instrument parameter (antenna length) and the borehole condition (type of drilling fluid) on NMR logging by establishing the equation of the NMR logging response in fracture reservoirs. First, the relationship between the transverse relaxation time of fluid-saturated fracture and fracture aperture in the condition of different transverse surface relaxation rates was analyzed; then, the impact of the fracture aperture, dip angle, length of two kinds of antennas and mud type was calculated through forward modeling and inversion. The results show that the existence of fractures affects the NMR logging; the characteristics of the NMR logging response become more obvious with increasing fracture aperture and number of fractures. It is also found that T2 distribution from the fracture reservoir will be affected by echo spacing, type of drilling fluids and length of antennas. A long echo spacing is more sensitive to the type of drilling fluid. A short antenna is more effective for identifying fractures. In addition, the impact of fracture dip angle on NMR logging is affected by the antenna length.

Xiao, Lizhi; Li, Kui

2011-04-01

143

Radon-222 Content of Natural Gas Samples from Upper and Middle Devonian Sandstone and Shale Reservoirs in Pennsylvania: Preliminary Data.  

National Technical Information Service (NTIS)

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 ...

E. L. Rowan T. F. Kraemer

2012-01-01

144

The Lessons Learned From Miscible Gas Flooding in Naturally Fractured Reservoirs: Integrated Studies, and Pilot and Field Cases  

Microsoft Academic Search

Suitable methods have to be employed for secondary and tertiary oil recovery from the naturally fractured reservoirs (NFRs). The miscible gas injection has shown some promising results for enhancing oil recovery from NFRs. However, proper design of the field-scale miscible gas injection projects in NFRs is still a major challenge. The authors evaluate the technical issues of the miscible gas

B. Yadali Jamaloei; Riyaz Kharrat

2012-01-01

145

Fracture detection, mapping, and analysis of naturally fractured gas reservoirs using seismic technology. Final report, November 1995  

SciTech Connect

Many basins in the Rocky Mountains contain naturally fractured gas reservoirs. Production from these reservoirs is controlled primarily by the shape, orientation and concentration of the natural fractures. The detection of gas filled fractures prior to drilling can, therefore, greatly benefit the field development of the reservoirs. The objective of this project was to test and verify specific seismic methods to detect and characterize fractures in a naturally fractured reservoir. The Upper Green River tight gas reservoir in the Uinta Basin, Northeast Utah was chosen for the project as a suitable reservoir to test the seismic technologies. Knowledge of the structural and stratigraphic geologic setting, the fracture azimuths, and estimates of the local in-situ stress field, were used to guide the acquisition and processing of approximately ten miles of nine-component seismic reflection data and a nine-component Vertical Seismic Profile (VSP). Three sources (compressional P-wave, inline shear S-wave, and cross-line, shear S-wave) were each recorded by 3-component (3C) geophones, to yield a nine-component data set. Evidence of fractures from cores, borehole image logs, outcrop studies, and production data, were integrated with the geophysical data to develop an understanding of how the seismic data relate to the fracture network, individual well production, and ultimately the preferred flow direction in the reservoir. The multi-disciplinary approach employed in this project is viewed as essential to the overall reservoir characterization, due to the interdependency of the above factors.

NONE

1995-10-01

146

Using gas geochemistry to delineate structural compartments and assess petroleum reservoir-filling directions: A Venezuelan case study  

NASA Astrophysics Data System (ADS)

Here we examined the light hydrocarbon and nitrogen content and isotopic signatures of eleven gaseous samples in order to evaluate lateral intra-reservoir continuity in a Venezuelan reservoir in the central area of Lake Maracaibo Basin. At least three single compartments, located in the northern-central and southern parts of the reservoir, are revealed by nitrogen concentrations showing clear step-like compositional breaks. The occurrence of step-breaks was also supported by the isotopic signature of individual hydrocarbon compounds in the range of C1-C4 alkanes. Samples presented only slight differences in N2 and hydrocarbon gas compositions within the central and northern parts of the reservoir, and therefore it was not possible to infer structural barriers in coherence with the geological section. Some oil bulk parameters corroborate gradual changes that provide additional information on the reservoir-filling history, thus suggesting that the lateral physical-chemical equilibrium of fluids was not reached in this reservoir.

Márquez, G.; Escobar, M.; Lorenzo, E.; Gallego, J. R.; Tocco, R.

2013-04-01

147

Reservoir modeling in the Bunyu Tapa Gas Field - an integrated case study  

SciTech Connect

Bunya Tapa gas field is located on the western edge of Bunyu Island, approximately 12 km northwest of Bunyu Nibung oil field; it is the main gas producer for the Bunyu methanol plant. Initially, the Bunyu Tapa sands were believed to be deposited as a blanket-type sheet sand, but after drilling 21 wells in this field, it is obvious that these sands lack lateral continuity. The Bunyu Tapa reservoir sands were deposited in a deltaic environment. Several wells, which were producing gas close to the structurally high western edge of this field, are exhibiting a high-water cut. This water production is not expected in a deltaic lens environment, especially since these wells are updip to other gas-producing wells. This Bunyu Tapa reservoir modeling study is an integrated investigation of 2-D seismic data, electric logs, dipmeter, petrophysical analysis, and production history data. The results of this integrated study show that the sands were deposited as distributary channel sands across the field and extend offshore. Structurally, the wells on the western edge are in fact on the eastern flank of a north-south-trending anticline, close to the gas/water contact and are separated from the eastern wells by north-south-trending normal faults. In the near future, as a result of this study, a deviated well is planned to evaluate the offshore area to the west.

Nugroho, S. (Pertamina Unit IV, Balikpapan (Indonesia)); Hansen, S.; Susanto, M. (Schlumberger, Balikpapan (Indonesia))

1994-07-01

148

A 3-D seismic case history evaluating fluvially deposited thin-bed reservoirs in a gas-producing property  

SciTech Connect

The authors conducted a study at Stratton Field, a large Frio gas-producing property in Kleberg and Nueces Counties in South Texas, to determine how to best integrate geophysics, geology, and reservoir engineering technologies to detect thin-bed compartmented reservoirs in a fluvially deposited reservoir system. This study documents that narrow, meandering, channel-fill reservoirs as thin as 10 ft (3 m) and as narrow as 200 ft (61 m) can be detected with 3-D seismic imaging at depths exceeding 6,000 ft (1,800 m) if the 3-D data are carefully calibrated using vertical seismic profile (VSP) control. Even though the 3-D seismic images show considerable stratigraphic detail in the interwell spaces and indicate where numerous thin-bed compartment boundaries could exist, the seismic images cannot b themselves specify which stratigraphic features are the flow barriers that create the reservoir compartmentalization. However, when well production histories, reservoir pressure histories, and pressure interference tests are incorporated into the 3-D seismic interpretation, a compartmentalized model of the reservoir system can be constructed that allows improved development drilling and reservoir management to be implemented. This case history illustrates how realistic, thin-bed, compartmented reservoir models result when geologists, engineers,and geophysicists work together to develop a unified model of a stratigraphically complex reservoir system.

Hardage, B.A.; Levey, R.A.; Pendleton, V.; Simmons, J.; Edson, R. (Univ. of Texas, Austin, TX (United States). Bureau of Economic Geology)

1994-11-01

149

Relationships between gas reservoir and the evolution of stope surrounding rock fracture at the process of mining the closed distance protection layer  

Microsoft Academic Search

Overburden rock movements and fracture developments occur during mining activities. Consequently, relief gas reservoirs and migration in coal seams being mined as well as in near distant coal seams appear. We considered a gas disaster management project and rules on stope relief of gas flows together and explored a gas reservoir and the evolution of stope surrounding rock fractures in

Zhi-yong HAO; Bai-quan LIN; Hai-jin WU; Jie MENG

2009-01-01

150

Characterization of oil and gas reservoir heterogeneity; Final report, November 1, 1989--June 30, 1993  

SciTech Connect

The Alaskan North Slope comprises one of the Nation`s and the world`s most prolific oil province. Original oil in place (OOIP) is estimated at nearly 70 BBL (Kamath and Sharma, 1986). Generalized reservoir descriptions have been completed by the University of Alaska`s Petroleum Development Laboratory over North Slope`s major fields. These fields include West Sak (20 BBL OOIP), Ugnu (15 BBL OOIP), Prudhoe Bay (23 BBL OOIP), Kuparuk (5.5 BBL OOIP), Milne Point (3 BBL OOIP), and Endicott (1 BBL OOIP). Reservoir description has included the acquisition of open hole log data from the Alaska Oil and Gas Conservation Commission (AOGCC), computerized well log analysis using state-of-the-art computers, and integration of geologic and logging data. The studies pertaining to fluid characterization described in this report include: experimental study of asphaltene precipitation for enriched gases, CO{sup 2} and West Sak crude system, modeling of asphaltene equilibria including homogeneous as well as polydispersed thermodynamic models, effect of asphaltene deposition on rock-fluid properties, fluid properties of some Alaskan north slope reservoirs. Finally, the last chapter summarizes the reservoir heterogeneity classification system for TORIS and TORIS database.

Sharma, G.D.

1993-09-01

151

DEVELOPMENT OF MORE-EFFICIENT GAS FLOODING APPLICABLE TO SHALLOW RESERVOIRS  

SciTech Connect

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 enrichment needed in the presence of dispersion. Subtask 1.2 develops a fast, efficient method to predict the extent of enrichment needed for crude oils at a given pressure. Task 2 develops improved foam processes to increase sweep efficiency in gas flooding. Subtask 2.1 comprises mechanistic experimental studies of foams with N2 gas. Subtask 2.2 conducts experiments with CO{sub 2} foam. Subtask 2.3 develops and applies a simulator for foam processes in field application.

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

2003-08-21

152

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

153

Reservoir fluid and gas chemistry during CO2 injection at the Cranfield field, Mississippi, USA  

NASA Astrophysics Data System (ADS)

At Cranfield field, Mississippi, USA, a monitored CO2-EOR project provides a unique opportunity to understand geochemical interactions of injected CO2 within the reservoir. Cranfield field, discovered in 1943, is a simple anticlinal four-way closure and had a large gas cap surrounded by an oil ring (Mississippi Oil and Gas Board, 1966). The field was abandoned in 1966. The reservoir returned to original reservoir pressure (hydrostatic pressure) by a strong aquifer drive by 2008. The reservoir is in the lower Tuscaloosa Formation at depths of more than 3000 m. It is composed of stacked and incised channel fills and is highly heterogeneous vertically and horizontally. A variable thickness (5 to 15 m) of terrestrial mudstone directly overlies the basal sandstone providing the primary seal, isolating the injection interval from a series of fluvial sand bodies occurring in the overlying 30 m of section. Above these fluvial channels, the marine mudstone of the Middle Tuscaloosa forms a continuous secondary confining system of approximately 75 m. The sandstones of the injection interval are rich in iron, containing abundant diagenetic chamosite (ferroan chlorite), hematite and pyrite. Geochemical modeling suggests that the iron-bearing minerals will be dissolved in the face of high CO2 and provide iron for siderite precipitation. CO2 injection by Denbury Resources Inc. begun in mid-July 2008 on the north side of the field with rates at ~500,000 tones per year. Water and gas samples were taken from seven production wells after eight months of CO2 injection. Gas analyses from three wells show high CO2 concentrations (up to 90 %) and heavy carbon isotopic signatures similar to injected CO2, whereas the other wells show original gas composition and isotope. The mixing ratio between original and injected CO2 is calculated based on its concentration and carbon isotope. However, there is little variation in fluid samples between the wells which have seen various levels of CO2. Comparison between preinjection and postinjection fluid analyses also shows little difference. It suggests that CO2 injection has not induced significant mineral-water reactions to change water chemistry. In October 2009, CO2 will be injected into the down-dip, non-productive Tuscaloosa Formation on the east side of the same field. In-situ fluid and gas samples will be collected using downhole U-tube. Fluid chemistry data through time will reveal mineral reactions during and after injection and confine timescales of the interactions. This project was funded thought the National Energy Technology Laboratory Regional Carbon Sequestration Partnership Program as part of the Southeast Regional Carbon Sequestration Partnership.

Lu, J.; Kharaka, Y. K.; Cole, D. R.; Horita, J.; Hovorka, S.

2009-12-01

154

Geology and diagenetic history of overpressured sandstone reservoirs, Venture Gas field, offshore Nova Scotia, Canada  

SciTech Connect

Deep exploratory wells in the Scotian Basin, offshore Nova Scotia, Canada, have encountered overpressured formations with pressures 1.9 {times} the normal hydrostatic gradient. The overpressures occur over an area of approximately 10,000 km{sup 2}. In the Venture field, the abnormal pressures are confined below a depth of 4,500 m and are associated with Upper Jurassic-Lower Cretaceous gas- and condensate-bearing sandstone reservoirs. The overpressures occur within normally compacted shales containing numerous overpressured sandstone reservoir beds. The development of overpressures, seals, and secondary reservoirs are all diagenetically driven. Three secondary porosity depth levels, which top at 2,500 m (65C), 3,700 m (95C), and 4,600 m (130C), correlate with major steps in the organic matter maturation in the basin. Secondary porosity is initially achieved by aluminosilicate dissolution, with ferroan sparry calcite cement dissolution dominating below 4,000 m. Porosity enhancement and preservation is not the result of a single diagenetic event but instead the result of a series of diagenetic events that overlapped in time. Formation of dynamic diagenetic barriers within the zone of peak gas generation helps retard the diffusive migration of hydrocarbons and other fluids expelled during shale diagenesis resulting in pressure build up. The preservation of up to 32% porosity under 500-1,000 atm of pressure could not be achieved without simultaneous pressuring of developing voids. Significant for hydrocarbon exploration is that Venture-type diagenetic overpressures are not associated with undercompacted sediments and, hence, they cannot be predicted from compaction trends during drilling. Petrographic diagenetic, and lithofacies studies can be instrumental in predicting potential areas of deep subsurface secondary reservoirs dependent.

Jansa, L.F. (Bedford Institute of Oceanography, Dartmouth, Nova Scotia (Canada) Dalhousie Univ., Halifax, Nova Scotia (Canada)); Urrea V.H.N. (Chevron Canada Resources, Calgary, Alberta (Canada))

1990-10-01

155

Gas reservoir potential of the Lower Ordovician Beekmantown Group, Quebec Lowlands, Canada  

SciTech Connect

The Beekmantown Group in the Quebec Lowlands was deposited as part of an extensive Early Ordovician coastal and shallow marine complex on the eastern margin of the North American craton. The Beekmantown is stratigraphically equivalent to the Beekmantown, Knox, Arbuckle, and Ellenburger rocks of the United States, and is subdivided into two formations: the sandstone-rich Theresa Formation and the overlying dolomite-rich Beauharnois. Dolomites of the Beekmantown provide an important exploration target in both the autochthon and the overlying thrust sheets of the Canadian and U.S. Appalachians. The reservoir potential of the autochthonous Beekmantown Group in the Quebec Lowlands can be determined from seismic data, well logs, cuttings, and petrographic analyses of depositional and diagenetic textures. Deposition of the Beekmantown occurred alongson the western passive margin of the Iapetus Ocean. By the Late Ordovician, the passive margin had been transformed into a foreland basin. Faulting locally positioned Upper Ordovician Utica source rocks against the Beekmantown and contributed to forming hydrocarbon reservoirs. The largest Beekmantown reservoir found to date is the St. Flavien field, with 7.75 bcf of original gas (methane) in place in fractured and possibly karst-influenced allochthonous dolomites within a thrust-fault anticline. Seven major depositional units can be distinguished in cuttings and correlated with wireline logs. Dolomites in the Beekmantown contain vuggy, moldic, intercrystalline, and fracture porosity. Early porosity formed at the top of the major depositional units in peritidal dolomites; however, much of this porosity was later filled by late-stage calcite cement after hydrocarbon migration. Thus, a key to finding gas reservoirs in the autochthonous Beekmantown is to define Ordovician poleostructures in which early and continuous entrapment of hydrocarbons prevented later cementation.

Dykstra, J.C.F. [Talisman Energy Inc., Alberta (Canada); Longman, M.W. [Consulting Geologist, Lakewood, CO (United States)

1995-04-01

156

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

157

HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS  

SciTech Connect

This report outlines progress in the first quarter of the second year of the DOE project ''High Resolution Prediction of Gas Injection Process Performance for Heterogeneous Reservoirs''. The application of the analytical theory for gas injection processes, including the effects of volume change on mixing, has up to now been limited to fully self-sharpening systems, systems where all solution segments that connect the key tie lines present in the displacement are shock fronts. In the following report, we describe the extension of the analytical theory to include systems with rarefactions (continuous composition and saturation variations) between key tie lines. With the completion of this analysis, a completely general procedure has been developed for finding solutions for problems in which a multicomponent gas displaces a multicomponent oil.

Franklin M. Orr, Jr.

2001-12-31

158

Interpretation of results from well testing gas-condensate reservoirs: Comparison of theory and field cases  

SciTech Connect

A more complete understanding of well test interpretation results for gas-condensate fields may depend significantly on the availability of sufficient, accurate and specific field correlations involving fluid and rock properties, and on flow meter surveys. Apart from compositional variations, the most useful parameters in reviewing gas-condensate samples are condensate-gas ratio, dewpoint pressure and gas gravity. Pressure data recorded by quartz crystal gauges can result in gas gradients with sufficient accuracy to confirm variations in gas composition with depth for a reservoir of several hundred metres in thickness. By comparing these gradients with gas gravities from fluid samples, variation of the initial dewpoint pressure with depth was established. Special core analysis was carried out/sup +/ to obtain specific high velocity ..beta..-factors. However, when these laboratory measurements are compared with results obtained from production test analysis, large discrepancies are found in most cases, which can be attributed to multiphase flow near the wellbore. Although wellstream composition is found to be a function of rate, the presence of a stable condensate bank appears to be unfounded.

Behrenbruch, P.; Kozma, G.

1984-09-01

159

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

160

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

USGS Publications Warehouse

Carbon dioxide and helium with isotopic compositions indicative of a magmatic source (??13C = -4.5 to -5???, 3He/4He = 4.5 to 6.7 RA) 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 CO2 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 are associated with CO2 concentrations of 30-90% in soil gas and gas flow rates of up to 31,000 g m-2 d-1 at the soil surface. Each of the tree-kill areas and one area of CO2 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 CO2 flux from the mountain is approximately 520 t/d, and that 30-50 t/d of CO2 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 CO2 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, N2/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.

Sorey, M. L.; Evans, W. C.; Kennedy, B. M.; Farrar, C. D.; Hainsworth, L. J.; Hausback, B.

1998-01-01

161

HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS  

SciTech Connect

This report outlines progress in the second 3 months of the first year of the DOE project ''High Resolution Prediction of Gas Injection Process Performance for Heterogeneous Reservoirs.'' The development of an automatic technique for analytical solution of one-dimensional gas flow problems with volume change on mixing is described. The aim of this work is to develop a set of ultra-fast compositional simulation tools that can be used to make field-scale predictions of the performance of gas injection processes. To achieve the necessary accuracy, these tools must satisfy the fundamental physics and chemistry of the displacement from the pore to the reservoir scales. Thus this project focuses on four main research areas: (1) determination of the most appropriate methods of mapping multicomponent solutions to streamlines and streamtubes in 3D; (2) development of techniques for automatic generation of analytical solutions for one-dimensional flow along a streamline; (3) experimental investigations to improve the representation of physical mechanisms that govern displacement efficiency along a streamline; and (4) theoretical and experimental investigations to establish the limitations of the streamline/streamtube approach. In this report they briefly review the status of the research effort in each area. They then give a more in depth discussion of their development of techniques for analytic solutions along a streamline including volume change on mixing for arbitrary numbers of components.

Franklin M. Orr, Jr.

2001-03-31

162

Correlation between gas compositions and physical phenomena affecting the reservoir fluid in Palinpinon geothermal field (Philippines)  

SciTech Connect

Using thermodynamic gas equilibria to calculate temperature and steam fraction in the reservoir, three main physical phenomena due to exploitation of Palinpinon field are identified. 1) Pressure drawdown producing a local increase in the computed steam fraction, with the fluid maintaining high temperature values (close to 300°C). Strong decline in flow rate is observed. 2) Irreversible steam losses from the original high temperature liquid phase during its ascent through fractures in upper zones of the reservoir. Steam is generally lost at temperatures (e.g. 240°C) lower then those of the original aquifer. 3) Dilution and cooling effects due to reinjection fluid returns. These are function of the local geostructural conditions linking through fractures the injectors and production wells. The computed fraction of the recovered reinjected brine can in some case exceed 80% of the total produced fluid. At the same time the computed gas equilibration temperatures can decline from 280-300°C to as low as 215-220°C. Comparing these values with the well bottom measured temperatures, the proposed methodology based on gas chemistry gives more reliable temperature estimate than water chemistry based geothermometers for fluids with high fractions of injected brine.

D'More F.; Nuti, S.; Ruaya, J.R.; Ramos-Candelaria, M.N.; Seastres, J.S.

1993-01-28

163

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

164

Sustaining Fracture Area and Conductivity of Gas shale Reservoirs for Enhancing Long-term Production and Recovery  

Microsoft Academic Search

Natural gas from organic rich shale formations has become an increasingly important energy resource worldwide over the past decade. Extensive hydraulic fracture networks with massive contact surface areas are frequently required to achieve satisfactory economic production in these highly heterogeneous reservoirs, with permeability in the nano-Darcy range. Current operational experience in gas shale plays indicates that the loss of productive

R. Suarez-Rivera; S. Marino; A. Ghassemi

2010-01-01

165

Formation and types of natural gas reservoirs of the Tangyuan fault depression in Yi-Shu graben  

Microsoft Academic Search

Based on drilling, logging and geochemical data from 32 wells, the depositional and tectonic evolution of the Tangyuan fault depression were studied and the gas accumulation conditions and gas reservoir types were analyzed. Based on interpretation of 2D and 3D seismic data, a structure map of each layer was plotted and the trap types developed in various structural layers were

Tang Jinsheng; Yang Jianguo; Guo Qingxia; Tang Jinrong

2009-01-01

166

Mixing of CO2 and CH4 in gas reservoirs: Code comparison studies  

SciTech Connect

Simulation of the mixing of carbon dioxide and methane is critical to modeling gas reservoir processes induced by the injection of carbon dioxide. We have compared physical property estimates and simulation results of the mixing of carbon dioxide and methane gases from four numerical simulation codes. Test Problem 1 considers molecular diffusion in a one-dimensional stably stratified system. Test Problem 2 considers molecular diffusion and advection in an unstable two-dimensional system. In general, fair to good agreement was observed between the codes tested.

Oldenburg, Curt; Law, D.H.-S.; Le Gallo, Y.; White, S.P.

2002-07-22

167

Correlation between gas compositions and physical phenomena affecting the reservoir fluid in Palinpinon geothermal field (Philippines)  

Microsoft Academic Search

Using thermodynamic gas equilibria to calculate;\\u000atemperature and steam fraction in the reservoir, three;\\u000amain physical phenomena due to exploitation of;\\u000aPalinpinon field are identified. 1) Pressure drawdown;\\u000aproducing a local increase in the computed steam;\\u000afraction, with the fluid maintaining high temperature;\\u000avalues (close to 300°C). Strong decline in flow rate is;\\u000aobserved. 2) Irreversible steam losses from the

DMore F; S. Nuti; J. R. Ruaya; M. N. Ramos-Candelaria; J. S. Seastres

1993-01-01

168

A massive reservoir of low-excitation molecular gas at high redshift  

NASA Astrophysics Data System (ADS)

Molecular hydrogen (H2) is an important component of galaxies because it fuels star formation and the accretion of gas onto active galactic nuclei (AGN), the two processes that can generate the large infrared luminosities of gas-rich galaxies. Observations of spectral-line emission from the tracer molecule carbon monoxide (CO) are used to probe the properties of this gas. But the lines that have been studied in the local Universe-mostly the lower rotational transitions of J = 1 --> 0 and J = 2 --> 1-have hitherto been unobservable in high-redshift galaxies. Instead, higher transitions have been used, although the densities and temperatures required to excite these higher transitions may not be reached by much of the gas. As a result, past observations may have underestimated the total amount of molecular gas by a substantial amount. Here we report the discovery of large amounts of low-excitation molecular gas around the infrared-luminous quasar APM08279+5255 at redshift z = 3.91, using the two lowest excitation lines of 12 CO (J = 1 --> 0 and J = 2 --> 1). The maps confirm the presence of hot and dense gas near the nucleus, and reveal an extended reservoir of molecular gas with low excitation that is 10 to 100 times more massive than the gas traced by the higher-excitation observations. This raises the possibility that significant amounts of low-excitation molecular gas may exist in the environments of high-redshift (z > 3) galaxies.

Papadopoulos, Padeli; Ivison, Rob; Carilli, Chris; Lewis, Geraint

2001-01-01

169

Interpretation of Microseismicity Resulting from Gel and Water Fracturing of Tight Gas Reservoirs  

NASA Astrophysics Data System (ADS)

We provide a comparative analysis of the spatio-temporal dynamics of hydraulic fracturing-induced microseismicity resulting from gel and water treatments. We show that the growth of a hydraulic fracture and its corresponding microseismic event cloud can be described by a model which combines geometry- and diffusion-controlled processes. It allows estimation of important parameters of fracture and reservoir from microseismic data, and contributes to a better understanding of related physical processes. We further develop an approach based on this model and apply it to data from hydraulic fracturing experiments in the Cotton Valley tight gas reservoir. The treatments were performed with different parameters such as the type of treatment fluid, the injection flow rate, the total volume of fluid and of proppant. In case of a gel-based fracturing, the spatio-temporal evolution of induced microseismicity shows signatures of fracture volume growth, fracturing fluid loss, as well as diffusion of the injection pressure. In contrast, in a water-based fracturing the volume creation growth and the diffusion controlled growth are not clearly separated from each other in the space-time diagram of the induced event cloud. Still, using the approach presented here, the interpretation of induced seismicity for the gel and the water treatments resulted in similar estimates of geometrical characteristics of the fractures and hydraulic properties of the reservoir. The observed difference in the permeability of the particular hydraulic fractures is probably caused by the different volume of pumped proppant.

Dinske, C.; Shapiro, S. A.; Rutledge, J. T.

2010-02-01

170

Spatial and temporal patterns of greenhouse gas emissions from Three Gorges Reservoir of China  

NASA Astrophysics Data System (ADS)

Anthropogenic activity has led to significant emissions of greenhouse gas (GHG), which is thought to play important roles in global climate changes. It remains unclear about the kinetics of GHG emissions, including carbon dioxide (CO2), methane (CH4) and nitrous Oxide (N2O) from the Three Gorges Reservoir (TGR) of China, which was formed after the construction of the famous Three Gorges Dam. Here we report monthly measurements for one year of the fluxes of these gases at multiple sites within the TGR region, including three major tributaries, six mainstream sites, two downstream sites and one upstream site. The tributary areas have lower CO2 fluxes than the main storage; CH4 fluxes in the tributaries and upper reach mainstream sites are relative higher. Overall, TGR showed significantly lower CH4 emission rates than most new reservoirs in temperate and tropical regions. We attribute this to the well-oxygenated deep water and high water velocities that may facilitate the consumption of CH4. TGR's CO2 fluxes were lower than most tropical reservoirs and higher than most temperate systems. This could be explained by the high load of labile soil carbon delivered through erosion to the Yangtze River. Compared to fossil-fuelled power plants of equivalent power output, TGR is a very small GHG emitter - annual CO2-equivalent emissions are approximately 1.7% of that of a coal-fired generating plant of comparable power output.

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

2013-02-01

171

Characterization of the deep microbial life in the Altmark natural gas reservoir  

NASA Astrophysics Data System (ADS)

Within the framework of the CLEAN project (CO2 Largescale Enhanced gas recovery in the Altmark Natural gas field) technical basics with special emphasis on process monitoring are explored by injecting CO2 into a gas reservoir. Our study focuses on the investigation of the in-situ microbial community of the Rotliegend natural gas reservoir in the Altmark, located south of the city Salzwedel, Germany. In order to characterize the microbial life in the extreme habitat we aim to localize and identify microbes including their metabolism influencing the creation and dissolution of minerals. The ability of microorganisms to speed up dissolution and formation of minerals might result in changes of the local permeability and the long-term safety of CO2 storage. However, geology, structure and chemistry of the reservoir rock and the cap rock as well as interaction with saline formation water and natural gases and the injected CO2 affect the microbial community composition and activity. The reservoir located at the depth of approximately 3500 m, is characterised by high salinity (420 g/l) and temperatures up to 127°C. It represents an extreme environment for microbial life and therefore the main focus is on hyperthermophilic, halophilic anaerobic microorganisms. In consequence of the injection of large amounts of CO2 in the course of a commercial EGR (Enhanced Gas Recovery), the environmental conditions (e.g. pH, temperature, pressure and solubility of minerals) for the autochthonous microorganisms will change. Genetic profiling of amplified 16S rRNA genes are applied for detecting structural changes in the community by using PCR- SSCP (PCR-Single-Strand-Conformation Polymorphism), DGGE (Denaturing Gradient Gel Electrophoresis) and 16S rRNA cloning. First results of the baseline survey indicate the presence of microorganisms similar to representatives from other deep environments. The sequence analyses revealed the presence of several H2-oxidising bacteria (Hydrogenophaga sp., Adicdovorax sp., Ralstonia sp., Pseudomonas sp.), thiosulfate-oxidising bacteria (Diaphorobacter sp.) and biocorrosive thermophilic microorganisms, which have not previously been cultivated. Furthermore, several uncultivated microorganisms were found, that were similar to representatives from other saline, hot, anoxic, deep environments. However, due to the hypersaline and hyperthermophilic reservoir conditions, cell numbers are low, so that the quantification of those microorganisms as well as the determination of microbial activity was not yet possible. Microbial monitoring methods have to be further developed to study microbial activities under these extreme conditions to access their influence on the EGR technique and on enhancing the long term safety of the process by fixation of carbon dioxide by precipitation of carbonates. We thank GDF SUEZ for providing the data for the Rotliegend reservoir, sample material and supporting sampling campaigns. The CLEAN project is funded by the German Federal Ministry of Education and Research (BMBF) in the framework of the GEOTECHNOLOGIEN Program.

Morozova, D.; Alawi, M.; Vieth-Hillebrand, A.; Kock, D.; Krüger, M.; Wuerdemann, H.

2010-12-01

172

HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS  

SciTech Connect

This report presents a detailed analysis of the development of miscibility during gas cycling in condensates and the formation of condensate banks at the leading edge of the displacement front. Dispersion-free, semi-analytical one-dimensional (1D) calculations are presented for enhanced condensate recovery by gas injection. The semi-analytical approach allows investigation of the possible formation of condensate banks (often at saturations that exceed the residual liquid saturation) and also allows fast screening of optimal injection gas compositions. We describe construction of the semi-analytical solutions, a process which differs in some ways from related displacements for oil systems. We use an analysis of key equilibrium tie lines that are part of the displacement composition path to demonstrate that the mechanism controlling the development of miscibility in gas condensates may vary from first-contact miscible drives to pure vaporizing and combined vaporizing/condensing drives. Depending on the compositions of the condensate and the injected gas, multicontact miscibility can develop at the dew point pressure, or below the dew point pressure of the reservoir fluid mixture. Finally, we discuss the possible impact on performance prediction of the formation of a mobile condensate bank at the displacement front in near-miscible gas cycling/injection schemes.

Franklin M. Orr, Jr.

2003-06-30

173

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

174

DOE THREE-DIMENSIONAL STRUCTURE AND PHYSICAL PROPERTIES OF A METHANE HYDRATE DEPOSIT AND GAS RESERVOIR, BLAKE RIDGE  

Microsoft Academic Search

This report contains a summary of work conducted and results produced under the auspices of award DE-FC26-00NT40921, ''DOE Three-Dimensional Structure and Physical Properties of a Methane Hydrate Deposit and Gas Reservoir, Blake Ridge.'' This award supported acquisition, processing, and interpretation of two- and three-dimensional seismic reflection data over a large methane hydrate reservoir on the Blake Ridge, offshore South Carolina.

W. Steven Holbrook

2004-01-01

175

The Net Impact of Hydroelectric Reservoir Creation on Greenhouse Gas Emissions: A Study of the Eastmain-1 Reservoir in the Eastern James Bay region of Quebec, Canada  

NASA Astrophysics Data System (ADS)

In order to satisfy present and future energy demands and to minimize greenhouse gas (GHG) emissions, there is a growing need to develop energy sources that are not based on combustion. In the boreal regions of Canada, there is a huge potential for hydroelectricity production. However, in most cases, large areas of the boreal ecosystem must be inundated to create hydroelectric reservoirs. Previous studies have established that reservoirs emit GHGs, but these studies have typically focused on emissions some years after reservoir creation. The critical question that has not been asked is 'what is the net change in the exchange of GHG that results directly from the creation of the reservoir?' - i.e. 'what is the net difference between the landscape scale exchange of GHGs before and after reservoir creation, and how does that net difference change over time from when the reservoir was first created to when it reaches a steady-state condition?'. The Eastmain-1 (EM-1) hydroelectric reservoir, located in the James Bay region of Quebec was created in late 2005 and provides a tremendous opportunity to study the impacts of reservoir creation on GHG emissions which are still largely unknown for this type of land conversion. The creation of the EM-1 hydroelectric reservoir required the flooding of over 600 km2 of the boreal ecosystem along the Eastmain River, of which 65% was occupied by forest, 14% by peatland, and 21% by lakes and rivers. In order to assess the impacts of the creation of the reservoir on GHG emissions, three eddy covariance (EC) tower flux sites were established in a black spruce forest, peatland and on an island in the reservoir itself to measure continuous net ecosystem exchange (NEE) of CO2. Together, these represent the dominant terrestrial pre-flooded (forest and peatland) and post-flooded (reservoir) environments. The forest and reservoir EC systems were installed and operational by the end of summer 2006 with the peatland site coming on-line summer of 2008. Through the use of the forest and peatland analogue sites, the EC results will be used to evaluate the pre-flooded vs. post- flooded CO2 fluxes, and thus the net impact of the EM-1 reservoir creation in terms of CO2 emissions. By measurement and modeling, we will provide an estimate of the change in GHG source the atmosphere would see, an estimate of the net emissions that can be used for intercomparison of GHG contributions with other modes of power production and a basis on which to develop biogeochemically sound, verifiable, and transparent estimates for GHG accounting. This presentation will provide an overview of the project and its goals and will discuss preliminary results from the EC and terrestrial measurement campaigns.

Strachan, I. B.; Lemieux, M.; Bonneville, M.; Roulet, N.; Tremblay, A.

2009-05-01

176

Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. (Quarterly technical progress report), July 1, 1990-September 30, 1990.  

National Technical Information Service (NTIS)

The objectives of this project are to augment the National Reservoir Database (TORIS database) and to increase our understanding of geologic heterogeneities that affect the recoveries of oil and gas from carbonate reservoirs in the State of Alabama and to...

E. A. Mancini

1990-01-01

177

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

178

Using guided waves to characterize gas reservoir continuity. Phase 1. Catalog of geological and petrophysical data from the Gypsy test site. Topical report, July 1993August 1994  

Microsoft Academic Search

The gas and oil industry is continuing to emphasize research and development efforts on advanced technology to improve reservoir description through the producing life and development history of heterogeneous hydrocarbon reservoirs. Continuity logging using guided waves is an alternative approach to analyzing interwell seismic data to confirm the continuity of heterogeneous hydrocarbon reservoir compartments; in particular, the continuity of sand

1994-01-01

179

Using guided waves to characterize gas reservoir continuity. Phase 1. Catalog of geological and petrophysical data from the Devine test site. Topical report, July 1993August 1994  

Microsoft Academic Search

The gas and oil industry is continuing to emphasize research and development efforts on advanced technology to improve reservoir description through the producing life and development history of heterogeneous hydrocarbon reservoirs. Continuity logging using guided waves is an alternative approach to analyzing interwell seismic data to confirm the continuity of heterogeneous hydrocarbon reservoir compartments; in particular, the continuity of sand

1994-01-01

180

Development of improved technologies and techniques for reducing base gas requirements in underground gas storage facilities: Simulation study of hanson field gas storage reservoir. Final report, May 1989-November 1989  

SciTech Connect

Base gas requirements in the U.S. amount to a few trillion cubic feet. The Gas Research Institute has proposed a gas storage operating plan whereby an inert gas or a low BTU gas could be injected to replace part of the hydrocarbon gas. A reservoir simulator has been developed, enhanced and tested to solve gas-water reservoir problems where the gas may be treated as a two-component miscible mixture. The previously developed reservoir simulator was further enhanced to include a local grid refinement option, which allows the engineer to study a portion of the field in more detail compared to the rest of the field. The simulator was tested for correctness and completeness. A simulation study was conducted for the Hanson Field Gas Storage Reservoir using two models with different layering. The reservoir history matching was duplicated and several prediction cases were run to study the effectiveness of the replacement of base gas with an inert gas. The results show that replacement of a portion of the hydrocarbon base gas with an inert gas can be an attractive alternative for the gas storage industry.

Modine, A.D.

1989-11-01

181

Electrochromically switched, gas-reservoir metal hydride devices with application to energy-efficient windows  

SciTech Connect

Proof-of-principle gas-reservoir MnNiMg electrochromic mirror devices have been investigated. In contrast to conventional electrochromic approaches, hydrogen is stored (at low concentration) in the gas volume between glass panes of the insulated glass units (IGUs). The elimination of a solid state ion storage layer simplifies the layer stack, enhances overall transmission, and reduces cost. The cyclic switching properties were demonstrated and system durability improved with the incorporation a thin Zr barrier layer between the MnNiMg layer and the Pd catalyst. Addition of 9 percent silver to the palladium catalyst further improved system durability. About 100 full cycles have been demonstrated before devices slow considerably. Degradation of device performance appears to be related to Pd catalyst mobility, rather than delamination or metal layer oxidation issues originally presumed likely to present significant challenges.

Anders, Andre; Slack, Jonathan L.; Richardson, Thomas J.

2008-05-05

182

The simulation of nature gas production from ocean gas hydrate reservoir by depressurization  

Microsoft Academic Search

The vast amount of hydrocarbon gas encaged in gas hydrates is regarded as a kind of future potential energy supply due to\\u000a its wide deposition and cleanness. How to exploit gas hydrate with safe, effective and economical methods is being pursued.\\u000a In this paper, a mathematical model is developed to simulate the hydrate dissociation by depressurization in hydrate-bearing\\u000a porous medium.

YuHu Bai; QingPing Li; XiangFang Li; Yan Du

2008-01-01

183

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

184

Sustaining Fracture Area and Conductivity of Gas shale Reservoirs for Enhancing Long-term Production and Recovery  

NASA Astrophysics Data System (ADS)

Natural gas from organic rich shale formations has become an increasingly important energy resource worldwide over the past decade. Extensive hydraulic fracture networks with massive contact surface areas are frequently required to achieve satisfactory economic production in these highly heterogeneous reservoirs, with permeability in the nano-Darcy range. Current operational experience in gas shale plays indicates that the loss of productive fracture area and loss of fracture conductivity, both immediate and over time, are the major factors leading to reduced flow rates, marginal production, and poor gas recovery. This theoretical and experimental project, funded by a RPSEA (Research Partnership to Secure Energy for America) program, is aimed at understanding the multiple causes of loss of fracture surface area and fracture conductivity. The main objectives of the project are: understand the multiple causes of loss of fracture area and fracture conductivity, and define solutions to mitigate the resulting loss of production. Define the types of fracture networks that are more prone to loosing fracture area and define critical parameters, for each reservoir type, (including proppant concentration, fluid interaction, relative shear displacement and others) to preserve fracture conductivity, and define an integrated methodology for evaluating reservoir properties that result in proneness to loss of fracture area and fracture conductivity, and define adequate solutions for the various reservoir types Current results include the evaluation of reservoir geology, mineralogy, reservoir properties, mechanical properties, including surface hardness, and petrologic analysis on cores representative of Barnett, Haynesville and Marcellus reservoir shales. A comparison of these properties provides an initial reference frame for identifying differences in behavior between the various reservoirs, and for anticipating the potential for embedment and loss of fracture conductivity. Actual measurements of fracture conductivity as a function of stress will be measured and presented in the future.

Suarez-Rivera, R.; Marino, S.; Ghassemi, A.

2010-12-01

185

Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. [Jurassic Smackover Formation  

SciTech Connect

The objective of this project is to augment the National Reservoir Database (TORIS database), to increase our understanding of geologic heterogeneities that affect the recoveries of oil and gas from carbonate reservoirs in the State of Alabama, and to identify resources that are producible at moderate cost. This objective will be achieved through detailed geological, geostatistical, and engineering characterization of typical Jurassic Smackover Formation hydrocarbon, and engineering characterization of typical Jurassic Smackover Formation hydrocarbon reservoirs in selected productive fields in the state of Alabama. The results of these studies will be used to develop and test mathematical models for prediction of the effects of reservoir heterogeneities in hydrocarbon production. Work to date has focused on completion of Subtasks 1, 2, and 3 of this project. Work on Subtask 4 began in this quarter, and substantial additional work has been accomplished on Subtask 2. Subtask 1 included the survey and tabulation of available reservoir engineering and geological data. Subtask 2 comprises the geologic and engineering characterization of smackover reservoir lithofacies. Subtask 3 includes the geologic modeling of reservoir heterogeneities. Subtask 4 includes the development of reservoir exploitation methodologies for strategic infill drilling. 1 fig.

Mancini, E.A.

1990-01-01

186

Geochemical analysis of atlantic rim water, carbon county, wyoming: New applications for characterizing coalbed natural gas reservoirs  

USGS Publications Warehouse

Coalbed natural gas (CBNG) production typically requires the extraction of large volumes of water from target formations, thereby influencing any associated reservoir systems. We describe isotopic tracers that provide immediate data on the presence or absence of biogenic natural gas and the identify methane-containing reservoirs are hydrologically confined. Isotopes of dissolved inorganic carbon and strontium, along with water quality data, were used to characterize the CBNG reservoirs and hydrogeologic systems of Wyoming's Atlantic Rim. Water was analyzed from a stream, springs, and CBNG wells. Strontium isotopic composition and major ion geochemistry identify two groups of surface water samples. Muddy Creek and Mesaverde Group spring samples are Ca-Mg-S04-type water with higher 87Sr/86Sr, reflecting relatively young groundwater recharged from precipitation in the Sierra Madre. Groundwaters emitted from the Lewis Shale springs are Na-HCO3-type waters with lower 87Sr/86Sr, reflecting sulfate reduction and more extensive water-rock interaction. To distinguish coalbed waters, methanogenically enriched ??13CDIC wasused from other natural waters. Enriched ??13CDIC, between -3.6 and +13.3???, identified spring water that likely originates from Mesaverde coalbed reservoirs. Strongly positive ??13CDIC, between +12.6 and +22.8???, identified those coalbed reservoirs that are confined, whereas lower ??13CDIC, between +0.0 and +9.9???, identified wells within unconfined reservoir systems. Copyright ?? 2011. The American Association of Petroleum Geologists. All rights reserved.

McLaughlin, J. F.; Frost, C. D.; Sharma, S.

2011-01-01

187

Geology and genesis of overpressured sandstone reservoirs in Venture gas field, offshore Nova Scotia, Canada  

SciTech Connect

Overpressured formations with pressure gradients up to 1.9 times normal hydrostatic occur over an area approximately 10,000 km/sup 2/ offshore Nova Scotia, Canada. In the Venture field, the abnormal pressures are confined below 4500 m and are associated with gas- and condensate-bearing Upper Jurassic-Lower Cretaceous sandstone reservoirs. Venture overpressures differ from Gulf Coast-type overpressures in that they occur within normally compacted shales containing numerous overpressured sandstone reservoir beds. Normal compaction is indicated indirectly by gradual increase in bulk density, sonic velocity, and shale resistivity with depth. Plots of temperature gradients, organic maturation gradients, and chemical composition of formation waters vs depth across the overpressured zone also indicate normal sediment compaction. Clay mineral studies show the overpressured shales are well indurated, with the transformation of smectite into mixed-layer clay minerals occurring 2500 m above the top of the overpressured zone. Furthermore, the overpressured sandstones exhibit textures indicative of normal compaction, with secondary porosity developed in both normally compacted and overpressured strata. The Venture represents hard-rock overpressures within normally compacted strata. As a result of a low geothermal gradient in the basin, the peak gas generation was reached late after most of the lithologies had lost their effective permeability due to progressing sediment diagenesis. Formation of diagenetic seals above the zone of peak gas generation in addition to continuing release of fluids as a result of shale diagenesis contribute to formation of overpressures, but organic matter maturation and hydrocarbon expulsion are the main driving forces behind the Venture overpressures.

Jansa, L.F.; Noguera, V.H.

1989-03-01

188

The effects of thermochemical sulfate reduction upon formation water salinity and oxygen isotopes in carbonate gas reservoirs  

NASA Astrophysics Data System (ADS)

Thermochemical sulfate reduction (TSR) is a well known process that can lead to sour (H 2S-rich) petroleum accumulations. Most studies of TSR have concentrated upon gas chemistry. In this study we have investigated palaeoformation water characteristics in a deep, anhydrite-bearing dolomite, sour-gas reservoir of Permian age in Abu Dhabi using fluid inclusion, stable isotope, petrographic, and gas chemical data. The data show that low salinity, isotopically-distinct water was generated within the reservoir by reaction between anhydrite and methane. The amount of water added to the reservoir from TSR, indicated by reduced fluid inclusion salinity and water ?18O values, varied systematically with the extent of anhydrite reaction with methane. Water salinity and isotope data show that the original formation water was diluted by between four and five times by water from TSR. Thus, we have shown that large volumes of very low salinity water were generated within the gas reservoirs during diagenesis following gas emplacement. The salinity of formation water in evaporite lithologies is, therefore, not necessarily high. Modelling, based upon a typical Khuff gas reservoir rock volume, suggests that initial formation water volumes can only be increased by about three times as a result of TSR. The extreme local dilution shown by the water salinity and ?18O data must, therefore, reflect transiently imperfect mixing between TSR water and original formation water. The creation of large volumes of water has important implications for the mechanism and rate of thermochemical sulphate reduction and the interpretation of gas volumes using petrophysical logging tools.

Worden, R. H.; Smalley, P. C.; Oxtoby, N. H.

1996-10-01

189

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

190

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

National Technical Information Service (NTIS)

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 ...

B. N. P. Paulsson

2002-01-01

191

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

192

Naturally fractured tight gas reservoir detection optimization. Annual report, August 1994--July 1995  

SciTech Connect

This report details the field work undertaken Blackhawk Geosciences and Lynn, Inc. during August 1994 to July 1995 at a gas field in the Wind River Basin in central Wyoming. The work described herein consisted of four parts: 9C VSP in a well at the site; additional processing of the previously recorded 3D P-wave survey on the site and Minivibrator testing; and planning and acquisition of a 3-D, 3-C seismic survey. The objectives of all four parts 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. The additional processing of the 3-D uses developmental techniques to determine areas of fractures in 3-D surveys. With the multicomponent studies, tests were conducted to establish the feasibility of surface recording of the anisotropic reservoir rocks. The 3-D, 3-C survey will provide both compressional and shear wave data sets over areas of known fracturing to verify the research.

NONE

1995-09-01

193

DEVELOPMENT OF MORE-EFFICIENT GAS FLOODING APPLICABLE TO SHALLOW RESERVOIRS  

SciTech Connect

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 enrichment needed in the presence of dispersion. Subtask 1.2 develops a fast, efficient method to predict the extent of enrichment needed for crude oils at a given pressure. Task 2 develops improved foam processes to increase sweep efficiency in gas flooding. Subtask 2.1 comprises mechanistic experimental studies of foams with N{sup 2} gas. Subtask 2.2 conducts experiments with CO{sup 2} foam. Subtask 2.3 develops and applies a simulator for foam processes in field application. Regarding Task 1, several results related to subtask 1.1 are given. In this period, most of our research centered on how to estimate the dispersivity at the field scale. Simulation studies (Solano et al. 2001) show that oil recovery for enriched gas drives depends on the amount of dispersion in reservoir media. But the true value of dispersion, expressed as dispersivity, at the field scale, is unknown. This research investigates three types of dispersion in permeable media to obtain realistic estimates of dispersive mixing at the field scale. The dispersivity from single-well tracer tests (SWTT), also known as echo dispersivity, is the dispersivity that is unaffected by fluid flow direction. Layering in permeable media tends to increase the observed dispersivity in well-to-well tracer tests, also known as transmission dispersivity, but leaves the echo dispersivity unaffected. A collection of SWTT data is analyzed to estimate echo dispersivity at the SWTT scale. The estimated echo dispersivities closely match a published trend with length scale in dispersivities obtained from groundwater tracer tests. This unexpected result--it was thought that transmission dispersivity should be greater than echo dispersivity--is analyzed with numerical simulation. A third type of dispersive mixing is local dispersivity, or the mixing observed at a point as tracer flows past it. Numerical simulation results show that the local dispersivity is always less than the transmission dispersivity and greater than the echo dispersivity limits. It is closer to one limit or the other depending on the amount and type of heterogeneity, the autocorrelation structure of the medium's permeability, and the lateral (vertical) permeability. The agreement between the SWTT echo dispersivities and the field trend suggests that the field data are measuring local dispersivities. All dispersivities appear to grow with length. Regarding Task 2, two results are described: (1) An experimental study of N{sup 2} foam finds the two steady-state foam-flow regimes at elevated temperature and with acid, adding evidence that the two regimes occur widely, if not universally, in foam in porous media. (2) A simulation finds that the optimal injection strategy for overcoming gravity override in homogeneous reservoirs is injection of large alternating slugs of surfactant and gas at fixed, maximum attainable injection rates. A simple model for the process explains why the this strategy works so well. Before conducting simulations of SAG displacements, however, it is important to analyze the given foam model using fractional-flow theory. Fractional-flow theory predicts that some foam processes will give foam collapse immediately behind the gas front. In simulations, numerical dispersion leads to a false impression of good sweep efficiency. In this case simply grid refinement may not warn of the inaccuracy of the simulation.

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

2003-01-28

194

Prediction of pressure drawdown in gas reservoirs using a semi-analytical solution of the non-linear gas flow equation  

SciTech Connect

The differential equation for flow of gases in a porous medium is nonlinear and cannot be solved by strictly analytical methods. Previous studies in the literature have obtained analytical solutions to this equation by linearlization (i.e., treating viscosity and compressibilty as constant). In this study, the solution for nonlinear gas flow equation is obtained using the semianalytical technique developed by Kale and Mattar which solves the nonlinear equation by the method of perturbation. Results obtained, for prediction of pressure drawdown in gas reservoirs, indicate that the solution of the linearlized form of the equation is valid for both low and high permeability reservoirs.

Mattar, L.; Adegbesan, L.O.

1980-01-01

195

Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. [Jurassic Smackover Formation  

SciTech Connect

This volume contains maps, well logging correlated to porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plot, detailed core log, paragenetic sequence and reservoir characterization sheet of the following fields in southwest Alabama: Appleton oil field; Barnett oil field; Barrytown oil field; Big Escambia Creek gas and condensate field; Blacksher oil field; Broken Leg Creed oil field; Bucatunna Creed oil field; Chappell Hill oil field; Chatom gas and condensate field; Choctaw Ridge oil field; Chunchula gas and condensate field; Cold Creek oil field; Copeland gas and condensate field; Crosbys Creed gas and condensate field; and East Barnett oil field. (AT)

Kopaska-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D.; Hall, D.R.

1992-06-01

196

Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. Appendix 1, Volume 1  

SciTech Connect

This volume contains maps, well logging correlated to porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plot, detailed core log, paragenetic sequence and reservoir characterization sheet of the following fields in southwest Alabama: Appleton oil field; Barnett oil field; Barrytown oil field; Big Escambia Creek gas and condensate field; Blacksher oil field; Broken Leg Creed oil field; Bucatunna Creed oil field; Chappell Hill oil field; Chatom gas and condensate field; Choctaw Ridge oil field; Chunchula gas and condensate field; Cold Creek oil field; Copeland gas and condensate field; Crosbys Creed gas and condensate field; and East Barnett oil field. (AT)

Kopaska-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D.; Hall, D.R.

1992-06-01

197

HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS  

SciTech Connect

This report outlines progress in the third quarter of the second year of the DOE project ''High Resolution Prediction of Gas Injection Process Performance for Heterogeneous Reservoirs''. High order finite difference schemes for one-dimensional, two-phase, multicomponent displacements are investigated. Numerical tests are run using a three component fluid description for a case when the interaction between phase behavior and flow is strong. Some currently used total variation diminishing (TVD) methods produce unstable results. A third order essentially non-oscillatory (ENO) method captures the effects of phase behavior for this test case. Possible modifications to ensure stability are discussed along with plans to incorporate higher order schemes into the 3DSL streamline simulator.

Franklin M. Orr, Jr.

2002-06-30

198

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

199

Phase field theory modeling of methane fluxes from exposed natural gas hydrate reservoirs  

NASA Astrophysics Data System (ADS)

Fluxes of methane from offshore natural gas hydrate into the oceans vary in intensity from massive bubble columns of natural gas all the way down to fluxes which are not visible within human eye resolution. The driving force for these fluxes is that methane hydrate is not stable towards nether minerals nor towards under saturated water. As such fluxes of methane from deep below hydrates zones may diffuse through fluid channels separating the hydrates from minerals surfaces and reach the seafloor. Additional hydrate fluxes from hydrates dissociating towards under saturated water will have different characteristics depending on the level of dynamics in the actual reservoirs. If the kinetic rate of hydrate dissociation is smaller than the mass transport rate of distributing released gas into the surrounding water through diffusion then hydrodynamics of bubble formation is not an issue and Phase Field Theory (PFT) simulations without hydrodynamics is expected to be adequate [1, 2]. In this work we present simulated results corresponding to thermodynamic conditions from a hydrate field offshore Norway and discuss these results with in situ observations. Observed fluxes are lower than what can be expected from hydrate dissociating and molecularly diffusing into the surrounding water. The PFT model was modified to account for the hydrodynamics. The modified model gave higher fluxes, but still lower than the observed in situ fluxes.

Kivelä, Pilvi-Helinä; Baig, Khuram; Qasim, Muhammad; Kvamme, Bjørn

2012-12-01

200

DOE THREE-DIMENSIONAL STRUCTURE AND PHYSICAL PROPERTIES OF A METHANE HYDRATE DEPOSIT AND GAS RESERVOIR, BLAKE RIDGE  

SciTech Connect

This report contains a summary of work conducted and results produced under the auspices of award DE-FC26-00NT40921, ''DOE Three-Dimensional Structure and Physical Properties of a Methane Hydrate Deposit and Gas Reservoir, Blake Ridge.'' This award supported acquisition, processing, and interpretation of two- and three-dimensional seismic reflection data over a large methane hydrate reservoir on the Blake Ridge, offshore South Carolina. The work supported by this project has led to important new conclusions regarding (1) the use of seismic reflection data to directly detect methane hydrate, (2) the migration and possible escape of free gas through the hydrate stability zone, and (3) the mechanical controls on the maximum thickness of the free gas zone and gas escape.

W. Steven Holbrook

2004-11-11

201

Main Pass 299, offshore, Louisiana: Producing oil, gas, and sulfur from the same reservoir  

SciTech Connect

In 1989, a world class sulfur deposit and a new oil pool with a small gas cap were discovered together in the limestone caprock of a shallow piercement salt dome at Main Pass 299, Offshore, Louisiana. Twenty exploration wells were drilled to delineate the resource. The salt dome is roughly circular and relatively flat-topped with a diameter of 8,000 ft at the shallowest occurrence of salt at 1,775 ft subsea. Vugular limestone caprock occurs at 1,250 ft subsea and is up to 400 ft thick in the southeast quadrant of the dome. Porosity in the limestone averages 27% with permeability as high as 18 d. Below the limestone is dense anhydrite, up to 125 thick, and then diapiric salt. Native sulfur occurs up to 200 ft thick in the lower part of the limestone. Oil and gas occur in the upper part of the limestone with the G/O contact at 1,350 ft subsea and the O/W contact at 1,532 ft subsea. Proven recoverable reserves are currently estimated at 67 million long tons sulfur, 38 MMBO, and 8.5 BCFG. Sulfur, oil, and gas will be produced concurrently using a synergistic blending of Frasch sulfur mining techniques and oil and gas production technology. Using the Frasch method, seawater heated under pressure to 325{degree}F is injected into the limestone caprock where it melts in situ the elemental sulfur at 246{degree}F, which is produced, stored, and transported as a liquid. Hot water injection is anticipated to enhance oil production by maintaining reservoir pressure and lowering the viscosity of the 22 degree gravity oil. Four platform structures and from 22 to 44 wells, some with horizontal completions, are planned to produced the oil and gas at an initial rate of 50,000 BOPD and 13 MMCFPD.

Christensen, R.J. (Freeport-McMoRan Oil and Gas Co., New Orleans, LA (United States)); Green, L.B. (Freeport Sulfur Co., New Orleans, LA (United States))

1991-03-01

202

The Impact of Azimuthal Anisotropy on Seismic AVO and Petrophysical Response in a Fractured Wabamun Gas Reservoir  

Microsoft Academic Search

The evaluation of many fractured carbonate reservoirs would benefit greatly from a reliable method of determining fracture density and orientation from seismic data. Although the most technically exhaustive approach would likely involve multi-component analysis, the potential of azimuthal information contained within conventional AVO must not be overlooked. The focus of this study is a prolific gas well drilled on a

Brian Rex; Bill Goodway; Cathy Martin; Gordon Uswak

203

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

204

Effects of salinity on hydrate stability and implications for storage of CO 2 in natural gas hydrate reservoirs  

Microsoft Academic Search

The win-win situation of CO2 storage in natural gas hydrate reservoirs is attractive for several reasons in addition to the associated natural gas production. Since both pure CO2 and pure methane form structure I hydrate there is no expected volume change by replacing the in situ methane with CO2, and there is not net production of associated water which requires

Jarle Husebø; Geir Ersland; Arne Graue; Bjørn Kvamme

2009-01-01

205

PRELIMINARY CHARACTERIZATION OF CO2 SEPARATION AND STORAGE PROPERTIES OF COAL GAS RESERVOIRS  

SciTech Connect

An attractive alternative of sequestering CO{sub 2} is to inject it into coalbed methane reservoirs, particularly since it has been shown to enhance the production of methane during near depletion stages. The basis for enhanced coalbed methane recovery and simultaneous sequestration of carbon dioxide in deep coals is the preferential sorption property of coal, with its affinity for carbon dioxide being significantly higher than that for methane. Yet, the sorption behavior of coal under competitive sorptive environment is not fully understood. Hence, the original objective of this research study was to carry out a laboratory study to investigate the effect of studying the sorption behavior of coal in the presence of multiple gases, primarily methane, CO{sub 2} and nitrogen, in order to understand the mechanisms involved in displacement of methane and its movement in coal. This had to be modified slightly since the PVT property of gas mixtures is still not well understood, and any laboratory work in the area of sorption of gases requires a definite equation of state to calculate the volumes of different gases in free and adsorbed forms. This research study started with establishing gas adsorption isotherms for pure methane and CO{sub 2}. The standard gas expansion technique based on volumetric analysis was used for the experimental work with the additional feature of incorporating a gas chromatograph for analysis of gas composition. The results were analyzed first using the Langmuir theory. As expected, the Langmuir analysis indicated that CO{sub 2} is more than three times as sorptive as methane. This was followed by carrying out a partial desorption isotherm for methane, and then injecting CO{sub 2} to displace methane. The results indicated that CO{sub 2} injection at low pressure displaced all of the sorbed methane, even when the total pressure continued to be high. However, the displacement appeared to be occurring due to a combination of the preferential sorption property of coal and reduction in the partial pressure of methane. As a final step, the Extended Langmuir (EL) model was used to model the coal-methane-CO{sub 2} binary adsorption system. The EL model was found to be very accurate in predicting adsorption of CO{sub 2}, but not so in predicting desorption of methane. The selectivity of CO{sub 2} over methane was calculated to be 4.3:1. This is, of course, not in very good agreement with the measured values which showed the ratio to be 3.5:1. However, the measured results are in good agreement with the field observation at one of the CO{sub 2} injection sites. Based on the findings of this study, it was concluded that low pressure injection of CO{sub 2} can be fairly effective in displacing methane in coalbed reservoirs although this might be difficult to achieve in field conditions. Furthermore, the displacement of methane appears to be not only due to the preferential sorption of methane, but reduction in partial pressure as well. Hence, using a highly adsorbing gas, such as CO{sub 2}, has the advantages of inert gas stripping and non-mixing since the injected gas does not mix with the recovered methane.

John Kemeny; Satya Harpalani

2004-03-01

206

DEVELOPMENT OF MORE-EFFICIENT GAS FLOODING APPLICABLE TO SHALLOW RESERVOIRS  

SciTech Connect

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 enrichment needed in the presence of dispersion. Subtask 1.2 develops a fast, efficient method to predict the extent of enrichment needed for crude oils at a given pressure. Task 2 develops improved foam processes to increase sweep efficiency in gas flooding. Subtask 2.1 comprises mechanistic experimental studies of foams with N{sup 2} gas. Subtask 2.2 conducts experiments with CO{sup 2} foam. Subtask 2.3 develops and applies a simulator for foam processes in field application. Regarding Task 1, several key results are described in this report relating to subtask 1.1. In particular, we show how for slimtube experiments, oil recoveries do not increase significantly with enrichments greater than the MME. For field projects, however, the optimum enrichment required to maximize recovery on a pattern scale may be different from the MME. The optimum enrichment is likely the result of greater mixing in reservoirs than in slimtubes. In addition, 2-D effects such as channeling, gravity tonguing, and crossflow can impact the enrichment selected. We also show the interplay between various mixing mechanisms, enrichment level, and numerical dispersion. The mixing mechanisms examined are mechanical dispersion, gravity crossflow, and viscous crossflow. UTCOMP is used to evaluate the effect of these mechanisms on recovery for different grid refinements, reservoir heterogeneities, injection boundary conditions, relative permeabilities, and numerical weighting methods including higher-order methods. For all simulations, the reservoir fluid used is a twelve-component oil displaced by gases enriched above the MME. The results for subtask 1.1 show that for 1-D enriched-gas floods, the recovery difference between displacements above the MME and those at or near the MME increases significantly with dispersion. The trend, however, is not monotonic and shows a maximum at a dispersivity (mixing level) of about 4 ft. The trend is independent of relative permeabilities and gas trapping for dispersivities less than about 4 ft. For 2-D enriched gas floods with slug injection, the difference in recovery generally increases as dispersion and crossflow increase. The magnitude of the recovery differences is less than observed for the 1-D displacements. Recovery differences for 2-D models are highly dependent on relative permeabilities and gas trapping. For water alternating gas (WAG) injection, the differences in recovery increase slightly as dispersion decreases. That is, the recovery difference is significantly greater with WAG at low levels of dispersion than with slug injection. For the cases examined, the magnitude of recovery difference varies from about 1 to 8 percent of the original oil-in-place (OOIP). Regarding Task 2, three results are described in this report: (1) New experiments with N{sup 2} foam examined the mobility of liquid injected following foam in alternating-slug (SAG) foam processes. These experiments were conducted in parallel with a simulation study of foam for acid diversion in well stimulation. The new experiments qualitatively confirm several of the trends predicted by simulation. (2) A literature study finds that the two steady-state foam-flow regimes seen with a wide variety of N{sup 2} foams also appears in many studies of CO{sup 2} foams, if the data are replotted in a format that makes these regimes clear. A new experimental study of dense CO{sup 2} foam here failed to reproduce these trends, however; the reason remains under investigation. (3) A number of published foam models were examined in terms of the two foam-flow regimes and using fractional-flow theory. At least two of the foam models predict the two foam-flow regimes. Fractional-flow t

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

2003-01-28

207

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

208

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

209

Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. [Jurassic Smackover Formation  

Microsoft Academic Search

This volume contains maps, well logging correlated to porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plot, detailed core log, paragenetic sequence and reservoir characterization sheet of the following fields in southwest Alabama: Appleton oil field; Barnett oil field; Barrytown oil field; Big Escambia Creek gas and condensate field; Blacksher oil field; Broken

D. C. Kopaska-Merkel; H. E. Jr. Moore; S. D. Mann; D. R. Hall

1992-01-01

210

Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. Appendix 1, Volume 1  

Microsoft Academic Search

This volume contains maps, well logging correlated to porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plot, detailed core log, paragenetic sequence and reservoir characterization sheet of the following fields in southwest Alabama: Appleton oil field; Barnett oil field; Barrytown oil field; Big Escambia Creek gas and condensate field; Blacksher oil field; Broken

D. C. Kopaska-Merkel; H. E. Jr. Moore; S. D. Mann; D. R. Hall

1992-01-01

211

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

212

Probing the cold molecular gas reservoir in a proto-cluster at z=4.11  

NASA Astrophysics Data System (ADS)

The existence of vigorous dusty, starbursts in distant, massive galaxies was first demonstrated by submillimeter photometry of high-z radio galaxies (HzRGs). In a few cases CO line emission was found to be associated with the dust, giving evidence of huge reservoirs of dust-enriched molecular gas capable of sustaining the prodigiouos star formation rates. The nature of this extended emission - cold accretion flows or merging of unresolved clumps? - has important implications for our understanding of the assembly of massive galaxies. Here we propose to measure the CO(2-1) emission towards TNJ1338-1942, a luminous radio galaxy residing at the centre of a massive proto-cluster at z=4.11. Our observations will measure the total molecular gas mass and dynamics of this massive galaxy during its formative stages. In addition, the broad bandwidth of CABB offers the exciting prospect of using CO to spectroscopically confirm about a handful of IR-luminous 1.2mm-selected galaxies detected in the near vicinity of TNJ1338-1942.

Greve, Thomas; De Breuck, Carlos; König, Sabine; Ivison, Rob; Papadopoulos, Padelis; Kovacs, Attila

2010-10-01

213

Sedimentology and reservoir characteristics of tight gas sandstones, Frontier formation, southwestern Wyoming  

SciTech Connect

The lower Frontier Formation, Moxa arch area, southwestern Wyoming, is one of the most prolific gas-producing formations in the Rocky Mountain region. Lowr Frontier sediments were deposited as strandplains and coalescing wave-dominated deltas that prograding into the western margin of the Cretaceous interior seaway during the Cenomanian. In this study, sedimentologic, petrologic, and stratigraphic analyses were conducted on cores and logs of Frontier wells from the Whiskey Buttes and Moxa fields. Twelve sedimentary facies have been identified. The most common sequence consists of burrowed to cross-bedded near shore marine (delta-front and inner-shelf) sandstones disconformably overlain by crossbedded (active) to deformed (abandoned) distributary-channel sandstones and conglomerates. The sequence is capped by delta-plain mudstones and silty sandstones. Tight-gas sandstone reservoir facies are nonhomogenous and include crevasse splay, abandoned and active distributary channel, shoreface, foreshore, and inner shelf sandstones. Distributary-channel facies represent 80% of perforated intervals in wells in the southern part of the Moxa area, but only 50% to the north. Channel sandstone bodies are occasionally stacked, occur on the same stratigraphic horizon, and are laterally discontinuous with numerous permeability barriers. Percentage of perforated intervals in upper shoreface and foreshore facies increases from 20% in the south to 50% in the north.

Moslow, T.F.; Tillman, R.W.

1984-04-01

214

Sedimentology and reservoir characteristics of tight gas sandstones, Frontier formation, southwestern Wyoming  

SciTech Connect

The lower Frontier Formation, Moxa arch area, southwestern Wyoming, is one of the most prolific gas-producing formations in the Rocky Mountain region. Lower Frontier sediments were deposited as strandplains and coalescing wave-dominated deltas that prograding into the western margin of the Cretaceous interior seaway during the Cenomanian. In this study, sedimentologic, petrologic, and stratigraphic analyses were conducted on cores and logs of Frontier wells from the Whiskey Buttes and Moxa fields. Twelve sedimentary facies have been identified. The most common sequence consists of burrowed to cross-bedded near shore marine (delta-front and inner-shelf) sandstones disconformably overlain by cross-bedded (active) to deformed (abandoned) distributary-channel sandstones and conglomerates. The sequence is capped by delta-plain mudstones and silty sandstones. Tight-gas sandstone reservoir facies are non-homogenous and include crevasse splay, abandoned and active distributary channel, shoreface, foreshore, and inner shelf sandstones. Distributary-channel facies represent 80% of perforated intervals in wells in the southern part of the Moxa area, but only 50% to the north. Channel sandstone bodies are occasionally stacked, occur on the same stratigraphic horizon, and are laterally discontinuous with numerous permeability barriers. Percentage of perforated intervals in upper shoreface and foreshore facies increases from 20% in the south to 50% in the north.

Moslow, T.F.; Tillman, R.W.

1984-04-01

215

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

216

Long Period, Long Duration Seismic Events during Hydraulic Fracture Stimulation of a Shale Gas Reservoir  

NASA Astrophysics Data System (ADS)

We report a series of long period and long duration (LPLD) seismic events observed during hydraulic fracturing in a gas shale reservoir located in West Texas. These unusual events, 10-100 seconds in duration, are observed most clearly in the frequency band of 10-80 Hz and are similar in appearance to tectonic tremor sequences which have been observed at depth in several subduction zones and continental strike slip faults. These complex but coherent wave trains have finite move-outs obtained from waveform cross-correlation. The move-out direction of the events confirms that they originate in the reservoir from the area where the fracturing is going on. Clear P- and S-wave arrivals cannot be resolved within the LPLD episodes, but in some cases, small micro-earthquakes occur in the sequences. Whether these micro-earthquakes are causal or coincidental is being studied. It has also been observed that in three contiguous frac-stages, all LPLD events appear to come from two distinct places along one of two hypothetical fracture planes. Interestingly, the stages which have the largest number of LPLD events also have the highest observed pumping pressures during fracturing, the highest density of natural fractures and the greatest number of microearthquakes. One possible explanation of these LPLD events is that the high pore fluid pressure during hydraulic fracturing stimulates slow slip on pre-existing fault planes that are poorly-oriented for slip in the ambient stress field. In the absence of elevated pressure, slip would not be expected on these planes. Slip on these fault planes appears to be occurring because the fluid pressure is close to the magnitude of the least principal stress. We observe a few events between pumping cycles perhaps indicating that once triggered, these planes continue to slip due to the high transient pressure within the fault planes after pumping has stopped.

Das, I.; Zoback, M. D.

2011-12-01

217

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

218

Coordinated reservoir development - an alternative to the rule of capture for the ownership and development of oil and gas. Part II  

SciTech Connect

Coordinated reservoir development (CRD) attempts to achieve two major goals: provide for rational development of the oil and gas reservoir and provide a property system which recognizes and protects each landowner's proportionate interest to oil and gas while in the reservoir. Part II examines CRD's theoretical basis to determine how it corresponds to existing property and conservation concepts; its technical basis to identify advances in reservoir engineering and the ability of courts to determine and marshal rights in the oil and gas reservoir; and its operational basis for coordinated development. Several approaches are offered to alleviate ownership and development problems associated with the rule of capture. Potential problems and transaction costs created by CRD are also discussed. 491 references.

Pierce, D.E.

1983-01-01

219

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

220

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

221

Production data as an indicator of gas reservoir heterogenesity in the Vicksburg S sandstones (Oligocene), McAllen Ranch field, Hidalgo County, Texas  

Microsoft Academic Search

To assess reservoir heterogeneity in low-permeability Vicksburg S sandstone reservoirs in McAllen Ranch gas field, production and pressure histories of 49 wells were analyzed; predominant well spacing is 80 acres. These histories were compared both fieldwide and in local areas defined by faults or facies. Production is through casing perforations, which commonly extend over 600 ft gross intervals within vertically

E. G. Wermund; R. P. Langford

1990-01-01

222

Accumulation and generation of electric power on air accumulating power stations with two-section air reservoirs, compressors and gas-expansion generating units  

Microsoft Academic Search

The paper considers the perspectives of construction of air accumulating power stations (AAPS) containing in their structure the isolated from the atmosphere two-section air reservoirs, compressors and gas-expansion generating units. The influence of the air pressure levels in the air reservoir sections on the electric energy accumulation rate, coming from the buses of the electrical power system to the buses

B. I. Mokin; O. B. Mokin; M. M. Chepurnyy

2008-01-01

223

Novel simulation techniques used in a gas reservoir with a thin oil zone; Troll field  

SciTech Connect

Choice of production strategy in modern reservoir management relies heavily on numerical simulation. Large fields may require prohibitively large computer times. This paper reports on new techniques developed to save computer and engineering time: local grid refinement with small timesteps and flux boundary conditions for simulating regions of special interest. The combined use of these techniques allowed flexible, non-time-consuming, user-friendly reservoir simulation of a variety of reservoir management scenarios for Troll field.

Henriquez, A.; Apeland, O.J.; Lie, O. (Statoil (Norway)); Cheshire, I. (Intera Petroleum Production Services (United Kingdom))

1992-11-01

224

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

225

Naturally fractured tight gas reservoir detection optimization. Annual report, September 1993--September 1994  

SciTech Connect

This report is an annual summarization of an ongoing research in the field of modeling and detecting naturally fractured gas reservoirs. The current research is in the Piceance basin of Western Colorado. The aim is to use existing information to determine the most optimal zone or area of fracturing using a unique reaction-transport-mechanical (RTM) numerical basin model. The RTM model will then subsequently help map subsurface lateral and vertical fracture geometries. The base collection techniques include in-situ fracture data, remote sensing, aeromagnetics, 2-D seismic, and regional geologic interpretations. Once identified, high resolution airborne and spaceborne imagery will be used to verify the RTM model by comparing surficial fractures. If this imagery agrees with the model data, then a further investigation using a three-dimensional seismic survey component will be added. This report presents an overview of the Piceance Creek basin and then reviews work in the Parachute and Rulison fields and the results of the RTM models in these fields.

NONE

1994-10-01

226

Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. Appendix 1, Volume 3  

SciTech Connect

This volume contains maps, well logging, structural cross section, graph of production history, porosity vs. natural log permeability plots, detailed core log, paragenetic sequence, and reservoir characterization sheet for the following fields in southwest Alabama: North Smiths Church oil field; North Wallers Creek oil field; Northeast Barnett oil field; Northwest Range oil field; Pace Creek oil field; Palmers Crossroads oil field; Perdido oil field; Puss Cuss Creek oil field; Red Creek gas condensate field; Robinson Creek oil field; Silas oil field; Sizemore Creek gas condensate field; Smiths Church gas condensate field; South Burnt Corn Creek oil field; South Cold Creek oil field; South Vocation oil field; South Wild Fork Creek gas condensate field; South Womack Hill oil field; Southeast Chatom gas condensate field; Southwest Barrytown oil field; and Souwilpa Creek gas condensate field.

Kopaska-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D.; Hall, D.R.

1992-06-01

227

Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. [Jurassic Smackover Formation  

SciTech Connect

This volume contains maps, well logging, structural cross section, graph of production history, porosity vs. natural log permeability plots, detailed core log, paragenetic sequence, and reservoir characterization sheet for the following fields in southwest Alabama: North Smiths Church oil field; North Wallers Creek oil field; Northeast Barnett oil field; Northwest Range oil field; Pace Creek oil field; Palmers Crossroads oil field; Perdido oil field; Puss Cuss Creek oil field; Red Creek gas condensate field; Robinson Creek oil field; Silas oil field; Sizemore Creek gas condensate field; Smiths Church gas condensate field; South Burnt Corn Creek oil field; South Cold Creek oil field; South Vocation oil field; South Wild Fork Creek gas condensate field; South Womack Hill oil field; Southeast Chatom gas condensate field; Southwest Barrytown oil field; and Souwilpa Creek gas condensate field.

Kopaska-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D.; Hall, D.R.

1992-06-01

228

Controls on early retention and late enhancement of microporosity in reefal gas reservoirs, offshore north Sumatra basin  

Microsoft Academic Search

Chalky lime-matrix texture is pervasive in 300 m of coralgal and skeletal carbonates in the NSB-A (North Sumatra basin-A) gas field (lower-middle Miocene), offshore northern Sumatra. Much of the reservoir quality can be attributed to matrix with abundant intercrystalline, vuggy, and channel-form micropores. Matrix is composed of calcite microrhombs which are interpreted to have developed during stabilization of the precursor

Stephen O. Moshier

1989-01-01

229

Division and evaluation of oil-gas prolific zones for litho-stratigraphic reservoirs in the Nanpu Sag  

Microsoft Academic Search

The Nanpu Sag is a typical lacustrine downfaulted hydrocarbon-rich depression. Some litho-stratigraphic reservoirs have been discovered in recent years. Based on “Sag-wide Oil-Bearing Theory” and petroleum system, the concept of “play” is used as a unit for the division and evaluation of oil-gas prolific zones in this paper. The overlaying technique of “four maps”, which are the fault structure map,

An-na XU; Yue-xia DONG; Cai-neng ZOU; Ze-cheng WANG; Hong-ju ZHENG; Xu-dong WANG; Ying CUI

2008-01-01

230

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

231

Net Greenhouse Gas Emissions at the Eastmain 1 Reservoir, Quebec, Canada  

Microsoft Academic Search

Canada has much potential to increase its already large use of hydroelectricity for energy production. However, hydroelectricity production in many cases requires the creation of reservoirs that inundate terrestrial ecosystems. While it has been reasonably well established that reservoirs emit GHGs, it has not been established what the net difference between the landscape scale exchange of GHGs would be before

I. B. Strachan; A. Tremblay; J. Bastien; M. Bonneville; P. Del Georgio; M. Demarty; M. Garneau; J. Helie; L. Pelletier; Y. Prairie; N. T. Roulet; C. R. Teodoru

2010-01-01

232

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

SciTech Connect

The ultimate objective 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. Results are discussed.

Sharma, G.D.

1992-10-01

233

Characterization of oil and gas reservoir heterogeneity. Technical progress report, July 1, 1991--September 30, 1991  

SciTech Connect

The ultimate objective 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.

Sharma, G.D.

1991-12-31

234

Characterization of oil and gas reservoir heterogeneity. Technical progress report, January 1, 1992--March 31, 1992  

SciTech Connect

The ultimate objective 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.

Sharma, G.D.

1992-08-01

235

Characterization of oil and gas reservoir heterogeneity. Technical progress report, October 1, 1991--December 31, 1991  

SciTech Connect

The ultimate objective 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.

Sharma, G.D.

1991-12-31

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  

NASA Astrophysics Data System (ADS)

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 ? |vLSR| ? 170 kilometers per second (where vLSR 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 |vLSR| ? 170 kilometers per second are at larger distances. These may be the next wave of infalling material.

Lehner, Nicolas; Howk, J. Christopher

2011-11-01

238

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

239

Net Greenhouse Gas Emissions at the Eastmain 1 Reservoir, Quebec, Canada  

NASA Astrophysics Data System (ADS)

Canada has much potential to increase its already large use of hydroelectricity for energy production. However, hydroelectricity production in many cases requires the creation of reservoirs that inundate terrestrial ecosystems. While it has been reasonably well established that reservoirs emit GHGs, it has not been established what the net difference between the landscape scale exchange of GHGs would be before and after reservoir creation. Further, there is no indication of how that net difference may change over time from when the reservoir was first created to when it reaches a steady-state condition. A team of University and private sector researchers in partnership with Hydro-Québec has been studying net GHG emissions from the Eastmain 1 reservoir located in the boreal forest region of Québec, Canada. Net emissions are defined as those emitted following the creation of a reservoir minus those that would have been emitted or absorbed by the natural systems over a 100-year period in the absence of the reservoir. Sedimentation rates, emissions at the surface of the reservoir and natural water bodies, the degassing emissions downstream of the power house as well as the emissions/absorption of the natural ecosystems (forest, peatlands, lakes, streams and rivers) before and after the impoundment were measured using different techniques (Eddy covariance, floating chambers, automated systems, etc.). This project provides the first measurements of CO2 and CH4 between a new boreal reservoir and the atmosphere as the reservoir is being created, the development of the methodology to obtain these, and the first attempt at approaching the GHGs emissions from northern hydroelectric reservoirs as a land cover change issue. We will therefore provide: an estimate of the change in GHG source the atmosphere would see; an estimate of the net emissions that can be used for intercomparison of GHG contributions with other modes of power production; and a basis on which to develop biogeochemical sound, verifiable, and transparent estimates for GHG accounting. The results of the mass balance for this boreal reservoir from 2005 to 2009 as well as an extrapolation over 100 years will be presented.

Strachan, I. B.; Tremblay, A.; Bastien, J.; Bonneville, M.; Del Georgio, P.; Demarty, M.; Garneau, M.; Helie, J.; Pelletier, L.; Prairie, Y.; Roulet, N. T.; Teodoru, C. R.

2010-12-01

240

Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. Appendix 1, Volume 2  

SciTech Connect

This volume contains maps, well logging correlated to porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plots, detailed core log, paragenetic sequence, and reservoir characterization sheet for the following fields in southwest Alabama: East Huxford oil field; Fanny Church oil field; Gin Creek oil field; Gulf Crest oil field; Hanberry Church oil field; Hatter`s Pond oil field; Healing Springs gas condensate field; Huxford oil field; Little Escambia Creek oil field; Little River oil field; Little Rock gas condensate field; Lovetts Creek oil field; Melvin oil field; Mill Creek oil field; Mineola oil field; Movico oil field; and North Choctaw Ridge oil field.

Kopaska-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D.; Hall, D.R.

1992-06-01

241

Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. [Jurassic Smackover Formation  

SciTech Connect

This volume contains maps, well logging correlated to porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plots, detailed core log, paragenetic sequence, and reservoir characterization sheet for the following fields in southwest Alabama: East Huxford oil field; Fanny Church oil field; Gin Creek oil field; Gulf Crest oil field; Hanberry Church oil field; Hatter's Pond oil field; Healing Springs gas condensate field; Huxford oil field; Little Escambia Creek oil field; Little River oil field; Little Rock gas condensate field; Lovetts Creek oil field; Melvin oil field; Mill Creek oil field; Mineola oil field; Movico oil field; and North Choctaw Ridge oil field.

Kopaska-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D.; Hall, D.R.

1992-06-01

242

Reservoir Simulation-Based Modeling for Characterizing Longwall Methane Emissions and Gob Gas Venthole Production.  

National Technical Information Service (NTIS)

Longwall mining alters the fluid-flow-related reservoir properties of the rocks overlying and underlying an extracted panel due to fracturing and relaxation of the strata. These mining-related disturbances create new pressure depletion zones and new flow ...

C. O. Karacan G. S. Esterhuizen S. J. Schatzel W. P. Diamond

2008-01-01

243

Strategies for Gas Production from Hydrate Accumulations Under Various Geological and Reservoir Conditions.  

National Technical Information Service (NTIS)

In this paper we classify hydrate deposits in three classes according to their geologic and reservoir conditions, and discuss the corresponding production strategies. Simple depressurization appears promising in Class 1 hydrates, but its appeal decreases ...

G. J. Moridis T. S. Collett

2003-01-01

244

Integrated seismic study of naturally fractured tight gas reservoirs. Technical progress report, January 1, 1994--March 31, 1994  

SciTech Connect

The study area is located at the southern end of the Powder River Basin in Converse County in east-central Wyoming. It is a low permeability fractured site, with both gas and oil present. Reservoirs are highly compartmentalized due to the low permeabilities, and fractures provide the only practical drainage paths for production. The two formations of interest are: The Niobrara, a fractured shale and limey shale to chalk, which is a reservoir rock, but also its own source rock; and the Frontier, a tight sandstone lying directly below the Niobrara, brought into contact with it by an unconformity. This was the tenth quarter of the contract. During this quarter the investigators (1) continued processing the seismic data, and (2) continued modeling some of the P-wave amplitude anomalies that we see in the data.

Mavko, G.; Nur, A.

1994-04-29

245

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

246

Preliminary Characterization of CO2 Separation and Storage Properties of Coal Gas Reservoirs.  

National Technical Information Service (NTIS)

This research study started with establishing gas adsorption isotherms for pure methane and CO2. The standard gas expansion technique based on volumetric analysis was used for the experimental work with the additional feature of incorporating a gas chroma...

J. Kemeny S. Harpalani

2004-01-01

247

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

248

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

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 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

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. 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

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

2004-05-01

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 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

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 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

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 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

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

2004-06-30

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. 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

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 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

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 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

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

2003-12-01

261

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

SciTech Connect

There are four primary goals of contract DE-FG26-99FT40703: (1) We seek to better understand how and why a specific iron-related inorganic precipitant, siderite, occurs at the reservoir/wellbore interface in gas storage wells. (2) We plan on testing potential prevention and remediation strategies related to this damage mechanism in the laboratory. (3) We expect to demonstrate in the field, cost-effective prevention and remediation strategies that laboratory testing deems viable. (4) We will investigate new technology for the gas storage industry that will provide operators with a cost effective method to reduce non-darcy turbulent flow effects on flow rate. For the above damage mechanism, our research efforts will demonstrate the diagnostic technique for determining the damage mechanisms associated with lost deliverability as well as demonstrate and evaluate the remedial techniques in the laboratory setting and in actual gas storage reservoirs. We plan on accomplishing the above goals by performing extensive lab analyses of rotary sidewall cores taken from at least two wells, testing potential remediation strategies in the lab, and demonstrating in the field the applicability of the proposed remediation treatments. The benefits from this work will be quantified from this study and extrapolated to the entire storage industry. The technology and project results will be transferred to the industry through DOE dissemination and through the industry service companies that work on gas storage wells. Achieving these goals will enable the underground gas storage industry to more cost-effectively mitigate declining deliverability in their storage fields.

J.H. Frantz; K.G. Brown

2003-02-01

262

Gulf of Mexico Oil and Gas Atlas Series: Chronostratigraphically bound reservoir plays in Texas and federal offshore waters  

SciTech Connect

The search for additional hydrocarbons in the Gulf of Mexico is directing exploration toward both deep-water frontier trends and historically productive areas on the shelf. The University of Texas at Austin, Bureau of Economic Geology, in cooperation with the Minerals Management Service, the Gas Research Institute, and the U.S. Department of Energy, is responding to this need through a coordinated research effort to develop an oil and gas atlas series for the offshore northern Gulf of Mexico. The atlas series will group regional trends of oil and gas reservoirs into subregional plays and will display graphical location and reservoir data on a computerized information system. Play methodology includes constructing composite type logs with producing zones for all fields, identifying progradational, aggradational, and retrogradational depositional styles, and displaying geologic data for type fields. Deep-water sand-rich depositional systems are identified separately on the basis of faunal ecozones, chronostratigraphic facies position, and log patterns. To date, 4 Oligocene, 19 Lower Miocene, and 5 Upper Miocene plays have been identified in Texas state offshore waters. Texas state offshore plays are gas prone and are preferentially trapped in rollover anticlines. Lower Miocene plays include deep-water sandstones of Lenticulina hanseni and jeffersonensis; progradational sandstones of Marginulina, Discorbis b, Siphonia davisi, and Lenticulina; transgressive sandstones associated with a barrier-bar system in the Matagorda area; and transgressive sandstones below Amphistegina B shale. Particularly productive gas-prone plays are progradational Siphonia davisi, shelf-margin deltas in the High Island area, and progradational Marginulina shelf and deltaic sands in association with large rollover anticlines in the Matagorda Island and Brazos areas.

Seni, S.J.; Desselle, B.A.; Standen, A. [Univ. of Texas, Austin, TX (United States)

1994-09-01

263

PRELIMINARY CHARACTERIZATION OF CO2 SEPARATION AND STORAGE PROPERTIES OF COAL GAS RESERVOIRS  

Microsoft Academic Search

An attractive alternative of sequestering COâ is to inject it into coalbed methane reservoirs, particularly since it has been shown to enhance the production of methane during near depletion stages. The basis for enhanced coalbed methane recovery and simultaneous sequestration of carbon dioxide in deep coals is the preferential sorption property of coal, with its affinity for carbon dioxide being

John Kemeny; Satya Harpalani

2004-01-01

264

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

Microsoft Academic Search

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

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

2011-01-01

265

A new approach for history matching of oil and gas reservoir  

Microsoft Academic Search

This work proposes a new approach for history matching using Kernel PCA to adjust the reservoir permeability field obeying geostatistical constraint. Although there are several methodologies in literature for history matching, most of them don't take into account geostatistical restrictions. Besides, history matching is a problem of huge dimensionality. So, Kernel PCA was chosen due to its ability to compress

S. C. Miyoshi; D. M. Szwarcman; M. M. B. R. Vellasco

2010-01-01

266

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

National Technical Information Service (NTIS)

The primary objective of this study is to quantify the net emissions of key greenhouse gases (GHG) notably, CO2 and CH4 from hydropower reservoirs in moist temperate areas within the U.S. The rationale for this objective is straightforward: if net emissio...

A. Fortner A. Stewart J. Mosher J. Phillips M. Bevelhimer P. Mulholland

2011-01-01

267

Naturally fractured reservoirs. Part 7. Fractured shales present an attractive gas potential  

Microsoft Academic Search

Fractured shales have produced gas since the early 1900s along the western margin of the Appalachian basin. The amount of gas in fractured shales has been estimated at 460 quadrillion SCF. An extensive area of fractured shales also is present in the lowlands of Quebec, which appears to have a good gas potential based on limited information available. Since gas

R. Aguilera; H. K. Van Poollen

1979-01-01

268

Controls on early retention and late enhancement of microporosity in reefal gas reservoirs, offshore north Sumatra basin  

SciTech Connect

Chalky lime-matrix texture is pervasive in 300 m of coralgal and skeletal carbonates in the NSB-A (North Sumatra basin-A) gas field (lower-middle Miocene), offshore northern Sumatra. Much of the reservoir quality can be attributed to matrix with abundant intercrystalline, vuggy, and channel-form micropores. Matrix is composed of calcite microrhombs which are interpreted to have developed during stabilization of the precursor mud. On the same shelf, the smaller NSB-H oil field is composed of more than 45-m thick buildup of similar lithofacies which lack abundant microporosity. In both fields, early diagenesis included dissolution of aragonitic skeletal material, matrix neomorphism, and precipitation of nonluminescent calcite followed by zoned, luminescent calcite cements. Stable isotopes from matrix reflect a more open or water-dominated matrix diagenesis at NSB-H field. More active flushing of oversaturated, organically charged meteoric waters was responsible for thorough matrix cementation and microporosity occlusion at NSB-H field. Calcite cements show progressive enrichment of iron and manganese and depletion of magnesium and strontium during growth. The matrix at NSB-H field contains iron-rich dolomite. At A field, remnant matrix microporosity and intraparticle microporosity in calcitic skeletal material were greatly enhanced after all phases of cementation. Some pore-rimming cements are partially dissolved. At NSB-H field, late-phase dissolution is limited to the vicinity of open fractures where matrix-calcite and dolomite crystals are leached. Reservoir brines have a limey marine origin but are depleted in Ca and Mg relative to seawater, and carbon dioxide accounts for 31% of reservoir gas. If present brines are carbonate undersaturated, they may be substantially enhanced microporosity at NSB-A field. Late-stage dissolution is insignificant at NSB-H field due to the lack of early formed matrix microporosity.

Moshier, S.O.

1989-03-01

269

Active microbial community in gas reservoirs in the North German Plain and the effects of high CO2 concentrations  

NASA Astrophysics Data System (ADS)

From the IPCC report on global warming, it is clear that large-scale solutions are needed immediately to reduce emissions of greenhouse gases. The CO2 capture and storage offers one option for reducing the greenhouse gas emissions. Favourable CO2 storage sites are depleted gas and oil fields and thus, are currently investigated by the BMBF-Geotechnologien RECOBIO-2 project. Our study is focussing on the direct influence of high CO2 concentrations on the autochthonous microbial population and environmental parameters (e.g. availability of nutrients). The gas fields Schneeren in the 'North German Plain' is operated by Gaz de France SUEZ E&V Deutschland GmbH. The conditions in the reservoir formation waters of two bore wells differ in various geochemical parameters (pH, salinity and temperature). In previous studies the community of this gas field was described by Ehinger et al. 2009. Based on these results our study included cultivation and molecular biological approaches. Our results showed significant differences of the community structure in regional distinctions of the gas reservoir. The activity profiles of two wells differed clearly in the inducible activity after substrate addition. The fluids of well A showed a high methane production rate after the addition of methanol or acetate. Well B showed a high sulphide production after the addition of sulphate and hydrogen. The molecular biological analysis of the original fluids supports the activity profile for both sites. The community analysis via real-time PCR showed for the production well head A a higher abundances for Archaea than for B. The community at site B in contrast was dominated by Bacteria. Fluids of both wells were also incubated with high CO2 concentrations in the headspace. These enrichments showed a significant decrease of methane and sulphide production with increasing CO2 levels. Currently, the community composition is analysed to identify changes connected to increased CO2 concentrations. This will provide information about possible biogeochemical and microbiological changes during and after the storage of CO2, and effects on the storage capacity and injectivity of the reservoir formation.

Frerichs, Janin; Gniese, Claudia; Mühling, Martin; Krüger, Martin

2010-05-01

270

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

SciTech Connect

There are four primary goals of contract DE-FG26-99FT40703: (1) We seek to better understand how and why two damage mechanisms--(1) inorganic precipitants, and (2) hydrocarbons and organic residues, occur at the reservoir/wellbore interface in gas storage wells. (2) We plan on testing potential prevention and remediation strategies related to these two damage mechanisms in the laboratory. (3) We expect to demonstrate in the field, cost-effective prevention and remediation strategies that laboratory testing deems viable. (4) We will investigate new technology for the gas storage industry that will provide operators with a cost effective method to reduce non-darcy turbulent flow effects on flow rate. For the above damage mechanisms, our research efforts will demonstrate the diagnostic technique for determining the damage mechanisms associated with lost deliverability as well as demonstrate and evaluate the remedial techniques in the laboratory setting and in actual gas storage reservoirs. We plan on accomplishing the above goals by performing extensive lab analyses of rotary sidewall cores taken from at least two wells, testing potential remediation strategies in the lab, and demonstrating in the field the applicability of the proposed remediation treatments. The benefits from this work will be quantified from this study and extrapolated to the entire storage industry. The technology and project results will be transferred to the industry through DOE dissemination and through the industry service companies that work on gas storage wells. Achieving these goals will enable the underground gas storage industry to more cost-effectively mitigate declining deliverability in their storage fields. Work completed to date includes the following: (1) Solicited potential participants from the gas storage industry; (2) Selected one participant experiencing damage from inorganic precipitates; (3) Developed laboratory testing procedures; (4) Collected cores from National Fuel Gas Summit No.1527 Well; (5) Analyzed cores from National Fuel Gas Summit No.1527 Well; (6) Began investigating methods to remove damage identified in Summit No.1527 cores; and (7) Began investigating methods to reduce non-darcy turbulent effects.

J.H. Frantz; K.E. Brown

2003-02-01

271

Exploratory Simulation Studies of Caprock Alteration Induced byStorage of CO2 in Depleted Gas Reservoirs  

SciTech Connect

This report presents numerical simulations of isothermalreactive flows which might be induced in the caprock of an Italiandepleted gas reservoir by the geological sequestration of carbon dioxide.Our objective is to verify that CO2 geological disposal activitiesalready planned for the study area are safe and do not induce anyundesired environmental impact.Gas-water-rock interactions have beenmodelled under two different intial conditions, i.e., assuming that i)caprock is perfectly sealed, or ii) partially fractured. Field conditionsare better approximated in terms of the "sealed caprock model". Thefractured caprock model has been implemented because it permits toexplore the geochemical beahvior of the system under particularly severeconditions which are not currently encountered in the field, and then todelineate a sort of hypothetical maximum risk scenario.Major evidencessupporting the assumption of a sealed caprock stem from the fact that nogas leakages have been detected during the exploitation phase, subsequentreservoir repressurization due to the ingression of a lateral aquifer,and during several cycles of gas storage in the latest life of reservoirmanagement.An extensive program of multidisciplinary laboratory tests onrock properties, geochemical and microseismic monitoring, and reservoirsimulation studies is underway to better characterize the reservoir andcap-rock behavior before the performance of a planned CO2 sequestrationpilot test.In our models, fluid flow and mineral alteration are inducedin the caprock by penetration of high CO2 concentrations from theunderlying reservoir, i.e., it was assumed that large amounts of CO2 havebeen already injected at depth. The main focus is on the potential effectof these geochemical transformations on the sealing efficiency of caprockformations. Batch and multi-dimensional 1D and 2D modeling has been usedto investigate multicomponent geochemical processes. Our simulationsaccount for fracture-matrix interactions, gas phase participation inmultiphase fluid flow and geochemical reactions, and kinetics offluid-rock interactions.The main objectives of the modeling are torecognize the geochemical processes or parameters to which theadvancement of high CO2 concentrations in the caprock is most sensitive,and to describe the most relevant mineralogical transformations occurringin the caprock as a consequence of such CO2 storage in the underlyingreservoir. We also examine the feedback of these geochemical processes onphysical properties such as porosity, and evaluate how the sealingcapacity of the caprock evolves in time.

Gherardi, Fabrizio; Xu, Tianfu; Pruess, Karsten

2005-11-23

272

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

273

Naturally fractured tight gas reservoir detection optimization. Quarterly report, October 1--December 31, 1994  

SciTech Connect

This progress report covers the following tasks: Computational geochemistry (Indiana University Laboratory); and geologic assessment of the Piceance Basin. Computational geochemistry covers; three- dimensional basin simulator; stress solver; two-dimensional basin simulator; organic reactions and multi-phase flow; grid optimization; database calibration and data input; and Piceance Basin initial simulation. Sub-tasks under geologic assessment of the Piceance Basin include: structural analysis; reservoir characterization; stratigraphic interpretation; seismic interpretation; and remote sensing interpretation.

NONE

1995-01-30

274

Simulation of Three-Dimensional, Two-Phase Flow In Oil and Gas Reservoirs  

Microsoft Academic Search

Two computer-~ rierrted techniques for simulating the three-dimensional flow behavior o\\/ Iwo fluid phases in petroleum reservoirs were developed. Under the first technique the flow equations are solved to.. model three-dimensional flow in a re~ert.uir. 'The second technique was developed \\/or modeling ftow in t bree-dimensiorwl media that have sufficient ly high permeability in the vertical direction so that vertical

K. H. COATS; R. L. NIELSEN; MARY TERHUNE; A. G. WEBER

1967-01-01

275

Novel Simulation Techniques Used in a Gas Reservoir With a Thin Oil Zone: Troll Field  

Microsoft Academic Search

Choice of production strategy in modern reservoir management relies heavily on numerical simulation. Large fields may require prohibitively large computer times. This paper reports on new techniques developed to save computer and engineering time: local grid refinement with small timesteps and flux boundary conditions for simulating regions of special interest. The combined use of these techniques allowed flexible, non-time-consuming, user-friendly

Adolfo Henriquez; Odd Apeland; Oystein Lie; Ian Cheshire

1992-01-01

276

Nurturing the geology-reservoir engineering team: Vital for efficient oil and gas recovery  

SciTech Connect

Of an estimated 482 billion bbl (76.6 Gm{sup 3}) of in-place oil discovered in the US, 158 billion (25.1 Gm{sup 3}) can be recovered with existing technology and economic conditions. The cost-effective recovery through infill drilling and enhanced oil recovery methods to recover any portion of the remaining 323 billion bbl (51.4 Gm3) will require a thorough understanding of reservoirs and the close cooperation of production geologists and reservoir engineers. This paper presents the concept of increased interaction between geologists and reservoir engineers through multifunctional teams and cross-training between the disciplines. A discussion of several factors supporting this concept is covered, including educational background, technical manpower trends, employee development, and job satisfaction. There are several ways from an organizational standpoint to achieve this cross-training, with or without a formal change in job assignment. This paper outlines three approaches, including case histories where each of the approaches has been implemented and the resulting benefits.

Sessions, K.P.; Lehman, D.H. (Exxon Co., Houston, TX (USA))

1990-05-01

277

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

278

Spatial and temporal aspects of greenhouse gas emissions from Three Gorges Reservoir, China  

NASA Astrophysics Data System (ADS)

Before completion of the Three Gorges Reservoir (TGR), China, there was growing apprehension that it would become a major emitter of greenhouse gases (GHG): Carbon Dioxide (CO2), Methane (CH4) and Nitrous Oxide (N2O). We report monthly measurements for one year of the fluxes of these gases at multiple sites within the TGR, Yangtze River, China, and from several major tributaries, and immediately downstream of the dam. The tributary areas have lower CO2 fluxes than the main storage; CH4 fluxes to the atmosphere after passage through the turbines are negligible. Overall, TGR showed significantly lower CH4 emission rates than most new reservoirs in temperate and tropical regions. We attribute this to the well-oxygenated deep water and high water velocities which produce oxic mainstem conditions inimical to CH4 emission. TGR's CO2 fluxes were lower than most tropical reservoirs and higher than most temperate systems. This is due to the high load of metabolizable soil carbon delivered through erosion to the Yangtze River. Compared to fossil fuelled power plants of equivalent power output TGR is a very small GHG emitter, annual CO2-equivalent emissions are approximately 1.7% of a coal-fired generating plant of comparable power output.

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

2012-10-01

279

Application of conditional simulation of heterogeneous rock properties to seismic scattering and attenuation analysis in gas hydrate reservoirs  

NASA Astrophysics Data System (ADS)

We present a conditional simulation algorithm to parameterize three-dimensional heterogeneities and construct heterogeneous petrophysical reservoir models. The models match the data at borehole locations, simulate heterogeneities at the same resolution as borehole logging data elsewhere in the model space, and simultaneously honor the correlations among multiple rock properties. The model provides a heterogeneous environment in which a variety of geophysical experiments can be simulated. This includes the estimation of petrophysical properties and the study of geophysical response to the heterogeneities. As an example, we model the elastic properties of a gas hydrate accumulation located at Mallik, Northwest Territories, Canada. The modeled properties include compressional and shear-wave velocities that primarily depend on the saturation of hydrate in the pore space of the subsurface lithologies. We introduce the conditional heterogeneous petrophysical models into a finite difference modeling program to study seismic scattering and attenuation due to multi-scale heterogeneity. Similarities between resonance scattering analysis of synthetic and field Vertical Seismic Profile data reveal heterogeneity with a horizontal-scale of approximately 50 m in the shallow part of the gas hydrate interval. A cross-borehole numerical experiment demonstrates that apparent seismic energy loss can occur in a pure elastic medium without any intrinsic attenuation of hydrate-bearing sediments. This apparent attenuation is largely attributed to attenuative leaky mode propagation of seismic waves through large-scale gas hydrate occurrence as well as scattering from patchy distribution of gas hydrate.

Huang, Jun-Wei; Bellefleur, Gilles; Milkereit, Bernd

2012-02-01

280

Geologic characterization of tight gas reservoirs: FY86 USGS annual report, October 1, 1985-September 30, 1986  

SciTech Connect

The objectives of US Geological Survey work are to conduct geologic research characterizing tight gas-bearing sequences in the western United States. The USGS research during the last few years has been in the Greater Green River, Piceance Creek, and Uinta basins of Wyoming, Colorado, and Utah. Additional critical objectives are to provide geologic consulting and research support for ongoing Multiwell Experiment (MWX) engineering, petrophysical, log-analysis, and well-testing research. Within these basins our research efforts have been regional in scope. The Greater Green River basin has high priority because most of the Piceance basin studies have been completed or are being completed, and because the Greater Green River basin has the greatest areal extent and greatest known thicknesses (>10,000 ft) of strata containing dominantly gas-bearing sandstone reservoirs. The Uinta Basin may have greater thicknesses of tight-gas strata, but there are presently no wells that have been drilled through the Cretaceous Mesaverde Group in the deeper parts of the basin. The objectives of these focused investigations are to provide geologic models that can be compared and utilized in tight gas-bearing sequences elsewhere. 18 figs.

Law, B.E.; Spencer, C.W.; Lickus, M.R.; Pollastro, R.M.; Johnson, R.C.; Nuccio, V.F.; Pitman, J.K.

1986-09-01

281

Prediction of gas injection performance for heterogenous reservoirs, semi-annual technical report, October 1, 1996--March 31, 1997  

SciTech Connect

The current project is a systematic research effort that will lead to a new generation of predictive tools for gas injection processes in heterogeneous reservoirs. The project is aimed at quantifying the impact of heterogeneity on oil recovery from pore level to reservoir scales. This research effort is, therefore, divided into four areas: (1) Laboratory Gas Injection Experiments (2) Network Modeling of Three-Phase Flow (3) Benchmark Simulation of Gas Injection Processes (4) Streamline Simulator Development. The status of the research effort in each area is reviewed briefly in the following section. Project Status Laboratory Gas Injection Experiments Gravity drainage of oil in the presence of gas and water has found to result in high recovery efficiency. Numerical representation of the high recovery efficiency requires a good understanding of three-phase relative permeabilities, especially at low oil saturations. Ph.D student Akshay Sahni has analyzed experimental results of selected three-phase displacements in the literature and compared them with the newly developed mathematical theory of three-phase flow in porous media. He approximated the relative permeability of each phase as a polynomial function of the saturation of that phase. An excellent agreement has been obtained between the measured and the calculated saturation paths. The analytical solution has also been checked by performing numerical simulations. Fig. 1 is an example of the comparisons of experiments, mathematical theory and numerical simulations. Fig. 1 shows a situation in which gas is injected into a system with high oil saturation and the formation of an oil bank is observed. The experiments in the literature were generally conducted at relatively high oil saturations. We have designed a series of gravity drainage experiments to measure three-phase relative permeability at low oil saturations. The CT scanner in the Petroleum Engineering Department at Stanford has been modified to measure in-situ saturations of vertically-placed samples, which is necessary in gravity drainage experiments. Akshay Sahni has finished a series of gravity drainage experiments in sand packs using different model oils to calibrate the scanner and to investigate the effect of spreading coefficient on three-phase relative permeability. A procedure has been developed for calculating relative permeabilities from measured in-situ saturations.

Blunt, M.J.

1997-04-30

282

Development of a 400 Level 3C Clamped Downhole Seismic Receiver Array for 3D Borehole Seismic Imaging of Gas Reservoirs. Quarterly Reports, July 1, 2004-September 30, 2004.  

National Technical Information Service (NTIS)

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 im...

B. J. Paulsson

2004-01-01

283

Development of a 400 Level 3C Clamped Downhole Seismic Receiver Array for 3D Borehole Seismic Imaging of Gas Reservoirs. Quarterly Reports, April 1, 2004-June 30, 2004.  

National Technical Information Service (NTIS)

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 im...

B. J. Paulsson

2004-01-01

284

Development of a 400 Level 3C Clamped Downhole Seismic Receiver Array for 3D Borehole Seismic Imaging of Gas Reservoirs. (Quarterly Report, April 1, 2005-June 30, 2005).  

National Technical Information Service (NTIS)

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 im...

B. N. Paulsson

2005-01-01

285

Development of a 400 Level 3C Clamped Downhole Seismic Receiver Array for 3D Borehole Seismic Imaging of Gas Reservoirs. Quarterly Reports: January 1, 2003-March 31, 2003.  

National Technical Information Service (NTIS)

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 im...

B. N. P. Paulsson

2003-01-01

286

Development of a 400 Level 3C Clamped Downhole Seismic Receiver Array for 3D Borehole Seismic Imaging of Gas Reservoirs. Quarterly Report: October 1, 2003-December 31, 2003.  

National Technical Information Service (NTIS)

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 im...

B. N. Paulsson

2005-01-01

287

Development of a 400 Level 3C Clamped Downhole Seismic Receiver Array for 3D Borehole Seismic Imaging of Gas Reservoirs. Quarterly Report: January 1, 2005-March 31, 2005.  

National Technical Information Service (NTIS)

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 industrys ability to economically do high resolution 3D ima...

2005-01-01

288

Development of a 400 Level 3C Clamped Downhole Seismic Receiver Array for 3D Borehole Seismic Imaging of Gas Reservoirs. Quarterly Reports: Oct 1, 2002-Dec 31, 2002.  

National Technical Information Service (NTIS)

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 im...

B. N. P. Paulsson

2003-01-01

289

Development of a 400 Level 3C Clamped Downhole Seismic Receiver Array for 3D Borehole Seismic Imaging of Gas Reservoirs. Quarterly Reports: Oct 1, 2001-Dec 31, 2001, Jan 1, 2002-March 31, 2002.  

National Technical Information Service (NTIS)

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 ...

B. N. P. Paulsson

2002-01-01

290

Development of a 400 Level 3C Clamped Downhole Seismic Receiver Array for 3D Borehole Seismic Imaging of Gas Reservoirs. Quarterly Report for October 1, 2005 to December 31, 2005.  

National Technical Information Service (NTIS)

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 industrys ability to economically do high resolution 3D ima...

B. N. P. Paulsson

2006-01-01

291

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

292

Integrated seismic study of naturally fractured tight gas reservoirs. Technical progress report, January 1, 1993--March 31, 1993  

SciTech Connect

During this quarter we (1) received the last of the field tapes and survey information for the seismic field data acquisition which was finished at the very end of the previous quarter, (2) began the large task of processing the seismic data, (3) collected well logs and other informination to aid in the interpretation, and (4) initiated some seismic modeling studies. As already reported, the field data acquisition was at Amoco`s Powder River Basin site in southeast Wyoming. This is a low permeability fractured site, with both gas and oil present. The reservoir is highly compartmentalized, due to the low permeability, with the fractures providing the only practical drainage paths for production. The two formations of interest are: The Niobrara: a fractured shale and limey shale to chalk, which is a reservoir rock, but also its own source rock. The Frontier: a tight sandstone lying directly below the Niobrara, brought into contact with it by an unconformity. The fractures are thought to lie in a roughly northwest-southeast trend, along the strike of a flexure, which forms one of the boundaries of the basin.

Mavko, G.; Nur, A.

1993-04-26

293

Integrated seismic study of naturally fractured tight gas reservoirs. Technical progress report, April 1, 1993--June 31, 1993  

SciTech Connect

This was the seventh quarter of the contract. During this quarter we (1) continued the large task of processing the seismic data, (2) collected additional geological information to aid in the interpretation, (3) tied the well log data to the seismic via generation of synthetic seismograms, (4) began integrating regional structural information and fracture trends with our observations of structure in the study area, (5) began constructing a velocity model for time-to-depth conversion and subsequent AVO and raytrace modeling experiments, and (6) completed formulation of some theoretical tools for relating fracture density to observed elastic anisotropy. The study area is located at the southern end of the Powder River Basin in Converse County in east-central Wyoming. It is a low permeability fractured site, with both gas and oil present. Reservoirs are highly compartmentalized due to the low permeabilities, and fractures provide the only practical drainage paths for production. The two formations of interest are: The Niobrara: a fractured shale and limey shale to chalk, which is a reservoir rock, but also its own source rock. The Frontier: a tight sandstone lying directly below the Niobrara, brought into contact with it by an unconformity. A basemap is presented with the seismic lines being analyzed for this project plus locations of 13 wells that we are using to supplement the analysis. The arrows point to two wells for which we have constructed synthetic seismograms.

Mavko, G.; Nur, A.

1993-07-26

294

Laboratory Investigation of Steam Adsorption in Geothermal Reservoir Rocks.  

National Technical Information Service (NTIS)

Some vapor-dominated geothermal reservoirs and low-permeability gas reservoirs exhibit anomalous behavior that may be caused by surface adsorption. For example, geothermal reservoirs in the Larderello area of Italy and reservoirs in the Geysers Geothermal...

J. Luetkehans

1988-01-01

295

Validation Status of the VARGOW Oil Reservoir Model.  

National Technical Information Service (NTIS)

VARGOW, a variable gas-oil-water reservoir model, provides recovery estimates suitable for assessing various reservoir production policies and regulations. Data were collected for a number of reservoirs. From this data base, three reservoirs approximating...

D. W. Mayer E. M. Arnold W. M. Bowen P. J. Gutknecht

1980-01-01

296

Geologic, geochemical, and geographic controls on NORM in produced water from Texas oil, gas, and geothermal reservoirs. Final report  

SciTech Connect

Water from Texas oil, gas, and geothermal wells contains natural radioactivity that ranges from several hundred to several thousand Picocuries per liter (pCi/L). This natural radioactivity in produced fluids and the scale that forms in producing and processing equipment can lead to increased concerns for worker safety and additional costs for handling and disposing of water and scale. Naturally occurring radioactive materials (NORM) in oil and gas operations are mainly caused by concentrations of radium-226 ({sup 226}Ra) and radium-228 ({sup 228}Ra), daughter products of uranium-238 ({sup 238}U) and thorium-232 ({sup 232}Th), respectively, in barite scale. We examined (1) the geographic distribution of high NORM levels in oil-producing and gas-processing equipment, (2) geologic controls on uranium (U), thorium (Th), and radium (Ra) in sedimentary basins and reservoirs, (3) mineralogy of NORM scale, (4) chemical variability and potential to form barite scale in Texas formation waters, (5) Ra activity in Texas formation waters, and (6) geochemical controls on Ra isotopes in formation water and barite scale to explore natural controls on radioactivity. Our approach combined extensive compilations of published data, collection and analyses of new water samples and scale material, and geochemical modeling of scale Precipitation and Ra incorporation in barite.

Fisher, R.

1995-08-01

297

Radionuclide Migration at the Rio Blanco Site, A Nuclear-stimulated Low-permeability Natural Gas Reservoir  

SciTech Connect

The U.S. Department of Energy and its predecessor agencies conducted a program in the 1960s and 1970s that evaluated technology for the nuclear stimulation of low-permeability gas reservoirs. The third and final project in the program, Project Rio Blanco, was conducted in Rio Blanco County, in northwestern Colorado. In this experiment, three 33-kiloton nuclear explosives were simultaneously detonated in a single emplacement well in the Mesaverde Group and Fort Union Formation, at depths of 1,780, 1,899, and 2,039 m below land surface on May 17, 1973. The objective of this work is to estimate lateral distances that tritium released from the detonations may have traveled in the subsurface and evaluate the possible effect of postulated natural-gas development on radionuclide migration. Other radionuclides were considered in the analysis, but the majority occur in relatively immobile forms (such as nuclear melt glass). Of the radionuclides present in the gas phase, tritium dominates in terms of quantity of radioactivity in the long term and contribution to possible whole body exposure. One simulation is performed for {sup 85}Kr, the second most abundant gaseous radionuclide produced after tritium.

Clay A. Cooper; Ming Ye; Jenny Chapman; Craig Shirley

2005-10-01

298

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 perform high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology has been hampered by the lack of acquisition technology necessary to record large volumes of high frequency, high signal-to-noise-ratio borehole seismic data. This project took 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 has removed the technical acquisition barrier for recording the data volumes necessary to do high resolution 3D VSP and 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 promise to take the gas industry to the next level in their quest for higher resolution images of deep and complex oil and gas reservoirs. Today only a fraction of the oil or gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of detailed compartmentalization of oil and gas reservoirs. In this project, we developed a 400 level 3C borehole seismic receiver array that allows for economic use of 3D borehole seismic imaging for reservoir characterization and monitoring. This new array has significantly increased the efficiency of recording large data volumes at sufficiently dense spatial sampling to resolve reservoir complexities. The receiver pods have been fabricated and tested to withstand high temperature (200 C/400 F) and high pressure (25,000 psi), so that they can operate in wells up to 7,620 meters (25,000 feet) deep. The receiver array is deployed on standard production or drill tubing. In combination with 3C surface seismic or 3C borehole seismic sources, the 400 level receiver array can be used to obtain 3D 9C data. These 9C borehole seismic data provide both compressional wave and shear wave information that can be used for quantitative prediction of rock and pore fluid types. The 400-level borehole receiver array has been deployed successfully in a number of oil and gas wells during the course of this project, and each survey has resulted in marked improvements in imaging of geologic features that are critical for oil or gas production but were previously considered to be below the limits of seismic resolution. This added level of reservoir detail has resulted in improved well placement in the oil and gas fields that have been drilled using the Massive 3D VSP{reg_sign} images. In the future, the 400-level downhole seismic receiver array is expected to continue to improve reservoir characterization and drilling success in deep and complex oil and gas reservoirs.

Bjorn N. P. Paulsson

2006-09-30

299

Reservoir engineering aspects and resource-assessment methodology of eastern Devonian Gas shales  

Microsoft Academic Search

The US Department of Energy's Morgantown Energy Technology Center (METC) and Science Applications, Inc., are cooperating in the characterization of the eastern Devonian Shale gas resource. This study, focusing on the Lincoln County, WV, area, characterizes the resource and shows that conventional volumetric techniques cannot be used to determine the amount of gas in place. Previous studies, using calculations based

F. Kucuk; J. Alam; D. L. Streib

1978-01-01

300

Reservoir-engineering aspects and resource-assessment methodology of Eastern Devonian gas shales  

Microsoft Academic Search

The US Department of Energy's Morgantown Energy Technology Center (METC) and Science Applications, Inc., are cooperating in the characterization of the Eastern Devonian Shale gas resource. This study, focusing on the Lincoln County, WV, area, characterizes the resource and shows that conventional volumetric techniques cannot be used to determine the amount of gas in place. Previous studies, using calculations based

F. Kucuk; J. Alam; D. L. Streib

1978-01-01

301

Advancing New 3D Seismic Interpretation Methods for Exploration and Development of Fractured Tight Gas Reservoirs. Final Report February 9, 2000 - January 31, 2005.  

National Technical Information Service (NTIS)

In a study funded by the U. S. Department of Energy and GeoSpectrum, Inc., new P-wave 3D seismic interpretation methods to characterize fractured gas reservoirs are developed. A data driven exploratory approach is used to determine empirical relationships...

J. J. Reeves

2006-01-01

302

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

303

Gas breakthrough pressure for hydrocarbon reservoir seal rocks: implications for the security of long-term CO2 storage in the Weyburn field  

Microsoft Academic Search

This paper reports a laboratory study of the gas breakthrough pressure for different gas\\/liquid systems in the Mis- sissippian-age Midale Evaporite. This low-permeability rock formation is the seal rock for the Weyburn Field in southeastern Saskatchewan, Canada, where CO2 is being injected into an oil reservoir for enhanced recovery and CO2 storage. A technique for experimentally determining CO2 breakthrough pressure

M. D ONG; Z. LI; S. HUA N G; H. QIN; E. NICKEL

2005-01-01

304

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

Microsoft Academic Search

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

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

2010-01-01

305

Mechanism for calcite dissolution and its contribution to development of reservoir porosity and permeability in the Kela 2 gas field, Tarim Basin, China  

Microsoft Academic Search

This study is undertaken to understand how calcite precipitation and dissolution contributes to depth-related changes in porosity\\u000a and permeability of gas-bearing sandstone reservoirs in the Kela 2 gas field of the Tarim Basin, Northwestern China. Sandstone\\u000a samples and pore water samples are collected from well KL201 in the Tarim Basin. Vertical profiles of porosity, permeability,\\u000a pore water chemistry, and the

BingSong Yu; HailLiang Dong; Zhuang Ruan

2008-01-01

306

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

307

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

308

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

309

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

310

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

National Technical Information Service (NTIS)

This report describes progress in 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 rese...

1995-01-01

311

The simulator TOUGH2\\/EWASG for modelling geothermal reservoirs with brines and non-condensible gas  

Microsoft Academic Search

An equation-of-state (EOS) module has been developed for the TOUGH2 simulator, belonging to the MULKOM family of computer codes developed at Lawrence Berkeley National Laboratory. This module, named EWASG (Equation-of-State for Water, Salt and Gas), is able to handle three-component mixtures of water, sodium chloride, and a slightly soluble non-condensible gas (NCG). At present the NCG can be chosen to

Alfredo Battistelli; Claudio Calore; Karsten Pruess

1997-01-01

312

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

313

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

Microsoft Academic Search

Carbon dioxide and helium with isotopic compositions indicative of a magmatic source (δthinsp¹³C=-4.5 to -5{per_thousand}, ³He\\/⁴He=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

M. L. Sorey; W. C. Evans; B. M. Kennedy; C. D. Farrar; L. J. Hainsworth; B. Hausback

1998-01-01

314

Regional and reservoir-scale analysis of fault systems and structural development of Pagerungan Gas Field, East Java Sea, Indonesia  

SciTech Connect

Pagerungan gas field lies on a complexly faulted and folded anticline just north of the major Sakala-Paliat Fault System (SPFS) offshore Bali. The Eocene clastic reservoir is affected by two generations of faults: Eocene normal and Neogene compressional faults. Fault geometry, timing and connectivity is determined by combining regional and field-scale methods. Restored regional structure maps and sections indicate the field is located on the L. Eocene, footwall-paleo-high of the south-dipping SPFS. Within the field, smaller normal faults nucleated sub-parallel to the SPFS with both synthetic and antithetic dips. Neogene to Present compression folded the strata creating closure in the field, reversed slip on selected preexisting normal faults, and nucleated new reverse fault sets. Some normal faults are completely inverted, others have net normal offset after some reverse slip, and still others are not reactivated. Reverse faults strike sub-parallel to earlier formed normal faults. The eastern and western parts of the field are distinguished by the style and magnitude of early compressional deformation. 3D seismic analysis indicates the geometry of reservoir faults is similar to the regional fault systems: sub-parallel segments share displacement at their terminations either by distributed deformation in the rock between adjacent terminations or through short cross-faults oriented at a high angle to the principal fault sets. Anomalous trends in the contours of throw projected onto fault surfaces predict the connectivity of complex fault patterns. Integration of regional and field-scale analysis provides the most accurate prediction of fault geometry and lays the foundation for field development.

Davies, R.K.; Medwedeff, D.A. (Arco Exploration and Production Technology, Plano, TX (United States))

1996-01-01

315

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

316

Understanding the Effect of Natural Fractures on the Hydrofracture Stimulation of Natural Gas Reservoirs.  

National Technical Information Service (NTIS)

A finite element model for propagation of discrete fractures has been coupled to an implicit time-dependent fluid flow capability to be used as a predictive tool for hydraulic fracturing through sandstone lenses, as found in the Western Tight Gas Sands. V...

F. E. Heuze R. J. Shaffer S. C. Blair R. K. Thorpe

1989-01-01

317

Tracing the cold molecular gas reservoir through dust emission in the SMC  

Microsoft Academic Search

The amount of molecular gas is a key for understanding the future star formation in a galaxy. However, this quantity is difficult to infer as the cold H2 is almost impossible to observe and, especially at low metallicities, CO only traces part of the clouds, keeping large envelopes of H2 hidden from observations. In this context, millimeter dust emission tracing

Caroline Bot; Mónica Rubio; François Boulanger; Marcus Albrecht; Frank Bertoldi; Alberto D. Bolatto; Adam K. Leroy

2009-01-01

318

Seismic modeling of multidimensional heterogeneity scales of Mallik gas hydrate reservoirs, Northwest Territories of Canada  

NASA Astrophysics Data System (ADS)

In hydrate-bearing sediments, the velocity and attenuation of compressional and shear waves depend primarily on the spatial distribution of hydrates in the pore space of the subsurface lithologies. Recent characterizations of gas hydrate accumulations based on seismic velocity and attenuation generally assume homogeneous sedimentary layers and neglect effects from large- and small-scale heterogeneities of hydrate-bearing sediments. We present an algorithm, based on stochastic medium theory, to construct heterogeneous multivariable models that mimic heterogeneities of hydrate-bearing sediments at the level of detail provided by borehole logging data. Using this algorithm, we model some key petrophysical properties of gas hydrates within heterogeneous sediments near the Mallik well site, Northwest Territories, Canada. The modeled density, and P and S wave velocities used in combination with a modified Biot-Gassmann theory provide a first-order estimate of the in situ volume of gas hydrate near the Mallik 5L-38 borehole. Our results suggest a range of 528 to 768 × 106 m3/km2 of natural gas trapped within hydrates, nearly an order of magnitude lower than earlier estimates which did not include effects of small-scale heterogeneities. Further, the petrophysical models are combined with a 3-D finite difference modeling algorithm to study seismic attenuation due to scattering and leaky mode propagation. Simulations of a near-offset vertical seismic profile and cross-borehole numerical surveys demonstrate that attenuation of seismic energy may not be directly related to the intrinsic attenuation of hydrate-bearing sediments but, instead, may be largely attributed to scattering from small-scale heterogeneities and highly attenuate leaky mode propagation of seismic waves through larger-scale heterogeneities in sediments.

Huang, Jun-Wei; Bellefleur, Gilles; Milkereit, Bernd

2009-07-01

319

A cold-gas reservoir to fuel the M 31 nuclear black hole and stellar cluster  

NASA Astrophysics Data System (ADS)

With IRAM-30 m/HERA, we have detected CO(2-1) gas complexes within 30 arcsec (~100 pc) from the center of M 31 that amount to a minimum total mass of 4.2 × 104 M? (one third of the positions are detected). Averaging the whole HERA field, we show that there is no additional undetected diffuse component. Moreover, the gas detection is associated with gas lying on the far side of the M 31 center as no extinction is observed in the optical, but some emission is present on infrared Spitzer maps. The kinematics is complex. (1) The velocity pattern is mainly redshifted: the dynamical center of the gas differs from the black hole position and the maximum of optical emission, and only the redshifted side is seen in our data. (2) Several velocity components are detected in some lines of sight. Our interpretation is supported by the reanalysis of the effect of dust on a complete planetary nebula sample. Two dust components are detected with respective position angles of 37 deg and -66 deg. This is compatible with a scenario where the superposition of the (PA = 37 deg) disk is dominated by the 10 kpc ring and the inner 0.7 kpc ring detected in infrared data, whose position angle (-66 deg) we measured for the first time. The large-scale disk, which dominates the HI data, is steeply inclined (i = 77 deg), warped and superposed on the line of sight on the less inclined inner ring. The detected CO emission might come from both components. The reduced spectra (FITS files) are only available at the CDS via anonymous ftp to cdsarc.u-strasbg.fr (130.79.128.5) or via http://cdsarc.u-strasbg.fr/viz-bin/qcat?J/A+A/549/A27

Melchior, A.-L.; Combes, F.

2013-01-01

320

Tracing the cold molecular gas reservoir through dust emission in the SMC  

NASA Astrophysics Data System (ADS)

The amount of molecular gas is a key for understanding the future star formation in a galaxy. However, this quantity is difficult to infer as the cold H2 is almost impossible to observe and, especially at low metallicities, CO only traces part of the clouds, keeping large envelopes of H2 hidden from observations. In this context, millimeter dust emission tracing the cold and dense regions can be used as a tracer to unveil the total molecular gas masses. I present studies of a sample of giant molecular clouds in the Small Magellanic Cloud. These clouds have been observed in the millimeter and sub-millimeter continuum of dust emission: with SIMBA/SEST at 1.2 mm and the new LABOCA bolometer on APEX at 870 ?m. Combining these with radio data for each cloud, the spectral energy distribution of dust emission are obtained and gas masses are inferred. The molecular cloud masses are found to be systematically larger than the virial masses deduced from CO emission. Therefore, the molecular gas mass in the SMC has been underestimated by CO observations, even through the dynamical masses. This result confirms what was previously observed by Bot et al. (2007). We discuss possible interpretations of the mass discrepancy observed: in the giant molecular clouds of the SMC, part of cloud's support against gravity could be given by a magnetic field. Alternatively, the inclusion of surface terms in the virial theorem for turbulent clouds could reproduce the observed results and the giant molecular clouds could be transient structures.

Bot, Caroline; Rubio, Mónica; Boulanger, François; Albrecht, Marcus; Bertoldi, Frank; Bolatto, Alberto D.; Leroy, Adam K.

2009-03-01

321

Laboratory studies for the design and analysis of hydraulic fracture stimulations in tight gas reservoirs  

SciTech Connect

Laboratory studies were used as an aid in designing stimulation treatments and to assist in the analysis of production results. These analyses were done in conjunction with coastal zone stimulation operations at the Department of Energy's Multiwell Experiment near Rifle, Colorado. A multitreatment stimulation plan was designed for the coastal zone because of apparent damage to the paludal zone formations in prior stimulation operations. The stimulation plan was made to minimize the use of water-based, gelled fluids. Two small stimulations were performed in the same coastal interval: an unpropped nitrogen gas frac and a propped, nitrogen foam frac. Gas production decreased from that of the gas frac after the nitrogen foam stimulation and formation damage was apparent. The laboratory program was used to (1) aid stimulation design; (2) help eliminate several possible causes of damage such as permeability degradation in the matrix rock, a gel block in the sand pack, proppant effects, or imbibition of brine from workover operations; and (3) examine the more probable causes, damage that may be centered around fluid effects in the natural fracture system. A unique explanation is not possible because there are some aspects of these damage mechanisms that cannot be verified in the laboratory. However, comparable damage mechanisms that have been seen in cracked core are described. Also, other postulated forms of fluid damage are discussed, largely in terms of natural fractures in core in combination with other measured core properties. 37 refs., 1 fig., 8 tabs.

Sattler, A.R.; Hudson, P.J.; Raible, C.J.; Gall, B.L.; Maloney, D.R.

1986-01-01

322

Supplemental Generic Environmental Impact Statement On The Oil, Gas and Solution Mining Regulatory Program: Well Permit Issuance for Horizontal Drilling and High-Volume Hydraulic Fracturing to Develop the Marcellus Shale and Other Low-Permeability Gas Reservoirs. (Revised Draft).  

National Technical Information Service (NTIS)

In New York, the primary target for shale-gas development is currently the Marcellus Shale, with the deeper Utica Shale also identified as a potential resource. Additional low-permeability reservoirs may be considered by project sponsors for development b...

E. Leff

2011-01-01

323

Gas Reservoirs and Star Formation in a Forming Galaxy Cluster at zbsime0.2  

NASA Astrophysics Data System (ADS)

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 ~ 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.

Jaffé, Yara L.; Poggianti, Bianca M.; Verheijen, Marc A. W.; Deshev, Boris Z.; van Gorkom, Jacqueline H.

2012-09-01

324

Secondary Natural Gas Recovery: Targeted Technology Applications for Infield Reserve Growth in Fluvial Reservoirs in the Frio Formation, Seeligson Field, South Texas. Topical Report, September 1, 1988-December 31, 1991.  

National Technical Information Service (NTIS)

The potential for secondary incremental recovery of natural gas exists in complex fluvial-deltaic reservoirs in the Texas Gulf Coast. Reservoirs in the Frio Fluvial-Deltaic Sandstone along the Vicksburg Fault Zone play (FR-4) in South Texas commonly conta...

W. A. Ambrose J. D. Grigsby B. A. Hardage R. P. Langford L. A. Jirik

1992-01-01

325

A Huge Reservoir of Ionized Gas around the Milky Way: Accounting for the Missing Mass?  

NASA Astrophysics Data System (ADS)

Most of the baryons from galaxies have been "missing" and several studies have attempted to map the circumgalactic medium (CGM) of galaxies in their quest. We report on X-ray observations made with the Chandra X-Ray Observatory probing the warm-hot phase of the CGM of our Milky Way at about 106 K. We detect O VII and O VIII absorption lines at z = 0 in extragalactic sight lines and measure accurate column densities using both K? and K? lines of O VII. We then combine these measurements with the emission measure of the Galactic halo from literature to derive the density and the path length of the CGM. We show that the warm-hot phase of the CGM is massive, extending over a large region around the Milky Way, with a radius of over 100 kpc. The mass content of this phase is over 10 billion solar masses, many times more than that in cooler gas phases and comparable to the total baryonic mass in the disk of the Galaxy. The missing mass of the Galaxy appears to be in this warm-hot gas phase.

Gupta, A.; Mathur, S.; Krongold, Y.; Nicastro, F.; Galeazzi, M.

2012-09-01

326

Tight gas field, reservoir, and completion analysis of the United States. Volume 1. Project summary. Topical report, November 1, 1991-May 31, 1992  

SciTech Connect

Tight gas fields, reservoirs, and completions have been identified in all non-Appalachian U.S. basins containing tight formation designations specified by the Federal Energy Regulatory Commission. A total of 909 fields containing 1,643 tight reservoirs and 37,074 tight gas completions have been identified (through 1988). Non-Appalachian tight production increased from 0.88 Tcf per year in 1970 to 1.71 Tcf per year in 1985 before declining slightly to 1.65 Tcf in 1988. Tight ultimate recovery (cumulative production plus proven reserves) is estimated to be 52.3 Tcf. Evaluation includes basin and formation level evaluation of completion counts, production, ultimate recovery, field size distribution and well density.

Hugman, R.H.; Springer, P.S.; Vidas, E.H.

1992-05-01

327

Tight gas field, reservoir, and completion analysis of the United States. Volume 2. Output tables. Topical report, November 1, 1991-May 31, 1992  

SciTech Connect

Tight gas fields, reservoirs, and completions have been identified in all non-Appalachian U.S. basins containing tight formation designations specified by the Federal Energy Regulatory Commission. A total of 909 fields containing 1,643 tight reservoirs and 37,074 tight gas completions have been identified (through 1988). Non-Appalachian tight production increased from 0.88 Tcf per year in 1970 to 1.71 Tcf per year in 1985 before declining slightly to 1.65 Tcf in 1988. Tight ultimate recovery (cumulative production plus proven reserves) is estimated to be 52.3 Tcf. Evaluation includes basin and formation level evaluation of completion counts, production, ultimate recovery, field size distribution and well density.

Hugman, R.H.; Springer, P.S.; Vidas, E.H.

1992-05-01

328

Impact of Shallow Convection on the Gas Hydrate Reservoir in the Gulf of Mexico Salt Tectonics Province  

NASA Astrophysics Data System (ADS)

Previous modeling studies have suggested that subseafloor hydrogeology in the northern Gulf of Mexico could be strongly affected by the presence of salt domes, but these efforts were at the time limited to formulations that decoupled thermal and chemical buoyancy. The earlier studies concluded that downwelling associated with the negative buoyancy of dense briny fluids dominated upwelling associated with positive thermal buoyancy near salt domes. In this study, we use modern hydrologic models that fully couple thermal and chemical effects to re-examine this problem with particular focus on Gulf of Mexico gas hydrate reservoirs. We first demonstrate that even slight variations in seafloor bathymetry lead to the onset of shallow convection in marine sediments and that the existence of such convective patterns is not dependent on the presence of salt or the geometry of the salt body. Bathymetric highs are generally the loci of upwelling, while downwelling is concentrated in bathymetric lows. The length scale of the convective cells depends on the wavelength of seafloor topography but is generally hundreds to less than 2000 m, consistent with observational evidence one of us has earlier reported for the Mississippi Canyon and Garden Banks gas hydrate areas. The model calculations are consistent with the observed pattern of chloride, sulfate, and thermal anomalies, suggesting that the modeling results can be used to estimate the variation in the depth of hydrate stability and hydrate occurrence in these highly dynamic systems. Our simulations of the transient evolution of convective regimes near salt domes show that the near-surface, thermally-driven system eventually separates from the deeper, chemically-driven system dominated by stable, dense brines. In this scenario, the gas hydrate stability zone will change as a function of time due to the changing hydraulic regime in the sediments. Superposed on such hydraulic effects on the hydrate stability zone would be the influence of better understood processes such as sedimentation or erosion of the sedimentary column. Finally, we explicitly consider the role of faults in focusing fluids in these systems and conclude that faults can radically perturb the chemical and thermal conditions near salt domes to the point of entirely dominating the flow field and thus the gas hydrate stability field. The results are applied to zones of focused flux, such as the mud mounds in the Garden Banks and Mississippi Canyon areas and the seeps at Bush Hill, and to a zone of 'diffuse advective flux' characterized by a regional BSR at Keathley Canyon.

Wilson, A.; Ruppel, C.

2005-12-01

329

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

330

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

331

CHARACTERIZING MARINE GAS-HYDRATE RESERVOIRS AND DETERMINING MECHANICAL PROPERTIES OF MARINE GAS-HYDRATE STRATA WITH 4-COMPONENT OCEAN-BOTTOM-CABLE SEISMIC DATA  

SciTech Connect

The technical approach taken in this gas-hydrate research is unique because it is based on applying large-scale, 3-D, multi-component seismic surveys to improve the understanding of marine gas-hydrate systems. Other gas-hydrate research uses only single-component seismic technology. In those rare instances when multi-component seismic data have been acquired for gas-hydrate research, the data acquisition has involved only a few receiver stations and a few source stations, sometimes only three or four of each. In contrast, the four-component, 3-D, ocean-bottom-cable (4C3D OBC) data used in this study were acquired at thousands of receiver stations spaced 50 m apart over an area of approximately 1,000 km{sup 2} using wavefields generated at thousands of source stations spaced 75 m apart over this same survey area. The reason for focusing research attention on marine multi-component seismic data is that 4C3D OBC will provide a converted-SV image of gas-hydrate systems in addition to an improved P-wave image. Because P and SV reflectivities differ at some stratal surfaces, P and SV data provide two independent, and different, images of subsurface geology. The existence of these two independent seismic images and the availability of facies-sensitive SV seismic attributes, which can be combined with conventional facies-sensitive, P-wave seismic attributes, means that marine gas-hydrate systems should be better evaluated using multi-component seismic data than using conventional single-component seismic data. Conventional seismic attributes, such as instantaneous reflection amplitude and reflection coherency, have been extracted from the P and SV data volumes created from the 4C3D OBC data used in this research. Comparisons of these attributes and comparisons of P and SV time slices and vertical slices show that SV data provide a more reliable image of stratigraphy and structure associated with gas-invaded strata than do P-wave data. This finding confirms that multi-component seismic data will be more valuable than conventional P-wave seismic data for exploiting gas-hydrate reservoirs that cause gas invasion into surrounding strata. Published laboratory studies have shown that the ratio of P-wave velocity (V{sub p}) and SV velocity (V{sub s}) is an important parameter for identifying lithofacies. (In this report, the subscript S that accompanies a parameter can be replaced with the subscript SV to more accurately define the type of shear wave data used in this study.) Seismic estimates of V{sub p}/V{sub s} can be made when multi-component seismic data are acquired. Seismic-based V{sub p}/V{sub s} ratios are being analyzed across the research study area to determine what types of shallow lithofacies can be distinguished by this velocity parameter. These research findings will be summarized in the final project report.

B.A. Hardage; M.M. Backus; M.V. DeAngelo; R.J. Graebner; P. Murray; L.J. Wood assisted by K. Rogers

2002-01-01

332

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

333

Structural evolution of the Pematang Reservoirs, Kelabu-Jingga Gas Fields, Sumatra  

SciTech Connect

The Kelabu-Jingga area, located in the Kiri trough of the central Sumatra Basin, produces gas from the Paleogene Pematang Group. The Pematang Group consists of sandstones, claystones, organic-rich shales, and conglomerates deposited in fluvial and fresh-water deltaic and lacustrine environments. Deposition occurred during a regional extensional tectonic event that resulted from a major plate reorganization in the Pacific and Indian oceans 43 m.y. Subsequent rifting and basin development occurred in the Kiri Trough area in central Sumatra. Deposition of the Pematang Group during active extension resulted in lateral discontinuity of individual sand members. Syngenetic listric faults and associated [open quotes]rollover[close quotes] formed during rifting. During the Neogene, oblique convergence resulted in a regional transpressional event, which overprinted the earlier extensional style of faulting. In the Kiri Trough area, both extensional and transpressional features are evident. A Jingga Kelabu 3-D seismic survey combined with wireline logs (including dipmeter and FMS data) and core provides geological information useful for identifying both faults and depositional trends within the Pematang Group. The resultant maps and cross sections show hydrocarbon reserves and new drilling opportunities in the Kelabu-Jingga fields.

Laing, J.E.; Atmodipurwo, S.P.; Rauf, A. (PT Caltex Pacific Indonesia, Sumatra (Indonesia))

1994-07-01

334

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

335

Experimental study on rock-water interaction due to CO2 injection under in-situ P-T condition of the Altmark gas reservoir, Germany  

NASA Astrophysics Data System (ADS)

CO2 sequestration in depleted gas reservoir is an economically feasible option to mitigate global warming. The Altmark gas reservoir, located in the western part of the northeast German basin, was selected for enhanced gas recovery (EGR) by injecting CO2. Under reservoir conditions (50 bars and 125°C), the injected CO2 has very high solubility leading to subsequent dissolution and precipitation of minerals of the surrounding rock matrix. Therefore, the main objective of the current study is to investigate the geochemical changes in fluid composition due to dissolution of minerals under controlled laboratory conditions. Dry sandstone sample from the Altmark reservoir was mounted in an autoclave system and flushed by a pre-equilibrated mixture of water saturated with CO2 at a constant flow rate at 50 bars and 125°C. The experiment was conducted for 100 hours during which fluid samples were collected at regular intervals and analyzed by Ion Chromatography (IC) and Inductively Coupled Plasma Optical Emission Spectroscopy (ICP-OES). pH was also measured in partially de-gassed samples. Fluid analysis showed an increased concentration of Ca and SO4 at the beginning of the reaction time indicating the early dissolution of anhydrite. However, the Ca/SO4 molar ratio (>1) proved the dissolution of both calcite and anhydrite. The source of Na and K could be the dissolution of feldspars (albite and K-feldspar). Low concentrations of these two elements reflect the lower solubility and slow dissolution kinetics of feldspar minerals. Moreover, trace amounts of Mn, Mg, Zn, Cu and Fe might be derived from the dissolution of trace minerals in the sandstone. Besides, thermodynamic calculations of mineral saturation indices enabled an evaluation of the CO2-water-rock interactions and highlighted the dissolution of the Ca-bearing minerals in the studied solution.

Huq, F.; Blum, P.; Nowak, M.; Haderlein, S.; Grathwohl, P.

2012-04-01

336

A detailed view of the injection-induced seismicity in a natural gas reservoir in Zigong, southwestern Sichuan Basin, China  

NASA Astrophysics Data System (ADS)

at a gas reservoir located in the relatively stable Sichuan Basin, China, mirrors the injection pressure of unwanted water, suggesting that the seismicity is injection induced. Injection under high pressure on a routine basis began on 9 January 2009 and continued to July 2011. During the injection period, over 120,000 m3 of water was pumped under a wellhead pressure of up to 6.2 MPa into the limestone formation of Permian 2.45 to 2.55 km beneath the surface. The injection induced more than 7000 surface-recorded earthquakes, including 2 M4+ (the largest one was ML4.4), 20 M3+, and more than 100 M2+ events. Data observed by a nearby local seismic network and five temporal stations provide a detailed view of the spatiotemporal distribution of the induced earthquakes. Most events were limited to depths ranging from 2.5 to 4 km, which is consistent with the limestone formation of Permian. In a map view, hypocenters are concentrated in a NNW extended ellipsoidal zone approximately 6 km long and approximately 2 km wide centered approximately at the injection well. Multisources of evidence such as the shear mechanism, pattern of hypocenter distribution, and small elevated pore pressure as compared with the least principal stress in the region show that the induced earthquakes occurred as a result of lowering of the effective normal stress on known or unknown preexisting blind faults which are critically loaded under the regional stress field. Epidemic-type aftershock sequence modeling results indicate that injection inducing and earthquake triggering are both important during earlier periods of injection, while later periods are dominated by forced (injection-induced) seismicity.

Lei, Xinglin; Ma, Shengli; Chen, Wenkang; Pang, Chunmei; Zeng, Jie; Jiang, Bing

2013-08-01

337

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

SciTech Connect

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{sub 2} 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 and mineral alteration are induced in the caprock by penetration of high CO{sub 2} concentrations from the underlying reservoir, where it was assumed that large amounts of CO{sub 2} have already been injected at depth. The main focus is on the potential effect of precipitation and dissolution processes on the sealing efficiency of caprock formations. Concerns that some leakage may occur in the investigated system arise because the seal is made up of potentially highly-reactive rocks, consisting of carbonate-rich shales (calcite+dolomite averaging up to more than 30% of solid volume fraction). Batch simulations and multi-dimensional 1D and 2D modeling have been used to investigate multicomponent geochemical processes. Numerical simulations account for fracture-matrix interactions, gas phase participation in multiphase fluid flow and geochemical reactions, and kinetics of fluid-rock interactions. The geochemical processes and parameters to which the occurrence of high CO{sub 2} concentrations are most sensitive are investigated by conceptualizing different mass transport mechanisms (i.e. diffusion and mixed advection+diffusion). The most relevant mineralogical transformations occurring in the caprock are described, and the feedback of these geochemical processes on physical properties such as porosity is examined to evaluate how the sealing capacity of the caprock could evolve in time. The simulations demonstrate that the occurrence of some gas leakage from the reservoir may have a strong influence on the geochemical evolution of the caprock. In fact, when a free CO{sub 2}-dominated phase migrates into the caprock through fractures, or through zones with high initial porosity possibly acting as preferential flow paths for reservoir fluids, low pH values are predicted, accompanied by significant calcite dissolution and porosity enhancement. In contrast, when fluid-rock interactions occur under fully liquid-saturated conditions and a diffusion-controlled regime, pH will be buffered at higher values, and some calcite precipitation is predicted which leads to further sealing of the storage reservoir.

Xu, Tianfu; Gherardi, Fabrizio; Xu, Tianfu; Pruess, Karsten

2007-09-07

338

The conversion of oil into gas in petroleum reservoirs. Part 1: Comparative kinetic investigation of gas generation from crude oils of lacustrine, marine and fluviodeltaic origin by programmed-temperature closed-system pyrolysis  

Microsoft Academic Search

The thermal alteration of reservoired petroleum upon burial was simulated comparatively by closed-system programmed-temperature pyrolysis of produced crude oils of lacustrine, fluviodeltaic, marine clastic and marine carbonate origin using the microscale sealed vessel (MSSV) technique. Bulk kinetics of oil-to-gas cracking and accompanying compositional changes were studied at heating rates of 0.1, 0.7 and 5.0 K\\/min. The oil type related variations

H. J. Schenk; R. Di Primio; B. Horsfield

1997-01-01

339

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

340

Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. Appendix 1, Volume 1.  

National Technical Information Service (NTIS)

This volume contains maps, well logging correlated to porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plot, detailed core log, paragenetic sequence and reservoir characterization shee...

D. C. Kopaska-Merkel H. E. Moore S. D. Mann D. R. Hall

1992-01-01

341

Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. Appendix 1, Volume 3.  

National Technical Information Service (NTIS)

This volume contains maps, well logging, structural cross section, graph of production history, porosity vs. natural log permeability plots, detailed core log, paragenetic sequence, and reservoir characterization sheet for the following fields in southwes...

D. C. Kopaska-Merkel D. R. Hall H. E. Moore S. D. Mann

1992-01-01

342

Pliocene facies trends and controls on deposition of lower gusher shallow gas reservoirs, North Coles Levee Field, San Joaquin Basin, California  

SciTech Connect

Net sand isochore maps of three Pliocene-age Lower Gusher sands in the Etchegoin Formation at North Coles Levee field, southern San Joaquin basin, California display geometries suggestive of deposition in delta front settings. The north-south depositional strike of these sands approximately parallels the orientation of the paleoshoreline. The sands thicken and display greater lateral continuity near distributary channel sands, which are oriented east-northeast approximately perpendicular to the shoreline. A comparison of the isochore maps of each of the three sand bodies show that they are stacked vertically above each other, indicating that the position of the shoreline remained stationary during deposition of the Gusher interval. This apparent stillstand of the shoreline is superimposed on an overall regression of the sea from the San Joaquin basin during the Pliocene. Therefore, we believe that the Lower Gusher sands were deposited during a period of relatively rapid basin subsidence, which negated the effects of the marine regression and caused vertical aggradation of shoreline facies in the North Coles Levee area. The Lower Gusher interval at North and South Coles Levee contains the most prolific shallow gas reservoirs on the Bakersfield Arch. A thorough knowledge of depositional trends in the Lower Gusher interval increases the probability of encountering reservoir-quality facies in exploration programs focusing on Pliocene gas.

Steward, D.C.; Gillespie, J.M. (California State Univ., Bakersfield, CA (United States))

1994-04-01

343

Focused fluid flow in the Baiyun Sag, northern South China Sea: implications for the source of gas in hydrate reservoirs  

NASA Astrophysics Data System (ADS)

The origin and migration of natural gas and the accumulation of gas hydrates within the Pearl River Mouth Basin of the northern South China Sea are poorly understood. Based on high-resolution 2D/3D seismic data, three environments of focused fluid flow: gas chimneys, mud diapirs and active faults have been identified. Widespread gas chimneys that act as important conduits for fluid flow are located below bottom simulating reflections and above basal uplifts. The occurrence and evolution of gas chimneys can be divided into a violent eruptive stage and a quiet seepage stage. For most gas chimneys, the strong eruptions are deduced to have happened during the Dongsha Movement in the latest Miocene, which are observed below Pliocene strata and few active faults develop above the top of the Miocene. The formation pressures of the Baiyun Sag currently are considered to be normal, based on these terms: 1) Borehole pressure tests with pressure coefficients of 1.043-1.047; 2) The distribution of gas chimneys is limited to strata older than the Pliocene; 3) Disseminated methane hydrates, rather than fractured hydrates, are found in the hydrate samples; 4) The gas hydrate is mainly charged with biogenic gas rather than thermogenic gas based on the chemical tests from gas hydrates cores. However, periods of quiet focused fluid flow also enable the establishment of good conduits for the migration of abundant biogenic gas and lesser volumes of thermogenic gas. A geological model governing fluid flow has been proposed to interpret the release of overpressure, the migration of fluids and the formation of gas hydrates, in an integrated manner. This model suggests that gas chimneys positioned above basal uplifts were caused by the Dongsha Movement at about 5.5 Ma. Biogenic gas occupies the strata above the base of the middle Miocene and migrates slowly into the gas chimney columns. Some of the biogenic gas and small volumes of thermogenic gas eventually contribute to the formation of the gas hydrates.

Chen, Duanxin; Wu, Shiguo; Dong, Dongdong; Mi, Lijun; Fu, Shaoying; Shi, Hesheng

2013-01-01

344

Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. [Jurassic Smackover Formation  

Microsoft Academic Search

This volume contains maps, well logging, structural cross section, graph of production history, porosity vs. natural log permeability plots, detailed core log, paragenetic sequence, and reservoir characterization sheet for the following fields in southwest Alabama: North Smiths Church oil field; North Wallers Creek oil field; Northeast Barnett oil field; Northwest Range oil field; Pace Creek oil field; Palmers Crossroads oil

D. C. Kopaska-Merkel; H. E. Jr. Moore; S. D. Mann; D. R. Hall

1992-01-01

345

Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. Appendix 1, Volume 3  

Microsoft Academic Search

This volume contains maps, well logging, structural cross section, graph of production history, porosity vs. natural log permeability plots, detailed core log, paragenetic sequence, and reservoir characterization sheet for the following fields in southwest Alabama: North Smiths Church oil field; North Wallers Creek oil field; Northeast Barnett oil field; Northwest Range oil field; Pace Creek oil field; Palmers Crossroads oil

D. C. Kopaska-Merkel; H. E. Jr. Moore; S. D. Mann; D. R. Hall

1992-01-01

346

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

347

The kinetics of in-reservoir oil destruction and gas formation: constraints from experimental and empirical data, and from thermodynamics  

Microsoft Academic Search

Experimental kinetic data on the reactions of pure chemicals, destruction of heavy hydrocarbons, and gas formation have been combined with thermodynamic theory and empirical data on oil and gas occurrences to constrain the range of plausible activation energies and frequency factors for oil destruction and gas formation in nature. It is assumed explicitly here that the kinetics of oil destruction

Douglas W Waples

2000-01-01

348

Reservoir description, Walker Creek field, Arkansas  

Microsoft Academic Search

A multidisciplinary reservoir description of Walker Creek field in southern Arkansas was conducted to evaluate the field's potential and determine the best method of increasing recovery. The reservoir is within a 100-ft-thick section of the ooid grainstone facies of the Jurassic Smackover Formation. The reservoir is currently under partial pressure maintenance by reinjection of produced gas at the crest of

D. M. Bliefnick; K. M. Frey; Thu-Thuy Dang; S. M. Bissmeyer

1990-01-01

349

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

350

Sandstone Reservoirs  

Microsoft Academic Search

The Rocky Mountain province of the United States contains structural and stratigraphic traps from which petroleum is produced from all types of sandstone reservoirs ranging in age from Cambrian to the Eocene. Three large typical stratigraphic traps in this province, where reservoirs are of Cretaceous age, are described. The Cut Bank Field, Montana produces from aluvial point bar sandstones; Patrick

Robert Weimer; R. W. Tillman

1982-01-01

351

CHARACTERIZING MARINE GAS-HYDRATE RESERVOIRS AND DETERMINING MECHANICAL PROPERTIES OF MARINE GAS-HYDRATE STRATA WITH 4COMPONENT OCEAN-BOTTOM-CABLE SEISMIC DATA  

Microsoft Academic Search

The technical approach taken in this gas-hydrate research is unique because it is based on applying large-scale, 3-D, multi-component seismic surveys to improve the understanding of marine gas-hydrate systems. Other gas-hydrate research uses only single-component seismic technology. In those rare instances when multi-component seismic data have been acquired for gas-hydrate research, the data acquisition has involved only a few receiver

B. A. Hardage; M. M. Backus; M. V. DeAngelo; R. J. Graebner; P. Murray

2002-01-01

352

Reservoir gases exhibit subtle differences; Part 4  

SciTech Connect

This segment of the reservoir fluids series describes the characteristics of wet and dry gases. At an initial producing gas-oil ratio greater than 15,000 scf/STB, engineers can treat the reservoir fluid as a wet gas. Gases with initial producing gas-oil ratios greater than 100,000 scf/STB can be treated as dry gases. Retrograde behavior has been observed in gases with initial producing gas-oil ratios greater than 150,000 scf/STB. The quantity of retrograde liquid in the reservoir is very small for gases this lean. If a gas has enough heavy components to release condensate at the surface, the gas will probably release some amount of condensate in the reservoir. This implies few true wet gases exist (liquid at the surface but no liquid in the reservoir).

McCain, W.D. Jr. (S.A. Holditch and Associates, College Station, TX (United States)); Piper, L.D. (Texas A M Univ., College Station, TX (United States))

1994-03-01

353

Development of the first coal seam gas exploration program in Indonesia: Reservoir properties of the Muaraenim Formation, south Sumatra  

Microsoft Academic Search

The Late Miocene Muaraenim Formation in southern Sumatra contains thick coal sequences, mostly of low rank ranging from lignite to sub-bituminous, and it is believed that these thick low rank coals are the most prospective for the production of coal seam gas (CSG), otherwise known as coalbed methane (CBM), in Indonesia.As part of a major CSG exploration project, gas exploration

I. B. Sosrowidjojo; A. Saghafi

2009-01-01

354

Imaging of CO 2 storage sites, geothermal reservoirs, and gas shales using controlled-source magnetotellurics: Modeling studies  

Microsoft Academic Search

To balance the steady decrease of conventional hydrocarbon resources, increased utilization of unconventional and new energy resources, such as shale gas and geothermal energy, is required. Also, the geological sequestration of carbon dioxide is being considered as a technology that may temporarily mitigate the effects of CO2 emission. Sites suitable for shale gas production, geothermal exploration, or CO2 sequestration are

Rita Streich; Michael Becken; Oliver Ritter

2010-01-01

355

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  

Microsoft Academic Search

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 by Temblor Petroleum with heavy mud and conventional completions; neither was commercially productive.

George Witter; Robert Knoll; William Rehm; Thomas Williams

2005-01-01

356

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  

Microsoft Academic Search

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

George Witter; Robert Knoll; William Rehm; Thomas Williams

2005-01-01

357

Research to understand and predict geopressured reservoir characteristics with confidence  

Microsoft Academic Search

The Department of Energy's Geopressured Geothermal Program has sponsored a series of geoscience studies to resolve key uncertainties in the performance of geopressured reservoirs. The priority areas for research include improving the ability to predict reservoir size and flow capabilities, understanding the role of oil and gas in reservoir depletion and evaluating mechanisms for reservoir pressure maintenance. Long-term production from

S. G. Stiger; S. M. Prestwich

1988-01-01

358

Whitney Canyon-Carter Creek field: Gas production from carbonate reservoirs in a thrust belt structural setting, western Wyoming, USA  

Microsoft Academic Search

Located in the Fossil basin area of the Wyoming thrust belt, giant Whitney Canyon-Carter Creek field has in place reserves of approximately 4.5 tcf of gas, 125 MMBO (condensate), and 24 million long tons sulfur. It is the largest gas field in the U.S. Rocky Mountains. Hydrocarbons are trapped in large, reverse faulted anticlinal closures that formed completely within the

J. L. Sieverding; F. Jr Royse

1991-01-01

359

Reservoir engineering. Volume 2  

SciTech Connect

Forty-two papers that were presented at the SPE Annual Technical Conference and Exhibition held in New Orleans, LA, September 25-28, 1994 are included in Volume 2 (Reservoir Engineering) of the proceedings. The papers covered such topics as predicting low interfacial tensions in condensate systems, measurements at reservoir conditions and effects on gas-gravity drainage, wettability and spreading gravity drainage/waterflood interactions in Prudhoe Bay, relative permeability hysteresis, high temperature water/oil relative permeabilities, microbial profile modification using spaces, surfactant-alcohol blends for conformance control, enhanced oil recovery methods, the electrofrac heat-flood-process, stability of displacement fronts in WAG operations, displacement of oil by enriched hydrocarbon gases, bypassing during gas-floods in heterogeneous porous media, gas injection schemes, reserve estimation and analysis, material-balance methods, landfill gas projects, improved reservoir management, nitrogen injection, and validation of predicted capillary trapping mechanisms. The papers were indexed separately for inclusion in the Energy Science and Technology Database.

Not Available

1994-01-01

360

Tertiary carbonate reservoirs in Indonesia  

SciTech Connect

Hydrocarbon production from Tertiary carbonate reservoirs accounted for ca. 10% of daily Indonesian production at the beginning of 1978. Environmentally, the reservoirs appear as parts of reef complexes and high-energy carbonate deposits within basinal areas situated mainly in the back arc of the archipelago. Good porosities of the reservoirs are represented by vugular/moldic and intergranular porosity types. The reservoirs are capable of producing prolific amounts of hydrocarbons: production tests in Salawati-Irian Jaya reaches maximum values of 32,000 bpd, and in Arun-North Sumatra tests recorded 200 MMCF gas/day. Significant hydrocarbon accumulations are related to good reservoir rocks in carbonates deposited as patch reefs, pinnacle reefs, and platform complexes. Exploration efforts expand continuously within carbonate formations which are extensive horizontally as well as vertically in the Tertiary stratigraphic column.

Nayoan, G.A.S.; Arpandi; Siregar, M.

1981-01-01

361

A Handbook for the Application of Seismic Methods for Quantifying Naturally Fractured Gas Reservoirs in the San Juan Basin, New Mexico  

SciTech Connect

A four year (2000-2004) comprehensive joint industry, University and National Lab project was carried out in a 20 square mile area in a producing gas field in the Northwest part of the San Juan Basin in New Mexico to develop and apply multi-scale seismic methods for detecting and quantifying fractures in a naturally fractured gas reservoirs. 3-D surface seismic, multi-offset 9-C VSP, 3-C single well seismic, and well logging data were complemented by geologic/core studies to model, process and interpret the data. The overall objective was to determine the seismic methods most useful in mapping productive gas zones. Data from nearby outcrops, cores, and well bore image logs suggest that natural fractures are probably numerous in the subsurface reservoirs at the site selected and trend north-northeast/south-southwest despite the apparent dearth of fracturing observed in the wells logged at the site (Newberry and Moore wells). Estimated fracture spacing is on the order of one to five meters in Mesaverde sandstones, less in Dakota sandstones. Fractures are also more frequent along fault zones, which in nearby areas trend between north-northeast/south-southwest and northeast-southwest and are probably spaced a mile or two apart. The maximum, in situ, horizontal, compressive stress in the vicinity of the seismic test site trends approximately north-northeast/south-southwest. The data are few but they are consistent. The seismic data present a much more complicated picture of the subsurface structure. Faulting inferred from surface seismic had a general trend of SW - NE but with varying dip, strike and spacing. Studies of P-wave anisotropy from surface seismic showed some evidence that the data did have indications of anisotropy in time and amplitude, however, compared to the production patterns there is little correlation with P-wave anisotropy. One conclusion is that the surface seismic reflection data are not detecting the complexity of fracturing controlling the production. Conclusions from the P-wave VSP studies showed a definite 3-D heterogeneity in both P- and S-wave characteristics. The analysis of shear-wave splitting from 3D VSP data gave insight into the anisotropy structure with depth around the borehole. In the reservoir, the VSP shear-wave splitting data do not provide sufficient constraints against a model of lower symmetry than orthorhombic, so that the existence of more than one fracture set must be considered. It was also demonstrated that a VTI and orthorhombic symmetry could be well defined from the field data by analyzing shear-wave splitting patterns. The detection of shear-wave singularities provides clear constraints to distinguish between different symmetry systems. The P-wave VSP CDP data showed evidence of fault detection at a smaller scale than the surface seismic showed, and in directions consistent with a complicated stress and fracture pattern. The single well data indicated zones of anomalous wave amplitude that correlated well with high gas shows. The high amplitude single well seismic data could not be explained by well bore artifacts, nor could it be explained by known seismic behavior in fractured zones. Geomechanical and full wave elastic modeling in 2- and 3-D provided results consistent with a complicated stress distribution induced by the interaction of the known regional stress and faults mapped with seismic methods. Sophisticated modeling capability was found to be a critical component in quantifying fractures through seismic data. Combining the results with the historical production data showed that the surface seismic provided a broad picture consistent with production, but not detailed enough to consistently map complex structuring which would allow accurate well placement. VSP and borehole methods show considerable promise in mapping the scale of fracturing necessary for more successful well placement. Specific recommendations are given at which scale each method and fracture complexity is appropriate.

Majer, Ernest; Queen, John; Daley, Tom; Fortuna, Mark; Cox, Dale; D'Onfro, Peter; Goetz, Rusty; Coates, Richard; Nihei, Kurt; Nakagawa, Seiji; Myer, Larry; Murphy, Jim; Emmons, Charles; Lynn, Heloise; Lorenz, John; LaClair, David; Imhoff, Mathias; Harris, Jerry; Wu, Chunling; Urban, Jame; Maultzsch, Sonja; Liu, Enru; Chapman, Mark; Li, Xiang-Yang

2004-09-28

362

Optimize production through balanced reservoir depletion  

SciTech Connect

The author discusses how one of the most important functions of a petroleum engineer working with a particular field (or fields) is reservoir monitoring. Production reservoir monitoring is, as the name implies, watching over all aspects of the field as it is being produced and depleted. This assures the reservoir is being properly managed-in that, it is being uniformly depleted. Over-producing part of a reservoir, for whatever reason, damages the reservoir and ultimately results in excessive influx of gas, water, or both-and in poor drainage and recovery form the reservoir. Under-producing other parts of the field could result in completely undrained areas that get bypassed by water or gas. It then becomes necessary to drill new wells in those undrained area, if they can be identified, to recover that oil. This article emphasizes the importance of accurate and reliable rate tests of oil, gas, and water produced taken on a frequent and periodic basis.

Patton, L.D. (L.D. Patton and Associates, Denver, CO (US))

1989-01-01

363

Studies of earth stress and hydraulic fracturing with applications in the stimulation of unconventional-gas reservoirs  

NASA Astrophysics Data System (ADS)

The mechanics of hydraulic fracturing for enhanced gas recovery were studied. A minifrac technique for stress measurements at coal mines in the Appalachian and Rocky Mountain regions, to be used to help design fracturing techniques to recover gas from gassy coal beds is discussed. It is indicated that fracture propagation is strongly influenced by existing stresses and that the stress gradient in a nonuniform stress field may stop or turn the fracture. Field evidence shows that anisotropic rock properties due to rock fabric can be a major factor in fracture geometry and in calculated stress values.

Hanson, M.; Towse, D.

1982-09-01

364

Petrographic and reservoir features of Hauterivian (Lower Cretaceous) Shatlyk horizon in the Malay gas field, Amu-Darya basin, east Turkmenia  

SciTech Connect

Malay gas field in Amu-Darya basin, eastern Turkmenia, is located on the structural high that is on the Malay-Bagadzha arch north of the Repetek-Kelif structure zone. With 500 km{sup 2} areal coverage, 16 producing wells and 200 billion m{sup 3} estimated reserves, the field was discovered in 1978 and production began in 1987 from 2400-m-deep Hauterivian-age (Early Cretaceous) Shatlyk horizon. The Shatlyk elastic sequence shows various thickness up to 100 m in the Malay structural closure and is studied through E-log, core, petrographic data and reservoir characteristics. The Shatlyk consists of poorly indurated, reddish-brown and gray sandstones, and sandy gray shales. The overall sand-shale ratio increases up and the shales interleave between the sand packages. The reservoir sandstones are very fine to medium grained, moderately sorted, compositionally immature, subarkosic arenites. The framework grains include quartz, feldspar and volcanic lithic fragments. Quartz grains are monocrystalline in type and most are volcanic in origin. Feldspars consist of K- Feldspar and plagioclase. The orthoclases are affected by preferential alteration. The sandstones show high primary intergranular porosity and variations in permeability. Patch-like evaporate cement and the iron-rich grain coatings are reducing effects in permeability. The coats are pervasive in reddish-brown sandstones but are not observed in the gray sandstones. The evaporate cement is present in all the sandstone samples examined and, in places, follows the oxidation coats. The petrographic evidences and the regional facies studies suggest the deposition in intersection area from continental to marine nearshore deltaic environment.

Naz, H.; Ersan, A. [Turkish Petroleum Corporation, Ankara (Turkey)

1996-08-01

365

Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. [Jurassic Smackover Formation  

SciTech Connect

This volume contains maps, well log correlated to lithology, porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plots; detailed core log, porosity vs. natural permeability plot for one lithofacies, paragenetic sequence and reservoir characterization sheet for the following fields in southwest Alabama: Stave Creek oil field; Sugar Ridge oil field; Toxey oil field, Turkey Creed oil field; Turnerville oil field, Uriah oil field; Vocation oil field; Wallace oil field; Wallers Creek oil field; West Appleton oil field; West Barrytown oil field; West Bend oil field; West Okatuppa Creed oil field; Wild Fork Creek oil field; Wimberly oil field; Womack Hill oil field; and Zion Chapel oil field. (AT)

Kopasaka-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D; Hall, D.R.

1992-06-01

366

Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. Appendix 1, Volume 4  

SciTech Connect

This volume contains maps, well log correlated to lithology, porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plots; detailed core log, porosity vs. natural permeability plot for one lithofacies, paragenetic sequence and reservoir characterization sheet for the following fields in southwest Alabama: Stave Creek oil field; Sugar Ridge oil field; Toxey oil field, Turkey Creed oil field; Turnerville oil field, Uriah oil field; Vocation oil field; Wallace oil field; Wallers Creek oil field; West Appleton oil field; West Barrytown oil field; West Bend oil field; West Okatuppa Creed oil field; Wild Fork Creek oil field; Wimberly oil field; Womack Hill oil field; and Zion Chapel oil field. (AT)

Kopasaka-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D; Hall, D.R.

1992-06-01

367

Improved oil recovery from oil-wet and mixed-wet reservoirs by gas flooding, alternately with water  

Microsoft Academic Search

The Department of Petroleum Engineering at Heriot -Watt University has been studying the water alternating gas (WAG) injection processes, using experimental (micromodels) and theoretical (network modelling) methods during the past 3 years. Last year we presented to the IEA the results of the micromodel studies on water -wet systems. This paper presents the results of the experiments on oil -wet

Vienna September; D H Tehrani; A Danesh; M Sohrabi; G Henderson

368

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

369

Recovery of oil as by-product of gas-storage operations  

Microsoft Academic Search

Most natural gas-storage projects make use of gas reservoirs. This practice is usually desirable when gas reservoirs can be found at all desired locations. When none is available, other types of reservoirs are used. Gas is stored underground in oil reservoirs, aquifers, depleted mines, and as liquefied gas in man-made caverns. Gas storage in some oil reservoirs may have more

A. B. Cook; F. S. Johnson

1967-01-01

370

CO(J = 1{yields}0) IN z > 2 QUASAR HOST GALAXIES: NO EVIDENCE FOR EXTENDED MOLECULAR GAS RESERVOIRS  

SciTech Connect

We report the detection of CO(J = 1{yields}0) emission in the strongly lensed high-redshift quasars IRAS F10214+4724 (z = 2.286), the Cloverleaf (z = 2.558), RX J0911+0551 (z = 2.796), SMM J04135+10277 (z = 2.846), and MG 0751+2716 (z = 3.200), using the Expanded Very Large Array and the Green Bank Telescope. We report lensing-corrected CO(J = 1{yields}0) line luminosities of L'{sub CO} = (0.34-18.4) x 10{sup 10} K km s{sup -1} pc{sup 2} and total molecular gas masses of M(H{sub 2}) = (0.27-14.7) x 10{sup 10} M{sub sun} for the sources in our sample. Based on CO line ratios relative to previously reported observations in J {>=} 3 rotational transitions and line excitation modeling, we find that the CO(J = 1{yields}0) line strengths in our targets are consistent with single, highly excited gas components with constant brightness temperature up to mid-J levels. We thus do not find any evidence for luminous-extended, low-excitation, low surface brightness molecular gas components. These properties are comparable to those found in z > 4 quasars with existing CO(J = 1{yields}0) observations. These findings stand in contrast to recent CO(J = 1{yields}0) observations of z {approx_equal} 2-4 submillimeter galaxies (SMGs), which have lower CO excitation and show evidence for multiple excitation components, including some low-excitation gas. These findings are consistent with the picture that gas-rich quasars and SMGs represent different stages in the early evolution of massive galaxies.

Riechers, Dominik A. [Astronomy Department, California Institute of Technology, MC 249-17, 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); Maddalena, Ronald J. [National Radio Astronomy Observatory, P.O. Box 2, Green Bank, WV 24944 (United States); Hodge, Jacqueline; Walter, Fabian [Max-Planck-Institut fuer Astronomie, Koenigstuhl 17, D-69117 Heidelberg (Germany); Harris, Andrew I. [Department of Astronomy, University of Maryland, College Park, MD 20742-2421 (United States); Baker, Andrew J.; Sharon, Chelsea E. [Department of Physics and Astronomy, Rutgers, State University of New Jersey, 136 Frelinghuysen Road, Piscataway, NJ 08854-8019 (United States); Wagg, Jeff [European Southern Observatory, Alonso de Cordova 3107, Vitacura, Casilla 19001, Santiago 19 (Chile); Vanden Bout, Paul A. [National Radio Astronomy Observatory, 520 Edgemont Road, Charlottesville, VA 22903-2475 (United States); Weiss, Axel, E-mail: dr@caltech.edu [Max-Planck-Institut fuer Radioastronomie, Auf dem Huegel 69, D-53121 Bonn (Germany)

2011-09-20

371

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

372

Using three-dimensional reconstructed microstructures for predicting intrinsic permeability of reservoir rocks based on a Boolean lattice gas method  

Microsoft Academic Search

This paper presents a method for predicting the intrinsic permeability of porous media based on the integration of the local velocity field. Three-dimensional representations of the porous structure are reconstructed from two-dimensional binary images, after segmentation of digital images acquired from thin plates, commonly used in microscopy. Velocity field is calculated on these three-dimensional representations using a Boolean lattice gas

L. O. E Santos; P. C Philippi; M. C Damiani; C. P Fernandes

2002-01-01

373

Concepts relating reservoir mineralogy to reservoir interpretation, completion and economics  

SciTech Connect

Reservoir interpretation using electric logs is affected by grain density and {open_quote}irreducible water{close_quotes} saturation values. Standard assumptions used without direct well sample information is often dangerous and misleading. The grain density for {open_quotes}sandstone{close_quotes} is assumed to be 2.68 g/cc, but it may vary from 2.63 g/cc to 2.85 g/cc for Appalachian {open_quotes}sandstones{close_quotes}. Examples are shown for various reservoirs. Porosity/permeability relationships are determined by both pore size and shape. Examples of various Appalachian reservoirs are shown, demonstrating effects of diagenesis on pore sizes and shapes and the resultant permeability and irreducible water. Reservoir composition and pore size are extremely important in determining completion methods. Examples of good and poor completion methods and the resultant well production (economics) are shown for some Appalachian Basin reservoirs. Reservoir permeability as well as reservoir continuity and gas/fluid ratios are directly related to well drainage and thus well economics. Examples are shown. Reservoir type and mineralogy are sometimes consistent within a given formation, but often are quite variable. The use of an average value for reserve interpretation or average type completion for a given formation is often dangerous. Examples are shown. Electric logs have improved greatly over the past four decades, but studies of well samples and cores are still an extremely important aspect of reservoir analysis, well completion and well economics, and thus the success and economic stability of an oil and gas company.

Yedlosky, R.J. [Consulting Geologist, Fairmont, WV (United States)

1996-09-01

374

Detection and analysis of naturally fractured gas reservoirs: Multiazimuth seismic surveys in the Wind River basin, Wyoming  

SciTech Connect

Multiazimuth binning of 3-D P-wave reflection data is a relatively simple but robust way of characterizing the spatial distribution of gas-producing natural fractures. In the authors survey, data were divided into two volumes by ray azimuth (approximately perpendicular and parallel ({+-}45{degree}) to the dominant fracture strike) and separately processed. Azimuthal differences or ratios of attributes provided a rough measure of anisotropy. Improved imaging was also attained in the more coherent fracture parallel volume. A neutral network using azimuthally dependent velocity, reflective, and frequency attributes identified commercial gas wells with greater than 85% success. Furthermore, the authors were able to interpret the physical mechanisms of most of these correlations and so better generalize the approach. The apparent velocity anisotropy was compared to that derived from other P- and S-wave methods in an inset three-component survey. Prestack determination of the azimuthal moveout ellipse will best quantify velocity anisotropy, but simple two- or four-azimuth poststack analysis can adequately identify regions of high fracture density and gas yield.

Grimm, R.E.; Lynn, H.B.; Bates, C.R.; Phillips, D.R.; Simon, K.M.; Beckham, W.E.

1999-08-01

375

Physics of a Partially Ionized Gas Relevant to Galaxy Formation Simulations—The Ionization Potential Energy Reservoir  

NASA Astrophysics Data System (ADS)

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.; Jachowicz, N.

2013-07-01

376

Integral field spectroscopy of H-alpha emission in cooling flow cluster cores: disturbing the molecular gas reservoir  

Microsoft Academic Search

We present optical integral field spectroscopy of the H-alpha-luminous (>1E42\\u000aerg\\/s) central cluster galaxies in the cores of the cooling flows A1664, A1835,\\u000aA2204 and Zw8193. From the [NII]+H-alpha complex we derive 2-D views of the\\u000adistribution and kinematics of the emission line gas, and further diagnostics\\u000afrom the [SII] and [OI] lines. The H-alpha emission shows a variety of

R. J. Wilman; A. M. Swinbank

2006-01-01

377

Non-standard grain properties, dark gas reservoir, and extended submillimeter excess, probed by Herschel in the Large Magellanic Cloud  

NASA Astrophysics Data System (ADS)

Context.Herschel provides crucial constraints on the IR SEDs of galaxies, allowing unprecedented accuracy on the dust mass estimates. However, these estimates rely on non-linear models and poorly-known optical properties. Aims: In this paper, we perform detailed modelling of the Spitzer and Herschel observations of the LMC, in order to: (i) systematically study the uncertainties and biases affecting dust mass estimates; and to (ii) explore the peculiar ISM properties of the LMC. Methods: To achieve these goals, we have modelled the spatially resolved SEDs with two alternate grain compositions, to study the impact of different submillimetre opacities on the dust mass. We have rigorously propagated the observational errors (noise and calibration) through the entire fitting process, in order to derive consistent parameter uncertainties. Results: First, we show that using the integrated SED leads to underestimating the dust mass by ?50% compared to the value obtained with sufficient spatial resolution, for the region we studied. This might be the case, in general, for unresolved galaxies. Second, we show that Milky Way type grains produce higher gas-to-dust mass ratios than what seems possible according to the element abundances in the LMC. A spatial analysis shows that this dilemma is the result of an exceptional property: the grains of the LMC have on average a larger intrinsic submm opacity (emissivity index ? ? 1.7 and opacity ?abs(160 ?m) = 1.6 m2 kg-1) than those of the Galaxy. By studying the spatial distribution of the gas-to-dust mass ratio, we are able to constrain the fraction of unseen gas mass between ?10, and ?100% and show that it is not sufficient to explain the gas-to-dust mass ratio obtained with Milky Way type grains. Finally, we confirm the detection of a 500 ?m extended emission excess with an average relative amplitude of ?15%, varying up to 40%. This excess anticorrelates well with the dust mass surface density. Although we do not know the origin of this excess, we show that it is unlikely the result of very cold dust, or CMB fluctuations. Appendices are available in elctronic form at http://www.aanda.org

Galliano, F.; Hony, S.; Bernard, J.-P.; Bot, C.; Madden, S. C.; Roman-Duval, J.; Galametz, M.; Li, A.; Meixner, M.; Engelbracht, C. W.; Lebouteiller, V.; Misselt, K.; Montiel, E.; Panuzzo, P.; Reach, W. T.; Skibba, R.

2011-12-01

378

Investigation and Application on Gas-Drive Development in Ultra-low Permeability Reservoirs * * Project supported by the National Natural Science Foundation of China (Grant No. 50634020)  

Microsoft Academic Search

To select a proper displacement medium with the purpose of developing ultra-low permeability reservoirs both effectively and economically, three kinds of gases, including CO2, NG and N2, are studied through physical modeling and numerical simulation under the specified reservoir conditions. The results indicate that the oil recovery through water injection is relatively low in ultra-low permeability reservoirs, where the water

Ming-guo ZHAO; Hai-fei ZHOU; Ding-feng CHEN

2008-01-01

379

Project 5 -- Solution gas drive in heavy oil reservoirs: Gas and oil phase mobilities in cold production of heavy oils. Quarterly progress report, October 1--December 31, 1996  

SciTech Connect

In this report, the authors present the results of their first experiment on a heavy crude of about 35,000 cp. A new visual coreholder was designed and built to accommodate the use of unconsolidated sand. From this work, several clear conclusions can be drawn: (1) oil viscosity does not decrease with the evolution of gas, (2) the critical gas saturation is in the range of 4--5%, and (3) the endpoint oil relative permeability is around 0.6. However, the most important parameter, gas phase mobility, is still unresolved. Gas flows intermittently, and therefore the length effect becomes important. Under the conditions that the authors run the experiment, recovery is minimal, about 7.5%. This recovery is still much higher than the recovery of the C{sub 1}/C{sub 10} model system which was 3%. After a duplicate test, they plan to conduct the experiment in the horizontal core. The horizontal core is expected to provide a higher recovery.

Firoozabadi, A.; Pooladi-Darvish, M.

1996-12-31

380

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

381

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

382

Migration depths of juvenile Chinook salmon and steelhead relative to total dissolved gas supersaturation in a Columbia River reservoir  

USGS Publications Warehouse

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 pressure-sensing radio transmitters were monitored from boats while they were migrating between the tailrace of Ice Harbor Dam on the Snake River and the forebay of McNary Dam on the Columbia River during 1997-1999. The TDG generally decreased with distance from the tailrace of the dam and was within levels known to cause GBD signs and mortality in laboratory bioassays. Results of repeated-measures analysis of variance indicated that the mean depths of juvenile steelhead were similar throughout the study area, ranging from 2.0 m in the Snake River to 2.3 m near the McNary Dam forebay. The mean depths of yearling Chinook salmon generally increased with distance from Ice Harbor Dam, ranging from 1.5 m in the Snake River to 3.2 m near the forebay. Juvenile steelhead were deeper at night than during the day, and yearling Chinook salmon were deeper during the day than at night. The TDG level was a significant covariate in models of the migration depth and rates of each species, but no effect of fish size was detected. Hydrostatic compensation, along with short exposure times in the area of greatest TDG, reduced the effects of TDG exposure below those generally shown to elicit GBD signs or mortality. Based on these factors, our results indicate that the TDG limits of the regional spill program were safe for these juvenile salmonids.

Beeman, J. W.; Maule, A. G.

2006-01-01

383

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. Technical Progress Report.  

National Technical Information Service (NTIS)

This project was undertaken to demonstrate that oil and gas can be explored, drilled and produced safely and economically from a fractured Monterey reservoir in the Santa Maria Basin of California by employing cutting-edge horizontal and underbalanced dri...

2004-01-01

384

Volatile Flux and Composition at Yellowstone Reflects a Gas-Charged Hydrothermal System Above a Basalt-Fueled Silicic Magma Reservoir  

NASA Astrophysics Data System (ADS)

Recent papers have documented the immense volatile (CO2, S, Cl-, F-) flux from the Yellowstone Caldera. Carbon dioxide is estimated to escape diffusively through soils at a rate of 45,000 t d-1 (Werner and Brantley, 2003) compared with 137 t d-1 of Cl- released from hot springs into rivers (Hurwitz and others, 2007). These high volatile fluxes and the CO2/Cl- ratio of ~300 are inconsistent with simple degassing of a mid- or upper-crustal silicic intrusion. For example, if the estimated CO2-flux were supplied solely by a 104 km3 silicic-magma reservoir with 500 ppm dissolved CO2, the reservoir would be exhausted in ~1000 years, less than 0.1% of the longevity of the present Yellowstone volcanic field. Moreover, silicate melt inclusions in phenocrysts from erupted rhyolites contain abundant dissolved Cl- and F-, but minimal CO2 and S, the dominant effluents from the hydrothermal system. The carbon budget is explained best by dominant basalt degassing (~0.3 km3 a-1 of magma) in the lower and mid- crust, augmented by metamorphic devolatilization of limestone and other sediments, plus what can be sourced from overlying rhyolitic magma. The volatiles then pass into and through the near-surface hydrothermal system. The relative abundances of emitted CO2 and Cl- appear to require that the shallow subsurface beneath Yellowstone is gas-saturated down to >2 km. Fournier (1989) concluded that the diverse Yellowstone geothermal waters are ultimately derived from a deep parent fluid with 400 ppm Cl-. If Cl- and CO2 are emitted in proportion to their abundance in the hydrothermal system, then given the CO2/Cl- of 300, this parent fluid would contain 12 wt.% CO2 (5 mol%). Solubility constraints reveal that such fluid would be saturated with CO2-rich steam within the upper few kilometers. The presence of a compressible and expandable vapor phase has important implications for the origin and interpretation of ground-surface displacements at active calderas such as Yellowstone. Fournier RO (1989) Ann Rev Earth Planet Sci 17, 13-53. Hurwitz S, Lowenstern JB, Heasler H (2007) J Volcanol Geothermal Res 162, 149-171. Werner C, Brantley S, (2003) Geochem Geophys Geosystems 4 (7) 1061, doi:10.1029/2002GC000473.

Lowenstern, J. B.; Hurwitz, S.

2007-12-01

385

300-Myr-old magmatic CO2 in natural gas reservoirs of the west Texas Permian basin.  

PubMed

Except in regions of recent crustal extension, the dominant origin of carbon dioxide in fluids in sedimentary basins has been assumed to be from crustal organic matter or mineral reactions. Here we show, by contrast, that Rayleigh fractionation caused by partial degassing of a magma body can explain the CO2/3He ratios and delta13C(CO2) values observed in CO2-rich natural gases in the west Texas Val Verde basin and also the mantle 3He/22Ne ratios observed in other basin systems. Regional changes in CO2/3He and CO2/CH4 ratios can be explained if the CO2 input pre-dates methane generation in the basin, which occurred about 280 Myr ago. Uplift to the north of the Val Verde basin between 310 and 280 Myr ago appears to be the only tectonic event with appropriate timing and location to be the source of the magmatic CO2. Our identification of magmatic CO2 in a foreland basin indicates that the origin of CO2 in other mid-continent basin systems should be re-evaluated. Also, the inferred closed-system preservation of natural gas in a trapping structure for approximately 300 Myr is far longer than the residence time predicted by diffusion models. PMID:11201738

Ballentine, C J; Schoell, M; Coleman, D; Cain, B A

2001-01-18

386

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

387

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

388

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