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1

Heat pipe with hot gas reservoir  

NASA Technical Reports Server (NTRS)

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

Marcus, B. D.

1974-01-01

2

Midcontinent natural gas reservoirs and plays  

Microsoft Academic Search

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

1993-01-01

3

Helium production in natural gas reservoirs  

Microsoft Academic Search

About 11,000 published natural gas analyses of helium are used in the estimation of the average global scale accumulation and concentration of radiogenic helium in sediments. Simple lognormal statistics is employed to derive a net accumulation rate between 1†105 to 6.7†105 helium atoms per cubic meter of reservoir rock per second. This acccumulation rate permitted to infer an average helium

E. B. Pereira; J. A. S. Adams

1982-01-01

4

Helium production in natural gas reservoirs  

Microsoft Academic Search

About 11,000 published natural gas analyses of helium are used in the estimation of the average global scale accumulation and concentration of radiogenic helium in sediments. Simple lognormal statistics is employed to derive a net accumulation rate between 1dagger10⁵ to 6.7dagger10⁵ helium atoms per cubic meter of reservoir rock per second. This acccumulation rate permitted to infer an average helium

E. B. Pereira; J. A. S. Adams

1982-01-01

5

Monitoring gas reservoirs by seismic interferometry  

NASA Astrophysics Data System (ADS)

Ambient seismic noise can be used to image spatial anomalies in the subsurface, without the need of recordings from seismic sources, such as earthquakes or explosions. Furthermore, the temporal variation of ambient seismic noise's can be used to infer temporal changes of the seismic velocities in the investigated medium. Such temporal variations can reflect changes of several physical properties/conditions in the medium. For example, they may be consequence of stress changes, variation of hydrogeological parameters, pore pressure and saturation changes due to fluid injection or extraction. Passive image interferometry allows to continuously monitor small temporal changes of seismic velocities in the subsurface, making it a suitable tool to monitor time-variant systems such as oil and gas reservoirs or volcanic environments. The technique does not require recordings from seismic sources in the classical sense, but is based on the processing of noise records. Moreover, it requires only data from one or two seismic stations, their locations constraining the sampled target area. Here we apply passive image interferometry to monitor a gas storage reservoir in northern Italy. The Collalto field (Northern Italy) is a depleted gas reservoir located at 1500 m depth, now used as a gas storage facility. The reservoir experience a significant temporal variation in the amount of stored gas: the injection phases mainly occur in the summer, while the extraction take place mostly in winter. In order to monitor induced seismicity related to gas storage operations, a seismic network (the Collalto Seismic Network) has been deployed in 2011. The Collalto Seismic Network is composed by 10 broadband stations, deployed within an area of about 20 km x 20 km, and provides high-quality continuous data since January 1st, 2012. In this work we present preliminary results from ambient noise interferometry using a two-months sample of continuous seismic data, i.e. from October 1st, 2012, to the November 30th, 2012, a time frame when gas extraction operations took place. This work has been funded by the German BMBF "Geothecnologien" project MINE (BMBF03G0737A).

Grigoli, Francesco; Cesca, Simone; Sens-Schoenfelder, Christoph; Priolo, Enrico

2014-05-01

6

Shale Gas reservoirs characterization using neural network  

NASA Astrophysics Data System (ADS)

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

Ouadfeul, Sid-Ali; Aliouane, Leila

2014-05-01

7

Evaluation of Devonian shale gas reservoirs  

SciTech Connect

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

Vanorsdale, C.R.

1987-05-01

8

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

9

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

SciTech Connect

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

Clarkson, Christopher R [ORNL

2011-01-01

10

Slaughter Estate Unit Tertiary Miscible Gas Pilot Reservoir Description  

Microsoft Academic Search

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

Joseph Ader; Michael Stein

1984-01-01

11

[Greenhouse gas emission from reservoir and its influence factors].  

PubMed

Reservoirs are significant sources of emissions of the greenhouse gases. Discussing greenhouse gas emission from the reservoirs and its influence factors are propitious to evaluate emission of the greenhouse gas accurately, reduce gas emission under hydraulic engineering and hydropower development. This paper expatiates the mechanism of the greenhouse gas production, sums three approaches of the greenhouse gas emission, which are emissions from nature emission of the reservoirs, turbines and spillways and downstream of the dam, respectively. Effects of greenhouse gas emission were discussed from character of the reservoirs, climate, pH of the water, vegetation growing in the reservoirs and so on. Finally, it has analyzed the heterogeneity of the greenhouse gas emission as well as the root of the uncertainty and carried on the forecast with emphasis to the next research. PMID:18839604

Zhao, Xiao-jie; Zhao, Tong-qian; Zheng, Hua; Duan, Xiao-nan; Chen, Fa-lin; Ouyang, Zhi-yun; Wang, Xiao-ke

2008-08-01

12

Deliverability projection model for overpressured gas-condensate reservoirs  

SciTech Connect

During the depletion history of abnormally pressured reservoir, pressure is initially maintained by a decrease in the pore volume. The P/Z vs cumulative gas produced graph in such reservoirs shows two distinct slopes and the initial gas in place can be estimated by extrapolation of P/Z straight line after the reservoir gradient has been reduced to normal. This decrease in pore volume also results in a reduction in the effective permeability of the rock thus affecting the formation in-flow performance. In the gas-condensate reservoirs, hydrocarbon liquids drop out of the gas phase below the dewpoint pressures increasing the total liquids saturation. An increase in the liquid saturation decreases the relative permeability to gas. The paper develops a high pressure gas-condensate reservoir deliverability calculation incorporating the effect of gas permeability reduction due to a decrease in pore volume and increase in oil saturation.

Aziz, R.M.

1985-03-01

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

Viscoelastic time lapse reservoir characterization for a gas sandstone reservoir  

NASA Astrophysics Data System (ADS)

Time-lapse, or 4D, seismic technology has the potential to monitor enhanced oil recovery and to delineate bypassed hydrocarbon reserves. Characterization of time-lapse 3D seismic data is based on detecting the different reservoir conditions associated with production between two survey times. Properties are estimated from two independent seismic surveys that are performed at two different times (called the base state and the monitor state). From analysis of these observations, conclusions are drawn with respect to fluid changes in the reservoir. Full wavefield inversions based on elastic and viscoelastic parameterizations give different estimates of the seismic parameters; effects associated with parameters that are not fitted lead to biases in the seismic parameters that are fitted, and hence to errors in the subsequent estimation of the reservoir variables. Inversion of synthetic seismic data for a viscoelastic reservoir model provides estimates of changes in effective pressure (Pe) and water saturation (Sw) over time. Estimation of unique values of Pe and Sw from two independent seismic data [such as P-wave velocity (V p) and S-wave quality factor (Qs)] is theoretically feasible, if the other reservoir properties are known. In the Sw-Pe plane, the solution corresponds to a point for noise-free data and a region for noisy data.

Tiwari, Upendra Kumar

16

Application of horizontal drilling to tight gas reservoirs  

SciTech Connect

Vertical fractures and lithologic heterogeneity are extremely important factors controlling gas flow rates and total gas recovery from tight (very low permeability) reservoirs. These reservoirs generally have in situ matrix permeabilities to gas of less than 0.1 md. Enhanced gas recovery methods have usually involved hydraulic fracturing; however, the induced vertical hydraulic fractures almost always parallel the natural fracture and may not be an efficient method to establish a good conduit to the wellbore. Horizontal drilling appears to be an optimum method to cut across many open vertical fractures. Horizontal holes will provide an efficient method to drain heterogeneous tight reservoirs even in unfractured rocks. Although many horizontal wells have now been completed in coalbed methane and oil reservoirs, very few have been drilled to exclusively evaluate tight gas reservoirs. The U.S. Department of Energy (DOE) has funded some horizontal and slanthole drilling in order to demonstrate the applicability of these techniques for gas development. Four DOE holes have been drilled in Devonian gas shales in the Appalachian basin, and one hole has been drilled in Upper Cretaceous tight sandstones in the Piceance basin of Colorado. The Colorado field experiment has provided valuable information on the abundance and openness of deeply buried vertical fractures in tight sandstones. These studies, plus higher gas prices, should help encourage industry to begin to further utilize horizontal drilling as a new exploitation method for tight gas reservoirs.

Spencer, C.W. (U.S. Geological Survey, Lakewood, CO (United States)); Lorenz, J.C. (Sandia National Labs., Albuquerque, NM (United States)); Brown, C.A. (Synder Oil Co., Denver, CO (United States))

1991-03-01

17

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

18

Developments in gas reservoir research with applications to tight sandstones  

SciTech Connect

Research on tight sandstone formations emphasizes the importance of applicability to overall reservoir geology based on geologic similarities, particularly in the areas of transferring hydraulic fracturing techniques. Examples of tight gas sandstone formations are the Travis Peak and the Corcoran-Cozzette deposits. Where gas recovery depends upon the conductivity of a propped hydraulic fracturing through a tight sandstone, the magnitude of the recoverable resource base has both technical and economic uncertainties. Future geologic research will continue to gain insight into the degree of interconnectedness within the reservoir of production levels, gas/water ratios, reservoir pressure, and other parameters. 20 references, 1 table.

Finley, R.J.

1985-06-01

19

Characterization of oil and gas reservoir heterogeneity  

SciTech Connect

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

Sharma, G.D.

1992-01-01

20

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

21

Material balance for a bottom-water-drive gas reservoir  

Microsoft Academic Search

A material balance is developed for a gas reservoir in which the rising gas-water contact remains horizontal. The time-integrated cumulative water influx is introduced, which for numerical computations is sometimes more advantageous than the van Everdingen and Hurst integral. Based on the equations developed, material balance calculations of the past history of an actual gas field are carried out to

Dumore

1972-01-01

22

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

23

A reservoir simulation study of naturally fractured lenticular tight gas sand reservoirs  

SciTech Connect

This paper presents the results of parametric studies of two naturally fractured lenticular tight gas reservoirs, Fluvial E-1 and Puludal Zones 3 and 4, of the U.S. Department of Energy Multi-Well Experiment (MWX) site of Northwestern Colorado. The three-dimensional, two-phase, black oil reservoir simulator that was developed in a previous phase of this research program is also discussed and the capabilities further explored by applying it to several example problems.

Evans, R.D. (School of Petroleum and Geological Engineering, Univ. of Oklahoma, Norman, OK (US)); Lekia, S.D.L. (Unocal Science and Technology Div., Brea, CA (US))

1990-12-01

24

Modeling of Gas Production from Unconfined Hydrate Reservoirs  

NASA Astrophysics Data System (ADS)

Description of material: Large quantities of natural gas hydrates are present in marine sediments along the coastlines of many countries as well as in the arctic region. The production of gas from these naturally occurring gas hydrates is difficult due to complexity of thermodynamics and fluid flow involved in the process. This research is aimed at assessing production of natural gas from unconfined marine deposits of methane gas hydrates. An implicit, multiphase, multi-component, thermal, 3D simulator is used which can simulate formation and dissociation of hydrates in porous media in both equilibrium and kinetic modes. Three components (hydrate, methane and water) and four phases (hydrate, gas, aqueous-phase and ice) are considered. In this work we simulate depressurization and warm water flooding for gas production from hydrates in reservoirs underlain by an unconfined aquifer layer. Water flooding has been studied as a function of injection temperature, injection pressure, production pressure and degree of un-confinement. Application: In order to produce gas from hydrates economically, efficient production techniques must be developed. Experiments on hydrates are difficult to perform; feasibility of production can be found from simulations. Hydrate reservoirs associated with unconfined aquifer beneath are not uncommon. The determination of injection and production conditions for these reservoirs through simulation will help in designing the effective production techniques. Results and discussion: For the unconfined reservoirs associated with large aquifers the production by depressurization is inefficient. Water from the aquifer maintains the pressure in the reservoir except in the near-well regions. Warm water flooding is very effective in hydrate dissociation. Sensitivity of gas production to injection and production well conditions and degree of un-confinement has been studied. Significant new contribution: Production strategy for unconfined hydrate reservoirs.

Phirani, J.; Mohanty, K.; Hirasaki, G.

2008-12-01

25

Geotechnology for low-permeability gas reservoirs, 1995  

SciTech Connect

The permeability, and thus the economics, of tight reservoirs are largely dependent on natural fractures, and on the in situ stresses that both originated fractures and control subsequent fracture permeability. Natural fracture permeability ultimately determines the gas (or oil) producibility from the rock matrix. Therefore, it is desirable to be able to predict, both prior to drilling and during reservoir production, (1) the natural fracture characteristics, (2) the mechanical and transport properties of fractures and the surrounding rock matrix, and (3) the present in situ stress magnitudes and orientations. The combination of activities described in this report extends the earlier work to other Rocky Mountain gas reservoirs. Additionally, it extends the fracture characterizations to attempts of crosswell geophysical fracture detection using shear wave birefringence and to obtaining detailed quantitative models of natural fracture systems for use in improved numerical reservoir simulations. Finally, the project continues collaborative efforts to evaluate and advance cost-effective methods for in situ stress measurements on core.

Brown, S.; Harstad, H.; Lorenz, J.; Warpinski, N.; Boneau, T.; Holcomb, D.; Teufel, L.; Young, C. [Sandia National Labs., Albuquerque, NM (United States). Geomechanics Dept.

1995-06-01

26

Joule-Thomson Cooling Due to CO2 Injection into Natural Gas Reservoirs.  

National Technical Information Service (NTIS)

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....

C. M. Oldenburg

2006-01-01

27

Mantle Reservoirs From a Noble Gas Perspective  

Microsoft Academic Search

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

S. Mukhopadhyay

2007-01-01

28

Reservoir characterization of the underground gas storage "Banatski Dvor"  

NASA Astrophysics Data System (ADS)

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

Nicic Jorovic, V.

2009-04-01

29

Gas hydrate reservoir characteristics and economics.  

National Technical Information Service (NTIS)

The primary objective of the DOE-funded USGS Gas Hydrate Program is to assess the production characteristics and economic potential of gas hydrates in northern Alaska. The objectives of this project for FY-1992 will include the following: (1) Utilize indu...

T. S. Collett K. J. Bird R. C. Burruss M. W. Lee

1992-01-01

30

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

31

Geologic characterization of tight gas reservoirs. Annual report, FY 1989.  

National Technical Information Service (NTIS)

The objectives of US Geological Survey (USGS) work during FY 89 were to conduct geologic research characterizing tight gas-bearing sandstone reservoirs and their resources in the western United States. Our research has been regional in scope but, in some ...

B. E. Law

1990-01-01

32

Calculation of hydrocarbon-in-place in gas and gas-condensate reservoirs - Carbon dioxide sequestration  

USGS Publications Warehouse

The Energy Independence and Security Act of 2007 (Public Law 110-140) authorized the U.S. Geological Survey (USGS) to conduct a national assessment of geologic storage resources for carbon dioxide (CO2), requiring estimation of hydrocarbon-in-place volumes and formation volume factors for all the oil, gas, and gas-condensate reservoirs within the U.S. sedimentary basins. The procedures to calculate in-place volumes for oil and gas reservoirs have already been presented by Verma and Bird (2005) to help with the USGS assessment of the undiscovered resources in the National Petroleum Reserve, Alaska, but there is no straightforward procedure available for calculating in-place volumes for gas-condensate reservoirs for the carbon sequestration project. The objective of the present study is to propose a simple procedure for calculating the hydrocarbon-in-place volume of a condensate reservoir to help estimate the hydrocarbon pore volume for potential CO2 sequestration.

Verma, Mahendra K.

2012-01-01

33

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

Microsoft Academic Search

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

Christopher R Clarkson; Lilin He; Michael Agamalian; Yuri B Melnichenko; Maria Mastalerz; Mark Bustin; Andrzej Pawell Radlinski; Tomasz P Blach

2012-01-01

34

Greenhouse Gas Evasion from Amazon Reservoirs and Lakes  

NASA Astrophysics Data System (ADS)

Few studies of carbon dioxide or methane evasion from Amazon lakes or reservoirs span a full year and include multiple stations and local meteorological data. Based on measurements in Lake Curuai, a large floodplain lake in the lower Amazon basin, made at 71 to 74 stations during the four hydrological phases of inundation and draining, we illustrate the spatial patterns associated with proximity to the shore and to inflows. Carbon dioxide exchange with the atmosphere was calculated based on three gas exchange models. Values computed using equations based on wind and buoyancy flux averaged 85% higher than those based only on wind. Estimates using a surface renewal model depended upon the mixed layer depth. Carbon dioxide and methane concentrations and evasion to the atmosphere were sampled over a year from multiple stations in Balbina Reservoir and downstream in the Uatuma River. In addition, samples and evasion measurements were made during four periods in the Samuel, Tucurui and Curua-Una reservoirs and downstream rivers. Degassing can be important as water passes through hydroelectric turbines, and we developed a sampler designed to avoid losses during the collections near the depth of the turbines. For depths greater than 20 m, carbon dioxide and methane concentrations in water samples collected with new sampler averaged 34% and 116% higher than those collected with a standard sampler, respectively. Annual greenhouse gas emission from Balbina Reservoir plus downstream evasion, including the carbon dioxide equivalent of methane emissions, was estimated as 3 Tg C per year.

Melack, J. M.; Kemenes, A.; Rudorff, C.; Forsberg, B.; MacIntyre, S.

2011-12-01

35

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

NASA Astrophysics Data System (ADS)

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

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

2014-05-01

36

Seismic resolution enhancement for tight-sand gas reservoir characterization  

Microsoft Academic Search

This is a case study on the application of inverse-Q filtering to improve the resolution of 3D seismic data, for the characterization of tight-sand gas reservoirs. When seismic waves propagate through multiple tight-sand layers in the subsurface media, the energy of high-frequency components is absorbed, and the wavelet shape is distorted. Stabilized inverse-Q filtering is able to simultaneously compensate the

Qigang Gan; Duo Xu; Jianming Tang; Yanghua Wang

2009-01-01

37

Calculation of minimum miscibility pressure for gas condensate reservoirs  

Microsoft Academic Search

This work focuses on analytical calculation of MMP for gas condensate reservoirs. For the sake of simplicity, the method outlined by Wang [Y. Wang, Doctoral Dissertation, Stanford University, USA, 1998] and pseudo-components are used for calculating MMP. We evaluated this method using the Peng–Robinson EOS, Patel–Teja EOS, Patel–Teja–Valderrama EOS, and the Esmaeilzadeh–Roshanfekr EOS and compared it with the experimental data.

F. Esmaeilzadeh; M. Roshanfekr

2006-01-01

38

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

NASA Astrophysics Data System (ADS)

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

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

2008-12-01

39

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

40

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

41

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

Microsoft Academic Search

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

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

42

Naturally fractured tight gas reservoir detection optimization. Final report  

SciTech Connect

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

NONE

1997-11-19

43

Reservoir and stimulation analysis of a Devonian shale gas field  

SciTech Connect

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

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

1989-11-01

44

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

45

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

Microsoft Academic Search

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

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

2010-01-01

46

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

Microsoft Academic Search

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

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

2010-01-01

47

Borehole Stability Analysis of Horizontal Drilling in Shale Gas Reservoirs  

NASA Astrophysics Data System (ADS)

Serious wellbore instability occurs frequently during horizontal drilling in shale gas reservoirs. The conventional forecast model of in situ stresses is not suitable for wellbore stability analysis in laminated shale gas formations because of the inhomogeneous mechanical properties of shale. In this study, a new prediction method is developed to calculate the in situ stresses in shale formations. The pore pressure near the borehole is heterogeneous along both the radial and tangential directions due to the inhomogeneity in the mechanical properties and permeability. Therefore, the stress state around the wellbore will vary with time after the formation is drained. Besides, based on the experimental results, a failure criterion is verified and applied to determine the strength of Silurian shale in the Sichuan Basin, including the long-term strength of gas shale. Based on this work, horizontal well borehole stability is analyzed by the new in situ stress prediction model. Finally, the results show that the collapse pressure will be underestimated if the conventional model is used in shale gas reservoirs improperly. The collapse pressure of a horizontal well is maximum at dip angle of 45°. The critical mud weight should be increased constantly to prevent borehole collapse if the borehole is exposed for some time.

Yuan, Jun-Liang; Deng, Jin-Gen; Tan, Qiang; Yu, Bao-Hua; Jin, Xiao-Chun

2013-09-01

48

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

49

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

50

Unconventional gas sources. Volume I. Executive summary. [Coal seams, black shale, geopressured brines, tight reservoirs  

SciTech Connect

An analysis was made of potential natural gas recovery from coal seams, Devonian shale, geopressured brines, and tight gas reservoirs. It was concluded that natural gas from coal seams, Devonian shale, and tight gas reservoirs could make a significant contribution to future US gas supply. At the $5.00/MMBtu gas price level and a 10% real ROR after tax, the total unconventional reserve additions between 1981 and 2000 would average 14 TCF per year. (DLC)

Not Available

1980-01-01

51

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

52

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

EIA Publications

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

Information Center

2010-05-11

53

Joule-Thomson cooling due to CO 2 injection into natural gas reservoirs  

Microsoft Academic Search

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 or heating that accompanies the expansion of a real gas. During CO2 injection into a natural gas

Curtis M. Oldenburg

2007-01-01

54

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

55

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

56

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

57

a Review of Hydropower Reservoir and Greenhouse Gas Emissions  

NASA Astrophysics Data System (ADS)

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

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

2013-05-01

58

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

USGS Publications Warehouse

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

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

1979-01-01

59

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

60

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

61

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

NASA Astrophysics Data System (ADS)

Established a well testing model for MFHW in shale gas reservoirs.The desorption, diffusion, viscous flow and stress-sensitivity were considered.Multiple mechanisms are simultaneously incorporated into the well testing model.Plotted the perfect typical curves of MFHW in shale gas reservoirs.Analyzed the characteristics of typical curves based flow mechanisms.

Wang, Hai-Tao

2014-03-01

62

Analysis of Flow of Gas and Water in a Low Permeability Reservoir  

Microsoft Academic Search

We modified Black Oil Applied Simulation Tool ( BOAST) Program for gas reservoirs, and successfully applied it to simulate production of gas from low permeability reservoirs. Our modification results in significant decrease in computational time and storage requirements, and allows us to reduce the designated grid blocks to the size of the high permeability zone and even the fracture. Pressure

HAMID ARASTOOPOUR; SHYH-TSUNG CHEN; M. H. HARIRI

1988-01-01

63

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

64

Reservoir controls on the occurrence and production of gas hydrates in nature  

USGS Publications Warehouse

modeling has shown that concentrated gas hydrate occurrences in sand reservoirs are conducive to existing well-based production technologies. The resource potential of gas hydrate accumulations in sand-dominated reservoirs have been assessed for several polar terrestrial basins. In 1995, the U.S. Geological Survey (USGS) assigned an in-place resource of 16.7 trillion cubic meters of gas for hydrates in sand-dominated reservoirs on the Alaska North Slope. In a more recent assessment, the USGS indicated that there are about 2.42 trillion cubic meters of technically recoverable gas resources within concentrated, sand-dominated, gas hydrate accumulations in northern Alaska. Estimates of the amount of in-place gas in the sand dominated gas hydrate accumulations of the Mackenzie Delta Beaufort Sea region of the Canadian arctic range from 1.0 to 10 trillion cubic meters of gas. Another prospective gas hydrate resources are those of moderate-to-high concentrations within sandstone reservoirs in marine environments. In 2008, the Bureau of Ocean Energy Management estimated that the Gulf of Mexico contains about 190 trillion cubic meters of gas in highly concentrated hydrate accumulations within sand reservoirs. In 2008, the Japan Oil, Gas and Metals National Corporation reported on a resource assessment of gas hydrates in which they estimated that the volume of gas within the hydrates of the eastern Nankai Trough at about 1.1 trillion cubic meters, with about half concentrated in sand reservoirs. Because conventional production technologies favor sand-dominated gas hydrate reservoirs, sand reservoirs are considered to be the most viable economic target for gas hydrate production and will be the prime focus of most future gas hydrate exploration and development projects.

Collett, Timothy S.

2014-01-01

65

Joule-Thomson Cooling Due to CO2 Injection into Natural GasReservoirs  

Microsoft Academic Search

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

Curtis M

2006-01-01

66

Reservoir engineering. Pt. 84. How to find original dry gas in place by material balance with no water drive  

Microsoft Academic Search

In this problem, a dry gas reservoir has a gas saturated pore volume of 90 x 10U9D cu ft. The available geological information shows that the reservoir has no water drive. Reservoir temperature is 230$F. Production history is given by tabulated data. Solution of the problem involves finding initial gas in place by material balance. The material balance equation for

Guerrero

1965-01-01

67

Reevaluation of the Reservoir Gas Sands of Rashidpur Gas Field: A Case Study  

NASA Astrophysics Data System (ADS)

Rashidpur Gas Field is located in the west of Srimongal in East Central Bangladesh. The accumulation associated with the Miocene Bhuban-Boka Bil Sandstone Reservoirs in a structural trap. The structure is about 35 km long and 7 km wide with amplitude of some 4900 ft. Rashidpur anticline is a sub-meriodinal axis, elongated, asymmetrical doubly plunging anticline which has two pay sands namely Upper Gas Sand (UGS) and Lower Gas Sand (LGS) indicated in all four wells drilled in the structure. After penetrating the shalebsection beneath LGS, drilling plan was rescheduled to a depth of 9200 ft in order to investigate the deeper sands of potential hydrocarbon accumulation. On reaching a depth of 10073 ft a sudden kick occurred, which halted the drilling operation and forced to kill the well. An immediate sidetrack well (4521 ft) was drilled at Well-4 and an existence of a sealing fault was drawn on the final report. But mud logs of Well-3 and Well-4 based on the hydrocarbon component of UGS and LGS clearly indicate the absence of any fault between Well-3 and Well-4. Recent geological investigation in the study area reveals the updated facts on the two wells of Rashidpur Gas Field. The paper analyses mud logs and other geological data and reevaluates the reservoir gas sands of Rashidpur Gas Field.

Eahsanul Haque, Akm; Ahmed, Nur

2010-05-01

68

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

Microsoft Academic Search

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

Daniel J. K. Ross; R. Marc Bustin

2009-01-01

69

H 2S-producing reactions in deep carbonate gas reservoirs: Khuff Formation, Abu Dhabi  

Microsoft Academic Search

The economic viability of gas production from deep reservoirs is often limited by the presence of hydrogen sulphide (H2S) thought to be the result of thermochemical sulphate reduction (TSR). This study constrains the reactions responsible for the origin of H2S-rich gas in a classic sour gas province: the Permian Khuff Formation of Abu Dhabi. In reservoirs hotter than 140°C, anhydrite

R. H. Worden; P. C. Smalley

1996-01-01

70

Use of compositional simulation in the management of Arun gas condensate reservoir  

SciTech Connect

This paper describes the simulation of the Arun gas condensate reservoir using a fully compositional simulator, COSMOS (COmpositional System Mobil Oil Simulator). The reservoir is a Miocene carbonate reef complex which occurs at a depth of approximately 10,000 feet, and is up to 1,000 feet thick in some areas. The Arun reservoir is a compositionally dynamic system. The purpose of this simulation study was to predict future reservoir performance under various demand scenarios and optimize gas and NGL recovery. The simulation model utilizes the Peng-Robinson equation of state to account for the compositionally dynamic behavior of the reservoir in predictions of future performance. The equation of state was modified to incorporate special features for Arun such as water vaporization in the reservoir under high temperature conditions.

Sutan-Assin, T.; Rastogi, S.C.; Abdullah, M. (Mobil Oil Indonesia (ID)); Hidayat, D. (BKKA - Pertamina (ID)); Bette, S.; Heineman, R.F. (Mobil R and D Corp. (US))

1988-01-01

71

CO2 Utilization and Storage in Shale Gas Reservoirs  

NASA Astrophysics Data System (ADS)

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

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

2013-12-01

72

Competent and practical approach to well testing and analysis in tight gas reservoirs  

SciTech Connect

Two types of pre-test perturbations inflicted upon a tight gas reservoir were investigated. The first involved water base fluid invasion and the second assumed that an unmeasured quantity of gas was lost prior to well testing. The direct effects of these perturbations on the derivation of permeability from drill stem tests and pre-frac tests were investigated and the subsequent effects on post-frac tests are discussed. Four different reservoir gas permeabilities were studied. A three phase, three dimensional, fully implicit reservoir simulator, was used to model the various cases. 12 refs.

Branagan, P.; Cotner, G.

1982-01-01

73

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

SciTech Connect

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

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

1996-07-01

74

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

Microsoft Academic Search

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

Mancini

1990-01-01

75

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

Microsoft Academic Search

The objective of this project is to augment the National Reservoir Database (TORIS database), to increase our understanding of how geologic heterogeneity affects the recovery 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

Mancini

1991-01-01

76

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

Microsoft Academic Search

The objective of this project is 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. This objective will be achieved through detailed geological, geostatistical, and engineering

Mancini

1989-01-01

77

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

Microsoft Academic Search

The objective of this project is 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. This objective will be achieved through detailed geological, geostatistical, and engineering

Mancini

1990-01-01

78

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

Microsoft Academic Search

The objective of this project is to augment the National Reservoir Database (TORIS database) and to increase our understanding of geologic heterogeneities that effect 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. This objective will be achieved through detailed geological, geostatistical, or engineering

Mancini

1990-01-01

79

Seismic resolution enhancement for tight-sand gas reservoir characterization  

NASA Astrophysics Data System (ADS)

This is a case study on the application of inverse-Q filtering to improve the resolution of 3D seismic data, for the characterization of tight-sand gas reservoirs. When seismic waves propagate through multiple tight-sand layers in the subsurface media, the energy of high-frequency components is absorbed, and the wavelet shape is distorted. Stabilized inverse-Q filtering is able to simultaneously compensate the amplitude and correct the phase of seismic waveforms. After application to 3D seismic data, the frequency bandwidth has been increased by about 10 Hz, and the width of the wavelet has been narrowed, so that we are able to identify reflections of thin sand layers clearly. Due to the phase correction in inverse-Q filtering, filtered seismic traces can match the synthetic traces at well locations. Because of the high signal-to-noise ratio with the stabilization scheme, low-amplitude zones of interest corresponding to target high-fracture areas can be easily identified, and the detail within the anomalies can also be observed. Finally, spatial variations of tight-sand layers are depicted in the inversion profile with high resolution.

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

2009-03-01

80

Monitoring underground gas storage in a fractured reservoir using time lapse vsp.  

National Technical Information Service (NTIS)

This paper reports on time lapse VSP study in a naturally fractured reservoir used for underground gas storage. Four 9-component VSPS were acquired along with a walkaway and then repeated after the reservoir properties changed. The initial survey was cond...

T. M. Daley M. A. Feighner E. L. Majer

2000-01-01

81

Production of Natural Gas and Fluid Flow in Tight Sand Reservoirs  

Microsoft Academic Search

This document reports progress of this research effort in identifying possible relationships and defining dependencies between macroscopic reservoir parameters strongly affected by microscopic flow dynamics and production well performance in tight gas sand reservoirs. Based on a critical review of the available literature, a better understanding of the main weaknesses of the current state of the art of modeling and

Maria Cecilia Bravo; Mariano Gurfinkel

2005-01-01

82

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

Microsoft Academic Search

We thank Friedman (1996) for his useful discussion comparing Beekmantown rocks from New York state with the Beekmantown rocks in Quebec. The objective of our paper (Dykstra and Longman, 1995) was to discuss the gas reservoir potential of the Beekmantown Group in Quebec and compare it to areas of analogous production, namely the Arbuckle reservoir in the Wilburton field in

J. C. F. Dykstra; M. W. Longman

1996-01-01

83

Insights and Contributions from the Multiwell Experiment: A Field Laboratory in Tight Gas Sandstone Reservoirs.  

National Technical Information Service (NTIS)

The U.S. Department of Energy's Multiwell Experiment (MWX) has led to insights and contributions into the technology for natural gas production from low permeability sandstones reservoirs in the western United States. Three wells, between 110 and 215 ft (...

D. A. Northrop K. H. Frohne

1988-01-01

84

Facies, faults and potential sweet spots in a tight gas reservoir: Almond Formation, Wyoming  

Microsoft Academic Search

The Almond Formation is a major producer of gas in southwestern Wyoming. Although exploration generally is aimed at finding conventional reservoirs in upper Almond marine sandstones, the majority of Almond gas is contained in the underlying main Almond, a succession of dominantly non-marine, interbedded tight sandstones, siltstones, carbonaceous shales and coals. Production data indicate that some of the best gas

R. Martinsen; W. Iverson; R. Surdam

1996-01-01

85

Discussion of case study of a stimulation experiment in a fluvial, tight-sandstone gas reservoir  

SciTech Connect

The authors found Warpinski et al.'s paper (Case Study of a Stimulation Experiment in Fluvial, Tight-Sandstone Gas Reservoir. Nov. 1990 SPE Production Engineering, Pages 403-10) to be very thorough and informative. That paper considered geological, logging, completion, and pressure-transient data to produce a comprehensive formation evaluation of a fluvial, tight-sandstone gas reservoir. The purpose of this paper is to present the author's view on the peculiar pressure-transient responses shown.

Azari, M.; Wooden, W. (Halliburton Reservoir Services (GB))

1991-08-01

86

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

Microsoft Academic Search

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

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

2009-01-01

87

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

USGS Publications Warehouse

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

Spencer, Charles, W.

1985-01-01

88

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

89

A New Technology for the Exploration of Shale Gas Reservoirs  

Microsoft Academic Search

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

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

2011-01-01

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

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

93

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

Microsoft Academic Search

Natural gas hydrates, a type of inclusion compound or clathrate, are composed of gas molecules trapped within a cage of water molecules. The occurrence of gas hydrates in permafrost regions has been confirmed by core samples recovered from the Mallik gas hydrate research wells located within Mackenzie Delta in Northwest Territories of Canada. Strong vertical variations of compressional and shear

Jun-Wei Huang; G. Bellefleur; B. Milkereit

2008-01-01

94

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

Microsoft Academic Search

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

Karl-Heinz Frohne; James Mercer

1984-01-01

95

Pore-scale mechanisms of gas flow in tight sand reservoirs  

Microsoft Academic Search

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

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

2010-01-01

96

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

97

Attic oil reservoir recovery method. [includes inspection of water excluding agent into well bore viscinity after its gas injection  

Microsoft Academic Search

In a conventional attic oil reservoir recovery program wherein gas is injected through a well into an attic reservoir, the gas then migrating updip and displacing oil downward to the producing interval in the well wherefrom the oil is then produced, the improvement is added wherein at the completion of the gas injection step, a water excluding agent is injected

Clauset

1980-01-01

98

Jia2 Member doloarenite reservoir in the Moxi gas field, middle Sichuan Basin  

Microsoft Academic Search

Based on analysis on the macroscopic and microcosmic features of doloarenite in C layer, sub-member 2, Jia-2 Member of the Jialingjiang Formation in the Moxi gas field, the genetic mechanism of favorable reservoirs in beach facies carbonate rock is established. Primary inter-granular pores are the main reservoir spaces in the beach facies carbonates, and have the following key characteristics and

Tan Xiucheng; Luo Bing; Li Zhuopei; Ding Xiong; Nie Yong; Wu Xingbo; Zou Juan; Tang Qingsong

2011-01-01

99

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

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

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

102

Production of Natural Gas and Fluid Flow in Tight Sand Reservoirs  

SciTech Connect

This document reports progress of this research effort in identifying possible relationships and defining dependencies between macroscopic reservoir parameters strongly affected by microscopic flow dynamics and production well performance in tight gas sand reservoirs. Based on a critical review of the available literature, a better understanding of the main weaknesses of the current state of the art of modeling and simulation for tight sand reservoirs has been reached. Progress has been made in the development and implementation of a simple reservoir simulator that is still able to overcome some of the deficiencies detected. The simulator will be used to quantify the impact of microscopic phenomena in the macroscopic behavior of tight sand gas reservoirs. Phenomena such as, Knudsen diffusion, electro-kinetic effects, ordinary diffusion mechanisms and water vaporization are being considered as part of this study. To date, the adequate modeling of gas slippage in porous media has been determined to be of great relevance in order to explain unexpected fluid flow behavior in tight sand reservoirs.

Maria Cecilia Bravo; Mariano Gurfinkel

2005-06-30

103

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

USGS Publications Warehouse

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

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

1985-01-01

104

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

NASA Astrophysics Data System (ADS)

Reservoirs are being built at an increasing rate each year to provide humans with resources such as hydroelectric power and drinking water. These man-made systems have provided society with important services, but these have come at the cost of enhanced greenhouse gas (GHG) emissions. Recent estimates suggest reservoirs are a globally significant source of GHG emissions, but these estimates are largely based on studies of oligotrophic boreal and tropical reservoirs. Reservoirs draining agricultural basins are common throughout much of the developed world and are subject to high nutrient loading rates from the watershed. Excess nutrient loading stimulates algae blooms and degrades water quality in these reservoirs, but surprisingly little is known about how nutrients and algal blooms affect GHG dynamics. To assess GHG dynamics in an agricultural reservoir we measured GHG emission rates, dissolved concentrations, and nutrient chemistry in William H. Harsha Lake, an agricultural reservoir located in southwestern Ohio (USA), on a monthly basis since October, 2011. Dissolved N2O was negatively related to nitrate (r2=.91, p<0.001) in October 2011, suggesting denitrification was an important source of N2O in the reservoir during fall turnover. Relationships between dissolved N2O and nitrate concentrations were inconsistent during the winter and spring, suggesting nitrate was not limited during these seasons. There was no consistent pattern in dissolved gas concentrations across the length of the reservoir, but concentrations were greater in hypolimnetic than eplimnetic waters during warmer months. The highest N2O and CH4 emissions occurred during lake turn over in the fall (CH4 flux= 4.76E+1 mg CH4 hr-1m-2, N2O flux= 9.24E+1 ?g N2O-N hr-1m-2, and CO2 flux = 8.62E+2 mg CO2 hr-1m-2), while the lowest emission rates were observed during the winter. We found no clear spatial pattern in GHG emission rates across the length of the reservoir. On an annual basis, we estimate the reservoir emits 1.52E+6 kg CH4-C/yr, equivalent to ~11,000 head of dairy cattle. On a per unit area basis, the reservoir was a hotspot of N2O emissions compared to the surrounding agricultural land; however, total annual N2O emissions from the reservoir (3.00E+3 kg N2O-N/yr) constitute only 1% of total watershed N2O emissions due to the much greater area of agricultural lands.

Smolenski, R. L.; Beaulieu, J.; Townsend-Small, A.; Nietch, C.

2012-12-01

105

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

...Resources 2 2013-07-01 2013-07-01 false How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap? 250.1157 Section 250.1157 Mineral Resources BUREAU OF SAFETY AND...

2013-07-01

106

Reservoir and Stimulation Analysis of a Devonian Shale Gas Field  

Microsoft Academic Search

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

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

1989-01-01

107

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

108

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

109

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

Microsoft Academic Search

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

Daniel J. K. Ross; R. Marc Bustin

2007-01-01

110

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

EPA Science Inventory

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

111

Simulation of Natural Depletion and Miscible Gas Injection Effects on Asphaltene Stability in Petroleum Reservoir Fluids  

Microsoft Academic Search

Natural depletion of petroleum reservoirs as well as gas injection for enhance oil recovery, are unavoidable processes in the oil industry. Foremost, prediction of the problems due to these two processes is very necessary and important. So many field and experimental experiences have shown that heavy organic depositions, especially asphaltene deposition, are principal results during these processes. Results of laboratory

S. A. Mousavi Dehghani; M. Vafaie Sefti; G. A. Mansoori

2007-01-01

112

Induced seismicity in the gas reservoirs of the Netherlands  

NASA Astrophysics Data System (ADS)

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

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

2009-04-01

113

Naturally fractured tight gas reservoir detection optimization. Quarterly report, July 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 July 1 to September 30, 1996. Data from seismic surveys are analyzed for structural imaging of reflector units as part of a 3-D basin modeling effort. The main activities of this quarter were 3-D, 3-C processing, correlation matrix, and paraxial ray-tracing modeling.

NONE

1998-12-31

114

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

SciTech Connect

This document contains the quarterly report dated January 1-March 31, 1997 for the Naturally Fractured Tight Gas Reservoir Detection Optimization project. Topics covered in this report include AVOA modeling using paraxial ray tracing, AVOA modeling for gas- and water-filled fractures, 3-D and 3-C processing, and technology transfer material. Several presentations from a Geophysical Applications Workshop workbook, workshop schedule, and list of workshop attendees are also included.

NONE

1998-04-01

115

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

NASA Astrophysics Data System (ADS)

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

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

2012-12-01

116

Naturally fractured tight gas reservoir detection optimization. Quarterly report, April--June 1994  

SciTech Connect

Geologic assessment of the basin during the third quarter possessed several major objectives. The first task was to test the validity of the gas-centered basin model for the Piceance Basin. The second objective was to define the location and variability of gas-saturated zones within the Williams Fork and Iles Formation reservoir horizons. A third objective was to prepare an updated structure map of the Piceance Basin on the top of the Iles Formation (Rollins Sandstone) to take advantage of new data provided by ten years of drilling activity throughout the basin. The first two objectives formed the core of the ARI poster session presented at the AAPG annual meeting in Denver. The delineation of the gas and water-saturated zone geometries for the Williams Fork and Iles Formations in the basin was presented in the form of a poster session at the AAPG Annual meeting held in Denver in mid-June. The poster session outlined the nature of the gas-centered basin geometry and demonstrated the gas and water-saturated conditions for the Williams Fork, Cozzette and Corcoran reservoir horizons throughout the basin. Initial and cumulative production data indicate that these reservoir horizons are gas-saturated in most of the south-central and eastern basin. The attached report summarizes the data and conclusions of the poster session.

Not Available

1994-07-01

117

Sound velocity of drilling mud saturated with reservoir gas  

Microsoft Academic Search

Knowledge of the in-situ sound velocity of drilling mud can be used in mud-pulse acoustic telemetry for evaluating the presence and amount of gas invasion in the drilling mud. The authors propose a model for calculating the in-situ density and sound velocity of water-based and oil-based drilling muds containing formation gas. Drilling muds are modeled as a suspension of clay

José M. Carcione; Flavio Poletto

2000-01-01

118

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

NASA Astrophysics Data System (ADS)

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

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

2013-05-01

119

Devonian gas shales and related tight reservoir rocks of Appalachian basin  

SciTech Connect

Devonian gas shales, a sequence of brown to black, low-permeability laminated rocks that contain 2 to 16% by volume of organic matter, underlie more than 170,000 mi/sup 2/ (440,000 km/sup 2/) of the Appalachian basin mainly under the Appalachian plateaus. Their volume exceeds 12,600 mi/sup 3/ (52,500 km/sup 3/), and they contain more than 3.3 trillion tons of gas producing organic matter. Their permeability ranges from 0.1 to 10 microdarcys and their porosity from 1 to 4%. Although their total gas production has been only about 3 tcf during the past 160 yr (since 1821), mainly from the Big Sandy area of eastern Kentucky, their gas-in-place resource has been estimated in the range from 2000 to 1,860 tcf. Shale gas is of low thermal maturity near the western outcrops, whereas dry gas deep in the basin to the east is of high thermal maturity. Because most of the shale-generated gas has been adsorbed by the organic components in the rock, gas shales must be broken by an extensive natural fracture system before they will yield gas in commercially exploitable volume. In the western part of the basin, gas shales are both source and reservoir for gas. To the east, dark gas shales interfinger with an eastward thickening sequence of low-permeability siltstone and sandstone turbidites. Where fractured, these more brittle beds are also reservoirs for gas migrating from adjacent gas shales. Successful exploitation of shale gas requires careful evaluation of geologic and engineering factors.

Dewitt, W. Jr.

1984-04-01

120

Cal Canal Field, California: case history of a tight and abnormally pressured gas condensate reservoir  

SciTech Connect

The Cal Canal Field, situated in the San Joaquin Valley near Bakersfield, California, produces a rich (280 bbl/MMSCF) gas condensate from an average depth of 11,500 feet. The upper Miocene Stevens Sand, the producing formation in the field, is a very tight, abnormally pressured gas condensate reservoir. The average reservoir parameters are 12 percent porosity, .01 to .1 md permeability and a connate water saturation of 59%. The dew point pressure of 5835 psi is 1508 psi below the initial reservoir pressure. The material balance method, corrected for abnormal pressure, indicates an original wet gas-in-place of 103.3 BSCF. Production performance history suggests that the ultimate recovery from the field will be approximately + or - 10% of the original wet GIP. Such a poor recovery could be attributed to retrograde fallout and increasing water saturation in the vicinity of the wellbores. This paper presents an analysis of the reservoir characteristics and a review of its performance to date. The purpose of the study was to investigate the feasibility of improving hydrocarbon recovery from the field.

Engineer, R.

1985-03-01

121

Calculation of geothermal reservoir temperatures and steam fractions from gas compositions  

SciTech Connect

This paper deals with the chemical equilibria and physical characteristics of the fluid in the reservoir (temperature, steam fraction with respect to total water, gas/steam ratio, redox conditions), which seem to be responsible for the observed concentrations of some reactive species found in the geothermal fluids (CO2, H2, H2S and CH4). Gas geochemistry is of particular interest in vapor-dominated fields where the fluid discharged consists of almost pure steam containing a limited number of volatile chemical species. Considering several geothermal systems, a good correlation has been obtained among the temperatures calculated from the gas geothermometers and the temperatures measured in the reservoir of evaluated by other physical or chemical methods. 24 refs., 5 figs.

D'Amore, F.; Truesdell, A.H.

1985-01-01

122

Mineral content prediction for unconventional oil and gas reservoirs based on logging data  

NASA Astrophysics Data System (ADS)

Coal bed methane and shale oil &gas are both important unconventional oil and gas resources, whose reservoirs are typical non-linear with complex and various mineral components, and the logging data interpretation model are difficult to establish for calculate the mineral contents, and the empirical formula cannot be constructed due to various mineral. The radial basis function (RBF) network analysis is a new method developed in recent years; the technique can generate smooth continuous function of several variables to approximate the unknown forward model. Firstly, the basic principles of the RBF is discussed including net construct and base function, and the network training is given in detail the adjacent clustering algorithm specific process. Multi-mineral content for coal bed methane and shale oil &gas, using the RBF interpolation method to achieve a number of well logging data to predict the mineral component contents; then, for coal-bed methane reservoir parameters prediction, the RBF method is used to realized some mineral contents calculation such as ash, volatile matter, carbon content, which achieves a mapping from various logging data to multimineral. To shale gas reservoirs, the RBF method can be used to predict the clay content, quartz content, feldspar content, carbonate content and pyrite content. Various tests in coalbed and gas shale show the method is effective and applicable for mineral component contents prediction

Maojin, Tan; Youlong, Zou; Guoyue

2012-09-01

123

The Antrim shale, fractured gas reservoirs with immense potential  

SciTech Connect

Antrim shale gas production has grown from 0.4 Bcf of gas in 1987 to 127 Bcf in 1994, causing record gas production in Michigan. Recent industry activity suggests the play will continue to expand. The GRI Hydrocarbon Model's Antrim resource base description was developed in 1991 based on industry activity through 1990. The 1991 description estimated 32 Tcf of recoverable resource, and was limited to northern Michigan which represents only part of the Antrim's total potential. This description indicated production could increase manyfold, even with low prices. However, its well recovery rate is less than current industry results and projected near term production lags actual production by 1 to 2 years. GRI is updating its description to better reflect current industry results and incorporate all prospective areas. The description in northern Michigan is updated using production and well data through 1994 and results from GRI's research program. The description is then expanded to the entire basin. Results indicate the northern resource is somewhat larger than the previous estimate and the wells perform better. Extrapolation to the entire basin using a geologic analog model approximately doubles the 1991 estimate. The model considers depositional, structural, and tectonic influences; fracturing; organic content; thermal history; and hydrocarbon generation, migration and storage. Pleistocene glaciation and biogenic gas are also included for areas near the Antrim subcrop.

Manger, K.C. (DynCorp., Alexandria, VA (United States)); Woods, T.J. (Gas Research Institute., Washington, DC (United States)) Curtis, J.B. (Colorado School of Mines, Golden, CO (United States))

1996-01-01

124

Reservoir properties and ore structure of tight gas sands  

Microsoft Academic Search

Thin section and SEM observations indicate that tight gas sands may be grouped into four broad categories based on pore geometry. These consist of (1) primary interparticle porosity; (2) primary interparticle porosity filled with authigenic minerals; (3) primary porosity reduced to narrow cracks with secondary honeycombed grains; and (4) intercrystalline porosity within a fine grained, elongate matrix. Type 1 porosity

Soeder

1984-01-01

125

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

126

Naturally fractured tight gas reservoir detection optimization. Quaterly report, October 1, 1996--December 31, 1996  

SciTech Connect

This document contains the status report for the Naturally Fractured Tight Gas-Gas Reservoir Detection Optimization project for the contract period October 1 to December 31, 1996. Data from seismic surveys are analyzed for structural imaging of reflector units as part of a 3-D basin modeling effort. The goal of this task is to assess the effects of structural complexity and regional anisotropy on a seismic attribute taken to indicate local fracturing and/or gas concentrations. The main activities of this quarter included basin modeling, 3-D, 3-C processing, correlation matrix, dipole sonic logging, and technology transfer.

NONE

1998-12-31

127

Some effects of non-condensible gas in geothermal reservoirs with steam-water counterflow  

SciTech Connect

A mathematical model is developed for fluid and heat flow in two-phase geothermal reservoirs containing non-condensible gas (CO{sub 2}). Vertical profiles of temperature, pressures and phase saturations in steady-state conditions are obtained by numerically integrating the coupled ordinary differential equations describing conservation of water, CO{sub 2}, and energy. Solutions including binary diffusion effects in the gas phase are generated for cases with net mass throughflow as well as for balanced liquid-vapor counterflow. Calculated examples illustrate some fundamental characteristics of two-phase heat transmission systems with non-condensible gas. 14 refs., 3 figs.

McKibbin, R.; Pruess, K.

1988-01-01

128

Some effects of non-condensible gas in geothermal reservoirs with steam-water counterflow  

SciTech Connect

A mathematical model is developed for fluid and heat flow in two-phase geothermal reservoirs containing non-condensible gas (CO{sub 2}). Vertical profiles of temperature, pressures and phase saturations in steady-state conditions are obtained by numerically integrating the coupled ordinary differential equations describing conservation of water, CO{sub 2}, and energy. Solutions including binary diffusion effects in the gas phase are generated for cases with net mass throughflow as well as for balanced liquid-vapor counterflow. Calculated examples illustrate some fundamental characteristics of two-phase heat transmission systems with non-condensible gas.

McKibbin, Robert; Pruess, Karsten

1988-01-01

129

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

NASA Astrophysics Data System (ADS)

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

Aminul Islam, M.

2009-06-01

130

Reservoir simulation study of CO 2 storage and CO 2 EGR in the Atzbach–Schwanenstadt gas field in Austria  

Microsoft Academic Search

The Atzbach–Schwanenstadt gas field has been investigated in the CASTOR project with respect to its suitability for safe, long-term underground CO2 storage.Storage capacity of the reservoir has been estimated to 14.5 million tonnes of CO2. Potential nearby CO2 sources emit together about 300 000 tonnes of CO2 per year. Assuming that reservoir would be filled up until its initial reservoir

Szczepan Polak; Alv-Arne Grimstad

2009-01-01

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

Facies, faults and potential sweet spots in a tight gas reservoir: Almond Formation, Wyoming  

SciTech Connect

The Almond Formation is a major producer of gas in southwestern Wyoming. Although exploration generally is aimed at finding conventional reservoirs in upper Almond marine sandstones, the majority of Almond gas is contained in the underlying main Almond, a succession of dominantly non-marine, interbedded tight sandstones, siltstones, carbonaceous shales and coals. Production data indicate that some of the best gas wells completed in upper Almond sands show little production decline and have already produced more gas than calculations indicate they contain. This implies that these wells have somehow successfully tapped into the vast supply of gas contained in the main Almond. We believe that the more permeable reservoirs, in addition to providing [open quotes]sweet spots[close quotes] for exploration, also serve as lateral conduits capable of draining gas over a broad area from the main Almond. The [open quotes]sweet spots[close quotes] themselves do not need to be volumetrically large, only permeable and laterally continuous. Previously unrecognized marine sands, similar to those in the upper Almond, are favorably located in the middle of the main Almond succession and may provide additional lateral conduits. Studies also show that syndepositional faults significantly influenced deposition and may also be important in terms of fluid flow. At least some syndepositional faults are associated with anomalously high gas and/or water production within fields, and may be vertical conduits for fluid flow.

Martinsen, R.; Iverson, W.; Surdam, R. (Univ. of Wyoming, Laramie, WY (United States))

1996-01-01

133

Calculation of porosity from nuclear magnetic resonance and conventional logs in gas-bearing reservoirs  

NASA Astrophysics Data System (ADS)

The porosity may be overestimated or underestimated when calculated from conventional logs and also underestimated when derived from nuclear magnetic resonance (NMR) logs due to the effect of the lower hydrogen index of natural gas in gas-bearing sandstones. Proceeding from the basic principle of NMR log and the results obtained from a physical rock volume model constructed on the basis of interval transit time logs, a technique of calculating porosity by combining the NMR log with the conventional interval transit time log is proposed. For wells with the NMR log acquired from the MRIL-C tool, this technique is reliable for evaluating the effect of natural gas and obtaining accurate porosity in any borehole. In wells with NMR log acquired from the CMR-Plus tool and with collapsed borehole, the NMR porosity should be first corrected by using the deep lateral resistivity log. Two field examples of tight gas sandstones in the Xujiahe Formation, central Sichuan basin, Southwest China, illustrate that the porosity calculated by using this technique matches the core analyzed results very well. Another field example of conventional gas-bearing reservoir in the Ziniquanzi Formation, southern Junggar basin, Northwest China, verifies that this technique is usable not only in tight gas sandstones, but also in any gas-bearing reservoirs.

Xiao, Liang; Mao, Zhi-qiang; Li, Gao-ren; Jin, Yan

2012-08-01

134

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

135

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

National Technical Information Service (NTIS)

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 ...

1995-01-01

136

Study on Using the Water Alternating Gas Injection Technologic to Improve the Ultra Low Permeability Reservoir Recovery  

Microsoft Academic Search

To rationally develop low permeability reservoir, enhanced oil recovery, Changqing Oilfield launched a special low permeability oil field development studies. Based Changqing oilfield Yanhewan block this typical ultra-low permeability reservoir, use the numerical simulation method simulate the instability of water injection and gas injection alternating different effects of the development. The simulation results show that injection cycle in the early

Zhang Yi; Zhang Ning-sheng; Li Jun-gang; Shi Hai-xia; Tong Xiao-hua

2010-01-01

137

Detection of gas and water using HHT by analyzing P- and S-wave attenuation in tight sandstone gas reservoirs  

NASA Astrophysics Data System (ADS)

A direct detection of hydrocarbons is used by connecting increased attenuation of seismic waves with oil and gas fields. This study analyzes the seismic attenuation of P- and S-waves in one tight sandstone gas reservoir and attempts to give the quantitative distinguishing results of gas and water by the characteristics of the seismic attenuation of P- and S-waves. The Hilbert-Huang Transform (HHT) is used to better measure attenuation associated with gas saturation. A formation absorption section is defined to compute the values of attenuation using the common frequency sections obtained by the HHT method. Values of attenuation have been extracted from three seismic sections intersecting three different wells: one gas-saturated well, one fully water-saturated well, and one gas- and water- saturated well. For the seismic data from the Sulige gas field located in northwest Ordos Basin, China, we observed that in the gas-saturated media the S-wave attenuation was very low and much lower than the P-wave attenuation. In the fully water-saturated media the S-wave attenuation was higher than the P-wave attenuation. We suggest that the joint application of P- and S-wave attenuation can improve the direct detection between gas and water in seismic sections. This study is hoped to be useful in seismic exploration as an aid for distinguishing gas and water from gas- and water-bearing formations.

Xue, Ya-juan; Cao, Jun-xing; Wang, Da-xing; Tian, Ren-fei; Shu, Ya-xiang

2013-11-01

138

Mapping the Fluid Pathways and Permeability Barriers of a Large Gas Hydrate Reservoir  

NASA Astrophysics Data System (ADS)

An understanding of the relationship between the physical properties of gas hydrate saturated sedimentary basins aids in the detection, exploration and monitoring one of the world's upcoming energy resources. A large gas hydrate reservoir is located in the MacKenzie Delta of the Canadian Arctic and geophysical logs from the Mallik test site are available for the gas hydrate stability zone (GHSZ) between depths of approximately 850 m to 1100 m. The geophysical data sets from two neighboring boreholes at the Mallik test site are analyzed. Commonly used porosity logs, as well as nuclear magnetic resonance, compressional and Stoneley wave velocity dispersion logs are used to map zones of elevated and severely reduced porosity and permeability respectively. The lateral continuity of horizontal permeability barriers can be further understood with the aid of surface seismic modeling studies. In this integrated study, the behavior of compressional and Stoneley wave velocity dispersion and surface seismic modeling studies are used to identify the fluid pathways and permeability barriers of the gas hydrate reservoir. The results are compared with known nuclear magnetic resonance-derived permeability values. The aim of investigating this heterogeneous medium is to map the fluid pathways and the associated permeability barriers throughout the gas hydrate stability zone. This provides a framework for an understanding of the long-term dissociation of gas hydrates along vertical and horizontal pathways, and will improve the knowledge pertaining to the production of such a promising energy source.

Campbell, A.; Zhang, Y. L.; Sun, L. F.; Saleh, R.; Pun, W.; Bellefleur, G.; Milkereit, B.

2012-12-01

139

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

140

Resource target for gas reserves to be developed by management of water-drive gas reservoirs. Topical report, June 1, 1991-December 31, 1992  

SciTech Connect

The study analyzed eleven documented projects that all showed incremental reserve potential from water-drive gas reservoirs through the use of management techniques. These projects were characterized by a factor called water-drive strength which was correlated with incremental recovery. The correlation confirmed earlier research that predicted the largest incremental potential in the moderate water-drive category. The parameters necessary to apply the correlation are initial gas in place and water-drive strength. Six hundred forty eight (648) reservoirs were analyzed in Texas, Louisiana Onshore and Louisiana Offshore production areas. Water-drive strength and initial gas-in-place were determined for each reservoir. Based on determinations for the 648 reservoirs, the entire production areas were estimated based on number of fields and reservoirs, number of wells, and cumulative production. The result of the calculation shows that the potential Resource Target is about 17 Tcf.

Ancell, K.L.; Fairchild, J.W.; Agnew, J.B.

1993-02-01

141

The Multiwell Experiment; A field laboratory in tight gas sandstone reservoirs  

SciTech Connect

This paper reports on the U.S. DOE's Multiwell Experiment (MWX), a field laboratory aimed at improved characterization and gas production from low-permeability reservoirs typified by the Mesaverde Group in western Colorado. A broad spectrum of activities was conducted over 8 years at a site containing three closely spaced (< 225 ft (< 68 m)), deep (7,500 to 8,350 ft (2300 to 2550 m)) wells. The results yield insights and contributions into the technology of gas production from this resource.

Northrop, D.A.; Frohne, K.H. (Sandia National Labs., Albuquerque, NM (USA))

1990-06-01

142

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

Microsoft Academic Search

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

S. J. Seni; R. J. Finley

1993-01-01

143

Case history: Use of a multiwell model to optimize infill development of a tight-gas-sand reservoir  

SciTech Connect

The ability to predict incremental rates and reserves reasonably from infill development drilling in tight-gas reservoirs is enhanced through use of a three-dimensional (3D), multiwell, dry-gas model. Single-well (two-dimensional (2D)) and multiwell (three-dimensional (3D)) input and results are compared, and examples of both are presented. Measured initial reservoir pressures on an eight-well infill program compared favorably with the 3D model predictions.

Hinn, R.L. Jr.; Glenn, J.M.; McNichol, K.C.

1988-06-01

144

The controlling factors and distribution prediction of H 2 S formation in marine carbonate gas reservoir, China  

Microsoft Academic Search

Generally, there are some anhydrites in carbonate reservoir, as H2S is also familiar in carbonate oil and gas reservoirs. Nowadays, natural gas with high H2S concentration is usually considered as TSR origin, so there is close relationship between H2S and anhydrite. On the contrary, some carbonate rocks with anhydrite do not contain H2S. Recently, researches show that H2S is only

GuangYou Zhu; ShuiChang Zhang; YingBo Liang

2007-01-01

145

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

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

Mancini

1990-01-01

146

Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity: Technical progress report, April 19, 1989June 30, 1989  

Microsoft Academic Search

The objective of this project is 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. This objective will be achieved through detailed geological, geostatistical, and engineering

Mancini

1989-01-01

147

Imaging pore space in tight gas sandstone reservoir: insights from broad ion beam cross-sectioning  

NASA Astrophysics Data System (ADS)

Monetization of tight gas reservoirs, which contain significant gas reserves world-wide, represents a challenge for the entire oil and gas industry. The development of new technologies to enhance tight gas reservoir productivity is strongly dependent on an improved understanding of the rock properties and especially the pore framework. Numerous methods are now available to characterize sandstone cores. However, the pore space characterization at pore scale remains difficult due to the fine pore size and delicate sample preparation, and has thus been mostly indirectly inferred until now. Here we propose a new method of ultra high-resolution petrography combining high resolution SEM and argon ion beam cross sectioning (BIB, Broad Ion Beam) which prepares smooth and damage free surfaces. We demonstrate this method using the example of Permian (Rotliegend) age tight gas sandstone core samples. The combination of Ar-beam cross-sectioning facility and high-resolution SEM imaging has the potential to result in a step change in the understanding of pore geometries, in terms of its morphology, spatial distribution and evolution based on the generation of unprecedented image quality and resolution enhancing the predictive reliability of image analysis.

Desbois, G.; Enzmann, F.; Urai, J. L.; Baerle, C.; Kukla, P. A.; Konstanty, J.

2010-06-01

148

Well-Production Data and Gas-Reservoir Heterogeneity -- Reserve Growth Applications  

USGS Publications Warehouse

Oil and gas well production parameters, including peakmonthly production (PMP), peak-consecutive-twelve month production (PYP), and cumulative production (CP), are tested as tools to quantify and understand the heterogeneity of reservoirs in fields where current monthly production is 10 percent or less of PMP. Variation coefficients, defined as VC= (F5-F95)/F50, where F5, F95, and F50 are the 5th, 95th, and 50th (median) fractiles of a probability distribution, are calculated for peak and cumulative production and examined with respect to internal consistency, type of production parameter, conventional versus unconventional accumulations, and reservoir depth. Well-production data for this study were compiled for 69 oil and gas fields in the Lower Pennsylvanian Morrow Formation of the Anadarko Basin, Oklahoma. Of these, 47 fields represent production from marine clastic facies. The Morrow data were supplemented by data from the Upper Cambrian and Lower Ordovician Arbuckle Group, Middle Ordovician Simpson Group, Middle Pennsylvanian Atoka Formation, and Silurian and Lower Devonian Hunton Group of the Anadarko Basin, one large gas field in Upper Cretaceous reservoirs of north-central Montana (Bowdoin field), and three areas of the Upper Devonian and Lower Mississippian Bakken Formation continuous-type (unconventional) oil accumulation in the Williston Basin, North Dakota and Montana. Production parameters (PMP, PYP, and CP) measure the net result of complex geologic, engineering, and economic processes. Our fundamental hypothesis is that well-production data provide information about subsurface heterogeneity in older fields that would be impossible to obtain using geologic techniques with smaller measurement scales such as petrographic, core, and well-log analysis. Results such as these indicate that quantitative measures of production rates and production volumes of wells, expressed as dimensionless variation coefficients, are potentially valuable tools for documenting reservoir heterogeneity in older fields for field redevelopment and risk analysis.

Dyman, Thaddeus S.; Schmoker, James W.

2003-01-01

149

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

150

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

SciTech Connect

We thank Friedman (1996) for his useful discussion comparing Beekmantown rocks from New York state with the Beekmantown rocks in Quebec. The objective of our paper (Dykstra and Longman, 1995) was to discuss the gas reservoir potential of the Beekmantown Group in Quebec and compare it to areas of analogous production, namely the Arbuckle reservoir in the Wilburton field in Oklahoma. In 1995, when our paper was published, we were unaware of any significant commercial gas production from the Beekmantown Group in New York state. Figure 1 is a map of North America during Early Ordovician time, showing the location of the paleoshoreline and the paleoequator. The Beekmantown Group, which was deposited along this coastal and shallow-marine complex on the eastern margin of the North America craton, could contain potential reservoir rocks almost anywhere along this trend. As explained in our paper, known hydrocarbon discoveries and production come from several locations along the Lower Ordovician coastal complex. This includes the Ellenburger and Arbuckle of the United States, and the Beekmantown and St. Georges groups of Canada (Figure 1). In conclusion we would like to reiterate, as Friedman pointed out, that dolomites of the Beekmantown provide an important exploration target in both the autochthon and the overlying thrust sheets of the Canadian and US Appalachians.

Dykstra, J.C.F. [Talisman Energy Inc., Alberta (Canada); Longman, M.W.

1996-10-01

151

Analysis of production tests of hydraulically fractured wells in a tight solution gas-drive reservoir  

SciTech Connect

A simulation study has been carried out to investigate how accurate existing techniques are to evaluate tests of non-ideal hydraulically fractured wells in tight solution gas drive reservoirs. In the reservoir under investigation some frac-jobs have been carried out in stages. Wells, deviating up to 45 degrees, can intersect several parallel vertical fractures. In that case a correct analysis of tests is almost impossible. In practice conclusive results can only be obtained if a prefrac test is available or when a postfrac test formation radial flow is evidently reached. Existing superposition methods were tested for constant pressure, constant rate and multirate cases to compare their applicabilities. In case radial flow superposition is applied in the time scale and if linear flow is significant results of multirate cases can show too optimistic kh values. Published pseudopressure techniques to find formation kh values for solution gas drive reservoirs are improved by using average fluid properties instead of those at wellbore conditions. To accurately define fracture and formation characteristics a pseudo time factor was needed to correct for drastic changes in viscosity and total compressibility.

Verbeek, C.M.J.

1982-09-01

152

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.  

National Technical Information Service (NTIS)

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 simulat...

A. D. Modine

1989-01-01

153

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

NASA Astrophysics Data System (ADS)

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

Alzarouni, Asim

154

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

SciTech Connect

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

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

1995-12-01

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

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

NASA Astrophysics Data System (ADS)

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

Karakitsios, Vasileios; Agiadi, Konstantina

2013-04-01

157

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

158

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

159

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

USGS Publications Warehouse

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

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

2009-01-01

160

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

NASA Astrophysics Data System (ADS)

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

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

2014-05-01

161

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

PubMed

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

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

2014-01-01

162

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

163

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

NASA Astrophysics Data System (ADS)

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.

1998-07-01

164

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

165

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

166

Relief-well requirements to kill a high-rate gas blowout from a deepwater reservoir  

SciTech Connect

Relief-well requirements were investigated for a dynamic kill of a high-rate gas blowout from a deepwater reservoir to define any necessary special procedures or equipment. Results of the investigation show that a high injection rate and a special-design large-diameter injection riser are required to dynamically kill such a blowout with seawater. The injection riser is necessary to limit surface pump pressure during the high-rate kill operation. Procedures to complete the kill operation hydrostatically with heavy fluid following the dynamic kill are outlined.

Warriner, R.A. (Triton Engineering Services Co. (US)); Cassity, T.G. (Cameron Iron Works (US))

1988-12-01

167

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

NASA Astrophysics Data System (ADS)

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

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

2007-06-01

168

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

169

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

170

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

Microsoft Academic Search

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

M. J. Burn; D. L. Carr; J. Stuede

1994-01-01

171

Structural-Diagenetic Controls on Fracture Opening in Tight Gas Sandstone Reservoirs, Alberta Foothills  

NASA Astrophysics Data System (ADS)

In tight gas reservoirs, understanding the characteristics, orientation and distribution of natural open fractures, and how these relate to the structural and stratigraphic setting are important for exploration and production. Outcrops provide the opportunity to sample fracture characteristics that would otherwise be unknown due to the limitations of sampling by cores and well logs. However, fractures in exhumed outcrops may not be representative of fractures in the reservoir because of differences in burial and exhumation history. Appropriate outcrop analogs of producing reservoirs with comparable geologic history, structural setting, fracture networks, and diagenetic attributes are desirable but rare. The Jurassic to Lower Cretaceous Nikanassin Formation from the Alberta Foothills produces gas at commercial rates where it contains a network of open fractures. Fractures from outcrops have the same diagenetic attributes as those observed in cores <100 km away, thus offering an ideal opportunity to 1) evaluate the distribution and characteristics of opening mode fractures relative to fold cores, hinges and limbs, 2) compare the distribution and attributes of fractures in outcrop vs. core samples, 3) estimate the timing of fracture formation relative to the evolution of the fold-and-thrust belt, and 4) estimate the degradation of fracture porosity due to postkinematic cementation. Cathodoluminescence images of cemented fractures in both outcrop and core samples reveal several generations of quartz and ankerite cement that is synkinematic and postkinematic relative to fracture opening. Crack-seal textures in synkinematic quartz are ubiquitous, and well-developed cement bridges abundant. Fracture porosity may be preserved in fractures wider than ~100 microns. 1-D scanlines in outcrop and core samples indicate fractures are most abundant within small parasitic folds within larger, tight, mesoscopic folds. Fracture intensity is lower away from parasitic folds; intensity progressively decreases from the faulted cores of mesoscopic folds to their forelimbs, with lowest intensities within relatively undeformed backlimb strata. Fracture apertures locally increase adjacent to reverse faults without an overall increase in fracture frequency. Fluid inclusion analyses of crack-seal quartz cement indicate both aqueous and methane-rich inclusions are present. Homogenization temperatures of two-phase inclusions indicate synkinematic fracture cement precipitation and fracture opening under conditions at or near maximum burial of 190-210°C in core samples, and 120-160°C in outcrop samples. In comparison with the fracture evolution in other, less deformed tight-gas sandstone reservoirs such as the Piceance and East Texas basins where fracture opening is primarily controlled by gas generation, gas charge, and pore fluid pressure, these results suggest a strong control of regional tectonic processes on fracture generation. In conjunction with timing and rate of gas charge, rates of fracture cement growth, and stratigraphic-lithological controls, these processes determine the overall distribution of open fractures in these reservoirs.

Ukar, E.; Eichhubl, P.; Fall, A.; Hooker, J. N.

2012-12-01

172

Timing and Duration of Gas Charge-Driven Fracturing in Tight-Gas Sandstone Reservoirs Based on Fluid Inclusion Observations: Piceance Basin, Colorado  

NASA Astrophysics Data System (ADS)

Natural fractures are universally present in tight-gas sandstone reservoirs. Fractures are recognized to enhance permeability of the reservoir, provide gas-migration pathways during charge, and boost connectivity with well bore during production of natural gas. "Sweet spots", or higher than average permeability and production regions, have been attributed to the presence of open fractures in the reservoir. Thus it is essential to understand the opening history of natural fractures, such as the timing with respect to hydrocarbon generation and migration in the reservoirs. The natural opening-mode fractures in the tight-gas sandstone of the Mesaverde Group in the Piceance Basin, Colorado, are partially or completely cemented by quartz and/or calcite that precipitated syn- or postkinematically relative to fracture opening. Fluid inclusions trapped in the cements record pressure, temperature, and fluid composition during subsequent fracture opening and cementation. SEM-CL imaging of cements combined with fluid inclusion microthermometry and Raman spectroscopy constrain fluid evolution trends during fracturing, and timing of fracture opening in the tight-gas sandstone reservoirs. Fluid inclusions indicate a thermal history varying from ~150°C to ~188°C to ~140°C in sandstones of the Piceance Basin. Based on microthermometry, Raman spectroscopy, and equation of state modeling calculated pore-fluid pressures varied from ~40 to 100 MPa suggesting fracture opening under significant pore-fluid overpressures. Observed variability in pore-fluid pressure over time is interpreted to reflect dynamic conditions of episodic gas charge. Models of gas and oil generation in the Piceance Basin suggest that fracture opening and elevated pore-fluid pressures coincided with maximum gas generation within the Mesaverde Group. These observations demonstrate that protracted growth of the pervasive fracture system was the consequence of gas maturation and reservoir charge, and that fracture opening lasted for ~35 m.y.

Fall, A.; Eichhubl, P.; Laubach, S.; Bodnar, R. J.

2012-12-01

173

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

PubMed Central

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

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

2012-01-01

174

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

PubMed

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

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

2012-12-11

175

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

176

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

Microsoft Academic Search

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

Ebrahim Fathi; I. Yücel Akkutlu

2009-01-01

177

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

178

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

179

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

Microsoft Academic Search

Thermochemical sulfate reduction (TSR) is a well known process that can lead to sour (H2S-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

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

1996-01-01

180

Development of general inflow performance relationships (IPR's) for slanted and horizontal wells producing heterogeneous solution-gas drive reservoirs  

SciTech Connect

Since 1968, the Vogel equation has been used extensively and successfully for analyzing the inflow performance relationship (IPR) of flowing vertical wells producing by solution-gas drive. Oil well productivity can be rapidly estimated by using the Vogel IPR curve and well outflow performance. With recent interests on horizontal well technology, several empirical IPRs for solution-gas drive horizontal and slanted wells have been developed under homogeneous reservoir conditions. This report presents the development of IPRs for horizontal and slanted wells by using a special vertical/horizontal/slanted well reservoir simulator under six different reservoir and well parameters: ratio of vertical to horizontal permeability, wellbore eccentricity, stratification, perforated length, formation thickness, and heterogeneous permeability. The pressure and gas saturation distributions around the wellbore are examined. The fundamental physical behavior of inflow performance for horizontal wells is described.

Cheng, A.M.

1992-04-01

181

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

182

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

183

Sealing mechanism for cap beds of shallow-biogenic gas reservoirs in the Qiantang River incised valley, China  

NASA Astrophysics Data System (ADS)

Late Quaternary shallow-biogenic gas reservoirs are well-developed in the Qiantang River incised valley, eastern China. They present as sand bodies in the floodplain-estuary facies. Silty clay beds of floodplain-estuary facies and mud beds of estuarine-shallow marine facies serve as the direct and indirect cap beds, respectively, and the former has much better sealing ability. Capillary pressure sealing, pore water pressure sealing, and hydrocarbon concentration sealing contribute to the conservation of shallow-biogenic gas in the reservoirs, in which the pore water pressure sealing may be the most important factor.

Zhang, Xia; Lin, Chun-Ming; Li, Yan-Li; Qu, Chang-Wei; Wang, Shu-Jun

2013-10-01

184

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

SciTech Connect

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

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

1993-01-28

185

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

186

Feasibility of gas drive in Fang48 fault block oil reservoir  

Microsoft Academic Search

The Fang-48 fault block oil reservoir is an extremely low permeability reservoir, and it is difficult to produce such a reservoir\\u000a by waterflooding. Laboratory analysis of reservoir oil shows that the minimum miscibility pressure for CO2 drive in Fang-48 fault block oil reservoir is 29 MPa, lower than the formation fracture pressure of 34 MPa, so the displacement\\u000a mechanism is

Lining Cui; Jirui Hou; Xiangwen Yin

2007-01-01

187

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

USGS Publications Warehouse

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

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

2012-01-01

188

Monte Carlo simulation for determining gas saturation using three-detector pulsed neutron logging technology in tight gas reservoir and its application.  

PubMed

A new method to accurately determine gas saturation in the tight gas reservoir using a three-detector pulsed neutron logging tool was proposed. Formation porosity is varied from 2% to 15% to simulate the distribution of thermal neutron under different borehole and formation conditions by using Monte Carlo method. The study result shows that the difference of three detectors counts can be used to determine gas saturation and have higher sensitivity than counting the ratio of different detectors. PMID:23672964

Zhang, Feng; Liu, Juntao; Yuan, Chao

2013-08-01

189

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

USGS Publications Warehouse

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

Lee, Myung Woong; Collett, Timothy S.

2013-01-01

190

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

191

A water-gas relative permeability relationship for tight gas sand reservoirs  

SciTech Connect

This paper presents a new approach for the analyses of laboratory-derived capillary pressure data for tight gas sands. The method uses the fact that a log-log plot of capillary pressure against water saturation is a straight line to derive new expressions for both wetting and nonwetting phase relative permeabilities. The new relative permeability equations are explicit functions of water saturation and the slope of the log-log straight line of capillary pressure plotted against water saturation. Relative permeabilities determined with the new expressions have been successfully used in simulation studies of naturally fractured tight gas sands where those determined with Corey-type expressions which are functions of reduced water saturation have failed. A dependence trend is observed between capillary pressure and gas permeability data from some of the tight gas sands of the North American Continent. The trend suggests that The lower the gas permeability, the higher the capillary pressure values at the same wetting phase saturation-especially for saturations less than 60 percent.

Evans, R.D. (School of Petroleum and Geological Engineering, Univ. of Oklahoma, Norman, OK (US))

1990-12-01

192

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

NASA Astrophysics Data System (ADS)

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

Pu, Wanli

193

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

NASA Astrophysics Data System (ADS)

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

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

2009-07-01

194

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

195

The characteristics and sources of natural gases from Ordovician weathered crust reservoirs in the Central Gas Field in the Ordos Basin  

Microsoft Academic Search

The Central Gas Field is a famous large-sized gas field in the Ordos Basin of China. However, identification of main gas sources\\u000a of the Ordovician reservoirs in this gas field remains puzzling. On the basis of a lot of geochemical data and geological\\u000a research on natural gases, the characteristics and sources of natural gases from Ordovician weathered crust reservoirs in

Xianqing Li; Guoyi Hu; Jian Li; Dujie Hou; Peng Dong; Zhihong Song; Yunfeng Yang

2008-01-01

196

A water-gas relative permeability relationship for tight gas sand reservoirs  

Microsoft Academic Search

This paper presents a new approach for the analyses of laboratory-derived capillary pressure data for tight gas sands. The method uses the fact that a log-log plot of capillary pressure against water saturation is a straight line to derive new expressions for both wetting and nonwetting phase relative permeabilities. The new relative permeability equations are explicit functions of water saturation

R. D. Evans

1990-01-01

197

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

198

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

199

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

200

Prolific Overton field gas reservoirs within large transverse oolite shoals, Upper Jurassic Haynesville, Eastern Margin East Texas basin  

Microsoft Academic Search

Late Triassic rifting along a northeast-southwest spreading center in east Texas resulted in basement highs along the eastern margin of the East Texas basin that became sites of extensive ooid shoal deposition during Late Jurassic time. Reservoirs within oolite facies at Overton field contain over 1 tcf of natural gas. These large shoals, each approximately 15 mi (24 km) long

T. E. Covington; R. G. Lighty; W. M. Ahr

1985-01-01

201

Fuzzy logic-driven and SVM-driven hybrid computational intelligence models applied to oil and gas reservoir characterization  

Microsoft Academic Search

This work demonstrates the capabilities of two hybrid models as Computational Intelligence tools in the prediction of two important oil and gas reservoir properties, viz., porosity and permeability. The hybrid modeling was based on the combination of three existing Artificial Intelligence techniques: Functional Networks, Type-2 Fuzzy Logic System, and Support Vector Machines, using six datasets by utilizing the functional approximation

Fatai Anifowose; Abdulazeez Abdulraheem

2011-01-01

202

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

Microsoft Academic Search

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

R. K. Davies; D. A. Medwedeff

1996-01-01

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

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

PubMed

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

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

2000-01-01

205

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

206

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

207

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

208

3-D seismic improves structural mapping of a gas storage reservoir (Paris basin)  

SciTech Connect

In the Paris basin, anticlinal structures with closure of no more than 80 m and surface area of a few km[sup 2] are used for underground gas storage. At Soings-en-Sologne, a three-dimensional (3-D) survey (13 km[sup 2]) was carried out over such a structure to establish its exact geometry and to detail its fault network. Various reflectors were picked automatically on the migrated data: the top of the Kimmeridgian, the top of the Bathoinian and the base of the Hettangian close to the top of the reservoir. The isochron maps were converted into depth using data from 12 wells. Horizon attributes (amplitude, dip, and azimuth) were used to reconstruct the fault's pattern with much greater accuracy than that supplied by interpretation from previous two-dimensional seismic. The Triassic and the Jurassic are affected by two systems of conjugate faults (N10-N110, inherited from the Hercynian basement and N30-N120). Alternating clay and limestone are the cause of numerous structural disharmonies, particularly on both sides of the Bathonian. Ridges associated with N30-N120 faults suggest compressive movements contemporaneous with the tertiary events. The northern structure in Soings-en-Sologne thus appear to be the result of polyphased tectonics. Its closure (25 m), which is associated either with dips or faults, is described in detail by 3-D seismic, permitting more accurate forecast of the volume available for gas storage.

Huguet, F. (Gaz de France/DETN, la Plaine St. Denis (France)); Pinson, C. (CGG/Geotop, Massy (France))

1993-09-01

209

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

210

The origin of pyrobitumens in upper Devonian Leduc formation gas reservoirs, Alberta, Canada: an optical and EDS study of oil to gas transformation  

Microsoft Academic Search

Pyrobitumens are common within deep basin, Devonian carbonate gas reservoirs of the Western Canada Sedimentary Basin. Incident light microscopy and SEM-EDS have been used to study the origin of pyrobitumens from Upper Devonian isolated reefs of the Leduc Formation, west central Alberta. Reflectance properties (%Romax and %Romin), coke microtextures and relative S\\/C ratios are used to classify the pyrobitumens. In

Lavern D. Stasiuk

1997-01-01

211

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

PubMed

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

Rogério, Jp; Santos, Ma; Santos, Eo

2013-11-01

212

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{sub 2} 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. Regarding Task 1, several very important results were achieved this period for subtask 1.2. In particular, we successfully developed a robust Windows-based code to calculate MMP and MME for fluid characterizations that consist of any number of pseudocomponents. We also were successful in developing a new technique to quantify the displacement mechanism of a gas flood--that is, to determine the fraction of a displacement that is vaporizing or condensing. These new technologies will be very important to develop new correlations and to determine important parameters for the design of gas injection floods. Regarding Task 2, several results were achieved: (1) A detailed study of the accuracy of foam simulation validates the model with fits to analytical fractional-flow solutions. It shows that there is no way to represent surfactant-concentration effects on foam without some numerical artifacts. (2) New results on capillary crossflow with foam show that this is much less detrimental than earlier studies had argued. (3) It was shown that the extremely useful model of Stone for gravity segregation with foam is rigorously true as long as the standard assumptions of fractional-flow theory apply. Without this proof, it was always possible that this powerful model would break down in some important application.

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

2003-01-28

213

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

214

Evaluation of the 3-D channeling flow in a fractured type of oil/gas reservoir  

NASA Astrophysics Data System (ADS)

An understanding of the flow and transport characteristics through rock fracture networks is of critical importance in many engineering and scientific applications. These include effective recovery of targeted fluid such as oil/gas, geothermal, or potable waters, and isolation of hazardous materials. Here, the formation of preferential flow path (i.e. channeling flow) is one of the most significant characteristics in considering fluid flow through rock fracture networks; however, the impact of channeling flow remains poorly understood. In order to deepen our understanding of channeling flow, the authors have developed a novel discrete fracture network (DFN) model simulator, GeoFlow. Different from the conventional DFN model simulators, we can characterize each fracture not by a single aperture value but by a heterogeneous aperture distribution in GeoFlow [Ishibashi et al., 2012]. As a result, the formation of 3-D preferential flow paths within fracture network can be considered by using this simulator. Therefore, we would challenge to construct the precise fracture networks whose fractures have heterogeneous aperture distributions in field scale, and to analyze fluid flows through the fracture networks by GeoFlow. In the present study, the Yufutsu oil/gas field in Hokkaido, Japan is selected as the subject area for study. This field is known as the fractured type of reservoir, and reliable DFN models can be constructed for this field based on the 3-D seismic data, well logging, in-situ stress measurement, and acoustic emission data [Tamagawa et al., 2012]. Based on these DFN models, new DFN models for 1,080 (East-West) × 1,080 (North-South) × 1,080 (Depth) m^3, where fractures are represented by squares of 44-346 m on a side, are re-constructed. In these new models, scale-dependent aperture distributions are considered for all fractures constructing the fracture networks. Note that the multi-scale modeling of fracture flow has been developed by the authors [Ishibashi et al., in preparation]. For the DFN models with aperture distributions, fluid flow simulations are conducted by GeoFlow. Before entering upon a discussion of the GeoFlow simulations, we show the interesting fact that approximately three-orders-of-magnitude difference in productivity is observed between two neighboring wells in the Yufutsu field. The conventional DFN model simulations can predict which productivity is high between these two wells, but they never reproduce the huge difference in well productivity. One of the reasons for this result is that the conventional DFN simulations ignored the concept of channeling flow. With these views in our mind, we see the result of the GeoFlow simulations. In the GeoFlow simulations, the huge difference in well productivity in the Yufutsu oil/gas field is successfully reproduced. This means that proper evaluation of 3D channeling flow is the key to predict well productivity in fractured reservoirs. Moreover, it is also clarified that the actual flow area is estimated to be around 20-50% of the flow area predicted by conventional DFN models. In this presentation, we will show the detail of the precise fracture network modeling and fluid flow analysis within them. The suggested method would be one of the most effective methods to improve our understanding of 3D channeling flow in fractured type of reservoirs.

Ishibashi, T.; Watanabe, N.; Tsuchiya, N.; Tamagawa, T.

2013-12-01

215

Monitoring of a gas reservoir in Western Siberia through SqueeSAR  

NASA Astrophysics Data System (ADS)

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

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

2014-05-01

216

Investigation of a gas regulatable heat pipe with a wicked reservoir  

NASA Astrophysics Data System (ADS)

Theoretical and experimental results are presented on a variable-conductance heat pipe with a wicked reservoir. The effects of vapor temperature, cooling liquid temperature, and reservoir temperature on control precision are studied. Differential equations describing the unsteady operating conditions of the heat pipe are obtained. The improvement of temperature control with stabilization of the reservoir temperature is reported, and good agreement between calculated and experimental results is obtained.

Semena, M. G.

1980-11-01

217

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

218

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

219

Satellite linear features and pressure variations in Cretaceous shallow gas reservoirs, southern Bowdoin dome, Montana  

SciTech Connect

For three decades prior to 1960, shallow gas was produced in the southern part of Bowdoin dome from the Cretaceous Bowdoin Sandstone of the Carlile Formation and the Phillips Sandstone of the Greenhorn Formation. Historical production records from this period suggest that patterns of pressure decline are closely related to the geometry of linear features visible on satellite images. Linear features mapped at a scale of 1:1,000,000 on multispectral scanner Landsat images correspond with geomorphic elements of the Milk River, Beaver Creek, and White Water Creek drainage systems. Regional lineament zones interpreted from linear features are believed to outline basement blocks which controlled deposition and deformation on Bowdoin Dome and in other areas of the northern Great Plains. Initial formation pressures on southern Bowdoin dome are lower in a zone marked by northwest linear features, and subsequent pressure declines through several decades show areas of greatest change are bounded by linear features. A series of pressure maps illustrate isobars elongated along the northwest trend and shifting to the northwest as production continues. In the western part of the field, isobars also parallel a northeast-trending linear feature. Correspondence of isobar patterns and linear features may be related to increased fracture porosity and permeability along a basement block boundary, or it may be influenced by other geologic features related to block geometry such as depth of burial or reservoir distribution.

Shurr, G.W.; Tozer, M.K.; Tweed, A.D. (St. Cloud State Univ., MN (United States)); Wosick, F.D. (Williston Basin Interstate Pipeline Co., Bismarck, ND (United States))

1991-06-01

220

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

221

A Massive Molecular Gas Reservoir in the z = 5.3 Submillimeter Galaxy AzTEC-3  

NASA Astrophysics Data System (ADS)

We report the detection of CO J = 2?1, 5?4, and 6?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 ~= 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 × 1010(?CO/0.8) M sun, which can maintain the intense 1800 M sun yr-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 ~ 2 SMGs and constitutes gsim80% 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 ?CO), and a "dense", high-excitation component, containing ~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.; Capak, Peter L.; Carilli, Christopher L.; Cox, Pierre; Neri, Roberto; Scoville, Nicholas Z.; Schinnerer, Eva; Bertoldi, Frank; Yan, Lin

2010-09-01

222

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

Microsoft Academic Search

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

D. L. Carr; K. L. Oliver

1996-01-01

223

Curry unit: a successful waterflood in a depleted carbonate reservoir with high gas saturation. [Texas  

Microsoft Academic Search

With the continuing shortage of oil and high exploration costs there is potential for increasing oil recovery by waterflooding the old depleted carbonate reservoirs which have been neglected in the past. These are the reservoirs that may have produced 30 to 40 yr and at a cursory look do not seem to be an attractive prospect for secondary recovery. The

Hasan

1973-01-01

224

Predicting variations of the least principal stress magnitudes in shale gas reservoirs utilizing variations of viscoplastic properties  

NASA Astrophysics Data System (ADS)

Predicting variations of the magnitude of least principal stress within unconventional reservoirs has significant practical value as these reservoirs require stimulation by hydraulic fracturing. It is common to approach this problem by calculating the horizontal stresses caused by uniaxial gravitational loading using log-derived linear elastic properties of the formation and adding arbitrary tectonic strain (or stress). We propose a new method for estimating stress magnitudes in shale gas reservoirs based on the principles of viscous relaxation and steady-state tectonic loading. Laboratory experiments show that shale gas reservoir rocks exhibit wide range of viscoplastic behavior most dominantly controlled by its composition, whose stress relaxation behavior is described by a simple power-law (in time) rheology. We demonstrate that a reasonable profile of the principal stress magnitudes can be obtained from geophysical logs by utilizing (1) the laboratory power-law constitutive law, (2) a reasonable estimate of the tectonic loading history, and (3) the assumption that stress ratios ([S2-S3]/[S1-S3]) remains constant due to stress relaxation between all principal stresses. Profiles of horizontal stress differences (SHmax-Shmin) generated based on our method for a vertical well in the Barnett shale (Ft. Worth basin, Texas) generally agrees with the occurrence of drilling-induced tensile fractures in the same well. Also, the decrease in the least principal stress (frac gradient) upon entering the limestone formation underlying the Barnett shale appears to explain the downward propagation of the hydraulic fractures observed in the region. Our approach better acknowledges the time-dependent geomechanical effects that could occur over the course of the geological history. The proposed method may prove to be particularly useful for understanding hydraulic fracture containment within targeted reservoirs.

Sone, H.; Zoback, M. D.

2013-12-01

225

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

SciTech Connect

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

Sharma, G.D.

1992-12-01

226

Gas Migration from a Tight-/Shale-Gas Reservoir to an Overlying Aquifer Through Long Fractures, Conductive Faults and Abandoned Older Wells  

NASA Astrophysics Data System (ADS)

Natural gas from shale reservoirs has become an increasingly important energy resource in recent years. However, the environmental challenges posed by hydraulic fracturing (a necessary stimulation method in tight- and shale-gas reservoirs) remain poorly characterized. There exist theoretical risks of leakage of contaminants from such reservoirs through hydraulically-induced fractures into groundwater resources, but no rigorous model-based analysis has been performed to assess the magnitude of these risks. The mechanisms and quantities of fluids that may realistically be transmitted through induced fractures and faults between geological strata are unknown. Possible exacerbating factors in shale gas well completion or stimulation design are likewise unknown. Quantification of these factors is necessary to quantify possible environmental risks and to aid the industry in the continuing development of sustainable hydraulic fracturing practices. We used the TOUGH+RealGasH2O code to model the two-phase flow of water and gas through long conductive features (such as fractures, conductive faults and abandoned older wells) connecting shale gas systems to shallower aquifers. The complex 3D domains in this study involve Voronoi grids describing challenging geometries that include vertical wells (in the aquifers and abandoned older gas wells), the hydraulically fractured system along long horizontal wells, and thin vertically extensive features intersecting multiple geologic strata. We investigate various configurations of the fractured system, we determine the upper limit if the possible contaminant transport solutions stemming from "worst-case scenarios", and we conduct a thorough sensitivity analysis to determine the dominant mechanisms, conditions and parameters. These include the conductivity of vertically extensive faults and fractures, the relative pressure differential of the underlying shale layer and the aquifer, the permeabilities of the productive intervals, the vertical distances between layers, etc..

Moridis, G. J.; Freeman, C. M.

2012-12-01

227

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

228

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

SciTech Connect

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

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

2008-10-01

229

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

PubMed

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

Lehner, Nicolas; Howk, J Christopher

2011-11-18

230

Caloribacterium cisternae gen. nov., sp. nov., an anaerobic thermophilic bacterium from an underground gas storage reservoir.  

PubMed

A novel anaerobic, moderately thermophilic bacterium (strain SGL43(T)) was isolated from Severo-Stavropolskoye underground gas storage reservoir (Russia). Cells of strain SGL43(T) were motile straight rods, 0.4 µm in diameter and 2.0-3.0 µm in length. The temperature range for growth was 28-65 °C, with optimum growth at 50 °C. The pH range for growth was 5.5-8.0, with optimum growth at pH 7.0-7.5. Growth of strain SGL43(T) was observed at NaCl concentrations of 0-4.0% (w/v) with optimum growth at 1.0% (w/v) NaCl. Substrates utilized by strain SGL43(T) included peptone, yeast extract, glucose, fructose, maltose, galactose, pyruvate and citrate. Products of glucose or citrate fermentation were acetate, hydrogen and CO(2). Thiosulfate was reduced to sulfide. The DNA G+C content of strain SGL43(T) was 43.1 mol%. 16S rRNA gene sequence analysis revealed that strain SGL43(T) belongs to the order Thermoanaerobacterales (phylum 'Firmicutes'). The closest relative of strain SGL43(T) was Thermoanaerobacterium saccharolyticum (86.2% 16S rRNA gene sequence similarity with the type strain). Based on the data presented here, strain SGL43(T) is considered to represent a novel species of a new genus, for which the name Caloribacterium cisternae gen. nov., sp. nov. is proposed. The type strain of Caloribacterium cisternae, the type species of the genus, is SGL43(T) (=DSM 23830(T)=VKM B-2670(T)). PMID:21856985

Slobodkina, G B; Kolganova, T V; Kostrikina, N A; Bonch-Osmolovskaya, E A; Slobodkin, A I

2012-07-01

231

Investigation of a gas regulatable heat pipe with a wicked reservoir  

NASA Astrophysics Data System (ADS)

Results are presented of an analytical and experimental investigation of the characteristics of a heat pipe with a wicked reservoir as the temperature of the cooling medium, and the heat supply intensity change.

Semena, M. G.

1980-05-01

232

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

233

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

234

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

235

Prolific Overton field gas reservoirs within large transverse oolite shoals, Upper Jurassic Haynesville, Eastern Margin East Texas basin  

SciTech Connect

Late Triassic rifting along a northeast-southwest spreading center in east Texas resulted in basement highs along the eastern margin of the East Texas basin that became sites of extensive ooid shoal deposition during Late Jurassic time. Reservoirs within oolite facies at Overton field contain over 1 tcf of natural gas. These large shoals, each approximately 15 mi (24 km) long and 3 mi (4.8 km) wide, trend north-south as a group and northeast-southwest individually. They are oblique to the basin margin but parallel with Jurassic diffracted tidal currents within the East Texas embayment. Modern Bahamian ooid shoals of similar size, trend, and depositional setting occur at the terminus of the deep Tongue-Of-The-Ocean platform reentrant. Overton field reservoirs are in ooid grainstone shoal facies and in transitional shoal margins of skeletal-oolitic-peloidal grainstones and packstones. Adjacent nonreservoir facies are peloidal-skeletal-siliciclastic wackestones and mudstones. Early diagenesis of grainstone reservoir facies included meteoric dissolution and grain stabilization, resulting in abundant chalky intraparticle porosity and equant and bladed calcite cements filling interparticle porosity. Subsequent burial diagenesis resulted in intense solution compaction and coarse equant calcite and saddle crystal dolomite that occluded remaining interparticle porosity. Whole-rock trace element analysis indicates greatest diagenetic flushing (less magnesium, strontium) in porous zones. Stable isotopes for grains and cements show strong overprint of later burial diagenesis, with greater depletion of delta/sup 18/O in reservoir facies. However, hydrocarbons were emplaced prior to late cementation, and unlike other Jurassic Gulf Coast reservoirs, deep burial diagenesis provided no late-stage formation of porosity.

Glynn, W.G.; Covington, T.E.; Lighty, R.G.; Ahr, W.M.

1985-02-01

236

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

237

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

USGS Publications Warehouse

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

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

2013-01-01

238

Greenhouse Gas Production From a Young Boreal Hydroelectric Reservoir (Eastern Canada): A Carbon Isotope Approach  

NASA Astrophysics Data System (ADS)

It is now accepted that boreal hydroelectric reservoirs and lakes produce greenhouse gases (GHG) mainly in the form of CO2. Much of the research has so far focused on old (> 20 year) reservoirs. However, the problems associated with a newly flooded reservoir are different because after flooding, salts and nutrients from the flooded soils are released into the water column (i.e. the reservoir's effect). It is anticipated that the CO2 fluxes should be higher in young reservoirs than in older ones, but little is known about their magnitude and their sources. The Eastmain-1 hydroelectric reservoir is a small reservoir of 603 km2 with a mean depth of 11.5m. Flooding began in November 2005 and ended in May 2006. The flooded area was covered with approximately 65% boreal forests, 21% rivers and lakes and 14% peatlands. Here, we make use stable carbon isotopes to constrain carbon sources and cycling in this disturbed environment. Ultimately, the study aims at estimating annual CO2 fluxes at the water-air interface of the reservoir. Sampling was performed four times (June 2006, August 2006, October 2006 and June 2007) to account for seasonality of the carbon cycle. Twelve sites were visited on the reservoir as well as a natural lake near the reservoir. Three sites were also sampled along a depth gradient. At each sampling site, in situ measurements included water and air temperatures, pH, alkalinity, wind speed, conductivity and dissolved oxygen content. Samples were collected for the analysis of dissolved organic and inorganic carbon (respectively DOC and DIC) and particulate organic carbon (POC) concentrations, for the analysis of the carbon isotopic compositions of DOC, DIC, POC and air CO2 at the water-air interface and finally for the C:N of DOM and POM. DOC concentrations are highest averaging 6.86±1.40 mg*l-1, DIC concentrations average 1.51±0.76 mg*l-1 and POC concentrations are up to 2 orders of magnitude lower averaging 0.036±0.018 mg*l-1. ?13C values of DOC average -27.42±0.32‰ vs V-PDB, close to average C3 plant values and vary little throughout the year as well as throughout the reservoir. ?13C-DIC values vary slightly throughout the reservoir but show large variations from one sampling campaign to the next. Depth profiles show a small decrease in ?13C-DIC with depth, in a well mixed water column. A strong relationship is observed between ?13C-DIC and DIC concentrations. Keeling type regressions (using ?13C-DIC and DIC concentrations) suggest that dissolved CO2 in the reservoir originate from the oxidation of dissolved organic matter within the reservoir.

Lalonde, A.; Helie, J.

2007-12-01

239

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

240

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

SciTech Connect

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

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

1993-07-01

241

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

USGS Publications Warehouse

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

Collett, T. S.

1999-01-01

242

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

243

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

244

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

245

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

246

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

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. 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

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

2006-05-05

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

2003-12-01

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

2003-01-01

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 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

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. 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

253

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

SciTech Connect

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

Bjorn N.P Paulsson

2003-07-01

254

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

SciTech Connect

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

Bjorn N.P. Paulsson

2002-12-01

255

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

SciTech Connect

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

Bjorn N.P. Paulsson

2005-08-21

256

The use of a 3-D compositional numerical reservoir model in the design of a miscible gas injection project. [Use of pseudo-components for ease of calculation  

Microsoft Academic Search

This paper describes the use of a 3-D compositional reservoir model to derive a suitable spacing for the first phase of a pattern miscible gas injection scheme and to predict its performance. A fully compositional thermodynamic programme based on the Peng-Robinson equation of state was used to derive pseudo-components for the 3-D compositional reservoir model. The validity of the pseudo-components

K. B. Arthur; M. A. Rioche; S. Sakthikumar

1983-01-01

257

An Analysis for Simulating Reservoir Performance Under Pressure Maintenance by Gas and\\/or Water Injection  

Microsoft Academic Search

A generalized analysis is described for calculating 3-phase, 3 dimensional flow in reservoirs. The analysis handles pressure maintenance type problems where fluid compressibility effects are negligible. The calculations consist of numerical, simultaneous solution of the 3-flow equations using the iterative alternating direction technique of Douglas and Rachford. The mathematical details are fully described in the Appendix. The analysis is a

K. H. Coats

1968-01-01

258

Study in Reservoir Conditions of Diffusion and Dispersion During Miscible Gas Injection for Enhanced Oil Recovery.  

National Technical Information Service (NTIS)

The experimental study on diffusion, in reservoir conditions was carried out both without a porous medium and with a porous medium. The approach was progressive;first binary mixtures (C/sub 1/ -C/sub 10/) to check our methods, then ternary mixtures (C/sub...

D. Hadiatno

1986-01-01

259

TSR versus non-TSR processes and their impact on gas geochemistry and carbon stable isotopes in Carboniferous, Permian and Lower Triassic marine carbonate gas reservoirs in the Eastern Sichuan Basin, China  

NASA Astrophysics Data System (ADS)

The Palaeozoic and lowermost Mesozoic marine carbonate reservoirs of the Sichuan Basin in China contain variably sour and very dry gas. The source of the gas in the Carboniferous, Permian and Lower Triassic reservoirs is not known for certain and it has proved difficult to discriminate and differentiate the effects of thermal cracking- and TSR-related processes for these gases. Sixty-three gas samples were collected and analysed for their composition and carbon stable isotope values. The gases are all typically very dry (alkane gases being >97.5% methane), with low (<1%) nitrogen and highly variable H2S and CO2. Carboniferous gas is negligibly sour while the Lower Triassic gas tends to be most sour. The elevated H2S (up to 62%) is due to thermochemical sulphate reduction with the most sour Triassic and Permian reservoirs being deeper than 4800 m. The non-TSR affected Carboniferous gas is a secondary gas that was derived from the cracking of sapropelic kerogen-derived oil and primary gas and is highly mature. Carboniferous (and non-sour Triassic and Permian) gas has unusual carbon isotopes with methane and propane being isotopically heavier than ethane (a reversal of typical low- to moderate-maturity patterns). The gas in the non-sour Triassic and Permian reservoirs has the same geochemical and isotopic characteristics (and therefore the same source) as the Carboniferous gas. TSR in the deepest Triassic reservoirs altered the gas composition reaching 100% dryness in the deepest, most sour reservoirs showing that ethane and propane react faster than methane during TSR. Ethane evolves to heavier carbon isotope values than methane during TSR leading to removal of the reversed alkane gas isotope trend found in the Carboniferous and non-sour Triassic and Permian reservoirs. However, methane was directly involved in TSR as shown by the progressive increase in its carbon isotope ratio as gas souring proceeded. CO2 increased in concentration as gas souring proceeded, but typical CO2 carbon isotope ratios in sour gases remained about -4‰ V-PDB showing that it was not solely derived from the oxidation of alkanes. Instead CO2 may partly result from reaction of sour gas with carbonate reservoir minerals, such as Fe-rich dolomite or calcite, resulting in pyrite growth as well as CO2-generation.

Liu, Q. Y.; Worden, R. H.; Jin, Z. J.; Liu, W. H.; Li, J.; Gao, B.; Zhang, D. W.; Hu, A. P.; Yang, C.

2013-01-01

260

Synthesis of fluorinated nano-silica and its application in wettability alteration near-wellbore region in gas condensate reservoirs  

NASA Astrophysics Data System (ADS)

Fluorinated silica nanoparticles were prepared to alter rock wettability near-wellbore region in gas condensate reservoirs. Hence fluorinated silica nanoparticles with average diameter of about 80 nm were prepared and used to alter limestone core wettability from highly liquid-wet to intermediate gas-wet state. Water and n-decane contact angles for rock were measured before and after treatment. The contact angle measured 147° for water and 61° for n-decane on the core surface. The rock surface could not support the formation of any water or n-decane droplets before treatment. The functionalized fluorinated silica nanoparticles have been confirmed by the Csbnd F bond along with Sisbnd Osbnd Si bond as analyzed by FT-IR. The elemental composition of treated limestone core surface was determined using energy dispersive X-ray spectroscopy analyses. The final evaluation of the fluorinated nanosilica treatment in terms of its effectiveness was measured by core flood experimental tests.

Mousavi, M. A.; Hassanajili, Sh.; Rahimpour, M. R.

2013-05-01

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 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

262

Dry Gas Zone, Elk Hills Field, Kern County, California: General reservoir study: Geologic text and tables: Final report  

SciTech Connect

The Dry Gas Zone was defined by US Naval Petroleum Reserve No. 1 Engineering Committee (1957) as ''/hor ellipsis/all sands bearing dry gas above the top of the Lower Scalez marker bed. The term is used to include the stratigraphic interval between the Scalez Sand Zone and the Tulare Formation - the Mya Sand Zone. The reservoirs in this upper zone are thin, lenticular, loosely cemented sandstones with relatively high permeabilities.'' Other than the limited Tulare production in the western part of the field, the Dry Gas Zone is the shallowest productive zone in the Elk Hills Reserve and is not included in the Shallow Oil Zone. It is Pliocene in age and makes up approximately eighty percent of the San Joaquin Formation as is summarized in Exhibit TL-1. The lithologic character of the zone is one of interbedded shales and siltstones with intermittent beds of various thickness sands. The stratigraphic thickness of the Dry Gas Zone ranges from 950 to 1150 feet with a general thickening along the flanks and thinning over the crests of the anticlines. The productive part of the Dry Gas Zone covers portions of 30 sections in an area roughly 10 miles long by 4 miles wide. 4 refs.

Not Available

1988-06-29

263

Organic geochemical and fluid inclusion evidence for filling stages of natural gas and bitumen in volcanic reservoir of Changling faulted depression, southeastern Songliao basin  

Microsoft Academic Search

Recently, volcanic gas reservoirs in Yaoyingtai (???) and Daerhan (???) tectonic belts in Changling (??) faulted depression\\u000a of southeastern Songliao (??) basin have been discovered. Based on the compositions and isotopic values, the natural gas is\\u000a characterized by high content of methane, low content of C2\\u000a +, and C1\\/C1–5 beyond 0.95. Also, the natural gas contains nonhydrocarbons including carbon dioxide

Liming Qin; Zhihuan Zhang; Yuyuan Wu; Rujin Feng; Ling Zan

2010-01-01

264

Development of general inflow performance relationships (IPR`s) for slanted and horizontal wells producing heterogeneous solution-gas drive reservoirs  

SciTech Connect

Since 1968, the Vogel equation has been used extensively and successfully for analyzing the inflow performance relationship (IPR) of flowing vertical wells producing by solution-gas drive. Oil well productivity can be rapidly estimated by using the Vogel IPR curve and well outflow performance. With recent interests on horizontal well technology, several empirical IPRs for solution-gas drive horizontal and slanted wells have been developed under homogeneous reservoir conditions. This report presents the development of IPRs for horizontal and slanted wells by using a special vertical/horizontal/slanted well reservoir simulator under six different reservoir and well parameters: ratio of vertical to horizontal permeability, wellbore eccentricity, stratification, perforated length, formation thickness, and heterogeneous permeability. The pressure and gas saturation distributions around the wellbore are examined. The fundamental physical behavior of inflow performance for horizontal wells is described.

Cheng, A.M.

1992-04-01

265

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

Microsoft Academic Search

Of an estimated 482 billion bbl (76.6 Gm³) of in-place oil discovered in the US, 158 billion (25.1 Gm³) 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

K. P. Sessions; D. H. Lehman

1990-01-01

266

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

267

Kinetics of hydrocarbon generation for Well Yingnan 2 gas reservoir, Tarim Basin, China  

Microsoft Academic Search

Well Yingnan 2, an important exploratory well in the east of Tarim Basin, yields high commercial oil and gas flow in Jurassic.\\u000a Natural gas components and carbon isotopic composition indicate that it belongs to sapropel type gas. Because this region\\u000a presents many suits of hydrocarbon source rocks, there are some controversies that natural gases were generated from kerogen\\u000a gas or

ZhongYao Xiao; XianMing Xiao; DeMing Ma; YuHong Lu; ChaoShi Yang

2008-01-01

268

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

SciTech Connect

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

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

1994-08-01

269

Anisotropic Velocities of Gas Hydrate-Bearing Sediments in Fractured Reservoirs.  

National Technical Information Service (NTIS)

During the Indian National Gas Hydrate Program Expedition 01 (NGHP01), one of the richest marine gas hydrate accumulations was discovered at drill site NGHP0110 in the Krishna-Godavari Basin, offshore of southeast India. The occurrence of concentrated gas...

2009-01-01

270

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

271

Integrated seismic study of naturally fractured tight gas reservoirs. Technical progress report, October 1, 1992--December 31, 1992  

SciTech Connect

This was the fifth quarter of the contract. During this quarter we (1) got approval for the NEPA requirements related to the field work, (2) placed the subcontract for the field data acquisition, (3) completed the field work, and (4) began processing the seismic data. As already reported, the field data acquisition was at Acomo`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.

Nur, A.

1993-01-21

272

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

273

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

274

2-D numerical simulation of digital rock experiments with lattice gas automation for electrical properties of reservoir formation  

NASA Astrophysics Data System (ADS)

The lattice gas automation (LGA) simulations for electrical transport properties have been performed on digital rock samples virtually saturated with oil and water to investigate the relationship between resistivity index and water (oil) saturation (I-Sw) of reservoir rocks at micropore scale. The digital rocks were constructed by the pileup of matrix grains with a radius distribution obtained by laboratory measurements on reservoir rock samples. The LGA was then applied to simulate the flow of electrical current through the pores of these virtually saturated digital rocks to reveal the non-Archie relation of I-Sw. The results from LGA simulation indicate that the I-Sw relation is generally a non-linear function changing with the decrease of water saturation and porosity on a log-log scale. Archie's equation is an approximation in high water saturation range. Based on this study, we developed a new equation for non-Archie relation of I-Sw to improve the calculation of pore fluid saturation. The calculated results with this new equation have shown better fit to laboratory measurements.

Yue, Wenzheng; Tao, Guo; Wang, Shangxu; Tian, Bin

2010-12-01

275

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

276

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

277

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

278

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

279

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

280

Numerical modeling of the simulated gas hydrate production test at Mallik 2L-38 in the pilot scale pressure reservoir LARS - Applying the "foamy oil" model  

NASA Astrophysics Data System (ADS)

In the context of the German joint project SUGAR (Submarine Gas Hydrate Reservoirs: exploration, extraction and transport) we conducted a series of experiments in the LArge Reservoir Simulator (LARS) at the German Research Centre of Geosciences Potsdam. These experiments allow us to investigate the formation and dissociation of hydrates at large scale laboratory conditions. We performed an experiment similar to the field-test conditions of the production test in the Mallik gas hydrate field (Mallik 2L-38) in the Beaufort Mackenzie Delta of the Canadian Arctic. The aim of this experiment was to study the transport behavior of fluids in gas hydrate reservoirs during depressurization (see also Heeschen et al. and Priegnitz et al., this volume). The experimental results from LARS are used to provide details about processes inside the pressure vessel, to validate the models through history matching, and to feed back into the design of future experiments. In experiments in LARS the amount of methane produced from gas hydrates was much lower than expected. Previously published models predict a methane production rate higher than the one observed in experiments and field studies (Uddin et al. 2010; Wright et al. 2011). The authors of the aforementioned studies point out that the current modeling approach overestimates the gas production rate when modeling gas production by depressurization. They suggest that trapping of gas bubbles inside the porous medium is responsible for the reduced gas production rate. They point out that this behavior of multi-phase flow is not well explained by a "residual oil" model, but rather resembles a "foamy oil" model. Our study applies Uddin's (2010) "foamy oil" model and combines it with history matches of our experiments in LARS. Our results indicate a better agreement between experimental and model results when using the "foamy oil" model instead of conventional models of gas flow in water. References Uddin M., Wright J.F. and Coombe D. (2010) - Numerical Study of gas evolution and transport behaviors in natural gas hydrate reservoirs; CSUG/SPE 137439. Wright J.F., Uddin M., Dallimore S.R. and Coombe D. (2011) - Mechanisms of gas evolution and transport in a producing gas hydrate reservoir: an unconventional basis for successful history matching of observed production flow data; International Conference on Gas Hydrates (ICGH 2011).

Abendroth, Sven; Thaler, Jan; Klump, Jens; Schicks, Judith; Uddin, Mafiz

2014-05-01

281

Petroleum reservoir data for testing simulation models  

Microsoft Academic Search

This report consists of reservoir pressure and production data for 25 petroleum reservoirs. Included are 5 data sets for single-phase (liquid) reservoirs, 1 data set for a single-phase (liquid) reservoir with pressure maintenance, 13 data sets for two-phase (liquid\\/gas) reservoirs and 6 for two-phase reservoirs with pressure maintenance. Also given are ancillary data for each reservoir that could be of

J. M. Lloyd; W. Harrison

1980-01-01

282

Analysis of stratigraphic and production relationships of Devonian-shale gas reservoirs in Ohio. Final report, October 1985-November 1988  

SciTech Connect

The stratigraphy, structure, and production characteristics of the Devonian-Mississippian shale sequence were evaluated for Lawrence, Meigs, Monroe, Noble, and Washington Counties, Ohio. The computerized data bases for the study consist of permit and completion data for 4,198 wells, geophysical-log tops of 3,555 wells and production records for 898 wells. Naturally completed wells have the highest cumulative production but account for less than 10% of the wells. Hydraulically fractured wells have the highest average initial potential. Structure, isopach, isopotential, and cumulative-production maps all show a northwest-southeast-trending 'grain' in the study area. Numerous stratigraphic and structural anomalies correlate with directional trends on isopotential and cumulative-production maps. This correlation indicates that fracture systems are the primary reservoir for Devonian shale natural gas.

Baranoski, M.T.; Riley, R.A.; Wickstrom, I.H.; Stith, D.A.

1988-12-01

283

Anisotropic Velocities of Gas Hydrate-Bearing Sediments in Fractured Reservoirs  

USGS Publications Warehouse

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

Lee, Myung W.

2009-01-01

284

Seismic Reservoir Oil-Gas Prediction Study Based on Rough Set and RBF Network  

Microsoft Academic Search

In predicting oil-gas reserves in the course of seismic prospecting, a direct employment of neural network will take up enormous storage, lead to prolonged computing time and complicate the structure thanks to the numerous input information dimensions of seismic attributes. To solve the problem, taking into account the characteristics of oil-gas seismic attributes, the paper proposes a prospecting approach based

Hongjie Liu; Boqin Feng; Kewen Xia; Hongmin Zheng

2006-01-01

285

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

NASA Astrophysics Data System (ADS)

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

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

2012-12-01

286

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

287

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

288

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

289

Detecting Low-Frequency Seismic Signals From Surface Microseismic Monitoring of Hydraulic Fracturing of a Tight-Sand Gas Reservoir  

NASA Astrophysics Data System (ADS)

For both surface and downhole microseismic monitoring, generally geophones with resonance frequency greater than 4.5 Hz are used. Therefore, useful information below 4.5 Hz may not be detected. In a recent experiment, we installed14 3-component broadband seismic sensors on the surface to monitor the process of hydraulic fracturing of tight sand gas reservoirs. The sensor has a broad frequency range of 30 s to 100 Hz with a very high sensitivity of 2400 m/v/s. The reservoirs are located around 1.5 km depth. There are two fracturing stages along a vertical well, lasting for about 2 hours. We recorded the data continuously during the fracturing process at a sampling rate of 50 Hz. From time-frequency analysis of continuous data, we found some high-energy signals at resonance frequencies between 10 and 20 Hz and a relatively weaker signal at a resonance frequency of ~27 Hz during the hydraulic fracturing. These signals with various resonance frequencies are likely caused by vibrations of high-pressure pipes. In addition to the resonance frequencies, the time-frequency analysis also showed consistent low frequency signals between 3 and 4 Hz at different time. The move-out analysis showed that these signals traveled at shear-wave speeds. We have detected 77 effective low frequency events during the 2-hour hydraulic fracturing process, among which 42 were located by a grid-search location method. The horizontal distribution of the events aligns with the maximum horizontal compressive stress direction. Because of the uncertainty in the velocity model, the low-frequency seismic events are not located in the fracturing depths. Recently, long-period, long-duration seismic events in the frequency band of 10 to 80 Hz were detected during hydraulic fracture stimulation of a shale gas reservoir, which may be caused by slow slip along faults/fractures (Das and Zoback, 2011). In the active volcanic areas, monochromatic events that are related to circulation of hydrothermal fluids are often detected. Our detected low frequency seismic signals have waveforms and frequency contents resembling the monochromatic events detected in volcanic areas, therefore we believe they are also likely caused by movement of fracturing fluids.

Yu, H.; Zhang, H.; Zeng, X.

2013-12-01

290

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

291

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

292

Modeling of fault reactivation and induced seismicity during hydraulic fracturing of shale-gas reservoirs  

EPA Science Inventory

We have conducted numerical simulation studies to assess the potential for injection-induced fault reactivation and notable seismic events associated with shale-gas hydraulic fracturing operations. The modeling is generally tuned toward conditions usually encountered in the Marce...

293

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

294

Chalk Project. Oil- and Gas Containing Chalk Reservoirs in the Danish Part of the Central Graben. Pt. 5 Q. Reservoir Parametres from Formation Evaluation. Kalkplot Description.  

National Technical Information Service (NTIS)

One of the items of the ''Chalk Project'' is to map the vertical and lateral distribution of some petrophysical reservoir parametres in the Chalk Group of the Danish Central Graben. For this purpose is chosen the petrophysical well logs and core-analysis ...

K. Lieberkind

1983-01-01

295

Rate and State Frictional Properties of Shale Gas Reservoir Rocks and FIB/SEM Microscopy of Lab-Generated Fault Surfaces  

NASA Astrophysics Data System (ADS)

To investigate the slip behavior of natural faults in shale gas reservoirs under the conditions of hydraulic stimulation, we conduct laboratory investigations of the frictional and hydrologic properties of shale gas reservoir rocks. We report on several initial studies of the frictional properties of cores from the Haynesville and Eagleford shale reservoirs, performed under dry and wet conditions and in-situ confining and pore pressures. The results of velocity-stepping experiments show strongly velocity-strengthening frictional behavior at sliding velocities ranging from 0.1 - 100 ?m/s and sliding displacements of up to 5 mm. Focused ion beam and scanning electron microscopy of the fault sliding surfaces from these experiments reveals slickenside lineations in the direction of fault slip and significant production of sub-micron clay gouge. In addition, fault surface damage is visible in the form of bedding-parallel, micron scale cracks, which form at pre-existing pores in the intact shale matrix, suggesting a mechanism for permeability enhancement during slow slip. These results are evaluated in terms of rate-and-state constitutive models for frictional stability to develop a physical model for induced slip by hydraulic stimulation in shale gas reservoirs.

Kohli, A. H.; Zoback, M. D.

2011-12-01

296

Efficiency analysis of greenhouse gas sequestration during miscible CO2 injection in fractured oil reservoirs.  

PubMed

During CO2 injection into naturally fractured oil reservoirs for enhanced oil recovery, the great portion of oil is recovered by matrix-fracture interaction. Diffusive mass transfer between matrix and fracture controls this process if CO2 is miscible with matrix oil. Oil expelled from matrix is replaced by CO2, and the matrix could be potentially a good storage medium for the long-term. For the cooptimization of the oil recovery and CO2 storage, i.e., maximizing the oil recovery while maximizing the amount of CO2 stored, we propose an efficiency analysis using a dimensionless term defined as the global effectiveness factor. The Biot number and Thiele modulus were incorporated in the development of the global effectiveness factor. Diffusion coefficients and the rate of mass-transfer constants were obtained from our previous finite element modeling study. We first defined and derived the dimensionless groups to be used in the efficiency analysis and then formulated a relationship between the dimensionless groups and the efficiency indicators, i.e., the ratios of total solute (oil) produced to total solvent injected and total solvent stored to total solvent injected. It was shown that the efficiency of the process can be represented by a dimensionless group that consists of well-known dimensionless numbers such as the Reynolds number, the Peclet number, the Sherwood number, and the global effectiveness factor. PMID:18754463

Trivedi, Japan; Babadagli, Tayfun

2008-08-01

297

Satellite linear features and pressure variations in Cretaceous shallow gas reservoirs, southern Bowdoin dome, Montana  

Microsoft Academic Search

For three decades prior to 1960, shallow gas was produced in the southern part of Bowdoin dome from the Cretaceous Bowdoin Sandstone of the Carlile Formation and the Phillips Sandstone of the Greenhorn Formation. Historical production records from this period suggest that patterns of pressure decline are closely related to the geometry of linear features visible on satellite images. Linear

G. W. Shurr; M. K. Tozer; A. D. Tweed; F. D. Wosick

1991-01-01

298

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

NASA Astrophysics Data System (ADS)

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

Hartigan, David; Lovell, Mike; Davies, Sarah

2014-05-01

299

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

NASA Astrophysics Data System (ADS)

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

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

2014-05-01

300

3-D seismic improves structural mapping of a gas storage reservoir (Paris basin)  

Microsoft Academic Search

In the Paris basin, anticlinal structures with closure of no more than 80 m and surface area of a few km[sup 2] are used for underground gas storage. At Soings-en-Sologne, a three-dimensional (3-D) survey (13 km[sup 2]) was carried out over such a structure to establish its exact geometry and to detail its fault network. Various reflectors were picked automatically

F. Huguet; C. Pinson

1993-01-01

301

Fracture detection, mapping, and analysis of naturally fractured gas reservoirs using seismic technology  

SciTech Connect

There are a number of producing gas fields in the United States where production is controlled by natural fractures. The host rock may consist of low porosity, low permeability formations, and wells completed in the unfractured rock have low productivity. On the other hand, wells intercepting fractured rocks may show good production. The objective of the research under this contract is to improve the technology for detecting fractures by surface geophysical methods. This remote detection of fractures will allow optimum placement of vertical or horizontal wells. The critical components of the project are: (1) Selection of a gas field with known production from naturally occurring fractures. The project scope does not allow for drilling of wells, so that evidence for occurrence of fractures and gas production from fractures must be obtained from existing wells` field production history, and other data. (2) Acquisition of both surface and downhole seismic P-wave and S-wave data. The project will acquire one 9-component (9-C) VSP. In a 9-C VSP survey, seismic events are recorded by 3-C geophones from one P-wave, and two perpendicular oriented S-wave sources (SH and SV). Also, approximately 12 miles of 9-C surface seismic data will be acquired. (3) Processing and interpretation of 9-C VSP and 9-C surface seismic data, and correlating the seismic anomalies observed to all available geologic and production information to show how the variations in seismic response is related to fracture density, fracture orientation, lithology, structure, and production history.

Hoekstra, P. [Coleman Research Corp., Orlando, FL (United States); Lynn, H. [Lynn (H.) Inc. (United States)

1993-12-31

302

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

NASA Astrophysics Data System (ADS)

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

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

2012-12-01

303

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

304

Large Reservoirs Of Metal-Poor Gas Around z<1 Galaxies  

NASA Astrophysics Data System (ADS)

Large-scale outflows and inflows through the circumgalactic medium (CGM) strongly affect the shape, structure, and evolution of galaxies. The metallicity distribution of gas in the CGM can shed light on the balance of infalling and outflowing material about galaxies. Using Hubble COS and ground-based observations, we have determined the metallicity distribution function of the cool CGM at z<1. It is strongly bimodal with metal-poor and metal-rich branches peaking at about 3% and 50% solar metallicity. Our results show that there is a not only a significant mass of metal-rich gas in the CGM of z<1 galaxies, but also a previously-undiscovered cold, metal-poor component. We argue that the metal poor branch of the cool CGM provides the best evidence for the long-sought cold accretion flows entering galaxies from the intergalactic medium. Based on HST, LBT, Keck, and Magellan observations. Support for this research was provided by NASA through grants HST-GO-11741, HST-GO-11598, HST-AR-12854 from the Space Telescope Science Institute and NSF under Grant No. AST-1212012.

Lehner, Nicolas; Howk, J. C.; Wotta, C.; Tumlinson, J.; Tripp, T. M.; Prochaska, J. X.; O'Meara, J.; Werk, J.; Fox, A.; Ribaudo, J.

2014-01-01

305

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

NASA Astrophysics Data System (ADS)

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

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

2014-05-01

306

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

USGS Publications Warehouse

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

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

2012-01-01

307

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

Microsoft Academic Search

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

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

1996-01-01

308

Characterization of oil and gas reservoir heterogeneity. [Quarterly technical progress report], April 1, 1993--June 30, 1993  

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 I 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.

1993-08-01

309

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

310

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

NASA Astrophysics Data System (ADS)

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

Ortega Mercado, Camilo Ernesto

311

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

312

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

NASA Astrophysics Data System (ADS)

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

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

2012-12-01

313

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

314

Reservoir sequence analysis: A new technology for the 90`s and its application to oil and gas fields  

SciTech Connect

Reservoir Sequence Analysis when applied to existing fields can increase the production, life of the field and extend the field with a minimum of cost. In this technology we identify reservoir sands in a standard-of-reference well, to establish a seismic sequence stratigraphic well-tie for the entire field. Age date the Maximum Flooding Surfaces and Sequence Boundaries above and below reservoir sands on a well-log and seismic pro- file and/or workstation using High Resolution Biostratigraphic Analysis, species abundance and diversity histograms and their patterns, and paleoenvironmental paleobathymetric changes. Identify the systems tracts and their corresponding reservoir sands in between age dated Maximum Flooding Surfaces. Interpret the reservoir sands as to type, i.e. IVF, point bar, coastal belt, forced regression, falling stage, bottom-set (shingled) turbidites, slope fan channel, channel overbank, and basin floor fans. Identify and correlate the same individual sands in different wells, and note new sands in a well and sands that shale-out in a well. Correlate the Maximum Flooding Surfaces above and below the reservoir section in additional wells to see which part of the reservoir section and sands have been penetrated. Identify systems tracts in additional wells and construct isopach, sand percent maps of individual systems tract interval in each well. Correlate sand packages, with a high degree of confidence, from upthrown to downthrown fault blocks, around salt domes, and updip with downdip.

Wornardt, W.W. [Micro-Strat Inc., Houston, TX (United States)

1996-08-01

315

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

316

NFFLOW Fractured Reservoir Flow Model Improvements  

NASA Astrophysics Data System (ADS)

NFFLOW is a reservoir simulator designed for fractured, tight reservoirs. It is used for modeling flows, pressures and compositions in such natural gas reservoirs, storage reservoirs, and carbon dioxide reservoir storage. It was first developed in 1997 and is subject to contonuinuous improvements. Originally, communication between rock matrix and fracture network was by flows from and to immediately adjacent fractures and matrix. We report on the capability of flows occurring across a rock matrix.

Boyle, E. J.; Sams, W. N.

2013-12-01

317

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

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 plots, detailed core log, paragenetic sequence, and reservoir characterization sh...

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

1992-01-01

318

Reservoir limnology  

SciTech Connect

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

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

1990-01-01

319

Petroleum reservoir data for testing simulation models  

SciTech Connect

This report consists of reservoir pressure and production data for 25 petroleum reservoirs. Included are 5 data sets for single-phase (liquid) reservoirs, 1 data set for a single-phase (liquid) reservoir with pressure maintenance, 13 data sets for two-phase (liquid/gas) reservoirs and 6 for two-phase reservoirs with pressure maintenance. Also given are ancillary data for each reservoir that could be of value in the development and validation of simulation models. A bibliography is included that lists the publications from which the data were obtained.

Lloyd, J.M.; Harrison, W.

1980-09-01

320

Integrated seismic study of naturally fractured tight gas reservoirs. Technical progress report for the period: 7/1/93--9/31/93  

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 paths of production. During this eighth quarter of the seismic study of this area, work continued in processing seismic data, collecting additional geological information to aid in the interpretation, and integrating regional structural information and fracture trends with observations of structure in the study area.

Mavko, G.; Nur, A.

1993-10-23

321

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

NASA Astrophysics Data System (ADS)

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

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

2014-05-01

322

A fuzzy logic approach for estimation of permeability and rock type from conventional well log data: an example from the Kangan reservoir in the Iran Offshore Gas Field  

NASA Astrophysics Data System (ADS)

Permeability and rock type are the most important rock properties which can be used as input parameters to build 3D petrophysical models of hydrocarbon reservoirs. These parameters are derived from core samples which may not be available for all boreholes, whereas, almost all boreholes have well log data. In this study, the importance of the fuzzy logic approach for prediction of rock type from well log responses was shown by using an example of the Vp to Vs ratio for lithology determination from crisp and fuzzy logic approaches. A fuzzy c-means clustering technique was used for rock type classification using porosity and permeability data. Then, based on the fuzzy possibility concept, an algorithm was prepared to estimate clustering derived rock types from well log data. Permeability was modelled and predicted using a Takagi-Sugeno fuzzy inference system. Then a back propagation neural network was applied to verify fuzzy results for permeability modelling. For this purpose, three wells of the Iran offshore gas field were chosen for the construction of intelligent models of the reservoir, and a forth well was used as a test well to evaluate the reliability of the models. The results of this study show that fuzzy logic approach was successful for the prediction of permeability and rock types in the Iran offshore gas field.

Kadkhodaie Ilkhchi, Ali; Rezaee, Mohammadreza; Moallemi, Seyed Ali

2006-12-01

323

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

SciTech Connect

This was the ninth quarter of the contract. During this quarter we (1) continued processing the seismic data, (2) collected additional logs to aid in the interpretation, and (3)began modeling some of the P-wave amplitude anomalies that we see in the data. 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 has and oil present. Reservoirs are highly compartmentalized due tot he 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 contract with it by an unconformity.

Mavko, G.; Nur, A.

1994-01-29

324

Modeling the Injection of Carbon Dioxide and Nitrogen into a Methane Hydrate Reservoir and the Subsequent Production of Methane Gas on the North Slope of Alaska  

NASA Astrophysics Data System (ADS)

HydrateResSim (HRS) is an open-source finite-difference reservoir simulation code capable of simulating the behavior of gas hydrate in porous media. The original version of HRS was developed to simulate pure methane hydrates, and the relationship between equilibrium temperature and pressure is given by a simple, 1-D regression expression. In this work, we have modified HydrateResSim to allow for the formation and dissociation of gas hydrates made from gas mixtures. This modification allows one to model the ConocoPhillips Ignik Sikumi #1 field test performed in early 2012 on the Alaska North Slope. The Ignik Sikumi #1 test is the first field-based demonstration of gas production through the injection of a mixture of carbon dioxide and nitrogen gases into a methane hydrate reservoir and thereby sequestering the greenhouse gas CO2 into hydrate form. The primary change to the HRS software is the added capability of modeling a ternary mixture consisting of CH4 + CO2 + N2 instead of only one hydrate guest molecule (CH4), therefore the new software is called Mix3HydrateResSim. This Mix3HydrateResSim upgrade to the software was accomplished by adding primary variables (for the concentrations of CO2 and N2), governing equations (for the mass balances of CO2 and N2), and phase equilibrium data. The phase equilibrium data in Mix3HydrateResSim is given as an input table obtained using a statistical mechanical method developed in our research group called the cell potential method. An additional phase state describing a two-phase Gas-Hydrate (GsH) system was added to consider the possibility of converting all available free water to form hydrate with injected gas. Using Mix3HydrateResSim, a methane hydrate reservoir with coexisting pure-CH4-hydrate and aqueous phases at 7.0 MPa and 5.5°C was modeled after the conditions of the Ignik Sikumi #1 test: (i) 14-day injection of CO2 and N2 followed by (ii) 30-day production of CH4 (by depressurization of the well). During the injection phase, the injection well is modeled as a fixed-condition boundary maintained as a gas phase (23% CO2+ 77% N2) at 9.65 MPa and 5.5 °C. Initially, there is an increase in the saturation of hydrate indicating the formation of secondary hydrate due to the injected gas and the available free water. There is also a slight increase in the temperature due to the exothermic reaction of hydrate formation. As the hydrate becomes saturated with the injected gases it releases CH4. After the initial 14 days of injection, a mixture of the three gases was produced through depressurization. This was modeled by maintaining the well as a fixed-state boundary at the bottom-hole pressure. The amount of CH4 released from the hydrate phase during the injection and production phases and the amount of CO2 and N2 gases sequestered as hydrates have been examined in this study. A model-based history-matching of the gas flow rates from the ConocoPhillips field test will be conducted to validate the code.

Garapati, N.; McGuire, P. C.; Liu, Y.; Anderson, B. J.

2012-12-01

325

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

SciTech Connect

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

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

1989-03-01

326

Gas hydrate reservoir and active methane-venting province in sediments on < 20 Ma young oceanic crust in the Fram Strait, offshore NW-Svalbard  

NASA Astrophysics Data System (ADS)

Seafloor pockmarks are common indicators for vertical fluid flow and frequently associated with methane discharge through the gas-hydrate stability zone (GHSZ). The present-day flux through these degassing systems is presumably at a low level on most rifted continental margins. A pockmark-field on the NW-Svalbard passive margin is located on young ocean crust (< 20 Ma) and shows evidence of ongoing, episodic degassing. New geophysical data from the Vestnesa Ridge (˜ 79°N), a mounded and elongated sediment drift in the eastern Fram Strait, reveal a gas-hydrate, free-gas and venting system that is exceptionally more dynamic than documented elsewhere along the northeastern North Atlantic margin. The prominent bottom-simulating reflection (BSR), about 200 mbsf, separates anomalously high P-wave velocities in the GHSZ from a remarkable underlying low-velocity zone, indicating the presence of gas hydrate and gas in the pore space. Inversion of P-wave velocity data using the differential effective medium theory yields a two-dimensional concentration model of methane hydrate and free gas. The model predicts saturations of up to 11% in the hydrate reservoir, which due to the seafloor topography forms a large anticlinal permeability-barrier. Below, in the low-velocity zone (i.e., 1350-1500 m/s), up to 3% of free gas is predicted across the apex of the Vestnesa Ridge and in the immediate vicinity of extensional faults. A conservative estimate indicates that 225 kg/m 2 of pure methane is stored in hydrate and gas in the upper 230 m of the sedimentary column. An elongated pockmark-field, consisting of > 100 individual pockmarks up to 600 m wide, systematically aligns the apex of the Vestnesa Ridge. Active, vigorous degassing from the topography-controlled pressure-valve system was evident from a 750-m-high and ˜ 150-m-wide gas flare observed in the water column during a cruise with R/V Jan Mayen in October 2008. The gas flare documents dynamic degassing through the corresponding chimney, which penetrates the entire GHSZ and into the underlying free gas zone. Cruises in 2006 and 2007 did not detect active gas venting above the pockmark-field. Accordingly, vigorous degassing may operate in an episodic mode, where hydrothermal circulation systems through young ocean crust may play a significant role.

Hustoft, Steinar; Bünz, Stefan; Mienert, Jürgen; Chand, Shyam

2009-06-01

327

76 FR 80553 - Mandatory Reporting of Greenhouse Gases: Technical Revisions to the Petroleum and Natural Gas...  

Federal Register 2010, 2011, 2012, 2013

...types: Oil, high permeability gas, shale gas, coal seam, or other tight reservoir...types: Oil, high permeability gas, shale gas, coal seam, or other tight reservoir...one of the four gas formations (shale gas, tight reservoir rock, coal...

2011-12-23

328

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

PubMed Central

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

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

2013-01-01

329

Increasing development efficiency in low-permeability gas reservoirs: A synopsis of tight gas sands project research, November 1982December 1992  

Microsoft Academic Search

To enhance the application of research results by industry, the report provides a guide to the literature developed at the Bureau of Economic Geology in the Geological Analysis of Primary and Secondary Tight Gas Sands Objectives Project as part of the Gas Research Institute (GRI) Tight Gas Sands Research Program during the period 1982 through 1992. The authors review some

Laubach

1993-01-01

330

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

USGS Publications Warehouse

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

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

2012-01-01

331

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

332

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

Microsoft Academic Search

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

John W. Beeman; Alec G. Maule

2006-01-01

333

Carbonate petroleum reservoirs  

SciTech Connect

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

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

1985-01-01

334

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

National Technical Information Service (NTIS)

The Molina Member of the Wasatch Formation produces natural gas from several fields along the Colorado River in the Piceance Basin, northwestern Colorado. The Molina Member is a distinctive sandstone that was deposited in a unique fluvial environment of s...

J. C. Lorenz

1997-01-01

335

Seismic attribute analysis of unconventional reservoirs, and stratigraphic patterns  

Microsoft Academic Search

Seismic volumetric attributes have become one of the key components in aiding interpretation and investigation of the hydrocarbon reservoirs. These reservoirs can be either conventional or unconventional. The application of seismic attributes in conventional reservoirs with mapping bright spots, faults, and channels has been quite successful. Now we face challenges in mapping unconventional reservoirs such as shales, tight gas sands,

Kui Zhang

2010-01-01

336

Geometry of thrusting in the Wilburton gas field and surrounding areas, Arkoma Basin, Oklahoma: Implications for gas exploration in the Spiro Sandstone reservoirs  

Microsoft Academic Search

The Arkoma basin is an arcuate structural feature located in southern Oklahoma and western Arkansas. It is recognized as a foreland basin of the Ouachita fold and thrust belt and is one of the most prolific gas producing basins in North America. The Choctaw fault is the leading-edge thrust of the Ouachita frontal belt. The Wilburton gas field is located

C. Ibrahim; A. S. Zuhair; H. Forrest

1995-01-01

337

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

338

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

NASA Astrophysics Data System (ADS)

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

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

2008-06-01

339

Fundamentals of gas flow in shale; What the unconventional reservoir industry can learn from the radioactive waste industry  

NASA Astrophysics Data System (ADS)

Tight formations, such as shale, have a wide range of potential usage; this includes shale gas exploitation, hydrocarbon sealing, carbon capture & storage and radioactive waste disposal. Considerable research effort has been conducted over the last 20 years on the fundamental controls on gas flow in a range of clay-rich materials at the British Geological Survey (BGS) mainly focused on radioactive waste disposal; including French Callovo-Oxfordian claystone, Belgian Boom Clay, Swiss Opalinus Clay, British Oxford Clay, as well as engineered barrier material such as bentonite and concrete. Recent work has concentrated on the underlying physics governing fluid flow, with evidence of dilatancy controlled advective flow demonstrated in Callovo-Oxfordian claystone. This has resulted in a review of how advective gas flow is dealt with in Performance Assessment and the applicability of numerical codes. Dilatancy flow has been shown in Boom clay using nano-particles and is seen in bentonite by the strong hydro-mechanical coupling displayed at the onset of gas flow. As well as observations made at BGS, dilatancy flow has been shown by other workers on shale (Cuss et al., 2012; Angeli et al. 2009). As well as experimental studies using cores of intact material, fractured material has been investigated in bespoke shear apparatus. Experimental results have shown that the transmission of gas by fractures is highly localised, dependent on normal stress, varies with shear, is strongly linked with stress history, is highly temporal in nature, and shows a clear correlation with fracture angle. Several orders of magnitude variation in fracture transmissivity is seen during individual tests. Flow experiments have been conducted using gas and water, showing remarkably different behaviour. The radioactive waste industry has also noted a number of important features related to sample preservation. Differences in gas entry pressure have been shown across many laboratories and these may be attributed to different core preparation techniques. Careful re-stressing of core barrels and sealing techniques also ensure that experiments are conducted on near in situ condition. The construction of tunnels within shale clearly aids our understanding of the interaction of engineered operations (borehole drilling or tunnelling) on the behaviour of the rock. References: Angeli, M., Soldal, M., Skurtveit, E. and Aker, E., (2009) Experimental percolation of supercritical CO2 through a caprock. Energy Procedia 1, 3351-3358 Cuss, R.J., Harrington, J.F., Giot, R., and Auvray, C. (2012) Experimental observations of mechanical dilation at the onset of gas flow in Callovo-Oxfordian Claystone. Poster Presentation 5th International Meeting Clays in Natural and Engineered Barriers for Radioactive Waste Confinement, Montpellier, France October 22nd - 25th 2012.

Cuss, Robert; Harrington, Jon; Graham, Caroline

2013-04-01

340

Noble gas evidence of an aqueous reservoir near the surface of Mars more recently than 1.3 Ga  

NASA Technical Reports Server (NTRS)

Considerable evidence points to a Martian origin of the SNC meteorites. One of these meteorites, Nakhla, contains a leachable component which has an elevated Xe-129/Xe-132 ratio relative to its Kr-84/Xe-132 ratio when compared to the approximately linear array defined by Chassigny, most shergottites, and lithology C of EETA 79001. This array is thought to be a mixing line between Martian mantle and Martian atmosphere. The leachable component probably consists in part of iddingsite, an alteration product produced by interaction of olivine with aqueous fluid at temperatures lower than 150 C. The radiogenic Xe component may represent a distinct reservoir in the Martian crust or mantle. More plausibly, it is Martian atmosphere, fractionated by solution in liquid water and by interaction with sediment. The crystallization age of Nakhla is 1.3 Ga. Its low shock state suggests that it was ejected from near the surface of Mars. Liquid water is required for the formation of iddingsite. These observations provide further evidence for the near surface existence of aqueous fluids more recently than 1.3 Ga.

Drake, Michael J.; Owen, Toby; Swindle, Timothy; Musselwhite, Donald

1993-01-01

341

Applications of the VARGOW oil reservoir model  

SciTech Connect

This report is a continuation of work performed previously and serves as an addendum to the previous report (PNL-3478). The purpose of this study is to perform additional simulations of three reservoirs using the VARGOW model. VARGOW is a variable gas-oil-water reservoir model that was developed by the US Geological Survey to provide recovery estimates suitable for assessing various reservoir production policies and regulations. One of the reservoirs was resimulated using better initial condition data. The other reservoirs were simulated using a modified gas segregation model. The major conclusions drawn from the study are that the VARGOW model can usually predict the reservoir pressure adequately but the producing gas/oil ratio is not as successfully simulated.

Mayer, D.W.

1980-12-01

342

Increasing development efficiency in low-permeability gas reservoirs: A synopsis of tight gas sands project research, November 1982-December 1992  

SciTech Connect

To enhance the application of research results by industry, the report provides a guide to the literature developed at the Bureau of Economic Geology in the Geological Analysis of Primary and Secondary Tight Gas Sands Objectives Project as part of the Gas Research Institute (GRI) Tight Gas Sands Research Program during the period 1982 through 1992. The authors review some of the key findings of the geologic studies published in 17 GRI topical reports and more than 90 Bureau of Economic Geology monographs, refereed journal papers, contributions to other GRI reports, and papers and abstracts in meeting transaction volumes. The report is intended to be a directory to this literature.

Laubach, S.E.

1993-04-01

343

30 CFR 250.1154 - How do I determine if my reservoir is sensitive?  

Code of Federal Regulations, 2010 CFR

...2010-07-01 false How do I determine if my reservoir is sensitive? 250.1154 Section 250...Gas Production Requirements Classifying Reservoirs § 250.1154 How do I determine if my reservoir is sensitive? (a) You must...

2010-07-01

344

Gas reservoir sweet spot detection and delineation in Rocky Mountain laramide basins. Topical report, May 1993March 1996  

Microsoft Academic Search

The determination of the position and configuration of the pressure boundary between normal and anomalously pressured regimes, and the detection and delineation of porosity\\/permeability `sweet spots` below this boundary are the two most important elements in exploring for basin-center or deep-basin gas in Rocky Mountain Laramide Basins. These two exploration elements from the basis for a new exploration paradigm. To

R. C. Surdam; W. O. Iverson; P. Yin

1995-01-01

345

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

SciTech Connect

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

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

2013-07-01

346

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

347

Gas reservoir sweet spot detection and delineation in Rocky Mountain laramide basins. Topical report, May 1993-March 1996  

SciTech Connect

The determination of the position and configuration of the pressure boundary between normal and anomalously pressured regimes, and the detection and delineation of porosity/permeability `sweet spots` below this boundary are the two most important elements in exploring for basin-center or deep-basin gas in Rocky Mountain Laramide Basins. These two exploration elements from the basis for a new exploration paradigm. To utilize this new paradigm, the following tasks need to be included in the exploration strategy: (1) determine the position of the pressure boundary; (2) evaluate the three-dimensional aspects of the pressure boundary surface; (3) determine which depositional facies has the greatest potential for enhances storage capacity and deliverability below the pressure boundary; (4) document the determinative factors that control sweet spot development in the targeted lithofacies; and (5) detect and delineate sweet spots using 2-D and 3-D models of eletric log responses and seismic data.

Surdam, R.C.; Iverson, W.O.; Yin, P.

1995-10-01

348

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

349

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

SciTech Connect

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

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

2006-11-01

350

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

351

Reservoir simulation  

SciTech Connect

A reservoir simulator template consists of mathematical descriptions of the physics and chemistry of recovery processes, operational constraints imposed on the reservoir, and the hardware and software components of computer technology. The paper discusses the state of the art of the template as applied to two classes of simulators (the black oil and the enhanced oil recovery). It shows that while significant advancement has been made in the solution of large systems of linearized difference equations which describe the mathematical formulation of the black oil type models, new mathematical approaches are still needed to realistically simulate enhanced oil recovery processes. Moreover, in some cases, discretization of the physical system, both in space and time, associated with the finite difference methods used by the industry introduces distortion in the physics that needs to be recognized. The paper also discusses some of the outstanding problems and difficulties that require research and solution, and the trend in computer hardware and software.

Aziz, S.; Heinemann, O.; Heinemann, R.F. (Mobil Research and Development Corp., Dallas Research Lab., P.O. Box 819047, Dallas, TX (US))

1988-01-01

352

AUTOMATED TECHNIQUE FOR FLOW MEASUREMENTS FROM MARIOTTE RESERVOIRS.  

USGS Publications Warehouse

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

Constantz, Jim; Murphy, Fred

1987-01-01

353

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

USGS Publications Warehouse

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

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

2000-01-01

354

Heavy Components Control Reservoir Fluid Behavior  

Microsoft Academic Search

The five reservoir fluids (black oils, volatile oils, retrograde gas-condensates, wet gases, and dry gases) are defined because production of each fluid requires different engineering techniques. The fluid type must be determined very early in the life of a reservoir (often before sampling or initial production) because fluid type is the critical factor in many of the decisions that must

William McCain Jr.; W. D. Jr

1994-01-01

355

Surrogate Reservoir Model  

NASA Astrophysics Data System (ADS)

Surrogate Reservoir Model (SRM) is new solution for fast track, comprehensive reservoir analysis (solving both direct and inverse problems) using existing reservoir simulation models. SRM is defined as a replica of the full field reservoir simulation model that runs and provides accurate results in real-time (one simulation run takes only a fraction of a second). SRM mimics the capabilities of a full field model with high accuracy. Reservoir simulation is the industry standard for reservoir management. It is used in all phases of field development in the oil and gas industry. The routine of simulation studies calls for integration of static and dynamic measurements into the reservoir model. Full field reservoir simulation models have become the major source of information for analysis, prediction and decision making. Large prolific fields usually go through several versions (updates) of their model. Each new version usually is a major improvement over the previous version. The updated model includes the latest available information incorporated along with adjustments that usually are the result of single-well or multi-well history matching. As the number of reservoir layers (thickness of the formations) increases, the number of cells representing the model approaches several millions. As the reservoir models grow in size, so does the time that is required for each run. Schemes such as grid computing and parallel processing helps to a certain degree but do not provide the required speed for tasks such as: field development strategies using comprehensive reservoir analysis, solving the inverse problem for injection/production optimization, quantifying uncertainties associated with the geological model and real-time optimization and decision making. These types of analyses require hundreds or thousands of runs. Furthermore, with the new push for smart fields in the oil/gas industry that is a natural growth of smart completion and smart wells, the need for real time reservoir modeling becomes more pronounced. SRM is developed using the state of the art in neural computing and fuzzy pattern recognition to address the ever growing need in the oil and gas industry to perform accurate, but high speed simulation and modeling. Unlike conventional geo-statistical approaches (response surfaces, proxy models …) that require hundreds of simulation runs for development, SRM is developed only with a few (from 10 to 30 runs) simulation runs. SRM can be developed regularly (as new versions of the full field model become available) off-line and can be put online for real-time processing to guide important decisions. SRM has proven its value in the field. An SRM was developed for a giant oil field in the Middle East. The model included about one million grid blocks with more than 165 horizontal wells and took ten hours for a single run on 12 parallel CPUs. Using only 10 simulation runs, an SRM was developed that was able to accurately mimic the behavior of the reservoir simulation model. Performing a comprehensive reservoir analysis that included making millions of SRM runs, wells in the field were divided into five clusters. It was predicted that wells in cluster one & two are best candidates for rate relaxation with minimal, long term water production while wells in clusters four and five are susceptive to high water cuts. Two and a half years and 20 wells later, rate relaxation results from the field proved that all the predictions made by the SRM analysis were correct. While incremental oil production increased in all wells (wells in clusters 1 produced the most followed by wells in cluster 2, 3 …) the percent change in average monthly water cut for wells in each cluster clearly demonstrated the analytic power of SRM. As it was correctly predicted, wells in clusters 1 and 2 actually experience a reduction in water cut while a substantial increase in water cut was observed in wells classified into clusters 4 and 5. Performing these analyses would have been impossible using the original full field simulation model.

Mohaghegh, Shahab

2010-05-01

356

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

Microsoft Academic Search

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

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

2006-01-01

357

The molecular gas reservoir of 6 low-metallicity galaxies from the Herschel Dwarf Galaxy Survey. A ground-based follow-up survey of CO(1-0), CO(2-1), and CO(3-2)  

NASA Astrophysics Data System (ADS)

Context. Observations of nearby starburst and spiral galaxies have revealed that molecular gas is the driver of star formation. However, some nearby low-metallicity dwarf galaxies are actively forming stars, but CO, the most common tracer of this reservoir, is faint, leaving us with a puzzle about how star formation proceeds in these environments. Aims: We aim to quantify the molecular gas reservoir in a subset of 6 galaxies from the Herschel Dwarf Galaxy Survey with newly acquired CO data and to link this reservoir to the observed star formation activity. Methods: We present CO(1-0), CO(2-1), and CO(3-2) observations obtained at the ATNF Mopra 22-m, APEX, and IRAM 30-m telescopes, as well as [C ii] 157?m and [O i] 63?m observations obtained with the Herschel/PACS spectrometer in the 6 low-metallicity dwarf galaxies: Haro 11, Mrk 1089, Mrk 930, NGC 4861, NGC 625, and UM 311. We derived their molecular gas masses from several methods, including using the CO-to-H2 conversion factor XCO (both Galactic and metallicity-scaled values) and dust measurements. The molecular and atomic gas reservoirs were compared to the star formation activity. We also constrained the physical conditions of the molecular clouds using the non-LTE code RADEX and the spectral synthesis code Cloudy. Results: We detect CO in 5 of the 6 galaxies, including first detections in Haro 11 (Z ~ 0.4 Z?), Mrk 930 (0.2 Z?), and UM 311 (0.5 Z?), but CO remains undetected in NGC 4861 (0.2 Z?). The CO luminosities are low, while [C ii] is bright in these galaxies, resulting in [C ii]/CO(1-0) ? 10 000. Our dwarf galaxies are in relatively good agreement with the Schmidt-Kennicutt relation for total gas. They show short molecular depletion timescales, even when considering metallicity-scaled XCO factors. Those galaxies are dominated by their H i gas, except Haro 11, which has high star formation efficiency and is dominated by ionized and molecular gas. We determine the mass of each ISM phase in Haro 11 using Cloudy and estimate an equivalent XCO factor that is 10 times higher than the Galactic value. Overall, our results confirm the emerging picture that CO suffers from significant selective photodissociation in low-metallicity dwarf galaxies.

Cormier, D.; Madden, S. C.; Lebouteiller, V.; Hony, S.; Aalto, S.; Costagliola, F.; Hughes, A.; Rémy-Ruyer, A.; Abel, N.; Bayet, E.; Bigiel, F.; Cannon, J. M.; Cumming, R. J.; Galametz, M.; Galliano, F.; Viti, S.; Wu, R.

2014-04-01

358

Crystallization of Gas-Laden Amorphous Water Ice, Activated by Heat Transport to its Subsurface Reservoirs, as Trigger of Huge Explosions of Comet 17P/Holmes  

NASA Astrophysics Data System (ADS)

Thick terrain layers, of the type recognized on the Deep Impact mission's close-up images of the nucleus of comet 9P/Tempel, and each 10^(13) to 10^(14) grams in mass, are suggested to be attractive candidate carriers of solid material released into the atmosphere during super-massive explosions (megabursts) and/or major fragmentation events. The properties of the 2007 megaburst of comet 17P/Holmes are shown to be consistent with the triggering mechanism being a transformation of gas-laden water ice from low-density amorphous phase to cubic phase (crystallization) in a reservoir located beneath a layer tens of meters thick. Molecules of highly volatile gases, carbon monoxide in particular, trapped in amorphous water ice and released during the phase transition (at 130 K to 150 K), are superheated, generating -- almost instantly in a runaway process -- a momentum needed to lift off, from the comet's nucleus, the mass of the layer and, after its collapse, to accelerate the pile of mostly microscopic dust debris to subkilometer-per-second velocities. Strongly temperature dependent, the crystallization rate increases progressively between about 100 K at aphelion and nearly 120 K (with about 10 percent of the ice in cubic phase) some 10 days before the megaburst and explosively afterwards, due to the release of the trapped volatiles and completion of the phase transition. The proposed model is in agreement with a wide range of relevant observations of the 2007 megaburst of comet 17P, including the event's post-perihelion timing, the water production rate, the CO-to-H_2O production rate ratio, the dust halo's expansion rate, and the energy involved. The observed recurrence rate of super-massive explosions of comet 17P is explained by heat transport through the terrain layers whose effective thermal conductivity is about 0.2 W m^(-1) K^(-1).

Sekanina, Zdenek

2009-10-01

359

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

NASA Astrophysics Data System (ADS)

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

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

2014-06-01

360

Geochemical analysis of reservoir continuity and connectivity, Arab-D and Hanifa Reservoirs, Abqaiq Field, Saudia Arabia  

Microsoft Academic Search

Organic geochemistry and its integration with geologic and reservoir engineering data is becoming increasingly utilized to assist geologists and petroleum engineers in solving production related problems. In Abqaiq Field of eastern Saudi Arabia, gas chromatographic analysis (FSCOT) of produced oils from the Arab-D and Hanifa reservoirs was used to evaluate vertical and lateral continuity within and between these reservoirs. Bulk

A. A. Mahdi; G. Grover; R. Hwang

1995-01-01

361

Damage tolerance of well-completion and stimulation techniques in coalbed methane reservoirs  

Microsoft Academic Search

Coalbed methane (CBM) reservoirs are characterized as naturally fractured, dual porosity, low permeability, and water saturated gas reservoirs. Initially, the gas, water and coal are at thermodynamic equilibrium under prevailing reservoir conditions. Dewatering is essential to promote gas production. This can be accomplished by suitable completion and stimulation techniques. This paper investigates the efficiency and performance of the openhole cavity,

Hossein Jahediesfanjani; Faruk Civan

2005-01-01

362

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

SciTech Connect

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

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

1991-09-01

363

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

SciTech Connect

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

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

1991-09-01

364

Analysis of a non-volumetric gas-condensate reservoir using a generalized material balance equation with fluid properties from an equation of state  

Microsoft Academic Search

Predicting the expansion of an underlying aquifer can be of paramount importance in certain aspects of petroleum engineering, such as the control of water coning, calculating reserves, designing well completions, designing surface facilities such as separators, pumps, etc. Predicting water encroachment can be of critical importance in describing and managing a hydrocarbon reservoir.This study focuses on the use of a

L. Vega; M. A. Barrufet

2005-01-01

365

Chalk Project. Oil- and Gas Containing Chalk Reservoirs in the Danish Part of the Central Graben. Pt. 1 B. Project Summary.  

National Technical Information Service (NTIS)

In the course of the intense exploration activity in the North-Sea chalk, a tremendous amount of new data and concepts have been introduced. The ''Chalk Project'' was initiated in 1981 with the purpose to investigate chalk reservoirs. This summary include...

P. Frykman K. Lieberkind E. Nygaard

1983-01-01

366

Thermal Effects in Cyclic Operation of Storage Reservoirs  

Microsoft Academic Search

This paper addresses the long-term temperature and pressure variations of natural gas that is stored cyclically in underground reservoirs to avoid the formation of gas hydrates. A detailed examination of the well and near-well reservoir emphasizes the cumulative importance of the Joule-Thomson effect over many years.

E. C. Batesole; J. O. Wilkes

1988-01-01

367

Storage of CO 2 in natural gas hydrate reservoirs and the effect of hydrate as an extra sealing in cold aquifers  

Microsoft Academic Search

Reservoirs of clathrate hydrates of natural gases (hydrates), found worldwide and containing huge amounts of bound natural gases (mostly methane), represent potentially vast and yet untapped energy resources. Since CO2-containing hydrates are considerably more stable thermodynamically than methane hydrates, if we find a way to replace the original hydrate-bound hydrocarbons by the CO2, two goals can be accomplished at the

B. Kvamme; A. Graue; T. Buanes; T. Kuznetsova; G. Ersland

2007-01-01

368

Status of Norris Reservoir  

SciTech Connect

This is one in a series of reports prepared by the Tennessee Valley Authority (TVA) for those interested in the conditions of TVA reservoirs. This overview of Norris Reservoir summarizes reservoir and watershed characteristics, reservoir uses, conditions that impair reservoir uses, water quality and aquatic biological conditions, and activities of reservoir management agencies. This information was extracted from the most up-to-date publications and data available, and from interviews with water resource professionals in various federal, state, and local agencies, and in public and private water supply and wastewater treatment facilities. 14 refs., 3 figs.

Not Available

1990-09-01

369

Fractured shale reservoirs: Towards a realistic model  

SciTech Connect

Fractured shale reservoirs are fundamentally unconventional, which is to say that their behavior is qualitatively different from reservoirs characterized by intergranular pore space. Attempts to analyze fractured shale reservoirs are essentially misleading. Reliance on such models can have only negative results for fractured shale oil and gas exploration and development. A realistic model of fractured shale reservoirs begins with the history of the shale as a hydrocarbon source rock. Minimum levels of both kerogen concentration and thermal maturity are required for effective hydrocarbon generation. Hydrocarbon generation results in overpressuring of the shale. At some critical level of repressuring, the shale fractures in the ambient stress field. This primary natural fracture system is fundamental to the future behavior of the fractured shale gas reservoir. The fractures facilitate primary migration of oil and gas out of the shale and into the basin. In this process, all connate water is expelled, leaving the fractured shale oil-wet and saturated with oil and gas. What fluids are eventually produced from the fractured shale depends on the consequent structural and geochemical history. As long as the shale remains hot, oil production may be obtained. (e.g. Bakken Shale, Green River Shale). If the shale is significantly cooled, mainly gas will be produced (e.g. Antrim Shale, Ohio Shale, New Albany Shale). Where secondary natural fracture systems are developed and connect the shale to aquifers or to surface recharge, the fractured shale will also produce water (e.g. Antrim Shale, Indiana New Albany Shale).

Hamilton-Smith, T. [Applied Earth Science, Lexington, KY (United States)

1996-09-01

370

Mass balance calculation of the pyrolysates generated from marine crude oil: A prediction model of oil cracking gas resources based on solid bitumen in reservoir  

Microsoft Academic Search

Oil cracking gas plays an important role in the resources of natural gas in the basins with high and over mature marine source\\u000a rocks in China. The prediction of the oil cracking gas resources becomes necessary and urgent in the gas exploration in these\\u000a basins. A marine crude oil sample was pyrolyzed using sealed gold tubes system. The pyrolysates including

TongShan Wang; AnSong Geng; YongQiang Xiong; XinHua Geng

2007-01-01

371

Reservoir description, Walker Creek field, Arkansas  

SciTech Connect

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 the structure. One of the goals of the study was to evaluate reservoir management options for effecting significant incremental oil recovery. The reservoir was originally divided into five producing zones (1-5). Of these, zones 2 and 4 account for nearly 95% of the production. The grainstone facies in zones 2 and 4 consist predominantly of ooids, but also contain peloids, oncolites, and intraclasts. Calcite cement creates discontinuous tight streaks throughout the reservoir. Porosity is predominantly intergranular and ranges from 1% to greater than 20%. Permeability also varies widely, ranging from 0.1 to > 5000 md. Five percent porosity and 0.6 md permeability, as determined by log analysis, were used as a net pay cutoff. Data from lithologic and log analyses were used to construct cross sections across the field. These sections and grainstone isopach maps illustrate that the two main reservoir zones represent two generations of prograding ooid shoal development. Calcite cemented intervals within the zones cannot be correlated beyond two or three wells. The local extent of these intervals does not justify using them to further subdivide the reservoir zones. Gross pay, net pay, and {delta}h maps indicate that development of porosity followed the trend and distribution of the ooid shoals. Production data (pressure plots, gas-to-oil-ratio maps, and tracer studies) suggest that individual reservoir zones are in communication across the field. These results led to a decision against infill drilling in the field.

Bliefnick, D.M.; Frey, K.M.; Dang, Thu-Thuy (ARCO Oil and Gas Co., Plano, TX (USA)); Bissmeyer, S.M. (ARCO Oil and Gas Co., Lafayette, LA (USA))

1990-05-01

372

Tight Gas Sands Log Interpretation: Problem Study.  

National Technical Information Service (NTIS)

A large undeveloped natural gas resource exists in low-permeability (tight) sandstone reservoirs. Difficulties in reservoir characterization and estimation of production potential in tight gas sands have hindered the development of this resource. Interpre...

C. L. Biddison E. R. Monson G. C. Kukal K. E. Simons R. E. Hill

1983-01-01

373

Integration of reservoir simulation and geomechanics  

NASA Astrophysics Data System (ADS)

Fluid production from tight and shale gas formations has increased significantly, and this unconventional portfolio of low-permeability reservoirs accounts for more than half of the gas produced in the United States. Stimulation and hydraulic fracturing are critical in making these systems productive, and hence it is important to understand the mechanics of the reservoir. When modeling fractured reservoirs using discrete-fracture network representation, the geomechanical effects are expected to have a significant impact on important reservoir characteristics. It has become more accepted that fracture growth, particularly in naturally fractured reservoirs with extremely low permeability, cannot be reliably represented by conventional planar representations. Characterizing the evolution of multiple, nonplanar, interconnected and possibly nonvertical hydraulic fractures requires hydraulic and mechanical characterization of the matrix, as well as existing latent or healed fracture networks. To solve these challenging problems, a reservoir simulator (Advanced Reactive Transport Simulator (ARTS)) capable of performing unconventional reservoir simulation is developed in this research work. A geomechanical model has been incorporated into the simulation framework with various coupling schemes and this model is used to understand the geomechanical effects in unconventional oil and gas recovery. This development allows ARTS to accept geomechanical information from external geomechanical simulators (soft coupling) or the solution of the geomechanical coupled problem (hard coupling). An iterative solution method of the flow and geomechanical equations has been used in implementing the hard coupling scheme. The hard coupling schemes were verified using one-dimensional and two-dimensional analytical solutions. The new reservoir simulator is applied to learn the influence of geomechanical impact on unconventional oil and gas production in a number of practical recovery scenarios. A commercial simulator called 3DEC was the geomechanical simulator used in soft coupling. In a naturally fractured reservoir, considering geomechanics may lead to an increase or decrease in production depending on the relationship between the reservoir petrophysical properties and mechanics. Combining geomechanics and flow in multiphase flow settings showed that production decrease could be caused by a combination of fracture contraction and water blockage. The concept of geomechanical coupling was illustrated with a complex naturally fractured system containing 44 fractures. Development of the generalized framework, being able to study multiphase flow reservoir processes with coupled geomechanics, and understanding of complex phenomena such as water blocks are the major outcomes from this research. These new tools will help in creating strategies for efficient and sustainable production of fluids from unconventional resources.

Zhao, Nan

374

Reef-Bank Features and Their Constraint to Reservoirs of Natural Gas, from Permian Changxing Formation to Triassic Feixianguan Formation in Daxian-Xuanhan Area of Sichuan Province, South China  

NASA Astrophysics Data System (ADS)

Detail studies of the seismic section and certain wells, such as the Puguang-2, the Puguang-6, and the Maoba Wells, demonstrate that the reef facies from the Permian Changxing Formation to the Triassic Feixianguan Formation are expressed as the lens with medium-strong changing swings and chaotic images in the seismic section. The reef facies is made up of gray limestones and dolomites of both baffling sponge reef and the frame sponge reef. Moreover, the bank facies from the Permian Changxing Formation to the Triassic Feixianguan Formation is represented as the lens with medium-strong changing swings and discontinuity images in the seismic section, which is made up of several petrologic types, that is, the French gray thick-bedded to massive sparitic oolitic dolomite, the sparitic gravel-oolitic dolomite, the sparitic pisolitic-oolitic dolomite, the sparitic bioclastic dolomite, and the sparitic dolarenite. Both the reef facies and the bank facies concomitant are developed and distributed in space along the platform margin, which form a special reef-bank facies zone. This facies zone controls the petrological features, the reservoir qualities, and the spatial distribution of the reservoirs of natural gas in the Daxian-Xuanhan area.

MA, Yongsheng; MOU, Chuanlong; TAN, Qinyin; YU, Qian; WANG, Ruihua

375

Distribution of natural gas and reservoir properties in the continental crust of the United States. Final report, June 15, 1988June 15, 1989  

Microsoft Academic Search

Analysis of limited drilling and production data and favorable combination of geologic factors indicate that deep gas (>15,000 feet) in U.S. sedimentary basins is an important energy resource. Structural history regulates many of the processes leading to deep gas accumulations. Overlooked sources of deep gas are cracking of C(15+) hydrocarbons in fine-grained rocksand generation from hydrogen-rich kerogen which occurs at

1989-01-01

376

Status of Cherokee Reservoir  

SciTech Connect

This is the first in a series of reports prepared by Tennessee Valley Authority (TVA) for those interested in the conditions of TVA reservoirs. This overviews of Cherokee Reservoir summarizes reservoir and watershed characteristics, reservoir uses and use impairments, water quality and aquatic biological conditions, and activities of reservoir management agencies. This information was extracted from the most current reports, publications, and data available, and interviews with water resource professionals in various Federal, state, and local agencies and in public and private water supply and wastewater treatment facilities. 11 refs., 4 figs., 1 tab.

Not Available

1990-08-01

377

Status of Wheeler Reservoir  

SciTech Connect

This is one in a series of status reports prepared by the Tennessee Valley Authority (TVA) for those interested in the conditions of TVA reservoirs. This overview of Wheeler Reservoir summarizes reservoir purposes and operation, reservoir and watershed characteristics, reservoir uses and use impairments, and water quality and aquatic biological conditions. The information presented here is from the most recent reports, publications, and original data available. If no recent data were available, historical data were summarized. If data were completely lacking, environmental professionals with special knowledge of the resource were interviewed. 12 refs., 2 figs.

Not Available

1990-09-01

378

Seismic attributes optimization and application in reservoir prediction  

Microsoft Academic Search

Petroleum geophysicists recognize that many parameters related to oil and gas reservoirs are predicted using seismic attribute\\u000a data. However, how best to optimize the seismic attributes, predict the character of thin sandstone reservoirs, and enhance\\u000a the reservoir description accuracy is an important goal for geologists and geophysicists. Based on the theory of main component\\u000a analysis, we present a new optimization

Jun Gao; Jianmin Wang; Meihou Yun; Baoshun Huang; Guocai Zhang

2006-01-01

379

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

Code of Federal Regulations, 2013 CFR

...ENFORCEMENT, DEPARTMENT OF THE INTERIOR OFFSHORE OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF Oil and Gas Drilling Operations General Requirements...and reservoir characteristics of oil, gas, sulphur, and water in...

2013-07-01

380

Modeling of Pressure Compartments in the St. Peter Sandstone Gas Reservoir in the Michigan Basin. Final Report, June 1989-December 1992.  

National Technical Information Service (NTIS)

To obtain new knowledge with predictive value for both gas exploration and production in many basins, the reported research represents an effort to explain presure anomalies and trapping mechanisms responsible for large accumulations of hydrocarbons in ma...

R. H. Dott G. Nadon

1992-01-01

381

The Method Research of Knowledge Discovery in Reservoir Management  

Microsoft Academic Search

Knowledge discovery is an important part of reservoir management, and it is also a bottleneck of widespread application of knowledge. So we should make use of some particular data mining methods to discover knowledge, which should be based on some particular fields. According to demand of oil and gas development and characters of reservoir data set, puts forward a new

Jun Yao; Yun Zhang

2006-01-01

382

A committee machine with intelligent systems for estimation of total organic carbon content from petrophysical data: An example from Kangan and Dalan reservoirs in South Pars Gas Field, Iran  

NASA Astrophysics Data System (ADS)

Total organic carbon (TOC) content present in reservoir rocks is one of the important parameters, which could be used for evaluation of residual production potential and geochemical characterization of hydrocarbon-bearing units. In general, organic-rich rocks are characterized by higher porosity, higher sonic transit time, lower density, higher ?-ray, and higher resistivity than other rocks. Current study suggests an improved and optimal model for TOC estimation by integration of intelligent systems and the concept of committee machine with an example from Kangan and Dalan Formations, in South Pars Gas Field, Iran. This committee machine with intelligent systems (CMIS) combines the results of TOC predicted from intelligent systems including fuzzy logic (FL), neuro-fuzzy (NF), and neural network (NN), each of them has a weight factor showing its contribution in overall prediction. The optimal combination of weights is derived by a genetic algorithm (GA). This method is illustrated using a case study. One hundred twenty-four data points including petrophysical data and measured TOC from three wells of South Pars Gas Field were divided into 87 training sets to build the CMIS model and 37 testing sets to evaluate the reliability of the developed model. The results show that the CMIS performs better than any one of the individual intelligent systems acting alone for predicting TOC.

Kadkhodaie-Ilkhchi, Ali; Rahimpour-Bonab, Hossain; Rezaee, Mohammadreza

2009-03-01

383

Possible Ordovician carbonate reservoirs in Mississippi  

Microsoft Academic Search

To mid-1973, carbonate rocks of Ordovician age in N. Mississippi had produced 7,813 bbl of 35° gravity oil from one well and 123,752 Mcf of gas from another. In spite of the poor results of exploration of Ordovician strata, large reservoirs may be present in these oil- and gas-bearing limestones and dolomites, and structural and stratigraphic conditions may favor commercially

Mellen

1974-01-01

384

Characterization of produced waters from underground natural gas storage reservoir operations. Volume 2. Appendix D. Analytical data report. Topical report, July 1986June 1988  

Microsoft Academic Search

This report presents the results of a nationwide characterization program for produced waters from underground natural gas storage operations. In all, seven produced water samples from seven different sites were collected and analyzed. The analytical methods used and parameters tested in the program paralleled those used in EPA's EandP Waste Study. In general, the produced waters from storage facilities sampled

L. H. Keith; S. K. Mertens; F. L. Shore; M. C. Shepherd; P. J. Schrynemeeckers

1988-01-01

385

Application of association theory to the prediction of asphaltene deposition: Deposition due to natural depletion and miscible gas injection processes in petroleum reservoirs  

Microsoft Academic Search

Asphaltene flocculation and deposition during natural depletion and\\/or miscible gas injection in enhanced oil recovery (EOR) processes is a common problem in oilfields throughout the world. The complexity of the asphaltene structure and the high affinity of these molecules to absorb on surfaces, such as rock surfaces, creates difficulties in deposition prediction. There are numerous models to predict the various

M. Vafaie-Sefti; S. A. Mousavi-Dehghani

2006-01-01

386

Sampling the marine gas-hydrate reservoir: Assessing the methane inventory, internal dynamics, and potential of methane discharges to the atmosphere. Final progress report.  

National Technical Information Service (NTIS)

The status of the pore water and sediment core analysis of the surface sediments that overlie a major gas-hydrate field on the Carolina Continental Rise and Blake Ridge is reported here. Funding from NIGEC's southern regional center provided support for a...

C. Paull

1993-01-01

387

Ray-based stochastic inversion of pre-stack seismic data for improved reservoir characterisation  

Microsoft Academic Search

To estimate rock and pore-fluid properties of oil and gas reservoirs in the subsurface, techniques can be used that invert seismic data. Hereby, the detailed information about the reservoir that is available at well locations, such as the thickness and porosity of individual layers, is extrapolated to all locations in the reservoir on the basis of seismic reflections. Stochastic inversion

D. W. van der Burg

2007-01-01

388

Validation status of the VARGOW oil reservoir model  

SciTech Connect

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 the model assumptions were selected for model testing purposes. For all three reservoirs, it has been possible to simulate the observed pressures in both interpolative and extrapolative modes. Simulating the gas/oil ratio (GOR) has not been as successful, however. The VARGOW model will predict physically unrealistic results if the reservoir being simulated is not initially at the bubble point pressure of the reservoir fluid. If the discovery pressure is slightly above the bubble point, adjustments to initial conditions can be made using a method that has been outlined in this report. If the discovery pressure is considerably above the bubble point, it is recommended that an undersaturated reservoir model be employed until the bubble point is reached. For simulating reservoirs whose discovery pressure is below the bubble point, the VARGOW model must be modified.

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

198