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1

Modeling well performance in compartmentalized gas reservoirs  

E-print Network

Predicting the performance of wells in compartmentalized reservoirs can be quite challenging to most conventional reservoir engineering tools. The purpose of this research is to develop a Compartmentalized Gas Depletion Model that applies not only...

Yusuf, Nurudeen

2008-10-10

2

Modeling well performance in compartmentalized gas reservoirs  

E-print Network

Predicting the performance of wells in compartmentalized reservoirs can be quite challenging to most conventional reservoir engineering tools. The purpose of this research is to develop a Compartmentalized Gas Depletion Model that applies not only...

Yusuf, Nurudeen

2009-05-15

3

Underground natural gas storage reservoir management  

SciTech Connect

The objective of this study is to research technologies and methodologies that will reduce the costs associated with the operation and maintenance of underground natural gas storage. This effort will include a survey of public information to determine the amount of natural gas lost from underground storage fields, determine the causes of this lost gas, and develop strategies and remedial designs to reduce or stop the gas loss from selected fields. Phase I includes a detailed survey of US natural gas storage reservoirs to determine the actual amount of natural gas annually lost from underground storage fields. These reservoirs will be ranked, the resultant will include the amount of gas and revenue annually lost. The results will be analyzed in conjunction with the type (geologic) of storage reservoirs to determine the significance and impact of the gas loss. A report of the work accomplished will be prepared. The report will include: (1) a summary list by geologic type of US gas storage reservoirs and their annual underground gas storage losses in ft{sup 3}; (2) a rank by geologic classifications as to the amount of gas lost and the resultant lost revenue; and (3) show the level of significance and impact of the losses by geologic type. Concurrently, the amount of storage activity has increased in conjunction with the net increase of natural gas imports as shown on Figure No. 3. Storage is playing an ever increasing importance in supplying the domestic energy requirements.

Ortiz, I.; Anthony, R.

1995-06-01

4

Coarse scale simulation of tight gas reservoirs  

E-print Network

equation for calculating the equivalent well block radius for all the wells in a reservoir that fully accounts for arbitrary well rates and the interaction between the wells. Babu and Odeh7 presented a relationship between well block and wellbore... permeability reservoir. Sharpe and Ramesh11 modified the Peaceman well model, which restored its validity for non-uniform aerial grids and for problems that model vertical flow process like gas and water coning. They investigated the effect of using...

El-Ahmady, Mohamed Hamed

2004-09-30

5

Enhanced gas recovery from a moderately strong water drive reservoir  

SciTech Connect

Blowdown performance of several S. Texas water drive gas reservoirs indicated a substantial quantity of gas was trapped in water invaded regions. Pressure support in many of these reservoirs is from limited aquifers. Depressuring of the reservoir by withdrawing large volumes of water in order to recover trapped gas was evaluated. The evaluation, implementation, and results of this enhanced gas recovery technique are discussed for one of these reservoirs.

Chesney, T.P.; Lewis, R.C.; Trice, M.L. Jr.

1981-01-01

6

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

SciTech Connect

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

Oldenburg, Curtis M.

2003-04-08

7

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

8

Feasibility of waterflooding Soku E7000 gas-condensate reservoir  

E-print Network

We performed a simple 3D compositional reservoir simulation study to examine the possibility of waterflooding the Soku E7 gas-condensate reservoir. This study shows that water injection results in higher condensate recovery than natural depletion...

Ajayi, Arashi

2012-06-07

9

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

10

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

11

Naturally fractured tight gas reservoir detection optimization  

SciTech Connect

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

NONE

1998-11-30

12

Critically Pressured Free Gas Reservoirs Below Gas Hydrate Provinces  

NASA Astrophysics Data System (ADS)

Paleoceanographic evidence suggests that methane hydrates play a significant role in global climate change; however, mechanisms for sustained methane release into the biosphere during periods of global warming are poorly understood (Katz et al. 1999, Kennett et al., 2000). Here, we evaluate the possibility that gas flux into the hydrate stability zone, and perhaps into the oceans and atmosphere is mechanically regulated by hydrofracture or fault reactivation in overlying hydrate-bearing sediments. Our results reveal that a critical gas column thickness exists below most hydrate provinces in basin settings, implying that these hydrate provinces are poised for mechanical failure. Our results suggest that a free gas "wedge" of increasing thickness with BSR depth occurs in hydrate basins, and that a mechanically regulated maximum thickness of free gas exists. Furthermore, our results are consistent with observations of thicker free gas zones in deep hydrate basins and thin free gas zones on active, possibly water-phase overpressured, continental margins. Incorporating our result with Dickens' 2001 model for estimating BSR depths along ocean margins, and assuming 50% sediment porosity with gas filling 1% of the pore space, we calculate a value for the total free methane gas reservoir below all hydrate provinces to be 1/8 the total methane trapped in hydrate, or ~1300 Gt if 10,000 Gt of methane exists in hydrate (Kvenvolden, 1993). One key implication is that a significant reservoir of methane may exist as free gas beneath hydrate provinces that is highly sensitive to changes in pressure and temperature.

Hornbach, M. J.; Saffer, D. M.; Holbrook, W. S.

2002-12-01

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

New inflow performance relationships for gas condensate reservoirs  

E-print Network

In this work we propose two new Vogel-type Inflow Performance Relations (or IPR) correlations for gas-condensate reservoir systems. One correlation predicts dry gas production the other predicts condensate (liquid) production. These correlations...

Del Castillo Maravi, Yanil

2004-09-30

15

A Variable Cell Model for Simulating Gas Condensate Reservoir Performance  

E-print Network

, SPE-~~~ SPE 21428 A Variable Cell Model for Simulating Gas Condensate Reservoir Performance A Librarian, SPE, P.O. Box 833836, Richardson, TX 75083.3836 U.S.A., Telex, 730989 SPEDAL. ABSTRACT Studies of depletion performance of gas condensate reservoirs report the existence of a A variable cell model

Al-Majed, Abdulaziz Abdullah

16

Tight gas reservoirs. Volume 5, Parts 1-2  

Microsoft Academic Search

This 2-part study examines natural gas resources in 12 US (excluding Alaska) gas reservoirs classified as containing tight gas formations and for which extensive data are available. A detailed appraisal was made of the tight gas resource in these basins, and estimates were made which included an extrapolation for remaining tight gas resources in the lower 48. Potential ultimate recovery

Bookout

1980-01-01

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

General inflow performance relationship for solution-gas reservoir wells  

SciTech Connect

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

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

1982-02-01

19

Naturally fractured tight gas reservoir detection optimization  

SciTech Connect

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

NONE

1998-11-30

20

Analyzing aquifers associated with gas reservoirs using aquifer influence functions  

E-print Network

ANALYZING AQUIFERS ASSOCIATED WITH GAS RESERVOIRS USING AQUIFER INFLUENCE FUNCTIONS A Thesis by GARY WAYNE TARGAC Submitted to the Graduate College of Texas A&M University in partial fulfillment of the requirements for the degree of MASTER... OF SCIENCE V z May 1988 z V z z I- Major Subject: Petroleum Engineering ANALYZING AQUIFERS ASSOCIATED WITH GAS RESERVOIRS USING AQUIFER INFLUENCE FUNCTIONS A Thesis by GARY WAYNE TARGAC Approved as to style and content by: (Chair of Committ R...

Targac, Gary Wayne

2012-06-07

21

Nonlinear filtering in oil/gas reservoir simulation: filter design  

SciTech Connect

In order to provide an additional mode of utility to the USGS reservoir model VARGOW, a nonlinear filter was designed and incorporated into the system. As a result, optimal (in the least squares sense) estimates of reservoir pressure, liquid mass, and gas cap plus free gas mass are obtained from an input of reservoir initial condition estimates and pressure history. These optimal estimates are provided continuously for each time after the initial time, and the input pressure history is allowed to be corrupted by measurement error. Preliminary testing of the VARGOW filter was begun and the results show promise. Synthetic data which could be readily manipulated during testing was used in tracking tests. The results were positive when the initial estimates of the reservoir initial conditions were reasonably close. Further testing is necessary to investigate the filter performance with real reservoir data.

Arnold, E.M.; Voss, D.A.; Mayer, D.W.

1980-10-01

22

Characterization of oil and gas reservoir heterogeneity  

SciTech Connect

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

Not Available

1991-01-01

23

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

24

Effects of reservoir geometry and permeability anisotropy on ultimate gas recovery in Devonian Shale reservoirs  

E-print Network

2 Y- direction l 2 3 4 5 6 7 x- djrectjeq Figure 1 - Plan view of a typical grid system kx Lx = Length and L?= Width kx ? kmax and k& = min Figure 2- Schematic of 2-D reservoir model with permeability anisotropy, uustimulated wells pattern... reservoir pressure of 600 psi 3. Dry gas with a specific gravity of 0. 65 4. Gas produced from a single well at a constant bottornhole pressure of 100 psi 5. Well life of 50 years 6. Well spacings of 20, 40, 80, and 160 acres 7. Formation depth of 2000...

Starnes, Lee McKennon

2012-06-07

25

Gas hydrate reservoir characteristics and economics  

SciTech Connect

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

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

1992-06-01

26

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

E-print Network

ACCOUNTING FOR ADSORBED GAS AND ITS EFFECT ON PRODUCTION BEHAVIOR OF SHALE GAS RESERVOIRS A Thesis by SALMAN AKRAM MENGAL Submitted to the Office of Graduate Studies of Texas A&M University in partial fulfillment... of the requirements for the degree of MASTER OF SCIENCE August 2010 Major Subject: Petroleum Engineering ACCOUNTING FOR ADSORBED GAS AND ITS EFFECT ON PRODUCTION BEHAVIOR OF SHALE GAS RESERVOIRS A Thesis by SALMAN AKRAM MENGAL...

Mengal, Salman Akram

2010-10-12

27

Integrated Hydraulic Fracture Placement and Design Optimization in Unconventional Gas Reservoirs  

E-print Network

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

Ma, Xiaodan

2013-12-10

28

Analysis of condensate banking dynamics in a gas condensate reservoir under different injection schemes  

E-print Network

If the reservoir pressure falls below the dewpoint pressure when producing a gas condensate reservoir, liquid dropout takes place in the reservoir. Liquid builds up in the near wellbore area causing what is known as a "condensate banking...

Sandoval Rodriguez, Angelica Patricia

2012-06-07

29

Compressibility Factor for Sour Gas Reservoirs  

Microsoft Academic Search

This paper presents the initial stage of an effort aimed at developing a new correlation to estimate pseudo critical properties for sour gas when the exact composition is not known. Several mixing rules and gas gravity correlations available in the literature are first evaluated and compared. The evaluation is performed on a large database consisting of more than 2000 samples

Adel M. Elsharkawy; Elkamel Ali

2000-01-01

30

Secondary gas recovery from a moderately strong water drive reservoir: a case history  

SciTech Connect

Blowdown performance of several south Texas water drive gas reservoirs indicated that a substantial quantity of gas was trapped in water invaded regions. Pressure support in many of these reservoirs is from limited aquifers. Depressuring the reservoir by withdrawing large volumes of water to recover trapped gas was evaluated. Evaluation, implementation, and results of this secondary gas-recovery (SGR) technique are discussed for one of these reservoirs.

Chesney, T.P.; Lewis, R.C.; Trice, M.L.

1982-09-01

31

The effects of production rates and some reservoir parameters on recovery in a strong water drive gas reservoir  

E-print Network

- associated gas reservoir having a strong water drive mechanism. The effect of different rock and fluid properties, including equilibrium gas saturation, relative permeability, capillarity, etc. , on gas recovery will also be investigated. An understanding...-gas ratio of approximately . 10 STB/NSCF. A total of more than 21 cases, consisting of combinations of production rates, relative permeabilities, and capillarities, were run using an Amdahl 470 V/6 high speed digital computer. TABLE 1 RESERVOIR ROCK...

Soemarso, Christophorus

2012-06-07

32

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

E-print Network

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

Henderson, Gideon

33

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

34

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

35

Incremental natural gas resources through infield reserve growth/secondary natural gas recovery. [Compartmented natural gas reservoir  

SciTech Connect

The objectives of the Infield Growth/Secondary Natural Gas Recovery project have been: To establish how depositional and diagenetic heterogeneities in reservoirs of conventional permeability cause reservoir compartmentalization and, hence, incomplete recovery of natural gas. To document practical, field-oriented examples of reserve growth from fluvial and deltaic sandstones of the Texas gulf coast basin and to use these gas reservoirs as a natural laboratory for developing concepts and testing applications of both tools and techniques to find secondary gas. To demonstrate how the integration of geology, reservoir engineering, geophysics, and well log analysis/petrophysics leads to strategic recompletion and well placement opportunities for reserve growth in mature fields. To transfer project results to natural gas producers, not just as field case studies, but as conceptual models of how heterogeneities determine natural gas flow and how to recognize the geologic and engineering clues that operators can use in a cost-effective manner to identify secondary gas. Accomplishments are presented for: reservoir characterization; integrated formation evaluation and engineering testing; compartmented reservoir simulator; and reservoir geophysics.

Finley, R.J.; Levey, R.A.

1992-01-01

36

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

37

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

38

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

E-print Network

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

Yan, Bicheng

2013-07-15

39

Experimental Investigation of Propped Fracture Conductivity in Tight Gas Reservoirs Using The Dynamic Conductivity Test  

E-print Network

Hydraulic Fracturing stimulation technology is used to increase the amount of oil and gas produced from low permeability reservoirs. The primary objective of the process is to increase the conductivity of the reservoir by the creation of fractures...

Romero Lugo, Jose 1985-

2012-10-24

40

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

...approval to produce gas-cap gas from an oil reservoir with an associated gas cap...DEPARTMENT OF THE INTERIOR OFFSHORE OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF Oil and Gas Production Requirements...

2014-07-01

41

Prediction of Gas Injection Performance for Heterogeneous Reservoirs  

SciTech Connect

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

Blunt, Michael J.; Orr, Franklin M.

1999-05-26

42

Paper #194973 GEOCHEMICAL CHARACTERIZATION OF THE RESERVOIR HOSTING SHALE-GAS AND OIL in  

E-print Network

Paper #194973 GEOCHEMICAL CHARACTERIZATION OF THE RESERVOIR HOSTING SHALE-GAS AND OIL a reservoir for shale-gas and oil. We examined organic-rich black shale, known as Macasty shale, of Upper SHALE-GAS AND OIL in THE SUBSURFACE OF ANTICOSTI ISLAND, CANADA Key Words: Provenance, Anticosti Island

43

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, 2011 CFR

... 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... How do I receive approval to produce gas-cap gas from an oil reservoir with an...

2011-07-01

44

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

Code of Federal Regulations, 2012 CFR

... 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... How do I receive approval to produce gas-cap gas from an oil reservoir with an...

2012-07-01

45

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

... 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... How do I receive approval to produce gas-cap gas from an oil reservoir with an...

2013-07-01

46

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

Code of Federal Regulations, 2010 CFR

...to produce gas-cap gas from an oil reservoir with an associated gas...250.1157 Section 250.1157 Mineral Resources MINERALS MANAGEMENT SERVICE, DEPARTMENT OF THE INTERIOR OFFSHORE OIL AND GAS AND SULPHUR...

2010-07-01

47

Gas trapping and mobilization through water influx in natural gas reservoirs  

NASA Astrophysics Data System (ADS)

Residual gas saturation is important in determining recovery from a gas reservoir, with water influx. This research addressed residual gas saturation, and other variables, resulting from imbibition tests in porous media, which included spontaneous and forced imbibition; co-current and counter-current imbibition; primary and secondary imbibition; water imbibition and oil imbibition. Several hundred water and oil imbibition experiments were performed on 47 core plugs, consisting of sandstone and carbonate samples. Concurrently, automated experimental rigs were developed, employing a balance in one case, and NMR in the other. The experimental techniques were critically evaluated with regard to repeatability and accuracy. The residual gas saturation, and gas saturation as a function of imbibition time, liquid distribution in different pore sizes, and relative wettability were investigated. A new Critical Capillary Number for gas-liquid system is postulated. A simple procedure was developed for determining wettability from imbibition data. Capillary pressure and relative permeability curves were extracted from the experimental data, and used in 1D and 3D numerical simulations of co-current and counter-current laboratory imbibition tests. The simulations showed the important role of gas compressibility and verified the residual gas saturation. Additionally, a gas reservoir with strong water influx was simulated, and methods for improving gas recovery were examined via many sensitivity studies. It is concluded that because of gas compressibility, residual gas saturation is important in low pressure systems, such as laboratory experiments, but is not important in a gas reservoir, unless the abandonment pressure is close to the initial pressure.

Ding, Minghua

48

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

EIA Publications

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

2010-01-01

49

Advanced Hydraulic Fracturing Technology for Unconventional Tight Gas Reservoirs  

SciTech Connect

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

Stephen Holditch; A. Daniel Hill; D. Zhu

2007-06-19

50

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

Microsoft Academic Search

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

D. K. Baskin; R. J. Hwang; R. K. Purdy

1995-01-01

51

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

52

Characterization and reservoir evaluation of a hydraulically fractured, shaly gas reservoir  

E-print Network

as to style and content by S. W. Poston (Chair of committee) Ronald M. Brimhall (Member) Robert R. Berg (Member) Ken Hall (Interin Head of Department) December 1991 ABSTRACT Characterization and Reservoir Evaluation of a Hydraulically Fractured.... Buildup tests will be analyzed using different approaches to calculate permeability and reservoir average pressure to check these results. It is expected to define a reservoir pressure behavior model which will improve the accuracy of the reservoir...

Santiago Molina, Cesar Alfonso

2012-06-07

53

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

E-print Network

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

Gajdica, Ronald Joseph

2012-06-07

54

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

55

Gas atomized chemical reservoir ODS ferritic stainless steels  

SciTech Connect

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

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

2010-06-27

56

Modeling effects of diffusion and gravity drainage on oil recovery in naturally fractured reservoirs under gas injection  

E-print Network

Gas injection in naturally fractured reservoirs maintains the reservoir pressure, and increases oil recovery primarily by gravity drainage and to a lesser extent by mass transfer between the flowing gas in the fracture and ...

Jamili, Ahmad

2010-04-22

57

Driven lattice gas of dimers coupled to a bulk reservoir  

NASA Astrophysics Data System (ADS)

We investigate the nonequilibrium steady state of a one-dimensional (1D) lattice gas of dimers. The dynamics is described by a totally asymmetric exclusion process (TASEP) supplemented by attachment and detachment processes, mimicking chemical equilibrium of the 1D driven transport with the bulk reservoir. The steady-state phase diagram and current and density profiles are calculated using both a refined mean-field theory and extensive stochastic simulations. As a consequence of the on-off kinetics, a phase coexistence region arises intervening between low and high density phases such that the discontinuous transition line of the TASEP splits into two continuous ones. The results of the mean-field theory and simulations are found to coincide. We show that the physical picture obtained in the corresponding lattice gas model with monomers is robust, in the sense that the phase diagram changes quantitatively, but the topology remains unaltered. The mechanism for phase separation is identified as generic for a wide class of driven 1D lattice gases.

Pierobon, Paolo; Frey, Erwin; Franosch, Thomas

2006-09-01

58

Inflow performance relationships for solution-gas-drive reservoirs  

SciTech Connect

In this theoretical study, a numerical model was used to examine the influence of pressure level and skin factor on the inflow performance relationships (IPR's) of wells producing under solution-gas-drive systems. Examination of the synthetic deliverability curves suggests that the exponent of the deliverability curve is a function of time and that the exponent is usually greater than unity. The implication of this observation to field data is discussed. The accuracy of procedures given in the literature to predict oilwell deliverabilities is also examined. It is shown that these methods can be used to predict future performance provided that the exponent of the deliverability curve is known and that extrapolations over large time ranges are avoided. If single-point tests are used to predict future performance (such tests assume that the exponent of the deliverability curve is constant), then errors in predictions will be minimized. Although relative permeability and fluid property data are required, the Muskat material-balance equation and the assumption that GOR is independent of distance can be used to predict future production rates. This method avoids problems associated with other methods in the literature and always yields reliable results. New methods to modify the IPR curve to incorporate changes in skin factor are presented. A new flow-efficiency definition based on the structure of the deliverability equations for solution-gas-drive reservoirs is proposed. This definition avoids problems that result when the currently available methods are applied to heavily stimulated wells.

Camacho-V, R.G.; Raghavan, R.

1989-05-01

59

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

SciTech Connect

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

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

1997-08-01

60

Altering Wettability in Gas Condensate Sandstone Reservoirs for Gas Mobillity Improvement  

E-print Network

. ______________ This thesis follows the style of SPE Journal. ? Fig Fig blo (Ka mo how ban foc F . 1-Gas-conde . 2 shows th cks the nea math 2007) re in extrem the satura king affect us of our stu ig. 2-Conden nsate phase d sta e condensat r... is 541 Mscf/D of gas and 198 bbl/D of condensate. Production decline is observed in Fig. 3 below. There was an estimate that only 10% of the OGIP could be recovered, even with the reservoir pressure still above the dewpoint pressure. Fracturing...

Fernandez Martinez, Ruth Gabriela

2012-07-16

61

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

NASA Astrophysics Data System (ADS)

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

Hu, Yuanan; Cheng, Hefa

2013-08-01

62

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

E-print Network

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

Zapata Arango, Jose? Francisco

2012-06-07

63

Greenhouse gas emissions from hydroelectric reservoirs: A global perspective  

Microsoft Academic Search

Background Since the potential of reservoirs to be net emitters of greenhouse gases (GHG) was suggested 12 years ago (Rudd et al. 1993), this aspect has become a standard argument against the construction of new dams. However, research on carbon and nitrogen cycling in natural lakes and reservoirs has been intense and today there is enough knowledge to discriminate between

Björn Svensson

64

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

SciTech Connect

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

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

1996-06-01

65

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

E-print Network

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

Boyer, Elizabeth W.

66

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

E-print Network

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

Statton, James Cody

2012-07-16

67

Comparison of Single, Double, and Triple Linear Flow Models for Shale Gas/Oil Reservoirs  

E-print Network

There have been many attempts to use mathematical method in order to characterize shale gas/oil reservoirs with multi-transverse hydraulic fractures horizontal well. Many authors have tried to come up with a suitable and practical mathematical model...

Tivayanonda, Vartit

2012-10-19

68

Application of the Continuous EUR Method to Estimate Reserves in Unconventional Gas Reservoirs  

E-print Network

demonstrate the methodology by applying the approach to 43 field examples producing from 7 different tight sandstone and shale gas reservoirs. We show that the difference between the "upper" and "lower" limit of reserves decreases with time and converges...

Currie, Stephanie M.

2010-10-12

69

Experimental and simulation studies of sequestration of supercritical carbon dioxide in depleted gas reservoirs  

E-print Network

he feasibility of sequestering supercritical CO2 in depleted gas reservoirs. The experimental runs involved the following steps. First, the 1 ft long by 1 in. diameter carbonate core is inserted into a viton Hassler sleeve and placed inside...

Seo, Jeong Gyu

2004-09-30

70

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

SciTech Connect

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

Ortiz, I.; Anthony, R.V.

1996-12-31

71

Production of Natural Gas and Fluid Flow in Tight Sand Reservoirs  

SciTech Connect

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

Maria Cecilia Bravo

2006-06-30

72

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

E-print Network

With increase of interest in exploiting shale gas/oil reservoirs with multiple stage fractured horizontal wells, complexity of production analysis and reservoir description have also increased. Different methods and models were used throughout...

Abdulal, Haider Jaffar

2012-02-14

73

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

74

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

75

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

NASA Astrophysics Data System (ADS)

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

Liu, Shimin; Harpalani, Satya

2014-08-01

76

DEVELOPMENT OF MORE-EFFICIENT GAS FLOODING APPLICABLE TO SHALLOW RESERVOIRS  

Microsoft Academic Search

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

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

2003-01-01

77

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

78

Application of Fast Marching Method in Shale Gas Reservoir Model Calibration  

E-print Network

, Song Du, Suksang Kang, Satyajit Taware, Jichao Han, Zheng Zhang, Jeong Min Kim, Shusei Tanaka, Shingo Watanabe, Dongjae Kam, Feyisayo Olalotiti-Lawal, Neha Bansal, Peerapong Ekkawong, Jixiang Huang, Xiaoyang Xia, Aditya Vyas, Yusuke Fujita, and other... for heterogeneous and fractured reservoirs, particularly shale gas reservoirs with multistage fractures. The Eikonal equation for the pressure front propagation is derived by Vasco et al. (2000) and Kulkarni et al. (2000). They introduced the concept...

Yang, Changdong

2013-07-26

79

Determination of gas-condensate relative permeability on whole cores under reservoir conditions  

SciTech Connect

Rock samples from a Middle East carbonate retrograde condensate gas field were studied to determine their relative permeability to gas and condensate curves. The authors emphasized the determination of condensate minimum flowing saturation-or critical condensate saturation-and the reduction of permeability to gas in the presence of immobile condensate saturation. A ternary pseudoreservoir fluid of methane/pentane/nonane made it possible to work in simulated reservoir conditions with a greater flexibility for experimental procedures. The initial water saturation equaling that in the reservoir was restored. The results of the gas-condensate indicate that the critical condensate saturations are high (the average value is 36% PV) and that the reduction of permeability to gas is higher than for a standard gas/oil system. Also presented are the details of the experimental procedures, the fluid characteristics, the results, and a discussion.

Gravier, J.F.; Lemouzy, P.; Barroux, C.; Abed, A.F.

1986-02-01

80

Selection of fracture fluid for stimulating tight gas reservoirs  

E-print Network

to the Office of Graduate Studies of Texas A&M University in partial fulfillment of the requirements for the degree of MASTER OF SCIENCE Approved as to style and content by: Chair of Committee, Stephen A. Holditch Committee Members, William D. Mc... also like to thank Michael Smith with NSI Technologies; D.J. White, George Waters, Tom Olsen, John Jochen, and Jeff Asbill with Schlumberger DCS; John Spivey with Phoenix Reservoir Engineering; Nicholas Tschirhart with XTO Energy; Tony Martin...

Malpani, Rajgopal Vijaykumar

2007-04-25

81

Horizontal Well Placement Optimization in Gas Reservoirs Using Genetic Algorithms  

E-print Network

(1995) optimized the drilling schedule and well location in an oil reservoir through a traveling salesman structure with the use of Simulated Annealing. Bittencourt and Horne (1997) approached the well placement optimization problem using a genetic... robust, stochastic, and streamlined optimization method. Genetic Algorithms ?efficiently exploit historical information to speculate on new search points with expected improved performance.? (Goldberg 1989) The GA population is represented by a...

Gibbs, Trevor Howard

2011-08-08

82

Natural gas leakage of Mizhi gas reservoir in Ordos Basin, recorded by natural gas fluid inclusion  

Microsoft Academic Search

Abundant natural gas inclusions were found in calcite veins filled in fractures of Central Fault Belt across the centre of\\u000a Ordos Basin. Time of the calcite veins and characteristics of natural gas fluid inclusion were investigated by means of dating\\u000a of thermolum luminescence (TL) and analyzing stable isotope of fluid inclusion. Results show that natural gas inclusion formed\\u000a at 130–140°C

RongXi Li; LingJun Di; ShengLi Xi

2007-01-01

83

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

E-print Network

. recoveries were obtained vhen the fluid was produced through a central weAl than when production was through a well in the extreme end of the reservoir. Lower viscosity gave substantially higher recoveries~ but larger amounts of gas in solution had.... recoveries were obtained vhen the fluid was produced through a central weAl than when production was through a well in the extreme end of the reservoir. Lower viscosity gave substantially higher recoveries~ but larger amounts of gas in solution had...

Goodwin, Robert Jennings

2012-06-07

84

The deep Madden Field, a super-deep Madison gas reservoir, Wind River Basin, Wyoming  

SciTech Connect

Madison dolomites form the reservoir of a super deep, potential giant sour gas field developed on the Madden Anticline immediately in front of the Owl Creek Thrust along the northern rim of the Wind River Basin, central Wyoming. The Madison reservoir dolomites are presently buried to some 25,000 feet at Madden Field and exhibit porosity in excess of 15%. An equivalent dolomitized Madison sequence is exposed in outcrop only 5 miles to the north on the hanging wall of the Owl Creek thrust at Lysite Mountain. Preliminary comparative stratigraphic, geochemical and petrologic data, between outcrop and available cores and logs at Deep Madden suggests: (1) early, sea level-controlled, evaporite-related dolomitization of the reservoir and outcrop prior to significant burial; (2) both outcrop and deep reservoir dolomites underwent significant recrystallization during a common burial history until their connection was severed during Laramide faulting in the Eocene; (3) While the dolomite reservoir at Madden suffered additional diagenesis during an additional 7-10 thousand feet of burial, the pore systems between outcrop and deep reservoir are remarkably similar. The two existing deep Madison wells at Madden are on stream, with a third deep Madison well currently drilling. The sequence stratigraphic framework and the diagenetic history of the Madison strongly suggests that outcrops and surface cores of the Madison in the Owl Creek Mountains will be useful in further development and detailed reservoir modeling of the Madden Deep Field.

Moore, C.H. [Louisiana State Univ., Baton Rouge, LA (United States); Hawkins, C. [Louisiana Land and Exploration, Denver, CO (United States)

1996-12-31

85

The deep Madden Field, a super-deep Madison gas reservoir, Wind River Basin, Wyoming  

SciTech Connect

Madison dolomites form the reservoir of a super deep, potential giant sour gas field developed on the Madden Anticline immediately in front of the Owl Creek Thrust along the northern rim of the Wind River Basin, central Wyoming. The Madison reservoir dolomites are presently buried to some 25,000 feet at Madden Field and exhibit porosity in excess of 15%. An equivalent dolomitized Madison sequence is exposed in outcrop only 5 miles to the north on the hanging wall of the Owl Creek thrust at Lysite Mountain. Preliminary comparative stratigraphic, geochemical and petrologic data, between outcrop and available cores and logs at Deep Madden suggests: (1) early, sea level-controlled, evaporite-related dolomitization of the reservoir and outcrop prior to significant burial; (2) both outcrop and deep reservoir dolomites underwent significant recrystallization during a common burial history until their connection was severed during Laramide faulting in the Eocene; (3) While the dolomite reservoir at Madden suffered additional diagenesis during an additional 7-10 thousand feet of burial, the pore systems between outcrop and deep reservoir are remarkably similar. The two existing deep Madison wells at Madden are on stream, with a third deep Madison well currently drilling. The sequence stratigraphic framework and the diagenetic history of the Madison strongly suggests that outcrops and surface cores of the Madison in the Owl Creek Mountains will be useful in further development and detailed reservoir modeling of the Madden Deep Field.

Moore, C.H. (Louisiana State Univ., Baton Rouge, LA (United States)); Hawkins, C. (Louisiana Land and Exploration, Denver, CO (United States))

1996-01-01

86

Recovery of oil from fractured reservoirs by gas displacement  

E-print Network

GAS REL. PERM. FRACTURE OIL REL. PERM. F TURE . 6 l5 LLJ W UJ I- ld GAS REL. I'ERM. MAT I OIL REL. PERM. RX . 0 O. . 2 . 4 . 6 OIL SATURATION- FRACTION FIG. 4- RELATIVE PERMEABILITY VS OIL SATURATION FOR LABORATORY EXPERIMENT GORE... GAS REL. PERM. FRACTURE OIL REL. PERM. F TURE . 6 l5 LLJ W UJ I- ld GAS REL. I'ERM. MAT I OIL REL. PERM. RX . 0 O. . 2 . 4 . 6 OIL SATURATION- FRACTION FIG. 4- RELATIVE PERMEABILITY VS OIL SATURATION FOR LABORATORY EXPERIMENT GORE...

Unneberg, Arild

2012-06-07

87

Optimizing Development Strategies to Increase Reserves in Unconventional Gas Reservoirs  

E-print Network

-160) ........................................ 118 Fig.C23? Probability distribution plot of stage-end average gas production for Well 4 on 160 acre-spacing (Stage 2, 160-160) ........................................ 118 Fig.D1? Crossplot of Stage 1 (640 acres) vs. Stage 2 (320 acres) gas... productions 119 Fig.D2? Crossplot of Stage 1 (640 acres) vs. Stage 2 (160 acres) gas productions 120 Fig.D3? Crossplot of Stage 1 (320 acres) vs. Stage 2 (320 acres) gas productions 120 Fig.D4? Crossplot of Stage 1 (320 acres) vs. Stage 2 (160...

Turkarslan, Gulcan

2011-10-21

88

Predicting horizontal well performance in solution-gas drive reservoirs  

E-print Network

-ations ar'd z ock prope ties were used Tl'e oil PVT properties where obtained ~ rcm Star d n~'s and Glaso's coz relations. Gas PVT proper ties wh re obtained using Caz r 's correlation for viscosity and the rea!-gas-!aw for for mation volume factors...-ations ar'd z ock prope ties were used Tl'e oil PVT properties where obtained ~ rcm Star d n~'s and Glaso's coz relations. Gas PVT proper ties wh re obtained using Caz r 's correlation for viscosity and the rea!-gas-!aw for for mation volume factors...

Plahn, Sheldon Von

2012-06-07

89

Vertical composition gradient effects on original hydrocarbon in place volumes and liquid recovery for volatile oil and gas condensate reservoirs  

E-print Network

was used or neglected during a depletion process. To accomplish this, we analyzed several z-grid sizes and well completion cases, for volatile oil, gas condensate and two-phase reservoirs. The studied reservoir fluid belongs to the Cusiana gas condensate...

Jaramillo Arias, Juan Manuel

2012-06-07

90

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

SciTech Connect

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

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

1993-09-01

91

Molecular Gas Reservoir in low-z Powerful Radio Galaxies  

Microsoft Academic Search

Classical double-lobed radio galaxies are hosted almost exclusively by elliptical galaxies that otherwise resemble normal elliptical galaxies in both their global stellar distribution and kinematics. Given that normal elliptical galaxies usually contain undetectable quantities of neutral gas, what fuels the AGN in powerful elliptical radio galaxies? Here, we present results of a search for molecular gas in radio galaxies at

J. Lim; S. Leon; F. Combes; Dinh-v-Trung

2003-01-01

92

A placement model for matrix acidizing of vertically extensive, multilayer gas reservoirs  

E-print Network

is very important especially for the case where the reservoir properties vary along the wellbore. This work provides development and application of an apparent skin factor model which accounts for both damage and mobility difference between acid and gas........................................................................ 21 3.4 Fluid Interface Tracking Model ........................................................... 24 3.5 Wormholing Model .............................................................................. 26 3.6 Apparent Skin Factor Model...

Nozaki, Manabu

2008-10-10

93

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

SciTech Connect

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

NONE

1995-08-01

94

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

E-print Network

to complex pore topology resulting from diagenesis. Conventional methods that rely dominantly on hydraulic classification method with field data acquired in the Cotton Valley tight-gas sandstone reservoir located, and n need to be assigned val- ues for a wide range of rocks. Using a set of fixed a, m, and n values

Torres-Verdín, Carlos

95

3-DIMENSIONAL GEOMECHANICAL MODELING OF A TIGHT GAS RESERVOIR, RULISON FIELD, PICEANCE BASIN, COLORADO  

E-print Network

of a tight gas reservoir at Rulison Field, Colorado has been built to identify and monitor depleted zones. I with time-lapse seismic. Numerous well data sets including one new zonal pressure test were used to extract with production over time. The results are then analyzed with time-lapse shear wave data shot in 2003, 2004

96

Review of fracture fluid-reservoir interactions in tight gas formations  

Microsoft Academic Search

This publication reviews the pertinent literature available on fracture fluid interactions with tight gas formations and other related subjects such as fracture proppants and reservoir characteristics. It deals primarily with the fracture fluids and their components and their effect on the rock matrix through which they flow during and after a massive hydraulic fracturing treatment. The fracture fluid components and

B. A. Baker; H. B. Jr. Carroll

1979-01-01

97

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

E-print Network

connate water salinitiesx zero, 50, 000 ppm and 100, 000 ppm. Choice 19 of salinity was arbitrary although comxnon ranges were represented. Each set of runs consisted of displacements at constant displacement pressures of 3800 psi, 4200 psi and 4600 psi..., 4600 psi being the practical upper limit at which the apparatus could be operated. The rich reservoir fluid was used to xnake displacexnents with natural gas, nitrogen and flue gas as the displacing media. Connate water salinity was zero...

Maxwell, H. D.

2012-06-07

98

Rate Transient Analysis in Shale Gas Reservoirs with Transient Linear Behavior  

E-print Network

APPENDIX C DEVELOPMENT OF ANALYSIS EQUATIONS ..................... 137 APPENDIX D HOMOGENEOUS LINEAR RESERVOIR RESPONSE .......... 148 APPENDIX E EFFECT OF SKIN....................................................................... 150... CHAPTER I INTRODUCTION Natural gas demand in the United States is expected to increase from 23 tcf/yr currently to 30-34 tcf/yr by the year 2025.1 United States natural gas production is also expected to increase from 19.5 tcf/yr in 2004 to more than...

Bello, Rasheed O.

2010-07-14

99

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

100

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

E-print Network

segregation of fluids during gas injection is very marked. With normal commercial depletion times there is essentially complete segregation of fluids when the vertical permeability is ten milli- darcys or more. Fluid segregation is less complete at very... Profiles 14 8. Comparison of Laboratory K /K Curve Calculated g 0 from Simulation Performance without Gravity Effects 9. Compairson of Reservoir Simulations for PSG = 1000. 18 10. Position of Gas-Oil Cpntact at Various Stages of Depletion for PSG...

Ferguson, Ed Martin

2012-06-07

101

Geomechanical Development of Fractured Reservoirs During Gas Production  

E-print Network

INTRODUCTION ....................................................................................... 1 1.1 Overview .................................................................................................................. 1 1.2 Motivation... ................................................................................................................ 21 CHAPTER II FULLY COUPLED POROELASTIC MODEL ...................................... 23 2.1 Introduction ............................................................................................................ 24 2.2 Gas adsorption...

Huang, Jian

2013-04-05

102

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

E-print Network

FRACTURED GAS WELL ANALYSIS - EVALUATION OF IN SITU RESERVOIR PROPERTIES OF LOW PERMEABILITY GAS WELLS STIMULATED BY FINITE CONDUCTIVITY HYDRAULIC FRACTURES A Thesis by CHARLES ADOIZA MAKOJU Submitted to the Graduate College of Texas AQ1... University in partial fulfillment of the requirement for the degree of MASTER OF SCIENCE December 1978 Major Subject: Petroleum Engineering FRACTURED GAS NELL ANALYSIS - EVALUATION OF IN SITU RESERVOIR PROPERTIES OF LOW PERMEABILITY GAS HELLS STIMULATED...

Makoju, Charles Adoiza

2012-06-07

103

Biogeochemical and microbial analyses around gas wells and in the reservoir in a long-term used gas field  

NASA Astrophysics Data System (ADS)

As part of a joint research project microbial communities in the area of the second largest natural gas field in Europe in the Altmark, Germany are analyzed. The Altmark gas field operated by GDF SUEZ E&P Germany GmbH is located at the southern edge of the Northeast German Basin. The reservoir horizons belong to the Permian Rotliegend formation (Saxon) and have an average depth of about 3300 m. CO2 will be injected to enhance the recovery of gas in this with conventional extraction methods nearly depleted gas field (Enhanced Gas Recovery - EGR, BMBF project CLEAN). Microbiological analyses are used to supplement a continuous gas monitoring program at the soil surface above the EGR-site. Microbial production and consumption of CH4 and CO2 are determined together with the carbon isotopic compositions to separate these indigenous biological activities from possibly upward migrating reservoir gases including CO2. The ?13C of CO2 collected in situ was similar to those in incubations, confirming a biological origin. Archaeal cell numbers were approximately one magnitude lower than bacterial cell numbers. In all samples the total number of detectable microorganisms was high in contrast to a generally low activity for CO2 and CH4 production and oxidation. For monitoring of the deep reservoir microbiological and isotopic analyses are used to investigate the microbial community before and after injection of CO2. The ?13C of CO2 and CH4 collected in situ in production waters indicate a thermogenic origin. High cell numbers for bacteria and archaea were detected in production waters from different wells. In contrast microbial activities for CO2 and CH4 production and oxidation were relatively low. So far microbial activities in reservoir fluids collected with in situ samplers at 3512m depth could not be determined in this hypersaline (salinity of 400 per mille) and hot (around 130° C) environment.

Kock, Dagmar; Krüger, Martin

2010-05-01

104

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

105

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

106

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)

1996-12-31

107

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

108

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

109

Impes modeling of volumetric dry gas reservoirs with mobile water  

E-print Network

generated by both the code and CMG...........................44 4.7 Gas rate plots for well W-3........................................................................................45 4.8 Water rate plots for wells W-1 and W-2.......................................................................45 4.9 Bottomhole pressure plots for wells W-1 and W-3....................................................46 4.10 Gp and Wp plots for well W-2..................................................................................47 4.11 Cumulative...

Forghany, Saeed

2004-09-30

110

Diagenesis of an 'overmature' gas reservoir: The Spiro sand of the Arkoma Basin, USA  

USGS Publications Warehouse

The Spiro sand is a laterally extensive thin sandstone of earliest Atokan (Pennsylvanian) age that forms a major natural gas reservoir in the western Arkoma Basin, Oklahoma. Petrographic analysis reveals a variety of diagenetic alterations, the majority of which occurred during moderate to deep burial. Early diagenetic processes include calcite cementation and the formation of Fe-clay mineral peloids and coatings around quartz framework grains. These clays, which underwent transformation to well-crystallized chamosite [polytype Ib(?? = 90??)] on burial, are particularly abundant in medium-grained channel sandstones, whereas illitic clays are predominant in fine-grained interchannel sandstones. Subsequent to mechanical compaction, saddle ankerite precipitated in the reservoir at temperatures in excess of 70??C. Crude oil collected in favourable structural locations during and after ankeritization. Whereas hydrocarbons apparently halted inorganic diagenesis in oil-saturated zones, cementation continued in the underlying water-saturated zones. As reservoir temperatures increased further, hydrocarbons were cracked and a solid pyrobitumen residue remained in the reservoir. At temperatures exceeding ???140-150??C, non-syntaxial quartz cement, ferroan calcite and traces of dickite(?) locally reduced the reservoir quality. Local secondary porosity was created by carbonate cement dissolution. This alteration post-dated hydrocarbon emplacement and is probably related to late-stage infiltration of freshwater along 'leaky' faults. The study shows that the Spiro sandstone locally retained excellent porosities despite deep burial and thermal conditions that correspond to the zone of incipient very low grade metamorphism.

Spotl, C.; Houseknecht, D.W.; Burns, S.J.

1996-01-01

111

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

112

Joule-Thomson Cooling Due to CO2 Injection into Natural GasReservoirs  

SciTech Connect

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

Oldenburg, Curtis M.

2006-04-21

113

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

114

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

SciTech Connect

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

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

2011-09-01

115

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

NASA Astrophysics Data System (ADS)

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

Eid, Mohamed El Gohary

116

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

117

Low permeability gas reservoir production using large hydraulic fractures  

E-print Network

IN 700 ? 4IB. G PSI/DAY DRAW DOWN 04 ~ 4332. 4 MCF / OAY + d 5 PSI/ OAY DRAW DOWN Qq ~ 627. B MCF/OAY 600 0 I 2 3 4 5 6 7 8 9 I 0 I I I 2 I 3 l4 I 5 l6 I 7 i8 TIME ( HRS) lP Z C X IO IL 0 cn ~ M O lal g M IO Is 20 0 IOOO 2000 3000 4000... at the end of the ten years monitored. The income is not discounted and assumes s. gas price of 20 cents per MCF. SUMMARY AND CONCLUSIONS 7 Using the concept of fracturing presented by Wiisey and s. 12 numerical model by Morse, the effect of long...

Holditch, Stephen A

2012-06-07

118

Predicting Well Stimulation Results in a Gas Storage Field in the Absence of Reservoir Data, Using Neural Networks  

E-print Network

SPE 31159 Predicting Well Stimulation Results in a Gas Storage Field in the Absence of Reservoir to increase their productivity is a challenging task. A systematic approach using a three-layer back, access to explicit reservoir data such as porosity, permeability-thickness and stress profile

Mohaghegh, Shahab

119

Inflow performance relationship for perforated wells producing from solution gas drive reservoir  

SciTech Connect

The IPR curve equations, which are available today, are developed for open hole wells. In the application of Nodal System Analysis in perforated wells, an accurate calculation of pressure loss in the perforation is very important. Nowadays, the equation which is widely used is Blount, Jones and Glaze equation, to estimate pressure loss across perforation. This equation is derived for single phase flow, either oil or gas, therefore it is not suitable for two-phase production wells. In this paper, an IPR curve equation for perforated wells, producing from solution gas drive reservoir, is introduced. The equation has been developed using two phase single well simulator combine to two phase flow in perforation equation, derived by Perez and Kelkar. A wide range of reservoir rock and fluid properties and perforation geometry are used to develop the equation statistically.

Sukarno, P. [Inst. Teknologi Bandung (Indonesia); Tobing, E.L.

1995-10-01

120

Determination of gas-condensate relative permeability on whole cores under reservoir conditions. [Middle East  

SciTech Connect

The work reported here was undertaken on rock samples from a Middle-East carbonate retrograde condensate gas field, in order to determine relative permeability to gas and condensate curves. Special attention was given to determination of condensate minimum flowing saturation (or critical condensate saturation) and to reduction of permeability to gas in the presence of immobile condensate saturation. The originality of this work lies in the use of a pseudoreservoir fluid, made up of a methane-pentane-nonane ternary mixture. This choice made it possible to work in conditions representative of reservoir conditions, but with a greater flexibility for experimental procedures. The initial water saturation was restored as in the reservoir. Results indicate two specific behaviours of the gas-condensate system: critical condensate saturations are high (the average value is 36% P.V.), and reduction of permeability to gas is higher than for a standard gas-oil system. Details on experimental procedures, fluid characteristics, results and discussion of these results are reported in this paper.

Gravier, J.F.; Abed, A.F.; Barroux, C.; Lemouzy, P.

1983-03-01

121

HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS  

SciTech Connect

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

Franklin M. Orr, Jr.

2001-06-30

122

Determining tight gas reservoir parameters with an automatic history matching model  

E-print Network

of Committee r~, v') "" Hea ' of Department I / / , ', !, , q l~, ~ /~-, + ( ', ? 6( s-'i, ! i. :. , Member Member August 1977 ABSTRACT Determining Tight Gas Reservoir Parameters With An Automatic History Matching Model. (August 1977) Samuel Robert... that a correct value for porosity cannot be calculated from a transient pressure test unless the skin factor is value for already known. This is not done in practice because a porosity is used to define skin f'actor 1nitially. Ramey 14 suggested...

Aydelotte, Samuel Robert

2012-06-07

123

Hydrothermal origin of oil and gas reservoirs in basement rock of the South Vietnam continental shelf  

SciTech Connect

Oil-saturated granites, with mineral parageneses typical of hydrothermal metasomatism and leaching haloes, have been found near faults in the crystalline basement of the South Vietnam continental shelf. The presence of native silver, barite, zincian copper, and iron chloride indicates a deep origin for the mineralizing fluids. Hydrothermally altered granites are a new possible type of reservoir and considerably broaden the possibilities of oil and gas exploration. 15 refs., 22 figs., 1 tab.

Dmitriyevskiy, A.N.; Kireyev, F.A.; Bochko, R.A.; Fedorova, T.A. (Institute of Oil and Gas Problems of the Russian Academy of Sciences and GANG, Moscow (Russian Federation))

1993-07-01

124

Gas hydrate reservoir degassing: thermodynamic and kinetic data as basis for predictions  

NASA Astrophysics Data System (ADS)

Natural gas hydrates contain predominantly methane but sometimes also other hydrocarbon- and non- hydrocarbon gases such as CO2 or H2S. The amount of other gases beside methane depends on the source of the gas: in case of a microbial origin the gas is almost pure methane whereas gases from thermal origin may contain a high percentage of higher-molecular weight compounds, such as ethane, propane and larger hydrocarbons. Calculated compositions of gas leaking from an oil reservoir also show a significant amount of nitrogen beside the other components. All components in addition to methane have a strong influence on the stability field of the resulting hydrate phase. In the presence of higher hydrocarbons the stability of the resulting gas hydrate is shifted to higher temperatures and lower pressures whereas the enclathration of nitrogen induces a shift of the hydrate stability to higher pressures and lower temperatures in comparison to pure methane hydrate. Furthermore, hydrate formation kinetics also depend on the composition of the gas phase: recent studies have shown the rapid formation of hydrates containing H2S in addition to methane, whereas the formation of hydrates containing small amounts of ethane and propane seemed to be kinetically inhibited. Due to the significant changes in hydrate stability and formation kinetics depending on gas composition thermodynamic and kinetic data for gas mixtures is crucial for all calculations and predictions regarding gas hydrate reservoir degassing as a consequence of climate change. In this study we will present thermodynamic and kinetic data from in-situ measurements (X-ray diffraction and Raman spectroscopy) on gas hydrates that had been synthesized under natural conditions.

Schicks, J. M.; Girod, M.; Naumann, R.; Erzinger, J.; Horsfield, B.; di Primio, R.

2008-12-01

125

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

126

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

NASA Astrophysics Data System (ADS)

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

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

2013-04-01

127

Hydrolyzed Polyacrylamide- Polyethylenimine- Dextran Sulfate Polymer Gel System as a Water Shut-Off Agent in Unconventional Gas Reservoirs  

E-print Network

Technologies such as horizontal wells and multi-stage hydraulic fracturing have made ultra-low permeability shale and tight gas reservoirs productive but the industry is still on the learning curve when it comes to addressing various production...

Jayakumar, Swathika 1986-

2012-07-09

128

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

SciTech Connect

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

NONE

1995-10-01

129

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

SciTech Connect

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

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

1993-09-01

130

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

131

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

SciTech Connect

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

C. Cooper; M. Ye; J. Chapman

2008-04-01

132

Factors Influencing Greenhouse Gas Emissions from Three Gorges Reservoir of China  

NASA Astrophysics Data System (ADS)

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

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

2013-05-01

133

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

134

Diagnosis of "fizz-gas" and gas reservoirs in deep-water environment De-hua Han, X RPL, Houston Unversity  

E-print Network

have systematically examined physical properties of fluid and rock, and fluid interaction with rock saturation effect Gas and water properties Surface seismic data are a measure of impedance contrastDiagnosis of "fizz-gas" and gas reservoirs in deep-water environment De-hua Han, X RPL, Houston

135

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

136

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

NASA Astrophysics Data System (ADS)

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

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

2013-12-01

137

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

NASA Astrophysics Data System (ADS)

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

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

2014-06-01

138

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

139

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

SciTech Connect

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

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

1995-12-31

140

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

USGS Publications Warehouse

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

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

2000-01-01

141

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

142

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

143

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

144

Natural and Induced Fracture Diagnostics from 4-D VSP in 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 Willis; Daniel Burns; M. Nafi Toksoz

2008-09-30

145

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

E-print Network

Various models featuring horizontal wells with multiple induced fractures have been proposed to characterize flow behavior over time in tight gas and shale gas systems. Currently, there is little consensus regarding the effects of non...

Olorode, Olufemi Morounfopefoluwa

2012-02-14

146

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

SciTech Connect

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

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

2002-07-22

147

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

E-print Network

, but it formed a thick water-saturated layer between the free-gas and gas-hydrate zone. Finally, thermodynamic behavior of gas hydrate decomposition was studied. Possible areas of hydrate preservation were determined. It was shown that the central top portion...

Omelchenko, Roman 1987-

2012-12-11

148

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

NASA Astrophysics Data System (ADS)

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

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

2013-02-01

149

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

E-print Network

and displacing methane. The continuing development of the Marcellus Shale has the potential to and positively1 CO2-Driven Enhanced Gas Recovery and Storage in Depleted Shale Reservoir- A Numerical Simulation for storage and enhanced gas recovery may be organic-rich shales, which CO2 is preferentially adsorbed

Mohaghegh, Shahab

150

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

NASA Astrophysics Data System (ADS)

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

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

2010-12-01

151

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

SciTech Connect

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

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

1992-12-01

152

Fracture Modeling and Flow Behavior in Shale Gas Reservoirs Using Discrete Fracture Networks  

E-print Network

Fluid flow process in fractured reservoirs is controlled primarily by the connectivity of fractures. The presence of fractures in these reservoirs significantly affects the mechanism of fluid flow. They have led to problems in the reservoir which...

Ogbechie, Joachim Nwabunwanne

2012-02-14

153

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

154

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

155

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

156

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

PubMed Central

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

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

2012-01-01

157

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

SciTech Connect

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

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

2006-04-28

158

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

159

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

160

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

161

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

162

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

163

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

164

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

SciTech Connect

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

NONE

1995-09-01

165

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

E-print Network

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

Haugen, Sigurd Arild

2012-06-07

166

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

SciTech Connect

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

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

1998-07-01

167

Numerical modeling of gas migration into and through faulted sand reservoirs in Pabst Field (Main Pass East Block 259), northern Gulf of Mexico  

E-print Network

The further exploration and development of Pabst Gas Field with faulted sand reservoirs require an understanding of the properties and roles of faults, particularly Low Throw near Vertical Faults (LTNVFs), in gas migration and accumulation at a...

Li, Yuqian

2006-08-16

168

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

169

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

170

Pore-scale mechanisms of gas flow in tight sand reservoirs  

SciTech Connect

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

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

2010-11-30

171

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

172

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

E-print Network

................................................................................. 36 4.4.1 Parameter Match to North American Shale Gas Field ....................... 36 4.4.2 Exploration of the Space of Sorption Parameters .............................. 44 4.5 Discussion of Compositional Change Results... associated with shales and mudrocks also contains its own microporosity. Illite, kaolinite and some montmorillonite possess a significant fraction of pores of effective radius less than 2 nm (Bustin et al. 2008). Scanning electron microscopic images...

Freeman, Craig Matthew

2013-11-25

173

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

174

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

SciTech Connect

Located in the Fossil basin area of the Wyoming thrust belt, giant Whitney Canyon-Carter Creek field has in place reserves of approximately 4.5 tcf of gas, 125 MMBO (condensate), and 24 million long tons sulfur. It is the largest gas field in the U.S. Rocky Mountains. Hydrocarbons are trapped in large, reverse faulted anticlinal closures that formed completely within the Absaroka thrust plate during Laramide deformation. These structures are ramp anticlines that developed when the Absaroka plate was thrust eastward over ramps in the underlying fault plane. Production is sour natural gas and condensate mainly from Paleozoic reservoirs. The most significant are dolomitized carbonate reservoirs of the Mississippian Mission Canyon and Lodgepole formations and the Ordovician Big Horn Dolomite. The Pennsylvanian Weber Sandstone and the Triassic Thaynes Formation have minor production. Source rocks are subthrust Cretaceous shales that were placed in the oil generation window after thrusting and subsidence. The economically most important reservoir is the Mission Canyon Formation with 79% of the total gas in place. Intercrystalline and moldic porosity was created by dolomitization and subsequent partial solution of mud-supported sediments during early diagenesis. Structural deformation fractured the reservoir, but also created a diagenetic environment that allowed calcite, anhydrite, and dolomite cements to sporadically plug all porosity types. Discovery of Whitney Canyon-Carter Creek field began by identifying a large, potentially productive area within the Fossil basin.

Sieverding, J.L. (Chevron USA, Inc., Houston, TX (United States)); Royse, F. Jr (Chevron USA, Inc., Arvada, CO (United States))

1991-03-01

175

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

176

Analysis of well test data from gas condensate reservoirs using single-phase dry gas methods: guidelines and examples  

E-print Network

as simulation of the test history to ensure a representative analysis. In this thesis we analyze four field cases that exhibit significant variations in reservoir and fluid properties, as well as reservoir attributes (pressure, lithology, etc. ). A general... as simulation of the test history to ensure a representative analysis. In this thesis we analyze four field cases that exhibit significant variations in reservoir and fluid properties, as well as reservoir attributes (pressure, lithology, etc. ). A general...

Bonilla Kalil, Jose Ricardo

2012-06-07

177

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

178

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

SciTech Connect

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

John Kemeny; Satya Harpalani

2004-03-01

179

Underground Gas Storage: Planning and Modeling with Simsim, a New Reservoir Engineering Software Tool  

Microsoft Academic Search

A novel, simplified reservoir simulation software tool has been developed for reservoir engineers called SimSim. It combines the advantages of the simple material balance technique and complex numerical reservoir simulation: it keeps the simplicity and speed of the former, and has results like the latter, i.e. it can calculate pressure, saturation, fluid flux and hydrocarbons in place distributions. An example

Andras Gilicz; F. Pach

180

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

181

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

182

Integrated Multi-Well Reservoir and Decision Model to Determine Optimal Well Spacing in Unconventional Gas Reservoirs  

E-print Network

and hence the optimal development strategy. The integrated model includes two development stages with a varying Stage-1 time span. The integrated tools were applied to an illustrative example in Deep Basin (Gething D) tight gas sands in Alberta, Canada...

Ortiz Prada, Rubiel Paul

2012-02-14

183

Full field reservoir modelling of Central Oman gas/condensate fields  

SciTech Connect

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

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

1995-12-31

184

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

185

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

SciTech Connect

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

NONE

1994-10-01

186

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

187

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

E-print Network

Model Jalal Jalali, Shahab D. Mohaghegh, Dept. of Petroleum & Natural Gas Engineering, West Virginia Reservoir simulation is the industry standard for reservoir management. Complex reservoir models usually contain hundreds of thousands or millions of grid cells. Complexity of reservoir models can result in long

Mohaghegh, Shahab

188

Chemical-mechanical interactions during natural fracture growth in tight gas and oil reservoirs: Implications for flow during reservoir charge and production  

NASA Astrophysics Data System (ADS)

Natural fractures in tight sandstone and shale reservoirs are characterized by partial to complete cementation. In all tight-gas sandstone reservoirs and suitable outcrop reservoir analogs, fractures frequently contain crack-seal quartz and carbonate cement that formed during incremental fracture opening. These synkinematic cements may be followed by blocky postkinematic cement occluding any residual fracture porosity. Fluid inclusion microthermometry combined with Raman analyses demonstrate that synkinematic cement formed under conditions close to maximum burial and incipient exhumation under elevated pore fluid pressures and over time spans of 10-40 m.y.. Fracture opening rates, integrated over the kinematic fracture aperture, are on the order of 10 ?m/m.y. Based on the textural evidence of synkinematic cement growth, in combination with kinetic models of quartz cementation, we infer that these rates are comparable to rates of dissolution-precipitation reactions in the host rock, and of mass transfer between host rock and fracture. It is thus suggested that dissolution-precipitation creep is a dominant deformation mechanism allowing accommodation of permanent fracture strain under these deep-burial, diagenetically reactive conditions. Synkinematic mineral reactions in the host rock and precipitation of fracture lining cement guarantee that partially cemented natural fractures remain propped open and thus conductive under production conditions. However, cement linings and bridges can inhibit flow between micro-porous host rock and residual fracture porosity resulting in flow barriers. Complex pore geometry in partially cemented fractures may impede multiphase fracture flow and production. In shale, the interface between host rock and fracture cement is frequently mechanically weak potentially allowing fracture reactivation during well completion. Such artificially reactivated fractures may thus increase flow of production fluids even in formation containing otherwise sealed natural fractures.

Eichhubl, P.; Fall, A.; Prodanovic, M.; Weisenberger, T.; Ukar, E.; Laubach, S.; Gale, J. F.

2012-12-01

189

Chemical-mechanical interactions during natural fracture growth in tight gas and oil reservoirs: Implications for flow during reservoir charge and production  

NASA Astrophysics Data System (ADS)

Natural fractures in tight sandstone and shale reservoirs are characterized by partial to complete cementation. In all tight-gas sandstone reservoirs and suitable outcrop reservoir analogs, fractures frequently contain crack-seal quartz and carbonate cement that formed during incremental fracture opening. These synkinematic cements may be followed by blocky postkinematic cement occluding any residual fracture porosity. Fluid inclusion microthermometry combined with Raman analyses demonstrate that synkinematic cement formed under conditions close to maximum burial and incipient exhumation under elevated pore fluid pressures and over time spans of 10-50 m.y.. Fracture opening rates, integrated over the kinematic fracture aperture, are on the order of 10 microm/m.y. Based on the textural evidence of synkinematic cement growth, in combination with kinetic models of quartz cementation, we infer that these rates are comparable to rates of dissolution-precipitation reactions in the host rock, and of mass transfer between host rock and fracture. It is thus suggested that dissolution-precipitation creep is a dominant deformation mechanism allowing accommodation of permanent fracture strain under these deep-burial, diagenetically reactive conditions. Synkinematic mineral reactions in the host rock and precipitation of fracture lining cement guarantee that partially cemented natural fractures remain propped open and thus conductive under production conditions. However, cement linings and bridges can inhibit flow between micro-porous host rock and residual fracture porosity resulting in flow barriers. Complex pore geometry in partially cemented fractures may impede multiphase fracture flow and production. In shale, the interface between host rock and fracture cement is frequently mechanically weak potentially allowing fracture reactivation during well completion. Such artificially reactivated fractures may thus increase flow of production fluids even in formation containing otherwise sealed natural fractures.

Eichhubl, Peter; Fall, Andras; Prodanovic, Masa; Tokan-Lawal, Adenike; Lander, Robert; Laubach, Steve

2013-04-01

190

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

NASA Astrophysics Data System (ADS)

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

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

2014-02-01

191

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

SciTech Connect

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

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

1994-12-31

192

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

193

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

194

HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS  

SciTech Connect

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

Franklin M. Orr, Jr.

2003-09-30

195

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

NASA Astrophysics Data System (ADS)

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

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

2010-12-01

196

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

SciTech Connect

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

Gardner, William Payton

2013-06-01

197

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

E-print Network

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

Farzad, Iman

2004-11-15

198

Fracture patterns and their origin in the upper Devonian Antrim Shale gas reservoir of the Michigan basin; a review  

USGS Publications Warehouse

INTRODUCTION: Black shale members of the Upper Devonian Antrim Shale are both the source and reservoir for a regional gas accumulation that presently extends across parts of six counties in the northern part of the Michigan basin (fig. 1). Natural fractures are considered by most petroleum geologists and oil and gas operators who work the Michigan basin to be a necessary condition for commercial gas production in the Antrim Shale. Fractures provide the conduits for free gas and associated water to flow to the borehole through the black shale which, otherwise, has a low matrix permeability. Moreover, the fractures assist in the release of gas adsorbed on mineral and(or) organic matter in the shale (Curtis, 1992). Depths to the gas-producing intervals (Norwood and Lachine Members) generally range from 1,200 to 1,800 ft (Oil and Gas Journal, 1994). Locally, wells that produce gas from the accumulation are as deep as 2,200 (Oil and Gas Journal, 1994). Even though natural fractures are an important control on Antrim Shale gas production, most wells require stimulation by hydraulic fracturing to attain commercial production rates (Kelly, 1992). In the U.S. Geological Survey's National Assessment of United States oil and gas, Dolton (1995) estimates that, at a mean value, 4.45 trillion cubic feet (TCF) of gas are recoverable as additions to already discovered quantities from the Antrim Shale in the productive area of the northern Michigan trend. Dolton (1995) also suggests that undiscovered Antrim Shale gas accumulations exist in other parts of the Michigan basin. The character, distribution, and origin of natural fractures in the Antrim Shale gas accumulation have been studied recently by academia and industry. The intent of these investigations is to: 1) predict 'sweet spots', prior to drilling, in the existing gas-producing trend, 2) improve production practices in the existing trend, 3) predict analogous fracture-controlled gas accumulations in other parts of the Michigan basin, and 4) improve estimates of the recoverable gas in the Antrim Shale gas plays (Dolton, 1995). This review of published literature on the characteristics of Antrim Shale fractures, their origin, and their controls on gas production will help to define objectives and goals in future U.S. Geological Survey studies of Antrim Shale gas resources.

Ryder, Robert T.

1996-01-01

199

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

200

Multiple atmospheric noble gas components in hydrocarbon reservoirs: a study of the Northwest Shelf, Delaware Basin, SE New Mexico  

NASA Astrophysics Data System (ADS)

The Northwest Shelf of the Delaware Basin, SE New Mexico is the site of several large and productive oil and gas fields. The most productive reservoirs are located in the late Pennsylvanian Morrow and early Permian Abo formations. Production from the latter more important play is predominately from fluvial Abo red beds of the Pecos Slope Field. The oxidizing conditions implied by the reddish color of the formation require an external hydrocarbon source. To test the existing migration model for the region and constrain the location of potential hydrocarbon sources, we measured the elemental and isotopic composition of noble gases produced along with the hydrocarbons. We found the hydrocarbons to be highly enriched in radiogenic 4He, 40*Ar and nucleogenic 21*Ne [F( 4He) = 44,000-250,000; 40Ar/ 36Ar = 400-3145; 21Ne/ 22Ne = 0.044-0.071]. The greatest enrichments occur in the Pecos Slope gas fields. The hydrocarbons also contain three independent nonradiogenic noble gas components each with an atmospheric isotopic composition. One component is most likely air-saturated water (ASW). The second component is enriched in the heavy noble gases [F( 130Xe) > 8.5] and is derived from the hydrocarbon sources. The third component is enriched in Ne [F( 20Ne) > 0.8] that we believe is degassed from sources within the reservoirs. This component is correlated with but decoupled from the dominant source of radiogenic 4He and 40*Ar. Very high concentrations of 4He (up to ˜1% by volume) in the Pecos slope reservoirs require a source external to the reservoirs, such as the underlying Precambrian basement granites and sedimentary equivalents. Structural buckles cutting through the Pecos field may act as high flux vertical pathways for the radiogenic 4He. If the hydrocarbons in the Pecos slope fields have migrated northward from the deeper Delaware Basin, as suggested by compositional trends, then perhaps the buckles also play an important role in the distribution and filling of the Pecos slope reservoirs.

Kennedy, B. M.; Torgersen, T.; van Soest, M. C.

2002-09-01

201

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

202

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

E-print Network

reasonable. Babu and Odeh (1989) developed a pseudo steady-state model of inflow performance. This model presumes that the reservoir is bounded by no-flow boundaries, and is based on radial flow in the y-z plane, with the deviation... reasonable. Babu and Odeh (1989) developed a pseudo steady-state model of inflow performance. This model presumes that the reservoir is bounded by no-flow boundaries, and is based on radial flow in the y-z plane, with the deviation...

Dong, Guangwei

2011-02-22

203

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

SciTech Connect

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

Not Available

1991-12-31

204

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

SciTech Connect

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

J.H. Frantz; K.G. Brown

2003-02-01

205

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

206

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

207

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

208

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

209

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

210

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

211

Hybrid computational models for the characterization of oil and gas reservoirs  

Microsoft Academic Search

The process of combining multiple computational intelligence techniques to build a single hybrid model has become increasingly popular. As reported in the literature, the performance indices of these hybrid models have proved to be better than the individual components when used alone. Hybrid models are extremely useful for reservoir characterization in petroleum engineering, which requires high-accuracy predictions for efficient exploration

Tarek Helmy; Anifowose Fatai; Kanaan A. Faisal

2010-01-01

212

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

SciTech Connect

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

Moshier, S.O.

1989-03-01

213

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

214

The simulation of gas production from oceanic gas hydrate reservoir by the combination of ocean surface warm water flooding with depressurization  

NASA Astrophysics Data System (ADS)

A new method is proposed to produce gas from oceanic gas hydrate reservoir by combining the ocean surface warm water flooding with depressurization which can efficiently utilize the synthetic effects of thermal, salt and depressurization on gas hydrate dissociation. The method has the advantage of high efficiency, low cost and enhanced safety. Based on the proposed conceptual method, the physical and mathematical models are established, in which the effects of the flow of multiphase fluid, the kinetic process of hydrate dissociation, the endothermic process of hydrate dissociation, ice-water phase equilibrium, salt inhibition, dispersion, convection and conduction on the hydrate dissociation and gas and water production are considered. The gas and water rates, formation pressure for the combination method are compared with that of the single depressurization, which is referred to the method in which only depressurization is used. The results show that the combination method can remedy the deficiency of individual producing methods. It has the advantage of longer stable period of high gas rate than the single depressurization. It can also reduce the geologic hazard caused by the formation deformation due to the maintaining of the formation pressure by injected ocean warm water.

Yang, Hao; Bai, Yu-Hu; Li, Qing-Ping

2012-10-01

215

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

216

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

SciTech Connect

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

NONE

1996-04-01

217

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

218

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

219

Determination of gas-condensate relative permeability on whole cores under reservoir conditions. [Middle East  

Microsoft Academic Search

The work reported here was undertaken on rock samples from a Middle-East carbonate retrograde condensate gas field, in order to determine relative permeability to gas and condensate curves. Special attention was given to determination of condensate minimum flowing saturation (or critical condensate saturation) and to reduction of permeability to gas in the presence of immobile condensate saturation. The originality of

J. F. Gravier; A. F. Abed; C. Barroux; P. Lemouzy

1983-01-01

220

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

SciTech Connect

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

Blunt, M.J.

1997-04-30

221

Inflow Performance Relationships (IPR) for Solution Gas Drive Reservoirs -- a Semi-Analytical Approach  

E-print Network

of the following parameters: ? = f(API i , GOR i , B oi , ? oi , p i , T Res , S oi , k ro,end , n Corey , ? oi ) We did successfully correlate the ?-parameter as a function of these variables, which proves that we can uniquely represent the pressure...-mobility path during depletion with specific reservoir and fluid property variables, taken as constant values for a particular case. The functional form of our correlation is: n g nnn B pk STAPI GOR A og A ow A w A oi A oi A oi A i A rog A oi A res A A A...

Nass, Maria A.

2010-07-14

222

A method for evaluating a gas reservoir using a digital computer  

E-print Network

-Pressure Test Curve Link III Data Form. Sample On-Line Comments. A-49 A-50 A-5 1 Calculated Individual Well Production Rate Plotted versus Cumulative Production . Calculated Total Reservoir Producing Rate A-5Z A-53 Execution I. A-54 10 Execution II... production data. Description of Link II Link II requires no additional card data. Input to the program consists solely of the individual well data placed on the magnetic tapes by Link I. The program reads this information into the computer for sorting...

Garb, Forrest Allan

2012-06-07

223

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

E-print Network

function (pD=(pi/zi-p/z)/pi/zi) versus a dimen- sionless cumulative production function (GpD=Gp/G), where the type curve solution is based on the new p/z-Gp2 material balance model. iv We also use the "Gan" analysis approach (3 (three) specialized... plots), where this analysis is based on the observation of 2-straight line trends on a p/z-Gp plot for an abnormally pressured reservoir. The Gan analysis is used primarily for orientation, particularly with regard to the 4 new ? -Gp performance plots...

Gonzalez, Felix Eduardo

2005-02-17

224

Paleokarst reservoirs and gas accumulation in the Jingbian field, Ordos Basin  

Microsoft Academic Search

The Jingbian gas field in central Ordos Basin, with a proven initial in place gas reserve of approximately 11 trillion cubic meters, is the largest paleokarst carbonate gas field in China. Paleokarst in Ordovician strata of central Ordos most commonly occurs in the paleo-weathering surface of the O1m5 member of the Majiagou Formation. The karst intervals are generally proximal to

Jian Li; Wenzheng Zhang; Xia Luo; Guoyi Hu

2008-01-01

225

Gas hydrate reservoir degassing: thermodynamic and kinetic data as basis for predictions  

Microsoft Academic Search

Natural gas hydrates contain predominantly methane but sometimes also other hydrocarbon- and non- hydrocarbon gases such as CO2 or H2S. The amount of other gases beside methane depends on the source of the gas: in case of a microbial origin the gas is almost pure methane whereas gases from thermal origin may contain a high percentage of higher-molecular weight compounds,

J. M. Schicks; M. Girod; R. Naumann; J. Erzinger; B. Horsfield; R. di Primio

2008-01-01

226

Determination of Gas-Condensate Relative Permeability on Whole Cores Under Reservoir Conditions  

Microsoft Academic Search

Rock samples from a Middle East carbonate retrograde condensate gas field were studied to determine their relative permeability to gas and condensate curves. The authors emphasized the determination of condensate minimum flowing saturation-or critical condensate saturation-and the reduction of permeability to gas in the presence of immobile condensate saturation. A ternary pseudoreservoir fluid of methane\\/pentane\\/nonane made it possible to work

J. F. Gravier; P. Lemouzy; C. Barroux; A. F. Abed

1986-01-01

227

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

228

"Solution plot technique"-Analysis of water influx in gas reservoirs using simulation studies  

E-print Network

Effects ( Rate = 10 MMscf/d) . . 17. Case 2 - p/z Versus Cumulative Gas Production . . 18. Case 2 - Cumulative Water Influx Versus Time. . . 27 29 29 19. Case 2 - Water Production Rate Versus Time . . 30 20. Case 2 - Cumulative Gas Production Versus... - Gas Production Rate Versus "X" . 26. Case 2 - p/z Versus "X" 27. Case 2 - Solution Plot For No Water Influx . . 33 34 28. Case 2 ? p/z Versus Cumulative Gas Production After Correcting For Water Influx Effects ( Rate = 10 MMscf/d) . . 34 Al ROB...

Hardikar, Sachin Suresh

2012-06-07

229

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

230

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

231

Modeling the phase partitioning behavior of gas tracers under geothermal reservoir conditions  

Microsoft Academic Search

A model of the liquid-vapor phase partitioning behavior of low concentrations of gas tracers in water at geothermal temperatures and pressures is presented. This model uses Henry's coefficient to describe the variation of the gas tracer solubility with temperature and pressure. A new method is described for the determination and representation of Henry's coefficients. The method uses experimentally determined values

Mark Trew; Michael J. O'Sullivan; Yoshio Yasuda

2001-01-01

232

An Advisory System For Selecting Drilling Technologies and Methods in Tight Gas Reservoirs  

E-print Network

,000 trillion cubic feet (Tcf) of natural gas in place worldwide. However, most of the studies such as the ones by the U.S. Geological Survey (U.S.G.S.) and Kuuskraa have focused on assessing the technically recoverable gas resources in the U.S. with numbers...

Pilisi, Nicolas

2010-01-16

233

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

234

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

235

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

E-print Network

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

Freeman, Craig M.

2010-07-14

236

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

237

General screening criteria for shale gas reservoirs and production data analysis of Barnett shale  

E-print Network

). As we notice in Figure 6, there is an important production potential for Shale gas in the US. Gas- in-place resource estimates for the five main plays total 581 Tcf, and recoverable resource estimates range from 31 to 76 Tcf 7 . Because estimates..., and is the most productive gas shale in Texas, with 1.6 Tcf 23 produced as of September 2005, see Figure 22. Permeability ranges from 7 to 50 nanodarcies 24 and porosity from 4 to 6%. Figure 20: General Stratigraphy of the Fort worth...

Deshpande, Vaibhav Prakashrao

2009-05-15

238

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

Microsoft Academic Search

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

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

2004-01-01

239

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

240

Optimal Process Design for Coupled CO2 Sequestration and Enhanced Gas Recovery in Carbonate Reservoirs  

E-print Network

Increasing energy demand combined with public concern for the environment obligates the oil industry to supply oil and natural gas to the public while minimizing the carbon footprint due to its activities. Today, fossil fuels are essential...

Odi, Uchenna

2013-12-09

241

Petrophysical Properties of Unconventional Low-Mobility Reservoirs (Shale Gas and Heavy Oil) by Using Newly Developed Adaptive Testing Approach  

E-print Network

by analyzing the entire pressure sequence. A genetic algorithm estimates additional reservoir parameters algorithm that reduces the testing times in a wide range of downhole conditions. The reservoir models Formation pressure is a fundamental key to assess the hydrocarbon yield of a reservoir. Without an estimate

Torres-Verdín, Carlos

242

Reservoir oil bubblepoint pressures revisited; solution gasoil ratios and surface gas specific gravities  

E-print Network

gravities P.P. Valko´, W.D. McCain Jr.* Harold Vance Department of Petroleum Engineering, Texas A derived using petroleum service company laboratory fluid property data. The primary goal of this paper, for bubblepoint pressure and other fluid properties, require use of stock-tank gas rate and specific gravity

Valkó, Peter

243

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

NASA Astrophysics Data System (ADS)

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

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

2014-07-01

244

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

E-print Network

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

Li, Yamin

2009-05-15

245

Modeling of performance behavior in gas condensate reservoirs using a variable mobility concept  

E-print Network

that the proposed concept (i.e., a radially-varying gas permeability) is oversimplified, in particular, it ignores the diffusive effects of the condensate (i.e., the viscosity-compressibility behavior). However, we have effectively validated the proposed model...

Wilson, Benton Wade

2004-09-30

246

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

E-print Network

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

Vera, Riene

2011-02-22

247

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

248

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

NASA Astrophysics Data System (ADS)

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

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

2013-01-01

249

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

NASA Astrophysics Data System (ADS)

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

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

2009-03-01

250

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

Microsoft Academic Search

In hydrate-bearing sediments, the velocity and attenuation of compressional and shear waves depend primarily on the spatial distribution of hydrates in the pore space of the subsurface lithologies. Recent characterizations of gas hydrate accumulations based on seismic velocity and attenuation generally assume homogeneous sedimentary layers and neglect effects from large- and small-scale heterogeneities of hydrate-bearing sediments. We present an algorithm,

Jun-Wei Huang; Gilles Bellefleur; Bernd Milkereit

2009-01-01

251

The performance of a volatile oil reservoir overlain by a gas cap  

E-print Network

Assumption Surface Production Under Various Separator Conditions (all Stages at 100 F) for m =. 0. 1 30 Oil Saturation in Oil Zone During Pressure Depletion, First Equilibrium and Fluid Distributions Assumptions 7. Recovery of Condensable Hydrocarbons... During Pressure Depletion, First Equilibrium and Fluid Disbribution As sumption 35 8. Gas-Oil Ratio Performance at Per Cent Recovery, First Equilibrium and Fluid Distribution Assumption Oil Saturation During Depletion, Second Equilibrium and Fluid...

Ellis, Joseph Ralph, Jr

2012-06-07

252

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

253

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

E-print Network

and linear gas flow systems. His set of curves uses a drawdown parameter, L This parameter accounts for the variations of pc product during depletion and assumes an average value between the initial pressure and the constant BHFP. For the liquid case...) This pseudo-pressure form was suggested by Al-Hussainy et aL ' ' in 1966. The use of pseudo-pressure dependent properties instead of pressure dependent properties in the diffusivity equation allows similarity between the flow of small compressibility liquid...

El-Banbi, Ahmed

2012-06-07

254

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

SciTech Connect

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

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

2004-12-01

255

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

256

Global importance of “continuous” petroleum reservoirs: Accumulation, distribution and evaluation  

Microsoft Academic Search

Based on distribution of oil and gas in the world, the connotation and characteristics of “continuous” petroleum reservoirs are elaborated in this paper. “Continuous” petroleum reservoirs refer to unconventional trap reservoirs existing in a large-scale unconventional reservoir system, and the distribution of oil and gas is continuous. The main geological characteristics of “continuous” petroleum reservoirs are as follows: located in

Zou Caineng; Tao Shizhen; Yuan Xuanjun; Zhu Rukai; Dong Dazhong; Li Wei; Wang Lan; Gao Xiaohui; Gong Yanjie; Jia Jinhua; Hou Lianhua; Zhang Guangya; Li Jianzhong; Xu Chunchun; Yang Hua

2009-01-01

257

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

NASA Astrophysics Data System (ADS)

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

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

2013-05-01

258

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

SciTech Connect

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

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

1994-07-01

259

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

NASA Astrophysics Data System (ADS)

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

Soua, Mohamed

2014-12-01

260

Application of the isochronal, transient p/z plotting method for determination of original gas in place, to low permeability reservoirs  

E-print Network

required. ACKNOWLEDGEMENTS The author would like to thank Drs. S. W. Poston and L. D. Piper of the Petroleum Engineering Department, and Dr. R. R. Berg of the Geology Department, for their willingness to serve on my advisory committee. He would like.... : "Determining Average Pressure from Pressure Buildup Tests, " SPE Journal, (Feb. 1974) 55-62. 6. Sullivan, S. A. , Poston, S. W. , and Piper, L. D. : "Using Short-Term Pressure Buildup Tests for Gas Reserves Estimation in Tight Gas Reservoirs, " paper SPE...

Protos, Nicholas Emmanuel

2012-06-07

261

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

USGS Publications Warehouse

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

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

2012-01-01

262

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

263

Chemical Changes in Pore Water Composition due to CO2 Injection Under In-Situ P-T Condition of the Altmark Gas Reservoir, Germany  

NASA Astrophysics Data System (ADS)

CO2 storage in depleted gas reservoir combined with enhanced gas recovery may be an economically feasible option to mitigate global warming. The Altmark gas field, located in the western part of the Northeast German Basin, is being considered as a potential candidate for this purpose. Under reservoir conditions (50 bars and 125°C), the CO2 saturated water causes dissolution and subsequent precipitation of minerals of the surrounding rock matrix. Therefore, the main objective of the current study was to investigate the chemical changes in fluid composition due to dissolution/precipitation of minerals under controlled laboratory conditions. A dry sandstone plug from the Altmark reservoir was mounted in a newly designed autoclave system and flushed by a pre-equilibrated mixture of water saturated with CO2 at a constant flow rate of 0.25 cm/h for 12 days at reservoir conditions. Fluid samples were taken at regular intervals for major and trace element analysis and pH was measured simultaneously in the partially de-gassed samples. Fluid analysis showed an increased concentration of Na, K and Cl ions at the beginning indicating early leaching of halite and sylvite which initially inhibited the dissolution of alkali feldspars. Feldspar dissolution occurred later and slower indicated by lower concentrations of Na and K reflecting the lower solubility and slow dissolution kinetics of feldspar. Dissolution of anhydrite was predominantly observed from the increased concentration of Ca and SO4 at earlier time periods. However, the Ca/SO4 molar ratio (>1) indicated the concurrent dissolution of both calcite and anhydrite. The presence of carbonates buffered the pH until day 6. Moreover, the mobilization of Mn, Mg, Ba and Fe might be derived from carbonate impurities. Thermodynamic calculations of mineral saturation indices enabled an evaluation of the CO2-water-rock interactions during the experiment and highlighted the dissolution of the Ca-bearing minerals in the studied solution.

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

2012-12-01

264

Analytical Estimation of CO2 Storage Capacity in Depleted Oil and Gas Reservoirs Based on Thermodynamic State Functions  

E-print Network

Numerical simulation has been used, as common practice, to estimate the CO2 storage capacity of depleted reservoirs. However, this method is time consuming, expensive and requires detailed input data. This investigation proposes an analytical method...

Valbuena Olivares, Ernesto

2012-02-14

265

Prediction of slug-to-annular flow pattern transition (STA) for reducing the risk of gas-lift instabilities and effective gas/liquid transport from low-pressure reservoirs  

SciTech Connect

Flow-pattern instabilities have frequently been observed in both conventional gas-lifting and unloading operations of water and oil in low-pressure gas and coalbed reservoirs. This paper identifies the slug-to-annular flow-pattern transition (STA) during upward gas/liquid transportation as a potential cause of flow instability in these operations. It is recommended that the slug-flow pattern be used mainly to minimize the pressure drop and gas compression work associated with gas-lifting large volumes of oil and water. Conversely, the annular flow pattern should be used during the unloading operation to produce gas with relatively small amounts of water and condensate. New and efficient artificial lifting strategies are required to transport the liquid out of the depleted gas or coalbed reservoir level to the surface. This paper presents held data and laboratory measurements supporting the hypothesis that STA significantly contributes to flow instabilities and should therefore be avoided in upward gas/liquid transportation operations. Laboratory high-speed measurements of flow-pressure components under a broad range of gas-injection rates including STA have also been included to illustrate the onset of large STA-related flow-pressure oscillations. The latter body of data provides important insights into gas deliquification mechanisms and identifies potential solutions for improved gas-lifting and unloading procedures. A comparison of laboratory data with existing STA models was performed first. Selected models were then numerically tested in field situations. Effective field strategies for avoiding STA occurrence in marginal and new (offshore) field applications (i.e.. through the use of a slug or annular flow pattern regimen from the bottomhole to wellhead levels) are discussed.

Toma, P.R.; Vargas, E.; Kuru, E.

2007-08-15

266

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

Microsoft Academic Search

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

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

1997-01-01

267

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

NASA Astrophysics Data System (ADS)

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

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

2013-01-01

268

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

269

The effects of fracture fluid cleanup upon the analysis of pressure buildup tests in tight gas reservoirs  

E-print Network

of Fracture Fluid, Case 4 . . . . . . . . . . . . . . 88 34 Square Root of Time Graph of Cinco's Solutions for Finite Conductivity Vertical Fractures . . . . 98 INTRODUCTION Hydraulic fracturing is used extensively for improving the productivity of wells... and treatments. There are currently four basic techniques which can be used to analyze post-fracture well performance: * semi-log analysis, * square root of time analysis, * type curve analysis, and * history matching by reservoir modeling. The limitations...

Johansen, Atle Thomas

2012-06-07

270

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

271

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

PubMed Central

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

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

2013-01-01

272

SMALL, GEOLOGICALLY COMPLEX RESERVOIRS CAN BENEFIT FROM RESERVOIR SIMULATION  

SciTech Connect

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

Richard E. Bennett

2002-06-24

273

Reservoir sedimentation  

SciTech Connect

Research on reservoir sedimentation in recent years has been aimed mainly at water resources projects in developing countries. These countries, especially in Africa, often have to cope with long droughts, flash floods and severe erosion problems. Large reservoir capacities are required to capture water provided by flash floods so as to ensure the supply of water in periods of drought. The problem arising however is that these floods, due to their tremendous stream power, carry enormous volumes of sediment which, due to the size of reservoirs, are virtually deposited into the reservoir basin, leading to fast deterioration of a costly investment. Accurate forecasting of reservoir behaviour is therefore of the utmost importance. The point of view in this book is that of the water resources engineer who predicts the effect of sediment deposition on a reservoir and its immediate environment. Practical procedures to estimate sediment yield, calculate sediment profiles and assess the influence sediment retention has on the river downstream of a reservoir are presented. Preventative measures are also discussed. The approach adopted in this book is through illustrating theory with examples. The recent theory presented regards processes involved in the deposition of sediment in reservoirs.

Annandale, G.W.

1987-01-01

274

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

275

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

276

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

NASA Astrophysics Data System (ADS)

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

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

2010-05-01

277

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

SciTech Connect

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

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

1996-08-01

278

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

E-print Network

Page 1 Diagnostic gas material balance plot (after Dake11)............................................. 9 2 Conventional p/Z plot (after Dake11).................................................................... 9 3 Procedure to quantify... Page 1 Performance Data from BB Sand....................................................................... 22 2 Mean and Standard Deviation of G, J, and Wi from Volumetric Analysis, BB Sand...

Aprilia, Asti Wulandari

2007-04-25

279

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

E-print Network

technologies, such as large volume fracture treatments, are required before a reasonable profit can be made. Hydraulic fracturing is one of the best methods to stimulate a tight gas well. Most fracture treatments result in 3-6 fold increases in the productivity...

Wang, Yilin

2009-05-15

280

Tertiary carbonate reservoirs in Indonesia  

SciTech Connect

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

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

1981-01-01

281

Optimize production through balanced reservoir depletion  

SciTech Connect

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

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

1989-01-01

282

Fracture characterization of multilayered reservoirs  

SciTech Connect

Fracture treatment optimization techniques have been developed using Long-Spaced-Digital-Sonic (LSDS) log, pumpin-flowback, mini-frac, and downhole treating pressure data. These analysis techniques have been successfully applied in massive hydraulic fracturing (MHF) of ''tight gas'' wells. Massive hydraulic fracture stimulations have been used to make many tight gas reservoirs commercially attractive. However, studies have shown that short highly conductive fractures are optimum for the successful stimulation of wells in moderate permeability reservoirs. As a result, the ability to design and place optimal fractures in these reservoirs is critical. This paper illustrates the application of fracture analysis techniques to a moderate permeability multi-layered reservoir. These techniques were used to identify large zonal variations in rock properties and pore pressure which result from the complex geology. The inclusion of geologic factors in fracture treatment design allowed the placement of short highly conductive fractures which were used to improve injectivity and vertical sweep, and therefore, ultimate recovery.

Britt, L.K.; Larsen, M.J.

1986-01-01

283

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

284

The effect of high-pressure injection of gas on the reservoir volume factor of a crude oil  

E-print Network

Visual Cell To observe the meniscus between oil and gas in the equilibrium cell, a small electric lamp was installed diametrically opposite the windows to transmit light through the cell. By placing a small mirror at 45 degrees to the light... and turning the light another 90 degrees by use of another mirror, the meniscus in the cell could be viewed without danger to the observor if the windows should fail. A Reise 10, 000 psi pressure gauge with 20 psi divisions was used throughout...

Honeycutt, Baxter Bewitt

2012-06-07

285

Estimation of original gas in place from short-term shut-in pressure data for commingled tight gas reservoirs with no crossflow  

E-print Network

-in pressure data; namely one-point (secant), two-point (tangent), curve fitting, and type curve methods. A two dimensional dry gas simulator (GASSIM simulator) was used in this study. The wellbore storage, non-darcy flow, and backflow phenomenon during shut...

Khuong, Chan Hung

2012-06-07

286

Please cite this article in press as: Gilfillan, S.M.V., et al., He and Ne as tracers of natural CO2 migration up a fault from a deep reservoir. Int. J. Greenhouse Gas Control (2011), doi:10.1016/j.ijggc.2011.08.008  

E-print Network

2 migration up a fault from a deep reservoir. Int. J. Greenhouse Gas Control (2011), doi:10.1016/j Control xxx (2011) xxx­xxx Contents lists available at SciVerse ScienceDirect International Journal migration up a fault from a deep reservoir Stuart M.V. Gilfillana, , Mark Wilkinsona , R. Stuart Haszeldinea

287

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

288

FRACTURED PETROLEUM RESERVOIRS  

SciTech Connect

The four chapters that are described in this report cover a variety of subjects that not only give insight into the understanding of multiphase flow in fractured porous media, but they provide also major contribution towards the understanding of flow processes with in-situ phase formation. In the following, a summary of all the chapters will be provided. Chapter I addresses issues related to water injection in water-wet fractured porous media. There are two parts in this chapter. Part I covers extensive set of measurements for water injection in water-wet fractured porous media. Both single matrix block and multiple matrix blocks tests are covered. There are two major findings from these experiments: (1) co-current imbibition can be more efficient than counter-current imbibition due to lower residual oil saturation and higher oil mobility, and (2) tight fractured porous media can be more efficient than a permeable porous media when subjected to water injection. These findings are directly related to the type of tests one can perform in the laboratory and to decide on the fate of water injection in fractured reservoirs. Part II of Chapter I presents modeling of water injection in water-wet fractured media by modifying the Buckley-Leverett Theory. A major element of the new model is the multiplication of the transfer flux by the fractured saturation with a power of 1/2. This simple model can account for both co-current and counter-current imbibition and computationally it is very efficient. It can be orders of magnitude faster than a conventional dual-porosity model. Part II also presents the results of water injection tests in very tight rocks of some 0.01 md permeability. Oil recovery from water imbibition tests from such at tight rock can be as high as 25 percent. Chapter II discusses solution gas-drive for cold production from heavy-oil reservoirs. The impetus for this work is the study of new gas phase formation from in-situ process which can be significantly different from that of gas displacement processes. The work is of experimental nature and clarifies several misconceptions in the literature. Based on experimental results, it is established that the main reason for high efficiency of solution gas drive from heavy oil reservoirs is due to low gas mobility. Chapter III presents the concept of the alteration of porous media wettability from liquid-wetting to intermediate gas-wetting. The idea is novel and has not been introduced in the petroleum literature before. There are significant implications from such as proposal. The most direct application of intermediate gas wetting is wettability alteration around the wellbore. Such an alteration can significantly improve well deliverability in gas condensate reservoirs where gas well deliverability decreases below dewpoint pressure. Part I of Chapter III studies the effect of gravity, viscous forces, interfacial tension, and wettability on the critical condensate saturation and relative permeability of gas condensate systems. A simple phenomenological network model is used for this study, The theoretical results reveal that wettability significantly affects both the critical gas saturation and gas relative permeability. Gas relative permeability may increase ten times as contact angle is altered from 0{sup o} (strongly liquid wet) to 85{sup o} (intermediate gas-wetting). The results from the theoretical study motivated the experimental investigation described in Part II. In Part II we demonstrate that the wettability of porous media can be altered from liquid-wetting to gas-wetting. This part describes our attempt to find appropriate chemicals for wettability alteration of various substrates including rock matrix. Chapter IV provides a comprehensive treatment of molecular, pressure, and thermal diffusion and convection in porous media Basic theoretical analysis is presented using irreversible thermodynamics.

Abbas Firoozabadi

1999-06-11

289

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

290

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)  

E-print Network

We aim to quantify the molecular gas reservoir in a subset of 6 low-metallicity galaxies from the Herschel Dwarf Galaxy Survey with newly acquired CO data, and link this reservoir to the observed star formation activity. 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 [CII] 157um and [OI] 63um observations obtained with the Herschel/PACS spectrometer in the 6 galaxies: Haro11, Mrk1089, Mrk930, NGC4861, NGC625, and UM311. We derive molecular gas mass from several methods including the use of the CO-to-H2 conversion factor Xco (both Galactic and metallicity-scaled values) and of dust measurements. The molecular and atomic gas reservoirs are compared to the star formation activity. We also constrain the physical conditions of the molecular clouds using the non-LTE code RADEX and the spectral synthesis code Cloudy. We detect CO in 5 of the 6 galaxies, including first detections in Haro11 (Z~0.4 Zsun), Mrk930 (0.2 Zsun), and UM311 (0...

Cormier, D; 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

2014-01-01

291

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

SciTech Connect

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

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

1996-09-01

292

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

293

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

294

Issues in geothermal reservoir engineering, modeling, and numerical simulation  

Microsoft Academic Search

The theoretical basis of geothermal reservoir engineering owes much of its origins to the oil and gas industries, but important differences in resource character and geological setting have resulted in substantial divergences from reservoir simulation as practiced in the petroleum industry. Geothermal reservoirs are hotter, contain different fluids, and are usually found within fractured volcanic formations with little or no

Pritchett

1996-01-01

295

Predicting reservoir sedimentation  

E-print Network

Sediments accumulate in reservoirs and significantly decrease storage capacity. Predicting sedimentation is an important consideration in the design of new reservoir projects and in the management of existing reservoirs. Sedimentation rates may vary...

Wooten, Stephanie

2012-06-07

296

Reservoir Characterization Research Laboratory  

E-print Network

Reservoir Characterization Research Laboratory for Carbonate Studies Executive Summary for 2014 Outcrop and Subsurface Characterization of Carbonate Reservoirs for Improved Recovery of Remaining......................................................................................................................................6 Reservoir Architecture and Structural Style of Carbonate Shelf-to-Basin Transitions

Texas at Austin, University of

297

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

298

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

299

New correlations for dew-point, specific gravity and producing yield for gas condensates  

E-print Network

correlation based on reservoir gas specific gravity has been attempted. The second correlation can be used to estimate the specific gravity of the gas currently in the reservoir, after some depletion, using the original reservoir gas specific gravity...

Ovalle Cortissoz, Adriana Patricia

2012-06-07

300

Technology and Economics Affecting Unconventional Reservoir Development  

E-print Network

???????????????????..??..?????? 7 1.6 The chronology of the US energy consumption by source and its relation with technological developments worldwide??????.?????? 8 1.7 Oil and natural gas R&D funds provided by the US government????.. 10 1.8 Investments in oil and gas... recovery R&D and unconventional gas produc- tion. Data from 29 major US-based energy producing companies???? 11 2.1 History matching and forecasting for a natural gas producer reservoir as example???????????????????????............. 16 2...

Flores Campero, Cecilia P.

2010-01-15

301

GAS EXPLORATION Winter 2006 GasTIPS 5  

E-print Network

Seismic-EM Inversion A method for identification of gas saturation in deep ocean oil-gas reservoirs, which- water-gas mix, the determination of gas satu- ration is inherently non-unique. Seismic technology can

Rubin, Yoram

302

Reservoir management practices  

SciTech Connect

This paper describes the reservoir management practices used at fields developed and operated by Esso Production Malaysia Inc. (EPMI). The goal of EPMI's reservoir management activities is to maximize profitability and economical recovery of oil. Excellence in reservoir management is achieved with clearly defined and endorsed plans for management of each reservoir and a coordinated process to collect, analyze, validate, and integrate reservoir description and performance data into optimal development and depletion plans. Use of a multidisciplinary team to identify problems and to implement timely, innovative solutions is a key ingredient. Through regular reports to management and frequent discussion among functional groups, reservoir management objectives and stewardship performance are communicated.

Trice, M.L. (Esso Production Malaysia Inc., EMPI Reservoir Development Section, Kuala Lampur (Malaysia)); Dawe, B.A. (EPMI Offshore Div., Esso Production Malaysia Inc., Kerteh (Malaysia))

1992-12-01

303

Integrated management of multiple reservoir field developments  

SciTech Connect

This paper consists of two sections. The authors first describe the coupling of a pipeline network model to a reservoir simulator and then the application of this new simulator to optimize the production strategy of two Mobil field developments. Mobil`s PEGASUS simulator is an integrated all purpose reservoir simulator that handles black-oil, compositional, faulted and naturally fractured reservoirs. The authors have extended the simulator to simultaneously model multiple reservoirs coupled with surface pipeline networks and processes. This allows them to account for the effects of geology, well placement, and surface production facilities on well deliverability in a fully integrated fashion. They have also developed a gas contract allocation system that takes the user-specified constraints, target rates and swing factors and automatically assigns rates to the individual wells of each reservoir. This algorithm calculates the overall deliverability and automatically reduces the user-specified target rates to meet the deliverability constraints. The algorithm and solution technique are described. This enhanced simulator has been applied to model a Mobil field development in the Southern Gas Basin, offshore United Kingdom, which consists of three separate gas reservoirs connected via a pipeline network. The simulator allowed the authors to accurately determine the impact on individual reservoir and total field performance by varying the development timing of these reservoirs. Several development scenarios are shown to illustrate the capabilities of PEGASUS. Another application of this technology is in the field developments in North Sumatra, Indonesia. Here the objective is to economically optimize the development of multiple fields to feed the PT Arun LNG facility. Consideration of a range of gas compositions, well productivity`s, and facilities constraints in an integrated fashion results in improved management of these assets. Model specifics are discussed.

Lyons, S.L.; Chan, H.M.; Harper, J.L.; Boyett, B.A.; Dowson, P.R.; Bette, S.

1995-10-01

304

Bubble convection within magma reservoirs  

NASA Astrophysics Data System (ADS)

Volcanoes are gas-rich hence small bubbles slowly rise in magma reservoirs. Under certain condition of gas flux, bubble size and reservoir height, the bubble rise is no more homogeneous: the collective buoyancy of the bubbles produces instabilities and the bubble motion becomes driven by convection. If such a convection occurs, the residence time of bubbles in the reservoir is reduced and thus eruptive activity is modified. By analogy with thermal convection, we define Rayleigh (Rab) and Prandtl (Prb) numbers for bubble convection. However, the critical Rab for bubble convection is hardly known from previous studies and its dependence to Prb is ignored. Laboratory experiments are performed with small bubbles rising in a cylindrical tank filled with viscous oils in order to quantify bubble convection and apply it to real volcanoes. Rab and Prb are acurately determined from measurement, via two hydrophones, of bubble size and gas volume fraction. Bubble velocity is obtained by PIV. Experiments show two main regimes: a steady cellular regime at low Rab and a bubble plume regime when Rab is higher. The critical Rab depends on the critical Prb for the two transitions.

Bouche, Emmanuella; Vergniolle, Sylvie; Gamblin, Yves; Vieira, Antonio

2008-11-01

305

Carbon emission from global hydroelectric reservoirs revisited.  

PubMed

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

Li, Siyue; Zhang, Quanfa

2014-12-01

306

Nacimiento Reservoir San Antonio Reservoir Searles Lake  

E-print Network

Nacimiento Reservoir San Antonio Reservoir Searles Lake (Dry) 5 CHOLAME ARCO DEVILS DEN PANOCHE SWICTHING STATION WESTLANDS 18RA CALFLAX PLEASANT VALLEY PUMPS TULARE LAKE KINGS KETTLEMAN HILLS AVENAL Tulare Lake Bed VEDDER POSO MOUNTAIN RIO BRAVO POSO COSO 1-3 COSO 4-6 COSO 8-9 COSO 7 HAIWEE BANK C DOWNS

307

Data quality enhancement in oil reservoir operations : an application of IPMAP  

E-print Network

This thesis presents a study of data quality enhancement opportunities in upstream oil and gas industry. Information Product MAP (IPMAP) methodology is used in reservoir pressure and reservoir simulation data, to propose ...

Lin, Paul Hong-Yi

2012-01-01

308

Sensitivity analysis of modeling parameters that affect the dual peaking behaviour in coalbed methane reservoirs  

E-print Network

gas reservoirs, one of which is in its modeling. This thesis includes a sensitivity study that provides a fuller understanding of the parameters involved in coalbed methane production, how coalbed methane reservoirs are modeled and the effects...

Okeke, Amarachukwu Ngozi

2006-10-30

309

30 CFR 250.1150 - What are the general reservoir production requirements?  

Code of Federal Regulations, 2011 CFR

...What are the general reservoir production requirements? 250.1150...Resources BUREAU OF OCEAN ENERGY MANAGEMENT, REGULATION...CONTINENTAL SHELF Oil and Gas Production Requirements General ...What are the general reservoir production requirements? You...

2011-07-01

310

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

311

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

National Technical Information Service (NTIS)

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 co...

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

1994-01-01

312

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

313

Dissolved methane in Indian freshwater reservoirs.  

PubMed

Emission of methane (CH4), a potent greenhouse gas, from tropical reservoirs is of interest because such reservoirs experience conducive conditions for CH4 production through anaerobic microbial activities. It has been suggested that Indian reservoirs have the potential to emit as much as 33.5 MT of CH4 per annum to the atmosphere. However, this estimate is based on assumptions rather than actual measurements. We present here the first data on dissolved CH4 concentrations from eight freshwater reservoirs in India, most of which experience seasonal anaerobic conditions and CH4 buildup in the hypolimnia. However, strong stratification prevents the CH4-rich subsurface layers to ventilate CH4 directly to the atmosphere, and surface water CH4 concentrations in these reservoirs are generally quite low (0.0028-0.305 ?M). Moreover, only in two small reservoirs substantial CH4 accumulation occurred at depths shallower than the level where water is used for power generation and irrigation, and in the only case where measurements were made in the outflowing water, CH4 concentrations were quite low. In conjunction with short periods of CH4 accumulation and generally lower concentrations than previously assumed, our study implies that CH4 emission from Indian reservoirs has been greatly overestimated. PMID:23397538

Narvenkar, G; Naqvi, S W A; Kurian, S; Shenoy, D M; Pratihary, A K; Naik, H; Patil, S; Sarkar, A; Gauns, M

2013-08-01

314

30 CFR 250.1159 - May the Regional Supervisor limit my well or reservoir production rates?  

Code of Federal Regulations, 2013 CFR

...INTERIOR OFFSHORE OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF Oil and Gas Production Requirements Production...production, reservoir sensitivity, gas-oil and water-oil ratios...by the Regional Supervisor. Flaring, Venting, and Burning...

2013-07-01

315

30 CFR 250.1159 - May the Regional Supervisor limit my well or reservoir production rates?  

Code of Federal Regulations, 2012 CFR

...INTERIOR OFFSHORE OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF Oil and Gas Production Requirements Production...production, reservoir sensitivity, gas-oil and water-oil ratios...by the Regional Supervisor. Flaring, Venting, and Burning...

2012-07-01

316

30 CFR 250.1159 - May the Regional Supervisor limit my well or reservoir production rates?  

...INTERIOR OFFSHORE OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF Oil and Gas Production Requirements Production...production, reservoir sensitivity, gas-oil and water-oil ratios...by the Regional Supervisor. Flaring, Venting, and Burning...

2014-07-01

317

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

E-print Network

Different methods have been proposed for history matching production of shale gas/oil wells which are drilled horizontally and usually hydraulically fractured with multiple stages. These methods are simulation, analytical models, and empirical...

Samandarli, Orkhan

2012-10-19

318

An on-demand microfluidic hydrogen generator with self-regulated gas generation and self-circulated reactant exchange with a rechargeable reservoir  

Microsoft Academic Search

This article introduces an on-demand microfluidic hydrogen generator that can be integrated with a micro-proton exchange membrane\\u000a (PEM) fuel cell. The catalytic reaction, reactant circulation, gas\\/liquid separation, and autonomous control functionalities\\u000a are all integrated into a single microfluidic device. It generates hydrated hydrogen gas from an aqueous ammonia borane solution\\u000a which is circulated and exchanged between the microfluidic reactor and

L. Zhu; N. Kroodsma; J. Yeom; J. L. Haan; M. A. Shannon; D. D. Meng

319

Top-Down, Intelligent Reservoir Model  

NASA Astrophysics Data System (ADS)

Conventional reservoir simulation and modeling is a bottom-up approach. It starts with building a geological model of the reservoir that is populated with the best available petrophysical and geophysical information at the time of development. Engineering fluid flow principles are added and solved numerically so as to arrive at a dynamic reservoir model. The dynamic reservoir model is calibrated using the production history of multiple wells and the history matched model is used to strategize field development in order to improve recovery. Top-Down, Intelligent Reservoir Modeling approaches the reservoir simulation and modeling from an opposite angle by attempting to build a realization of the reservoir starting with the measured well production behavior (history). The production history is augmented by core, log, well test and seismic data in order to increase the accuracy of the Top-Down modeling technique. Although not intended as a substitute for the conventional reservoir simulation of large, complex fields, this novel approach to reservoir modeling can be used as an alternative (at a fraction of the cost) to conventional reservoir simulation and modeling in cases where performing conventional modeling is cost (and man-power) prohibitive. In cases where a conventional model of a reservoir already exists, Top-Down modeling should be considered as a compliment to, rather than a competition for the conventional technique, to provide an independent look at the data coming from the reservoir/wells for optimum development strategy and recovery enhancement. Top-Down, Intelligent Reservoir Modeling starts with well-known reservoir engineering techniques such as Decline Curve Analysis, Type Curve Matching, History Matching using single well numerical reservoir simulation, Volumetric Reserve Estimation and calculation of Recovery Factors for all the wells (individually) in the field. Using statistical techniques multiple Production Indicators (3, 6, and 9 months cum. production as well as 1, 3, 5, and 10 year cum. oil, gas and water production and Gas Oil Ratio and Water Cut) are calculated. These analyses and statistics generate a large volume of data and information that are snapshots of reservoir behavior in discrete slices of time and space. This large volume of data is processed using state-of-the-art in artificial intelligence and data mining (neural modeling, genetic optimization and fuzzy pattern recognition), first using a set of discrete modeling techniques to generate production related predictive models of well behavior. The set of discrete, intelligent models are then integrated using a continuous fuzzy pattern recognition algorithm in order to arrive at a cohesive picture and model of the reservoir as a whole. The Top-Down, Intelligent Reservoir Model is calibrated using the most recent set of wells that have been drilled. The calibrated model is used for field development strategies to improve and enhance hydrocarbon recovery.

Mohaghegh, Shahab

2010-05-01

320

Geothermal reservoir technology  

SciTech Connect

A status report on Lawrence Berkeley Laboratory's Reservoir Technology projects under DOE's Hydrothermal Research Subprogram is presented. During FY 1985 significant accomplishments were made in developing and evaluating methods for (1) describing geothermal systems and processes; (2) predicting reservoir changes; (3) mapping faults and fractures; and (4) field data analysis. In addition, LBL assisted DOE in establishing the research needs of the geothermal industry in the area of Reservoir Technology. 15 refs., 5 figs.

Lippmann, M.J.

1985-09-01

321

Global Carbon Reservoir Oxidative Ratios  

NASA Astrophysics Data System (ADS)

Photosynthesis and respiration move carbon and oxygen between the atmosphere and the biosphere at a ratio that is characteristic of the biogeochemical processes involved. This ratio is called the oxidative ratio (OR) of photosynthesis and respiration, and is defined as the ratio of moles of O2 per moles of CO2. This O2/CO2 ratio is a characteristic of biosphere-atmosphere gas fluxes, much like the 13C signature of CO2 transferred between the biosphere and the atmosphere has a characteristic signature. OR values vary on a scale of 0 (CO2) to 2 (CH4), with most ecosystem values clustered between 0.9 and 1.2. Just as 13C can be measured for both carbon fluxes and carbon pools, OR can also be measured for fluxes and pools and can provide information about the processes involved in carbon and oxygen cycling. OR values also provide information about reservoir organic geochemistry because pool OR values are proportional to the oxidation state of carbon (Cox) in the reservoir. OR may prove to be a particularly valuable biogeochemical tracer because of its ability to couple information about ecosystem gas fluxes with ecosystem organic geochemistry. We have developed 3 methods to measure the OR of ecosystem carbon reservoirs and intercalibrated them to assure that they yield accurate, intercomparable data. Using these tools we have built a large enough database of biomass and soil OR values that it is now possible to consider the implications of global patterns in ecosystem OR values. Here we present a map of the natural range in ecosystem OR values and begin to consider its implications. One striking pattern is an apparent offset between soil and biospheric OR values: soil OR values are frequently higher than that of their source biomass. We discuss this trend in the context of soil organic geochemistry and gas fluxes.

Masiello, C. A.; Gallagher, M. E.; Hockaday, W. C.

2010-12-01

322

Coastal barrier reservoirs  

SciTech Connect

Coastal barriers are long, narrow, wave-built, sandy islands parallel to the shore. Part of the island has a beach, but many have sand dunes and areas of vegetation above the high-tide line. A lagoon or estuary is behind the barrier on the protected side away from the ocean. Coastal barrier reservoirs can hold major accumulations of oil and gas. Coastal barriers can build by three major processes; addition of sand washed onto the beach from breaker bars, addition on one end by sand washed from the other end and moved by riptides, and deposition of sand into the lagoon by waves breaking over the barrier during storms. Galveston Island, offshore Texas, is a good example of a modern coastal barrier. Waves in the Gulf of Mexico have sufficient energy to transport and deposit fine-grained sand on Galveston Island. (Fine-grained sand is the coarsest sand available in upper Texas coastal waters). Other examples of modern coastal barriers are found in the Gulf of California, where medium-sized sands are deposited. An example of an ancient deposit was found in the Elk City field, where the barrier beach was composed of well-sorted gravel and coarse sand.

Richardson, J.G.; Sangree, J.B.; Sneider, R.M.

1988-09-01

323

The Role of Acidizing in Proppant Fracturing in Carbonate Reservoirs  

E-print Network

Today, optimizing well stimulation techniques to obtain maximum return of investment is still a challenge. Hydraulic fracturing is a typical application to improve ultimate recovery from oil and gas reservoirs. Proppant fracturing has become one...

Densirimongkol, Jurairat

2010-10-12

324

The Ahuachapan geothermal field, El Salvador: Reservoir analysis  

SciTech Connect

These are appendices F through I of the Ahuachapan Geothermal Field Reservoir Analysis. The volume contains: well logs, water chemistry plots, gas chemistry plots, temperature plots, and flow plots. (JEF)

Aunzo, Z.; Bodvarsson, G.S.; Laky, C.; Lippmann, M.J.; Steingrimsson, B.; Truesdell, A.H.; Witherspoon, P.A. (Lawrence Berkeley Lab., CA (USA); Icelandic National Energy Authority, Reykjavik (Iceland); Geological Survey, Menlo Park, CA (USA); Lawrence Berkeley Lab., CA (USA))

1989-08-01

325

Optimising hydraulic fracture treatments in reservoirs under complex conditions.  

E-print Network

??Growing global energy demand has prompted the exploitation of non-conventional resources such as Coal Bed Methane (CBM) and conventional resources such as gas-condensate reservoirs. Exploitation… (more)

Valencia, Karen Joy

2005-01-01

326

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.

1980-10-01

327

Determination of permeability index using Stoneley slowness analysis, NMR models, and formation evaluations: a case study from a gas reservoir, south of Iran  

NASA Astrophysics Data System (ADS)

In hydrocarbon reservoirs, permeability is one of the most critical parameters with a significant role in the production of hydrocarbon resources. Direct determination of permeability using Stoneley waves has always had some difficulties. In addition, some un-calibrated empirical models such as Nuclear Magnetic Resonance (NMR) models and petrophysical evaluation model (intrinsic permeability) do not provide reliable estimates of permeability in carbonate formations. Therefore, utilizing an appropriate numerical method for direct determination of permeability using Stoneley waves as well as an appropriate calibration method for the empirical models is necessary to have reliable results. This paper shows the application of a numerical method, called bisection method, in the direct determination of permeability from Stoneley wave slowness. In addition, a linear regression (least squares) method was used to calibrate the NMR models including Schlumberger Doll Research (SDR) and Timur-Coates models as well as the intrinsic permeability equation (permeability from petrophysical evaluations). The Express Pressure Tester (XPT) permeability was considered as an option for the reference permeability. Therefore, all permeability models were validated for the Stoneley permeability and calibrated for the empirical models with the XPT permeability. In order to have a quantitative assessment on the results and compare the results before and after the calibration, the Root Mean Squares Error (RMSE) was calculated for each of the used models. The results for the Stoneley permeability showed that, in many points there was not much difference between the Stoneley permeability calculated by the bisection method and the XPT permeability. Comparing the results showed that the calibration of the empirical models reduced their RMSE values. As a result of the calibration, the RMSE was decreased by about 39% for the SDR model, 18% for the Timur-Coates model, and 91% for the petrophysical evaluations model. Presented bisection method calculates permeability directly without of any inversion or external calibration.

Hosseini, Mirhasan; Javaherian, Abdolrahim; Movahed, Bahram

2014-10-01

328

3D reservoir visualization  

SciTech Connect

This paper shows how some simple 3D computer graphics tools can be combined to provide efficient software for visualizing and analyzing data obtained from reservoir simulators and geological simulations. The animation and interactive capabilities of the software quickly provide a deep understanding of the fluid-flow behavior and an accurate idea of the internal architecture of a reservoir.

Van, B.T.; Pajon, J.L.; Joseph, P. (Inst. Francais du Petrole (FR))

1991-11-01

329

COMPUTATION OF RESERVOIRS SEDIMENTATION  

Microsoft Academic Search

Methods for the computation of sedimentation by suspended sediments and bed load of the projected reservoirs are given, or the first year Of the reservoir operation computation is made according to the balance of sediments computed by the difference between the transport capacity and the hydraulic parameters of the current at the upper pool (transient region) and at the dan

A. V. Karaushev; I. V. Bogoliubova

330

Protozoa in open reservoirs  

Microsoft Academic Search

The impact of storage of potable water in open reservoirs assessed by examining inlet and effluent water samples from six open finished water reservoirs used by four New Jersey utilities. Water quality parameters investigated included Giardia cysts, Cryptosporidium oocysts, total and fecal coliforms, bacteriophage, heterotrophic plate count bacteria, turbidity, particle counts, chlorine residuals and other parameters. Fifteen percent of inlet

Mark W. LeChevallier; William D. Norton; Thomas B. Atherholt

1997-01-01

331

Geysers reservoir studies  

SciTech Connect

LBL is conducting several research projects related to issues of interest to The Geysers operators, including those that deal with understanding the nature of vapor-dominated systems, measuring or inferring reservoir processes and parameters, and studying the effects of liquid injection. All of these topics are directly or indirectly relevant to the development of reservoir strategies aimed at stabilizing or increasing production rates of non-corrosive steam, low in non-condensable gases. Only reservoir engineering studies will be described here, since microearthquake and geochemical projects carried out by LBL or its contractors are discussed in accompanying papers. Three reservoir engineering studies will be described in some detail, that is: (a) Modeling studies of heat transfer and phase distribution in two-phase geothermal reservoirs; (b) Numerical modeling studies of Geysers injection experiments; and (c) Development of a dual-porosity model to calculate mass flow between rock matrix blocks and neighboring fractures.

Bodvarsson, G.S.; Lippmann, M.J.; Pruess, K.

1993-04-01

332

Relation between facies, diagenesis, and reservoir quality of Rotliegende reservoirs in north Germany  

SciTech Connect

In north Germany, the majority of Rotliegende gas fields is confined to an approximately 50 km-wide east-west-orientated belt, which is situated on the gently north-dipping flank of the southern Permian basin. Approximately 400 billion m[sup 3] of natural gas has been found in Rotliegende reservoir sandstones with average porosities of depths ranging from 3500 to 5000 m. Rotliegende deposition was controlled by the Autunian paleo-relief, and arid climate and cyclic transgressions of the desert lake. In general, wadis and large dunefields occur in the hinterland, sebkhas with small isolate dunes and shorelines define the coastal area, and a desert lake occurs to the north. The sandstones deposited in large dunefields contain only minor amounts of illite, anhydrite, and calcite and form good reservoirs. In contrast, the small dunes formed in the sebkha areas were affected by fluctuations of the desert lake groundwaters, causing the infiltration of detrital clay and precipitation of gypsum and calcite. These cements were transformed to illite, anhydrite, and calcite-II during later diagenesis, leading to a significant reduction of the reservoir quality. The best reservoirs occur in the shoreline sandstones because porosity and permeability were preserved by early magnesium-chlorite diagenesis. Since facies controls diagenesis and consequently reservoir quality, mapping of facies also indicates the distribution of reservoir and nonreservoir rocks. This information is used to identify play area and to interpret and calibrate three-dimensional seismic data.

David, F.; Gast, R.; Kraft, T. (BEB Erdgas Erdol GmbH, Hannover (Germany))

1993-09-01

333

Geothermal-reservoir engineering research at Stanford University. Second annual report, October 1, 1981-September 30, 1982  

SciTech Connect

Progress in the following tasks is discussed: heat extraction from hydrothermal reservoirs, noncondensable gas reservoir engineering, well test analysis and bench-scale experiments, DOE-ENEL Cooperative Research, Stanford-IIE Cooperative Research, and workshop and seminars. (MHR)

Ramey, H.J. Jr.; Kruger, P.; Horne, R.N.; Brigham, W.E.; Miller, F.G.

1982-09-01

334

Integrated reservoir studies enhance well completions  

SciTech Connect

Integrated reservoir studies, together with modern completion and stimulation techniques, enhance well productivity while lowering completion costs. Results from different areas show that this approach increased productivity from 40% to 100% over previous applied methods. These approaches incorporate detailed production response characterization with a technical examination of past completion and stimulation practices to: Quantify the effectiveness of prior completion methods; Customize completions by specifically tailoring stimulation procedures to match the individual reservoir with its specific producing and fracturing idiosyncrasies. Two case histories, the Deep Red Fork (oil) formation of Oklahoma and the Haynesville (natural gas) formation of Louisiana, are used to illustrate the method.

Jordan, J.S.; Aud, W.W. [Integrated Petroleum Technologies, Inc., Golden, CO (United States); Burns, R. [UMC Petroleum Corp., Denver, CO (United States)

1998-03-16

335

Mechanism of reservoir testing  

SciTech Connect

In evaluating geothermal resources we are primarily interested in data on the distribution of temperature and fluid conductivity within the reservoir, the total volume of the productive formations, recharge characteristics and chemical quality of the thermal fluids. While geophysical exploration by surface methods may furnish some data on the temperature field and give indications as to the reservoir volume, they furnish practically no information on the fluid conductivity and production characteristics. Such information will generally have to be obtained by tests performed within the reservoir, primarily by production tests on sufficiently deep wells. Reservoir testing is therefore one of the most important tasks in a general exploration program. In principal, reservoir testing has much in common with conventional geophysical exploration. Although the physical fields applied are to some extent different, they face the same type of selection between controlled and natural drives, forward and inverse problem setting, etc. The basic philosophy (Bodvarsson, 1966) is quite similar. In the present paper, they discuss some fundamentals of the theory of reservoir testing where the fluid conductivity field is the primary target. The emphasis is on local and global aspects of the forward approach to the case of liquid saturated (dominated) Darcy type formations. Both controlled and natural driving pressure or strain fields are to be considered and particular emphasis is placed on the situation resulting from the effects of a free liquid surface at the top of the reservoir.

Bodvarsson, Gunnar

1987-01-01

336

Integrated management of multiple-reservoir field development  

SciTech Connect

This paper describes the coupling of a pipeline network model to a reservoir simulator and its application to optimize the production strategy of two Mobil field developments. Mobil`s PEGASUS simulator is an integrated, all-purpose reservoir simulator that handles black-oil, compositional, faulted, and naturally fractured reservoirs. The authors have extended the simulator to allow simultaneous modeling of multiple reservoirs coupled with surface pipeline networks and processes. This allows one to account for the effects of geology, well placement, and surface production facilities on well deliverability in a fully integrated fashion. They have also developed a gas-contract allocation system that takes the user-specified constraints, target rates, and swing factors and automatically assigns rates to the individual wells of each reservoir. This algorithm calculates the overall deliverability and automatically reduces the user-specified target rates to meet the deliverability constraints. The algorithm and solution technique are described. This enhanced simulator has been applied to model a Mobil field development in the Southern gas basin offshore the UK, which consists of three separate gas reservoirs connected by means of a pipeline network. Another application of this technology is in their field development in North Sumatra, Indonesia. Here the objective is to optimize the development of multiple fields economically to feed the P.T. Arun liquid natural gas (LNG) facility. A range of gas compositions, well productivities, and facilities constraints are considered in an integrated fashion, resulting in improved management of these assets. Model specifics are discussed.

Lyons, S.L.; Chan, H.M.; Harper, J.L.; Boyett, B.A. [Mobil E ad P Technical Center, Dallas, TX (United States); Dowson, P.R. [Mobil North Sea Ltd., London (United Kingdom); Bette, S.

1995-12-01

337

Reservoir characterization of Pennsylvanian sandstone reservoirs. Final report  

SciTech Connect

This final report summarizes the progress during the three years of a project on Reservoir Characterization of Pennsylvanian Sandstone Reservoirs. The report is divided into three sections: (i) reservoir description; (ii) scale-up procedures; (iii) outcrop investigation. The first section describes the methods by which a reservoir can be described in three dimensions. The next step in reservoir description is to scale up reservoir properties for flow simulation. The second section addresses the issue of scale-up of reservoir properties once the spatial descriptions of properties are created. The last section describes the investigation of an outcrop.

Kelkar, M.

1995-02-01

338

Reservoir and injection technology and Heat Extraction Project  

SciTech Connect

For the Stanford Geothermal Program in the fiscal year 1989, the task areas include predictive modeling of reservoir behavior and tracer test interpretation and testing. Major emphasis is in reservoir technology, reinjection technology, and heat extraction. Predictive modeling of reservoir behavior consists of a multi-pronged approach to well test analysis under a variety of conditions. The efforts have been directed to designing and analyzing well tests in (1) naturally fractured reservoirs; (2) fractured wells; (3) complex reservoir geometries; and, (4) gas reservoirs including inertial and other effects. The analytical solutions for naturally fractured reservoirs are determined using fracture size distribution. In the study of fractured wells, an elliptical coordinate system is used to obtain semi-analytical solutions to finite conductivity fractures. Effort has also been directed to the modeling and creation of a user friendly computer program for steam/gas reservoirs including wellbore storage, skin and non-Darcy flow effects. This work has a complementary effort on modeling high flow rate wells including inertial effects in the wellbore and fractures. In addition, work on gravity drainage systems is being continued.

Horne, R.N.; Ramey, H.H. Jr.; Miller, F.G.; Brigham, W.E.; Kruger, P.

1989-12-31

339

Potential Mammalian Filovirus Reservoirs  

PubMed Central

Ebola and Marburg viruses are maintained in unknown reservoir species; spillover into human populations results in occasional human cases or epidemics. We attempted to narrow the list of possibilities regarding the identity of those reservoir species. We made a series of explicit assumptions about the reservoir: it is a mammal; it supports persistent, largely asymptomatic filovirus infections; its range subsumes that of its associated filovirus; it has coevolved with the virus; it is of small body size; and it is not a species that is commensal with humans. Under these assumptions, we developed priority lists of mammal clades that coincide distributionally with filovirus outbreak distributions and compared these lists with those mammal taxa that have been tested for filovirus infection in previous epidemiologic studies. Studying the remainder of these taxa may be a fruitful avenue for pursuing the identity of natural reservoirs of filoviruses. PMID:15663841

Carroll, Darin S.; Mills, James N.; Johnson, Karl M.

2004-01-01

340

Martian Surface Water Reservoir  

NASA Astrophysics Data System (ADS)

We present a comprehensive study of the water-related 3µm absorption using OMEGA data. We quantify the surface water reservoir using laboratory studies and reveal the distribution of the amorphous hydrated component measured by Curiosity.

Audouard, J.; Poulet, F.; Vincendon, M.; Milliken, R. E.; Jouglet, D.; Bibring, J.-P.; Gondet, B.; Langevin, Y.

2014-07-01

341

Uncertainty Analysis of Reservoir Sedimentation  

Microsoft Academic Search

Significant advances have been made in understanding the importance of the factors involved in reservoir sedimentation. However, predicting the accumulation of sediment in a reservoir is still a complex problem. In estimating reservoir sedimentation and accumulation, a number of uncertainties arise. These are related to quantity of streamflow, sediment load, sediment particle size, and specific weight, trap efficiency, and reservoir

Jose D. Salas; Hyun-Suk Shin

1999-01-01

342

CO2 storage resources, reserves, and reserve growth: Toward a methodology for integrated assessment of the storage capacity of oil and gas reservoirs and saline formations  

USGS Publications Warehouse

Geologically based methodologies to assess the possible volumes of subsurface CO2 storage must apply clear and uniform definitions of resource and reserve concepts to each assessment unit (AU). Application of the current state of knowledge of geologic, hydrologic, geochemical, and geophysical parameters (contingencies) that control storage volume and injectivity allows definition of the contingent resource (CR) of storage. The parameters known with the greatest certainty are based on observations on known traps (KTs) within the AU that produced oil, gas, and water. The aggregate volume of KTs within an AU defines the most conservation volume of contingent resource. Application of the concept of reserve growth to CR volume provides a logical path for subsequent reevaluation of the total resource as knowledge of CO2 storage processes increases during implementation of storage projects. Increased knowledge of storage performance over time will probably allow the volume of the contingent resource of storage to grow over time, although negative growth is possible. ?? 2009 Elsevier Ltd. All rights reserved.

Burruss, R. C.

2009-01-01

343

Session: Reservoir Technology  

SciTech Connect

This session at the Geothermal Energy Program Review X: Geothermal Energy and the Utility Market consisted of five papers: ''Reservoir Technology'' by Joel L. Renner; ''LBL Research on the Geysers: Conceptual Models, Simulation and Monitoring Studies'' by Gudmundur S. Bodvarsson; ''Geothermal Geophysical Research in Electrical Methods at UURI'' by Philip E. Wannamaker; ''Optimizing Reinjection Strategy at Palinpinon, Philippines Based on Chloride Data'' by Roland N. Horne; ''TETRAD Reservoir Simulation'' by G. Michael Shook

Renner, Joel L.; Bodvarsson, Gudmundur S.; Wannamaker, Philip E.; Horne, Roland N.; Shook, G. Michael

1992-01-01

344

Potential mammalian filovirus reservoirs  

E-print Network

Ebola and Marburg viruses are maintained in unknown reservoir species; spillover into human populations results in occasional human cases or epidemics. We attempted to narrow the list of possibilities regarding the identity of those reservoir... known since 1967, when Marburg virus caused an outbreak of hem- orrhagic disease associated with exposure to primates imported into Germany; Marburg and Ebola viruses were subsequently the cause of isolated cases or epidemics of hemorrhagic fever...

Peterson, A. Townsend; Carroll, Darin S.; Mills, James N.; Johnson, Karl M.

2004-12-01

345

Microseismic monitoring: a tool for reservoir characterization.  

NASA Astrophysics Data System (ADS)

Characterization of fluid-transport properties of rocks is one of the most important, yet one of most challenging goals of reservoir geophysics. There are some fundamental difficulties related to using active seismic methods for estimating fluid mobility. However, it would be very attractive to have a possibility of exploring hydraulic properties of rocks using seismic methods because of their large penetration range and their high resolution. Microseismic monitoring of borehole fluid injections is exactly the tool to provide us with such a possibility. Stimulation of rocks by fluid injections belong to a standard development practice of hydrocarbon and geothermal reservoirs. Production of shale gas and of heavy oil, CO2 sequestrations, enhanced recovery of oil and of geothermal energy are branches that require broad applications of this technology. The fact that fluid injection causes seismicity has been well-established for several decades. Observations and data analyzes show that seismicity is triggered by different processes ranging from linear pore pressure diffusion to non-linear fluid impact onto rocks leading to their hydraulic fracturing and strong changes of their structure and permeability. Understanding and monitoring of fluid-induced seismicity is necessary for hydraulic characterization of reservoirs, for assessments of reservoir stimulation and for controlling related seismic hazard. This presentation provides an overview of several theoretical, numerical, laboratory and field studies of fluid-induced microseismicity, and it gives an introduction into the principles of seismicity-based reservoir characterization.

Shapiro, S. A.

2011-12-01

346

Seismic Imaging of Reservoir Structure at The Geysers Geothermal Reservoir  

NASA Astrophysics Data System (ADS)

Three-dimensional Vp/Vs-ratio structure is presented for The Geysers geothermal field using seismic travel-time data. The data were recorded by the Lawrence Berkeley National Laboratory (LBNL) using a 34-station seismic network. The results are based on 32,000 events recorded in 2011 and represent the highest resolution seismic imaging campaign at The Geysers to date. The results indicate low Vp/Vs-ratios in the central section of The Geysers within and below the current reservoir. The extent of the Vp/Vs anomaly deceases with increasing depth. Spatial correlation with micro-seismicity, used as a proxy for subsurface water flow, indicates the following. Swarms of seismicity correlate well with areas of high and intermediate Vp/Vs estimates, while regions of low Vp/Vs estimates appear almost aseismic. This result supports past observations that high and low Vp/Vs-ratios are related to water and gas saturated zones, respectively. In addition, the correlation of seismicity to intermediate Vp/Vs-ratios is supportive of the fact that the process of water flashing to steam requires four times more energy than the initial heating of the injected water to the flashing point. Because this energy is dawn from the reservoir rock, the associated cooling of the rock generates more contraction and thus seismic events than water being heated towards the flashing point. The consequences are the presence of some events in regions saturated with water, most events in regions of water flashing to steam (low steam saturation) and the absence of seismicity in regions of high steam concentrations where the water has already been converted to steam. Furthermore, it is observed that Vp/Vs is inversely correlated to Vs but uncorrelated to Vp, leading support to laboratory measurements on rock samples from The Geysers that observe an increase in shear modulus while the core samples are dried out. As a consequence, traditional poroelastic theory is no applicable at The Geysers geothermal reservoir. We also conduct time-lapse seismic imaging to investigate the occurrence of temporal changes in the reservoir.

Gritto, R.; Yoo, S.; Jarpe, S.

2013-12-01

347

Use of Cutting-Edge Horizontal and Underbalanced Drilling Technologies and Subsurface Seismic Techniques to Explore, Drill and Produce Reservoired Oil and Gas from the Fractured Monterey Below 10,000 ft in the Santa Maria Basin of California  

SciTech Connect

This project was undertaken to demonstrate that oil and gas can be drilled and produced safely and economically from a fractured Monterey reservoir in the Santa Maria Basin of California by employing horizontal wellbores and underbalanced drilling technologies. Two vertical wells were previously drilled in this area with heavy mud and conventional completions; neither was commercially productive. A new well was drilled by the project team in 2004 with the objective of accessing an extended length of oil-bearing, high-resistivity Monterey shale via a horizontal wellbore, while implementing managed-pressure drilling (MPD) techniques to avoid formation damage. Initial project meetings were conducted in October 2003. The team confirmed that the demonstration well would be completed open-hole to minimize productivity impairment. Following an overview of the geologic setting and local field experience, critical aspects of the application were identified. At the pre-spud meeting in January 2004, the final well design was confirmed and the well programming/service company requirements assigned. Various design elements were reduced in scope due to significant budgetary constraints. Major alterations to the original plan included: (1) a VSP seismic survey was delayed to a later phase; (2) a new (larger) surface hole would be drilled rather than re-enter an existing well; (3) a 7-in. liner would be placed into the top of the Monterey target as quickly as possible to avoid problems with hole stability; (4) evaluation activities were reduced in scope; (5) geosteering observations for fracture access would be deduced from penetration rate, cuttings description and hydrocarbon in-flow; and (6) rather than use nitrogen, a novel air-injection MPD system was to be implemented. Drilling operations, delayed from the original schedule by capital constraints and lack of rig availability, were conducted from September 12 to November 11, 2004. The vertical and upper curved sections were drilled and lined through the problematic shale member without major stability problems. The top of the targeted Monterey was thought to be seen at the expected TVD of 10,000 ft where the 7-in. liner was set at a 60{sup o} hole angle. Significant oil and gas shows suggested the fractured interval anticipated at the heel location had been penetrated. A total of 2572 ft of 6{Delta}-in. near-horizontal interval was placed in the shale section, extending planned well length by approximately 470 ft. Very little hydrocarbon in-flow was observed from fractures along the productive interval. This may be a result of the well trajectory falling underneath the Monterey fractured zone. Hydrocarbon observations, cuttings analysis and gamma-ray response indicated additional fractured intervals were accessed along the last {+-}900 ft of well length. The well was completed with a 2 and 7/8-in. tubing string set in a production packer in preparation for flow and swab tests to be conducted later by a service rig. The planned well time was estimated as 39 days and overall cost as $2.4 million. The actual results are 66 days at a total cost of $3.4 million. Well productivity responses during subsequent flow and swabbing tests were negative. The well failed to inflow and only minor amounts (a few barrels) of light oil were recovered. The lack of production may suggest that actual sustainable reservoir pressure is far less than anticipated. Temblor attempted in July, 2006, to re-enter and clean out the well and run an Array Induction log (primarily for resistivity and correlation purposes), and an FMI log (for fracture detection). Application of surfactant in the length of the horizontal hole, and acid over the fracture zone at 10,236 was also planned. This attempt was not successful in that the clean out tools became stuck and had to be abandoned.

George Witter; Robert Knoll; William Rehm; Thomas Williams

2006-06-30

348

USE OF CUTTING-EDGE HORIZONTAL AND UNDERBALANCED DRILLING TECHNOLOGIES AND SUBSURFACE SEISMIC TECHNIQUES TO EXPLORE, DRILL AND PRODUCE RESERVOIRED OIL AND GAS FROM THE FRACTURED MONTEREY BELOW 10,000 FT IN THE SANTA MARIA BASIN OF CALIFORNIA  

SciTech Connect

This project was undertaken to demonstrate that oil and gas can be drilled and produced safely and economically from a fractured Monterey reservoir in the Santa Maria Basin of California by employing horizontal wellbores and underbalanced drilling technologies. Two vertical wells were previously drilled in this area by Temblor Petroleum with heavy mud and conventional completions; neither was commercially productive. A new well was drilled by the project team in 2004 with the objective of accessing an extended length of oil-bearing, high-resistivity Monterey shale via a horizontal wellbore, while implementing managed-pressure drilling (MPD) techniques to avoid formation damage. Initial project meetings were conducted in October 2003. The team confirmed that the demonstration well would be completed open-hole to minimize productivity impairment. Following an overview of the geologic setting and local field experience, critical aspects of the application were identified. At the pre-spud meeting in January 2004, the final well design was confirmed and the well programming/service company requirements assigned. Various design elements were reduced in scope due to significant budgetary constraints. Major alterations to the original plan included: (1) a VSP seismic survey was delayed to a later phase; (2) a new (larger) surface hole would be drilled rather than re-enter an existing well; (3) a 7-in. liner would be placed into the top of the Monterey target as quickly as possible to avoid problems with hole stability; (4) evaluation activities were reduced in scope; (5) geosteering observations for fracture access would be deduced from penetration rate, cuttings description and hydrocarbon in-flow; and (6) rather than use nitrogen, a novel air-injection MPD system was to be implemented. Drilling operations, delayed from the original schedule by capital constraints and lack of rig availability, were conducted from September 12 to November 11, 2004. The vertical and upper curved sections were drilled and lined through the problematic shale member without major stability problems. The top of the targeted Monterey was thought to be seen at the expected TVD of 10,000 ft where the 7-in. liner was set at a 60{sup o} hole angle. Significant oil and gas shows suggested the fractured interval anticipated at the heel location had been penetrated. A total of 2572 ft of 6.-in. near-horizontal interval was placed in the shale section, extending planned well length by approximately 470 ft. Very little hydrocarbon in-flow was observed from fractures along the productive interval. This may be a result of the well trajectory falling underneath the Monterey fractured zone. Hydrocarbon observations, cuttings analysis and gamma-ray response indicated additional fractured intervals were accessed along the last {+-}900 ft of well length. The well was completed with a 2 7/8-in. tubing string set in a production packer in preparation for flow and swab tests to be conducted later by a service rig. The planned well time was estimated as 39 days and overall cost as $2.4 million. The actual results are 66 days at a total cost of $3.4 million. Well productivity responses during subsequent flow and swabbing tests were negative. The well failed to inflow and only minor amounts (a few barrels) of light oil were recovered. The lack of production may suggest that actual sustainable reservoir pressure is far less than anticipated. Temblor is currently investigating the costs and operational viability of re-entering the well and conducting an FMI (fracture detection) log and/or an acid stimulation. No final decision or detailed plans have been made regarding these potential interventions at this time.

George Witter; Robert Knoll; William Rehm; Thomas Williams

2005-02-01

349

Use of Cutting-Edge Horizontal and Underbalanced Drilling Technologies and Subsurface Seismic Techniques to Explore, Drill and Produce Reservoired Oil and Gas from the Fractured Monterey Below 10,000 ft in the Santa Maria Basin of California  

SciTech Connect

This project was undertaken to demonstrate that oil and gas can be drilled and produced safely and economically from a fractured Monterey reservoir in the Santa Maria Basin of California by employing horizontal wellbores and underbalanced drilling technologies. Two vertical wells were previously drilled in this area with heavy mud and conventional completions; neither was commercially productive. A new well was drilled by the project team in 2004 with the objective of accessing an extended length of oil-bearing, high-resistivity Monterey shale via a horizontal wellbore, while implementing managed-pressure drilling (MPD) techniques to avoid formation damage. Initial project meetings were conducted in October 2003. The team confirmed that the demonstration well would be completed open-hole to minimize productivity impairment. Following an overview of the geologic setting and local field experience, critical aspects of the application were identified. At the pre-spud meeting in January 2004, the final well design was confirmed and the well programming/service company requirements assigned. Various design elements were reduced in scope due to significant budgetary constraints. Major alterations to the original plan included: (1) a VSP seismic survey was delayed to a later phase; (2) a new (larger) surface hole would be drilled rather than re-enter an existing well; (3) a 7-in. liner would be placed into the top of the Monterey target as quickly as possible to avoid problems with hole stability; (4) evaluation activities were reduced in scope; (5) geosteering observations for fracture access would be deduced from penetration rate, cuttings description and hydrocarbon in-flow; and (6) rather than use nitrogen, a novel air-injection MPD system was to be implemented. Drilling operations, delayed from the original schedule by capital constraints and lack of rig availability, were conducted from September 12 to November 11, 2004. The vertical and upper curved sections were drilled and lined through the problematic shale member without major stability problems. The top of the targeted Monterey was thought to be seen at the expected TVD of 10,000 ft where the 7-in. liner was set at a 60{sup o} hole angle. Significant oil and gas shows suggested the fractured interval anticipated at the heel location had been penetrated. A total of 2572 ft of 6 1/8-in. near-horizontal interval was placed in the shale section, extending planned well length by approximately 470 ft. Very little hydrocarbon in-flow was observed from fractures along the productive interval. This may be a result of the well trajectory falling underneath the Monterey fractured zone. Hydrocarbon observations, cuttings analysis and gamma-ray response indicated additional fractured intervals were accessed along the last {+-}900 ft of well length. The well was completed with a 2 7/8-in. tubing string set in a production packer in preparation for flow and swab tests to be conducted later by a service rig. The planned well time was estimated as 39 days and overall cost as $2.4 million. The actual results are 66 days at a total cost of $3.4 million. Well productivity responses during subsequent flow and swabbing tests were negative. The well failed to inflow and only minor amounts (a few barrels) of light oil were recovered. The lack of production may suggest that actual sustainable reservoir pressure is far less than anticipated. Temblor is currently planning to re-enter and clean out the well and run an Array Induction log (primarily for resistivity and correlation purposes), and an FMI log (for fracture detection). Depending on the results of these logs, an acidizing or re-drill program will be planned.

George Witter; Robert Knoll; William Rehm; Thomas Williams

2005-09-29

350

Gas Hydrates: It's A Gas!  

NSDL National Science Digital Library

In this activity, students will investigate the occurrence of gas hydrates on the ocean floor. They will discover the importance of carbon, where carbon is stored on Earth, and that the largest reservoir of carbon is gas hydrates. Students will discover that Earth's climate changes, and how the greenhouse effect works. They will also learn about the potential of hydrates as a major new energy resource and explore the conditions under which hydrates form.

351

Optoelectronic Reservoir Computing  

PubMed Central

Reservoir computing is a recently introduced, highly efficient bio-inspired approach for processing time dependent data. The basic scheme of reservoir computing consists of a non linear recurrent dynamical system coupled to a single input layer and a single output layer. Within these constraints many implementations are possible. Here we report an optoelectronic implementation of reservoir computing based on a recently proposed architecture consisting of a single non linear node and a delay line. Our implementation is sufficiently fast for real time information processing. We illustrate its performance on tasks of practical importance such as nonlinear channel equalization and speech recognition, and obtain results comparable to state of the art digital implementations. PMID:22371825

Paquot, Y.; Duport, F.; Smerieri, A.; Dambre, J.; Schrauwen, B.; Haelterman, M.; Massar, S.

2012-01-01

352

Optoelectronic reservoir computing.  

PubMed

Reservoir computing is a recently introduced, highly efficient bio-inspired approach for processing time dependent data. The basic scheme of reservoir computing consists of a non linear recurrent dynamical system coupled to a single input layer and a single output layer. Within these constraints many implementations are possible. Here we report an optoelectronic implementation of reservoir computing based on a recently proposed architecture consisting of a single non linear node and a delay line. Our implementation is sufficiently fast for real time information processing. We illustrate its performance on tasks of practical importance such as nonlinear channel equalization and speech recognition, and obtain results comparable to state of the art digital implementations. PMID:22371825

Paquot, Y; Duport, F; Smerieri, A; Dambre, J; Schrauwen, B; Haelterman, M; Massar, S

2012-01-01

353

Simulation of paraffin damage due to natural cooling in reservoirs  

E-print Network

and phases at reservoir conditions Fig. 4 - Solid-liquid phase equilibrium Fig. 5 - Paraffin plugging pore spaces 12 15 Fig. 6 - Simulated oil rates for a well in a reservoir without gas . . . . . . . . . Fig. 7 - Paraffin deposition profile... at pressures and teinperatures below the cloud point of the fluid. The cloud point is defined as the equilibrium teinperature and pressure at which solid paraffin crystals begin to form in the liquid phase. This thesis follows the style of the Journal...

Peddibhotla, Sriram

2012-06-07

354

A generalized compositional model for naturally fractured reservoirs  

SciTech Connect

This paper presents the formulation of a generalized dual-porosity compositional reservoir model. The model uses the implicit-pressure, explicit-saturation (IMPES) method, with semi-implicit treatment of wells, and the Newton-Raphson iteration method to solve the dual-porosity flow equations. The model was used to study the depletion performance of dual-porosity volatile-oil and gas-condensate reservoirs.

Peng, C.P.; Yanosik, J.L.; Stephenson, R.E. (Amoco Production Co. (US))

1990-05-01

355

Appalachian Basin Low-Permeability Sandstone Reservoir Characterizations  

SciTech Connect

A preliminary assessment of Appalachian basin natural gas reservoirs designated as 'tight sands' by the Federal Energy Regulatory Commission (FERC) suggests that greater than 90% of the 'tight sand' resource occurs within two groups of genetically-related units; (1) the Lower Silurian Medina interval, and (2) the Upper Devonian-Lower Mississippian Acadian clastic wedge. These intervals were targeted for detailed study with the goal of producing geologic reservoir characterization data sets compatible with the Tight Gas Analysis System (TGAS: ICF Resources, Inc.) reservoir simulator. The first phase of the study, completed in September, 1991, addressed the Medina reservoirs. The second phase, concerned with the Acadian clastic wedge, was completed in October, 1992. This report is a combined and updated version of the reports submitted in association with those efforts. The Medina interval consists of numerous interfingering fluvial/deltaic sandstones that produce oil and natural gas along an arcuate belt that stretches from eastern Kentucky to western New York. Geophysical well logs from 433 wells were examined in order to determine the geologic characteristics of six separate reservoir-bearing intervals. The Acadian clastic wedge is a thick, highly-lenticular package of interfingering fluvial-deltaic sandstones, siltstones, and shales. Geologic analyses of more than 800 wells resulted in a geologic/engineering characterization of seven separate stratigraphic intervals. For both study areas, well log and other data were analyzed to determine regional reservoir distribution, reservoir thickness, lithology, porosity, water saturation, pressure and temperature. These data were mapped, evaluated, and compiled into various TGAS data sets that reflect estimates of original gas-in-place, remaining reserves, and 'tight' reserves. The maps and data produced represent the first basin-wide geologic characterization for either interval. This report outlines the methods and assumptions used in creating the TGAS data input, and provides basic geologic perspective on the gas-bearing sandstones of the Medina interval and the Acadian clastic wedge.

Ray Boswell; Susan Pool; Skip Pratt; David Matchen

1993-04-30

356

Naturally fractured tight gas reservoir detection optimization  

SciTech Connect

The focus of this report was on preparing data and modules for Piceance Basin-wide fracture prediction. A review of the geological data input and automated history reconstruction approach was made. Fluid pressure data analysis and preliminary basin simulations were carried out. These activities are summarized briefly below and reviewed in more detail in Appendices A-E. Appendix D is a review of the fluid pressure data and its implications for compartmentation. Preliminary fracture prediction computations on generic basins are presented in Appendix E; these were carried out as part of our code testing activities. The results of these two Appendices are the beginning of what will be the basis of the model testing; fluid pressures are directly comparable with the model predictions and are a key element of fracture nucleation and presentation. We summarize the tectonic and sedimentary history of the Piceance Basin based on our automated history reconstruction and published interpretations. The narrative and figures provide the basic material we have quantified for our CIRF.B basin simulator input. This data supplements our existing well data interpretation approach. It provides an independent check of the automated sedimentary/subsidence history reconstruction module. Fluid pressure data was gathered and analyzed. This data serves two functions. Fluid pressure distribution across the basin provides a quantitative test as it is a direct prediction of CIRF.B. Furthermore, fluid pressure modifies effective stress. It thereby enters fracture nucleation criteria and fracture extension rate and aperture laws. The pressure data is presented in Appendix Din terms of overpressure maps and isosurfaces.

NONE

1996-09-30

357

Naturally fractured tight gas reservoir detection optimization  

SciTech Connect

The previous report provided a detailed summary of the work data on the project at the Rulison field. Key to this report was the finding that the regions where wells showed good EURs were spatially associated with faulting. Specifically, areas considered more permeable due to the presence of natural fractures are generally located in the high-side (footwall) of reverse faults. While this association seems to hold in the Rulison seismic data coverage, this association requires corroboration. Thus the work plan for the quarter of July 1, 1997--September 30, 1997 consisted of three tasks: (1) perform detailed fault mapping of Rulison 3-D seismic data with Barrett Resources; (2) review SOCO 2-D seismic fault mapping and structural interpretations; and (3) initial work into developing a predictive method for locating fault-related natural fractures. The first two tasks were initiated and completed during this reporting period. The work involved required at the collaborative effort between the field operators and ARI staff. The third task marks the beginning of quantitative fracture mechanics analysis of the geologic processes that are involved for the development of fault-related natural fractures. The goal of this work is to develop a predictive capability of locating natural fractures prior to drilling.

NONE

1998-02-06

358

Water Supplies and Reservoirs  

Microsoft Academic Search

HAVING observed in NATURE (p. 375) an article on the drought of past years, and the probability of one this year also, from deficient rainfall, I take the occasion of suggesting that the old reservoirs might still be made more available for an additional storage of water to counteract its effects. As there is always abundance of rainfall, 40 inches,

W. G. Black

1888-01-01

359

Reservoir sedimentation and flushing  

Microsoft Academic Search

This paper is concerned with the engineering assessment of the deposition and re-erosion of sediments in reservoirs. This deposition and re-erosion can be assessed by methods which vary in their complexity. Historically, simple empirical methods have been used which require only a limited amount of data and analysis. More recently, however, computer models have been developed which can simulate the

W. R. WHITE

1990-01-01

360

33 CFR 211.81 - Reservoir areas.  

Code of Federal Regulations, 2012 CFR

...Norfork Reservoir Area, Arkansas and Missouri. (n) Clark Hill Reservoir Area, Georgia and South Carolina. (o) Alatoona Reservoir Area, Georgia. (p) Center Hill Reservoir Area, Tennessee. (q) Dale Hollow...

2012-07-01

361

Pierre Y. Julien Reservoir Sedimentation  

E-print Network

Mississippi Dykes Cottage Bend 1995 1976 1984 3. Reservoir Sedimentation Solutions L&D No. 3 Locks and Dams1 Pierre Y. Julien Reservoir Sedimentation: Problems and Solutions Department of Civil Engineering Objectives Brief overview of Solutions to Reservoir Sedimentation Problems: 1. Upland Erosion Control; 2

Julien, Pierre Y.

362

A simulation method for the rapid screening of potential depleted oil reservoirs for CO 2 sequestration  

Microsoft Academic Search

The reduction of greenhouse gases emission is a growing concern of many industries. The oil and gas industry has a long commercial practice of gas injection, enhanced oil recovery (EOR) and gas storage. Using a depleted oil or gas reservoir for CO2 storage has several interesting advantages. The long-term risk analysis of the CO2 behavior and its impact on the

D. Bossie-Codreanu; Y. Le Gallo

2004-01-01

363

Seismic attribute analysis of unconventional reservoirs, and stratigraphic patterns  

NASA Astrophysics Data System (ADS)

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, and carbonates as well as igneous reservoir. This dissertation focuses on developing new workflows to map unconventional reservoirs in a qualitative or quantitative fashion using seismic attributes. The unconventional reservoirs under study include shales, carbonates and volcanic build-ups. A common challenge with many unconventional reservoirs is that they have low permeability, such that fractures are critical to economic success. I apply a different workflow measuring azimuthal anisotropy in the Barnett Shale of the Fort Worth Basin after hydraulic fracturing. The resulting anisotropy is not only heterogeneous, but compartmentalized by previous (Pennsylvanian) deformation. I also develop a workflow to correlate production with proximity of the well to curvature lineaments by scanning hypothesized open fractures as a function of azimuth. I calibrate this workflow to a previously studied Mississippian limestone reservoir from Kansas prior to application to the Woodford Shale of the Arkoma Basin. My final study is a volcanic extrusive reservoir from the Songliao Basin, Northeast China. Volcanic are usually avoided, while I hope that this example may serve as an analogue for others. As part of my analysis, I also document the extension of the previous workflow and development of new algorithm related to spectral-decomposition.

Zhang, Kui

364

Status of Blue Ridge 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 Blue Ridge 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 and data available, as well as interview with water resource professionals in various federal, state, and local agencies. Blue Ridge Reservoir is a single-purpose hydropower generating project. When consistent with this primary objective, the reservoir is also operated to benefit secondary objectives including water quality, recreation, fish and aquatic habitat, development of shoreline, aesthetic quality, and other public and private uses that support overall regional economic growth and development. 8 refs., 1 fig.

Not Available

1990-09-01

365

NMR properties of petroleum reservoir fluids.  

PubMed

NMR well logging of petroleum reservoir require the measurement of the NMR response of water, oil, and gas in the pore space of rocks at elevated temperatures and pressures. The viscosity of the oil may range from less than 1 cp to greater than 10,000 cp. Also, the oil and gas are not a single component but rather a broad distribution of components. The log mean T1 and T2 relaxation time of dead (gas free) crude oils are correlated with viscosity/temperature and Larmor frequency. The relaxation time of live oils deviate from the correlation for dead crude oils. This deviation can be correlated with the methane content of the oil. Natural gas in the reservoir has components other than methane. Mixing rules are developed to accommodate components such as ethane, propane, carbon dioxide, and nitrogen. Interpretation of NMR logs uses both relaxation and diffusion to distinguish the different fluids present in the formation. Crude oils have a broad spectrum of components but the relaxation time distribution and diffusion coefficient distribution are correlated. This correlation is used to distinguish crude oil from the response of water in the pores of the rock. This correlation can also be used to estimate viscosity of the crude oil. PMID:12850718

Hirasaki, George J; Lo, Sho-Wei; Zhang, Ying

2003-01-01

366

Reviving Abandoned Reservoirs with High-Pressure Air Injection: Application in a Fractured and Karsted Dolomite Reservoir  

SciTech Connect

Despite declining production rates, existing reservoirs in the United States contain vast volumes of remaining oil that is not being effectively recovered. This oil resource constitutes a huge target for the development and application of modern, cost-effective technologies for producing oil. Chief among the barriers to the recovery of this oil are the high costs of designing and implementing conventional advanced recovery technologies in these mature, in many cases pressure-depleted, reservoirs. An additional, increasingly significant barrier is the lack of vital technical expertise necessary for the application of these technologies. This lack of expertise is especially notable among the small operators and independents that operate many of these mature, yet oil-rich, reservoirs. We addressed these barriers to more effective oil recovery by developing, testing, applying, and documenting an innovative technology that can be used by even the smallest operator to significantly increase the flow of oil from mature U.S. reservoirs. The Bureau of Economic Geology and Goldrus Producing Company assembled a multidisciplinary team of geoscientists and engineers to evaluate the applicability of high-pressure air injection (HPAI) in revitalizing a nearly abandoned carbonate reservoir in the Permian Basin of West Texas. The Permian Basin, the largest oil-bearing basin in North America, contains more than 70 billion barrels of remaining oil in place and is an ideal venue to validate this technology. We have demonstrated the potential of HPAI for oil-recovery improvement in preliminary laboratory tests and a reservoir pilot project. To more completely test the technology, this project emphasized detailed characterization of reservoir properties, which were integrated to access the effectiveness and economics of HPAI. The characterization phase of the project utilized geoscientists and petroleum engineers from the Bureau of Economic Geology and the Department of Petroleum Engineering (both at The University of Texas at Austin) to define the controls on fluid flow in the reservoir as a basis for developing a reservoir model. The successful development of HPAI technology has tremendous potential for increasing the flow of oil from deep carbonate reservoirs in the Permian Basin, a target resource that can be conservatively estimated at more than 1.5 billion barrels. Successful implementation in the field chosen for demonstration, for example, could result in the recovery of more than 34 million barrels of oil that will not otherwise be produced. Geological and petrophysical analysis of available data at Barnhart field reveals the following important observations: (1) the Barnhart Ellenburger reservoir is similar to most other Ellenburger reservoirs in terms of depositional facies, diagenesis, and petrophysical attributes; (2) the reservoir is characterized by low to moderate matrix porosity much like most other Ellenburger reservoirs in the Permian Basin; (3) karst processes (cave formation, infill, and collapse) have substantially altered stratigraphic architecture and reservoir properties; (4) porosity and permeability increase with depth and may be associated with the degree of karst-related diagenesis; (5) tectonic fractures overprint the reservoir, improving overall connectivity; (6) oil-saturation profiles show that the oil-water contact (OWC) is as much as 125 ft lower than previous estimations; (7) production history and trends suggest that this reservoir is very similar to other solution-gas-drive reservoirs in the Permian Basin; and (8) reservoir simulation study showed that the Barnhart reservoir is a good candidate for HPAI and that application of horizontal-well technology can improve ultimate resource recovery from the reservoir.

Robert Loucks; Stephen C. Ruppel; Dembla Dhiraj; Julia Gale; Jon Holder; Jeff Kane; Jon Olson; John A. Jackson; Katherine G. Jackson

2006-09-30

367

Program calculates pseudoskin in a multilayer reservoir  

SciTech Connect

Often, a well is completed in only a limited number of the layers in a reservoir. For these wells it is important to calculate the pseudoskin under partial penetration. A simple, easy-to-use Fortran program calculates pseudoskin for a vertical well partially penetrating a multilayer reservoir under pseudosteady-state interlayer crossflow conditions. Expressions for pseudoskin are listed for conditions covering both closed top and bottom boundaries and the existence of either a gas cap or bottom water zone. The Fortran program is based on these simple expressions for pseudoskin. The program allows for any arbitrary number of layers in the well. The article also gives directions for obtaining a diskette of the computer code.

Ambastha, A.K. [Univ. of Alberta, Edmonton, Alberta (Canada); Gomes, E. [Bangladesh Univ. of Engineering and Technology, Dacca (Bangladesh)

1995-06-12

368

Geothermal reservoir simulation  

Microsoft Academic Search

The prediction of long-term geothermal reservoir performance and the environmental impact of exploiting this resource are two important problems associated with the utilization of geothermal energy for power production. Our research effort addresses these problems through numerical simulation. Computer codes based on the solution of partial-differential equations using finite-element techniques are being prepared to simulate multiphase energy transport, energy transport

J. W. Mercer Jr.; C. Faust; G. F. Pinder

1974-01-01

369

Hierarchical Bayesian reservoir memory  

Microsoft Academic Search

In a quest for modeling human brain, we are going to introduce a brain model based on a general framework for brain called Memory-Prediction Framework. The model is a hierarchical Bayesian structure that uses Reservoir Computing methods as the state-of-the-art and the most biological plausible Temporal Sequence Processing method for online and unsupervised learning. So, the model is called Hierarchical

Ali Nouri; Hooman Nikmehr

2009-01-01

370

Completion methods in thick, multilayered tight gas sands  

E-print Network

Tight gas sands, coal-bed methane, and gas shales are commonly called unconventional reservoirs. Tight gas sands (TGS) are often described as formations with an expected average permeability of 0.1mD or less. Gas production rates from TGS reservoirs...

Ogueri, Obinna Stavely

2009-05-15

371

Completion methods in thick, multilayered tight gas sands  

E-print Network

Tight gas sands, coal-bed methane, and gas shales are commonly called unconventional reservoirs. Tight gas sands (TGS) are often described as formations with an expected average permeability of 0.1mD or less. Gas production rates from TGS reservoirs...

Ogueri, Obinna Stavely

2008-10-10

372

Major influences of clastic reservoir anatomy on oil recovery  

SciTech Connect

Even in simple layer cake reservoirs, contrasting strata, pinchouts, and impermeable intercalations commonly impair vertical sweep efficiency. However, extensive impermeable streaks may prevent coning of water or gas. For many reservoir configurations, certain features can be either favorable or unfavorable for oil recovery depending on accumulation conditions, mobility ratio, structural dip magnitude and orientation, and applied drainage and injection schemes. Although this complicates relating classification systems of recovery efficiency directly to geological aspects, clastic reservoirs commonly display predictable production behavior closely related to environment of deposition. For example, fluid flow in deltaic reservoirs composed of sand bodies with contrasting permeabilities is dominated by pathways of least resistivity. These occur in typical patterns related to paleogeographical trends. The threat of local cusping, coning, and breakthrough of water or gas dictates careful planning of locations, completions and production levels of individual wells. Extreme anisotropy is often associated with low net-to-gross [open quotes]labyrinth[close quotes] reservoirs deposited in coastal plain environments. Overall connectivity may be attained at net-to-gross levels of between 0.3 and 0.4, but major vertical and lateral discontinuities will exist on a well-to-well scale. Sweep efficiency is strongly influenced by sand body trends relative to dip orientation, and specific well patterns are required. Reservoir simulation input should preserve reservoir architecture and correctly incorporate no-flow boundaries and intercalations. Probabilistic modeling systems using representative sand-body geometry databases can provide estimate of connectivity and simulation input at an early stage of field development. The crux of the matter is the prediction of production behavior for alternative development plans to reduce the negative influences of reservoir heterogeneity.

Weber, K.J. (Technical Univ. Delft, The Hague (Netherlands))

1993-09-01

373

Extreme organic carbon burial fuels intense methane bubbling in a temperate reservoir  

E-print Network

strata, fuelling methanogenesis and gas bubble emission (ebullition) of CH4 from the sediment. Damming for reservoirs, since they have been estimated to bury more OC in their sediments than the entire ocean [Tranvik Wohlen, a small hydroelectric reservoir in Switzer- land, allowing us to relate sediment properties

Wehrli, Bernhard

374

URTeC 1620617 Thermal Shock in Reservoir Rock Enhances the Hydraulic  

E-print Network

URTeC 1620617 Thermal Shock in Reservoir Rock Enhances the Hydraulic Fracturing of Gas Shales Saeid through strain and stress. As the temperature diffuses from hydraulic fracture into reservoir the rock matrix beyond hydraulic fracturing stimulation by cooling down the rock. The physics

Patzek, Tadeusz W.

375

Mineral transformations in siliceous mudstones and implications for shale reservoir properties: the Miocene Monterey Formation,  

E-print Network

Mineral transformations in siliceous mudstones and implications for shale reservoir properties-grained organic carbon-rich sediments are increasingly being targeted as shale gas and light oil "reservoirs mineral transformations and related pore-structure changes across a gradient from opal-A to quartz

Henderson, Gideon

376

Fluvial architecture and reservoir compartmentalization in the Oligocene middle Frio Formation of south Texas  

SciTech Connect

Seeligson, Stratton, and Agua Dulce fields are being studied as part of a Gas Research Institute/Department of Energy/State of Texas cosponsored program designed to develop and test methodologies and technologies for gas reserve growth in conventional reservoirs in mature gas fields. Over the last four decades, each field has produced approximately 2 tcf of gas from middle Frio reservoirs alone. Recent drilling and workover results and reservoir pressure data, however, point to the possibility of additional reserves. Stratigraphic and sedimentologic studies based on well logs and cores indicate that middle Frio reservoirs are architecturally complex. Deposition on an aggrading coastal plain resulted in a continuum of architectural styles that has important implications for reservoir compartmentalization. The middle Frio is composed of sand-rich channel-fill and splay deposits interstratified with floodplain mudstones, all forming part of the Gueydan fluvial system. Relatively slow aggradation resulted in laterally stacked channel systems; whereas more rapid aggradation resulted in vertically stacked channel systems. Laterally stacked sandstone bodies predominate at Seeligson field, leading to separate but potentially leaky reservoir compartments. By contrast, vertically stacked sandstone bodies predominate at Stratton and Agua Dulce fields, favoring more isolated reservoir compartments. Thus, a high potential for reserve growth through the identification of untapped compartments, poorly drained acreage, and bypassed zones exists for each of these fields, but differences in reservoir architecture must be taken into account as part of exploitation strategies.

Kerr, D.R.; Jirik, L.A. (Univ. of Texas, Austin (USA))

1990-09-01

377

Reliability programing in reservoir management: 3. System of multipurpose reservoirs  

NASA Astrophysics Data System (ADS)

A reliability programing technique, which includes the concept of `reliability or risk' in an optimization, is applied to multiple multipurpose reservoir systems. The procedure can be applied to any multipurpose multiunit reservoir system with two general types of linkage: normal channel flow for reservoir releases and pipelines or pumping canals. Thus each reservoir could be connected to every other reservoir, and each could receive releases from any or all other reservoirs as dictated by a particular system configuration. A two-level solution algorithm is proposed. A solution can be obtained for a reservoir system with few purposes (flood control, power production, irrigation, water supply, and water quality enhancement) and random inflows and demands. The random inflows and demands are represented by conditional distribution functions. The objective function of economic efficiency, representing the tradeoff between benefits and risks embodied by a risk-loss function, is included in the present approach. The reliability programing model is nonlinear and can be split into two models: search model and special linear programing model. The procedure is illustrated using a portion of the Red River system in Oklahoma and Texas, a system of three multipurpose reservoirs. The three reservoirs individually satisfy purposes (flood protection, hydroelectric power generation, water supply, and water quality enhancement), and two of the reservoirs work together to satisfy additional water requirements (flood control and water quality enhancement downstream). Input data necessary for solving the optimization model are presented. Results of the operation of the system, including optimal operating policies for the reservoirs and reliabilities of the operation, illustrate the major advantages of the reliability programing approach compared with other stochastic optimization techniques.

Simonovi?, Slobodan P.; Marino, Miguel A.

1982-08-01

378

Coupled Planetary Reservoirs  

NASA Astrophysics Data System (ADS)

We can look beyond the Earth, to Venus and Mars, to find opportunities to understand interactions among crust, mantle, hydrosphere, and atmosphere reservoirs. There has obviously been coupling among some of these reservoirs on other worlds, and in some cases feedback may have been in play but that is more difficult to demonstrate. The massive CO2 atmosphere of Venus has likely fluctuated significantly over its history due to exchange with other reservoirs, with attendant greenhouse effects strongly modulating surface temperature. Additionally, release of H2O and SO2 from large-scale magmatic events may have led to significant surface temperature increases, ?T0, and the details depend on the competition between IR radiation warming and planetary albedo increase due to cloud formation. Diffusion of ? T0 into the shallow crust may be responsible for the rapid global formation of compressional wrinkle ridges following widespread volcanic resurfacing [Solomon et al., 1999]. Diffusion of ?T0 into the venusian upper mantle could have increased the rate of partial melting. The accompanying increase in volatile release to the atmosphere could set up a positive feedback because of increased greenhouse warming diffusing into the planet's interior [Phillips et al., 2001, Venus]. Another outcome of deep penetration of a greenhouse-induced positive ?T0 is the lowering of mantle viscosity and an accompanying decrease in convective stress, which could shut down an exisiting lithospheric recycling regime [Lenardic et al., 2008]. Mars offers a rich set of possibilities for coupling between reservoirs [Jakosky and Phillips, 2001]. Magmatism at the massive Tharsis volcanic complex possibly induced episodic climate changes in the latter part of the Noachian era (~3.6-4.2 Ga). This could have led to clement conditions, forming valley networks that follow a regional slope caused partly by the mass load of Tharsis itself [Phillips et al., 2001, Mars]. Earlier in the Noachian, lithospheric recycling may have ended as surface temperatures warmed due to planetary outgassing, leading to the Lenardic catastrophe. Outer core convection may have been muted as the mantle heated up, shutting down the martian dynamo [Nimmo and Stevenson, 2000]. In turn, much of the extant atmosphere could have been lost to space, no longer protected from the solar wind by a global magnetic field.

Phillips, R. J.

2008-12-01

379

Reservoir computing for static pattern recognition  

Microsoft Academic Search

This paper introduces reservoir computing for static pattern recognition. Reservoir computing networks are neural networks with a sparsely connected recurrent hidden layer (or reservoir) of neurons. The weights from the inputs to the reservoir and the reservoir weights are ran- domly selected. The weights of the second layer are determined with a linear partial least squares solver. The outputs of

Mark J. Embrechts; A. Alexandre; Jonathan D. Linton

380

The Interfacial Interaction Problem in Complex Multiple Porosity Fractured Reservoirs  

Microsoft Academic Search

Many productive reservoirs (oil, gas, water, geothermal) are associated to natural fracturing. Fault zones and fractures act as open networks for fluid and energy flow from depth. Their petrophysical parameters are heterogeneous and randomly distributed, conforming extremely complex natural systems. Here, the simultaneous heat and mass flows are coupled to the deformation of thermoporoelastic rocks. The system's volume is divided

Mario-Cesar Suarez-Arriaga

2003-01-01

381

Oil recovery from naturally fractured reservoirs by steam injection methods  

SciTech Connect

The objective of this study is to develop accurate models for predicting oil recovery in naturally fractured reservoirs by steam injection. This objective is being met through an integrated experimental, numerical, and analytical study of the recovery mechanisms that control oil recovery for this process. These mechanisms include capillary imbibition, thermal expansion, gas generation from chemical reactions, and temperature-dependent thermal properties.

Reis, J.; Miller, M.

1991-01-01

382

JOHN W. SNEDDEN RESEARCH INTERESTS: Sequence Stratigraphy, sedimentology, reservoir development  

E-print Network

, Shale Gas, Light Tight Oil). CERTIFIED PETROLEUM GEOLOGIST #5279 AWARDS AND KEY PROFESSIONAL SOCIETY. 32, p. 497-514. Snedden, J.W., 1984, Validity of the use of the spontaneous potential curve shape, in Barwis, J.H., McPherson, J.G., and Studlick, J.R.J., eds., Sandstone Petroleum Reservoirs: Casebooks

Yang, Zong-Liang

383

Existence of an 16 Gaseous Reservoir in the Solar  

E-print Network

Existence of an 16 O-Rich Gaseous Reservoir in the Solar Nebula Alexander N. Krot,1 * Kevin D. Mc that CAIs and AOAs formed in a spatially restricted region of the solar nebula containing 16 O-rich gas the earliest stages of solar sys- tem evolution. Chondrites are made up of three major components: refractory

384

Coupled Modeling of Dynamic Reservoir/Well Interactions under Liquid-loading Conditions  

E-print Network

backpressure on the formation, which decreases the gas production rate and may stop the well from flowing. To model these phenomena, the dynamic interaction between the reservoir and the wellbore must be characterized. Due to wellbore phase re...

Limpasurat, Akkharachai

2013-10-23

385

Socioeconomic impact of infill drilling recovery from carbonate reservoirs in the Permian Basin, West Texas  

E-print Network

most from the infill drilling. The observations from this research are that most of the San Andres and Clearfork carbonate reservoir units in the Permian Basin are potentially profitable to infill drill. The incremental oil and gas production from...

Jagoe, Bryan Keith

2012-06-07

386

Multiscale Reservoir Simulation: Layer Design, Full Field Pseudoization and Near Well Modeling  

E-print Network

In the past decades, considerable effort has been put into developing high resolution geological models for oil and gas reservoirs. Although the growth of computational power is rapid, the static model size still exceeds the model size for routine...

Du, Song

2012-12-10

387

Modeling and Analysis of Reservoir Response to Stimulation by Water Injection  

E-print Network

The distributions of pore pressure and stresses around a fracture are of interest in conventional hydraulic fracturing operations, fracturing during water-flooding of petroleum reservoirs, shale gas, and injection/extraction operations in a...

Ge, Jun

2011-02-22

388

Practical natural gas engineering  

Microsoft Academic Search

According to the author, there is no fundamental difference between the behavior of wells producing liquids and the behavior of wells producing gas. This book bridges the gap between the results of empirical testing and the theory of unsteady-state flow in porous media. It strengthens the bond between conventional reservoir engineering practices and understanding gas well behavior. Problems are included

1983-01-01

389

Brine and gas recovery from geopressured systems  

Microsoft Academic Search

A series of parametric calculations was run with the geopressured - geothermal simulator MUSHRM to assess the effects of important formation, fluid and well parameters on brine and gas recovery from geopressured reservoir systems. The specific parameters considered are formation permeability, pore-fluid salinity, temperature and gas content, well radius and location with respect to reservoir boundaries, desired flow rate, and

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

1986-01-01

390

'A reservoir within a reservoir' - An unusual complication associated with a defunctioned inflatable penile prosthesis reservoir  

PubMed Central

INTRODUCTION Inflatable penile prostheses (IPP) have been a successful method of treating men with erectile dysfunction since the early 1970s. IPP are comprised of two intracorporal cylinders, a scrotal pump and a fluid reservoir. PRESENTATION OF CASE We present a case of a retained reservoir in a sixty eight year old gentlemen presenting with a cystic abdominal mass and bothersome LUTS, 15 years after the removal of the penile components of a three-piece penile prosthesis. Percutaneous drainage of the cyst was performed, with four litres of purulent fluid evacuated. A midline laparotomy was required to remove the reservoir and drain the collection completely. DISCUSSION Inflammatory reaction and subsequent erosion of an IPP reservoir is an infrequent but severe complication of IPP insertion, replacement or infection. Infection remains the primary indication for penile prosthesis removal and in this setting removal of the reservoir is routine. A thorough literature search has identified that in the non-infective setting, the routine removal of the original reservoir is not standard practice during three-component IPP replacement. In patients with a history of IPP presenting with new LUTS, reservoir erosion should be considered in the differential diagnosis and investigation with cystoscopy and computed tomography included early in the investigatory armament of the urologist. CONCLUSION It is our belief that a defunctionalized reservoir serves no purpose; rather it can only cause trouble in the future. Consequently, at our institution we do not leave defunctionalized reservoirs in situ. PMID:25247874

Abboudi, Hamid; Bolgeri, Marco; Nair, Rajesh; Chetwood, Andrew; Symes, Andrew; Thomas, Philip

2014-01-01

391

Over the past decade, the use of numerical reservoir simulation with high-speed electronic computers has gained wide acceptance throughout the  

E-print Network

PREFACE Over the past decade, the use of numerical reservoir simulation with high- speed electronic. For example, he may have a choice among several simulators that use different numerical methods. He may have of a wide variety of oil and gas reservoirs throughout the world. These reservoir simulators have been

Santos, Juan

392

Reservoir, seal, and source rock distribution in Essaouira Rift Basin  

SciTech Connect

The Essaouira onshore basin is an important hydrocarbon generating basin, which is situated in western Morocco. There are seven oil and gas-with-condensate fields; six are from Jurassic reservoirs and one from a Triassic reservoir. As a segment of the Atlantic passive continental margin, the Essaouira basin was subjected to several post-Hercynian basin deformation phases, which resulted in distribution, in space and time, of reservoir, seal, and source rock. These basin deformations are synsedimentary infilling of major half grabens with continental red buds and evaporite associated with the rifting phase, emplacement of a thick postrifting Jurassic and Cretaceous sedimentary wedge during thermal subsidence, salt movements, and structural deformations in relation to the Atlas mergence. The widely extending lower Oxfordian shales are the only Jurassic shale beds penetrated and recognized as potential and mature source rocks. However, facies analysis and mapping suggested the presence of untested source rocks in Dogger marine shales and Triassic to Liassic lacustrine shales. Rocks with adequate reservoir characteristics were encountered in Triassic/Liassic fluvial sands, upper Liassic dolomites, and upper Oxfordian sandy dolomites. The seals are provided by Liassic salt for the lower reservoirs and Middle to Upper Jurassic anhydrite for the upper reservoirs. Recent exploration studies demonstrate that many prospective structure reserves remain untested.

Ait Salem, A. (ONAREP, Rabat (Morocco))

1994-07-01

393

The research on borehole stability in depleted reservoir and caprock: using the geophysics logging data.  

PubMed

Long-term oil and gas exploitation in reservoir will lead to pore pressure depletion. The pore pressure depletion will result in changes of horizontal in-situ stresses both in reservoirs and caprock formations. Using the geophysics logging data, the magnitude and orientation changes of horizontal stresses in caprock and reservoir are studied. Furthermore, the borehole stability can be affected by in-situ stresses changes. To address this issue, the dehydration from caprock to reservoir and roof effect of caprock are performed. Based on that, the influence scope and magnitude of horizontal stresses reduction in caprock above the depleted reservoirs are estimated. The effects of development on borehole stability in both reservoir and caprock are studied step by step with the above geomechanical model. PMID:24228021

Yuan, Junliang; Deng, Jingen; Luo, Yong; Guo, Shisheng; Zhang, Haishan; Tan, Qiang; Zhao, Kai; Hu, Lianbo

2013-01-01

394

Fluid Flow Simulation in Fractured Reservoirs  

E-print Network

The purpose of this study is to analyze fluid flow in fractured reservoirs. In most petroleum reservoirs, particularly carbonate reservoirs and some tight sands, natural fractures play a critical role in controlling fluid ...

Sarkar, Sudipta

2002-01-01

395

Geothermal reservoir simulation on microcomputers  

Microsoft Academic Search

Reservoir simulation is an important tool in the development of a reservoir management plan. Historically, simulation studies have been performed exclusively by large companies and on mainframe computers. Recent advances in microcomputer designs have led to the development of simulators that run on smaller machines. This places and important design tool in the hands of smaller firms and consultant. This

D. D. Faulder; M. Shook

1991-01-01

396

Reservoir Sedimentation Management in Asia  

Microsoft Academic Search

In order to reduce and remove reservoir sedimentation for sustainable use, different sediment control measures have been developed and used in Asia. This paper is to review the reservoir sedimentation status in the Asian nations and also to describe the sedimentation management experience in China, India and Japan. The sedimentation control measures at the Dujiangyan, Three Gorge Project and Tianjiawan

Jian Liu; Bingyi Liu; Kazuo Ashida

397

Mathematical model for reservoir silting  

Microsoft Academic Search

The construction of a dam changes the natural equilibrium of a river: the flow velocity will be reduced and the sediment transported will be deposited in the reservoir. Estimation of the reservoir sedimentation rates and location of sediment is a complex task due to many interrelated factors, such as size and texture of the sediment particles, seasonal variations in river

P. R. J. COGOLLO; S. M. VILLELA

1988-01-01

398

Reservoir Modeling for Production Management  

SciTech Connect

For both petroleum and geothermal resources, many of the reservoirs are fracture dominated--rather than matrix-permeability controlled. For such reservoirs, a knowledge of the pressure-dependent permeability of the interconnected system of natural joints (i.e., pre-existing fractures) is critical to the efficient exploitation of the resource through proper pressure management. Our experience and that reported by others indicates that a reduction in the reservoir pressure sometimes leads to an overall reduction in production rate due to the ''pinching off'' of the joint network, rather than the anticipated increase in production rate. This effect occurs not just in the vicinity of the wellbore, where proppants are sometimes employed, but throughout much of the reservoir region. This follows