Gas Storage Reservoir Research Articles

3-D Seismic Improves Structural Mapping of a Gas Storage Reservoir (Paris Basin)

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

Carbon isotope study of gas migration in underground gas storage reservoirs, Czechoslovakia

Migration of gas can be a serious problem in underground gas storage reservoirs. Injected gas can migrate through the reservoir and mix with local gas deposits and/or leak out. Isotope analysis is an effective method of identifying the different gases in the reservoir and tracing them through the storage zone in time and space. This paper reports an application of combined chemical and isotope analysis to three underground storage reservoirs in Czechoslovakia. All reservoirs are depleted gas fields where injected gas is mixed with native gases. In theZˇukov reservoir and an adjacent field, an extensive migration of injected gas was proved. Two types of biogenic gases were located in the Dunajovice reservoir, where only a part of the storage has mixed with the injected gas. Vertical migration of injected gas in stratified storage zones occurred in the Hrusˇky reservoir. The method seems to be applicable generally to distinguish injected or stored gas from the locally produced (native) gas.

Stratigraphic Influence on Reservoir Rock Quality in the Mount Simon Gas Storage Reservoir, Pontiac Field, Illinois

Stratigraphic Influence on Reservoir Rock Quality in the Mount Simon Gas Storage Reservoir, Pontiac Field, Illinois

Identification ofP/S-wave successions for application in microseismicity

Interpretation ofP/S-wave successions is used in induced or passive microseismicity. It makes the location of microseismic events possible when the triangulation technique cannot be used. To improve the reliability of the method, we propose a technique that identifies theP/S-wave successions among recorded wave successions. A polarization software is used to verify the orthogonality between theP andS polarization axes. The polarization parameters are computed all along the 3-component acoustic signal. Then the algorithm detects time windows within which the signal polarization axis is perpendicular to the polarization axis of the wave in the reference time window (representative of theP wave). The technique is demonstrated for a synthetic event, and three application cases are presented. The first one corresponds to a calibration shot within which the arrivals of perpendicularly polarized waves are correctly detected in spite of their moderate amplitude. The second example presents a microseismic event recorded during gas withdrawal from an underground gas storage reservoir. The last example is chosen as a counter-example, concerning a microseismic event recorded during a hydraulic fracturing job. The detection algorithm reveals that, in this case, the wave succession does not correspond to aP/S one. This implies that such an event must not be located by the method based on the interpretation of aP/S-wave succession as no such a succession is confirmed.

Natural gas engineering: production and storage

Natural gas technology and earth sciences properties of rocks thermodynamics flow equation fluid properties combustion physical behaviour of natural gas systems physical and thermal properties phase behaviour analysis gas hydrates and their prevention applications of flow equations pressure drop compression metering drilling and completion of wells flow in reservoir and adjacent aquifer gas well testing reservoir engineering applied to gas gas/condesate and gas/oil fields simulation: field and reservoir performance conversion of depleted gas, gas condensate fields to gas storage reservoirs gas storage in aquifers monitoring inventory verification deliverability assurance and safety in storage operations natural gas liquid recovery gas treating and conditioning for the fuel market storage in salt cacities and mined caverns.

Observed Relation of Soil Magnetic Susceptibility and Soil Gas Hydrocarbon Analyses to Subsurface Hydrocarbon Accumulations (1)

Magnetic susceptibility (MS) studies on soils over 19 oil and gas fields showed anomalously large amounts of diagenetic magnetic minerals in shallow-depth samples in about 89% of the cases tested. Soil MS anomalies were compared with soil gas hydrocarbon (GHC) anomalies over 12 oil and gas fields (including several stratigraphic traps) and one gas storage reservoir. Samples were collected along the same profiles. Six examples are presented with detailed data listings. Our goal is to test the utility of soil magnetic susceptibility and soil gas hydrocarbons as petroleum prospecting methods. We emphasize statistical evaluation of anomalies and their empirical correlation with producing areas and leads identified by other geochemical, geological, or geophysical data. For direct comparison of anomaly strengths, data are expressed statistically in terms of the appropriate background mean and standard deviation. Soil MS and soil GHC data complement each other, providing better guidance to productive areas than either data set alone. When used in an integrated exploration program, their combined positive evidence of hydrocarbon presence under prospects could result in fewer dry holes than when drilling with structural information only.

The Rough Gas Storage Field, Blocks 47/3d, 47/8b, UK North Sea

Abstract The Rough Gas Field is operated by British Gas as the world's first offshore gas storage reservoir. This relatively small field (original reserves 366 BCF) is located on the western margin of the Southern North Sea Basin. The reservoir, the Rotliegendes Gp (Leman Sandstone Fm.) average thickness 95 ft, is developed in a basin-margin facies association in which aeolian and wadi-related fluvial processes have interacted. Small-scale dune and interdune sandstones, with generally excellent permeability, alternate with wadi facies sandstones with variable but mainly poorer permeability. The vertical distribution of these facies permits a three-fold zonation of the reservoir. Flow profiles obtained from Production Logging Tools show a very strong correspondence between sedimentary facies and productivity/injectivity. The Carboniferous subcrop includes several very low-permeability sandstone intervals which contact the Rotliegendes at the angular Base Rotliegendes unconformity. A small amount of gas from these sandstones seeps across the unconformity surface into the Rotliegendes. The Rough Field was discovered by Gulf in 1968, and was operated by Amoco on a conventional depletion basis with 6 development wells from 1975 until the early 1980s. In 1980 British Gas secured 100% ownership of the Field and its facilities, and converted it to storage mode. Excess summer supplies are injected into the reservoir, to be produced during the winter to meet the peak demand. Conversion to storage mode has necessitated the installation of substantial new facilities, and the drilling of 23 further wells. First injection of gas was achieved in 1985.

Practical Model for Predicting Pressure in Gas-Storage Reservoirs

Summary Optimal planning, design, and operation of gas fields in production or storage critically depends on reliable models for predicting pressures that are often based on sophisticated numerical and mathematical concepts. The pressure that prevails at a given time is a direct function of production/injection schedules, past history, and surface equipment as related to reserves and reservoir characteristics. Maintaining the pressure within prescribed limits is particularly important in underground storage to avoid pressures above a maximum for reasons of safety and migration and below a minimum for surface-equipment and contracted-deliverability considerations. This paper presents a new way to calculate the convolution integral on which the pressure variations depend. The classic methods were long and costly to run and seldom used. Our method, which identifies this convolution integral with a finite sum of exponential terms, is much quicker and has been implemented in a program called PREPRE, usable on microcomputers. Based on a production/pressure schedule, the model is capable of forecasting the evolution of pressures in main zones of interest, such as wellbores, gathering systems, and surface equipment. The data required for the model—past production/pressure history—are matched by a special algorithm that automatically calculates the main reservoir parameters used as bases for future projections. The quick and easy-to-run program is now in use at all engineering levels at Gaz de France.

Oil and Gas Developments in Western Canada in 1988

There were 7,849 wells drilled in western Canada during 1988. Total meterage drilled was 9,489,399 m, for an average well depth of 1,208 m. The total well count represents an increase of 15% from 1987; the average depth, however, dropped 1.6% from 1,228 m in 1987. The cased-hole success rate for exploratory wells was 55.8% on a per well basis and 53.6% on a meterage basis. Land expenditures fell dramatically in 1988. Total bonuses declined 17% to $658 million in 1988, while the volume of acreage rose 27.3% to 3.73 million ha. The average bid per hectare fell from $270.82 (FOOTNOTE 5) in 1987 to $176.50 in 1988. In Alberta, Cretaceous gas was discovered in the south and east, particularly in the Hector, Badger, Long Coulee, Jenner, and Sunnynook areas. Paleozoic gas was discovered in the overthrust Mississippian at Ram River, and in the Devonian in the Berland River and Kaybob areas. Oil was discovered in the Devonian Wabamun and the Triassic Halfway on the Peace River arch; in the Devonian Keg River off the northeast nose of the arch; and in the Keg River pinnacles of the Zama subbasin. Industry was chasing a deep play in the Twining area in 1988, but little information was available at press time. Industry was active in British Columbia during 1988. Shell made a significant discovery in the Triassic at Boulder (NTS 93-0), whereas Canadian Hunter continued its exploration of the extension of Elmworth field. Discoveries were made in the Mississippian Kiskatinaw, Triassic Montney and Halfway, and Devonian Slave Point formations in 1988. Interest in finding gas storage reservoirs and hydrocarbons on the Fraser delta continued as a 290-km seismic program was shot to delineate prospects. In addition, negotiations on ending the moratorium on offshore drilling continued between the federal and provincial governments. Manitoba had a 58% drop in drilling activity during 1988 to only 69 wells, and this resulted in only a 20% success rate. On the Northwest Territories mainland, 3 exploratory dry holes were drilled. In the Beaufort Sea, an exploratory well by Gulf at Amauligak West, 4 km west of the Amauligak structure, discovered oil which tested at rates of 1,050 m3/day. In Saskatchewan, Jurassic oil was discovered in the Wapella and Battle Creek areas, Createceous Viking oil was discovered on the Verendrye-Inglenook trend, and Devonian Winnipegosis oil was discovered at Macoun and Hitchcock. The shallow gas boom in southwest Saksatchewan continued in 1988 with 574 gas completions in the Burstall, Freefight, and Hatton areas, and 78 gas wells in the Bigstick and Crane Lake areas.

On Parameter Identification for Ordinary Differential Equations

The regularized solution of identification problems in ordinary differential equations is investigated when the data are noisy. For minimizing the occurring regularization functionals the gradient method and the Gauss-Newton method are examined by exploiting the concept of adjoint equations. An application to a particular inverse problem arising in the study of water movement about a gas-storage reservoir of aquifer type completes the paper.

Optimal Hydrocarbon Reservoir Production Policies

This paper describes a methodology for investigating optimal production polices for hydrocarbon reservoirs by an approach that brings together reservoir simulation models and numerical optimization techniques. It describes the results of applying this methodology to a dry gas storage reservoir using a single phase, two-dimensional reservoir simulator. The paper investigates optimal production strategies for several optimization criteria and potential constraints on reservoir operations, and discusses extensions to more complex systems.

Applications of Geochemistry to Production, Storage, and Use of Natural Gas: ABSTRACT

Geochemistry has become a standard tool in the exploration for oil and gas. Many of the concepts and techniques developed for exploration can be used with equal effectiveness in identifying environmental problems related to the production, storage, and use of natural gas. Contamination of shallow aquifers as a result of improperly completed gas or oil wells is a problem in some area. Similarly, gas which has migrated from underground gas-storage reservoirs also can contaminate shallow aquifers. Many shallow aquifers contain relatively high concentrations of microbially generated methane, and therefore detection of hydrocarbons is not sufficient to determine the source of the gas. Although microbial gas can frequently be distinguished from thermogenic gases by the absence of ethane and heavier hydrocarbons, migration through hundreds or thousands of feet of porous sediments can result in changes in the chemical composition of the gas, analogous to the changes that occur as gas passes through a chromatographic column. Therefore, the absence of heavier hy rocarbons is not always an indicator of source. Carbon isotopic composition of methane, however, appears to be relatively unaffected by migrational changes and can generally be used to distinguish between microbial and thermogenic methane. Questions also frequently arise as to the source of gas from gas and oil wells around the margins of gas-storage reservoirs. Although chemical analysis can sometimes be useful in distinguishing between storage gas and native gas, these gases are sometimes chemically quite similar. In the event that the gases cannot be distinguished chemically, determination of the carbon and/or the hydrogen isotopic composition of the methane may still provide positive identification. Gases generated in sanitary landfills or marshy areas sometimes can be interpreted as being the result of leakage from pipelines. In addition to the techniques already mentioned, radiocarbon dating of methane can be used to identify gases from these sources. End_of_Article - Last_Page 245------------

Method for dimensioning underground oil and gas storage reservoirs (in German) : Paraschkewow, R; Nikolaew, N In: Rock Mechanics: Caverns and Pressure Shafts (papers to the ISRM Symposium, Aachen, 26–28 May 1982)V2, P979–982. Publ Rotterdam: A. A. Balkema, 1982

Method for dimensioning underground oil and gas storage reservoirs (in German) : Paraschkewow, R; Nikolaew, N In: Rock Mechanics: Caverns and Pressure Shafts (papers to the ISRM Symposium, Aachen, 26–28 May 1982)V2, P979–982. Publ Rotterdam: A. A. Balkema, 1982

Identified Models for Gas Storage Dynamics

Abstract The classical approach to forecasting hydrocarbon reservoir behavior is through modeling. Traditional models are based on equations describing the physical behavior of the reservoir-plus-aquifer system; usually the parameters describing aquifer behavior are not known beforehand and are evaluated by a trial-and-error procedure based on the best fit of past reservoir performance. This approach leads to models that are intrinsically realistic, as they reflect the physical nature of the phenomena involved. A completely different approach, based on system theory techniques, is presented in this paper. This technique, called identification, consists of the determination of a mathematical model equivalent to the process under test, the word "equivalent" meaning that the process and the model show the same input/output behavior. As a consequence, an identified model of this type can be used to predict the response of an actual reservoir-plus-aquifer system to different inputs – i.e., to different production schedules. Case histories of the application of the identification technique to actual gas storage reservoirs are presented.

Stimulation of Gas Storage Fields To Restore Deliverability

Deliverability of a number of gas storage fields in the Michigan stray sandshas been decreasing steadily in recent years. This paper describes thedevelopment of a successful stimulation procedure through mathematicalmodeling, laboratory core flood experiments, and field observations. Theprocedure was applied to a number of wells in the Michigan stray sands andprocedure was applied to a number of wells in the Michigan stray sands andachieved deliverability increases of up to 426%. Introduction The deliverability of a number of gas storage wells in the Michigan straysands has been declining steadily over the years. In the Austin storage field, the loss of deliverability had averaged 4.8% per year for the last few years.One of the major reasons for this loss of deliverability is damage to theformation in the immediate vicinity of the wellbore. This damage can resultfrom a number of causes, such as salt precipitation, shale fillup, finesmigration, and oil precipitation, shale fillup, fines migration, and oilresidue. One method for increasing or restoring the productivity of oil and gassandstone reservoirs is productivity of oil and gas sandstone reservoirs ismatrix acidization. While acid stimulation has been extremely successful inincreasing or restoring the productivity of oil and gas producing reservoirs, it productivity of oil and gas producing reservoirs, it previously has not beenvery successful in stimulating previously has not been very successful instimulating the gas storage reservoirs of central Michigan. This paperdescribes the procedure and results for the paper describes the procedure andresults for the successful acid stimulation of wells in gas storage that havedeteriorated greatly. The Michigan stray sandstone formations are of the lateMississippian age and have a mineralogical composition of approximately 86%quartz, 3% feldspars, 4% chlorite, 2% kaolinite, 2% illite, 2% calcite, and 1%siderite and pyrite. Historically the stray sand reservoirs were completedopenhole and, depending on the era, some type of absolute open flow or gaugeflow during drilling-in was obtained. Upon conversion to the use of storage, along-term deterioration of flow potential was noted. This deterioration was notonly from the reported original potential but also from the more accuratepotential but also from the more accurate backpressure tests run earlier duringthe storage operation. The need for corrective procedures was apparent. Earlystimulation attempts for the stray sandstone were designed to increase porosityby solution of the silicates and calcite with HF and HCl, respectively. Theseattempts did not increase the deliverability significantly. A review of thetreatment reports and discussion with field engineers indicate that it wasdifficult to inject the acid and, when it was able to be injected, it wasfracturing into undesirable zones rather than flowing uniformly into theopenhole formation. Two conclusions from this earlier work were a relativelyhigh increase in cost per thousand cubic feet and a reaffirmation of thedifficulty of liquid injection into the Michigan stray sands. Theory During the past 5 years, significant advances have been made in modelingflow and reaction in porous media. JPT P. 1612

PETROLOGICAL AND PETROPHYSICAL STUDY OF PERMIAN ARENITES FOR POTENTIAL SUBSURFACE STORAGE OF NATURAL GAS, SYDNEY BASIN, NEW SOUTH WALES, AUSTRALIA

The expanding natural gas market in New South Wales during the next decades will require guaranteed back-up supplies in the event of insufficient deliverability through the Moomba-Sydney pipeline and/or cut-off of the pipeline. Subsurface storage of natural gas in natural reservoirs near the market area offers one solution for ensuring continuity of supply to this market.A petrological, wireline log, structural and reservoir-engineering study has been conducted of water-bearing arenites of the Permian Nowra Sandstone, Muree Sandstone and Snapper Point Formation in the Sydney Basin. This has resulted in the delineation of seven potential natural gas storage reservoirs near Sydney.The cap-rocks to the seven reservoirs are Permian impermeable arenites, siltstone, claystone and shale beds of the Berry Formation, Mulbring Siltstone, Wandrawandian Siltstone and Snapper Point Formation.Porosity in the Nowra and Muree Sandstone ranges from 5.5 to 12.2 percent and in the Snapper Point Formation from 5.4 to 6.8 per cent. Permeability is estimated to range from 0.47 to 5.00 millidarcies.The structures of these potential reservoirs include both faulted and unfaulted, gently folded anticlines, and an irregular dome. Their areal extent and vertical closure range from 1 to 45 sq km and 20 to 225 respectively.Total potential storage capacity for the seven reservoirs is estimated to be 21.3 x 109m3 of natural gas, and their deliverability potential, based on permeabilities of 1.0 and 5.0 millidarcies, ranges from 0.002 to 0.103 x 106m3 of natural gas per day per well.

Application of acoustic emission in the geotechnical area

A review of the application of acoustic emission (microseismic) techniques to the geotechnical area will be given. The approach will be somewhat historical starting with the pioneering work (in the 1930's) by Obert and Duvall in the coal and metal mines and continuing up to the present where currently a host of materials and engineering problems are being investigated with acoustic emission techniques. Acoustic emission measurements in the laboratory will be described which have given insight into the mechanical behavior of rocks, soils, coal and ice. Field applications which will be dealt with include determination of the stability of mine tunnels, open pit mine slopes, underground gas storage reservoirs, and earthem dikes and dams. The use of acoustic emission techniques in earthquake prediction studies will be reviewed. [The authors' work has been supported by EPA.]

Optimal Scheduling of Production and Compression in Gas Fields

Two new algorithms to optimize the well location and the sequence of flow rates and compressor duties at each well subject to a prespecified demand schedule have been developed. These algorithms can use any capitalization method and can be applied to either primary production or gas storage. A new method for approximating integer variables as continuous variables also is tested. Introduction Optimal reservoir development has been investigated often in recent years. This paper studies the optimal selection of well locations in a gas reservoir and discusses the sequential optimization of flow scheduling in a known gas reservoir constrained by allowable wellhead compressor duty. A model for the reservoir is required, and the production demand schedule must be known. All possible wellsites and compressors and their positions in the reservoir are specified discretely. positions in the reservoir are specified discretely. This discrete character and the continuous aspect of fluid flow from the individual wells are emphasized because both continuous variables and discrete or integer variables are accounted for in developing optimization techniques for a mixed integer programming problem. Several studies on the optimization of the operation or design of gas storage systems and natural gas fields have been published. This research has investigated optimum production scheduling, well location, and design of gas production scheduling, well location, and design of gas wells and gathering systems. These studies fall into two groups: those that concentrate on the operation of the system, and those that focus on the design problem. Most studies of optimum operation primarily have determined the best operating policy from several feasible schemes. In addition, the models usually are simplified and neglect well interference, reservoir heterogeneity, and time-varying behavior. Boyd and Millers and Duane have performed limited studies on optimizing well completions and a compressor schedule for a multiperiod reservoir. No rigorous optimization was attempted, and no well interference effects were considered. Linear programming has been applied to the scheduling of crude oil production over time from a single reservoir. Influence functions and superposition were used to obtain linear relationships between flow rate and pressure drop for a given time interval. Wattenbarger improved previous studies by using inmuence functions to simulate reservoir behavior. He used linear programming to optimize the production from a gas storage reservoir during the withdrawal period. This minimized the difference between the desired production and the actual production. Cooksey et al. used a two-dimensional reservoir simulator to determine the best operating policies. Considering several fixed alternatives of operation, they studied the interaction between compressor operation and well flows. They determined intuitively that it is best to produce from high-deliverability wells because the produce from high-deliverability wells because the compressor costs would be less. Sharp et al. and Dempsey et al. simulated case histories of compression effects on field productivity. They also compared the economic cost of adding compression facilities at a fixed location with drilling new wells. Optimal well location in the development of a gas field has been studied by several authors. Using trial-and-error solution, Henderson et al. indicated that new wells should be placed in the region of low permeability. Coats determined the order in which wells were to be drilled from a list of possible sites using the technique of enumeration, that is, considering every possibility. JPT P. 109

Determination of Reservoir Properties From Backpressure Tests With Applications to Reservoir Simulation

The Odeh-Jones technique for determining values of formation flow capacity and skin factor from backpressure-test data is investigated using a three-dimensional reservoir simulator. An application of the technique to the simulation of a gas storage reservoir is also presented. Introduction A number of situations exist in gas reservoirs where a fast, cheap, reliable method for determining reservoir properties - especially formation capacity - is properties - especially formation capacity - is desirable. In some cases a standard buildup test may be out of the question because of the long buildup times required. Yet, formation capacities are necessary to predict gas deliverability. One may desire to simulate predict gas deliverability. One may desire to simulate the behavior of a gas reservoir where good pressure decline data are available for each well but where the permeability information required for the simulator is permeability information required for the simulator is nonexistent. The question then arises: Is it possible to quickly and cheaply obtain such data without appealing to core analyses or well logs? This paper focuses attention on a technique for analyzing backpressure-test data to determine formation capacities and skin factors. The method is advantageous since field measurements can be made rapidly, easily, and at low cost; and well shutdown is not required. It is based on the Odeh-Jones procedure for analyzing multiple-rate flow tests. Their work was first adapted by Fraser to the analysis of backpressure tests assuming the existence of small pressure gradients and ideal gas. Subsequently, Essis B. and Thomas extended the Odeh-Jones procedure to real gas flow and analyzed backpressure-test data from 16 Oklahoma and Texas gas wells. Flow capacities calculated by the Odeh-Jones technique were compared with those obtained from pressure buildup tests. However, in applying this pressure buildup tests. However, in applying this method Essis B. and Thomas observed various anomalies. These took the form of abrupt changes in slope, breaks in plots, etc. Accordingly, they implied that the utility of this technique was limited. Their attempts to interpret these changes in terms of formation characteristics or wellbore effects were largely based on conjecture since the formation characteristics were, for the most part, inferred. The main objective of this investigation was to determine reasons for the anomalies observed by Essis B. and Thomas. We shall determine whether the various effects (turbulence, skin effect, fractures, etc.) attributed by Essis B. and Thomas to be the cause of anomalous behavior do really cause unusual bends or breaks when flow/afterflow data are plotted in the manner suggested by Odeh and Jones. In addition, it was our purpose-to delineate those reservoir conditions where one could expect reasonably reliable results from the Odeh-Jones method. Finally, we demonstrate how the technique can be useful in determining permeabilities for subsequent use in a reservoir simulation study. Procedure Procedure To achieve the first two goals we used a reservoir simulator to generate the necessary backpressure-test data under a wide range of well and reservoir conditions. This insured better system control; that is, formation and well characteristics were those actually used as input data in the simulator. JPT P. 603

Identification of Leakage Gas from Underground Natural Gas Storage Reservoirs by Isotopic Analysis of Methane: ABSTRACT

Identification of Leakage Gas from Underground Natural Gas Storage Reservoirs by Isotopic Analysis of Methane: ABSTRACT