SPE 59738 Detailed Protocol for the Screening and Selection of Gas Storage Reservoirs D. B. Bennion, F. B. Thomas, T. Ma and D. Imer, Hycal Energy Research Laboratories Ltd. Copyright 2000, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the 2000 SPE/CERI Gas Technology Symposium to be held in Calgary, Alberta Canada, 3-5 April 2000. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s).contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibitted. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract Gas storage reservoirs are used worldwide to store produced natural gas during periods of low demand for use during periods of high demand. These formations are often depleted natural gas reservoirs. Proper selection of a gas storage reservoir is important to allow proper and economic operation of the project on a long-term basis. This paper describes issues which need to be taken into consideration from a reservoir perspective when considering the development of a gas storage reservoir. These issues include the proper containment of the injected gas, maintaining injectivity and productivity over long-term operations, and problems which may be associated with the presence of free water or hydrocarbons in the storage reservoir (both mobile and immobile) as well as formation damage issues that often surround the drilling and completion of new wells in the gas storage reservoirs for development purposes. Introduction Gas storage reservoirs are used on a worldwide basis for the storage of natural gas for use in periods of peak consumption, generally in the colder portions of the year when gas demand for heating is higher. Storage reservoirs are also used to buffer periods of peak demand and prevent disruption of supplies during mechanical or other problems in producing fields. Gas storage reservoirs generally consist of good to excellent quality formations which are often located spatially close to the ultimate demand source (i.e. major population centers). Most of these reservoirs represent natural gas pools which have been depleted below their abandonment pressure during normal production operations, but are now used on a seasonal basis for gas storage. For a reservoir to be a candidate for gas storage, the following criteria must be satisfied: 1. Sufficient reservoir volume to allow for storage of the required amount of gas without exceeding containment pressure constraints and without requiring uneconomic compression to high pressure levels. 2. Satisfactory containment of the gas by competent upper and lower sealing caprock. 3. Sufficient inherent permeability to allow injection and production at required delivery rates during peak demand periods. 4. Limited sensitivity to reductions in permeability (and injectivity/productivity) due to: S presence of in-situ water (mobile or immobile) S presence of liquid hydrocarbons (mobile or immobile) S plugging of the near injector region by compressor lubricants or other introduced fluids S reservoir stress fluctuations during successive pressure cycles 5. Absence of hydrogen sulphide gas (in-situ or bacterially generated) 6. We must be able to drill and complete additional wells in the formation as required with causing severe formation damage (due to the highly depleted pressure condition which may often exist in these reservoirs). The Typical Gas Storage Reservoir Gas storage reservoirs are generally high permeability clastics or carbonates (1000-10,000 md in-situ permeability is common) existing at intermediate depths and temperatures. In general, these reservoirs are depleted formations which originally contained dry (non-retrograde), sweet (no H 2 S) natural gas. Typically, these zones do not contain mobile water or active or partially active aquifers, oil legs or residual liquid hydrocarbon saturations, although this is not always the case.
2 D.B.BENNION, F.B.THOMAS, T.MA, D. IMER SPE 59738 Containment of Reservoir Gas For an effective gas storage reservoir, the injected gas must obviously remain in place, possibly for an extended period of time, without escaping through permeable channels in the overlying or underlying reservoir seal. We refer, in this situation, to competent barriers that separate the storage zone from other zones and may act as permanent bleed zones for gas losses which cannot be recovered. These connected zones may also contain undesirable fluids (gases containing liquids, hydrogen sulphide, water zones, oil/hydrocarbon zones, etc.). Typically thick (3-4 meters or more) dense shales are present in these intervals to act as an impermeable seal for the reservoir gas. To verify that the cap and base rock have sealing competency, a cap rock permeability test is generally conducted in the laboratory on a sample of preserved cap rock which is taken via coring from the penetration of the storage formation and the cap and base rock. Two different cap rock competency tests are generally conducted and are required to be satisfied for sealing competency to be present. These are: 1. Absolute liquid permeability measurement 2. Threshold intrusion pressure to gas Core material must be properly handled and preserved for the proper analysis of caprock. In general, a low invasion coring program with an inhibitive water-based or oil-based mud system should be used to obtain the core material. The cap rock samples should be preserved on site using PROTEC or CORESEAL and should not be subjected to conventional solvent extraction and drying protocols that can remove water of hydration from the clays and shales present and permanently destroy the caprock morphology, which may result in obtaining erroneously high permeability and intrusion pressure measurements. Absolute Liquid Permeability Measurements. Fig. 1 provides a schematic illustration of the equipment used for caprock permeability measurements. These tests are almost always conducted on vertical full diameter core (oriented in the vertical direction). In some cases, vertical plugs (cut from the long axis of a vertically oriented core (Fig. 2) are used for the tests. Tests should not be conducted on horizontally oriented core plugs, as streamlines of flow in this situation run parallel to naturally occurring bedding planes, and may result in anomalously high permeabilities in comparison to those expected to be encountered by the stored gas which will be intruding into the overlying caprock in a vertical fashion. Caprock samples should be subjected to X-ray or NMR analysis prior to testing to ensure that they do not contain coring induced fractures or other features which may represent permeability conduits that are not reflective of the reservoir. Natural open fractures existing in the caprock are obvious detriments to the gas storage process and should be carefully evaluated from a core analysis, seismic and geotechnical stress analysis of the subject formations, as these will eliminate the zone almost immediately as a gas storage candidate. The caprock test apparatus allows the preserved state sample to be confined at reservoir overburden pressure conditions in a uniaxial cell and also allows full reservoir conditions of temperature and pore pressure to be applied to the sample to precisely duplicate downhole conditions. A positive displacement pump/pressure source is used to apply a net pressure differential of 7000 kpa (approx. 1000 psi) to the core face using formation water (or another brine known to be chemically compatible with the caprock). A digital capacitance transducer is used to measure the applied pressure drop precisely. Flow rate through the caprock sample is monitored over an extended time period (generally 7-14 days) and an effective fluid permeability to the formation brine is determined. For effective caprock, the measured brine permeability should be less than 1 nanodarcy (1 x 10**-06 md or 0.000000001 Darcy). Caprock permeability higher than this would indicate, on a long-term basis, that expulsion of connate water from the caprock could occur which may allow the intrusion and production of gas. Multiple samples of caprock should usually be tested, particularly if multiple lithologies are present, but may not be spatially continuous throughout the reservoir. This is illustrated in Fig. 3 where we observe that although lithology 1 is good sealing caprock, it is not regionally continuous over the entire reservoir and in places only lithology 2 or 3, which may not be competent, are present as a seal. Table 1 illustrates the results of typical satisfactory and unsatisfactory cap rock evaluations. Gas Intrusion Testing. Fig. 4 illustrates the experimental apparatus used for a caprock gas intrusion test. This test is generally conducted on the same sample used for the liquid permeability measurement, described previously, if satisfactory results from the liquid permeability measurement test are obtained. The equipment consists of the vertically mounted full diameter vertical core sample maintained at bottomhole temperature and pressure conditions. In this test, however, water saturated natural gas is exposed to the face of the core at a 7000 kpa pressure differential. A highly accurate production burette (0.01 cc accuracy) is attached to the production end of the core sample which allows one to determine over a long-term exposure period (14-21 days) if any production of fluid from the saturated pore space (indicating gas intrusion into the sample) occurs. Any appreciable fluid intrusion occurring over this period indicates a failure and once again suggests that the sample may not be competent caprock from a sealing perspective. In-Situ Permeability and Permeability Variations with Stress As mentioned previously, gas storage reservoirs typically have high inherent permeability to allow for easy gas injection and rapid delivery of large gas volumes during peak demand
SPE 59738 DETAILED PROTOCOL FOR THE SCREENING AND SELECTION OF GAS-STORAGE RESERVOIRS 3 periods. The threshold of required permeability varies depending on the amount of pay present and the type of well being used (vertical, fractured vertical or horizontal). In general, in-situ permeability in gas storage reservoirs exceeds 1 Darcy and is often substantially higher than this. Core analysis permeability (gas permeability measured on clean, dry core samples extracted from the formation using air or nitrogen under a nominal (1378 kpa confining pressure)) may not be reflective (are often higher) of those present in the reservoir, due to the fact that the routine samples do not contain a irreducible water saturation (which will be present in the reservoir), and are generally not measured under a confining overburden pressure (which may substantially reduce the permeability of the formation due to grain compression effects). This is particularly significant in high permeability formations composed of conglomeritic grains or by relying on pervasive, open micro-fracturing for the high inherent permeability. Proper permeability evaluations can generally be obtained from in-situ condition core tests (under proper overburden pressure conditions and with the correct initial water saturation in place), or via pressure transient analysis of the in-situ permeability in the reservoir (often a more accurate technique if fractures or macro-scale heterogeneities exist in the reservoir which cannot be adequately represented in small core samples tested in the lab). Typical permeability water saturation and permeabilityoverburden pressure variation plots are shown as Figs. 5 and 6 respectively. These are generic representations only and the specific configuration of these curves will be highly dependant on reservoir pore system lithology and morphology. Gas storage reservoirs are also susceptible to significant cyclic variations in overburden stress through the annual pressure cycling operation. This is schematically illustrated as Fig. 7. It can be seen that at the peak of the storage cycle, the reservoir pressure will be at its greatest level resulting in the presence of the least amount of effective stress on an in-situ basis, which usually corresponds to the highest permeability and facilitates improved permeability and injectivity. When the reservoir is depleted during peak production, the bottomhole pressure falls and the net overburden stress increases which may result in reductions in permeability and potentially in deliverability. This issue should be evaluated prior to design of the project as certain types of formations (as mentioned previously) may be highly sensitive to this phenomena. Wellconsolidated competent intercrystalline sandstones and carbonates tend to be the least affected by this phenomena in most circumstances. Presence of Mobile or Immobile Liquid Saturations In general, the optimum gas storage reservoir does not contain any substantial free mobile water. Mobile water results in reduction in productivity, due to relative permeability effects, and can result in severe hydrate problems at high production rates due to Joule Thompson expansion effects. The presence of mobile water contacts in the base of the reservoir can also result in cyclic trapping of a portion of the injected gas due to cyclic hysteresis effects when water-gas or water-oil contact advances and retreats in the same reservoir volume over a period of time. This phenomena has been discussed in the literature (Ref. 1) and can result in some cases in substantial permanent losses of injected gas due to trapping effects. Figs. 7 and 8 illustrate this phenomena. Trapped hydrocarbon saturations may also be problematic in certain circumstances due to solubility and swelling effects. Trapped immobile liquid saturations may be present in some gas reservoirs due to accumulation of condensate liquids (if the reservoir initially contained a retrograde condensate gas system). Injection of gas may result in a solubility increase (dissolution of a portion of the injected gas into the hydrocarbon liquids) which results in an increase in the apparent liquid saturation (swelling of the liquid). This may result in a reduction in the gas phase permeability as illustrated in Fig. 9. In some gases, swelling and viscosity reductions in the immobile hydrocarbon phase may combine to actually result in mobile hydrocarbon production, generally highly undesirable for a gas storage reservoir application. Maintaining Injectivity and Productivity All benefits of the gas storage operation will be lost if the operator is unable to inject or produce sufficient gas to meet the design and demand criteria of the project. On existing wells (those generally present from the original production life of the reservoir) which have good initial productivity, the greatest problem is often reduced injectivity/productively due to compressor lubricant carryover. Many compressors, particularly older models, can consume large volumes (sometimes many liters per day) of lubricants. This material is often carried as a finely atomized mist into the formation, where it can gradually accumulate in the near wellbore region, resulting in a trapped extraneous phase which may plug or severely reduce productivity over a period of time (as illustrated in Fig. 10). Properly designed and maintained compressors and filtration / precipitation equipment to remove or reduce the volume of atomized lubricant can be useful in this situation. Many lubricants are oil-based and result in the introduction of an extraneous phase into the reservoir. In some cases, water-based lubricants may be used, which may have less affinity for plugging due to a natural solubility in connate water which may be present in the reservoir. This, however, is not always effective as, in most mature gas storage injectors, little, if any, connate water saturation remains in the near wellbore region as the large volume of dehydrated dry natural gas injected through this zone often removes virtually all water present over a period of time by dehydration and desiccation effects. This can actually result in some long-term increases in injectivity, depending on the configuration of the relative permeability curves for the porous media (Fig. 11). This may also make wells of this type susceptible to reductions in injectivity if water-based kill or workover fluids are used as the
4 D.B.BENNION, F.B.THOMAS, T.MA, D. IMER SPE 59738 introduced water will rehydrate into the dry cylinder of rock surrounding the injection well and will re-establish the irreducible water saturation which may take an extended period of time to revaporize. High salinity brines, therefore, are a potential concern in this situation as, due to subsequent desiccation effects caused by extensive dehydrated gas injection, precipitation of the suspended solids in the pore system by supersaturation effects may also contribute to near wellbore plugging issues. Care must also be taken to avoid the introduction of viable bacteria with workover or completion fluids, which may possibly result in plugging or souring of the wells (although this is generally not a problem if no substantial water saturation is present in the near wellbore region). Formation Damage Effects In many situations, to properly develop a reservoir for gas storage, recompletion of existing wells and drilling of new wells is required. This is particularly the case in recent years where horizontal wells have been used increasingly for gas storage applications, as a single horizontal well can replace multiple vertical penetrations, or, due to increased reservoir exposure, allow formations which may not have been considered to have sufficiently high permeability for development with vertical wells to now be viable gas storage candidates. Two factors can combine to create significant formation damage in these situations: 1. The formations are generally highly pressure depleted at the time of completion of the wells. This means that extreme overbalance pressures will be present with conventionally weighted drilling or completion fluids, and that the potential for lost circulation and severe invasion and mechanical damage of the high permeability pore system, due to whole mud invasion, may be an issue. 2. High natural permeability, which is almost always a prerequisite for a gas storage zone, combines with this overbalance effect to increase the potential for lost circulation and near wellbore damage effects. Although high permeability formations are generally fairly forgiving with respect to many classical formation damage mechanisms such as fines migration (due to large pore throats and often very little mobile material), phase trapping and blocking (due to very low, favorable capillary pressure) and clay related damage (due to generally excellent reservoir quality and very little reactive clay in most situations), mechanical damage caused by the loss of large volume of fluid containing drill solids, corrosion products, clay, improperly sized bridging agents, etc., may be severely damaging. This is particularly the case if an open hole completion is contemplated, as even a very shallow zone of mechanical damage of this type may severely compromise the productivity of the wellbore. Tables 2 and 3 illustrate the results of whole mud leakoff tests, conducted at only a moderate (1379 kpa) overbalance pressure in a high permeability conglomeritic gas storage reservoir candidate. It can be seen from examining this data that uncontrolled fluid losses occurred, resulting in deep invasion and large reductions in permeability due to permanent mechanical entrainment of drill and mud solids. Fig. 12 illustrates the appearance of the pore system in such a situation where significant plugging of the high permeability matrix by invaded mud solids is clearly apparent. Proper lab testing (Ref. 8) can allow one to determine if the drilling and completion practices proposed for a gas storage reservoir will provide suitable results prior to the actual execution of the operation in the reservoir. If damage with conventional drilling and completion practices appears to be severe, several options are available to reduce the damage. These include: 1. Underbalanced drilling and completion. If properly executed, a UBD application may eliminate invasive formation damage even in a pressure depleted high permeability reservoir. Problems with this approach center around the ability to maintain the underbalanced condition on a constant basis throughout the entire drilling and completion operation, as it has been demonstrated that even relatively short periods of overbalance pressure (such as those associated with pipe connections, survey jobs, bit trips, frictional flow effects, etc.) can result in significant invasive damage to the formation where all or a portion of the benefit of the UBD application may be lost (Ref. 9). In some cases, if very low bottomhole pressures are present, maintaining an underbalanced condition with a nitrified fluid system may not be possible. In this situation, even gas or mist drilling may be overbalanced due solely to frictional backpressure effects associated with high circulation rates required to maintain sufficient annular velocity to facilitate adequate hole cleaning. 2. Specially designed overbalanced fluid systems containing custom-designed bridging and fluid loss agents to rapidly create a sealing, competent filter cake on the formation face to limit fluid invasion. The filter cake must be designed to be easily removed by backflow or a non-invasive completion treatment, or be shallow enough to be penetrated by a mechanical stimulation treatment (such as open hole perforating, etc). 3. Repressurization of the reservoir by using existing gas injection in wells (with the caveat that this may take an extended period of time and not be practical due to the type, location, condition and number of wells available) to increase bottomhole pressure to a much higher level in order to reduce overbalance pressure conditions. This may allow for a more conventional drilling application, or easier application of one of the methods discussed in Point 1 or 2 above. Conclusions Not all reservoirs are good candidates for gas storage. This
SPE 59738 DETAILED PROTOCOL FOR THE SCREENING AND SELECTION OF GAS-STORAGE RESERVOIRS 5 paper has outlined a number of the reservoir criteria that should be evaluated and potential concerns which need to be investigated when considering if a reservoir is a suitable candidate for gas storage. Issues that have been discussed include: S Reservoir quality S Competence and stability of sealing caprock S Reservoir stress issues S Reservoir issues causing reduced injectivity and productivity Lab testing and evaluation using core analysis has been illustrated to be an effective technique in diagnosing many of these reservoir issues and allows the accurate determination of the suitability of a reservoir as a gas storage candidate prior to the cost and risk of actual project implementation. 9. Bennion, D.B. et al, Underbalanced Drilling: Praises and Perils, SPEDE, Nov. 1998. Acknowledgments The authors express appreciation to the management of Hycal Energy Research Laboratories for permission to publish this paper and to Vivian Whiting for her assistance in the preparation of the manuscript, figures and tables. References 1. Bietz et al, Gas Storage Reservoir Optimization Through the Application of Drainage and Imbibition Relative Permeability Data, CIM 92-75, presented at the CIM 1992 ATM, Calgary, AB. June 7-10, 1992. 2. Craft, B.C., Hawkins, M.F., Applied Petroleum Reservoir Engineering, Prentice-Hall, Inc. (1959). 3. Bennion, D.B., Thomas, F.B., Recent Improvements in Experimental and Analytical Techniques for the Determination of Relative Permeability from Unsteady State Flow Experiments, paper presented at the SPE Technical Conference at Trinidad and Tobago, June 27, 1991. 4. Buckley, S.E. and Leverett, M.D., Mechanisms of Fluid Displacement in Sands, Trans., AIME, Vol. 146 (1942) 107. 5. Welge, H.J., A Simplified Method for Computing Recovery by Gas or Water Drive, Trans., AIME, Vol. 195 (1952), 91. 6. Archer, J.S. and Wong, S.W., Use of a Reservoir Simulator to Interpret Laboratory Waterflood Data, SPEJ (Dec. 1973) 343. 7. Sigmund, P.M. and McCaffery, F.G., An Improved Unsteady-state Procedure for Determining the Relative Permeability Characteristics of Homogeneous Porous Media, SPEJ (Dec. 1973) 343. 8. Bennion, D.B. et al, Recent Advances in Laboratory Test Protocols to Evaluate Optimum Drilling, Completion and Stimulation Practices for Low Permeability Gas Reservoirs, SPE 60324 to be presented at the SPE Rocky Mountain Regional Meeting, Denver, CO, Mar. 12-15, 2000.
6 D.B.BENNION, F.B.THOMAS, T.MA, D. IMER SPE 59738 TABLE 1 SUMMARY OF CAPROCK GAS THRESHOLD PRESSURE TESTS Directional Orientation Intrusion Pressure to Gas (MPa) Effective Permeability to Fluid (md) Comments Vertical Vertical Vertical Vertical 11.41 Higher than 18.0 8 18 0.00005 <0.000001 0.00021 <0.000001 Fail Pass Fail Pass TABLE 2 UNDERBALANCED/OVERBALANCED MUD LEAKOFF TEST IN A GAS STORAGE RESERVOIR CORE AND TEST PARAMETERS Stack Length (cm) Diameter (cm) Effective Flow Area (cm 2 ) Bulk Volume (cm 3 ) Porosity (fraction) Pore Volume (cm 3 ) Routine Air Permeability (md) Test Temperature (EC) Gas Viscosity (mpa s) Fixed Initial Water Saturation (fraction) Net Overburden Pressure (kpag) Mud Overbalance Pulse Pressure (kpag) Mud Underbalance Pressure (kpag) Rock Microfine Concentration (kg/m 3 ) Rock Microfine Size (micron) 5.14 2.54 5.08 26.10 0.135 3.52 5888 46 0.0190 0.160 26400 1379 690 30 <38 TABLE 3 UNDERBALANCED/OVERBALANCED MUD LEAKOFF TEST IN A GAS STORAGE RESERVOIR PERMEABILITY SUMMARY Test Phase Initial Gas Permeability @ Sw i (Direction #1) Underbalance Mud Circulation (Direction #2) Regain Gas Permeability (Direction #1) @ 7 kpa Drawdown 14 kpa Drawdown 28 kpa Drawdown Overbalance Pulse - 5 Minutes (Direction #2) Regain Gas Permeability (Direction #1) @ 7 kpa Drawdown 14 kpa Drawdown 69 kpa Drawdown * Baseline Permeability (md) 3035 2311 2560 3035 774 821 860 Regain Permeability (%) * 76 84 100 26 27 28
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10 D.B.BENNION, F.B.THOMAS, T.MA, D. IMER SPE 59738 Net Overburden Stress Net Overburden Stress
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