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Laboratory and Field Observations of an Apparent Sub-Capillary-Equilibrium 
Water
Saturation Distribution in a Tight Gas Sand Reservoir*
K.E. Newsham1 and J.A. Rushing2
Search and Discovery Article #40400 (2009)
Posted May 4, 2009
*Adapted from paper prepared for presentation at the SPE Gas Technology Symposium held in Calgary, Alberta, Canada, 30 April–2 May 2002. Copyright held by the authors.
Authors’ Note: 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.
1 SPE, Anadarko Petroleum Corporation; currently Apache Corporation, Houston, Texas ([email protected])
2 SPE, Anadarko Petroleum Corporation ([email protected])
This article documents laboratory and field observations of an apparent sub-capillary-equilibrium water saturation distribution in the Bossier tight gas sands. These observations are validated with consistent measurements from several different techniques, including production performance analysis, reservoir fluid phase behavior, log evaluation, and both conventional and special core analyses. We also identify several mechanisms, including those associated with a basin-centered gas system, which may be responsible for this phenomenon.
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Tight gas sands constitute a significant percentage of the U.S. natural gas resource base and offer tremendous potential for future reserve growth and production. A recent study by the Gas Technology Institute (Prouty, 2001) indicated tight gas sands comprise almost 70% of gas production from all unconventional gas resources and account for 19% of the total gas production from both conventional and unconventional sources in the U.S. The same study (Prouty, (2001) estimated total producible tight gas sand resources exceed 600 tcf, while economically recoverable reserves are 185 tcf. This article focuses on one of the most active domestic U.S. tight gas sand plays, the Bossier Sands in the East Texas Basin. Specifically, we present results from a reservoir description and characterization study in the Mimms Creek and Dew fields in Freestone County, Texas.
Similar to conventional oil and gas systems, tight gas sands are often described by complex geological and petrophysical systems as well as heterogeneities at all scales. Unlike conventional reservoirs, however, tight gas sands often exhibit unique gas storage and producing characteristics. Consequently, effective exploitation of these resources requires accurate description of key reservoir parameters, particularly
We present laboratory and field observations of the Bossier sands, a deep abnormally pressured, high-temperature tight gas sand reservoir exhibiting an apparent sub-capillary-equilibrium Regional Geology and Depositional Environment The Bossier sands are Late Jurassic in age and were deposited in the East Texas Basin. Located in northeast Texas, this sedimentary basin is a deep elongated trough structure with shelf-slope systems on the basin flanks. Several major tectonic features, including the Sabine Uplift to the east, the Mexia-Talco Fault System to the north and west, and the Angelina-Caldwell Flexure to the south bound the basin (Montgomery, 2000). East Texas is recognized as one of three major salt provinces in the U.S. The East Texas Basin is characterized by major salt features - salt anticlines, piercement domes, pillows, etc. within its interior (Montgomery, 2000). Current geological models suggest a relationship between generation of the major fault systems, salt deformation and migration, basin subsidence, and sediment deposition during Middle to Late Mesozoic (Montgomery, 2000). The significant salt structures also appear to control the distribution of sediments within the basin interior (Montgomery, 2000). A typical stratigraphic column for the East Texas Basin (Figure 1) shows that the Bossier sands are part of the Upper Jurassic Cotton Valley Group and are overlain by the Cotton Valley Sandstone (Montgomery, 2000). The Bossier interval is thick and lithologically complex and contains black to gray-black shale interbedded with very fine- to fine-grained argillaceous sandstone. Similarly, the Cotton Valley Sandstones are comprised of interbedded shale and very quartz rich sandstone layers. The Cotton Valley Group is underlain regionally by the Upper Jurassic Louark Group. This includes other hydrocarbon-bearing formations such as the Smackover carbonates and Haynesville/Cotton Valley Limestones. Overlying the Cotton Valley Group is the regionally productive, Lower Cretaceous Travis Peak and Pettit (Sligo) formations. As illustrated by the generalized regional dip-section in Figure 2, Bossier deposition represents cycles of sand progradation into the basin onto organic rich mud, succeeded by marine transgression. Much of the Bossier interval downdip appears to be time equivalent to the Cotton Valley Sandstone updip and represents prodelta/delta front material related to Cotton Valley deltaic systems (Montgomery, 2000; Perrizela, 2002). The Bossier sands appear to originate from the north and west and were transported downslope by slumping, debris flow, and turbidity currents. Significant Bossier sand thicknesses are located in topographic lows created by a combination of faulting, subsidence, and salt movement in the basin. Bossier Sand Characteristics of the Mimms Creek and Dew Fields
The current Bossier sand play is centered along the western shelf margin of the East Texas Basin, specifically in Robertson, Leon, Limestone, and Freestone counties. In this section we summarize the reservoir characteristics of the Mimms Creek and Dew fields located in Freestone County. Much of the reservoir description is based on more than 1000 ft of whole core and more than 200 rotary sidewall core samples. Sand Facies and Depositional Environment The Bossier sands in Mimms Creek and Dew fields are comprised of a series of stacked sandy packages, as illustrated by the type log in Figure 3. In chronological order of deposition, these packages are known as the York, Bonner, Shelley, and Moore sands. Stratigraphic sequences observed from several whole cores indicate the sands were deposited as a prograding sediment wedge complex during a lowstand onto organic shelf mud deposited during a highstand. At the top of the sand packages, ravinement or transgressive lag deposits have been observed, indicating the onset of a marine transgression during which very little sand was preserved above wave base. The Bossier sands are capped by restricted to open shelfal muds deposited during another highstand (Perrizela, 2002). As illustrated in Figure 4, typical Bossier sand-body geometry is elongated with the long axis oriented parallel to the depositional dip; so lateral continuity along depositional strike is often limited. The sand-body thickness varies from tens to several hundred feet. The combination of low depositional relief and limited lateral sand continuity minimizes the hydrocarbon column height potential within each sand body. In addition, the elongated geometry of the isolated sand bodies combined with low permeability and high degree of heterogeneity limits the volume of recoverable gas from a single well. This observation is confirmed from production decline type curve analysis which indicates small drainage areas, typically ranging from 40 to 80 acres but frequently less than 40 acres per well. The Bossier shales are prevalent both areally and vertically in Mimms Creek and Dew fields. Laterally extensive shales appear to act as both seals and hydrocarbon source rock for the sands, while local interbedded shales also appear to be an important hydrocarbon source for the Bossier sands. A reservoir study of these shales shows current total organic carbon (TOC) ranges from 1% to 5%, while the kerogen type is mixed Type II and III. Vitrinite reflectance measurements average 1.25% but range from 1.2 to as high as 2.5%, indicating the shales are in the gas window for hydrocarbon generation. Measurements using the RockEval technique (Espitalie et al.., 1985) validated observations from the vitrinite reflectance data. As we discuss in the next section, most of the Bossier section in the Mimms Creek and Dew fields is abnormally overpressured. A probable source for this overpressured system is gas generation from the shales. The data suggests hydrocarbons have been generated not only from kerogen cracking in the shales but also from cracking of liquid hydrocarbons trapped in the sands. This cracking phenomenon, which has been documented by Hunt (1990), has been postulated on the basis of pyrobitumen observed in core thin sections. We also conducted gas isotope analysis on Bossier gas samples, and the computed carbon isotope separations (δ13C) range from –30 ppt to –40 ppt which is consistent with gases of thermal origin. Gases produced from the Mimms Creek and Dew fields are composed primarily of methane, but we also measure ethane and small quantities of propane, which are also indicative of thermal rather than biogenic origin. Pressure and Temperature Gradients
The Bossier Sands are overpressured throughout most of the East Texas Basin, including the Mimms Creek and Dew Field area. As illustrated by Figure 3, pressure gradients range from 0.50 to 0.55 psi/ft in the upper Cotton Valley Sands, 0.60 to 0.65 psi/ft in the upper Bossier, Moore, and Shelley Sands, and 0.70 to 0.90 psi/ft in the lower Bossier Bonner and York Sands. The Cotton Valley Sand pressure gradient represents a normal to slightly abnormal pressure gradient of a very saline formation This overpressured system, which has been confirmed using both static bottomhole pressure measurements and from acoustic log analysis (Figure 5), is easily recognized by pressure-depth profiles. The deviation from the normal pressure gradient is referred to as the top of abnormal pressure (TAG) point. The overpressure gradient, when calculated from mean sea level, increases with depth; however, the pressure transition trend, referred to as the incremental pressure gradient (IPG), ranges from 3.5 psi/ft to 5.00 psi/ft. Note that the IPG is significantly greater than the lithostatic gradient. The inequality between the lithostatic and incremental pressure gradients suggests the source of overpressure is not caused by compaction/disequilibrium (Swarbrick and Osborne, 1998; Finkbeiner, 2001). Rather, we believe the source of overpressure is primarily from hydrocarbon generation and secondarily from chemical compaction effects of diagenesis. Bossier sands in this area and throughout the East Texas Basin also exhibit abnormally high temperature gradients. Bottomhole temperatures in the Mimms Creek and Dew fields range from 280oF to 325oF at depths ranging from 12,500 ft to 13,500 ft. This corresponds to temperature gradients of 2.2 to 2.4oF per 100 ft of depth. Typical Producing Characteristics The average initial gas production rates vary from 2 to 5 MMscfd in the Moore and Shelley sands, while the Bonner and York sands range from 5 to 15 MMscfd. Similarly, the estimated ultimate gas recovery ranges from 1.5 to 3 Bcf in the Moore and Shelley sands and 3 to 10 Bcf in the Bonner and York. Most wells exhibit hyperbolic decline with stabilized rates of 500 to 900 Mscfd after two to three years. The differences between producing characteristics in the sands reflect both better reservoir quality and higher pressures in the Bonner and York sands.
The Bossier sands also produce some Wells completed in the Bossier sands produce a dry to slightly wet gas, with specific gravity ranging from 0.58 to 0.61. Condensate production averages one to three STB/MMscf over the life of the well. Gas composition typically averages 94 mole% methane and 2 mole% ethane. The remaining hydrocarbon mixture includes fractional percentages of propane through hexane, with typically no heptanes plus. Non-hydrocarbon components include 2 to 2.5 mole% carbon dioxide, 0.2 to 0.5 mole% nitrogen, and relatively no hydrogen sulfide.
As we noted above, the Bossier sands produce some We have also conducted a comprehensive Bossier sand description program, using evaluations of more than 1000 ft of whole core obtained from four wells in the Mimms Creek and Dew fields. Our description includes classification of petrophysical rock types, which are identified based on similar pore and grain scale characteristics, such as composition, texture, mineralogy, clay type, and types of diagenesis. We have also defined several hydraulic rock types representing similar ranges of storage and flow characteristics. Table 1 summarizes the various measurements made to describe the Bossier sands. The petrographic rock types observed within the Bossier Sands (Newsham and Rushing, 2001) include clean sandstone, argillaceous/weakly laminated sandstone, dolomitic sandstone, and argillaceous/burrowed siltstone (Newsham and Rushing, 2001). Using the Folk (1974) classification, the types range from subarkose to sublitharentite to lithic wackes. The framework grains contain, on average, 84% quartz, 6.5% feldspar, and 9.5% rock fragments. The range for these constituents is 41%-94% for quartz, 0%-11.7% for feldspar, and 0.5%-59% for the rock fragments. The intergranular constituents are primarily quartz overgrowths, diagenetic clay in the sands, detrital clay found in sand and silt, dolomite cement, and local pyrite. The clay fraction is dominantly grain-coating chlorite and illite. Texturally, the Bossier Sands have a narrow range of grain size, typically from upper very fine to fine. The sands are medium to well sorted, while the silts are typically poorly sorted. Sand grain shape is subangular to well rounded. A significant degree of compaction is observed from thin sections in the form of suturing, elongation of grain contacts, and ductile grain deformation. Bossier sands also exhibit a significant diagenetic overprint. Diagenesis, the physical or chemical processes that cause changes in the initial rock properties, tends to modify the initial pore structure and geometry. This results in an increase in the tortuosity from a reduction in pore throat size and a subsequent increase in the number of isolated and disconnected pores. Most diagenetic effects are manifested as reductions in permeability and porosity. The most important forms of diagenesis in the Bossier sands are mechanical compaction, cementation from quartz overgrowths, grain-coating/pore lining clay development, and grain dissolution. Although less important and prevalent, carbonate cementation has also been observed in Bossier sandstones.
We have also identified several Bossier sand hydraulic rock types (Newsham and Rushing, 2001). When described on the basis of the dominant pore throat diameter determined from high-pressure mercury capillary pressure data, we observed distinct groupings of rocks having similar flow and storage properties; i.e., hydraulic rock types. Figure 6 is an example of an incremental mercury intrusion plot used to identify rock types (Pittman, 1992; Gunter et al., 1997; Washburn, 1921; Swanson, 1979; Thompson et al., 1987; Newsham and Rusing, 2001). Figure 7 shows the general region of each rock type in porosity-permeability space, while Table 2 lists the permeability, pore throat aperture size, and range of initial Effective Porosity and Absolute Permeability Figure 7 shows a typical distribution of effective porosity and absolute permeability. Effective porosity varies from 1% to 17%, while absolute permeability ranges from 0.001 to 1 mD. Non-reservoir and seal rocks have permeability values lower than 0.001 mD. In general, the Bonner and York sands have better permeability and porosity than the Moore and Shelley sands. Better reservoir quality combined with higher pressures is demonstrated by greater gas recovery. Similar to most tight gas sands, the Bossier sands display both stress-dependent porosity and permeability characteristics. For example, the hyperbolic decline behavior exhibited by many tight gas sand wells can be attributed, in part, to reductions in permeability and porosity during the depletion history. We measured porosity and permeability over a wide range of stress conditions and observed slight changes in porosity. We did, however, measure significant reductions in permeability as net mean stress is increased. We also noticed that the degree of stress dependency increased for the lower quality rock types. Effective and Relative Permeability
Although we believe no mobile liquid phase exists in the Bossier sands at reservoir conditions, the presence of
We also measured connate Capillary Pressure Characteristics
We measured capillary pressure characteristics using high-pressure, mercury injection (MICP). We used MICP since the low porosity and permeability precluded using either centrifuge or porous plate methods, which are limited by the maximum attainable pressure. From the capillary pressure measurements, we were able to describe the vertical
Reservoir Description Program to Quantify
To verify the low
Core-Based
We obtained more than 1000 ft of whole core from four wells in the Mimms Creek and Dew fields. To minimize invasion effects and preserve connate
Log-Based
We also computed the vertical distribution of
Application of the Modified Simandoux (1963) model also requires estimates of the Archie (1950)
The final component required to compute connate
Commutation or residual salt analysis is a process that extracts or leaches connate
In general, results from the log-based analysis agreed with
Capillary-Equilibrium-Based
As we noted above, we also attempted to compute a vertical distribution of
Because of these discrepancies, our next step was to determine the column height required to match the range of
Sub-capillary-Equilibrium
In summary, vertical distributions of core-derived measurements and log-derived calculations of
Possible Mechanisms for Sub-Capillary-EquilibriumWater
In this section, we present a hypothesis to explain the physical mechanisms and conditions that could cause the development of a sub-capillary-equilibrium, Elements of our Petroleum System Process Model are presented in Figure 12. These elements - i.e., source rock, reservoir rock, and reservoir seals - are very similar to conventional oil and gas systems. The reservoir rock is most often deposited as hydraulically isolated or disconnected sands interbedded with organic-rich marine shales. These sand-shale sequences usually occur as vertically stacked but isolated sands. As the sand-shale systems are buried by overlying sediments, the sands are buried deeper and exposed to higher pressures and temperatures. Continued burial and exposure to extreme environmental conditions causes the organic material to decay and generate hydrocarbons. Depending not only on the type and quantity of organic material but also the environmental conditions, organic diagenesis occurs in several discrete stages, resulting in generation of both liquid and gas hydrocarbons. If the shales are exposed to sufficiently high pressures and temperatures associated with the gas generation window, all hydrocarbons will be in the gas phase. During all stages of shale diagenesis, hydrocarbons are frequently expelled from the shales and migrate into reservoir rock. If an adequate sealing system exists, then the hydrocarbons will be trapped in the reservoir rock. Sands in our model are isolated and interbedded with the shale; so shales most often act both as seals and local hydrocarbon sources. Continued hydrocarbon migration into the reservoir causes an increase in pore pressure until the shale seal capacity is exceeded, causing hydrocarbons to be expelled. Hydrocarbon expulsion continues until the reservoir pore pressure equilibrates with the shale seal capacity. At this point the shale heals and re-seals. As long as hydrocarbons are generated, the process becomes cyclical. We have given the cyclical process the acronym GENPERR (hydrocarbon generation, pressurizing, expelling, re-sealing, and recharging). This cyclical process explaining the petroleum system genesis has been documented by others (Swarbrick and Osborne, 1998; Law, 1984a, b; 1994; Law and Dickinson, 1985; Spencer, 1987; Meissner, 1987).
The critical element in our model is a mechanism to remove connate
Consequently, we have identified another mechanism for removing connate
The final element required to explain a sub-capillary-equilibrium
We have documented an apparent sub-capillary-equilibrium
We would like to express our thanks to Anadarko Petroleum Corp. for permission to publish this article. Special thanks to Kevin Hae Hae (Anadarko Petroleum Corporation) for his editorial input on the Bossier sand geology, Ahmed Chaouche (Anadarko Petroleum Corporation) for his help with the Bossier Shale properties, and Brant Bennion (Hycal Energy Research Laboratories Ltd) for his technical suggestions regarding the concept of sub-capillary-equilibrium Archie, G.E., 1950, Introduction to petrophysics of reservoir rocks: AAPG Bulletin, v.34, p.943-961. Espitalie, J., Deroo, G., and Marquis, F., 1985, La pyrolyse Rock-Eval et ses applications: Rev. Inst. Fr. Pet. 40, p. 563579, p. 755-784, Rev. Inst. Fr. Pet. 41, p. 73-89. Finkbeiner, T., Zoback, M., Flemmings,. P., and Stump, B., 2001, Stress, pore pressure, and dynamically constrained hydrocarbon columns in the South Eugene Island 330, northern Gulf of Mexico: AAPG Bulletin, v.85, no.6 (June 2001), p. 1007-1031. Folk, R.L., 1974, Petrology of Sedimentary Rocks: Hemphill Publishing Co., Austin, Texas, 78703. Gunter, G.W., et al., 1997, Early determination of reservoir flow units using an integrated petrophysical model: Paper SPE 38679 presented at the 1997 SPE Annual Technical Conference and Exhibition, San Antonio, TX, October 5-8. Hunt, J.M., 1990, Generation and migration of petroleum from abnormally pressured fluid compartments: AAPG Bulletin, v. 74, no.1 (January 1990), p.1-12. Law, B. E., 1984a, Relationships of source rocks, thermal maturity, and overpressuring to gas generation and occurrence in low-permeability Upper Cretaceous and lower Tertiary rocks, Greater Green River Basin, Wyoming, Colorado, and Utah, in Woodward, J., Meissner, F.F., and Clayton, J.L., eds., Hydrocarbon source rocks of the greater Rocky Mountain region: Rocky Mountain Association of Geologists, p. 469-490. Law, B.E., 1984b, ed., Geological characteristics of low-permeability Upper Cretaceous and Lower Tertiary rocks in the Pinedale anticline area, Sublette County, Wyoming: U.S. Geological Survey Open-File Report 84-753, 107 p. Law, B.E., 1995, Columbia Basin-basin-centered gas play (0503), in Tennyson, M.E., Eastern Oregon-Washington Province (005), in Gautier, D.L., Dolton, G.L., Masters, J.A., 1979, Deep basin gas trap, western Canada: AAPG Bulletin, v. 63, p.152-181. Law, B.E., and Dickinson, W.W., 1985, A conceptual model for the origin of abnormally pressured gas accumulations in low-permeability reservoirs: AAPG Bulletin, v.69, p.1295-1304. Leverett, M.C., 1941, Capillary behavior in porous sands, Trans. AIME, 1941.
Gunter, G., et. al., 1999, Masters, J.A., 1984, ed., Elmworth - Case study of a deep basin gas field: AAPG Memoir 38, 316 p. Matinsen, R.S, 1994, Summary of published literature on anomalous pressures: implications for the study of pressure compartments, in Ortoleva, P.J. ed., AAPG Memoir 61, 1994. McCain, W.D., 1990, The Properties of Petroleum Fluids, 2nd Edition: Penwell Publishing Company, 548 p. Meissner, F.F, 1987, Mechanisms and patterns of gas generation/storage/explusion-migration/accumulation associated with coals measures in the Green River and San Juan Basins, Rocky Mountain. Region, USA, in Dolgigez, B., ed.,Migration of hydrocarbons in sedimentary basins:, 2nd IFP Exploration Research Conference, Carcias, France, June 15-19, 1987, Editions Technip. Paris, p. 79-112. Montgomery, S., 2000, East Texas Basin Bossier gas play in petroleum frontiers, Anderson, J., ed.: IHS Energy Group, Englewood CO (2000), p. 1-60.
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2002©K.E. Newsham and J.A. Rushing
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