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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 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 water saturation. This article presents results of a Bossier tight gas sand characterization study from which capillary pressure data indicated a very high connate water saturation distribution throughout the entire vertical column. Yet, these low-permeability Bossier sands produce at economically viable rates even though relative permeability measurements suggest these rates are not possible unless the initial water saturation is lower than that predicted by capillary equilibrium. We attribute this anomalous production behavior to the presence of a sub-capillary-equilibrium distribution of water saturation; i.e., an unusually low water saturation distribution that cannot be predicted by conventional capillary pressure analysis. 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 water saturation distribution. These observations are based upon consistent measurements obtained from several different techniques, including production performance analysis, reservoir fluid phase behavior, log evaluation, and both conventional and special core analyses. We provide a detailed description of the analysis techniques used in our study and discuss specific results which indicate an unusually low water saturation distribution. We also identify several mechanisms, including those associated with a basin-centered gas system, which may be responsible for the long-term desiccation or evaporation of the connate water saturation. Regional Geology and Depositional Environment
The Bossier sands are Late Jurassic in age and were deposited in the
A typical stratigraphic column for the 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 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 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 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 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 water. Initial water production rates, which range from 50 to 100 bbl/d for the first one to three months, can be attributed to clean-up of stimulation fluids. However, most wells produce between 1 to 5 bbl/day for the life of the well. Because of the low permeability of the Bossier sands, we do not believe a mobile liquid phase exists in the reservoir. The source of long-term water production is probably condensed water vapor. This observation seems to be confirmed by the low salinity of the produced waters. 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 water; however, we believe that no mobile liquid water phase exists in the reservoir. Laboratory analyses indicate that five to ten mole% of water vapor may be dissolved in the gas at reservoir conditions. Consequently, most of the low water production rate over a well’s life can be attributed to condensed water vapor.
Intrinsic
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
Petrographic
The petrographic 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
Hydraulic
We have also identified several Bossier sand hydraulic 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
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 Effective and Relative Permeability
Although we believe no mobile liquid phase exists in the Bossier sands at reservoir conditions, the presence of water does affect gas flow capacity. Consequently, we measured effective gas permeability for a range of water saturation. Figure 8 shows computed relative permeability curves for hydraulic
We also measured connate water saturation from more than 500 Bossier whole core plugs. Since the whole core was obtained with a low invasion, oil-base mud system, we were able to obtain consistent and accurate estimates of in-situ connate water saturation. We used the Dean Stark solvent extraction technique with toluene as the solvent. Most of the non-reservoir 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 water saturation distribution (Leverett, 1041; Gunter, 1999; Negabahn et al., 2000), range of irreducible water saturation, and capillary Reservoir Description Program to Quantify Water Saturation
To verify the low water saturations measured from the core plugs, we initiated a rigorous evaluation and validation program composed of three methods:
Core-Based Water Saturation Measurements
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 water saturation, we used an oil-base mud system. Properties of the oil-base mud included very low fluid loss as well as low surfactant energy. For most
Water saturation was measured directly with the Dean Stark solvent extraction process using toluene as the solvent. On the basis of more than 500 plugs, we observed water saturations ranging from as low as 5% in the best reservoir Log-Based Water Saturation Calculations We also computed the vertical distribution of water saturation in the same wells from which the core was obtained. The best match between core-based and log-based water saturation was obtained with the Modified Simandoux (1963) shaly sand model. Shale volume was estimated from the gamma ray response and porosity cross-plot techniques, while effective porosity was computed from a neutron-density cross-plot corrected for shale and gas effects. Application of the Modified Simandoux (1963) model also requires estimates of the Archie (1950) saturation exponent, n, and the cementation exponent, m. These parameters were measured in the laboratory using both two-and four-electrode resistivity devices. Core samples were saturated with a 220,000 ppm brine, and all measurements were made at initial reservoir conditions; i.e., 3500 psia net stress and temperature of 300oF. Results from both two- and four-electrode devices were in close agreement. The average values of m and n were 2.15 and 1.85, respectively. We also measured excess conductance using the Co/Cw method. Average corrected values of m* and n* were 2.2 and 1.87, respectively. The effect is minimized by the highly saline connate water. The final component required to compute connate water saturation is water resistivity, Rw, at reservoir conditions. Unfortunately, direct sampling and testing of the formation water is impractical in the Bossier sands in the Mimms Creek and Dew fields. Low permeability and the associated relative permeability curves suggest a mobile water phase is improbable. Initial water production is mostly fracturing fluids from the stimulation treatment, while water produced following fracture clean-up is probably condensed water of vaporization. This observation is based upon the relatively low salinities observed in the produced water. Consequently, we used commutation analysis and fluid inclusion micro-thermometry to estimate connate water salinity from core samples. Commutation or residual salt analysis is a process that extracts or leaches connate water and the associated salts from preserved core samples using ultra-pure, deionized water. Salt concentration and composition in the leachate are measured using an atomic absorption or mass spectrometer technique, while salinity is estimated from material balance calculations. Salinity measurements in the Bossier sands ranged from 200,000 to 230,000 ppm. Fluid inclusion micro-thermometry (FIT) uses thin sections from core samples to measure the temperature at which fluid inclusions melt. This melting temperature is directly related to the connate water salinity. Results from the FIT analysis ranged from 180,000 to 240,000 ppm, which is consistent with results from the commutation analysis. These results indicate the water resistivity ranges from 0.012 to 0.015 ohm-m at reservoir conditions.
In general, results from the log-based analysis agreed with water saturation estimates from the core measurements in the reservoir Capillary-Equilibrium-Based Water Saturation Calculations As we noted above, we also attempted to compute a vertical distribution of water saturation from capillary pressure characteristics to verify the apparent unusually low water saturations from the core and logs. We converted capillary pressures to height above free water and plotted them against water saturation. Our current understanding of the Bossier Sand geology in the Mimms Creek and Dew fields indicates the sands were deposited on a low-relief shelf/slope topography and appear to be laterally discontinuous. Under these conditions, the total relief is about 200 ft. Using this total column height, the computed range of irreducible water saturation is 35% to 100% for the reservoir rocks. This range, which is illustrated in Figure 11 as the dashed horizontal line, is significantly greater than the core-based measurements and log-based calculations, which ranged from 5% to 50% for the same reservoir-quality rocks.
Because of these discrepancies, our next step was to determine the column height required to match the range of water saturations determined from core and log analyses. Our calculations indicate an average total column height of 1000 ft is required to generate irreducible water saturations from 5% to 50% for Sub-capillary-Equilibrium Water Saturation Concept In summary, vertical distributions of core-derived measurements and log-derived calculations of water saturation cannot be matched with estimates from capillary pressure characteristics unless we make unrealistic assumptions about sand geology and structure, particularly column height. This observation suggests the vertical distribution of water saturation in the Bossier sands may not be in capillary equilibrium. In fact, measured water saturation is much lower than that which would be predicted by capillarity; i.e., a sub-capillary-equilibrium or sub-irreducible water saturation condition. We also observed an abnormally high capillary pressure profile associated with the low water saturations. Although not common in the petroleum industry, this phenomenon has been observed and documented in basin-centered gas systems (Swarbrick and Osborne, 1998; Law, 1984a, b; 1994; Law and Dickinson, 1985; Masters, 1979, 1984; Ryder et al., 1996; Nuccio et al., 1992; Matinsen, 1994; Spencer, 1987; Meissner, 1987). Possible Mechanisms for Sub-Capillary-EquilibriumWater Saturation Phenomenon
In this section, we present a hypothesis to explain the physical mechanisms and conditions that could cause the development of a sub-capillary-equilibrium, water saturation distribution. We also present a geological process model under which this phenomenon would most likely occur. Our model is discussed as part of a total petroleum systems genesis but within the context of a basin-centered gas accumulation. Attributes of basin-centered gas systems are summarized in Table 3. Note that the Bossier sands and shales exhibit most of the properties listed in Table 3.
Elements of our Petroleum System Process Model are presented in Figure 12. These elements - i.e., source
During all stages of shale diagenesis, hydrocarbons are frequently expelled from the shales and migrate into reservoir
The critical element in our model is a mechanism to remove connate water effectively and transport the water up the vertical section. It has been recognized that several mechanisms can remove connate water from reservoir Consequently, we have identified another mechanism for removing connate water. We believe the key element required to remove water effectively is the process of vaporizing connate water into the gas phase. Laboratory data suggests that, at temperatures exceeding 280oF to 300oF, significant volumes of water vapor may be dissolved in the hydrocarbon gas (McCain, 1990). Furthermore, the solubility of water vapor in gas is enhanced when non-hydrocarbon gases, such as CO2 and H2S, are present. We believe that most of the connate water displaced from the Bossier sands is in the form of water vapor dissolved in the hydrocarbon gas. Gas generated and expelled from the shales is dry (i.e., initially no dissolved water vapor). As long as hydrocarbon gases continue to migrate into the reservoir, we have a mechanism to continuously vaporize and effectively remove connate water. In addition, the effective shale permeability to gas is much greater than that for water, thus allowing gas to flow more readily.
The final element required to explain a sub-capillary-equilibrium water saturation distribution is related to the hydrocarbon generation potential of the shales. For very organic-rich shales, hydrocarbon generation and migration may continue for thousands of years. Furthermore, if hydrocarbon migration into the reservoir is still ongoing and if the migration rate exceeds the rate at which hydrocarbons are expelled, then the reservoir conditions will be dynamic (albeit at very slow rates) rather than static. In addition, this dynamic condition should be manifested by varying degrees of abnormally high pressure gradients. Under normal conditions, a vertical distribution of water saturation in capillary equilibrium (i.e., static conditions) suggests surface wetting or adhesion forces are exactly balanced by gravitational forces. If, however, we have an external source of energy (i.e., influx of gas from source We have documented an apparent sub-capillary-equilibrium water saturation distribution in the Bossier sands in the Mimms Creek and Dew fields, Freestone County, Texas. Our observations are based on consistent measurements and calculations from several different techniques and data sources. We have also postulated that the Mimms Creek and Dew fields may be part of a basin-centered gas system, and the mechanisms responsible for that system may have contributed to the unusually low water saturation distribution. We also believe that the Bossier sands in the Mimms Creek and Dew fields are not in capillary equilibrium. Finally, we have identified and provided evidence that water vaporization and dissolution in the hydrocarbon gas may be an effective mechanism for removing and transporting connate water up the vertical column. 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 water saturation. Archie, G.E., 1950, Introduction to petrophysics of reservoir rocks: AAPG Bulletin, v.34, p.943-961.
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2002©K.E. Newsham and J.A. Rushing
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