Grayburg Formation Research Articles

Seismic attribute and well-log analysis for channel characterization in the upper San Andres and Grayburg formations of the Midland Basin, Texas

The Permian Basin is one of the most prolific, and currently one of the most active, oil and gas basins in the USA. The Lower Permian strata in the Permian Basin have produced more than 14 billion barrels of oil (BBO), making it the largest volume of hydrocarbon in the basin. Sedimentation in the Midland Basin during late Leonardian through early Guadalupian (ca. 272–269 Ma) resulted in progradation of shelf edge and ultimately closure of the basin by Middle Permian time. We analyzed a merged seismic survey covering parts of the Permian Basin (i.e., Central Basin Platform and Midland Basin) in Andrews, Ector, and Midland Counties, Texas. The seismic survey and well logs show the presence of gently dipping (ca. 1°) clinoforms in the Upper San Andres and Grayburg Formations on the eastern edge of the Central Basin Platform and western Midland Basin. The seismic attributes, curvature, and spectral decomposition identify low sinuosity slope channels oriented north-south, but such channels do not appear beyond the slope. The shelf edge shifts from north to south during deposition of the Upper San Andres and Grayburg Formations. We identify five basinward shifts noted by the migration of the shelf edge toward the basin center and the presence of channel features along the depositional slope. The petrophysical analysis indicates that channels cut into carbonate rocks and are filled by siliciclastic sediments; this interpretation is supported by the most negative curvature anomalies along the channel axes caused by the differential compaction between the carbonate and siliciclastic rocks. There are a few channels with a northwest-southeast strike, which matches the direction of the Concho Lineament observed by satellite data. Such observations are consistent with previous interpretations of the northern Midland Basin closure during Middle-Late Permian time.

The impact of heterogeneous mixed siliciclastic–carbonate systems on CO 2 geological storage

Three different outcrops are selected in this study, each representing a shallow-marine system with varying heterogeneity provided by siliciclastic–carbonate mixing that may form a small or large stratigraphic trap. The impact of these styles of mixed facies on CO 2 storage is relatively poorly known. This study demonstrates the significance of these systems for safe CO 2 geological storage, as stratigraphic traps are likely to be a significant feature of many future storage sites. The three 3D models are based on: (1) the Grayburg Formation (USA), which displays spatial permeability linked to variations in the mixture of siliciclastic–carbonate sediments; (2) the Lorca Basin outcrop (Spain), which demonstrates the interfingering of clastic and carbonate facies; and (3) the Bridport Sand Formation outcrop (UK), which is an example of a layered reservoir and has thin carbonate-cemented horizons. This study demonstrates that facies interplay and associated sediment heterogeneity have a varying effect on fluid flow, storage capacity and security. In the Grayburg Formation, storage security and capacity are not controlled by heterogeneity alone but are influenced mainly by the permeability of each facies (i.e. permeability contrast), the degree of heterogeneity and the relative permeability characteristic of the system. In the case of the Lorca Basin, heterogeneity through interfingering of the carbonate and clastic facies improved the storage security regardless of their permeability. For the Bridport Sand Formation, the existence of extended sheets of cemented carbonate contributed to storage security but not storage capacity, which depends on the continuity of the sheets. These mixed systems especially minimize the large buoyancy forces that act on the top seal and reduce the reliance of the storage security on the overlying cap rock. They also increase the contact area between the injected CO 2 and brine, thereby promoting the CO 2 dissolution processes. Overall, reservoir systems with mixed carbonate–siliciclastic facies contribute to improving the safe and effective storage of CO 2 . Thematic collection: This article is part of the Geoscience for CO 2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage

Seismic chronostratigraphy at reservoir scale: Lessons from a realistic seismic modeling of mixed clastic-carbonate strata in the Permian Basin, West Texas and New Mexico, USA

We tested the validity of tracking seismic events as representations of chronostratigraphic surfaces at the subseismic, high-frequency-cycle level. A high-resolution geocellular model was generated from approximately 400 m of mixed clastic-carbonate sequences in the San Andres and Grayburg Formations in the Permian Basin, with 0.3–0.6 m layering and minimal upscaling. Realistic stratigraphic framework, facies, and velocity volumes were created by geostatistically mapping data from outcrop and subsurface sources while honoring state-of-the-art principles of stratigraphic and sedimentary analyses. Using the synthetic seismic data of different frequencies, the potential and pitfalls of using autotracked seismic horizons in building high-resolution reservoir models were tested. At the reservoir (meter) scale, the seismic reflections from flatter and thicker sediments with less facies and velocity heterogeneities tend to follow geologic-time surfaces; on the contrary, reflections from where thin sediments dip against flat strata with more facies and velocity heterogeneities tend to follow lithostratigraphy. For the latter seismic-guided reservoir modeling is not very precise, even with data as high as 140 Hz frequency. Therefore, for seismic-assisted reservoir prediction and modeling, the interpretation of seismic events is useful, but well calibration is critical.

Improving three-dimensional high-order seismic-stratigraphic interpretation for reservoir model construction: An example of geostatistical and seismic forward modeling of Permian San Andres shelf–Grayburg platform mixed clastic–carbonate strata

The three-dimensionally complex, highly progradational mixed siliciclastic–carbonate strata of the San Andres and Grayburg Formations have long been the backbone of conventional hydrocarbon reservoir production from the Permian Basin, and significant recovery continues via waterflooding and CO2 injection. Besides, nonreservoir equivalents of these formations have recently taken increasing significance as produced water disposal targets. However, seismic-stratigraphic interpretations are challenged by complex internal shelfal-stratal geometries and numerous laterally continuous but vertically thin fluid barriers in overlying platforms. We built a three-dimensional (3-D) geocellular model of Guadalupian 8–13 high-frequency sequences (G8–G13 HFSs) and then conducted forward seismic modeling (35-Hz 0° phase). This allows investigations on the validity of applying conventional reflection-geometry–based interpretation to delineate the G9 HFS top and base, which can potentially serve as bounding/constraining surfaces for upper San Andres shelf–Grayburg platform reservoirs. This study contributes to 3-D modeling methodologies by introducing a query tree to select geostatistical methods for modeling dual-scale heterogeneities and by integrating data from diverse sources for seamless and realistic 3-D models. Our seismic-stratigraphic evaluation demonstrates that conventional reflection–geometry-based interpretation does not adequately resolve the G9 top and base; deviations from the geocellular model reach up to 80 m (260 ft) and are thus well beyond the maximum acceptable error limits of ±0.5 wavelength. We suggest improving conventional interpretations of the G9 base by selective interpolation or mixed-polarity event picking near the error-prone shelf margin and upper slope. Besides, instead of picking the highly discontinuous seismic peak as G9 top, bulk-shifting of a shallower trough horizon near actual G10 top should deliver a more accurate surface representing G9 top.

Outcrop Analog for Mixed Siliciclastic-Carbonate Ramp Reservoirs--Stratigraphic Hierarchy, Facies Architecture, and Geologic Heterogeneity: Grayburg Formation, Permian Basin, U.S.A.

Abstract The Grayburg Formation (Late Permian, Guadalupian) is a shallow-marine succession flanking the Delaware and Midland basins of Texas and New Mexico, U.S.A. The Grayburg exemplifies the facies heterogeneity imparted by cyclic interbedding of siliciclastic and carbonate rocks from lithologically diverse, inner-ramp to outer-ramp facies assemblages. High-resolution correlation and mapping of laterally continuous Grayburg strata exposed in the Brokeoff Mountains, New Mexico, allow the stratigraphic architecture, facies distribution, and lateral variability to be characterized in detail. This study provides an outcrop analog for stratigraphically equivalent subsurface reservoirs and comparable carbonate-ramp reservoirs that accumulated during periods of low-amplitude sea-level fluctuations. Vertical and lateral facies successions in the Grayburg record four hierarchical scales of cyclicity. The entire Grayburg is a composite sequence that initiated with transgression of the San Andres platform and culminated with subaerial exposure, followed by a major basinward shift in deposition. This third-order cycle contains four high-frequency sequences defined by transgressive outer-ramp facies overlain by aggradational ramp-crest to inner-ramp facies capped by an unconformity. Each high-frequency sequence contains several composite cycles, intermediate-scale cyclic successions. The high-frequency (fifth-order) cycles constitute the smallest-scale upward-shoaling facies successions that can be recognized and mapped, comprising the basic correlation entity to delineate lithofacies bodies. Lateral heterogeneity in the Grayburg reflects both systematic facies transitions and interwell-scale (meters to hundreds of meters) variability due to geologic complexity. Larger-scale systematic facies changes that reflect primary environmental and/or depositional controls (e.g., water depth, platform position, accommodation trends) can be characterized using well and/or seismic data abetted by appropriate depositional models. Interwell heterogeneity due to geologic complexity, however, is difficult to recognize from subsurface datasets. Appropriate outcrop analogs provide information on lateral facies dimensions and heterogeneity architecture that is essential for constructing more realistic three-dimensional reservoir models, rather than oversimplified models based on lithofacies correlations forced between wells by linear interpolation. An understanding of geologic heterogeneity exhibited in outcrop analogs is crucial for geoscientists involved with characterizing and modeling subsurface heterogeneity.

Distribution of porosity and permeability in platform dolomites: Insight from the Permian of west Texas (Discussion & Reply)

Saller and Henderson (1998) presented an article concerning porosity and permeability variations in two west Texas oil fields (North Riley and South Cowden fields). These fields occur within dolomitized Permian platform carbonates near the basinward shelf edge of the Central Basin platform, a paleogeographic element that influenced Permian deposition in west Texas. Their carefully documented study outlines several anomalous aspects concerning porosity distribution. They noted, in particular, that porosity distribution is not strictly facies dependent but that porosity tends to increase in a basinward direction. They suggested that porosity developed largely during dolomitization by the action of hypersaline evaporative fluids that flowed downdip in a basinward direction during the Permian. These brines were generated in restricted shelf interior lagoons and moved downdip parallel with bedding in a shallow reflux type of hydrologic system driven by subsurface fluid density differences in the Permian Clear Fork and Grayburg formations, as shown here in Figure 1 (see figure 18 in Saller and Henderson [1998]). Figure 1 Part A shows the scenario proposed by Saller and Henderson (1998) for porosity creation, dolomitization, and dolomite cementation of the Permian Clear Fork and Grayburg formations of west Texas. They suggested that macrodissolution of calcium carbonate occurred contemporaneously with dolomitization and dolomite cementation. This process of brine backreaction, however, would cause a net increase of porosity in the shelf interior, the opposite of what is observed. Part B shows a two-stage scenario proposed here to circumvent the problem of limestone macrodissolution by shelf interior brines that must have been initially in approximate bulk equilibrium with calcium carbonate. The first stage records dolomitization by replacement of limestone with little macrodissolution. In stage two, evaporative shelf interior brines may have evolved in equilibrium with dolomite only and became undersaturated with calcite and aragonite. Reflux migration of these brines downdip may …

Mitigation of asphaltics deposition during CO2 flood by enhancing CO2 solvency with chemical modifiers

CO2 injected in the reservoir of McElroy Field, TX, for a CO2 flood was in the supercritical state. Supercritical CO2 fluid is capable of extracting light and intermediate hydrocarbons from rocks but is unable to extract heavy hydrocarbons and asphaltics. Therefore, plugging of asphaltics in reservoir rocks and a consequent reduction in injectivity and recovery may result when CO2 only is used in enhanced oil recovery. By adding common solvents as chemical modifiers, the flooding fluid shows marked improvement in solvency for heavy components of crudes due to its increased density and polarity. Numerous supercritical CO2 fluid extractions of dolomite rock from the Grayburg Formation containing known amount of spiked McElroy crude oil have been carried out to evaluate extraction efficiencies of CO2 and CO2 with chemical modifiers at various temperatures and pressures. All experiments show that extraction efficiency increases with increasing CO2 pressure but decreases with increasing temperature. Addition of chemical modifiers to CO2 also shows improved extraction efficiency and reduced asphaltic deposits. Under the pressure and temperature similar to McElroy reservoir conditions; chemically modified CO2 yielded almost 3 times as much oil extracts as those in extractions with CO2 only. It also reduced the asphaltics content in extracted rocks to nearly one half; indicating its potential for mitigating asphaltics plugging of formation rocks

Modeling a Vuggy Carbonate Reservoir, McElroy Field, West Texas

The McElroy field produces approximately 17,000 BOPD (barrels of oil per day) under a mature waterflood from the Permian Grayburg Formation. The main pay zone in the reservoir is primarily peloidal dolograinstones/packstones with interparticle/intercrystalline porosities. The central portion of the field is more heterogeneous because of thin high-porosity and high-permeability vuggy zones. The occurrence of these zones is confirmed by core description and measurements, porosity logs, tracer studies, and injectivity measurements. These thin high-porosity and high-permeability vuggy zones diminish waterflood effectiveness and leave millions of barrels of bypassed oil in the lower permeability matrix. A method was developed to identify the vuggy zones on logs, create geostatistical models of porosity and permeability incorporating the vuggy zones, and characterize them in simulation models. The methodology involved the following: (1) developing a log trace to identify zones of high secondary porosity, mainly vuggy porosity, in the area of the field that was modeled, (2) creating a detailed geostatistical model (1 million cells) of total porosity using well-log data, (3) creating a geostatistical permeability model based on total porosity, (4) creating a separate detailed geostatistical model of secondary porosity, and (5) superimposing exceptionally high permeability in areas of the permeability model defined by high secondary porosities. The detailed permeability models were scaled-up to 12,000-cell models for simulation studies. The models incorporating vuggy permeability distributions showed a far superior history match of primary and waterflood processes than did models that did not incorporate vuggy permeability; these models also showed good-quality history matches for individual wells. Successful history matching of the simulation models validates our method and indicates that core data underestimate the permeability of vuggy zones due to sampling and measurement issues.

Effect of CO 2 flood on geochemistry of McElroy oil

Geochemical characterization has been completed on a series of oil samples collected over time from the McElroy Field, Texas, where a pilot CO 2 flood project was initiated a few years ago. A non-waxy, 31 gravity ( oAPI) oil is produced from carbonate reservoirs within the Permian Grayburg Formation. The samples were taken from various wells over a time span of one and one half years for monitoring changes in oil composition induced by CO 2 injection over time. The oil samples taken from about 40 wells shortly after the start of CO 2 injection showed a marked reduction (∼50%) in the asphaltene content, indicating CO 2-induced asphaltene deposition had occurred. Mapping asphaltene reduction could provide information on the flow direction of CO 2 in the reservoir. Hydrocarbon profiles of the oils from some wells also showed a significant reduction in the heavy paraffin content (i.e. > C 25), suggesting deposition of heavy hydrocarbons within the reservoir. The observation of a slight increase in oil API gravity is also consistent with precipitation of heavy components from the oil phase due to CO 2 injection. The organic deposits (or flocs) which can cause restriction of fluid flow in the reservoir by reducing porosity and permeability have probably contributed to reduction in injectivity experienced by some injection wells shortly after the start of CO 2 injection. Field observations have been duplicated in laboratory core flood experiments to mimic the field recovery process. The experiments show that most of heavy organics were deposited near the CO 2 injection port, suggesting organic deposition in the field occurs near the injection wells rather than producing wells. Despite the continued CO 2 flood, some molecular properties such as sterane and hopane distributions remain relatively unchanged. These geochemical parameters are commonly derived from ratios of compounds with similar molecular properties and are generally not affected by the CO 2 flood as precipitation of heavy hydrocarbons causes little fractionation among these compounds. Thus, oil samples from fields under the gas flood are still viable for correlation, source evaluation and maturity determination.

Facies Architecture of Ooid Grainstone-Dominated Cycles In a Sequence Stratigraphic Framework: Grayburg Formation, New Mexico : ABSTRACTS

Facies Architecture of Ooid Grainstone-Dominated Cycles In a Sequence Stratigraphic Framework: Grayburg Formation, New Mexico : ABSTRACTS

Abstract :Dynamic Facies Models Linked To Stratigraphic Hierarchy: Grayburg Formation (Guadalupian), Brokeoff Mountains, New Mexico

Abstract :Dynamic Facies Models Linked To Stratigraphic Hierarchy: Grayburg Formation (Guadalupian), Brokeoff Mountains, New Mexico

Stratigraphlc Hierarchy and Cycle Stacking, Facies Distribution, and Interwell-Scale Heterogenelty: Grayburg Formation, New Mexico: ABSTRACT

The Grayburg Formation (middle Guadaluplan) of southeastern New Mexico is a mixed carbonate-siliciclastic succession that represents predominantly shallow water sedimentation on the Northwest Shelf of the Delaware Basin. Exceptional Grayburg outcrops in the Brokeoff Mountains permit high-resolution correlation and mapping of interwell-scale facies complexity both along depositional dip and across strike. Three orders of stratigraphic hierarchy are recognized using vertical facies successions and transgressive-regressive relationships expressed along a dip cross section. This stratigraphic organization cannot be fully defined from a vertical section. Cycles (3-30 ft thick) are the smallest-scale, upward-shoaling facies successions that can be correlated across facies tracts and constitute the basic chronostratigraphic unit. Cycles are organized into transgressive-regressive cycle sets (15-40 ft thick). High-frequency sequences (100-160 ft thick) are unconformity-bound successions composed of 10 to 20 cycles arranged into transgressive and highstand systems tracts. One-dimensional cycle thickness stacking patterns do not reflect the long-term accommodation trends imposed by high-frequency sequences because most cycles did not fully aggrade to sea level. Interwell-scale heterogeneity (hundreds of ft) is high in transgressive ooid grainstones, which formed dip-elongate tidal channels and shoals. Highstand ooid grainstones formed strike-elongate shoals that are laterally continuous along dip and across strike (thousands of feet) due tomore » stacking and amalgamation of grainstone bodies in an accommodation-limited highstand setting. The well-defined relationship between stratigraphic hierarchy and facies composition and heterogeneity can be used to improve correlations and better predict lateral dimensions of reservoir facies.« less

Diagenetic Overprint of Original Depositional Architecture in a Shallow Water Carbonate Reservoir, Permian Basin, Texas: ABSTRACT

Permian shallow-water carbonate reservoirs are highly heterogeneous because of complex variations in depositional facies produced by high-frequency sea level rise and fall. Accordingly, establishment of a cycle stratigraphic framework is fundamental to defining reservoir heterogeneity. Because nearly all of these reservoirs have experienced multiple episodes of dolomitization and sulfate emplacement, however, permeability is a n of diagenetic overprint. The extent to which diagenesis can affect permeability development is dramatically displayed in the Grayburg Formation (middle Permian) at South Cowden field, Weit Texas. Three scales of cyclicity contribute to original depositional facies heterogeneity in the Grayburg; high-frequency cycles, averaging 3 meters in thickness, constitute the fundamental architectural element in the main reservoir interval. Despite original depositional heterogeneity due to this cyclicity, however, permeability development is substantially the result of two diagenetic events: (1) dolomite diagenesis in vertically burrowed wackestones and packstones and (2) late alteration and removal of anhydrite. Dolomite diagenesis in vertically burrowed wackestones and packstones has produced irregular vertical zones of higher permeability in mud-dominated bases of high-frequency cycles in leeward ramp-crest highstand successions. Because dolomite diagenesis is concentrated in burrowed highstand successions, the distribution of resultant permeability trends is partly constrained by patterns of longterm accommodation and highmore » frequency cyclicity. Anhydrite diagenesis, which is characterized by conversion to gypsum or by complete removal of sulfate, is developed along basinward margins of the field and cross cuts original depositional framework.« less

Carbonate Sequence Stratigraphy on the Development Geology Scale: Outcrop and Subsurface Examples from the Permian Grayburg Formation, Permian Basin: ABSTRACT

Carbonate Sequence Stratigraphy on the Development Geology Scale: Outcrop and Subsurface Examples from the Permian Grayburg Formation, Permian Basin: ABSTRACT

Sequence Stratigraphic Relationships of the Grayburg Formation, Midland Farms and Foster Fields, Central Basin Platform, West Texas

Sequence Stratigraphic Relationships of the Grayburg Formation, Midland Farms and Foster Fields, Central Basin Platform, West Texas

Role of Sequence Stratigraphy in Reservoir Characterization and Solving Waterflood Production Problems, Grayburg Formation (Permian-Guadalupian), Eunice Monument South Unit, Lea County, New Mexico

The Grayburg Formation was deposited upon a carbonate ramp as shallowing-upward fifth-order parasequences of interbedded carbonates (dominant) and siliciclastics (subordinate). Sandstones were deposited as offshore shallow-marine blankets, and form some but not all parasequence bases. Seaward, carbonates were deposited as ooid grainstones/mud-poor packstones in a high-energy shoal complex. Landward, carbonates are mud-rich packstones/wackestones that were deposited in a low-energy back-shoal environment. Reservoir-quality porosity (grainstones/mud-poor packstones) is preserved and enhanced by (1) depositional controls, such as bed thickness, grain richness, and grain size; (2) dissolution during subaerial exposure; (3) dolomitization (early diagenesis); and (4) dissolution during deep burial (late diagenesis). Thinner bedded, mud-rich packstones/wackestones contain lower reservoir porosity updip, and eventually form a stratigraphic trap. Using reservoir characteristics and outcrop studies, and applying sequence stratigraphic interpretation have enhanced reservoir management during initial waterflood and reservoir fill. Early water breakthrough occurred in EMSU well 119. Here, a high-porosity high-permeability bed within one parasequence was connected with EMSU injection well 108. Once reservoir connectivity was understood the flow unit in well 119 was squeezed off. The injection well immediately built up pressure and redirected the waterflood. Later, an oil bank arrived at EMSU well 109, another offset producer.

Geological/Stochastic Mapping of Heterogeneity in a Carbonate Reservoir

Summary Two major problems in estimating interwell porosity and permeabilitypatterns are estimating permeability patterns are estimating permeabilityprofiles in uncored wells permeability profiles in uncored wells andinterpolating wellbore information between wells. A technique combining coreanalysis, rock fabrics, and wireline logs was used to estimate permeabilityvalues at 1 -ft intervals permeability values at 1 -ft intervals in 32 wells inSection 15 of the Dune field. Stochastic geologic interpolation was generatedwith a geostatistical method known as conditional simulation. Simulation ofwaterflooding showed that the stochastic realizations with a low degree ofcontinuity gave the most realistic results. Infill drilling to achieve anaverage well spacing of 2.5 acres increased recovery by 27 to 32%. Introduction San Andres and Grayburg reservoirs in the Permian Basin originally contained35 Permian Basin originally contained 35 billion bbl of oil in place and haveproduced about 10 billion bbl in the last 40 to 50 years. Current productionoperations will produce an additional 5 billion bbl, The remaining 20 billionbbl is divided into residual (immobile) and mobile oil. Residual oil is definedhere as oil trapped in the reservoir by capillary and viscous forces; it is thevolume of oil remaining in a rock swept by waterflood. Mobile oil is the oilthat can be moved by waterflood or by improved connection to a wellbore throughinfill drilling or other techniques. A multidisciplinary, integrated reservoirstudy of the Dune Grayburg reservoir in Crane County, TX, located about 13million bbl of remaining mobile oil in Section 15 of University Block 30. Onezone, Zone MA, contains 9 million bbl, with most of the oil located within anarrow belt through the middle of the section. This paper describes the 3Dspatial distribution of porosity, permeability, and saturation in Section 15. Use of these data in a reservoir simulator allowed prediction of the effect ofinfill drilling on oil recovery. Current methods of estimating oil recoveryfrom waterflooding are based on either pay continuity or the influence ofvertical stratification. George and Stiles assumed that the percentage of theformation that can be flooded is approximately equal to the pay continuity, which is defined as the fraction of total pay of one well connected to another. This approach uses well-to-well correlations and a cutoff porosity to definepay continuity and, therefore, cannot adequately describe the permeabilityheterogeneity between wells. The Dykstra-Parsons method assumes a verticallystratified reservoir with no lateral discontinuities. Numerous field studiesand infill-drilling programs, however, have demonstrated the significance oflateral discontinuities in reservoirs. This study uses geostatistical methodsconditioned by wellbore data to generate realistically complex interwellpatterns of heterogeneity that are critical to oil recovery. Dune Field Dune field is located in Crane County, TX, on the east side of the CentralBasin Platform (Fig. 1) and produces from the Platform (Fig. 1) and producesfrom the Grayburg formation of early Guadalupian (Upper Permian) Age. The fieldproduces from a Permian) Age. The field produces from a 200-ft-thick pay zoneat an average depth of 3,300 ft. Well spacing varies from 10 to 20 acres. Section 15 is currently drilled on 10-acre spacing. Water injection in Section15 was initiated in Well 1530 in 1976. Since 1980, the number of wellsconverted to injectors has steadily increased to 27 injectors in 1987. Thereservoir interval is divided into zones on the basis of quartz silt markersthat can be identified from gamma ray logs. In Section 15, the uppermostreservoir zone is Zone CZ, which is composed of pellet grainstone andpackstone. The next two zones, in descending order, the Zones BC and AB, whichconsist of fusulinid wackestone/ packstone. The lowest producing zone, the zonepackstone. The lowest producing zone, the zone of primary interest in thisstudy, is Zone MA, which is composed of a crinoidal packstone/grainstone faciesgrading laterally packstone/grainstone facies grading laterally into acrinoidal wackestone. Reservoir Characterization Reservoir characterization is the description of the 3D spatialrelationships of petrophysical parameters for the purpose of petrophysicalparameters for the purpose of improving recovery from oil and gas reservoirs. The petrophysical parameters of interest in the Dune study are porosity, permeability, and oil saturation. The characterization is conducted by firstdetermining the petrophysical values in the wellbores and then petrophysicalvalues in the wellbores and then interpolating these values betweenwellbores. Petrophysical Data From Borehole Petrophysical Data From BoreholeInformation. Porosity data were obtained from cores and wireline logs for theDune reservoir-characterization study. Saturation data were obtained from loganalysis; no capillary pressure curves were available. Permeability data wereobtained from core Permeability data were obtained from core material andrelated to wireline-log response by use of the rock-fabric method; no pressuredata were available. pressure data were available. JPT P. 1298

Outcrop Analogs for Modeling Heterogeneous Restricted Platform Reservoirs: Grayburg Formation (Guadalupian) of the Guadalupe Mountains and Subsurface Permian Basin: ABSTRACT

Restricted platform deposits of the Permian basin have produced more than 10 billion bbl of oil, but because of complex internal facies architecture ultimate recovery rarely exceeds 30% of original oil in place. The first step in locating and exploiting the substantial unrecovered hydrocarbons in this play is developing improved development-oriented (as opposed to exploration-oriented) models of facies/permeability heterogeneity. Quantitative geologic/engineering analysis of outcrops analogous to reservoirs allows characterization of styles of variability and three-dimensional geometry at interwell, reservoir, and play scales beyond that possible using limited subsurface data. The Guadalupian Grayburg Formation is exposed in the northern Guadalupe Mountains less than 60 mi west of reservoir trends on the Northwest Shelf and Central Basin platform. These outcrops provide a test for the development of outcrop-based reservoir heterogeneity models. A 10-mi dip section of the mixed siliciclastic/carbonate Grayburg of the Guadalupes exhibits inner ramp (4-mi dip width), ramp-crest ooid shoal/tidal flat (4 mi dip width), and outer ramp fusulinid-peloid (2-mi dip width) facies tracts. Maximum facies heterogeneity occurs in upward-shallowing cycles of the ramp crest where porous ooid shoals pass laterally into tight peloid packstones in less than 1,000 ft. Siliciclastic sands are intercalated in all facies tracts typically asmore » sheets. However, in the ramp crest they also occur as 15-ft-thick by 50-ft-wide channels dissecting ooid shoals. Grayburg reservoirs on the eastern side of the Central Basin platform contain facies tracts and styles of heterogeneity analogous to the outcrop. Production trends from these reservoirs similarly illustrate most variability in grainstone shoal complexes.« less

Heterogeneity in Grainstone Reservoirs--Investigation of a Modern Analog, Joulters Cays, Bahamas: ABSTRACT

Skeletal. peloidal, and ooid grainstones form major carbonate reservoirs for hydrocarbons throughout the world. Reservoirs in the San Andres and Grayburg formations of the Permian basin provide excellent examples of this reservoir type. Subsurface and outcrop studies have documented extreme permeability variability within thin grainstone units of shoallng cycles that occur within these foundations. The Joulters Cays ooid shoal, located north of Andros Island, Great Bahamas Bank, is the most thoroughly documented modern carbonate sand complex. But even at Joulters, the core spacing of previous studies was approximately one core per square mile, which does not approach the sc le needed to address most problems of interwell heterogeneity. Using the existing regional core framework as a guide, a detailed coring program with well spacing approximating that in mature oil reservoirs (between 20 and 40 ac/well) was undertaken to examine the sediment variation and early diagenesis within some subenvironments of the active shoal. Cores and box cores taken at Joulters are dominantly clean ooid sands (grainstones) with minor muddy sands (packstone). However, changes in depositional style across the shoal and the effect of these changes on the preserved texture are of particular significance. Variations in the penetration of resin through boxmore » cores suggest greater permeability differences that are related to minor changes in grain size. These differences are most evident within graded units of spillover-lobe cross stratification on the bankward side of the shoal. Parallel-laminated seaward-dipping units show less variation. Cemented zones (hardgrounds), ranging up to at least 1 m{sup 2} in extent, also may contribute to the permeability heterogeneity. These types of subtle depositional and early diagenetic fabrics influence subsequent diagenesis and resultant permeability variations in grainstone reservoirs.« less

Dolomite, Gypsum, and Anhydrite in Permian McElroy Field, Central Basin Platform: Genetic and Spatial Relationships to Facies Tracts, Cyclicity, Structure, and Pay Zones?: ABSTRACT

The Permian McElroy field at the eastern margin of the Central Basin platform is part of the giant P.J.W.D.M. field complex. Oil production occurs mainly from the Grayburg Formation, which consists of at least four and possibly five internal sedimentary cycles. Trapping is facilitated by a combination of structure (asymmetrical anticline) and a seal of fine-grained peritidal and supratidal dolostones plugged and overlain by gypsum and anhydrite. Although most oil is located close to the top of the structure, the gross pay zone appears to be subdivided into smaller irregularly shaped pods. The geometry and degree of interconnection of these pods are difficult to predict and may be related to the internal cyclicity as well as to diagenesis and structure. Dolomitization largely enhanced and emplacement of sulfates largely reduced the reservoir quality. Data suggest subhorizontal fluid flow in at least one part of the field during dolomite formation or recrystallization from gypsum-saturated brines. Sulfur and oxygen isotope data of the sulfates scatter from 10.0 to 12.5 /per thousand/ CDT and 10.0 to 14.3 /per thousand/ SMOW, respectively, suggesting precipitation from Late Permian brines and later recrystallization and redistribution accompanied by oxidation of bacterial sulfide, minor mixing with older or youngermore » sulfate, equilibration of isotopically heavier formation waters, or a combination thereof.« less