McElroy Field Research Articles

Applications of boundary-preserving seismic tomography for delineating reservoir boundaries and zones of CO2 saturation

Delineating reservoir units is still a challenge for seismic approaches. Even high-resolution crosswell tomographic approaches that produce smooth velocity models to match traveltime data usually provide limited information about the boundaries of subsurface targets. A recent development of seismic traveltime tomography incorporated with a boundary-preserving regularization constraint promisingly helps to resolve ambiguities in reservoir boundaries, while allowing lateral variations. We applied a kind of boundary-preserving traveltime tomography to delineate boundaries of the reservoir and [Formula: see text]-saturated zones. We chose the minimum gradient support as the regularization to preserve boundaries of the geologic target by penalizing smaller model gradients and smoothing small model variations caused by noise. We evaluated several synthetic and real data applications. Synthetic examples demonstrated that the boundary-preserving algorithm produced improved recovery of the profile shape and velocity values of the blocky targets. Two real applications were for delineating the top and base of the reservoir in the King Mountain field, and for delineating a [Formula: see text]-saturated zone in the McElroy field. These inversion results suggested that the boundary-preserving inversion is able to provide better delineation of the top and base boundaries of the reservoir and boundaries of the [Formula: see text]-saturated zone than the conventional smooth-constrained inversion.

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.

Seismic monitoring of a CO2 flood in a carbonate reservoir: A rock physics study

A carbon dioxide (CO2) injection pilot project is underway in Section 205 of the McElroy field, West Texas. High‐resolution crosswell seismic imaging surveys were conducted before and after CO2 flooding to monitor the CO2 flood process and map the flooded zones. The velocity changes observed by these time‐lapse surveys are typically on the order of −6%, with maximum values on the order of −10% in the vicinity of the injection well. These values generally agree with laboratory measurements if the effects of changing pore pressure are included. The observed dramatic compressional ([Formula: see text]) and shear ([Formula: see text]) velocity changes are considerably greater than we had initially predicted using the Gassmann (1951) fluid substitution analysis (Nolen‐Hoeksema et al., 1995) because we had assumed reservoir pressure would not change from survey to survey. However, the post‐CO2 reservoir pore fluid pressure was substantially higher than the original pore pressure. In addition, our original petrophysical data for dry and brine‐saturated reservoir rocks did not cover the range of pressures actually seen in the field. Therefore, we undertook a rock physics study of CO2 flooding in the laboratory, under the simulated McElroy pressures and temperature. Our results show that the combined effects of pore pressure buildup and fluid substitution caused by CO2 flooding make it petrophysically feasible to monitor the CO2 flood process and to map the flooded zones seismically. The measured data show that [Formula: see text] decreases from a minimum 3.0% to as high as 10.9%, while [Formula: see text] decreases from 3.3% to 9.5% as the reservoir rocks are flooded with CO2 under in‐situ conditions. Such [Formula: see text] and [Formula: see text] decreases, even if averaged over all the samples measured, are probably detectable by either crosswell or high‐resolution surface seismic imaging technologies. Our results show [Formula: see text] is sensitive to both the CO2 saturation and the pore pressure increase, but [Formula: see text] is particularly sensitive to the pore pressure increase. As a result, the combined [Formula: see text] and [Formula: see text] changes caused by the CO2 injection may be used, at least semiquantitatively, to separate CO2‐flooded zones with pore pressure buildup from those regions without pore pressure buildup or to separate CO2 zones from pressured‐up, non‐CO2 zones. Our laboratory results show that the largest [Formula: see text] and [Formula: see text] changes caused by CO2 injection are associated with high‐porosity, high‐permeability rocks. In other words, CO2 flooding and pore pressure buildup decrease [Formula: see text] and [Formula: see text] more in high‐porosity, high‐permeability samples. Therefore, it may be possible to delineate such high‐porosity, high‐permeability streaks seismically in situ. If the streaks are thick enough compared to seismic resolution, they can be identified by the larger [Formula: see text] or [Formula: see text] changes.

Geologic Investigation of Cross-Well Seismic Response in a Carbonate Reservoir, McElroy Field, West Texas

Cross-well seismic data from McElroy field, a Permian dolomite reservoir in west Texas, demonstrate that high-resolution velocity and reflection images are obtainable in this carbonate reservoir. Our geologic ground-truthing results suggest that cross-well data, when integrated with porosity models based on log facies, add value to reservoir characterization. The cross-well data added information at the interwell scale that we could get no other way. Reservoir quality in the portion of McElroy field that we investigated does not obviously relate to core-based lithofacies due to a complex diagenetic overprint, primarily cementation by gypsum and anhydrite. The coincidence of S-wave reflections on the cross-well data with decreases in porosity or gypsum cement from whole-core analysis suggests that total porosity and mineralogy dominantly influence velocity. Overall, the vertical location of layers generated by reflection imaging correlates fairly well with major log variations. In particular, positive events on the S-wave images correspond almost exactly with increases in sonic velocity, increases in resistivity, increases in bulk density, and decreases on the neutron porosity log from high porosity (or gypsum) to low porosity (or gypsum). Both the log and cross-well data respond to the same diagenetic overprint and its resulting petrophysical characteristics; therefore, we group log data into log facies using multivariate statistical techniques, such as cluster analysis, rather than using core data for correlating reservoir flow units and relating them to the cross-well images. Many of the positive-amplitude events on the S-wave profiles correspond to transitions, in a vertical sense, between the best reservoir cluster and less porous reservoir clusters, which indicates the strong relationship between velocity and porosity. In addition, lateral variations in many of the positive-amplitude events can be tied to changes in porosity and differences in the clusters between the wells. Comparing geostatistical porosity models directly to the S-wave images suggests that the S-wave reflection images appear to be resolving lateral changes in porosity of less than 56 m (185 ft) but more than 15 m (50 ft).

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.

Elastic wave equation traveltime and waveform inversion of crosswell data

A method is presented for reconstructing P‐ and S‐velocity distributions from elastic traveltimes and waveforms. The input data consist of crosswell hydrophone records generated by a piezoelectric borehole source. Borehole effects are partially accounted for by using a low‐frequency Green's function to simulate the pressure generated in the fluid‐filled receiver well. The tube waves in the borehole are ignored, on the assumption that they can be removed from the field data by median filtering. In addition, the source‐radiation pattern is partially taken into account by inverting for the equivalent stress components acting on the earth at the source location. The elastic wave equation traveltime and waveform inversion (WTW) method is applied to both synthetic crosswell data and the McElroy field crosswell data. As predicted by theory, results show that elastic WTW tomograms provide a sharper interface image than delineated in the traveltime tomograms. The spatial resolution of the McElroy traveltime tomogram is about 20 m compared to about 3 m and 1.5 m, respectively, for the associated P‐ and S‐velocity WTW tomograms. From these tomograms, detailed porosity maps of the interwell geology are constructed. There is a very good correlation between the P‐velocity tomograms and the P‐velocity log profiles, and there is a good correlation between the smooth parts of the S‐velocity tomogram and the S‐velocity logs. Unfortunately, the high‐wavenumber parts of the S‐velocity tomograms do not correlate well with the high‐wavenumber parts of the S‐velocity logs. We believe this problem is partly caused by not taking into account attenuation effects in the WTW algorithm.

Three Dimensional Visualization Of Geostatistical Models In The McElroy Field Of West Texas: ABSTRACT

The 3-D visualizations of geostatistical models have proved useful in identifying stratigraphic variations that affect oil production in the McElroy field of west Texas. Traditionally these models have been viewed using vertical and horizontal slices but by viewing the model in [open quotes]3-D[close quotes] subtle, and not so subtle, features related to the stratigraphic complexity of the reservoir are much more apparent. Even those of us who claim that we can [open quotes]think in three dimensions[close quotes] have been surprised at how much more we can [open quotes]see[close quotes] when we are presented with a 3-D projection or stereo image of the reservoir. [open quote]Three dimensional[close quotes] visualization has been a very valuable tool in communicating geologic concepts and models to multidisciplinary teams. We have found it much easier for non-earth scientists to understand geologic models, or even to question the validity of the models, when using these displays. When well bore information, such as injectivity profiles, is added to the model a better understanding of fluid flow, including fluid cycling pathways, and the dynamics within the reservoir can be developed. This information can be used to realign wells to take advantage of variations in subtle changes in geology ormore » to identify potential areas of by-passed oil that can be targeted by horizontal wells.« less

High‐resolution crosswell imaging of a west Texas carbonate reservoir: Part 1—Project summary and interpretation

A carbon dioxide flood pilot is being conducted in a section of Chevron’s McElroy field in Crane County, west Texas. Prior to [Formula: see text] injection, two high‐frequency crosswell seismic profiles were recorded to investigate the use of seismic profiling for high‐resolution reservoir delineation and [Formula: see text] monitoring. These preinjection profiles provide the baseline for time‐lapse monitoring. Profile #1 was recorded between an injector well and an offset observation well at a nominal well‐to‐well distance of 184 ft (56 m). Profile #2 was recorded between a producing well and the observation well at a nominal distance of 600 ft (183 m). The combination of traveltime tomography and stacked CDP reflection amplitudes demonstrates how high‐frequency crosswell seismic data can be used to image both large and small scale heterogeneity between wells: Transmission traveltime tomography is used to image the large scale velocity variations; CDP reflection imaging is then used to image smaller scale impedance heterogeneities. The resolution capability of crosswell data is clearly illustrated by an image of the Grayburg‐San Andres angular unconformity, seen in both the P‐wave and S‐wave velocity tomograms and the reflection images. In addition to the imaging study, cores from an observation well were analyzed to support interpretation of the crosswell images and assess the feasibility of monitoring changes in [Formula: see text] saturation. The results of this integrated study demonstrate (1) the use of crosswell seismic profiling to produce a high‐resolution reservoir delineation and (2) the possibility for successful monitoring of [Formula: see text] in carbonate reservoirs. The crosswell data were acquired with a piezoelectric source and a multilevel hydrophone array. Both profiles, nearly 80 000 seismic traces, were recorded in approximately 80 hours using a new acquisition technique of shooting on‐the‐fly. This paper presents the overall project summary and interpretation of the results from the near‐offset profile.

High‐resolution crosswell imaging of a west Texas carbonate reservoir: Part 5—Core analysis

We conducted a core analysis program to provide supporting data to a series of crosswell field experiments being carried out in McElroy Field by Stanford University’s Seismic Tomography Project. The objective of these experiments is to demonstrate the use of crosswell seismic profiling for reservoir characterization and for monitoring [Formula: see text] flooding. For these west Texas carbonates, we estimate that [Formula: see text] saturation causes P‐wave velocity to change by −1.9% (pooled average, range = −6.3 to +0.1%), S‐wave velocity by +0.6% (range = 0 to 2.7%), and the P‐to‐S velocity ratio by −2.4% (range = −6.4 to −0.3%). When we compare these results to the precisions we can expect from traveltime tomography (about ±1% for P‐ and S‐wave velocity and about ±2% for the P‐to‐S velocity ratio), we conclude that time‐lapse traveltime tomography is sensitive enough to resolve changes in the P‐wave velocity, S‐wave velocity, and P‐to‐S velocity ratio that result from [Formula: see text] saturation. We concentrated here on the potential for [Formula: see text] saturation to affect seismic velocities. The potential for [Formula: see text] saturation to affect other seismic properties, not discussed here, may prove to be more significant (e.g., P‐wave and S‐wave impedance).

Waterflood Improvement in the Permian Basin: Impact of In-Situ-Stress Evaluations

Summary We evaluated in-situ-stress magnitudes and directions to support waterflood improvement programs in McElroy field and North Westbrook Unit. In-situ-stress and hydraulic-fracture directions coincided with directional floodwater effects. This information contributed to successful waterflood realignment programs.

In-situ stress evaluation in the McElroy field, West Texas : Avasthi, J M; Nolen-Hoeksema, R C; El Rabas, A W M SPE Form EvalV6, N3, Sept 1991, P301–309

In-situ stress evaluation in the McElroy field, West Texas : Avasthi, J M; Nolen-Hoeksema, R C; El Rabas, A W M SPE Form EvalV6, N3, Sept 1991, P301–309

In-Situ Stress Evaluation in the McElroy Field, West Texas

Summary This paper discusses an in-situ-stress evaluation program conducted in the McElroy field in preparation for waterflood realignment. Microfracturing and borehole logging results indicated that the maximum horizontal stress orientation was north-northwest, west-northwest, and north-northwest in the upper, middle, and lower payzone intervals, respectively. Microfracturing proved to be the most reliable and cost-effective technique for in-situ stress evaluation in this heterogeneous reservoir.

Geologic Evolution of the Late Permian Capitan Shelf Margin, Northern Delaware Basin

A two-phase model, based on outcrop and subsurface data rimming the northern half of the Delaware basin, characterizes the evolution of the late Guadalupian Capitan shelf margin, a margin that prograded up to 19 km basinward while an interval of over 700 m accumulated. Phase 1, during Seven Rivers shelf (early Capitan) deposition, accounts for 70-80% of the total progradation, over 50% of the total aggradation, and corresponds with shelf facies devoid of siliciclastics, emplacement of abundant carbonate debris on the slope and basin margin, and deposition of 50-70% of the Bell Canyon siliciclastic interval in the basin. The clastics bypassed the growing Capitan margin and were equally important to that of the allochthonous carbonate debris in filling accommodation space to facilitate progradation of the margin. The second phase, during Yates-Tansill (middle-upper Capitan) time, was dominated by aggradation, steepening of the shelf margin, deepening of the basin, and deposition of abundant siliciclastics on the shelf. This model differs from previous reconstructions that show uniform growth of the Capitan reef, and it contradicts the long-standing dogma of reciprocal sedimentation. This two-phase growth model adds insight into deposition of the two principle Guadalupian reservoir facies that account for nearly 50% of themore » Permian basin in-place oil reserves. Offlapping sheets of inner shelf carbonates (e.g., San Andres Formation, McElroy field) relate to periods of shelf progradation whereas widespread sheets of shelf clastics (e.g., Yates Formation, N. Ward Estes field) reflect periods of shelf aggradation. The model should be useful in evaluating the evolution of other shelves, particularly mixed shelves.« 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

McElroy Field, Permian Basin, West Texas: Cyclic Sequence Dolomite Reservoir of Central Basin Platform: ABSTRACT

The McElroy field, located in Crane and Upton Countries of west Texas, is one of several carbonate reservoirs developed along the eastern margin of the Central Basin platform. The reservoir rock at McElroy consists of Permian System (Guadalupian Series) dolomite of the Grayburg Formation. The Grayburg dolomite and the underlying San Andres Formation were formed as shallowing-upward carbonate sequences. The carbonate facies are overlain by the Queen Formation, an evaporite-dominated unit that serves as the reservoir seal. The Grayburg Formation carbonates consist of dolomitized lime mudstones, wackestones, pelletal and skeletal packstones, and ooid grainstones deposited in subtidal to supratidal environments. Facies prograde eastward toward the Midland basin, suggesting relative sea level lowering or progressive shallowing. The westward limit of the McElroy field is determined by pinch out of reservoir carbonates that interfinger with supratidal nodular and bedded anhydrite. The reservoir petrophysical characteristics are defined by diagenetic overprinting on primary carbonate depositional fabrics. The principal diagenetic processes include dolomitization, anhydrite occlusion of primary porosity, and leaching. McElroy, which was discovered in 1926, produces approximately 13,500 BOPD. This Chevron-operated field has 2.2 billion bbl of oil in place; 329 million bbl have been produced from nearly 1,600 wells. The field is currentlymore » under waterflood and is being evaluated for potential CO/sub 2/ injection.« less

Application of Sequence Stratigraphy to Permian Carbonates and Evaporites, McElroy Field, Central Basin Platform, Texas: ABSTRACT

The McElroy field in west Texas is part of a series of Permian subsurface carbonate reservoirs fringing the eastern margin of the Central Basin platform. Traditionally, these reservoirs have been subdivided into three stratigraphic units: San Andres Formation, Grayburg Formation, and Queen Formation. The San Andres and Grayburg Formations apparently form shallowing-upward cycles capped by intertidal or low-supratidal facies. Oil production occurs mainly from the Grayburg Formation. The Queen Formation consists largely of bedded sulfates and siltstones, and forms the reservoir seal. Applying the concept of sequence stratigraphy to wireline logs and core data refines the previous stratigraphic and geologic interpretations. (1) The Grayburg Formation consists of three internal cycles. (2) Laterally equivalent types of microfacies are similar but not identical during transgression and regression. (3) A paleo-shoreline was present near the eastern margin of the field before the end of Grayburg deposition. (4) Syndepositional downfaulting of the eastern part of the field by several meters occurred during Grayburg deposition. (5) Downfaulting of the eastern part of the field by several tens of meters occurred after Queen deposition. These findings may help interpret reservoir diagenesis. In particular, pervasive dolomitization and emplacement of sulfates (mainly gypsum and anhydrites) may be relatedmore » to the internal cyclicity or the faulting events.« less

McElroy Field: Development of a Dolomite Reservoir, Permian Basin of West Texas: ABSTRACT

McElroy Field: Development of a Dolomite Reservoir, Permian Basin of West Texas: ABSTRACT

Similarity of Grayburg/San Andres Dolomite Reservoirs--Eastern Edge of Central Basin Platform, Permian Basin: ABSTRACT

Porous dolomites of the Grayburg/San Andres Formations (Permian, Guadalupian) form major hydrocarbon reservoirs along the eastern edge of the Central Basin platform of the Permian basin, Texas. A comparison of the lithologic descriptions and depositional models for these reservoirs shows that although substantial local variation exists, the overall generalized vertical sequence and, particularly, the occurrence of porous shoal grainstones are strikingly similar. Data presented in this pilot study comes from the Gulf Oil 223-R J. T. McElroy Cons. well in McElroy field, the Gulf Oil 35 E.N. Snodgrass well in Waddell field, and the Gulf Oil 1359-56 C.A. Goldsmith et al well in Goldsmith field. Grayburg/San Andres reservoirs in all three fields occur mainly in the middle part of a shallowing-upward carbonate-shelf sequence that is 250-300 ft thick. The sequence consists of: (1) basal open-shelf, bioturbated dolowackestones/packstones; (2) middle shallow shelf fusulinid dolowackestones overlain by nonskeletal shoal dolopackstones/grainstones; and (3) upper variable intertidal/supratidal deposits that grade into the Queen Formation. The depositional sequence formed in a regional facies tract of shallow-water shelf and shoal environments with related tidal-flat and evaporitic (sabkha) sediments. The facies developed during easterly progradation across a deeper water open shelf. Porosity was formed by near-surface dolomitizationmore » and minor dissolution. Early and late evaporite plugging reduced porosity, so reservoir zones average 9% intercrystalline and moldic porosity with 10-md permeability.« less

Methods For Correcting Porosity Data in a Gypsum-Bearing Carbonate Reservoir

Summary The McElroy field in west Texas is an example of a carbonate reservoir that contains significant quantities of gypsum. Large amounts of reservoir data have been obtained in this field by conventional core analyses and by sidewall neutron porosity (SNP) logs. These data do not account for the effect of gypsum in porosity determination. In an effort to characterize this heterogeneous reservoir more thoroughly, we used special low-temperature core analysis and developed a new method of log analysis to correct old core and log porosity data for gypsum content. These data then were used for a more accurate determination of OOIP. Introduction The McElroy field is one of the major reservoirs of west Texas. It is located in Crane and Upton Counties (Fig. 1). The reservoir encompasses about 30,000 acres (121.5×106 m2) and contains about 2,000 wells. Production is from the Grayburg-San Andres dolomite formation of the Permian period at an average depth of about 3,000 ft (900 m). The field was discovered in 1926 and has been in various stages of development since that time.1 Most of the porosity data acquired have been in the form of conventional core analyses and SNP logs. These data are known to be affected significantly by the presence of gypsum. Since this reservoir rock has been found to contain significant amounts of gypsum, direct use of these data would lead to significant errors in porosity estimation. In early 1959, a method of core analysis was developed that prevented the dehydration of gypsum.2 As new infill wells were drilled, selected wells were cored, and the cores were analyzed by this technique. To utilize as much data as possible in this very large reservoir. Many of the more recently drilled wells were logged with SNP logs.3 To utilize these data, a method of correcting these logs was developed. The corrections were based on information obtained from special log analysis techniques in nearby infill wells. Porosity data from logs and cores in the new wells and corrected porosity data from logs and cores in the old wells were used in conjunction with capillary pressure measurements to determine OOIP by the volumetric method. Theory and Definitions Core Analysis Gypsum (CaS04·2H20) is an evaporite mineral found in many carbonate and some sandstone reservoirs. In laboratory measurements, gypsum has been observed to convert to anhydrite and water at temperatures above about 140°F (60°C). Assuming that the conversion from gypsum to anhydrite takes place at approximately this same temperature in the reservoir and that a typical geothermal gradient exists, gypsum general1y is not expected to exist below a depth of about 6,000 ft (1800 m). Standard core analysis can cause serious errors in the measurement of porosity if gypsum is present in the cores. Vacuum distillation or retort procedures yield porosity values that are too high by as much as 48 % of the bulk volume of gypsum present. Heating the core samples for cleaning or measurement of fluid content is a necessary step in most forms of standard core analysis. The heat applied is high enough for the gypsum to lose its crystallization water and to form anhydrite. It is the loss of this crystallization water that causes the error in the measurement of porosity. This process was described in detail by Hurd and Fitch2 in 1959. Core Analysis Gypsum (CaS04·2H20) is an evaporite mineral found in many carbonate and some sandstone reservoirs. In laboratory measurements, gypsum has been observed to convert to anhydrite and water at temperatures above about 140°F (60°C). Assuming that the conversion from gypsum to anhydrite takes place at approximately this same temperature in the reservoir and that a typical geothermal gradient exists, gypsum general1y is not expected to exist below a depth of about 6,000 ft (1800 m). Standard core analysis can cause serious errors in the measurement of porosity if gypsum is present in the cores. Vacuum distillation or retort procedures yield porosity values that are too high by as much as 48 % of the bulk volume of gypsum present. Heating the core samples for cleaning or measurement of fluid content is a necessary step in most forms of standard core analysis. The heat applied is high enough for the gypsum to lose its crystallization water and to form anhydrite. It is the loss of this crystallization water that causes the error in the measurement of porosity. This process was described in detail by Hurd and Fitch2 in 1959.