(XuX S^ulKO^ Reservoir Characterization and Its Application to Improved Oil Recovery from the Cypress Formation (Mississippian) at Richview Field, Washington County, Illinois John P. Grube and Wayne T. Frankie Illinois Petroleum 155 1999 Department of Natural Resources ILLINOIS STATE GEOLOGICAL SURVEY f inn a »v APR 1 1999 Reservoir Characterization and Its Application to Improved Oil Recovery from the Cypress Formation (Mississippian) at Richview Field, Washington County, Illinois John P. Grube and Wayne T. Frankie Illinois Petroleum 155 1999 ILLINOIS STATE GEOLOGICAL SURVEY William W. Shilts, Chief Natural Resources Building _ 615 East Peabody Drive APR 1 1993 Champaign, Illinois 61820-6964 4 DISCLAIMER This report was prepared by the Illinois State Geological Survey (ISGS) as part of a project sponsored by the State of Illinois and the U.S. Department of Energy (USDOE). It presents reasonable interpretations of available scientific data. Any opinions, findings, conclusions, or recommendations expressed herein are those of the authors and do not necessarily reflect the views of the USDOE. Neither the ISGS, any individual members of the ISGS staff, the Illinois Department of Natural Resources, nor the USDOE assumes any liability with respect to the use of any information contained in this report. Trade names cited in this report are provided solely for the purpose of informing the public. Use of a particular product does not constitute an endorsement by the ISGS or the USDOE. ACKNOWLEDGMENTS Special recognition is due the Evans Family of Nashville, Illinois, fortheir donation of field data. Technical assistance, analytical services, and data interpretation were provided by several colleagues at the Illinois State Geological Survey: Istvan Barany, Scott Beaty, llham Demir, Dennis Haggerty, Randall Hughes, Duane Moore, Beverly Seyler, and Emmanuel Udegbunam. Their work is much appreciated. This research was funded by the United States Department of Energy (USDOE) under grant DE-FG2289BC14250 and the Illinois Department of Energy and Natural Re- sources under grant AE-45. Principal Investigator for this research was Donald F. Oltz. Support for the research in this strategic program is gratefully acknowledged. Graphic Artist— Mike Knapp Editor— Tom McGeary Editorial Board Jonathan H. Goodwin, chair Michael L. Barnhardt Anne L. Erdmann B. Brandon Curry David R. Larson Heinz H. Damberger Donald G. Mikulic William R. Roy ILLINOIS NATURAL RESOURCES Printed by Authority of the State of Illinois/1999/600 ® Printed with soy ink on recycled paper CONTENTS ABSTRACT 1 INTRODUCTION 1 FIELD DISCOVERY AND PRODUCTION HISTORY 5 Geologic Setting 5 Discovery History 5 Production History 7 RESERVOIR CHARACTERIZATION 8 Stratigraphy 8 Cypress A sandstone 1 1 Cypress B and C sandstones 1 1 Cypress D sandstone 12 Structure 13 Trap Type 17 Reservoir Lithology and Petrology 17 Depositional Environments 21 Diagenesis 22 Petrophysical and Stratigraphic Characteristics That Influence Reservoir Quality 23 Identification of Play 25 PRODUCTION CHARACTERISTICS 25 Production and Completion Procedures 25 Production and Waterflood Data 25 Reservoir Temperature, Pressure, and Drive 26 Oil Characteristics 26 Water Characteristics 26 Volumetrics 27 RECOMMENDATIONS FOR DEVELOPMENT AND PRODUCTION STRATEGY 28 Waterflood and Pressure-Maintenance Programs 29 Avoiding Clay Damage Caused by Drilling and Completion Techniques 30 Infill Drilling 31 REFERENCES 32 APPENDIX A CYPRESS RESERVOIR FLUID ANALYSIS 34 APPENDIX B RESERVOIR SUMMARY 38 FIGURES 1 Generalized geologic column for southern Illinois 2 2 Richview Field and outline of the Illinois Basin 3 3 Structure map contoured on top of the Beech Creek (Barlow) Limestone 4 4 Structure map contoured on the base of the Beech Creek (Barlow) Limestone 6 5 Decline curve for Richview Field 7 6 Type log of the Cypress Formation 9 7 Net thickness map of the Cypress A sandstone 10 8 Cross section A-A' showing widespread shaley interval that separates the Cypress B and C sandstones 1 2 9 Net thickness map of the Cypress B sandstone 14 10 Net thickness map of the Cypress C sandstone 15 11 Net thickness map of the Cypress D sandstone 16 12 Thickness map of the Beech Creek (Barlow) Limestone 18 13 SEM photomicrograph showing angular sand grains resulting from quartz overgrowths 19 14 SEM photomicrograph showing sites where feldspar grains have undergone near-total to total dissolution 20 15 SEM photomicrograph showing kaolinite crystals on a quartz overgrowth substrate 23 16 Iron-rich chlorite rosettes on a quartz grain 24 Table 1 Weight percentages of mineral constituents from six Droege Unit No. 2 core plugs 19 ABSTRACT Richview Field, discovered in 1946, is located in eastern Washington County, south- central Illinois. Petroleum is produced from northeast-southwest trending, vertically stacked, lenticular sandstone bodies in the upper part of the Mississippian Cypress Formation. The sandstone lenses that make up the primary reservoirs range from 1 to 2 miles in length, are up to Vz mile in width, and average 10 feet in thickness. Reservoir porosity averages 20%, and permeability averages 175 millidarcies. The reservoirs extend over 640 acres at an average depth of 1 ,500 feet. Discrete reser- voir compartments are created within the field by shale beds that separate the verti- cally stacked sandstone lenses. Combined stratigraphic/structural trapping occurs where stacked, compartmentalized sandstone lenses lap onto and drape over a structural saddle. Geometry and stratigraphic associations indicate that these sand- stones were deposited in shallow coastal marine environments. Diagenesis has affected the quality of the sandstone reservoirs at Richview Field. Quartz cementation has reduced permeability and porosity within the reservoirs. Diagenetic clay minerals, including kaolinite, mixed-layered illite/smectite, and iron- rich chlorite, are common constituents within these sandstones. Although clay min- erals constitute only about 5% by weight of the Richview sandstone reservoirs, their potential to cause formation damage can be large. The introduction of water into a reservoir that is less saline than the native brine can cause kaolinite and illite/smec- tite to react in ways that decrease permeability. Hydrochloric acid can react with iron chlorite to form iron hydroxides, which can also reduce permeability. Maintenance of reservoir pressure has increased ultimate cumulative oil recovery. Initiation of waterf boding after as little as 1 year of primary production very likely increased recovery efficiency at Richview Field. Of the estimated 7.3 million barrels of stock tank original oil in place (STOOIP), 3.3 million barrels have been produced, yielding a recovery efficiency of 45.6%. The study concludes that production can be optimized most efficiently by single- operator or unitized and coordinated projects, waterflood and pressure-maintenance programs, use of correct correlations in waterflood programs, and use of field pressure analyses to evaluate reservoir continuity and flow unit correlation. For Richview Field, infill drilling may prove feasible for increasing recovery efficency. Clay damage caused by drilling and completion techniques can be avoided by clay stabilization systems, avoiding "water shock," addition of oxygen scavengers and iron chelating agents to acid, and introduction into a reservoir of fluids that are compati- ble with the clay minerals in the reservoir. INTRODUCTION The Mississippian Cypress Formation (fig. 1 ) is a major producing formation in the Illinois Basin. An estimated 800 million barrels of oil have been produced from Cypress sandstone reservoirs. Most of these reservoirs were discovered 30 to 60 years ago and are either depleted or undergoing secondary recovery operations. While primary and secondary production has drained a significant amount of the recoverable oil from these reservoirs, unswept mobile oil that may be economically recoverable remains. A comprehensive geologic investigation integrated with engineering analysis of all production-related reservoir characteristics is necessary to identify and evaluate the FORMATION, GROUP, MEMBER MATTOON BOND Carthage (Shoal Creek) LsMbr MODESTO CARBONDALE Herrin Coal Mbr Springfield Coal Member Colchester Coal Mbr TRADEWATER (SPOON and ABBOTT undifferentiated) •>:■?:: :'.••>,■■?«] CASEYVILLE GROVE CHURCH KINKAID DEGONIA CLORE PALESTINE MENARD WALTERSBURG VIENNA TAR SPRINGS GLEN DEAN HARDINSBURG HANEY FRAILEYS BEECH CREEK (BARLOW) CYPRESS RIDENHOW ER BETHEL w^S- m im &Fr RENAULT Shetfervllle Ls Mbr \ Levlas La Mbr AUX VASES Figure 1 Generalized geologic column for southern Illinois. Rocks that underlie the St. Peter Formation are not shown. Formations or members that contain pay zones are given in bold type. The names Alexandrian, Cayugan, Upper Devonian, Kinderhookian, Valmeyeran, and Virgilian are abbreviated as Alex., Cayu., Up., K., Val., and Virg. Variable vertical scale (after Howard and Whitaker 1990). 30 60 mi Figure 2 Richview Field and outline of the Illinois Basin. potential to recover the remaining unswept mobile oil. Drilling, completion and stimulation methods, well spacing, pressure maintenance, and waterflood designs are highly dependent on the characteristics of individual reservoirs. This study was conducted to geologically characterize the Cypress sandstone reservoirs at Richview Field and to identify the factors that control recovery efficiencies. Techniques that may improve oil recoveries or have already been successfully employed to recover oil from the Richview reservoirs were also investigated in this study. Richview Field is located in eastern Washington County, in south-central Illinois (fig. 2). The field trends northeast-southwest and underlies parts of Section 35, Township 1 South, Range 1 West, and portions of Sections 2, 3, 10, 11, and 15, Township 2 South, Range 1 West (fig. 3). The field is approximately 3 miles long, 0.5 to 0.75 miles wide, and is centered directly beneath the town of Richview. No obvious natural surface expressions of this oil field are apparent. As with many oil fields in the Illinois Basin, Quaternary cover tends to mask the underlying struc- tural features at Richview. This study was part of an investigation that was designed to improve and enhance oil recovery in Illinois through reservoir characterization. Funding for the investiga- tion was provided by the Illinois Department of Energy and Natural Resources and the U.S. Department of Energy. Richview Field is one of seven Cypress oil fields chosen for study on the basis of availability of data, regional location, stratigraphic R 1 W • oil well -0- dry/abandoned well ♦ dry/abandoned well (oil show) o permitted location jf water injection e salt water disposal / indicates well is currently plugged Figure 3 Structure map contoured on the top of the Beech Creek (Barlow) Limestone. Richview Field produces from a principal pool and two subsidiary pools offset to the southeast and southwest of the main pool. Contour interval is 10 feet. position of the reservoir within the Cypress Formation, and cumulative production. A comprehensive evaluation of Cypress reservoirs and their respective characteris- tics was obtained by selecting fields that (1) produced from several distinct strati- graphic intervals within the Cypress Formation and (2) represented a diversity in location, cumulative production, reservoir development and management strate- gies, and company size. Many of the field studies have been published by the Illinois State Geological Survey, and all the studies are summarized in Oltz (1994). FIELD DISCOVERY AND PRODUCTION HISTORY Geologic Setting Richview Field is situated on the west flank of the Illinois Basin. The field is on the uplifted side of the Du Quoin Monocline, immediately west of the monoclinal flexure. The monocline, a major structural feature in the basin, strikes north-south over a distance of 50 miles. Locally, more than 400 feet of structural relief occurs within a distance of approximately 1 mile on the Beech Creek (Barlow) Limestone across the flank of the monocline (fig. 3). Because the name Barlow is widely used to refer to the Beech Creek Limestone, the term Barlow will be employed in this publication. The Du Quoin Monocline marks the eastern edge of the Sparta Shelf, the structural terrace on which Richview Field is located (fig. 4). Subsidiary folds along the Du Quoin Monocline form the structural component of the hydrocarbon trap for the Richview reservoirs. A structure map contoured on the base of the Barlow limestone (fig. 4) shows the location of Richview Field. Regional dip on the Barlow averages 30 feet per mile across the Illinois Basin. The Barlow is a widespread limestone that directly over- lies the Cypress and is commonly used as a structural reference for the Cypress. Richview Field lies in a structural saddle between the Irvington Anticline to the north and the structural extension of that anticline to the south. The Irvington Anticline traps oil at Irvington Field, and the southern extension of that anticline traps oil at Ashley and Dubois Fields. Changes in thickness of Pennsylvanian strata and indications of movement across the Du Quoin Monocline during earlier Paleozoic periods indicate that recurrent movement has taken place along a system of basement faults (Nelson 1995, Hopkins and Simon 1975). Folding that formed the Irvington Anticline and related structures that trap oil in the Irvington, Richview, and Ashley Fields may have resulted from tectonic events that created the Du Quoin Monocline; therefore, deformation formed the trap during and possibly afterthe Pennsylvanian Period (Siever 1 951 ). Relatively few Cypress oil fields have been established in this region, although Cypress sandstones are widespread across the west flank of the basin. In general, hydrocarbon production in these fields is limited to the uppermost Cypress sand- stone, even though structural closure may exist throughout the entire formation. Therefore, the Cypress has not been fully charged with hydrocarbons. Discovery History Richview Field was discovered by the drilling and completion of the National Con- sumers Oil Company's No. 1 Pitchford-Koelling well on August 6, 1946. The well is located in the NW SW SE, Section 1 0, T2S, R1 W, and was drilled to a depth of 1 ,532 feet. Initial production was 31 barrels of oil per day (BOPD) from the upper Cypress sandstone at 1 ,521 to 1 ,532 feet. Although the field was discovered in 1 946, most of the development occurred in the early 1 960s after Charles T. Evans drilled the No. 1 10 km Figure 4 Structure map contoured on the base of the Beech Creek (Barlow) Limestone. The location of Richview Field on the west flank of the present structural basin is shown (after Bristol 1968). Contour interval is 100 feet. Droege Unit in the SW SW NW, Section 2. The No. 1 Droege Unit, completed on September 27, 1 961 , discovered a Cypress pool that is separate from the initial dis- covery well in Section 10 and is the most extensive of the three pools that make up Richview Field. Centralia Petroleum Company established the third pool by comple- tion of the No. 1 Koelling, SE NW SW, Section 1 1 , in September 1 962. Records show that 89 wells were drilled and completed in the field. To date, 37 wells are recorded as plugged. The three pools that make up the field are outlined by 53 offsetting dry holes. The field contains approximately 640 acres of proven reserves. 1,000,000 100,000 <0 o "§ 10,000 1 ,000 : 100 discovery and development of additional pools i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 year Figure 5 Decline curve for Richview Field, showing annual production for 1947-1995. Production History Figure 5 is a graph of yearly production. The first 1 6 years of production, from 1 946 through 1961, was from two wells in the original discovery area in Section 10. Just under 17,000 barrels of oil were produced from the two wells through 1961. The large increase in production beginning in 1 962 is the result of the discovery and con- centrated development of the main pool and the subsidiary pool in Section 11. In 1 962 the number of wells in the field increased to 39 and subsequently to 53 wells in 1963. Production wells are predominantly drilled on 10 acre spacing. An increase in production starting in 1 967 was the result of a waterflood program ini- tiated in 1 966. Six separate waterflood programs were established at Richview Field that effectively flattened and extended the decline curve (fig. 5). Injected water for waterflooding is derived from produced brine and supplementary water extracted from sandstones of the overlying Tar Springs Formation. Cumulative production for the entire field from 1 946 throughl 995 is 3.3 million bar- rels of oil. Records from the Section 1 1 subsidiary pool show a cumulative produc- tion of 1 25,000 barrels of oil. Records are incomplete for the original discovery pool in Sections 1 and 1 5. Data available from 4 of the 1 wells in this pool show produc- tion of 52,000 barrels of oil. RESERVOIR CHARACTERIZATION Stratigraphy The Cypress Formation was deposited during a major pulse of siliciclastic sedimen- tation that occurred in the Illinois Basin during the early part of the Chesterian Epoch (fig. 1). A shallow cratonic sea initially occupied the Illinois Basin as the siliciclastic materials entered the Basin from the northeast (Potter et al. 1958, Swann 1963, Cole and Nelson 1995). The maximum thickness of the Cypress Formation at Richview Field, from the base of the overlying Barlow limestone to the base of the lowermost Cypress sandstone (fig. 6), is approximately 1 10 feet. The Cypress con- sists predominantly of sandstones and shales, with some siltstone, mudstone, and thin calcareous sandstones grading to limestones. Within the upper part of the Cypress, beds of impure coal or carbonaceous shale and regionally widespread variegated mudstones and mottled red and green mudstones are apparent on out- crops and in core and drill cuttings. These variegated mudstones and coaly deposits indicate that subaerial to near-subaerial exposure occurred after deposition of these muds. Also, some of the thick outcropping and subsurface sandstones that occur at or below the variegated horizon are interpreted by the authors to be incised valley fill deposits. Both the variegated rocks and the presence of incised valleys indicate that during deposition of the Cypress, widespread subaerial exposure occurred. Regional exposure surfaces such as these are defined in sequence stratigraphic analysis as sequence boundaries (Van Wagoner et al. 1990). Sequence boundaries are useful guides for the correlation of depositionally related facies and have practical applica- tion in defining reservoir compartments and trend direction. Overlying the Cypress in the study area are 8 to 29 feet of Barlow limestone. Shales, siltstones, and thin limestones of the Ridenhower Formation underlie the Cypress Formation. Electric log signatures indicate that a well-developed Downeys Bluff Limestone underlies the Ridenhower. Because most of the wells did not penetrate the entire Cypress Formation, only limited data exist for the lower Cypress and the underlying section. Although well control is limited, there does not appear to be sandstone development within the Bethel-Ridenhower interval in the study area. The reservoir at Richview Field was characterized, in part, through lithofacies map- ping and depositional facies interpretation. Four separate reservoir intervals were defined within the Cypress on the basis of correlations of distinctive spontaneous potential (SP) and resistivity log signatures. Three correlation parameters were used to define the divisions: (1) similarity of log character, (2) stratigraphic position of sandstones in the Cypress Formation, and (3) stratigraphic position of shales in the Cypress Formation. Sandstones within these intervals have been designated in ascending order as the Cypress A, B, C, and D sandstones (fig. 6.). Shale or SP breaks are not apparent in the Cypress D sandstone, whereas breaks up to several feet thick are common in the sandstones of the Cypress B and C intervals. Shale breaks from less than 1 foot to several tens of feet thick occur between the individual sandstones of the Cypress A interval. Separate sandstone bodies that commonly stack and coalesce or split and pinchout make correlations uncertain even between wells drilled on 10 acre spacing. The designation Cypress A, B, or C sandstone, therefore, represents a composite or net of all sandstones that occur in their correla- tive interval rather than a reference to specific sandstone beds. The Cypress A sandstone, usually composed of multiple benches, is varied in char- acter and equivalent to the lower Cypress, blocky type sandstone common in fields east of the Du Quoin Monocline. Only a small amount of oil has been produced from this sandstone at Richview. The Cypress B and C sandstones, which form the most Charles T. Evans McDonald-Richardson Unit no. 2 T2S, R1W, Sec. 2, NE SW NW Washington County, IL K.B. 540 ft IPP60BOPD S.P. resistivity Figure 6 Type log of the Cypress Formation with divisions used for mapping in this study. The Cypress B and C sandstones are the principal reservoirs at Richview Field. The Cypress D sandstone is a less extensive reservoir. prolific reservoirs in the field, are lenticular and stacked like the Cypress sandstones at Tamaroa and Tamaroa South Fields (Grube 1992). Thin, lenticular Cypress D sandstones that occur directly beneath the Barlow limestone are, in general, mar- ginally productive. R 1 W • oil well -0- dry/abandoned well ■» dry/abandoned well (oil show) o permitted location jf water injection e salt water disposal / indicates well is currently plugged Figure 7 Net thickness map of the Cypress A sandstone that is greater than 50% clean. Contour interval is 5 feet. 10 Isopach maps were constructed for each of the four sandstones to determine their geometry and their spatial relationships to each other; the geometry and spatial rela- tionships are useful for determining environments of depositionand for identifying reservoir compartments. The maps were also used to calculate the volumetrics of the field. Cypress A sandstone A thickness map of 50% clean sandstone in the Cypress A interval (fig. 7) shows sandstone bodies up to 40 feet thick trending northeast-south- west in the study area. For each particular well, a 50% clean sandstone refers to that portion of a sandstone response on the SP curve that deflects to the left of a point that is one-half the distance between the shale baseline (0% clean sandstone) and a sandstone with the greatest amount of SP deflection (100% clean sandstone). The shale baseline for the Cypress was established by using the consistent flat-line response of the Fraileys Shale. The 100% clean sandstone SP response was calibrated using the Tar Springs Sandstone or a Cypress sandstone with the great- est amount of SP deflection. A 1 00% clean Cypress sandstone in the Richview area com- monly displays a negative 100-120 millivolt deflection from the shale baseline. A 50% or greater clean sandstone cutoff was used to delimit reservoir-quality sandstone. The Cypress A sandstone appears to be present in most of the northern part of the field but absent in the very southern part of the field. The SP log character shows a variety of Cypress A sandstone responses throughout the study area, including mul- tiple benches, fining upward, coarsening upward, and blocky. Log characteristics and core analysis of this sandstone indicate that the Cypress A sandstone is of reservoir quality. The Cypress A sandstone is productive in the northern part of the field where the sandstone is structurally high enough to extend above the oil-water contact. Cypress B and C sandstones The Cypress B and C sandstones form the primary reservoirs in Richview Field. A shaley interval, ranging in thickness from less than 1 foot to 4 feet, commonly separates the Cypress B and C sandstones (fig. 6). This shaley interval decreases in thickness toward the middle of the field and becomes imperceptible on some logs (fig. 8). A shale interval, commonly 10 feet thick but ranging from less than 1 foot to 30 feet thick, separates the Cypress A sandstone from the overlying Cypress B sandstone. Drill cuttings from representative wells across the field commonly contain red and green to variegated mudstone beds near the top of the shale between the Cypress A and B sandstones. Rare coal cuttings are also observed in this shale interval. A 50% clean sandstone thickness map of the Cypress B interval shows a principal sandstone body with two southern offset lenses (fig. 9). These sandstone bodies trend northeast-southwest and measure over 3 miles long and 1 /3 to Vz mile wide. The Cypress B sandstone attains a thickness of approximately 25 feet along the central part of the main pool and is less than 1 feet thick in the two southern offsets. Production from the Cypress B sandstone is restricted to the structurally higher por- tion of the field. An oil-water contact at -963 feet subsea (963 ft below sea level) is common to all productive sandstones throughout the field. For the Cypress B sand- stone, the oil-water contact lies approximately halfway between the -91 and -920 foot contours on the Barlow structure map (fig. 3). The southwestern offset field in Sections 10 and 15 appears to produce entirely from the Cypress B sandstone. A 50% clean sandstone thickness map of the Cypress C (fig. 10) interval shows this sandstone coincides geographically with the underlying Cypress B sandstone 11 A south o N. A. Baldridge Skibiski no. 1 SedONWNESE T2SR1W KB 556 ft / N. A. Baldridge Gray no. 2 Sec. 10SENE T2SR1W KB 550 ft D. Smith Walker-Emerick no. 1 Sec. 10NENE T2SR1W KB 548 ft N. A. Baldridge Richview Methodist Church Sec. 3 SE SE SE T2SR1W KB 527 ft N. A. Baldridge Sproul Community no. 1 Sec. 2 SW NW SW T2SR1W KB 541 ft Ridenhower Formation SP res SP res Figure 8 Stratigraphic cross section, A-A\ showing the widespread shaley interval that separates the Cypress B and C sandstones. The Cypress C sandstone increases in thickness by the addition of stacked pods or lenses of sandstone. The Cypress B sandstone has similar characteristics. Stacked lenses appear to form vertically continuous sandstones more than 20 feet thick, but an examination of the SP traces show subtle to obvious positive deflections at the boundaries of the lenses. The SP deflections indicate that the lenses are commonly separated by very thin impermeable beds that compartmentalize and reduce the fluid flow capability of the Cypress B and C sandstones. Line of this cross section is shown on figure 9. (fig. 9). Unlike the Cypress B sandstone, the Cypress C sandstone has no offset lenses. Thickness of this sandstone is greatest along the central part and reaches a maximum thickness of 20 feet. The Cypress C sandstone increases in thickness from north to south by the addition of discrete, stacked or shingled pods of sand- stone (fig. 8). This stacking characteristic indicates migration or aggradation during deposition from north to south. The Cypress C sandstone lies structurally above the oil-water contact across the entire field and therefore produces where it becomes reservoir quality. The Cypress C sandstone continues northeast of the field, where it dips below the oil-water contact as it plunges down the Du Quoin Monocline along the east edge of Section 35, T1 S, R 1 W. The continuity of the Cypress C sandstone and its position above the oil-water contact are favorable for secondary recovery, particularly in areas where this sandstone is separated from underlying water-bearing zones. Cypress D sandstone The Cypress D sandstone, referred to as the "Notch" in parts of the Illinois Basin because of the way it lies directly beneath the Barlow lime- stone, is separated from the underlying Cypress C interval by a shale. Drill cuttings of this shale also display variegated beds and rare coal cuttings. The 50% clean sandstone thickness map of the Cypress D interval shows multiple lenticular sand- stones up to 6 feet thick that trend northeast-southwest (fig. 11). The trend and loca- tion of these sandstones coincide with the underlying Cypress B and C sandstones. Low SP log responses for the Cypress D sandstone throughout the field indicate that the average permeability of this sandstone is less than the average permeability of the Cypress A, B, or C sandstones. Core reports from four wells in the northwest 12 / C. T. Evans Vernon Richardson no. 1-W Sec. 2 S/2 SW T2SR1W KB 539 ft C. T. Evans McDonald-Richardson Unit no. 2 Sec. 2 NE SW NW T2SR1W KB 540 ft C. T. Evans Vernon Richardson no. 4 Sec. 2 SW NE NW T2SR1W KB 538 ft A north • o Thompson, Evans and Bailey C. T. Evans George Thompson no. 5 Vernon Richardson no. 1-A Sec. 35NESWSE Sec.35SWSENE T1SR1W T1SR1W KB 546 ft KB 551 ft SP res quarter of Section 2 confirm that the Cypress D sandstone has abundant shale part- ings and wavy shale laminations. Average porosity and permeability values for the Cypress D sandstone in these cores are smaller than the average values for the Cypress B and C sandstones in cores from elsewhere in the field. Production from the Cypress D sandstone occurs in the southeastern pool, Section 1 1 , T2S, R1 W, where it is the only reservoir and, therefore, the primary objective. Scattered Cypress D production occurs in the central part of the main pool, in Sec- tions 2 and 3, T2S, R1W. Structure The major structural features related to Richview Field were described on page 5. An examination of the Barlow structure map (fig. 3) shows no significant four-way closure within the study area. The field lies along a well-defined structural saddle between the Irvington Anticline to the north and the structural extension of that anti- cline to the south. Production is associated with the draping of lenticular reservoir sandstone bodies onto and across the structural saddle. The structural trend of the saddle sharply changes direction starting approximately at the center of Section 2 (figs. 3 and 4). The saddle trends northeast-southwest in the southern part of the field and trends northwest-southeast in the northern part of the field. The thickness and depositional trends of the Cypress B, C, and D sand- stones and the Barlow limestone all change at this structural bend, which indicates that their deposition may have been influenced by a preexisting tectonic feature. The change of structural trend is likely the result of deformation of the sedimentary section overlying basement fault blocks. The stratigraphic changes that occur in the Cypress B, C, D and Barlow intervals in the north half of Section 2 may have been induced by recurrent movement of the fault blocks during or preceding deposition. A surface expression of a fault or fracture zone along a basement block boundary 13 R1 W • oil well <> dry/abandoned well ♦ dry/abandoned well (oil show) o permitted location ft water injection e salt water disposal / indicates well is currently plugged Figure 9 Net thickness map of the Cypress B sandstone that is greater than 50% clean. Contour interval is 5 feet. Location of cross section A-A' is shown. 14 R1 W • oil well -0- dry/abandoned well ♦ dry/abandoned well (oil show) o permitted location jf water injection e salt water disposal / indicates well is currently plugged Figure 1 Net thickness map of the Cypress C sandstone that is greater than 50% clean. Contour interval is 5 feet. 15 R1 W • oil well -0- dry/abandoned well ■$■ dry/abandoned well (oil show) o permitted location jf water injection e salt water disposal / indicates well is currently plugged Figure 11 Net thickness map of the Cypress D sandstone showing multiple, lenticular sandstones trending northeast-southwest. Contour interval is 2 feet. 16 may be reflected in the drainage pattern of Rayse Creek, particularly in the north half of Section 2 where the creek parallels the northwest-southeast trend of the Irvington Anticline. Rayse Creek, which generally flows southeast from the Richview area, branches to the north in the northeast quarter of Section 1 1 and then resumes a northwest-southeast trend through the north half of Section 2 (fig. 11). The portion of the creek in the north half of Section 2 coincides with the area where the Cypress B and C sandstones become thin and narrow, the Cypress D sandstone truncates, and the Barlow thins and thickens randomly (fig. 12). The trend and location of Rayse Creek coincident with the change in stratigraphy in multiple horizons, the change in trend of the structural saddle, and the higher cumulative production from the part of the field near the creek indicate that a fault or fracture zone may cross the north half of Section 2. A faulted or fractured zone not only may have enhanced pro- duction in this area, but may also be the conduit that allowed hydrocarbons to migrate into and charge the Richview Field reservoirs. Although structural closure is not observed on the Barlow limestone, the limestone thins at a location coincident with the main part of the field. Thickness of the lime- stone ranges from 8 to 29 feet within the study area (fig. 12). The Barlow also thins over Cypress sandstones at the Tamaroa and Tamaroa South Fields (Grube 1 992). Thinning of the Barlow in both the Tamaroa and Richview Fields appears to be the result of compensating deposition. Where the Cypress consists predominantly of sandstones, the Barlow is thin; and where the Cypress is made up predominantly of shale, the Barlow is thick. The greater compaction of the shales relative to the sand- stones in the Cypress Formation was compensated for during the deposition of the Barlow limestone. Trap Type The trapping mechanism at Richview Field is a combination of structure and stra- tigraphy. Oil at Richview Field is not trapped within a closed structure. The reser- voirs at Richview are lenticular sandstones that are encased in shale. Oil is trapped at the updip pinchout of the lenticular sandstones, along the flank of the structural fold (saddle), or where the sandstones drape across the crest of the fold. The field has a uniform oil-water contact, which allows sandstones above that contact on the flank of the structure to be productive. The shales that overlie the sandstones and most likely underlie the Barlow provide the permeability seal. The fact that a uniform oil-water contact exists throughout the field indicates either that oil has migrated through fractures in the shale between the Cypress B and C sandstones or that the sandstones are connected locally. Reservoir Lithology and Petrology Drill cuttings for approximately 20% of the 1 50 wells in and within Vz mile of Richview Field were available for lithologic analysis. Core analysis reports for the Cypress Formation from 1 1 wells in Section 35, T1S, R1W, and Section 2, T2S, R1W, pro- vided petrophysical and lithologic data. Small-diameter plugs taken from a core of the Cypress C and D sandstones of the Cecil Newcomb et al. No. 2 well (NW SW NW, Section 2) were the only source for cored rock samples available for use in thin section, scanning electron microscope (SEM) with energy dispersive X-ray (EDX), and X-ray diffraction analyses. Drill cuttings and core plugs of reservoir rock from all intervals are lithologically simi- lar and are composed of very light gray to white, moderately well sorted, fine to very fine grained sandstone; where this sandstone is the reservoir, it is oil stained light brown. The Cypress B and C reservoir sandstones are very clean where the SP log 17 R1 W • oil well -0- dry/abandoned well -$■ dry/abandoned well (oil show) o permitted location jf water injection © salt water disposal / indicates well is currently plugged Figure 1 2 Thickness map of the Beech Creek (Barlow) Limestone. Contour interval is 2 feet. The Cypress consists predominantly of sandstones where the Barlow is thin. 18 Figure 1 3 SEM photomicrograph shows angular sand grains resulting from quartz overgrowths. Several pore throats in the center of the photomicrograph are restricted by overgrowths. In the lower part of the image, clay minerals coat the sand grains and appear to retard quartz overgrowths. Sample is from the Cypress C sandstone reservoir of the Droege Unit No. 2 (1 ,505.5 feet). shows at least a 75% clean deflection. Silica cement is pervasive throughout the sandstones and is the dominant cement in the reservoirs (fig. 13). Thin section and X-ray diffraction analyses from the Droege well core plugs show that the petro- graphic characteristics of the Cypress C sandstone and the Cypress D sandstone were all generally similar. The analyses indicate that the sandstones are relatively clean. Quartz accounts for approximately 90% of the samples; feldspar, clay miner- als, calcite, dolomite, chert, mica, and traces of heavy minerals make up the remain- ing 10% (table 1). Table 1 Weight percentages of mineral constituents taken from bulk pack (total mineral) X-ray diffraction analyses of six Droege Unit No. 2 core plugs. Depth (ft) 1,484.5 1,504.5 1,505.5 1,507.5 1,510.5 1,512.5 Weight (%) Clay lllite 5 0.2 4 2.3 7 1.8 1 5 0.3 6 1.1 lllite/smectite 0.2 1.2 1.4 0.1 0.8 Kaolinite 4.7 0.3 3.6 1.2 4.1 3.9 Quartz 83 93 88 99 90 80 K-feldspar (Na-Ca) feldspar Calcite 2.6 2.9 0.9 2.0 1.6 3.1 tr tr 0.7 2.0 1.3 1.4 3.0 10.0 Dolomite 6.2 1.3 19 Figure 14 SEM photomicrograph shows sites where feldspar grains have undergone near-total to total dissolution (D). Common to these sites is a concentration of diagenetic clay minerals. Kaolinite is the dominant clay mineral in this image. Pore space between the quartz grains and the size of pore throats are restricted by quartz overgrowths. Sample is from the Cypress C sandstone reservoir of the Droege Unit No. 2 (1 ,51 feet). Fine grained quartz sand having pervasive quartz overgrowths dominates these samples. The subangular to angular appearance of the grains results from the sub- hedral to euhedral crystal habit of the quartz overgrowths. Visible infilling by quartz overgrowths along grain contacts has decreased the pore space and pore throat size, which thereby decreases porosity and permeability (fig. 13). Quartz over- growths may also have increased the tortuosity of flow paths within the sandstones, which can reduce hydrocarbon flow rates through the reservoir. Secondary porosity has been created by the dissolution of feldspar grains. Partial to complete dissolution of fine sized feldspar grains is clearly visible in SEM images (fig. 14) and in thin sections. Calcite, mica, and heavy minerals are minor constituents of the reservoir rock. In the available samples, calcite occurs as a scattered to rare, patchy cement that usually is of little consequence to oil production. Calcite cement patches rarely incorporate more than a few sand grains and may be fossil induced like the syntaxial cements associated with echinoderm fragments observed by Whitaker and Finley (1992, plate 4). Fine to very fine, rounded, heavy mineral grains are scattered to rare. Over- all, mica grains are rare but do occur disseminated throughout the sandstones or concentrated along shale laminations. Carbonaceous flakes are commonly observed in drill cuttings from particular hori- zons in the field area. The carbonaceous material is in the basal Cypress D and B sandstones and in the upper Cypress C and upper Cypress A sandstones. The shales between the Cypress A and B sandstones and between the Cypress C and D sandstones also contain carbonaceous flakes and rare to scattered coal cuttings. 20 Core descriptions from core analysis reports and observations of core plugs from the Cecil Newcomb et al. No. 2 indicate that thin, wispy, wavy shale laminations are common in some parts of the reservoir sandstones. Thin sections show paper-thin laminations that are discontinuous; their appearance suggests they probably were deposited cyclically. Scattered, flat clay clasts were also observed in some beds in the cores and core plugs. Calcareous beds, typically thinner than 2 feet, occur in some cores at the base of the Cypress B sandstone, in the uppermost part of the Cypress C sandstone, or both, and can be distinguished on logs by high resistivity spikes with a correspondingly low SP (fig. 8, No.1 Sproul Community and No. 2 Gray wells). Fossil fragments are common in these beds. Some of the sandstones include thin limestone beds within the sandstones. Depositional Environments Interpretation of the depositional environments of the Cypress Formation requires discussing many aspects of shallow marine deposition, including the nature of tidal and wave energies, shelf gradient, subsidence rates versus rates of deposition in rela- tion to accommodation space, and the effects of variations in sea level. While it is beyond the scope of this publication to discuss these aspects in detail, some basic facts can be established from which a simple depositional model can be developed. The classical interpretation by Swann (1963) of a southwestward-prograding delta that flooded siliclastic materials into the Ridenhower sea can be applied as a basic model for deposition of the Cypress Formation. It is generally accepted that water depths throughout the area were not great and probably never greatly exceeded wave base. That the thickness of the Cypress For- mation exceeds approximately 110 feet only in areas where it appears to be incised into the underlying Ridenhower, facies changes that are widespread and very rapid, and the presence of subaerial indicators (including coals and variegated beds) in the upper one-third of the formation support the interpretation of shallow water deposi- tion interrupted by periods of subaerial exposure. These characteristics also indi- cate that the Cypress delta(s) deposited sediments onto a low-gradient shelf that had very little accommodation space. Sedimentary features indicate that tidal processes more than storm processes con- trolled Cypress deposition. Thick beds of sandstone that contain wispy, wavy, dis- continuous shale laminations or even grade to flaser beds predominate over scattered, thin beds of subhorizontal or cross-laminated sandstones. Sandstone bodies, particularly in the upper Cypress, are lenticular, 1-2 miles long, and less than 1 /2 mile wide. The lenses commonly form a series of subparallel ridges that trend northeast-southwest. These ridges are comprised of thin discrete bodies, generally 3-10 feet thick, that stack and appear to coalesce on electric logs. Sedi- mentary features and sandstone body geometries are not those generally found in river-dominated (lobate) or wave-dominated (cuspate) deltaic depositional sys- tems. The lenticular, stacked, and aligned sandstone bodies of the Richview Field are most analogous to the linear tidal ridges that form in the high-tidal-range- dominated environments of the Ord River Delta of northern Australia (Wright et al. 1 975) or the Gulf of Korea portion of the Yellow Sea (Off 1 963). In this model, then, the highly variable Cypress A sandstone bodies of the lower Cypress in the Richview area represent progradational (regressive) deposits of a tidally dominated delta system capped by tidal-flat siltstones, mudstones, marsh deposits, and thin coals. Variegated beds in this capping horizon indicate subaerial exposure. The beds may have formed as a result of the oxidation or reduction reactions that occur at the groundwater-air interface, or they may represent in some places a remnant soil horizon. 21 The Cypress B and C sandstones appear to be tidal-ridge deposits that formed dur- ing a subsequent, short-lived transgressive pulse that flooded and embayed the earlier delta systems. Variegated beds and minor coals that lie between the Cypress C and D sandstones indicate another period of subaerial influence that followed deposition of the Cypress C sandstone. A final transgressive pulse that marks the end of siliciclastic deposition within the Cypress is represented by the Cypress D inter- val. Because lithologic characteristics of the Cypress D sandstones and the geome- try and alignment of the Cypress D sandstone bodies are similar to those of the Cypress B and C sandstones, the Cypress D sands may also have been deposited as tidal ridges. Immediately overlying the sediments of the Cypress D interval are the carbonates of the widespread Barlow limestone. Diagenesis Petrographic analyses of the reservoir samples show that three diagenetic altera- tions significantly modified the Richview Field reservoir rock. These alterations include (1 ) precipitation of quartz overgrowths, (2) dissolution of feldspar, and (3) precipita- tion of the clay minerals kaolinite, chlorite, and illite/smectite. Precipitation of quartz overgrowths and quartz cement occurred early in the diage- netic events recorded in the Cypress reservoirs. Quartz precipitation in the Cypress B and C sandstones was widespread and, for the most part, unimpeded by detrital clay within the clean, reservoir-quality sandstones. Detrital clay was probably win- nowed by currents during deposition of these sands, which made them susceptible to diagenetic alteration. Where quartz grains are in contact with detrital clay or dia- genetic clay minerals, silica precipitation appears to have been impeded (fig. 13). Feldspar dissolution not only created secondary porosity but also may have enriched the brine waters with the aluminum and silica necessary for the precipitation of kao- linite, chlorite, illite/smectite, and quartz overgrowths. Various stages of feldspar altera- tion occur in the upper Cypress sandstones at Richview. Partial and presumed total dissolution are pervasive in the clean reservoir sandstones. Voids and cavities formed by the dissolved feldspar grains are common. The remaining feldspar is mostly sodium-rich plagioclase. A trace of potassium feldspar also is present. The calcium type plagioclase was probably more extensively altered and dissolved than the other types of feldspar because it is generally less stable under normal reservoir conditions. Three separate methods were used to analyze the reservoir clay minerals: (1) thin section, (2) X-ray diffraction bulk pack, and (3) SEM with an energy dispersive X-ray analyzer (EDX). Although the quantity of clay minerals in the clean reservoir sam- ples appears to be less than 4% of the sample (table 1), knowledge of the types of clay minerals present in the reservoirs and their specific location is crucial for opti- mal development of the reservoirs. Thin section analysis revealed relatively few clay-filled pores in the clean portion of the reservoir. Patchy, clay-filled areas and thinly laminated, bedded clays, probably both detrital and diagenetic in origin, were observed as minor constituents within the cleaner reservoir samples. The diage- netic clay minerals observed by SEM are concentrated near the dissolved feldspar grains where they form a delicate veneer on the surface of quartz grains. Otherwise, the clay minerals are very spotty and rarely coat an entire grain. Both diagenetic kaolinite and chlorite were observed with the SEM in samples of the clean reservoir sandstone. Illite and mixed-layered illite/smectite and kaolinite were found in the bulk x-ray diffraction samples of the reservoir sandstone (table 1 ). Kaolinite (fig. 1 5) and chlorite (fig. 1 6), largely the iron-rich variety, are present in the samples accord- ing to SEM-EDX observations, although bulk X-ray diffraction analysis does not indi- 22 Figure 15 SEM photomicrograph shows kaolinite crystals on a quartz overgrowth substrate. The kaolinite booklets are loosely bound to the quartz grain. The sample is from the Cypress C sandstone reservoir of the Droege Unit No. 2 (1 ,505 feet). cate the presence of chlorite (table 1). Although the detrital clay laminations affect the reservoir by decreasing vertical permeability, the dispersed, diagenetic clay minerals that veneer quartz grains present a large surface area to passing fluids and thus have a greater potential than the detrital clay to reduce reservoir permeability. Petrophysical and Stratigraphic Characteristics That Influence Reservoir Quality Post-depositional processes such as silica cementation and clay mineral precipita- tion have reduced the porosity and permeability of the rocks at Richview Field. Per- meability is a function of pore throat size. Reduction of the pore throat size, which increases flow resistance due to flow path tortuosity, may help to explain the low pro- duction rates and longevity of many Cypress wells. Although primary porosity has been significantly reduced by silica precipitation, secondary porosity of up to several percent has been created by the dissolution of feldspar grains, which yields a net porosity of approximately 20%. While the post-depositional addition of clay minerals has only slightly reduced the porosity and permeability of the reservoir rocks, the susceptibility of these minerals to alteration by reaction to drilling, stimulation, or other fluids injected into the reservoir poses a very significant threat of permeability reduction. This problem is discussed on pages 30-31. Core analysis reports of Cypress cores from 1 1 wells in Section 35, T1 S, and Sec- tion 2, T2S, provided porosity and permeability analyses from 2 cores of the Cypress A sandstone, 9 cores of the Cypress B sandstone, 1 1 cores of the Cypress C sand- stone, and 4 cores of the Cypress D sandstone. The core data indicate that within individual sandstones the permeability is more variable than the porosity. In gen- eral, porosity appears to be fairly constant, and increases slightly with increased permeability. 23 Figure 16 SEM photomicrograph shows iron-rich chlorite rosettes on a quartz grain. Blocky crystals of kaolinite are intermixed. The sample is from the Cypress C sandstone reservoir of the Droege Unit No. 2 (1,510 feet). Permeability generally increases toward the middle of the individual sandstone beds. Measured porosity values for the Cypress A, B, and C sandstones that have high SP values range from 14% to 26% and average approximately 20%, whereas permeability values ranged from 3.5 to 752 millidarcies and average approximately 1 75 millidarcies. The SP deflection for sandstone with average porosity and permea- bility typically is more than 90% of the 100% clean sandstone response. Average measured porosities for three cores of reservoir-quality Cypress D sandstone are approximately 1 7%. A maximum permeability of 88 millidarcies was measured from the Cypress D sandstone cores, but the average permeability for the reservoir- quality Cypress D sandstones was 36 millidarcies. Reservoir compartmentalization is widespread throughout the Cypress sandstones at Richview Field and occurs where discrete sandstone packages are stacked or shingled with thin shales or impermeable, shaley sandstone separating the pack- ages. The shale break between the Cypress B and C sandstones, apparent in figs. 6 and 8, separates these sandstones into horizontal compartments. In parts of Richview Field, the intervening shale is not obvious on logs, and the B and C sand- stones appear to form one sandstone body. Although the two sandstones may coa- lesce and actually form one compartment in a limited area, core analyses and core to log comparisons show that a thin shale or shaley sandstone commonly is present. In these cases, the SP or resistivity log failed to significantly react because of the thinness of the impermeable bed. The isolation of the two separate compartments is therefore maintained, although the conventional electric log interpretation suggests that only one compartment exists. In this situation, a secondary recovery program may fail to flood one of the two compartments because the more permeable com- partment accepts the flood and is effectively drained, while the other compartment, which may not be permeable at the wellbore, is ineffectively drained. Small-scale heterogeneity is common and is created by the abundant shale laminations ob- served within the sandstones packages. Thin sections from this type of reservoir rock in other fields show isolated, oil-saturated compartments thinner than 1 centi- 24 meter that occur between wavy shale laminations. From a practical standpoint, the oil in these small-scale compartments is nonproducible. Identification of Play The upper Cypress sandstones that make up the reservoirs that constitute Richview Field were deposited as linear tidal ridges during a brief marine transgression. The northeast-trending lenticular sand ridges are encased in shale that forms the reservoir seal. Widespread, thin shale beds appear to separate and compartmentalize these stacked reservoirs. Oil is trapped at Richview by a combination of structure and stratigraphy. Structural closure is not a factor in trapping this oil. Oil is trapped in the updip portions of len- ticular sandstone bodies that drape across or are on the flank of a structural fold (saddle). The Richview structure is part of a subsidiary fold that formed along the up- lifted side of the Du Quoin Monocline. Flexure and the resultant fracturing along the monocline probably facilitated oil migration and increased the oil productivity from Richview Field. PRODUCTION CHARACTERISTICS Production and Completion Procedures Records indicate that rotary drive rigs were used to drill the wells at Richview Field. Mud systems utilized freshwater with gel, an additive that increases particle suspen- sion. Most wells at Richview Field were drilled and cased through the reservoirs and then perforated with two to eight holes per foot. Completions commonly included hydraulic fracturing of the reservoir, usually using lease oil and sand. Fracture treat- ments using up to 20,000 gallons of fluid and 20,000 pounds of sand were adminis- tered, but most treatments used less than 5,000 gallons of fluid and 5,000 pounds of sand. Records show that many wells had natural completions without fracture stimulation. Acid was used mostly for mud and perforation cleanup. Calcite cement was apparently not a problem in these reservoirs; therefore, large-scale acid stimu- lation was unnecessary. Wells were pump produced from their initial completion; no flowing wells are recorded in the field. Production and Waterflood Data Production background for Richview Field was described on page 7. The decline curve (fig. 5) clearly shows the two-stage discovery and development of the field. Stage one, from 1946 through 1961, includes the initial discovery and production from the subsidiary Cypress B sandstone pool in Section 10. The second stage, starting in late 1 961 , includes the discovery and development of the main pool and the subsidiary pool in Section 1 1 . Most of the field was developed by early 1 963. A very steep decline in production from 1 963 to 1 966 approximates the natural decline of primary production as the reservoir's gas solution energy was rapidly depleted. Although an early flood was initiated in September of 1 963, the effects are not imme- diately reflected on the curve. The effect of this early waterflood and a second flood initiated in October 1966 was a strong reversal of the decline in 1967. Restoration and maintenance of reservoir energy through waterflooding have proved to be very effective and are reflected in the flatness of the decline curve and the longevity of production. Ultimately, the maintenance of reservoir energy assisted in recovering significant amounts of incremental oil. Five waterflood projects have been established in the main pool of Richview Field. Of the three not mentioned above, one was initiated in 1970 and the other two in 25 1971. Records show that the five waterflood projects included 12 injection wells, mostly converted producers, and 33 producers. The combined production and injec- tion data for all five projects from inception of the waterfloods through 1 985 indicate that 1 .6 million barrels of oil and 1 2.3 million barrels of water were produced from the Cypress reservoirs and 22 million barrels of water were injected into the Cypress. Injection water was a combination of produced Cypress brine and brine from the overlying Tar Springs sandstone. Well head injection pressure records are available for only the Richview waterflood unit in the northern part of Section 2. Injec- tion pressures in this waterflood range from approximately 50 to 1 ,000 psi but are commonly between 500 and 1 ,000 psi. Reservoir Temperature, Pressure, and Drive Drill stem tests and drilling mud measurements noted on electric logs are the only sources of reservoir pressure and temperature data for the field. The highest recorded drill stem test shut-in pressures are 475 to 480 psi at a depth of approxi- mately 1 ,500 feet. The standard hydrostatic pressure gradient of 0.43 psi/foot is sig- nificantly greater than the 0.32 psi/foot value calculated from the drill stem test data. Several factors may contribute to the low reservoir pressure measurements: (1 ) Cypress reservoirs, in general, yield under-pressured values on drill stem tests, (2) formation damage from drilling fluids is very possible, and (3) the shut-in duration on the tests may have been too short, particularly if formation damage had occurred. A maximum temperature of 96°F was measured from drilling mud during logging operations and is therefore the closest estimation of bottomhole temperature. Numerous well logs recorded measurements between 90° and 96T. Gas solution appears to be the primary drive mechanism at Richview, although no drill stem test reports recorded gas to the surface and most tests recovered low amounts of gas. That the reservoirs are encased in shale and that waterflooding was initiated early in the production history indicate water was not the energy source in the field. Oil Characteristics Oil samples were collected for gravity and viscosity analysis in 1992 from the McDonald-Richardson No. 2, SW NW, Section 2, and the Thompson No. 7, NE SE, Section 35. Gravity values for the two wells were similar, 37.5 and 37.3 degrees API at 60T, as were the viscosity values, 4.9 and 4.7 cp at 73T, respectively. The Thompson No. 7 is an anomalous well; it produces from the Cypress A sandstone, whereas the McDonald-Richardson No. 2 produces from the Cypress B and C sand- stones. Records for the Richview waterflood unit in the northern part of the field showed values similar to those above: 39 degrees API gravity at 60°F and a viscosity of 3.3 cp at 84°F. Geochemical analyses of the oils and brines from the Thompson No. 7 and three other wells in the field are given in Appendix A. Water Characteristics Reservoir brine samples were collected simultaneously with the oil samples from the four wells used for oil geochemical analysis. Brine geochemical analyses (see Appendix A) include the measurement of Eh, pH, brine resistivity, and quantity of anions and cations. Samples from the Weisbecher Community No. 1 , SW SW, Sec- tion 2, and the Edwards waterflood unit No. 1 , SE SE, Section 3, may contain com- mingled waterflood brines consisting of Tar Springs and reinjected Cypress brine and, therefore, should not be considered as native Cypress brine data. The sample from the Pitchford No. 1 , SE SW, Section 1 0, is from the Cypress B sandstone of the 26 initial discovery subsidiary pool and should represent original formation brine. The Thompson No. 7 is one of the few wells completed in the Cypress A sandstone. The brine sample from this well therefore represents the Cypress A sandstone and should be uncontaminated by the waterflooding of the primary Cypress B and C sandstones. Brine water resistivities of these samples measured between 0.068 and 0.077 ohm-m at 77°F and may be useful for calculations requiring an R w value. Resistivity values from the Pitchford No. 1 and the Thompson No. 7 are 0.068 ohm-m and 0.072 ohm-m, respectively, and are least likely to be influenced by reinjected fluids. Volumetrics Original oil in place (OOIP) and stock tank original oil in place (STOOIP) were deter- mined for the Cypress B, C, and D sandstones. The recovery factor was also calcu- lated for the entire field. An adjustment in the cumulative production for the field is necessary to more accurately calculate the recovery factor because an unknown quantity of Cypress A sandstone production is included in the cumulative value. Six to eight wells appear to have produced from the Cypress A interval. Calculation of the volumetrics of the Cypress A sandstone is not feasible because (1) producing horizons and sandstone lenses are noncorrelative, (2) some perfora- tions are below the oil-water contact, and (3) in the Thompson No. 7, the oil-bearing horizon lies below the oil-water contact for the rest of the field. Total production data from the Cypress A interval is not available because of commingled production with the Cypress B and C intervals and the reporting of production by lease rather than by individual well. An arbitrary quantity of 100,000 barrels (12,000-16,000 BO/well) was subtracted from the total field production in order to adjust the recovery effi- ciency value to reflect production from only the Cypress B, C, and D intervals. The OOIP was calculated using the standard volumetric formula: OOIP = 7,758xHxAx = average porosity of reservoir sandstone S w = water saturation of reservoir sandstone An average porosity value of 20%, determined from the 1 1 available core analyses in the field, was used in the volumetric calculations for the Cypress B and C sand- stones. An average porosity value of 17%, also determined from core, was used for the Cypress D sandstone. A conservative water saturation value of 40% was assumed for calculations. Calculations of water saturation from logs that show a definite oil response (oil leg) range from approximately 30% to 45%. The height (thickness) and area of net reservoir sandstones were determined from the thick- ness maps (figs. 9, 10, and 11). STOOIP represents the conversion and reduction of oil volume at original reservoir pressure to oil volume at atmospheric conditions. A reduction in oil volume is caused by the release of solution gas dissolved in the oil at reservoir pressure as the confin- 27 ing pressure on the oil approaches atmospheric pressure. The assumption that solution gas is the driving mechanism for these reservoirs requires this conversion. The quantity of solution gas in any particular reservoir varies. Without actual labora- tory or field data from a reservoir, a value for the conversion factor or formation vol- ume factor (B oi ) must be assumed. The most commonly used values in the Illinois Basin range from 1 .1 to 1 .1 5. Considering the low hydrostatic pressure values from drill stem tests and the low volume of gas recovered on these tests, a B oi value of 1.10 was used for the Richview volumetric calculations. STOOIP is calculated by dividing the OOIP by the formation factor. The volumetric calculations (in barrels of oil) using the factors described above are as follows: Cypress D sandstone OOIP = 863,000 STOOIP = 785,000 Cypress C sandstone OOIP = 3,551,000 STOOIP = 3,228,000 Cypress B sandstone OOIP = 3,297,000 STOOIP = 2,998,000 Total OOIP = 7,711,000 Total STOOIP = 7,011,000 Cumulative oil production for Richview Field is 3.3 million barrels. The Cypress B, C, and D cumulative oil production is 3.2 million barrels, after subtracting 100,000 bar- rels of Cypress A sandstone production as mentioned above. The recovery factor of the combined Cypress B, C, and D sandstones is therefore 45.6%. Recovery factors for the separate sandstones cannot be calculated from the readily available data because data are commonly reported only by lease and are likely to include com- mingled Cypress production values. RECOMMENDATIONS FOR DEVELOPMENT AND PRODUCTION STRATEGY Each stage of reservoir development— from the drilling of the discovery well to the final abandonment of a reservoir — should employ a strategy to optimize production. A comprehensive, detailed discussion regarding the methods and techniques avail- able to achieve optimum production from a field is beyond the scope of this publica- tion, but some recommendations, based on observations of the Richview Field and comparisons of data, can be offered. Various field studies have established that the most effectively drained reservoirs are those that have been developed by one operator or those that, through a coordi- nated effort, incorporate all operators from separate leases into a single waterflood program. Examples of increased efficiency from a field operated by a single pro- ducer or where production has been unitized and coordinated include Tamaroa Field (Grube 1992), Energy Field (Udegbunam and Huff 1994), and Zeigler Field (Sim et al. 1994, Seyler 1998). 28 Waterflood and Pressure-Maintenance Programs Waterflood and pressure-maintenance programs are the most effective ways to increase cumulative production. Drilling and completion techniques, especially those preventing formation damage due to alteration of indigenous clay minerals, also can influence the amount of recoverable reserves. Finally, while enhanced oil recovery (EOR) programs (for example, carbon dioxide treatment) are proving eco- nomical and gaining technical acceptance, Fisher and Galloway (1 983) found that in Texas, intensive development and infill drilling most effectively extend and increase production from an oil field. They base this finding on the amount of oil recovered by EOR techniques. Ninety percent of the EOR programs for this study are miscible gas flood programs. Retaining reservoir energy is crucial to maximizing recovery efficiency, particularly in a reservoir of limited extent with a correspondingly limited drive. Initiation of water- flood projects early in the life of production at Richview Field probably retained or at least reestablished reservoir energy. The high recovery factor (45.6%) calculated for Richview Field is likely to be partly the result of these pressure-maintenance waterflood projects. A potential problem with waterflooding of Mississippian sandstone reservoirs such as those at Richview Field is that the stacking or shingling of reservoir sandstones creates discrete compartments that can be bypassed by a waterflood. This situation can develop either where a compartment is not present in an injection well but is present in the offseting producer(s) or where the injector well (probably a converted producer) penetrates a compartment that is not in communication with a producer. Primary production is therefore drained from the separate compartment while the waterflood, in communication through another compartment or multiple compart- ments, bypasses the separate compartment. Stratigraphic correlations between vertically stacked or shingled, discontinuous reservoir compartments are not always obvious. A misunderstanding of these characteristics can lead to miscorrelations that consequently inhibit development and production. Within Richview Field, the north to south thickening of the Cypress C sandstone results from shingling or stacking of additional sandstone lenses, some of which may contain bypassed oil as described above. Also, compartments may exist in the northern part of Section 2 where the general northeast-southwest trend of the Cypress B and C sandstones is cross-cut by northwest-southeast-trending re- entrants and salients. A possible interpretation here is that a northwest-southeast- trending channel may have dissected the sand ridge and caused a break in the northeast-southwest-trending flow units. While the ridge deposits and the channel deposits may appear correlative on logs, impermeable zones may be present at the transition between the two deposits. The impermeable zone at this transition will divide the reservoir into compartments. A similar waterflood problem develops where multiple stacked reservoir sandstones are present in a waterflood unit but permeability variations between compartments are great enough to channel the flood away from the compartments with lower per- meability. In this case, the less permeable compartments contain bypassed, mov- able oil. Even compartments with increased permeability away from the wellbore contain bypassed oil. Because hydraulic fracturing was a common completion prac- tice in many of the Mississippian stacked sandstone reservoirs in Illinois, including Richview, the capability to selectively flood a lower-permeability compartment may be limited. The induced fractures are typically designed to propagate through all 29 compartments within the oil column and cause communication between all compart- ments. Therefore, a particular compartment cannot be isolated for flooding. Reservoir continuity and flow unit correlation should be evaluated through use of field pressure analyses, including pulse, interference, build-up, draw-down, and tracer tests (Lee 1982). Pressure maintenance and other reservoir management requirements can also be evaluated using field tests and accurate, well-specific pro- duction histories that include water and, if possible, gas production. Avoiding Clay Damage Caused by Drilling and Completion Techniques While their effects on cumulative production are not as obvious as waterflooding, drilling and completion techniques can be significant factors for both short-term ini- tial production and overall cumulative production. Evaluation of well performance at Tamaroa Field (Grube 1 992) established that wells with open hole completions that did not drill deeper than the reservoir, and particularly wells that were completed using standard tools (cable) to penetrate the reservoir, tend to have the greatest cumulative production and higher initial production rates. These findings suggest that these Cypress sandstones may be susceptible to formation damage by drilling fluids or completion procedures. Drilling fluids, both the filtrate and the fines portion, can reduce permeability during invasion either (1 ) by dislodging clay-sized fines that migrate and catch in pore throats (2) or by clogging pore throats near the well- bore with drilling fines. Fluids introduced into the reservoir during drilling, completion, and other develop- ment procedures can interact with the diagenetic kaolinite, chlorite, and mixed-layer illite/smectite common to many of the Cypress reservoirs. Interaction of these clay minerals with the introduced fluids can significantly reduce the permeability of the reservoir. Although clay minerals are minor constituents in the Richview sandstones, they are in almost total contact with drilling, completion, and development fluids because they line pores and pore throats. Because clay minerals have a high surface-area- to-volume ratio, they are very susceptible to alteration, which consequently dam- ages the formation when fluids are introduced. Kaolinite, the dominant clay mineral in the Richview reservoirs, generally is chemi- cally stable in the presence of the commonly introduced drilling, completion, and development fluids as long as the salinity of the introduced fluids does not greatly differ from the original brines. However, the diagenetic kaolinite is very loosely attached to the surface of host grains and can be easily dislodged and moved by flu- ids. Kaolinite particles can then migrate into pore throats, where they lodge, decrease permeability, and reduce production flow. This process occurs, particularly in the area close to the wellbore, where fluid flow rates reach velocities capable of migrat- ing these particles. Clay stabilization systems are available that can easily resolve this potential problem, as long as treatment is applied early in the history of the well (Almon and Davies 1981). Mixing incompatible brines can also cause kaolinite migration damage (Vaidya and Fogler 1 990). "Water shock," a term Vaidya and Fogler applied to an abrupt change in salinity in a reservoir, leads to a rapid and drastic decline in permeability. The shock is caused by introducing fresh or low-salinity water into a reservoir containing normal- to high-salinity brine. This problem can be avoided in the case of a water- flood by gradually lowering the salinity of an injection fluid, or in the case of drilling 30 fluids by using a brine that is compatible with the reservoir being drilled (Vaidya and Fogler1990). Illite and mixed-layer illite/smectite clay minerals also react adversely to changes in water salinity. These clay minerals can swell when subjected to fresh water (Grim 1 947, Allen and Roberts 1 989). Swelling of these clays also decreases permeability. Chlorite that has a high iron content is a clay mineral that is widespread in the Cypress sandstones. High-iron chlorite is extremely sensitive to acid and to oxygenated waters (Almon and Davies 1 981 ). It dissolves readily in dilute HCI, and the liberated iron reprecipitates as an iron hydroxide gel when the acid is spent. This iron hydrox- ide clogs the pore throats, effectively blocking the production flow paths. This poten- tial problem can be avoided if an oxygen scavenger and an iron chelating agent are added to the acid and all the treatment fluid introduced into the reservoir is recov- ered. Because of the minor amount of calcite in the Richview reservoirs, the only practical use of acid is for mud clean-up during completion. Even then, Almon and Davis (1981) recommend that an oxygen scavenger and an iron chelating agent should be used and that all acid should be removed from the hole rapidly. Almon and Davis (1 981 ) further recommend that if ferric hydroxide has been precipitated in the reservoir due to an inadequately designed acid treatment, it can be removed by treatment with weak (5%) HCI combined with appropriate iron chelating agents and an oxygen scavenger. They strongly recommended that all acid should be recov- ered before it is spent. Almon and Davies (1981) further recommend that any program that introduces flu- ids into a reservoir be designed for the specific clay mineral(s) in that reservoir. Therefore, a mineralogical analysis of the reservoir, particularly of the clay min- eral(s), is highly recommended prior to introduction of fluids into the system. Four suggested clay mineral analyses are: (1 ) scanning electron microscope (SEM) with energy dispersive X-ray (EDX) analyzer, (2) X-ray diffraction analysis of the fine fraction (reservoir clays alone), (3) petrographic analysis by thin section, and (4) bulk X-ray diffraction analysis. At the very minimum, analysis by SEM-EDX will reveal where the clay minerals are located and indicate most types of clay minerals and their relative iron content. Brine analysis, although not mentioned by Almon and Davies (1 981 ), should be included; the composition of the introduced fluids must also be known to evaluate the potential chemical reactions that may occur between the components of the res- ervoir, particularly reservoir fluids, and the introduced chemicals. Iron materials used in oil well installations, such as casing and tubing, should also be considered as a re- active material that can affect the reservoir. An optimum drilling and development program that avoids formation damage can then be designed based on these results. Infill Drilling Infill drilling of Richview Field may prove to be economically feasible. Whitaker and Finley (1992) found that 10-acre well spacing and a 5-spot waterflooding program combined with off-pattern infill wells yielded an estimated recovery efficiency of more than 49% and possibly as much as 60% (Steven Whitaker, personal communi- cation 1 992) from marine bar-type reservoirs at Bartelso Field. Considering the simi- larity of the reservoir characteristics at Bartelso and Richview Fields, infill drilling to increase the recovery efficiency from 45% to 60% may be warranted. Infill drilling may be required to assess the degree of reservoir compartmentalization that exists throughout the Richview area. The compartments related to the stacking TimvAnv APR 1 1999 31 of the Cypress C sandstone and the complication in the northern part of Section 2 where a channel appears to cut across the northeast-southwest-trending reservoirs may have to be evaluated by infill drilling. REFERENCES Allen, T.O., and A. P. Roberts, 1989, Formation damage (chapter 5), in Production Operations: Oil & Gas Consultants International, Inc., Tulsa, Oklahoma, p. 67-79. Almon, W.R., and D.K. Davies, 1981, Formation damage and crystal chemistry of clays, in? J. Longstaffer, ed., Clays and the Resource Geologist: Mineralogical Association of Canada Short Course, Calgary, p. 81-103. Bristol, H.M., 1 968, Structure of the Base of the Mississippian Beech Creek (Barlow) Limestone in Illinois: Illinois State Geological Survey, Illinois Petroleum 88, 1 2 p. Cole, R.D., and W.J. Nelson, 1995, Stratigraphic Framework and Environments of Deposition of the Cypress Formation in the Outcrop Belt of Southern Illinois: Illinois State Geological Survey, Illinois Petroleum 149, 47 p. Fisher, W.L., and W.E. Galloway, 1983, Potential for Additional Oil Recovery in Texas: The University of Texas at Austin, Bureau of Economic Geology Geological Circular 83-2, 20 p. Grim, R.E., 1947, Relation of clay mineralogy to origin and recovery of petroleum: AAPG Bulletin, v. 31, p. 1491-1499. Grube, J. P., 1992, Reservoir Characterization and Improved Oil Recovery from Multiple Bar Sandstones, Cypress Formation, Tamaroa and Tamaroa South Fields, Perry County, Illinois: Illinois State Geological Survey, Illinois Petroleum 138, 49 p. Howard, R.H., and ST. Whitaker, 1990, Fluvial-estuarine valley fill at the Mississippian-Pennslvanian unconformity, Main Consolidated field, Illinois, in J.H. Barwis, J.G. McPherson, and J.R.J. Studlick, eds., Sandstone Petroleum Reservoirs: Springer- Verlag, New York, p. 319-341. Hopkins, M.E., and J.A. Simon, 1975, Pennsylvanian System, in H.B. Willman, E. Atherton, T.C. Buschbach, C. Collinson, J. Frye, M.E. Hopkins, J.A. Lineback, and J.A. Simon, Handbook of Illinois Stratigraphy: Illinois State Geological Survey Bulletin 95, p. 163-201. Lee, J., 1982, Well Testing: New York, Society of Petroleum Engineers of AIME, Textbook Series, Vol. 1, 159 p. Nelson, W.J., 1995, Structural Features in Illinois: Illinois State Geological Survey Bulletin 100, 144 p. Off, T., 1 963, Rhythmic linear sand bodies caused by tidal currents: AAPG Bulletin, v. 47, p. 324-341. Oltz, D.F., 1 994, Improved and Enhanced Oil Recovery in Illinois Through Reservoir Characterization: Final Report prepared for U.S. Department of Energy, DOE/BC/1 4250-1 9(UC-1 22), 403 p. 32 Potter, P.E., E. Noscow, N.M. Smith, D.H. Swann, and F.H. Walker, 1958, Chester cross-bedding and sandstone trends in the Illinois Basin: AAPG Bulletin, v. 42, p. 1013-1046. Seyler, B., 1998, Geologic and Engineering Controls on Aux Vases Sandstone Reservoirs in Zeigler Field, Illinois — A Comprehensive Study of a Well-managed Oil Field: Illinois State Geological Survey, Illinois Petroleum 153, 79 p. Siever, R., 1951, The Mississippian-Pennsylvanian unconformity in southern Illinois: AAPG Bulletin, v. 35, p. 542-581. Sim, S.K., B. Seyler, and E.O. Udegbunam, 1994, An Integrated Geologic and Engineering Study of the Plumfield Lease Aux Vases Reservoirs, Zeigler Field, Franklin County, Illinois: Illinois State Geological Survey, Illinois Petroleum 146, 29 p. Swann, D.H., 1 963, Classification of Genevievian and Chesterian (Late Mississippian) Rocks of Illinois: Illinois State Geological Survey, Report of Investigations 216, 91 p. Udegbunam, E.O., and B.G. Huff, 1994, Integrated Geologic and Engineering Model for Improved Reservoir Development and Management at Energy Field, Williamson County, Illinois: Illinois State Geological Survey, Illinois Petroleum 145, 25 p. Vaidya, R.N., and H.S. Fogler, 1990, Fines migration and formation damage — Influence of pH and ion exchange: 9th SPE Symposium on Formation Damage, Lafayette, LA, p. 125-132. Van Wagoner, J.C., R.M. Mitchum, K.M. Campion, and V.D. Rahmanian, 1990, Siliciclastic Sequence Stratigraphy in Well Logs, Cores, and Outcrops — Concepts for High-Resolution Correlation of Time and Facies: Tulsa, OK, AAPG Methods in Exploration Series, No. 7, 55 p. Whitaker, ST., and A.K. Finley, 1 992, Reservoir Heterogeneity and the Potential for Improved Recovery within the Cypress Formation at Bartelso Field: Illinois State Geological Survey, Illinois Petroleum 137, 40 p. Wright, L.D., J.M. Coleman, and B.G. Thorn, 1975, Sediment Transport and Deposition in a Macrotidal River Channel, Ord River, Western Australia, in L.E. Cronin, ed., Estuarine Research, Vol. II: Academic Press, New York, p. 309-322. 33 APPENDIX A CYPRESS RESERVOIR FLUID ANALYSIS API Number 121890191900 Operator Thompson/Evans Well Name George Thompson No. 7 Location NE NW SE, Sec. 35, T1S R1 W Reservoir Depth (ft) 1 ,532 Surface Elevation (ft) 553 (ground level) Water Flooded Yes Brine Analysis Brine sample number EOR-B24 Resistivity 0.0719 ohm-m @ 25°C Eh(mV) -99 pH 7.02 Total dissolved solids 1 13,763 ppm Anion chemistry (mg/L) Br NA I NA CI 67,712 N0 3 NA co 3 NA so 4 NA HC0 3 NA Cation chemistry (mg/L) Al NA I NA Sb <0.3 As NA K 186 Se NA B 3.28 Li NA Si 4.14 Ba 11.8 Mg 1,760 Sr 302 Be NA Mn 2.57 Ti 0.21 Ca 4,125 Mo <0.05 V NA Cd <0.05 Na 39,650 Zn <0.02 Co <0.05 NH 4 NA Zr 0.1 Cr NA Ni <0.15 Cu 0.24 Pb <0.4 Fe 8.0 Rb NA Oil Analysis Oil sample number EOR-021 Hydrocarbon fraction (%) Saturated hydrocarbons 19.11 Aromatic hydrocarbons 32.84 Resins 20.14 Asphaltenes 2.42 Selected hydrocarbon ratios C17/C18 1.02 Pristane/Phytane 1 .82 C17/Pristane 0.85 C18/Phytane 0.47 34 APPENDIX A continued API Number 121890182700 Operator N.A. Baldridge Well Name Weisbecher Community No. 1 Location NW SW SW, Sec. 2, T2S R1W Reservoir Depth (ft) 1 ,482 Surface Elevation (ft) 550 (KB) Water Flooded Yes Brine Analysis Brine sample number EOR-B25 Resistivity 0.0771 ohm-m @25°C Eh (mV) -193 pH 6.56 Total dissolved solids 104,201 ppm Anion chemistry (mg/L) Br NA I NA CI ( 32,658 N0 3 NA co 3 NA S0 4 NA HC0 3 NA Cation chemistry (mg/L) Al NA Fe 5.7 Pb <0.4 As NA I NA Rb NA B 2.98 K 153 Sb <0.3 Ba 90.5 Li NA Se NA Be NA Mg 1,270 Si 4.84 Ca 3,070 Mn 1.69 Sr 195 Cd <0.05 Mo <0.05 Ti 0.71 Co <0.05 Na 36,750 V NA Cr NA NH 4 NA Zn <0.02 Cu 0.2 Ni <0.15 Zr 0.09 Oil Analysis Oil sample number EOR-022 Hydrocarbon fraction (%) Saturated hydrocarbons 27.84 Aromatic hydrocarbons 27.60 Resins 8.55 Asphaltenes 1.8 Selected hydrocarbon ratios C17/C18 1.09 Pristane/Phytane 1.96 C17/Pristane 0.83 C18/Phytane 0.46 35 APPENDIX A continued API Number 121890183600 Operator Canter Drilling Well Name Edwards Unit No. 1 Location SE SE SE, Sec. 3, T2S R1W Reservoir Depth (ft) 1 ,474 Surface Elevation (ft) 525 (ground level) Water Flooded Yes Brine Analysis Brine sample number EOR-B26 Resistivity 0.0758 ohm-m @ 25°C Eh(mV) -131 pH 6.76 Total dissolved solids 106,489 ppm Anion chemistry (mg/L) Br NA I NA CI 63,878 N0 3 NA C0 3 NA S0 4 NA HC0 3 NA Cation chemistry (mg/L) Al NA Fe 16.1 Pb <0.4 As NA I NA Rb NA B 3.02 K 160 Sb <0.3 Ba 26.5 Li NA Se NA Be NA Mg 1,390 Si 4.51 Ca 3,345 Mn 1.67 Sr 216 Cd <0.05 Mo <0.05 Ti 0.18 Co <0.05 Na 37,450 V NA Cr NA NH 4 NA Zn <0.02 Cu 0.18 Ni <0.15 Zr 0.09 Oil Analysis Oil sample number EOR-023 Hydrocarbon fraction (%) Saturated hydrocarbons 26.01 Aromatic hydrocarbons 29.10 Resins 5.87 Asphaltenes 1.43 Selected hydrocarbon ratios C17/C18 1.03 Pristane/Phytane 1 .87 C17/Pristane 0.89 C18/Phytane 0.49 36 APPENDIX A continued API Number 121892407200 Operator Elmer Oelze, Jr. Well Name Pitchford No. 1 Location SE SE SW, Sec. 10, T2S R1W Reservoir Depth (ft) 1,530 Surface Elevation (ft) 582 (ground level) Water Flooded No Brine Analysis Brine sample number EOR-B27 Resistivity 0.0676 ohm-m @ 25°C Eh (mV) -209 pH 6.91 Total dissolved solids 122,960 ppm Anion chemistry (mg/L) Br 150 I NA CI 75,000 N0 3 <0.04 co 3 0.03 so 4 <1 HCO 88. NH 4 46 Cation chemistry(mg/L) Al <0.04 Fe 5.7 Pb <0.4 As <0.5 I NA Rb NA B 1.6 K 172 Sb 1.2 Ba 14.2 Li 6.31 Se <0.7 Be 0.011 Mg 2,040 Si 3.3 Ca 5,120 Mn 3.22 Sr 302 Cd <0.05 Mo <0.08 Ti 0.04 Co <0.07 Na 40,010 V <0.08 Cr <0.07 NH 4 NA Zn <0.02 Cu <0.05 Ni <0.1 Zr <0.08 Oil Analysis Oil sample number EOR-024 Hydrocarbon fraction (%) Saturated hydrocarbons 41.54 Aromatic hydrocarbons 22.16 Resins 6.42 Asphaitenes 1.9 Selected hydrocarbon ratios C17/C18 1.03 Pristane/Phytane 1.98 Cl7/Pristane 0.86 C18/Phytane 0.45 37 APPENDIX B RESERVOIR SUMMARY Field Richview Location Washington County, Illinois Tectonic/Regional Paleosetting Intracratonic Basin Geologic Structure Saddle along anticline Trap Type Structural/stratigraphic Reservoir Drive Gas solution Original Reservoir Pressure NA; DST shut-in pressures range up to 480 psi Reservoir Rocks Age Mississippian (Chesterian) Stratigraphic unit Cypress Lithology Quartz arenite Wetting characteristics NA Depositional environments Marine tidal ridges, vertically stacked Productive facies Sandstones of the clean, central ridge Petrophysics ( and k from unstressed conventional core; Cypress B and C sandstones) Average (%) Range (%) Cutoff ♦ 20 14-26 16 ka\r (md) 175 3.5-752 100 k liquid NA NA NA s w NA 30^5 NA So, NA NA NA s » NA NA NA Cementation factor NA NA NA Source Rocks Lithology and stratigraphic unit New Albany Time of hydrocarbon maturation Permo-Triassic Time of trap formation Chesterian (stratigraphic); Pennsylvanian/Permian (structural) Cypress Reservoir Dimensions Depth 1,480 ft (940 ft, subsea elev.) Areal dimensions 667 net acres Productive area As above Number of pay zones 3 Hydrocarbon column 42 ft (Cypress B and C interval combined) Initial fluid contacts Oil-water = 963 ft Avg. net sand thickness Cypress B = 9.0 ft; south offset = 4 ft Cypress C = 9.9 ft Cypress D = 2.0 ft Initial reservoir temperature 96°F (estimated from logs) Fractured Hydraulically induced 38 APPENDIX B continued Wells Spacing 10 acre primary Pattern Normal in Section 35 and north half of Section 2, variable in south half of Section 2 and in Sections 3, 10, 11, and 15 Total Producers 89, Water source 1, Observation 0, Suspended NA, Injection 11, Disposal 1, Abandoned 37 (recorded), Dry holes 53 Reservoir Fluid Properties Hydrocarbons Type oil and gas Gas-oil ratio NA API Gravity 37°to39° B 0/ 1.10 (estimate) Viscosity 4.7 cp to 4.9 cp @ 73°F, 3.3 cp @ 84° F Bubble point pressure NA Formation water Resistivity 0.077 to 0.068 ohm-m at 77°F Total dissolved solids 1 04,000-1 23,000 ppm Volumetrics In-place 7,011,000 BO STOOIP (total) Cypress D sandstone 785,000 Cypress C sandstone 3,228,000 Cypress B sandstone 2,998,000 Cumulative production 3,345,000 BO through Dec. 1995 Ultimate recovery 3,500,000 BO Recovery efficiency Primary 17.6% Secondary 28.0% Tertiary none Typical Drilling/Completion/Production Practices Completions Most wells were cased through pay, perforated with two to four shots per foot and hydraulically fractured. Drilling fluid Fresh water mud with gel additive Fracture treatment Most fracture stimulations utilized from 2,000 to 5,000 gallons of crude oil with 2,000 to 5,000 pounds of 20-40 mesh sand propant. Acidization None; perforation cleanup only Producing mechanism Primary = pump; secondary = pump Typical Well Production (to date) Average initial production (IP) 56 BOPD; Range <1 to 180 BOPD main field, 1 1 BOPD southern offset, 30 BOPD southeastern offset Cumulative production NA Water-oil ratio (initial) NA 39