IP 146 M.Q%: QaJl^u^^i An Integrated Geologic and Engineering Study of the Plumfield Lease Aux Vases Reservoirs, Zeigler Field, Franklin County, Illinois Steve K. Sim, Beverly Seyler, Emmanuel O. Udegbunam A + Illinois Petroleum 146 1994 Department of Energy and Natural Resources ILLINOIS STATE GEOLOGICAL SURVEY # H IJMHI STATE ^GEOLOGICAL SURVEY 3 3051 00004 8797 An Integrated Geologic and Engineering Study of the Plumfield Lease Aux Vases Reservoirs, Zeigler Field, Franklin County, Illinois Steve K. Sim, Beverly Seyler, Emmanuel O. Udegbunam Illinois Petroleum 146 1994 ILLINOIS STATE GEOLOGICAL SURVEY Morris W. Leighton, Chief Natural Resources Building 615 E. Peabody Drive Champaign, Illinois 61820-6964 DISCLAIMER This report was prepared by the Illinois State Geological Survey (ISGS) for 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, find- ings, conclusions, or recommendations expressed herein are those of the authors and do not necessarily reflect the views of the USDOE. Neither the ISGS, any member of the ISGS staff, the Illinois Department of Energy and Natural Resources (ENR), nor the USDOE assumes any liability with respect to the use, or for any damages resulting from the use, of any information contained in this report. Use of trademarks and brand names in this report does not constitute endorsement of any product by the ISGS, ENR, or USDOE. Editor — E. Anne Latimer Graphic Artist — Sandra Stecyk Printed by the authority of the State of Illinois/1994/1200 printed with soybean ink on recycled paper CONTENTS ABSTRACT 1 INTRODUCTION 2 FIELD HISTORY 3 Production History 3 Pressure Maintenance History 3 Historical Recovery Performance 4 RESERVOIR CHARACTERIZATION 4 Geological Description of Reservoirs at Zeigler Field 4 Depositional processes 5 Bottom-hole pressure surveys 6 Trapping mechanism 7 Diagenesis 7 Reservoir Properties 8 Drill stem test data 8 Original reservoir pressure from drill stem tests 12 Effective in situ permeability and permeability-thickness product 12 Estimated damage ratio 13 Determination of productivity index 13 Trends of Reservoir Data in the Plumfield Lease 15 Hydrocarbon PVT properties 16 Initial water saturations 1 7 Oil-water contact 17 Estimation of Reserves 20 Geological Modeling 20 RESERVOIR SIMULATION 22 Gridblock Selection and Simulation Technique 22 Initialization of the Reservoir Simulation Model 22 History Match 23 Waterflood History in the Plumfield Lease 23 Oil Recovery Factor and Unrecovered Mobile Oil in the Plumfield Lease 26 FUTURE DEVELOPMENT OPPORTUNITIES IN THE PLUMFIELD LEASE 26 SUMMARY AND CONCLUSIONS 27 ACKNOWLEDGMENTS 28 REFERENCES 28 FIGURES 1 Location of Zeigler Field, Franklin County, Illinois 2 2 Generalized stratigraphic column for southern Illinois 2 3 Well location map of Plumfield and Mack leases, Zeigler Field 4 4 Oil production history of Plumfield lease 5 5 Conceptual geologic model depicts conditions leading to encasement of reservoir sandbars 5 6 Contour map of net pay in the Plumfield and Mack leases 6 7 Cross section (A-A') of South Plumfield lease shows the convex geometry of the sandstone bar 7 8 Cross section (B-B') of the northern part of the West Plumfield and Plumfield leases 8 9 Distribution of bottom-hole pressure in the Plumfield lease in January 1966 10 10 Distribution of bottom-hole pressure in the Plumfield lease in January 1967 10 1 1 Structure map of top of the Ste. Genevieve Limestone Formation 1 1 12 Horner plot for analysis of drill stem test data from the Plumfield no. 1 well 13 13 Contour map of permeability-thickness (kh) in the Plumfield lease 14 14 Contour map of heterogeneity index in the Plumfield lease 14 15 Cumulative distribution function of permeability in the Plumfield no. 2 well 15 16 Variation of solution gas-oil ratio with saturation pressure as determined by experimental PVT measurements of gas-crude oil mixtures from the Aux Vases Formation, Zeigler Field 18 17 Variation of oil formation volume factor with saturation pressure as determined by experimental PVT measurements of gas-crude oil mixtures from the Aux Vases Formation, Zeigler Field 1 8 18 Comparison of core-derived water saturation values with calculated values 19 19 Relationship between capillary pressure and water saturation in the Plumfield lease as determined by Leverett (J) function for various permeability values 19 20 Comparison of core-derived permeability values with those determined by SGM™ 21 21 Permeability distribution of the cross section (C-C') of West Plumfield and Plumfield leases 22 22 Comparison of simulated values for oil production rates and water cuts for the South Plumfield no. 2 well with actual values through time 24 23 Comparison between observed and calculated field pressure at the Plumfield no. 2 well 24 24 Relationship between permeability-thickness (kh) and cumulative oil production of Plumfield lease 25 25 Comparison of historical and alternative (predicted) waterflood oil recovery performance 25 TABLES 1 Nomenclature used in the report 3 2 Drill stem test of the Plumfield no. 1 well 12 3 Average permeability and porosity of some producing formations in the United States 1 6 4 Original oil in place (OOIP) as a function of oil-water (OWC) elevation and rock permeability 20 ABSTRACT The number of well abandonments in Illinois since 1987 has increased threefold. One reason for the increase is difficulties encountered in waterflooding small heterogeneous reservoirs. This study describes the development strategies used in a successful waterflood project in the Plumfield lease at Zeigler Field in Franklin County, Illinois. These strategies could be applicable to similar reservoirs. The Plumfield lease produced approximately 2 million barrels of oil during the past 29 years. The reservoir zone is in the Mississippian Aux Vases Formation and comprises three slightly overlapping and narrowly connected offshore marine sandstone bars. Reservoir management strategies used at the Plumfield lease included obtaining cores from almost every well, bottom-hole pressure surveys, and production and injection surveillances. Bottom-hole pressure surveys and production and injection surveillances were used to locate permeability barriers, essential knowledge for optimum placement of water injectors in the field. The extensive core analyses showed whether reservoir intervals existed, and the reservoir porosity, permeability, and residual fluid saturations. Data from the core analyses were very important in defining flow units within the reservoirs in the Plumfield lease. The waterflood performance of the Plumfield lease at Zeigler Field was evaluated using an integrated three-dimensional geologic and reservoir simulation model. A two-layer model was used to characterize the distribution of porosity, permeability, and fluid saturations in the reservoirs. Estimates from reservoir analyses showed that the Plumfield lease contained 4.56 MMSTB (million stock tank barrels), of which 43.07% was produced between June 1963 and February 1992. Simulation of another reservoir management scenario in which water injectors were placed at the onset of oil production showed a recovery of 1 .05% more oil than the historical case. The predicted ultimate oil recovery factor without waterflood was 23%. Reserve calculations indicate that about 57% of the original oil in place (OOIP) was bypassed at the Plumfield lease and that 14% of the remaining OOIP is moveable. The results of the reservoir simulation indicate the bulk of the recovered oil was produced from the upper, more permeable sand. Future development opportunities at Plumfield should include improvement of sweep efficiency with polymers or cross-linked polymers and use of microbial enhanced oil recovery techniques. Targeted infill drilling, as part of an improved oil recovery project, should also be considered if economically feasible. Field-wide tracer tests or other tests to define flow units are strongly recommended to identify various scales of heterogeneities not detected by previous reservoir management programs in the field. The information gathered will provide a better understanding of the reservoir architecture and show the best ways to recover the remaining oil through improved recovery techniques. Oil recovery during waterflood in this lease is relatively high for the Aux Vases Formation and attributable to the good reservoir management practices by the operator. INTRODUCTION Zeigler Field is in the southern half of Franklin County, in the south-central part of the Illinois Basin (fig. 1). Although Zeigler Field consists of several leases, only the Plumfield lease is considered in this study. Since its discovery in 1 963, the Plumfield lease has produced close to 2 million barrels of oil from the Mississippian Aux Vases Formation sandstone reservoir intervals (fig. 2). The reservoir covers 500 acres and contains 30 productive wells on a 10-acre spacing. The Plumfield reservoir is near the end of the waterflood recovery stage. Most of the wells in this reservoir have been abandoned since the mid-1970s because of their high water cuts. Figure 1 Location of Zeigler Field, Franklin County, Illinois. Figure 2 right Generalized strati- graphic column for upper Mississip- pian rocks in southern Illinois. Fraileys Beech Creek Cypress Ridenhower Bethel ^Downeys Bluff Yankeetown cd O < o_ 0- CO CO CO CO Renault Aux Vases Ste. Genevieve -?- c CO i__ CD CD E 3 Nearly all the wells were cored during drilling. Porosity and permeability values were determined for more than 90% of the core samples. Spontaneous potential (SP) resistivity logs were also available for most wells. Oil and water production data, as well as water injection data, were recorded monthly for each well. Five pressure surveys of the oil-producing wells in the Plumfield lease were performed between January 1966 and January 1969. Fields that produce from the Aux Vases Formation are noted for poor oil recovery during waterflood. Poor oil recovery is generally caused by reservoir compartmen- talization and heterogeneity. The Plumfield lease, a combination of the West Plumfield, Plumfield, and South Plumfield leases, has a relatively high waterflood oil recovery factor despite compartmentalization and heterogeneity. This success is attributed mainly to prudent reservoir management by the operator. By gathering the necessary laboratory and field information during development of the lease, the operator was able to make timely reservoir management decisions to anticipate and overcome problems caused by reservoir heterogeneity. This study uses the Plumfield reservoir to demonstrate the value of acquiring and using geological, engineering, and field data for reservoir management. The abun- dant core analyses from Plumfield provided useful information for constructing an integrated geological and engineering reservoir model. Simulation shows that the operator's careful management of the Plumfield lease resulted in a cumulative oil recovery far above the average for most Aux Vases reservoirs. The study also uses the model to (1) estimate the oil recovery factors to date and the amounts of remaining OOIP (table 1) and unrecovered mobile oil, and (2) evaluate future development opportunities for the Plumfield lease. Table 1 Nomenclature used in the report. °API = oil degree API gravity PI = productivity index bbl = barrel psia = pounds per square inch absolute BOPD = barrels of oil per day psig = pounds per square inch gauge B g = gas formation volume factor (cf/scf) PVT = pressure-volume-temperature B = oil formation volume factor (rb/stb) q = flow rate (bbl/day) CDF = cumulative density function R c = resistivity of adjacent shale bed (ohm-m) cf = cubic feet R s = solution gas-oil ratio (scf/stb) cp = centipoise Rt = formation resistivity (ohm-m) DST = drill stem test rb = reservoir barrel EDR = estimated damage ratio ROIP = remaining oil in place GOR = gas-oil ratio Sw = water saturation (%) h = net pay thickness (ft) scf = standard cubic feet J(S W ) = Leverett J function SP = spontaneous potential k = permeability (md) stb = stock tank barrel In = natural logarithm T = temperature (°F) md = millidarcy t p = cumulative flowing time (days) OOIP = original oil in place T r = reservoir temperature (°F) P = pressure (psia) Vdp = Dykstra-Parson heterogeneity index P c = capillary pressure (psia) V S h = volume of shale Pi = initial pressure (psia) W(r,R) = weighing function P = bubble-point pressure (psia) u. = viscosity (cp) Pwi = well flow pressure (psia) = porosity (%) P ws = shut-in bottom-hole pressure (psia) FIELD HISTORY Production History The discovery well in the Plumfield lease, Plumfield no. 1 (P1 , fig. 3), was completed in the spring of 1 963 by Gallagher Drilling Company. Production began in June 1 963 at an initial rate of 237 barrels of oil per day (BOPD). During the following 6 months, eight more wells (P2-P7, P9, P1 0) were drilled and completed. The total production rate of the nine wells in December 1 963 was 571 BOPD (event 1 , fig. 4). More wells were developed during 1964 in the West Plumfield and South Plumfield leases. By December 1964, 27 wells were producing at the rate of 645 BOPD. At peak production in the study area, 30 oil-producing and water injection wells were active. Pressure Maintenance History By the spring of 1965, the pumping rate at the Plumfield no.1 (P1) well had decreased from the initial rate of 237 BOPD to 1 1 BOPD. Reservoir pressure decline was precipitous, falling below 50 psig (pounds per square inch gauge) from an original reservoir pressure of about 1250 psig. The injection of water started in February 1 965 when four of the lower producers, West Plumfield no. 3 (WP3), West Plumfield no. 10 (WP10), Plumfield no.12 (P12) and Plumfield no. 20 (P20), were converted into water injectors (event 3, fig. 4). As a result, the declining field production rate and declining pressure were reversed. As more oil producers were shut in because of excessive water cut, some were converted into water injectors. By 1 979, only six wells, producing a total of 28 BOPD, continued to pump oil (event 7, fig. 4). R 1 E R2E P - Plumfield WP-WestPlumfield SP - South Plumfield M - Mack • Oil well \ Water injector -y- Dry well -w- Dry well (oil show) Figure 3 Well location map of Plumfield and Mack leases, Zeigler Field. Lines of cross sections A-A', B-B', and C-C are shown. No peripheral water injectors were placed at the east end of the reservoir. The oil bank was swept eastward toward the stratigraphic pinch-out. This strategy worked well, as reflected by the high total oil production and delay of water breakthrough in the eastern peripheral wells, Plumfield no.1 (P1) and Plumfield no. 9 (P9) (fig. 3). Historical Recovery Performance As of February 1 992, the total oil recovered from the Plumfield leases was 1 ,963,955 barrels. Given an estimated OOIP of 4.56 MMSTB (see section on Estimation of Reserves), the ultimate recovery factor to February 1992 was calculated to be 43.07% of OOIP. RESERVOIR CHARACTERIZATION Geological Description of Reservoirs at Zeigler Field Depositional processes, mineralogy, and diagenesis affected the geometry, volume, connectivity, and composition of the Aux Vases Sandstone reservoirs at Zeigler Field. Brief discussions of these geologic characteristics and their effects on reservoir behavior follow. A detailed geologic description of Zeigler Field is pre- sented in Seyler (in preparation). 800- 600- Q Q. o m ^ 400- 1 Q. 200- o-V Event 4 Event 2 Event 1 Event 1—9 producers Event 2—27 producers Event 3— Water injection started Event 4—1 8 producers Event 5 — 1 6 producers Event 6—1 1 producers Event 7—6 producers Event 7 T T 1960 1965 1970 Figure 4 Oil production history of Plumfield lease. 1975 1980 : Jr.xCr» Green, ripple-bedded, nonporous, fine- grained sandstone Tidal flat — shale Tidal channel — red, hematitic grainstone Peloidal, oolitic shoal (Aux Vases Ss) j-fXt^j Oolitic shoal (Ste. Genevieve Ls) Figure 5 Conceptual geologic model depicts conditions leading to encasement of reservoir sandbars in reservoir-sealing units in a mixed carbonate-siliciclastic environment deposited by tidal processes. Depositional processes The Aux Vases Formation at Zeigler Field was depos- ited in a mixed carbonate-siliciclastic environment by tidal processes. Figure 5 shows a conceptual geologic model for deposition of the reservoir and reservoir- sealing facies. Reservoir sandstone bars are effectively sealed by tidal-flat siltstones and shales at the top; by low energy, fine grained, ripple-bedded, nonporous sandstones and siltstones at the base; and by impermeable tidal-flat and and other low energy siltstones and fine grained sandstones laterally. R1 E R2E Figure 6 Contour map of net pay in the Plumfield and Mack leases. Three sandstone bars, with varying amounts of interconnection, constitute the main body of Zeigler Field. These bars were also identified on the Plumfield lease in the main body of Zeigler Field (fig. 6). The sandstone bar on the west side of the field (West Plumfield) overlaps the bar on the east side of the lease (Plumfield), but no fluid communication exists between these two bars. At well P12 (fig. 3), the east Plumfield bar is narrowly connected with the sandstone bar in the south part of the lease, therefore fluid communication between these two bars is limited. The Mack lease consists of an isolated sandstone bar separated from the main body of Zeigler Field. The bars are isolated from each other because of lateral depositional facies changes from porous sandstone to nonporous facies. Figure 7, a cross section (A-A', fig. 3) of the South Plumfield lease, shows the convex-upward geometry of the sandstone bar. Bottom-hole pressure surveys The existence of permeability barriers separat- ing the three bars is more evident in pressure data than in correlations of electric logs or core descriptions. Surveys of bottom-hole pressures were used to confirm the existence of the permeability barrier that separates the east part of the field (composed mostly of the Plumfield lease) from the west part of the field (composed mostly of the West Plumfield lease). Figure 8 (B-B', fig. 3), a west-east cross section SP8 SP6 139,525 BO 514,258 BW SP3 73,068 BO 56,998 BW I • SP2 71,416 BO 333,694 BW -4" A' SP7 t=W top Ste Genevieve Ls | imeston £ i — i — i — i Figure 7 Cross section (A-A') of South Plumfield lease shows the convex geometry of the sandstone 400 10 ^J 5 ° bar. See figure 3 for line of section. md of the north part of the field, shows what appears to be a small, 2-foot shale break in the middle of the sandstone bar fades at the Plumfield no. 18 well. A pressure survey of the field (fig. 9) conducted in January 1966 showed a very large pressure differential between the west and east parts of the field near this location. This observation indicated that water injected into the west part of the unit did not affect oil production and reservoir pressures in the east part of the Plumfield lease. Knowledge of the existence and location of this permeability barrier led to the conversion of the Plumfield no. 18 (P18), located east of the permeability barrier, into an injection well. After 12 months of water injection, bottom-hole pressure at the Plumfield no. 17 well (P17) had risen from 149 psig to 951 psig (fig. 10). Information obtained from bottom-hole pressure surveillance conducted from 1966 through 1969 guided the strategic placement of injection wells, which were largely responsible for the relatively high recovery efficiencies attained in this field. Trapping mechanism Zeigler Field is primarily a stratigraphic trap formed by sandstone bars that coincide with a slight structural saddle (fig. 11). The regional structure map of the top of the Ste. Genevieve Limestone shows no structural closure in the field. Diagenesis The high porosities and permeabilities in this field are due mostly to the favorable effects of diagenetic events during lithification of the sandbars. Dissolution of feldspar grains led to the precipitation of diagenetic clay minerals. Porosities as high as 28% are common in these reservoirs because the diagenetic clay minerals that coat virtually every sand grain inhibited the precipitation of quartz overgrowths. In addition, large amounts of early calcite cement were dissolved in the thicker, central parts of the sandbars, further enhancing the porosity and permeability of the reservoir (Seyler in preparation). Pores lined with diagenetic clay minerals can cause significant problems during drilling, completion, and recovery programs (Haggerty and Seyler 1993). Diagenetic clay minerals can cause abnor- mally low resistivity readings on wireline logs; 2 ohm-meter deflections are very common at Zeigler Field (Seyler 1986). This phenomenon makes calculating water and oil saturations difficult. WP3 5,638 BO WP2 35,900 BO Figure 8 Cross section (B-B') of the northern part of the West Plumfield and Plumfield leases. Reservoir sandstone bars possessing excellent to good porosity and permeability (graphed on the left side of logs) are encased in tidally deposited units Reservoir Properties Early in the development of the Plumfield lease, the operator conducted drill stem tests in selected wells, analyzed the pressure-volume-temperature (PVT) proper- ties of an oil sample from the Plumfield no. 1 well (fig. 3), and analyzed cores from the producing interval. Bottom-hole pressure surveys and water injection surveil- lances were begun later to understand the performance of the water injection program. Consequently, large amounts of reservoir data are available to help characterize and manage the reservoir of the Plumfield lease. Drill stem test data Data for a complete DST (table 1 ) of the Plumfield no. 1 well (P1 ) were provided by the operator. The data for the Plumfield no. 1 well were used in this study to demonstrate how DSTs can aid in reservoir characterization studies (table 2, fig. 12). Although DSTs are commonly conducted, many operators in the Illinois Basin do not take maximum advantage of the data. \ P19 24,570 BO P18 6,020 BO P6 75,733 BO P5 81,069 BO 7> ■permeability barrier -§- B' P7 that have minimal porosity and permeability. Location of permeability barrier was determined by pressure surveys and electric log signals. See figure 3 for line of section. A DST is primarily designed to sample formation fluids and establish the possibility of commercial production. Data can also be used to determine reservoir pressures and several other reservoir characteristics, including well productivity, formation permeability, well bore damage, and the possible existence of permeability barriers, such as those formed by faults, pinch-outs, and facies changes (Lee 1 982). To take full advantage of DST runs, the operator should be furnished with the test summary, as well as with pressure readings taken at consistent time intervals from the recorded pressure charts of a DST. Although many historical records do not include such detailed data, pressure readings from recent charts sometimes are available from the service companies that ran the tests. R1 E R2E > P22 • P20 P19 /# • Mk P18 P24 P6 • P8 P5 • V M ^ P3 z 2 WP1 • V 791 Jl WP4 809 WP5 1002 P25 P23 1100 /^ • '/ , P17 P16 • • 46 P4 46 P2 P1 P15 A ~7r • • • • • • y 530 774 711 929 ~~\ 149 121 57 69 45 1 / WP13 WP8 T • • WP7 • \ P11 \ • P10 • P3 • P9 • \ 613 608 780 149 138 121 206/ \ , ^WPIO y -^SP6 SP3 SP2 • • Y 13 18 I 63 115 86 24 19 N. P - Plumfield SP4 I WP - West Plumfield SP - South Plumfield 809 - BHP • "$>"' I 1000 I 2000 ft I Figure 9 Distribution of bottom-hole pressure (BHP) in the Plumfield lease in January 1 966. R1 E R2E + P24 P8 V 1245 \l WP4 7^ 25 1132 WP1 • 958 WP5 • 1135 P22 • 1217 P25 • 1239 P20 \ P23 P19 /^ 1711 4> s \ /<* 7 P17 P16 • • ■^s951 888 P6 • 800 P4 • 613 P5 • 95 P2 • 247 P1 • 134 P15 x 1 / WP13 WP8 T • • I 1012 977 WP7 • 1004 \ P11 \ • 947 P10 • 628 P3 • 217 P9 • 174/ \ . .WP10 13 18 I -^SP6 81 SP3 SP2 • • 134 170 y P - Plumfield WP - West Plumfield SP - South Plumfield 24 19 \^ SP4 I I 1 000 I 2000 ft I 958 - BHP Figure 10 Distribution of bottom-hole pressure in the Plumfield lease in January 1967, after P18 was converted into an injection well. 10 hNW 11 Table 2 Drill stem test of Plumfield no. 1 well. Data summary Interval tested: 2627-2640 feet, Aux Vases Formation Drill pipe size: 4.5 inches Initial flow period: 15 minutes Initial shut-in period: 30 minutes Final flow period: 45 minutes Final shut-in period: 31 minutes Reported recoveries Liquid: 90 feet of mud-cut oil, 840 feet of oil (API = 38.9) during flow periods Oil formation volume factor: 1 .06 bbl/STB Oil viscosity: 1.96 cp Original reservoir pressure from drill stem tests Pressure buildup data from a DST are analyzed using equation 1 and Horner plot (fig. 12): Pi -P ws =^ 62.6 &l± log [(t p + At )/Af ] [1 ] where t p = cumulative flowing time (min) At = time during shut in when each pressure is read (min) Pi = original (static) reservoir pressure (psia) Pws = shut-in BHP recorded during DST (psia) q = flow rate (BOPD) Bo = oil formation volume factor (rb/stb) (i = oil viscosity (cp) k - formation permeability (md) h = net pay thickness (ft) Figure 12 shows a plot of the shut-in pressure, Pws, against log(/p + At)/ At as expressed in equation 1 . All the data points from the initial and final shut-in periods of this test are on a straight line, which has a slope of 140.44 psig/logarithmic cycle. The original reservoir pressure of 1 ,245 psig was determined by extrapolating the straight line to (tp + At)/ At = 1 . Effective in situ permeability and permeability-thickness product The in situ permeability of the reservoir in the drainage area of the well and the damage ratio (or skin) around the well bore may also be estimated using the information presented in figure 12. The slope (m) of the straight line in figure 12 is used to determine the in situ permeability from the following equation: k _ 162.6 gg u [2] mh Given that 840 feet of oil was recovered from the reservoir after a total flow time of 60 minutes through a pipe 4 1/2 inches in diameter, the oil flow rate is _ (drill-pipe capacity, bbl/ft ) x (liquid leg, ft ) x (1 ,440, min/day ) (flow period, min) Substituting the values for Bo, m, and q = 403.2 bbl/day into equation 2, the in situ flow capacity (kh) is 946 millidarciesfeet (md-ft). The kh value determined from core analysis of the Plumfield no. 1 well is 924 md-ft, which deviates only 2.4% from the DST value of 840 md ft. Given an average reservoir thickness of 1 3 feet, the effective in situ permeability is 76 md. 12 1400 1300- g> 1200- 1100 - 1000 Original reservoir pressure = 1245 psig slope (m) = 140.44 >ig/logarithmic cycle 1 10 (fp+Afj/Af Figure 12 Horner plot for analysis of DST data from the Plumfield no. 1 well. 100 Estimated damage ratio The estimated damage ratio (EDR) also can be calcu- lated from the DST data. The EDR value shows how much the productive capacity of the well would be increased had formation damage not occurred. In other words, the EDR informs the operator whether formation damage exists. It may also be useful for deciding whether to attempt to mitigate formation damage through treatments such as acidization or hydraulic fracturing. According to Reid (1 983), the simplified equation commonly used by service companies is EDR = 0.1 83 (Pi-Pwf) m [4] where Pwf = flowing pressure (i.e., final flowing pressure, FFP) m = slope of Horner plot = 140.44 psig/logarithmic cycle For the Plumfield no. 1 well, ,_„, 0.183(1245-222) EDR = -uttta = 1 - 33 140.44 This EDR value (1.33) implies that formation damage occurred and that the production capacity would be increased 1 .33 times if the damage did not exist. Hence, instead of 393 bbl/day, the oil recovery rate during DST could have been as much as 524 bbl/day. Determination of productivity index The results of a DST also can be used to estimate an oil well's productivity index {Pi). The PI is used to forecast the long-term stable flow rate of a well and has an obvious economic significance in decision making. The stabilized PI equation is 13 Pl= 0.00708 kh/\i In ( — ) - 0.75 + S [5] where r w = well bore radius (ft) r e = drainage radius (ft; taken as half the spacing unit) s = skin factor = 7(EDR - 1 ) = 7(1 .33 - 1 ) = 2.31 . When the values of kh/\i (from the DST), r e , r w , and s are substituted into equation 5, the stabilized P/forthe Plumfield no. 1 well is 0.40 stb/day/psi. From this stabilized PI value, an operator can predict what the flow rate will be at a particular flow pressure, Pwf, using the following relationship: PlX(Pi-Pwi) Figure 13 Contour map of permeability-thickness (kh) in the Plumfield lease. R1 E R2E 1000 _l Figure 14 Contour map of heterogeneity index in the Plumfield lease. 14 1000 2000 ft I 2000 ft In summary, DST results that include actual values of the pressure and time recorded by the pressure gauge are extremely useful for detailed analysis of the reservoir. As shown above, these data can be used to calculate original (static) reservoir pressure, in situ flow capacity (kh), effective permeability, estimated damage ratio, and productivity index for the reservoir at a given well location. These data are important for optimizing productivity of the reservoir. Drill stem tests also are used to sample formation fluids and establish the possibility of commercial production. Trends of Reservoir Data in the Plumfield Lease Analyses of 37 core samples from both productive and nonproductive wells in the Plumfield lease were used for this study. Zeigler Field as a whole has the highest density (92.5%) of cored wells among all Aux Vases reservoirs in Illinois. Core permeability and porosity values were approximated for each well. Porosity values ranged from 8% to 25.8%; the mean value was 18%. The average porosity of the oil-producing sandstone interval was 21%. Permeability values ranged from 2 md to 261 md; the mean value for the entire lease was 95 md. The mean permeability of the oil-producing sandstone interval in the study area was 119 md. Figures 1 3 and 1 4 show the distributions of the permeability-thickness product {kh) and the Dykstra-Parsons heterogeneity index values, respectively, for the Plumfield lease. The Dykstra-Parsons coefficient (Vdp; Dykstra and Parsons 1950), a mea- sure of the vertical heterogeneity of the formation, was calculated from the perme- ability cumulative distribution function (CDF) of the wells. The CDF is a statistical relationship for representing the probability of occurrence of random variables. The Vdp is for a very homogeneous porous medium and 1 for a highly heterogeneous porous medium. A typical plot of a permeability CDF is shown in figure 15. The contour maps (figs. 13, 14) show that the reservoirs are less heterogenous in the regions having higher 1000 E n co Q. B o < 100 • Data — Regression V D p = 0.32 — 1 1 1 1 20 40 60 80 100 Percentage of sample having permeability greater than values on the ordinate (y) axis Figure 15 Cumulative distribution function of permeability in the Plumfield no. 2 well. The slope is the Dykstra-Parsons heterogeneity index (Vdp). 15 lvalues. Poor vertical sweep efficiency is more likely to occur in areas with higher Dykstra-Parsons coefficients. The Vdp in the Plumfield lease ranges from 0.20 at the center to 1 .0 at its periphery or boundary; the mean is 0.8, and the standard deviation is 0.24. The Plumfield lease field may be classified as "moderately heterogenous" (Dykstra and Parsons 1950). Table 3 (Lake 1992) compares average reservoir properties of the Aux Vases Sandstone of the Plumfield lease with similar data from other major producing units in the United States. It shows that the average vertical heterogeneity within the Aux Vases Formation at the Plumfield lease is within the range found in other producing reservoirs in the United States. Table 3 Average permeability (k) and porosity (<)>) of some producing formations. 3 Field name Formation Wells sampled Mean k (md) Mean<}» Mean Vdp El Dorado Admire 262 370.14 0.254 0.697 Keystone Cardium 67 15.15 0.106 0.653 Zeigler Aux Vases 37 95.00 0.180 0.800 Carrington Manville B 38 5.73 0.112 0.822 Madison Bartesville 36 29.95 0.179 0.823 Pembina Cardium 16 273.64 0.122 0.894 HamiltonDome Tensleep 33 98.42 0.143 0.694 Rozet Muddy 20 43.14 0.171 0.846 Recluse Muddy 12 74.93 0.144 0.855 Ute Muddy 8 62.14 0.179 0.758 Pitchfork Tensleep 5 91.54 0.141 0.723 a Modified from Lake (1992). Hydrocarbon PVT properties The results of a partial PVT analysis of an oil mixture from the Plumfield no.1 discovery well were reported by Oilwell Research Inc. of Texas in April 1964. The oil gravity was 38.5° API, and the laboratory gas gravity was 0.928. This analysis, performed on a recombined oil sample prepared from 128 scf/stb (standard cubic feet of gas per barrel of stock tank oil), yielded an oil formation volume factor (B ) of 1 .074 rb/stb at a bubble-point pressure of 489 psig. The major uncertainty was the gas-oil ratio (GOR). The separator GOR was 141 scf/stb at 60°F; the estimated gas specific gravity was 1 .25 (air = 1 .0). The GOR was corrected, however, to correspond to the gas specific gravity value of 0.928 observed in the laboratory. The average oil formation factor estimated from the data of 20 years of oil production, as of February 1992, is as follows: total volume of stock tank oil produced = 1 ,963,955 STB total volume of water injected = 5,270,212 bbl total volume of water produced = 3,1 1 1 ,893 bbl injected water not produced = 5,270,212 -3,111,893 = 2,158,319 bbl If the natural water production, water influx, and free gas saturation are assumed to be negligible (which is reasonable since the average reservoir pressure was above bubble point during most of the waterflood period), the unproduced injected water only served to replace the produced oil volume. Thus, B = unproduced injected water/ stock tank oil = 2,158,319/1 ,963,955 = 1 .09896. This value is the upper limit for the oil formation volume factor and agrees fairly well with the value of 1 .074 rb/stb obtained for the recombined sample at a bubble-point pressure of 489 psig and 1.068 rb/stb at the original reservoir pressure of 1,200 psig. Consequently, an oil formation volume factor of 1 .068 rb/stb and a bubble-point pressure of 489 psig were used as the starting, predevelopment values for the reservoir model. 16 Another PVT analysis performed recently in the ISGS PVT laboratory and an oil and gas mixture from the Aux Vases Formation at the Gallagher Alex no. 1 , a new well drilled south of the Plumfield leases in Zeigler Field. The sample, which was recombined at a gas-oil mixing ratio of 200 scf/stb, yielded an oil formation factor of 1 .138 rb/stb at a bubble-point pressure of 707 psig and a reservoir temperature of 95°F. Differential vaporization data were generated for this mixture. Measured values of the gas-oil mixing ratio were adjusted from 200 scf/stb to 124 scf/stb to establish the variation of some properties (GOR, B , viscosity, and B g ) needed for reservoir simulation. Figures 16 and 17 show the variations of GOR and B 0l respectively, with changes in saturation pressure at 95°F, as used in this study. Initial water saturations Fluid saturation values from core analyses were re- ported for four wells in the Plumfield lease. Invasion of the core plug by the mud filtrate from the water-based drilling mud and expansion of the hydrocarbon phase during retrieval to the surface often render core-derived saturation values suspect. In this work, calculations of initial water saturations (S w ) from old electric logs were based on the Simandoux method (Mian 1992): _ 0.4fttv &w — , Vsh Re [7] where R w = formation water resistivity(ohm-m) Rt = formation resistivity (ohm-m) Vsh = fraction of shale in formation R c = resistivity of adjacent shale layer (ohm-m) <]> = porosity of formation (fraction). Values for Rt and R c were determined from the well resistivity logs. The R w values were measured from produced formation water (Demir 1993). Values for V S h were estimated from x-ray diffraction (XRD) analysis. Porosity was obtained from core analysis reports of the wells. Equation 7 gives initial water saturation values in the range of 30% to 79% in the oil-producing wells. These values are about 5% to 20% lower than those obtained from core analyses (fig. 1 8). Water saturation values measured during core analyses probably are consistently higher than those measured in the field because of the invasion of mud filtrates from water-based mud into the formation during drilling. Water saturation values obtained from core analyses are, therefore, higher than actual values. The initial water saturation values, obtained from equation 7, were used in the reservoir simulation modeling. The average initial water saturation of both the oil-producing and nonproducing intervals, as calculated by the reservoir simulator, is 48.9%. The estimated OOIP is 4.5 MMSTB, which is within the range of OOIP (4.3-5.0 MMSTB) calculated using the capillary pressure method described below. Oil-water contact Use of the equlibrium (capillary pressure) approach to initial- ize the resevior simulation model requires knowledge of the elevation of the oil-water contact in the reservoir. No distinct oil-water contact could be detected from either wireline logs or core analysis. Even though the wells at Zeigler Field were completed open hole, no water production was observed during the period of primary production in the eastern and southern parts of the field, indicating that the producing intervals were well above the oil-water contact. Small and intermittent water production observed in the western part of the field during this time indicated that permeable porosity was present below the oil-water transition zone or the oil-water contact. 17 140 T 300 Pressure (psia) 600 Figure 16 Variation of solution gas-oil ratio (R s ) with saturation pressure as determined by experimental PVT measurements on gas-crude oil mixtures from the Aux Vases Formation, Zeigler Field. 1.08 T 300 Pressure (psia) 400 500 600 Figure 17 Variation of oil formation volume factor (6 ) with saturation pressure as deter- mined by experimental PVT measurements on gas-crude oil mixtures from the Aux Vases Formation, Zeigler Field. 18 0.9- 0.8- .2 °- 7- o (0 I 0.6 H | 0.5 -| <5 I 0.4 H 0.3- 0.2 • core-derived values _ values calculated with Simandoux method 10 15 20 25 —r- 30 35 Core porosity (%) Figure 18 Comparison of core-derived water saturation values with calculated values. I 10 I 20 I I I 30 40 50 Water saturation (%) l 60 I 70 80 Figure 19 Relationship between capillary pressure and water saturation in the Plumfield lease as determined by Leverett (J) function for various permeability values. 19 An oil-water contact for the field was estimated from sensitivity analyses using capillary pressure data provided by the operator (fig. 19). This capillary pressure curve was obtained from a core sample that had an air permeability of 800 md and an irreducible water saturation of 20%. The permeability values of the productive intervals in the Plumfield lease were determined from core data and ranged from 1 00 to 200 md. The average irreducible water saturation was expected to be slightly higher in low permeability zones. The experimental capillary pressure data were normalized by using the Leverett (1941) J(S W ) function (equation 8) and a series of new capillary pressure curves were generated for rock samples that had other permeability values. J (S w ) = -a/7 ;0 \ 6 a cos© \ = porosity P c = capillary pressure Sw = water saturation Table 4 shows the effect of the elevation of the oil-water contact on reserve estimates in the Plumfield lease. The elevation of the oil-water contact ranges from -2,266 to -2,291 feet depending on the permeability and porosity values. Table 4 Original oil in place (OOIP) as a function of the oil-water contact (OWC) elevation and rock permeability. Permeability (md) OWC (ft) OOIP (MSTB) Overall recovery factor (%) 200 -2,266 4385.2 44.77 -2,271 4734.8 41.47 -2,281 5062.6 38.78 -2,291 5125.2 38.31 100 -2,266 4158.6 47.22 -2,271 4308.8 45.58 -2,281 4852.4 40.46 -2,291 5079.1 38.66 Estimation of Reserves The average values for reservoir properties used in estimating the reserves in the Plumfield leases were as follows: Reservoir volume = 6,825 acre-feet Porosity (%; core analysis) = 18 Oil formation volume factor (rb/stb) = 1.068 Water saturation (%) = 48.9 The estimated OOIP is 4.56 MMSTB. This value differs from the operator's prelimi- nary reserve estimate by 4.8% and yields an ultimate recovery factor of 43.07% after 29 years of production. Geological Modeling A three-dimensional geological model of the Plumfield lease was constructed using the Stratigraphic Geocellular Modeling (SGM™) computer software. This software subdivides the gross rock volume into many cells. Attributes that can be assigned 20 to the cells include lithology, porosity, permeability, and fluid saturation. Attribute values for each cell are estimated by the software from the petrophysical data for the wells. The process uses one of two interpolation schemes and a search radius specified by the user. A detailed geological model of the Plumfield lease was created by generating surface grids of the top and base of the Aux Vases Formation (generated by the Zycor™ program) and by inputting all available reservoir attributes, such as permeability, porosity, lithology, and fluids saturations from 34 wells. The values of the attributes in each cell were determined by an interpolation scheme that depends on a search radius and power factors. Depending on the search radius and the power factor, a weighting function (W(r,R)) to be used for calculating interwell attribute values is determined, using either a deterministic or a statistical algorithm as shown in equations 9 and 10, respectively (Stratamodel Inc. 1991). The appro- priate values of the search radius, weighting function, and power factors to use were investigated in this study by means of sensitivity tests. W(r,R) = (1 -r/RHR/r) x deterministic function W(r,R) = (1-r/R) 2 (1+2r/R) x statistical function [9] [10] where R = search radius x = power factor r = distance from the interpolated point Figure 20 compares core-derived permeability values for the West Plumfield no. 4 well (WP4) with the values calculated by SGM™ for various search radii using a power factor of 2 and a statistical algorithm. Although the absolute difference between the core-derived and calculated permeability values increases with the search radius, the mean deviation between the two was lowest for the search radius 250 *# w G^° V S\3* M# 200- 1 150- CO o E o5 100 0_ 50- Search radius (ft) • 500 + 1000 ♦ 2000 ■ 3000 O Core data Mean (% dev) -8.0 -3.5 16.4 30.7 Abs (dev) 16.2 21.2 42.2 46.6 -2235 -2240 -2245 -2250 -2255 Subsea elevation (ft) — i — -2260 -2265 Figure 20 Comparison of core-derived permeability values with those determined by SGM 21 TM 15 feet • Oil well -6- Dry well Figure 21 Permeability distribution of the cross section (C-C') of West Plumfield and Plumfield leases. See figure 3 for line of section. of 1 ,000 feet. Consequently, a search radius of 1 ,000 feet was used in this work. Furthermore, a search radius of 1 ,000 feet only permits data from neighboring wells that are within one well spacing (660 feet) of each other to be used in the calculation of interwell attributes. This observation is particularly important in formations for which reservoir attribute values vary over relatively small distances. Figure 21 shows the permeability values for cross section C-C' (fig. 3) and illus- trates the absence of permeability continuity between the sandbars in the West Plumfield and Plumfield leases across the permeability barrier (fig. 9). RESERVOIR SIMULATION Gridblock Selection and Simulation Technique Geological modeling was the basis for selecting a reservoir simulation consisting of two separate flow units. Permeability in the upper interval generally exceeded 50 md, whereas permeability in the lower interval generally was less than 50 md. The individual cell attributes were averaged arithmetically and exported to the reservoir simulator for subsequent model initialization. A three-dimensional grid system consisting of 48 x 33 x 2 cells and 3 grid cells between adjacent wells was built. Both two- and three-dimensional, full-field, implicit black-oil models were used to simulate the depletion of the Plumfield lease. The software used in this study was the Western Atlas Integrated Technologies VIP CORE™ simulator, licensed to the ISGS and operated on a Silicon-Graphics workstation. VIP's BLITZ solution tech- nique was used to solve the algebraic equations. Initialization of the Reservoir Simulation Model The end-point relative permeability and water saturation values used in the simula- tion were obtained from two Aux Vases sandstone reservoirs in the South East Jordan School and Feller units, Wayne County, Illinois (Sandiford and Eggebrecht 1972). These are the only published relative permeability and water saturation values for the Aux Vases Formation in the Illinois Basin. The relative permeability values used in the simulation were then adjusted by an iterative process to obtain a good match with the oil and water production history for the field. Five oil-water relative permeability curves were used to obtain a reasonable match with the historical performance of 30 oil-producing wells. 22 History Match Several history-match runs were necessary to ensure that the model closely simulated known field performance and to ensure its reliability for prediction. The reservoir simulation model was calibrated by matching histories of (1) monthly oil and water production values for the 30 selected wells and (2) reservoir pressures from a drill stem test (Plumfield no.1) and bottom-hole surveys. Gas production records were not available. Necessary adjustments were made in the initial water saturation and relative permeability curves for oil-water and oil-gas to match the simulation results to the actual historical data. The overall quality of the history match was good. Water cut and oil production matches were made for each well. The match between the simulated and actual data for water cut and oil production for the South Plumfield no. 2 well is shown in figure 22. The pressure match for the Plumfield no. 2 well (fig. 23) typifies the quality of the match obtained for the Plumfield wells for this parameter. Waterflood Performance in the Plumfield Lease As figure 24 shows, there is a good correlation between cumulative oil production and pemeability-thickness values (kh), except for wells with low kh. Some wells with low kh had very high cumulative oil production because of their location. Even though Plumfield no. 9 (P9), Plumfield no. 1 (P1), South Plumfield no. 6 (SP6), and West Plumfield no. 7 (WP7) wells have low kh values, their respective cumulative oil productions far exceeded the norm because the placement of water injection wells caused oil to bank near their locations. All four wells are bordered by impermeable lithologies. The waterflood development of the Plumfield lease was also simulated. Two alternative scenarios, in addition to the historical development, were compared. In one scenario, no water was injected. The cumulative oil production from the Plumfield unit, in this case, was only about 23% of OOIP (compared with the historical ultimate oil recovery factor of 43%). In the second scenario, two nonpro- ductive wells (P8 and P24, fig. 3) at the north flank of the Plumfield unit were used as injectors at the onset of oil production instead of after 1 year. In the actual development of the lease, water injection did not commence until 1 year after production start-up, when reservoir pressure and oil production rates had begun to decline precipitously. In effect, this case quantified the effect of the delay in implementing pressure maintenance. Simulation results (fig. 25) show a mere 1 .05% improvement (42 MSTB) under the early water injection scenario, as com- pared with total historical oil production at the end of 1 990. Location of the water injection wells is quite important. Another run simulated the conversion to injectors of two other nonproducing wells, the Plumfield no. 7 (P7) and Plumfield no. 15 (P15), on the east flank of the Plumfield unit. This simulation did not result in a significant increase in cumulative oil recovery. The model indicated that this scenario would have caused earlier water breakthrough than was histori- cally the case at Plumfield no. 1 (P1) and Plumfield no. 9 (P9), the most productive wells in the field. The simulation calculations show less oil saturation remaining in the upper layer (oil recovery is 48.9%) than in the lower layer (oil recovery is 26.4%) (fig. 21). This finding suggests poor sweep of the lower sand interval in the model. The available evidence indicates that the upper sandstone interval is more permeable and probably more continuous than the lower interval. Consequently, the upper sand- stone interval can be more efficiently swept than the lower sandstone interval. 23 Figure 22 Comparison of simulated values for oil production rates and water cuts for the South Plumfield no. 2 well with actual values through time. 1500- « 1000- w w s Q. © O £ E o o 500 CD 1963 • Simulation ♦ Field data - 1 — 1969 1970 Figure 23 Comparison between observed and calculated field pressure at the Plumfield no. 2 well. 24 Z5U ~ ▲ excluded from calculation of best fit line 200- ♦ P1 2 oil productior i ^ + WP7 V SP6 • WP8 ^^ • WP5 •J^^^ Cumulative 8 8 i i • P3 P5^^^^ ~P6 WP4^^^ #P4 (§WP13 •^^•SP3 # S P2 P25«^^ #P13 ^ #WP1 • WP2 _P20 P7 • #pig P9 P10 - ~l T — 1 1 o- 1 1000 2000 3000 kh (md-ft) 4000 5000 6000 Figure 24 Permeability-thickness value (kh) related to cumulative oil production of the Plumfield lease. 1000- m W 800- E 6 600' Q. CD .> 3 400' E 3 o 200- ■ Early water injection • History ^ Without water injection 1955 1960 1965 1970 1975 1980 1985 1990 — f 1995 Figure 25 Comparison of historical and alternative (predicted) waterflood oil recovery performance. 25 Oil Recovery Factor and Unrecovered Mobile Oil in the Plumfield Lease Total production from June 1 963 to February 1 992 was 1 ,963,955 barrels of oil. With an estimated OOIP of 4.56 MMSTB, the ultimate oil recovery is calculated to be 43.07%. If an average residual oil saturation of 22% (from core analysis) were used, the amount of unproduced mobile oil would be 633 MSTB, which is about 1 4% of the OOIP. This estimated amount represents bypassed oil that can be targeted for recovery through improved waterflooding and, possibly, infill drilling. FUTURE DEVELOPMENT OPPORTUNITIES IN THE PLUMFIELD LEASE The simulation results showed that the waterflood project in the Plumfield unit achieved a good overall areal sweep efficiency in the upper sand layer. The vertical sweep efficiency was hampered, however, by vertical heterogeneities. Most of the unrecovered mobile oil is in the lower, less permeable part of the reservoir. The remaining oil in place (ROIP) is estimated to be 2,596 MSTB (about 57% of the OOIP). It is also estimated that 24% of the ROIP (633 MSTB) could be bypassed in regions of low permeability and small-scale heterogeneities. Among the advanced improved oil recovery methods that can be considered are (1 ) targeted infill drilling; (2) profile modification with cross-linked polymer, foams, or polymer floods (Schoel- ing et al. 1989); and (3) enhanced oil recovery methods such as alkaline, alkaline- polymer, surfactant, and microbial floods. The best recovery method for a particular reservoir depends on its predicted performance and economics. Targeted infill drilling is feasible if pockets of bypassed oil can be identified. As interpreted from the present level of reservoir descriptions, the bulk of the moveable oil is in the lower zone, where the average permeability is lower. Carefully planned tracer tests throughout the field may help to reveal areas that are unswept or poorly swept. The quantity of bypassed oil would have to economically justify the expense of new wells. Studies (US DOE 1991) have shown that oil recovery from EOR projects is generally inversely related to well spacing. When well spacing is decreased by infill drilling, oil recovery increases in many cases. The use of polymers to plug swept zones may be necessary to recover mobile oil from unswept regions. A problem in applying polymers or their cross-linked varieties in unswept regions is that no distinct permeability barrier delineates the more permeable top area from the less permeable zone below. Permeability declines gradually from top to bottom, particularly in wells containing a sedimentary se- quence that coarsens upward. The use of ordinary polymers or cross-linked polymers to improve the sweep efficiency of the lower layer is restricted to the vicinity of the well bores for economic reasons. In the interwell regions, where the bypassed oil resides chiefly in the lower layer, injected water may return to higher permeability strata. Compared with polymers, the use of microorganisms as profile modification agents, called microbial enhanced oil recovery (MEOR), may be an advantageous alterna- tive for the following reasons. • The comparatively low cost of MEOR application makes it attractive, especially for stripper oil production. • Microbial transport is facilitated in regions of higher water saturation and larger pore openings, and it is not limited to the well bore region (Schoeling et al. 1989, Tanner et al. 1991). The expectation is that injected microbes will follow aque- ous solutions to regions with higher permeability. Consequently, biomass and 26 biopolymers should act to reduce the permeability of a reservoir in precisely those zones where action is most needed. • Depending on the type of nutrients injected and the type of microbes injected or stimulated, metabolic products formed by the microbes, including CO2 and surfactants, also can improve oil recovery. SUMMARY AND CONCLUSIONS • The Plumfield leases of the Zeigler Field, which encompass 500 acres, have produced approximately 2 million barrels of oil from 30 wells during 29 years. The reservoir comprises three narrowly connected and slightly overlapping offshore marine sandstone bars in the Mississippian Aux Vases Formation. • Historical reservoir management practices at Zeigler Field included coring almost every well, obtaining detailed DST data, and conducting bottom-hole pressure surveys and production-injection surveillances. Waterflood management was enhanced by adequate surveillance practices, such as bottom-hole pressure surveys and monitoring of the injected and produced streams. Interpretation of data from these surveillances enabled the operators to locate a permeability barrier between wells P18 and P19. This knowledge led to the placement of injectors in the eastern part of the field. • The Plumfield lease contained an estimated 4.560 MMSTB, of which 43.07% had been produced by February 1992. Only two wells are still pumping, and the daily oil production rate is below 28 BOPD. The waterflood recovery, relatively high for the Aux Vases Formation, is attributable to good reservoir management by the operator. The strategies used in this successful waterflood project should be applicable to other similar reservoirs in Illinois. • Simulation of other possible reservoir management scenarios showed that placement of two water injectors (Plumfield no. 7 and Plumfield no. 15 wells) at the onset of oil production instead a year or so later would have recovered about 1 .05% more oil than the historical case of 1.963 million barrels of oil. • Reserve calculations indicate that about 57% of the OOIP still remains at the Plumfield leases and 14% of the OOIP is probably moveable oil that was bypassed. Results of the reservoir simulation indicate that the bulk of the recovered oil was produced from the uppermost permeable sand. The bypassed lower layer of the reservoir may have the best potential for future oil recovery. • Future development opportunities at the Zeigler Field include selective plugging of the channelized highly permeable upper sandstone layer(s) with polymers or cross-linked polymers and microbial enhanced oil recovery techniques. Targeted infill drilling, as part of an improved oil recovery project, should also be considered if economic considerations permit. Field-wide tracer tests or other flow unit definition tests are strongly recommended to identify permeability barriers not detected by previous management programs in the field. Improved definition of flow units provides a better understanding of the reservoir architecture and indicates how best to recover the remaining oil through improved oil recovery techniques. 27 ACKNOWLEDGMENTS We gratefully acknowledge the support of the operator of Zeigler Field, Victor R. Gallagher Company, which supplied most of the field data used in this work. This report is part of a major research project on improved oil recovery through reservoir characterization, funded by the U.S. Department of Energy (Grant DE- FG22-89BC 14250) and the Illinois Department of Energy and Natural Resources (Grant AE-45). Their funding and dedication to the goals of this research are gratefully acknowledged. We also thank Donald F. Oltz, principal investigator of the project, for his encouragement, intellectual input, and critical review of this manu- script, and Jonathan Goodwin for the painstaking and thorough review of this work. REFERENCES Allen, T.O., and A.P. Roberts, 1989, Production Operations: Oil & Gas Consultants International, Inc., v. 1, p. 82-92. 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Genevieve Formations: Illinois Geological Society, Illinois State Geological Survey, and Southern Illinois University at Carbondale, p. 12^6. Stratamodel Inc., 1 991 , SGM™ User's Manual: Silicon Graphics Version 1 .2, Strata- model, Inc., Houston, Texas. Tanner, R.S., E.O.Udegbunam, M.J. Mclnerney, R.M. Knapp, and J. P. Adkins, 1991, Microbial Enhancement of Oil Production from Carbonate Reservoirs: University of Oklahoma, Norman, Final Report, various pages. U.S. Department of Energy, 1991, General reservoir characteristics for deltaic reservoirs in the TORIS database, in Opportunities to Improve Oil Productivity in Unstructured Deltaic Reservoirs: A Public Meeting for Views and Com- ments, Dallas, Texas, January 29-30, p.3-28-3-33. 29