AUTHORS

Ernest A. Mancini � Center for SedimentaryBasin Studies and Department of GeologicalSciences, University of Alabama, Box 870338,Tuscaloosa, Alabama 35487;emancini@wgs.geo.ua.edu

Ernest A. Mancini is regional director of the Eastern GulfRegion of the Petroleum Technology Transfer Council,director of the Center for Sedimentary Basin Studies,and professor in petroleum geology in the Departmentof Geological Sciences at the University of Alabama. Hisresearch focus is on reservoir characterization andmodeling, petroleum systems, and the applicationof stratigraphic analysis to petroleum exploration.

Thomas A. Blasingame � Department of Petro-leum Engineering, Texas A&M University, CollegeStation, Texas 77843; t-blasingame@tamu.edu

Tom Blasingame is an associate professor in theDepartment of Petroleum Engineering at Texas A&MUniversity. He holds B.S. and M.S. degrees and a Ph.D.from Texas A&M University in petroleum engineer-ing. He is a distinguished member of the Societyof Petroleum Engineers and a member of the So-ciety for Exploration Geophysicists and AAPG.

Rosalind Archer � Department of EngineeringScience, University of Auckland, Private Bag 92019,Auckland, 1020, New Zealand;r.archer@auckland.ac.nz

Rosalind Archer holds a Ph.D. in petroleum engineer-ing from Stanford University. Her research interestsare in reservoir characterization, well testing, andreservoir simulation. She is currently a lecturer in theDepartment of Engineering Science at the Universityof Auckland, Auckland, New Zealand. She is also anadjunct assistant professor in the Department ofPetroleum Engineering at Texas A&M University.

Brian J. Panetta � Center for Sedimentary BasinStudies and Department of Geological Sciences,University of Alabama, Box 870338, Tuscaloosa,Alabama 35487; bpanetta@petromod.geo.ua.edu

Brian Panetta is a research associate in the Departmentof Geological Sciences at the University of Alabama.He received a B.S. degree from the University of SouthCarolina, an M.S. degree from the University of Ken-tucky, and an M.S. degree and a Ph.D. from the Uni-versity of Alabama. His research interests are inreservoir characterization and geologic modeling.

Juan Carlos Llinas � Center for SedimentaryBasin Studies and Department of GeologicalSciences, University of Alabama, Box 870338,Tuscaloosa, Alabama 35487; llina001@bama.ua.edu

Juan Carlos Llinas obtained his B.A degree fromthe National University of Colombia in 1995 and

Improving recovery frommature oil fields producingfrom carbonate reservoirs:Upper Jurassic SmackoverFormation, Womack Hill field(eastern Gulf Coast, U.S.A.)Ernest A. Mancini, Thomas A. Blasingame,Rosalind Archer, Brian J. Panetta, Juan Carlos Llinas,Charles D. Haynes, and D. Joe Benson

ABSTRACT

Reservoir characterization, modeling, and simulation were under-

taken to improve production from Womack Hill field (eastern Gulf

Coast, United States). This field produces oil from Upper Jurassic

Smackover carbonate shoal reservoirs. These reservoirs occur in

vertically stacked, heterogeneous depositional and porosity cycles.

The cycles consist of lime mudstone and wackestone at the base and

ooid grainstone at the top. Porosity has been enhanced through dis-

solution and dolomitization. Porosity is chiefly interparticle, solution-

enlarged interparticle, grain moldic, intercrystalline dolomite, and

vuggy pores. Dolostone pore systems and flow units have the high-

est reservoir potential. Petroleum-trapping mechanisms include a

fault trap (footwall uplift with closure to the south against a major

west-southeast–trending normal fault) in the western area, a foot-

wall uplift trap associated with a possible southwest-northeast–

trending normal fault in the south-central area, and a salt-cored anti-

cline with four-way dip closure in the eastern area. Potential barriers

to flow are present as a result of petrophysical differences among

and within the cycles, as well as the presence of normal faulting.

Reservoir performance analysis and simulation indicate that the

unitized western area has less than 1 MMSTB of oil remaining to

be recovered, and that the eastern area has 2–3 MMSTB of oil to

be recovered. A field-scale reservoir management strategy that

E&P NOTES

AAPG Bulletin, v. 88, no. 12 (December 2004), pp. 1629–1651 1629

Copyright #2004. The American Association of Petroleum Geologists. All rights reserved.

Manuscript received March 17, 2004; provisional acceptance May 26, 2004; revised manuscript receivedJune 10, 2004; final acceptance June 21, 2004.

includes the drilling of infill wells in the eastern area of the field

and perforating existing wells in stratigraphically higher porosity

zones in the unitized western area is recommended for sustaining

production from the Womack Hill field.

INTRODUCTION

Womack Hill field, southwest Alabama, was discovered in 1970.

The petroleum trap was originally interpreted as a salt pillow anti-

cline associated with the Pickens-Gilbertown-West Bend fault

system (McKee, 1990). With increasing oil production rates, the

reservoir pressure declined rapidly on the west end of the field. Be-

cause of this decline in reservoir pressure in the western area of the

reservoir, this portion of the field was unitized in 1975, and a fresh-

and salt-water injection program for pressure maintenance was

initiated. Ultimate oil recovery was estimated to be 17.1 MMSTB of

oil from the unitized western area where the dominant reservoir

drive mechanism is a combination of solution gas and water drive.

From mathematical computer modeling associated with unit-

ization, ultimate primary oil recovery from Womack Hill field was

estimated at 25.2 MMSTB of oil or 29% of the original oil in place

(87 MMSTB of oil). The estimated oil recovery from secondary

operations was 40% or 34.8 MMSTB of oil from the field. As a

result of the modeling, it was concluded that a fluid-flow barrier

was present and was located approximately along the production

unit lease line between wells 2130B and 1804 (Figure 1). It was

determined that the eastern area of the field was performing under

the influence of a substantial water drive, and secondary recovery

in this area was not justified at this time.

Thirty-seven wells have been drilled in the field area. Overall,

the Womack Hill field has produced 31.2 MMSTB of oil, 15.4 bscf

(billion standard cubic feet) of gas, and 51.7 MMSTB of water from

the Upper Jurassic Smackover Formation from 27 wells. The unit-

ized western area of Womack Hill field has produced 17.0 MMSTB

of oil and 9.3 bscf of gas.

The principal problem at the field is productivity and prof-

itability. With time, there has been a decrease in oil production, while

operating costs continue to increase. To maintain pressure in the

reservoir, increasing amounts of water must be injected annually. The

major producibility problems are related to cost-effective, field-scale

reservoir management; reservoir connectivity caused by carbonate

rock architecture and heterogeneity; pressure communication caused

by carbonate petrophysical and engineering properties; and cost-

effective operations associated with the oil recovery process.

The purposes of this paper therefore are to (1) characterize the

geologic, petrophysical, and engineering properties of the Smack-

over reservoir intervals at Womack Hill field; (2) construct a three-

dimensional (3-D) geologic model and a reservoir simulation model

for the reservoir intervals; and (3) use the reservoir characteriza-

tion, engineering reservoir performance analysis, and geologic and

his M.S. degree in 2003 from the University ofAlabama, and he is currently working on his Ph.D.at the University of Alabama. He works in geologicmodeling of oil fields with siliciclastic and carbonatereservoirs using well-log, core, and seismic data.

Charles D. Haynes � Department of Civil andEnvironmental Engineering, University of Alabama,Box 870205, Tuscaloosa, Alabama 35487;chaynes@coe.eng.ua.edu

Charles D. Haynes is a businessman and educatorwith degrees in mining and petroleum engineering.He was an independent petroleum producer beforejoining the faculty at the University of Alabama. Hecontinues his professional practice through minerals-related research, consulting, and joint ownership ofan independent oil-producing company. He serveson the State Board of Licensure for Engineers andLand Surveyors.

D. Joe Benson � Center for Sedimentary BasinStudies and Department of Geological Sciences,University of Alabama, Box 870338, Tuscaloosa,Alabama 35487; dbenson@as.ua.edu

Joe Benson is a professor in the Department ofGeological Sciences and senior associate dean ofthe College of Arts and Sciences at the Universityof Alabama. His research interests lie in carbonatesedimentology and sedimentary petrology. He re-ceived a B.A. degree from the College of Woosterand an M.S. degree and a Ph.D. from the Universityof Cincinnati.

ACKNOWLEDGEMENTS

We thank the State Oil and Gas Board of Alabamafor access to cores, well files, and production datafrom Womack Hill field. Pruet Production Co. pro-vided the water injection and production data fromthis field. The reservoir characterization, geologicvisualization modeling, and reservoir simulationwere accomplished using software provided byLandmark Graphics Corporation. We thank Leo-nard Brown, Jack Pashin, and Mihaela Ryer fortheir reviews of the manuscript. This research hasbeen funded by the U.S. Department of Energy(DOE) through its National Energy TechnologyLaboratory to the University of Alabama. However,any opinions, findings, conclusions, or recommen-dations expressed herein are those of the authorsand do not necessarily reflect the views of the DOE.

1630 E&P Notes

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Mancini et al. 1631

reservoir simulation modeling to assess the current

field-scale reservoir management practices to provide

a foundation for improving production from this field.

GEOLOGIC RESERVOIR CHARACTERIZATION

Reservoir characterization of the Smackover carbon-

ate facies at Womack Hill field (Figure 1) has included

the description of the six available cores (Figure 2) and

petrographic analysis of 304 thin sections. In addition,

electrical and geophysical logs for 37 wells and core

analyses for 24 wells (Figure 3) were studied. The core

data were calibrated to the well-log patterns to establish

electrofacies for correlation, mapping, and modeling.

In the Womack Hill field, the Smackover Forma-

tion ranges in thickness from 67 to 129 m (220 to 422 ft),

has an average thickness of 104 m (340 ft), and overlies

sandstone of the Norphlet Formation. The Norphlet

Formation overlies the Jurassic Louann Salt, which, in

combination with faulting, is responsible for the pe-

troleum trap at the field. The Smackover Formation

is overlain by the Buckner Anhydrite Member of the

Haynesville Formation. These anhydrite beds form the

top seal in the field. The Smackover Formation includes

lower,middle,andupperunits intheWomackHill field.

The lower member or unit of the Smackover is typi-

cally composed of peloidal packstone and wackestone

(Benson, 1988). The middle member or unit includes la-

minated lime mudstone and fossiliferous wackestone

and lime mudstone. Porosity is developed in the upper

partofthemiddleSmackoverinthesouth-centralpartof

the field. The upper member or unit ranges in thickness

from 13 to 64 m (44 to 209 ft), has an average thickness

of 37 m (120 ft) (Figure 3), and consists of a series of

three cycles (Figures 4, 5). Stratigraphically, these

cycles are higher order parasequences that accumulat-

ed as part of the highstand or regressive systems tract of

an Upper Jurassic depositional sequence.

The upper cycle (cycle 3) is a shoaling-upward

parasequence composed of lower energy, lime mud-

stone and peloidal wackestone at the base capped by

higher energy, ooid grainstone. The lime mudstone and

wackestone (generally less porous strata) have been

Figure 2. Structure map of the top of the Smackover Formationat Womack Hill field, location of injection wells, cores studied,and outline of areas with high potential for containing undrainedand attic oil in the field. Note petroleum trap types. See Figure 1for well symbols.

1632 E&P Notes

interpreted as restricted bay and lagoon sediment, and

the grainstone has been described as shoreface and shoal

deposits (generally porous strata) (McKee, 1990). Al-

though this cycle is present across the field (Figure 5),

its reservoir quality varies. The cycle has an average

thickness of 9 m (30 ft). The grainstone associated with

this cycle is dolomitized in much of the field area and is

the main reservoir interval perforated in the field. The

dolomitized portion of cycle 3 is part of the upper

dolomitized zone in the field (Figure 4). Hydrocarbons

have been produced from this cycle in 21 of the 27

productive wells in the field. Six wells (wells 1678, 1781,

1826, 2257B, 2327, and 3657) have been perforated

only in this cycle, and the cumulative oil production

ranges from 0.13 to 1.97 MMSTB of oil (Figure 1).

Porosity and permeability in the more productive wells

(e.g., well 1678) in cycle 3 average 21.0% and 59.3 md,

respectively (Figure 6A), and porosity and permeabil-

ity in the less productive wells (e.g., well 2327) average

12% and 3 md, respectively. The lime mudstone and

wackestone in the lower part of the cycle have po-

tential to be a barrier to vertical flow in the field.

The middle cycle (cycle 2) and the lower cycle

(cycle 1) also occur across the field. Cycle 2 has an aver-

age thickness of 14 m (47 ft), and cycle 1 has an average

thickness of 12 m (40 ft). These cycles include shoal

grainstone/packstone facies, which is underlain by la-

goonal mudstone and wackestone deposits. The reser-

voir intervals associated with these cycles are a result

of depositional and diagenetic processes. Dolomitiza-

tion can be pervasive in the shoal grainstone litho-

facies and, in some cases, in the lagoon mudstone and

wackestone lithofacies of these cycles and in the inter-

val immediately below cycle 1. The dolomitized por-

tion of these cycles and the interval below cycle 1 is part

of the lower dolomitized zone in the field (Figure 4).

Hydrocarbons have been produced from cycle 2 in

18 wells and from cycle 1 in 6 wells. Three wells (wells

1847, 2248B, and 2263; see Appendix) have been per-

forated only in cycle 2, and the cumulative oil pro-

duction is 0.35–3.18 MMSTB of oil per well (Figure 1).

One well (2109) has been perforated only in cycle 1,

and its cumulative oil production is 1.72 MMSTB of

oil (Figure 1). Porosity and permeability in well 1720

(see Appendix) average 20.3% and 61.7 md, respec-

tively, for cycle 2 (Figure 6B), and porosity and per-

meability in well 1591 (see Appendix) average 18.0%

and 18.8 md, respectively, for cycle 1 (Figure 6C). Pro-

duction from the upper part of the middle Smackover

interval immediately below cycle 1 (Figure 4) is from

one well (4575B, see Appendix) that is located in the

south-central part of the field. This well is perforated

only in this interval. Cumulative oil production for

well 4575B is 2.48 MMSTB of oil (Figure 1). Porosity

and permeability in well 4575B for the porous zone

below cycle 1 average 23.4% and 21.2 md, respectively

(Figure 6D). Permeability shows good correlation (0.74–

0.81) with porosity in these four reservoir intervals

(Figure 6). The most productive well (1804) in the field

is perforated in all three cycles, and the cumulative

production is 3.4 MMSTB of oil (Figure 1). Porosity and

permeability in these three cycles in this well average

20.1% and 5.1 md, respectively.

Although the primary control on reservoir architec-

ture in Smackover carbonates, including Womack Hill

field, is the depositional fabric, diagenesis is a significant

factor in modifying reservoir quality (Benson, 1985).

Of the diagenetic events, multiple dolomitization and

Figure 3. Isopach map of the upper part of the Smackover Formation at Womack Hill field and location of wells with core analysisdata. Note thickness variations in the upper Smackover interval. See Figure 1 for well symbols.

Mancini et al. 1633

dissolution events probably had the greatest influence

on reservoir quality in the Smackover Formation. Al-

though dolomitization created only minor amounts of

intercrystalline porosity, it significantly enhanced per-

meability; it also stabilized the lithology that reduced

the potential for later porosity loss because of com-

paction (Benson, 1985). The dissolution events enlarged

primary (interparticle) and early secondary (moldic and

intercrystalline) pores (McKee, 1990). Although dis-

solution did not create large amounts of new poros-

ity, it did expand existing pore throats and enhance

permeability (Benson, 1985).

Porosity in the shoal grainstone reservoir intervals

at Womack Hill field is both primary and secondary.

The main pore types in Smackover reservoirs, including

the Womack Hill field area, are interparticle, solution-

enlarged interparticle, grain moldic, intercrystalline

dolomite, and vuggy (Hopkins, 2002). Primary inter-

particle porosity has been reduced in the field because

of compaction and cementation. Solution-enlarged in-

terparticle and grain moldic porosity is produced by

early leaching in the vadose zone that dissolved ara-

gonite in the Smackover carbonates (McKee, 1990).

Moldic porosity is produced by early, fabric-selective

dissolution of aragonitic grains and is associated with

areas of subaerial exposure (Benson, 1985). Several phases

of dolomitization have been identified in the Smack-

over carbonates at Womack Hill field. The upper zone

of dolomitization is fabric destructive and is the re-

sult of an early-stage, diagenetic event involving the

Figure 4. Well-log patternsfor well 1667 in Womack Hillfield illustrating stratigraphicunits, upper Smackover cycles,porous (U) and less porous (L)portions of the cycles, porouszone below cycle 1, and upperand lower dolomitized zones.See Figure 1 for well location.

1634 E&P Notes

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Mancini et al. 1635

downward movement of evaporitically concentrated

brine (Tedesco, 2002). The lower zone of dolomitiza-

tion contains large amounts of intercrystalline porosity

and permeability and is the result, in part, of fabric-

destructive, mixing-zone processes (Tedesco, 2002).

Vuggy porosity, as defined by Choquette and Pray

(1970), is present in the field area as the product of late,

nonfabric-selective dissolution of calcite or dolomite

and is produced by solution enlargement of earlier

formed interparticle or intercrystalline pores (Benson,

1985; Benson and Mancini, 1999). Smackover reser-

voirs characterized by vuggy porosity have high poros-

ity (up to 29%) and permeability (up to 4106 md) val-

ues (Benson and Mancini, 1984; Mancini et al., 2000).

Pore systems are the fundamental building blocks

of reservoir architecture. Pore origin, geometry, and

spatial distribution determine the amount and kind

of reservoir heterogeneity. Pore systems affect not

only hydrocarbon storage and flow but also reservoir

producibility and flow-unit quality and comparative

rank in a field. Hydrocarbon recovery efficiency and

total recovery volume are determined by the 3-D

shape and size of the pores and pore throats (Kopaska-

Merkel and Hall, 1993; Ahr and Hammel, 1999). There-

fore, the pore systems (pore topology and geometry

and pore-throat size distribution) of the Womack Hill

field reservoir intervals are extremely important. Pore-

throat size distribution is one of the important factors

Figure 6. Porosity vs. permeability plots for reservoir zones (cycles) in wells in the Womack Hill field: (A) cycle 3, well 1678; (B)cycle 2, well 1720; (C) cycle 1, well 1591; and (D) below cycle 1, well 4575B. See Figure 1 for the location and productivity of wells.

1636 E&P Notes

determining permeability because the smallest pore

throats are the bottlenecks that determine the rate

at which fluid can pass through a rock. Permeability

has been shown to be directly related to the inherent

pore system and degree of heterogeneity in Smack-

over reservoirs (Carlson et al., 1998; Mancini et al.,

2000). Generally, the more homogeneous (little vari-

ability in architecture and pore systems) the reservoir,

the greater the hydrocarbon recovery from that res-

ervoir. However, heterogeneity at one scale is not nec-

essarily paralleled by heterogeneity at other scales. For

example, the shoal grainstone reservoir intervals at

Womack Hill field can be dominated by an interpar-

ticle and solution-enlarged, moldic and intercrystal-

line, or intercrystalline and vuggy pore system and

have low mesoscopic-scale heterogeneity but low to

high microscopic-scale heterogeneity, depending on the

pore system. Such heterogeneity is a function of both

depositional and diagenetic processes. The grainstone

deposits accumulated in shoal environments, which

tend to have uniformity of paleoenvironmental condi-

tions in a given shoal, but these carbonates can be later

subjected to dissolution and dolomitization, such as at

Womack Hill field, to produce dolograinstone and

coarse (large) crystalline dolostone. The moldic and

intercrystalline pore system produced is characterized

by pores of variable size that are poorly connected by

narrow pore throats. Pore size is dependent on the

size of the carbonate grain that was leached. The

intercrystalline and vuggy pore system is charac-

terized by more large-sized pores that are inter-

connected by larger and more uniform pore throats.

The size of the pores is dependent on the dolomite

crystal size. Interparticle porosity of Lucia (1999),

which includes intergrain and intercrystal pore types

in grainstone, dolograinstone, and large crystalline

dolostone, provides for high connectivity in carbon-

ate reservoirs and high permeability (Lucia, 1999;

Jennings and Lucia, 2001). In the Womack Hill field,

leached and dolomitized grainstone flow units domi-

nated by moldic and intercrystalline porosity have

lower reservoir potential than the grainstone flow

units dominated by depositional interparticle and

solution-enlarged porosity because the leached (mol-

dic) grainstone pore system is characterized by a higher

percentage of small-sized pores poorly connected by nar-

row pore throats. Dolostone flow units dominated by

intercrystalline and vuggy porosity have the highest res-

ervoir potential because of a pore system characterized

by a higher percentage of large-sized pores intercon-

nected by larger and more uniform pore throats.

ENGINEERING DATA AND ANALYSIS

The production history for Womack Hill field reflects

a rapid development in the number of producing wells

(17 wells from 1971 to 1973). After the initial drilling

phase, the oil production rate began to decline, and a

pressure maintenance project involving the injection

of fresh and salt water was implemented in the unit-

ized western area of the field. The initiation of this

project arrested production decline in this part of the

field. The current production decline is caused by wells

being taken offline, decreased injection capacity, and a

need for workovers on producing wells. Oil and gas

production for the field has reached a plateau, while

water production continues to rise (Figure 7), indicat-

ing that the field is approaching maximum recovery.

Womack Hill field has continuously produced more

water than the amount of water being injected, sug-

gesting that an external source of water (adjoining and/

or underlying aquifer) is contributing as a production

mechanism (water drive) in the field.

The reservoir fluid sample for pressure, volume,

and temperature analysis for the Smackover reservoir

confirms that the fluid in Womack Hill field reser-

voir is a conventional black oil. The original reservoir

pressure was 5433 psia, the bubble-point pressure was

1925 psig, the separator gas-oil ratio was 579 scf/STB,

and the separator oil gravity was 42.6j API for a sep-

arator pressure of 100 psig and a temperature of 74jF.

At the bubble point, the formation volume factor of the

oil was 1.41 reservoir bbl/stock tank bbl at 400 psig,

and the viscosity of the oil at a temperature of 212jF

has a minimum of 0.342 cp.

Reservoir performance analysis, using decline-type

curve analysis for an unfractured well model after Doublet

and Blasingame (1995) (Figure 8) and estimated ulti-

mate recovery (EUR) analysis (oil-flow rate/pressure

drop vs. cumulative oil production) after Fetkovich

(1980) (Figure 9), shows good volumetric correlation

of fluid volumes for high-producing wells and indi-

cates that low-producing wells correlate with lower

reservoir continuity. Good correlation is evident for the

production data and model trends in the field as il-

lustrated for well 1639 in Figure 8. A strong depletion

trend (terminal production decline) for production

in the field is evident in Figure 9 as shown for well

1639. In utilizing cumulative oil and water produc-

tion from the field, ultimate oil recovery for the field

will approximate at least 34.6 MMSTB of oil. Using

EUR, conservatively about 10% of the recoverable

34.6 MMSTB of oil remains to be produced from

Mancini et al. 1637

Figure 7. Production and water injection history of the Womack Hill field. Oil and gas production rates have declined, waterproduction rate has increased, and gas-oil ratio (GOR) has remained constant. Water injection efficiency appears to be declining. Thehigher volume of produced water is probably caused by an external water influx.

Figure 8. Decline-type curve analysis for an unfractured well model after Doublet and Blasingame (1995) for well 1639, WomackHill field. Most of the data lie in the boundary-dominated flow region, and the transient flow regime is less well defined. See Figure 1for well location.

1638 E&P Notes

Womack Hill field. With production from the field

totaling 31.2 MMSTB of oil, at least 3.4 MMSTB of oil

remains to be recovered.

In Figure 10, the dimensionless multiwell perfor-

mance index (DMPI) approach of Valko et al. (2000)

is computed for the individual wells in Womack Hill

field. Figure 10A shows the DMPI determined using

total rates of oil and water, and Figure 10B illustrates

the DMPI computed using only the total oil rate. This

analysis shows that the influence of a water drive, either

by water injection and/or influx, is pervasive in the field

reservoir. Essentially, every well reflects a strong influ-

ence of external energy support. For wells in the eastern

area of the field, this support is probably from an adjoin-

ing and/or underlying aquifer. In the unitized western

area of the field, injection of water provides the ex-

ternal support. In using exponential and harmonic rate

decline cases to evaluate the production behavior of the

reservoir in the western unitized and eastern areas of

the field (Figure 11), production at Womack Hill field

is shown to be best characterized by the exponential

rate decline case (natural depletion).

Pressure transient tests were conducted for wells

1655, 1678, 1804, and 4575B to characterize the

reservoir (Figure 12). The pressure transient tests

support the interpretations that compartmentaliza-

tion is a characteristic of the Womack Hill field res-

ervoir (Figure 12A, B), that production from wells

in the eastern area of the field is facilitated by a natu-

ral external influx of water from the bottom up

(Figure 12C), and that a fault bounds the field to the

south (Figure 12D).

In using the engineering property data, analysis, and

interpretation to evaluate the effectiveness of the pres-

sure maintenance program, a correlation of oil produc-

tion, water injection, and structure is evident in Womack

Hill field. Oil production appears to be correlated with

reservoir structure, and water injection appears to be

correlated with oil production (Figure 13). Therefore,

water injection should be continued and conducted

downdip and focused toward areas of the field that are

structurally low to maximize the effect of the water

injection for pressure maintenance. The remainingoilto

be recovered in the field is concentrated in the south-

central part of the field in the vicinity of well 4575B and

along a west-east trend in the eastern area of the field,

north of wells 1826, 1825, and 1760.

3-D GEOLOGIC MODELING

The stratigraphic, sedimentologic, and petrophysical

information obtained from core, well-log, and thin-

section analysis is fundamental to the construction of

the 3-D geologic model. These data and information

from the subsurface structure and isopach maps and

cross sections are integrated into the model to illustrate

Smackover cycle distribution, thickness, reservoir qual-

ity, and structural configuration.

The 3-D geologic model illustrates that the petro-

leum trap at Womack Hill field is more complex than

originally interpreted (Figure 14). Two-dimensional

seismic data were used to assist with the location of a

major high-angle normal fault having significant stratal

displacement of 411 m (1350 ft) (McKee, 1990) to

the south of the field. Based on bed elevations and

subsurface mapping, the trap in the western part of

the field can be described as a fault trap (footwall

Figure 9. Estimated ultimaterecovery (EUR) analysis (oilflow rate/pressure drop vs.cumulative oil production) forwell 1639, Womack Hill field.Cumulative production is ap-proaching total recoverable oil.See Figure 1 for well location.

Mancini et al. 1639

uplift with closure to the south against the major west-

southeast–trending normal fault), and the trap in the

eastern part of the field appears to be a salt-cored

anticline with four-way dip closure (Figures 2, 14). In

the south-central part of the field, there is a third,

smaller structure related to a possible southwest-

northeast–trending high-angle normal fault, with its

displacement decreasing gradually to the north (Fig-

ures 2, 14). Although there is no direct evidence of

this fault, the mapped surface at the top of the

Smackover Formation suggests the presence of such a

normal fault. Additionally, two-dimensional seismic

data immediately north of the field show the presence

of north-south–trending normal faults. The south-

west-northeast–trending fault could have formed as

the result of the accommodation of differential vertical

displacement related to the bend in the strike of the

major normal fault to the south. The resulting trap is a

footwall uplift structure bounded by the major fault to

the south, by the accommodation fault to the west and

north, and by a dip closure to the east. The southwest-

northeast–trending fault has the potential to act as a

Figure 10. Dimensionless multiwell performance index (DMPI) computed for wells in the Womack Hill field: (A) Total oil and waterrates are used in this calculation, and (B) total oil rates only are used in this calculation.

1640 E&P Notes

Figu

re1

1.D

imen

sion

less

prod

uctio

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ime

–ty

pecu

rve,

Wom

ack

Hill

field

.(A

)Ex

pone

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lrat

ede

clin

em

odel

com

pare

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prod

uctio

nda

tafr

omth

eun

itize

dw

este

rnar

ea.

(B)

Har

mon

icra

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clin

em

odel

com

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tafr

omth

eun

itize

dw

este

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ea.(

C)

Expo

nent

ialr

ate

decl

ine

mod

elco

mpa

red

topr

oduc

tion

data

from

the

east

ern

area

.(D

)H

arm

onic

rate

decl

ine

mod

elco

mpa

red

topr

oduc

tion

from

the

east

ern

area

.The

expo

nent

ialt

rend

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lutio

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rno

rmal

rese

rvoi

rde

plet

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The

gene

ral

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that

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dw

ater

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ctio

nsu

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Mancini et al. 1641

Figu

re1

2.S

umm

ary

plot

s(n

ora

tehi

stor

y)fr

omth

efie

ld-t

estin

gse

quen

ceof

wel

ls:(

A)w

ell1

655,

(B)w

ell1

678,

(C)w

ell1

804,

and

(D)w

ell4

575B

,Wom

ack

Hill

field

.See

Figu

re1

for

the

loca

tion

ofw

ells

.

1642 E&P Notes

flow barrier, thus helping to explain the pressure dif-

ference between wells in the western and central parts

of the field and wells in the eastern part of the field.

Interestingly, the most productive wells (wells 2248B,

2130B, 4575B, and 1804) are located in the south-

central part of the field and are associated with this

footwall uplift feature (Figures 1, 2, 14).

The 3-D geologic modeling also shows that the

reservoir intervals at Womack Hill field are heteroge-

neous. Although the upper cycle (cycle 3) reservoir

interval is the most productive areally (has been pro-

ductive in 21 wells), the production from this reser-

voir is highly variable, with cumulative oil production

ranging from 0.13 to 1.97 MMSTB of oil for wells

perforated only in this cycle. The thickness and res-

ervoir quality are also variable for the upper reservoir

interval. The middle cycle (cycle 2) reservoir interval

is also heterogeneous in thickness and lateral and ver-

tical reservoir quality; however, the porosity, as indi-

cated by density log analysis, is overall higher in this

interval than in the other reservoir intervals (Figure 15).

The lower cycle (cycle 1) reservoir interval is also het-

erogeneous in thickness and reservoir quality. Although

the total oil production from this cycle is not as high

as the cycle 2 or cycle 3 reservoir intervals, well 2109,

the only well solely perforated in cycle 1 and located

in the unitized western part of the field, has had

a cumulative oil production of 1.72 MMSTB of oil

(Figure 1). The reservoir interval immediately below

cycle 1 has been perforated in one well (4575B) in the

south-central portion of the field. Reservoir quality

in this well is high, and production is high. This res-

ervoir interval has potential for high reservoir qual-

ity in the vicinity of well 2109 (Figures 2, 14). The

high reservoir quality and productivity in this inter-

val in well 4575B is attributed to mixing-zone dolomi-

tization (freshwater lens development in structurally

higher areas of the field). The area around well 2109

is structurally high. In the eastern part of the field,

the structurally high area north of wells 1804, 1826,

1825, and 1760 and the structurally high area around

wells 1781 and 1847 have excellent potential for re-

maining oil to be recovered (Figures 2, 14). Wells 1781

and 1847 continue to be highly productive wells, and

Figure 13. Correlation ofestimated ultimate recovery(EUR) vs. effective permeabil-ity (k) for wells in WomackHill field. See Figure 1 for thelocation of wells. WPA = wellperformance analysis.

Mancini et al. 1643

well 1804 is the most productive well in the field

(Figure 1). The recent (2003) successful drilling of

well 12762 immediately northwest of well 1826 sup-

ports this interpretation. This well was perforated at

3452–3455 m (11,324–11,336 ft) and tested 160

STB of oil/day. The shut-in bottomhole pressure for

the well was 4760 psia. The well had produced

18,415 STB of oil and 113,505 STB of water through

December 2003.

A porosity (fluid-flow) barrier, especially apparent

in the cycle 3 reservoir interval, appears to be present

between the unitized western area and eastern areas

of the field (Figure 15). Comparing the porosity and

permeability data between wells 1748 and 1804, it

appears that there is flow communication in the field

through the cycle 2 reservoir interval. The improved

reservoir communication in the cycle 2 reservoir in-

terval is probably a result of dolomitization. Porosity

and permeability data are insufficient in the field to

assess the potential of a barrier to flow in the cycle 1

reservoir interval and the reservoir interval imme-

diately below cycle 1. Communication also appears likely

between the eastern part of the unitized western area

(wells 2130B, 2248B, and 4575B) and the area around

well 1804 because these wells are draining hydrocarbons

from the same trap located in the south-central part of

the field (Figures 2, 14). However, communication be-

tween the wells in the unitized western area and the

other wells east of well 1804 in the eastern area of the

field probably is limited because of a combination of

structural and petrophysical factors.

The cycle 1 reservoir interval and the reservoir

interval immediately below cycle 1 are underdeveloped

reservoir intervals in the unitized western area of the

field. Specifically, the area south of well 2109 has the

potential to contain undrained attic oil. This possibil-

ity is based on the interpretation that the petroleum

trap in the western part of the field is a fault trap, and

this structure is similar to the North Choctaw Ridge

field structure interpreted by Qi et al. (1998). The res-

ervoir volume was increased by 12% at North Choctaw

Ridge field if the structural trap is interpreted as a

footwall uplift along a fault instead of a faulted anti-

cline (Qi et al., 1998). The structurally high position

of the acreage south of well 2109 makes the area a

strong candidate to contain a dolomitized cycle 1 res-

ervoir interval and a dolomitized reservoir interval be-

low cycle 1. This observation is based on the concept

that the high reservoir quality and productivity of

the reservoir interval below cycle 1 in well 4575B

are caused by mixing-zone dolomitization (freshwater

lens) as a result of association with the structurally

Figure 14. Three-dimensional geologic model of Womack Hill field. Note structurally high areas in the vicinity of wells 2109 and4575B, north of wells 1826, 1825, and 1760, and in the area of well 1781. See Figure 2 for the structural map of the field.

1644 E&P Notes

high position of these wells. Because the reservoir in-

terval below cycle 1 has only been perforated on the

eastern margin of the unitized area and no injection is

occurring in this zone, any oil in this interval in the

western part of the unitized area probably has not been

drained. The lateral heterogeneity in this interval

probably precludes this oil from being drained by the

wells located on the eastern margin of the unitized

area. The cumulative oil production from well 2109,

the only well solely perforated in the cycle 1 reservoir

interval, supports the concept that the area south of

this well contains oil.

RESERVOIR SIMULATION

Reservoir simulation has produced a model for the

Womack Hill field reservoir based on the 3-D geo-

logic model, and this simulation model has been used

for history matching. The static data for the reservoir

simulation model, such as permeability, porosity, and

geometry, were obtained from well-log and core data,

reservoir performance analysis, and the 3-D geologic

model. The geologic model was upscaled for the sim-

ulation modeling.

The simulation model used a grid of 60 � 30 cells

and 19 layers. Each cell was approximately 216 � 82 m

(414 � 268 ft) areally. In reservoir zones, the grid cells

were 3 m (10 ft) or less in thickness, and in the strata

below the reservoir zones, the cells were 30 m (100 ft)

or more in thickness. The model consisted of the fol-

lowing layers: layer 1 (above cycle 3 interval), layers

2–6 (cycle 3 interval), layers 7–13 (cycle 2 interval),

and layers 14–19 (cycle 1 interval and porous inter-

val below cycle 1). An aquifer was attached to the

lowest layer (layer 19) of the model because field pro-

duction was determined to be supported by water in-

flux. The original oil-water contact was reported at

3463 m (11,360 ft). This contact was varied during the

history match.

Because relative permeability and capillary pres-

sure data were not available for this study, various sets

of relative permeability and capillary pressure curves

were tested in the history-matching process. In the

final version of the model, the relative permeability

curves included a residual oil saturation of 0.3 and an

Figure 15. Cross section across Womack Hill field showing changes in porosity for the upper Smackover reservoir intervals asdetermined from density log analysis. This cross section corresponds to the cross section illustrated in Figure 5. See Figure 1 for thelocation of the wells.

Mancini et al. 1645

endpoint water relative permeability of 1.0. The cap-

illary pressure curves used represent strong imbibition

water. To match the water influx, a value of 1.0 was

used for the ratio of vertical to horizontal permeabil-

ity. With the capillary pressure and oil-water contact

defined for a particular simulation, the modeling was

commenced for an initial fluid distribution.

Monthly oil and gas production volumes used for

the study were available from the beginning of pro-

duction in the field in 1970. Monthly volumes of water

production and of water injection data were acquired

for each well since 1982. The lack of water production

data from 1970 to 1982 was an issue in the history-

matching process because it was difficult to determine

when breakthrough occurred in many of the wells in

the field. Well completion and perforation depths and

dates were also obtained. A significant change in field

operations occurred in 1990–1991 when jet pumps

were installed in the production wells. The increase in

field watercut that occurred at the time may be a result

of this operational change. Acid treatments were per-

formed periodically in the wells.

During the history-matching process, the wells

were operated by withdrawing the same amount of oil

as was historically produced. Because pressure data

were limited, the success of the history match was

judged by the ability to match the reported water pro-

duction data from the simulation modeling. Analysis

of the production data shows that the reservoir has

remained above the bubble point; therefore, detailed

history matching information could not be obtained

from the gas production data.

Initially, global model parameters, such as the

water-oil contact depth, ratio of vertical to horizontal

permeability, degree of connectivity between the unit-

ized western and eastern areas of the field, and the

aquifer strength and location, were adjusted to achieve

the best possible match. Based on the results of the

production data analysis and well test analysis, compart-

mentalization was introduced using transmissibility

barriers around well 1804. This well has been the most

productive well in the field and probably is produc-

ing from its own reservoir compartment. In this stage

of the history-matching study, the impact of changes

in global parameters was evaluated to gain insight into

the key factors controlling flow in the reservoir. Twenty-

four simulation runs were made, systematically varying

the oil-water contact depth, the aquifer location (under

the entire reservoir or under the eastern area only), the

aquifer strength (weak, strong), and the strength of

a possible flow barrier between the unitized western

and eastern areas of the field. The oil-water contact

depth has the strongest influence on cumulative wa-

ter production. Indications are that the presence of a

flow barrier between the unitized western and east-

ern areas of the field has little impact on cumulative

water production.

The final phase of the history-matching effort in-

volved making some local changes to the geologic mod-

el in the neighborhood of key wells (commonly those

with high water and/or oil production). Typically, these

changes involved reducing porosity in a window around

the well to accelerate the process of water invasion

into the well. In some cases, porosity was increased

to reduce amounts of water production. These local

changes were based on the results from the produc-

tion data analysis, which assigned in-place volumes to

individual wells.

The field watercut as determined from the mod-

eling is shown in Figure 16. The final part of the solid line

on this figure presents the expected watercut in the

field if production is maintained from the existing

wells and if two additional infill wells are drilled. The

performance of the individual wells was matched with

varying degrees of success. Several wells had excellent

watercut history matches until 1990. At this point, jet

pumps were installed, and the watercut in certain wells

showed a marked increase. This effect was very difficult

to capture in the reservoir simulation model. Altering

the relative permeability curve assigned to the con-

nection between the well and its grid block in the res-

ervoir at the time jet pumps were introduced was the

most successful history-matching strategy to account

for the installation of the jet pumps.

Figure 17 shows the oil saturation in the top of the

upper cycle or cycle 3 in the Womack Hill field at the

end of the history match (February 2003). The oil satu-

ration is progressively less in layers below the cycle 3

interval. In the unitized western area of the field, there

is some remaining mobile oil in the vicinity of wells

4575B and 2109.

High remaining oil saturations are in the eastern

area of the field, north of wells 1804, 1825, and around

well 1781 (Figure 17). These areas are structurally high

and are predicted by the geologic model to have

reservoir-quality porosity and permeability. To target

this remaining oil, the production performance of two

infill wells (001 and 002) was simulated. The resulting

production profiles are shown in Figure 18. In the

simulation model, the wells were perforated above

11,300 ft (3440 m) and produced at a rate of 500 STB

of oil/day. Over 5 yr, the cumulative production of

1646 E&P Notes

simulated well 001 was 826 MSTB of oil and 888

MSTB of water. Simulated well 002 produced 664

MSTB of oil and 1248 MSTB of water.

APPLICATION

Because of the highly complex nature of carbonate

reservoirs, cost-effective development of these reser-

voirs requires the implementation of an integrated

reservoir management strategy. The Smackover res-

ervoir characterization and modeling at Womack Hill

field can be used to assess the current field-scale res-

ervoir management practices in this field. Areas for

future consideration for improved field operations

include the evaluation of the pressure maintenance

and waterflood project in the field, the opportunity

for the drilling of infill wells, and the possibility

of perforating existing wells in additional poros-

ity zones.

Figure 16. Comparison of actual fieldwide watercut and simulated watercut in the history-match model. The end portion of thesimulated watercut curve shows the results of a prediction simulation with two new additional wells drilled in the field.

Figure 17. Oil saturation in the top of zone 3 (cycle 3) interval at the conclusion of the history match (February 2003). Note highremaining oil saturations north of wells 1804 and 1825 and around well 1781 in the eastern area of the field and in the vicinity ofwells 4575B and 2109 in the unitized western area.

Mancini et al. 1647

The unit operator is integrating the information

from the reservoir characterization, 3-D geologic mod-

eling, reservoir performance analysis, and reservoir sim-

ulation into a field-scale reservoir management strategy

to improve operations in the Womack Hill field unit.

The company will consider perforating wells 4575B

and 2109 in higher porosity zones (cycles) in the Smack-

over reservoir in the unitized western area of the field

(Figures 2, 14) at the appropriate time. The areas cur-

rently being drained by these wells were shown to

have high potential for undrained oil through the 3-D

geologic modeling, reservoir performance analysis, and

reservoir simulation studies. Potential strategic sites to

consider for drilling infill wells to recover additional

oil from the field are located in the eastern area of the

field (Figures 2, 14, 17). The operator also has used

the pressure transient test data to assess the effective-

ness of the pressure maintenance project involving

water injection in the unitized western area. The res-

ervoir performance, multiwell productivity analysis,

and reservoir simulation studies indicate that water

injection continues to provide stable support to main-

tain production from wells in the unitized western

area, and that the strong water drive present in the

eastern area of the field presently is adequate to sustain

production in this part of the Womack Hill field.

CONCLUSIONS

1. Geologic reservoir characterization has shown that

the upper part of the Smackover Formation in

Womack Hill field is productive from carbonate

shoal reservoirs that occur in vertically stacked,

Figure 18. Simulated produc-tion profiles for potential newinfill producing wells drilled inWomack Hill field: (A) simulatedwell 001 and (B) simulated well002. See Figure 17 for the loca-tion of the wells.

1648 E&P Notes

heterogeneous depositional and porosity cycles. The

cycles typically consist of lime mudstone and wacke-

stone at the base and ooid grainstone at the top. The

lime mudstone and wackestone lithofacies has been

interpreted as restricted bay and lagoon sediment,

and the grainstone lithofacies has been described as

beach shoreface and shoal deposits. The grainstone

associated with the upper cycle (cycle 3) is dolomi-

tized (upper dolomitized zone) in much of the field

area. Dolomitization (lower dolomitized zone) can

be pervasive in the middle cycle (cycle 2) and the

lower cycle (cycle 1) and the interval immediately

below cycle 1. These cycles occur across the field,

but they are laterally heterogeneous in depositional

texture and diagenetic fabric. Porosity consists chiefly

of depositional interparticle, solution-enlarged in-

terparticle, grain moldic, intercrystalline dolomite

and vuggy pores. Dolostone pore systems and flow

units dominated by intercrystalline and vuggy pores

have the highest reservoir potential. Dolostone flow

units have a higher percentage of large-sized pores

with larger pore throats, and dolomitized and leached

grainstone flow units have a lower percentage of large-

sized pores with narrow pore throats.

2. Engineering characterization and analysis have

shown that the reservoir fluid in Womack Hill field

is conventional black oil. Pressure transient test data

support the interpretations that the Womack Hill

field reservoir is compartmentalized, and that a fault

bounds the field reservoir to the south. Reservoir

performance analysis indicates good volumetric cor-

relation for high-producing wells, and that low-

producing wells correlate with lower reservoir

continuity. Multiwell productivity analysis shows

that the influence of water drive by water injection

and/or water influx from the aquifer is pervasive

in the field reservoir. Production behavior analysis

indicates that the production in the field is best

characterized by the exponential decline case. Res-

ervoir performance studies have shown that 10%

of the recoverable 34.6 MMSTB of oil remains to

be produced from the field. The undrained oil is

concentrated in structural highs associated with

footwall uplifts in the unitized western area and

along an elongated west-east anticline in the eastern

part of the field. Water injection in the field should

be continued and conducted downdip and focused

toward areas of the field that are structurally low.

3. A 3-D geologic model has been constructed for the

Womack Hill field structure and reservoir. The 3-D

geologic modeling shows that the petroleum trap

is more complex than originally interpreted. The

petroleum-trapping mechanisms include a fault trap

(footwall uplift with closure to the south against

a major west-southeast–trending, high-angle nor-

mal fault) in the western area, a footwall uplift trap

associated with a possible southwest-northeast–

trending, high-angle normal fault in the south-central

area, and a salt-cored anticline with four-way dip

closure in the eastern area. The pressure difference

between wells in the unitized western area of the

field and wells in the eastern area of the field may be

attributed to a flow barrier caused by the presence

of a possible southwest-northeast–trending fault and

a change in porosity and/or permeability in Smack-

over facies. The geologic modeling shows that the

Smackover reservoirs are heterogeneous. The petro-

physical component of the barrier to flow is present

potentially in the vicinity of the unit line between

the unitized western and the eastern areas of the

field. Reservoir characterization and geologic model-

ing have shown that four areas in the Womack Hill

field have potential for the recovery of undrained oil.

4. Reservoir simulation has produced a model for the

Womack Hill field reservoir based on the 3-D

geologic model and reservoir performance analysis.

Analysis of the production data shows that the

reservoir has remained above the bubble point. The

simulation model has been used successfully for

history matching. The depth of the oil-water con-

tact has the strongest influence on cumulative water

production. The history match of the performance

of the field is satisfactory, and the reservoir sim-

ulation model indicates that oil remains to be re-

covered in the eastern area of the field. The unitized

western area of the field appears to have some oil

remaining to be recovered.

5. The operator for the Womack Hill field unit is

integrating the information and results from this

study into a field-scale reservoir management strat-

egy to improve operations at the Womack Hill field.

The company will consider perforating wells in

higher porosity zones in the Smackover reservoir to

recover attic oil in the unitized western area at the

appropriate time. The operator is using the pres-

sure transient test data to assess the effectiveness of

the pressure maintenance project involving water

injection in the unitized western area. The company

is evaluating the cost-effectiveness and risks asso-

ciated with instituting an infill drilling program to

recover undrained oil in the eastern area of the

Womack Hill field.

Mancini et al. 1649

REFERENCES CITED

Ahr, W. M., and B. Hammel, 1999, Identification and mapping flowunits in carbonate reservoirs: An example from Spraberry(Permian) field, Garza County, Texas, U.S.A.: Energy Ex-ploration and Exploitation, v. 17, p. 311–334.

Benson, D. J., 1985, Diagenetic controls on reservoir developmentand quality, Smackover Formation of southwest Alabama:Gulf Coast Association of Geological Societies Transactions,v. 35, p. 317–326.

Benson, D. J., 1988, Depositional history of the SmackoverFormation in southwest Alabama: Gulf Coast Association ofGeological Societies Transactions, v. 38, p. 197–205.

Benson, D. J., and E. A. Mancini, 1984, Porosity development andreservoir characteristics of the Smackover Formation insouthwest Alabama, in Jurassic of the Gulf Rim: ProceedingsGulf Coast Section SEPM Foundation 3rd Research, p. 1–17.

Benson, D. J., and E. A. Mancini, 1999, Diagenetic influence onreservoir development and quality in the Smackover updipbasement ridge play, southwest Alabama: Gulf Coast Associ-ation of Geological Society Transactions, v. 99, p. 95–101.

Carlson, E. C., D. J. Benson, R. H. Groshong, and E. A. Mancini,1998, Improved oil recovery from heterogeneous carbonatereservoirs associated with paleotopographic basement struc-tures: Appleton field, Alabama: Society of Petroleum Engi-neers/Department of Energy 11th Symposium on ImprovedOil Recovery, p. 99–105.

Choquette, P. W., and L. C. Pray, 1970, Geologic nomenclatureand classification of porosity in sedimentary carbonates: AAPGBulletin, v. 54, p. 207–250.

Doublet, L. E., and T. A. Blasingame, 1995, Decline curve analysisusing type curves: Water influx/waterflood cases: Presented atthe 1995 Annual Society of Petroleum Engineers TechnicalConference and Exhibition, Dallas, Texas, October 22–25,SPE Paper 30774, 32 p.

APPENDIX: LISTING OF WELLS IN THE WOMACK HILL FIELD AREA

Well Permit Number* Well Name Company

1573-WI-69 Carlisle 16-4 Pruet Production Co.1579 Dungan 17-5 Getty Oil Co.1591-WI-77-1 Scruggs, Parker & Norton 9-14 Pruet Production Co.1635 Martin-Norton et al. 9-12 Pruet & Hughes-Pelto Oil Co.1639 Fluker-Bend-Scruggs 9-15 Pruet Production Co.1655 Parker-Locke 9-16 Pruet Production Co.1667 Locke 10-13 Pruet Production Co.1678-WI-93-8 Locke 10-14 Pruet Production Co.1697 McPhearson 8-15 Pruet & Hughes-Pelto Oil Co.1713-SWD-74-24 Turner 13-1 Placid Oil Co.1720-WI-77-2 Womack Hill 15-2 Pruet Production Co.1732-B Gross Turner 15-4 Placid Oil Co.1748-WI-92-1 Locke S. L. 15-1 Pruet Production Co.1760 Turner 13-5 Pruet Production Co.1781 Turner 13-6 Pruet Production Co.1804 Turner 14-6 Pruet Production Co.1811-SWD-75-104 Knight 13-15 Pruet Production Co.1825 Gross Turner 14-8 Exxon Corp.1826 Gross Turner 14-7 Exxon Corp.1847 Turner 13-7 Pruet Production Co.1890-SWD-83-3 Turner 13-9 Petro-Lewis Corp.1899 Counselman 18-12 Pruet Production Co.2109 Womack Hill 9-16-A Pruet Production Co.2130-B Womack Hill 14-4-A Pruet Production Co.2168-WI-72 Womack Hill WI 9-10 FMP Operating Co., Ltd. Ptn.2183 Louise Locke 1 North American Royalties2257-B Womack Hill 15-4 Pruet Production Co.2263-SWD-85-5 Turner 13-21 Pruet Production Co.2327 Turner 13-25 Pruet Production Co.2341 Gross Turner 14-8A J. R. Pounds, Inc.2737-B Womack Hill 15-2-A Placid Oil Co.2916 White 19-5 Midroc Operating Co.3657 Turner 13-21A Pruet Production Co.4335-B Womack Hill 14-12 Pruet Production Co.4575-B Womack Hill 14-5 2 Pruet Production Co.4805-B Womack Hill 14-6 2 Petro-Lewis Corp.4852-B C. A. Cox Estate 15-8 Santa Fe Minerals, Inc.4860 Gross-Turner 14-10 Exxon Corp.12762 Gross Turner 14-7 2 J. R. Pounds, Inc.

*WI = water injection; SWD = salt water disposal.

1650 E&P Notes

Fetkovich, M. J., 1980, Decline curve analysis using type curves:Journal of Petroleum Technology, v. 32, no. 6, p. 1065–1077.

Hopkins, T. L., 2002, Integrated petrographic and petrophysicalstudy of the Smackover Formation, Womack Hill field, Clarkeand Choctaw counties, Alabama: M.S. thesis, Texas A&MUniversity, College Station, Texas, 156 p.

Jennings, J. W., and F. J. Lucia, 2001, Predicting permeability fromwell logs in carbonates with a link to geology for interwellpermeability mapping: Society of Petroleum Engineers Paper71336, p. 1–16.

Kopaska-Merkel, D. C., and D. R. Hall, 1993, Reservoir character-ization of the Smackover Formation in southwest Alabama:Geological Survey of Alabama Bulletin, v. 153, 111 p.

Lucia, F. J., 1999, Carbonate reservoir characterization: New York,Springer, 226 p.

Mancini, E. A., D. J. Benson, B. S. Hart, R. S. Balch, W. C. Parcell,and B. J. Panetta, 2000, Appleton field case study (eastern Gulfcoastal plain): Field development model for Upper Jurassic

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McKee, D. A., 1990, Structural controls on lithofacies and pe-troleum geology of the Smackover Formation: Eastern Missis-sippi Interior Salt basin, Alabama: M.S. thesis, University ofAlabama, Tuscaloosa, Alabama, 254 p.

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