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Three-Dimensional Geologic Modeling and Horizontal Drilling Bring More Oil out of the Wilmington Oil Field of Southern California*
By
Donald D. Clarke1 and Christopher C. Phillips2
Search and Discovery Article #20019 (2004)
*Adapted for online presentation of the article of the same title by the same authors in AAPG Methods in Exploration Series No. 14, entitled Horizontal Wells: Focus on the Reservoir, edited by Timothy R. Carr, Erik P. Mason, and Charles T. Feazel. This publication is available from AAPG’s Online Bookstore (http://bookstore.aapg.org/)
1City of Long Beach, Department of Oil Properties, Long Beach, California, U.S.A. ([email protected])
2Tidelands Oil Production Company, Long Beach, California, U.S.A. ([email protected])
Abstract
The giant
Wilmington oil field of Los Angeles County, California, on production since
1932, has produced more than 2.6 billion barrels of oil from basin turbidite
sandstones of the Pliocene and Miocene. To better define the actual hydrologic
units, the seven productive zones were subdivided into 52 subzones through
detailed reservoir characterization. The asymmetrical anticline is highly
faulted, and development proceeded from west to east through each of the 10
fault
blocks. In the western fault blocks, water cuts exceed 96%, and the
reservoirs are near their economic limit. Several new technologies have been
applied to specific areas to improve the production efficiencies and thus
prolong the field life.
Tertiary and
secondary recovery techniques utilizing steam have proved successful in the
heavy oil reservoirs, but potential subsidence has limited their application.
Case history 1 involves detailed reservoir characterization and optimization of
a steamflood in the Tar zone of Fault Block II. Lessons learned were
successfully applied in the Tar zone, of Fault Block V (4000 m to the east).
Case history 2 focuses on 3-D reservoir property and geologic modeling to define
and exploit bypassed oil. Case history 3 describes how this technology is
brought deeper into the formation to capture bypassed oil with a tight-radius
horizontal well.
Introduction
This paper describes three drilling projects that used computerized mapping, modeling, and simulation programs in conjunction with detailed reservoir characterization and advanced geosteering technology to successfully help tap bypassed, heavy oil in California’s mature supergiant, the Wilmington oil field. To date, the Wilmington oil field has yielded more than 2.6 billion barrels of oil of the original 9 billion barrels of oil in place. This paper focuses on how detailed reservoir characterization and 3-D visualization tools applied to horizontal drilling have improved Tidelands Oil Production Company’s recovery factor in the “Old Wilmington” or western portion of the field. Background data from THUMS’ Long Beach Unit (the field contractor for the eastern portion of the field) are included where needed to provide a thorough field overview. The methods and technologies described herein have the capability of increasing the ultimate reserves of the Wilmington oil field by hundreds of millions of barrels and will find immediate application in other mature oil fields.
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uHistory of old Wilmington area uCase history 3 (Terminal zone)
uHistory of old Wilmington area uCase history 3 (Terminal zone)
uHistory of old Wilmington area uCase history 3 (Terminal zone)
uHistory of old Wilmington area uCase history 3 (Terminal zone)
uHistory of old Wilmington area uCase history 3 (Terminal zone)
uHistory of old Wilmington area uCase history 3 (Terminal zone)
uHistory of old Wilmington area uCase history 3 (Terminal zone)
uHistory of old Wilmington area uCase history 3 (Terminal zone)
uHistory of old Wilmington area uCase history 3 (Terminal zone)
uHistory of old Wilmington area uCase history 3 (Terminal zone)
uHistory of old Wilmington area uCase history 3 (Terminal zone)
uHistory of old Wilmington area uCase history 3 (Terminal zone)
uHistory of old Wilmington area uCase history 3 (Terminal zone)
uHistory of old Wilmington area uCase history 3 (Terminal zone)
uHistory of old Wilmington area uCase history 3 (Terminal zone)
uHistory of old Wilmington area uCase history 3 (Terminal zone)
uHistory of old Wilmington area uCase history 3 (Terminal zone)
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BackgroundThe Wilmington oil field of southern California (Figure 1), the largest oil field in the Los Angeles Basin (Biddle, 1991), has produced more than 2.6 billion barrels of oil (California Department of Conservation, 1999). Discovered in 1932, it produces from semi- and unconsolidated Pliocene and Miocene clastic slope and basin turbidite sandstones (Henderson, 1987; Blake, 1991). The individual reservoirs are defined by graded sequences of sandstone interlayered with siltstones and shales (Slatt et al., 1993). The entire sequence is folded and faulted (Mayuga, 1970; Clarke, 1987; Wright, 1991). Even the typical rhythmically deposited sequences have lenticular, lobate shapes and are complicated by basal scour, amalgamation, onlapping, and channeling. The result is a sequence of rocks that often appears to be uniform but is not. These complexities also result in permeability variations that hinder the producibility of the sandstones, impact waterflooding, and result in a substantial amount of bypassed oil. The
Wilmington field has been divided stratigraphically into seven producing
zones, 52 subzones and, locally, into even finer subsubzones (Henderson,
1987). A serious effort was made to establish stratigraphic continuity
in detail as fine as possible. The finer subdivisions are defined as
hydrologic bodies or depositional sequences. Many techniques and tools
were applied to characterize the thinner sand bodies into unique units,
including core description combined with log-rock typing, detailed log
correlation, production/injection history matching, bypassed
pay-saturation Although we are still learning about the intricacies of Wilmington field’s reservoirs, today’s computerized visualization tools, combined with advanced measurement-while-drilling (MWD) data, have contributed significantly to the collective knowledge base about this field. We thus confidently conclude that the field’s poorly drained sandstones remain ideal targets for horizontal drilling.
History of the Long Beach UnitThe
Wilmington oil field is a faulted asymmetrical anticline. The reservoirs
of the 10 larger An
additional 460 wells were drilled in the Long Beach Unit from 1982 to
1986 using a subzone approach to improve sweep efficiency, which allowed
another 25.4 million cubic meters (m3), or 160 million
barrels (bbl), to be produced. After 1986, bypassed sandstones were
selectively perforated in even finer intervals. The first horizontal
well was completed in November 1993 as part of the optimized waterflood
project. Thirty-nine more horizontal wells have been drilled since then,
using a combination of computerized mapping and digitized injection
surveys to identify the dominant, unswept flow units. Reservoir
exploitation was enhanced by geosteering supported by logging while
drilling (LWD) and real-time Typically, the wells were placed 3 to 5 m (10 to 15 ft) below the top of the sandstone. Initial oil-production rates from the best horizontal wells exceeded 95.4 m3/day (600 bbl/day) and about 47.7 m3/day (300 bbl/day) from the average wells, at 80% water cut, stabilizing at about 15.9 m3/day after 300 days. Total unit oil production is 6042 m3/day (38,000 bbl/day). Blesener and Henderson (1996) describe several of the new engineering technologies that have been applied to the Long Beach Unit. These include coiled-tubing drilling, drill-cuttings injection, and reclaimed-water injection. In 1995, the LBU ran a 3-D seismic survey to help define the subsurface in greater detail (Otott et al., 1996). The survey did not provide the desired results, but it did serve as a valuable tool for deep work. Several exploratory prospects were identified. One or more of these may be drilled in 2003. THUMS was purchased from ARCO by Occidental Oil and Gas Corporation in May 2000. In 2002, THUMS conducted a 3-D vertical seismic profile (VSP) in the area between Islands Freeman and Chaffee. These data are being processed.
History of the Old Wilmington AreaThe history
of the Wilmington oil field has been detailed by Mayuga (1970), Ames
(1987), and Otott and Clarke (1996). More than 5000 wells have been
drilled conventionally in the 70 years Old Wilmington has been on
production. The entire field is on secondary recovery, and oil
production is down to 1113 m3/day (7000 bbl/day) with an
average water cut of 96.9%. Because of the steep, 14%-per-year decline,
it was decided to investigate new ways to produce more oil. As part of
this effort, Tidelands Oil Production Company has drilled 14 horizontal
wells since 1993 in four heavily drilled (3000-plus wells) For each project, the horizontal laterals for the waterflood wells were placed at the top of the sandstone to recover attic reserves. The laterals for the steamflood wells were placed at the bottom of the sandstone to maximize capture of oil through steam-assisted gravity drainage. Except for
the first project, 3-D modeling and visualization were used from
planning through completion. To be effective, horizontal wells require
precision placement. The studied areas required significant geologic
evaluation and characterization. The area then was modeled with software
that provided 3-D visual displays of stratigraphic and structural
relationships and enabled excellent error checking of data and grids in
3-D space. The geologic model was revised and modified in 3-D space. The
3-D model provided a visual reference for well planning and
communicating the spatial relationships contained within the reservoir.
Accurate 2-D and 3-D visualization was used for interpreting the LWD
response and monitoring well progress while drilling. Maps and section
plots brought to the rig site allowed the drilling team to relate to the
geology, thus providing a strong confidence factor. Accurate and rapid
postdrilling
Case HistoriesThree case
histories are presented herein. Case history 1 describes a
thermal-enhanced recovery project that expanded on an existing
steamflood project. The expansion area was subjected to detailed
characterization with 3-D modeling and visualization before completion
of the development project. The technologies developed in the steamflood
project were applied to the areas in
Case History 1: Case
history 1 is in the Tar zone of
A Tar zone
steamflood in The four
horizontal wells were drilled into the bottom of the18.3 m- (60 ft-)
thick D1 sandstone. Two steam injectors and two producers
were placed about 122 m (400 ft) apart horizontally as part of a
pseudosteam-assisted, gravity-drainage project. This innovative The
existing maps had insufficient detail for the planned development. The
only way to obtain success was to perform a detailed geologic The existing six subzone intervals were further divided into 18 subsubzones, and the faults were reevaluated. A team of geologists spent months on detailed log work to define the 18 horizons and six faults. The log data ranged from electric logs from the 1930s through complete log suites of the 1980s. Each subsubzone was hand-mapped for lateral extent. The faults and horizons were then modeled three-dimensionally and compared to the original interpretation. A significant amount of the well planning was performed using this detailed, 3-D working model, which made visualization of the inconsistent data very easy. The data inconsistencies came from differentially subsiding horizons caused by intraformational compaction from oil withdrawal over a 60-year period and an assortment of data entry and coordinate conversion errors. These errors were rapidly identified and corrected. Subsidence was probably the most difficult problem to solve. The intraformational compaction of the producing reservoirs varied over time and directly impacted the surface (and the distance to the producing horizons). From 3.7 to 6.7 m (12 to 22 ft) of surface elevation was lost above the proposed horizontal lateral locations (Figure 6). The subsidence varies, increasing from west to east toward the center of an elliptical subsidence bowl, where the maximum subsidence to date is 8.8 m (29 ft). To compensate for the errors, data were adjusted for ground-level change and internal compaction. These adjustments are time dependent. For example, a well drilled in 1940 could have been drilled to 762 m (2500 ft) below sea level to reach the T marker. The same well drilled today to the same X, Y position might require drilling to 768 m (2520 ft) below sea level to reach the T marker (Phillips, 1996). The ground level is lower now because of subsidence, and the depths to the other markers also are different (intraformational compaction). The stratigraphic section has been compressed. Figure 7 illustrates the corrections that are applied. After data were modified, the mapping software facilitated the rapidly generated new geologic models by using the predefined geologic criteria. This data was quickly integrated into a more comprehensive structural model (Figure 8), which was edited and modified where necessary. The 3-D model was recalculated many times during this iterative process. Not only was the resulting model excellent at revealing subtle differences in the geology, it also was an invaluable tool for finding data errors. When the acceptable 3-D deterministic model was established, cross sections along the well courses were constructed and used for geosteering (Figure 9). The cross sections derived from the model proved extremely accurate and were used extensively. The combination of detailed sequence characterization and 3-D modeling allowed us to accurately map a previously unrecognized channel (Figure 10) and onlap (Figure 11). The computerized 3-D displays greatly enhanced communication among the geologist, the petroleum engineer, and the driller. The geologist could rotate, slice, and change the look of the model to improve the visualization. The geologist also displayed the offset log information on a cross section along a well course that had been scaled up to match the real-time LWD logs. This was invaluable during drilling because the geologist could accurately follow the drill bit by plotting the MWD data directly onto the computer-generated cross section. In Although this project was marginally economic, we consider it a technical success. The project started with a steam/oil ratio of 7; by the time the steam project was shut down, the steam/oil ratio was 14. More drilling would have helped greatly, but expansion was not possible at the time. In October 1999, flank wells were converted to cold-water injection. A 3-D deterministic reservoir simulation model that calculated mass balance and heat balance was used for injection conversion. Subsidence was halted, and by September, 2002, the area was very profitable, producing 179 m3/day (1130 bbl/day) net with a gross of 4515 m3/day (28,400 bbl/ day).
The next
step was to see if these techniques could be applied to
As with the
A deterministic geologic model was created, from which the maps and cross sections were extracted and used to geosteer the horizontal wells. The modeling was more straightforward than the earlier project, because the area where the horizontal wells were planned is unfaulted (Figure 14). The
experience gained in Data from one area of the model indicated an anomalous structural low. The survey and log picks appeared to be correct for a well located in the area of this low. The data point was honored, and horizontal well J-201 was drilled into the area. It was apparent from the LWD curve separation and bed boundary intersections that the T shale was shallower than the model indicated. The offending well data were removed, and the model was rebuilt based on the horizon picks from well J-201. Because this remodeling can now be done in almost real time, the geologist revises the model as drilling proceeds. An improved model is built if needed as each new well is completed. Well J-201 did not go as planned; it was difficult to determine the completion interval until the other horizontal wells and their perforations were displayed in 3-D (Figure 14). The 3-D model in Figure 14 is bench cut and shows the five horizontal wells and their perforations. The goal was to keep the wells parallel to the top of the T shale to maximize recoverable reserves from the superjacent S4 sandstone. The maps, cross sections, and geologic model all were used to place the horizontal wells accurately. Figure 15 shows the cross section for well J-203. Overall,
the Tar V drilling project (case history 2) was a major technical and
economic success. Based on what was learned in The drilling team appreciated having visuals from 3-D modeling at the rig site because they stimulated better feedback and established a clearer understanding of the geology encountered. The team could see what a particular directional tool set accomplished and thus refine drilling techniques for added efficiency. Previously, drillers had relied only on numbers, which were much less intuitive and informative. The Tar V
horizontal well budget was based on the The five horizontal wells were steam cycled and placed on production (Figures 16, 17, and 18). Two of them, FJ- 204 and FJ-202, were placed on permanent steam injection. A-186 3, A-195 0, and A-320 0, each well more than 30 years old, remained on production within the steamproject boundaries. As of March 1996, they had averaged 2.5 m3/day (16 bbl/day) net with 31.8 m3/day (200 bbl/day) gross, at an average water cut of 92%. When the horizontal project was initiated, this area had only about five years of remaining economic life under waterflood, and recoverable reserves were estimated at 11,924 m3 (75,000 bbl). The average pool-water cut prior to steaming was 95%. The water cut in the project area was 81% in 1998 and 92% in July 2000; another 270,283 m3 (1,700,000 bbl) of reserves has been added to the Tar V pool. Steam communication to the existing waterflood wells, from cyclic steam injection into wells FJ-202 and FJ-204, resulted in a six- to tenfold net production increase in the old waterflood wells (Figure 17). Peak annual production rates under steam drive were forecast at 93.8 m3/day (590 bbl/day) for the horizontal project. During the first four months of 1998, the average oil production was 111 m3/day (698 bbl/ day). In July 2000, the average oil production was 38.5 m3/day (242 bbl/ day). The production rates should be several times greater, but the performance of each well has been hindered by fluid levels exceeding 457.2 m (1500 ft). The high fluid level suppresses oil production and cools the produced fluids, resulting in lower recoveries. The success of the program is reflected in Figures 16, 17, and 18, which show how the project area has changed over time. Note in Figure 16 that prior to steaming, the average net was about 2.5 m3 day (16 bbl/day). By January 1998 (Figure 17). the average net was more than 23.9 m3/day (150 bbl/day). In August 2000, the average net was still more than 15.9 m3/day (100 bbl/day). Three-dimensional techniques contributed significantly to the success of the Tar zone horizontal project. Assuming a 50% recovery factor, every foot above the target is equivalent to 2524 STCM (15,876 STB) in lost reserves (Phillips, 1996). At U.S. $14/bbl oil, an error of as much as 1.5 m (5 ft) vertically would equate to U.S. $ 1.1 million in lost revenue.
Case History 3: Upper Terminal Zone: Hx0 Thin-Sandstone Sequence The Hx0
sandstones of A deterministic geologic model was created to define the Hx0 layer and the horizons above and below it (Hx1 above, Hx2 and Hx below). The sandstone percentage was calculated for each data point. A 3-D property model was created by gridding the sandstone percentage in 3-D space using the top and bottom of the Hx0 as confining surfaces (Figure 19). The original oil saturation (So) was property modeled similarly to identifying target areas for exploitation (Figure 20). A display
of the So model and wells drilled in the 1980s clearly showed that Based on the geologic model, the block engineer proposed that a horizontal well be drilled within and adjacent to the modeled area along the structural high. An existing wellbore was sidetracked with a horizontal lateral to capture hydrocarbon reserves not economically recoverable with conventional methods. Idle well J-017 was selected for drilling the high dogleg horizontal well, and a production rig was configured for drilling to keep costs to a minimum. By investigating the area west of the original Hx0 project area, it was determined that the target sandstone thins and shales out to the west, thus reducing oil saturation. Electric logs from wells penetrating the area as far as 305 m (1000 ft) to the west were correlated, and a second 3-D geologic model was created. A facies boundary was delineated to constrain the planned well course within the higher water-saturation (So) target. The Hx0 layer was subdivided, and two sandstone lobes were identified within the Hx0 layer. The Hx0J and Hx0B horizons were defined and added to the 3-D model. Maps and cross sections were extracted from the 3-D model and used for well planning (Figures 21 and 22). A cross section along the well course was created for the geologist. The directional vendor required three linear cross sections for drilling because the well plan showed a U-turn (Figure 22). Stratigraphic sections consisting of adjacent wells also were created to help in geosteering. Both pasteup and digital varieties were used. Structure maps were created on the Hx1, Hx0, and newly defined Hx0J (Figure 23) and Hx0B sandstones. These plots, as well as the 3-D model, were used for geosteering. Ultimately, they also were used for directional control because of rig-site problems. A recently introduced, probe-based multiple-propagation- resistivity (MPR) device was used to provide LWD geosteering as well as directional information. This resistivity sensor was part of a slim-hole, positive-pulsetype MWD/LWD system that was used instead of carrier wave tools because of its smaller size (the tool diameter is 4 3/4 in.). These newer tools have well-integrated surface equipment, are battery-powered, and provide more reliable telemetry signals. The MPR tool is a four-transmitter, two-receiver array that provides a total of eight compensated resistivities at 2 MHz and the deeper-reading 400 kHz in boreholes as small as 5 7/8 in. For additional geosteering control, an inclinometer and gamma-ray scintillation detector are placed below the MPR sub (MacCallum et al., 1998). The well was successfully placed within two sandstone lobes of the thin sequence by geosteering using the LWD data. The interval is thin and shaley (total thickness of 5.2 m [17 ft]), and the LWD showed the anisotropic effect throughout the log (Figure 24). The resistivity response in anisotropic conditions is similar to conductive invasion in that the short-spaced measurement reads less than the long-spaced for both the phase difference and attenuation resistivity measurements. However, the shallow-reading, phase-difference resistivity curves measure a higher resistivity than the deep-reading attenuation curves for both frequencies and spacings. This curve order is not indicative of conductive invasion but of anisotropy (Meyer et al., 1996). The presence of anisotropy plus formation heterogeneity complicated the interpretation of the LWD data so that the geosteering team had to rely significantly on the geologic model. A simple layer model was used for previous horizontal-well projects. The sandstone package was thick enough that the LWD gave a unique, easily interpretable response. The Hx0 sandstone is divided by a continuous shale. The upper sandstone, referred to as the Hx0, is 1.8 m (6 ft) thick; the lower sandstone, Hx0J, is 2.4 m (8 ft) thick. Again, the horizontal well was successfully placed into each of these sandstones. Postwell
The 3-D model was refined based on conclusions reached by collaboration between the LWD analyst and the geologist. The shales above the Hx0 and Hx0J sandstones were modeled, which helped significantly in data interpretation. A new anisotropy inversion algorithm and the inclusion of shales in the geologic model allowed for a clearer understanding of the 2-MHz resistivity responses to the formation and their boundaries. The
ConclusionsA geologist working with carefully characterized rock data and 3-D modeling and visualization techniques adds greatly to a horizontal drilling team. The highly accurate 3-D visualizations of the reservoir greatly increase the confidence factor of the team, thus enabling Wilmington field reserves to be maximized. To be
effective, horizontal wells require precision placement.
Three-dimensional models help isolate data inconsistencies, and 3-D
viewers are good for adding data to correct the geologic model. Once the
final geologic model is created, the drilling team can use the resulting
3-D visuals with confidence to improve drilling techniques and
directional control. Postwell
AcknowledgmentsWe would like to acknowledge the help and support of Mike Domanski, president of Tidelands Oil Production Company; Jim Quay, Steve Siegwein, Scott Walker, Scott Hara, Rudy “Bud” Payan, and Chris Parmelee, technical engineering staff at Tidelands Oil Production Company; Dennis Sullivan, director of the Department of Oil Properties, city of Long Beach; Donald McCallum of Baker-Hughes INTEQ; and Art and Tamara Paradis and Heather Kelley of Dynamic Graphics Inc. Computer modeling was done with DGI EarthVision on an SGI Iris Indigo workstation.
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