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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.
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 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 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 fault blocks in the field have been managed
independently. The city of Long Beach, Department of Oil Properties,
operates most of them (Figure 2). The Wilmington Townlot Unit (WTU), a
portion of the westernmost Fault Block I, is operated by Magness
Petroleum Company. Pacific Energy Resources operates a portion of Fault
Block II. Tidelands Oil Production Company is the field contractor for
most of the western portion (Fault Blocks I–V). THUMS Long Beach Company
is the field contractor for the eastern part of Wilmington oil field
(Fault Blocks VI–90N), which is called the Long Beach Unit (LBU). The
LBU was originally produced with more than 1000 wells drilled between
1965 and 1982 (Otott and Clarke, 1996). Despite the very long completion
intervals used and water injection for pressure support, oil remained in
pockets of tight, thin sandstones, as 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
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) fault blocks
(Phillips and Clarke, 1998; Phillips et al., 1998). The first horizontal
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
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 Fault Block V and are described as case histories 2 and 3. Figure 3 shows the location of the three case histories.
Case History 1: Fault Block II, Tar Zone Steamflood Project Case
history 1 is in the Tar zone of Fault Block II (Figure 4). The Tar zone
of the lower Pliocene Repetto Formation (Figure 5) is the shallowest of
the major oil-producing zones in the Wilmington field. It has been
interpreted to consist of large, lobate, submarine-fan deposits (Redin,
1991), which are composed of interbedded siltstones, shales, and
unconsolidated fine- to medium-grained arkosic sandstones. The sand
bodies were deposited as a set of compensating turbidite lobes, as
opposed to the sheet sandstones (or larger sheet lobes) that occur lower
in the section. This section is composed of smaller sandstone lobes that
are generally limited to less than two miles in lateral extent. The
Fault Block IIA is located in the western portion of the field between the Wilmington and the Ford faults (Figure 3) and is downplunge from the crest of the Wilmington structure. The fault block is bounded to the west by the Wilmington fault and to the east by the Cerritos fault, both of which are permeability barriers (Figure 3). The faults show normal displacement with vertical offsets that range from 15 to 30 m (50 to 100 ft), but they may have complex histories of movement. In addition, several smaller-scale faults (Ford, Ford A-1, Ford A-lB) exist in the southeastern portion of the block (Figure 4). These faults exhibit vertical offset on the order of 4.5–9.0 m (15–30 ft) and are only partially sealing. The north and south limits of production are defined by oil-water contacts within the productive sandstones. A Tar zone
steamflood in Fault Block II was initiated in 1982 and expanded in 1989,
1990, 1991, and 1993. In 1995, a plan was created to expand the
steamflood to the south (Figure 4). Instead of the inverted seven-spot
pattern used in the earlier phases, it was decided to use horizontal
wells, carefully laid out so that each horizontal 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 Fault Block II steamflood project received partial funding from the U.S. Department of Energy as part of a class III midterm project (Koerner et al., 1997; U.S. Department of Energy, 1999). 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 A
significant amount of the 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 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 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 In Fault
Block II, the bottom of the D1 sandstone was targeted.
Instantaneous drilling rates as great as 183 m/hr (600 ft/hr) were
achieved because the accurate geologic model enabled the 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).
Fault Block V Projects (Case Histories 2 and 3) The next
step was to see if these techniques could be applied to Fault Block V.
There are two horizontal-
As with the
Fault Block II project, the more than 60-year-old electric logs were
reviewed and recorrelated, dividing the Tar zone into 14 subsubzones.
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 Fault Block II and improvements to the software made modeling still easier. Areas of no data were controlled by adding interpretive “ghost” points through the 3-D viewer, then reconstructing the model. This interpretive technique cut modeling time significantly. Data from
one area of the model indicated an anomalous structural low. The survey
and 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 Overall, the Tar V drilling project (case history 2) was a major technical and economic success. Based on what was learned in Fault Block II and the accuracy of the 3-D model, the drilling team was able to plan and drill with confidence. It was easy to anticipate the highs and lows of the horizons and the locations of bed boundaries. No wells were plugged back for geologic reasons, and drilling time was reduced by spreading out survey lengths, using less time for correctional sets, and rotating the tool string while drilling a large percentage of the horizontal section. Roller reaming prior to running casing was eliminated by avoiding shales, thus allowing reaming with the bit already in the hole. In addition, no pilot holes (except for FJ-204) were necessary. As a result, time and money were saved. 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 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 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 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
The Hx0 sandstones of Fault Blocks V and VI were reviewed as part of a U.S. Department of Energy (DOE) class III short-term project (Phillips, 1998). The project proposed using new reservoir characterization tools and techniques to exploit bypassed oil. The new technologies included detailed reservoir characterization; 3-D geologic modeling; geosteering in thin, heterogeneous beds; and modeling the LWD responses (MacCallum et al., 1998). 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 Fault Block VI was effectively drained, but Fault Block V still had reserves. The difference between the original So and that indicated by the 1980s wells was quantifiable. This is easily seen in Figure 20 for wells A-160 and A-189. The calculated So is less than 40%, whereas the property model shows the original So to be 60%. The So calculated from the old wells was decremented, the two data sets were combined, and Fault Block V was again property modeled (Figure 21). The sandstone percentage model and the So model were combined, and the original oil in place was calculated to be 540,566 STCM (3.4 million STB). The current oil in place was calculated, and the reserves were reduced to 445,172 STCM (2.8 million STB) (Phillips and Clarke, 1998). Obviously, significant reserves remain. Based on
the geologic model, the block engineer proposed that a horizontal A facies
boundary was delineated to constrain the planned A cross
section along the Structure
maps were created on the Hx1, Hx0, and newly
defined Hx0J (Figure 23) and Hx0B sandstones.
These plots, as A recently
introduced, probe-based multiple-propagation- resistivity (MPR) device
was used to provide LWD geosteering as The
interval is thin and shaley (total thickness of 5.2 m [17 ft]), and the
LWD showed the anisotropic effect throughout the A simple
layer model was used for previous horizontal- 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 fault
geometry of a previously unidentified fault also was determined during
this process using the 3-D model and further mathematical modeling of
the LWD. There was a good correlation between the tops calculated from
the 3-D geologic model and the tops selected from the LWD
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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