Print this pageBelridge Giant Oil Field, Diatomite Pool--
Learnings from an Unusual Marine Reservoir in an Old Field*
By
Malcolm E. Allan1, Mahmood Rahman1, and Barbara A. Rycerski1
Search and Discovery Article #20043 (2006)
Posted December 17, 2006
*Adapted from abstract and slides prepared for presentation at AAPG Annual Convention, Houston, Texas, April 9-12, 2006
Click to view presentation in PDF format.
1Aera Energy LLC, 10,000 Ming Avenue, Bakersfield, California 93311 ([email protected])
Abstract
The Belridge giant oil field in the San Joaquin Valley, California, has produced more then 1.5 billion BO & 1.2 trillion CFG from multiple reservoirs since being discovered in 1911. Aera Energy LLC (a company owned jointly by Shell & ExxonMobil) currently produces 65 thousand barrels (10,300 cu m) of oil and 40 million CF (1.1 million cu m) of gas daily from a sequence of deep marine diatomite layers in the Miocene Monterey Formation. The diatomite sequence is vertically continuous for over 2000 ft (600 m) and covers about 4100 acres (1,650 ha) inside Aera’s field limits. Aera has over 3500 producers and 1100 water injectors actively maintaining oil production from the diatomite. Wells are very closely spaced, less than 50 ft (15m) apart in better areas, and hydraulic fracturing is essential for production from a reservoir that would be considered an excellent seal elsewhere.
Learnings from this field that can be readily applied elsewhere:
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Why we need another log when we have a 5-year old one 50 ft (15m) away.
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Formation pressure logs can be used to fine-tune completion intervals in water injection wells.
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Orientations of induced fractures can be measured and control infill drilling locations.
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Horizontal wells are easy to plan and drill and can be more profitable than vertical wells.
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Areal and vertical limits of economic production are still expanding
Reservoir management continues to be a challenge because of the size and complexity of the reservoir, and because of the 700-800 new wells being drilled annually to maintain production.
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(Figures 1-6) Belridge Field Has a Huge Surface Footprint (Figures 1, 2, and 3).
Historical Production and Injection Rates (Figure 4)
Depositional Environment of Diatomite (Figures 5 and 6)
Diatomite is the term given to the unconventional rock composed predominantly of the biogenic siliceous deposits of diatoms. In California, this rock type is common in the Central Valley and coastal basins. It is a major oil reservoir, and it is prolific producer when hydraulically fractured. Diatoms are unicellular pelagic algae with siliceous skeletons deposited onto a mid-bathyal seafloor.
Benefits from Our Novel Applications of Existing Technology and Techniques (Figures 7-18)
The diatomite reservoir in the Belridge giant field was discovered in 1911 but only became an economic target with the advent of hydraulic fracturing in the late 1970s. The reservoir has unique petrophysical properties:
Successfully developing and producing unconventional reservoirs like diatomite requires using conventional technologies and techniques in new and unconventional ways: 1. Open-hole log data show us saturation changes and are needed for 3D modeling. 2. Open-hole formation pressures are used to monitor the water injection program and to pick completion intervals in new injector wells. 3. Tiltmeter data from hydraulic fractures are used to make well spacing and location decisions. 4. Horizontal wells are exploiting thin pay zones that are uneconomic for vertical wells.
The result. . . .
Data coverage for Diatomite reservoir (Figure 7)
All geologic, petrophysical, and completion data for the diatomite and deeper units over the entire Belridge Field and surrounding area are stored in a single unified database (Landmark’s OpenWorks®). Directional and completion data are updated nightly for all wells from corporate database.
Statistics as of January, 2006
Note:
Same database is used by all geoscientists.
Logging Suite and Log Examples, Diatomite (Figure 8)
All wireline data are captured digitally and are available in a single Landmark database. About 20-30% of ± 400 new wells are drilled yearly, and 10-20% of 300-400 replacement wells drilled yearly are logged.
Saturation Changes Can Be Found by Comparing New and Old Logs (Figure 9).
Saturation Changes Show Areas That Need to Be Avoided during Well Completion (Figure 10).
Pre-Planning of Completions Requires a High Density of Logged Wells (Figure 11).
High density and good areal coverage of modern log data are essential for the creation of 3D structure and property models. These models are used to predict porosity (RHOB) and oil saturation for an undrilled well and generate Pseudo-Logs for it. The Pseudo-Logs are used to pre-plan and schedule completion intervals. If the well is logged and we get real log data, there is a final review, but predictions of porosity and saturation are normally very accurate.
Formation Pressures Can Be Used to Monitor Performance of Water Injection (Figure 12).
Formation Pressures Can Guide Completions (Figure 13).
We are now using formation pressure data to decide the completion intervals of new or replacement multi-string water injection wells.
Multi-String Injectors:
Tiltmeters Are Used to Map Hydraulic Fractures (Figure 14).
Fracture Azimuths Control Infill Spacings and Pattern Configuration (Figure 15).
Horizontal Wells Are Easy to Plan and Drill, and Often More Profitable Than Vertical Wells (Figure 16).
Thin pay zones (on the flanks and noses) are often uneconomic for vertical wells that would only be able to produce from a single hydraulic fracture stage accessing less than 400 ft of pay. These thin, vertical pay zones (< 400 ft pay) are best produced using horizontal wells. There were 160 horizontal wells drilled to January, 2006 (135 in South Belridge, 90% in last 3 years).
3D geologic models make well planning very easy.
Alignment of the wellbore in relation to the direction of the fracture azimuth is critical:
Horizontal Wells Can Drain Thin Pay Zones (Figure 17).
Example in Figure 17 shows how borehole is ‘toe-up’ and intersects thin but high quality pay (equivalent to 1200 ft of continuous pay in a vertical well).
Defining Limits of Economic Production (Figure 18)
The flanks and nose areas of the field are the most challenging.
Example for South Belridge (Figure 18)
The thick diatomite sequence of the Belridge giant oil field makes a unique reservoir with unusual petrophysical properties. The great pay thickness and high oil content make it an excellent resource that is being unlocked by new applications of existing technology and techniques.
Even though it is a relatively old field with a wealth of existing data, we continue to acquire more data. The reservoir is very challenging, and we use the data to help us in novel ways: 1. Logs and formation pressure data are needed for monitoring saturation changes and for 3D modeling even though the field already has thousands of logs. 2. Formation pressure data help improve placement of injection water and guide completion intervals. 3. Knowing the azimuths of hydraulic fractures helps determine well placement when infilling a pattern with tighter spacing. 4. Horizontal wells are great at tapping pay that is too thin for an economic vertical well.
The result. . . .
Assistance from co-workers and knowledge gained from work done by previous geoscientists is much appreciated. Support and approval by Aera Energy’s management are also acknowledged.
Schwartz, D.E., 1988, D.E., 1988, Characterizing the lithology, petrophysical properties, and depositional setting of the Belridge Diatomite, South Belridge field, Kern County, California, in Studies of the geology of the San Joaquin basin: Pacific Section SEPM, v. 60, p. 281-301. |
