Water Injection in the Lower Jones Sands, Huntington Beach Offshore Field
- Sherwin D. Yoelin (Signal Oil And Gas Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- February 1968
- Document Type
- Journal Paper
- 127 - 134
- 1968. Society of Petroleum Engineers
- 1.2.3 Rock properties, 4.3.4 Scale, 5.2.1 Phase Behavior and PVT Measurements, 5.7.2 Recovery Factors, 6.5.2 Water use, produced water discharge and disposal, 4.1.5 Processing Equipment, 7.3.3 Project Management, 5.4.2 Gas Injection Methods, 1.5.1 Surveying and survey programs, 5.4.1 Waterflooding, 2.4.5 Gravel pack design & evaluation, 5.2 Reservoir Fluid Dynamics, 2 Well Completion, 5.1.2 Faults and Fracture Characterisation, 1.6 Drilling Operations, 2.7.1 Completion Fluids, 2.2.2 Perforating, 4.6 Natural Gas, 4.1.2 Separation and Treating, 1.14 Casing and Cementing, 2.4.3 Sand/Solids Control
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The Lower Jones is an unconsolidated, multiple-sand reservoir several hundred feet thick, containing a 14 to 19 deg. API crude oil. However, the sand thickness and unfavorable mobility ratios caused by the viscous crude have not deterred a successful waterflood project. Oil production has approximately tripled since the flood started in Nov., 1963. The reservoir is broken up by an extremely complex faulting system. The effect of these faults, with displacements ranging from 10 to 75 ft, is so significant that the over-all project must be handled as 17 individual fault block floods. Both crestal and downdip injectors were utilized early in the life of the waterflood, but the unfavorable effects of crestal injection, as noted in injector profile surveys and crestal producer performance, caused the oil production to decline and the water-ail ratio to increase prematurely. A shift to flank injection in most of the fault blocks stopped the decline and the excessive rate of water- cut increase.
Sand control, which is essential in the Lower Jones, is achieved by installing gravel flow-packed liners in both the injectors and producers. Drift angles of 75 deg. or more are required in individual wells to reach some of the more remote locations in the reservoir. The flow pack is accomplished by dropping the drift angle through the productive interval to 45 deg. or less. The production and injection history of the project through July, 1967, is presented to show the results being achieved.
The Huntington Beach oil field is situated 41 miles southeast of Los Angeles on a high point on the coastal fold close to the south edge of the Los Angeles basin in Orange County, Calif. Location of the Huntington Beach field with respect to other fields in the Los Angeles basin is shown in Fig. 1.
The offshore Jones pool lies in a westerly plunging anticline on the extreme west side of the field. The heavily faulted reservoir is composed of a 700-ft section of continuous Upper Miocene unconsolidated sands separated by shales containing interbedded sand stringers. The productive thickness ranges from 350 to 400 ft.
A typical electric log of the productive interval is shown in Fig. 2. The most significant shale is found near the middle of the section at the electric log marker AG. The sands above the AG marker are known as Upper Jones (Div. A of the Upper Miocene) while the sands below the AG2 marker are called Lower Jones (Div. B of the Upper Miocene). Productive area of the Lower Jones under Signal Oil and Gas Co.'s leases in the offshore field covers more than 770 acres.
The primary recovery efficiency of the Jones zone was quite low due to the high viscosity of the crude oil and the lack of sufficient natural pressure maintenance. Ultimate recovery under normal depletion, supplemented by such programs as gas-oil ratio control, a limited gas injection project and redrilling of idle producers, was estimated to be 20 percent of the original oil in place.
In 1959 a pilot waterflood project was started in the sands between the AK and AL markers in the Lower Jones to determine if water injection would be a satisfactory method to improve recovery performance. Results of the pilot test, which ended in early 1961, were so encouraging that planning began immediately to extend waterflood operations to the entire reservoir.
The first phase of the full-scale Lower Jones waterflood began in Nov., 1963, and injection was expanded to most areas of the reservoir by Sept., 1965.
This article discusses the performance of waterflooding activities and highlights some of the unusual problems encountered during the early life of this unique offshore waterflood project.
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