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The Section 27 Zone I steam drive project in this California field was started in early 1963. Originally designed and operated as a five-spot steam drive, the project has gradually been converted to a five-spot waterflood. Injected water has been able to displace significant quantities of oil, aided by the improved oil mobility resulting from heat retained in the reservoir. Introduction The Section 27 Zone I drive project is located in the East Coalinga field in Fresno County, Calif. The project was started in Jan. 1963 with a pilot consisting of six injectors enclosing two interior producers to form a double five-spot pattern (see producers to form a double five-spot pattern (see Fig. 1). Production response from the pilot was very encouraging and by the end of 1964 the project had been expanded to 60 injectors and 93 producers in an irregular five-spot pattern encompassing an area of 530 acres. The project suffered its first major setback in early 1965 when casing failures induced by thermal stresses were detected in 23 steam injectors. These were old primary production wells that had been converted to steam injectors. Steam injection was reduced while repairs were carried out in the 23 injectors by cementing inner strings. Owing to extremely poor injectivity and production performance, steam injection into all but one northern performance, steam injection into all but one northern area injector was suspended in June 1966. By this time steam and hot water breakthrough had occurred in many central area producers as a result of the presence of high-permeability alluvial channel sands presence of high-permeability alluvial channel sands that were found to be accepting most of the steam in injectors where they were present. Attempts to plug off the channel sands with cement and silica gel were unsuccessful. In 1966 eight central area wells were converted from steam to water injection to evaluate cold-water scavenging as a follow-up to steam injection. In Aug. 1966, water injection was extended around all but the downdip eastern edge of the project. enclosing a total area of 700 acres within the project. On the basis of encouraging performance by producers surrounding the eight water injectors and producers surrounding the eight water injectors and supported by Shell Development Co. model studies, all but the 13 injectors in the downdip high-viscosity area were converted to water injection in Oct. 1967. Better injection profiles were obtained with water, and efforts in plugging the thief channel sands in water injectors were successful in more than half the attempts made. Economic considerations led to the conversion of the 13 remaining steam injectors to water injection at the end of 1969. Geology The Temblor (middle Miocene) Zone I reservoir consists of an easterly dipping (14 degrees) homocline with well depths varying from 900 ft on the updip western edge of the project to 2,200 ft in the downdip eastern edge, averaging about 1,500 ft. The reservoir is confined on the north, east and south to edge water and on the west by subcropping of the sands. approximately 1 mile updip of the project area. The gross thickness of the reservoir is about 300 ft, of which an average of only 50 ft is considered net oil sand. Geologically, the gross interval is subdivided into 10 distinct reservoir layers (see Fig. 2). JPT P. 1227
Another A combination of laboratory experiments and numerical important factor is the speed of the steam front, as it determines simulations is used to determine the effect of clay on the whether distilled, condensed steam vapor combines electrical response of a steam-flooded reservoir. We find with saline steam liquid.
ABSTRACT Successes with steam injection as a means of increasing recovery from certain types of oil reservoirs have brought an entirely new line of equipment to the oil fields. This paper discusses operating principles and characteristics of equipment needed to carry out an oilfield steaming program, except for the steam generator. Water-treating and handling equipment, flow lines, well heads, down-hole tools, and accessory items are covered. INTRODUCTION Whether oil production is stimulated through the steam-soak (huff-and-puff) method or by well-to-well steam drive, there is more to the operation than just putting steam into the ground. Careful engineering of all phases of the operation is needed to avoid physical damage to surface equipment and injection wells, and chemical and mechanical damage to the reservoir Proper selection and application of equipment is one of the first steps in this careful engineering design, which covers the full range of operations from water treatment on the surface to injection of steam into the reservoir many feet underground. WATER TREATMENT Two major differences between industrials team boilers and oil-field steam generators dictate the differences in feed-water treatment, Fig 1. Conventional industrial steam systems usually operate oil a closed cycle in which steam used for turbine operation, heating of buildings, etc is returned to the holler for conversion to steam again Oil-field steamers operate on a "once-through" basis, where all steam generated is injected into the reservoir, and never recycled. Only a small amount of makeup water is needed to replace that which is accidentally lost from a conventional boiler system, or that which is used to "blow down" the boiler but feed water for an oil-field steam generator must be continuously replaced on a 100-percent basis. Cost of water treatment for a conventional boiler system, on a unit basis, is not too important because of the small number of 'units involved, but this same cost might be prohibitive in the oil fields. Conventional steam boilers take the steam to the dry saturated condition, or into the super-heat region, whereas oil-field steam is "wet" - generally about 80-percent quality (80-percent in the vapor phase, 20-percent in the liquid phase). The first of these differences is a disadvantage; the second is a distinct advantage The water-handling portion of a steam-injection system involves filtration, chemical treatment, storage, deaeration, conversion to steam, separation (optional), and metering (Fig 2) A description of equipment needed to treat feed water for oil-field steamers is impossible without some discussion of water-conditioning fundamentals, but no attempt will be made to cover the subject in detail as this has been clone adequately in recent publications Filters Feed water should be free of excessive suspended matter (non-ionic solids) to prevent contamination of subsequent treating equipment and plugging of parts of the system, including the sand face of the injection well Fig. 1 - Oil-field Steam-generating ProceduresRequire Unique Water-treatment (Available in full paper) Fig. 2 - Basic Components of a Steam-injection System, to the Well Head(Available in full paper)
Abstract The Water-Alternating-Steam-Process (WASP) has been utilized on Section 13D, West Coalinga Field since 1988. Originally implemented to control premature, high-temperature steam breakthrough, the process has improved sales oil recovery in both breakthrough and non-breakthrough patterns. A desktop, semi-conceptual simulation study was initiated in June 1993 to provide a theoretical basis for optimizing and monitoring the WASP project. The simulation study results showed that the existing WASP injection strategy could be further optimized. It also showed that conversion to continuous hot waterflood was the optimum injection strategy for the steamflood sands. The Section 13D WASP project was gradually converted to hot waterflood during 1994. Conversion to hot waterflood has significantly improved project cash flow and increased the value of the Section 13D thermal project. Introduction As a steamflood matures, the oil production rate decreases, and if the steam injection rate remains constant, the steam-oil ratio increases. It then becomes necessary to employ alternative strategies, such as rate or quality reduction and post-steam waterflood, to reduce the injection costs and maintain profits. In many steamfloods, reservoir heterogeneities lead to poor vertical and areal conformance. If these heterogeneities include regions of high permeability, injected steam can propagate rapidly towards the producing wells. This can lead to premature steam breakthrough. Steam entering a producing wellbore wastes injected heat, thereby increasing operating costs. Steam breakthrough can cause high-temperature operational problems in the producers, which also increase operating costs. High operating costs can shorten the life of a project and reduce the net present value of the reserves. The Water-Alternating-Steam Process (WASP) was successfully employed in 1988 on Section 13D, West Coalinga Field, to combat steam breakthrough and its attendant problems. WASP effectively reduced temperatures in breakthrough wells so that pumps could be lowered and shut-in wells returned to production. This led to increased sales oil and improved project economics. Since WASP was first implemented, there was a need to optimize the process and determine its effectiveness in nonbreakthrough patterns. A semi-conceptual simulation study was initiated to optimize WASP and determine the optimum injection strategy for the Section 13D property. P. 499
Three of Chevron's successful Kern River Field Steam Drive Projects (Section 3, Monte Cristo II, and American Naphtha) have been converted to either hot waterfloods or low quality (10%) steam injection projects. The projects' net oil production has projects. The projects' net oil production has increased significantly because of the reduced oil consumption at the steam generators. In general, the conversion to low quality steam or hot water injection has improved the oil production response of each project.
Production and reservoir data suggest that improved Production and reservoir data suggest that improved sweep efficiency in the lower part of the steam driven sands occurred as a result of the switch from high steam quality injection to reduced steam quality. This paper discusses the performance of these three projects. Production and reservoir parameters are identified which can be used to parameters are identified which can be used to determine the timing for conversion of a mature steamflood to a lower quality steam injection project. project
This paper discusses the performance of Chevron's Section 3 (Ten-Pattern), American Naphtha, and Monte Cristo II steam drive projects located within the Kern River Field. Sections (patterns) of the American Naphtha and Monte Cristo II steam drive projects were converted from high quality steam projects were converted from high quality steam (greater than 40%) to low quality steam (10% quality steam at the wellhead) injection in September 1981 and February 1982, respectively. The Phase I area (Ten-Pattern) of the Section 3 steam drive project was converted from high quality steam to hot water injection in October 1975. The objectives of the study presented in this paper were to: (1) define reservoir characteristics; (2) review the field performance, reservoir behavior, and overall performance, reservoir behavior, and overall operating costs; and (3) develop guidelines for selecting candidates for the conversion of mature steam drive projects (generally where steam qualities greater than 40% were being injected) to low quality steam and/or hot water injection.
In general, the projects did not experience any significant loss in production as a result of the conversion to low quality steam and/or hot water injection. This appears to be the result of improved vertical sweep efficiency in the lower drive sands and reduced gravity override effects as a consequence of thermal distribution changes that occurred since the conversion. Converting from high to low quality steam and/or hot water injection resulted in reduced fuel oil consumption which enhanced the net oil production and overall operating economics of the three projects.
The performances of these three projects were analyzed to develop some general guidelines which could be used to determine the optimum time to convert mature steam drives to low quality steam injection or hot waterflood projects. Parameters for these guidelines include reservoir properties, heat input, temperature profiles, steamflood maturity, and steam-oil ratio.
RESERVOIR AND PROJECT DESCRIPTIONS
The three Chevron projects discussed in this paper were chosen for analysis because they are currently under low quality (10%) steam injection or hot water injection after high quality steam injection. The projects are located in the Kern River Field (see projects are located in the Kern River Field (see Figure 1). Section 3 Ten-Pattern (Phase I) project is Chevron's oldest steam drive project and has been discussed in previous publications. The Monte Cristo II project is located within Chevron's Monte Cristo II property and consists of nine 2.5 acre 5 spot inverted patterns. This project is surrounded by other steam drive patterns on the Monte Cristo II property. The American Naphtha project consists of property. The American Naphtha project consists of sixteen 2.5 acre 5-spot patterns and is located on the American Naphtha lease.
The steam drive sands are part of the Kern River Series. These sands are Mio-Pliocene in age and are composed of unsorted, coarse grained, angular and silty sands. The steam drive sands have an average porosity of about 34 percent, a pre-steam drive oil porosity of about 34 percent, a pre-steam drive oil saturation of 50 percent and permeability ranging from 1,000-2,000 millidarcies.