No abstract

TX 75083-3836, U.S.A., fax 01-972-952-9435.

This paper was prepared for the 44th Annual California Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in San Francisco, Calif., April 4–5, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Landslides have damaged 65 oil wells on Getty Oil Company's leases in the Ventura Avenue Field. During a landslide, some wells may remain connected to the surface while other wells may be buried. Well damage ranges from slight bending to complete severing of all casing strings, and depth of damage varies from 15' to 120'. Two major problems have been encountered when problems have been encountered when repair work is planned for a landslide damaged well. The first problem is to locate the undamaged well casing below the landslide. The second problem is to recover the well and replace the damaged casing. Some methods used by Getty Oil Company to locate the undamaged portion of a well are conventional surveys, dip-needle surveys, magnetometer surveys, kinkmeter surveys, and test holes. In wells that remain connected to the surface following a landslide, an oriented kinkmeter survey may provide all of the information necessary for planning a well recovery program. For planning a well recovery program. For wells which are buried or have severed casing, conventional surveys, magnetic surveys, and test holes may provide enough information for planning recovery programs. Information on the movement, depth, and dimensions of a particular landslide may also be particular landslide may also be helpful or necessary. Three methods have been used to recover landslide damaged wells in the Ventura Avenue Field. The simplest method is an open excavation made with standard earthmoving equipment. This method is limited to shallow depths and locations where the landslide would not be reactivated. To reach greater depths, special methods such as hand-dug or machine-dug shafts must be used. All three methods have been used successfully by Getty Oil Company. Introduction Landslides have affected oil production in the Ventura Avenue Field since production in the Ventura Avenue Field since 1926. On Getty Oil Company's leases, 143 wells are located on the 11 landslides shown in Figure 1. These slides vary in size from 1.5 to 150 acres, and cover 43 percent of the productive surface area. productive surface area.

TX 75083-3836, U.S.A., fax 01-972-952-9435.

The Coalinga field is one of the oldest oilfields in California and has been under production for over 100 years. The Temblor sands comprise the major reservoir in Coalinga at a depth of 500–2000 ft, with porosity of 33%, oil gravity of 12–14 API, and air permeability of 0.7–3 darcies. Each Temblor sand is at a different stage of drainage and thermal maturity. Steam production represents Coalinga Field's single largest operating expenditure and managing this expense is critical to Coalinga's success. Starting in 2002, ChevronTexaco has followed an aggressive plan in Coalinga to manage and optimize the field steam injection by using monitoring tools and also maintenance and growth heat calculation tools. Heat management is used to optimize thermal recovery economic performance in Coalinga. This paper documents how these tools are being used in Coalinga, and, more specifically, how steam Identification logs and temperature viewing tools are providing insight into how effectively the reservoir is being heated. Introduction The Coalinga oilfield is located on the West side of the San Joaquin Valley approximately 100 miles northwest of Bakersfield, California (Figure 1). The field was discovered in 1887 and is about 5 Miles wide and over 13 Miles long. Steamflood operation started in 1964 and is ongoing today. Production in the field is primarily heavy crude from the middle Miocene Temblor Formation (Figure 2). The geologic structure of the reservoir is a 14° eastward dipping homocline (Figures 3 and 4). An angular unconformity truncates the homocline forming a stratigraphic hydrocarbon trap. In the Coalinga area, lithology, sand body geometry, and trace fossils indicate that Temblor deposition is a marginal marine environment. The environment has been characterized by channelized sands and numerous flooding cycles. This has created a sequence of sands 10 to 35 ft thick, separated by shale and mudstone units of similar thickness. Low porosity zones composed of calcite-cemented fossil shell detritus further compartmentalize the reservoir sands. The thin sands and the resulting net to gross ratio of 0.5 to 0.7 contribute to high heat losses during steamflooding. Permeability is low in some areas of the field, creating injectivity problems. In other areas there are regions of high permeability which contribute to premature steam breakthrough1. Approximately 4500 wells have been drilled since 1887 and the last major steamflood expansion was implemented in 1998. Currently there are 696 active producers and 139 active injectors in West Coalinga. Development work is focused on expansion projects adjacent to the existing operations. What is heat Management? Heat Management is the process of identifying and applying the minimum heat to yield the maximum value production of heavy oil. When steam is injected at improper amounts, two outcomes are possible — either production does not increase as expected (too little steam) and money spent to make steam is lost, or money is wasted by excessive well work, produced steam handling and over-pressuring (too much steam). Identifying correct steam injection rates is critical in Coalinga in two ways - cost of steam is 60–70% of operating cost (fuel gas cost drives steam cost) and up to 80–90% of produced oil comes from thermal operations. The Coalinga project surveillance and heat management process consists of four key steps; data collection, evaluation, heat adjustment, and follow-up monitoring.