Polymer injection and filtration field tests being carried out inthe East Coalinga field have been used to determine the degree ofin-situ mobility control and to furnish measurements and determine the nature of wellbore impairment. These tests also have been usedto develop criteria for describing solution quality using polyacrylamideand two grades of biopolymer. Introduction Water and polymer field-injection tests are beingconducted to furnish data for a planned pilot projectin the Temblor Zone II reservoir in the East Coalingafield, Calif. The pilot project will evaluate therelative merits of polymer flooding and waterflooding.A waterflood would have an unfavorable mobility ratioof 14.0, but this could be reduced to 1.5 with polymerflooding. Fig. 1 is an index map of the Coalinga fieldshowing the pilot project area.To choose the most suitable polymer for this project, it was necessary to determine the injection characteristicsof both polyacrylamide polymer and biopolymers. Theinjection field tests were supported by field filtrationtests and laboratory studies to define polymer viscosityand filtration properties. The field tests consistedof injecting both polymer solutions and pure water atdifferent times for periods of weeks to generate comparison data for polymer and water for determining thedegree of in-situ mobility control and possible wellboreimpairment. Polyacrylamide Injectivity Test Polyacrylamide polymer (Pusher 700) was originallyselected for field testing at the Coalinga field because, at the time of the test, more was known about thispolymer. To achieve maximum mobility control usingpolyacrylamide, and because it was readily available, afresh-water (300-ppm NACI) source was developed forthe project. This water caused severe wellbore damage (20-fold decrease in permeability) from clay swellingand dispersion during initial water-injection testing;therefore, the test well was chemically treated with theDarley treatment to prevent this damage.The properties of the unconsolidated sand and thefluids involved with the tests are as follows: Property Hx Sand Jv Sand Dept, ft 1,660 1,750Thickness ft 8 17Permeability, md 470 230water at Sor, md 165 80Porosity 0.28 0.28Oil gravity, deg.API 20 20 20Reservoirtemperature, deg.F 100 100Oil viscosityat reservoirtemperature, cp 25.0 25.0Water viscosityat reservoirtemperature, cp 0.64 0.64 The injection system for the polyacrylamide testwas carefully designed to prevent mechanical shear oroxygen degradation of the polymer at the surface. Fig.2 is a plot of water and polymer injectivity vs cumulative injection. JPT P. 586^
Tinker, Gordon E.; SPE; Shell OilCo. Summary Water flooding started in the carbonate oil reservoirs of the northern Michigan Salina Niagaran reef trend in 1978 with Shell's Chester 18waterflood. Ten projects had been installed by the end of 1982, so operational results are available to expand and to reinforce the reservoir-simulation-based design and operating program. The small areal size of these pinnacle reef fields. variations in rock quality, and uncertain reservoir continuity have made successful water flood design difficult to achieve. Some existing wells are being, redrilled at the stall of a project and others may have to be redrilled later in the life of a water flood to allow the various porosity zones to be fully exploited within the flood pattern and to maintain adequate well spacing for oil bank formation. The operating strategies for these projects are based on a reservoir simulation study that stressed increased oil recovery and project economics. The operating procedures planned for these projects have been proved successful as evaluated by 4.5 year, of actual water flood performance in the Chester 18 water flood and from preliminary results from other projects. One of the most successful of these operational techniques has been the use of high-volume submersible pumps to maintain oil production response with increasing volumes of water, to give flexibility to injection pattern design, and to increase ultimate recovery. The mobility ratio in these reservoirs is very favorable, so water production results from channeling and, in some cases, bottom water coning rather than fingering. Well-completion strategy, a part of fluid-production and water-injection control, depends on knowing the location of secondary gas caps and the water zone. Water injection into even thin gas caps should be avoided to prevent gas trapping at the top of the reservoir and excessive early water production. Coning of gas and water, potential problems in many reservoirs, can result in reduced oil-recovery. Project monitoring procedures were carefully planned to facilitate project evaluation and changes in operating policy. It is believed that the design and operating policies as developed in this study have continued application for the many water floods planned in northern Michigan and to some extent for projects in other areas, but they may not be optimal for other types of reservoirs. Introduction Waterflooding for Shell started in Michigan during 1978 with the Chester 18project. Ten projects had been installed by the end of 1982, so operational results are available to expand and reinforce the early design and operating program based on reservoir simulation. The various projects located in northern Michigan (Fig. 1) range in size from two wells on 50acres to 17 wells covering 560 acres. This wide size range has led to some variation in results and problems, but it has been possible to develop a system of design and operating factors that pertain to the program as a whole. Shell's initial success in water flooding is expected to develop into a program that could eventually include as many as 50 water flood projects in northern Michigan. JPT P. 1884^
The fmt annual report under this contract was issued as SAN/ 1 004-7611. NOTICE Thb laport was prepared as an account of work s p o n d by the United Stator Gommment. Neither the United Statss nor the United States Department of Energy, nor my of their employes, nor any of their contraotors, subcontractors, or W employees, makes any warranty, express or implied. or assumes any legal liability or responsibility for the accuracy, completenew or usefulness of my information, apparatus. product or procars disclosed, or repmaents that its ust. would not infringe privately owned rights, This report has been reproduced diectiy from the bed avaitable copy.
The Brassey field, located in northeast British Columbia, Canada, is a dune sand reservoir, containing a volatile, under saturated oil. The "Artex" sand is approximately 12 feet thick and is interpreted to be part of a large aeolian complex. Primary recovery is uneconomic, so a miscible flood will be operated from inception. Development of this oil-wet reservoir required the simultaneous integration of petroleum engineering and geoscience disciplines. A British Columbia Provincial Government 24 month royalty holiday program encouraged the pursuit of an aggressive development plan. This resulted in final development drilling being conducted during the miscible flood facility installation. Development was started by implementing an extensive seismic acquisition and pulse testing/pressure transient program to determine reservoir boundaries and continuity. The ultimate well density, pattern design, and well location were altered prior to startup, based on this program. Fundamental reservoir engineering methods were applied in determining oil-in-place, performance predictions, and the necessary EOR process. Introduction The Brassey field is a Triassic stratigraphic trap in northeast British Columbia, Canada (Figure 1). In 1980, an areally-limited Artex sand reservoir was discovered, but a followup well proved to be dry, and interest in the area waned. In August 1987, another Artex well was drilled by Canadian Hunter Exploration Ltd., operator of a joint venture with BP Exploration. The well penetrated an overpressured Artex sand and blew penetrated an overpressured Artex sand and blew out for 24 days. A subsequent 3.5 mile stepout well was completed producing 2400 BOPD. Subsequent drilling has identified five separate Artex oil pools in the Brassey field (Figure 2). The field is approximately 60 miles from the nearest oil pipeline, and 20 miles from the nearest gas tie-in point. Commercial production will start in August 1989, simultaneous with the initiation of a miscible flood. The reservoir is at a depth of 9850 feet. The Artex is a thin aeolian sand and exhibits excellent reservoir properties. Brassey oil is a volatile undersaturated fluid. The fluid and formation properties have been evaluated extensively to enhance the understanding of this complex system. In 1986, the British Columbia Provincial Government initiated a royalty exemption incentive program to promote exploration and development drilling. In order to qualify for 24 months of royalty-free status, a well had to be capable of production by June 30, 1989. The program limits operators to December 31, 1991 to program limits operators to December 31, 1991 to produce the 24 royalty-free months. Crown produce the 24 royalty-free months. Crown royalty in British Columbia is normally about 30 percent of wellhead revenue. Brassey field percent of wellhead revenue. Brassey field development drilling was conducted simultaneously with the implementation of the miscible flood scheme, as encouraged by the incentive program. The development was a team effort requiring a detailed geological description. It involved a reservoir study incorporating reservoir simulation and pressure transient analysis, extensive laboratory support including special core analysis and PVT testing, and an operating strategy complementing the results. P. 279
Waterflooding started in the carbonate oil reservoirs of the Northern Michigan Niagaran reef trend in 1978 with Shell's Chester 18 waterflood. Ten projects had been installed by the end of 1982 so that significant operational results are available for evaluation. The design and operating programs initially planned for the projects have been proven successful. Operating data from some of the more mature projects indicate that the understanding and proper management of the geochemical systems for these projects will be crucial to the success of the project. The intent of this paper is to present what is currently known and understood about the geochemistry of Michigan waterfloods. The geochemical system is here defined as all the various interconnected fluid environments constituting the project, namely the fresh water source system, the injection well system, the reservoir, the production wells, the production facilities, and the produced water disposal or reinjection facilities. Problem areas have been identified and corrective action has been taken or planned to counteract the detrimental effects of disruptions to the geochemical system. These upsets are brought about by injection of water into the reservoir where an equilibrium condition had existed between the formation fluids and the rock. Project monitoring procedures, established to control and optimize waterflood operations, have made it possible to develop the proper approach to these geochemical disruptions. The more important items in this program are the measurement of produced and injected volumes, transient pressure analyses, injection well profile surveys, chemical analysis of the injection and production fluid samples, radioactive injection tracers, and continuous bottomhole pressures from submersible pumps.
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