This paper describes the Repeat Formation Tester, a tool that can make on one open-hole trip an unlimited number of pressure determinations. Down-hole pressure data from the tool are used to monitor and enhance the effectiveness of a waterflood in Rangeley Field, CO. Data from this tool also are used in a technique to evaluate permeability; results in U.S. Gulf Coast wells are compared with those from sidewall cores. Introduction One key to meeting our future energy requirements is more efficient production of new and remaining reserves. To this end, information is needed on conditions down hole, including accurate down-hole formation pressures. The Schlumberger Repeat Formation Tester (RFT) is an open-hole wireline device capable of providing such pressure data with minimal demands for drilling-rig time. pressure data with minimal demands for drilling-rig time.The RFT may be set any number of times during a single logging run. At each setting depth, a "pretest" is made in which small samples of fluid are withdrawn from the formation. During this pretest, the fluid pressure in the formation adjacent to the wellbore is monitored until equilibrium formation pressure is reached. These RFT pressure data are recorded at the surface on both analog pressure data are recorded at the surface on both analog and high-resolution digital scales. The pretest fluid samples are not saved. However, after the pretests in a zone of interest, another larger fluid sample can be taken optionally and retained, with the possibility of retrieving two such fluid samples per trip in possibility of retrieving two such fluid samples per trip in the hole. In this paper, however, interest is directed to the large number of pressure measurements that can be made by setting the tool and going through the pretest cycle at successively different levels. Recent experience of Chevron U.S.A. Inc., in the Rangely Field of Colorado is described to demonstrate the quality of the pressure measurements and the reliability of tool operation. Chevron applies the pressure information to the planning and monitoring of pressure information to the planning and monitoring of a secondary-recovery waterflood project. Pressure data, in conjunction with other data available during the drilling of infill wells, were used to predict which flooded zones would produce with a high water cut. By eliminating these zones from production and by injecting into essentially unflooded zones, the effectiveness of the flood could be enhanced. The pressure measurements have been used with open-hole and mud-log data to predict the expected water cut. Significant pressure predict the expected water cut. Significant pressure overbalance suppresses hydrocarbon shows on the mud log. Pressure underbalance exaggerates hydrocarbon shows. Both lead to erroneous water-cut predictions. Knowledge of the pressures makes it possible to allow for such errors. Pressure profiles through the Weber sandstone reservoir were determined in a number of wells in the Rangely Field. Reservoir pressures were found to vary greatly and to be distributed erratically both vertically and horizontally. This is attributed to the field's long history of production and water injection and to the fact that many of the permeable zones are discontinuous. Plotting these pressure permeable zones are discontinuous. Plotting these pressure data on contour maps delineates areas requiring increased flooding to maintain the effectiveness of the waterflood program. program.During the drawdown phase of the pretest, when fluid is being extracted from the formation, the pressure behavior is indicative of the minimum local permeability at that depth. A simple technique is described for computation of permeability from the pressure data, based on a steady-state spherical flow model. JPT P. 25
A new tool provides simultaneous recording of measurements from all downhole production-logging sensors used in the analysis of production or injection wells. The system was used to evaluate production-well profiles in the South Swan Hills miscible flood project in Alberta, Canada. The dynamic reservoir picture obtained from the information proved useful in improving reservoir performance. Introduction Production logs have been used for many years to Production logs have been used for many years to evaluate producing and injection wells. In the past, when reservoirs with excess capacity were limited by allowables, production logs were used basically to diagnose a problem on an individual well, such as locating a source of water production or defining a mechanical problem such as a packer leak. Today, with the increased demand for oil and the declining capacity of mature reservoirs, combined with more sophisticated recovery schemes, the oil industry is becoming increasingly aware of the importance of improving fieldwide reservoir performance. With this shift in emphasis, the role of production logging has taken on a much wider scope.For the evaluation and management of a reservoir, the reservoir engineer may get the information he needs by running production logs on selected production and injection wells throughout the production and injection wells throughout the reservoir. By repeating this on an appropriate time scale, a dynamic description of the reservoir can be evolved. This information can be integrated with formation evaluation logs, such as the TDT log and the initial openhole logs, to compare actual performance with indicated reservoir potential. performance with indicated reservoir potential. The analysis of producing wells is rarely simple. Downhole flow usually involves different fluids (oil, water, and gas) having different densities and moving at different velocities. Furthermore, these may vary with time because of well instability. Typically, several measurements are needed to resolve the problem. The effect of well instability can be reduced problem. The effect of well instability can be reduced by obtaining the measurements simultaneously. Much has been published in the literature on the use of flowmeter, thermometer, manometer, Gradiomanometer TM and caliper tools to analyze downhole flow. In addition, a casing-collar locator and a gamma-ray log are useful for depth control and correlation with the formation evaluation logs.In this paper we describe a new 1 11/16-in. (42.9-mm) diameter telemetry-based tool - the PLT (TM) (simultaneous production logging tool) - capable of transmitting all these measurements simultaneously during one trip in the well. It is relatively easy to add new sensors to this flexible system. A new dual tracer ejector tool and a high-precision pressure gauge, which have been added to the above family of sensors, also are discussed.This paper presents the results of a 15-well logging program in which the PLT tool was used to evaluate program in which the PLT tool was used to evaluate a miscible flood project in the South Swan Hills pool in Alberta, Canada. While tracer materials were used to monitor the lateral progress of the flood front, production logging was used to monitor the vertical production logging was used to monitor the vertical distribution in both injection and production wells. JPT P. 191
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Due to the problems interpreting conventional production logs (i.e., spinner) in horizontal wells, a video camera was run along with conventional production logs to provide insight into well performance. The video log gave visual information about the fluid flow regime along a horizontal wellbore and fluid entry at each fracture stage. This valuable information significantly enhanced the interpretation of conventional production logs and showed the various and complex flow regimes that occur in horizontal wells. These are the first successful video logs obtained in horizontal wells. This paper presents the design changes that made it possible to successfully run the video logs, the procedures used to run the logs in rod pump wells, and the results obtained from both the video and conventional production logging tools. It is beyond the scope of this paper to discuss the implications the results may have on future horizontal well completions. Introduction Production logging combined with downhole video logging provided significant insight into the production characteristics of three horizontal wells completed with multi-stage hydraulic fracture treatments in the diatomite reservoir of the South Belridge Field of California. Conventional production logging tools (PL) are difficult to evaluate in horizontal wells due to very complex flow regimes that can rapidly change along the wellbore. Although PL logs alone have been successful in evaluating horizontal wells, the video camera was included in this project in an attempt to provide visual information about the flow regimes and fluid entries. This paper presents the design changes that made it possible to successfully run the video logs, the procedures used to run the logs in rod pump wells and the results obtained from both the video and conventional production logging tools. The Belridge oil field (Fig. 1) located about 40 miles west of Bakersfield California, is one of the larger producing fields in the United States, containing over three billion barrels of oil-in-place in a diatomite column greater than 1000 foot thick and extending over five square miles. The low permeability (<1 mD) diatomite requires application of massive hydraulic fracture stimulation to obtain economic production. This horizontal well project was initiated in December 1995 to provide insight into the cost, productivity and technical aspects of applying massive hydraulic fracture stimulation technology to horizontal wells in the diatomite. Productivity of the horizontal wells was expected to be about the same as analog vertical wells but the actual productivity was only 50% of expected. Fig. 2 shows the mechanical diagram of the horizontal well completions. (The second tubing string was not initially installed until production logging commenced as explained further in the paper.) Each well was drilled with the same medium bend radius (120/100 ft.) to accommodate conventional completion equipment. A 9–5/8" casing string was set and cemented after the well path reached 900 deviation. After reaching total measured depth, a 5–1/2" liner was cemented in place. The wells were then completed in stages (8–9) by perforating one foot intervals spaced every +/- 200 feet followed by massive hydraulic fracture treatments. The wells were then placed on rod pump. After the initial production rates were found significantly less than expected, a production logging program was designed to investigate the poor performance. Production Logging Tool Selection The production logging tools consisted of conventional 1–11/16 inch O.D., basket flowmeter, radioactive tracer, noise, nuclear fluid density, capacitance, Amerada pressure gauge, and a temperature probe. Appendix - PL Equipment gives additional basic information for readers not familiar with PL tools. Although new technologies exist for horizontal well production logging, conventional tools were considered adequate since the fluid entries would occur at a point source (1 foot interval) spaced up to 200 feet apart. P. 337^
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