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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents the case history of a focused Well and Reservoir Management (WRM) effort in a giant densely fractured carbonate reservoir in Oman. The field is currently producing under the gas oil gravity drainage reservoir process. The fracture network in the reservoir is largely gas-filled and has a thin oil rim underlain by active aquifer. Horizontal and multilateral producers are positioned in the oil rim while aquifer influx is limited to the optimum rate by water withdrawal from flank water producers. Delicate balance of crestal gas injection, aquifer water withdrawal and oil production is required to keep the oil rim at its optimal position. As the fracture oil rim has been lowered over a period of several years, a large number of wells have gassed out and started to circulate injected gas. Initial analysis of the production trends indicated that additional compression capacity was required in the field.An integrated WRM effort was undertaken in 2003 to manage this complex field. Active reservoir surveillance planning and execution was carried out to map current fracture fluid contacts across the field. Strategic well optimizations and recompletions were performed in selected wells to capture production from oil rim and avoid short-circuiting of the injected gas. Also, several gassed out intermittent producers and very high GOR continuous producers were shut-in. An eightwell production logging campaign provided better understanding of well and reservoir behaviour. Well integrity tests in over 110 wells further assisted in problem diagnosis and workover planning.These focused WRM efforts have resulted in sustained 10% production gain over a one-year period. A major capex benefit was also realized when a better understanding of the reservoir and improved GOR performance of the field eliminated the previously perceived need for additional compression.

In-situ combustion process was initiated in March, 1990 on a pilot scale in heavy oil field of Balol. Based on the success of the Pilot in terms of stabilised combustion and additional oil gain, the process was extended to a near by larger pattern in January, 1992. The main objectives were to observe the process performance in a larger area and to see the effect of placing the injector closer to downdip producers. The overall combustion performance of the project indicates that combustion can be initiated, sustained and propagated in reservoir like Balol and substantial oil gain can be achieved through proper monitoring of the process. The success of the project and the experienced gained through operating it, led to the decision of commercialisation of the process in the entire field. This paper deals with the performance of the in-situ combustion process at Pilot and extended scale, operational problems faced during implementation and the future strategy of commercialisation of the process. Introduction Oil and Natural Gas Corporation Limited (ONGC) initiated Pilot testing of in-situ combustion process in March, 1990 in the heavy oil field of Balol in North Gujarat, India. Interest in application of in-situ combustion process as an Enhanced Oil Recovery (EOR) tool was stimulated mostly due to the existence of large heavy oil reserves with low expected primary recovery. The encouraging results of the Pilot led to the extension of the process to an adjoining 9-hectare pattern in January, 1992. Presently combustion is in progress in both the patterns. Pilot Based on the laboratory findings, an inverted 5-spot pattern of 2.2 hectare was initiated on March 16, 1990. The Pilot has four producers (IC-2, IC-3, IC-4 & IC-5), one injector (IC-1) and one observation well (IC-6), 20 m away from injector and in line with IC-5. Figs. 1 & 2 show configuration of Pilot and location map of Balol field respectively. Table 1 shows petrophysical parameters of the Pilot area. The main objectives of the Pilot were:–To test whether combustion can be sustained and propagated.–To assess incremental oil recovery and Air-Oil Ratio.–To build-up and absorb the technology. Pilot Operation Ignition. Sand-face ignition was initiated by means of a gas burner. A total of 6.64 MM kcal (26.34 MM Btu) of heat was injected in a span of seven days during ignition operation. Air and water injection performance. Air & water injection profiles of the Pilot are shown in Figs. 3 & 4 respectively. Dry combustion phase lasted for 110 days after ignition period. Thereafter, the process was switched over to wet combustion phase. Air injection was increased in steps from 10,000 Nm3/d to 35,000 Nm3/d during dry combustion period. But due to subsequent rise in gas-liquid ratio in updip wells, air rate was reduced to 20,000 Nm3/d. Initially, during wet combustion phase, air and water were injected simultaneously at water-air ratio (WAR) of 0.002 m3/Nm3. It was switched over to cyclic injection in January, 1992. WAR was maintained, thereafter, at 0.001 m3/Nm3. A cycle consists of 6 days of air injection followed by one day of water injection. Since last week of February '96 water injection is being carried out through updip well IC-5 and air injection is being continued through IC-1. As on March 31, 1996 cumulative air and water injected were 32.81 MM Nm3 and 34,250 m3 respectively. P. 289^

PDO has implemented Enhanced Oil Recovery (EOR) methods including thermal, chemical and miscible gas injection projects in several fields. In the initial phase of these EOR projects, well and reservoir surveillance is key to increase the understanding of the effectiveness of the EOR processes in the various reservoirs. Well-planned and executed reservoir surveillance has proven in the past to add significantly to the production and ultimate recovery from reservoirs. Because of progress in technology in areas of data acquisition, processing and modeling techniques, well and reservoir surveillance data are increasingly used to optimize EOR processes. However, the interpretation of all data and integration into well and reservoir management workflows is still challenging. This paper describes the ongoing development of workflows for the interpretation, modeling and integration of surveillance data in three EOR projects. The surveillance methods include geomechanical modeling, thermal reservoir modeling and monitoring through time-lapse seismic, surface deformation, microseismic, temperature, pressure and saturation logging.

Steam Assisted Gas-Oil Gravity Drainage (SAGOGD) trial is planned for a limited area of a giant producing light oil field in Oman. Oil production from this oil-wet fractured carbonate reservoir commenced in 1967, and recovery factor currently stands at approximately 20%. The SAGOGD process in a light oil fractured reservoir is complex and is comprised of numerous recovery mechanisms, with a number of these being uncertain and poorly understood. Very little world analogue data is available [1], and that, combined with large recovery process uncertainties make this ‘large pilot scale’ Phase 1 essential to mitigate the downside risk in a full-field development. During Phase-1 it is planned to inject 2000t/d of steam by means of 4 vertical steam injectors. Oil, gas and condensed steam will be produced by 7 horizontal producers and 5 vertical back-up producers. The magnitude of the SAGOGD production response is highly uncertain. Having the capability to accurately measure the incremental oil production response over this wide uncertainty range was considered to be a key success factor for the Phase 1 project. To accurately measure the incremental response required that a ‘no steam’ production response could be confidently projected into the future for a minimum of two, and up to five years. This task was made considerably more complex by the fact that historical GOGD well production profiles were often relatively unstable. This paper describes the work carried out within PDO to ensure that one of the key Phase 1 success criteria – that being to measure the incremental oil due to SAGOGD – can be achieved over a primary evaluation period of two to five years. The discussion will include a description of efforts linked to optimization of cold GOGD performance (optimum oil rim management), well production stabilization (via installation of new production control hardware) and accurate measurement of total and individual well production levels (dedicated bulk and well-test facilities), and how this all came together to yield a stable cold production baseline which could be confidently projected into the future.