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.

No abstract

Summary Three-phase production-allocation programs have continuously evolved in the Prudhoe Bay Eastern Operating Area (PBEOA) over the past 19 years. These programs are necessary because the actual production rate of a well can be measured only when a well is being tested. Since each well is tested for about 6 hours per week, some method of estimating well production rates in real time while the well is not being tested is required. These estimates are used to optimize well and field production as surface processing and product shipping constraints vary. These estimates are also used to estimate field production rates in real time, track well performance, and allocate production volumes to wells for accounting and reservoir management purposes. Rate tables for most naturally flowing wells and all gas lifted wells are based upon the Fetkovich inflow performance model and tubing performance relationships (TPR's) developed from various tubing hydraulics models. Specialty rate table programs allow engineers to allocate production to wells which always produce at the same choke setting, wells which are in the process of gassing out, and to automatically allocate wells which maintain consistent performance. A recent upgrade of the allocation system, utilizing current generation computer hardware, communications hardware, and software has resulted in a 60% reduction in engineering time required for production allocation. The allocation process discussed here can be applied to many other fields to improve the link between field well test data and the optimization of field production rate, estimation of well and field production rates in real time, well performance tracking and allocation of field production to wells for reservoir management and accounting purposes. Introduction The oil rate at the Prudhoe Bay Field is limited by the available gas handling capacity. The main objective of production rate optimization at the PBEOA is to utilize the gas compression facilities as efficiently as possible to maximize oil, natural gas liquids (NGL), and miscible injectant (MI) production rates. Well production rates are changed almost continuously to optimize these field production rates. Reliable estimates of well performance are essential to this optimization effort. Since it is not possible to obtain real-time measurements of three-phase production from each well, estimates of well performance are generated by Anchorage-based Drill Site Surveillance Engineers from well test data and a personal knowledge of the history of each well. These estimates of well performance are then stored in look-up tables known as "rate tables."

Movement of fluids in cement channels outside of well casing is a frequently-occuring problem in the production of hydrocarbons. This may result in cross-flow between formations, or fluids being injected into -or produced from -unintended formations. Although channels above perforations are sometimes suspected, their existence is often difficult to detect. An improved method of detecting channels above perforations was developed by computer simulation and correlation of field data. This method, the pump-in temperature survey (PITS), has been proved reliable with recent usage on producing wells at the Prudhoe Bay Field.

A giant fractured carbonate field in north Oman has both complex geology and complex reservoir drive mechanisms. The upper densely fractured layers are produced using the gas oil gravity drainage (GOGD) process, while the less fractured lower set of layers is subjected to water flooding. The production from the GOGD layers is through vertical and horizontal wells completed in a thin fracture oil rim. Gas conformance control is a challenge in many of these wells as the gas breakthrough occurs for a variety of reasons:downward movement of fracture gas-oil contact (fracture oil rim thinning),gas breakthrough via high conductivity fractures (fracture gas breakthrough),zonal isolation failure at the wellbore (mechanical gas breakthrough) andincreasing gas saturation in the matrix (matrix gas breakthrough). An integrated multidisciplinary team studied well and reservoir performance and open-hole and cased-hole logs to diagnose the source of higher than expected GOR in several GOGD wells. The most important logs in this work were MPLT surveys used to identify the sources of gas production and FMI logs used for fracture identification and characterization. This paper illustrates the work carried out in horizontal openhole and vertical cased-hole completions in a giant fractured carbonate field to successfully shut-off the undesirable gas flow. The horizontal wells identified with poor zonal isolation behind the liner were treated with an innovative gel gas shut-off procedure. The merits of this procedure outweighed other solutions: targeted placement; a strong full-blocking gel to fill up channels behind the liner, inert particles to control fluid loss of the full blocking gel to small fractures and the formation matrix, and displacement with an already cured gel which could be washed out of the wellbore. Significant drops in the GORs of these wells resulted in sustained oil production gains. This is a step change in the ability to manage detrimental gas production in this field and is expected to lead to further opportunities for improved gas management and well performance in this field and other fields where the GOGD recovery mechanism is used. Introduction The giant fractured carbonate field was discovered in 1964 and came on stream three years later. The field has 7 reservoir layers A - G and multiple subunits within each layer. The upper layers A, C, D and E1/E2 are more intensely fractured than lower layers E3/E4, F and G reservoirs. Initial production from the reservoirs (1967–1970) was by natural depletion, supported by gas injection in the A reservoir unit from 1968 onwards. After this initial period of gas injection, water injection was implemented in the A, C, D and E reservoirs (1970–1984). Previously unknown fracture networks in these layers resulted in rapid water breakthrough. This was followed by GOGD (Gas-Oil-Gravity-Drainage) development (1983–1998), which was successful in arresting the decline in the oil production. Following a simulation study in 1996, it was decided to implement a line-drive waterflood with horizontal wells in those layers considered to be sparsely fractured. Because GOGD is not effective in sparsely fractured reservoirs, waterflooding these layers was expected to substantially increase recovery in those layers. Since 1997, field development and operation has utilized this combination of GOGD and localised waterflood. A recent review of production and petrophysical data showed that the fracture spacing varies significantly both hortizontally and vertically. This impacts the GOGD efficiency and recovery factor, since GOGD is inefficient where fracture spacing is larger, as the oil has to travel long distances through the matrix to the nearest fracture set in order to be recovered.