TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Digital Oil Field is rapidly gaining attention within the oil and gas industry. Several oil and gas operators are working to develop their vision for an oil field of the future, testing new technologies, setting up programs and participating in industry events. The vision is an integrated approach allowing more real-time control of asset management. Many different names are used in the upstream industry to describe this trend; Smart Fields, Digital Oil Field, Next Generation Oilfield, Field of the Future, e-field, Instrumented Field and Intelligent Energy. However, there is still uncertainty as to what needs to be done and what value it will actually bring to the industry. Several operators and service companies are transitioning from the initial envisioning and abstract phase to projects creating measurable value for the company. In this paper, Chevron's efforts within the Digital Oil Field domain, including concept, business case, corporate governance, technology development, partnerships, deployment and field experience are presented.

Original SPE manuscript received for review Sept. 7, 1993. Revised manuscript received May 10, 1994. Paper accepted for publication May 23, 1994. Paper first presented at the 1993 SPE Offshore Europe Conference held in Aberdeen, Sept. 7–10. SPE Production & Facilities, August 1994. Summary This paper presents experience with and applications of permanent downhole pressure and temperature gauges in the reservoir management of two complex North Sea oil fields, Gullfaks and Veslefrikk (both operated by Statoil A/S). In total, 40 quartz and quartz capacitance gauges from three different suppliers have been installed in platform wells over 6 years. The gauges have given invaluable real-time data for reservoir management of these two fields and contribute directly to increased daily oil production. The installations have proved to be safe and reliable, as well as good investments. Introduction The Gullfaks field is in the central part of the Eastern Shetland basin in the North Sea, 175 km [109 miles] northwest of Bergen, Norway (Fig. 1). The field has been developed with three concrete gravity-based platforms-Gullfaks A, B, and C-and started production in Dec. 1986. The oil is located in three major sandstone units: the Brent group, the Cook formation, and the Statfjord formation. These shallow, highly porous sandstones are generally poorly consolidated, and sand control is necessary in a number of high-permeability producers. The reservoirs are overpressured, and water injection is the main drive mechanism. As of June 1993, 80 of 107 planned wells had been drilled. Of these wells, 29 have a permanent downhole gauge installed. The daily oil production is 85 000 std m3/d [530,000 std B/D]. The Veslefrikk field consists of an upthrown horst block on the northwestern flank of the Horda platform, approximately 145 km [90 miles] northwest of Bergen (Fig. 1). The field has been developed with a lightweight drilling and wellhead platform and a floating production platform. Production started in 1989 from six predrilled wells. The oil is produced from two separate sandstone reservoirs: the deltaic Brent group and the deeper, shallow marine Intra Dunlin sand (IDS). The reservoirs are slightly overpressured. The production strategy is to commingle production and injection with peripheral water injection to maintain the average reservoir pressure above the saturation pressure. As of June 1993, 17 of 20 planned wells had been drilled. Permanent downhole gauges are installed in eight wells. The daily oil production is 12 000 std m3/d [75,000 std B/D]. Table 1 lists general field and reservoir data for the two fields. Differences between the two fields lead to various applications for permanent gauges. The Gullfaks field is heavily faulted with a number of sealing or partially sealing faults. One important reservoir monitoring objective is to identify the degree of communication between the fault blocks. The Veslefrikk field is partially developed with commingled wells. Permanent gauges are installed in dedicated wells to monitor the two reservoirs independently. Data from the permanent gauges are used for both fields to ensure single-phase oil flow in each fault block. That information also is used to monitor and optimize well performance with time, for transient well-test analysis, and for matching numerical models. Permanent downhole gauges are installed in key wells where the need for enhanced data acquisition is defined. The first permanent downhole pressure gauge was installed in July 1987 in a Gullfaks well. As of June 1993, 40 gauges had been installed in Gullfaks and Veslefrikk wells in 35 producers and 5 injectors. Locations of the wells with permanent gauges are given in Fig. 2 for Gullfaks and Fig. 3 for Veslefrikk. Three different gauge systems delivered by three different suppliers have been used. Fig. 4 shows the gauge installation history for each platform during 1987-93, and Fig. 5 shows the number of gauges installed for each system. Cost/Benefit Analysis The decision to install permanent gauges was based on three primary factors.The need for enhanced reservoir description, especially during the initial production phase.Increased production resulting from a combination of less downtime for data acquisition and optimization of reservoir and well management.Safety and operational considerations. Large investments before production startup are typical for most North Sea developments, requiring a high early production to ensure project profitability. At the same time, reservoir complexity and relatively short field lifetimes necessitate extensive data acquisition during the initial production phase. Permanent gauges support both these requirements by supplying continuous downhole data with a minimum of well downtime. Production from the Gullfaks field has mainly been limited by well capacity, whereas Veslefrikk production has been partly limited by well capacity and partly by injection system capacity and availability. Consequently, well downtime owing to data acquisition results in deferred production. Running a wireline gauge typically requires 28 hours of shut-in, including shut-in of neighboring wells for safety reasons. Because individual well rates vary between 500 and 5000 std m3/d [3,145 and 31,450 std B/D], this represents a significant production deferment. The cost of the deferred production depends on several parameters: the platform in question, plateau length, planned well lifetime, oil price, dollar exchange rate, and taxation. A common factor among the most important parameters is that the cost is highest early in the life of the well when the information is most important. On average, a cost of 270 NOK/stock-tank m3 [$US 7/STB] for deferred production is estimated. In addition, the cost for a well test with wireline gauges is approximately 600 000 NOK [$US 100,000]. The extra rig time required to install a permanent gauge is about 8 hours, and the investment costs average 1 100 000 NOK [$US 180,000] per installation. Comparison of direct costs shows that the average payback period for permanent gauge installations is less than 1 year. This cost/benefit analysis is based on a comparison of permanent and wireline gauges. However, a number of Gullfaks wells are highly deviated and require coiled tubing or snubbing equipment for downhole data acquisition. This increases the cost dramatically. In these wells, the cost of installing a permanent gauge is less than the cost of a single data-acquisition operation. Furthermore, considerable potential for increased production through improved reservoir and well management exists. The possibility of using pressure data from drawdowns and operationally derived shut-ins also results in increased production by avoiding extra shut-ins for data acquisition. The use of wireline gauges for data acquisition in a North Sea well is a complex operation that may involve 10 or more people, including service company personnel and company representatives. P. 195^

Summary This paper presents a procedure for interpreting data acquired with permanent downhole pressure sensors in association with surface or downhole rate measurements. The usefulness of this data source in reservoir description and well performance monitoring is illustrated. Unlike previously published examples, the interpretation is based on the analysis on a stream of data acquired over large periods of time, thus utilizing the continuous nature of the measurements. Three field cases are presented using the pressure and rate data in decline-curve analysis for wells with a variable downhole flowing pressure, and through more sophisticated models that are similar to the ones used in well test analysis. Because such interpretation is conducted while continuing production, it is particularly well suited for a well or group of wells under extended testing, which are equipped with downhole gauges and are flowing through surface separation and metering systems. Wells completed with both permanent downhole rate and pressure measurements are also ideal candidates for this type of analysis. Finally, the influence of the pressure sensor long term drift and the rate measurement error on the interpretation results and future forecasts are investigated. Introduction Since the first permanent downhole gauge installations in the early 1960's on land wells, the new technology in cable manufacturing, gauge sensor and electronics has permitted reliable installations also in hot, deep wells and subsea completions. These systems have gained acceptance among operators, and currently several hundred downhole gauges are installed every year. The traditional applications associated with permanent downhole systems can be characterized by four distinctions:single well optimization,reservoir description,safety improvement, andoperating cost reduction. Combining the recent technology development and these applications, the downhole gauge installations can be safe and reliable, as well as good investments. Most of the previous papers on the subject have focused on the hardware involved in permanent downhole pressure gauge installations. Regarding reservoir description, a few examples have been published where data recorded by the permanent downhole gauges have been used in well test transient analysis and multiwell interference tests. However, little has been published on the use of continuous downhole measurement in order to enhance reservoir description when associated with rate data during the pseudosteady state or depletion period of a field or a separate block. Decline curve analysis is one of the most widely used and documented methods for reserve estimation and production forecasting for a field under depletion. Solutions have been published for the case of a well producing at constant downhole flowing pressure. In reality, due to production constraints or change in operating procedures, the downhole flowing pressure seldom remains at a constant level over long periods of time. In the decline curve analysis literature, various methods have been proposed to account for these pressure variations; these include normalization and various types of superposition based on the pressure change observed at the wellhead.

Summary This paper presents field data and performance analysis for high-rate gravel-packed oil wells in the Gullfaks field. More, than 2 years' worth of production history is available for the earliest gravel-packed wells. From extensive production testing and reservoir monitoring, the initial performance and performance history before water breakthrough was evaluated. An addendum reviewing later developments (1991–1993) is also included. Introduction The Gullfaks field, operated by Statoil A/S, is in the central part of the East Shetland basin in the northern North Sea, 175 km northwest of Bergen, Norway. Developed with three Condeep(TM) platforms (Gullfaks A, B, and C) the field started production in Dec. 1986. Of a total of 102 planned wells, 56 were drilled as of June 1991; six are subsea satellite wells. Estimated production life of the field is 20 years. The main drive mechanism is water injection. Predicted ultimate oil production from the field is 230 × 10(6) Sm3. The oil is located within three major sandstone units, the Brent Group, the Cook formation, and the Statfjord formation. The lower Brent delta sequence comprises the Broom, Rannoch, Etive, and Ness formations; the Upper Brent consists of the Tarbert formation. The reservoirs are overpressured, with an initial reservoir pressure of 31 MPa at datum depth (1850 m below mean sea level], and a temperature of 70 degrees C. The shallow, highly porous sands generally are poorly consolidated. The oil is undersaturated, with a saturation pressure of approximately 24 500 kPa, depending on depth and location. The oil viscosity is between 1.0 and 1.2 mPa.s at initial pressure conditions. Average horizontal formation permeability in gravel-packed wells varies from 250 to 10 000 md on the basis of transient well-test analysis. Porosity is high, generally between 35 and 40 porosity units. The Gullfaks field is divided into a number of fault blocks and is classified as a complex North Sea reservoir. During the first years of reservoir development, wells were naturally completed and selectively perforated in the relatively strong Rannoch formation. Considerable research was conducted to avoid sand production. After 2 years, development of the overlying weaker Ness and Tarbert formations began. Concurrently, a number of Rannoch wells were constrained by sand production initiated by water breakthrough. In these wells, water breakthrough severely reduced the maximum sand-free rate. Therefore, the need for sand control has increased with time. As a result, 2 years after production started, the completion strategy was changed to gravel packing. By June 1991, 14 platform oil producers were cased-hole gravel-packed. Earlier publications on high-rate gravel-packed oil wells discuss rates of up to 750 Sm3/d. The maximum oil rate produced through a single Gullfaks gravel pack is 5000 Sm3/d, limited only by calculated erosion velocity in the tubing. Gullfaks gravel-packed wells have been production-tested extensively, and laboratory work has been performed for better understanding of gravel-pack performance. This paper presents field data and its evaluation as of June 1991.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Digital Oil Field is rapidly gaining attention within the oil and gas industry. Several oil and gas operators are working to develop their vision for an oil field of the future, testing new technologies, setting up programs and participating in industry events. The vision is an integrated approach allowing more real-time control of asset management. Many different names are used in the upstream industry to describe this trend; Smart Fields, Digital Oil Field, Next Generation Oilfield, Field of the Future, e-field, Instrumented Field and Intelligent Energy. However, there is still uncertainty as to what needs to be done and what value it will actually bring to the industry. Several operators and service companies are transitioning from the initial envisioning and abstract phase to projects creating measurable value for the company. In this paper, Chevron's efforts within the Digital Oil Field domain, including concept, business case, corporate governance, technology development, partnerships, deployment and field experience are presented.