Summary Several multirate separator tests (MRTs) have been undertaken on wells in the Veslefrikk field that are on commingled production from the Brent Group and Intra Dunlin Sand. During these tests, produced-water samples were also collected. Integrated analysis of the results of interpretion of the produced-water analyses and the MRT results have provided a range of information for each production zone including the nature and composition of the produced water, seawater fraction of these produced waters, fraction of total water flow being produced, pressure, productivity index, oil and water rates, and water cut. This information can reduce the need for deploying production-logging tools (PLTs), allows the scaling potential between the deeper and the shallower zones to be evaluated, aids squeeze-treatment design, is beneficial for predicting formation damage from crossflow, and aids water-shutoff decisions. In this paper, the methods of interpreting the produced-water analyses are presented through the use of a field example. To aid interpretation, interpretation of other produced-water analyses from the field and reactive-transport modeling have been undertaken to better understand reactions occurring in the reservoir as a result of seawater injection and the effects of these reactions on produced-water compositions. In an accompanying paper (Tjomsland et al. 2011), the integrated MRT-analysis techniques are described and the results and applications of additional field examples are presented.
A 4-zone intelligent WAG injector was installed at the Statoil Veslefrikk Field in the North Sea, in May 2004. The completion includes one on/off and three variable downhole chokes for controlling injection rate into each of the four zones. The completion also includes three downhole optical flowmeters and three optical pressure and temperature gauges. Measurement of the surface injection rate and the rate from each of the three flow meters provides real-time measurement of injection rate into each zone, regardless of choke positions. The well is on a Water Alternating Gas (WAG) cycle where one zone is primarily intended for gas injection and the other three zones are primarily intended for water injection. Therefore, equipment that can control and measure water and gas flow with no changes in hardware was critical for the success of this installation. The combination of downhole chokes and flowmeters allow full control and monitoring of zonal injection rates and has proved to be a valuable tool in managing reservoir pressures and optimizing production. After more than one year of operation during water injection, all the valves and the optical monitoring equipment are functioning satisfactorily. It is estimated that up to about half of the well's value creation during its expected lifetime is due to the DIACSinstallation. Introduction Production optimization is traditionally associated with maximizing the performance of a producing well by controlling the wellhead choke, ESP's, or gas-lift rate. Conversely, water or gas (or WAG) injectors have traditionally been employed to maintain reservoir pressure, but not typically used in a structured production optimization program. However, employing multi-zone intelligent injectors (employing downhole flow control and monitoring) is shifting this paradigm. It is widely recognized that real-time, downhole, flow control and measurement is critical for production optimization in complex intelligent completions and in dual and multi-lateral wells. Applications include: zonal production or injection allocation in multi-zone completions, increased accuracy of injection profiles, in producing wells the ability to commingle production from multiple zones and reduce or eliminate surface well tests (and facilities). It is critical for the successful implementation of intelligent wells that reliable downhole flow control and monitoring equipment is employed. The nature of downhole monitoring and control systems renders it inaccessible after installation and repairs or replacement of faulty downhole equipment normally means pulling the entire completion. Monitoring equipment ranges from downhole electronic pressure and temperature gauges to downhole optical single- and multiphase flowmeters. Downhole monitoring equipment is normally designed for life-of-well, however, in practice, many technologies fail to deliver on such promises and stop working after only a few months in the well. In recent years, and especially with the advent of fiber optic sensing, the reliability picture is changing. In electronic systems, the reliability of monitoring equipment deteriorates rapidly with increasing temperatures although vendors are continually introducing new products that address high-temperature issues. In low temperature wells, both electronic and optical systems have proven records of years of reliable operation. In addition, the operator needs a reliable control valve system to allow adjustments and to fine-tune production or injection. Sensors provide the data which helps identify recovery potential, but a reliable flow control system can turn that potential into real value by providing the operator with reservoir management options which do not require costly well intervention. Some operators consider the real value of production optimization technology to be the ability to remotely reconfigure the flow profile without intervention. Early in the development of downhole production optimization technology, the high price of the systems combined with poor reliability was of primary concern to operators.
Several multirate separator tests (MRTs) have been undertaken on wells in the Veslefrikk field that are on commingled production from the Brent Group and Intra Dunlin Sand (IDS). During these tests, produced-water (PW) samples were also collected. Integrated analysis of the results of interpretion of the PW analyses and the MRT results has provided a range of information for each production zone, including the nature and composition of the PW, the seawater fraction of these produced waters, the fraction of total water flow being produced, pressure, productivity index, oil and water rates, and water cut. This information can reduce the need for running production-logging tools (PLTs), allows the scaling potential between the deeper and the shallower zones to be evaluated, aids squeeze-treatment design, is beneficial for predicting formation damage from crossflow, and aids water-shutoff decisions.In an accompanying paper, McCartney et al. (2012) describe how PW analyses from the MRT are interpreted to determineamong other parameters-the amount of water produced from each zone (water allocation) at each of the test rates during an MRT. In this paper, the methods of analyzing these results in combination with separator-test data are described with the aid of a field example to demonstrate how they provide detailed information about the downhole conditions and zone properties of the well. On the basis of the analysis, a set of well interventions was recommended. Following confirmation of the principal MRT results by a PLT, some of the recommended interventions have been performed successfully. Experience from Veslefrikk suggests that MRTs can be considered as a possible replacement for running PLTs or as an additional source of data that can be acquired more frequently.
Summary A four-zone intelligent water-alternating-gas (WAG) injector was installed at the Statoil Veslefrikk Field in the North Sea in May 2004. The completion includes one on/off and three variable downhole chokes for controlling injection rate into each of the four zones. The completion also includes three downhole optical flowmeters and three optical pressure and temperature gauges. Measurement of surface injection rate and the rate from each of the three flowmeters provides real-time measurement of injection rate into each zone, regardless of choke positions. The well is on a WAG cycle in which one zone is primarily intended for gas injection and the other three zones are primarily intended for water injection. Therefore, equipment that can control and measure water flow and gas flow with no changes in hardware was critical for the success of this installation. The combination of downhole chokes and flowmeters allows full control and monitoring of zonal injection rates and has proved to be a valuable tool for managing reservoir pressures and optimizing production. After more than 1 year of operation during water injection, all the valves and the optical monitoring equipment are functioning satisfactorily. It is estimated that up to half of the well's value creation during its expected lifetime is because of the DIACS (Downhole Instrumentation and Control System) installation. Introduction Production optimization is traditionally associated with maximizing the performance of a producing well by control of the wellhead choke, electric submersible pumps (ESPs), or gas lift rate. Conversely, water or gas (or WAG) injectors have traditionally been used to maintain reservoir pressure, but have not typically been used in a structured production optimization program. However, use of multizone intelligent injectors with downhole flow control and monitoring is shifting this paradigm. It is widely recognized that real-time, downhole flow control and measurement is critical for production optimization in complex intelligent completions and in dual and multilateral wells. Applications include zonal production or injection allocation in multizone completions, increased accuracy of injection profiles, and in producing wells, the ability to commingle production from multiple zones and reduce or eliminate surface well tests and facilities. It is critical for the successful implementation of intelligent wells that reliable downhole flow control and monitoring equipment be used. The nature of downhole monitoring and control systems renders them inaccessible after installation, and therefore repair or replacement of faulty downhole equipment normally means pulling the entire completion. Monitoring equipment ranges from downhole electronic pressure and temperature gauges to downhole optical single- and multiphase flowmeters. Downhole monitoring equipment is normally designed for life-of-well; however, in practice, many technologies fail to deliver on this promise and stop working after only a few months in the well. In recent years, and especially with the advent of fiber-optic sensing, the reliability picture is changing. In electronic systems, the reliability of monitoring equipment deteriorates rapidly with increasing temperatures, although vendors are continually introducing new products that address high-temperature issues. In low-temperature wells, both electronic and optical systems have proven records of years of reliable operation. In addition, the operator needs a reliable control valve system to allow adjustments and to fine-tune production or injection. Sensors provide data which help identify recovery potential, but a reliable flow control system can turn that potential into real value by providing the operator with reservoir management options which do not require costly well intervention. Some operators consider the real value of production optimization technology to be the ability to reconfigure the flow profile remotely without intervention. Early in the development of downhole production optimization technology, the high price of the systems combined with poor reliability was of primary concern to operators. Most operators associated downhole electronics and complexity used in the early systems with high potential workover cost. From the adoption of the early systems to date, there has been a dramatic improvement in reliability. Today, the reliability of these systems is proven, and they are seeing market acceptance and wider application.
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