Combination of intelligent well design and ESP flexibility reduces water cut in UK offshore.

Intelligent well completion technology enables operators to actively monitor and selectively modify the zones from which hydrocarbons are produced while a well is onstream, without intervention. As such, intelligent well completion systems are a powerful complementary technology to the evolving capabilities of electric submersible pump (ESP) artificial lift. The synergy of combining intelligent well completions with ESPs results from the capability to restrict or exclude production from specific zones experiencing water or gas breakthrough. Control of water and/or gas production permits more efficient operation of the downhole pump and improves ultimate recovery of hydrocarbons.

Objectives

Beyond the attraction of interventionless completions in the high cost arena of subsea wells and deepwater developments, intelligent well technology also can deliver improvements in hydrocarbon production and reserve recovery, with fewer wells, in conventional environments. When applied to injection or production wells, it also can improve the efficiency of water and gas injection projects in heterogeneous or multi-layered reservoirs. The production and reservoir data acquired with downhole sensors can improve the understanding of reservoir behavior and assist in the appropriate selection of infill drilling locations and well designs. Intelligent well technology can enable a single well to do the job of several wells, whether through controlled commingling of zones, monitoring and control of multiple laterals, or by allowing a well to take on multiple functions simultaneously (e.g., injection well, observation well and production well). Finally, intelligent well technology allows the operator to monitor aspects of wellbore mechanical integrity or the environmental conditions under which the completion is operating, and to modify operating conditions in order to maintain them within an acceptable mechanical integrity envelope.

ESPs and intelligent completions

Zonal flow control is made possible through remotely controlled hydraulic, electric or electro-hydraulically actuated inflow control valves in conjunction with purpose-built feed-through isolation and production packers. Permanently installed instrumentation that includes pressure, temperature and flow gauges can monitor the condition and contribution from each segregated zone and transmit this data to the petroleum professional in real time. The following benefits can be realized by applying intelligent well technology to ESP installations:

• more energy dedicated to lifting oil rather than water;
• greater drawdown on oil-producing zones;
• reduced wear-and-tear due to slugging and inclusion of gas;
• reduced pump and gas handling equipment size matched to lifting requirements; and
• improved well control and minimization of formation damage due to the ability to shut-in well at sand face while pulling ESP.

These benefits result in greater recovery and reduced lifting costs.

Issues to applying intelligent wells

When considering combining ESP and intelligent well technology, several key issues must be evaluated in a total system context to ensure the optimal design, installation and operation of a "smart ESP" well.
Wellhead penetrations. The area available for electrical power conductors, instrument cables, hydraulic control lines and fiber-optic cables to pass through the wellhead is limited. Solutions to this limitation can include multiplexing the function of some of the conduits (e.g., pumping the optical fiber down the hydraulic control line), and combining intelligent well electrical power and data transmission with ESP cabling.
Intelligent well cable disconnects. Intelligent well components are generally installed for an extensive mission profile, perhaps for the full life cycle of the well. ESP equipment generally has a more limited lifetime and requires relatively frequent change-out over the life of the well. If the ESP is deployed on the same production conduit on which the intelligent well cabling is conveyed, then downhole wet disconnects must be provided for intelligent component hydraulic control lines and electric conductors. Hydraulic wet connects allow the downhole completion equipment to be re-integrated with the intelligent well control system at surface, once the ESP is back in place.

Flow scenarios, ESP sizing and speed control. The key to the successful marriage of intelligent well technology with ESP technology is an understanding of the mission profile for the completion design - that is, what range of inflow/outflow conditions are expected for the life of the intelligent well completion and for the typical run life of the ESP. In particular, the artificial lift system must have adequate turndown capability to cope with the closing in of one or more zones. This can be accomplished by selecting the appropriate pump design and variable speed control system for the most likely productivity scenarios given the probable selective inflow operating options.

Communication and control systems interface and integration. Maximum value of the synergy between intelligent wells and ESP technology will be realized with the full integration of the communication and control systems, and development of related petroleum engineering tools as well as production optimization software.

Putting theory into practice

BHP's Douglas Well D17 is a successful example of the application and benefits of real-time monitoring and inflow control at the reservoir in a well that is produced with the assistance of an ESP. The Douglas Field is a shallow, low pressure, under-saturated oil reservoir situated offshore in the Liverpool Bay area of the East Irish Sea west of Great Britain. The field is produced under a combination of natural aquifer support and water injection to maintain reservoir pressure and manage oil sweep efficiency. The oil producers are all completed with ESPs that provide the necessary artificial lift to obtain economic production rates. Trends in produced fluid water cut are very similar in all wells with the timing of water breakthrough and the current level of watercut being a function of the well's structural elevation and the cumulative oil produced. More than 6 years into the producing life of the field, water cuts have reached levels in excess of 80% in some wells. Limitations on handling water at surface have resulted in the need for downhole water management to maximize oil production, optimize oil recovery and add project value.
The data show that any water management scheme must be capable of isolating water production from the middle or upper reservoir intervals, while allowing continued production from the other zones. Based on these studies and data, the completion for the D17 well was designed to allow selective isolation of the major reservoir zones and also to allow zones to be returned to production.

D17 completion design

The D17 completion was designed with several objectives in mind: first, to provide a capability for water shutoff to optimize production from both individual wells and the total field; and second, to reduce well intervention costs. This objective was furthered by providing distributed temperature survey (DTS) data to monitor watercut development in each reservoir zone, reducing the need for interventions associated with production logging. The design also allowed for the replacement of the DTS optical fiber without significant intervention. In addition the well design allowed the upper ESP completion to be serviced while leaving the lower completion in place.

The capability to reopen closed zones at a later date is of value as watercut progressively increases in other zones or other wells. In addition, production water-cut performance has indicated that gravity separation occurs in the reservoir during long periods of shut-in. This phenomenon suggests there might be an added benefit from cycling high water producing intervals.

The D17 multizone completion, as depicted by the schematic in Figure 1, was designed with isolation packers between each zone and remotely actuated interval control valves to shut off production from high watercut intervals. For the purpose of servicing the ESP, the upper completion can be separated from the lower completion by means of an on/off disconnect sub.

D17 Performance

The D17 completion was successfully installed in December, 2000. After 1 year of production, watercuts reached 82%. In line with other wells in the field, the upper zone was suspected of producing at the highest watercut, so it was isolated by closing the interval control valve. The operation was safe, quick and trouble free, and resulted in less than 4 hours lost production. Production rates before and after closure clearly demonstrate the increased production rate achieved by closure of the interval control valve. Inflow performance was reduced due to the elimination of production from the upper zone (Table 1). However, the reduction in watercut due to closure of the interval control valve increased oil production by approximately 1200 STB/D. The watercut stabilized at 70-72% compared to 79-82% before the sleeve was closed. In addition, the pump operating frequency was reduced from 60Hz to 50Hz as a result of the reduced loading, with a reduction in pump wear as a result.

The closure of the interval control valve also resulted in an increase in reserves, as illustrated by the decline curve plot in Figure 2. The shift in the curve indicates that use of smart well technology on D17 is expected to increase reserves by at least 800,000 STB (from 3.2 to 4.0 MMSTB). The performance of Douglas well D17 clearly demonstrates the technical and economic benefit of intelligent well technologies in combination with ESPs. There will probably be further gains from water shutoffs achieved through closing the other interval control valves, as well as the future benefit of re-opening the upper sleeve once gravity segregation has reduced the interval watercut.

Acknowledgements

The authors wish to thank the management of BHPBilliton Petroleum, Douglas Field partners Agip and WellDynamics International Ltd. for their permission to publish this paper.