A major company took its time to select the most appropriate intelligent completion system for the job.

Well economics put more pressure than ever on decision-making during well design. Intelligent completions recently have become a viable option, but concerns over increased subsurface complexity often have driven design criteria back to a more conventional level. This conflicts with the overall system goal, which is to optimize production of desired hydrocarbons and limit production of unwanted well fluids. Effective completion design can resolve the difficulties inherent in commingled and noncommingled production.
One oil and gas company enacted a policy involving oilfield services personnel early in the project to ensure the appropriate front-end engineering and well design took into account the greatest number of possible scenarios to ensure the best success for the well. This review included candidate selection; overall well design, including tubing size and placement of individual components; and valve configuration and sizing. The company put this policy into place because of concerns over early gas breakthrough in a North Sea oil field.
The well
Since coming on production in December 1988, the field has produced more than 1.5 billion bbl of oil, including more than 500,000 b/d during its peak in the mid-1990s. Before deciding to complete the well as an intelligent completion, the company had completed five wells with remotely operating valves, allowing for zonal isolation and production control from two or more zones. The well has a horizontal section of about 7,219 ft (2,200 m) and a vertical drop of about 656 ft (200 m). The total vertical depth of the top sand is close to the mean position of the gas-oil contact; that of the lower sand is near the presumed position of the water-oil contact. The upper sand was expected to assist in the lift performance, while the middle and lower sands were expected to be the principal producers. The incentives for commingling production included the use of limited well slots on the platform to tap multiple targets, the acceleration of production relative to sequential production and the use of in-situ gas to assist lift under high wellhead pressures.
Despite the valve's main requirement of simple hydraulic operation, the team considered many alternatives during the conceptual design phase. This ensured that the selected design was practical, robust and fit for purpose. For example, the company reviewed several options for valve closure assist: nitrogen, spring, balance control line and reservoir pressure. It chose nitrogen assist based on its previous subsurface safety valve success record; the nitrogen-assist technology also enables the tool to operate at virtually any depth.
The tubing-retrievable hydraulic flow control valve was the most appropriate solution to provide remotely controlled flow adjustment from the reservoir. The valve uses one dedicated 0.25-in. control line to the surface to hydraulically control the tool's choke section. The flow control device consists of a choke section and actuator section driven by an indexer pin and ratchet system. An indexer controls the choke position by securing the choke in any of 11 incremental positions, including closed.
From the closed position, application of cycled hydraulic pressure from the surface against the nitrogen-charged closing force indexes the choke to the first position. Each subsequent pressure cycle indexes the choke to the next position, increasing the effective choke size until the fully open position is reached. When it is fully open, the choke area is equivalent to the tubing bore flow area, allowing full flow with no restriction. The hydraulic pressure cycle following the open position returns the choke to the closed position. The choke and indexer were designed with flexibility in mind. For example, the number of incremental positions can be reduced, the choke sizes can be altered to fit a particular reservoir's requirements, and it can be configured to close incrementally rather than open incrementally. This flexibility allows the system to be configured specifically to the requirements of the reservoir over the lifetime of the well.
Following design selection, the team subjected the flow control device to extensive qualification testing at the Schlumberger Reservoir Completions Center in Rosharon, Texas, near Houston.
The intelligent completion provided isolation between three fluvial sand channels, using a new packer that allows bypass of electric and hydraulic conduits, necessary to monitor and operate the flow control valves. The packers are retrievable, hydraulically set seal bore packers based on field-proven sand-control packers. Other issues successfully resolved during the design process included tubing movement calculations, intervention requirements, control line protection and personnel training.
Installation of the completion equipment took place in 14 days, despite a budgeted 20 days. The initial upfront engineering and implementation team ensured all contingencies were evaluated thoroughly; the result was a 30% savings on rig time.
Following installation, the company tested each producing zone individually to determine production potential. After testing, it opened the upper and lower zones with both valves in the full open position. After the first few days of production, indications of gas breakthrough appeared. The upper valve was choked back to reduce the gas-to-oil ratio (GOR). After 4 months of production, the well was producing more than 17,000 b/d. Still, the well needed further adjustments. In January 2001, the team shut in the well and tested each zone again to monitor seawater breakthrough and assess the subsequent need for scale squeeze to prevent scale precipitation. The upper zone was producing predominantly gas, the lower mainly water and the middle zone was relatively unaffected by water and gas production.
Optimization of valve positions yielded positive results with about 160 flow control valve position changes since the installation.
During the first year of operation, the company encountered no operational difficulties.
The operation's success was a direct result of cooperation between disparate groups of people and the sound design of the valves and packers. Without that cooperation, the well and equipment easily could have been designed with a much lower output yet still successful compared to a conventional completion.
Increased incremental production was the installation's main objective. During its first 4 months, the well produced an additional 1 million bbl of oil, according to an analysis that compared a conventional well with an intelligent one. The ability to operate the
in-situ valves remotely helped minimize intervention activities, thereby decreasing the effective risk to facilities and personnel.
Additional wells with similar design considerations have benefited and continue to benefit from these initial designs. Seven wells using the same approach have been completed since - each with two to three zones - and two more are planned.
The multiple position choke
A multiple position choke provides several advantages:
• Commingling is possible by the downhole control of the pressure differential between formation and wellbore (drawdown) at the various layers. The choke's position can be modified to vary the flow rate from the individual zones, thereby reducing any cross-flow and frictional pressure losses and optimizing the commingled production.
• Changing the choke settings and optimizing oil production from each layer controls GOR and water cut.
• Reducing the drawdown pressures
at selective points in the layers controls water and gas coning by the downhole chokes.
• Each valve has 11 positions, including one that is fully closed and one that is fully open (equivalent to the tubing flow area). A key design consideration, critical to the success of any given completion, is that the remaining nine positions can be designed individually to match the optimum choke settings for the life of the zone or the well, based on specific reservoir modeling and analysis performed before the completion takes place. Different size chokes and inserts allow even more operational efficiency and flexibility.
Valve operation
The valve uses a single, dedicated 0.25-in. hydraulic control line to connect the valve to the surface and control the tool's choke section. Hydraulic pressure cycles shift the flow control valve from the fully open position to the fully closed position in increments determined by the operator. If necessary, the operator can shift the direction of the control choke at any time by increasing the control line pressure to a predetermined threshold.
In addition to controlling the GOR and water cut even when they change over time, changing the choke position also can optimize commingled production by modifying flow rate from individual zones and reducing cross-flow and frictional pressure losses.
The valve's actuator sections use mechanical ratchets to reduce the piston stroke to a small length. Even though the valve discussed uses nitrogen assist, other types of assist can be used in differing scenarios.
The focus for the future is on designing intelligent completions that can operate reliably for lengthy periods under increasingly extreme environments. For example, the spring-assist flow control valve was designed for the highest reliability under harsh conditions. It uses a patented seal design with a spring-energized protective sleeve, so the seals are always protected, including during equalization. The nonelastomer seals are in constant compression in any position, and the piston design is based on field-proven safety valve hydraulic technology. The valve also incorporates a lower seal bore and optional landing nipple.
What the future holds
The adoption of new technology is critical to improvements in oil and gas production efficiencies. This well demonstrated that effective collaboration with service companies, coupled with technical leadership and communication, has given rise to a superior level of performance. Future developments will include the coupling of subsurface gauges and distributed fiber-optic sensing systems to actuation devices in the wellbore. Further developments of the flow control devices to enable a higher resolution of flow control will be necessary. These systems are undergoing extended field tests in the United Kingdom and United States. These electric systems, which provide infinite flow adjustment from fully open to fully closed, give even higher resolution of flow control than with the multiposition hydraulically controlled valves. Schlumberger has installed 46 valves in 28 installations with an excellent track record of 46 valve years, with only one valve malfunctioning during the 4 years of successful deployment.

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