Deep-Set Subsurface Safety Valve Actuated by Jet-Pump Differential Pressure
- J.A. Barnes (Marathon Oil Co.) | P.M. Snider (Marathon Oil Co.) | C. Swafford (BST Lift Co.)
- Document ID
- Society of Petroleum Engineers
- SPE Production Engineering
- Publication Date
- November 1990
- Document Type
- Journal Paper
- 365 - 369
- 1990. Society of Petroleum Engineers
- 4.1.6 Compressors, Engines and Turbines, 5.4.1 Waterflooding, 2.2.2 Perforating, 4.5.7 Controls and Umbilicals, 3 Production and Well Operations, 6.5.2 Water use, produced water discharge and disposal, 3.1.6 Gas Lift, 2 Well Completion, 3.1 Artificial Lift Systems, 3.1.3 Hydraulic and Jet Pumps
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Summary. Offshore oil and gas production often requires placement of a subsurface safety valve (SSSV) in the tubing string to pre-vent uncontrolled flow from the well. In many wells, this requirement can preclude maximizing production through the use of high-capacity artificial-lift techniques, such as jet pumping. An innovative approach was developed and field-tested in the McArthur River field, Cook Inlet, AK, to overcome problems associated with incorporating SSSV's in jet-pump completions. This method provides surface control over the valve and does not restrict production rate. In this approach, an SSSSV was placed in the tubing string below a jet pump at 9,800-ft [3000-m] true vertical depth (TVD) to satisfy safety requirements. The system design allows the SSSV to be controlled from the surface with no dependence on hydraulic control lines to surface. The system was later improved to allow the SSSV to be reverse-circulated from the well for repairs or remedial activities.
In 1984, alternatives to gas lift were evaluated for the offshore McArthur River field. Of particular interest was jet pumping, which appeared to be an attractive alternative for wells with a high PI. For several wells, jet pumping provided the opportunity to produce at rates greater than those possible with gas lift. To evaluate the feasibility of alternative lift techniques, Well D-4RD was selected for recompletion from gas lift to jet pumping. Because Well D-4RD is located offshore and has sufficient reservoir pressure to flow to surface, incorporating an SSSV into the completion was necessary to prevent uncontrolled flow to surface. Previous authors have reviewed the physical principles, operating characteristics, and design of jet-pump completions. It is necessary here, however, to review those fundamentals of pump performance on which SSSV control is based. In the casing-free completion selected, high-pressure power fluid is pumped down the tubing string. The power fluid is then mixed with produced fluid in the jet pump, transferring energy to the produced fluid. The combined stream is then produced up the annulus. A safety valve located below the jet pump was chosen as the most reliable method to meet safety regulations. To allow the safety valve to be surface-controlled, without dependence on hydraulic-control-line integrity, the safety valve is actuated by the differential pressure generated across the jet pump.
McArthur River Field Historical Development
Discovered in 1965, the McArthur River field was subsequently developed from three offshore platforms. Commercial production began in late 1967. The primary producing horizon is the Hemlock reservoir, which at its crest is located at about 9,300-ft [2800-m] TVD. A water-injection program initiated in 1968 has maintained average reservoir pressure near original conditions. The field water cut has risen as a consequence of significant production and water injection, resulting in increased gas-lift requirements. In 1984, the need for increased artificial-lift capacity was evaluated, with particular emphasis toward alternative methods. This study indicated that, with few exceptions (most notably, wells with extremely high productivity located in areas of higher-than-average reservoir pressure), gas lift would remain the method of choice.
Well D-4RD History
Well D-4RD was dried in 1982 and completed with a typical Cook Inlet gas-lift completion (Fig. 1). Note that this well differs from many wells in that it was necessary to run 7-in. [180-mm] casing to surface after redrill operations. The 7-in. [180-mm] casing is notable in that it limits the maximum tubing size for this completion to 3 1/2 in. [90 mm]. The well produced at an initial rate of 2,200 BFPD [350 m3/d fluid]. This rate was greater than anticipated because of an extremely high PI of 1.5 BFPD/psi [34.6 m3/d fluid - MPa] compared with a field average of 1.0 BFPD/psi [23.1 m3/d fluid - MPa]. Further perforating in 1983 increased the PI to 2.0 BFPD/psi [46.1 m3/d fluid-MPa]. Additionally, the reservoir pressure was determined to be 4,255 psi [29 MPa], 1,055 psi [7 MPa] higher than the field average.
As a result of high productivity, high reservoir pressure, and increases in water cut following completion, it was not possible to gas lift this well from the bottom gas-lift valve with the existing gas-lift header pressure. Fig. 2 is the plot resulting from a gas-lift survey showing this well to be lifting from the 4th of 14 gas-lift valves, over-naming the lower 10 valves. The 3 1/2 -in. [90-mm] tubing in this well prevents a transfer to a lower valve. The friction-pressure drop makes it impossible to pass enough gas through a single valve to lower the flowing gradient sufficiently. Without additional gas-lift horsepower, in the form of a high-pressure booster compressor to increase header pressure, significant increases in this well's production rate were not possible. Because the majority of the other wells on the platform were known to be lifting at or near the bottom valve, the booster compressor was not warranted. An evaluation of artificial-lift methods in 1984 indicated that jet pumping would be an attractive alternative to increase the production rate of Well D-4RD. Sufficient excess waterflood capacity existed on Platform Dolly Varden to provide power fluid to test jet pumping in one well. The power fluid would be pumped down the tubing string at 4,000-psi [28-MPa] surface pressure through a jet pump, and produced commingled with formation fluids up the tubing/casing annulus. The 7-in. [180-mm] casing run to surface in Well D-4RD proved beneficial to this @ of completion because of its new condition and higher burst-pressure rating than the 9 5/8-in. [240-mm] casing string. No off-the-shelf technology existed to meet the requirement for an SSSV operating under these conditions.
Several options were considered before plans were finalized to use the differential pressure created across the jet pump to control the SSSV. These alternatives fall into two general categories and apply under conditions other than those in Well D-4RD.
The first alternative was the use of safety valves located near the surface just below the mudline, or at about 300-ft [90-m] TVD in the McArthur River field. Conventional offshore completions require safety valves to control produced-fluid flow. To prevent back-flow through the jet pump, a safety valve is also required on the power-fluid injection string. Safety valves set at this shallow depth are routinely controlled by hydraulic lines run to surface. To minimize friction-pressure drop in this type for completion, production would flow up the annulus until it reached a packer set below the mudline. The packer would then direct the flow through either an annular or a short-string safety valve. As a result of the 7-in. [180-mm] casing ID, the tubing/annular (Fig. 3) or dual- tubing safety-valve (Fig. 4) completions result in severe flow restrictions.
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