Wells – Processes – Operating valve – closure – or changeable restrictor in a well
Reexamination Certificate
2000-02-14
2002-10-29
Bagnell, David (Department: 3672)
Wells
Processes
Operating valve, closure, or changeable restrictor in a well
C166S319000, C166S053000, C166S072000
Reexamination Certificate
active
06470970
ABSTRACT:
BACKGROUND OF THE INVENTION
The present invention relates to a system for controlling the production of hydrocarbons and other fluids from downhole wells. More particularly, the invention relates to a system for providing hydraulic control signals and power through multiple hydraulic lines by controlling power distribution to selective hydraulic lines.
Various tools and tool systems have been developed to control, select or regulate the production of hydrocarbon fluids and other fluids produced downhole from subterranean wells. Downhole well tools such as sliding sleeves, sliding windows, interval control lines, safety valves, lubricator valves, and gas lift valves are representative examples of control tools positioned downhole in wells.
Sliding sleeves and similar devices can be placed in isolated sections of the wellbore to control fluid flow from such wellbore section. Multiple sliding sleeves and interval control valves (ICVs) can be placed in different isolated sections within production tubing to jointly control fluid flow within the particular production tubing section, and to commingle the various fluids within the common production tubing interior. This production method is known as “comingling” or “coproduction”. Reverse circulation of fluids through the production of tubing, known as “injection splitting”, is performed by pumping a production chemical or other fluid downwardly into the production tubing and through different production tubing sections.
Wellbore tool actuators generally comprise short term or long term devices. Short term devices include one shot tools and tool having limited operating cycles. Long term devices can use hydraulically operated mechanical mechanisms performing over multiple cycles. Actuation signals are provided through mechanical, direct pressure, pressure pulsing, electrical, electromagnetic, acoustic, and other mechanisms. The control mechanism may involve simple mechanics, fluid logic controls, timers, or electronics. Motive power to actuated the tools can be provided through springs, differential pressure, hydrostatic pressure, or locally generated power.
Long term devices provide virtually unlimited operating cycles and are designed for operation through the well producing life. These devices are particularly useful in subsea wells and deep horizontal wells. One type of long term safety valve device closes the tubing interior with spring powered force when the hydraulic line pressure is lost. Other electrical and hydraulic combination powered systems have been developed for downhole use, and sensors can verify proper operation of tool components.
Interval control valve (ICV) activation is typically accomplished with mechanical techniques such as a shifting tool deployed from the well surface on a workstring or coiled tubing. This technique is expensive and inefficient because the surface controlled rigs may be unavailable, advance logistical planning is required, and hydrocarbon production is lost during operation of the shifting tool. Alternatively, electrical and hydraulic umbilical lines have been used to remotely control one or more ICVs without reentry into the wellbore.
Control for one downhole tool can be hydraulically accomplished by connecting a single hydraulic line to a tool such as an ICV or a lubricator valve, and by discharging hydraulic fluid from the line end into the wellbore. This technique has several limitations as the hydraulic fluid exits the wellbore because of differential pressures between the hydraulic line and the wellbore. Time delays in the propagation of pressure through several kilometers of thin hydraulic line, compressibility of the hydraulic fluid, and line friction impedes efficient hydraulic fluid operation. Additionally, the setting depths are limited by the maximum pressure that a pressure relief valve can hold between the differential pressure between the control line pressure and the production tubing when the system is at rest. These limitations restrict single line hydraulics to relatively low differential pressure applications such as lubricator valves and ESP sliding sleeves. Further, discharge of hydraulic fluid into the wellbore comprises an environmental discharge and risks backflow and particulate contamination into the hydraulic system. To avoid such contamination and corrosion problems, a closed loop hydraulic system would be preferred over hydraulic fluid discharge valves, however closed loop systems require at least one additional hydraulic line in the narrow wellbore confines.
Various proposals have been made for multiple tool operation through a single hydraulic line. U.S. Pat. No. 4,660,647 to Richart (1987) disclosed a system for changing downhole flow paths by providing different plug assemblies suitable for insertion within a side pocket mandrel downhole in the wellbore. In U.S. Pat. No. 4,796,699 to Upchurch (1989), an electronic downhole controller received pulsed signals for operating multiple well tools. In U.S. Pat. No. 4,942,926 to Lessi (1990), solenoid valves directed hydraulic fluid pressure from a single line to control different operations, and a spring return device facilitated return of the components to the original position. A second hydraulic line provided dual operation of the same tool function by controlling hydraulic fluid flow in different directions. Similarly, U.S. Pat. No. 4,945,995 to Thulance et al. (1990) disclosed an electrically operated solenoid valve for selectively controlling operation of a hydraulic line for opening downhole wellbore valves.
Other downhole well tools use two hydraulic lines to control a single tool. In U.S. Pat. No. 3,906,726 to Jameson (1975), a manual control disable valve and a manual choke control valve controlled the flow of hydraulic fluid on either side of a piston head. In U.S. Pat. No. 4,197,879 to Young (1980), and in U.S. Pat. No. 4,368,871 to Young (1983), two hydraulic hoses controlled from a vessel were selectively pressurized to open and close a lubricator valve during well test operations. A separate control fluid was directed by each hydraulic hose so that one fluid pressure opened the valve and a different fluid pressure closed the valve. In U.S. Pat. No. 4,476,933 to Brooks (1984), a piston shoulder functioned as a double acting piston in a lubricator valve, and two separate control lines were connected to conduits and to conventional fittings to provide high or low pressures in chambers on opposite sides of the piston shoulder. In U.S. Pat. No. 4,522,370 to Noack et al. (1985), a combined lubricator and retainer valve was operable with first and second pressure fluids and pressure responsive members, and two control lines provided two hydraulic fluid pressures to the control valve. Multiple hydraulic line techniques are typically inefficient because the volume of hydraulic lines required for multiple downhole tools cannot fit through packers and wellheads.
To avoid multiple hydraulic lines, other techniques have attempted to establish an operating sequence for well tools. In U.S. Pat. No. 5,065,825 to Bardin et al. (1991), a solenoid valve was operated in response to a predetermined sequence to move fluid from one position to another. A check valve permitted discharge of oil into a reservoir to replenish the reservoir oil pressure. Other systems use electronic controllers downhole in the wellbore, however electronics are susceptible to temperature induced deterioration and other reliability problems.
Mechanical shifting devices have limitations in deep and horizontal wellbores. Frictional loads on the tool can encumber tool operation. The tool string weight in horizontal wells decentralizes the tool and reduces the ability of the tool to maintain an optimal position within the wellbore. A lack of surface feedback prevents confirmation of tool operation such as sleeve movement and latching. High friction loads can indicate tensile or compressive load indicators, leading to inaccurate assumptions regarding proper tool deployment.
Downhole hydraulic lines in a wellbore can extend for thousands of feet int
Bouldin Brett
Purkis Dan
Rubbo Richard
Bagnell David
Herman Paul I.
Imwalle William M.
Smith Marlin R.
Stephenson Daniel
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