The present invention relates generally to the oil and gas industry and in particular to oil well production utilizing reciprocating pumps.
Oil wells are produced using a variety of methods ranging from self-production, where the formation pressure is high enough to cause the oil to flow up the wellbore, to various forms of artificial lift, where the formation pressure is insufficient and cannot lift the hydrocarbon fluid up the wellbore. The most common artificial form used in the oil industry is the reciprocating pump.
The standard industry reciprocating pump consists of a prime mover that is positioned at the surface, and a pumping barrel that is positioned within the production tubing at or near the bottom of the wellbore. The wellbore is lined with steel pipe called casing.
The production tubing is concentric within the casing and is the conduit through which produced fluids are sent to the surface. The area between the production tubing and the casing (wellbore) is called the annulus. The production tubing is generally suspended from the surface and “rests” against the casing forming a seal at the surface. The steel casing has a series of holes or perforations punched in the casing where the producing formation is found, that allow the formation fluid to enter the annulus.
The production tubing has a “seating nipple” at the formation end of the tubing into which the pump will seat. The tubing may be terminated in a rounded end with a series of perforations that act as a course filter and allow the formation fluid to enter the production tubing. The seating nipple has a reduced inside diameter when compared to the tubing that forms a hold-down into which the pump barrel locks or is held-down. The barrel is locked into place within the production tubing so that a seal is formed between the pump and the production tubing. This seal keeps the produced fluid from re-entering the formation.
There are two ways by which the pump at the end of the production tubing is driven (reciprocated). The first uses the industry standard sucker rods, and the second uses a new technique that employs a wire cable. Both the cable and the sucker rod string terminate at the pump and at the prime mover. A cable driven pump will employ the same (or similar) pull rod at the downhole end plus a set of sinker (weighted) rods.
After a period of time, the downhole pump must be serviced, and the cable or sucker rod string is employed to lift the pump up and out of the well. The pump is pulled up to the surface within the production tubing. A certain amount of force is required to “pop” the pump loose from the hold-down at the bottom of the production tubing.
Very often the force to “pop” the pump loose is excessive and is caused by build-up of “flower sand” around and about the pump at the hold-down. Flower sand is entrained in the produced fluid and tends to precipitate from the fluid as it passes up the production tubing. The sand then falls to the bottom of the tubing and “packs” around the hold-down thereby substantially increasing the force required to “pop” the pump loose from the hold-down.
Furthermore because there are series of ball and check valves within the pump (the associated standing valve), the initial force required to “pop” the pump loose must also pull against the hydrostatic head contained within the production tubing which thereby increases the required unseating force. As the depth of the well increases, the weight of the produced fluid increases: essentially, the weight of produced fluid is related to the hydrostatic head contained within the production tubing. As soon as the pump pops loose the hydrostatic head will reduce because the fluid in the production tubing will U-tube within the annulus and tubing.
There have been instances when the sucker rod string breaks in two, due to the high force required to “pop” the pump loose, thus leaving the pump in the tubing. At this point, the well operator must pull the production tubing to retrieve the pump: an expensive operation. In the case of the wire cable driven pump, the wire cable is often limited in pulling force, and the tubing would have to be pulled.
Among some of the prior art attempting to solve the problem caused by sand buildup and hydrostatic head are: Hall (U.S. Pat. Nos. 5,018,581 and 4,103,739), Hix (U.S. Pat. No. 3,994,338), Howe (U.S. Pat. No. 3,150,605), Owen (U.S. Pat. No. 4,909,326), Sonderberg (U.S. Pat. No. 4,645,007) and Sutliff et al. (U.S. Pat. No. 4,273,520. Hall envisions an auxiliary valve-like device that is placed at some point (mid) in the pump barrel as the barrel is being made up. This valve opens during withdrawal of the pump if the pulling force exceeds a predetermined force caused by sand buildup. If the device does not open, then it is assumed there is no sand buildup and the device may be re-inserted into the wellbore.
Hix describes a frangible rupture disk that is placed between the standing valve and the hold down in a barrel pump assembly. The rupture disk is activated by increasing the pressure in the standing column of produced fluid; thus, some sort of pumping device is required at the surface. The device also incorporates a left hand thread that allows the pump to be unscrewed if the rupture disk fails to rupture. This is a one shot device.
Howe illustrates a complex ball and seat device that is placed at the pump head and drains the tubing fluid above and around the pump whenever the pump is raised out of the tubing. It does not release the hydrostatic head in the tubing.
Owen portrays a tubing unloader that is placed in the tubing itself As the tubing is pulled upward the unloader opens and allows the entrapped fluid to drain back into the annulus.
Sonderberg also describes a tubing unloader that is placed in the tubing like the device of Owens. However, the Sonderberg device uses an increase in fluid pressure to open the device. Again this implies some sort of pump source at the surface. Finally, Sutliff et al. disclose a deep well pump that incorporates a drain valve that allows the pump to drain within the tubing so that the pump is basically pulled dry from the well.
The industry has attempted to solve the flower sand problem by using a bottom discharge valve mounted below the pump and above the lower check valve (stationary valve), that allows back flow of produced fluid within the production tubing, thereby causing a swirl that hopefully picks up the sand about the hold-down reducing the force required to “pop” the pump loose. The valve which is really a second check valve that, on the downstroke, allows flow of produced fluid from the pump barrel into the tubing (Note the valve is spring loaded so that downward force is required to force the produced fluid backwards into the tubing.) The by-passed flow causes a swirl around the bottom section of the pump and up into the tubing. The device helps but, because it is located away from the hold-down and because the backflow fluid still remains within the tubing, it is somewhat inefficient when washing sand. The force required to push the fluid through the bottom discharge valve is supplied by the weight of the sucker rod string (coupled through the pull rod). The required force (“weight”) is unavailable in a cable driven pump. (“One cannot push on a rope.”) The industry has not resolved the hydrostatic head problem.
Furthermore, the industry must inject corrosion control chemicals into and about the pump. The dead flow area between the pump barrel and the production tubing presents a problem because there is no known method (or apparatus) to place (spot) chemicals in this area. Current methods dump chemical down the annulus or down the production tubing where the chemical can migrate throughout the system where fluid flow is occurring. Since there is no flow between the barrel and the production tubing, corrosion control chemicals cannot currently be spotted in that area.
Thus, there remains a need for a device that will wash the flower sand buildup from about the hold-down within the production tubing and/or reduce hydrostatic head, thereby reducing the force required to “pop” a pump loose for servicing. The need is even higher for cable driven pumps. There also remains a need for equipment and a method for spotting chemicals in a well.