Wells – Processes – Producing the well
Reexamination Certificate
2000-06-01
2002-09-24
Tsay, Frank (Department: 3672)
Wells
Processes
Producing the well
C166S105000, C417S423600
Reexamination Certificate
active
06454010
ABSTRACT:
FIELD OF INVENTION
This invention relates generally to the field of well production apparatus such as used, for example, in down-hole pumping systems in wells. It also relates to pumping apparatus and methods for use of that apparatus.
BACKGROUND OF THE INVENTION
Specific challenges arise in oil production when it is desired to extract heavy, sandy, gaseous or corrosive high temperature oil and water slurries from underground wells. These slurries to be pumped range over the breadth of fluid rheology from highly viscous, heavy, cold crude to hot thermal fluids. Recent technological advances have permitted wells to be sunk vertically, and then to continue horizontally into an oil producing zone. Thus wells can be drilled vertically, on a slant, or horizontally. To date, although equipment is available to drill these wells, at present there is a need for a relatively efficient, and reasonably economical means to extract slurries from wells of these types.
In particular, it would be desirable to have a type of pump that would permit relatively efficient extraction of oil slurries from underground well bores that include horizontal and steam assisted gravity drainage (SAGD) or non-thermal conventional wells. In one SAGD, process twin horizontal wells are drilled in parallel, one somewhat above the other. Steam is injected into the upper bore. This encourages oil from the adjacent region of the oil bearing formation to drain toward the lower bore. The production fluids drawn from the lower bore can then be pumped from the lower bore to the surface.
It is advantageous to match the pumping draw down of the lower bore to the rate of steam injection used in the upper bore. This will depend on the nature of the oil bearing formation, the viscosity of the oil and so on. If the rates can be matched to achieve a relative balance, the amount of steam pressure required can be reduced, thus reducing the power of the steam injection system required, and resulting in a more economical process.
Pumping the production oil or slurry from the lower horizontal bore presents a number of challenges. An artificial lift, or pumping, system must be able to operate even when the “liquid” to be pumped is rather abrasive. For example, some design criteria are based on slurries that may contain typically 3% by weight, and for short periods as much as 30% by weight, of abrasives, such as sand The pumping technology must be capable of handling a high volume of formation solids in the presence of high gas oil ratios (GOR). The system may well be called upon to handle slugs of hydrocarbon gas and steam created by flashing of water into vapour. On occasion the system may run dry for periods of time. As such, it is desirable that the system be capable of processing gases, and of running “dry”. It is also desirable that a pump, and associated tubing, be able to operate to a depth of 1000 M below well-head, or more, with an allowance of 100 psi as the minimum flow-line input pressure. It is also desirable that the equipment be able to operate in chemically aggressive conditions where pH is +/−10.
Further still, it would be advantageous to be able to cope with a large range of viscosities—from thick, viscous fluids to water, and at relatively high temperatures. The chosen equipment should be operable in both vertical and horizontal well bores.
Another requirement is the ability to pump all of the available fluid from the well bore. To that end it is advantageous to be able to operate the pump as far as possible in depth into a horizontal section. The system needs to be able to operate at high volume capacities, i.e., high volumetric flow rates, and to operate reasonably well under saturated steam conditions while processing hydrocarbon gases. As far as the inventors are aware, there is at present no artificial lifting equipment that addresses these problems in a fully satisfactory manner. It would be desirable to have a relatively efficient high temperature, high volume pumping system that can accommodate a large range of production requirements, with the capability of being installed into, and operating from, the horizontal section of a well bore.
Other artificial lift systems have been tried. For example, one known type of pump is referred to as a “Pump Jack”. It employs sucker rod pumping with a down-hole plunger pump. This is a reciprocating beam pumping system that includes a surface unit (a gearbox, Pittman arms, a walking beam, a horsehead and a bridle) that causes a rod string to reciprocate, thereby driving a down-hole plunger pump.
Pump jack systems have a number of disadvantages. First, it is difficult to operate a down-hole reciprocating rod pump in a horizontal section because of the reliance on gravity to exert a downward force on the pump plunger. Further, a horizontal application may tend to cause increased pump wear due to curvature in the pump barrel (to get to the horizontal section) and increased sucker rod and tubing wear. Second, down-hole pumps are susceptible to damage from sand, high temperature operation, and other contaminants. Third, plunger pumps are prone to gas lock. Fourth, the downward stroke of the pump rod, being governed by gravity, is subject to “rod float”. That is, as the length of the rod increases, the rod itself has sufficient resiliency, and play, that the motion transmitted from the surface is not accurately copied at the plunger—it may be out of phase, damped, or otherwise degraded so that much pumping effort is wasted. Fifth, pump jacks tend to require relatively extensive surface site preparation. Horizontal units tend to require larger than normal pump units because of the need to activate (i.e., operate) the rod string around the bend of the “build section” as well as to lift the weight of the rod string.
Another type of pump is the progressive cavity pump, or screw pump. In this type of pump a single helical rotor, usually a hard chrome screw, rotates within a double helical synthetic stator that is bonded within a steel tube. Progressive cavity pumps also have disadvantages: First, they tend not to operate well, if at all, at high temperatures. It appears that the maximum temperature for continuous operation in a well bore is about 180 F. (80 C.). It is desirable that the pump be able to operate over a range of −30 to 350 C. (−20 to 650 F.), and that the pump be able to remain in place during steam injection. Second, progressive cavity pumps tend not to operate well “dry”. It is desirable to be able to purge hydrocarbon gases, or steam created by flashing water into vapour. As far as the present inventors are aware, progressive cavity pumps have not been capable of operation in high GOR conditions. Further, the synthetic stator material of some known pumps appears not to be suitable for operation with aromatic oils. Due to the design of the screws, and their friction fit, progressive cavity pumps tend to have little, if any, ability to generate high pressures, thereby restricting their use to relatively shallow wells. In addition, progressive cavity pumps tend to be prone to wear between the rotor and the stator, and tend to have relatively short service run lives between overhauls. Progressive cavity pumps do not appear to provide high operational efficiency.
Electric submersible pumps (ESP) include a down-hole electric motor that rotates an impeller (or impellers) in the pump, thereby generating pressure to urge the fluid up the tubing to the surface. Electric submersible pumps tend to operate at high rotational speeds, and tend to be adversely affected by inflow viscosity limitations. They tend not to be suitable for use in heavy oil applications. Electric submersible pumps tend to be susceptible to contaminants. Electric submersible pumps are not, as far as the inventors are aware, positive displacement pumps, and consequently are subject to slippage and a corresponding decrease in efficiency. The use of electric submersible pumps is limited by horsepower and temperature restrictions.
Jet pumps typically employ a high pressure surface pump
Morcom Gary
Thomas Wayne
Blake Cassels & Graydon LLP
Pan Canadian Petroleum Limited
Tsay Frank
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