PEH:Hydraulic Pumping in Oil Wells - PetroWiki - SPE

Surface Pumps

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Hydraulic pumping systems have evolved toward the use of relatively high pressures and low flow rates to reduce friction losses and to increase the lift capability and efficiency of the system. Surface operating pressures are generally between 2,000 and 4,000 psi, with the higher pressures used in deeper wells, and power-fluid rates may range from a few hundred to more than 3,000 B/D. While some surface multistage centrifugal pumps are rated to this pressure range, they are generally quite inefficient at the modest flow rates associated with single-well applications. Multistage centrifugals can be used effectively when multiple wells are pumped from a central location. The surface pump for a single well or for just a few wells must be a high-head and low-specific-speed pump. Wide experience in the overall pumping industry has led to the use of positive-displacement pumps for this type of application, and triplex or quintuplex pumps, driven by gas engines or electric motors, power the vast majority of hydraulic pump installations. See Fig. 14.17.

• Fig. 14.17-Horizontal plunger pumps.

Multiplex pumps consist of a power end and a fluid end. The power end houses a crankshaft in a crankcase. The connecting rods are similar to those in internal combustion engines, but connect to crossheads instead of pistons. The fluid end houses individual plungers, each with intake and discharge check valves usually spring loaded, and is attached to the power end by the spacer block, which houses the intermediate rods and provides a working space for access to the plunger system. Most units being installed in the oil field are of the horizontal configuration, which minimizes contamination of the crankcase oil with leakage from the fluid end. Vertical installations are still found, however, particularly with oil as the pumped fluid or when space is at a premium, as in townsite leases.

Multiplex pumps applied to hydraulic pumping usually have stroke lengths from 2 to 7 in. and plunger diameters between 1 and 2½ in. The larger plungers provide higher flow rates but are generally rated at lower maximum pressure because of crankshaft loading limitations. The larger plungers provide higher flow rates, but are generally rated at lower maximum pressure because of crankshaft loading limitations. The normal maximum rating of multiplexes for continuous duty in hydraulic pumping applications is 5,000 psi, with lower ratings for the larger plungers, but applications above 4,000 psi are uncommon. Multiplex pumps are run at low speed to minimize vibration and wear and to avoid dynamic problems with the spring-loaded intake and discharge valves. Most applications fall between 200 and 450 rev/min, and because this is below the speeds of gas engines or electric motors, some form of speed reduction is usually required. Belt drives are found on some units, although gear reduction is more common while gear-reduction units are integral to some multiplexes and separate on others. A variety of reduction ratios are offered for each series of pumps. Because a positive-displacement pump has an essentially constant discharge flow rate for a given prime-mover speed, bypass of excess fluid normally is used to match a particular pressure and flow demand. Another option that has been used successfully is to drive the multiplex pump through a four-speed transmission, which greatly enhances the flexibility of the system. This allows much closer tailoring of the triplex output to the demand, thereby pumping at reduced speed when needed, which also tends to increase the life of such components as the packing and valving.

Each plunger pumps individually from a common intake manifold into a common discharge, and because discharge occurs only on the upstroke, there is some pulsation, for which pulsation dampers are commonly used.

Two types of plunger systems are in common use. For oil service, a simple and effective plunger-and-liner system is used that consists of a closely fitted metallic plunger inside a metallic liner. Sprayed metal coatings or other hard-facing means are often used to extend the life of the plunger and liner. When pumping water, the metal-to-metal system is not practical because the fit would have to be extremely close to keep leakage to an acceptable level. Galling and scoring are problems with close fits and the low lubricity of water, and to solve this problem, spring-loaded packing systems are used that do not require adjusting. The advent of high-strength aramid fibers for packing, in conjunction with other compounds to improve the friction characteristics, has resulted in a pronounced improvement in the ability of the pump to handle high-pressure water for extended periods of time. Water still presents a more severe challenge than oil, however, and water systems show much better life if operated at or below 3,500 psi.

Suction conditions are important to multiplex operation. Friction losses in piping, fluid end porting, and across the suction valving reduce the pressure available to fill the pumping chamber on the plunger downstroke, and if these losses are sufficiently great, cavitation may result. When pumping oil with dissolved gas, the reduction in pressure liberates free gas and causes knocking, so it is necessary to have a positive head on the suction side to overcome the friction losses. In addition, another phenomenon known as "acceleration head" must be considered. The flow in the suction piping must accelerate and decelerate a number of times for each crankshaft revolution. For the fluid (which has inertia) to follow the acceleration, energy must be supplied, which is then returned to the fluid on deceleration. The energy supplied during acceleration comes from a reduction in the pressure in the fluid, and if this drops too low, cavitation or gas liberation will result. The minimum suction head for the multiplex pump is then the sum of the friction losses and the acceleration head. Although the pump can draw a vacuum, this will flash gas and may tend to suck air across the valve or plunger packing. Manufacturers of multiplex pumps recommend appropriate suction charging pressures for their products, but it is worth noting that long, small-diameter suction lines increase the acceleration head loss and friction loss. It is therefore recommended for suction lines to be short and of large diameter, with no high spots to trap air or gas. Suction stabilizers or pulsation dampeners that tend to absorb the pulsations from the pump also reduce acceleration head, and users are encouraged to follow good piping practices in the installation of surface pumps.

In many cases, sufficient hydrostatic head is not available to provide the necessary suction pressure, and charge pumps are used to overcome this problem. Positive displacement pumps of the vane or crescent-gear type driven from the triplex have been used extensively, but they require a pressure-control valve to bypass excess fluid and match the multiplex displacement. Where electric power is available, centrifugal charge pumps have given excellent service. Centrifugal pumps generally need to run at speeds considerably above the multiplex speed, and so driving them from the multiplex presents problems, particularly with a gas engine drive where prime-mover speed variations cause significant variations in the charge-pump output pressure.

While good charging pressures are necessary to ensure proper loading and smooth operation, there are problems associated with very high charge pressures. These add to the crankshaft loading, and for charge pressures above about 250 psi, it is advisable to derate the maximum discharge pressure by one third of the charge pressure. High charge pressures also can adversely affect the lubrication of bearings, particularly in the crosshead wristpin. In addition, the mechanical efficiency of multiplex pumps is some 3 to 5% lower on the suction side compared to the discharge side. Consequently, the combination of a charge pump and multiplex pump is most efficient with low charging pressures and a high boost by the multiplex pump. The charging pressure should therefore be limited to that necessary to give complete filling of the multiplex pump with a moderate safety allowance for variations in the system parameters.

In some cases, it is desirable to inject corrosion inhibitors or lubricants into the multiplex suction, and fresh water is sometimes injected to dissolve high salt concentrations. In severe pumping applications with low-lubricity fluids, lubricating oil is sometimes injected or dripped onto the plungers in the spacer block area to improve plunger life. Injection pumps are often driven from the multiplex drive for these applications. A troubleshooting guide for multiplex pumps is given in Table 14.8.

• Table 14.8

Fluid Controls

Various types of valves are used to regulate and to distribute the power-fluid supply to one or more wellheads. Common to all free-pump systems is a four-way valve or wellhead control valve, which is mounted at the wellhead, as shown in Fig. 14.18. Its function is to provide for different modes of operation by shifting it to different positions. To circulate the pump into the hole, as shown in Fig. 14.15, power fluid is directed down the main tubing string. The power fluid begins to operate the pump once it is on bottom and seated on the standing valve. In the pump-out mode, power fluid is directed down the return tubing or casing annulus to unseat the pump and to circulate it to the surface. When the pump is on the surface, putting the valve in the bypass and bleed position permits the well to be bled down and the pump to be removed and replaced.

• Fig. 14.18-Wellhead control valve.

Most systems include a constant-pressure controller, as shown in Fig. 14.19, which maintains a discharge-pressure load on the multiplex pump by continuously bypassing the excess discharge fluid. It generally operates on the principle of an adjustable spring force on a piston-and-valve assembly that is pressure compensated. If the pressure rises on the high-pressure side, which is being controlled because of changing system loads, the pressure forces on the various areas within the valve will cause the valve to open and to bypass more fluid, restoring the high-pressure side to the preset condition. Jet pumps frequently are operated with a constant-pressure valve as the only surface control valve. The constant-pressure controller can be used to regulate the pressure on a manifold assembly serving multiple wells.


Reciprocating downhole pumps are usually regulated with a constant-flow control valve. The downhole unit can be maintained at a constant stroking rate if a constant volume of power fluid is supplied to it, and the constant-flow control valve is designed to provide a preset flow rate even if the downhole operating pressure fluctuated because of changing well conditions. Because this valve does not bypass fluid, it must be used with a constant-pressure controller on the higher-pressure or inlet side.

Control Manifolds

Hydraulic pumping systems have evolved toward the use of relatively high pressures and low flow rates to reduce friction losses and to increase the lift capability and efficiency of the system. Surface operating pressures are generally between 2,000 and 4,000 psi, with the higher pressures used in deeper wells, and power-fluid rates may range from a few hundred to more than 3,000 B/D. While some surface multistage centrifugal pumps are rated to this pressure range, they are generally quite inefficient at the modest flow rates associated with single-well applications. Multistage centrifugals can be used effectively when multiple wells are pumped from a central location. The surface pump for a single well or for just a few wells must be a high-head and low-specific-speed pump. Wide experience in the overall pumping industry has led to the use of positive-displacement pumps for this type of application, and triplex or quintuplex pumps, driven by gas engines or electric motors, power the vast majority of hydraulic pump installations. SeeMultiplex pumps consist of a power end and a fluid end. The power end houses a crankshaft in a crankcase. The connecting rods are similar to those in internal combustion engines, but connect to crossheads instead of pistons. The fluid end houses individual plungers, each with intake and discharge check valves usually spring loaded, and is attached to the power end by the spacer block, which houses the intermediate rods and provides a working space for access to the plunger system. Most units being installed in the oil field are of the horizontal configuration, which minimizes contamination of the crankcase oil with leakage from the fluid end. Vertical installations are still found, however, particularly with oil as the pumped fluid or when space is at a premium, as in townsite leases.Multiplex pumps applied to hydraulic pumping usually have stroke lengths from 2 to 7 in. and plunger diameters between 1 and 2½ in. The larger plungers provide higher flow rates but are generally rated at lower maximum pressure because of crankshaft loading limitations. The larger plungers provide higher flow rates, but are generally rated at lower maximum pressure because of crankshaft loading limitations. The normal maximum rating of multiplexes for continuous duty in hydraulic pumping applications is 5,000 psi, with lower ratings for the larger plungers, but applications above 4,000 psi are uncommon. Multiplex pumps are run at low speed to minimize vibration and wear and to avoid dynamic problems with the spring-loaded intake and discharge valves. Most applications fall between 200 and 450 rev/min, and because this is below the speeds of gas engines or electric motors, some form of speed reduction is usually required. Belt drives are found on some units, although gear reduction is more common while gear-reduction units are integral to some multiplexes and separate on others. A variety of reduction ratios are offered for each series of pumps. Because a positive-displacement pump has an essentially constant discharge flow rate for a given prime-mover speed, bypass of excess fluid normally is used to match a particular pressure and flow demand. Another option that has been used successfully is to drive the multiplex pump through a four-speed transmission, which greatly enhances the flexibility of the system. This allows much closer tailoring of the triplex output to the demand, thereby pumping at reduced speed when needed, which also tends to increase the life of such components as the packing and valving.Each plunger pumps individually from a common intake manifold into a common discharge, and because discharge occurs only on the upstroke, there is some pulsation, for which pulsation dampers are commonly used.Two types of plunger systems are in common use. For oil service, a simple and effective plunger-and-liner system is used that consists of a closely fitted metallic plunger inside a metallic liner. Sprayed metal coatings or other hard-facing means are often used to extend the life of the plunger and liner. When pumping water, the metal-to-metal system is not practical because the fit would have to be extremely close to keep leakage to an acceptable level. Galling and scoring are problems with close fits and the low lubricity of water, and to solve this problem, spring-loaded packing systems are used that do not require adjusting. The advent of high-strength aramid fibers for packing, in conjunction with other compounds to improve the friction characteristics, has resulted in a pronounced improvement in the ability of the pump to handle high-pressure water for extended periods of time. Water still presents a more severe challenge than oil, however, and water systems show much better life if operated at or below 3,500 psi.Suction conditions are important to multiplex operation. Friction losses in piping, fluid end porting, and across the suction valving reduce the pressure available to fill the pumping chamber on the plunger downstroke, and if these losses are sufficiently great, cavitation may result. When pumping oil with dissolved gas, the reduction in pressure liberates free gas and causes knocking, so it is necessary to have a positive head on the suction side to overcome the friction losses. In addition, another phenomenon known as "acceleration head" must be considered. The flow in the suction piping must accelerate and decelerate a number of times for each crankshaft revolution. For the fluid (which has inertia) to follow the acceleration, energy must be supplied, which is then returned to the fluid on deceleration. The energy supplied during acceleration comes from a reduction in the pressure in the fluid, and if this drops too low, cavitation or gas liberation will result. The minimum suction head for the multiplex pump is then the sum of the friction losses and the acceleration head. Although the pump can draw a vacuum, this will flash gas and may tend to suck air across the valve or plunger packing. Manufacturers of multiplex pumps recommend appropriate suction charging pressures for their products, but it is worth noting that long, small-diameter suction lines increase the acceleration head loss and friction loss. It is therefore recommended for suction lines to be short and of large diameter, with no high spots to trap air or gas. Suction stabilizers or pulsation dampeners that tend to absorb the pulsations from the pump also reduce acceleration head, and users are encouraged to follow good piping practices in the installation of surface pumps.In many cases, sufficient hydrostatic head is not available to provide the necessary suction pressure, and charge pumps are used to overcome this problem. Positive displacement pumps of the vane or crescent-gear type driven from the triplex have been used extensively, but they require a pressure-control valve to bypass excess fluid and match the multiplex displacement. Where electric power is available, centrifugal charge pumps have given excellent service. Centrifugal pumps generally need to run at speeds considerably above the multiplex speed, and so driving them from the multiplex presents problems, particularly with a gas engine drive where prime-mover speed variations cause significant variations in the charge-pump output pressure.While good charging pressures are necessary to ensure proper loading and smooth operation, there are problems associated with very high charge pressures. These add to the crankshaft loading, and for charge pressures above about 250 psi, it is advisable to derate the maximum discharge pressure by one third of the charge pressure. High charge pressures also can adversely affect the lubrication of bearings, particularly in the crosshead wristpin. In addition, the mechanical efficiency of multiplex pumps is some 3 to 5% lower on the suction side compared to the discharge side.Consequently, the combination of a charge pump and multiplex pump is most efficient with low charging pressures and a high boost by the multiplex pump. The charging pressure should therefore be limited to that necessary to give complete filling of the multiplex pump with a moderate safety allowance for variations in the system parameters.In some cases, it is desirable to inject corrosion inhibitors or lubricants into the multiplex suction, and fresh water is sometimes injected to dissolve high salt concentrations. In severe pumping applications with low-lubricity fluids, lubricating oil is sometimes injected or dripped onto the plungers in the spacer block area to improve plunger life. Injection pumps are often driven from the multiplex drive for these applications. A troubleshooting guide for multiplex pumps is given inVarious types of valves are used to regulate and to distribute the power-fluid supply to one or more wellheads. Common to all free-pump systems is a four-way valve or wellhead control valve, which is mounted at the wellhead, as shown in. Its function is to provide for different modes of operation by shifting it to different positions. To circulate the pump into the hole, as shown in, power fluid is directed down the main tubing string. The power fluid begins to operate the pump once it is on bottom and seated on the standing valve. In the pump-out mode, power fluid is directed down the return tubing or casing annulus to unseat the pump and to circulate it to the surface. When the pump is on the surface, putting the valve in the bypass and bleed position permits the well to be bled down and the pump to be removed and replaced.Most systems include a constant-pressure controller, as shown in, which maintains a discharge-pressure load on the multiplex pump by continuously bypassing the excess discharge fluid. It generally operates on the principle of an adjustable spring force on a piston-and-valve assembly that is pressure compensated. If the pressure rises on the high-pressure side, which is being controlled because of changing system loads, the pressure forces on the various areas within the valve will cause the valve to open and to bypass more fluid, restoring the high-pressure side to the preset condition. Jet pumps frequently are operated with a constant-pressure valve as the only surface control valve. The constant-pressure controller can be used to regulate the pressure on a manifold assembly serving multiple wells.Reciprocating downhole pumps are usually regulated with a constant-flow control valve. The downhole unit can be maintained at a constant stroking rate if a constant volume of power fluid is supplied to it, and the constant-flow control valve is designed to provide a preset flow rate even if the downhole operating pressure fluctuated because of changing well conditions. Because this valve does not bypass fluid, it must be used with a constant-pressure controller on the higher-pressure or inlet side.

Where a number of wells are to be pumped from a central battery, a control manifold is used to direct the flows to and from the individual wells. Control manifolds are designed to be built up in modular fashion to match the number of wells being pumped and are generally rated for 5,000 psi working pressure. A constant pressure control valve regulates the pressure on the common power fluid side of the manifold. This pressure is generally a few hundred pounds per square inch greater than the highest pressure demanded by any well to allow proper operation of the individual well-control valves. Individual constant-flow control valves regulate the amount of power fluid going to each well. The use of a constant pressure valve allows excess fluid to bypass at the highest pressure. Meter loops or individual meters for each station can be integrated into the manifold.

Lubricator

Some wells flow or "kick back" when the operator is attempting to remove or insert a pump into the wellhead. Also, the presence of water may make it inadvisable to open up the entire tubing string for pump insertion and removal. The use of a lubricator allows the master valve below the wellhead to be closed, and the entire lubricator with the pump in it to be removed from the wellhead. The lubricator is essentially an extended piece of the tubing with a sideline to allow fluid flow when the pump is circulating in or out of the hole.

Power-Fluid Systems

The function of the surface treating systems is to provide a constant supply of suitable power fluid to be used to operate the subsurface production units. The successful and economical operation of any hydraulic pumping system is to a large extent dependent on the effectiveness of the treating system in supplying high-quality power fluid. The presence of gas, solids, or abrasive materials in the power fluid adversely affects the operation and wears both the surface and downhole units. Therefore, the primary objective in treating crude oil or water for use as power fluid is to make it as free of gas and solids as possible. In addition, chemical treatment of the power fluid may be beneficial to the life of the downhole unit. In tests, it has been found that for best operation of the unit, a maximum total solids of 20 ppm, maximum salt content of 12 lbm/1,000 bbl oil, and a maximum particle size of 15 μm should be maintained. (These norms were established using oil in 30 to 40°API gravity range). It has been observed, however, that acceptable performance has been achieved in many cases where these values were exceeded, especially with the use of jet pumps and larger nozzles and throats. When using piston hydraulic pumps in heavy crude, these limitations have been exceeded and satisfactory results achieved, probably because the resulting wear does not increase leakage to the same degree. The periodic analysis of power fluid indicates steps to be taken for improved operation. For example, if the power-fluid analysis shows that iron sulfide or sulfate compounds make up the bulk of the solids, then a corrosion or scale problem exists that would require the use of chemical inhibitors to correct the problem. Water is the primary power fluid being used for jet pumping on offshore platforms and in applications where the majority of produced fluid being made is water. Water requires that a lubricant be added for use with reciprocating pumps. Other considerations in the choice of water or oil as a power fluid include:

• Maintenance on surface pumps is usually less with the use of oil. The lower bulk modulus of oil also contributes to reduced pressure pulsations and vibrations that can affect all the surface equipment.
• Well testing for oil production is simpler with water as the power fluid because all the oil coming back is produced oil. With oil power fluid, the power rate must be closely metered and subtracted from the total oil returning to surface. This can be a source of considerable error in high-water-cut wells where the power oil rate is large compared to the net production.
• In high-friction systems, as sometime occurs with jet pumps in restricted tubulars, the lower viscosity of water can increase efficiency. With no moving parts, the jet pump is not adversely affected by the poor lubrication properties of water.
• In deep casing-type installations, particularly with a jet pump, water when used as the power fluid can load up in the casing annulus return, negating any beneficial gas lifting effects for the produced gas.

It has been found that, in most cases, an upward velocity of 1ft/hr is low enough to provide sufficient gravity separation of entrained particles to clean power fluid to requirements, provided that there is no free gas in the fluids or large thermal effects.

Open Power-Fluid System

A typical power-oil treating system that has proved adequate for most OPF systems, when stock-tank-quality oil is supplied, is shown in Fig. 14.20. This system has the general characteristic that all return fluids from the well, both production and power fluid, must pass through the surface treating facility. The power-oil settling tank in this system is usually a 24-ft-high, three-ring, bolted steel tank. A tank of this height generally provides adequate head for gravity flow of oil from the tank to the multiplex pump suction. If more than one multiplex pump is required for the system, individual power-oil tanks can be set up for each pump, or a single large tank can be used, whichever is more economical and best meets the operating requirements. If a single large tank supplies the suction for several pumps, individual suction lines are preferable.

• Fig. 14.20-Central OPF hydraulic power-oil treating system.

The gas boot is essentially a part of the power-oil tank; its purpose is to provide final gas/oil separation so that the oil will be stable at near-atmospheric pressure. If the gas is not sufficiently separated from the oil, entrained free gas can enter the power-oil tank and destroy the settling process by causing the fluid in the tank to roll. The following piping specifications for the gas boot are necessary to ensure undisturbed settling:

• The gas-boot inlet height should be 4 ft above the top of the power-oil tank to allow the incoming fluid to fall, so that the agitation will encourage gas/oil separation.
• The top section of the gas boot should be at least 3 ft in diameter and 8 ft higher than the top of the power-oil tank. These two factors will provide a reservoir that should absorb the volume of the surges.
• The gas line out of the top of the boot should be tied into the power-oil tank and stock-tank vent line with a riser on the top of the power-oil tank. In the event the gas boot does become overloaded and kicks fluid over through the gas line, this arrangement will prevent the raw or unsettled fluid from being dumped in the top of the power-oil tank, where it may contaminate the oil drawn off to the multiplex. A minimum diameter of 3 in. is recommended for the gas line.
• The line connecting the gas boot to the power-oil tank should be at least 4 in. in diameter. This is necessary to minimize restrictions to low during surge loading of the boot.

A typical power-oil treating system that has proved adequate for most OPF systems, when stock-tank-quality oil is supplied, is shown in. This system has the general characteristic that all return fluids from the well, both production and power fluid, must pass through the surface treating facility. The power-oil settling tank in this system is usually a 24-ft-high, three-ring, bolted steel tank. A tank of this height generally provides adequate head for gravity flow of oil from the tank to the multiplex pump suction. If more than one multiplex pump is required for the system, individual power-oil tanks can be set up for each pump, or a single large tank can be used, whichever is more economical and best meets the operating requirements. If a single large tank supplies the suction for several pumps, individual suction lines are preferable.The gas boot is essentially a part of the power-oil tank; its purpose is to provide final gas/oil separation so that the oil will be stable at near-atmospheric pressure. If the gas is not sufficiently separated from the oil, entrained free gas can enter the power-oil tank and destroy the settling process by causing the fluid in the tank to roll. The following piping specifications for the gas boot are necessary to ensure undisturbed settling:

Oil entering a large tank (at the bottom and rising to be drawn off the top) tends to channel from the tank inlet to the outlet; thus, an inlet spreader is used. The purpose of the spreader is to reduce the velocity of the incoming fluid by distributing the incoming volume over a large area, thus allowing the fluid to rise upward at a more uniform rate. The recommended spreader consists of a round, flat plate with a diameter approximately half that of the tank with a 4-in. skirt that has 60° triangular, saw-tooth slots cut in it. The slots provide automatic opening adjustment for varying amounts of flow. It is essential that they be cut to uniform depth to obtain an even distribution of flow. This type of spreader must be installed with the tops of all the slots in a level plane to prevent fluid from "bumping out" under a high side, and it should be mounted about 2 ft above the bottom rim of the tank.

The location of the stock-tank take-off and level control is important because it establishes the effective settling interval of the power-oil tank and controls the fluid level. All fluid coming from the spreader rises to the stock take-off level, where stock-tank oil is drawn off. Fluid rising above this level is only that amount required to replace the fluid withdrawn by the multiplex pump, and it is in this region that the power-oil settling process takes place. The light solids settled out are carried with the production through the stock-tank take-off, and the heavier particles settle to the bottom, where they must be removed periodically. The location of the stock take-off point should be within 6 ft of the spreader. The height to which the stock oil must rise in the piping, to overflow into the stock tank, determines the fluid level in the power-oil tank. The diameter of the piping used should be sufficient to provide negligible resistance to the volume of flow required (4-in. minimum diameter recommended). The extension at the top of the level control is connected to the gas line to provide a vent that keeps oil in the power-oil tank from being siphoned down to the level of the top of the stock tank.

The power-oil outlet should be located on the opposite side of the power-oil tank from the stock take-off outlet to balance the flow distribution within the tank. Because the fluid level in the tank is maintained approximately 18 in. from the top of the tank, the location of the upper outlet, for use in starting up or filling tubing strings, depends on estimated emergency requirements and the capacity per foot of the tank. A distance of 7 ft from the top of the tank is usually sufficient. This lower outlet line contains a shutoff valve that is kept closed during normal operations so that the full settling interval is used.

Closed Power-Fluid Systems

In the closed power-fluid system, the power fluid returns to the surface in a separate conduit and need not go through the surface production treating facilities. The consequent reduction in surface treating facilities can tend to offset the additional downhole cost of the system. Virtually all closed power-fluid systems are in California because of the large number of townsite leases and offshore platforms, and water is usually the power fluid. Gravity settling separation in the power-fluid tank ensures that the power fluid remains clean despite the addition of solids from power-fluid makeup, corrosion products, and contamination during pump-in and pump-out operations. The power-fluid makeup is required to replace the small amount of fluid lost through fits and seals in the downhole pump and wellhead control valve. A certain amount of power fluid is also lost during circulating operations as well.

Single-Well Systems

The central battery systems previously discussed have been used successfully for years and provide a number of benefits. The use of lease fluid treating facilities as part of the of the hydraulic system ensures good, low-pressure separation of the gas, oil, water, and solids phases present in any system. Good triplex charging of clean, gas-free oil and consistently clean power fluid supplied to the downhole pump are desirable features of this system. The lease treating facilities, however, must have sufficient capacity to process both the well production and the return power fluid. When the wells are closely spaced, the clustering of power generation, fluid treating, and control functions in one location (but sufficiently spread out) is very efficient and allows good use of the installed horsepower. Because the system is not limited by production variations on any one well, an adequate supply of the desired power fluid is ensured by the size of the system. A further benefit associated with the use of the lease separation facilities is the option of a closed power-fluid system. When well spacing is large, however, long, high-pressure power-fluid lines must be run. Also, individual well testing is complicated by the need to meter the power-fluid rate for each well, which can introduce measurement errors. As a final consideration, only a few wells in a field may be best suited to artificial lift by hydraulic pumping, so the installation of a central system is difficult to justify.

To address the limitations of the central battery system, single-well systems have been designed, many of the requirements of which are the same as for a central battery. The oil, water, gas, and solids phases must be separated to provide a consistent source of power fluid to run the system. A choice of water or oil power fluid should be possible, and the fluid used as power fluid must be sufficiently clean to ensure reliable operation and that it is gas-free at the multiplex suction to prevent cavitation and partial fluid end loading. An adequate reservoir of fluid must be present to allow continuous operation and the various circulating functions associated with the free-pump procedures. Finally, a means of disposing of and measuring the well production to the lease treating and storage facilities must be provided.

To achieve these objectives, several of the manufacturers of hydraulic pumping units offer packaged single-well systems that include all the control, metering, and pumping equipment necessary. All components are skid mounted on one or two skids to facilitate installation at the well and to make the systems easily portable if the unit is to be moved to a different well. Usually, the only plumbing required at the wellsite is the power fluid and return-line hookup at the wellhead and the connection of the vessel outlet to the flowline.

An example of a typical single-well power unit is illustrated in Fig. 14.1. All units of this type share certain design concepts, with small variations depending on the manufacturer. Either one or two pressure vessels are located at the wellsite. The size of the main reservoir vessel depends on the nature of the well and the tubular completion. The reservoir vessel should ensure that, if the wellhead partially empties the return conduit to the flowline, adequate capacity remains to operate the downhole unit until production returns re-enter the vessel. Even if the well does not head, extra capacity is needed. When the unit is shut down for maintenance or pump changes, that portion of the return conduit occupied by gas needs to be filled from the vessel to unseat the pump and to circulate it to the surface. The vessel sizes normally used range from 42 × 120 in. to 60 × 240 in. In some wells, even the largest vessel may not be able to compensate fully for heading, in which case it is common to use backpressure to stabilize the heading. The vessels themselves are normally in the 175- to 240-psi working pressure range, with higher ratings available for special applications. Coal-tar-epoxy internal coatings are common, with special coatings for extreme cases.

The return power fluid and production for the well enter the vessel system where basic separation of water, oil, and gas phases takes place. Free gas at the vessel pressure is discharged to the flowline with a vent system that ensures a gas cap in the vessel at all times, while the oil and water separate in the vessel, and the desired fluid is withdrawn for use as power fluid. The power fluid passes through one or more cyclone desanders to remove solids before entering the multiplex suction, where it is pressurized for reinjection down the power-fluid tubing. Any excess multiplex output that is bypassed for downhole pump control is returned to the vessel. The underflow from the bottom of the cyclone desanders contains a high-solids concentration and is discharged either into the flowline or back into the vessel system. Once the system is stabilized on the selected power fluid, the well production of oil, water, and gas is discharged into the flowline from the vessel, which is maintained at a pressure above the flowline. Because the flowline is carrying only what the well makes, additional treating and separating facilities are not needed, as they are in the central battery system that handles mixed well production and power fluid. This feature also facilitates individual well testing.

Overall, simple gravity dump piping, which consists of a riser on the outside of the vessel, controls the fluid level in the vessel system. To prevent siphoning of the vessel, the gas-vent line is tied in the top of the riser as a siphon breaker. The choice of oil or water power fluid is made by selection of the appropriate take-off points on the vessel so that the production goes to the flowline and the power fluid goes to the multiplex pump. If the multiplex suction is low in the vessel and the flowline is high in the vessel, water will tend to accumulate in the vessel and will be the power fluid. If the multiplex suction is high in the vessel and the flowline is low, oil will tend to accumulate in the vessel and will be the power fluid. Opening and closing appropriate valves sets the system up for the chosen power fluid. The multiplex suction outlets are positioned with respect to the overall fluid level in the vessel to avoid drawing power fluid from the emulsion layer between the oil and water because this layer generally contains a significantly higher concentration of solids and is not easily cleaned in the cyclones.

The power-fluid cleaning is accomplished with cyclone desanders that require a pressure differential across them. In the two-vessel system, a differential pressure valve between the two vessels that stages the pressure drop from the wellhead accomplishes this. The energy to maintain this staged pressure is supplied by the multiplex pump through the downhole pump.

The flow path through a cyclone cleaner is shown in Fig. 14.21. Fluid enters the top of the cone tangentially through the feed nozzle and spirals downward toward the apex of the cone. Conservation of angular momentum dictates that the rotational speed of the fluid increases as the radius of curvature decreases, and it is the high rotational speed that cleans the fluid by centrifugal force. The clean fluid, called the overflow, spirals back upward through the vortex core to the vortex finder, while the dirty fluid exits downward at the apex through the underflow nozzle. The cones are usually constructed of cast iron with an elastomer interior. Different feed-nozzle and vortex-finder sizes and shapes are available to alter the performance characteristics of the cyclone. Different sizes of cyclones are available, with the smaller sizes having lower flow-rate capacities but somewhat higher cleaning efficiencies.


Maintaining the proper flow through the cyclone to ensure good cleaning depends on correctly adjusting the pressures at the feed nozzle, overflow, and underflow. At the design flow rates, a 30- to 50-psi drop normally occurs from the feed nozzle to the overflow. In the single-vessel system, a charged pump supplies the pressure, while in a dual-vessel system, the pressure is supplied by a higher backpressure on the returns from the well. Because of the centrifugal head, the cyclone overflow pressure is generally 5 to 15 psi higher than the underflow pressure. An underflow restrictor is commonly used to adjust the amount of underflow to between 5 and 10% of the overflow. This ensures good cleaning without circulation of excessive fluid volumes. It should be noted that the volume flow rates through a cyclone vary inversely with the specific gravity of the fluid, and that within the range of normal power fluids, increased viscosity leads to increased flow rates. The viscosity that suppresses the internal vortex action causes this latter effect. Therefore, proper cyclone sizing to match the charge and multiplex pump characteristics must be done carefully and with detailed knowledge of the fluid to be processed. The manufacturers of the packaged systems supply appropriate cyclones for the installation, but it should be noted that moving the portable unit to another well might require resizing of the cyclone system.

The routing of the dirty underflow varies with different systems, and may be an adjustable option in some systems. Two basic choices are available: return of underflow to the vessel or routing of the underflow to the flowline. In a dual-vessel system, the underflow must be returned to the flowline downstream of the backpressure valve to provide sufficient pressure differential to ensure underflow. Discharging the solids to the flowline is attractive because they are disposed of immediately and are excluded from possible entry into the power fluid. Under some conditions, however, continuous operation may not be possible. If the net well production is less than the underflow from the cyclone for any length of time, the level of fluid in the vessel will drop, and over an extended period of time, this can result in a shutdown of the system. Shutting off the cyclone underflow during these periods stops the loss of fluid, but apex plugging occurs during the shutoff period. Returning the underflow to the vessel eliminates the problem of running the vessel dry but does potentially reintroduce solids into the power fluid. In single-vessel units, the underflow is generally plumbed back to the vessel in a baffled section adjacent to the flowline outlet. This provides for the maximum conservation but requires a differential pressure valve, between the cyclone underflow and the vessel, which is normally set at about 20 psi to ensure a positive pressure to the underflow fluid.

As mentioned previously, the vessel pressure is held above the flowline pressure to ensure flow into the flowline and a backpressure control valve is sometimes used for this purpose. This keeps the vessel pressure, which is backpressure on the well, at a minimum for any flowline pressure that may occur during normal field operation. When water is the power fluid, "riding" the flowline in this manner is acceptable. However, when oil is the power fluid, changing vessel pressure causes flashing of gas in the power oil and adversely affects the multiplex suction. When oil is used as power fluid, it is recommended that a pressure control valve be used to keep the vessel at a steady pressure some 10 to 15 psi above the highest expected flowline pressure.

Although, the single-vessel system was developed for applications involving widely spaced wells, two or three well installations have been successfully operated from a single-well system. This installation is very attractive on offshore platforms. With a large number of highly deviated wells, offshore production is well suited to hydraulic pumping with free pumps, but the extra fluid treating facilities with an open power-fluid system is a drawback when severe weight and space limitations exist. The closed power-fluid system answers this problem, but the extra tubulars in deviated holes create their own set of problems and expense. Furthermore, the use of jet pumps, which is quite attractive offshore, is not possible with the closed power-fluid system. For safety and environmental reasons, water is almost always the power fluid of choice offshore. A large single-well system can receive the returns from all the wells and separate the power water necessary for reinjection to power downhole units. Full 100% separation of the oil from the power water is not necessary, and, in fact, some minor oil carryover will contribute to the power-fluid lubricity. The platform separation facilities then have to handle only the actual production from the wells. A compact bank of cyclone cleaners completes the power-fluid separation and cleaning unit.

In summary, the hydraulic system normally is used in areas where other types of artificial lift have failed or, because of well conditions, have been eliminated because of their shortcomings. Hydraulic pumping systems have been labeled expensive, where, in truth, the use of other artificial lift methods may not be feasible. These include, but are not limited to, the following:

• Using hydraulic free pumps in remote areas where the rig costs are unusually high or the availability of workover rigs is limited.
• Crooked or deviated wells.
• Use of hydraulic systems in relatively deep, hot, high-volume wells. (Note: Hydraulic pumps can go through tubing with as much as a 24° buildup per 100 ft.)
• The use of jet pumps in sandy corrosive wells.
• The use of reciprocating pumps in deep wells with low bottomhole producing pressure.
• Wells with rapidly changing producing volumes.
• The use of jet pumping systems in wells producing with gas/liquid ratios less than 750:1 but producing under a packer where free gas must be pumped.
• Using hydraulic free pumps in wells with high-paraffin contents.
• Using hydraulic OPF systems in low-API-gravity wells.

The central battery systems previously discussed have been used successfully for years and provide a number of benefits. The use of lease fluid treating facilities as part of the of the hydraulic system ensures good, low-pressure separation of the gas, oil, water, and solids phases present in any system. Good triplex charging of clean, gas-free oil and consistently clean power fluid supplied to the downhole pump are desirable features of this system. The lease treating facilities, however, must have sufficient capacity to process both the well production and the return power fluid. When the wells are closely spaced, the clustering of power generation, fluid treating, and control functions in one location (but sufficiently spread out) is very efficient and allows good use of the installed horsepower. Because the system is not limited by production variations on any one well, an adequate supply of the desired power fluid is ensured by the size of the system. A further benefit associated with the use of the lease separation facilities is the option of a closed power-fluid system. When well spacing is large, however, long, high-pressure power-fluid lines must be run. Also, individual well testing is complicated by the need to meter the power-fluid rate for each well, which can introduce measurement errors. As a final consideration, only a few wells in a field may be best suited to artificial lift by hydraulic pumping, so the installation of a central system is difficult to justify.To address the limitations of the central battery system, single-well systems have been designed,many of the requirements of which are the same as for a central battery. The oil, water, gas, and solids phases must be separated to provide a consistent source of power fluid to run the system. A choice of water or oil power fluid should be possible, and the fluid used as power fluid must be sufficiently clean to ensure reliable operation and that it is gas-free at the multiplex suction to prevent cavitation and partial fluid end loading. An adequate reservoir of fluid must be present to allow continuous operation and the various circulating functions associated with the free-pump procedures. Finally, a means of disposing of and measuring the well production to the lease treating and storage facilities must be provided.To achieve these objectives, several of the manufacturers of hydraulic pumping units offer packaged single-well systems that include all the control, metering, and pumping equipment necessary. All components are skid mounted on one or two skids to facilitate installation at the well and to make the systems easily portable if the unit is to be moved to a different well. Usually, the only plumbing required at the wellsite is the power fluid and return-line hookup at the wellhead and the connection of the vessel outlet to the flowline.An example of a typical single-well power unit is illustrated in. All units of this type share certain design concepts, with small variations depending on the manufacturer. Either one or two pressure vessels are located at the wellsite. The size of the main reservoir vessel depends on the nature of the well and the tubular completion. The reservoir vessel should ensure that, if the wellhead partially empties the return conduit to the flowline, adequate capacity remains to operate the downhole unit until production returns re-enter the vessel. Even if the well does not head, extra capacity is needed. When the unit is shut down for maintenance or pump changes, that portion of the return conduit occupied by gas needs to be filled from the vessel to unseat the pump and to circulate it to the surface. The vessel sizes normally used range from 42 × 120 in. to 60 × 240 in. In some wells, even the largest vessel may not be able to compensate fully for heading, in which case it is common to use backpressure to stabilize the heading. The vessels themselves are normally in the 175- to 240-psi working pressure range, with higher ratings available for special applications. Coal-tar-epoxy internal coatings are common, with special coatings for extreme cases.The return power fluid and production for the well enter the vessel system where basic separation of water, oil, and gas phases takes place. Free gas at the vessel pressure is discharged to the flowline with a vent system that ensures a gas cap in the vessel at all times, while the oil and water separate in the vessel, and the desired fluid is withdrawn for use as power fluid. The power fluid passes through one or more cyclone desanders to remove solids before entering the multiplex suction, where it is pressurized for reinjection down the power-fluid tubing. Any excess multiplex output that is bypassed for downhole pump control is returned to the vessel. The underflow from the bottom of the cyclone desanders contains a high-solids concentration and is discharged either into the flowline or back into the vessel system. Once the system is stabilized on the selected power fluid, the well production of oil, water, and gas is discharged into the flowline from the vessel, which is maintained at a pressure above the flowline. Because the flowline is carrying only what the well makes, additional treating and separating facilities are not needed, as they are in the central battery system that handles mixed well production and power fluid. This feature also facilitates individual well testing.Overall, simple gravity dump piping, which consists of a riser on the outside of the vessel, controls the fluid level in the vessel system. To prevent siphoning of the vessel, the gas-vent line is tied in the top of the riser as a siphon breaker. The choice of oil or water power fluid is made by selection of the appropriate take-off points on the vessel so that the production goes to the flowline and the power fluid goes to the multiplex pump. If the multiplex suction is low in the vessel and the flowline is high in the vessel, water will tend to accumulate in the vessel and will be the power fluid. If the multiplex suction is high in the vessel and the flowline is low, oil will tend to accumulate in the vessel and will be the power fluid. Opening and closing appropriate valves sets the system up for the chosen power fluid. The multiplex suction outlets are positioned with respect to the overall fluid level in the vessel to avoid drawing power fluid from the emulsion layer between the oil and water because this layer generally contains a significantly higher concentration of solids and is not easily cleaned in the cyclones.The power-fluid cleaning is accomplished with cyclone desanders that require a pressure differential across them. In the two-vessel system, a differential pressure valve between the two vessels that stages the pressure drop from the wellhead accomplishes this. The energy to maintain this staged pressure is supplied by the multiplex pump through the downhole pump.The flow path through a cyclone cleaner is shown in. Fluid enters the top of the cone tangentially through the feed nozzle and spirals downward toward the apex of the cone. Conservation of angular momentum dictates that the rotational speed of the fluid increases as the radius of curvature decreases, and it is the high rotational speed that cleans the fluid by centrifugal force. The clean fluid, called the overflow, spirals back upward through the vortex core to the vortex finder, while the dirty fluid exits downward at the apex through the underflow nozzle. The cones are usually constructed of cast iron with an elastomer interior. Different feed-nozzle and vortex-finder sizes and shapes are available to alter the performance characteristics of the cyclone. Different sizes of cyclones are available, with the smaller sizes having lower flow-rate capacities but somewhat higher cleaning efficiencies.Maintaining the proper flow through the cyclone to ensure good cleaning depends on correctly adjusting the pressures at the feed nozzle, overflow, and underflow. At the design flow rates, a 30- to 50-psi drop normally occurs from the feed nozzle to the overflow. In the single-vessel system, a charged pump supplies the pressure, while in a dual-vessel system, the pressure is supplied by a higher backpressure on the returns from the well. Because of the centrifugal head, the cyclone overflow pressure is generally 5 to 15 psi higher than the underflow pressure. An underflow restrictor is commonly used to adjust the amount of underflow to between 5 and 10% of the overflow. This ensures good cleaning without circulation of excessive fluid volumes. It should be noted that the volume flow rates through a cyclone vary inversely with the specific gravity of the fluid, and that within the range of normal power fluids, increased viscosity leads to increased flow rates. The viscosity that suppresses the internal vortex action causes this latter effect. Therefore, proper cyclone sizing to match the charge and multiplex pump characteristics must be done carefully and with detailed knowledge of the fluid to be processed. The manufacturers of the packaged systems supply appropriate cyclones for the installation, but it should be noted that moving the portable unit to another well might require resizing of the cyclone system.The routing of the dirty underflow varies with different systems, and may be an adjustable option in some systems. Two basic choices are available: return of underflow to the vessel or routing of the underflow to the flowline. In a dual-vessel system, the underflow must be returned to the flowline downstream of the backpressure valve to provide sufficient pressure differential to ensure underflow. Discharging the solids to the flowline is attractive because they are disposed of immediately and are excluded from possible entry into the power fluid. Under some conditions, however, continuous operation may not be possible. If the net well production is less than the underflow from the cyclone for any length of time, the level of fluid in the vessel will drop, and over an extended period of time, this can result in a shutdown of the system. Shutting off the cyclone underflow during these periods stops the loss of fluid, but apex plugging occurs during the shutoff period. Returning the underflow to the vessel eliminates the problem of running the vessel dry but does potentially reintroduce solids into the power fluid. In single-vessel units, the underflow is generally plumbed back to the vessel in a baffled section adjacent to the flowline outlet. This provides for the maximum conservation but requires a differential pressure valve, between the cyclone underflow and the vessel, which is normally set at about 20 psi to ensure a positive pressure to the underflow fluid.As mentioned previously, the vessel pressure is held above the flowline pressure to ensure flow into the flowline and a backpressure control valve is sometimes used for this purpose. This keeps the vessel pressure, which is backpressure on the well, at a minimum for any flowline pressure that may occur during normal field operation. When water is the power fluid, "riding" the flowline in this manner is acceptable. However, when oil is the power fluid, changing vessel pressure causes flashing of gas in the power oil and adversely affects the multiplex suction. When oil is used as power fluid, it is recommended that a pressure control valve be used to keep the vessel at a steady pressure some 10 to 15 psi above the highest expected flowline pressure.Although, the single-vessel system was developed for applications involving widely spaced wells, two or three well installations have been successfully operated from a single-well system. This installation is very attractive on offshore platforms. With a large number of highly deviated wells, offshore production is well suited to hydraulic pumping with free pumps, but the extra fluid treating facilities with an open power-fluid system is a drawback when severe weight and space limitations exist. The closed power-fluid system answers this problem, but the extra tubulars in deviated holes create their own set of problems and expense. Furthermore, the use of jet pumps, which is quite attractive offshore, is not possible with the closed power-fluid system. For safety and environmental reasons, water is almost always the power fluid of choice offshore. A large single-well system can receive the returns from all the wells and separate the power water necessary for reinjection to power downhole units. Full 100% separation of the oil from the power water is not necessary, and, in fact, some minor oil carryover will contribute to the power-fluid lubricity. The platform separation facilities then have to handle only the actual production from the wells. A compact bank of cyclone cleaners completes the power-fluid separation and cleaning unit.In summary, the hydraulic system normally is used in areas where other types of artificial lift have failed or, because of well conditions, have been eliminated because of their shortcomings. Hydraulic pumping systems have been labeled expensive, where, in truth, the use of other artificial lift methods may not be feasible. These include, but are not limited to, the following:

Jet Pumping System Design Example

The following is an example of a design for a well using a jet pumping system. The design data must be carefully collected and is shown in Table 14.9. Because there are numerous possible combinations, and a design typically requires many iterations, current design methods utilize computer software programs.

• Table 14.9

A jet pumping system was chosen because of the remote location, the advantage of the free-pump system to reduce pump pulling costs, and the advantages and flexibility of a central system to produce several wells drilled in the same field. There are no gas-sales lines, and the produced gas is used to provide the necessary energy to drive the prime movers. The wells are 5,400 ft in depth and have a static reservoir pressure of 2,050 psia. The jet hydraulic pumping system has been operating successfully for 5 years with low operating expenses.

One well was producing only 150 B/D, and a pressure buildup survey and production test indicated a skin of 50. Following a successful reperforating and stimulation treatment, the well is capable of producing significantly higher rates. By running the original jet combination and matching the power fluid, injection pressure, and total production, a new pump intake was calculated, and a new IPR curve was determined.

A design was made to find what could be produced with the existing horsepower and also what might be achieved if excess horsepower from a second well was used. A throat and nozzle (10B) with an annulus of 0. was determined to be a good fit for both cases. See Table 14.6. The selected jet has an ability to produce 1,063 B/D using 1,720 B/D of power fluid at 2,500 psi injection or 81 hp. See Table 14.9. If the power-fluid injection pressure is increased to 3,000 psi, the power-fluid volume is increased to 1,896 B/D, and the pump intake pressure is reduced to 850 psig, then 1,200 B/D of production is feasible, which will take 108 hp.

The predicted performance of the jet pump system for this well is shown in Fig. 14.22. Line 1 on the graph represents 2,500 psi injection and 81 hp. Line 2 represents 3,000 psi and 108 hp. If pressure is increased to 3,500 psi, the pump will go into cavitation, and damage might occur to the jet nozzle throat.

• Fig. 14.22-IPR curve vs. jet production for a given combination 10B.

Design Example for a Reciprocating Hydraulic Pump System

Currently a 12,000-ft well is equipped with a sucker rod beam pumping system with the pump set at only 9,000 ft. The design data, plus the well completion and pump installation data summary and a pump performance summary, are shown in Table 14.10. The well is deviated with a severe dogleg at 9,100 ft and produces only 100 B/D with a pump intake pressure (PIP) of about 1,000 psi. Workover rig cost is high, and a free-pump installation is desirable to reduce maintenance costs. Furthermore, a production increase is essential for this remotely located well. A review of the IPR data shown in Fig. 14.23 indicates that production can easily be increased from 100 B/D to 350 B/D, if the well can be pumped with a Pwf of 500 psi without significant gas interference. Pressure maintenance operations have begun in the field, and further decrease in the reservoir pressure is not expected. An economic analysis indicates a payout from changing to the hydraulic system in less than 3 years.

• Table 14.10

  Contact us to discuss your requirements of how does an oil well pump work. Our experienced sales team can help you identify the options that best suit your needs.

• Fig. 14.23-Vogel oilwell IPR.

The 5½-in. casing has a significant effect on the proposed design. Considering the casing size, depth, production requirements, and reservoir conditions, a casing free-pump system was selected. Power oil is pumped down the tubing and returned up the casing-tubing annulus with the oil, water, and gas production. The 2 7/8-in. [2.441-in. inside diameter (ID)] N-80 tubing now in the well has ample tension, burst, and collapse strengths and will be used. The pump is set at the lowest possible depth (12,000 ft) in order to achieve an operating pressure of 500 psi at the perforations. At design conditions, a pump displacement of about 580 B/D is required to produce the oil and water liquids, plus the free gas. In order to decrease the number of pump failures, the strokes per minute are limited to 33.4. Pump model was chosen to stay within this range. See Table 14.1.

The selected pump is designed to run at 46.3% of rated speed, requiring a power-fluid volume of 741 B/D and an injection pressure of 3,211.8 psi. Horsepower required for this well is 44.9 hp, and a 60-hp system is selected to provide more flexibility and compensate for wear and possible higher gas volumes.

The following is an example of a design for a well using a jet pumping system. The design data must be carefully collected and is shown in. Because there are numerous possible combinations, and a design typically requires many iterations, current design methods utilize computer software programs.A jet pumping system was chosen because of the remote location, the advantage of the free-pump system to reduce pump pulling costs, and the advantages and flexibility of a central system to produce several wells drilled in the same field. There are no gas-sales lines, and the produced gas is used to provide the necessary energy to drive the prime movers. The wells are 5,400 ft in depth and have a static reservoir pressure of 2,050 psia. The jet hydraulic pumping system has been operating successfully for 5 years with low operating expenses.One well was producing only 150 B/D, and a pressure buildup survey and production test indicated a skin of 50. Following a successful reperforating and stimulation treatment, the well is capable of producing significantly higher rates. By running the original jet combination and matching the power fluid, injection pressure, and total production, a new pump intake was calculated, and a new IPR curve was determined.A design was made to find what could be produced with the existing horsepower and also what might be achieved if excess horsepower from a second well was used. A throat and nozzle (10B) with an annulus of 0. was determined to be a good fit for both cases. See. The selected jet has an ability to produce 1,063 B/D using 1,720 B/D of power fluid at 2,500 psi injection or 81 hp. See. If the power-fluid injection pressure is increased to 3,000 psi, the power-fluid volume is increased to 1,896 B/D, and the pump intake pressure is reduced to 850 psig, then 1,200 B/D of production is feasible, which will take 108 hp.The predicted performance of the jet pump system for this well is shown in. Line 1 on the graph represents 2,500 psi injection and 81 hp. Line 2 represents 3,000 psi and 108 hp. If pressure is increased to 3,500 psi, the pump will go into cavitation, and damage might occur to the jet nozzle throat.Currently a 12,000-ft well is equipped with a sucker rod beam pumping system with the pump set at only 9,000 ft. The design data, plus the well completion and pump installation data summary and a pump performance summary, are shown in. The well is deviated with a severe dogleg at 9,100 ft and produces only 100 B/D with a pump intake pressure (PIP) of about 1,000 psi. Workover rig cost is high, and a free-pump installation is desirable to reduce maintenance costs. Furthermore, a production increase is essential for this remotely located well. A review of the IPR data shown inindicates that production can easily be increased from 100 B/D to 350 B/D, if the well can be pumped with aof 500 psi without significant gas interference. Pressure maintenance operations have begun in the field, and further decrease in the reservoir pressure is not expected. An economic analysis indicates a payout from changing to the hydraulic system in less than 3 years.The 5½-in. casing has a significant effect on the proposed design. Considering the casing size, depth, production requirements, and reservoir conditions, a casing free-pump system was selected. Power oil is pumped down the tubing and returned up the casing-tubing annulus with the oil, water, and gas production. The 2 7/8-in. [2.441-in. inside diameter (ID)] N-80 tubing now in the well has ample tension, burst, and collapse strengths and will be used. The pump is set at the lowest possible depth (12,000 ft) in order to achieve an operating pressure of 500 psi at the perforations. At design conditions, a pump displacement of about 580 B/D is required to produce the oil and water liquids, plus the free gas. In order to decrease the number of pump failures, the strokes per minute are limited to 33.4. Pump model was chosen to stay within this range. SeeThe selected pump is designed to run at 46.3% of rated speed, requiring a power-fluid volume of 741 B/D and an injection pressure of 3,211.8 psi. Horsepower required for this well is 44.9 hp, and a 60-hp system is selected to provide more flexibility and compensate for wear and possible higher gas volumes.

Hydraulic jet pumps can defeat the challenges presented by oil wells that feature a number of dogleg severities (DLS) because they have been designed to maneuver through even the most significant DLSs, which results in improved production rates with minimized downtime and cost for service and maintenance. Dogleg severities (DLS) can be the bane of optimized oil recovery, with the image showing that the drilling path in a well with a high number of DLSs can oftentimes end up resembling a corkscrew. A production chart for three wells on an Eagle Ford well pad in Texas shows that since hydraulic jet pumps have begun being used on the two wells with significant dogleg seventies (DLS), total cumulative production has overcome the SRP by 71% and 92% for those wells. A six-week sample of the daily production rates for the wells on the Eagle Ford wellpad shows that those that utilize hydraulic jet pumps (red and blue lines) consistently exceed the daily production of the well that is equipped with a sucker rod pump (green line). The amount of oil that eventually reaches the surface during a recovery operation is greatly influenced by the shape of the drilling path.

More than 90% of the oil-and-gas wells use some form of artificial-lift technology to enhance production and recovery rates, but the correct methods must be used to ensure optimum performance.

It&#;s a fact of oil-drilling life that no well can ever be drilled in a perfectly straight line down to the oil-and-gas reservoir. This makes what has come to be known as the &#;dogleg severity,&#; or DLS, the bane of optimized oil recovery. Simply put, a DLS is caused by the topography that is encountered when the well is drilled. The amount and types of rock, dirt, grit and sand, along with a list of other hindrances, determine how serious the DLSs are, with some wells encountering so many obstructions in the drilling path that they may be forced to go horizontal at times, or even have the well bore end up in a corkscrew shape.

Oilfield operators have known about and combated the challenges that are created by DLSs for the better part of a century. In that time, they have developed different forms of downhole artificial-lift technology that are designed to improve operations in wells that are hampered by severe DLS characteristics.

The key to optimizing the artificial-lift operation is the pump that is sent to the bottom of the well, as this uses energy to send any trapped reservoir fluids racing to the surface. Over the years, many different modes of pumping technologies have been used in artificial-lift applications, but this article will illustrate why hydraulic jet pumps can be the most productive, cost-effective and reliable solution, especially for wells that have many DLS-caused twists and turns.

The challenge

In the vast majority of these artificial-lift installations, the pumping technology of choice has been the sucker-rod pump (SRP). SRPs are mechanically driven from the surface with a motor-driven pumping unit that connects to the downhole SRP with a rod string. While SRPs have been proven to be very effective at increasing production rates in wells with relatively straight bores, they are not an ideal choice for wells with DLSs for a couple of significant reasons:

&#;    Because of the presence of the rod string, SRPs can not be used in wells with horizontal sections, meaning that they can only be used to a certain depth, with the knowledge that additional product can lie deeper within the well, but can&#;t be reached by the SRP. &#;    If an SRP is due for maintenance or needs to be replaced, a workover rig crew needs to come to the well site and pull the entire section of rod string and tubing out of the well bore. This can be an expensive and unsafe proposition, with an average cost of up to $50,000, and additional well-downtime costs also likely to be incurred, while any on-site work can increase the likelihood that a safety incident may occur.

These are noteworthy considerations for operators who must be concerned with optimizing capital expenditures and operating expenses, all while keeping an eye on the overall return on investment and the net revenues that are produced by each well.

Case study

A wellpad located in the Eagle Ford shale in south Texas that is operated by a prominent North American exploration and production company had three wells drilled in early . The DLS of two of the wells was high, prompting the operator to consider various forms of artificial lift other than one that used SRPs.

Since the third well did not have pronounced or prohibitive DLS, it would use an artificial-lift system featuring SRP technology for its recovery operation. Because of the high DLS values in the other two wells, it was determined that the best course of action would be to use hydraulic jet pumps instead of SRPs in the artificial-lift system.

It was decided that a 'one pump, two well' setup would work best for the DLS-hampered wells, meaning that both wells would use one surface pump to provide power fluid to run each well. A 200 hp pump was chosen to send the power fluid down the 2-7/8 inch tubing to the jet pump and return the fluids up the 5-1/2 inch casing to mitigate the oil-recovery process.

This 'one pump, two well' design had a number of advantages for the operator. Both hydraulic jet pumps could be sent deep into the lateral well at close to 40-degree inclinations. Since the jet pumps had no moving parts, and despite the fact they are four ft long, they have the capability to move freely up and down the tubing, even in the sections with high DLS values. The operational costs were divided among the cumulative production from both wells, thus cutting the cost in half when compared to a conventional 'one well, one pump' system and being comparable in cost to an installation that relies on SRPs. Jet pumps also allowed for flexibility in production; as the pump was set deeper in the well, there was the possibility to increase the drawdown and produce more in the same time when compared to an SRP. Finally, the surface unit came with a rent/purchase option, giving the operator the flexibility to pay a month-to-month rent depending on the productivity of the wells

After a two-month trial run, the productivity rates of the jet pumps were compared to the SRP and they showed that pump downtime was lower. Additionally, the initial production rates of oil for all three pumps were compared and the production of the two jet-pump wells outpaced that of the SRP well.

The two jet pumps were kept in operation and after nearly two years, the production returns from the jet-pump wells have been substantially more than the returns from the SRP well. The jet pumps also had more run time than the SRP well with less workover time required. Finally, and most significantly, the jet-pump wells produced 71% and 92% more cumulative oil than the SRP well. Even though the overall operational efficiency of the jet pumps was lower, this was made up by the increased uptime and production levels that were being experienced in the two jet-pump wells.

In the end, since the jet pumps resoundingly demonstrated that they could deliver greater flexibility, lower downtime and increased production, the exploration company has chosen to make them one of its primary choices for artificial-lift solutions going forward.

The solution

While the SRP has proven to be a reliable pump for artificial-lift in wells with relatively straight drilling paths, the better solution for DLS-dominant wells is the hydraulic jet pump.

Hydraulic pumps in general can be more effective than mechanical pumps because they are powered by existing or produced well fluid that is pressurized at the well&#;s surface and sent through the tubing to actuate the downhole pump. More specifically, hydraulic jet pumps have been designed to increase production-rate capacity from the deepest wells with the most severe DLSs, and whether they are traveling through sand, paraffin, heavy oil, water, gas or corrosive fluids.

There are certain features and benefits that help make hydraulic jet pumps the 'champion' of DLS-well recovery operations:

&#;    They can be retrieved and serviced by simply reversing the fluid flow, which brings the downhole pump to the surface. This eliminates well downtime and can be done at a cost of as little as $2,000, a far cry from the previously noted $50,000 that it can cost to service a well that is equipped with SRPs. &#;    Jet pumps have no moving parts, which eliminates wear and tear on the tubing, as well as the aforementioned pulling and replacement costs that can be associated with the other types of pumps that are used in artificial-lift applications. &#;    Because jet pumps have no moving parts, they are very rugged and can have long downhole lives. If they do require maintenance, they are easily repairable in the field, which minimizes repair and replacement costs. &#;    The size of a typical jet pump ranges from four to six feet and can easily be handled by one person.  In addition, the small sizes allow the pump to easily travel down the tubing with severe DLSs.

There are a couple of reasons why operators might hesitate when considering the use of jet pumps. One, they are generally not very efficient when compared to a positive displacement pump like an SRP. Secondly, they require a high-pressure surface pump and piping. Also, in some cases where frac tanks have been used, pitting and corrosion of the tubing was found. Closer study determined that oxidation was the cause of the pitting and corrosion because oxygen was allowed to enter the power fluid. This shortcoming can be solved by using a closed-loop system for distributing the power fluid and treating it before use with the proper oxygen-scavenging chemicals.

In the end, though, these perceived drawbacks of hydraulic jet pumps can be overridden by the fact that they are less costly to maintain, along with being less complicated to operate, with any time and cost savings more than making up for any operational inefficiencies.

With all that being said, and most importantly, the jet pump, unlike its SRP cousins, is able to go where it is needed most, no matter the configuration of the well or the degree and type of DLSs that are encountered. The goal of any oil-production regime is to optimize the amount of oil and gas that makes its way to the surface in the most cost-effective and reliable way possible. The jet pump checks all the right boxes, particularly when used in high-DLS wells.

Conclusion

There&#;s no doubt that oil wells with drilling paths that feature high dogleg severities can take a significant 'bite' out of production rates. By extension, wells that do not produce at optimum levels do not create enough revenue to keep them viable, despite the large amounts of recoverable reserves that may be tantalizingly within reach. That&#;s why artificial-lift can be such an important part of optimizing the returns in an oilfield, but, again, only if the system functions at the height of reliability and cost-effectiveness. Artificial-lift systems that deploy hydraulic jet pumps have been proven to overcome the ill effects of wells that are beset by DLS concerns and are a tried-and-true way to ensure that all wells are capable of reaching their required production rates.

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