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Difference between revisions of "Hydraulic pumping surface equipment"

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[[Category:3.1.3 Hydraulic and jet pumps]] [[Category:YR]]

Latest revision as of 12:39, 4 February 2016

Surface facilities for hydraulic pumping systems include a pump at the surface to send the power fluid downhole, a gas, diesel or electric engine to drive the pump, and a system for storing, treating and delivering the power fluid (produced oil or water) for use by the downhole pump. This page discusses some of the key surface components of the system.

Surface pumps

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. 1.

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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 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.

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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.

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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. [1] 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 1.

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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. 2. 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. 3, 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 Fig. 4, 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.

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Control manifolds

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.

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Power fluid system

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.

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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. 1. 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:

  • 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.

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.

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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.

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References

  1. Hydraulic Institute Standards, 13th edition. 1975. Cleveland, Ohio: Hydraulic Institute.

Noteworthy papers in OnePetro

Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read

Noteworthy books

Bradley, H. B., & Gipson, F. W. (1992). Petroleum engineering handbook. Richardson, TX, U.S.A: Society of Petroleum Engineers. WorldCat

Frick, T. C., & Taylor, R. W. (1962). Petroleum production handbook. Dallas, Tex: Society of Petroleum Engineers of AIME. WorldCat

iBook

Pugh, Toby. (2014). Overview of Hydraulic Pumping. Weatherford. iBook.

External links

Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro

See also

Hydraulic pumping systems for single wells

Hydraulic pumping

Downhole hydraulic pump installations

Downhole hydraulic pump types

Hydraulic pumping system design

PEH:Hydraulic_Pumping_in_Oil_Wells

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Page champions

Toby Pugh P.E.

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