PEH:Hydraulic Pumping in Oil Wells - PetroWiki - SPE

Surface Pumps

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Hydraulic pumping systems have advanced to utilize relatively high pressures while maintaining low flow rates. This innovation helps to reduce friction losses and enhances the lift capability and overall efficiency of the system. Typically, surface operating pressures range between 2,000 and 4,000 psi. Higher pressures are particularly applied in deeper wells, and power-fluid rates can vary from a few hundred to over 3,000 B/D. Although some surface multistage centrifugal pumps are rated for this pressure range, they often exhibit inefficiency at the lower flow rates linked to single-well applications. Conversely, multistage centrifugals are more effective when pumping multiple wells from a centralized location. For a single well, or just a few, a high-head and low-specific-speed pump is requisite. The extensive experience amassed in the pumping industry has favored positive-displacement pumps for this application, with triplex or quintuplex pumps typically driven by gas engines or electric motors powering the majority of hydraulic pump installations. See Fig. 14.17.

• Fig. 14.17-Horizontal plunger pumps.

Multiplex pumps are composed of two main parts: a power end and a fluid end. The power end encompasses a crankshaft housed in a crankcase, and the connecting rods are similar to those found in internal combustion engines but connect to crossheads rather than pistons. The fluid end contains individual plungers, each with spring-loaded intake and discharge check valves. This assembly is connected to the power end via a spacer block that contains the intermediate rods and provides a working area for access to the plunger system. Most oilfield units are configured horizontally to minimize crankcase oil contamination. However, vertical installations remain viable, particularly in applications where oil is the pumped fluid or where space constraints are a factor in townsite leases.

Multiplex pumps utilized in hydraulic pumping typically feature stroke lengths ranging from 2 to 7 inches and plunger diameters between 1 and 2½ inches. Larger plungers yield increased flow rates but are usually rated for lower maximum pressure due to crankshaft loading limits. In standard continuous duty applications, multiplex ratings max out at 5,000 psi, with lower ratings applying to larger plungers; instances exceeding 4,000 psi remain uncommon. To reduce vibration and wear, multiplex pumps operate at low speeds, usually between 200 and 450 revolutions per minute (rev/min). Since this operates below the gas engines or electric motors' speeds, some form of speed reduction is typically necessary. While belt drives appear in some units, gear reduction is more common, and some multiplex models contain integrated gear-reduction units alongside separate options. Each pump series offers various reduction ratios. As a positive-displacement pump maintains a nearly constant discharge flow rate for a given prime-mover speed, bypassing excess fluid is generally necessary to meet specific pressure and flow demands. A further successful approach is to utilize a four-speed transmission to drive the multiplex pump, allowing for enhanced flexibility. This arrangement provides closer tailoring of the triplex output to demand, effectively pumping at reduced speed if necessary, which can lengthen the components' life—particularly packing and valving.

Every plunger operates independently, drawing from a common intake manifold into a shared discharge. Discharge occurs solely during the upstroke, which results in some pulsation, and hence pulsation dampers are frequently utilized.

Two common types of plunger systems exist. For oil service, a straightforward and efficient plunger-and-liner system is employed, comprising a closely fitted metallic plunger within a metallic liner. Spray metal coatings or other hard-facing techniques frequently extend the lifespan of both plunger and liner. For water pumping, however, a metal-to-metal system is impractical due to the necessity for an extremely close fit to prevent unacceptable leakage. Issues like galling and scoring arise from close fits along with the water's low lubricity; thus, spring-loaded packing systems are necessary and self-adjusting. High-strength aramid fibers combined with various compounds that enhance friction characteristics demonstrate substantial improvements in a pump's capacity to handle high-pressure water for prolonged durations. Nonetheless, water remains a more challenging fluid than oil, and systems designed for water exhibit enhanced durability when operated at or below 3,500 psi.

Suction conditions significantly affect multiplex function. Losses from friction in piping, fluid end porting, and suction valve operations reduce the pressure needed to refill the pumping chamber on the plunger's downstroke. Should these losses become considerable, cavitation may ensue. Additionally, for oil containing dissolved gas, reduced pressure can liberate free gas, leading to knocking—thus necessitating a positive head on the suction side to compensate for frictional losses. "Acceleration head" is another relevant measurement; the suction piping must speed up and slow down multiple times during each crankshaft rotation. The energy supplied during acceleration manifests as a pressure reduction in the fluid, and should this drop too severely, gas liberation or cavitation may occur. Thus, the minimum suction head for a multiplex pump is the sum of friction losses and the acceleration head. While a pump can create a vacuum, this leads to gas flashing and may inadvertently draw air across the valve or plunger packing. Manufacturers recommend specific suction charging pressures for their products, but it's crucial to recognize that extended lengths of small-diameter suction lines amplify both acceleration head loss and frictional loss. Therefore, it is advisable to maintain suction lines as short and large-diameter without high spots prone to trapping air or gas. Suction stabilizers or pulsation dampeners can absorb pump pulsations and thereby help reduce acceleration head; installers are encouraged to adhere to good piping practices when setting up surface pumps.

When adequate hydrostatic head is lacking for necessary suction pressure, charge pumps provide a pertinent solution. Positive displacement pumps, belonging to either the vane or crescent-gear types driven from the triplex, have extensive applications but require a pressure-control valve to bypass excess fluid and align multiplex displacement accordingly. If electrically powered options are available, centrifugal charge pumps have demonstrated superior performance. Centrifugal systems often require operation above the multiplex speed range, presenting various challenges, primarily when utilizing gas engine drives that introduce significant variability in charge-pump output pressure.

While suitable charging pressures are critical for proper loading and smooth operation, exceedingly high charge pressures provoke problems by adding to crankshaft loads. For pressures above 250 psi, it’s generally recommended to reduce the maximum discharge pressure by one-third of the charge pressure. Elevated charge pressures can adversely impact bearing lubrication, notably in the crosshead wristpin. Further, multiplex pumps display lower mechanical efficiency (3 to 5%) on the suction side compared to the discharge. Thus, the optimal efficiency combination of charge pump and multiplex pump arises with low charging pressures accompanied by significant support from the multiplex pump. This necessitates limiting the charging pressure exclusively to what is required for adequate filling of the multiplex pump with a moderate safety allowance to cover variations in operational parameters.

In certain scenarios, it might be beneficial to inject corrosion inhibitors or lubricants into the multiplex suction, while fresh water may be introduced for dissolving high salt concentrations. In demanding pumping applications with low-lubricity media, lubricating oils may be injected or applied through dripping on the plungers within the spacer block area to prolong plunger longevity. Injection pumps typically derive their drive from the multiplex drive for these functions. A troubleshooting guide for multiplex pumps is found in Table 14.8.

• Table 14.8

Fluid Controls

Various types of valves manage and distribute the power-fluid supply to one or more wellheads. Each free-pump system incorporates a four-way valve or wellhead control valve positioned at the wellhead, depicted in Fig. 14.18. This valve facilitates different operational modes through positional adjustments. To enable pump circulation into the well, as represented in Fig. 14.15, power fluid is directed down the main tubing string. Once the pump reaches the bottom and aligns with the standing valve, the power fluid begins operating the pump. During the pump-out mode, power fluid is routed down the return tubing or casing annulus to unseat the pump before bringing it back to the surface. When the pump is at the surface, the valve’s bypass and bleed position allows for venting the well, enabling the removal and replacement of the pump.

• Fig. 14.18-Wellhead control valve.

Typically, control systems entail a constant-pressure controller, illustrated in Fig. 14.19, that maintains a discharge-pressure load on the multiplex pump by continuously bypassing excess discharge fluid. Operating based on adjustable spring force on a piston-and-valve assembly that is pressure compensated, this controller maintains pressure on the high-pressure side, which adjusts automatically to changing loads. If the pressure increases, forces acting on various areas within the valve open it, allowing more fluid to bypass and restoring the high-pressure side to preset conditions. Jet pumps often operate under a constant-pressure valve as their primary control. Moreover, the constant-pressure controller can regulate pressure for manifold assemblies serving multiple wells.

Reciprocating downhole pumps are generally regulated using a constant-flow control valve. Supplying a constant volume of power fluid allows for maintaining a steady stroking rate downhole, despite fluctuations in the operating pressure linked to varying well conditions. Since this valve does not bypass fluid, it must work alongside a constant-pressure controller on the higher-pressure or inlet side.

Control Manifolds

Hydraulic pumping systems have advanced to utilize relatively high pressures while maintaining low flow rates. This innovation helps to reduce friction losses and enhances the lift capability and overall efficiency of the system. Surface operating pressures range between 2,000 and 4,000 psi. Higher pressures are particularly applied in deeper wells, and power-fluid rates can vary from a few hundred to over 3,000 B/D. Although some surface multistage centrifugal pumps are rated for this pressure range, they often exhibit inefficiency at the lower flow rates linked to single-well applications. Conversely, multistage centrifugals are more effective when pumping multiple wells from a centralized location. For a single well, or just a few, a high-head and low-specific-speed pump is requisite. The extensive experience amassed in the pumping industry has favored positive-displacement pumps for this application, with triplex or quintuplex pumps typically driven by gas engines or electric motors powering the majority of hydraulic pump installations. See Multiplex pumps consist of a power end and a fluid end. The power end encompasses a crankshaft housed in a crankcase, while the connecting rods are similar to those found in internal combustion engines but connect to crossheads rather than pistons. The fluid end contains individual plungers, each with spring-loaded intake and discharge check valves. This assembly is connected to the power end via a spacer block that contains the intermediate rods and provides a working area for access to the plunger system. Most oilfield units are configured horizontally to minimize crankcase oil contamination, yet vertical installations remain viable, particularly in applications where oil is the pumped fluid or where space constraints are a factor in townsite leases.Multiplex pumps utilized in hydraulic pumping typically feature stroke lengths ranging from 2 to 7 inches and plunger diameters between 1 and 2½ inches. Larger plungers yield increased flow rates but are usually rated for lower maximum pressure due to crankshaft loading limits. The standard continuous duty applications max out at 5,000 psi in multiplex ratings, with lower ratings applying for larger plungers; instances exceeding 4,000 psi remain uncommon. To reduce vibration and wear, multiplex pumps operate at low speeds, usually between 200 and 450 revolutions per minute (rev/min). Since this operates below the gas engines or electric motors' speeds, some form of speed reduction is typically necessary. While belt drives appear in some units, gear reduction is more common, and some multiplex models contain integrated gear-reduction units alongside separate options. Each pump series offers various reduction ratios. As a positive-displacement pump maintains a nearly constant discharge flow rate for a given prime-mover speed, bypassing excess fluid is generally necessary to meet specific pressure and flow demands. A successful approach is utilizing a four-speed transmission to drive the multiplex pump, allowing for enhanced flexibility. This arrangement provides closer tailoring of the triplex output to demand, effectively pumping at reduced speed when needed, which can lengthen the components' life, particularly packing and valving.

Every plunger operates independently, drawing from a common intake manifold into a shared discharge. Discharge occurs solely during the upstroke, which results in some pulsation, and thus pulsation dampers are frequently utilized.

Two common types of plunger systems exist. For oil service, a straightforward and effective plunger-and-liner system is employed, comprising a closely fitted metallic plunger within a metallic liner. Spray metal coatings or other hard-facing techniques frequently extend the lifespan of both plunger and liner. For water pumping, however, a metal-to-metal system is impractical due to the necessity for an extremely close fit to prevent unacceptable leakage. Issues like galling and scoring arise from close fits along with the water's low lubricity; thus, spring-loaded packing systems are necessary and self-adjusting. High-strength aramid fibers combined with various compounds that enhance friction characteristics demonstrate substantial improvements in a pump's capacity to handle high-pressure water for prolonged durations. Nonetheless, water remains a more challenging fluid than oil, and systems designed for water exhibit enhanced durability when operated at or below 3,500 psi.

Suction conditions significantly affect multiplex function. Losses from friction in piping, fluid end porting, and suction valve operations reduce the pressure needed to refill the pumping chamber on the plunger's downstroke. Should these losses become considerable, cavitation may ensue. Additionally, for oil containing dissolved gas, reduced pressure can liberate free gas, leading to knocking—thus necessitating a positive head on the suction side to compensate for frictional losses. "Acceleration head" is another pertinent measurement; the suction piping must speed up and slow down multiple times during each crankshaft rotation. The energy supplied during acceleration manifests as a pressure reduction in the fluid, and should this drop too severely, gas liberation or cavitation may occur. Thus, the minimum suction head for a multiplex pump is the sum of friction losses and the acceleration head. While a pump can create a vacuum, this leads to gas flashing and may inadvertently draw air across the valve or plunger packing. Manufacturers recommend specific suction charging pressures for their products. However, it's crucial to recognize that extended lengths of small-diameter suction lines amplify both acceleration head loss and frictional loss. Therefore, it is advisable to maintain suction lines as short and large-diameter without high spots prone to trapping air or gas. Suction stabilizers or pulsation dampeners can absorb pump pulsations and thereby help reduce acceleration head; installers are encouraged to adhere to good piping practices when setting up surface pumps.

When adequate hydrostatic head is lacking for necessary suction pressure, charge pumps provide a pertinent solution. Positive displacement pumps, belonging to either the vane or crescent-gear types driven from the triplex, have extensive applications but require a pressure-control valve to bypass excess fluid and align multiplex displacement accordingly. If electrically powered options are available, centrifugal charge pumps have demonstrated superior performance. Centrifugal systems often require operation above the multiplex speed range, presenting various challenges primarily when utilizing gas engine drives that introduce significant variability in charge-pump output pressure.

While suitable charging pressures are critical for proper loading and smooth operation, exceedingly high charge pressures provoke problems by adding to crankshaft loads. For pressures above 250 psi, it’s generally recommended to reduce the maximum discharge pressure by one-third of the charge pressure. Elevated charge pressures can adversely impact bearing lubrication, notably in the crosshead wristpin. Further, multiplex pumps display lower mechanical efficiency (3 to 5%) on the suction side compared to the discharge. Thus, the optimal efficiency combination of charge pump and multiplex pump arises with low charging pressures accompanied by significant support from the multiplex pump. This necessitates limiting the charging pressure exclusively to what is required for adequate filling of the multiplex pump with a moderate safety allowance to cover variations in operational parameters.

In certain scenarios, it might be beneficial to inject corrosion inhibitors or lubricants into the multiplex suction, while fresh water may be introduced for dissolving high salt concentrations. In demanding pumping applications with low-lubricity media, lubricating oils may be injected or applied through dripping on the plungers within the spacer block area to prolong plunger longevity. Injection pumps typically derive their drive from the multiplex drive for these functions. A troubleshooting guide for multiplex pumps is found in Various types of valves manage and distribute the power-fluid supply to one or more wellheads. Each free-pump system incorporates a four-way valve or wellhead control valve positioned at the wellhead, depicted in Fig. 14.18. This valve facilitates different operational modes through positional adjustments. To enable pump circulation into the well, as represented in Fig. 14.15, power fluid is directed down the main tubing string. Once the pump reaches the bottom and aligns with the standing valve, the power fluid begins operating the pump. During the pump-out mode, power fluid is routed down the return tubing or casing annulus to unseat the pump before bringing it back to the surface. When the pump is at the surface, the valve’s bypass and bleed position allows for venting the well, enabling the removal and replacement of the pump.

Most systems also incorporate a constant-pressure controller, depicted in Fig. 14.19, which maintains a discharge-pressure load on the multiplex pump by consistently bypassing excess discharge fluid. Operative on the principles of adjustable spring force applied to a pressure-compensated piston-and-valve assembly, this controller is crucial for managing pressure on the high-pressure side, adapting automatically to fluctuating system loads. If pressure rises, forces act within the valve, enabling it to open and permit excess fluid bypass thereby restoring conditions to the prescribed level.

Reciprocating downhole pumps typically use a constant-flow control valve. Supplying a steady volume of power fluid lets the downhole unit oscillate at a consistent stroking rate, while the constant-flow valve is crafted to ensure a prescribed flow rate even amidst changing downhole operating pressures. Since this valve does not facilitate fluid bypass, it must pair with a constant-pressure controller on the higher-pressure or inlet side.

Lubricator

Some wells experience backflow when exiting or entering the pump into the wellhead. The presence of water can complicate opening up the entire tubing string for pump manipulation. Implementing a lubricator allows for closure of the master valve beneath the wellhead, thus facilitating removal of the full lubricator assembly containing the pump without compromising well integrity. Essentially, lubricators serve as lengthened tubing segments equipped with a sideline facilitating fluid flow during pump movements.

Power-Fluid Systems

The surface treatment systems aim to maintain a consistent supply of suitable power fluid for operating downhole production units. The efficient and economical performance of any hydraulic pumping system largely hinges on the treating system's capacity to deliver high-quality power fluids. Contaminants such as gas, solids, and abrasive particles adversely affect both surface and downhole unit operation and longevity. Consequently, the primary goal behind treating crude oil or water for use as power fluid is to eliminate as much gas and solids as possible. Testing indicates that maximizing total solids to 20 ppm, restricting salt content to 12 lbm/1,000 bbl oil, and capping particle size at 15 μm yield optimal functioning parameters. (These benchmarks were derived from oil with API gravities in the 30 to 40 range.) Despite these thresholds, it bears noting that satisfactory performances have often occurred despite exceeding the specified limits, particularly in jet pump applications and larger nozzle configurations. Conversely, hydraulic pumps utilizing heavy crude typically surpassed these thresholds, yet the wear incurred didn’t increase leakage proportionately. Regular power fluid analyses allow for trends in operational efficiency; for instance, observing iron sulfide or sulfate elements suggesting significant solid content indicates a critical need for chemical inhibitors to mitigate corrosion or scaling issues. Water serves as the primary power fluid in jet pumping, especially on offshore platforms where produced fluids primarily comprise water. Water application demands lubricants for use with reciprocating pumps. Several factors impact the water/oil choice for power fluids:

• Surface pump maintenance generally incurs lesser costs with oil utilization. The oil’s lower bulk modulus enhances reduced pressure pulsations, positively impacting the entirety of surface equipment.
• Testing oil output is more straightforward with water as the power fluid since all returned output is produced oil. When applying oil power fluid, careful metering must occur alongside deducting from total output, which could lead to substantial measurement inaccuracies in high-water-cut wells where the power oil rate is considerable relative to net production.
• In high-friction scenarios, which occasionally manifest with jet pumps within restricted tubular configurations, the lower viscosity of water increases efficiency. In contrast, as jet pumps possess no moving parts, they remain unaffected by water's poor lubrication properties.
• In deep casing installations, particularly combined with jet pumps, the use of water as a power fluid can render burdensome buildup in annulus returns, negating gas-lifting benefits.

In most cases, a vertical velocity of 1ft/hr suffices to ensure satisfactory gravitational separation of entrained particles, generating clean power fluid, provided no free gas exists in the fluids or significant thermal effects disturb the scenario.

Open Power-Fluid System

A conventional power-oil treatment system deemed adequate for most Open Power-Fluid (OPF) systems operating under stock-tank quality oil conditions is depicted in Fig. 14.20. This approach mandates that all return fluids from the well—production and power fluid alike—must traverse the surface treatment facility. Typically, the power-oil settling tank measures 24 feet in height and consists of three bolted steel rings. Such a height habitually provides sufficient gravity-head for oil transfer to pump suction. Individual power-oil tanks may be established for multiple pumps or a single large tank, contingent upon operational requirements and cost-effectiveness. Outlet structuring is preferred where multiple pumps pull suction from a single tank.

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

The gas boot constitutes an integral feature of the power-oil tank, designed to yield final gas/oil separation, ensuring stability of oil at near-atmospheric pressures. Should gaseous components remain insufficiently detached from oil, the entrance of free gas into the power-oil tank could disrupt settling processes, agitating fluid therein. The following piping specifications for the gas boot are crucial to secure undisturbed settling outcomes:

• The gas-boot inlet height should extend 4 ft above the top of the power-oil tank. This ensures incoming fluid falls, promoting agitation to facilitate gas/oil separation.
• The gas boot's upper section, ideally 3 ft in diameter and exceeding the top of the power-oil tank by 8 ft, creates a reservoir to absorb surge volumes.
• The gas line extending from the boot's top needs proper jointing into the power-oil tank and the stock-tank vent line via a riser positioned atop the power-oil tank. Should the gas boot become jostled, this setup guarantees that raw or unsettled fluid does not contaminate that fed into the multiplex pump.
• At minimum, 3-in. diameter is recommended for the gas line.
• Similarly, the line connecting the gas boot to the power-oil tank should measure no less than 4-in. in diameter, preventing restrictions during surge scenarios.

A conventional power-oil treatment system deemed adequate for most Open Power-Fluid (OPF) systems operating under stock-tank quality oil conditions is depicted in Fig. 14.20. This approach mandates that all return fluids from the well—production and power fluid alike—must traverse the surface treatment facility.

The incoming oil to a large tank (at the base and ascending to be withdrawn from the top) tends to exhibit channeling behavior due to its inlet—hence, an inlet spreader becomes necessary. The spreader's primary task involves voltage reduction by distributing the fluid volume across extensive areas, thus facilitating even upward flow rates. An effective spreader is a flat plate roughly half the tank diameter fitted with a skirt featuring triangular saw-tooth slots (60°) that automatically adjust to varying flow levels. Ensuring uniform slot depth prevents lean flow and assists consistent flux distribution. Installation should maintain the tops of every slot in a level plane, placing it about 2 ft above the tank's bottom rim.

The positioning of the stock-tank take-off and level control plays a vital role, determining the effective settling duration within the power-oil tank while simultaneously governing fluid levels. All fluid traveling from the spreader ascends to the stock take-off elevation, leading to the withdrawal of stock-tank oil. The rising fluid above this threshold solely compensates for the volume extracted via the multiplex pump, coinciding with the pivotal part of the settling process. Lighter solids settle during this phase and are transported onboard stock-tank oil, while heavier material settles to the bottom, necessitating periodic extraction. The stock take-off should reside within 6 ft of the spreader.

The fluid level within the tank hinges upon the height stipulated for its connectivity to the stock take-off. Pipe diameter must accommodate flow requirements sufficiently (a minimum 4-in. diameter is advisable). At the gas line's upper extent, it should also connect to provide egress, preventing siphoning of oil from within the power-oil tank to the stock tank’s elevation.

The power-oil outlet typically installs on the power-oil tank’s opposite side from the stock take-off, aiding flow distribution throughout the tank. If implemented, the gas vent and rising pipe facilitate necessary pressure management to stabilize flow from the stock tank into the power-oil tank.

Fluid trajectory alteration necessitates close review, permitting possible operational fluid economy across the gathering system.

Closed Power-Fluid Systems

Closed power-fluid systems signify that the power fluid returns to the surface via a distinct conduit and does not pass through surface production treatment facilities. This resulting diminishment in surface treatment facilities can offset additional downhole system costs. The vast majority of closed power-fluid systems are located in California, dictating the substantial arrangements due to myriad townsite leases and offshore platforms. Water typically serves as the primary power fluid. Gravity settling separates constituents effectively within the power-fluid tank, guaranteeing elevated fluid cleanliness despite incorporation of solids via makeup, corrosion residues, and contamination ensuing from pumping operations. Administrative makeup of power fluid serves in replacing minor losses through pump and valve seals.

Single-Well Systems

The previously discussed central battery systems have succeeded over the years, yielding numerous advantages. Incorporating lease fluid treatment facilities into hydraulic systems guarantees low-pressure efficient separation of gaseous, liquid, and solid phases characterizing any system. Consistent triplex charging of clean, gas-free oil plus reliably clean power fluid for the downhole pump constitute invaluable system assets. However, the lease treatment facilities must have ample capacity to process well production alongside return power fluid. When wells are closely spaced together, clustering power generation, fluid treatment, and control functions at a single location optimizes efficiency and leverages installed horsepower. This allows adequate supply of the chosen power fluid irrespective of production variation across individual wells, ensuring functionality with a suspended closed-system option. In situations involving larger well spacing, consequential demands necessitate long, high-pressure power-fluid lines. Furthermore, testing accomplished for each well is confounded by required metering of power-fluid rates, potentially resulting in measurement inaccuracies. Final considerations highlight that only a select few wells within any field might be ideally suited for hydraulic pumping through artificial lift, which complicates justifying the integration of a central system.

To address inherent limits within central battery systems, single-well systems have been designed. Many requirements for effective operation are akin to those in central systems. Specific separation of liquid, gas, oil, and solid phases ensures the supply of a consistent power fluid for running the system operates effectively, offering choices between water or oil power fluids. The selected power fluid must maintain consistent cleanliness and gas-free conditions at the multiplex suction to inhibit cavitation or partial loading in the fluid end. A sufficient fluid reservoir must ensure uninterrupted operation and facilitate various circulatory functionalities associated with free-pump protocols. Moreover, logical provisions must exist for production disposal alongside measurement contraints directing well production to treatment and storage facilities.

To meet these goals, several manufacturers of hydraulic pumping units provide packaged single-well systems encompassing all necessary control, measuring, and pumping equipment. Generally, all components are skid mounted for ease of well installation, enabling portability if relocation becomes relevant. Typically, the only installations necessary are power fluid and return line setups at the wellhead, connecting the vessel outlet to the flowline.

An exemplar of a typical single-well power unit is provided in Fig. 14.1. All units of this type incorporate fundamental design principles, diverging slightly by manufacturer. One or two pressure vessels generally reside at the well site. The reservoir vessel size is contingent on well specifics and tubular completions. The reservoir vessel must accommodate capacity such that if the wellhead partially discontinues the return conduit to the flowline, sufficient capacity remains to utilize the downhole unit until production resumes within that vessel.

Even with instances of heading, added capacity proves necessary. During unit maintenance or pump replacement, any gas-containing segment must be replenished from the reservoir to conclude the unseating process before circulating back to the surface. Regular vessel sizes fall between 42 × 120 in. and 60 × 240 in. In certain well scenarios, even maximized size vessels cannot fully compensate for heading, rendering backpressure stabilization a commonly utilized solution. The vessels themselves typically operate within a working pressure range of 175 to 240 psi, with special designs for unique applications. Conventional coal-tar-epoxy internal coatings work well, alongside tailored coatings suited for extreme conditions.

Subsequent return power fluid alongside well production flow into the vessel system, wherein basic separation of water, oil, and gas occurs. Any free gas at vessel pressure is discharged into the flowline using a vent system that maintains a gas cap within the vessel throughout operations. Concurrently, oil and water phases separate in the vessel, followed by preferential extraction of high-quality fluid designated for use as a power fluid. Power fluid traverses through one or more cyclone desanders, ensuring proper solid removal before entering the multiplex suction for reinjection down the power-fluid tubing. Any multiplex output that remains bypassed for control returns to the vessel. The desander’s underflow—characterized by high solids—gets discharged back into the flowline or the vessel system. Once stabilized, the designated power fluid permits delivered oil, gas, and water production to flow seamlessly into the flowline from the vessel, maintained at pressure above that of the flowline. Since the flowline only conveys produced fluids, additional treatment operations are unnecessary, as compared to conventional central battery systems that handle mixed production alongside power fluid. This capability further supports independent well evaluations.

In summary, gravity-driven pipe systems controlling the vessel fluid levels comprise effective methodologies. To avert undesired siphoning from the vessel, attaching the gas vent line atop the riser serves as a siphon break. Deciding on water or oil power fluid follows from the selection of appropriate vessel takeoff points for routing production to the flowline and power fluid to the multiplex pump. In general, if the multiplex suction measurements trend lower than the vessel while the corresponding flowline indicators trend higher, water tends to concentrate in the vessel, establishing itself as the power fluid. Conversely, if multiplex suction levels exceed flowline volumes, oil is more likely to define fluid conditions. Setting appropriate valve openings or closures solidifies the system’s power fluid specificity. The multiplex suction outlets occupy strategic placements in relation to the overall fluid levels in the vessel to avoid drawing power fluid from the emulsion layer intersecting both oil and water, which ordinarily contains an elevated solids concentration and poses cleaning challenges during cyclone operation.

Cyclone desanders perform power fluid cleanup tasks requiring sufficient pressure differential. In configurations featuring dual vessels, the differential pressure valve facilitates a natural acclimatization of pressure drop during wellhead management. The multiplex pump supplies requisite energy to uphold this staged pressure. Flow patterns through a cyclone cleaner are referenced in Fig. 14.21. Fluid enters the top of the cone tangentially through its feed nozzle, spiraling downward toward the apex. Conservation of angular momentum demands a heightened rotational fluid velocity as the radius contracts, allowing centrifugal force to cleanse the fluid. The clean overflow spirals back up through the vortex core while dirty materials exit through the apex’ underflow nozzle. Collins are generally made from cast iron lined with elastomer elements. Varieties of feed nozzle, vortex finder model configurations, feature variance in performance characteristics. Varieties in cyclone sizes offer differences in flow capacities against cleaning efficiency ratios.

Maintaining proper cyclone flow demands accurately set pressures at the feed nozzle, overflow, and underflow levels. Generally, during designed flow rates, a pressure drop of 30 to 50 psi arises from feed nozzle down to overflowing components. Utilizing a charged pump, a single vessel maintains this pressure structure, whereas in dual-vessel designs, backpressure necessitates provision from returns. The centrifugal head affixed upon the cyclone overflow often sees pressure levied at 5–15 psi more than in the underflow sectors. An underflow restrictor typically adjusts downflow to between 5 and 10% of the overflow quantity. This linkage assuredly garners effective cleansing without circulating excess fluid volumes. It’s imperative to note that volume flow rates through a cyclone invert inversely with fluid specific gravity; generally speaking, increased viscosity augments flow rates, attributed to viscosity that suppresses internal vortex actions. Thus, precision cyclone sizing matching charge and multiplex pump specifications necessitates careful consideration, grounded in fluid processing knowledge aligning with operational frameworks. Manufacturers conducting these operations supply compatible cyclone systems, yet it’s crucial to ensure portability corollary with initialization at varied well sites necessitates system nuances.

Routing of the dirty underflow displays variability across distinct systems, manifesting adjustment options across implementations. Two fundamental choices exist: routing the underflow back to the vessel or directly towards the flowline. In dual-vessel schemes, the underflow must be directed to a flowline downstream of the backpressure valve to ensure sufficient pressure divergence validates underflow functions. Handling of solids discharged to the flowline offers prompt disposal segregating potential introduction into power fluid. Continuous operation may risk discontinuities in scenarios where the net well profit wanes below underflow contributions for any extended duration, thereby risking unaddressed apex plugging during shutoff cycles. Channeling the underflow into the vessel eliminates the risk of depleting vessel resources, although re-contamination of power fluids remains a concern. In single-vessel designs, adjacent baffled sections permit optimal resource conservation while necessitating a differential pressure valve between the cyclone underflow and vessel with adjustments typically set around 20 psi to ensure positive underflow pressure.

Moreover, vessel pressures maintained above flowline regulations guarantee seamless fluid transitioning while enforcement protocols find function within backpressure control valves. Through this mechanism, overarching vessel pressures imposing backpressure upon the well remain nurtured as a minimized range for flowline pressures that manifest under normal field manipulations. Implementing water as the power fluid invites propriety regarding matching pressure levels; however, successive alterations to vessel pressures could instigate gas-flashing within power oil harming multiplex pressures. Thus meticulous attention mandates employing pressure control valves, allowing stable pressure maintenance 10 to 15 psi above peak expected flowline pressures.

Although the single-vessel system aligns with applications accommodating widely distributed wells, two or more wells successfully function from single-well systems. This setup proves advantageous in offshore platforms. Significant adaptability from extensive, highly deviated wells showcases offshore production dynamics favoring hydraulic pumping with free pumps, but the extra fluid treatment facilities accompanying open power-fluid systems produce drawbacks under critical weight and space thresholds. The closed power-fluid system effectively addresses such challenges; nonetheless, additional tubulars involved in deviated pathways yield unique challenges and expenses. Importantly, jet pumps, often appealing in offshore conditions, don’t operate facilitated under closed power-fluid systems. To enhance safety and protect environmental integrity, water typically presents itself as the primary power fluid offshore, allowing single-well systems to accept returns from multiple wells facilitating power-water segregation essential for re-injection tied to downhole units. Achieving complete separation of oil within the power-water framework isn't necessary; minimal oil carryover aids power fluid lubrication, allowing platform separation facilities solely to address production liquidity from wells. Within cyclone cleaners, compact operations furnish the power-fluid separation and cleansing unit.

In general, hydraulic systems prevail within areas where other forms of artificial lifts prove ineffectual or precluded due to existing well conditions. Hydraulic pumping systems face common misconceptions regarding high operational expenses—even as alternative artificial lift systems may present feasibility hurdles. These obstacles include, but are not limited to:

• Deployment of hydraulic free pumps within remote sectors where rig costs surge beyond normal making workover accessibility scarce.
• Operational aptitudes for crooked or deviated wells.
• Hydraulic systems adapted for relatively deep, hot, and high-volume wells. (Hydraulic pumps can maneuver through tubing with increases reaching 24° per 100 ft.)
• Utilization of jet pumps amid sandy corrosive wells.
• Reciprocating pump applications within expansive wells characterized by low bottomhole producing pressures.
• Effective management of wells exhibiting rapid production fluctuations.
• Utilizing jet pumping systems in wells producing low gas-to-liquid ratios lower than 750:1 where free gas must be extracted beneath packers.
• Curating hydraulic free pumps serving wells rich in paraffins.
• Implementing hydraulic OPF systems across low-API-gravity wells.

The central battery systems previously discussed have succeeded over the years, yielding numerous advantages. Incorporating lease fluid treatment facilities into hydraulic systems guarantees low-pressure efficient separation of gaseous, liquid, and solid phases characterizing any system. Consistent triplex charging of clean, gas-free oil plus reliably clean power fluid for the downhole pump constitute invaluable system assets. However, the lease treatment facilities must have ample capacity to process well production alongside return power fluid. When wells are closely spaced together, clustering power generation, fluid treatment, and control functions at a single location optimizes efficiency and leverages installed horsepower. This allows adequate supply of the chosen power fluid irrespective of production variation across individual wells, ensuring functionality with a suspended closed-system option. In situations involving larger well spacing, consequential demands necessitate long, high-pressure power-fluid lines. Furthermore, testing accomplished for each well is confounded by required metering of power-fluid rates, potentially resulting in measurement inaccuracies. Final considerations highlight that only a select few wells within any field might be ideally suited for hydraulic pumping through artificial lift, which complicates justifying the integration of a central system.

To address inherent limits within central battery systems, single-well systems have been designed. Many requirements for effective operation are akin to those in central systems.

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