Artificial Lift Overview PDF

Artificial Lift Overview Artificial Lift Overview 1. Introduction to Artificial Lift 2. Selecting an Artificial Lift Method Gas Lift 1. Gas Lift System Overview 2. Gas Lift Applications 3. Downhole Installations 4. Gas Lift Valves 5. Gas Lift Valve Mechanics 6. Continuous Ga...

Artificial Lift Overview Artificial Lift Overview 1. Introduction to Artificial Lift 2. Selecting an Artificial Lift Method Gas Lift 1. Gas Lift System Overview 2. Gas Lift Applications 3. Downhole Installations 4. Gas Lift Valves 5. Gas Lift Valve Mechanics 6. Continuous Gas Lift 7. Intermittent Gas Lift 8. Practical Aspects of Well Unloading and Operation 9. Gas Lift Surface Facilities Reciprocating Rod Pump Systems 1. Rod Pumping Overview 2. Surface Equipment 3. Subsurface Equipment 4. Subsurface Pump Selection 5. Rod String Design 6. API System Design Procedure 7. Pumping Unit Design Procedure – Rapid Analysis 8. Polished Rod Dynamometers 9. Rod Load Versus Displacement 10. System Monitoring: Dynagraphs Progressive Cavity Pump Systems 1. PCP System Overview 2. PCP System Components 3. PCP System Applications 4. PCP System Design and Installation 5. PCP Operation Hydraulic Pump Systems 1. Hydraulic Pumping: Overview 2. Subsurface Hydraulic Pumps 3. Downhole Installations  4. Surface Facilities 5. Reciprocating Pumps: System Design 6. Reciprocating Pumps: Operating Considerations 7. Jet Pumps: Design and Operation Electrical Submersible Pump Systems 1. ESP System Overview 2. ESP Power Components 3. ESP Operating Principles 4. ESP System Design 5. ESP System Operation Plunger Lift Systems 1. Plunger Lift Overview 2. Plunger Lift Design and Installation Introduction to Artificial Lift The Inflow Performance Relationship (IPR), defines a well’s flowing production potential: 𝑞 = 𝑃𝐼 ∙ (𝑝̅𝑅 − 𝑝𝑤𝑓 ) where q = production rate, B/D PI = productivity index, B/D/psi p¯R = average reservoir pressure, psi pwf = flowing bottomhole pressure psi Figure 1 illustrates this relationship for a solution gas drive reservoir. Note that for a given average reservoir pressure and productivity index, PW determines the well’s production potential. The lower the flowing bottomhole pressure, the higher the production rate. The well’s maximum or absolute open flow (AOF) potential would correspond to a flowing sandface pressure, pwf, of zero. Figure 1: IPR for a gas drive reservoir Figure 2 illustrates the potential improvement in production by introducing artificial lift. Figure 2: Potential improvement in production using artificial lift A well never actually attains its absolute flow potential, because for it to flow, pwf must exceed the backpressure that the producing fluid exerts on the formation as it moves through the production system. This backpressure, or bottomhole pressure, has the following components: Hydrostatic pressure of the producing fluid column Friction pressure caused by fluid movement through the tubing, wellhead, and surface equipment Kinetic or potential losses due to diameter restrictions, pipe bends, or elevation changes. In most production systems, these losses are not of the same magnitude as hydrostatic or friction pressures; in others, however, they may be significant. Artificial lift is a means of "artificially" reducing a well's bottomhole pressure so that it can produce at some improved rate. This is accomplished either by injecting gas into the producing fluid column to reduce the density of the column–and thus its hydrostatic pressure–or by using a downhole pump, plunger or compressed gas slug to physically displace the fluid to surface. Artificial lift is often associated with mature, depleted fields, where p¯R has declined such that the reservoir can no longer produce under its natural energy. But these methods are also used in younger fields to increase early time production rates and improve project economics. Artificial Lift Methods The two major categories of artificial lift are gas lift and pump-assisted lift. A third hybrid approach, plunger lift, combines elements of both categories, and is used primarily in gas and high gas/oil ratio (GOR) wells to produce relatively small volumes of liquid. Gas Lift In a gas lift well, high pressure gas is injected down the well annulus, between the casing and production tubing, and into the producing fluid column through one or more subsurface valves set at predetermined depths (Figure 3). Figure 3: Gas lift system The two main types of gas lift are continuous gas lift and intermittent gas lift.  Continuous gas lift, used in most gas lift applications, injects gas in a constant, uninterrupted stream. This lowers the overall density of the fluid column and reduces the hydrostatic component of the flowing bottomhole pressure. Thus, for a given average reservoir pressure and productivity index, the well is able to flow at a higher rate. This method is generally applied to wells with high productivity indexes and high bottomhole pressures relative to their depths. Intermittent gas lift is designed for lower-productivity wells, where a volume of formation fluid accumulates inside the production tubing. In this type of gas lift installation, a high-pressure “slug” of gas is injected below the liquid, physically displacing it to the surface. As soon as the fluid is produced, gas injection is interrupted, and the cycle of liquid accumulation-gas injection-liquid production is repeated. Advantages and Disadvantages of Gas Lift The availability of gas and the costs for compression and injection are major considerations in planning a gas lift installation. Where these gas injection requirements can be satisfied, gas lift offers a flexible means of optimizing production. It can be used in deviated or crooked wellbores, and in high-temperature environments that might adversely affect other lift methods, and it is conducive to maximizing lift efficiency in high-GOR wells. Wireline-retrievable gas lift valves can be pulled and reinstalled without pulling the tubing, making it relatively easy and economical to modify the design. On the negative side, additional costs for gas processing and surface compression can adversely affect profitability. Corrosion and paraffin formation tend to increase system pressure losses and reduce lift efficiency. System efficiency is also sensitive to tubing diameter and surface flowline length. Another disadvantage of gas lift is its inherently higher bottomhole pressure compared with pump-assisted lift systems. This makes it difficult to fully deplete low- pressure, low-productivity wells. Also, the start-and-stop nature of intermittent gas lift may cause downhole pressure surges and lead to increased sand production. Pump-Assisted Lift The vast majority of wells (more than 85%) that utilize artificial lift technology use pump assisted lift. Downhole pumps mechanically lift fluid to the surface and in turn lower the backpressure on the formation, pwf. These pumps fall into two basic categories: positive displacement pumps and dynamic displacement pumps. A positive displacement pump works by moving fluid from a suction chamber to a discharge chamber. The suction chamber volume increases as the discharge chamber volume decreases, causing fluid to enter the suction chamber. As the cycle reverses, the  suction volume decreases and the discharge volume increases, forcing the fluid to the discharge end of the pump. This basic operating principle applies to reciprocating rod pumps, hydraulic piston pumps and progressive cavity pumps (PCPs). A dynamic displacement pump works by causing fluid to move from inlet to outlet under its own momentum, as is the case with a centrifugal pump. Dynamic displacement pumps commonly used in artificial lift include electrical submersible pumps (ESPs) and hydraulic jet pumps. Reciprocating Rod Pump Systems A reciprocating rod pump system is made up of the following components (Figure 4): A beam pumping unit, operated by an electric motor or gas engine A string of steel or fiberglass sucker rods that connect the beam pumping unit to the downhole pump A subsurface pump, which consists of a barrel, plunger and valve assembly that moves fluid through the tubing and up to the surface Figure 4: Rod pumping system Beam pumping is the most common and arguably the most recognizable artificial lift method. It can be used for a wide range of production rates and operating conditions, and rod pump systems are relatively simple to operate and maintain. However, the volumetric efficiency (capacity) of a rod pump is lower in wells with high gas-liquid ratios, small tubing diameters, or deep producing intervals. Highly deviated wells also may incur tubing wear problems due to the angle of decline. The surface equipment requires more space than other lift methods, and the initial installation may involve relatively high capital costs. Progressive Cavity Pump (PCP) Systems A progressive cavity pump consists of a spiral rotor that turns eccentrically inside an elastomer- lined stator (Figure 5). Figure 5: PCP system As the rotor turns, cavities between the threads of the pump rotor and stator move upward. The rotor is most often powered by rods connected to a motor on the surface, although some assemblies are driven by subsurface electric motors. Progressive cavity pumps are commonly used for dewatering coal bed methane gas wells, for production and injection applications in waterflood projects, and for producing heavy or high- solids oil. They are versatile, generally very efficient, and excellent for handling fluids with high solids content. However, because of the torsional stresses placed on rod strings and temperature limitations on the stator elastomers, they are not used in deeper wells. Hydraulic Pump Systems Hydraulic pump systems inject a power fluid—usually light oil or water—from the surface to operate a downhole pump. Multiple wells can be produced using a single surface power fluid installation (Figure 6). Figure 6: Hydraulic pumping system Downhole hydraulic pumps may be either of two types. With a reciprocating hydraulic pump, the injected power fluid operates a downhole fluid engine, which drives a piston to pump formation fluid and spent power fluid to the surface. A hydraulic jet pump has no moving parts. Power fluid is injected into the pump body and into a small-diameter nozzle, where it becomes a low-pressure, high-velocity jet. Formation fluid mixes with the power fluid, and then passes into an expanding-  diameter diffuser. This reduces the velocity of the fluid mixture, while causing its pressure to increase to a level that is sufficient to lift it to the surface. Advantages and Disadvantages of Hydraulic Pumping Systems Advantages Disadvantages Can be used at depths from 1,000 to 17,000 The potential fire hazard if feet. oil is used as a power fluid. Capable of producing at rates from 100 to Difficulty in pumping 10,000 B/D. produced fluids with high Can be hydraulically circulated in and out of solids content. the well, thus eliminating the need for Effects of gas on pump wireline or rig operations to replace pumps, efficiency. making this system adaptable to changing Dual strings of tubing field conditions. needed on some Heavy, viscous fluids are easier to lift after installations. mixing with the lighter power fluid. Electrical Submersible Pumps An electric submersible pumping (ESP) assembly consists of a downhole centrifugal pump driven by a submersible electric motor, which is connected to a power source at the surface (Figure 7).  Figure 7: ESP system The pump and motor assembly, which may be several hundred feet long, is connected to the surface by an armored cable that provides electric power and control. Advantages and Disadvantages of Electrical Submersible Pumps Advantages Disadvantages On a cost-per-barrel basis, ESP systems are ESP pumps can be damaged among the most efficient and economical of lift from “gas lock” or sand methods, especially in high volume applications. production. Fluid volumes ranging from 100 to 60,000 B/D, In wells producing high GOR including high water-cut production, can be fluids, a downhole gas handled by ESP systems. separator must be installed. ESP systems can be installed in high-temperature ESP pumps have limited wells (above 350°F) using high-temperature production ranges determined motors and cables. by the number and type of pump stages; changing  Advantages Disadvantages The pumps can be modified to lift corrosive fluids production rates requires either and sand. a pump change or installation of ESP systems can be used in high-angle and a variable-speed surface drive. horizontal wells if placed in straight or vertical The tubing must be pulled for sections of the well. pump repairs or replacement. Plunger Lift Plunger lift is the only artificial lift method that relies solely on the well’s natural energy to lift fluids. The plunger, sometimes called a “rabbit”, is automatically dropped from the surface inside the production tubing after a reduction in pressure or production rate due to fluid starting to accumulate in the bottom of the well bore. Once the plunger is dropped and reaches the bottom of the tubing, it moves upward when the pressure of the gas below it is greater than the pressure of the liquid above it (Figure 8). Figure 8: Plunger lift system As the plunger travels to the surface, it creates a solid interface between the lifted gas below and produced fluid above to maximize lifting energy. Any gas that bypasses the plunger during the lifting cycle flows up the production tubing and sweeps the area to minimize liquid fallback. Once the plunger and liquid reaches the well head, it is “caught” and held at the surface until the next reduction in rate/pressure is sensed. Plunger lift provides a cost-effective method of artificial lift that can be used to efficiently produce both gas wells with fluid loads and high GOR oil wells. Selecting an Artificial Lift Method Artificial lift considerations should ideally be part of the well planning process. Future lift requirements will be based on the overall reservoir exploitation strategy, and will have a strong impact on the well’s design. Initial Screening Criteria Table 1 describes reservoir characteristics, and Table 2 describes surface and field operating considerations that influence the selection of an artificial lift method. Table 1: Reservoir and Hole Considerations in Selecting an Artificial Lift Method (after Brown, 1980) Reservoir Characteristics: IPR A well’s inflow performance relationship defines its production potential and helps bracket the maximum lift capacity needed. Liquid The anticipated production rate is a controlling factor in selecting a lift method. Production Rate Positive displacement pumps are generally limited to rates of 4000-6000 B/D. Water Cut High water cuts require a lift method that can move large volumes of fluid. Gas-Liquid A high GLR generally lowers the efficiency of pump-assisted and gas lift systems. Ratio Viscosity Viscosities less than 10 cp are generally not a factor in selecting a lift method. High-viscosity fluids can cause difficulty, particularly in sucker rod pumping where the rods and ball valves cannot sink and seat properly in the viscous crude. Formation The ratio of reservoir volume to surface volume determines how much total fluid Volume Factor must be lifted to achieve the desired surface production rate. Reservoir Drive Depletion drive reservoirs: Late-stage production will usually require pumping to Mechanism produce low fluid volumes or injected water. Water drive reservoirs: High water cuts may cause problems for lifting systems (see Water Cut above). Gas cap drive reservoirs: Increasing gas-liquid ratios may affect lift efficiency (see Gas Liquid Ratio above). Table 1: Reservoir and Hole Considerations in Selecting an Artificial Lift Method (after Brown, 1980) Other Reservoir Sand, paraffin, or scale can cause plugging and/or abrasion and wear. Presence of Problems H2S, CO2 or salt water can cause corrosion. Downhole emulsions can increase backpressure and reduce lifting efficiency. High bottomhole temperatures can affect downhole equipment. Well Characteristics: Well Depth The well depth dictates how much surface energy is needed to move fluids to surface, and may place limits on sucker rods and other equipment. Completion Completion and perforation skin factors affect inflow performance. Type Casing and Small-diameter casing limits the production tubing size and constrains multiple Tubing Sizes options. Small-diameter tubing will limit production rates, but larger tubing may allow excessive fluid fallback. Wellbore Highly deviated wells may limit applications of beam pumping or progressive Deviation cavity pump systems because of drag, compressive forces, and potential for rod and tubing wear. Table 2: Surface and Field Operating Considerations in Selecting an Artificial Lift Method (after Brown, 1980) Surface Characteristics: Flow Rates Flow rates are governed by wellhead pressures and backpressures in surface production equipment (i.e., separators, chokes and flow lines). Flowline Size Flowline length and diameter determines wellhead pressure requirements and and Length affects the overall performance of the production system. Fluid Scale, paraffin, or salt can increase the backpressure on a well. Contaminants  Table 1: Reservoir and Hole Considerations in Selecting an Artificial Lift Method (after Brown, 1980) Power Sources The availability of electricity or natural gas governs the type of artificial lift selected. Diesel, propane, or other sources may also be considered. Field Location For offshore fields, the availability of platform space and placement of directional wells are primary considerations. For onshore fields, such factors as noise limits, safety, environmental, pollution concerns, surface access, and well spacing must be considered. Climate and The climate and physical environment affect the performance of surface Physical equipment. Environment Field Operating Characteristics: Long-Range Field conditions may change over time. Recovery Plans Pressure Water or gas injection may change the artificial lift requirements for a field. Maintenance Operations Enhanced Oil EOR processes may change fluid properties and require changes in the artificial Recovery lift system. Projects Field If the surface control equipment will be electrically powered, an electrically Automation powered artificial lift system should be considered. Availability of Some artificial lift systems are relatively low-maintenance; others require regular Operating and monitoring and adjustment. Servicing requirements should be considered (for Service example, workover rig versus wireline unit). Familiarity of field personnel with Personnel and Support Services equipment should also be taken into account. In an article written for the SPE Distinguished Author Series, Clegg, Bucaram and Hein (1993), observe that “selecting the proper artificial lift method is critical to the long-term profitability of most producing oil and gas wells.” They list 31 attributes for comparing the eight most common artificial lift techniques (continuous and intermittent gas lift, beam pumping, progressing cavity pumping, hydraulic pumping, electric submersible pumping, jet pumping and plunger lift), and provide practical guidelines for assessing each method’s capabilities. These guidelines are summarized as follows: Design considerations and overall comparisons: Capital cost Operating costs Downhole equipment Reliability Efficiency Salvage value Flexibility System (total) Miscellaneous operating Usage/outlook problems Normal operating considerations: Casing size limits Prime mover flexibility Depth limits Surveillance Intake capabilities Testing Noise level Time cycle and pump-off controllers Obtrusiveness application Artificial lift considerations: Corrosive/scale handling Slim-hole completions ability Solids/sand-handling ability Crooked/deviated holes Temperature limitations Multiple completions High-viscosity fluid handling Gas-handling ability High-volume lift capabilities Offshore application Low-volume lift capabilities Paraffin-handling capability Table 3 summarizes typical characteristics and applications for each form of artificial lift. These are general guidelines, which vary among manufacturers and researchers. Each application needs to be evaluated on a well-by-well basis. Table 3: Artificial Lift Methods—Characteristics and Areas of Application (after Weatherford, 2005) Positive Displacement Pumps Dynamic Displacement Pumps Operating Parameters Gas Lift Plunger Lift Hydraulic Rod Pump PCP ESP Hydraulic Jet Piston Typical Operating 100 to 2000 to 7500 to 5000 to 5000 to To 8000 ft (TVD) 11000 ft 4500 ft 10000 ft 10000 ft 10000 ft Max. Oper. (TVD) 16000 ft 6000 ft 17000 ft 15000 ft 15000 ft 15000 ft 20000 ft 100 - Typical Oper. 5 - 1500 5 - 2200 50 - 500 300 - 4000 100 - 10000 1 - 5 30000 Volume BFPD BFPD BFPD BFPD BFPD BFPD BFPD Max. Oper. Temp. 550 ºF 250 ºF 500 ºF 400 ºF 500 ºF 400 ºF 500 ºF Typical Wellbore 0 - 20 deg 0 - 20 deg 0 - 20 deg hole N/A 0 - 50 deg N/A Deviation landed pump landed pump angle 70 deg, Max. Wellbore 0 - 90 deg 0 - 90 deg 0 - 90 deg 0 - 90 deg 0 - 90 deg short to 80 deg Deviation landed pump < 15 deg/100 ft < 15 deg/100 ft < 24 deg/100 ft medium radius Corrosion Good to Good to Fair Good Good Excellent Excellent Handling Excellent Excellent Table 3: Artificial Lift Methods—Characteristics and Areas of Application (after Weatherford, 2005) Good to Gas Handling Fair to Good Good Fair Fair Good Excellent Excellent Solids Handling Fair to Good Excellent Poor Fair Good Good Poor to Fair GLR > 300 SCF/Bbl Fluid Gravity > 8º API < 35º API > 8º API > 10º API > 8º API > 15º API per 1000 ft of depth Workover Workover or Workover or Hydraulic or Hydraulic or Wireline or Wellhead catcher or Servicing or pulling pulling rig pulling rig wireline wireline workover rig wireline rig Multi-cylinder Electric Multi-cylinder Prime Mover Gas or electric Gas or electric Compressor Well’s natural energy or electric motor or electric Offshore Limited Good Good Excellent Excellent Excellent N/A Applications System Efficiency 45 - 60% 40 - 70% 45 - 55% 35 - 60% 10 - 30% 10 - 30% N/A Economics of Artificial Lift The features, benefits, and limitations of one artificial lift method are relative to those of the other methods under consideration. Each method should be evaluated from the standpoint of comparative economics. Brown (1980) lists six critical bases of comparison: Initial capital cost Monthly operating expense Equipment reliability and maintenance Number of wells to be lifted Surplus equipment availability Expected producing life of well(s) Capital cost considerations may favor one type of system over another, particularly when there is significant uncertainty regarding well performance characteristics or reserve volumes. For example, gas lift is not likely to be a good option for a one or two-well system, particularly if it requires adding surface compression facilities. For multiple wells, however, it may be a very economical choice. Hydraulic pumping is likewise less costly when multiple wells are operated from a central injection facility. Projected operating costs also figure into the selection of an artificial lift method. High gas prices will reduce the profitability of gas lift, particularly if it becomes necessary to purchase additional gas for injection. But gas lift may be an attractive option in a remote field where there is no market for produced gas. In the same way, in places where electricity is not readily available, submersible pumps will be less attractive compared to gas lift or other forms of pump-assisted lift. System reliability and access to repair equipment and services must also be considered. Sometimes, the prevalence of a particular type of lift equipment in a given area will make that system more attractive. If a well is expected to have a short producing life, capital and operating costs will play an important role in the overall field economics and will affect the choice of an artificial lift system. It is clear that for each well or field situation, a number of factors will affect the choice of artificial lift system. For typical onshore well applications, rod pumping is the overwhelming choice. For high volume wells, with little gas or solids production, ESPs would be the proper lift approach.  For solids production such as sand in a waterflood supply well, PCPs show favorable results. For deviated wells, hydraulic pumping may be the lift application of choice. Offshore, where space is at a premium, gas lift is by far the most widely used application. For gas wells with little water production, plunger lift or periodically dropping soap sticks down the tubing is a best practice. Figure 1 shows typical high rate artificial lift systems applications at depth. Figure 1: Typical high rate artificial lift systems applications at depth (after Weatherford, 2000) Figure 2 shows typical lower rate artificial lift systems applications at depth. Figure 2: Typical lower rate artificial lift systems applications at depth (after Weatherford, 2000) Equipment manufacturers can more fully explain important advantages and disadvantages of different systems. Each type of artificial lift method has economic and operating limitations that can make it more or less desirable when compared to others. Similarly, one artificial lift system will usually have at least one advantage over all others for a given set of operating conditions. With such a wide range of variables to consider, and in lieu of local experience and applications, one might use a lift selection expert system to select and design an optimal artificial lift system. These systems build in branching rules and logic to select the best artificial lift system as a function of well and operating conditions. Relative costs for a common well are shown in Table 4 (Lake 2007). Table 4: Relative Lift Method Beam Hydraulic Gas Lift ESP Target rate, B/D 1,000 1,000 1,000 1,000 Initial Installation, $ 141,000 173,000 239,000 105,000 Energy efficiency, % 58 16 15 48 Direct operating expenses (fixed), $/month 600 700 600 600 Direct operating expenses per BFPD, $/month 0.50 0.50 1.00 0.50 Pull and repair, $/month 200 100 100 250 Artificial Lift in Horizontal Wells Dunham (2012) noted that producing fluids from horizontal wells presents many challenges: Some of the water used to fracture the wells must be produced back from the formation. Some of the sand used to prop fractures open will be produced with this water. Both the water and sand must be artificially lifted. Most artificial lift systems are designed to work in vertical sections of wells. Methods must continue to be developed to lift fluids from the deviated and/or horizontal portions of the well.  Most horizontal wells are not actually horizontal. Figure 3 and Figure 4 show typical basic and complex horizontal well profiles. These vary from “toe up,” to essentially horizontal, to “toe down.” Each profile presents special production challenges. Often the horizontal portions of the wells have up and down undulations (Figure 5) with fluids accumulating in the low spots and delivered to the vertical part of the well in slugs. Figure 3: Basic horizontal well profiles  Figure 4: Representative horizontal well profiles Figure 5: Typical undulations in horizontal wells It’s important, then, to recognize that the well’s lateral profile impacts the selection of the type of artificial lift system that is most appropriate for each well. The toe-down profile provides a single liquid accumulation spot at the toe, farthest away from the kickoff point. This type of profile creates a “sump” that collects the liquids at the end of the lateral. Because artificial lift systems have difficulty moving liquids through a 5,000-10,000 foot lateral and up the vertical section, the toe-up design, with the low point of the lateral positioned in the heel and the horizontal section angled upward at 2 to 5 degrees from horizontal may be easier to produce. The multiple high and low points, undulating lateral allows for spaces where liquid can accumulate in the lateral, which means it will not produce a steady flow. This creates slugging, which can be a major problem for artificial lift because it is difficult for most systems to handle production without a steady input of liquid or gas. In general, for horizontal well artificial lift applications, the pump is most effective when placed as close to the depth (TVD) of the reservoir as possible. The higher the pump’s intake above the perforations, the more hydrostatic pressure (fluid column back pressure) is exerted in the reservoir, lowering the reservoir’s ability to flow. Artificial Lift Options for Horizontal Wells There are a variety of artificial lift systems that can be effectively installed depending on the geometry of the lateral (Table 5). Table 5: Artificial Lift Options for Horizontal Wells Lift Volume Lift Deviation Efficiency Lifted Solids Gas Comments Mechanism Applicability in per Day Tolerance Tolerance Horizontal (BFPD) Limited Deviation Set in vertical Not usually Requires Rod Pump to ~1000 Poor angle limited section deviated separation BFPD by rod wear Varies Can be run to Poor in High gas rates Gas Lift with gas Excellent Excellent any position horizontal required to lift used Requires Electric constant flow Full Excellent if > 20,000 Requires Submersible Poor and straight Horizontal gas diverted BFPD separation (ESP) section to set pump  Table 5: Artificial Lift Options for Horizontal Wells Tubular Requires flow Full Moderate Jet Hydraulic Moderate and depth Limited path for Horizontal to poor limited power fluid Low rate Up to 20° 10 to 50 Plunger Not used Poor Good liquid deviation BFPD removal Requires Downhole Varies, constant flow Full Good but Progressive usually Excellent Moderate and straight Horizontal rate limited Cavity (PCP) low section to set pump Each system brings its own set of challenges when applied to horizontal wells, in part because of the deviation angle of the well (Figure 6). Figure 6: Relative pump setting locations - deviation limits Expanding the discussion, Presley (2012) provided the following summary of artificial lift systems in horizontal wells. Rod Pumping Systems While beam pumping may be the most efficient and widely applied artificial lift method, it is also the most susceptible to gas locking in highly deviated wells. Also, in the deviated sections of a horizontal well, the rods slide against the tubing and may erode it unless rod guides are used to keep the rods from contacting the tubing wall. In addition to rod wear and gas locking, rod pumps also place additional back pressure on the reservoir (lowering the production rate) because of the “fluid head” that exists between the pump setting depth and the “bottom” of the well (Figure 7). Figure 7: Well back pressure is a function of fluid head (TVD minus pump setting depth) assuming a pumped off well in rod pump systems Gas Lift Systems Like beam pumping, gas lift is used widely in vertical wells, but faces limitations in horizontal wells. The first is getting the gas lift equipment in place in the horizontal leg. Normally, gas lift equipment is installed with wireline tools, which only work to a deviation angle between 65 and 75 degrees from vertical (you can’t push a wireline). It stands to reason, then, that putting gas lift equipment in the highly deviated or horizontal part of the well requires coiled tubing or other special tools to “pump” the gas lift equipment down the horizontal. However, once installed in laterally undulating sections of the well, gas lift equipment can be effective. Liquids and solids that collect in the low parts of an undulating lateral leg, flow into the vertical section in large slugs, which make it difficult to produce. If the gas lift equipment extends out into the horizontal and enough gas is injected, the gas can help produce the liquids and solids along before they have the chance to collect, eliminating the slugs. Gas lift has additional limitations in deviated wells. It only delivers less than 20 percent of the energy it consumes into lift. Also, gas segregates to the high points in undulating horizontal legs and stays there until it approaches the vertical section. Until that point, the gravity forces that help lift the fluids in a vertical section do not help lift the production (Figure 8) but may instead override it. Figure 8: Gravity effects on gas lift Electric Submersible Pumps (ESPs) Electric submersible pumps are a viable option for producing large volumes of liquid. If a well has a long, straight run that can hold the ESP, the motor, and the associated equipment (30 to 40 feet), producers can land the pump there and get good results. Without a long, straight run the drive shaft on the motor or the pump will flex, causing the bearings to fail. For horizontal applications, ESPs also need: Low gas-to-liquid ratios to prevent gas lock Sufficient liquid flow to prevent overheating Low solids production Like most pumps, ESPs do not like sand. Considering the huge amounts of proppant placed in horizontal wells during the hydraulic fracturing process, a certain amount of proppant is invariably swept from the fractures and into the production stream over time. That usually makes ESPs a less desirable choice in tight shale, large frac completion wells. Other Pumps Progressive cavity pumps are less susceptible than ESPs to sand and other solids, but their application envelope has its share of limitations. PCPs can work at any deviation angle, but they do not work well in hot downhole environments. Like ESPs, PCPs do not handle dry operation or gas production well, and must be set in a straight section of the well bore to prevent bearing failure. Hydraulic jet pumps can be used at any deviation angle through the full length of a horizontal well, but are less efficient than ESPs and have limited tolerance to solids and gases. They also require a dedicated flow path for the power fluid. All these options involve trade-offs in horizontal wells. To apply artificial lift methods effectively in horizontal wells, one needs to look at each well’s characteristics—from their deviation and lateral profile to production stream variability and downhole temperatures and pressures—to determine which approaches will be effective and reliable. Artificial Lift Applications Summary There are approximately 2 million oil wells in operation worldwide. More than 1 million wells use some type of artificial lift (Figure 9). More than 750,000 of the lifted wells use sucker-rod pumps. In the US, sucker-rod pumps lift approximately 350,000 wells. Approximately 80% of all US oil wells are stripper wells making less than 10 B/D with some water cut. The vast majority of these stripper wells are lifted with sucker-rod pumps. Of the non-stripper “higher” volume wells, 27% are rod pumped, 52% are gas lifted, and the remainder are lifted with ESPs, hydraulic pumps, and other methods of lift.  Figure 9: Artificial lift usage in US wells These statistics indicate the dominance of rod pumping for onshore operations. For offshore and higher-rate wells around the world, the use of ESPs and gas lift is much higher. In summary: Rod Pump: Excellent reliability. Low maintenance. Low capital investment. Used in approximately 85% of U.S. artificial lift wells. The normal standard artificial lift method. PCP: Limited to relatively shallow wells with low rates. Low maintenance. Low capital investment. Used on