Selection of Artificial Lift

SPE 52157 Selection of Artificial Lift James F. Lea and Henry V. Nickens--Amoco EPTG/RPM

Copyright 1999, Society of Petroleum Engineers, Inc. This paper was prepared for presentation at the 1999 SPE Mid-Continent Operations Symposium held in Oklahoma City, Oklahoma, March 28-31, 1999. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract Selection of the most economical artificial lift method is necessary for the operator to realize the maximum potential from developing any oil or gas field. Historically the methods used to select the method of lift for a particular field have varied broadly across the industry, including • Determining what methods will lift at the desired rates and from the required depths. • Evaluating lists of advantages and disadvantages. • Use of “expert” systems to both eliminate and select systems. • Evaluation of initial costs, operating costs, production capabilities, etc. using economics as a tool of selection. This paper will highlight some of the methods commonly used for selection and also include some examples of costs and profits over time calculated to the present time as a tool of selection. The operator should consider all of these methods when selecting a method of artificial lift, especially for a large, long-term project. Introduction In artificial lift design the engineer is faced with matching facility constraints, artificial lift capabilities and the well productivity so that an efficient lift installation results. Energy efficiency will partially determine the cost of operation, but this is only one of many factors to be considered. In the typical artificial lift problem, the type of lift has already been determined and the engineer has the problem of applying that system to the particular well. The more basic question, however, is how to determine what is the proper type of artificial lift to apply in a given field. Each of the four major types of artificial lift will be

discussed before examining some of the selection techniques. Some additional methods of lift will also be discussed. Preliminary comments related to reservoir and well factors that should be taken into consideration are presented. There are certain environmental and geographical considerations that may be overriding issues. For example, sucker rod pumping is by far the most widely used artificial lift method in the United States. However, if we are in the middle of a densely populated city or on an offshore platform with forty wells contained in a very small deck area, sucker rod pumping may be eliminated. Deep wells producing several thousands of barrels per day cannot be lifted by beam lift and other methods must be considered. These geographic and environmental considerations may simply make our decision for us; however, there are many considerations that need to be taken into account when these conditions are not predetermining factors. Reservoir Pressure and Well Productivity. Among the most important factors to consider are reservoir pressure and well productivity. If producing rate vs. producing bottom-hole pressure is plotted, one of two inflow performance relationships (IPR) will usually occur. Above bubble point pressure, it will be a straight line. Below bubble point pressure, a curve as described by Vogel will occur. These two curve types are shown in Figure 1 as a single IPR with a bubble point at about 750 psi. Some types of artificial lift are able to reduce the producing sand face pressure to a lower level than others. The reward for achieving a lower producing pressure will depend on the reservoir IPR. For example, the well of Figure 1 would have an absolute open flow (AOF) of about 670 bopd if no gas was being produced. However due to the gas, the AOF is reduced to about 580 bopd. If you are using a pumping system on this well, there may be good reason for not lowering the sand face pressure below about 500 psi as the increasing amount of free gas may cause gas interference and diminishing returns on production with lowered pressure. It also would be difficult to lower the pressure as much compared to some other lift methods using gas lift although a gassy well would in general be beneficial for gas lift applications. In addition to the older conventional IPR expressions for vertical wells, there are now available a number of IPR

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J.F. LEA, H.V. NICKENS

models for horizontal wells. An input panel for one such model is shown Figure 2. This allows calculation of inflow from a horizontal well, which typically produces several multiples of what a vertical well would produce in the same formation. Use of horizontal well inflow models for present or for future depleted horizontal wells can be used to determine if the flowing production rates can be economically increased through the use of some method of artificial lift. If the horizontal well is low pressure and ceases to flow, the inflow model can estimate what the well could produce if supplied with a form of artificial lift. For a large project, reservoir models may be used to predict expected inflow conditions of the expected life of the project. Reservoir Fluid. The characteristics of the reservoir fluid must also be considered. Paraffin is a much more difficult problem for some kinds of lift than for others. Sand production can be very detrimental to some types of lift. The producing gas-liquid ratio (GLR) is very important to the lift designer. Free gas at pump intake is a significant problem to all of the pumping lift methods but is beneficial for gas lift, which simply supplements the lift energy already contained in the producing gas. Long Term Reservoir Performance and Facility Constraints. Two approaches have frequently been taken in the past to account for long term reservoir performance. In our opinion, both of these approaches are extreme and wrong. In some cases, we predict long term reservoir performance and install artificial lift equipment that can handle the well over its entire life. This frequently lead to the installation of oversized equipment in the anticipation of ultimately producing large quantities of water. As a result, the equipment may operate at poor efficiency due to under-loading over a significant portion of its total life. The other extreme is to design for what the well is producing today and not worry about tomorrow. This can lead to change after change after change in the type of lift equipment installed in the hole. We may operate efficiently short term but spend large amounts of capital dollars in changing equipment. For instance, the changing reservoir conditions with time shown in Figure 3 would have to be carefully considered in sizing artificial lift equipment for current conditions and for some selected future period of time. Reference 14 is concerned in detail with timing of artificial lift methods. In a new field development, the fluid handling requirement can significantly increase the size and cost of the facilities required to produce the field. With beam or electric submersible pumps, only the produced fluid is handled through the facilities. With gas lift, the injection gas compression and distribution facilities and additional gas in the production adds to the facilities. With hydraulics, the power fluid pumps, power fluid injection lines and additional

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power fluid, many times combined with the production fluid, adds to the fluid handling costs. The design engineer must consider both long term and short term aspects. Our aim is to maximize the present value profit of the operation. The highest present value profit may or may not result from greatest production rate available from the well and may or may not anticipate a lift system change in the future. Many of the introductory comments and observations in the proceeding discussion will be included in lists of advantages/disadvantages, expert systems and other types of selection analyses discussed in following sections. Types of Artificial Lift. The various major forms of artificial lift are shown schematically in Figure 4. There are other methods as well which will be mentioned as appropriate in the following discussions, such as the ESPCP for pumping solids and viscous oils. This system has a PCP pump with the motor and other components similar to an ESP. Other methods include long stroke modifications of beam pump systems. The selection of the lift method should be a part of the overall well design. Once the lift method is selected, consideration should be given to the size of the well bore required to obtain the desired production rate. More than once, a casing program has been designed to minimize well cost and then find that the desired production could not be obtained because of the size limitation on the artificial lift equipment. Even if production rates can be achieved, smaller casing sizes can lead to higher long term production costs such as well servicing and gas separation problems. If oil prices are low, it is tempting to select a small casing size to help with current economics. On rare occasions wells are drilled with the future lift methods in mind. The following sections will further detail each method of lift with major advantages and disadvantages and how they may be expected to perform in various well environments. Selection by Consideration of Depth/Rate System Capabilities. One selection criteria is the range of depth and rate where particular lift types can function (Figure 5). This chart is a slightly modified version of the original chart published by R. Blais, Pennwell. The depth-rate ranges in Figure 5 are approximate and there are many exceptions to them, but they provide a quick idea of what systems are available to lift with certain rates and from certain depths. Particular well conditions can lead to wide divergences from the initial selection from using these charts alone. Specific designs are recommended for specific well conditions to determine the rates possible from given depths. Note how Figure 5 shows hydraulics systems can pump from the greatest depths due to the “U” tube balancing of produced fluid pressures with the hydraulic fluid pressure. Gas lift has a wide range of production capacity. Beam pump produces more from shallower depths and less from deeper depths due to increasing rod weight and stretch as depth increases. ESP’s are depth limited due to burst limitations on housings and energy considerations for long cables, but can

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SELECTION OF ARTIFICIAL LIFT

produce large production rates. Plunger lift is for low liquid rates to primarily clear liquids from gas wells. Plunger is not particularly depth limited, due to increased energy storage in the casing annulus as depth increases.

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Details of Major Systems. Sucker Rod Pumping. Sucker rod pumping systems are the oldest and most widely used type of artificial lift for oil wells. Figure 6 shows a schematic of a typical rod pumping system. About 85 percent of all artificially lifted wells in the USA are produced by rod pumps. This is also true in some areas of S. America and Canada. About 80 percent of all oil wells are stripper wells, making less than 10 bopd. A vast majority of these stripper wells are lifted with sucker rod pumps. Of the remaining 20 percent, about 27 percent are rod pumped, 52 percent gas lifted and the remainder lifted with ESP’s, hydraulic pumps and other methods of lift. Although these statistics are ca. 1980, and are no doubt somewhat different today, they indicate the dominance of rod pumping for onshore operations. For offshore and higher rate wells, the use of ESP’s and especially gas lift increases dramatically. • Sucker rod pumping systems should be considered for new, low volume stripper wells because operating personnel are usually familiar with these mechanically simple systems and can operate them more efficiently. Inexperienced personnel also can often operate rod pumps more effectively than other types of artificial lift. Sucker rod pumping systems can operate efficiently over a wide range of well producing characteristics. Most of these systems have a high salvage value. • Sucker rod systems also should be considered for lifting moderate volumes from shallow depths and small volumes from intermediate depths. It is possible to lift 1,000 barrels from about 7,000 feet and 200 barrels from approximately 14,000 feet (special rods may be required). If the well fluids contain hydrogen sulfide, sucker rod pumping systems can lift 1,000 barrels of liquid per day from 4,000 feet and 200 barrels per day from 10,000 feet (exclusive of other mitigating conditions). • Most of the parts of the sucker rod pumping system are manufactured to meet existing standards, which have been established by the American Petroleum Institute. Numerous manufacturers can supply each part, and all interconnecting parts are compatible. • The sucker rod string, parts of the pump and unanchored tubing are continuously subjected to fatigue. Therefore, the system must be more effectively protected against corrosion more than any other lift system to insure long equipment life. • Sucker rod pumping systems and well dog-leg severity are often incompatible. Deviated wells with smooth profiles may allow satisfactory sucker rod pumping.

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The ability of sucker rod pumping systems to lift sand is limited. Paraffin and scale can interfere with the efficient operation of sucker rod pumping systems. If the gas-liquid separation capacity of the tubing-casing annulus is too low, or if the annulus is not used efficiently, and the pump is not designed and operated properly, the pump will operate inefficiently and tend to gas lock. One of the disadvantages of a beam pumping system is that the polished rod stuffing box can leak. However, if proper design and operating criteria are considered and followed, that disadvantage can be minimized. If the system is not sized to the well productivity and is over-pumped without POC (pump-off control), mechanical damage and inefficient pump operation will occur.

Electrical Submersible Pumping (ESP). As an example area where ESP’s are applied extensively, THUMS Long Beach Company was formed in April 1965 to drill, develop, and produce the 6479 acre Long Beach Unit in Wilmington Field, Long Beach, California. It was necessary to choose the best method of lift for approximately 1100 deviated wells over a 35 year contract period from four (4) man-made offshore islands and one (1) onshore site. A schematic of a typical ESP system is shown in Figure 7. Advantages. • Adaptable to highly deviated wells - up to 80°. • Adaptable to required subsurface wellheads 6' apart for maximum surface location density. • Permit use of minimum space for subsurface controls and associated production facilities. • Quiet, safe and sanitary for acceptable operations in an offshore and environmentally conscious area. • Generally considered a high volume pump - provides for increased volumes and water cuts brought on by pressure maintenance and secondary recovery operations. • Permits placing well production even while drilling and working over wells in immediate vicinity. Disadvantages. • Will tolerate only minimal percents of solids (sand) production. • Costly pulling operations to correct downhole failures (DHF’s). • While on a DHF there is a loss of production during the time well is covered by drilling operations in immediate vicinity. • Not particularly adaptable to low volumes - less than 150 B/D gross. Long life of ESP equipment is required to keep production economical with high water cuts, approximately greater than

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90%. Required improvements and recommendations based upon experience are as follows: • Specify new stages and shaft in a rebuilt pump. Do not reuse pumps except in a test case. • Pump designs are normally “floating” but use compression to handle abrasives or to provide down thrust resistance if cycling or gas slugging is expected or if uncertain about rate - improves rate flexibility. • Low amperage, high voltage motors are preferred. • Motors run at 60°F above ambient. Above 200°F use high temperature equipment. • Reuse motors in cool wells if cumulative run life < 1,200 days and passes QC inspection. • Use a modular (3 chamber -BSBSL) or a tandem (4 chamber) seal configuration for redundancy and deviation angle resistance. Never reuse a seal chamber. • Use high temperature elastomers and oil where warranted. • Cable best success is with 5KV, #4 solid conductor (solid preferred to stranded) with barrier and braid and heavy armor. Use cable with lead sheathing in high H2S conditions. • Taped cable splices are preferred to molded. • Good cable handling practices are imperative in reducing cable failures. Pull slow to prevent decompression problems. Use 2” pre -formed “super-bands” especially in deviated wells. Use no more than 7 splices per string including motor lead extension and lower mandrel connection. Try not to place splice near fluid level. Place motor lead extension/round splice well above pump outlet (~200’) to keep cool. Use new cable with no splices in hot wells. • The latest generation of motor controllers can collect and store operational and forensic data (amps, kWh usage, phase leakage, restart records, backspin, rotation, etc.) and can provide restart lockout during backspin. The Electrical Submersible Progressive Cavity Pump (ESPCP). A schematic of a progressive cavity pump (PCP) is shown in Figure 8. The PCP has a rotating metal rotor and a flexible rubber molded stator. The rotating stator forms a cavity that moves up as the rotor turns. The pump is well suited for handling solids and viscous fluids as the solids that move though the pump may deflect the rubber stator but do not abrade or wear the stator or rotor to any appreciable degree. In the past, most PCP’s were powered by rotating rods driven from the surface with a hydraulic or electrical motor. Introduced in 1936, the PCP is of simple design and rugged construction, and its low operating speeds enable the pump to maintain long periods of downhole operation if it is not subjected to chemical attack, excessive wear, or installed at depths greater than about 4000 feet. The pump has only one moving part downhole, with no valves to stick, clog or wear out. The pump will not gas lock, can easily handle sandy and abrasive formation fluids and it not plugged by paraffin,

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gypsum or scale. With this system, the rotating rods would wear and also wear the casing. The rotating rods would “wind” up on start and “unwind” on the shut-down. Rotating rods must be sealed at the surface and many installations would have oil leaks at the surface. To alleviate the problems with the conventional rotating rod PCP systems, the ESPCP system is being made available. This is not a new system. It has been run in Russia for a number of years and also was available from ODI (ESP vendor) a number of years ago. The new ESPCP system (Figures 9-10) has a number of advantages over the rotating sucker rod systems. As shown in Figures 9 and 10, the PCP pump is located on top of the assembly. There is problem of rotating the eccentric rotor with the motor shaft because of possible vibration hence a flexible connection is used. There is a seal section as in an ESP assembly to protect the underlying motor from well-bore fluids and also to accommodate and thrust in the internal thrust bearing. Because the PCP usually turns around 3-600 rpm and the ESP motor turns around 3500 rpm under load, there must be a way of reducing speed before the shaft connects to the PCP. Methods in use from the various manufacturers include using a gear box to reduce the 3500 rpm to acceptable speeds or using higher pole motors with lower synchronous speeds to allow the PCP to turn at operational speeds. The motor is located on the bottom of the assembly so fluids can pass the motor and provide cooling as in the conventional ESP. Since the ESPCP is not rod connected, it can be run into deviated or horizontal wells. Some manufacturers refer to this system as the PCSPS (Progressive Cavity Submersible Pump System) or the ESPCP (Electrical Submersible Progressive Cavity Pump). Advantages. • The pumping system can be run into deviated and horizontal wells. • The pump handles solids in production well. • The pump handles viscous production well. • Several of the components are off the shelf ESP components. • The production rates can be varied with use of a variable speed controller (VSC). There is one modification of this system whereby the pump can be wire-lined out of the hole leaving the motor and the rest of the system behind. This is desirable because the pump is likely to have the shortest run life. Disadvantages. • The unit does not tolerate heat due to the softening of the stator material. • Gas must be separated to increase efficiency. It will not gas lock but if ingesting large amounts of gas continuously, or if pumped off, it will overheat and damage will occur to the stator.

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If the unit pumps off the well, the stator will likely be permanently damaged. • The gearbox is another source of failure if well-bore fluids or solids leak inside. This pump is suited for deviated wells and can be run in most locations of a horizontal well. Summary. If you have a low pressure well with solids and/or heavy oil, and the well temperature is not high, then you could consider an ESPCP. If this is offshore or where pulling the well is very expensive, you could consider the option of the ESPCP that allows wire-lining out a failed pump from the well while leaving the seal section, gear box, motor, and cable still installed for additional usage. This modification is in use in THUMS in Long Beach, CA. Hydraulic Pumping. There are two kinds of hydraulic pumps currently on the market; (1) positive displacement pumps and (2) jet pumps. The positive displacement pump consists of a reciprocating hydraulic engine directly coupled to a pump piston or pump plunger (Figure 11). Power fluid (oil or water) is directed down the tubing string to operate the engine. The pump piston or plunger draws fluid from the well bore through a standing valve. Exhausted power fluid and production can be returned up a separate tubing string or up the casing. The jet pump is also shown in Figure 11. High pressure power fluid is directed down the tubing to the nozzle where the pressure energy is converted to velocity head. The high velocity-low pressure power fluid entrains the production fluid in the throat of the pump. A diffuser then reduces the velocity and increases the pressure to allow the commingled fluids to flow to the surface. Combining the power fluid and production is called an Open Power Fluid system. If production and power fluid are returned up separate tubing, then this is a Parallel installation with gas vented through the casing annulus to the surface. A Casing installation requires the pump to handle the gas. Both types are used with positive displacement pumps and with jet pumps. In fact, most bottom hole assemblies can accommodate interchangeability of jet pumps and positive displacement pumps. A Closed Power Fluid arrangement is where power fluid is returned to the surface separately from the production. Because the jet pump must commingle the power fluid and production, it cannot operate as a Closed Power Fluid pump. The most outstanding feature of hydraulic pumps is the “free pump” (Figure 12). The drawing on the left of Figure 12 shows a standing valve (inserted by wireline) at the bottom of the tubing and the tubing filled with fluid. In the second drawing, a pump has been inserted in the tubing and is being circulated to the bottom. In the third drawing the pump is on bottom and pumping. When the pump is in need of repair, it is circulated to the surface as shown in the drawing on the right. The positive displacement pump, the jet pump and the closed

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power fluid system previously shown above are all “free pumps”. Surface facilities required are a power fluid cleaning system and a pump. The most common cleaning systems are settling tanks located at the tank battery. Sometimes cyclone de-sanders are used in addition to settling tanks. In the last few years “well site power plants” have been very popular. These are separators located at the well with cyclone desanders to remove solids from the power fluid. Surface pumps are most commonly triplex plunger pumps. Other types are quintiplex plunger pumps, multistage centrifugal pumps and “canned” electric submersible pumps. Surface pressure required is usually in the 1500-4000 PSI range. It is important to specify 100% continuous duty for the power fluid pump at the required rate and pressure. Low volume (<10000 BPD), high pressure installations (>2500 psi) use plunger type pumps. Approximate maximum capacities and lift capabilities for positive displacement pumps are shown in Table 3. In some cases, two pumps have been installed in one tubing string. Seal collars in the bottom hole assembly connect the pumps in parallel hydraulically. Thus, the maximum displacement values shown above are doubled. A tabulation of capacity vs. lift is not practical for jet pumps because of the many variables and their complex relationships. To keep fluid velocities below 50 ft/sec. in suction and discharge passages, the maximum production rates vs. tubing size for Jet FREE PUMPS are approximately as shown in Table 4. Fixed type jet pumps (those too large to fit inside the tubing) have been made with capacities to 17,000 B/D. Even larger pumps can be made. Maximum lifting depth for jet pumps is around 8000-9000 feet if surface power fluid pressure is limited to 3500 PSI. The maximum capacities listed above can be obtained only to about 5000-6000 feet. These jet pump figures are only guidelines because well conditions and fluid properties can have significant influences on them. It should also be noted that the maximum capacities listed above are for high volume jet pumps that require bottom hole assemblies that are not capable of also accommodating piston pumps. Advantages. • FREE PUMP - Being able to circulate the pump in and out of the well is the most obvious and significant feature of hydraulic pumps. It is especially attractive on offshore platforms, remote locations, populated, and agricultural areas. • Deep Wells - Positive displacement pumps are capable of pumping depths to 17,000 feet, and deeper. Jet pumps can be run to 20,000 feet with design target of 25% submergence at intake. • Speed Control - By changing the power fluid rate to pumps, production can be varied from 10 percent to

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100 percent of pump capacity. The optimum speed range is 20 to 85 percent of rated speed. Crooked Wells - Deviated wells typically present no problem to hydraulic “free pumps”. Jet pumps can even be used in TFL installations. Sand Production - jet pumps, because they have no moving parts, can handle sand and other solids with hardened nozzle throats. Viscous Oils - Positive displacement pumps can handle viscous oils very well. The power fluid can be heated or it can have diluent added to further aid getting the oil to the surface. Corrosion - Corrosion inhibitors can be injected into the power fluid for corrosion control.

Disadvantages. • Power Fluid Cleaning - Removing solids from the power fluid is very important for positive displacement pumps. Surface plunger pumps are also affected by solids in the power fluid. Jet pumps, on the other hand, are very tolerant of poor power fluid quality. • Pump Life - Positive displacement pumps, on average, have shorter life between repairs than Jet, sucker rod and electric submersible pumps. Mostly, this is a function of the quality of power fluid, but also, on average, they are pumping from greater depths which is also a factor. Jet pumps, on the other hand, have very long pump life between repairs without solids or if not being subjected to cavitation. • Bottom Hole Pressure - Positive displacement pumps can pump to practically zero bottom hole pressure in the absence of gas interference and other problems (lowest bottom hole pressure is a gas gradient to the pump depth plus casing pressure) Jet pumps cannot pump to low intake pressures. Jet pumps require approximately 1000 PSI bottom hole pressure when set at 10,000 feet and approximately 500 PSI when set at 5000 feet. • Skilled Personnel - Positive displacement pumps generally require more highly skilled operating personnel, or perhaps, just more attention, than jet pumps and other types of artificial lift. There are two reasons for this. First, pump speed needs to be monitored daily and not allowed to become excessive. Secondly, power fluid cleaning systems need frequent checking to keep them operating at their optimum effectiveness. To answer the question, “when do you use jet pumps and when do you use positive displacement pumps?”, our answer is: Use jet pumps if the flowing (pumping) bottom hole pressure is adequate (see disadvantage No. 3 above). Gas Lift. Gas lift dominates the USA Gulf Coast and is used extensively around the world. Most of these wells are on

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constant flow gas lift. Thus, the questions: “Why choose gas lift?, “Where do you use constant flow?” and “When do you select intermittent lift?” Constant Flow Gas Lift. A schematic of a gas lift system is shown in Figure 13. Constant flow gas lift is recommended for high volume and high static bottom hole pressure wells where major pumping problems will occur. It is an excellent application for offshore classic-type formations with water drive, or waterflood reservoirs with good productivity indices (PI’s) and high gas-oil ratios (GOR’s). When high pressure gas is available without compression or where gas is low in cost, gas lift is especially attractive. Constant flow gas lift supplements the produced gas with additional gas injection to lower the intake pressure to the tubing, including lowering formation pressure. A reliable, adequate supply of good quality high-pressure lift gas is mandatory. This supply is necessary throughout the producing life if gas lift is to be effectively maintained. In many fields the produced gas declines as water cut increases, requiring some outside source of gas. The gas lift pressure is typically fixed during the initial phase of the facility design and as the water cut increases the depth of lift is decreased not allowing the gas lift system to obtain the desired flowing bottom hole pressure. Also the wells will produce erratically or not at all when the lift supply stops or pressure fluctuates radically. Poor quality gas will impair or even stop production. Thus, the basic requirement for gas must be met or other artificial lift means should be installed. Constant flow gas lift imposes a relatively high back pressure on the reservoir compared to pumping methods and is at best only moderately efficient. The high back pressure may significantly reduce production as compared with some pumping methods and poor efficiency significantly increases both capital cost and operating energy costs. Advantages. • Gas lift is the best artificial lift method for handling sand or solid materials. Many wells make some sand even if sand control is installed. The produced sand causes almost no mechanical problem to the gas lift valve; whereas, only a little sand plays havoc with most pumping methods. • Deviated or crooked holes can be gas lifted with only minor lift problems. This is especially important for offshore platform wells which are directionally drilled. • Gas lift permits the use of wireline equipment and such equipment is easily and economically serviced. This feature allows for routine repairs through the tubing. • The normal design leaves the tubing full opening. This permits use of BHP surveys, sand sounding and bailing, production logging, cutting, paraffin, etc.

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High formation GOR’s are helpful rather than being a hindrance. Thus in gas lift, less injection gas is required; whereas, in all pumping methods, pumped gas reduces efficiency drastically. Gas lift is flexible. A wide range of volumes and lift depths can be achieved with essentially the same well equipment. In some cases, switching to annular flow can also be easily accomplished to handle exceedingly high volumes. A central gas lift system can be easily used to service many wells or operate an entire field. Centralization usually lowers total capital cost and permits easier well control and testing. Gas lift has a low profile. The surface well equipment is the same as for flowing wells except for injection gas metering. The low profile is usually an advantage in urban environments. Well subsurface equipment is relatively inexpensive and repair and maintenance of this subsurface equipment is normally low. The equipment is easily pulled and repaired or replaced. Also major well workovers occur infrequently. Installation of gas lift is compatible with subsurface safety valves and other surface equipment. Use of the surface controlled subsurface safety valve with the 1/4-inch control line allows easy shut-in of the well. Gas lift will tolerate some bad design assumptions and still work. This is fortunate since the spacing design must usually be made before the well is completed and tested.

Disadvantages. • Relatively high back pressure may seriously restrict production in continuous gas lift. This problem becomes more significant with increasing depths and declining static BHP’s. Thus a 10,000 foot well with a static BHP of 1000 psi and a PI of 1.0 would be difficult to lift with the standard constant flow gas lift system. However, there are some special schemes that could be tried for such wells. • Gas lift is relatively inefficient, often resulting in large capital investments and high energy operating costs. The cost of compressors is relatively high and are often long delivery items. Costs in 1981 were found to be $500 to $600 per horsepower for typical land locations and $1000 to $1400 per horsepower for offshore packages. The compressor presents space and weight design problems when used on offshore platforms. Also, the cost of the distribution systems onshore may be significant. Increased gas usage also may increase the size of flow line and separators needed. • Adequate gas supply is needed throughout life of project. If the field runs out of gas or if gas becomes

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too expensive, one may have to switch to another lift method. In addition, there must be enough gas for easy start-ups. • Increasing water cut increases the flowing bottom hole pressure with a fixed gas lift pressure. At some water cut, another form of lift, such as ESP’s, should be evaluated to increase production be reducing the flowing bottom hole pressure, especially if the produced gas is low. • Operation and maintenance of compressors can be expensive. Skilled operators and good compressor mechanics are required for successful and reliable operation. • There is increased difficulty when lifting low gravity (less than 15° API) crude due to greater friction. The cooling effect of gas expansion further aggravates this problem. Also the cooling effect will compound any paraffin problem. • Low fluid volumes in conjunction with high water cuts (less than 200 BPD in 2-3/8" OD tubing) become less efficient to lift and frequently severe heading is experienced. Good data are required to make a good design. Such data may not be available and you may have to continue operations with an inefficient design that does not produce the well to capacity. Potential gas lift problems that must be resolved. • Freezing and hydrate problems in injection gas lines. • Corrosive injection gas. • Severe paraffin problems. • Fluctuating suction and discharge pressures. • Wireline problems. • Dual artificial lift frequently results in poor lift efficiency. • Changing well conditions, especially decline in BHP and PI. • Deep high volume lift. • Valve interference – multi-pointing. • Emulsions forming in the tubing

Intermittent Gas Lift. Intermittent gas lift method is generally used on wells that produce low volumes of fluid (~<200 bpd). Wells where intermittent lift is recommended normally have the characteristic of (1) high PI and low bottom hole pressure (BHP ) or (2) low PI with high BHP. Its use stems from known major pumping problems or where continuous gas lift is already installed or low cost high pressure gas is available. If an adequate, good quality, low cost gas supply is available and plans are to lift a relatively shallow, high GOR, low PI or low BHP well with a bad dog-leg that produces some sand, then intermittent gas lift would be an excellent choice. Intermittent gas lift has many of the same advantages/disadvantages as constant flow gas lift, and the

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major factors to be considered are similar. Only the differences will be highlighted in the ensuing discussion. Advantages. • Intermittent gas lift has a significantly lower producing BHP than the constant flow methods. • It has the ability to handle low volumes of fluid with relatively low production BHP’s. Disadvantages. • Intermittent gas lift is limited to low volume wells. For example an 8,000 foot well with 2" nominal tubing can seldom be produced at rates of over 200 BPD with an average producing pressure much below 250 psig. Smaller sizes of tubing have even a lower maximum rate. • The average producing pressure of a conventional intermittent lift system is still relatively high when compared to rod pumping. However, the producing BHP can be reduced by use of chambers. Chambers are particularly suited to high PI, low BHP wells. • The output to input horsepower efficiency is low. More gas is used per barrel of produced fluid than with constant flow gas lift. Also the slippage increases with depth and water cut making the lift system even more inefficient. However, slippage can be reduced by use of plungers. In general if the cycle time allows time for the plunger to fall, then plunger should be used with intermittent lift if not solids are present. • The fluctuation in rate and BHP can be detrimental to wells with sand control. The produced sand may plug the tubing or standing valve. Also surface fluctuations cause gas and fluid handling problems. • Intermittent gas lift requires frequent adjustments. The lease operator must alter the injection rate and time period routinely to increase the production and keep the lift gas requirement relatively low. Conclusion. Gas lift has numerous strengths that in many fields make it the best choice of artificial lift. However, there are limitations and potential problems to be dealt with. One has a choice of using either constant flow for high volume wells or intermittent for low volume wells and there is little difficulty in switching from one to the other. In addition, gas lift can be used to kick off wells, unload water from gas wells, or back flow injection wells. Gas lift deserves serious consideration as a means of artificial lift. Other Methods of Lift. There are other methods of lift that will not be discussed in a paper of this length. Plunger lift is commonly used to remove liquids from gas wells to maintain a low gradient in the tubing. There is a chamber pump that relies on gas pressure to periodically empty the chamber and force the fluids to the surface with no gas mixing.

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Rather than try to examine all possible forms of lift, the rest of the discussion below will be relegated to methods that can be used to select the best form of lift for a particular application. The methods should be applicable to any form of lift under consideration. Selection by Advantages and Disadvantages. Although the previous sections detailed the major systems of artificial lift and listed some advantages/disadvantages, there are other more detailed listings of advantages and disadvantages. Reference 1 by Clegg, Bucaram & Hein is the most extensive and useful listing of the various advantages and disadvantages of various lift systems under a broad range of categories. Some of their information is open to discussion such as their low limit on gas lift with viscous fluids, but in general it is the best available list of artificial lift advantages and disadvantages. Tables 1 and 2 after Brown (Ref. 2) do provide a useful summary of the various advantages and disadvantages of the various lift systems that were described briefly in the proceeding sections. It is probable that many artificial lift systems have been and can be selected by using tables similar to those generated by Clegg, Bucaram & Hein (Ref. 1) or the Tables 1 & 2 repeated here from Brown (Ref. 2). However there are other important considerations beyond a list of advantages/disadvantages. Reference 3 is a brief summary of advantages/disadvantages and selection criteria for various lift systems separately presented by experts in a forum discussion. Selection by Expert Programs. An advancement that should be a step above a simple list of advantages/disadvantages is the advent of “expert” programs or computerized lift selection programs. These programs include rules and logic so they will branch to select the best system of lift as a function of user input of well and operating conditions. References 4-6 are publications dealing with expert systems for the selection of artificial lift systems. Reference 4 describes an expert system with selection criteria on: 1. Sucker rod 2. Hydraulic pump 3. ESP 4. Progressive pump 5. Continuous gas lift 6. Intermittent gas lift 7. Intermittent gas lift with plunger 8. Constant slug injection gas lift 9. Chamber gas lift 10. Conventional plunger lift The program contains; an (1) Expert Module, a (2) Design Module, and a (3) Economic Module. Module 1 is an expert module that includes a knowledge base structured from human expertise, theoretical written knowledge available and known “rule of thumb” type calculations. Module 2 incorporates simulation design and facility component specification programs for all lift methods considered. Module 3 is an

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economics evaluation module that includes a costs data base, and cost analysis programs to calculate lift profitability. Module 1 ranks the methods and also issues some warnings, some of which may rule out high ranked methods. Module 2 contains a suite of design methods with advice to follow from Module 1. Module 3 utilizes the designs and expected production rate to calculate profitability using evaluation parameters such as net present value and rate of return. It also includes investment costs and repair and maintenance costs. Reference 5 describes the program AL which decides, from user input, what system among gas lift, hydraulic, sucker rod or ESP pumping systems, is best for particular conditions. Problems such as sand, paraffin, crooked hole, corrosion, small casing, flexibility, and scale are used, with the stored knowledge base and user input, to allow the program to rank by score, the most appropriate method of lift for particular conditions. Details of the program’s input, structure, and output are contained in the reference. Reference 6 describes another expert system, which is very encompassing in scope. The reference describes the OPUS (Optimum Pumping Unit Search) program, later described commercially as the Artilip program. The program consists of; (a) a knowledge base containing the complete set of specific information on the domain of expertise; (b) an inference engine using the data and heuristics of the knowledge base to solve the problem and (c) interactive modules enabling very simple use of the expert system. The structure of the rules in Reference 5 is of the form, if (condition) then ( type of process) For each process (i.e., lift method) , a suitability coefficient (SC) from –1 to + 1 for the given condition is defined, where SC = –1 eliminates the process from further consideration and SC = +1 indicates a process well suited to the given condition. For example, the simple expression if (Pump Temperature > 275F) then (ESP), -1 defines a rule that eliminates ESP’s if the pump temperature exceeds 275F (although this rule would have to be updated to include use of hot line ESP’s). Intermediate values can be used to refine the system and methods are presented for combining the coefficients into a single coefficient. The program can combine the suitability coefficients into one value for over-all evaluation. Other details for the “knowledge representation” and the “technical and economic evaluation” are given in the paper. Another interesting feature (Ref. 6) is the presentation of economical data for annual costs to be incurred by various lift systems. The costs are presented in bar graphs showing how the component costs would occur above the well head or subsurface. For instance, much of the possible re-occurring costs for ESP’s can be subsurface whereas for gas lift, other

9

than wireline work, larger repair and servicing costs associated with compressors would be above ground. Selection by Net Present Value (NPV) Comparison. A more complete selection technique will depend upon the lifetime economics of the available lift methods. The economics in turn depend, for example, upon the failure rates of the system components, fuel costs, maintenance costs, inflation rates, anticipated revenue from produced oil and gas and other factors that may vary from system to system. Reference 7-9 by Etherton, et. al., by Smith and by Kol, et. al. are example studies in selection that follow economically guided selection techniques. References 10-16 provide various references on artificial lift in general, efficiency of lift methods, selection techniques and limitations on various lift systems. This section will illustrate the economic concepts for a low-rate and high rate example. Methods considered are ESP, gas lift, hydraulic pump and rod pump. It will use an enhanced method of analysis similar to calculation methods available in Ref. 17. The equations used in the following example analysis are given in detail in the Appendix. In order to use the NPV comparison method, the user must have a good idea of the associated costs for each system. This requires that the user evaluate each system carefully for his particular well and be aware of the advantages/disadvantages of each system and additional equipment (i.e., additional costs) that may be required. Since energy costs are included in the NPV analysis, an optimal design for each feasible method must be determined before running the NPV analysis. These factors force the user to consider all the selection methods discussed previously to generate the necessary information for the NPV analysis. Low-Rate Example. Consider an example well with the following characteristics. Vertical Depth to Perforations 6000 ft Separator Pressure 100 psig Surface Temperature 100 F Casing Size 7 inch Tubing Size 3.500 inch, Gas Lift 2.875 inch, Other Methods Water Cut 50 % Oil Gravity 30 API Gas Gravity .7 Water Gravity 1.03 Produced GOR 400 scf/bbl Bubble Point 2227 psig Static Reservoir Pressure 2000 psig Productivity Index 1 STB/psi There are common costs and economic variables that are the same for all the different methods. Fixed Costs 300 $/month Fluid Disposal .35 $/bbl water Electricity .05 $/kW-hr Oil Revenue 12 $/bbl

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Gas Revenue 1.25 $/Mscf Inflation Rate 3 %/yr. Discount Rate for Present Value 8 %/yr. Oil Revenue Increase 1 %/yr. To calculate the expected lifetime of the well, reasonable reservoir production estimates must be supplied. For this example, we assume that all lift methods (ESP, Gas Lift, Beam Pump & Hydraulics) will produce initially at the same rate, 1000 bbl/day with 50% water cut and 400 GOR. The reservoir is assumed to decline immediately at 20 %/year reduction in oil rate. Water cut is assumed to increase maintaining the rate constant (water injection). At 90% water cut, the simulation is stopped. The GOR is assumed to remain constant for this example. The actual possible initial production rate would differ for each method, but for comparison purposes and to illustrate the concepts, a rate of 1000 bbl/day for each method is assumed. Different rates would possibly require different production facilities and different initial costs. Thus each method should be optimized and the associated required costs included in the economic analysis. Method specific costs must also be included as shown in Tables 5-9. Run Life Tables. The average pump run life for the pumping systems, and the injected gas volume for gas lift, is required to estimate the life-time costs for the different methods. The values assumed for this example are listed in Table 10. The last value in each table is used for subsequent years. The different methods are compared by calculating the net present value (NPV) income as a function of time until the production rate decreases to the abandonment rate. This gives a direct comparison of the different methods in terms of the net revenue the well would be expected to produce. Figure 14 shows results for the assumptions of this example. Rod pumping would be the best method, showing to be slightly more profitable than ESP, over the ~7 year life of the well. The analysis is stopped at ~7 years when 90% water cut is reached. These analyses also can be run for depleting rates. The NPV and total lifetime costs for each method are summarized in Table 11. The operating costs are significant, ranging from 14-26% of the NPV for this low rate example. Reduction in operating costs could therefore be a significant factor in selecting the optimum lift method. To re-emphasize, the results will depend upon the particular cost related data for each method. For this case, however, it is likely that rod pump or ESP would be the most economical method depending on the detailed cost data, and gas lift and hydraulic pump would not be recommended. High Rate Example. A well with productivity index PI = 24 bbl/d/psi is considered. Rod pumping cannot deliver the rates required for this design and is eliminated from consideration. Artificial lift designs with jet pump, ESP and gas lift yield only are considered. Production GOR and water cut is constant at 100 scf/bbl and 1% respectively. Abandonment rate is 500 bbl/d, oil +

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water. The reservoir oil production declines at 20% year. Operation and equipment specific costs are provided in Tables 12-15. Fixed Costs 1000 $/month Water Disposal .15 $/bbl Electricity .05 $/kW-hr Oil Revenue 12 $/bbl Gas Revenue 1.25 $/Mscf Inflation Rate 3 %/yr. Discount Rate for Present Value 8 %/yr. Oil Revenue Increase 1 %/yr. Run Life Tables. The average pump run life for the pumping systems, and the injected gas volume for gas lift, is required to estimate the life-time costs for the different methods. The values assumed for this example are listed in Table 16. The last value in each table is used for subsequent years. Figure 15 shows results for the assumptions of this example. jet pump would be the best method, producing about $4,000,000 more NPV than the ESP and $11,000,000 more than gas lift over the life of the well. Although the curves show that the NPV is near the point of no further increase, the curves are terminated at the point where the abandonment rate of 500 bpd occurs. The NPV and total lifetime costs for each method are summarized in Table 17. The operating costs are relatively insignificant for this high rate case, ranging from 1.6 – 2.0 % of the NPV for this high rate example. Operating costs therefore are not as significant a factor in selecting the optimum lift method for high rate wells. Run Life Information. As shown in the above examples of selection of artificial lift, one of the main factors in many cases is knowing what the failure rates of are for the various possible systems or the individual components of the systems. Some typical examples of failure rates and costs are discussed here. Figure 16 shows failure rates from a group of 500+ beam pumped wells over a period of years. The costs for downhole lift replacement and servicing are shown over the bars on the figure. Figure 17 shows a pie chart breakdown of the major causes for failure of the beam pump systems that went into the accumulation of the failure rate data plot. If a lift selection study is needed, data such as this for a field of similar conditions would be very helpful in evaluating beam pump as a candidate and being able to compare beam pump to others methods of lift. The conditions for the data presented here are a mix of deep and shallower wells. The deep wells average about 8,880'-9,200'. They make about 926 BOPD and 8,562 BWPD. The unit size averages out to be close to a 640. The shallower wells will average to be about 4,200' deep. They make 2,885 BOPD and 37,577 BWPD. For the pumping unit they average out to be about a 320. Different field conditions and methods of operations will result in different failure rates and a

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different distribution of failed components. Figure 18 shows run lives of ESP’s in the THUM”S operations offshore Long Beach, CA. There have been a number of improvements to the submersible system at THUMS that have been implemented over a 16 year period that are responsible for increasing the mean time between failures from 320 days in 1983 to over 1100 days in 1997. These statistics are based on any cause that required the downhole equipment to be pulled. Table 18 gives a summary of the conditions in this operation. Figure 19 shows ESP run lives for various fields. This data was collected and presented in Reference 6 below for a study for a study of artificial lift feasibility and what method to use in a Siberian location. Table 19 shows one panel of information collected for ESP’s and details the costs and equipment for a 900 bpd installation based on data collected from other similar fields. This application detailed in Reference 6 was for deep deviated wells drilled from onshore locations in a marshy environment. Component service lives are shown in Table 20. Targets and downside potentials were established for this study as shown in Figure 19. Reference 18 also includes various run life information and selection criteria. Swan Hills (Alberta), Milne Point (Alaska), the Amoco Congo field, the THUMS E. Wilmington field, and the Amoco N. Sea field, the Montrose field were used to help predict run lives for the Priobskoye field in Siberia. More information on the conditions present in these fields can be found in Reference 6. The “learning curve” aspect of these fields is costly showing the time required to come up to reasonable operational lives for the ESP installations. Table 21 shows some downhole hydraulic pump lives for a collection of fields. The conditions for these fields are presented in Reference 6 as well. The average life of the pumps is about 114 days. Target, downside and industry data is summarized in Figure 20 for the downhole hydraulic pumps. Table 22 summarizes costs for operating with Hydraulics in the study of Reference 6 for a 1000 bpd rate. These type of costs would have to be gathered for a number of rates and conditions for the data to be available for general application to an artificial lift study. No data is presented for gas lift system costs and failures expected. Initial compressor costs are high but after installation, most of the expenses are wireline work and new or repaired valves, unless a major compressor fix or addition is needed. Cost examples for other systems are not shown here. The data that is shown is, again, for particular fields and may/may not be indicative of what you would expect for a study that might be undertaken with other conditions present. Conclusions Discussion has been presented on various methods available for the selection of the best artificial lift system for given conditions. The discussion reviews methods from a depth-rate feasibility map, tables of advantages and disadvantages,

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through “expert system” programs containing feasibility, technical, and economic programs. Examples are given for calculating the net present value of artificial lift methods as one example of how to economically select the best method of lift. The examples show what data is needed to allow the engineer to be able to make a choice that should maximize profits over the life or a portion of the life of the field. The examples presented assume that the user of the NPV method has used previously mentioned methods of reviewing advantages and disadvantages, and other feasibility methods to be sure that the systems economically analyzed can be used for given conditions. Since the NPV method reviewed requires designs to meet target rates, then the user is somewhat forced to evaluate harsh conditions, etc., during the course of the design. He has to then add gas separators, sand trim, or whatever is necessary to try to meet target rates before the NPV analysis is performed, so by necessity, various feasibility criteria has to be considered. If target rates are not possible, then the system is eliminated from consideration. The reader is left with a menu of various possibilities for selection of a lift method varying from use of simple charts and tables, to economic analysis calculations, to use of existing or future expert system computer programs. References 1. Clegg, J.D., Bucaram, S.M. and Hein, N.W., New Recommendations and Comparisons for Artificial Lift Method Selection, SPE 24834; and Journal of Petroleum Technology, 1128, December 1993. 2. Brown, K.E., Overview of Artificial Lift Systems, Journal of Petroleum Technology, 2384, October 1982. 3. Panel Discussion, Neely, B. Moderator, Selection of Artificial Lift Method, SPE 10337. 4. Espin, D.A., Gasbarri, S. and Chacin, J.E., Expert System for Selection of Optimum Artificial Lift Method, SPE 26967. 5. Heinze, L.R., Thornsberry, K. and Wit, L.D., AL: An Expert System for Selecting the Optimal Pumping Method, SPE 18872. 6. Valentin, E.P. and Hoffman, F.C., OPUS: An Expert Advisor for Artificial Lift, SPE 18184. 7. Etherton, J.H. and Thornton, P., A Case Study of the Selection Procedure for Artificial Lift in a High Capacity Reservoir, SW Petroleum Short Course – 88. 8. Smith, G.L., Lease Operational Study – Gas Lift vs. Submersible Pump Lift – G.H. Arledge “C” Lease, Scurry County, Texas, SPE 6852. 9. Kol, H. and Lea, J.F., Selection of the Most Effective Artificial List System for the Priobskoye Field, SPE ESP Workshop, April 26-28, Houston, TX. 10. Clegg, J.D., Artificial Lift Efficiency Depends on Design, The American Oil & Gas Reporter, 48, June 1991. 11. Lea, J.F., Artificial Lift—Operating at Lower Cost, SPE Distinguished Lecturer Presentation. 12. Clegg, J.D., Artificial Lift: Producing at High Rates, SPE Distinguished Lecturer Presentation. 13. Johnson, L.D., Selection of Artificial Lift for a Permian Basin Waterflood, SW Petroleum Short Course, Lubbock, 1968. 14. Bennett, P., Artificial Lift Concepts and Timing, Petroleum Engineer, 144, May 1980.

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15. Weighhill, G.T., ESP Selection and Operating Strategy at Wytch Farm. 16. Powers, M.L., The Depth Constraint of Electric Submersible Pumps, SPE 24835. 17. “Toolkit” of computer programs by Integrity Consulting, Parker, CO. 18. Lea, J.F., Patterson, J., “Selection Considerations for Artificial Lift”, Artificial Lift Equipment Forum, Dubai, 1997.

Appendix The economic equations used for the selection of lift methods by economic analysis are summarized in this Appendix. The equations are presented as pseudo code for readability. Values not explicitly calculated are assumed to be user input values. Initial Oil Rate (BBL/YR) = 365.25 x Initial Production Rate x Initial Water Cut Abandonment Oil Rate = 365.25 x Total Abandonment Rate x Abandonment Water Cut Rdecl = Oil Production Decline Rate/100 Years to Abandonment = - (Ln(Initial Oil Rate) – Ln(Aband. Oil Rate))/Ln(1 – Rdecl) Initialize at Year 0 BOPD(0) Water Cut(0) GOR(0) Cumulative NPV (0) Cumulative Oil (0)

= = = = =

Initial Oil Rate / 365.25 Initial Water Cut Initial GOR 0 0

Calculate production decline factor R = Ln(1 – Rdecl) Begin loop to calculate costs and present value up to the abandonment year. FOR YEARS I = 1 TO YEARS TO ABANDONMENT Calculate daily production rate at end of year 1 BOPD (I) = BOPD(0) x Exp(R* I) Calculate maximum production for year I for full production Qmax (I) = 365.25 * (BOPD (I) – BOPD (I - 1)) / R Adjust for lost production Qoil (I) = Qmax (I) - (Qmax (I) / 365.25) x Days/Workover x Workovers/Year Calculate cumulative oil produced to end of year I Cumulative Oil (I) = Cumulative Oil (I-1) + Qoil (I) Straight line GOR and Water Cut

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WC (I)

=

WC (0) + I x (Abandonment WC Initial WC)/ Years to Abandonment GOR (I) = GOR (0) + I x (Abandonment GOR Initial GOR)/ Years to Abandonment Calculate Water and Gas Rates for Year I Qwat (I) = Qoil (I) x WC (I) / (1 – WC (I)) Qgas (I) = .001 x Qoil (I) x GOR (I) Calculate Required Cost and Revenue Factors Rinflation = (1 + Inflation Rate / 100) ^ (I - 0.5) Rdiscount = (1 + Discount Rate / 100) ^ (I - 0.5) Roil = (1 + Oil Price Increase Rate/ 100) ^ (I - 0.5) Requip = (1 + Equipment Cost Increase Rate / 100) ^ (I 0.5) Relec = Electricity cost / bbl liquid produced = 24 x kW/blpd x $/kW Calculate Fluid Costs Fluid Cost (I) = Rinflation x Fluid Disposal Cost/BBL x (Qoil (I) + Qwat (I) ) Calculated Fixed Operating Cost Fixed Cost (I) = Rinflation x 12 x (Common Fixed Cost + Method Specific Fixed Cost) Calculate Workover Cost Workover Cost (I) = Rinflation x Cost/Workover Day x Days/Workover x Workovers/Year Calculate Equipment Cost. Equipment costs are specified for each lift method and vary from method to method. For each method, the type of equipment (pump, sucker rods, tubing, ESP cable, etc), replacement cost for each type and the anticipated frequency of replacement (either as a run life table or a fixed replacement interval) are specified. Total equipment cost is calculated by summing over all identified method specific equipment, including the equipment cost ONLY during those years where replacement is scheduled from the run life table or specified fixed replacement interval. Equipment Cost (I) = Equipment Cost (I-1) FOR J = 1 to Number of Equipment Types IF year I is a replacement year for Equipment (J) THEN

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Equipment Cost (I)


=

ENDIF END FOR Calculate Electricity Cost Electricity Cost (I) =

Equipment Cost (I) + Requip x Cost of Equipment (J)

Rinflation x Relec x (Qoil (I) + Qwat (I)) Calculate Total Costs for Year 1 Yearly Cost (I) = Fluid Cost (I) + Fixed Cost (I) + Workover Cost (I) + Equipment Cost (I) + Electricity Cost (I) Calculate Total Income for Year I Yearly Income (I) = Roil x (1 – Royalty/100) x (Qoil (I) x $/BBl Oil + Qgas (I) x $/Mscf) Calculate Net Present Value from Year I Net PV (I) = (Yearly Income (I) Yearly Cost (I)) / Rdiscount Calculate Cumulative Net PV from Year 0 to Year I Cumulative NPV (I) = Cumulative NPV (I-1) + Net PV (I) END FOR

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Table 1: Relative Advantages of Artificial Lift Systems (After K. E. Brown, JPT, Oct., 1982)

Rod Pumping Relatively simple system design Units easily changed to other wells with minimum cost

Hydraulic Piston Pumping

Electric Submersible Pumping

Not so depth limited-can lift large volumes from great depths

Can lift extremely high volumes, 20,000 B/D (19078 m 3/d), in shallow wells with large casing.

Efficient, simple and easy for field people to operate.

500 B/D (79.49 m 3 /d) from 15,000 ft. (4572 m) have been installed to 18,000 ft. (5486.4 m)

Applicable to slim holes and multiple completions.

Crooked holes present minimal problems.

Can pump a well down to very low pressure (depth and rate dependent).

Unobtrusive in urban locations.

System usually is naturally vented for gas separation and fluid level soundings. Flexible-can match displacement rate to well capability as well declines.

Power source can be remotely located. Analyzable. Flexible-can usually match displacement to well’s capability as well declines. Can use gas or electricity as power source.

Analyzable. Can lift hightemperature and viscous oils.

Downhole pumps can be circulated out in free systems.

Can use gas or electricity as power source.

Can pump a well down to fairly low pressure.

Corrosion and scale treatments easy to perform.

Applicable to multiple completion’s.

Applicable to pump off control if electrified.

Applicable offshore.

Availability of different sizes. Hollow sucker rods are available for slim hole completion’s and ease of inhibitor treatment. Have pumps with double valving that pump on both upstroke and downstroke.

Closed system will combat corrosion. Easy to pump in cycles by time clock. Adjustable gear box for Triplex offers more flexibility. Mixing power fluid with waxy or viscous crudes can reduce viscosity.

Currently lifting ± 120,000 B/D (19068 m 3/d) from water supply wells in Middle East with 600-hp (448-kW) units; 720-hp (537kW) available, 1,000-hp (746kW) under development. Unobtrusive in urban locations. Simple to operate. Easy to install downhole pressure sensor for telemetering pressure to surface via cable. Crooked hole present no problem. Applicable offshore. Corrosion and scale treatment easy to perform. Availability in different size. Lifting cost for high volumes generally very low.

Gas Lift Can handle large volume of solids with minor problems. Handles large volume in highPl wells (continuous lift). 50,000 B/D (7949.37 m 3/d). Fairly flexibleconvertible from continuous to intermittent to chamber or plunger lift as well declines. Unobtrusive in urban locations. Power source can be remotely located. Easy to obtain downhole pressures and gradients. Lifting gassy wells is no problem. Sometimes serviceable with wireline unit. Crooked holes present no problem. Corrosion is not usually as adverse. Applicable offshore.

Hydraulic Jet Pump

Plunger lift

Retrievable without pulling tubing.

Retrievable without pulling tubing.

Has no moving parts.

Very inexpensive installation.

No problems in deviated or crooked holes. Unobtrusive in urban locations.

Automatically keeps tubing clean of paraffin, scale. Applicable for high gas oil ratio wells.

Applicable offshore. Can use water as a power source. Power fluid does not have to be so clean as for hydraulic piston pumping. Corrosion scale emulsion treatment easy to perform. Power source can be remotely located and can handle high volumes to 30,000 B/D (4769.62 m 3/d).

Can be used in conjunction with intermittent gas lift. Can be used to unload liquid from gas wells.

Progressive Cavity Pumps Some types are retrievable with rods Moderate Cost Low Profile Can use downhole electric motors that handle sand and viscous fluid well High electrical efficiency

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Table 2: Relative Disadvantages of Artificial Lift Systems Rod Pumping Crooked holes present a friction problem. High solids production is troublesome. Gassy wells usually lower volumetric efficiency. Is depth limited, primarily due to rod capability. Obtrusive in urban locations. Heavy and bulky in offshore operations. Susceptible to paraffin problems. Tubing cannot be internally coated for corrosion. H2S limits depth at which a large volume pump can be set. Limitation of downhole pump design in small diameter casing.

Hydraulic Piston Pumping Power oil systems are a fire hazard. Large oil inventory required in power oil system which detracts from profitability. High solids production is troublesome. Operating costs are sometimes higher. Usually susceptible to gas interferenceusually not vented. Vented installations are more expensive because of extra tubing required. Treating for scale below packer is difficult. Not easy for field personnel to troubleshoot. Difficult to obtain valid well tests in low volume wells. Requires two strings of tubing for some installations. Problems in treating power water where used. Safety problem for high surface pressure power oil. Lost of power oil in surface equipment failure.

Electric Submersible Pumping

Gas Lift

Not applicable to multiple compilations.

Lift gas is not always available.

Only applicable with electric power.

Not efficient in lifting small fields or one well leases.

High voltages (1,000 V) are necessary. Impractical in shallow, low-volume wells. Expensive to change equipment to match declining well capability. Cable causes problems in handling tubulars. Cables deteriorate in high temperatures. System is depth limited, 10,000 ft. (3048.0 m), due to cable cost and inability to install enough power downhole (depends on casing size). Gas and solids production are troublesome. Not easily analyzable unless good engineering knowhow. Lack of production rate flexibility. Casing size limitation. Cannot be set below fluid entry without a shroud to route fluid by the motor. Shroud also allows corrosion inhibitor to protect outside of motor. More downtime when problems are encountered due to entire unit being downhole.

Difficult to lift emulsions and viscous crudes. Not efficient for small fields or one-well leases if compression equipment is required. Gas freezing and hydrate problems. Problems with dirty surface lines. Some difficulty in analyzing properly without engineering supervision. Cannot effectively produce deep wells to abandonment. Requires makeup gas in rotative systems. Casing must withstand lift pressure. Safety problem with high pressure gas.

Hydraulic Jet Pump Relatively inefficient lift method. Requires at least 20% submergence to approach best lift efficiency. Design of system is more complex. Pump may cavitate under certain conditions. Very sensitive to any change in back pressure. The producing of free gas through the pump causes reduction in ability to handle liquids. Power oil systems are fire hazard. High surface power fluid pressures are required.

Plunger Lift

Progressive Cavity Pumps

May not take well to depletion; hence, eventually requiring another lift method.

Elastomers in stator swell in some well fluids

Good for lowrate wells only normally less than 200 B/D (31.8 m/d).

Rotating rods wear tubing; windup and after-spin of rods increase with depth

Requires more engineering supervision to adjust properly. Danger exists in plunger reaching too high a velocity and causing surface damage. Communication between tubing and casing required for good operation unless used in conjunction with gas lift.

POC is difficult Lose efficiency with depth

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Table 3: Capacities of Reciprocating Hydraulic Pumps Tubing Working Fluid Maximum Pump Size Level, ft. Displacement, B/D 2-3/8" 6000 to 17000 1311 to 381 2-7/8" 6000 to 17000 2500 to 744 3-1/2" 6000 to 15000 4015 to 1357 Table 4: Capacities of jet free pumps Tubing Production B/D 2-3/8" 3000 2-7/8" 6000 3-1/2" 10000

Target Rate (bbl/day) Initial Installation ($) Energy Efficiency (%) Intake Pressure (psia) Lift Energy (kw/bbl/day) Workover Cost ($/day) Wireline Cost ($/day) Injection Gas ($/Mscf) Other Costs($/month)

Table 5: Lift Methods Costs: Low Rate Case Beam Hydraulic Gas Lift 1000 1000 1000 141000 173000 239000 58 16 15 900 900 900 .025 .096 .100 1000 1000 1000 1000 .24 200 2900 600 (Maintenance) (Maintenance) (Compressor Maintenance)

ESP 1000 105000 48 900 .031 1000 225 (Inventory)

Table 6: Beam Pump Equipment Costs, Low Rate Case Item Cost ($) Life (yrs) Tubing 80000 15 Rods 20000 4 Pump 6000 Run Life Table Table 7: ESP Equipment Costs, Low Rate Case Item Cost ($) Life (yrs) Tubing 80000 15 Pump 25000 Run Life Table Protector 4000 Run Life Table Separator 5000 Run Life Table Motor 15000 *Run Life Table Cable 50000 6 Cable Protector 20000 15 Transformer 12000 15 VSD 35000 15 •

Item Tubing Valve Mandrel

Motor life assumed 2 x pump life Table 8: Gas Lift Equipment Costs, Low Rate Case Cost ($) Life (yrs) 80000 15 2000 3 5000 10

Replace 2 6

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Table 9: Hydraulic Pump Equipment Costs, Low Rate Case Item Cost ($) Life (yrs) Tubing 80000 15 Pump 20000 Run Life Table

Year 1 2 3 4 5

Table 10: System Run Life Data Hyd. Pump Beam Pump ESP Pump (days) (days) (days) 300 200 300 400 600 750

Inj. Gas Volume (Mscf/d) 600 700 800 900 1000

Table 11: Summary of Low Rate NPV Calculations - Constant Rate Method NPV (MM$) Costs (MM$) Cost/NPV ESP 4.7 .82 .17 Gas Lift 3.80 .82 .22 Hydraulic Pump 4.28 1.12 .26 Rod Pump 4.70 .67 .142 Table 12: Equipment Operational Costs, High Rate Case Jet Gas Lift ESP Target Rate (bbl/day) 17000 17460 17020 Initial Installation ($) 200000 265000 150000 Energy Efficiency (%) 21 16 41 Lift Energy (kw/bbl/day) .042 .056 .022 Workover Cost ($/day) 2000 2000 2000 Wireline Cost ($/day) 2000 Injection Gas ($/Mscf) .24 Other Costs($/month) 2900 3000 225 (Maintenance) (Compressor (Inventory) Maintenance) Table 13: ESP Equipment Costs, High Rate Case Item Cost ($) Life (yrs) Tubing 80000 15 Pump 25000 Run Life Table Protector 4000 Run Life Table Separator 5000 Run Life Table Motor 15000 *Run Life Table Cable 50000 6 Cable Protector 20000 15 Transformer 12000 15 VSD 35000 15 * Motor life assumed 2 x pump life Table 14: Gas Lift Equipment Costs, High Rate Case Item Cost ($) Life (yrs) Replace Tubing 80000 15 Valve 2000 3 2 Mandrel 5000 10 6

18


SPE 52157

Table 15: Hydraulic Pump Equipment Costs, High Rate Case Item Cost ($) Life (yrs) Tubing 80000 15 Pump 20000 Run Life Table

Year 1 2 3 4

Method ESP Gas Lift Jet Pump

Table 16: System Run Lives, High Rate Case Hyd. Pump Inj. Gas Volume Beam Pump ESP Pump (days) (Mscf/d) (days) (days) 300 200 300 300 400 600 750 Table 17: Summary of NPV Analysis, High Rate Case NPV (MM$) Costs (MM$) Cost/NPV 218.2 3.4 .016 211.1 4.0 .019 222.9 4.4 .020

Table 18: Field conditions for THUMS field where MTBFs’ are illustrated in Figure 18 Zone On/Offshore Active Producers General Description

Well Production, BFPD Pump Intake Pressure, psi Vertical Depth, ft Oil Gravity, oAPI GLR, scf/bbl Avg. Resv. Press., psi Avg. Temp. oF Avg. W ater Cut, (%) Avg. Viscosity, cp Scale Abrasives CO2, ppm, H2S, ppm Emulsion Problems Casing Size Liner Size Completion Tubing Size

Ranger Terminal Offshore Offshore 439 128 Unconsolidated Poorly Sandstone Consolidated Sandstone 200 - 5,500 120 - 3,500

UP Ford Offshore 44 Moderately Consolidated Sandstone 40 - 1,500

100 - 850 100 - 850 100 - 600 2,100-3,200 2,800 - 4,200 4,100 - 7,100 15 20 28 11 35 80 1,000 1,100 1,400 130 160 210 94 82.5 80 80 15 5 CaCO, BaSO4 CaCO, BaSO4 CaCO light - heavy light - heavy light - heavy 0-5% 0-5% 0-1% 0-4000 0-4000 0-2000 0-4000 0-4000 0-2000 Y Y Y 8-5/8", 32# 8-5/8", 32# 9-5/8", 40# 6-5/8", 28# 6-5/8", 28# 7", 26# Gravel Pack Gravel Pack Slotted Liner 2-7/8", 6.4# 2-7/8", 6.4# 2-7/8", 6.4#

SPE 52157


19

Table 19: Summary of lives and costs of various components of an ESP system (Ref. 6) 900 BPD TARGET CASE

ite m c o st

PV

/ ye a rly c o st 1 2

Wo rko ve r fre q ue nc y investment: p ump / p rotec to r se p a ra tor c a b le mo to r d o w nho le se nso r tub ing ste p -up tra nsfo rme r VSD/ sw itc h b o a rd c a b le p ro te c tors opera ting costs: e le c tric ity w o rko ve r inve nto ry o ve rhe a d TOTAL ESC . EXPENSE ca shflow

24.3 3.9 50.3 20.4 5.6 83.0 10.2 31.2 14.0

15.0

(977) 257.9

equipment: 389 sta g e p ump 120 HP mo to r No 2 c a b le

3

4

5

6

2.8

1.1

0.6

0.5

0.5

0.5

68.5 11.1 50.3 28.7 15.8 83.0 10.2 31.2 14.0

26.5 4.3

14.6 2.4

12.1 2.0

12.1

20.4 42.3 2.7 22.7 400.8 -401

7

8

9

10

11

12

0.5

0.5

0.5

0.5

0.5

0.5

12.1

12.1

12.1

12.1

12.1

12.1

12.1

5.1

5.1

5.1

5.1

5.1

22.1 7.5 2.7 3.0 69.2 -69

22.4 7.5 2.7 3.0 72.3 -72

22.7 7.5 2.7 3.0 75.6 -76

22.9 7.5 2.7 3.0 79.1 -79

23.2 7.5 2.7 3.0 82.7 -83

11.1 5.6

6.1 5.6

5.1 5.6

5.1

5.1

50.3 5.1

20.6 16.4 2.7 5.2 96.0 -96

20.9 9.0 2.7 3.7 70.2 -70

21.1 7.5 2.7 3.4 66.9 -67

21.4 7.5 2.7 2.9 60.5 -61

21.6 7.5 2.7 2.9 63.3 -63

21.9 7.5 2.7 6.0 133.7 -134

a ll c ost x $1000

Table 20: Summary of some lives of ESP equipment derived for the study in Reference 6. Estimated cumulative service life for ESP components1. Component/case Pump/intake Separator2 Motor Cable d.h. sensor Transformer VSD3 Tubing 1

150 BFPB target

300 BFPD target

>450 BFPD target

150 BFPD downside

target curve target curve 2x target 6 years target curve 15 years 5 year 15 years



<250 curve <250 curve 2x <250 6 years <250 curve 15 years 5 year 15 years

Cumulative service life in this table is related to the estimated run life depicted in Figure 19. Rotary separators will be used for the first 5 years only VSD’s will only be used for the first 5 years.

2 3

300 BFPD downside interpolated interpolated 2x interp. 6 years interpolated 15 years 5 year 15 years

>450 BFPD downside >500 curve >500 curve 2x >500 6 years >500 curve 15 years 5 year 15 years

20


SPE 52157

Table 21: Summary of hydraulic pump lives for various fields.

Operator Citronell Unit Operator,

Depth

Production

(ft)

(bpd)

10-11000

300-400

N. Of Mobile, Al. Texaco Barre Field,

Triplex, oil system 3000 psi inj Several wells on one pump Triplex, oil system 1800-2400 bpd oil

49

Use Kevlar spring loaded plungers & liners

75

Like soft pack Triplex

100-450

10,500

15-50

Triplex, oil Vortex to clean oil

165

10,000

75

Triplex, 3000-3500 psi

90

at 3900 psi

Woodland Unit MWJ Baum/Sanders

Comments

(days)

15,000

S. Al. Unocal Wyoming

RUN LIFE DATA FOR HYDRAULICS JFL / TRC Power System Pump Run Life

Single string systems Pressure annulus to bring pump up Takes about 1000 psi to move pmp up

in New Mexico

no trouble

Recip pumps, corrosion treat BHA's 1 inch vent string Production up casing

J. Schlagel

Injection down tubing (2 3/8) Recommends individual pwr supply

Marathon Cody Unit, WY

7,500

475

Triplex,uses water and oil

180 (min)

Slower pumps (lt. 45 spm) may run 3 years..

Andy Franklin

for pwr fluid

Pump repair: $1500-2000

(likes now with

Vortex cleanup

For frac cleanup the fill

experience)

4 spd trans

well with liquids, circulate and filter with vortex unit at surface Single string- monitor tub press for pump off..trying VSD 200-300 psi on casing brings up pmp

UNOCAL Huntington Beach

4,000

295

Joe Gonzales

1st Triplex with oil now ESP with water some 3000 psi

Use 3 string, main& 2 side strings Free pump installations

some 2000 psi

BHA's 3 years

Power water not mixed with production side strings leak, pull only one string if side string few hrs to pull side string 4 hrs to round trip new pump ESP's less maintenance, more energy to run Triplex's more maintenance, less energy to run

Cook Inlet UNICAL Dean Geisert likes hydraulic better than ESP's

7,500

105 avg

Triplex & ESP Oil system tank only separation no vortex cleanup 3550 psi generated 60 hz esps

180 plus

Use recip and jet pumps 2 1/2 hrs to replace pumps Tubing tripped not more than 3-4 years two strings, open annulus check fluid level with echometer runs two strings simultanously

gears on triplex's Average Pump Run Life, days 114.5

SPE 52157


21

Table 22: Summary of run lives and costs assumed for one rate for study of Reference 6. 1000 B PD

PV

it e m cost

/ y e a r ly c o s t 1 2

p u m p r e p a ir f r e q .

2 .0 0

in v e s t m e n t : d o w n h o le p u m p a s s o c ia t e d e q u ip m e n t p o w e r f lu id p u m p * p o w e r f lu id s y s t e m a u t o m a t io n e q u ip m e n t t u b in g

1 0 .0 3 0 .0 5 0 .0 1 1 0 .0 1 0 .0 1 5 5 .4

o p e r a t in g c o s t s : e le c t r ic it y w o rk o ve r w e ll a t t e n d e n c e s u r f a c e e q p m . m a in t . d o w n h o le p u m p r e p a ir * o ve rh e a d TO TA L E S C . E X PE N S E c a s h f lo w

H y d r a u lic P u m p S y s t e m s

TA R G E T C A S E

3

2 .0 0

4

2 .0 0

5

2 .0 0

2 .0 0

6

2 .0 0

1 0 .0 3 0 .0 5 0 .0 1 1 0 .0 1 0 .0 1 5 5 .4

3 8 .4 6 0 .0 2 .5 1 1 .2 8 .0 2 9 .1 5 1 4 .6 -5 1 5

3 0 .0

4 .0

(1,222) 3 9 9 .4

7

2 .0 0

8

9

10

11

12

2 .0 0

2 .0 0

2 .0 0

2 .0 0

2 .0 0

4 1 .7

4 2 .2

4 2 .7

4 3 .2

4 3 .7

2 .5 1 1 .2 8 .0 3 .8 8 8 .5 -8 8

2 .5 1 1 .2 8 .0 3 .8 9 2 .7 -9 3

2 .5 1 1 .2 8 .0 3 .9 9 7 .2 -9 7

2 .5 1 1 .2 8 .0 3 .9 1 0 1 .9 -1 0 2

2 .5 1 1 .2 8 .0 3 .9 1 0 6 .8 -1 0 7

1 0 .0 1 0 .0 5 0 .0

3 8 .8

3 9 .3

3 9 .8

4 0 .2

4 0 .7

2 .5 1 1 .2 8 .0 3 .6 6 6 .7 -6 7

2 .5 1 1 .2 8 .0 3 .7 6 9 .9 -7 0

2 .5 1 1 .2 8 .0 3 .7 7 3 .3 -7 3

2 .5 1 1 .2 8 .0 3 .7 7 6 .8 -7 7

2 .5 1 1 .2 8 .0 3 .7 8 0 .5 -8 1

4 1 .2 3 0 .0 2 .5 1 1 .2 8 .0 9 .8 2 1 8 .5 -2 1 9

a ll c o s t x $ 1 0 0 0

2000

Pressure, psig

1500

1000

500

0

1 0

Inflow @ Sandface (1) Inflow (1) Not Used Not Used Not Used Not Used Not Used Not Used

100 Not Used Outflow (A) Not Used Not Used Not Used Not Used Not Used

200

300

400

Liquid Rate, Bbl/D

Reg: James F. Lea - Amoco

Figure 1: IPR with bubble point below static reservoir pressure.

Figure 2: Schmetic of geometry of horizontal well inflow model.

500

600

22


SPE 52157

2000

Pressure, psig

1500

1000

500

0

5 0

Inflow @ Sandface (1) Inflow (1) Case 2 (2) Case 3 (3) Case 4 (4) Case 5 (5) Not Used Not Used

100

200

Not Used Outflow (A) Case 2 (B) Case 3 (C) Case 4 (D) Case 5 (E) Not Used

Figure 3: IPR’s decreasing with time.

Figure 4: Major Artificial Lift Systems (from Trico)

4

3 300

Liquid Rate, Bbl/D Inflow Declining reservoir press, psia

Reg: James F. Lea - Amoco

2 400

1 500

Inflow (1) 2000.0 (2) 1800.0 (3) 1600.0 (4) 1400.0 (5) 1200.0

600

SPE 52157


A r t if ic ia l L if t :

R a t e

v s . D e p t h

10

100

v s . M

e t h o d

Ref: Pennwell AI Methods Chart, 1986

BPD 1

23

1000

10000

100000

0 2000

Plunger

4000

DEPTH, FT

6000

Gaslift

8000 10000

Beam

12000

ESP 14000 16000 18000

1

10

100

0 2000

Hyd. Jet

4000

DEPTH, FT

6000

PCP

8000 10000 12000 14000 16000

Hyd. Recip.

18000 Figure 5: Depth/Rate Selection Chart after Blais

1000

10000

100000

24


Figure 6: Schematic of Beam Pumping System

Figure 7: Schematic of Typical ESP system

SPE 52157

SPE 52157


25

Figure 8: Schematic of PC pump.

The ESPCP System y Progressing cavity pump driven by submersible motor y Replaces Rod-Driven PC Pump Units:

PCP Flex Shaft Assembly

– Deviated wells – Viscous production

Cable

Seal Section

Gear Reducer Electric Motor

Figure 9: Schematic of ESPPC system

26


SPE 52157

The ESPCP System y Standard components include: – Seal section – Motor

PCP

– Cable

Flex Shaft Assembly

– PC pump y New components include: – Intake with flex shaft – Gear reducer

Cable

Seal Section

Gear Reducer Electric Motor

Figure 10: Components of an ESPPC System

Figure 11: Reciprocating hydraulic pump and Jet Hydraulic Pump

SPE 52157


Figure 12: Showing operation of “free” hydraulic pump installation.

Figure 13. Schematic of gaslift system:

27

28


Present Value MM $

SPE 52157

ESP

Gas Lift

Hydraulic Pump

Rod Pump

5.0 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0 0

1

2

3

4

5

6

7

8

9

Years D:\LANG\VB4\ECON\LORATE1.PEP

Figure 14: Summary of Low Rate NPV Analysis

Present Value MM $ 225 200 175 150 125 100 75 50 25 0

0

1

2

3

4

5

6

7

8

9

Years Figure 15: Summary of High Rate NPV Analysis

10

11

12

13

14

15

16

17

18

SPE 52157


29

Ty p ica l B ea m S y s t em Fa ilu r es P er Yea r - 532 w ell s 35 0

1.2 0

1.14

30 0 25 0

0.74

20 0

0.81 $9 7 2 .4 K

P u lls

1.0 0

F PW PY

0.8 0

$8 6 3 .4 K

0.60

15 0

$6 4 1 .6

0.45

10 0

0.6 0

$567.5K

$8 6 3 .7 K

0.51 $4 6 1 .1 K

0.41

0.39

0.4 0

0.29

50

0.2 0

0

0.0 0 1989

1 990

19 91

199 2

1993

1 994

1 995

19 96

199 7

Figure 16: History of typical beam pump opeation: failures per year with approximate associated costs.

Total P um p Failures = 418

Typical D istribution of B eam P ump Failures Total Tubing Failures = 224

Total B eam Failures = 1110

Total P in & Coupling Failures = 206

P olis h Rods 5%

Other 3%

Rod B odies 15%

Total Rod B ody Failures = 171

Total P olis h Rod Failures = 58

Total "Other" B eam Failures = 33

P um ps 38%

P in & Couplings 19%

Tubing 20%

Figure 17: Typical distribution of failures among the beam pump system components

30


SPE 52157

1,4 00 1,3 00 1,2 00

A c tiv e E S P s

1,1 00

M TB F , D ay s

1,0 00 9 00 8 00 7 00 6 00 5 00 4 00 3 00 2 00 1 00 0 1983

1984

1985

1986

1987

1988

1989

1990

1991 1992

1993 1994

1995

1996

1997

Figure 18: History of increasingly better run lives (MTBF) in the THUMS field.

PRIOBSKOYE average ESP run life prediction 900

Sw an Hills (Im Target

800

Runlife (days)

700 Sw an Hills

600 Congo

500

Dow n side > 500BPD

400 300

Dow n side < 250BPD Montrose

200

Milne Point

100 0 0

2

4

6

8

10

Years of deployment

Figure 19: Failure data from a number of field locations and also target values for the study in Reference 6. 400 350

Days

300 250

industry data

200

target

150

downside

100 50

BFPD NOTE : several values reported as 180 days plus

Figure 20: Run life of downhole hydraulic pumps

1000

900

800

700

600

500

400

300

200

100

0

0

Selection of Artificial Lift

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