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Designing a Sucker-Rod Pumping System for Maximum Efficiency
Abstract
Consideration of the energy requirements in the design of a sucker-rod pumping system is very important. Examples are given that detail how the use of the largest possible pump with the lightest, strongest rod string and special-geometry units can provide a substantial energy reduction.
Introduction
A number of variables are important in the design of a sucker-rod pumping system. To get the best design for a specific application, each variable must be evaluated in terms of the particular requirements of that specific system. A system that might be ideal for the operating conditions of one area might be a very poor selection for another area with different operating conditions. The importance of the energy requirement is in proportion to the cost of energy. Twenty years ago, proportion to the cost of energy. Twenty years ago, electricity sold for about 0.002/MJ] and gas for about 0.0088/m3]. The energy bill was so, small that it was not even considered in the design of the system. Because most of the expertise in the design of sucker-rod systems was gained in this era of low energy costs, the impact of energy costs on the system design has been largely ignored. Today, the average cost of electricity is about 0.019/MJ], and the average lease value of natural gas is about 0.106/m3]. Now the energy bill is usually the largest operating cost item on the lease and has become a very important design consideration.
Theoretical Energy Costs
A discussion of energy usage and cost should start with hydraulic horsepower. This is the theoretical work that is required to lift the pounds of well fluid from the net depth. The equation for calculating hydraulic horsepower for a fluid weighing 8.34 lbm/gal [999 kg/m3] (specific gravity of 1.0) is
Lw h = 33,000 h t
q × 42 × 8.34 1 h = Lx ×, h 1,440 33,000
h = 0.00000736 qL, h
where h = hydraulic horsepower, h L = net left, ft, w = weight, lbm t = time, minutes, and q = flow rate, B/D.
In SI units, W = 0.0001135 qL, h
The theoretical hydraulic horsepower to lift 500 B/D [79.49 m3/d] of fluid with a specific gravity of 1.0 from 6,000 ft [1828.8 m] would be
0.00000736 × 500 B/D × 6,000 ft = 22.08 hhp.
In kilowatts,
22.08 hhp × 0.746 kW/hp = 16.47 kW.
In SI units,
0.0001133 × 79.49 m3/d × 1828.8 m = 16.47 kW.
The annual power bill, x, with 0.019/MJ] electricity would be
x = 10,100/yr.
This is the theoretical cost to do the work of lifting 500 B/D [79.49 m3/d] from 6,000 ft [1828.8 m].
Actual Energy Considerations
Polished-rod horsepower starts with this theoretical work at the Polished-rod horsepower starts with this theoretical work at the pump and includes the other downhole requirements of the system: pump and includes the other downhole requirements of the system:the horsepower required to move the sucker-rod string dynamically,the frictional losses between the sucker rods and the tubing,hydraulic frictional losses of the fluid as it flows between rods and tubing, andbottomhole pump losses and inefficiencies.
The dynamic horsepower requirements are related to the weight of the sucker-rod string and the pumping speed (strokes per minute times stroke length). The pumping speed for a given stroke length and producing rate is determined primarily by the size of the bottomhole pump. The frictional losses between the sucker rods and the tubing are related principally to fluid viscosity and tubing straightness. The hydraulic flow losses are a function of the producing rate and the annular area between rods and tubing. The bottomhole pump losses are related to the amount of slippage that passes the plunger and valves. The inefficiencies are related to the free gas in the pump from poor gas separation and the volume shrinkage resulting from the gas absorbed in the oil at pump intake pressure and then desorbed at atmospheric pressure.
... In contrast to these efficiencies, lifting efficiency, η lift , changes in very broad ranges depending on the pumping mode (combination of plunger size, stroke length, and pumping speed) selected. As first proved by Gault (1987) considerable improvements of lifting efficiencies can be realized by the proper selection of the pumping mode. Thus, to achieve maximum power efficiency one must find the pumping mode with the maximum possible value of lifting efficiency. ...
The most decisive constituent of operating expenditures in sucker-rod pumping operations is related to the system's electric power use as most installations are driven by electric motors. Consequently, the reduction of operating costs can be translated to the reduction of energy losses both downhole and on the surface. Therefore, the energy efficiency of the surface and downhole components of the pumping system as well as the overall system efficiency play a big role in maximizing profits. The paper presents a critical analysis of the energy efficiency of the individual components of the sucker-rod pumping system and introduces novel models to find the system's total efficiency.
The typical energy losses in the sucker-rod pumping system's main components (the downhole pump, the sucker-rod string, the surface pumping unit, the gearbox, the V-belt drive, and the prime mover) are discussed in detail. It is demonstrated that the level of the pumping unit's counterbalancing as well as any inertial effects do not impact on the net gearbox torques and on the required average mechanical output power of the motor. The energy consumption of the electric motor, however, is affected by the pumping unit's counterbalancing and the inertial effects because of the changes in motor efficiency due its variable loading within the pumping cycle.
The system's useful output power is performed by the downhole pump when it lifts the produced liquid to the surface. The paper demonstrates that the so-called hydraulic power, calculated from the increase of the produced liquid's potential energy, is a reliable indicator of the system's useful power. Using the hydraulic power together with the electric power taken from the power supply permits an easy way to assess the over-all energy efficiency of the pumping system. The paper proposes several other variants of system efficiency calculations; they are based on the fact that all components of the pumping system are connected in series to each other.
Sizing of electric motors for sucker-rod pumping installations is normally done with the use of a cyclic load factor (CLF) that accounts for the fluctuations in motor load during the pumping cycle. Originally, CLFs were found from the variation of motor current, but mechanical CLFs based on net gearbox torques are much more practical to use. This practice is fully justified in the paper by proving that the correlation between the motor's real current and its net torque loading is nearly linear. It is further shown that the safety of sucker-rod pumping installation design is improved if the electric motor is sized with the use of a mechanical CLF because that case gives the highest required nameplate motor power.
... With the depth of the pump stroke increasing, the stroke loss also increases. If you have no oil pumping technology matching well with deep well, and ultimately the system efficiency will decrease with the increase of depth [7]. Pump parameters and downhole tools should be selected according to the specific conditions of each well, so as to accommodate gas, sand, wax and other well conditions requirements. ...
... • The subsurface sucker rod-driven pump • The sucker rod string • The surface pumping equipment • The power transmission unit • The prime mover It is suggested from studies that optimizing the swabbing parameters is an effective way to enhance the system efficiency of pumping well (Gault, 1987;Lekia and Evans, 1995;Shedid, 2009). Domestic and foreign scholars have made great contribution in designing and optimizing method of the parameters of pumping wells (Han et al., 1995;Mo, 2000;Yao, 2005). ...
Aiming at the drawbacks of the optimization and design methods and the practical production goal of least energy consumption, a new theory is raised that the gas of the layer released energy in the lifting process including two parts: dissolved-gas expansion energy and free-gas expansion energy. The motor's input power of rod pumping system is divided into hydraulic horse power, gas expansion power, surface mechanical loss power, subsurface loss power. Using the theory of energy-conservation, the simulation model of free-gas expansion power has been established, the simulating models of the motor's input power which are based on the energy method have been improved and the simulation precision of system efficiency has been enhanced. The entire optimization design models have been set up in which the single-well output is taken as the optimum design variable, the planed production of all oil wells in an overall oilfield as the restraint condition and the least input power of the overall oilfield as the object. Synthesizing the optimization design results of the single well and the entire oilfield, the optimal output and the optimal swabbing parameters of all wells can be got. The actual optimizing examples show that the total power consumption designed by the entire optimization method is less 12.95% than that by the single optimization method.
... For example, Takacs (1990) reports lifting efficiencies between 94 and 38%. According to Gault (1987), considerable improvements in lifting efficiencies can be realized by selecting the optimum pumping mode (i.e., the combination of pump size, polished-rod-stroke length, pumping speed, and rodstring design). ...
Two of the most important artificial-lift methods applied in oil wells are sucker-rod pumping (SRP) and electrical submersible pumping (ESP, with thousands of installations all over the world. Their operational features and application ranges are quite different, but in many cases either of them can be used in a given well. The final selection of the proper method has to be on the basis of energy efficiency, and the one requiring the least amount of surface power input is selected. This paper provides the necessary background for evaluating the effectiveness of the two lift methods investigated and for pinpointing the requirements of achieving maximum power efficiency of artificial lifting.
The power flow in the pumping system is investigated, and the sources of power losses, along with their usual ranges, are described. The overall power efficiency of the system is defined by a simple formula that provides the necessary insight into the main components of the power losses occurring in different system elements. A thorough investigation of the efficiency components allows one to find the factors that most markedly influence the total system's power requirement. As shown in the paper, the most important requirement for achieving maximum effectiveness is the proper choice of the pumping mode (i.e., the combination of plunger size, stroke length, and pumping speed).
The calculation of energy losses in the components of the ESP system is detailed, and the relative importance of the individual losses is shown. Because the components of the ESP system are connected in series, a relatively simple formula can be used to describe the effect of electrical and hydraulic losses on the efficiency of the total system. The terms of the final formula were investigated for their importance and contribution to the overall effectiveness of the ESP system. Results of this investigation provide crucial information that explain how to design an ESP system that provides the highest power efficiency. The practical use of the proposed calculation models is illustrated by presenting an example case where a relatively high liquid rate (1,300 B/D) from the same well is produced by rod pumping and by ESP. Detailed installation designs resulted in several different operation modes for both SRP and ESP. The paper demonstrates that using the latest technologies (e.g., high-strength sucker-rod connections), SRP can compete successfully with ESP installations by attaining higher energy efficiencies.
... For example, Takacs [ 6 ] reports lifting efficiencies between 94% and 38% when producing 500 bpd from 6,000 ft with different pumping modes. As supported by Gault [ 7 ], considerable improvements on lifting efficiencies can be realized by selecting the optimum pumping mode i.e. the combination of pump size, polished rod stroke length, pumping speed, and rod string design. In summary, the basic requirement for achieving high overall system efficiencies is to find the maximum possible value of the lifting efficiency. ...
Worldwide more than two thirds of the oil wells are placed on some kind of artificial lift, mostly on sucker-rod pumping, ESP, or gas lift. Because of the great number of installations it is extremely important that they operate under optimum conditions. Even small changes in operational efficiencies can significantly increase operational expenditures, so optimization of the energy efficiency has a great impact on profitability of oil production. The presentation deals with establishing the most energy-efficient operation of artificial lift installations. The aim of the optimization is finding the minimum operational costs while producing a prescribed liquid rate from the well, i.e. attaining the maximum power efficiency. Three forms of artificial lifting are studied: sucker-rod pumping, ESP, and gas lifting.
The power efficiency of any artificial lift system is defined by the relation of the useful power used for fluid lifting and the total input power. The useful hydraulic power is defined by the change of potential energy of the produced fluid, while the total input power can be calculated. Analysis of the power flow in rod pumped wells shows that maximum efficiency is reached with the proper combination of pump size, polished rod stroke length, and pumping speed. The installation's power efficiency is primarily determined by the choice of the pumping mode. The power efficiency of ESP installations is shown to reach a maximum when using a motor and a pump with the maximum efficiency while minimizing the power losses in the electric cable. Optimum design of continuous flow gas lift installations involves NODAL analyses and finds the combination of tubing size, injection and wellhead pressures, and flowline size that ensures the minimum compressor power requirements.
Volume IV: Production Operations Engineering will bring readers up to date in the areas of design, equipment selection, and operation procedures for most oil and gas wells. Chapters cover three main topic areas: well completions, problems caused by formation damage, and artificial lift—a major concern for production engineers.
For a long time, there is no unified method and standard for efficiency analysis and evaluation index of pumping well system. Therefore, this paper studies the theoretical extreme value of pumping well system efficiency. Based on the model of system efficiency evaluation method, the single factor analysis and comprehensive impact analysis are carried out, and a set of simple and convenient evaluation method of pumping well system efficiency is found out by using examples. It provides strong technical support for relevant technical departments and different oil production units to reasonably formulate measures and plans.
The present work aims to expose the study and development of a potentially disruptive change of focus in the mechanical sucker rod artificial lift system. This is a new solution based on the installation of a linear speed reducer located at the bottom of the well between the pump and the rods. This new configuration pursues the goal of dramatically reducing loads on the rod string, surface equipment and power motor, thus allowing to expand, in efficiency and field of application, the limits of the sucker rod pumping, and in some cases of the artificial lift systems as a whole.
Several ways for improving pumping operations were found from a study of a mature onshore field with more than seventy rod-pumped wells. The tasks of the study include: asses the current operating conditions of producing wells and find problems; determine the optimum pumping mode for each well while keeping current equipment rate restrictions; and take into account available inflow performance information to determine and verify optimum pumping system design. Measurements were obtained on the pumping wells with a portable computerized system and a complete analysis of a rod-pumped installation. A portable analyzer was used to measure processed data and evaluated dynamic fluid level, flowing bottomhole pressure, surface system and beam loadings, motor load and others. An analysis program calculated the degree of counterbalancing of the gearbox and recommends ways for achieving optimum conditions. Results show that practically all of the determined optimum pumping modes have lifting efficiencies from 70-85%; the fatigue loading of the top tapers in the rod strings is sufficiently high to ensure proper utilization of the rod's strength; all of the beam loads are greater than 60% indicating proper design and gearboxes are loaded fully to ensure a high torque efficiency of the pumping unit.
System efficiency is a reflection of utilization degree of the input energy. Exact evaluation system efficiency is the key to judge performance of rod pumping systems. Based on the system power loss reanalysis, crude oil viscosity, water content, and gas/oil ratio are considered to be the remarkably influencing factors. Mathematical data matching and 0-1 numerical regulation are employed to establish the system efficiency evaluation model with viscosity-factor. Also new variables of dimensionless gas/oil ratio and realized efficiency rate are defined in the process. This method is thought to be the basic to determine system efficiency top as well as bottom limit of the rod - pumped well. The model proposed is applied in some oil field and the system efficiency obtained agrees well with the tested one. It provides theoretical support for whether the optimal design should be done and the order to take measures.
To select a proper electrical machine and control strategy, based on dynamic parameters predicting model of oil-pumping, the geometry model and movement model are modified and expended. The characteristic of suspension load, driving characteristic of gearbox and coupled torque characteristic of electrical machine are analyzed, as a result, a dynamic coupled model for oil-pumping system is built, and its calculation accuracy is increased by deep analysis of static and dynamic suspension load. Finally, a typical system is selected to be simulated, and the correctness of the model is proved.
Hydraulically actuated sucker rod pumps have been around since the 1940's but have not received a widespread adoption or acceptance on the order of beam pumps, ESP's or PCP's. This is in no small part, due to a reputation of high maintenance costs and frequent failures. Innovations in hydraulically actuated sucker rod pumps, with a keen insight for the oilfield environment, have helped improve reliability and reduce maintenance costs. Among these improvements are the elimination of persistent external hydraulic leaks, a long-stroke capability, and a simplified control system. The instrumentation and control of the hydro-mechanical system is accomplished with an innovative method for determining both polished rod position and load based solely on the hydraulic fluid dynamics. This eliminates any sensors, or points of failure, at the wellhead. Vast improvements in control and data acquisition have greatly reduced the failure rates of hydraulic sucker rod pumping systems by automatically responding to adverse conditions. By allowing operators to remotely interact and troubleshoot the system, a finer grained level of optimization can be achieved by closely matching the wells inflow to the production rate. In some down-hole failure cases, such as a stuck pump, a unique advantage of a hydraulic system allows the operator to attempt unsticking the pump by overloading the polished rod. Although this procedure is not always successful, it does provide a last resort that may save the cost of pulling the well. This procedure is unique to a hydraulic system because there are no structural or reducer load limitations beyond that of the rod-string capacity. The long-stroke improves down-hole equipment runtimes by distributing the wear over a larger surface and by reducing the cyclic fatigue on the rod-string. While the hydraulically actuated sucker rod pump is not appropriate for every well, it does offer significant advantages in those wells where it is suitable. These advantages include long-stroke capability, remote optimization, and safe operation in terms of no external moving parts. The complete system is simple, cost effective, and portable, making it ideal for both permanent and trial installations.
The dynamic performance simulation of the beam pumping system is composed of two numerical simulation models. One numerical simulation model is built on the basis of the mathematical model to describe the crank movement, and the other is set up to describe the sucker rod longitudinal vibration. Taking into consideration the continuity conditions of beam pumping system, the comprehensive numerical simulation model for the system is established based on the mentioned above models. The comprehensive simulation algorithm is proposed, which is based on the numerical integration. The simulations reveal that good agreement is found between the experimentally obtained results and the simulations. The results between maximum and minimum polished rod loads of pumping unit appear to be accurate to within plus or minus 11%. In the same calculation environment, the simulation speed of the simulation software applying the comprehensive simulation algorithm is more than 10 times faster than those with the old algorithm. The improvement of the simulation speed establishes the foundation for combinatorial optimization of system dynamic parameters and energy consumption optimization of the system.
Pumping mode selection, optimum counterbalance determination, and rod string design are factors that can reduce operational costs and improve sucker-rod pumping operations. To maximize profits from sucker-rod pumped wells, designs must aim at technically and economically optimum conditions. Assessment of surface and downhole energy losses are basic considerations for improving system efficiency. It is important to properly select the pumping mode, such as the combination of plunger size, pumping speed, stroke length, and rod taper design. The best pumping mode maximizes lifting efficiency and, at the same time, reduces prime-mover power requirements and electrical costs. Surface equipment operational efficiency can be improved with optimum counterbalancing of the pumping unit, and top achieve an ideal sucker-rod pumping system, a tapered rod string must have a proper mechanical design. The paper discusses rod pumping, downhole energy losses, surface losses, optimum efficiency, mode selection, counterbalancing, minimizing the cyclic load factor, and rod string design.
The cost of electricity used by walking beam pumping units is a major expense in producing crude oil. However, only very limited information is available on the efficiency of beam pumping systems and less is known about the efficiency of the various components of the pumping unit.
This paper presents and discusses measurements that have been made on wells at several Shell locations and on a specially designed walking beam pump test stand at Lufkin Industries. These measurements were made in order to determine the overall system efficiency and efficiency of individual components.
The results of this work show that the overall beam pumping system efficiency is normally between 48 and 58 percent. This is primarily dependent on the motor size, motor type, gearbox size, system’s age, production, pump size, tubing size, and rod sizes. Typically the surface unit efficiency (including the motor) is between 60 and 75 percent and the subsurface equipment efficiency is between 70 and 85 percent for well designed systems.
A hydraulically driven walking beam pumping jack* is introduced which differs from the conventional pumping jack in that the walking beam is activated by two telescopic joints. To analyze the performance of sucker rod pumping systems (both standard and hydraulic), a mathematical model and a numerical simulation were developed. Seven performance criteria were used to characterize the pumping systems. Full scale laboratory type experiments were performed to verity the mathematical model. Both computer generated and experimental results indicate that the hydraulic pumping jack consumes less energy at the polished rod than does the conventional pumping jack.
This paper presents an improve optimization criterion that permit to select the optimum pumping mode from a large number of combinations of pumping rod parameters. The function that modeling the optimization criterion represent the sum of non-dimensional pumping rod parameters. The optimization criterion developed, includes eight operational parameters that characterizes the sucker-rod pumping system: (1) the maximum polished-rod load, (2) the maximum polished-rod stress, (3) the safety coefficient at variable loads, (4) the asymmetry coefficient, (5) the stroke efficiency, (6) the volumetric efficiency, (7) the buckling length of the sucker-rod string and (8) the performance index. Each of these parameters can influence the efficiency of the pumping system.
In order to select the optimum pumping mode, calculations must be made covering a wide range of variables. If four rod sizes are selecting with the available polished rod stroke lengths, pumping speeds (from 3 to maximum SPM of the pumping unit) and six plunger diameters, there are approximate 2200 possible pumping modes that may be considered. The optimization criterion proposed permit to select (using the computer program) only one pumping mode considered the best that correspond with maximum efficiency. The design technique used, allows prediction of surface dynamometer card using the exact kinematics parameters of pumping units, static loads, fluid friction along the string and dynamic rod loads, and the downhole cards based on solutions of the wave equation. Also, the main pumping rod parameters and the length of rods in compression are calculated. The result of this work is a complex computer program based on improve optimization criterion and pumping system design calculations. The application of this criterion for many suckers pumping wells, increases the efficiency of pumping system.
The cost of electricity is one of the single largest items associated with oil and gas production. This cost however tends to be overlooked relative to other production costs, due to the regulated nature of the utilities combined with its specialized and non-core technical requirements. In spite of this, several studies and strategies over the years have looked at ways of reducing this cost component with meaningful results. Many of these strategies consist of structuring loads and designing equipment to take advantage of the utilities regulated rate structure. As the electricity industry in the US moves towards deregulation, these rate structures will no longer exist and in their place will be contracts negotiated on a free market basis between the user and supplier(s) of electricity.
In the upcoming deregulated electricity market, three key strategies are available to effectively manage oilfield power costs;real time monitoring and control of the electrical loadin-field generation of electricity andnegotiation of an integrated power supply agreement.
Because electricity is the ultimate just-in-time product, prices vary greatly depending upon when the power is consumed. The strategies listed above allow for the user to proactively structure their power supply systems to address the fundamental volatility of the real price of electricity. The effect is to strip out the historic premium that is paid to the utility to handle the natural volatility of electricity prices by blending load shifting, internal generation and market purchases.
This paper examines different scenarios where the above strategies are proposed and makes estimates for potential cost savings. These solutions utilize existing technology applied to the changing market environment and therefore focus on economic justification as opposed to technology verification. In one such case the pumping intervals for a collection of wells is adjusted using real time power prices combined with remote operations. This has the effect of reducing the total cost of the electricity consumed per barrel of production while only marginally reducing the actual number of barrels produced.
Introduction
The cost of electricity has historically been one of the largest operating costs in the production of oil and gas. Additionally this cost tends to increase over time as the typical oil field ages. Artificial lift, gas compression, water treating, water injection and so forth are installed as the fields' age and all of these functions consume an ever-increasing amount of electricity. This increasing electric load trends in the opposite direction from the net oil recovered.1 The result is that electricity costs tend to make up a larger and larger percentage of the field's lifting costs. It is not uncommon to see power costs representing up to 40–50% of total production costs.
Although power costs are a major cost component of field profitability, they tend to be overlooked relative to other production costs. The reasons are twofold:1)The technical skills needed are specialized and non-core to the production company and2)Unlike other suppliers, the utility that provides the electricity is a regulated monopoly.
The skills necessary to optimize power costs in this kind of environment are not the same as optimizing the other more conventional costs such as well servicing, treating chemicals, artificial lift... As a direct consequence of this, most oil operators do not manage their power costs. Most operating companies endure their power costs without taking proactive measures to change undesirable situations.1
A novel gas separator design has been developed and successfully tested in several beam pumped wells which were subject to severe gas interference. This paper presents a detailed description of various designs to cover various ranges of fluid production for the most common sizes of completions(4-1/2 to 7 inch casing) and rates from 120 to 825 barrels of liquid per day.
The new design is based on two innovations:
Decentralization of the gas separator in the casing, insures that a minimum amount of gas enters the separator. The presence of two ports located on the narrow side of the annulus and placed a significant distance apart allow continuous flow of fluids into and out of the separator during both the upstroke and downstroke of the pump.
These innovations have resulted in a gas separator efficiency much greater than that of conventional designs.
Electricity is one of the single largest costs associated with oil and gas production. This cost, however, tends to be overlooked relative to other production costs because of utilities regulation combined with its specialized and noncore technical requirements. In spite of this, several studies and strategies over the years have looked at ways of reducing this cost component with meaningful results. Many of these strategies consist of structuring loads and designing equipment to take advantage of the utilities' regulated rate structure. As the electricity industry in the United States moves toward deregulation, these rate structures will no longer exist; in their place, contracts will be negotiated on a free-market basis between the user and supplier(s) of electricity.
In the upcoming deregulated electricity market, three key strategies are available to effectively manage oilfield power costs.Real-time monitoring and control of the electrical load.In-field electricity generation.Negotiation of an integrated power-supply agreement. Because electricity is the ultimate just-in-time product, prices vary greatly depending upon when the power is consumed. The strategies listed previously allow users to proactively structure power supply systems to address the fundamental volatility of the real price of electricity. The effect is to strip out the historic premium paid to the utility to handle the natural volatility of electricity prices by blending load shifting, internal generation, and market purchases.
This paper examines different scenarios in which the previous strategies are proposed and makes estimates for potential savings. These solutions use existing technology applied to the changing market environment and, therefore, focus on economic justification as opposed to technology verification. In one such case, the pumping intervals for a collection of wells is adjusted with real time power prices combined with remote operations. This reduces the total cost of electricity consumed per barrel of production while only marginally reducing the actual number of barrels produced.
Introduction
The cost of electricity has historically been one of the largest operating costs in the production of oil and gas. Additionally, this cost tends to increase over time as the typical oil field ages. Artificial lift, gas compression, water treating, water injection, etc. are installed as the fields age, and all these functions consume an ever-increasing amount of electricity. This increasing electric load trends in the opposite direction from the net oil recovered.1 The result is that electricity costs tend to make up a larger and larger percentage of the field's lifting costs. It is not uncommon to see power costs representing 40 to 50% of total production costs.
Although power costs are a major cost component of field profitability, they tend to be overlooked relative to other production costs for the following reasons.The technical skills needed are specialized and not core to the production company.Unlike other suppliers, the utility that provides electricity is a regulated monopoly.
The skills necessary to optimize power costs in this kind of environment are not the same as optimizing other, more conventional costs, such as well servicing, treating chemicals, and artificial lift. As a direct consequence of this, most oil operators do not manage their power costs but endure them without taking proactive measures to change undesirable situations.1
In spite of this, several studies have looked at ways of reducing the cost of power with meaningful results. The recommendations from these studies can be divided into three groups.Optimizing mechanical systems.2,3Optimizing electrical systems.3–5Working with the utility to optimize usage against a regulated rate structure.3–6
Examples of Item 1 include balancing pump units, installing pump-off controllers, and modifying the pumping unit's stroke length and speed. Examples of Item 2 include correctly sizing electric motors, correcting power-factor penalties and resultant line losses with capacitor banks, meter consolidation, distribution system optimization and retrofit, and using high-voltage substations. Examples of Item 3 include moving to interruptible or curtailable rate structures, bill verification, demand management, and regulatory intervention. All the approaches mentioned in Items 1 and 2 should be thoroughly researched and implemented to begin any electricity cost-reduction initiative.
The approaches examined in Item 3, however, work within a defined and rigid rate and business structure. Operators were encouraged to examine how they were being charged for electricity and to change their behavior to optimize their positions within these relatively rigid price and rate structures. With the advent of deregulation, this area will change radically. Operators must understand how deregulation works in their area and how to best position their company to take advantage of these changes.
Deregulation
Electric power generation in the United States is changing from a regulated industry to a competitive one.7 Where power generation was once dominated by vertically integrated, investor-owned utilities (IOUs) that held most of the generation capacity, transmission, and distribution facilities, the electric power industry now has many new companies that produce and market wholesale and retail electric power. These new companies are in direct competition with traditional electric utilities. Today, vertically integrated IOUs still produce most of the country's electrical power, but that is changing.
The long-standing traditional structure of the industry was based, in part, on the economic theory that electric power production and delivery were natural monopolies and that large, centralized power plants were the most efficient and inexpensive means for producing electric power and delivering it to customers. Large power-generating plants, integrated with transmission and distribution systems, achieved economies of scale and, consequently, lower operating costs than relatively smaller plants could realize. Because of the monopoly structure, federal and state government regulations were developed to control operating procedures, prices, and entry to the industry to protect consumers from potential monopolistic abuses.
Mainly due to its long history, sucker-rod pumping is a very popular means of arti- ficial lift all over the world, roughly two-thirds of the producing oil wells are on this type of lift. To maximize profits from these wells in the ever-changing economic situa- tion with rising costs of electric power, installation designs must ensure optimum con- ditions. In the paper, basic considerations on ensuring profitable rod pumping opera- tions are given. The key topics of installation design (pumping mode selection, optimum counterbalance, rod string design) are addressed and their role in the improvement of sucker-rod pumping operations and the reduction of lifting costs is discussed. After a review of the surface and downhole energy losses in sucker-rod pumped wells, some key considerations on the ways to improve system efficiency are given. The most important task is the proper selection of the pumping mode, i.e. the combination of plunger size, pumping speed, stroke length, and rod taper design for lifting the pre- scribed amount of liquid to the surface. The best pumping mode maximizes the lifting efficiency and, at the same time, reduces prime mover power requirements and electri- cal costs. The operational efficiency of the surface equipment is improved by using an optimum counterbalancing of the pumping unit. To achieve an ideal sucker-rod pump- ing system the mechanical design of the tapered rod string must be properly made. The paper gives aspects and details of installation design improvements along with practical examples. IMPROVING ENERGY EFFICIENCY In order to increase the profitability of sucker-rod pumping installations, the reduc- tion of operating costs is of prime importance. Since the majority of installations is driven by an electric motor and the cost of electric energy has steadily increased in re- cent years, energy losses both downhole and on the surface must be minimized. After a discussion of the possible sources of energy losses in the rod pumping system, an over- all efficiency formula is derived. An evaluation of this formula allows important con- clusions to be drawn on the most efficient pumping system. Downhole Energy Losses The rod pumping system does its useful work by lifting the given amount of liquid from the well bottom to the surface. The hydraulic power is easily calculated based on the depth of effective lift and the volume of the liquid produced:
An improved method is presented for the evaluation of performance characteristics and optimum selection of sucker-rod pumping well systems. The procedure is conceptually general for all class I lever (conventional) systems and for the Mark II type of the class III lever systems. The procedure can easily be modified for any kind of special surface pumping unit.
This study uses basic sucker-rod theory already presented in the literature. The new approach, however, groups the most important variables affecting the operation of a total sucker rod pumping well system (from the prime mover to the downhole pump) into eleven dimensionless numbers which are used to aid the simulation of performance characteristics and design parameters. The final results consist of design parameters for various rod size-pump depth-production rate combinations from which an optimum pumping mode is selected. The selection of the optimum pumping mode is based on an optimization criterion proposed in this paper.
Based on limited specified information on a well being considered for the installation of a rod pumping system, the method presented can be used to select a total sucker rod pumping system that will optimize both production and longevity of all parts of the system. The procedure minimizes the design of incompatible parts that very frequently leads to system failures. For already existing installations, the method furnishes information on pumping speed, counter-balance weight, polished rod stroke, etc., for setting a new optimum operation.
The occurrence of streaming potentials is directly related to movement of fluids in the subsurface. To investigate whether streaming potential measurements in boreholes and at the surface can be used to monitor subsurface flow and detect subsurface slow patterns in oil reservoirs, the authors model streaming potential responses caused by oil well pumping in monitoring wells and at the earth`s surface. Since the model parameters: permeabilities, cross-coupling properties, and electric conductivities depend on a few basic rock-physics parameters such as brine conductivity, amount of water saturation, and porosity, the model parameters are evaluated self-consistently using rock-physics models. Using a three-dimensional, (3-D) finite-difference algorithm, the governing differential equations that are drawn from nonequilibrium thermodynamics are solved numerically in three self-consistent steps: solution of the hydraulic problem, computation of the streaming current sources based on the principle of conservation of charge, and solution of the resistivity problem.
A method that considers inertia effects is presented for computing gearbox and motor loading on beam units. Previous methods neglected the inertia torques, which can be important when ultrahigh-slip prime movers are used. The method has practical application in determining the type of prime mover/beam unit combination to be used.
Introduction
During the past few years, ultrahigh-slip electric motors have been introduced for powering beam pumping units. These prime movers employ inertia effects to diminish equipment loading, particularly on the gearbox and the motor itself.
The torque factor method accepted in the API standards does not consider inertia effects and so should not be expected to give correct answers when ultrahigh-slip prime movers are used. To provide a suitable computation prime movers are used. To provide a suitable computation method, two additional terms have been added to the API technique - rotary and articulating inertia torques. To account for inertias, it is necessary to measure instantaneous motor speed, an item previously not required in conventional dynamometer analysis. Once motor speed variations are known, it is possible to account for torsional work and kinetic energy interchanges as the rotary components accelerate and decelerate. Also, the torsional effects related to accelerations of the articulating components, primarily the beam assembly, can be computed.
Two methods have been used to evaluate the various moments of inertia required in the analysis. The method most frequently used has been the direct calculation method, based on the engineering drawings of the unit components. The other method infers the moments of inertia by the manner in which the unit coasts to a stop after the motor switch is turned off.
Review of Torque Computation Methods
Two frequently used methods for inferring gearbox torque from a surface dynamometer card are the API torque factor method and an unnamed technique that is based on surface load range and unit stroke.
The API torque factor method is based on the following equation.
T = F (Q - Q ) - M sin(0j + ).........(1)
The net torque is the difference between the rod load torque and the counterbalance torque. Rod load torque, Fj(Q RL -Q SU), is the product of the torque factor and the polished rod load corrected for structural unbalance of the polished rod load corrected for structural unbalance of the unit. The counterbalance torque, M sin (0 j + beta), opposes the rod load torque with a sinusoidally varying effect with amplitude M.
Pumping-unit manufacturers usually publish a set of torque factors vs crank angle. To assist in relating crank angle to stroke position on the measured dynamometer card, corresponding stroke positions in nondimensional form are also published. Position zero refers to the bottom of the unit's stroke and position unity (1.0) denotes the top of the stroke. A sample set of torque factors and positions for a 120-in. unit equipped with a 456,000-in.-lb gearbox is shown in Table 1.
A dynamometer card for an example well is shown in Fig. 1. To illustrate the torque factor method, the net torque at a crank angle of 60 degrees is determined as follows. According to Table 1, the crank angle of 60 degrees produces a nondimensional, polished rod position of 0.304 on the upstroke and a torque factor of 61.08 in. The polished rod load at this position is 15,036 lb.
JPT
P. 1153