Technical and economical optimization of the performance of sucker rod pumping system.
The energy crisis confronting the world makes the optimum selection and operating of the oil field production equipment to be a must. This is certainly very important for oil field pumping units, especially for the developed/depleted wells. It is imperative to optimize the pumping unit performance according to the well conditions as accurate as possible. In the mean time, it is equally important to operate the pumping unit within its optimum rate and speed to avoid the costly downtime due to breakdown. This means obtaining a better understanding of the important factors affecting the pump performance such as the influence of the stroke length and suitable speed, on both the pump flow rate and expenses.
The purpose of the artificial lift methods is to maintain a reduced bottom-hole pressure so that the producing formation can provide the desired flow rate of reservoir fluids. There are many artificial lift systems (Gibbs, 1975; Brown, 1980; Nind, 1981) currently applicable in the petroleum industry. These systems include: (1) Sucker rod pumping (Beam pumping), (2) Gas lift, (3) Electrical submersible pumping, (4) Hydraulic (Piston and Jet) pumping, (5) progressive cavity pumping, (6) Plunger (Free-piston) lift, and (7) Other methods such as: Ball-pump and Gas-actuated pump. The beam pumping system is the most popular artificial lift system all over the world since it represents more than 80 % of all artificially lifted wells.
The Beam pumping systems are recognized as the most widely applied mean of artificial lift worldwide. It is almost 75 % of the one million wells utilizing artificial lift are run with a sucker-rod pump. This popularity of this system is attributed to its durability, simplicity, and flexibility.
Considering beam pumping has maintained and is expected to continue its dominance as the premier form of artificial lift, continuous optimization of the system plays an integral and important role in maximizing production. The unit geometry and mechanics, downhole assembly, and pump mechanism are critical components that must be functioning at optimal levels for effective operations.
Beam Pumping System
A beam pumping system, Fig. 1, has various main components (Rowlan et al, 2007) as follows
It is a gas or electric motor, carrying no more than half of the fluid load provided by the pump on the upstroke;
It manages the loading of the system on up and downstroke transferred to prime mover as the source of power for rotational motion of system;
Connected to the gearbox transferring rotational motion to the vertical motion of the of the sucker-rod downhole via the walking beam;
Positioned on the crank arms ensuring a balanced unit to apply only half of the fluid load to the prime mover;
Carrying the entire fluid load and weight of rods while clamped to polished rod, which holds sucker-rods;
Link between the carrier bar and the pump downhole at typically 30ft/joint; Stuffing Box
Rubber packing on surface to prevent fluid leak and maintain lubricated polished rod for smooth translational movement;
Belts and Sheaves
Provide rotational motion from flywheel to gearbox and should be properly tightened to prevent wear as well as protected with a belt guard.
[FIGURE 1 OMITTED]
Types of Beam Pumping System
Ghareeb and Shedid (2007) indicated that there are three main beam pumping types/structures, each one holding its own advantages and disadvantages, Fig. 2. The first type is the conventional pumping unit is the most widely used surface structure, acting as the modern version of the crank counter-balanced unit of 1926. Such a unit can be rotated clockwise as well as counterclockwise with roughly similar efficiencies in both directions operating efficiently between 0-3000 ft of depth. The second type is the Mark II pumping unit, which is known for creating more uniform torque and less peak torque, limiting strain on the mechanical system. The third type is the Reverse Mark pumping unit, which contains a phased counterbalance with 190 degrees of crank rotation on the upstroke and a 170 degree rotation to complete the downstroke allowing for lower peak torque and less energy consumption.
[FIGURE 2 OMITTED]
[FIGURE 3 OMITTED]
Sucker Rod Pump
Brown (1982 and Rowlan et al, (2007) indicated that the sucker-rod pump, shown in Fig. 3 consists of several components including:
Attached to the internal production tubing of the well housing the remaining pumping unit;
Travels vertically utilizing pressure differences to transfer fluid from below the standing valve into the pump chamber and to tubing for surface production via traveling valve;
A static valve positioned at the bottom section of the pump transferring fluid from well into pump chamber;
Located above the standing valve and pump chamber moving vertically with the sucker-rods acting to hold fluid in chamber and also bring fluid to surface on the upstroke.
Action of Sucker Rod Pump
The action of the sucker-rod pump is presented in Figure 4 through a dynamometer card, assisting the following detailed explanation as shown by Rowlan et al (2007). It is important to note that a beam pumping system converts the rotational motion on the surface to a vertical lifting mechanism of the rod string and downhole plunger unit. This motion has an identifiable upstroke and downstroke. The dynamometer conveys the plunger as its lowest position as point A. The explanation begins at this point and transitioning through one complete cycle as follows
* At point A, the standing and traveling valves are both closed;
* The path from point A to point B transition consists of the rods fully extended (stretch out) to transfer the fluid load from the tubing to the rod string. As this occurs, the pressure inside the pump starts to decrease; gas will expand from the tubing discharge pressure to below the pump intake pressure.
* At point B, the standing valve with open allowing fluid to enter from the tubing into the chamber as a result of pressure differential from higher tubing pressure to below the pump intake pressure.
* The path from point B to point C transition consists of rods carrying fluid to surface line in addition to reservoir fluid flowing into the pump donwhole.
* At point C, the downstroke begins and the standing valve will close halting fluid intake. The traveling valve will remain closed at the start of the downstroke until pump pressure rises above tubing discharge pressure.
* The path from point C to point D transition consists of the plunger moving downward with gas compressed as pressure within the pump increases on the fluid until is rises above tubing discharge pressure, at which point the traveling valve will open.
* At point D, the traveling valve opens allowing fluid to flow upward
* The path from point D to point A transition consists of fluid moving from the pump and into the tubing as the standing valve remains closed ensuring the fluid remains in the tubing during this upward pressure differential induced upward movement.
[FIGURE 4 OMITTED]
Design of Beam Pumping System
Several considerations should be made when designing the sucker-rod artificial lift system for a specific well. Stroke length, strokes per minute (spm), rod string design, pump setting depth, and plunger diameter are the main parameters for the pump design. Depending on the well, several combinations are capable of producing identical pump displacement without overloading the pumping system (Rowlan et al, 2007; Brown, 1984). In addition, to maintain efficient production rates and energy consumption the unit should be properly balanced, the pump should appropriately match fluid loads, no gas interference should be present, and motor size is expected to suit the well load with an efficiency of >50%.
Best Practices of Beam Pump Design
Along with design specifications, the following best practices should be noted to maximize production and increase lifecycle of unit (Byrd, 1977; Rowlan et al 2007; Hirschfeldt, 2007). Typically, beam pumping units are appropriate for lower to moderate volume (< 1000 BPD) wells at moderate depths (<10000ft). Rods must be properly protected from corrosion and erosion threats in such adverse environments (ie.H2S presence). Scale and Paraffin present can severely harm the operations of a sucker-rod system leading to clogging and mechanical failures within the pump itself, if a problem persists. Furthermore, free gas escaping solution if intake pressure is low enough causes a drop in volumetric efficiency figures. Fluid levels should remain high within the well to ensure protection from 'fluid pound', mechanical damages, and possible energy inefficiencies. Deviated and horizontal wells are not compatible with sucker-rod systems, as problems arise with rod-protectors in addition to rotating rod tools. Sand production can create clogging and erosion difficulties with the downhole pump unless specific sand-proof pumps are utilized; noting that such technology has come about only very recently as with be elaborated on further in this review.
Advantages of Beam Pumping System
With a detailed look at beam units above, numerous professionals have concretely established several advantages of the sucker-rod beam pumping system (Byrd, 1977; Brown, 1982; Guirados et al, 1995; Rowlan, 2007) as follows
* Simple design and easily operated by field specialists without extensive training
* Easily interchangeable between wells with changing conditions at minimum cost
* Can be applied to small-diameter wells with multiple completions
* Capable of lifting viscous fluids at high temperatures
* Has flexibility with prime mover selection- gas or electric motor
* Unique in ability to produce well down to very low pressures while maintaining economical production rates
* Maintenance work easily performed (ie. Scale, corrosion treatment)
* Production automatable and analyzable real-time without frequent on-site personnel
* Flexibility with downhole pump sizing to adapt with changing economical production rates
Disadvantages of Beam Pumping System
Despite the extensive advantages backing the utilization of beam units, disadvantages have been experienced over the past few decades as well (Brown, 1982; Ghareeb and Shedid, 2007; Guirados, 1995):
* Depth has historically been an issue > 12000ft, mainly due to rod capabilities
* Deviated and horizontal wells create inherent difficulties from the rod string, even with rod rotators and roller-rod protectors
* Gas production severely limits volumetric efficiency, due to dependence on pump pressure mechanics to lift fluids to surface
* Susceptible to paraffin and asphaltene presence (ie. mechanical failures)
* Limitations of downhole pump design with small-diameter wells
Efficiency and Power Loss of the Beam Pumping System
Typical inefficiencies of the system are summarized by Antoniolli and Stocco (2007) to be
1. Downhole Losses
* Pump losses: (i) mechanical friction- Sucker-rod barrel and plunger, and (ii) hydraulic losses- improperly sized valves
* Losses in Rod String: mechanical Friction- rod string rubbing on inside tubing wall and from within the stuffing box (typically on a very small scale)
* Losses in Liquid Column: (i) Liquid Friction-within the tubing-rod annulus, (ii) Wellhead Pressure-creates more power loss on downhole dynamics, and (iii) Damping-forces opposing motion of rod string, mainly from viscous forces of well fluids
2. Surface Losses
* Losses in drive train: mechanical Friction-sourced from structural bearings, gearbox, and V-belts and sheaves
* Prime Mover losses: mechanical losses-friction within structural bearings of motor
The McElroy field was discovered is 1926 along the southeastern border of the central Permian basin platform, roughly 30 miles south of Midland, Texas, USA. The reservoir structure is an asymmetrical anticline with the eastern portion falling off as a dip that leads into the Midland basin. Moreover, the field covers over 17,000 acres of land. The McElroy field has a 160-ft thick pay zone of the Permian-aged, dolomite composed Grayburg formation. Average drilling depth is roughly 2900 ft.
Production levels peaked at 22 MBOPD early in 1974 with an additional peak in the early 1990's due to a 10-acre spacing infill program. Waterflood has stimulated the vast majority of production, having begun in 1948 and becoming an expanded full-field operation by 1966. Currently, the McElroy field is producing 10 MBOPD and over 300 MBWPD with such a large waterflood operation. Artificial lift dominates the production mechanism of the field with over 632 producing wells as of August 2008. Beam pumping covers over 90% of the field's artificial lift followed by ESP's and a few Rotaflex units.
The flexibility and reliability of the beam pumping system has enabled to maintain its dominance throughout the McElroy field and as production rates are relatively low per well, such a system produces high quality results while minimizing costs. Moreover, several wells have been producing for over 30 to 40 years with consistency, without TA or SI time, providing reliable and highly comparable wells for this study of optimizing production through the variables of stroke length and pumping speed (McElroy, 2008).
System Design Considerations
Two wells are analyzed and optimal performance is determined with respect to maintaining production levels and minimizing operating costs. This study is completed with the use of Petroleum Production System, PPS, (Economides et al., 1993), predictive artificial lift software to analyze the effects on power and operating cost as well as with a derived equation set, detailed in appendix A, to determine effects of PPRL.
Applied well conditions are listed in Table 1, outlining the range of working conditions for this study. Moreover, several consistent factors were established between all tested wells:
* In all cases, tubing was anchored, therefore no tubing stretch was observed.
* GOR was negligible, therefore 100% fluid production was considered.
* All wells are operating from a conventional beam pumping unit.
* Depth is in the range of 2500-2800ft for real field data wells
* API gravity is in the range of 32-35.
To achieve the optimal performance, tests were completed to determine power, Peak polished Rod load (PPRL), and electricity costs with respect to stroke length (S) and pumping speed (N). All other design criteria remained constant in both the derived equation set and PPS analysis.
This study was achieved to answer the question of is it better to apply high speed with long stroke length or low speed with high stroke length?. The goal of this study is to optimize the mechanics of the unit for maximum fluid production. Currently, these two variables are at center stage of industry research, while experts search for an answer which will show the optimal relationship with respect to optimal performance. For the purpose of this investigation, optimal performance is measured on two levels: 1) Maintaining an optimal level of production- defined by the capability of each well involved in the case study, and 2) Minimizing operating costs from a short and long term perspective.
Results and Discussion
Effects of Stroke length on Power and PPRL
Through the petroleum production system (PPS) analysis, pumping speed of the well was kept at a constant rate while stroke length was varied to achieve optimal pumping rates from 100 stb/day to 1000stb/day. A linear relationship is depicted in Fig. 5 with respect to stroke length and prime mover power. Data in Tables 1 to 4 are used to develop Figures 5, 6 and 7 using the PPS program.
[FIGURE 5 OMITTED]
It is clear from resulting graphical relationships in Fig.6 that stroke length has a direct linear relationship with the peak polished rod load. In sharp contrast to the effects of pumping speed, stroke length can be increased with minimal increases in the PPRL on the beam pumping system.
[FIGURE 6 OMITTED]
Effects of pumping speed on Power
From Fig. 5 analysis, an almost identical power relationship exists between pumping speed and the prime mover power as that of stroke length. Again, the same method was used to optimize production rates keeping stroke length constant and varying pumping speed to achieve the result, which yielded a specific required hp by the system's power unit.
Effects of Pumping speed on PPRL
Pumping speed carries a quadratic relationship with PPRL as also viewed from Fig. 6. In terms of loading and wear and tear on the system, increasing pumping speed has drastic consequences as it very sensitively affects the load on the polished rod.
Effect of Pumping Speed and Stroke length on Electricity Costs
As observed in Fig. 7, Pumping speed carries a direct relationship with respect to electricity costs. This is expected considering the linear relationship between horsepower requirements and following power supply brought to the system.
Fig. 7 also shows a direct relationship between electricity costs and stroke length. Such a relationship allows the development of a thought that operating costs from an electricity standpoint will be identical whether using pumping speed or stroke length to alter production rates.
[FIGURE 7 OMITTED]
Considerations of Two General Cases
From the previous equation set and Petroleum Production System (PPS) analysis of PPRL, horsepower requirements, and electricity costs, it is clear that pumping speed and stroke length play a very important role in optimizing the efficiency and production associated with a beam pumping system. The graphical analysis shows that pumping speed only carries a non-linear relationship will respect to PPRL. Therefore, it is necessary to consider the implications of two general cases with respect to the efficiency and expected power losses of the system and whether they are reduced or increased based on pumping speed and stroke length.
Considering the two General Cases
Long Stroke length, Low Pumping Speed
With respect to the inefficiencies mentioned above, a long stroke length with a low pumping speed carries several advantages. Firstly, production optimization is maintained as the longer stroke length enables more fluid to be brought to surface on each cycle.
Moreover, along with maintaining production levels low pumping speed is said to increase the life span of the unit, decrease wear and tear of the units parts, and decrease the frequency of maintenance of a beam pump. In addition to these benefits, a longer stroke length is known to actually increase production as a result of providing for uniform polished rod movement.
This uniform polished rod movement and slower motion of the unit will decrease turbulent flow of fluids into the pump barrel, maintain steady flow of hydrocarbons, and decrease the frictional losses in power on all mechanical motion of the beam pumping downhole and surface equipment (Ewing, 1970).
Short stroke length, High pumping speed
Three of the main disadvantages associated with a high pumping speed are fluid pound, gas lock, and cavitations within the pump. Such occurrences are detrimental to maintaining steady production, usually harm downhole mechanisms, and severely decrease the efficiency with which a sucker-rod pump can bring fluids to surface.
In addition, a high pumping speed leads to faster rod contraction reduces its life span, and also increases torque on the gear reducer due to faster accelerations to complete more strokes per minute. In theory, these disadvantages are well-founded and established in industry (von Hollen and Newton, 1996).
However, in most situations as also seen in this case study of two beam pumping wells on the McElroy field the marginal benefits of maintaining a high stroke length and lower pumping speed are not capitalized on due to belief in the fact that higher pumping speed will produce more fluid. As seen from graph's two and three, this is clearly not the situation as pumping speed increases production rates at a proportional rate with reference to stroke length while prime mover power must also be increased to maintain increasing production levels.
Based up the conducted analysis, evaluation, and achieved simulation research using actual data of the McElroy field, the following conclusions can be drawn:
* The application of long-stroke length with lower pumping speeds for sucker rod pumping units has resulted in similar operating costs to the same unit operated at shorter stroke length with high pumping speed for a short tem application. However, over the long-term application, the long-stroke with low-speed produces the best financial and mechanical advantages for the beam pumping unit.
* The use of higher pumping speeds exerts long-term stress and frictional efficiency losses on the beam pumping system, which increases capital depreciation. Consequently, this results in long-term financial losses on the operating system.
* The change of pumping speed has shown an important and strong effect on loading and stress of the beam pumping unit. This leads to various inefficiencies and creates a financial loss in the long run.
* The pumping speed and stroke length have shown very similar linear relationships with the consumed electricity cost. Furthermore, the cost of running a beam unit using electricity represents almost over 40% of field operating costs these days.
Nomenclature Ap Area of pump plunger, square inch Atr Cross-sectional area of top section of rod, square inch K Pump constant Wr Weight of the rod string, lb Wf Weight of the fluid, lb Ea Maximum stress on rods at top of string SF Service Factor T Minimum tensile strength for the rods S Stroke length, inch N Pumping speed, stroke/min (spm) PPRL Peak Polished Rod Load, lb TA Temporarily Abandoned SI Shut In
Table 1: Well Data for Field wells Well CM470P Well CM67 Unit Type Conventional Conventional Pump Type Insert Insert Rod String Norris 90, tapered Norris 90, tapered Surface Rod Diameter [in] 1 1 Plunger size [in] 2.25 2.25 Oil Service Factor 0.9 0.9 Stroke length/S [in] 123 168 Pumping speed/N [spm] 6.91 5.54 Crank-to-pitman ratio 0.33 0.33 API oil gravity 32 32 Pump Depth 2651 2777 Tensile Strength (min) [psi] 9.00E+04 1.15E+05 PPRL [lbs] 1.13E+04 1.65E+04 Production [bfpd] 176 398 Table 2: Sample Data Set for PPS Analysis Well: CM470P Length of Rod String/ L [ft] 2600 Rod Diameter/ D r [in] 1 Rod Weight/ D_r [lb/ft] 2.5 Plunger diameter/ D_p [in] 2.25 Tubing I.D. [in] 2.441 Tubing O.D. [in] 2.875 Effeciency of pump/ E_v 75% Young's Modulus/ E 3.E+07 Liquid specific gravity/ [gamma] 0.85 Depth of liquid level H [ft] 2550 Surface tubing pressure [psi] 50 Safety factor 0.9 Formation factor 1.1 Table 3: Sample Data Set for Derived Equation Well: CM470P Unit Type Conventional Pump Type Insert Rod String Grade K, tapered Surface Rod Diameter [in] 1 Plunger size [in] 2.25 Oil Service Factor 0.9 Stroke length/S [in] 123 Pumping speed/N [spm] 6.91 Crank-to-pitman ratio 0.33 API oil gravity 32 Pump Depth 2651 Tensile Strength (min) [psi] 9.00E+04 PPRL [lbs] 1.13E+04 Production [bfpd] 1.76E+02 Table 4: Power and Electricity Requirements Vs S & N Resulting Calculated Data: 1 A_p [in[conjunction]2] 3.976 A_tr [in[conjunction]2] 0.785 K [in[conjunction]2] 0.590 W_r [lbs] 5807 W_f 4426 2 Q vs N 3 Q vs S 4 PPRL vs N 5 PPRL vs S Well: CM470P @ 6.91spm Production Prime Mover Electricity Rate Stroke Power (hp) Costs ($/ month) (bfpd) Length 2.5 94 100 43 5 188 200 79 7.4 278 300 114 9.8 368 400 150 12 451 500 186 14.7 553 600 222 17.1 643 700 257 18.7 703 800 293 21.8 820 900 329 24.2 910 1000 365 Well: CM470P @123in Prime Mover Electricity Costs Production Pumping Power (hp) ($/ month) Rate Speed 2.5 94 100 2 4.9 184 200 4 7.4 278 300 6 9.8 368 400 8 12.3 462 500 11 14.7 553 600 13 17.1 643 700 15 19.5 733 800 17 21.8 820 900 18 24.2 910 1000 20
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Shedid A. Shedid
British University in Egypt (BUE), Cairo, Egypt
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|Author:||Shedid, Shedid A.|
|Publication:||International Journal of Petroleum Science and Technology|
|Date:||May 1, 2012|
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