Copyright 2005, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the 2005 Asia Pacific Oil & Gas Conference and Exhibition held in Jakarta, Indonesia, 5 – 7 April 2005. This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal 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 a proposal of not more than 300 words; illustrations may not be copied. The proposal 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

The original Kulin Horizontal well project scope was to drill two horizontal wells and run Electric Submersible Progressive Cavity Pumps (ESPCP’s). ESPCP is a combination of Progressive Cavity Pump (PCP) and Electric Submersible Pump (ESP) motor as a down hole fluid lifting system and is ideal for use in horizontal wells. With rod less system, it will eliminate friction loss at tubing and rod. The PCP has more resistance to sand production and provides high efficiency production of viscous fluid. The Kulin Horizontal Drilling project started in early 2002 and ended in February 2003. The first horizontal well was Kulin 082 (KL082) and the second well was Kulin 083 (KL083). After the wells were completed using ESPCP as artificial lift, the initial production for KL082 was 708 BFPD, 531 BOPD, 25% water cut and KL083 was 518 BFPD, 394 BOPD, 24% water cut. The initial production was above estimated initial production of 300 BOPD/well.

The ESPCP’s in both Kulin horizontal wells are installed in tangent sections with less than 2 o/100 ft build rate inside 9-5/8” production casing. The design threshold for ESPCPs is up to a maximum of 15o/100 ft build rate in the tangent section. The stator elastomer inside the PCP is operated at temperatures between 135oF and 150 oF and this is below the maximum temperature limitation for the elastomer. The flow rates, head and pump efficiency of the ESPCPs are controlled using surface mounted Variable Speed Drive (VSD).

As of June 2004, the ESPCPs that are installed in both Kulin horizontal wells have been operating for over 450 days and 800 days respectively without any mechanical problem from pump or ESP failures. Both ESPCPs was down in period mid of June’04 until early August’04 when the Kulin field was shut down due to facility safety issue.

The production rates from these horizontal wells are about 2.5 – 3.5 times greater than an average vertical producer in the field.

This paper will discuss ESPCP design, installation and performance in the Kulin Horizontal wells. Introduction The horizontal wells were designed with 9-5/8” production casing with a 8.5” open hole lateral section containing a 7” pre-perforated completion liner. The well KL082, is producing from Duri “E” sand with 1,340 ft TVD sand depth and 393 ft lateral length. The well KL083 is producing from Duri “B” sand with 980 ft TVD sand depth and 1,214 ft lateral length. A summary of reservoir properties at initial condition is listed in table 1.

KL082 KL083 Porosity 33% 25% Permeability 5000 md 2131 md Sand Thickness 34 ft 18 ft Reservoir Pressure 220 psi 235 psi Reservoir Temp 150o F 135o F Oil Gravity 20o API 16o API

Table 1. Reservoir properties

During pre execution phase of the project, the Kulin Horizontal Well Execution Team did an assessment to identify appropriate artificial lift methods for the horizontal well project that would optimize pump operability and well production. Horizontal wells located in the adjacent Duri field were used to evaluate tubing pump performance. This analysis was done to understand the critical factors that affected pump performance. The Duri field has unconsolidated sand with high reservoir temperature as result of steam flood process. Statistically, tubing pump performance at 25 horizontal wells in Duri is poor. The average of tubing pump efficiency is less than 30% with 118 days average pump run life. Table 2 provides the tubing pump efficiency of Duri Horizontal wells.

Year # of Pump Installed Avg Pump Efficiency (%) 1999 6 20 2000 15 27 2001 19 43 2002 7 29

Table 2. Tubing pump efficiency in Duri Horizontal

wells (25 wells) Some contributing factors that have caused low tubing pump

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Electrical Submersible Progressive Cavity Pump (ESPCP) Application in Kulin Horizontal Wells M. Taufan, SPE, R. Adriansyah, SPE, and D. Satriana, SPE, P.T. Caltex Pacific Indonesia

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ROTOR

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performance in Duri horizontal wells are: high friction losses that prevent adequate pump travel and excessive sand production that damages the tubing pump plunger. Although some modifications had been made to reduce friction loss by installing roller guides on the rod string, pump failure still occurred frequently. The roller guides were damaged by excessive production of sand due to poor sand control in horizontal wells. Most of Duri Horizontal wells use pre-perforated liner set in open hole as sand control and this has failed to reduce sand production. Realizing that Kulin has unconsolidated sand and the horizontal wells were designed using a similar completion with pre-perforated liner in open hole; the team took the initiative to identify other artificial lift alternatives to tubing pumps. The desired characteristics of the new system were a rodless system with more resistance to sand production. The team has considered both ESP and PCP separately but the ESP is not designed to handle sand production, and the PCP is using a rod system that is prone to failure in horizontal well. The team then decided to utilize ESPCP as solution. ESPCP Design ESPCP is PCP (Progressive Cavity Pump) driving with an ESP (Electric Submersible Pump) motor as a downhole drive system. This configuration is a rodless system which eliminates friction loss at tubing and rod. PCP is a single helical (rotor) which rotates eccentric inside double helical (stator). The PCP is a positive displacement pump. As the rotor rotates inside the stator, fluid moves through the pump from cavity to cavity. As one cavity closes, it’s opposing cavity opens at exactly the same rate. This results in a constant non-pulsating flow. The PCP can handle viscous fluids and solids laden fluid. The standard rotor is made from stainless steel, and hard chrome plated for abrasion protection. The stator elastomer is made from a mixture of compounds designed to handle variety of produced fluids, solids and gases. Figure 1 is Progressive Cavity Pump with 2 main component, rotor and stator.

Fig 1. Progressive Cavity Pump

Various types of stator elastomers are available from vendors. The stator elastomer generally has a heat limitation associated with bottom hole temperature. Some available products have variety of temperature resistance to a maximum of 95o C (203o F), 105o C (221o F), 135o C (275o F) and 150o C (302o F). Because the BHT of the producing sand was about 65.6o C (150o F), we chose an elastomer with a temperature resistance of 95o C (203o F). Another consideration when designing a PCP installation is determining whether the elastomer will be compatible with the aromatics in the produced fluids. The ESPCP system configuration is provided at figure 2.

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Fig 2. Electric Submersible Progressive Cavity Pump (ESPCP)

ESP Motor ESP motor sizing is determined by the power required to start and operate the PCP, the size of the casing and the downhole temperature. Standard for the ESPCP system is two pole motor with a 50Hz speed at 2,917 rpm and a 60Hz speed of 3,500 rpm. Gear Reducer The primary function of the gear reducer is to provide a speed that is acceptable to PCP. The normal range of the PCP is 100 to 500 rpm. The second function of gear reducer is to increase the torque available to the PCP. Gear ratio are varying depend on each product. Example of gear ratio: 9:1 and 11:1 Seal Section The main function is to prevent well fluids entering the gear reducer and motor, isolating the specially formulated motor oil from the well bore fluids. This isolation allows the motor oil to expand or contract as downhole temperatures and pressure vary. Flex Shaft and Intake The flex shaft assembly is designed to convert the concentric rotation of the seal section shaft to the eccentric rotation required by PCP. Design for high torque load. Utilize standard

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ESP intake base. Maximum intake flow is 9,000 bpd (1,430m3/d). To control the flow rates, head and pump efficiency, the ESPCP was run using Variable Speed Drive (VSD), which is operated at the surface. By adjusting the frequency, the VSD system offers potential for controlling production and reduces down time. ESPCP Installation ESPCP installation at horizontal wells KL082 and KL083 has considered the maximum allowable inclination for the pump placement. The ESPCP is capable to be operated in horizontal wells with less than 15o/100 ft tangent section. ESPCP in KL082 was installed at 64o inclination with 1.6o/100 ft build rate inside 9-5/8” casing. Depth installation is 1,440 ft MD or 1,267 ft TVD. ESPCP in KL083 was installed at 58o inclination with 1.5o/100 ft build rate. The pump depth is 1,014 ft MD or 891 ft TVD. The pumps were installed using 3-1/2” tubing and equipped with 3-1/2” check valve and bleeder valve 90 ft above the pump. To prevent motor cable friction with casing, a cable guard was installed along the pump and tubing. The ESP motor that was installed at both wells are two pole motor with 60 Hz speed of 3,500 rpm, 562 series, 38 HP, 453 volts and 53 ampere. Actual setting is 40 Hz speed of 2,333 rpm. Motor Outside Diameter is 5.62” with 6.98 ft length. The 562 motor series is suitable for minimum 7”-32# casing size. Both Kulin Horizontal wells are using 9:1 gear ratio. At 40 Hz speed of 2,333 rpm results in speed at the pump: 2,333/9 = 259 rpm Motor Output torque = Motor HP * 5,252/ Motor Speed = 38 (HP)*5,252/2,333 (rpm) = 86 ft lbs Gear reducer output torque = 86 ft lbs * 9 = 774 ft lbs The PCP model is 054-12-045 with capacity of 340 BFPD/100 rpm. Pump Rate = Pump Speed * Pump Capacity = 259 (rpm) * 340 (BFPD/100 rpm) = 881 BFPD Pump dimension is 4.25” pump OD with 13.3 ft stator length. Table 3 summarizes the ESPCP design which was installed at KL082 and KL083 wells.

Motor Speed (RPM) @ 40 Hz 2,333 Gear Reducer 9:1 Pump Speed (RPM) 259 PCP Capacity (BFPD/100 RPM) 340 Pump Rate (BFPD) 881

Table 3. ESPCP design at KL082 & KL083

Field Result KULIN 082 Well KL082 started production in April 2002. Initial production was 708 BFPD, 531 BOPD and 25% water cut. Average production of the wells is 445 BOPD with 20-30%

water cut range. Fiq 3 showing production performance at KL082

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Since initial production the water cut is stable at level 20-25% and slightly increase to 27% starting March 2004. Fig 4 showing water cut trend at well KL082.

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Fiq 4. Water Cut trend at KL082

The ESPCP has better pump efficiency compared to tubing pump efficiency in Duri horizontal wells. Average pump efficiency at well KL082 since initial production is 66%. After more than 800 days (2.2 years) producing time, there have been no indications of pump failures. Fig 5 shows Pump Efficiency at well KL082.

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Fig 5. Pump Efficiency at KL082

Some operational problems were encountered early in the life of the wells, when no fluids were produced while the pump was running. A fluid level survey also indicated a high fluid level above the pump. The team suspected that something was plugging the pump intake. The team successfully used the

4 SPE 93594

technique of backflushing the pump by reversing the motor to return the well to production without pulling the pump. By reversed the motor rotation in couple minutes and then turn back to normal motor rotation, the well was successfully returned to production. KULIN 083 Well KL083 starting producing in March 2003. Initial production of the well was 518 BFPD, 394 BOPD and 24% water cut. There were some problems early in the life of this well. High oil viscosity with 16o API gravity and about 2 kilometers of 4” production line generated pressure build up in production line. When starting the pump during the first 24 hours, the pressure at the well head reached 200 psi and was continuing to increase. The Operations Team decided to shut- in the pump while conducting a flushing job on the production line. The flushing job indicated that there were no materials plugging the production line. The team then decided to tie-in KL083 surface production line with production line from offset well KL073, which has high rate and high water cut, with average 90% water cut and 900 BFPD. This commingled production succeeded in reducing the well head pressure at KL083 to 130 psi. The well was then successfully put on production with close monitoring. This well has demonstrated increasing water cut from an average of 30% to 64% and resulted in lower oil production. Average oil production in first 6 months was 400 BOPD and decreased to average 150 BOPD. Fig 6 and 7 provides production performance and water cut trend of KL083.

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Fig 7. Water cut trend at KL083 As of June 2004, The ESPCP performance at KL083 exceeds the expectation of the Kulin Horizontal Well Execution team with running life of the pump is 450 days. There was no pump

recondition or pulling out job during this period. There were pump down time recorded but not associated with pump failure. The pump was down due to power outage and unrelated facility issues with the pump performance. Average pump efficiency since the well put on production is 56%. Fig 8 showing pump efficiency at KL083.

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Fig 8. Pump Down & Pump Efficiency at KL083

Another advantage of the ESPCP system is that during the put-on-production operations no oil was spilled at surface. This was possible because the rodless system of the ESPCP, eliminated the friction between the rod and stuffing box at the well head that can contribute to small spills during start-up. Production from these horizontal wells significantly contributes to total Kulin field production. Incremental production from horizontal wells is about 17% of total Kulin production. Fig 9 illustrates the impact of the development of horizontal wells on Kulin field’s production. Since May 2004, some wells in Kulin field were shut down due to an unrelated facility safety issue, resulting in lower field-wide production.

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Fig 9. Illustrated the impact of the development of horizontal wells in Kulin field. Conclusion 1. ESPCP which is a combination between PCP and ESP

motor has some advantages to be implemented at Horizontal well: a. High production efficiency even for viscous fluid and

high solid content. b. Rodless system will eliminate friction loss. c. Without stuffing box, avoid oil spill at surface.

SPE 93594 5

d. High torque capabilities e. Allows back flush capability by reversing motor.

2. ESPCP application at Kulin horizontal wells results in higher pump efficiency with average 56 – 66 % compared to tubing pump efficiency at Duri Horizontal wells which has less than 30% efficiency.

3. ESPCP offers longer pump run life, proven at KL082 & KL083 horizontal wells that never have pump problems or pulling out job. As of June 2004, ESPCP KL082 has been operating over than 800 days and ESPCP KL083 over 450 days.

References 1. Centrilift Product Catalog, “Electric Submersible Pumps &

Equipment” 2. Lee, Zabel., “Electric Submersible Progressing Cavity Pump

(ESPCP): An Alternative Lift Method for Problem Applications” , Centrilift

3. Taufan, Mochamad., “Horizontal Well KL082 Evaluation”, Internal Report, PT.CPI, 2002