Installation of Pump-off Control Technology in Goldsmith-Cummins Deep Unit. Proposed by: 16 March 2005 Marietta College

Transcription

1 Installation of Pump-off Control Technology in Goldsmith-Cummins Deep Unit Proposed by: 16 March 2005 Marietta College

2 Table of Contents I. Executive Summary 3 II. Introduction 6 Chart 1 Costs Incurred by GCDU in III. Technical Description 8 Figure 1 Rod Pumping System 8 Figure 2 Surface Dynamometer Card 9 Table 1 Pump-off Controller Features 10 IV. Field Criteria and Compatibility 11 V. Cost 12 Table 2 - Pump-off Controller Installation Costs 12 Table 3 Program Costs 13 VI. Method 13 VII. Qualifications 14 VIII. Conclusion 14 Table 4 Potential Cost Savings 15 IX. Works Cited 16 X. Appendix A: GCDU Production History 17 XI. Appendix B: Pump-Off Controller Diagram 17 XII. Appendix C: Résumé 18 2

3 I. Executive Summary Problem The Permian Basin is one of the largest hydrocarbon reservoirs ever discovered. Goldsmith-Cummins Deep Unit (GCDU), located in West Texas, is located in the heart of the Permian Basin. Owned and operated by Anadarko Petroleum Corporation, the Goldsmith-Cummins Deep Unit has produced from the Clearfork formation for over fifty years. Producing primarily oil, over ninety percent of the 140 producing wells in the GCDU use sucker-rod pumping for artificial lift. An aggressive water-flood injection program currently injects approximately 17,000 barrels of produced water every day. This large volume of water injected throughout the field leads to unpredictable reservoir behavior. Production rates vary day to day, causing the need for adjustable run times for the sucker-rod pumping systems. The current runtime control system in place, however, does not allow operators to adjust run times according to reservoir inflow properties. Percentage timers, which run a preset percentage of time per thirty minutes are set by the operators according to the previous month s production data or other warning signs such as audible fluid pound. A direct correlation can be drawn between these excessive run times and excessive down-hole equipment wear, which has caused unnecessary expense to the GCDU over the past few years. Most wells in the field produce ninety percent formation water which contains corrosive chemicals such as H2S and ten percent oil. This high volume of formation water production causes premature wear on the down-hole pump as well as the rod 3

4 Solution string and production tubing string. Excessive run times cause excessive wear on these components The solution to this problem is the installation of a pump-off control system installed on every producing, rod-pumped well in Goldsmith-Cummins Deep Unit. Each well will have a standalone control box with graphical display capabilities on site. Pump-off control helps to diagnose inefficient run times and down times, stuck pumps, parted rods, worn pumps and many other down-hole problems when they happen as opposed to weeks or months after the incident as with percentage timers. Pump-off control uses the dynamometer card to measure load versus position as the system cycles and pumps hydrocarbons from the reservoir to the surface into production. Once the pumpoff controller recognizes that the pump is not performing to its desired capacity, the well is shut in for a set period then pumped again until it pumps off. This process is repeated and adjusted automatically in an effort to optimize the pumping system with the reservoir inflow properties. Conclusion The process to install pump-off control technology in the Goldsmith-Cummins Deep Unit will take place in two steps. A pilot program of twenty-five wells with a history of premature equipment failure will be outfitted with the technology. After six months, the entire field will be outfitted with the technology. Pump-off control technology best optimizes the rod-pumping system, which accounts for over ninety percent of artificial lift in the Goldsmith-Cummins Deep Unit. Pump-off control technology would greatly benefit operations in Goldsmith- 4

5 Cummins Deep Unit by reducing wasted electricity and unnecessary equipment wear. The cost of pump-off control would pay for itself up to five times over in saved expenses within one year (See Section VIII: Conclusion for specific example). These savings are reason enough to merit installation of pump-off control field wide. A nearby field, TXL North Unit, which produces out of the same formation was outfitted with pump-off control technology and has reaped the benefits of less maintenance and more efficient run times. 5

6 II. Introduction Rod pumping is one of the oldest methods of secondary recovery in the petroleum industry. It is also the most popular choice, accounting for eighty-five percent of artificial lift systems in use today. 1 Rod pumping is even more popular in the Permian Basin due to the small amount of gas production and high volumes of oil and formation water. The Permian Basin contains a vast amount of hydrocarbons but was discovered over a century ago, therefore a high percentage of oil has already been recovered. Infill drilling, which is the practice of drilling a set pattern of wells within an area bounded by known producing wells, has been employed in most fields. It is logical to assume that the longer a reservoir is produced and the more wells produce out of said reservoir that production rates will decline. This is the case in the field proposed for installation of pump-off control technology. The Goldsmith-Cummins Deep Unit (GCDU), operated by Anadarko Petroleum Corporation, is located near Goldsmith, a small town near Midland in West Texas. Discovered in the 1950 s, the field has been in constant production for over fifty years and has been the subject of radical infill drilling down to ten acre spacing and water flood program which currently injects approximately 17,000 barrels of water per day. The field currently contains 140 producing wells. Production History is illustrated in Appendix A, page 17. Nearly every well in the Goldsmith-Cummins Deep Unit is rod pumped. The current method of well control is percentage timers, which run a set percentage of time per thirty minutes. Operators set the timers and adjust them as production rates fluctuate. This method of adjusting run times is highly inefficient for two main reasons. First, the field inflow behavior often fluctuates due to the injection program. Volume of injection per day depends on volume of produced water per day, therefore injection rates can vary daily. This fluctuation of injection volume causes reservoir properties to change and therefore production rates change as well. Percentage timers cannot compensate for changing production rates. 2 Second, operators can only adjust percentage timers once per month, accounting for poor efficiency. This is not the operator s fault; individual well 6

7 production data is only available once per month when wells are tested individually for their respective production rate. These inefficiencies in adapting run times to reservoir performance cost the company a significant amount of money. Production inefficiency due to erroneous run times is not the only cause of extra spending averted with the use of pump-off control. Goldsmith-Cummins Deep Unit incurs expenses in the form of pulling costs and down production time due to down-hole problems. A stuck pump is one such problem that is common in many new infill wells in the field. Once a well is stimulated and put into production, there is a considerable amount of sand encroachment into the well bore causing the pump to become stuck in the tubing. Another problem is parted rods. When this happens, the rod string is pulled and replaced, incurring extra cost. A worn out pump is a third reason to pull a well. Sand and water production cause premature pump wear, resulting in lower production potential for the well. The rod string and pump are pulled and the pump is replaced. All three of these cases also result in a loss of production before the problem is realized. It can take up to a Chart 1 - Costs Incurred by GCDU in 2004 year to realize through decreased production data that there are down-hole problems. Chart 1 illustrates total costs incurred by Goldsmith-Cummins Deep Unit in The solution to this problem is the installation of a pump-off control system installed on every producing, rod-pumped well in Goldsmith-Cummins Deep Unit. Each well will have a stand-alone control box with graphical display capabilities on site. Pump-off control helps to diagnose inefficient run times and down times, stuck pumps, parted rods, worn pumps as well as other down-hole problems when they happen as opposed to 7

8 months after the incident. 3 Section III covers the specific method by which pump-off control technology diagnoses these problems. In a similar field operated by Shell in the Permian Basin, rod failures, pump changes and run times were compared before and after the installation of pump-off control. After one year, rod failures were reduced by 39%, pump changes by 19% and run time by 23.5%. 4 Most of these decreases in problems can be attributed to more efficient run times and therefore less fatigue on the rod pumping system. This proposal utilizes research from the Society of Petroleum Engineers elibrary database of SPE papers. These papers include research from professionals with extensive experience with the application of pump-off control technology. Information for specific technical descriptions and applications is derived from industry vendors as well as personal knowledge and experience with the subject. III. Technical Description In order to understand how a pump-off controller works, the user must first understand two basic concepts: how a rod pump works and what a dynamometer card is. Pump-off controller technology relies on the function of rod pumping to gather data and troubleshoot down-hole problems, while dynamometer cards are the graphical representation used by pump-off control technology to describe the action of the well. Figure 1 - Rod Pumping System Rod pumping is one of the oldest methods of secondary recovery and is also the most popular, accounting for eighty-five percent of the industry. 1 Over ninety percent of the producers in Goldsmith- Cummins Deep Unit are rod pumped. There are 8

9 four main components of rod pumping: power source, rod string, positive displacement pump and tubing string. Figure 1, page 8, shows these four main components. The power source, usually a pumping unit, strokes the rod string, which runs the entire depth of the well. The rod string is connected to the positive displacement pump, which is the prime mover of reservoir fluids, is consequently stroked up and down to move the fluids towards the surface. The tubing string serves as a conduit for the reservoir fluids. As they leave the pump, the fluids travel up the tubing to the surface and into separator facilities. 5 Dynamometer Cards measure the action of the rod pumping system as it moves fluid up the tubing into production. The dynamometer card measures pump position (x-axis) versus load on the rod string (y-axis). This card is redrawn with each complete stroke performed by the system. There are two types of dynamometer cards: surface and downhole cards. Pump-off controllers record and display surface cards. An example of a dynamometer card be seen in Figure 2. Dynamometer cards are the main tool used by pump-off control technology to determine the status of the rod pumping system. Figure 2 - Surface Dynamometer Card There are many variations of the pump-off controller that have developed over the years. These include fluid level testing, vibration sensing, motor current sensing and rod loading. 6 Rod loading type is the most accurate form of pump-off control and is the method proposed for installation in the GCDU. The basic rod-loading pump-off controller consists of three basic components: load sensor, position sensor and control 9

10 interface. A detailed diagram of the pump-off controller is illustrated in Appendix B. There are many variations of each component but each performs the same basic function. The load cell is located on the polished rod string above the polished rod clamp. It records the weight in tension as the rod string moves up, pulling the pump open and the weight in compression as the rod string moves down, forcing the fluids out of the pump. The load cell transmits this data back to the control interface and accounts for the load portion of the dynamometer card. The position sensor, known as a dual position sensor (DPS) mounts on the walking beam of the pumping unit. The DPS is a dual axis accelerometer that senses changes in movements as the pumping unit completes each stroke. The DPS also transmits to the control interface and accounts for the position portion of the dynamometer card. The third component of the pump-off controller is the control interface, which gathers load and position data and processes it to display the dynamometer card. The control interface is located at the well location and displays vital information for the operator through a full LCD graphics display. Through the control interface, the operator sets the pump-off point, a set position and corresponding load value at which the well is said to be pumped off. This pump-off point is illustrated in Figure 2. The operator sets the number of times the dynamometer card can travel outside the pump-off point before the control interface automatically shuts off the pumping unit. The user also sets a preliminary down time value once the well pumps off until the pumping unit restarts. The pump-off controller technology, however, is available to customize the down times based on the length of run times in an effort to optimize run times compared to reservoir performance. Other features of the control interface are outlined in Table 1. Diagnostic Tools Parameters Alarms Past Run Times Pump-Off Point High Load Limit Past Down Times Pump-Off Strokes Low Load Limit Pumped off Dynamometer Cards Down Time High Tank Level Live Dynamometer Cards High/Low Load Limits Flowline Pressure Limit Table 1 Pump-off Controller Features 10

11 IV. Field Criteria and Compatibility In order for pump-off control technology to be feasible, there is a set of criteria for the field. The first requirement for pump-off control technology is a primary production of liquid hydrocarbons. Fields producing mostly gas are not optimum candidates for pumpoff control technology. The second requirement is that the field is primarily produced using rod pumping. It would be impossible to draw the required dynamometer card without the cyclical pumping action of a rod pump. The last requirement for pump-off control technology is a semi-hospitable environment. 7 A quality electric source is necessary for pump-off control technology to function properly. Harsh environments such as extreme cold, extreme heat or excessive moisture are hazardous to the sensitive components of the pump-off controller and would not be economically feasible due to excessive maintenance required. Goldsmith-Cummins Deep Unit meets all three criterion, making it a prime candidate for pump-off control installation. The Clearfork Formation produces almost exclusively oil and water with little gas production. Secondly, over ninety percent of the producing wells in the field are rod pumped. Lastly, the environment of West Texas is suitable for installation and maintenance of the technology. An expansive, dependable electricity source has been developed during the field s life, providing a dependable infrastructure for pump-off control. The warm, dry climate is cause for few maintenance concerns for equipment malfunction. There are other reasons for the need of pump-off control technology in Goldsmith- Cummins Deep Unit. The first is the excessive amount of water production in the GCDU. Most wells currently produce approximately a ten percent oil cut, meaning that for every one hundred barrels of fluid produced, only ten barrels will be crude oil. Positive displacements depend on lubrication from the fluid produced and most are not designed to pump such a high percentage of water. This leads to a lower tolerance for excessive run times and leads to premature failure of pumps. Pump-off control technology would reduce excessive times and extend the life of the pumps, reducing costs. Another reason for pump-off control installation in the GCDU is aggressive injection program employed 11

12 in the field. If injection rates decrease for some reason, this affects reservoir performance by causing a decline in the reservoir drive mechanism. Production capability of the reservoir then declines causing excessive run times and unnecessary fatigue on the downhole assembly and pumping unit as well as wasted electricity. Pump-off control would recognize lower production capability and reduce the run times of the wells to account for these variations. V. Cost The installation cost per well for eproduction Solutions CAC 2000 Rod Pump Controller is shown in Table 2. Control Interface with full graphics display $ 1, Stainless Steel Polished Rod Load Cell $ Continuous Position Device $ Load Cell Cable $ Installation $ Total $ 3, Table 2 Pump-off Controller Installation Costs 7 Basic training is offered for operators at no cost with the purchase of the above technology. eproduction Solutions also suggests that at least one employee receive extensive training to diagnose down-hole problems and optimize run times as well as perform basic maintenance on the equipment. This extensive training session costs $500 and also includes troubleshooting manuals and dynamometer card interpretation handbook. The total cost of the program is illustrated in Table 3, page 13. The costs are split between a test program and full program. The explanation and ramifications of this method are described in Section IV: Method. 12

13 Test Program Pump-off Contol Installation $ 3,030 per well Number of Wells 25 Training $ 500 Total $ 76, Full Program Pump-off Control Installation $ 3, per well Number of Wells 105 Total $ 318, Sub-Total $ 394, Tax 7.50% Grand Total $ 423, Table 3 Program Costs The installation of pump-off control technology in the Goldsmith-Cummins Deep Unit would improve employee morale due to improved optimization capability and ease of use. Basic operation of the technology is very simple and any equipment malfunction is covered under warranty. There will be a minimal loss of production due to downtime during installation of technology on the pumping unit. Hardware is installed by a certified eproductions Solutions technician and is completed in less than two hours. In the event of equipment malfunction, the pumping cycle can be controlled manually or by a percentage timer until the error is corrected, causing no lost production time. VI. Method The proposed method of installation involves two steps. The first is to install pump-off control technology on twenty-five wells that have a history of excessive pump wear or other down-hole problems such as parted rods or split tubing. This process will be completed within one month of approval in order to reduce excessive maintenance costs as quickly as possible. At this time, all operators will be trained for basic operation. The current field technician will be assigned to the extensive training session to be educated on further optimization and troubleshooting of the technology at this time as well. 13

14 If the technology has reduced pulling and maintenance costs in the test wells and the technology is well received by the operators after six months, the remaining 105 producing sucker-rod pumped wells will be outfitted with the technology. This arrangement will not only give the technology a chance to prove itself useful, but the monetary investment will be broken into two parts. The total required investment is shown in Table 3, page 13. Total timeline for the project is eight months. VII. Qualifications As a student in the petroleum engineering program at Marietta College, I completed Production Systems I, where I learned basic operation of sucker rod pumps and interpretation of dynamometer cards. I also interned with Anadarko Petroleum Corporation in the NoTrees office Summer 2004, where I worked in the TXL North Unit. TXL North and Goldsmith-Cummins Deep Unit are located 5 miles apart and produce from the same formation, the Clearfork. TXL North Unit was outfitted with pump-off control technology five years ago and I worked extensively with the production technician in charge of the field gaining valuable knowledge on the operation of pumpoff control technology. During my internship, I attended a basic training session from eproduction Solutions, which provided valuable information. My further qualifications can be found in Appendix C: Résumé. VIII. Conclusion Goldsmith-Cummins Deep Unit, located in the Permian Basin in West Texas has been producing for over fifty years. The field was put on artificial lift in the 1960 s and a water-flood was developed in Excessive pumping unit run times and excessive equipment wear places an unnecessary financial burden on Goldsmith-Cummins Deep Unit. The reason for this is inadequate well control technology. Percentage timers currently control run times on all sucker-rod pumps. This antiquated system does not allow run-time adjustment as reservoir inflow properties change due to an aggressive water flood. 14

15 Pump-off control technology best optimizes the system of rod pumping, which accounts for over ninety percent of artificial lift in the Goldsmith-Cummins Deep Unit. Pump-off control technology would greatly benefit operations in Goldsmith-Cummins Deep Unit by reducing wasted electricity and unnecessary equipment wear. Table 4, below, illustrates costs saved based on results from SPE paper and well histories. As illustrated, the cost of pump-off control would pay for itself five times over in saved expenses within one year ($16,420 savings). GCDU 143: Average per year Cost per year % Reduction with POC Cost after POC Installation Rod Failures 3 $ 25, % $ 15, Pump Failures 2 $ 18, % $ 14, Electricity Usage (kw) $ 13, % $ 9, $ 56, $ 40, Table 4 Potential Cost Savings These savings are reason enough to merit installation of pump-off control field wide. A nearby field, TXL North Unit, which produces out of the same formation was outfitted with pump-off control technology and has reaped the benefits of less maintenance and more efficient run times. 15

16 IX. Works Cited 1 Freeman, Dave. "Artificial Lift Lecture." Petroleum Production Systems I. Brown Petroleum Building, Marietta. 16 Feb McCoy, J.N., O.L. Rowlan, D.J. Becker, and A.L. Podio. "How to Maintain High Producing Efficiency in Sucker Rod Lift Operations." Mar SPE 80924:1-11. SPE elibrary. Society of Petroleum Engineers. 15 Feb 2005 < 3 "ep's Rod Pump Solution is a Complete Solution for Optimizing Rod-Pumped Well." ep-solutions.com. eproduction Solutions. 23 Feb < Solutions/IDM_Rod_Pump.htm>. 4 Neely, A. Buford, and H.O. Tolbert. "Experience With Pumpoff Control in the Permian Basin." Journal of Petroleum Technology May SPE 14345: SPE elibrary. Society of Petroleum Engineers. 15 Feb 2005 < 5 Economides, Michael J., A. Daniel Hill, and Christine Ehlig-Economides. Petroleum Production Systems. Upper Saddle River: Prentice Hall, Westerman, G. Wayne. "Successful Application of Pump-Off Controllers." Oct SPE 6853:1-7. SPE elibrary. Society of Petroleum Engineers. 15 Feb 2005 < 7 Gann, Nathan. "RE: Pump-Off Controller Inquiry." to Timothy Byers. 22 Feb

17 X. Appendix A: GCDU Production History Goldsmith-Cummins Deep Unit Individual Oil Production Rate # ProducingWells # Injection Wells Rate (bpd) Number of Wells Year XI. Appendix B: Pump-Off Controller Diagram 17