SPE 165047

Successful Strategy through Artificial Lift Systems to Develop Coalbed Methane Production in Colombia D.B. Sarmiento Varela, M. Monroy Barrios, A. Gil Chacon, Weatherford Colombia Ltd; L. Luna, A. Buitrago, Drummond Ltd Colombia

Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Artificial Lift Conference-Americas held in Cartagena, Colombia, 21-22 May 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract Beam pumping system implementation as alternative of Artificial Lift System to produce the water associated to coalbed methane (CBM), was found for this specific case as the best options in performance and realiability also (production of gas and water, handling of liquid level over the pump and higher run life). The coal extraction developed in Pribbenow and El Descanso Mines involve degassing of coal stratums and dewatering. An artifitial lift is required to ensure an effective dewatering process and accelerate the gas and water recovery. Since the start of the project of CBM (Coalbed Methane) In Pribbenow and El Descanso Mines has been installed three types of artificial lift systems: Progressive Cavity Pump (PCP), Electrosubmersible Pumping (ESP) and Reciprocating Rod Lift (RRP). The installation of Reciprocating Rod Lift Systems began with four wells on February 2010 and currently the project has a population of eleven operative wells, and the expansion program includes the completion of eighteen additional wells by 2012 and 2013. Optimum design installed in each well is composed of:

− Hydropneumatic Variable Speed pumping units which had proven been the best choice for this application due to versatility in changing production conditions and in order to have a better handle of presented gas bags.

− High Stretch sucker rods that has large resistance and also presenting good performance in corrosion environments, these are centralized according to the wear evidence.

− Subsurface Tubing Pumps developed for handling high volumes of water and gas and solids production.

The achieved run life with Reciprocating Rod Lift is above seven times the run life obtained with the previous artificial lift systems (PCP and ESP). This application becomes the first successful CBM project in Colombia and has a high potential for expansion to other areas considering that preliminaries evaluations of the CBM resources of Colombia indicates that there are at least 8 regions with large CBM potential. Introduction Currently, the demand for energy is constantly increasing and at the same time conventional oil and gas resources are being depleted, this makes necessary to develop new resources and find new energy sources; this forces the industry to focus in the development of unconventional reservoirs. Unconventional resources are hydrocarbons found in conditions that do not allow fluid movement, either by being trapped in low permeability rocks or due to being very high viscosity oils. Types of unconventional resources are:

− Coal Bed Methane (CBM) − Shale Gas − Tar sands − Oil shale − Tight gas − Gas hydrates

Colombia possesses extensive unconventional energy reserves; however, bringing them to market supposes numerous challenges. Focusing on CBM, Colombia has significant coal reserves that have a coal rank suitable for CBM exploitation, CBM total potential estimates is in range from 11 to 35 TCF, although only a portion of these reserves will be economically recoverable.

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Pribbenow and El Descanso development is the only ongoing CBM project in Colombia. There are three CBM fields present: Iguana, Caporo and El Descaso, producing from Cesar – Rancheria basin, wich is located in Colombian northeastern in the departments of Cesar and Guajira. It has an area of 11,530 km2. This area contains the largest coal operation in the country. Generalities of Coal Bed Methane CBM is natural gas (virtually 100% methane, CH4) that is sourced and reservoired in a coal seam. CBM is often produced at shallow depths and is often produced with large volumes of water. It is often produced through a borehole that allows gas and water be produced to the surface. Being an unconventional reservoir, engineering practices and processes of drilling, cementing, completion and production are different from conventional oil and gas reservoirs. Methane is stored in the coal by absorption process which makes individual gas molecules link to organic molecules form solid coal by weak electrical forces. Gas storage capacity depends on the type of coal and the reservoir pressure, maturation in coal increases gas storage capacity. Most CMB wells require some artificial lift system to recover the water produced by the coal beds. Only trough effective and continuos dewatering will optimum gas production be initiated and sustained. One importan aspect of dewatering coal beds is that the produced water rate can vary widely with time. Normally CBM wells produce substancial quantities of water in their early life followed by a long period of stablished production at a much reduced rate. See Figure 1. History of the Project In 2004 began drilling of pilot wells with the corresponding studies in order to give information about the possibilities of initiating the production stage. In Phase 2 of the exploration contract were drilled 13 stratigraphic wells for sampling of coals and characterization of reservoir cores, looking for necessary information as: adsorption isotherms, gas composition, rank coal, porosity and permeability. With characterization of reservoir was possible to construct the model of the basin and calculate gas resources in-place, a volume between 1.8 and 2.3 TPC was estimated for the block. The first wells in Caporo field were completed with surface casing section of 9-5/8 in, the section of interest was hydraulically fractured and completed with gravel packing and 7 in slotted liner, these in order to not generate carbon damage caused by the cementing operation and to prevent high production of solids. Some wells were drilled with a particular spacing, in order to perform pressure tests interference with two observation

wells and an active well with a constant production rate. As a result of these tests was determined that the reservoir permeability was very small and there was a great restriction in the flow of fluid from the reservoir to the well, the time for fill thehole was very large, was established that the gravel packing was not the best way to complete the wells. The last well in Caporo field was completed with 5-½ in casing J55 of 15.5 lb/ft, then perforated and hydraulically fractured. In contrast to the first wells in Caporo field, the last one presented satisfactory results; due to its completion permeability of reservoir was increased providing a high fluids production. The wells in Iguana and El Descanso fields were completed with 5-½ in casing J55 of 15.5 lb/ft, perforated and hydraulically fractured in the same way that the last one in Caporo. The results in production of water and gas were good. In order to ensure effective dewatering process and accelerate the recovery of water and gas in the coal seams, was implemented an artificial lift system. In Cesar – Rancheria basin had been implemented three types of artificial lift for dewatering; Progressive Cavity Pump (PCP), Electrosubmersible Pumping (ESP) and Reciprocating Rod Lift (RRL). In the first CBM wells were installed PCP systems; as gas separation strategy, all pump intakes were ubicated below the perforated zone and gas separators were installed also. PCP was strongly affected by the presence of solids and gas in the well. The presence of solids generated abrasion in rotor that affects the pump efficiency; solids increases friction so increases temperature which results in: cracking and loss of elastomer properties. In the other hand, interruptions in electricity supply generated solids settling in the pump, blocking the rotation, causing torque increase and inducing failures in rods, pump and surface equipment. The presence of gas caused swelling of the elastomer and explosive decompression. There were two types of ESP installed in fields; the first type was electro–submersible centrifugal multistage pumps with coiled tubing powered with 10-15 HP motors. The problem with this ESP design consists in its low volumetric capacity and the high susceptibility to solid content due to coiled tubing diameter. The second type of ESP installed was designed to provide larger volumetric capacity (600 to 1000 BPD), but cost analysis makes unattractive this artificial lift system. ESP was affected by the large amount of solids (sand fracturing and coal fines) produced by the well, these solids increase the axial loads and power requirement. Electrical shutdowns causes that suspended solids in the water will deposit and lock pump rotation; also the continuous electrical starts generate fatigue in components due to voltage peaks that are received at each connection point. The use of beam pumping in CBM wells of Cesar –

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Rancheria basin began on February of 2010, with this artificial lif system was passible to produce the desired rates of water in a cost–effective way. Beam Pumping Design The surface pumping units used in this project are hydroneumatic technology units. The operation principle of Hydropneumatic Variable Speed pumping units is associated with hydraulic fluid pushing on pistons in upstroke and downstroke. Below the first piston (upper mast) acting hydraulic fluid, this is connected to the pressure accumulator. This accumulator is a cylinder with an internal piston which in its upper part contains nitrogen and at in its bottom contains hydraulic oil, nitrogen provides the necessary pressure to cushion the weight of rod string and fluids in downstroke and suplies hydraulic power in the upstroke, achieving with this decrease by up to 50% the required energy to lift the load on the polished rod. Figure 2. The second piston located in the mast, is driven by a hydraulic pump, which delivers power below of this piston in upstroke and above of it in downstroke. A servo valve routes pressurized fluid from the pump to the lower stage of the cylinder to cycle the cylinder rod up and down. Proximity switches activates the electric displacement control that operates the servo valve, which changes stroke direction The use of Hydropneumatic Variable Speed pumping units provides versatility as the strokes per minute can be changed manipulating a dial on control panel, in order to optimize production and performance; moreover, these allow setting different speeds for the upstroke and downstroke if this is required, this feature benefits the gas handling and is possible configure the system to ensure effective pump filling. The operating conditions can be easily changed, without the need for charging equipment or technical crew. These units were installed in CBM wells due to the given uncertainty in water production of each well. High strenght sucker rods were the choise for this application in order to can handle high volumes with low diameter that meet 2-7/8” tubing available; those were centralized, although the wells deviations were not marked and contact loads were low but, the high water oil relationship created high rod wear. This situation is created basically by the water that decreases the lubricant effect and wetting capacity. Subsurface reciprocating pumps selected for most wells were oversized tubing pumps developed for handling high volumes of water, gas and create high speed in the fluid to help keep solids in production. Oversized tubing pump is the largest pump made with a bore limited in size only by the well casing size. The design maximizes the flow area throughout the pump for optimal fluid recovery. The assembled pump attaches directly to the tubing and is

lowered into the well with production string. The sucker rods are connected to the plunger assembly by an On-off tool. Oversized tubing pumps were selected because their pumping capacity and the existing limitation in tubing size. In addition, pump design was two stages to:

1. Increase the pumping efficiency and handle the high gas production, this pump uses two compression stages with two chambers, as the plunger starts downstroke the two stage valve creates a low pressure chamber on the piston. The hydrostatic pressure is transferred from the traveling plunger valve to the two stage valve allowing the traveling plunger valve opens faster. These pumps were equipped with materials appropriate for abrasive and corrosive well conditions.

2. Help to keep the pump free during the electric shut down.

When the pump was possible to set below perforated, a casing gas separator concept was implemented in order to maximize the gas handling capacity, if not a beam pump gas separator in downhole was installed. It was designed to provide a method of allowing gas to separate out of the solution and migrate up the annulus, preventing gas locking of the downhole pump. The theory of this design is to provide a quiet chamber within the separator with a suction tube at the bottom of the quiet chamber, ported in such a way to allow fluid entering the separator to reach a predetermined fall rate, which allows time for the gas to migrate out of the solution on the down stroke of the pump and migrate up the annulus. Like an additional measure was used a back pressure valve installed in wellhead to maintain a constant pressure in tubing and keep the gas in solution, ensuring the proper functioning of the pump. Field Results All CBM wells showed the same tendency after RRP installation and operation. The resuls will be shown for one well as an example. As shown in Figure 3, an important increase in production rate was noted on wells after the installation of RRP System. On average, the water test production rate was 200% higher than with ESP. The system was able to begin gas production achieving 117 MSCFD. Figure 4 presents the history of events for this well; regarding to fluid level above pump was presented a marked decrease that allowed gas break out; the increment in fluid level over pump observed on November of 2010 corresponds with low pump efficiency due to wear by abrasion; this pump was changed recovering the decrease trend in behavior . Fluid level above pump and production has a direct relationship, at the same time that artificial lift systems is able to lift a given flow rate, the level of fluid in the annulus decreases generating a reduction of fluid column and back pressure onthe reservoir, when fluid level drop

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under specific point the gas desorption start and allow the gas break out from the coal. Flexibility is a very important feature to evaluate an artificial lift system in this CBM application, because the system has to be able to exactly adapt to well production; more capacity of the system could be an economic waste and detrimental to the well, less capacity do not allow gas production. With Hydropneumatic Variable Speed pumping units is easy and fast to adjust strokes per minute, or upstroke and downstroke speeds separately, or modify stroke length without needing crane, crews or stops of equipment. The presence of free gas in subsurface pump could affect the performance of beam pumping system causing significant decrease in well production. In Figure 5 are shown surface and pump dyna cards, there can be observed that effective plunger stroke is around 96.31% that means that gas quantity in pump does not decrease pupm fillage and pumping efficiency in the current design. Figure 4 shows all failure presented in this well along its operative life. With RRL, the surface equipment had three failures related with position sensors. The main cause of failure in pump is related with wear due abrasion of pupm components, that causes low pumping efficiency. According to statistical analysis of failure datas, the average times to failure estimates for pumps are: 30 days for ESP, 124 days for PCP and 221 days for RRL (Table 1) As can see in Table 2, result of the life cycle cost analysis for artificial lift systems was found that in for RRL the average lifting cost is 0.13 USD/Water barrel, ESP has a lifting cost of 0.58 U USD/Water barrel and PCP has 0.19 USD/Water barrel. RRL provides savings of 77.6% and 30.54% in operating costs associated with artificial lift in comparison respectively with ESP and PCP. Conclusions For CBM applications with similar conditions to Cesar – Rancheria basin, the results confirm that reciprocating rod lift system opered with Hydropneumatic Variable Speed Pumping units can offer a cost-effective artificial lift system over progressive cavity pumping or electrical submersible pumping. The primary benefits of the use of reciprocating rod lift arise from:

1. Higher pump efficiencies under gas production. 2. Longer downhole pump life against abrasion and

gas conditions. 3. Lower maintenance and repair cost.

The Hydropneumatic Variable Speed pumping units implementation provided versatility and flexibility to the system allowing adjusting operating conditions to the production requirements.

Solids and gas production are the main causes of operational issues in CBM wells; the design of reciprocating rod lift with Hydropneumatic Variable Speed pumping units, high strenght sucker rods, oversized two stage tubing pumps, downhole gas separator and back pressure valve shown be suitable for hand this conditions. References

1. Boyer C. M., Reeves S. R. “A Strategy for Coalbed Methane Development - Part III: Production Operations”. Alabama, Coalbed Methane Symposium, 1989.

2. Guzmán Rodolfo, “Potential Resources of

Unconventional Hydrocarbons in Colombia”. Bogota, June 8, 2011.

3. Hernández D. Y., Naranjo S. A., “Evaluación de

los tipos de levantamiento artificial usados en el dewatering de yacimientos CBM (Coal-Bed Methane) en el campo La Loma en la Cuenca del Cesar”. Bogotá, 2010

4. Hollub Vicki A., Schafer Paul S. “A Guide to

Coalbed Methane Operations” Gas Researh Institute, 1992.

5. Simpson David A., Lea, SPE James F., “Coal

Bed Methane Production” Texas Tech University; J. C. Cox, Texas Tech University”. SPE Production and Operations Symposium, Oklahoma, 23–25 March 2003.

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Tables Table 1. Average Times to Failure

Type of Failure

ESP PCP RRL

ALS 14,75 37,11 58,30

Electrical 8,43 10,60 11,38

Pump 29,84 123,45 221

Sucker Rod ----- 70,41 -----

Tubing ----- 536,18 -----

VDF 26,32 284,64 ----

Drivehead or Pumping Unit

----- 90 ----

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Table 2. Life Cycle Cost Analysis for ALS installed

LIFE CYCLE COST ANALYSIS

Project Life, years 20Average Well rate, BFPD 600Average Water Cut, % 100% Discount rate 13.0%Average Oil rate, BOPD 0Average Oil Barrel Price, US/bbl -$ ProjectedAverage KWH cost, US$ 0.08$ "Inflation"Average Dow n time, % 10.0% Rate % PRESENT VALUE

BM ESP PCP RRLS ESP PCP

Cic Initial Investment Cost, US$ 187,806$ 71,050$ 133,993$ 187,806$ 71,050$ 133,993$

Cin Installation Cost, US$ 6,214$ 9,114$ 6,214$ 6,214$ 9,114$ 6,214$

Pow er consumption, KW 40 50 40Ce Energy Cost / Year, US$ 3.0% 215,232$ 223,185$ 212,634$

BM 24,780$ ESP 25,696$ PCP 24,481$

Co Operating Cost / year, US$ 3.0% 28,662$ 33,874$ 26,925$ BM 3,300$ ESP 3,900$ PCP 3,100$

MTBF, days 250 30 150Failures per year 1.46 12.17 2.43Avg Active Pulling Unit Rate, US$/day 2,500$ 2,500$ 2,500$ Avg Intervention time, days 2 3 2Pump Repair Cost, US$ 17,913$ 14,840$ 33,999$ Other Wellservice related Cost, US$ 414$ 1,614$ 414$

Cm Repair Cost, year 3.0% 295,806$ 2,531,332$ 833,001$ BM 34,057$ ESP 291,440$ PCP 95,906$

Avg Rig Waiting time, days 2 2 2Cs ALS Dow n time Cost, year 3.0% 13,011$ 144,563$ 21,684$

BM 1,498$ ESP 16,644$ PCP 2,497$

Cd Salvage Value after Project Life, US$ 74,123$ -$ -$ BM 74,123$ ESP -$ PCP -$

LCC LIFE CYCLE COST, US$ 672,609$ 3,013,118$ 1,234,453$

Water Barrel Lifting Cost, US$ 0.15$ 0.69$ 0.28$

--- 77.68% 45.51%Reducción

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Figures Figure 1. De-Watering/Production Cycle

Figure 2. Nitrogen-Over-Hydraulic Pumping Unit Diagram

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Figure 3. Water and Gas Dayly Production

Figure 4. Well Chronological History of Events

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Figure 5. Surface and Pump Dyna Card