Each change in well design has introduced artificial lift challenges. Vertical wells were perforated in two seams and hydraulically fractured. Frac sand and coal fines caused plugging problems. Horizontal wells were not fractured and a slotted liner reduced the amount of solids entering the well, but gas locking/interference became an issue.
Multilateral drilling allowed gas locking to be avoided by
drilling a sump below the horizontal legs, but introduced serious solids issues. The motherbore is drilled horizontally through the coal and cased. Windows are then cut in this horizontal section, legs are drilled out through the seam and slotted liner is run in. There is a short section of open hole between the motherbore and liner top on each leg, typically 2m long. Solids enter the wellbore through this open hole section and cause pump plugging. These solids range from coal muds/pastes, fines, pebble-sized pieces to gravel sized coal rocks.
Another challenge inherent in the dewatering process is declining water inflow over time. Upon completion, pumps are appropriately sized to handle water inflow when bottom hole pressures are high at 8,000 to 10,000 kPa. As the well is dewatered, BHP is lowered and water production decreases. Most pumps become oversized after 6 months, when inefficient pumping and reduced pump life starts to occur. Timers and pump-off controllers are then used to control the oversized pumps.
Trident operates about 130 producing CBM wells in the Corbett area as of March 2008. Of these, 100 wells utilize electric submersible pumps (ESPs), 10 utilize beam pumps and the remainder are free-flowing or use other forms of artificial lift. ESPs have proven to be the most effective lift method to date because ESPs can move large volumes of water economically and have a wide operating range. ESPs have been proven to draw down and maintain a low fluid level, keeping hydrostatic head on the formation to a minimum. Almost all horizontal or multilateral wells have ESPs installed.
The main disadvantages of ESPs are intolerance to solids and a practical minimum flow rate. The root cause of 90% ESP of failures is solids. Common failures include plugged stages, plugged intake screens, shaft breaks, and overheating causing electrical failure. These solids also prevent the use of very low volume ESPs. Reductions in vane height to achieve lower volumes make the pump more prone to plugging. Also, field experience has shown there is a practical minimum flow rate for effective operation because of problems maintaining prime and insufficient motor cooling.
Beam pumps are utilized on about 10 wells. These pumps have been applied to wells with 60 bbl/d to 120 bbl/d (10 m3/d to 20 m3/d) water inflow. Workover costs are significantly less expensive than ESP installations. Beam pumps are excellent in vertical applications, but have suffered rod/tubing wear in horizontal application. Solids again pose problems in the form of plugged intakes and seized pumps. Gas interference also causes reduced fill efficiencies, which can be reduced with solution gas valves on the plunger. Overall success has been limited. Beam pumps that replace ESP installations after initial dewatering have not matched the gas production when an ESP was installed.
Progressive cavity pumps (PCPs) were used in 2004 and 2005 on vertical wells for their ability to moves sand and coal. Difficulties with stator elastomers swelling and blistering caused pumps to seize up. Rotors would also momentarily seize and release, causing the rod string to act as a torsional pendulum. PCPs were not tried in horizontal or multilateral wells because of anticipated rod and tubing problems.
ESPCPs
In light of the solids problems with ESPs and rod/tubing problems in horizontal applications, a system that drives a PCP with an electric downhole motor was installed in July 2007. The electric submersible progressive cavity pump (ESPCP) allows reliable horizontal operation while taking advantage of the solids handling capabilities of a PCP.
The system uses a standard ESP motor coupled to a planetary gearbox. A speed reduction of 11.57:1 was used for the trial system. The flex shaft couples the gearbox to the PCP rotor. The flex shaft is used to convert the concentric rotation of the ESP motor to the necessary eccentric rotation for the PCP. The rotor and stator used in the pump are similar to those used in heavy oil production. Downhole pressure and temperature sensors were also used.
3
due to solids and low fluid level. The candidate well had been completed in November 2006 and the well dewatered with an ESP. Solids in surface equipment had been reported and the pump would periodically show minor plugging. The ESP eventually failed in May 2007 and the pump was seized upon being pulled. Teardown showed the pump stages were plugged with coal. The well was pumped down at the time of failure. Production before failure was 250 mcf/d (7 e3m3/d) gas and 75 bbl/d (12 m3/d) water.
Pump sizing was difficult because of the unknown behavior of the elastomer at reservoir conditions. Previous use of PCPs had shown elastomer blistering and swelling. The pump on the trial system was sized to be installed with a very low efficiency, hoping a loose fitting pump would swell to higher efficiencies. The ESPCP was installed July 2007. It was landed in the sump to avoid gas from the horizontal legs and avoid potentially running the pump dry. The approach to sizing worked well, with the pump showing signs of swelling up to high efficiencies within 2 months. No hard starting or seizing was seen during this time. Maximum water production was 90 bbl/d (14 m3/d) before high motor temperature problems reduced daily runtimes.
The unit was pulled in February 2008 because the pump volume was ultimately too small and could not match the water inflow. Gas production had not returned to the 250 mcf/d (7 e3m3/d) achieved with the ESP. A moderate amount of coal solids and paste were bailed from the sump of this well, indicating solids production. The rotor, gearbox, flex shaft and electrical components passed shop inspection with only signs of minor wear. The stator was in good condition, showing only minor wear in the top of the pump.
This trial showed the ESPCP has the potential to achieve pump life beyond that of an ESP because of better solids handling. The ESPCP had matched the same life of an ESP, and would have lasted longer if left in service. Another ESPCP with a higher volume pump and improved motor cooling was installed in the same well in February 2008.
Conclusion
Trident operates a significant part of a wet CBM project in Ft. Assiniboine, Alberta, Canada. This is the only commercial Mannville CBM project in Alberta at the present time. The Corbett project was declared commercial in 2005.
An evolution in well design from vertical to horizontal to multilateral wells has increased gas and water production, decreased the initial dewatering period, reduced drilling costs and reduced surface facility footprint. This evolution has also introduced artificial lift challenges, such as gas interference in horizontal wells and solids production in multilaterals.
ESPs are used in 75% of wells for dewatering and ESPs are primarily used because of an ability to economically produce high volumes and operate in a horizontal position. Solids pose a major problem and are the root cause of 90% of ESP failures.
were used in vertical wells, but suffered from stator problems. An ESPCP system was installed to take advantage of the PCPs excellent solids handling yet operate in the horizontally. After a 6 month trial, the unit showed no plugging problems. The ESPCP was pulled because of an undersized pump, not a failure. A cleanout during the workover showed signs of solids production. Teardown of the system showed only minor wear. Results of this trial were encouraging. The ESPCP may have the potential to improve average pump life of the field and reduce workover costs.
Acknowledgements
Trident Exploration Staff
Community of Fort Assiniboine and Surrounding Area Baker Hughes Centrilift
Nomenclature
Bbl/d = Barrels per day
BHP = Bottom Hole Pressure
CBM = Coalbed Methane
E3m3/d = thousand cubic meters
ESP = Electric Submersible Pump
ESPCP = Electric submersible progressive cavity pump
Ft. = Feet
Mcf/d = Thousand cubic feet per day
Mmcf/d = Million Cubic feet per day
M3/d = cubic meters per day
PCP = Progressive Cavity Pump
TCF = Trillion Cubic Feet
REFERENCES
1. Dr. Logan, K., “TransCanada’s CBM Forecast for 2007,” CSUG 2006 Conference, Calgary, Alberta, November 15-17, 2006
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Overview
Every day in the oil and gas industry, cutting-edge technology is driven—sometimes inch by inch and occasionally in great leaps forward. Commitments are taken to make the seemingly impossible, possible, to provide solutions to the challenges of tomorrow. Advanced technology is used, not for its own sake, but to find practical solutions that enhance safety, are user friendly, are well engineered, and enable better recovery. Therefore, the primary endeavors in any upstream environment are to fully perceive the application needs of wells and thereafter provide innovative and reliable solutions that withstand the test of time and cost, and to continue to pursue improvements in quality without compromising safety.
Here, solution means integrated resources; integrated resources means people, process and technology. The target is to make the integrated resources a successful collaboration between these three, the scale of measuring how successful this solution is judged only by comparing it to a similar solution of the same environment and applications needs.
The solution discussed in this paper is a “flushby”—a state-of-the-art technology adaption that requires fewer operating people and has shorter work process with less nonproductive time (NPT) compared to alternatives, such as a service workover rig, for the same applications.
The possibilities and value potential associated with integrated resources are substantial, and implementation is therefore identified by the industry as a strategic tool to ensure a sustainable development. Thus, integrated resources yield accelerated and increased production at reduced operating costs and with uncompromised high safety levels and high standards of environmental stewardship.
The oil and gas industry, like any other industry, is affected by the global market economic stability and oil prices. Hence, during exigent economic times, a producer’s concern is to minimize operating costs. In contrast, during prosperous periods, producers focus on optimizing the operating time to maximize recovery. Flushbys can play a vital positive role in both economic periods.
Introduction
The flushby1 is an innovative, highly mobile and efficient unit for servicing existing wells of artificial-lift nature. The unit
(Fig. 1) consists of a fluid tank, a triplex pump, a small derrick-and-hoist assembly, with tools and safety equipment
including rod tongs and blowout preventer (BOP), all mounted on one truck. The integration of the service mechanisms creates the unique ability to perform several servicing tasks. Moreover, flushby servicing capabilities expand if the unit is deployed in collaboration with other service units and/or supporting equipment and tools.
Flushbys were first introduced to the oil and gas industry in Canada during the 1980s. The first generations of flushbys were designed for the artificial-lift segment; specifically only for the progressive cavity pump (PCP) applications in which sand levels in wellbores become problematic. Flushbys were called to lift up on the rods and flush water or oil past the rotor and through the stator to clear the pump of sand. In a brief period of time, both applications and area of operations have expanded. The presence of flushbys spread from Canada to South America, where heavy-oil operators also found benefit in the efficiency of the flushby, then continued to spread into the rest of North America and, now, globally.
Configuration
Both at surface and downhole, the flushby can be stand-alone equipment on the job to service PCP systems and reciprocating-rod-pump (RRP) systems. In addition, the flushby can be combined with other equipment, such as a coiled- tubing unit (CTU) for stimulation purposes and a Mobile Gripper™ (MG™) automated hydraulic injector for continuous-rod applications. Flushbys are sometimes customized and manufactured with a built-in injector (integral gripper unit) for continuous-rod applications.