With the coalbed methane market heating up, equipment manufacturers are custom-designing artificial lift solutions.

Coalbed methane (CBM) is the fastest growing unconventional natural gas resource, and energy companies are rapidly climbing the learning curve to economically maximize production from coal seams throughout the world.
Today, there are an estimated 30,000 producing CBM wells in the United States - by far the most active region of the world for CBM production. However, activity in Canada has increased since 2000, when there were less than 200 wells, to approximately 3,900 wells today, producing over 150 MMcfgd. Reserve estimates vary depending on the reporting agency; however, the most consistent figures indicate the mature producing basins in the United States account for an estimated 17 Tcf of recoverable reserves, and emerging developing US basins have an estimated 35 Tcf of gas reserves. The bulk of US reserves are in the Rocky Mountain basins as well as the Black Warrior Basin of Alabama and the Appalachian Basin. The 700 Tcf of estimated reserves in Canada include 500 Tcf in Alberta, where much of the activity is taking place today, with the balance primarily in British Columbia, Saskatchewan and Nova Scotia.
Production concerns
Most coal seams with gas in commercial quantities contain water that is produced along with the gas. The coal zones typically require local or regional dewatering before commercial gas production can be achieved, and the key to economic production is cost-effective reservoir dewatering techniques. CBM plays such as the Powder River Basin, Black Warrior Basin, Manville coals of Alberta and coals in Australia all require dewatering to realize economically attractive recovery rates.
Most producible coals have a natural cleat or fracture structure that serves as a flow path for the water and desorbed gas. Production normally requires dewatering one or more coal zones to reduce the in-situ reservoir pressure below the "critical desorption pressure" at which methane is released from the coals and flows with the water to the area of pressure drop at the well bore.
A wide variety of completion and treatment techniques are used, depending on the coal structure, thickness, porosity and relative permeability. However, regardless of the well configuration and completion treatment, the operational objectives require maintaining the lowest possible reservoir pressure to maximize the gas desorption rate, and reducing reservoir pressure requires pumping the fluid level in the well down to the lowest possible point.
CBM well pumping requirements present challenges due to the nature of the production and completion methods. The well tubulars are configured so that gas will migrate to the surface in the annular space between the production tubing and the casing. A pump is typically landed as low as possible in the well to maximize fluid drawdown, which can result in periods of reduced fluid volumes and, therefore, increasing internal pump temperatures. Plus, minimal fluid levels over the pump and a foamy liquid/gas interface can cause gas to migrate to the pump intake, resulting in internal compression and operating temperature increases.
Another issue for CBM pumping systems is solids in the fluid. Depending on the type of well completion used to stimulate the coals, a pump can be initially inundated with fracture proppant. Coal particles also can be carried in the fluid. Both proppant and coal fines are abrasive and can damage the pumping system components.
These production challenges can mean escalating operating costs, potentially making CBM projects economically unfeasible. Consequently, a sustainable and reliable pumping system is critical to the positive payout of a well or field.
In addition to adverse pumping conditions, another major consideration for CBM production systems is operating costs. Historically, revenue from CBM production has been relatively marginal due to water handling and disposal costs as well as costs associated with compressing the gas from as low as 1 psi to a pipeline entry pressure of 300 psi to 1,500 psi. With these operational and economic hurdles to overcome, operators have challenged pump manufacturers to develop cost-effective solutions.
Artificial lift options
Traditionally, electrical submersible water well systems and rod-driven progressing cavity pumping systems (PCPs) have been employed to dewater CBM wells. However, reliability has been an issue with water well equipment, while cost considerations have stymied PCP and more rugged oilfield electrical submersible pumping systems. To overcome these issues, oilfield service companies have designed pumping systems specifically for CBM applications, providing more rugged yet cost-effective equipment.
For example, Centrilift developed a 30 hp drivehead for rod-driven progressing cavity pumping systems as a more cost-effective fit for the 10 hp to 30 hp applications typical of shallow CBM wells. PCP systems have been used in CBM wells since 1986, both as the primary dewatering system and as a solution for troublesome wells, since PCPs can effectively pump coal fines, sand particles and gaseous fluids. Plus, PCP is a positive displacement system with the output rate directly tied to the speed of the pump. This feature allows the system to be adjusted via pump speed to match the decline curve of the water production, eliminating over-pumping the well.
The single or double helix design of the steel rotor in a PCP pump, coupled with the stator, which is a steel tube with an elastomer permanently bonded inside, provides a design with sealed cavities within the pump. As this seal line moves up along the pump, any solid particles are trapped between the rotor and stator and temporarily deflect the elastomer until the seal line passes and the solids re-enter the fluid stream.
Gas impacts a pump by taking up space meant for fluid and, in many systems, can cause grossly inefficient fluid production, intermittent production or a gas-locked pump. The main effect of gas on PCPs is a decrease of volumetric efficiencies. A PCP of a given capacity moves a given volume per revolution, regardless of whether that volume is oil, gas or some combination. As a general rule, 40% free gas at the pump intake is considered acceptable and will not adversely impact pump life.
PCP elastomers balance the needs of CBM production. The elastomer is flexible enough to provide the deflection needed to pass solids through the pump without gross erosion of the elastomer or the chrome plate of the rotor. The elastomer constituents and structural matrix are designed to remain stable while in operation in order to resist expansion that can occur due to decompression caused by gas migration into the rubber as well as resisting swelling from exposure to water.
Applications
As with any oil and gas play, specific applica-tions dictate the choice of production equipment. While PCPs are suited for wells with abrasive conditions, electrical submersible pumping (ESP) systems are a good choice for wells with water volumes above 1,200 bbl of fluid per day.
Electrical submersible pumping systems have been used in CBM wells since about 1999, but initially water well systems were employed due to the low cost of the equipment. However, water well systems cannot handle coal fines and other solids. During the initial dewatering stage, the water is relatively clean (in wells where sand proppant is not used during the completion), but as the well is drawn down, more solids enter the system. As a result, the water well equipment runs reasonably well for a period of time but then fails as the coal fines increase.
As the CBM market has matured, a growing number of producers with oil industry backgrounds have jumped into these unconventional plays, and those companies have sought better equipment choices. Oilfield service companies were approached to supply hybrid ESP systems that are more robust than water well systems but still cost-effective for CBM wells. The ideal solution was an oilfield-type pump, which is more resistant to abrasives, with a water well-type motor and surface package.
In addition to a more robust design, oilfield service companies were challenged to develop a system that could go deeper and fit in smaller casing sizes. Traditional water well motors rated over 10 hp are too large for small casing, and below about 2,000 ft (610 m) the water temperature exceeds the limits of water well systems. To overcome these challenges, Centrilift recently developed its 450 CBM motor with an integral motor/seal design.
The 450 CBM motor is a redesign of the conventional oilfield 450 motor train with no threads on the ends - the head and base are welded. A single shaft is used for the motor and the single chamber seal. The thrust bearing and motor carry the pump load versus both a motor and seal thrust bearing in a standard oilfield configuration. The motor leads for the electrical cable come directly out of the motor head, unlike a standard motor that has a separate plug-in connector.
The biggest challenges for the new design were the motor head redesign, making it part of the seal. Also, there is only one mechanical seal in the unit, so to provide some redundancy in the event of a seal leak, a lip seal was included under the mechanical seal at a dramatic cost savings compared to the traditional design.
To further reduce operating costs, the motor is pre-filled and pre-serviced and can be installed by the operator, which eliminates field service costs. Additionally, the cable splice design is common to operators, making installation by the operator feasible.
The 450 CBM motor is designed for applications from 20 hp to 30 hp and up to 2,200 ft (670 m) deep. The motor is run below the perforations. Down to 2,200 ft, the water temperature is cool enough to keep the motor cool. The most significant advantage of the new motor is the cost savings associated with drilling smaller cased wells versus the 7-in. casing required for water well systems over 10 hp.

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