Gas-Lift Technology Applied to Dewatering of Coalbed Methane Wells in the Black Warrior Basin

Johnson, K.J.; Coats, A.; Marinello, S.A.

doi:10.2118/21590-pa

Cited by 3 publications

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“…Johnson [12] et al, present a study of using gas lift for dewatering a CBM field. Johnson points out that single-point injection down the tubing with returns up the annulus is a common clean-up method in the Black Warrior Basin as it is in other CBM fields.…”

Section: Gas Liftmentioning

confidence: 99%

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Coal Bed Methane Production

Simpson¹,

Lea²,

Cox³

2003

Proceedings of SPE Production and Operations Symposium

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Section: Gas Liftmentioning

confidence: 99%

“…Boswell [14] et al, describes a system of gas lift bringing injection gas down the annulus and returns up the tubing. This is a simple de-watering completion, but it would, again have to be evaluated to see what producing pressures could be obtained.…”

Section: Gas Liftmentioning

confidence: 99%

Coal Bed Methane Production

Simpson¹,

Lea²,

Cox³

2003

Proceedings of SPE Production and Operations Symposium

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Dewatering of Coalbed Methane Wells with Hydraulic Gas Pump

Amani

Juvkam-Wold

1995

SPE Eastern Regional Meeting

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The coalbed methane industry has become an important source of natural gas production. Proper dewatering of coalbed methane (CBM) wells is the key to efficient gas production from these reservoirs. This paper presents the Hydraulic Gas Pump as a new alternative dewatering system for CBM wells. The Hydraulic Gas Pump (HGP) concept offers several operational advantages for CBM wells. Gas interference does not affect its operation. It resists solids damage by eliminating the lift mechanism and reducing the number of moving parts. The HGP has a flexible production rate and is suitable for all production phases of CBM wells. It can also be designed as a wireline retrievable system. We conclude that the Hydraulic Gas Pump is a suitable dewatering system for coalbed methane wells. Introduction Coalbed methane has emerged as a significant source of natural gas. The original perception of coal-associated methane as a hazard in mining operations is changing. Today a coalbed is considered a reservoir from which large quantities of methane can be extracted. Between 1983 and 1993, industry drilled an estimated 6,600 coalbed methane wells in the United States that account for nearly 5% of domestic natural gas production. Production of coalbed methane is widespread in the US; however, production is primarily centered in the San Juan and Black Warrior Basins. The CBM gas is now estimated to account for some 17% of total recoverable gas reserves in the US. Early studies by the Gas Research Institute (GRI) and others estimate the size of the CBM resource base at approximately 400 TCF of gas-in-place for the continental United States. Vast CBM resource potential also exists in many other countries. In some of these countries these resources dwarf the conventional gas potential and may be the only significant hydrocarbons present. Ref. 7 estimates a potential world coalbed gas resource of 4,000 to 7,000 TCF. Coalbeds are naturally fractured, low pressure, water saturated gas reservoirs. The mechanism by which gas is stored and produced in coalbed reservoirs is quite different from sandstone reservoirs. In a conventional sandstone reservoir, gas is stored in the pore space and flows through the pores into the fractures and/or the wellbore In a coal-seam reservoir, while some free gas may exist in the coal deposits, the majority of the gas is adsorbed on the surface of the coal matrix. To produce this gas, the reservoir pressure must be reduced so that the gas can be desorbed and released from the matrix into the fractures. The gas can then migrate through the fractures and coal cleat system and flow into the wellbore. Initially the natural fractures of the coal are typically water saturated. This water has to be removed in order to achieve any significant gas production. Dewatering of the coal seam reduces the hydrostatic pressure of the reservoir, which allows the gas to be desorbed from the coal matrix. At the same time, lowering the water saturation level of the reservoir increases the relative permeability of gas, thereby permitting the desorbed gas to flow to the wellbore. The maximum gas production is achieved when the BHP is minimized. A proper dewatering system is essential for the production of methane from most coalbeds The most common systems for dewatering coalbed methane wells include sucker rod, electric submersible, progressive cavity, and gas lift. These systems have all been used in the field. Each has its own unique advantages for some situations and its own limitations. The advantages and limitations of these methods will be further discussed throughout this paper. This paper presents the theoretical application of the Hydraulic Gas Pump as a new method for dewatering of CBM wells. The operation and the advantages of this method will be discussed. It concludes that the Hydraulic Gas Pump concept can be a suitable dewatering system for coalbed methane wells. P. 73

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Coal Bed Methane Production

Simpson

Lea

Cox

2003

SPE Production and Operations Symposium

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Provided that certain conditions are met, Coalbed Methane (CBM) wells have demonstrated the capacity to continue to produce a significant proportion of their peak production rates at very low reservoir pressures. Low reservoir producing pressures require low bottom-hole and surface pressures. Chief among the conditions for high production rates is being able to manage water at low surface pressure. Minimum-net-positive-suction-head considerations limit artificial-lift options. The dew point at low pressures allows large volumes of water to move as vapor - rendering mechanical separation equipment ineffective and leaving solids behind at inconvenient places. Temperature changes in buried piping condense water vapor and create both corrosion and pipe-efficiency problems. Low separator pressures preclude easy methods to remove liquid water. This paper addresses the design considerations for these low-pressure operations and related artificial lift systems Background Methane adsorbed to the surface of coal is a very old issue with some new commercial ramifications. This methane has made underground coalmines dangerous both from the risk of explosion and from the possibility of an oxygen-poor atmosphere. The miner's main concern with CBM has been how to get rid of it. With the advent of active drilling for CBM in the 1980's, the problems for CBM producers have ranged from the possible inapplicability of D'Arcy's equations to having to develop techniques to remove solids from piping and surface equipment. Coal has most of the characteristics of both source rock and cap rock [3], but few of the required characteristics of reservoir rock. Consequently, we talk about "cleat porosity" and "fracture permeability" and assign largely meaningless values to force the coal to fit our mathematical and numeric models. We talk about the flow constant in the Bureau of Mines Method of Gauging Gas Well Capacity [1] equation (i.e., q=cp (P2-PBH2)n) as being anything but constant (in the San Juan Basin of Northern New Mexico and Southern Colorado you see the cp term changing by 3% to 15% per month). The non-linearity (n) term is generally used as a fudge factor without any real physical explanation for selecting a value or for justifying changing the value. The primary offshoot of the odd behavior of CBM is that the wells retain a significant portion of their peak rates down to very low reservoir pressures. For example, one well produced 10 MMCF/d when reservoir pressure was 1,200 psia and flowing bottom-hole pressure was 125 psia - if "n" is 1.0, then cp is 0.007 MCF/(psi)2. Recently the well was making over 2 MMCF/d with 110 psia reservoir pressure and 30 psia flowing bottom-hole pressure (which would make the current cp equal to 0.179 or 25 times the peak value). The arguments around trying to describe a reason for this behavior have been much more spirited than enlightening. Most CBM fields start with low reservoir pressure, so it is important that wells in these fields see very low producing bottom-hole pressures from first production onward. There has to be a staged approach to achieving these pressures. Surface compression is used either on the gathering system or on the wellhead (or both) to pull wellhead pressures to the lowest possible values. The choice of wellbore tubulars must include minimizing the friction drop up the wellbore. A water lifting/handling strategy must be developed to keep hydrostatic head off the coalface. One strategy that has worked in several fields has been to assign the wellbore tubing to the task of water management and the tubing/casing annulus to the task of gas production. This strategy makes selection of tubing size easier and has been effective for a considerable range of individual-well production. Every CBM field produces some water. The water production ranges from over 300 bbl/MMCF in the northern end of the San Juan Basin to 2–6 bbl/MMCF in many other fields. Production and lift strategies need to be constructed around the requirements of a particular field. For high-water volume wells, many options are available. For more normal water rates, the need for lift is at least as great, but the options are significantly curtailed. A well that has inflow rates of 1 bbl/day above its evaporation-rate will collect over 20 feet of water per day in 7-inch casing - exerting almost 10 psi on the formation. A very few days of adding this kind of pressure to the formation will log a well off, but finding a lift method to move 1 bbl/day is difficult.

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Gas-Lift Technology Applied to Dewatering of Coalbed Methane Wells in the Black Warrior Basin

Cited by 3 publications

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Coal Bed Methane Production

Coal Bed Methane Production

Dewatering of Coalbed Methane Wells with Hydraulic Gas Pump

Coal Bed Methane Production

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