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Process-control engineering is a fairly narrow field of study that has used inconsistent terminology among practitioners. Naturalgas-actuated pneumatic-control equipment has recently become a focus area for regulators trying to reduce the quantity of actual pollutants and greenhouse gases released to the atmosphere. The historical use of inconsistent key terms by experts has led to regulations that are at odds with the realities of existing equipment. The intention of this paper is to begin development of a rigorous set of terms and operational classifications that can help create a framework of knowledge consistent with how this equipment functions. Standardization of terminology has benefits for operators, manufacturers, and regulators alike.

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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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