COALBED GAS OPERATIONS FROM THE STATE REGULATORY PERSPECTIVE

• Jurisdiction: United States

Coalbed Gas Development
(Apr 1992)
CHAPTER 6A
COALBED GAS OPERATIONS FROM THE STATE REGULATORY PERSPECTIVE
William A. Keefe
Gorsuch, Kirgis, Campbell, Walker and Grover
Denver, Colorado

When most of the oil and gas conservation statutes were enacted, their application was directed toward more traditional means of exploration and production. Coalbed gas operations do not always neatly fit into traditional molds. As a result, problems can occur in applying these statutes and their underlying regulations to coalbed gas development. This paper will examine some of those problems.

At the outset, it should be noted that the conservation statutes and regulations do seem to apply to coalbed gas operations generally. These acts provide in some manner that their respective regulating commissions have authority to regulate all natural gas operations¹ with natural gas including all gases occurring naturally in the gaseous stage in the

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reservoir.² Notwithstanding such general application, various specific provisions of the statutes and regulations do not apply with such ease to coalbed gas activities. To a large degree, this is due to differences between more traditional oil and gas operations and coalbed gas operations.

Unlike most gas reservoirs where the gas migrated from the source rock to the reservoir rock, coal generally is both the source rock and reservoir for coalbed gas. Permeability of the coalbed gas reservoir depends upon the presence of a natural fracture system, or cleats. Release of the coalbed gas is controlled by diffusion through a solid coal matrix and the rate of release can be difficult to predict without actual coal samples. While small amounts of coalbed gas exist within the cleats dissolved in formation water, most of the gas in coalseams is adsorbed on the surface of the coal matrix where it is held by pressure.

Coalbed gas wells usually are drilled with a rotary rig using a mud based fluid system. Casing the wellbore enables a

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number of vertically stacked coal seams to be accessed. Coalseams often are aquifers with water present in the cleat system. For coalbed gas to be produced, this water must be removed to reduce the hydrostatic pressure. This reduction of pressure will allow the gas to desorb from the coal, diffuse through the coal matrix until it reaches a coal cleat, and move through the cleat system to the wellbore. This gas movement may be enhanced by stimulation procedures such as fracing. In a potentially productive well the water production can actually increase for a period of time.

Spacing

One of the primary functions of the conservation statutes is to provide a means for the spacing of wells in order to avoid waste which could occur if too many wells were drilled and produced. Typically, an operator will make application to the regulating commission requesting that a certain area and formation be spaced. That commission, in deciding whether to grant spacing, will evaluate the evidence introduced at hearing. The statutes provide, however, that the regulating body may not order a drilling and spacing unit which is smaller than the maximum area that can be efficiently and economically drained by one well.³

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For traditional sand reservoirs, the evidence typically introduced to justify spacing will include testimony by a geologist that the formation to be spaced generally underlies the area for which spacing has been requested and testimony by a petroleum engineer as to what are the characteristics of the reservoir being spaced and what is the estimated area within the reservoir that will be drained by one well.

Coalbeds, however, may not always lend themselves to easy definition from a geological perspective. Among the features that may contribute to coalbed heterogeneity are faults and channel-fill sandstones.⁴ The coalseams may interfinger with these sandstones in various different ways.⁵ These and other geological complications can make it much more difficult for the geologist to conclude that a common coalbed formation underlies a given area for which spacing has been requested.

As to oil and gas which is produced from typical sand formations, there are various means by which reservoir engineers are able to determine reserves and drainage areas. These include analyzing well decline curves, making volumetric and material

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balance calculations based upon sand thicknesses and permeabilities and, usually as a last resort due to time and expense, undertaking reservoir simulations. It may be much more difficult however for the reservoir engineer to calculate gas production rates, ultimate reserves and areas of drainage for coalbed gas wells. Whereas a traditional gas well producing from a sand formation may go through a declining production phase almost from commencement of production, a coalbed gas well can pass through three phases of flow, these being the dewatering phase, the stable production phase and the declining production phase.⁶ Due to these different flow characteristics, traditional means of determining drainage such as decline curve analysis and material balance calculations, may not work.⁷ The only reliable method for estimating coalbed methane reserves may be reservoir simulation.⁸ Indeed, the State of New Mexico, Oil Conservation Commission, when considering special field rules for the Basin-Fruitland Coal Gas Pool in San Juan, Rio Arriba, McKinley and Sandoval Counties, specifically found that, based upon evidence presented...