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Difference between revisions of "Reserves estimation of coalbed methane"

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[[Category:5.8.3 Coal seam gas]][[Category:5.7.1 Estimates of resource in place]]
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Revision as of 13:19, 16 July 2015

Coalbed methane discusses the development of coal deposits in the US and around the world for recovery of natural gas. Such natural gas is predominantly methane, but it also may contain small amounts of:

  • Ethane
  • Carbon dioxide
  • Nitrogen

Coalbed methane (CBM) is adsorbed onto the coal surfaces exposed through the matrix microporosity and the naturally occurring fracture or cleat system. This cleat system typically is water-filled, often with fresh or slightly saline water, but may also contain some free gas.

Estimate of gas-in-place

Calculation of gas-in-place for a unit volume of the coal layers being developed does not follow the “porous media” approach of determining effective:

  • Porosity
  • Saturations
  • Pressures
  • Temperatures
  • Gas quality

Instead, the gas-in-place is measured physically through the recovery of coal samples, the number and distribution of which are important to the estimation of total gas in place pertinent to the property being evaluated.

Cored samples are transferred carefully from the core barrel to canisters, which are sealed immediately and transported to an analysis laboratory. In analysis, two measurements are taken. First, free gas in the canister is measured, and then the coal sample is crushed and the liberated gas measured. These two measurements are combined with an estimate of gas lost during the core recovery operation. The lost gas volume is estimated as a function of the coal type and depth of burial and other factors. Total gas in place is calculated as the product of the unit gas in place—considering areal variations—and the mapped volume of the coal seams being developed.

A volumetric estimate of gas-in-place (GIP) (scf) in coalbed reservoirs can be calculated by[1]

RTENOTITLE....................(1)

The first term in the square brackets of Eq. 1 is used to calculate the gas volume contained in the interconnected fracture or cleat system (if any) and is identical to the term used for porous media reservoirs. The second term in the square brackets is used to calculate the adsorbed gas in the coal matrix. The adsorbed gas quantity results from laboratory measurements of the adsorbed gas in a unit of dry, ash-free coal and other coal-quality factors.

Consideration of reserves estimation

In most cases, cleat porosity is water-filled, so that the free gas therein essentially is zero. Most engineers ignore the gas volume in solution in the water.

Most of the data on which the reservoir engineer must rely is gathered through core analysis, fluid analyses, and well tests. Table 1 presents certain pertinent data items and primary sources for each item.[1]

Seismic data historically has not been used in CBM project analysis because most of these projects have been in areas that had an abundance of subsurface data obtained as a result of either:

  • Underground mining (e.g., the Black Warrior basin)
  • Oil and gas wells drilled to deeper objectives (e.g., the San Juan basin)

As the industry advances into areas with a dearth of existing subsurface information, seismic information is expected to become more important in determining reservoir extent and structure. Section sequence is not intended to convey authors’ views of relative importance.

Reserves estimates (REs), typically up to 75% GIP, are related to well density, the degree of naturally occurring fractures, the effectiveness of wellbore hydraulic fracturing programs, and the ability to “dewater” the reservoir to reduce the reservoir pressure to a level where desorption can be effective. Laboratory measurements can be used to develop composited desorption isotherms, which are useful in estimating the rate of gas liberation while reservoir pressure is reduced.

Proved reserves can be assigned to an area where wells have been drilled and have demonstrated that commercial gas rates can be maintained. Well spacing in the US ranges from approximately 40 to 160 acres per well. For coalbed projects in areas remote from comparable analog operations, the time to confirm commerciality may be as long as several years. Some projects dewater quickly, allowing commercial gas rates to be attained early; other projects might prove to be noncommercial because of dewatering failure. A cluster of wells might need to create a pressure sink large enough to overcome the influx of water from a large aquifer. High permeability, together with a large aquifer, might create enough water influx to cause project failure.

Fig. 1[1] illustrates a typical individual well decline curve exhibiting a 2-year period of dewatering that is characterized by increasing gas production rates. An exponential trend has been drawn through the approximate 1-year decline period.

Confidence in the forecast would increase if there were nearby analog wells with more production history supporting the exponential projection. Lacking such support, however, the projection should be confirmed through volumetric means before booking the forecast volumes as proved reserves. Many (perhaps most) coalbed wells producing from coal that has low to moderate permeability will exhibit a wide range of hyperbolic declines, underscoring the need for suitable analogs.

Type curves (production vs. time) from successful analog operations are the most useful tools for predicting the production profile and reserves for completed wells. As in traditional reserves estimation, volumetric reserves estimates should be checked against performance-driven reserves estimates.

Assigning of proved undeveloped reserves to coalbed projects usually should be restricted to the “one-offset” limitation imposed by the 1978 U.S. SEC definitions, unless the engineer can demonstrate “certainty of production” beyond the one-offset location. The 1997 SPE/WPC definitions may, in some circumstances, permit a larger area to be classified as proved, but one should be cautious until both the presence of coal of commercial thickness and adequate permeability are determined with reasonable certainty.

Probable and possible reserves typically are assigned to acreage at increasing distances from the commercially developed portion of the project.

Nomenclature

A = area of reservoir or accumulation, acre
Bgi = initial formation volume factor, gas, Rcf/scf or RB/scf
Cgi = initial sorbed gas concentration, scf/ton, dry, ash-free coal or shale
fa = average weight fraction of ash, fraction
fm = average weight fraction of moisture, fraction
Gi = gas-in-place at initial reservoir conditions, scf
h = thickness, ft
Swfi = interconnected fracture water saturation, fraction
ρc = density, coal, g/cm3
Фf = interconnected fracture (effective) porosity, fraction

References

  1. 1.0 1.1 1.2 1.3 Zuber, M.D. 1996. A Guide to Coalbed Methane Reservoir Engineering. Gas Research Inst. Chicago, Illinois: (Gas Technology Inst.), GRI-93/0293.

Noteworthy papers in OnePetro

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External links

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See also

PEH:Estimation_of_Primary_Reserves_of_Crude_Oil,_Natural_Gas,_and_Condensate

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