Fractured Gas Reservoirs Research Articles

Observation and analysis of frequency-dependent anisotropy from a multicomponent VSP at Bluebell-Altamont field, Utah

In this paper, we present results from the analysis of a multicomponent VSP from a fractured gas reservoir in the Bluebell-Altamont Field, Utah. Our analysis is focused on frequency-dependent anisotropy. The four-component shear-wave data are first band-pass filtered into different frequency bands and then rotated to the natural coordinates so that the fast and slow shear-waves are effectively separated. We find that the polarisations of the fast shear-waves are almost constant over the whole depth interval, and show no apparent variation with frequency. In contrast, the time delays between the split shear-waves decrease as the frequency increases. A linear regression is then applied to fit the time-delay variations in the target and we find that the gradients of linear fits to time delays show a decrease as frequency increases. Finally, we apply a time-frequency analysis method based on the wavelet transform with a Morlet wavelet to the data. The variation of shear-wave time delays with frequency is highlighted in the time-delay and frequency spectra. We also discuss two mechanisms giving rise to dispersion and frequency-dependent anisotropy, which are likely to explain the observation. These are scattering of seismic waves by preferentially aligned inhomogeneneities, such as fractures or fine layers, and fluid flow in porous rocks with micro-cracks and macro-fractures.

P‐wave velocity and permeability distribution of sandstones from a fractured tight gas reservoir

Fractures are an important fabric element in many tight gas reservoirs because they provide the necessary channels for fluid flow in rocks which usually have low matrix permeabilities. Several sandstone samples of such a reservoir type were chosen for a combined study of rock fabric elements and petrophysical properties. Geological investigations of the distribution and orientation of the fractures and sedimentary layering were performed. In addition, laboratory measurements were carried out to determine the directional dependence of the permeability and P‐wave velocities. Higher permeability values are generally in the plane of the nearly horizontal sedimentary layering with regard to the core axis. With the occurrence of subvertical fractures, however, the highest permeabilities were determined to be parallel to the core axis.Compressional wave velocities were measured on spherical samples in more than 100 directions to get the VPsymmetry without prior assumptions. Below 50 MPa confining pressure, all samples show a monoclinic symmetry of the P wave velocity distribution, caused by sedimentary layering, fractures, and crossbedding. At higher confining pressure, sedimentary layering is approximately the only effective fabric element, resulting in a more transverse isotropic VPsymmetry. Using the geological‐petrophysical model introduced here, the complex symmetry of the VPdistributions can only be explained by the rock fabric elements. Furthermore, water saturation increases the velocities and decreases the anisotropy but does not change VPsymmetry. This indicates that at this state, all fabric elements, including the fractures, have an influence on P‐wave velocity distribution.

ABSTRACT: Integrating Surface, Subsurface and Seismic Data with Geomechanical Modeling to Predict Areas of Increased Permeability in Naturally Fractured Gas Reservoirs

ABSTRACT: Integrating Surface, Subsurface and Seismic Data with Geomechanical Modeling to Predict Areas of Increased Permeability in Naturally Fractured Gas Reservoirs

Flow of Coal-Bed Methane to a Gallery

Coal-seam methane reservoirs have a number of unique feature compared to conventional porous or fractured gas reservoirs. We propose a simplified mathematical model of methane movement in a coal seam taking into account the following features: a relatively regular cleat system, adsorptive methane storage, an extremely slow mechanism of methane release from the coal matrix into cleats and a significant change of permeability due to desorption. Parameters of the model have been combined into a few dimensionless complexes which are estimated to an order of magnitude. The simplicity of the model allows us to fully investigate the influence of each parameter on the production characteristics of the coal seam. We show that the reference time of methane release from the coal matrix into cleats – the parameter which is most poorly investigated – may have a critical influence on the overall methane production.

Detection of fracture orientation using azimuthal variation ofP-wave AVO responses

Azimuthally dependent P-wave amplitude variation with offset (AVO) responses can be related theoretically to open fracture orientation and have been suggested as a geophysical tool to identify fracture orientation in fractured oil and gas reservoirs. A field experiment conducted recently over a fractured reservoir in the Barinas Basin, Venezuela provides data for an excellent test of this approach. Three lines of data were collected in three different azimuths, and three component receivers were used. The distribution of fractures in this reservoir was obtained previously using measurements of shear‐wave splitting from P-S converted waves from the same data set. In this work, we use P-wave data to see if the data can yield the same information using azimuthal variation of P-wave AVO responses. Results obtained from the azimuthal P-wave AVO analysis corroborate the fracture orientation obtained previously using P-S converted waves. This analysis with field data is an example of the high potential of P-waves to detect fracture effects on seismic wave propagation.

P-wave andS-wave azimuthal anisotropy at a naturally fractured gas reservoir, Bluebell‐Altamont Field, Utah

Reflection P- and S-wave data were used in an investigation to determine the relative merits and strengths of these two data sets to characterize a naturally fractured gas reservoir in the Tertiary Upper Green River formation. The objective is to evaluate the viability of P-wave seismic to detect the presence of gas‐filled fractures, estimate fracture density and orientation, and compare the results with estimates obtained from the S-wave data. The P-wave response to vertical fractures must be evaluated at different source‐receiver azimuths (travelpaths) relative to fracture strike. Two perpendicular lines of multicomponent reflection data were acquired approximately parallel and normal to the dominant strike of Upper Green River fractures as obtained from outcrop, core analysis, and borehole image logs. The P-wave amplitude response is extracted from prestack amplitude variation with offset (AVO) analysis, which is compared to isotropic‐model AVO responses of gas sand versus brine sand in the Upper Green River. A nine‐component vertical seismic profile (VSP) was also obtained for calibration of S-wave reflections with P-wave reflections, and support of reflection S-wave results. The direction of the fast (S1) shear‐wave component from the reflection data and the VSP coincides with the northwest orientation of Upper Green River fractures, and the direction of maximum horizontal in‐situ stress as determined from borehole ellipticity logs. Significant differences were observed in the P-wave AVO gradient measured parallel and perpendicular to the orientation of Upper Green River fractures. Positive AVO gradients were associated with gas‐producing fractured intervals for propagation normal to fractures. AVO gradients measured normal to fractures at known waterwet zones were near zero or negative. A proportional relationship was observed between the azimuthal variation of the P-wave AVO gradient as measured at the tops of fractured intervals, and the fractional difference between the vertical traveltimes of split S-waves (the “S-wave anisotropy”) of the intervals.

Production of Gas From Tight Naturally Fractured Reservoirs With Active Water

Abstract There are numerous examples of tight naturally fractured gas reservoirs with active water in the foothills of Alberta and northeastern British Columbia. Examples include the Pincher Creek field in Alberta and the Bucking Horse, Pocketknife, Sikanni and Grassy fields in British Columbia. Recovery factor is typically low from this type of reservoir due to water production. The problem is frequently attributed to coning, but coning may actually playa minor role. In fact, the gas/water contact in the fracture system may be relatively flat Initial gas recovery com.. prises gas displaced from fractures plus pressure depletion from the matrix. The amount of pressure depletion in the matrix is a function of structural relief above the original gas/water contact Subsequent gas recovery is an imbibition process, which may be very slow. Laboratory work, conducted at the TIPM Laboratory on behalf of Husky, demonstrates that water will continue to imbibe into tight matrix rock submerged under water for months. This work implies that the best operating strategy may be to produce the wells at the highest rates possible until water breakthrough, followed by a shut-in period of perhaps several years to allow gas to re-accumulate. Introduction Significant gas reserves are contained in structured Mississippian-age reservoirs along the eastern foothills of the Rocky Mountains. Equivalent formation names include Livingstone, Turner Valley and Debolt (from southern Alberta through northeastern British Columbia). Matrix permeability in these reservoirs is often insufficient to support commercial production rates. Fortunately, natural fracturing enhances reservoir permeability, and many foothills gas reservoirs are intensely fractured. Fracturing results from post-depositional thrusting. Prolific wells can be drilled where fracture intensity is greatest, usually along the hinge of a folded structure. In most cases, these reservoirs overlie inactive aquifers. Recovery is simply a function of abandonment pressure, which is in turn a function of the minimum economic production rate. Recovery is typically greater than 80% of original gas-in-place. Aquifer influx can have a devastating influence on recovery, however. Recovery from a reservoir overlying an active aquifer may be less than 20% of the original gas-in-place. Wells may waterout very abruptly. The problem is often blamed on coning or channelling. Fractures are mistakenly seen as preferential conduits, or "pipelines" into the water leg. With this view, gel treatments, rate restrictions, and plug-backs may be implemented to reduce water production; almost always unsuccessfully. Our premise is that the problem is not caused by coning or channelling. Fractures are planar; not tubular. Even in a vertical fracture, horizontal permeability along the plane of the fracture is approximately equal to vertical permeability. Fractures are not preferential conduits into the water leg. Furthermore, the viscosity of gas is typically two orders of magnitude less than the viscosity of water, and the density of gas at reservoir conditions may be an order of magnitude lower than the density of water. Therefore, extremely high pressure gradients would be required to generate a small cone in a permeable fracture system. Rather, in most cases, gas is efficiently displaced from the fractures as the free gas/water contact rises uniformly across the pool.

Detection and analysis of naturally fractured gas reservoirs: Multiazimuth seismic surveys in the Wind River basin, Wyoming

Multiazimuth binning of 3-D P-wave reflection data is a relatively simple but robust way of characterizing the spatial distribution of gas‐producing natural fractures. In our survey, data were divided into two volumes by ray azimuth (approximately perpendicular and parallel (±45° to the dominant fracture strike) and separately processed. Azimuthal differences or ratios of attributes provided a rough measure of anisotropy. Improved imaging was also attained in the more coherent fracture‐parallel volume. A neural network using azimuthally dependent velocity, reflectivity, and frequency attributes identified commercial gas wells with greater than 85% success. Furthermore, we were able to interpret the physical mechanisms of most of these correlations and so better generalize the approach. The apparent velocity anisotropy was compared to that derived from other P- and S-wave methods in an inset three‐component survey. Prestack determination of the azimuthal moveout ellipse will best quantify velocity anisotropy, but simple two‐ or four‐azimuth poststack analysis can adequately identify regions of high fracture density and gas yield.

The Study of a Naturally Fractured Gas Reservoir Using Seismic Techniques

The upper Green River Formation at the Bluebell-Altamont field, Utah (Figure 1) is a tight gas sand reservoir where economic production can be sustained only in regions of high natural fracturing. In 1994, a demonstration seismic project was conducted at the field to show how exploration for, and the characterization of, naturally fractured gas reservoirs can be more effective through the integrated use of seismic techniques. Study of field exposures, well logs, and regional stress indicators prior to the seismic survey indicated a high degree of preferential orientation to the dominant fracture trend at the field. The seismic survey consisted of two crossing, nine-component surface seismic lines and a nine-component vertical seismic profile. The compression, and shear-wave surface seismic both recorded anisotropies that were related to the presence and azimuth of the natural fracturing. The surface seismic results were supported by results from the nine-component vertical seismic profile. This program demonstrates the potential offered by the use of integrated seismic and geological techniques for the analysis of both land and marine naturally fractured reservoirs; furthermore, it demonstrates the possibilities of reviewing existing databases containing compression-wave surface seismic data for fracture information.

Fracture-related amplitude variations with offset and azimuth in marine seismic data

Fractures are of great interest for hydrocarbon production. In particular, they can provide conduits for fluid flow, hence knowledge of their distribution and orientation can be critical, especially for horizontal wells. Unfortunately, most fractures are relatively small, and well beyond the imaging range of conventional seismic data. On the other hand, it is increasingly recognized that fractures do have a strong influence on shear-wave energy (S waves). Indeed, amplitude variations in stacked (qS2) shear-wave data have successfully been used to identify productive fracture clusters in the Austin Chalk formation in Texas (Mueller 1991). Although seismic information on fracturing is most readily obtained from shear waves, direct measurements of shear-wave energy require both specialized sources and multicomponent receivers, and are not feasible in marine environments, except perhaps at the sea floor. Of importance is the fact that fractures have an impact on the entire seismic wavefield, with the imprint of the fracture symmetries leading to a general azimuthal behaviour. As a result, although compressional (P) waves are relatively insensitive to fracturing at near offsets, they can become linked to the larger effects experienced by the shear-waves through mode conversion at oblique incidence, and also through their own specific sensitivity. Thus, it is feasible that anisotropic variations in P-wave behaviour can provide a way of obtaining information on fracture properties at subseismic scales. (MacBeth 1995). This then offers a potential means of studying fracture distributions and orientations in marine areas. In this paper we present evidence to show that information on both the presence and nature of fractures can be obtained from conventional marine (i>P-wave) seismic data using AVO (amplitude variation with offset) analysis. In particular, our results demonstrate that fracture-related AVO has a distinct anisotropic (directional) behaviour that can be linked directly to the azimuthal orientation of the fractures. Indeed, this is consistent with the numerical study of Mallick & Frazer (1991), and has previously been observed in land data for a variety of fractured gas reservoirs (Lynn et al. 1996). However, to our knowledge, the results given in this paper constitute the first example of this phenomenon for a marine dataset.

An Efficient Boundary Integral Formulation for Flow Through Fractured Porous Media

In this paper we present a new model for flow in fractured porous media. We formulate our model in terms of a coupled system of boundary integral equations and present an efficient procedure for solving the equations using the boundary element method. In the new model, the flow in the matrix is governed by the usual Darcy law for porous media, with the fractures being treated as planar sources embedded in the matrix. The flow in an individual fracture is governed by a two-dimensional Darcy law (as in a Hele–Shaw cell), with an associated planar sink distribution. The essential feature of this approach is that the fractures are treated as special planes rather than narrow-gap voids. The error in the resulting system of equations is on the order of an intrinsic dimensionless parameter (the ratio of the fracture gap size to the scale of the volume under consideration). We also describe how we adapt the new model to compute effective grid block permeabilities. This was the principal motivation behind the development of the new model. Using effective grid block permeabilities to model flow in fractured oil and gas reservoirs is a much more efficient process than modeling the flow when every fracture is precisely represented. We present some numerical examples that illustrate the new flow model and how it is used to model flow in a reservoir.

Fracture detection using crosswell and single well surveys

We recorded high‐resolution (1 to 10 kHz), crosswell and single well seismic data in a shallow (15 to 35 m), water‐saturated, fractured limestone sequence at Conoco's borehole test facility near Newkirk, Oklahoma. Our objective was to develop seismic methodologies for imaging gas‐filled fractures in naturally fractured gas reservoirs. The crosswell (1/4 m receiver spacing, 50 to 100 m well separation) surveys used a piezoelectric source and hydrophones before, during, and after an air injection that we designed to displace water from a fracture zone. Our intent was to increase the visibility of the fracture zone to seismic imaging and to confirm previous hydrologic data that indicated a preferred pathway. For the single well seismic imaging (a piezoelectric source and an eight‐element hydrophone array at 1/4 m spacing), we also recorded data before and after the air injection. The crosswell results indicate that the air did follow a preferred pathway that was predicted by hydrologic modeling. In addition, the single well seismic imaging using vertical common depth‐point (CDP) gathers indicated an anomaly consistent with the anomaly location of crosswell and hydrologic inversion results. Following the field tests, a slant well was drilled and cored to confirm the existence and nature of the rock associated with the seismic anomalies. A vertical fracture was intersected within less than 1 m of where the seismic results had predicted.

Guest editors’ introduction to this issue

The idea for this special issue of The Leading Edge came from a symposium last October in Houston, on technology development for fractured tight gas reservoirs. The symposium, cohosted by the Morgantown Energy Technology Center of the Department of Energy, the Geophysical Society of Houston, and Amoco Production Company, generated a good deal of interest among the earth sciences community. Presentations were made on the six research projects funded by the DOE/METC, under the direction of Royal Watts. Several poster papers on geophysical investigation of fractured reservoirs were given by Amoco Production, which has long been interested in naturally‐fractured reservoirs.

Utilizing crosswell, single well and pressure transient tests for characterizing fractured gas reservoirs

As part of its Department of Energy (DOE)/Industry cooperative program in oil and gas, Berkeley Lab has an ongoing effort in cooperation with Conoco and Amoco to develop equipment, field techniques, and interpretational methods to further the practice of characterizing naturally fractured, heterogeneous reservoirs. The focus of the project is an interdisciplinary approach, involving geology, rock physics, geophysics, and reservoir engineering. The goal is to combine the various methods into a unified approach for predicting fluid migration.

The Antrim Shale, Fractured Gas Reservoirs with Immense Potential: ABSTRACT

The Antrim Shale, Fractured Gas Reservoirs with Immense Potential: ABSTRACT

Fractured Shale Reservoirs: Towards a Realistic Model: ABSTRACT

Fractured shale reservoirs are fundamentally unconventional, which is to say that their behavior is qualitatively different from reservoirs characterized by intergranular pore space. Attempts to analyze fractured shale reservoirs are essentially misleading. Reliance on such models can have only negative results for fractured shale oil and gas exploration and development. A realistic model of fractured shale reservoirs begins with the history of the shale as a hydrocarbon source rock. Minimum levels of both kerogen concentration and thermal maturity are required for effective hydrocarbon generation. Hydrocarbon generation results in overpressuring of the shale. At some critical level of repressuring, the shale fractures in the ambient stress field. This primary natural fracture system is fundamental to the future behavior of the fractured shale gas reservoir. The fractures facilitate primary migration of oil and gas out of the shale and into the basin. In this process, all connate water is expelled, leaving the fractured shale oil-wet and saturated with oil and gas. What fluids are eventually produced from the fractured shale depends on the consequent structural and geochemical history. As long as the shale remains hot, oil production may be obtained. (e.g. Bakken Shale, Green River Shale). If the shale is significantly cooled,more » mainly gas will be produced (e.g. Antrim Shale, Ohio Shale, New Albany Shale). Where secondary natural fracture systems are developed and connect the shale to aquifers or to surface recharge, the fractured shale will also produce water (e.g. Antrim Shale, Indiana New Albany Shale).« less

Geochemical Constraints on Microbial Methanogenesis in an Unconventional Gas Reservoir: Devonian Antrim Shale, MI: ABSTRACT

The Upper Devonian Antrim Shale is a self-sourced, highly fractured gas reservoir. It subcrops around the margin of the Michigan Basin below Pleistocene glacial drift, which has served as a source of meteoric recharge to the unit. The Antrim Shale is organic-rich (>10% total organic carbon), hydrogen-rich (Type I kerogen) and thermally immature (R[sub o] = 0.4 to 0.6). Reserve estimates range from 4-8 Tcf, based on assumptions of a thermogenic gas play. Chemical and isotopic properties measured in the formation waters show significant regional variations and probably delineate zones of increased fluid flow controlled by the fracture network. [sup 14]C determinations on dissolved inorganic carbon indicate that freshwater recharge occurred during the period between the last glacial advance and the present. The isotopic composition of Antrim methane ([delta][sup 13]C = -49 to -59[per thousand]) has been used to suggest that the gas is of early thermogenic origin. However, the highly positive carbon of co-produced CO[sub 2] gas ([delta][sup 13]C [approximately] +22[per thousand]) and DIC in associated Antrim brines ([delta][sup 13]C = +19 to +31[per thousand]) are consistent with bacterially mediated fractionation. The correlation of deuterium in methane ([delta]D = -200 to -260[per thousand]) with that of the co-produced watersmore » (SD = -20 to -90176) suggests that the major source of this microbial gas is via the CO[sub 2] reduction pathway within the reservoir. Chemical and isotopic results also demonstrate a significant (up to 25%) component of thermogenic gas as the production interval depth increases. The connection between the timing of groundwater recharge, hydrogeochemistry and gas production within the Antrim Shale, Michigan Basin, is likely not unique and may find application to similar resources elsewhere.« less

The Use of 3-D Seismic in the Understanding and Monitoring of Waterflooding in a Naturally Fractured Gas Reservoir: ABSTRACT

The reservoir of the Meillon field (France) consists of vuggy limestone with natural fractures. Three different sets of fractures occur in the reservoir. A few years after the field was put on production, several wells located 700 m above the initial gas/water contact started producing water. Flow simulation with a dual porosity model indicated that water bypasses most of the matrix gas by flowing in the fractures. Assuming that the production mechanism was understood, the organization of open fractures in the reservoir was poorly determined since a 3-D seismic interpretation provided a structural picture of the field. To improve the characterization of the field's dynamic behavior, a multidisciplinary study was performed to integrate results from well-test interpretation, production logging, core analyses and drilling fluid losses with production history, and 3-D seismic interpretation. A study of fractures at different scales showed that major faults (determined from seismic) are the dominant control on water flooding.

Isochronal Testing of a Naturally Fractured Gas Reservoir:A Case History

Abstract Isochronal, modified isochronal, and LIT testing are used routinely as a basis to forecast deliverability of gas reservoirs. This paper shows an application of this technique to the naturally fractured Palm Valley gas field in central Australia. Results are corroborated with the use of a dual-porosity numerical simulator. The initial isochronal tests of four wells are presented together with the deliverability equations. This is followed by a comparison with 40 months of production history. The data show, that values of C in the Rawlins and Schellardt equation have been declining continuously for all four wells throughout the 40 months of production history. The conclusion reached is that conventional isochronal test analysis and a constant value of C are not reliable to forecast deliverability of gas wells in naturally fractured reservoirs. Use of this approach can easily lead to optimistic forecasts. Introduction The Palm Valley Gas Field is situated in the central-northern Amadeus Basin, Northern Territory, Australia (Figure I), approximately 120 km southwest of Alice Springs. Geologically the structure has been defined as an arcuate anticline mapped from surface expression and seismic data (Figure 2). The amount of seismic data, however, is very limited due to the very rough surface topography. Although the western and eastern plunges are thus poorly defined, the anticline axis can be traced for over 40km. A stratigraphic column of the Amadeus Basin including distribution of gas reservoirs in the Palm Valley Field is presented on Figure 3. Gas has been found in the lower Stairway sandstone, the basal Horn Valley siltstone, and the Pacoota sandstone, all within the Larapinta Group of Ordovician Age. These reservoir units can be summarized as follows: The Stairway Sandstone varies in thickness between 295 and 310 m (969 and 1018 ft.). It is a shallow, intertidal marine sequence of sandstones siltstones and shales. A basal quartizitic unit of approximately 40 m (130 fl.). It is occasionally pyritised and fractured, and has associated good gas production. FIGURE 1: Location map of the Palm Valley gas field. Illustrations available in full paper. FIGURE 2: Palm Valley field - Top Pacoota structure showing location of gas pipelines. Illustrations available in full paper. FIGURE 3: Stratigraphic column of the Amadeus Basin including distribution of gas reservoirs in the Palm Valley field. Illustrations available in full paper. The sandstones, also termed orthoquartzites, are generally very line to fine, and once in a while medium to coarse grained. The siltstones are partially sandy, dark grey to black, micromicaceous-hard and generally silteified. The shales are dark brittle and hard. The horn Valley Siltstone consists of siltstone and shale with thin interbeds of limestone and dolomite. The formation was deposited on a shallow marine shelf and ranges in thickness between 100 and 114 m (330 and 375 ft). A limestone and dolomite layer 3m (10,15 ft) thick at the base of the formation is gas productive in Palm Valley 1. The Pacoota Sandstone, the main gas bearing reservoir, lies conformably below the Horn Valley Siltstone. It consists of nearshore, marine, interbedded sandstones, siltstones, and shales.

Long-Term Gas Deliverability of a Dewatered Coalbed

Summary Gas and water production from a coal deposit can be divided into three distinct stages. In the first, gas and water production rates are almost constant. The second stage, beginning production rates are almost constant. The second stage, beginning once pseudosteady state is reached, is characterized by a "negative decline" in gas production rate and a declining water rate. The third stage begins when the peak gas rate is reached. This final stage spans most of the economic life of a coal well and is characterized by a gentle decline in gas rate and negligible water production. Gas production in this stage is described by two production. Gas production in this stage is described by two equations. The first is a gas-deliverability equation using the real-gas pseudo pressure developed by Al-Hussainy et al. This equation is applied to published data from a well in the Deerlick Creek field in the Warrior basin of Alabama. The second is a mass-balance equation combining elements from conventional and shale gas reservoirs. The two equations can be coupled to predict gas rates and recoveries of dewatered coal wells. Published simulation results from the Warrior basin Brookwood field and a San Juan basin coal well are compared. The deliverability equation also is used to construct gas-deliverability curves for a typical Brookwood coal well. The method presented here is applicable to coal wells completed in dry coalbeds. Introduction An important characteristic of a gas well is its deliverability over the course of reservoir depletion. A considerable body of literature describes conventional gas-well behavior mathematically. Theoretical aspects of wells completed in conventional dry gas reservoirs have been discussed thoroughly. Gas flow in porous media can be described by three methods: pressure, pressure-squared, and the real-gas pseudo pressure of Al-Hussainy et al. and Al-Hussainy and Ramey. While the last method is more cumbersome to use than the first two, it is more rigorous and is the only reliable method when large drawdowns exist. This paper shows that the traditional real-gas pseudo pressure can be extended to describe gas deliverability of a dewatered coal well. Coal deposits are naturally fractured gas reservoirs. Initially, the natural fractures, or cleats, of the coal typically are water saturated and the coal matrix adsorbs most, if not all, of the gas. Coal gas is mostly methane with minor amounts of CO2, nitrogen, and heavier hydrocarbons, similar to dry natural gas from conventional reservoirs. Wells completed in coal deposits progress through three distinct stages, as Fig. 1 illustrates. In the first stage, gas and water production rates are almost constant. The second stage is characterized by a negative decline in gas production rate and a declining water rate. Once the peak gas rate is attained, the third stage of production begins where the gas production rate shows a gentle decline and water production is often negligible. This final stage spans most of the economic life of a coal well.