Recently, considerable attention has been focused on the long term potential of natural gas. Studies have included resources that range from conventional gas in Stratigraphie traps to unconventional gas locked in hydrates. However, these studies have overlooked one large and potentially productive gas resource — the methane stored in deep coal seams. Currently, the conventional wisdom is that coals below 5.0 feet will be extremely low in permeability and thus unproductive. This viewpoint stems from the early laboratory based tests of confining pressure (depth) versus permeability and from the initial field tests in the deeper portions of the Piceance Basin, U.S.A. Recent basin studies show that the resource potential in deep coal basins is considerable, both in the U.S. and worldwide. For example, in the U.S. the bulk of the 84 Tcf of coalbed methane contained in the Piceance Basin is in deep coals, below 5.0 feet. Even larger amounts of gas exist in deep coal seams in Alberta, Canada and other deep coal basins of the world. Also, comparisons of laboratory based permeability tests on coal with field results indicate that the lab tests may be unduly pessimistic. While the evidence that deep coals can be economically productive is limited, some data is now available and discussed in this paper. For example:An experimental completion of a Cretaceous age coal seam at 10,0 feet in the Deep Basin of Alberta, showed that deep coals contain substantial methane, that gas can be produced from such depths, but that the well completions are very challenging.A recently drilled 6,000 foot deep well at Piny on Ridge (Northern Piceance Basin) had an initial gas flow of nearly a million cubic feet per day. The purpose of this paper is to examine the resource and production potential of deep coal seams and thus add this resource to the list of long-term sources of natural gas.

Introduction Low permeability gas reservoirs are currently being developed in numerous basins in the United States and Canada. Typical reservoirs contain 25 to 100 net feet of gas pay, gas porosities ranging from 3 to 8 percent, original reservoir pressures from 1500 to 15,000 psi and formation gas permeabilities that range from .001 to 1.0 md. Considering these wide ranges in formation properties, it is of primary concern to determine the properties, it is of primary concern to determine the economic optimum well spacing and fracture length for a particular formation. Numerous publications in recent years have proposed and documented the use of massive hydraulic fracturing techniques for stimulating tight gas reservoirs. As a result of the success of massive hydraulic fracturing, the average size of a typical treatment has been increasing. As the propped fractured length is increased, the initial flow rate and the ultimate recovery from a well are usually increased. This does not mean, however, that the bigger the fracture treatment the better. For any given set of reservoir parameters, an economic optimum fracture length can be parameters, an economic optimum fracture length can be calculated. If the induced fracture actually created in a well is greater than the economic optimum length, the well performance may be better but the profit from the well can be reduced. To determine the optimum fracture length and well spacing in a given reservoir, it is necessary to (1) predict propped fracture length as a function of fracturing costs, (2) predict well performance as a function of fracture length and (3) performance as a function of fracture length and (3) to perform present value economic calculations considering well costs, operating costs, fracturing costs and well performance. After these calculations are made, graphs of present value profit versus fracture length for various well spacings can be constructed. Such graphs can be used to determine the optimum economic values of well spacing and fracture length for a given reservoir. The objectives of this paper are to present a simple technique for optimizing profit from a tight gas reservoir and to present several examples which illustrate the utility of the proposed method. THE OPTIMIZATION MODEL A computer model, FRACOP, was written to solve this problem. The model combines the fracture length problem. The model combines the fracture length calculations of Geertsma and de Klerk, reservoir performance calculations using the analytical solutions of performance calculations using the analytical solutions of Gringarten et al. and a present value economic analysis. The computer model requires minimum storage, minimum computing time and is well suited for use on a time-share computing system. Fracture Length Calculations The equations of Geertsma and de Klerk, for vertical fractures, were used to calculate the created fracture dimensions. The fracture length calculations in FRACOP are very similar to a model built for designing stable foam fracturing treatments. Non-Newtonian fracturing fluids can be simulated by inputting values of n' and K' for the specified fluid. The program uses the following equation to calculate the apparent viscosity of the fluid in the fracture. (1) Then using Eq. 1 and Eqs. 7a and 21a in ref. 4, the model simultaneously solves for width, length and viscosity. Sand transport is not included in FRACOP. The total volume of the fracturing treatment is, however, corrected for the volume of sand. The propped fracture length is determined by first calculating the volume of pad that is still in the fracture at the end of the pad that is still in the fracture at the end of the treatment. This volume represents the initial pad volume minus the volume lost to the formation due to spurt and fluid loss. By assuming the remaining pad volume occupies the far end of the fracture, the propped fracture length is the distance from the wellbore to the pad remaining in the fracture.

The special techniques described here appear to be promising for determining precise quantitative residual oil saturations - under certain reservoir conditions. A field test of one method was encouraging. The PNC logs showed saturations that agreed with other measurements, and the degree of uncertainty in the estimates approached theoretical expectations. Purpose and Scope The basic physical principles of pulsed neutron capture (PNC) logging and descriptions of logging instrumentation and operation have been documented in earlier publications.3,4 In addition, several methods of PNC data interpretation for petroleum engineering applications have appeared in the literature.6 These latter reports demonstrate that PNC logging has become a valuable technique for formation evaluation. The most significant use of PNC logging has been to discriminate among gas-bearing, oil-bearing, and salt-water-bearing formations in cased holes. For example, gas-oil, gas-water, and oil-water contacts have been found and followed. Unsuspected hydrocarbon migration between zones also has been detected. In addition, water saturations have been calculated from PNC log data when porosity, rock type, formation hydrocarbon type, and formation water salinity were known or could be estimated. Interpretations of PNC log data are often precise enough for decisions regarding recompletion or for a qualitative assessment of reservoir mechanism and performance. But how useful are these data when we must decide whether or not to conduct a tertiary recovery project in the flooded-out portion of a reservoir? In comparison with waterflooding, tertiary recovery is more complicated; thus its performance is harder to predict. Also, the process costs are higher, so there is much less margin for error. Therefore, many of the parameters must be measured with great accuracy for designing a tertiary recovery project. One of the most important parameters is the residual oil saturation - the target for profit. A decision to undertake a tertiary recovery project could depend entirely on the estimate of residual oil saturation and the margin of error associated with the estimate. Minimum expected errors in oil saturation and saturation distribution (among other parameters) are essential for a tertiary recovery project. The purpose of this paper is to describe in some detail the possibility of using PNC data to estimate more precisely the residual oil saturation remaining at the end of a waterflood (either natural or induced).

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Summary A tight gas sand with 1-µd permeability was produced, after a large hydraulic foam fracture, at rates close to predicted values. The rates of about 300 Mcf/D (8495m3/d) after 23 days would not bear the cost of development at 1979 Canadian prices. However, it is estimated that, with higher netbacks and longer fractures, commercial development would be feasible. Introduction The Elmworth gas field is located within the Deep basin near Grande Prairie, Alberta (Fig. 1). The Deep basin covers about 26,000 sq miles and appears to contain an enormous amount of gas in different-quality rocks. Masters1 has estimated the Deep basin could contain more than 400 Tcf of gas, recoverable at various levels of price and technology. Canadian Hunter visualizes the gas distribution in the Deep basin as a resource triangle. In such a distribution, the sands and conglomerates of highest porosity and permeability are at the very top of the triangle. As reservoir quality decreases, the resource triangle indicates larger and larger quantities of gas in lower-porosity and lower-permeability rocks. Near the bottom of the triangle are sands approaching 7% porosity and 1 µd in-situ permeability. Within these lower porosity rocks (7 to 11%) resides a huge ultimate potential. Detailed analyses were made of logs, cores, and tests of about 20 zones from 57 wells in a 60-township area around the Elmworth field. This study indicated that, with sufficient but reasonable economic incentives, it would be possible to recover more than 200 Tcf from the lower-quality rocks within the Deep basin.2 To obtain more information on the technology and economics required to recover this gas, Canadian Hunter performed a large hydraulic fracture over the Cretaceous Falher Zones A and B in the Canhunter Texcan Elmworth Well 11–12–71–13W6. This paper presents a description and analysis of the fracture. Petrophysical Properties The Falher Zones A and B were cored completely, and a full suite of openhole logs was run. This suite included the induction-electrical, acoustic with variable density display, compensated neutron-density, and microlog. Selected logs and the core analysis (made at atmospheric conditions) are shown in Fig. 2. Although the entire cross section of 164 ft is considered gas-bearing, less than one-half of the section is estimated to be net pay, based on analysis of logs, cores, and pressure buildups. Sixty-six feet of this section have measured core porosities equal to or above 7%; this is shown by the shaded area on the porosity curve in Fig. 2. Permeabilities above 0.1 md also are shaded. Sonic log and pressure buildup analysis indicate a net pay closer to 45 ft. The relation between fractional core porosities (f) measured at 200 psi and sonic travel time (?t) in µs/ft is described byf=0.0054?t-0.2865.