It wasn't always this complicated! In 1990, Seidle and Arri1 demonstrated how to easily adapt a conventional black oil simulation model for use in coalbed methane simulation. These days, when setting up a coalbed methane simulation model, one needs to worry about a single or multi-component gas description; depletion or enhanced coal bed methane recovery; single, dual or triple porosity; vertical, horizontal, or multi-lateral wells; coals only or a mix of coals and sands; and coalbed methane or coal mine methane? Correctly determining what to model is almost as daunting a task as the simulation work itself. All of these variations add complexity to the task and, in some cases, require specialized simulation models to adequately characterize the problem. This paper discusses how the exploitation and development of coalbed resources throughout the world is changing, and with it how our approach to reservoir simulation of the process is changing as well. The paper will provide a valuable resource to engineers and geoscientists faced with developing predictive tools to assist them in evaluating the optimum strategy to exploit these valuable resources. Introduction There is probably not a more appropriate place to start a discussion on the evolution of coalbed methane reservoir simulation than to point out that one really doesn't need a coalbed methane reservoir simulator to perform coalbed methane reservoir simulation. Any conventional black oil simulator will do the job. The idea of modifying a conventional black oil model to simulate the performance of coalbed methane wells was first presented by Amoco1. The technique is quite simple. One first initializes the model with a small immobile oil saturation. The magnitude of the oil saturation is not important, however, it is important that the oil be immobile and the flow of the other fluids not be impacted. To accomplish this, the porosity and fluid saturations (gas, water) are adjusted accordingly based on the oil saturation:Equations In the above notation, ‘eff’ refers to the modified values, while ‘act’ refers to the original values. The impact of the above modifications is to adjust the pore volume to maintain the proper initial fluid volumes, and to shift the fluid saturations to maintain the original relative permeability relationships. After the above modifications, the only remaining change required is to supply an effective dissolved gas relationship with pressure which will mimic the gas content isotherm one would normally use to describe a coalbed methane system. In essence, the dissolved gas in the oil replaces the Langmuir isotherm function. This is done via:Equation In the above equation, ‘V’ is the original coal gas content at any given pressure expressed in Scf/ft3 and the oil formation volume factor is normally set equal to 1.0. As was pointed out in the original reference, the modified black oil representation works well if the release of gas from the matrix to the cleats is fast compared to the flow of gas and water in the cleats. This is because the modified black oil technique implicitly assumes that the sorption time is instantaneous. Potential problems can occur if the actual sorption time in the coals is unusually long, or if the permeability of the cleat system is extremely high.

Diagnostic techniques are presented for detecting and quantifying poorly drained compartments in volumetric gas reservoirs. It is shown that p/z versus Gp data can be used to assess unrecovered gas reserves and assist in targeting infield development.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractJust over ten years ago, coal bed methane production from Wyoming's Powder River Basin was virtually non-existent. Today, total gas production from Powder River Basin coals is almost 1 Bcf per day from nearly 10,000 wells. This tremendous resource is unique compared to other commercial coalbed methane plays with gas content an order of magnitude lower, and reservoir permeability values several orders of magnitude higher than other producing coal bed plays. This paper discusses the production characteristics of the Wyodak coal, the impact of well spacing and well timing on the recovery factor, and the influence of outside factors such as recharge from the regional aquifer. Our results contradict conclusions reported in prior studies concerning the influx of water from adjacent sand horizons. In addition, the effects of multiple well interference and depletion of undrilled portions of the coal by existing wells are documented and discussed.

An analytical model is presented which predicts the performance of gas reservoirs producing under water-drive conditions. The model incorporates a modified water influx technique which accounts for pressure gradients and relative permeability effects across the water invaded region of the reservoir. Under certain conditions in gas reservoirs, these effects can cause significant deviations in predicted performance from that behavior projected using conventional water influx theory. The conditions necessary for this to occur and the improvements realized by using the modified approach are discussed in detail. In addition, the results of the analytical model are compared to solutions generated using a radial, numerical simulator.Previous work has shown that for water-drive gas reservoirs, ultimate recovery increases with decreasing permeability, trapped gas saturation and aquifer size, and increasing fluid withdrawal rates. However, these parameters are all interrelated. Gas recovery cannot be determined based on one factor without considering the influence of the others. Thus, this paper details the development of new parameters which incorporate the key factors that influence gas recovery. These parameters describe the shape of the References & illustrations at end of paper 525 p/z performance curves for the reservoir and allow the engineer to estimate the ultimate gas recovery for a particular reservoir/aquifer configuration.

SPE Members Abstract A detailed engineering and geologic evaluation of an offshore Gulf Coast gas reservoir with water influx is presented. The study was undertaken to analyze various production management strategies in order to optimize the ultimate recovery of the reservoir given the detrimental effects of the water influx Without implementing any reservoir management techniques, the recovery factor of the reservoir is estimated at 66%, much lower than would be expected under volumetric depletion performance. It is demonstrated that producing high volumes of water from downdip wells and adding an additional well high on the structure can significantly increase the ultimate gas recovery from the reservoir. This is achieved by lowering the reservoir pressure which liberates trapped residual gas and by recovering mobile attic gas. However, accelerated gas production does not appear to be beneficial in this particular case due to a reduced volumetric sweep efficiency associated with the accelerated rate case. Economic analyses show that recompletion of an additional well at a higher structural position is the optimum strategy for this particular reservoir. Due to the limited extent of the aquifer, this single well will effectively lower reservoir pressure, liberate gas trapped at residual saturation and recover mobile gas remaining at the top of the structure. Introduction Many natural gas reservoirs located throughout the world experience water influx and water production. The types of reservoirs in which this occurs and the effect this influx has on ultimate recovery is variable in terms of depositional environment and reservoir characteristics. Significant water influx tends to maintain reservoir pressure and reduce ultimate recovery by trapping residual gas at high pressure. Active water influx can also promote water coning and areal cusping, which increases individual well water production and traps gas through reduced volumetric displacement efficiency. Ultimate recovery in this type of reservoir is largely a function of reservoir management. There are several techniques an operator can use in an attempt to increase the ultimate recovery from a waterdrive gas reservoir. Accelerated gas production, selective recompletion of existing wells or the drilling of new wells, and continued production of certain wells at very high water cuts may all result in increased recovery. In many cases, it is necessary to consider the economics of the project not on a well by well basis but on an overall field basis. Any action taken which increases the ultimate gas recovery of a reservoir obviously has the potential for increasing the net present value of that reservoir as well. P. 9^