Summary
The unique properties and complex characteristics of coalbed methane (CBM)reservoirs, and their consequent operating strategies, call for an integrated approach to be used to explore for and develop coal plays and prospects economically. An integrated approach involves the use of sophisticated reservoir, wellbore, and facilities modeling combined with economics and decision-making criteria.
A new CBM prospecting tool (CPT) was generated by combining single-well(multilayered) reservoir simulators with a gridded reservoir model, Monte Carlo(MC) simulation, and economic modules. The multilayered reservoir model is divided into pods, representing relatively uniform reservoir properties, and a" type well" is created for each pod. At every MC iteration, type-well forecasts are generated for the pods and are coupled with economic modules. A set of decision criteria contingent upon economic outcomes and reservoir characteristics is used to advance prospect exploration from the initial exploration well to the pilot and development stages. A novel approach has been used to determine the optimal well spacing should prospect development be contemplated. CPT model outcomes include a distribution of after-tax net present value (ATNPV), mean ATNPV (expected value), chance of economic success(Pe), distribution of type-well and pod gas and water production, reserves, peak gas volume, and capital. An example application of CPT to a hypothetical prospect is provided.
An integrated approach also has been used to assist with production optimization of developed reservoirs. For example, an infill-well locating tool(ILT) has been constructed to provide a quick-look evaluation of infill locations in a developed reservoir. ILT, like CPT, is used for multiwell applications, combining the single-well simulator with a multilayered reservoir model and economics. An application of ILT to a CBM reservoir is provided, and the results are compared with the predictions of an Eclipse reservoir simulation.
Introduction
CBM reservoirs have a relatively short history of development compared to conventional reservoirs; therefore, few analog fields may be relied upon for extrapolation to new basins and new plays. Further, key reservoir properties such as absolute permeability vary greatly within and between existing developing basins, which complicates prediction of these parameters for new plays. The production performance of CBM reservoirs in new plays or basins, in which few reservoir data exist, is correspondingly difficult to predict.
Existing conventional reservoir fields cannot be relied upon as analogs for CBM play analysis because coal-gas reservoirs differ from conventional reservoirs in their fluid-storage and -transport mechanisms. Coals act as source rocks and reservoirs to gas, and a significant amount of gas may be stored in the adsorbed state relative to the free-gas state. CBM reservoirs are often naturally fractured and may be modeled as dual-porosity, or even triple-porosity, reservoirs. Gas-transport mechanisms vary depending on the scale and location within the reservoir. For example, gas transport at the scale of the matrix between natural fractures is caused by the mechanism of diffusion, whereas Darcy flow occurs in the fracture system. Single- or two-phase (gas and water) flow can occur, and, hence, relative permeability characteristics are important.
Permeability and gas content are two critical parameters that dictate the economic viability of CBM reservoirs. Unfortunately, there are many controls upon these parameters. For example, gas content is a function of the amount of organic matter within these rocks, the organic matter composition, organic matter thermal maturity, in-situ PT conditions, gas composition, and matrix and fracture gas-saturated porosity. Absolute permeability is dependent upon natural-fracture existence, frequency, orientation (with respect to in-situ stress), and degree of mineralization. Natural-fracture permeability is also stress- and/or desorption-dependent. Although the range of expected parameter values for a new unconventional play may be reduced by knowledge of basin hydrodynamic characteristics, tectonic regime, local and regional stratigraphy and sedimentology, local and regional structural geology, and existing production within the basin, the uncertainty associated with key reservoir variables is still likely to preclude a deterministic evaluation of reservoir producibility and recoverable reserves.
Because of the variability in reservoir parameters that could be expected when exploring for CBM in existing or new basins, it is natural to use a statistically based (stochastic) approach in the prediction of gas in place, recoverable reserves, well performance, and economic return. A comprehensive study by Roadifer et al. demonstrated the use of MC simulation for screening key parameters affecting CBM production.
Well performance is a key factor determining the economic viability of CBM reservoirs. Accurate prediction of well performance is required for development strategies such as optimized well spacing, completion gathering system, and wellsite design.
The current work discusses how to integrate reservoir simulation and economics for the purpose of optimizing CBM exploration and development strategies. Central to the discussion is the use of single-well (multilayered)simulators, which were constructed in Excel* and incorporate many attributes of CBM reservoirs. These single-well (tank) models are discussed in the following section and have some utility for exploration and development applications when used on their own, but they are particularly powerful when integrated with reservoir, surface, and wellbore models, MC simulation,7 and economics. Two new tools (CPT and ILT) described in this work are examples of integrated tools for application to exploration and development, respectively.
Natural Fracture Detection, Characterisation and Modeling using the Event Solution Synergy Approach