Coalbed Methane (CBM) is becoming a significant portion of the US gas resource and is gaining importance in Australia, China, Indonesia and Europe. CBM reserves in the United States are estimated at some 450 Tscf. In Australia, CBM resources exceed 300 Tscf, while China has a resource potential greater than the United States and Australia combined. Recent advances in well design and production technology offer scope to significantly increase the proportion of gas contained in coal that can be commercialized. Generally, initial water saturation is 100% within coal seams and gas can only be found as an adsorbed phase inside the coal matrix, so how much adsorbed gas can be released at an economical rate will determine the ultimate gas recovery. The Langmuir isotherm has been widely used in industry to describe the pressure dependence of adsorbed gas. However, temperature dependent adsorption behavior and its major implications for evaluating thermal stimulation as a recovery method for coalbed methane have not been thoroughly explored. Therefore in order to investigate the feasibility of thermal treatment in coal bed methane reservoir successfully, it is crucial to understand the effects of thermal stimulation on the adsorption and desorption phenomenon, and how can we exploit such effects to enhance coalbed methane recovery from hydraulically fractured reservoirs. In this study, we propose a method to evaluate desorbed gas as a function of pressure and temperature in coal seams, by regression on Langmuir isotherm data. In addition, a CBM reservoir simulator is developed, which is capable of capturing real gas diffusion in the coal matrix and flow in the hydraulic fractures, as well as the heat transfer process within the matrix. This simulator enables us to investigate various thermal stimulation techniques on the global well performance and recovery. The results of this study show that by increasing the formation temperature, ultimate gas recovery can be improved in CBM reservoirs. The higher the thermal stimulation treatment temperature, the more extra gas can be recovered. However, the efficiency of thermal stimulation is mostly constrained by how much the formation area/volume that can be stimulated in a reasonable period of time. Due to the low heat conductivity of coal, it is not possible to heat up a large drainage area/volume by heating the surface of vertical hydraulic fractures directly. If the heating source (e.g., electromagnetically excited nano-particles) can be dispersed further into the formation through the cleat system during hydraulic fracture execution, then larger formation area/volume can be heated up, depending on how further the nano-particles can be pushed and the arrangement of production (injection) wells. In the case of horizontal fractures, a large formation volume can be thermally stimulated if the fractures can be placed close enough to cover the whole lateral area. Thermal stimulation by hot water/steam injection can increase formation temperature more rapidly than direct element heating methods, especially when the formation permeability is large. Considering large amount of residual adsorption gas still left behind even with low production pressure, thermal stimulation has the potential to enhance CBM recovery substantially if techniques and designs are tailored to the formation properties appropriately.

Most multiple transverse fracture horizontal wells in shale gas formations remain in transient bilinear or linear flow for very long periods, typically several years. Some plays show very different behavior that has been attributed to pressure dependent permeability. Often, there are reported cases of shale wells that exhibit boundary dominated flow in a very short period that implies a stimulated rock volume (SRV) much smaller than would be expected based on the hydraulic fracture treatment design. This paper offers an alternative explanation for the early boundary dominated flow related to dissolution of salt-sealed natural fractures in the shale. Three plays are the target of this study, namely, the Haynesville shale, the Marcellus shale, and the Horn River Basin.Flowback of water with significantly higher salinity than the injected fracture fluid may suggest that the injected low salinity fracturing fluid dissolved salts that seal an existing natural fracture system. Evidence would be seen in long-term transient rate and pressure production data as early boundary dominated flow providing the natural fracture pore volume dissolved by injected low salinity fracturing fluid that leaked off during the hydraulic fracture treatment. In this scenario, the effective permeability would represent that of the natural fracture system induced by salt dissolution, and the stimulated rock volume would be directly related to the leakoff volume.This study first discusses a plausible diagenetic history for generation of a salt-sealed natural fracture system in shale gas and how core, log, and conventional test data may behave. We then present a material balance model for behavior of the salt-sealed fracture porosity, the shale matrix porosity, and fracture pore volume dissolved by the leaked off fracture fluid, during the fracture treatment and subsequent early and long term production. We show the resulting permeability loss as residual water vaporizes. The significance of the model is a new rationale for a correlation between apparent stimulated rock volume and injected fluid during hydraulic fracturing.

Underground natural gas storage has been used extensively in countries with large natural gas demand. Although much of the storage and withdrawal have been associated with seasonality, storage is becoming essential in an integrated natural gas management. It is particularly important in large operations, such as liquefied natural gas (LNG), where the total production rate must be maintained irrespective of the producing field day-to-day capacity.Natural gas storage capacity is affected by reservoir volume and tolerable pressure (to avoid fracturing) and injection or production rates that are affected by reservoir permeability, natural reservoir drive mechanism, well completion/stimulation, and the impact of cyclical losses.We present here a new sequence of calculations and estimations demonstrating salient elements of this practice:• Maximum capacity estimation with a new type of graphical construction, blending concepts of the classical p/Z vs. cumulative recovery straight line in natural gas production. • Prediction of withdrawal rates and time, constrained by decreasing storage pressure. • Determination of maximum or sustainable withdrawal rate for a period of time. In all cases, the injecting and producing wells are hydraulically fractured. The hydraulic fractures are designed for the withdrawal rate. Thus, the required number of wells is determined.These concepts are applied to a depleted natural gas field with an average pay of 33 ft and a permeability of 45 md. Forecasts of injection or production rates, cumulative storage or withdrawal, and pressure buildup or decline are presented as functions of time. The purpose of this case study is to sustain an LNG liquefaction operation for a specified period of time by employing underground natural gas storage.