Thermally enhanced gas recovery and infill well placement optimization in coalbed methane reservoirs.

The aim of this thesis is to investigate innovate approaches that can help to improve methane recovery and production rate from coalbed methane (CBM) reservoirs. The results of two following subjects are presented and discussed. First, thermally enhanced gas recovery from gassy coalbeds is introduced. Second, an integrated reservoir simulation-optimization framework is developed and employed to optimize infill well locations across coalbed reservoirs. When coalbed methane and geothermal activities coexist in the same field, coalbeds can be thermally treated prior to the gas production using available underground geothermal resources. Feasibility of this method is investigated both using methane sorption tests on Australian coal samples at different temperatures and also reservoir simulation. The impact of temperature elevation on methane sorption and diffusion in coal is investigated by running sorption experiments on two the Australian coal samples using a manometric adsorption apparatus. Experiments are performed to indicate that how the difference between original reservoir pressure and critical desorption pressure is decreased at elevated reservoir temperatures. Lower pressure gradient is required to extract methane from coalbed when it is thermally treated prior to gas production. Following the experimental study, the feasibility of thermally enhanced gas production from coalbeds is studied by coupling of coalbed methane and thermal simulators. The coalbed methane simulator of Computer Group Modelling (CMG) and the thermal simulator of CMG known as STARS are loosely coupled to study the effect of temperature elevation on total gas and water production. Both gas rate and ultimate gas recovery from the reservoir are increased by thermal operation. In the second part of this thesis, an integrated reservoir simulation-optimization framework is developed to intelligently obtain locations of new infill wells in a way to maximize profitability of the infill plan. This framework consists of a reservoir flow simulator (Eclipse E100), an optimization method (genetic algorithm), and an economic objective function. The objective function in this framework is to maximize discounted net cash flow of infill project. The importance of optimization is magnified when cost of water treatment is increased. When optimization approach is compared with standard five spot pattern well arrangements, the impact of water treatment cost is observed. When cost of water treatment is high, there is a large difference between the profit of the infill project calculated using the optimization approach and the standard five spot pattern. Simulation results indicate that at higher cost of water treatment, infill wells are preferably located either on the front of the water depletion zone or close to existing wells. On the other hand, when water treatment cost is low, infill wells are located in virgin sections of the coalbed where both gas content and cleat water saturation are high.Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum, 201

Flowing Material Balance and Rate-Transient Analysis of Horizontal Wells in Under-Saturated Coal Seam Gas Reservoirs: A Case Study from the Qinshui Basin, China

Two phase flow and horizontal well completion pose additional challenges for rate-transient analysis (RTA) techniques in under-saturated coal seam gas (CSG) reservoirs. To better obtain reservoir parameters, a practical workflow for the two phase RTA technique is presented to extract reservoir information by the analysis of production data of a horizontal well in an under-saturated CSG reservoir. This workflow includes a flowing material balance (FMB) technique and an improved form of two phase (water + gas) RTA. At production stage of a horizontal well in under-saturated CSG reservoirs, a FMB technique was developed to extract original water in-place (OWIP) and horizontal permeability. This FMB technique involves the application of an appropriate productivity equation representing the relative position of the horizontal well in the drainage area. Then, two phase (water + gas) RTA of a horizontal well was also investigated by introducing the concept of the area of influence (AI), which enables the calculation of the water saturation during the transient formation linear flow. Finally, simulation and field examples are presented to validate and demonstrate the application of the proposed techniques. Simulation results indicate that the proposed FMB technique accurately predicts OWIP and coal permeability when an appropriate productivity equation is selected. The field application of the proposed methods is demonstrated by analysis of production data of a horizontal CSG well in the Qinshui Basin, China

Identification of potential locations for well placement in developed coalbed methane reservoirs

This study investigates well placement in developed coalbed methane (CBM) reservoirs. A workflow is developed to find potential locations for well placement within the reservoir. It consists of a reservoir simulator and statistical analysis. The application of this workflow is to reduce the need to perform computationally expensive simulations in large reservoirs to obtain potential locations for drilling an additional well. The workflow is also used to study the role of dominant reservoir properties in finding potential locations for well placement. The effects of permeability anisotropy, gas and water relative permeabilities, sorption time, and water content in well placement are discussed.Results demonstrate that permeability anisotropy results in the formation of elliptical drainage areas around the wells. When drainage patterns are orthogonal to the direction of placement of wells, the drainage area of the reservoir is large and penetrated into distant locations. This leads to a non-uniform drainage area and extends well placement options to distant locations. Comparison between well placement in two scenarios with different gas and water relative permeabilities shows that potential locations tend to be on a border region between existing wells and virgin area when water mobility is restricted by water relative permeabilities. This region has the advantage of having higher pressure and gas content compared to locations among existing wells. In this study, changing the sorption time does not affect the well placement within the reservoir. Except at very early times, gas production from presented reservoir models is mainly controlled by Darcy flow in cleat system (permeability-dominated) rather than diffusion process in coal matrix

The effect of magmatic intrusions on coalbed methane reservoir characteristics: a case study from the Hoskissons coalbed, Gunnedah Basin, Australia

Magmatic intrusions can deteriorate coalbed methane reservoir quality by precipitating minerals in natural fracture and cleat system. To date, the effect of magmatic intrusions on coal rank and maturity has been studied extensively. However, their impact on fluid flow capacity and gas content is poorly investigated. This study evaluates the impact of magmatic intrusions on reservoir characteristics of the Hoskissons coal interval in the Gunnedah Basin (eastern Australia) where numerous coal-intrusion associations exist. Drill stem test (DST), borehole image logs and core data are used to determine fluid flow characteristics, gas content and quality in 14 wells across the Gunnedah Basin. The integration of borehole image logs and DST data analysis enables us to determine the existence, openness, and hydraulic conductivity of natural fracture and cleat systems in the Hoskissons coal interval. In addition, available desorption canister data, gas composition data, and conventional well logs are interpreted to investigate probable thermal effect on gas content.Our analyses of different datasets reveal that the thickness of intrusions and their positions with respect to the Hoskissons coal interval are variable in the studied wells. Permeability varies from 1091 mD down to zero owing to heterogeneous fracture and cleat systems. Interpreted natural fracture/cleat systems are well correlated with measured permeability from DST data analysis. This highlights the role of open natural fractures/cleats in fluid flow characteristics of the Hoskissons coal interval. Results indicate that the mineralizing effect of hydro thermal fluids derived either from magmatic intrusions or coal itself is not a controlling factor in fluid flow capacity of the Hoskissons coal interval in the studied wells. This is described by either the distance between coal section and major intrusions in some wells or perhaps emplacement of intrusive bodies prior to development of cleat and natural fracture networks. The destructive impact of intrusions on permeability is observed in one of the studied wells in which in-situ stress perturbation is large (due to presence of magmatic intrusions in sedimentary rocks). Variable in-situ stress orientation can decrease fracture connectivity and consequently fluid flow properties are affected. Gas content largely varies in heat affected coal intervals. This signature is the result of thermal effect fading with distance and is more pronounced when intrusions are in close proximity to coal intervals. Gas composition is variable in the studied wells. Gas composition data indicate that high quality desorbed gas with methane concentration higher than 90% could be found even in coal intervals which are heavily intruded. (C) 2016 Elsevier B.V. All rights reserved

History, Geology, In Situ Stress Pattern, Gas Content and Permeability of Coal Seam Gas Basins in Australia: A Review

Coal seam gas (CSG), also known as coalbed methane (CBM), is an important source of gas supply to the liquefied natural gas (LNG) exporting facilities in eastern Australia and to the Australian domestic market. In late 2018, Australia became the largest exporter of LNG in the world. 29% of the country’s LNG nameplate capacity is in three east coast facilities that are supplied primarily by coal seam gas. Six geological basins including Bowen, Sydney, Gunnedah, Surat, Cooper and Gloucester host the majority of CSG resources in Australia. The Bowen and Surat basins contain an estimated 40Tcf of CSG whereas other basins contain relatively minor accumulations. In the Cooper Basin of South Australia, thick and laterally extensive Permian deep coal seams (>2 km) are currently underdeveloped resources. Since 2013, gas production exclusively from deep coal seams has been tested as a single add-on fracture stimulation in vertical well completions across the Cooper Basin. The rates and reserves achieved since 2013 demonstrate a robust statistical distribution (>130 hydraulic fracture stages), the mean of which, is economically viable. The geological characteristics including coal rank, thickness and hydrogeology as well as the present-day stress pattern create favourable conditions for CSG production. Detailed analyses of high-resolution borehole image log data reveal that there are major perturbations in maximum horizontal stress (SHmax) orientation, both spatially and with depth in Australian CSG basins, which is critical in hydraulic fracture stimulation and geomechanical modelling. Within a basin, significant variability in gas content and permeability may be observed with depth. The major reasons for such variabilities are coal rank, sealing capacity of overlying formations, measurement methods, thermal effects of magmatic intrusions, geological structures and stress regime. Field studies in Australia show permeability may enhance throughout depletion in CSG fields and the functional form of permeability versus reservoir pressure is exponential, consistent with observations in North American CSG fields