Feasibility study of thermally enhanced gas recovery of coal seam gas reservoirs using geothermal resources

Thermally enhanced gas recovery of coal seam gas reservoirs is proposed as a new enhanced recovery technique. The endothermic nature of desorption process facilitates methane desorption of coal surface at elevated temperatures. Any thermal treatment of coal seam assists bond breakdown between methane molecules and coal surface and changes the sorption properties of the coal while the initial gas content of the coal is constant. It results in higher critical desorption pressure and higher gas recovery. The higher critical desorption pressure advances gas production and consequently shortens the dewatering stage. Coal seam gas production can be coupled with extensive underlying geothermal resources where a vast amount of hot water is available to thermally treat the coal seams. To investigate the feasibility of thermally enhanced gas recovery, the reservoir thermal simulator (CMG-STARS) and the coal seam gas simulator (CMG-GEM) were linked together. An inverted five spot pattern with a hot water injector well and four discharge wells was created to simulate hot water injection into the coal seam. When the injection phase was finished, the new reservoir temperature distribution from thermal simulator was imported into the coal bed methane simulator. Coal seam gas production was simulated at elevated reservoir temperatures while the seam temperature was updated every 2 years to account for the effect of heat loss to the neighboring formations. Hot water injection (80 °C) for a period of 2 years into the coal seam with an area of 40 acres successfully increases average reservoir temperature by 30 °C. Thermal treatment dramatically increases gas recovery by 58% during 12 years of production compared with conventional production. During thermally enhanced gas recovery, peak gas rate is almost 6.8 times higher than conventional recovery. In addition, the dewatering time, which was previously 9 months for conventional production, is eliminated when coal is thermally treated prior to gas production. © 2012 American Chemical Society.Alireza Salmachi and Manouchehr Haghigh

Temperature effect on methane sorption and diffusion in coal: application for thermal recovery from coal seam gas reservoirs

Investigating the effects of in situ thermal treatment on coal seams requires adequate knowledge of gas sorption and its kinet¬ics in coal at various temperatures. Methane sorption onto two Australian coal samples (high-volatile bituminous) at dry state and different temperatures was measured. Methane adsorption isotherms were measured at pressures up to 7 MPa by the gas ad¬sorption manometric method. Adsorption isotherms data at two temperatures were used to investigate the effects of in situ thermal treatment on critical desorption pressure, ultimate gas recovery and the diffusion coefficient in coal. An increase of experimental temperature from 308 to 348 K resulted in a 50% reduction in the adsorption affinity of the coal sample and an insignificant reduction in the saturation capacity of the isotherms. At higher ex¬perimental temperatures, Langmuir isotherms exhibit downward shift with the initial gas content of the coal seam being constant, resulting in critical gas desorption pressure increase. According to the measured Langmuir isotherms at different temperatures, an increase in reservoir temperature by 1 K leads to a 2% and 1.2% increase in total recovery for the tested coal seams. Gas left in the coal seam at the abandonment pressure can only be recovered at a higher reservoir temperature. Diffusion coefficients of coal seam samples were calculated for different experimental temperatures. Fractional uptakes of the first coal sample show a good agreement with the results obtained using the unipore diffusion model with the diffusion coefficient to be 4.7 × 10–12 m2/s at 348 K. For the second coal sample, the unipore diffusion model fairly matches the uptake data. A bidisperse diffusion model was also applied to measure the adsorp¬tion kinetics of the second coal sample, resulting in an improved agreement with the experimental uptake data. Both coal samples exhibited a reduction of the diffusion coefficient with an increase in equilibrium pressure; this effect was more pronounced at equilibrium pressures below 0.045 MPa. It was observed that the diffusion coefficient change with pressure becomes flat at high pressures, with the pressure effect diminishing much faster at lower temperatures.A. Salmachi and M. Haghigh

Cross-formational flow of water into coalbed methane reservoirs: controls on relative permeability curve shape and production profile

Coalbed methane (CBM) wells tend to produce large volumes of water, especially when there is hydraulic connectivity between coalbed and nearby formations. Cross-formational flow between producing coal and adjacent formations can have significant production and environmental implications, affecting economic viability of production from these shallow reservoirs. Such flows can also affect how much gas can be removed from a coalbed prior to mining and thus can have implications for methane control in mining as well. The aim of this paper is to investigate the impact of water flow from an external source into coalbed on production performance and also on reservoir variables including cleat porosity and relative permeability curves derived from production data analysis. A reservoir model is constructed to investigate the production performance of a CBM well when cross-formational flow is present between the coalbed and the overlying formation. Results show that cleat porosity calculated by analysis of production data can be more than one order of magnitude higher than actual cleat porosity. Due to hydraulic connectivity, water saturation within coalbed does not considerably change for a period of time, and hence, the peak of gas production is delayed. Upon depletion of the overlying formation, water saturation in coalbed quickly decreases. Rapid decline of water saturation in the coalbed corresponds to a sharp increase in gas production. As an important consequence, when cross-flow is present, gas and water relative permeability curves, derived from simulated production data, have distinctive features compared to the initial relative permeability curves. In the case of cross-flow, signatures of relative permeability curves are concave downward and low gas permeability for a range of water saturation, followed by rapid increase afterward for water and gas, respectively. The results and analyses presented in this work can help to assess the impact of cross-formational flow on reservoir variables derived from production data analysis and can also contribute to identifying hydraulic connectivity between coalbed and adjacent formations.Alireza Salmachi, C. Özgen Karaca

Production data analysis of coalbed methane wells to estimate the time required to reach to peak of gas production

Abstract not availableAlireza Salmachi, Zahra Yarmohammadtoosk

Optimisation and economical evaluation of infill drilling in CSG reservoirs using a multi-objective genetic algorithm

Water production in the early life of Coal Seam Gas (CSG) recovery makes these reservoirs different from conventional gas reservoirs. Normally, a large amount of water is produced during the early production period, while the gas-rate is negligible. It is essential to drill infill wells in optimum locations to reduce the water production and increase the gas recovery. To optimise infill locations in a CSG reservoir, an integrated framework is developed to couple the reservoir flow simulator (ECLIPSE) and the genetic algorithm (GA) optimisation toolbox of (MATLAB). In this study, the desired objective function is the NPV of the infill drilling. To obtain the economics of the infill drilling project, the objective function is split into two objectives. The first objective is the gas income; the second objective is the cost associated with water production. The optimisation problem is then solved using the multi-objective solver. The economics of the infill drilling program is investigated for a case study constructed based on the available data from the Tiffany unit in San Juan basin when gas price and water treatment cost are variable. Best obtained optimal locations of 20 new wells in the reservoir are attained using this optimisation framework to maximise the profit of this project. The results indicate that when the gas price is less than $2/Mscf, the infill plan, regardless of the cost of water treatment, is not economical and drilling additional wells cannot be economically justified. When the cost of water treatment and disposal increases from$0.01/STB to $4/STB, the optimisation framework intelligently distributes the infill wells across the reservoir in a way that the total water production of infill wells is reduced by 26%. Simulation results also indicate that when water treatment is an expensive operation, lower water production is attained by placing the infill wells in depleted sections of the coal bed, close to the existing wells. When water treatment cost is low, however, infill wells are freely allocated in virgin sections of the coal bed, where both coal gas content and reservoir pressure are high.A. Salmachi, M. Sayyafzadeh and M. Haghighihttp://www.appeaconference.com.au/2013

Estimation of time of peak gas production in coalbed methane wells using production data analysis

For coalbed methane (CBM) wells with rising gas production, time to reach peak of gas production and peak gas rate are two fundamental features of a production profile. This paper investigates the time of occurrence of peak of gas production in CBM wells using production data analysis (PDA). The methodology is simple and requires gas rate and flowing bottom-hole pressure (BHP) data. Signatures of time of peak gas production are obtained using time derivative of square of BHP over gas rate. Signatures are obtained for constant and variable bottom-hole pressure operational constraints. Derivative of square of BHP over gas rate with respect to time is calculated for observed production data. Then, plot of this derivative versus production time is constructed for the CBM well. Finally, the plot is extrapolated to a time at which the signature of peak production appears. This time is estimated to be the time of occurrence of peak of gas production. The production data for a CBM well in San Juan basin is analyzed using this technique to demonstrate the signature and the estimation of time of peak gas production. The accuracy and correctness of estimation depend upon quality of production data, goodness of fitted functions used in this approach, and time interval between time of peak gas rate and observed production data. The signatures of time of peak production introduced in this paper can contribute to production forecasting of the negative decline portion of the production profile of CBM wells.Alireza Salmachi, Jake Darby, Zahra Yarmohammadtoosk

Effect of volcanic intrusions and mineral matters on desorption characteristics of coals (Case Study)

In this study, coal seams properties in two coal core wells are studied to identify dominant parameters controlling desorption characteristics of coals. Available published data from desorption canister tests including sorption time and gas content (lost gas, desorbed gas, and residual gas) are employed. Proximate analysis data assists in coal characterization and data from high pressure adsorption tests are used to investigate the methane adsorption on coal as a function of pressure. For fracture and cleat analysis, gamma ray, density, and acoustic image logs are used. All data and analysis combined with regional geology assist to study desorption properties of different coal seams in these two wells. Kalbar-1 and Peebs-1 are the two core wells in this study. Entirely different patterns (gas content versus depth) are observed which can be explained by their different geological setting. A major volcanic intrusion of approximately 60m in thickness and a few minor intrusions in the area explain abnormally high gas content of shallow coal seams. The methane Langmuir adsorption isotherm for shallow coals (composite sample) is steep and has higher gas adsorption capacity compared to other seams. The shallow coal seams have been cooked by volcanic intrusions and have higher than expected gas content. For Peebs-1, the composite plot of gas content, sorption time, and ash content combined with gamma ray, density, and acoustic image logs provides a useful set to study desorption properties of coal seams. The fracture and cleat analysis reveals that low sorption time generally belongs to coal seams with higher cleat and fracture density. The existence of open cleats and fractures might facilitate gas release from coal matrix. The inverse correlation observed between sorption time and ash content while maceral composition is fairly similar suggests that desorption properties might be controlled by mineral matters in this well.Alireza Salmachi, Carmine C. Wainman, Mojtaba Rajabi, Peter McCab

Infill well placement optimization in coal bed methane reservoirs using genetic algorithm

The unprecedented growth of coal bed methane drilling, expensive coal bed water treatment, and low gas rates urge the integration of petroleum engineering and optimization disciplines to meet production goals. An integrated framework is constructed to attain best-obtained optimal locations of infill wells in coal bed methane reservoirs. This framework consists of a flow simulator (ECLIPSE E100), an optimization method (genetic algorithm), and an economic objective function. The objective function is the net present value of the infill project based on an annual discount rate. Best obtained optimal well locations are attained using the integrated framework when net present value is maximized. In this study, a semi synthetic model is constructed based on the Tiffany unit coal bed data in the San Juan basin. The number of infill wells in reservoir resulting in peak production profit is selected as an optimum number of the infill drilling plan. Cost of water treatment and disposal is a key economical parameter which controls infill well locations across the reservoir. When cost of water treatment is low, infill wells are mostly located in virgin section of the reservoir where reservoir pressure is high and fracture porosity is low. Water content in fractures does not play a significant role on infill wells selection when water treatment and disposal is a cheap operation. When cost of water treatment is high, infill wells are mostly located on the transition section between virgin and depleted sections of the reservoir to minimize water production. © 2013 Elsevier Ltd. All rights reserved.Alireza Salmachi, Mohammad Sayyafzadeh, Manouchehr Haghigh

Drilling data of deep coal seams of the Cooper Basin: analysis and lessons learned

Deep (>4920 ft; >1500 m) coal seams of the Cooper Basin accommodate large amounts of natural gas; however, permeability of this unconventional resource is low and reservoir stimulation in prospective coal intervals is essential to achieve commercial production. This paper aims to analyse drilling data of deep coal seams of the Cooper Basin in South Australia. Drilling data obtained from mud logs are utilised to construct a drillability index (DI), in which rate of penetration is normalised by drilling factors, making DI more sensitive to coal rock strength. Analysis of DI and gas show information provides a preliminary screening tool for studying prospective deep coal seams, before performing in-depth reservoir characterisation and production tests. The decline in DI with depth is attributed to a compaction effect that makes deeper coal seams more difficult to drill through compared with shallow seams. The existence of a fracture network can reduce coal rock strength and consequently DI may increase. The increase in DI may be indirectly related to fluid flow characteristics of the coal seam helping in identifying prospective coal intervals. The DI is also affected by other factors and, hence, should be used in combination with reservoir information to yield conclusive indications. Gas show information and DI results were utilised to indicate the effectiveness of dewatering operation and hydraulic fracture confinement in the wells drilled in the Klebb area located in the Weena Trough.Alireza Salmachi, Erik Dunlop and Mojtaba Rajab

Fluid flow characteristics of Bandanna Coal Formation: a case study from the Fairview Field, eastern Australia

Fluid flow characteristics of cleat systems in coalbed methane reservoirs are crucial in reservoir management and field development plans. This paper aims to evaluate the cleat system properties including cleat porosity, permeability, and aperture as well as the impact of permeability growth on production performance in the Bandanna Coal Formation of the Fairview Field, eastern Queensland. Owing to the presence of bad hole conditions and poor core recovery of the coal intervals, the petrophysical well logs and laboratory measurements cannot be used as a source of information for this purpose. Hence, a new approach is employed that utilises early water production data to measure water in place and absolute permeability of the coal. In addition, micro-computed tomography (CT) scan method is used to investigate the cleat system that is preserved in a core sample and results are compared with the ones obtained by analysis of production data. Cleat system evaluation by analysis of production data and micro-CT scan technique provides a comprehensive approach that brings confidence in measurements and helps to obtain cleat properties at the sufficient scale for reservoir engineering purposes. The necessary information including production data and core samples are collected from a dewatering well and the nearby observation well in the study area. Analysis of early water production data (single-phase flow) indicates that coal permeability is 189 mD and the average cleat porosity is approximately 5%. High cleat porosity describes the large volume of water produced over the life of the study well. The 3D model of the fossilised cleat system constructed by the micro-CT scan method reveals that coal is well-cleated and cleat spacing and mean cleat aperture are 4 and 0.136 mm, respectively. The average cleat porosity that is measured by the micro-CT scan method is 5.7%, which is fairly close to the cleat porosity measured by analysis of production data. Production data analysis indicates that effective permeability to gas starts to grow at the midlife of the well and it strongly controls the shape of the production profile. The results of this study help in future field development and infill drilling programs in the Fairview Field and provide important insights into cleat system of Bandanna Coal Formation.Z. Yarmohammadtooski, A. Salmachi, A. White and M. Rajab