Search

Abstract A new method of coalbed methane (CBM) recovery is proposed wherein hot carbon dioxide at or near supercritical condition is injected into a CBM reservoir to take advantage of enhanced desorption of methane at elevated temperatures and the preferential adsorption of CO2 on coal surfaces compared to methane. The feasibility of this concept was studied by reservoir simulations using one quarter of an inverted five spot pattern using CO2 and CH4 adsorption isotherms published in the literature. The study compared CBM recovery by pressure depletion, CO2 injection and injection of CO2 that is 10°C hotter than the reservoir temperature. Results show that hot CO2 injection can significantly increase the production rate and recovery factor over and above that achievable by reservoir heating or CO2 injection alone. This new method holds promise for enhanced CBM recovery and also CO2 sequestration, especially for high-rank coals where swelling of coal by CO2 injection is minimized. Preliminary considerations suggest that this method can be economic over a range of CO2 and natural gas price if the CO2 comes from natural sources and the CBM field is located near an existing CO2 pipeline. Alternatively, if the source of CO2 is industrial, this method can be profitable if the cost of CO2 capture is offset by the trading price of CO2 and if the CBM project is located near the CO2 source. Introduction Coalbed methane, also known as coal seam gas, is a significant source of natural gas worldwide, with sizable reserves in the United States, Australia, Russia, Canada and China. In 2015, CBM production in the US was 1.27 Tcf (35.97 Bcm), accounting for 3.9% of all US natural gas production (EIA, 2017). Commercial production of CBM occurs in ten US basins with major production coming from the San Juan, Black Warrior and the Central Appalachian. In 2015, CBM production in Australia was 270 Bcf (7.65 Bcm) accounting for 18% of Australia's total natural gas production (Australian Government, 2016).

The Walloon Coal Measure (WCM) in the Surat Basin in Australia consists of coal-rich mire and a fine-grained meandering fluvial system. The main gas producing targets of WCM are numerous thin coal plies within six coal members with frequent pinching outs, splitting and merging. The geology is stratigraphically complex making correlations of individual coal plies difficult. Consequently, previous geological studies have been mostly based on coal members instead of individual coal plies resulting in inadequate description of the heterogeneity of the coal deposit. To remedy this situation, we proposed a workflow using high-resolution sequence stratigraphy to build an isochronic stratigraphy framework of sublayers and coal plies by utilizing all available data from cores and logs. The key methodology was to identify single fining-upwards cycles with coal, clay or siltstone at the top and sandstone at the base. Then similarity analysis on the cycles was used to identify aggradation, progradation or retrogradation of fluvial facies sequence between adjacent wells. Log density cutoff was used to identify coal, shaly coal, shale, sandstone and siltstone from the whole Walloon fluvial system. Reservoir parameters including gas, ash, moisture content, density, and permeability versus depth were correlated taking into consideration depth shift, regional core data and lithology in different members. All of the above were integrated into a ply-based geomodel which was used to identify highly concentrated, overlapping, continuous plies that are potential sweet pots for field development. Our intent is to provide analogue information and understanding for the coal seam distribution in the green field development of the Surat Basin. This methodology was applied to WCM to perform division and correlation of 20 sub-layers and 125 single plies with thickness ranging from 0.3–1.4 m. Coal distribution area versus thickness relationship was generated to analyze the variogram range used for some key properties, especially density and net-to-gross, and to investigate the impact of coal continuity on well spacing. Five micro-facies in fluvial system were used to describe the distribution of coal properties, impact of coal architecture and heterogeneity. Several potential sweet spots for field development were identified. With proper upscaling, this high-resolution ply-based model can be used in reservoir simulation to forecast production and calculate estimated ultimate recovery (EUR). This methodology has been applied to three coalbed methane (CBM) fields in the Surat Basin in Australia. It is novel in applying high-resolution sequence stratigraphy used in geomodel building of convention oil and gas reservoirs to CBM characterization. It has resulted in a better understanding of the complex depositional character of the WCM and consequently more accurate determination of potential sweet spots, production forecast and EUR calculation.

Raniganj field in West Bengal is the largest producing coal bed methane reservoir in India, belonging to the Gondwana Super Group. Block RG (East)-CBM-2001/1 is located in the eastern-most part of Raniganj coalfield. The block was awarded to Essar Oil Limited under the CBM Round I of the Government of India in 1997. More than 1200 hydraulic fracturing jobs have been carried out since then. Fracturing treatment plans for each well in this block comprises of more than one hydraulic fracturing job since this coal-bed reservoir is made up of a number of laminated sequences of coal seams separated at variable distances. Due to a very strong heterogeneity between these seams, it is essential to understand the behavior of fracture propagation in all of them individually. Fracture diagnostics involves analyzing the data before, during, and after a hydraulic fracture treatment to determine the shape and dimensions of both the created and propped fracture. Fracture diagnostic techniques can provide important data when entering a new area or a new formation. In most cases, however, fracture diagnostics is expensive, which limits its widespread use in industry. However, many researchers have come up with a much simpler and cost effective technique of predicting the fracture behavior based on the analysis of net pressure trend of the fracturing job. Analysis of fracturing treatment pressure behavior is an easy tool to gain some insight into the fracturing parameters and fracture propagation, and consequently, optimize the future fracturing treatments. The ever exhaustive fracturing database of Essar Oil Limited was taken into deliberation to study the fracturing treatments carried out in different seams and an attempt is made to correlate the efficacy of these treatments based on the diagnostic tools postulated by Nolte (1979) and Conway (1985). The study is been extended to correlate the fracturing behavior of each coal seam to the production history. Consequently, suggestions are provided to optimize the future fracturing treatments in order to increase the production index of each well. Formations like coal bed methane and other similar unconventionals are highly unpredictable when it comes to evaluating the accuracy of simulations carried out. This technique helps realize that each reservoir behaves differently and correlating different studies undertaken to study the particular reservoir will help engineers understand it better.

This study investigates the chemical signature of produced water from the Huntly coalbed methane (CBM) using a newly proposed Cl-HCO3-B ternary diagram. This ternary diagram is used to identify the source of fluid in the different aquifers (ground water, CBM and deep basement) and the potential communication between these aquifers. A comparison study of Huntly with other CBM fields (Maramarua, Powder River Basin, San Juan Basin, Raton, Atlantic Rim, Liulin and Alberta) was also carried out to help characterize and verify the water being abstracted. Results from the ternary diagram show that produced water samples from Huntly CBM wells are plotted in the middle along chloride-bicarbonate axis. This indicates that the water samples are CBM water originated from moderate to good permeability coal seams. The water samples also indicate that they have some communication with shallow aquifer due to significant bicarbonate concentration. Meanwhile water samples from basement well (B1) are plotted near to Boron side along Boron-chloride axis, which signifies basement water. The water originated from low permeable formations and afar from recharge area. Furthermore, results from schoeller diagrams show that Huntly water samples from CBM wells, shallow monitoring well and basement well exhibit distinct water chemistry patterns. The CBM water pattern shows sodium, bicarbonte and chloride as the predominant ions. It is similar to the typical CBM water pattern and comparable with CBM water from selected methane producing CBM fields with minor differences. Water samples from the basement well on the other hand shows sulfate and magnesium as the primary ions and the concentration for all ions are lower than CBM water. Shallow water sample exhibits the lowest concentration for all ions compared to CBM water and basement water with bicarbonate as the main ion. In conclusion, this ternary diagram is a reliable tool to identify the possible links between deep and shallow aquifers, formation permeability and origin of the water in one diagram. It enhances the understanding of the natural CBM reservoir setting for future field development, wastewater management and water quality monitoring.

During gas production, coalbed experiences compaction over time when effective stress increases as a result of pressure depletion triggered by escaping gas from micropores through desorption and diffusion. It is deemed that time-dependent compaction deformation (compaction creep) and deterioration of coal structure lead to a decrease in coal permeability. Alteration of compaction rate and permeability of coalbed depends on factors such as coal properties, pore pressure, time, and temperature. Thus far, little studies have been conducted to investigate the impact of compaction creep, viscoelastic, and viscoplastic behavior of coal on permeability. Creep may have such significant impact on coal permeability that its negligence may result in overestimation of Coalbed Methane (CBM) production. Appreciation of creep phenomenon, coal properties such as viscoelasticity and viscoplasticity, and their impact on the interaction of coal permeability and gas production borehole enables optimisation of CBM production. In this study, we aim to examin permeability models and highlight the significance of creep as a factor influencing the evolution of coal permeability and CBM production.

Exploration and development of coalbed methane (CBM) reservoirs is ongoing in the Asia Pacific region, with low permeability, undersaturated coals being the target in some areas. Horizontal wells are typically required to produce low permeability CBM reservoirs at commercial rates, and may experience a period of single-phase (water) transient flow, followed by a transition to two-phase (water+gas) transient flow. Wells exhibiting this behavior are particularly difficult to model analytically, yet simple analytical and semi-analytical tools are desirable for making quick, but reasonably accurate forecasts. The purpose of this work is to therefore provide a new forecasting methodology for low permeability, undersaturated CBM wells. The new method for forecasting CBM wells introduced in this work is based on the concept of a dynamic drainage area (DDA), recently adapted to forecast tight black oil and gas condensate wells exhibiting two-phase flow. A critical advancement provided in the current work is modeling the transition from single-phase flow of water to two-phase flow of gas and water during the transient linear flow period, which was not attempted for the black oil/gas condensate cases. Above desorption pressure, material balance, performed on the dynamic drainage area to determine average pressure in the distance of investigation, is combined with the linear flow productivity index equation to forecast water production at each time step. For two-phase flow below desorption pressure, the two-phase version of the linear productivity equation and material balance equations for water and gas are solved iteratively for pressure, saturation and fluid production rate within the DDA. The gas material balance equation accounts for desorption effects. In order to calculate the DDA at each time step, the linear flow distance of investigation equation is used. Importantly, using the DDA method, variable operating conditions (flowing pressures) may be accounted for, which is critical for CBM wells during early stages of production. The new semi-analytical DDA model is used to history-match production data from an actual horizontal well completed in a low permeability, undersaturated, western Canadian CBM reservoir. Further, the match is compared to that obtained from rigorous numerical simulation. The history-match of the field data is reasonable with the new model and comparable to numerical simulation. The new model is however easier to setup and less data-intensive than numerical simulation, providing a practical alternative to CBM reservoir engineers who are responsible for generating a large number of forecasts.

Acceptable data quality for formation evaluation forms the foundation for understanding the petrophysical & reservoir properties, coal quality and properties and pay zones identification. The petrophysical logs are used in both subsurface modelling and to optimise the well completion strategy, ensuring effective coal dewatering and desorption for gas production. At the moment, the industry common practice for data acquisition is to use open-hole wireline logging tools, which were developed primarily for the oil and gas industry. These tools are designed for higher pressure and temperature specifications compared to the reservoir conditions normally seen in CSG operations. This results in heavier tools, bigger logging trucks and increased manpower requirements than seen in mining logging operations. Arrow's CBM development projects in Queensland, Australia, are designed with a large volume of wells (more than ~1000 wells) that will need to be drilled and evaluated over the next ten years. At present, the cost of logging (direct wireline contractors and associated rig time cost) is forcing Arrow to choose between early data coverage (eroding project economics value) versus restricted logging (increasing project risk). In order to resolve this issue, Arrow has embarked on a series of technology trials to investigate various cost effective formation evaluation solutions, while still ensuring data quality and operational safety. This paper will present the results of a comparison (logoff) of state-of-the-art mining logging technology and conventional oil and gas logging technology. Also, the paper will focus on the mining-style logging technology data quality, equipment footprint, tool handling, calibration procedures, limitations and general operational efficiency.

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.

The inflow performance relationship (IPR) for a coalbed methane (CBM) reservoir is relatively complex as the production behaviour is different from conventional gas wells, as gas in coal is stored by means of adsorption. Most often coal reservoirs are relatively under saturated, meaning the pressure in the reservoir needs to be substantially depleted prior to gas desorption. Gas from coal is produced at relatively low reservoir pressures, thus requiring the pseudo pressure function to be included in any deliverability calculations. A two phase flow system in a coal reservoir adds to that complexity as relative permeability, reservoir geo-mechanics and saturation needs to be taken into account within the IPR correlation. The IPR correlation for coalbed methane wells is an important part of any well performance optimisation and nodal analysis.A simplistic IPR correlation for multi-phase coalbed methane wells was generated based on the history matching of field production data. The correlation has been tested both for a multi seam completion in the Surat Basin and for horizontal wells in low permeability coals within the Bowen Basin. Furthermore the empirical CBM IPR correlation for single and multi-phase reservoir was compared. A sorption isotherm was used to limit the maximum recovery and generate recovery efficiency based on the IPR correlation.One of the potential risks to a CBM development is the likely loss in recovery efficiency due to higher backpressures on wells as a result of suboptimal gathering network sizing due to a chosen surface concept. This risk needed to be further evaluated and addressed for potential outcomes when the field starts production. The study was initiated by means of using the CBM field IPR's to evaluate this risk in more detail, identify mitigation measures and capture any associated opportunities that may be available.

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.

Coalbed methane (CBM) has been considered a relatively mature unconventional gas resource in North America. In Australia, where the CBM or coal seam gas (CSG) industry is nearly two decades old, there have been successful and unsuccessful pilot projects and resources have been slower to develop after nearly twenty-five years since North American technologies were exported internationally. Thus, it is reasonable to believe that there are differences outside North America that have hindered CBM development in Australia. Often CBM pilots owe their degree of success to one of three major factors: geologic or structural setting, reservoir properties, or completion strategies. Most pilot testing have been conducted either to characterize the production from a particular geo-domain associated with certain perceived geological risk and uncertainty or to estimate potential project reserves to a reasonable degree of accuracy. This need to reduce uncertainty is more pronounced in Australia based on the need to balance development decisions, tenure retention requirements, whilst minimising the risk for the upcoming development phase. Often in hindsight, the opportunity to increase the chance of success for good areas or reduce the expenditures in poor areas was achievable through improved reservoir characterisation or better pilot planning. In some cases, the resource volumes are large, but the progression of resources to reserves has been less certainty based on challenges. In this paper we will highlight some key observations from several Australian CSG pilots that led to success or challenges for each case. The authors' goals are to identify key indicators, which if recognised earlier may have increased the rate of success or reduced unnecessary expenditures in these pilot areas.

Following the first commercial recovery of coal-seam gas (CSG) in the 1990s, the CSG industry in Queensland has grown rapidly due to the abundant reserves (~33 000 PJ) and global demand for LNG. There are currently three LNG export projects under construction on Curtis Island near Gladstone in Queensland, with the first shipment scheduled for middle to late 2014. In preparation for the completion of the first LNG plant, the QCLNG project, operated by QGC, is currently ramping up CSG production in the Surat basin. By the end of 2014, more than 2000 wells will be drilled and connected to the QGC gas-and-water-gathering network, and thousands more are scheduled for drilling and completion in subsequent years of the project. To meet the production target, it is increasingly important for QGC to accurately evaluate the well productivity during the early stage of development to optimise the operation of the field and ensure all LNG contractual agreements are met.To date, drillstem testing (DST) has been the most common form of evaluating CSG well productivity. However, the improved capabilities of the wireline formation tester (wireline FT) for testing larger coal intervals (between 1 and 15 m) and deriving similar reservoir parameters is making it a popular alternative to the more costly DST. Nevertheless, although facing very few issues in low-permeability coal seams, the wireline FT is unable to create sufficient pressure drawdown in higher permeability coal seams (>100 md) due to the mechanical limit of its downhole pump (This paper describes utilising super flow technique to create sufficient drawdown in highly permeable coals using wireline FT sample chamber module. Superflow simulates closed-chamber DST by using the high volume sample chamber module of the wireline FT tool. Two different superflow techniques have been implemented with positive results. Several superflow tests were compared with conventional drawdown/build-up tests over a number of coal intervals of varying permeability to confirm the validity of the new testing method. The results indicate this technique has extended the wireline FT capabilities to higher permeability coals that have been typically conducted by DST services. The addition of the sample chamber module and corresponding superflow theory, the wireline FT has broadened the range of CSG applications.

Development of a coalbed methane (CBM) field in its early stage is often plagued by the lack of well control and scarcity of geological data over a large geographical area. Therefore, constructing a representative static model to estimate the in-place-volume presents a formidable challenge. In this paper we proposed a workflow to overcome this challenge and applied it to a CBM field in the northern Bowen Basin of Australia. This workflow may be considered as a best practice for the following reasons. First, it makes use of data from various sources including cores, well logs, seismic interpretation, and topography. Second, it performs rigorous quality control on these data, such as depth shift and log normalization. Third, coal ply division and correlation and subsequent structural modeling are based on three types of correlation: well-to-well, well-to-seismic and, well-seismic-Graphic Information System. Fourth, it establishes the low, base and high trends for the most important reservoir properties. Fifth, it constructs a base case static model by combining the aforementioned structural and reservoir property models. Sixth, it uses sensitivity analysis, which varies one reservoir parameter at one time, to rank the impact of reservoir parameters on in-place-volume. Seventh, it uses uncertainty analysis which varies all reservoir parameters simultaneously to arrive at the P10, P50 and P90 in-place-volumes and their corresponding static models which can then be used for reservoir simulations to estimate the recoverable volumes.

With depletion of coalbed methane (CBM) wells in the San Juan Basin, permeability rises by 10 to 100 times. Similar permeability increases are found in other CBM basins around the world. Models previously advanced to explain this behavior combine a compaction mechanism (which closes cleats) with matrix shrinkage (which opens cleats). In this paper, the original model (Palmer-Mansoori model) is extended to include the transversely isotropic elastic response found in vertically cleated coals. This new version of the model has been calibrated by laboratory measurements on San Juan Basin coal loaded under uniaxial-strain conditions to simulate reservoir depletion. The result is a predictive model characterized by two measured Young's moduli and three measured Poisson's ratios. To our knowledge, a rigorous geomechanical analysis of anisotropic coal has not before been incorporated into efforts to match large permeability increases observed in the field. We have been able to match the permeability increases in CBM wells using rock and reservoir parameters that are viable and consistent with independent constraints. To illustrate the results, permeability increases with depletion from a few wells in one area of the San Juan basin have been matched by the new model. The new model should allow better forecasting of gas rates by reservoir simulators, as well as improved predictions of gas production in fields yet to be developed. While there exist many models that seek to explain the huge permeability increases in coalbed methane wells, the significance of this logical extension to the Palmer-Mansoori model (i.e., the addition of coal anisotropy) is that it has the ability to predict permeability increases in wells in the field using measurable rock moduli and other quantities, thus reducing the need for empirically-derived field-matching parameters. Note that this new model confirms an empirical constant that was invoked in a previous version of the Palmer-Mansoori model to account for cleat anisotropy. The rigorous derivation, for anisotropic coal, of permeability increase during depletion provides a missing link (and a significant one) that will save modelers from invoking more esoteric (and unnecessary) factors to try to get a match to field data.

A number of coalbed methane (CBM) to liquefied natural gas (LNG) projects are currently advancing in Australia, among which is the Arrow LNG project. To ensure reliable supply to an LNG plant, production availability of the integrated CBM system consisting of a large amount of wells and production facilities needs to be understood, including the behavior of CBM wells after planned and unplanned shutdowns. This paper provides an analysis of post-shutdown recovery behavior of horizontal CBM wells based on a large volume of field data. There is no known published work on shutdown recovery for CBM wells to date, so there are no comparison data. Arrow Energy has produced CBM for domestic consumption since 2004 and currently supplies about 20 per cent of Queensland's gas from fields in the Bowen and Surat basins. A shutdown recovery analysis is conducted on Arrow's Moranbah Gas Project (MGP) in the Bowen Basin. Field data for 6,436 shutdown periods are used, including: gas rates, water rates and bottomhole pressures (BHP). The following effects on recovery times are analyzed: shutdown duration, pre-shutdown water rate, pre-shutdown gas-water ratio, and pre-shutdown producing days. The results indicate that approximately 70% of wells, shutdown for one day, return to 90% of their previous gas rates within one day. Approximately 20% wells recover in a week and the remaining 10% wells come back to 90% of original rates within 2 months. Furthermore, shutdown periods longer than five days have significantly higher recovery times. Wells with a lower water rate and higher gas-water ratio before the shutdown return to their pre-shutdown gas rate faster than wells with a higher water rate and lower gas-water ratio. Also, late life wells recover faster than wells in early production life. These findings are critical for planning well shutdown and ramp-up strategies (well classifications and priority lists) to manage required gas supply during the operational phase of integrated CBM-LNG projects.

The Qinshui basin covers an area of approximately 42,000 km2 with coal resources and is one of the important regions for coal production and coalbed methane (CBM) exploitation in China. There are two major coalbeds that are important for CBM development. These coalbeds are laminated among sand, shale, and limestone formations and are located approximately from 200 to 1100 m in depth across the basin, with an average thickness between 3 and 6 m. This paper presents a case history of fracture evaluation for a CBM development project in the basin. In this study, fracture growth behavior was evaluated using fracture modeling and microseismic monitoring techniques. The instantaneous shut-in pressure (ISIP) for some treatments in the area of this study was well above the formation overburden stress. Closure stress obtained from diagnostic injection tests was high but lower than the overburden stress. Microseismic mapping results indicated significant fracture complexities, ranging from both confined and excessive height growth to asymmetric fracture growth and multidirectional fracture growth. An abundance of microseisms were detected, but most of them were located in the brittle sand and shale formations below and above the target coalbed. The complex fracture growth is believed to be caused by complex stress regimes and geologic settings in the study area. Fracture closure stress analysis from offset wells confirmed that stress variation was the primary reason for asymmetric fracture growth. Fracture modeling revealed that viscous fluids provided better fracture conductivity in the target coalbed than KCl water, as most proppant would settle below the target coalbed because of the poor transport capacity of water when KCl water was used alone. Based on the results from this study, improvements in fracture treatment design and well spacing should be considered. This paper demonstrates the benefits of an integrated approach to understanding hydraulic fracture growth behavior, which is important for developing a new CBMreservoir.

Coalbed methane (CBM) reservoir with Lower Young's Modulus, higher Poisson's ratio, and lower permeability is different from conventional sandstone reservoir in composition, structure, tectonic and mechanical property, therefore, the fracturing technique and mechanism are much more different. Qinshui Basin located in the southeast of Shanxi Province is of simple synclinorium structure, less of faults, and it has up to 10 layers of coal seams, total thickness 1.2–23.6m and the maximum 6.5m. By far, No.3 and No.15 coal seam of Qinshui Basin have been developed for CBM production, depth from 600m to 900m, and the rank of the coal are mainly meager-lean coal and anthracite. No.3 coal seam of Shanxi Formation is 0.53–7.84m thick, gas content 11.94m3 / t on average, mainly semi-bright coal and semi-dull coal, reservoir pressure gradient 0.7149MPa/100m on average, well-testing permeability 1.589mD on average, Langmuir volume 39.03m3/t on average, Langmuir pressure 2.902 MPa. No.15 coal seam of Taiyuan Formation is 0.6– 9.9m thick, gas content 12.45m3/t on average, mainly bright coal and semi-bright coal, reservoir pressure gradient 0.7727MPa/100m on average, well-testing permeability 1.14mD on average, Langmuir volume 40.91m3/t, Langmuir pressure 2.5417 MPa. Through optimizing the fracturing designs, evaluating fracturing fluid systems and implementing control measures, a set of ‘network fracturing’ treatments with casing injection, high displacement and activated water fracturing fluid as key techniques were developed and applied successfully for coalbed methane in Qinshui Basin with the rate of success more than 95%. The study also showed that the multi-fracture treatment by plugging perforation with plastic ball can be used in separate layer treatment of coalbed methane reservoir. Furthermore, variable injection rate and slug injection of proppant can also be used to achieve the purpose of controlling extension of fractures. In five years,1264 layers (at 1096 wells) were treated by using this fracturing technology in QinShui Basin, and the gas production rate is over 2000 m3/d in 60% fracturing wells.

Dewatering is required to remove water from the coal seams so that bottomhole pressure (BHP) is reduced to a critical point where gas will begin to desorb from the coal. Production Data analysis of over 100 wells which includes both vertical and deviated in Raniganj East Coalbed Methane (CBM) field, India indicates that wells were not dewatered continuously. This was mainly due to the fact that the wells go on workover and extended periods of pump downtime result in re-saturation of the cleat and fracture system with water, thereby inhibiting gas production. So starting and stopping pumping resets the hydrostatic back pressure and water saturation profiles to initial conditions in the reservoir while the gas content remains unchanged, thereby requiring more pumping to achieve the previous level of gas production. An attempt was made to analyze the problem and through production surveillance of past four years production history, various reasons why continuous dewatering was not achieved were pump failures due to high torque, low torque, low pump efficiency and erratic loading conditions. The causes of these pump failures were gas locking, rod/tubing unscrew, stator damage, hole in tubing, plugged intake screens and insufficient motor cooling, etc. This paper discusses best practices to dewater CBM well after rich experience gained by operator in CBM Raniganj East field from series of trial of artificial lift ESP and PCP pump run in individual wells with design modification by using tailpipes and provides specific recommendations and pump operating parameters to dewater effectively and continuously from both vertical and deviated well.

Coalbed methane (CBM) plays usually consist of multiple zones with geologic variability within the areal extent of the play. One of the key indicators of well productivity potential is permeability, which is highly variable zone by zone and area by area. Permeability is also important for understanding gas in place (GIP) and production variability, designing the completion, optimizing well spacing, and diagnosing production problems. Numerous tests may be required to develop a statistically valid permeability data set. The longer rig time and lower-than-expected success ratio of conventional tests are considered the main obstacles in obtaining such a data set. The wireline-conveyed formation tester (WFT) used with a dual packer provides measurements of the permeability, skin, pressure, fracture flow regime, reservoir heterogeneity, and state of saturation of the coal seam through drawdown and buildup. Compared with conventional testing, improved operational efficiency is achieved through more efficient wireline conveyance, improved packer isolation, reduced wellbore storage, ability to conduct downhole fluid analysis, precise downhole rate control, and surface readout and real-time data monitoring and interpretation for informed decisions. Measurement in the openhole conditions allows operational flexibility. The packers are typically set in the bounding shale or sand. To accommodate a multilayer coal seam with varying thickness and typical washout in the bounding shale, several wireline trips may be required to change the tool configuration and distance between the packers at surface. Previously run openhole logs such as dual-axis caliper, acoustic/resistivity borehole imaging, advance dipole sonic, and 3D induction resistivity are used for the coal seam selection and packer positioning. Conducting a WFT productivity test in a low-permeability coal seam provides atypical challenges from conventional oil and gas applications. The method was tested using field data and pressure transient analysis from six CBM wells in eastern and central Kalimantan of Indonesia.

Extended abstract Tight sands gas, coalbed methane and shale gas are three kinds of typical unconventional natural gas. With the decrease of conventional oil and gas reserves, unconventional reservoirs, especially unconventional gas-bearing reservoirs have become the most important supplement and alternative resources. At present, studies of the tight sands gas, coalbed methane and shale gas have become the hotspot of energy research all over the world. As the unconventional gas-bearing reservoirs, they all characterize as ultra-low porosity and permeability, the pore sizes are nanoscale. For tight gas sands, the porosity is main lower than 10.0%, and the permeability is always lower than 0.5 mD, the pore size ranges from 300 to 900 nm, the proportion of nanoscale pore is nearly 85.0%, and the critical pore radius of the lower limit is 20 to 60nm (Zou et al., 2011). For coalbed methane reservoir, the porosity is always lower than 6.0%, and the permeability is lower than 0.002mD, the pore size is lower than 130nm (Yan et al., 2008). In the shale gas formation, the porosity is lower than 10.0%, and permeability is even lower than 0.002mD, the pore size ranges from 80 to 200nm (Erik et al. 2013). The information of pore structure is very important in unconventional gas-bearing reservoirs evaluation. The coalbed methane and shale gas are authigenic reservoirs, and the gas contents are dominant by the adsorbed gas (Sun et al., 2011). Hence, the developmental degree of micropore is of great importance in effective unconventional coalbed and shale gas reservoirs evaluation. Zhao et al. (2012) pointed out that the more development of micropore volumen, the higher content of gas in coalbed methane reservoir. However, in tight gas sands, the micropore content is inversely proportional to the gas production. In this paper, to understand the pore structure of the effective unconventional gas bearing reservoirs, we review the microstructure of these three kinds of unconventional gas bearing formation, and compare the NMR T2 spectra at laboratory and field conditions. The results illustrate that in tight gas sands, the lab NMR T2 spectra in the Xujiahe tight gas sands of Sichuan basin are dominant as unimodal distribution; the T2 relaxation time of the main peak is lower than 100.0 ms. The Bound fluid volume (BFV) ranges from 35.0% to 60.0%, and the average value is 44.3%, and the NMR T2 distributions of field condition are also main unimodal, the T2 distribution are wide in formations with high gas production, and on the contrary, for formations with low gas production, the T2 distributions are narrow and unimodal, and the largest T2 transverse relaxation time is relative lower. In coalbed methane and shale gas reservoirs, the lab NMR T2 spectra are also main unimodal, and the largest T2 transverse relaxation times are far less than that of the tight gas sands. In field condition, the T2 spectra in coalbed methane formations are narrow, and the largest T2 transverse relaxation times are lower than those of the adjacent strata (Adrian et al., 2010). At present, we cannot collect the field NMR logs, hence, the NMR T2 distribution for shale gas reservoir in field condition cannot be compared. In the meanwhile, comparisons of lab NMR spectra for core samples drilled from coalbed methane and shale gas reservoirs illustrate that there are the rapid relaxation components, and a insulated peak with ultra-short relaxation time exist in the NMR T2 spectra under fully water saturated, and there are T2 spectra in dry core samples. For core samples drilled from coalbed methane reservoirs, the relaxation time of insulated peak is lower than 2.0 ms, and for core samples drilled from shale gas reservoirs, the relaxation time of insulated peak is lower than 1.0 ms. With the lab NMR experimental measurements of braise, Guo et al. (2007) and Zhao et al. (2011) pointed that the signals on NMR spectra with rapid relaxation time are contributed by the blind pore. Odusina et al. (2011) and Sulucarnain et al. (2011) also obtained the same conclusion that the signals on NMR spectra with rapid relaxation time for core samples drilled from shale gas reservoirs are contributed by the disconnected blind pore.

Economic production from shale has been intimately tied to hydraulic fracturing since the first signs of success in Barnet Shale in the late 90s. The introduction of horizontal wells and multi-stage hydraulic fracturing was met by a huge move by operators towards developing shale formations that were mainly ignored in the past. Today using pad drilling, multiple horizontal wells share surface facilities and infrastructure, a development that minimizes the industry’s environmental footprint. To understand production from shale reservoirs one must understand the network of natural fractures in the shale and the role of hydraulically induced fractures and their interaction. In this article author proposes a new view of the network of natural fractures in shale that when interfaced with the induced hydraulic fractures, will provide a completely different picture of how stored hydrocarbon is produced. Modeling this new network of natural fractures and its interactions with induced fracture requires fundamental changes in our existing simulation models. Hydraulic fracturing has been around and been studied by engineers for decades. Analytical, numerical and datadriven models have been built to explain their behavior and contribution to flow. Contribution of natural fracture networks to storage and flow in carbonate (and some sandstone) reservoirs had led to the development of techniques to study and model them. Since they are the predominant source of connected porosity and permeability in shale, more attention has been focused on their characteristics in the recent years. Studies of methane production from coal seams in the mid 80s provided insights on sorption as a storage mechanism and desorption and diffusion as a transport phenomenon in reservoirs that came to be known as CBM (Coalbed Methane). Today, production from shale is mainly modeled based on the lessons learned in the past several decades where all the above techniques are integrated to create the modern shale reservoir models. In other words, we use the “Pre-Shale” technology to understand and model hydrocarbon production from shale. This may not be the most efficient path forward 1 . The coupling of hydraulic fractures and natural fracture networks and their integration and interaction with the shale matrix remains the major challenge in reservoir simulation and modeling of shale formations. This article reviews the methods used by the scientists and engineers in recent years to understand the complexities associated with production from shale. This will shed light on the commonly held belief amongst some of the best minds in reservoir engineering (those that have been intimately involved in modeling production from shale) that there is much to be learned about this complex resource and that our best days in understanding and modeling how oil and gas are produced from shale are still ahead of us. Furthermore, an alternative solution to the conventional simulation and moldeing currently used in the industry is proposed. This technology that is used and implemented today can enhance our understanding of production from shale. 1 Needless to say that there is much to be learned from the “Pre-Shale” technology. Nevertheless, hydrocarbon production from shale seem to be different enough to require a completely fresh look at the storage and transport phenomena as it is modeled today in our simulators. May be fluid flow through porouse media is not the dominant phenomenon and needs to be augmented and/or completely replaced by other modes of flow such as flow between parallel, diffiusion controlled, thin plates.

Beam pumping system implementation as alternative of Artificial Lift System to produce the water associated to coalbed methane (CBM), was found for this specific case as the best options in performance and realiability also (production of gas and water, handling of liquid level over the pump and higher run life). The coal extraction developed in Pribbenow and El Descanso Mines involve degassing of coal stratums and dewatering. An artifitial lift is required to ensure an effective dewatering process and accelerate the gas and water recovery. Since the start of the project of CBM (Coalbed Methane) In Pribbenow and El Descanso Mines has been installed three types of artificial lift systems: Progressive Cavity Pump (PCP), Electrosubmersible Pumping (ESP) and Reciprocating Rod Lift (RRP). The installation of Reciprocating Rod Lift Systems began with four wells on February 2010 and currently the project has a population of eleven operative wells, and the expansion program includes the completion of eighteen additional wells by 2012 and 2013. Optimum design installed in each well is composed of: – Hydropneumatic Variable Speed pumping units which had proven been the best choice for this application due to versatility in changing production conditions and in order to have a better handle of presented gas bags.– High Stretch sucker rods that has large resistance and also presenting good performance in corrosion environments, these are centralized according to the wear evidence.– Subsurface Tubing Pumps developed for handling high volumes of water and gas and solids production. The achieved run life with Reciprocating Rod Lift is above seven times the run life obtained with the previous artificial lift systems (PCP and ESP). This application becomes the first successful CBM project in Colombia and has a high potential for expansion to other areas considering that preliminaries evaluations of the CBM resources of Colombia indicates that there are at least 8 regions with large CBM potential.

Abstract DESCRIPTION: In east Ordos basin, there are plenty of coalbed methane (CBM) resources. However, the coalbeds are of strong heterogeneity due to laterally variant thickness and gas contents. Consequently, the heterogeneity gives rise to the great challenges for fine reservoir prediction and evaluation in seismic exploration. For the purpose of applying AVO to CBM prediction, in this paper, combining with geological and geophysical characteristics of CBM reservoirs NO. 5 coal seams from drilling, logging and the relationship between elastic parameters and gas contents in the lab, we established a set of thin coalbed models with different thickness and gas contents to model AVO using reflectivity method. Subsequently, AVO responses to gas contents and thickness of CBM reservoir are systematically investigated. APPLICATIONS: Our researches are theoretical discussion about the relationships between AVO responses and coalbed thickness and gas contents. These relationships can be applied to exploration of CBM reservoirs in practice.

Abstract Geographically, coal-bed methane exploration or development has occurred on every continent with the exception of Antarctica. Worldwide, many different completion techniques have been utilized to develop coal-bed methane reservoirs. These techniques range from vertical well multi seam completions to multiple lateral wellbores drilled into a single coal seam. Stimulation techniques include open-hole under-ream, cavity creation, and hydraulic fracturing. A number of factors influence the selection of completion techniques including proximity to established oil and gas infrastructure, depth, number and thickness of coal seams, permeability, gas content, composition, and saturation, porosity, etc. The purpose of this paper is to survey the various techniques that have been utilized, to provide the rationale for utilization of each technique, to comment on the commercial success of the various techniques, and to propose a general selection criteria approach that may be useful in the selection of a drilling and completion technique. Introduction While CBM well drilling and completion permutations may be practically endless, the following summary descriptions will be covered in this paper: Vertical well, open-hole and under-ream completion, single seamVertical well, cased and open-hole, perforate and under-ream completion, multi-seamVertical well, open-hole cavity completion, single seamVertical well, cased perforated, hydraulic fracture completion, multi seam Plug and Perforate Ball and Baffle Multiple Zone Stimulation Technology (MZST)Vertical well, open-hole under-ream with intercepting single or multiple surface to in-seam open-hole horizontal well(s), single seamVertical well, open-hole under-ream with intercepting a surface to in-seam open-hole multi-lateral horizontal well Other techniques not listed here can generally be considered to be a variation or combination of one or more of these techniques. Many authors have proposed methods for determining the optimum drilling and completion method [1, 2, 3]. These methods have consisted of flow diagrams, empirical studies, and reliance on a few critical reservoir parameters and form the basis for conceptual understanding of the problem. This paper will present an overview of the various CBM drilling and completion techniques; reservoir parameters that need to be considered in the selection of drilling and completion techniques; and a proposed methodology for selecting optimum drilling and completion techniques will be proposed.

Abstract Coalbed methane (CBM) is one of the major clean-burning gas resources. Development and utilization of CBM can increase the energy supply, improve coalmine safety, and protect the global environment. The southern Qinshui basin of China is rich in coalbed methane; it is the first area that obtained good results in the commercial development of CBM in China. However, lost circulation is a common problem during cementing through the fractured coal-seams known as cleats. These cleats form an interconnected fracture network and this allows cement slurry to loss through the coal-seams during cementing operations. Cleats are often wide enough to accept cement slurry, not just cement slurry filtrate. Hence, simply reducing slurry density does not ensure a good cement job. Preventing cement slurry loss to coal-seams while cementing production casing is a major challenge. To solve lost circulation problem across coal formations, an innovative hydrophilic-fiber-based spacer fluid and ultralow density cement slurries with density of 0.95–1.20 g/cm3 have been formulated. Laboratory tests have verified the effectiveness of hydrophilic-fiber-based spacer fluid in plugging these cleats of coal-seams. The ultralow density cement slurries exhibite favorable properties. These test results are confirmed by the goodfield application results obtained in southern Qinshui basin. Fourteen CBM wells have been successfully cemented using the novel spacer fluid and the ultra low density cement slurries. The combined application of the hydrophilic-fiber-based spacer fluid and the ultralow density cement slurry system is able to successfully combate the lost circulation problem in CBM wells, and provides better zonal isolation as well. This paper provides details about the slurry design and field application, and also presents the cement bond evaluations that verify the conclusions.

This paper presents the methodology and technical solutions used to perform an evaluation of Gas Resources for two coalbed methane (CBM) projects in former coal mining basins in the North and East of France. These assessed gas volumes constitute one of Europe's important reported coal bed methane's resources. Successful gas flow rates were also obtained from a horizontal well drilled in coal strata. CBM resources classification principles as described in the Guidelines for Application of the Petroleum Resources Management System (PRMS - November 2011) were applied. The main issues encountered were the allocation and categorization of the 1C/2C/3C Contingent Resources and Low/Best/High Prospective Resources. Dealing rigorously with uncertainties inherent to the type of data used was an essential part of the study. A fully integrated workflow was used to undertake the resources evaluation. The Gas Initially in Place (GIIP) estimation is based on 3D geological models. Project specific criteria were applied to derive the final volume estimation in the context of CBM resources in the vicinity of former coal mines. Potential recovery factor calculations followed 3 different approaches: Langmuir isotherm curves, material balance based on mining data and 3-D dynamic simulation based on pilot horizontal well results. Due to large uncertainties existing on various parameters, a sensitivity analysis was performed to evaluate their relative impact on production during the dynamic simulation, using experimental design techniques. The final resources calculations and their respective categorization were based on a probabilistic methodology using Monte Carlo simulations with specific distributions for all parameters used at each stage of the workflow (net coal, gas content, coal density, level of coal undersaturation, permeability and recovery factor distributions). Key parameters were identified as critical with a large impact on the final assessment (gas content, level of undersaturation, shape of Langmuir isotherm curve, abandonment pressure). The elaborated workflow allowed the classification in Contingent and Prospective resources as well as evaluating their respective range of uncertainty which was required to complete the evaluation.

On the basis of coal-bed methane particularity in China, the pressure, penetration and water-bearing are low. Generally, an extra straight well is needed for the coal-bed methane horizontal wells. And the straight well is connected to the horizontal wells for the entry of rod pump etc to drain water and collect gas. For the connection spot of the vertical well and horizontal well is less than 0.5m in diameter, the connection goal can not be achieved by conventional wellpath measurement. Based on the features of horizontal well, a suit of remote needle technique and relevant equipment is invented, which is used to guide the intersection between horizontal wells and the vertical well. The theoretical principle is rotating magnetic field orientation. By processing the real-time collection data of rotating magnetic field, the distance and angular deviation of drilling direction can be calculated to locate the drill bit and the vertical cavity, and connect the horizontal well and vertical well. In this paper, wellpath measurement and controlling model, method of remote needle technique, and theory of needle equipment were elaborated. This technique has been applied successfully to six horizontal wells in Chinese coal-bed methane basin, such as Ordos basin. All intersections were finshed once only. In the field application, 60m distance away from the cavity can be precisely located for leading connection, the signal of magnetic field is distinct. By the improvement of the model, the system possessees the capability of measuring well deflection to guide the nitersection in 3D. The success of applying needle technique to Ordos basin demonstrates that the established measurement model of needle can be used for the intersection of coal-bed methane horizontal wells, and positioning accuracy of needle equipment satisfy the field demand.

Unlocking the potential of unconventional gas reservoirs can change the balance and future of the oil industry. Unconventional gas reservoirs can be tight-gas, coalbed methane (CBM), or shale reservoirs. Economic production of any of these three types requires the creation of multiple fractures from a long horizontal well. Fracturing horizontal wells presents several challenges regarding the rock mechanics, change of stresses around the created fractures, and fluid flow. New and reinterpreted laboratory experiments have shed new light on fracturing a horizontal well and the effect of how the well is completed on the fracturing process. The results could explain the presence of multiple fractures at the wellbore. These geomechanical issues could influence the fracturing process, especially in naturally fractured formations. This paper investigates the effect of various fracturing scenarios on the stress distribution around the fractures. Optimization of the number of fractures is also investigated from both fluid-flow and geomechanical points of view. Special attention is given to shale formations for two reasons—because of the great potential of shale formations, and because of the special characteristics that makes shale unique and challenging. Shale formations have ultra-low permeability that can be in the nanodarcy range. Shale formations are naturally fractured, and, depending on the carbon content, can have a significant amount of adsorbed gas. This paper also investigates the effect of gas adsorption on productivity. Field examples are presented.

Production enhancement and ultimate recovery improvement have given multi-branch horizontal wells the advantage over the vertical wells in many CBM marginal reservoirs. However, it is relatively very expensive to drill a muti-branch horizontal well than the vertical one, which makes difficulties for the engineers to determine an economical feasibility of drilling the multi-branch horizontal well as well as to estimate the productivity. Through a widely literature review, an advanced non-analytical coupled CBM model has been developed in this study for predicting the flux and pressure in the CBM reservoir and multi-branch wellbore simultaneously. The gridding partition is achieved through adjusting the length of the grid to make the branch with an angle of horizontal direction just across the grid intersect point. The coupled multi-branch CBM model is differeciated using modified IMPES method, LDU decomposition method is used for solving the formed seven point diagonal sparse matrix. Thereafter, the sensitivity analyses were performed to identify the dominant governing parameters such as gas slippage factor, threshold pressure gradient of formation model, branch angle, and branch number of muti-branch horizontal wellbore on the measurements of well deliverability. The observation shows that gas slippage effect can enlarge gas production rate, while the threshold pressure gradient has the opposite effect. The gas production rate increases with the branch number ranging from 2-6, while decreases when the branch number reached to 8, so it is obviously not the case that the more the branch the better the flux enhancement. The gas flux reached to maximum when the branch angle is 45 degree, while minimum with 30 degree angle. Comparison of the fluid flux between vertical well, horizontal well and multibranch horizontal well was also made. Subsequently the proposed coupled model and developed program is validated by its application to Qinshui basin in Shanxi of China.

The inflow performance relationship (IPR) plays an important part in well completion, well production optimization, nodal analysis calculations, and artificial lift design. The production of coalbed methane is different from the conventional gas. For coalbed formation, permeability is sensitive to changes in effective horizontal stress which includes a cleat compression term and a matrix shrinkage term that have competing effects on cleat permeability. Therefore, the conventional method to calculate IPR curve is not completely appropriate for coalbed methane. The production of under-saturated coalbed methane reservoir can be divided into three distinct stages-: single water phase, multiphase gas and water, and single gas phase. Previous literatures either neglect the matrix shrinkage which results in increasing production rate at a given bottom hole pressure or only focus on the last single gas phase stage. This paper presents a new method to calculate the IPR curve for coalbed methane reservoir in the presence of permeability dynamics with pressure based upon P&M or Shi model. A second objective of this paper is to develop an approach for multiphase flow which requires a relationship between relative permeability and pressure, analogous to Fetkovich’s method for oil and gas flow. The methodology is further validated with field data from Qinshui Basin in China. The results indicated that the tool proposed here provides reservoir enginners with a quicker and easier way to estimate the performance of coalbed methane well.

In 2009, a service company performed its first hydraulic fracturing treatment using a conventional hydraulic-fracturing technique in coalbed methane (CBM) wells in India. As progress was made, the potential for performing an extensive number of hydraulic-fracturing treatments in CBM wells was observed. From an operational standpoint, the advantages of recovering CBM wells are that they have more target coal seams at shallower depths that are candidates for stimulation, and the size of the treatments makes them ideal for multiple applications in a shorter period of time, reducing nonproductive time (NPT) for the operating company (Seldle and Arri 1990). The service company introduced a unique fracturing service that integrated two components—coiled-tubing (CT) deployed hydrajet perforating and then immediately performing hydraulic fracturing. By combining these two processes into one continuous service operation it eliminates the use of wireline for perforating and plug setting, making the new multistage technology economical for CBM wells. For the first time in India, this CT perforating/fracturing service was introduced to a CBM well operator. The observations and knowledge gained from the fracturing-service operations in India are discussed in this paper. This process employed hydrajetting technology through CT using a hydrajetting tool in the bottomhole assembly (BHA). Based on the casing specifications, cementing conditions, rock properties, and experience gained with each perforating experience, the jetting flow rates, differential pressures, and casing annulus backpressure requirements were optimized. This increased the life of the tool and improved the overall operations. The hydrajetting tool life was increased from 6 to 8 perforation sets to about 19 to 21 per tool, improving the operational efficiency. The advantages of jetting acid into the created perforations, pressure squeezing with acid, and using the many services of CT are examined. In addition, the BHA is also discussed. In some of the frac stages, the treatment screened out and experienced high concentrations of sand in the wellbore; therefore, the steps taken to help prevent sanding off the tool or getting the CT stuck are reviewed. Sand concentrations of 12 lbm/gal. were achieved for extended periods of time to pack the formations off. The need for using wellbore sand plugs was eliminated for many frac stages in these wells as a result of successfully packing the proppant into the fractures with higher sand concentrations. This helped eliminate concerns of losing fluid and sand into previous fractures when performing new frac stages uphole. As more treatments were executed and experience was gained, fluid usage was optimized and the fluid consumption was reduced by approximately 30 to 40%, providing further value to the operator. Finally, the lessons learned from a projectmanagement viewpoint are also examined, discussing streamlining operations based on the various field and reservoir conditions experienced in India. The knowledge gained from this project could be directly applicable to the fracturing-service operations in other regions with CBM wells. The operational learnings during the course of this project could also serve as a guide to operations in this region where similar challenges are encountered. Introduction It has been observed that CBM wells in India are relatively shallow, ranging between maximum true vertical depths (TVDs) of 2,500 to 4,500 ft. These wells have multiple coal seams, but only a few have an appreciable seam thickness and are targeted for fracturing. It has been observed that the number of seams usually targeted is anywhere from 4 to 14. The treatment number range for one well is ~4 to 14 fracturing stages, with the average number at approximately nine treatments

This paper presents the development of material balance equations (MBE) for coalbed methane (CBM) reservoirs. This method is appropriate for determining Original Gas In Place (OGIP) and predicting fluid mechanisms in coalbed methane reservoirs. Previously, material balance for coalbed has been developed by G.R. King and several researchers. King’s MBE has considered water expansion, rock (cleat) compaction and water influx. In this paper, author added some new aspects such as gas expansion, water connate expansion, moisture expansion, rock (matrix) compaction and also modified King’s p/Z*. Author also explained the derivation of average water saturation equation that hasn’t been explained before. The author used actual data to validate the equation and the results were compared with King’s MBE results. These comparisons are used to determine the magnitude effects between these equations. The proposed material balance provides more accurate results and more options of variables which can be considered and applied as a new equation for simulation.

Resource plays such as Coalbed Methane (also called Coal Seam Gas) fields typically exhibit a number of unique characteristics that set them apart to other hydrocarbon accumulations. We will argue in this paper that as consequence, conducting effective field development planning studies for CBM resources requires adopting a markedly different approach to the ones typically followed with conventional oil and gas fields. In contrast to traditional offshore plays, replete with a rich literature of best practices and adequate tools, coalbed methane field development planning typically involves very large areas and number of wells, hence a correlative abundance of (static and dynamic) data, but also displays an often surprising variability between neighbouring wells. This variability is the consequence of a high degree of heterogeneity present at a small (1’s-10’s metres) to medium (10’s-100’s meters) scale, notably for permeability, but also isothermal properties, gas content, and even net coal distribution and seam geometry for some plays. This paper offers insights on integrated development planning methods, uncertainty management techniques and modelling workflows, accumulated through the experience of a number of CBM plays. Expected relationships and possible cross-parameter models for the key reservoir properties are discussed. The development of practical tools to characterise the reservoir properties, as well as the performance of different well and completion configurations, simulation, field development planning, all the way to ultimately assessing the economic potential of the play are also illustrated.

We discuss detailed well history matches, from the San Juan basin, of coalbed methane (CBM) gas rates, water rates, and pressures. In the sweetspot (fairway) the matching includes permeability that increases strongly with depletion, and is assumed to be exponential, as indicated by independent well tests spaced over time. The permeability increases are well matched by the Palmer-Mansoori (P-M) model. We present statistics of permeability matching to field results by the P-M model in the fairway. First, initial cleat porosities are 0.05–0.17% and consistent with porosities derived from observed water rates. Large permeability increases are not consistent with large cleat porosities. Second, the permeability increase ratio, defined by the maximum permeability reached over the permeability at initial reservoir pressure, varies from 16–170. Third, the matrix shrinkage parameters agree with a recent lab measurement. Fourth, cleat-volume compressibility mostly increases with depletion, when matrix shrinkage becomes dominant and cleats open wider. Last, in many wells north-east of the fairway the perm increase with depletion was found to be similar to that seen in fairway wells. This again suggests cleat porosities less than roughly 0.3%. At low reservoir pressures (

Over the past decade, production from unconventional reservoirs such as coalbed methane has increased dramatically. The focal driving force for this growth in coalbed methane production was the development and promulgation of reservoir engineering and completion technology. There have been many studies performed on the well configuration and production optimization techniques in the coal seams. According to many of these studies horizontal, deviated and multi lateral wells are of more benefit compared to the vertical wells. However, the target of these studies has mostly been the thin coal seams hence this result might not hold for the thick CBM reservoirs. The experience has proved that one thick coal is better than an equivalent thickness of multiple thin coals. Samples of the deep thickest accumulation of coal in the world can be found in some of the areas of the United States such as Uintah basin and Piceance basin in Colorado, Black Warrior basin in Alabama and Arkoma basin in Oklahoma and Alaska. The thickness of coal beds in these areas can reach up to 150 ft and they can be as deep as 9000 ft. Although horizontal drilling will result in higher gas production and consequently more revenue, the drilling cost in these wells are significantly higher than the vertical wells. When the coal beds are thick enough that the contact of wellbore and formation is not a limiting issue, the practicality of drilling horizontally versus multiple vertical wells might be questioned. In this work, the most appropriate drilling patterns in thick and deep CBM reservoirs have been identified. A sensitivity analysis has been performed with the intention of addressing the effect of different reservoir parameters and well configurations germane to methane production from CBM. These characteristics include fracture permeability, fracture porosity, gas content, and desorption time. The yardstick for comparing the economical practicality of different drilling configurations under diverse reservoir properties is the Net Present Value (NPV).

Pioneer Natural Resources (Pioneer) operates over 2200 Coalbed Methane (CBM) wells in the Raton Basin in Colorado. The wells produce out of two formations: the upper Raton and the lower Vermejo Formations. Many of the wells in the basin are completed in only one formation, with two wells on each pad; each well is completed in one of the formations. A number of the wells in the basin are completed in both formations and have commingled production. Pressure drawdown is critical in coalbed methane production, particularly in wells with large commingled perforation intervals; this is accomplished by lowering the gathering pressures and lowering the annular producing gas-water interface (fluid level) of the wells down below the perforation intervals. Pioneer uses acoustic measurement tools to determine the fluid level in the majority of the wells. However, in some of the wells, particularly the commingled wells, the acoustic tool is unable to measure the fluid level. A different method to determine the fluid level is to measure the bottom hole pressure and calculate the fluid level using a downhole pressure gauge. To test pressure gauges in the Raton basin, three wells with large perforation intervals were chosen for a pilot test. Pioneer also chose three companies with different components for comparison. The system was designed to be durable and mobile; it was also designed to connect to the existing production monitoring system. The installations for the three wells were successful, though, there were two gauge failures and several pump failures. After the failures were analyzed, and the production of the wells had stabilized with the fluid below the perforations, two of the gauges were moved to other wells. The intermittent acoustic measurements were compared with the pressure gauge information and the two tracked closely; this increased the confidence in the acoustic measurements when values can be obtained. Several of the goals of the pilot project were achieved, including developing the successful system as planned and obtaining reliable bottom hole pressures. There were additional unexpected results from the project; the failure analysis of the pumps lead to a solution for pump problems in the field, and the results provided Pioneer with a visual training tool for the field employees. It is too early to determine if the gauges could be used to more efficiently manage the commingled wells in the field, but a larger dataset of wells may improve the understanding.

One of the horizons of interest for future unconventional resource development is deep (greate than ~5,000 ft) coalbed methane (CBM) production. Unfortunately, coal permeability is highly sensitive to changes in stress leading to the belief of limited permeability in deep coals. However, this conclusion is generally based on the assumption of constant pore volume compressibility of a coal's porosity/cleat system during changing stress conditions. Modeling the evolution of permeability within potential deep coal reservoirs is highly dependent on this assumption of constant or variable pore volume compressibility. This paper shows how this assumption affects modeled permeability changes and that permeability in deep coals may maintain much higher values during production than previously suggested. Utilizing prior work and data, ideas are reorganized into an alternative view of deep CBM permeability. The modeled compressibility and permeability results are then applied to the simulation of deep CBM reservoirs to discover the practical difference of the compressibility assumption on a coal's simulated production. Simulations show significant difference in production based on the two assumptions. Application of the simulation results may provide a justification for exploration into deeper CBM reservoirs.

Coalbed methane (CBM) production in the San Juan Basin of northwestern New Mexico and southwestern Colorado has spanned over 30 years. Some parts of the field, such as the high-permeability Fairway, are now in a mature stage of reservoir pressure depletion. Optimization of well production operations in the Fairway presents many challenges because of its extremely low reservoir pressure (less than 100 psi in some areas), heavy coal fines production, difficult artificial lift challenges, increasing CO2%, and the presence of paraffin, inorganic scale and corrosion. We use history matching by reservoir simulation to help diagnose the causes of well production inefficiencies and then plan how to mitigate them. Simulation of Fairway wells typically requires the use of an increasing reservoir permeability trend caused by coal matrix shrinkage with the desorption of methane and CO2. However, we have observed in some Fairway wells that below a reservoir pressure of around 300 psi, there is a flattening or even a decrease in the permeability trend. This shift in the permeability trend is likely caused by coal failure (i.e. a change in mechanical properties of coal) that is evidenced in the wells by an increased amount of coal fines production. This paper is written in two parts. The first part presents the challenges we face in operating Fairway wells and the solutions we have developed to overcome them. Field observations and operating guidelines will be shared along with well intervention histories where we have seen success. The second part discusses our use of reservoir simulation to diagnose the causes of reduced well production efficiency.

Fort Assiniboine is a commercial Coalbed Methane field in central Alberta, Canada with over 200 multilateral horizontal wells in the Upper Cretaceous Mannville coal. The Mannville coal seams in this area are under-saturated. Therefore the reservoir's ability to dewater the coal through the fracture fabric to establish a gas phase is key to improving permeability to gas within the fracture system and thus achieving economic gas production rates. There is a wide range of production rates seen across the field. The multiple variables that affect gas production can be divided into a two main categories, wellbore parameters and reservoir parameters. Some of these variables were sufficiently straightforward to establish while other variables, such as permeability, are not as easily ascertained in a fractured coal system having multiphase flow. Field wide data was collected from core, wells, geological and geophysical mapping and production data. The information was compiled and analyzed in order to determine the major controls on gas production rates.

Accurate estimation of gas-in-place is crucial for successful evaluation and exploitation of unconventional gas reservoirs, such as shale gas, coalbed methane, and tight gas. However, gas effective porosity, one of the most important parameter in estimating gas in-place, is commonly measured on crushed samples of cores or cuttings at ambient pressure although many studies have shown that the porosity and permeability of reservoirs rocks decrease with increasing effective stress, and thus the pore volume/porosity measured on crushed samples at ambient (zero stress) conditions will be larger than porosity measured under in-situ reservoir stress conditions. Normally the stress-dependence of porosity is simply accounted for by a correction factor based on the linear poro-elastic deformation, which is likely an over-simplification. In present study, we developed a new protocol for simultaneously measuring stress-dependent In-Situ Permeability and Porosity (ISPP) that provides a method for routine characterization of effective porosity and permeability under simulated reservoir conditions. Our new method can significantly reduce the uncertainties of porosity introduced by testing crushed samples under ambient conditions, testing time, and the need for good quality core samples that are usually unavailable. Preliminary test results indicate that the stress dependence of porosity (or pore compressibility) of fine grained reservoir rocks follows a unique trend of each tested sample, which cannot be simply adjusted from ambient porosity by a universal factor. Physical and numerical sample tests suggest that our ISPP method can obtain permeability similar to the normal pressure Pulse-Decay Permeability (PDP) technique if samples are homogeneous or transversely layered along their axes. Otherwise, our ISPP method likely tests the geometrical average permeability of longitudinally layered samples instead of the weighted arithmetical average permeability tested by the PDP method. Overall, our approach of simultaneously measuring effective porosity and permeability under reservoir conditions offers intrinsically consistent porosity-permeability data to characterize unconventional reservoirs. Our study also reveals that utilization of different methods to test samples in different orientations and different sizes is necessary to rigorously characterize the hierarchical permeability and porosity of heterogeneous and microporous unconventional reservoir rocks.

The purpose of this paper is to provide a view on the South Sumatra basin CBM development potential. The basin ranks as one of Indonesia's most prospective coalbed methane (CBM) basins, but well testing is still in the earliest stages. In S. Sumatra basin there are three distinct identifiable sub-basin evolution periods. First, a period of horst-graben development controlled by major localized extensional faults that initiated the basin architecture. This episode was followed by rapid to moderate sedimentation controlled by normal faults resulting in deposition of Oligocene Talang Akar alluvial, fluvial and deltaic deposits. Secondly, a period of decreased fault activity along with regional subsidence coinciding with the deposition of the post-rifting Miocene Air Benekat and Muara Enim Formations. The third period is marked by regional uplift resulting in wide spread basin inversion over the entire region. Coal seams in the Muara Enim Formation are thickest and most numerous in the SW half of the South Sumatra basin representing key target for CBM development. This is the axial region of the basin where the subsidence has been most pronounced and the formation is thickest. While the coals are quite thick and laterally extensive in the broad synclines, most of the Miocene Muara Enim Formation has been eroded out along the anticlines. The Lematang Depression and the Central Palembang sub-basin are considered the most prospective CBM areas on the basis of coal thickness, depth, and gas kicks on mud logs. The Muara Enim formation comprises more than 3500 ft of paralic sandstones and mudstones, with thick intercalated coal seams. Typically some 10 to 15 individual coal seams are present.The coals are of sub-bituminous rank and characterized by low vitrinite (huminite) reflectance (VRr = 0.35 – 0.46%). These low rank coals are dominated by huminite (34.6 – 94.6 vol. %). Less abundant are liptinite (4.0 – 22.5 vol. %) and inertinite (0.2 – 43.9 vol. %). Minerals are found only in small amounts (0 – 5 vol. %); mostly as iron sulfide. Kaolinite occurs as cleat fillings at some places. The coals are characterized by high moisture content (4 – 21 %) and volatile matter content (> 40 wt.%, daf), and less than 80 wt. % (daf) carbon cotent.CO2 and CH4 sorption isotherms on six different coal samples were carried out at reservoir temperature. Given the uncertainty around the gas content measurements, the coals tend to suffer from some serious under saturation. The sorption capacities of the coals tend to decrease with increasing depth. This behavior can either be related to the increasing moisture content of the coal with depth or with the significant variation of the vitrinite content of the deeper seams. The high CO2 adsorption capacity and the low rank tend to make these coals ideal targets for CO2 sequestration.

When coalbed methane is recovered, complex interactions of stress and chemistry have a strong influence on the properties of the coal. These include influences on gas desorption and flow, coal deformation, porosity change and permeability modification. Although coal-gas interactions have been comprehensively investigated, all of these prior studies usually assume that these interactions are under conditions of invariant total stress where effective stresses scale inversely with applied pore pressures. Here we develop a novel coal permeability model that defines the relations between directional permeabilities and strains, and implement a FE model that couples desorption of the coalbed methane and water flow within a deformable medium (coal) where the effects of deformation are rigorously accommodated. This relaxes the prior assumption that total stresses remain constant and allows exploration of the coalbed methane production under the full range of mechanical boundary conditions from invariant stress to restrained displacement. We apply this model to investigate the productivity of coalbed methane production under in situ conditions. The results show that increasing the absolute permeability could shorten the dewatering stage of the coalbed methane production, but the shape of the production curves does not change with the absolute permeability. For permeability anisotropy coal seams, the fluids mainly flow in face cleats direction and locating more wells in butt cleats direction is high efficient for coalbed methane production. The relative permeability dominates the fractional flow and thus controls the shape of the production curves. It determines when the commercial gas rate could be achieved and how much water should be coped with during the dewatering stage. Therefore both the absolute permeability and relative permeability are key factors for the dewatering stage of the coalbed methane production.

Detecting and locating microseismic events that occur during a hydraulic treatment of a coalbed-methane (CBM) formation can be challenging because of the special properties of the formation itself and the specific treatment parameters. Based on experience gained working with dozens of monitored CBM treatments, several specific challenges and their solutions can be identified. Events created during such treatments are usually small in magnitude as a result of the often small injection rates and petrophysical properties of the target formation. To detect these small events over the ambient noise, the sensors have to be in relatively close proximity to the injection. In addition, it is important to reduce the ambient noise as much as possible. Because options to reduce ambient noise are limited, it is imperative to ensure that the sensors and casing are securely coupled to the surrounding rock. In some cases, it is better to place the sensors higher above the zone of interest if a better coupling can be achieved. Another common challenge in CBM formations is the high velocity contrast between the target formation and the surrounding rock, which creates some mathematical challenges in the accurate localization of the events. Extensive model calibration, accurate logs, and clear events in known locations (e.g., perforation shots) can improve the overall location accuracy significantly. Most of these issues can be addressed in prejob modeling studies that quantify viewing distances, location accuracy, and waveform appearance etc., before any microseismic data is acquired. These studies help anticipate potential challenges for particular projects as well as document realistic accuracy levels, which are essential for a comprehensive interpretation of the microseismic-event distribution.

In the San Juan basin Fairway, cavitated Fruitland coalbed-methane (CBM) wells have been successfully producing for the past 30 years. However, over the years, coal-fines migration into these cavitated wellbores has resulted in pump issues and coal-fines production, leading to a significant decline in production. To clean out the coal fines and replace the pumps on a continuous basis is a costly workover issue. Hence, a foamed remedial treatment was designed to displace the conductivity-plugging coal fines away from the wellbore and immobilize them with the foam also serving as a diverting agent. This has allowed the production and dewatering process to continue without any interruption. The remedial treatment was chosen because the aqueous tackifier in it can control the fines and help prevent them from plugging the flow path. Also, it dissolves any calcium-carbonate scale in the wellbore and near-wellbore region. In this study, 15 cavitated wells with coal-fine issues were selected for the foamed remedial treatment. In all of these 15 wells, the coal-fines issues were resolved. This allowed production to be uninterrupted and reduced the cost of workover rigs and pumps. As a secondary benefit, production stabilized in 10 wells and increased in 5 of these wells. This study shows the production results from these two groups of wells that were treated. It also discusses the design options for the treatments and lessons learned from the process. This technology can be applied to openhole as well as cased multilayered CBM wells.

In coal seam gas (CSG), also known as coalbed methane (CBM), appraisal, the development potential of a play requires an understanding of the interrelationship between stress and permeability, critical elements in defining deliverability and hydraulic fracturing effectiveness. Unfortunately, the interdependency of these variables may not emerge until the post-treatment evaluation of a hydraulic fracturing treatment. Herein is an example from the Walloon Subgroup (WSG), Surat Basin, where regional data were used to target a small, localized, structural setting for CSG appraisal and subsequent hydraulic fracturing.Due to the rank of the WSG coals in this area, the cleat network was deemed to be immature and permeability is understood to be derived from exogenetic fracturing from external stresses acting on the coal, creating a unidirectional fracture network. The fractures are commonly constrained to brittle lithologies and truncate at bedding boundaries, while evidences exist of minor low angle faulting in non-reservoir lithologies. Eventually, the local stress regime was determined from the petrophysical log data, injection stress testing, and subsequent one-dimensional (1D) mechanical earth model (MEM). Ultimately, these data support the proposed reservoir and stress environment.We will show how data were acquired, evaluated and integrated to support the development of the 1D MEM and aided the interpretation of the hydraulic fracture treatment results. While localized, the results of this evaluation indicate a potential pitfall can exist in some CSG environments. This case illustrates a scenario where stress and dominant permeability axes can be properly aligned to maximize hydraulic fracture effectiveness, but where sub-optimal stress magnitudes prevent achieving the full benefit of the hydraulic fracturing process.

In developing new coalbed methane (CBM) or coal seam gas (CSG) fields or reservoirs, the effect of many parameters are important in understanding the success or potential areas for improvement of hydraulic fracturing treatments. Estimating fracture geometry relative to the reservoir architecture is critical to understanding production variability. The Walloon Coal Measures, in the Surat Basin of Eastern Queensland, Australia, are a complex reservoir containing interbedded sandstone, siltstone, carbonaceous shale and coal seams where initial attempts at hydraulic fracturing in early pilot areas of the Surat Basin yielded poor results. Thus, when a hydraulic fracturing program was planned for this reservoir, it was decided to integrate a group of diagnostics that would be useful in understanding past results as well as deriving future improvements. Data is presented from two wells in the Walloon Sub Group (WSG) where tiltmeters and microseismic monitoring were used to evaluate fracture effectiveness relative to the reservoir architecture and to assist further design work. The treatments carried out in the studied wells were typical of CSG frac treatments used in other producing areas, incorporating stages of treated, gelled and crosslinked-gelled water with increasing concentrations of sand, up to six (6) lbm/gal. During the treatments, complex fractures were inferred based on analyses of data from both tiltmeter and microseismic monitoring methods. The collaborative data set for these wells also included a large amount of other analyses and diagnostic data. It was only possible to fully explain the treatment results through the combination of multiple diagnostics and an in-depth understanding of how the created fracture interacted with the complex reservoir and stress environment. In this paper, we outline the steps used to plan the monitoring program and describe how geological data was integrated to better understand the results observed during the treatments. We describe each of six (6) stages performed across the two wells, and how the diagnostics did or did not support the overall conclusions as to the effectiveness of each stage. Finally, this paper presents a logical framework to evaluate and integrate these technologies for use in future CSG well stimulation.

Methane production from coalbed methane (CBM) fields started as a method for keeping coal mining safe from explosions. Major CBM fields are located in San Juan, Powder River, Forest City, Black Worrier and Illinois. Majority of the US natural gas production comes from coalbed methane formations. These formations also have the potential of carbon dioxide (CO2) storage through enhanced gas recovery operations. Enhanced coalbed methane (ECBM) recovery by injection of gases such as CO2, nitrogen (N2) or a mixture of both gases has been proven to recover additional natural gas resources. Most of the coalbed methane formations contain large amounts of water or can be in communication with an aquifer. As a result a large amount of water is often co-produced during the natural gas extraction. The water being produced from deep formations is not high purity water and contains nitrate, nitrite, and chlorides and has high level of total dissolved solids. Production of methane from CBM is facilitated by the reduction of the methane partial pressure in the coal seam by either pumping the formation water to the surface or by injecting a dissimilar gas. The produced water contains a lot of harmful impurities which should be removed. Therefore, disposal of the produced water is an environmental challenge and accordingly, a reduction of the produced water is enviable. In this paper we present a detailed numerical investigation of the potential reduction in water production during ECBM operations while increasing the methane production. We employ a three-dimensional coalbed model with an aquifer located on the bottom to investigate the amounts of gas and water produced in ECBM operations per volume of coal seam as a function of aquifer strength, cleat spacing and sorption characteristics of the coal. The amount of gas/water that is produced varies extensively depending on the aquifer strength. We demonstrate that injection of CO2 and/or N2 in some settings reduces the water handling problem substantially. CBM is an essential energy source with a lot of formations being exceptional candidates for ECBM recovery processes. The analysis we present in this paper on the water production reduction by using the injection gas which relatively produces less water provides new strategy for future operations.

Cement is placed as a sheath across coal seams in coalbed methane wells primarily for hydraulic isolation and to support the casing. Designing a cement job for coal seam wells requires contemplating factors beyond those considered in cementing conventional oil & gas wells. Cement invasion into coal seams, losses during jobs, annulus pack off and low fracture gradient are the challenges generally encountered during cementing these wells. The low formation temperature also exacerbates the challenges as the cement must set within drilling schedule time constraints. Predicting the bottom hole circulating temperature during cementation is also a challenge because many such wells are drilled with air. Finally, most coal wells will be fractured and proppant placed for production enhancement. Cement invasion or improper cement sheath will hinder fracture performance. Based on a seven-year study, pumping lower-density slurries does not completely prevent cement invasion but does affect the cement quality behind the casing. Achieving successful cement jobs in these wells requires special designs and techniques. The requirements include not only extensive testing in the lab, but also special placement techniques and cement systems designed to accommodate a low fracture gradient and to avoid cement invasion into these soft seams. This paper will share case histories and best practices developed from seven years of experience in designing and placing cement successfully in coalbed methane wells in India. These case histories will include cement design considerations, lab testing procedures, special placement techniques and cement system choices.

Coalbed methane (CBM) formations deliver a considerable amount of the US natural gas production and have the potential of storing significant amounts of carbon dioxide (CO2) through enhanced gas recovery operations. Enhanced coalbed methane (ECBM) recovery by injection of CO2 or a mixture of CO2 and nitrogen (N2) has been proven to recover additional natural gas resources. However, since coalbeds are normally saturated with water and can be in communication with an aquifer, a large amount of water is often co-produced during the natural gas extraction. The conventional approach for CBM production relies on the reduction of the gas partial pressure in the coal seam. This can be accomplished by either pumping the formation water to the surface or by injecting gas. Disposal of the produced water is an environmental challenge and harmful impurities must be removed. Consequently, a reduction of the water production is desirable. In this paper we present a detailed numerical investigation of the potential reduction in water production during ECBM operations while increasing the methane production. We use a three-dimensional coalbed model with an aquifer located on the bottom to investigate the amounts of gas and water produced in ECBM operations per volume of coal seam as a function of aquifer strength, cleat spacing and sorption characteristics of the coal. The amount of gas/water that is produced varies significantly depending on the aquifer strength. We demonstrate that injection of CO2 and/or (N2) in some settings reduces the water handling problem substantially. CBM is an important worldwide energy source with a large number of formations being excellent candidates for ECBM recovery processes. Our analysis of the interplay between coal characteristics, aquifer support and the resultant behavior in terms of gas/water production and CO2 storage capacity provides valuable new guidelines for future operations.

After 30 years of CBM production in the USA, and internationally more recently, general principles and decision trees have emerged to guide an operator in choosing a well completion based on permeability. If enough permeability measurements are made, well completions can be prioritized, and hybrid well completions evaluated. The benefits of horizontal and multilateral wells are made clear. Low permeability is a serious challenge for CBM ventures, and further success will entail finding regions of enhanced permeability, utilizing horizontal wells, and "creating" permeability by new-paradigm methods. Perm-based guidelines for CBM well completions are given, which include permeability bands and benchmarks. Industry success has led to two benchmarks for evaluating ahead of full-field development (1) commercial success from reservoir parameters, and (2) effectiveness of well completions. The perm-based guidelines are simple and practical, and should benefit any CBM completions strategy. We also re-examine the striking observations of permeability increases with depletion (10-100 times) in the San Juan basin. The latest attempts to model and match the strong permeability increases with depletion in the San Juan basin are evaluated. Although there remain differences, a consensus has been obtained for some reservoir parameters.