Coal Seam Gas Field Research Articles

Don’t forget your keys when trying to unlock the productivity of low-permeability coals

Low-permeability coal seam gas (CSG) wells have been the subject of laboratory research and modelling studies over the past decade, particularly focusing on the pressure-dependent permeability (PDP) behaviour of coals. These research efforts have progressed diagnostic methods to identify and quantify PDP and provide practical technologies to counter these effects. Firstly, machine learning methods based on drilling and historical well-test data can provide insight into the range of coal permeability during drilling. Next, the process of history-matching the after-closure pressures from a diagnostic fracture injection test (DFIT), using reservoir simulators, can determine best-fit values for fracture compressibility, a key parameter for reservoir models. Finally, these data, along with DFIT reservoir pressure and permeability data, can inform the decision-making process regarding the most applicable completion strategy and aid developmental planning. For areas where vertical or surface-to-inseam (SIS) wells have been unsuccessful, new hydraulic fracturing technologies have been developed to enhance the stimulated reservoir volume (SRV) in coals, using horizontal wells with multi-stage hydraulic fracturing in excess of 20 stages. Recent laboratory and modelling of micro-proppants has extended prior laboratory and modelling studies and provided insight into proppant transport, embedment, and screen-out behaviour. These well stimulation technologies can be co-applied in new or existing CSG fields and are suitable for areas where overlapping tenements limit conventional, steel-based completion strategies. In conclusion, this paper will bring the key findings of these studies together in a cohesive framework and provide the workflows to implement these technologies for better productivity in low-permeability coals.

A novel methodology for assessing the potential for formation bridging in coal seam gas fields: A case study from southern Queensland

The substantial growth in the development of coal seam gas (CSG) – also known as coal bed methane – fields in southern Queensland, Australia, over the past decade has been associated with various impacts on the environment and human activities. Of particular concern is the potential impact of CSG-induced subsidence on farming operations. Previous research in underground coal mining has shown that overlying competent formations can function as bridges over mined-out areas, effectively preventing subsurface deformation from fully or partially reaching the ground surface. Formation bridging can also occur in CSG producing areas. Modelling formation bridging is essential for understanding and predicting the historical and future impact of CSG production on the surface, respectively. This paper introduces a novel modelling methodology based on the elastic plate theory that helps in assessing the potential for formation bridging in overlying formations during CSG production. The applicability of this approach is demonstrated through a case study in the Surat Basin of southern Queensland. This study shows that excluding bridging for a particular formation rules it out for that formation when overlain by other formations or when it is thinner. Results of this study indicate that formation bridging in the study area may only occur during the very early phase of a CSG well's life cycle. Where the diffusivity of the coal seam is low, leading to a slower expansion of the influence area, there is also an increased likelihood of bridging taking place and persisting for an extended duration. Although the methodology introduced in this paper is mainly analytical, it offers an initial evaluation of the formation bridging probability across extensive basins where conducting detailed three-dimensional numerical modelling is challenging, if not impractical. This preliminary analysis may assist in deciding whether, and where, more comprehensive and detailed assessment of formation bridging is necessary.

Concurrent 14. Presentation for: The transformation of Australia’s first commercial CSG field into a major gas project: how innovation and subsurface understanding has driven its success

Presented on Wednesday 18 May: Session 14 Mount Isa Mines Limited discovered coal seam gas (CSG) in the ‘Dawson Valley’ in 1991. It was the first commercial coal seam gas field in Australia, with production and sales of gas commencing circa 1994, then operated by Conoco and known as Meridian SeamGas. In 2010, Westside Corporation acquired a 51% operating interest in Meridian SeamGas from Anglo American (Anglo) and Mitsui Moura Investment Pty Ltd (MMI). Over the last 10 years, Westside has increased sales by 466% from 9 terajoules per day (TJ/d) to 42 TJ/d with gas being sold to both domestic and export markets. Further acreage acquisition to the north and south increased the asset area by 264%; now known as the Greater Meridian Fields (GMF). The steep rise in gas demand, complex market dynamics, regulatory environment, and competition from large global oil and gas operators makes it a challenging environment for smaller gas producers in Australia. Remaining agile and employing innovative approaches to optimise field development are key factors for Westside’s growth. In particular, the pad-based drilling of up dip multi-lateral wells has reduced cost and surface footprint, while enabling more efficient gas drainage. To support this field development, a more robust subsurface framework was required. Adequate knowledge of the distribution and variability of coal thickness, gas content/composition, structure, and geohazards forms the basis of the static model. It is used for resource definition and for the optimal planning and execution of multi-lateral wells, reducing drilling risks. To access the presentation click the link on the right. To read the full paper click here

The transformation of Australia’s first commercial CSG field into a major gas project: how innovation and subsurface understanding has driven its success

Mount Isa Mines Limited discovered coal seam gas (CSG) in the ‘Dawson Valley’ in 1991. It was the first commercial coal seam gas field in Australia, with production and sales of gas commencing circa 1994, then operated by Conoco and known as Meridian SeamGas. In 2010, Westside Corporation acquired a 51% operating interest in Meridian SeamGas from Anglo American (Anglo) and Mitsui Moura Investment Pty Ltd (MMI). Over the last 10 years, Westside has increased sales by 466% from 9 terajoules per day (TJ/d) to 42 TJ/d with gas being sold to both domestic and export markets. Further acreage acquisition to the north and south increased the asset area by 264%; now known as the Greater Meridian Fields (GMF). The steep rise in gas demand, complex market dynamics, regulatory environment, and competition from large global oil and gas operators makes it a challenging environment for smaller gas producers in Australia. Remaining agile and employing innovative approaches to optimise field development are key factors for Westside’s growth. In particular, the pad-based drilling of up dip multi-lateral wells has reduced cost and surface footprint, while enabling more efficient gas drainage. To support this field development, a more robust subsurface framework was required. Adequate knowledge of the distribution and variability of coal thickness, gas content/composition, structure, and geohazards forms the basis of the static model. It is used for resource definition and for the optimal planning and execution of multi-lateral wells, reducing drilling risks.

Coal seam gas industry methane emissions in the Surat Basin, Australia: comparing airborne measurements with inventories.

Coal seam gas (CSG) accounts for about one-quarter of natural gas production in Australia and rapidly increasing amounts globally. This is the first study worldwide using airborne measurement techniques to quantify methane (CH4) emissions from a producing CSG field: the Surat Basin, Queensland, Australia. Spatially resolved CH4 emissions were quantified from all major sources based on top-down (TD) and bottom-up (BU) approaches, the latter using Australia's UNFCCC reporting workflow. Based on our TD-validated BU inventory, CSG sources emit about 0.4% of the produced gas, comparable to onshore dry gas fields in the USA and The Netherlands, but substantially smaller than in other onshore regions, especially those where oil is co-produced (wet gas). The CSG CH4 emission per unit of gas production determined in this study is two to three times higher than existing inventories for the region. Our results indicate that the BU emission factors for feedlots and grazing cattle need review, possibly requiring an increase for Queensland's conditions. In some subregions, the BU estimate for gathering and boosting stations is potentially too high. The results from our iterative BU inventory process, which feeds into TD data, illustrate how global characterization of CH4 emissions could be improved by incorporating empirical TD verification surveys into national reporting.This article is part of a discussion meeting issue ‘Rising methane: is warming feeding warming? (part 1)’.

Isotopic signatures of major methane sources in the coal seam gas fields and adjacent agricultural districts, Queensland, Australia

Abstract. In regions where there are multiple sources of methane (CH4) in close proximity, it can be difficult to apportion the CH4 measured in the atmosphere to the appropriate sources. In the Surat Basin, Queensland, Australia, coal seam gas (CSG) developments are surrounded by cattle feedlots, grazing cattle, piggeries, coal mines, urban centres and natural sources of CH4. The characterization of carbon (δ13C) and hydrogen (δD) stable isotopic composition of CH4 can help distinguish between specific emitters of CH4. However, in Australia there is a paucity of data on the various isotopic signatures of the different source types. This research examines whether dual isotopic signatures of CH4 can be used to distinguish between sources of CH4 in the Surat Basin. We also highlight the benefits of sampling at nighttime. During two campaigns in 2018 and 2019, a mobile CH4 monitoring system was used to detect CH4 plumes. Sixteen plumes immediately downwind from known CH4 sources (or individual facilities) were sampled and analysed for their CH4 mole fraction and δ13CCH4 and δDCH4 signatures. The isotopic signatures of the CH4 sources were determined using the Keeling plot method. These new source signatures were then compared to values documented in reports and peer-reviewed journal articles. In the Surat Basin, CSG sources have δ13CCH4 signatures between −55.6 ‰ and −50.9 ‰ and δDCH4 signatures between −207.1 ‰ and −193.8 ‰. Emissions from an open-cut coal mine have δ13CCH4 and δDCH4 signatures of -60.0±0.6 ‰ and -209.7±1.8 ‰ respectively. Emissions from two ground seeps (abandoned coal exploration wells) have δ13CCH4 signatures of -59.9±0.3 ‰ and -60.5±0.2 ‰ and δDCH4 signatures of -185.0±3.1 ‰ and -190.2±1.4 ‰. A river seep had a δ13CCH4 signature of -61.2±1.4 ‰ and a δDCH4 signature of -225.1±2.9 ‰. Three dominant agricultural sources were analysed. The δ13CCH4 and δDCH4 signatures of a cattle feedlot are -62.9±1.3 ‰ and -310.5±4.6 ‰ respectively, grazing (pasture) cattle have δ13CCH4 and δDCH4 signatures of -59.7±1.0 ‰ and -290.5±3.1 ‰ respectively, and a piggery sampled had δ13CCH4 and δDCH4 signatures of -47.6±0.2 ‰ and -300.1±2.6 ‰ respectively, which reflects emissions from animal waste. An export abattoir (meat works and processing) had δ13CCH4 and δDCH4 signatures of -44.5±0.2 ‰ and -314.6±1.8 ‰ respectively. A plume from a wastewater treatment plant had δ13CCH4 and δDCH4 signatures of -47.6±0.2 ‰ and -177.3±2.3 ‰ respectively. In the Surat Basin, source attribution is possible when both δ13CCH4 and δDCH4 are measured for the key categories of CSG, cattle, waste from feedlots and piggeries, and water treatment plants. Under most field situations using δ13CCH4 alone will not enable clear source attribution. It is common in the Surat Basin for CSG and feedlot facilities to be co-located. Measurement of both δ13CCH4 and δDCH4 will assist in source apportionment where the plumes from two such sources are mixed.

Modelling the cumulative impacts of future coal mining and coal seam gas extraction on river flows: Applications of methodology

This manuscript presents examples of the modelling of the impacts of coal mining and coal seam gas extraction on streamflow in five study catchments in Australia. The manuscript includes details on data preparation and model set-up and calibration. The modelling methodology enables the prediction of cumulative impacts from multiple future coal resource developments and distributes these predictions at multiple locations in the landscape. It is framed in terms of a structured uncertainty analysis to provide information on the likelihoods and potential ranges of various impacts. Also included is a qualitative uncertainty analysis which subjectively assesses the likely impact on model results of various assumptions made during the modelling procedure. Model results suggest that, in the Australian context, maximum percentage reductions in annual streamflow are approximately commensurate with the proportion of coal mine coverage. In coal seam gas fields, reductions in annual streamflow are proportional to well density. The manuscript goes on to demonstrate how these modelling results can be used to identify a zone of potential hydrological change within a catchment. This zone delineates those parts of the landscape where water-dependent landscape classes and assets may be vulnerable to change associated with changes in the streamflow regime. A corollary of this is that any parts of the landscape outside the zone of potential hydrological change are unlikely to be affected by coal resource development.

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

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

A framework for inclusion of faults in coal seam gas risk assessments

Assessments for coal seam gas (CSG) projects may be required to consider the potential hydrological impacts of faults on surface and near-surface groundwater assets. This study presents three distinct end-member geological scenarios and outlines methods for characterising fault-related groundwater flow within a risk assessment context. Scenario 1: a regional aquitard isolates the water assets from the coal seams. There is little risk of leakage across the aquitard because there are no faults, or because the faults have maximum displacements less than the thickness of the aquitard. Scenario 2: a region-wide aquitard is not present, and the seams and the groundwater assets are located within the same groundwater system. In this scenario, CSG development may cause pressure changes to propagate parallel to the strike and dip of the fault in the fault damage zones. Scenario 3: regional aquitard(s) are present, but larger displacement faults breach the aquitards, allowing for possible combinations of across-fault connections between the different aquifers, and between aquifers and the coal seams. In this scenario, potential flow pathways between the groundwater and the CSG field need to be characterised using Allan Maps (fault plane profiles). It is essential to compare calculated flow rates of any new or potentially new flow pathways with the predevelopment flow regime. It is also important to recognise that flow estimates are best made using a Darcy’s law treatment for flow across fault zones and within the aquifers, and a Snow’s law treatment (discrete fracture network) for flow through fractures in fault damage zones.

Improved modelling of pressure-dependent permeability behaviour in coal based on a new workflow of petrophysics, hydraulic fracturing and reservoir simulation

Many coal seam gas (CSG) reservoirs (also known as coalbed methane) can have low permeability, require stimulation to produce economic rates and often exhibit pressure-dependent permeability (PDP) behaviour. Defining PDP behaviour in coal using reservoir simulation is a non-unique problem based on the uncertainty in coal properties and input parameters. Recent research demonstrated that an integrated analysis coupling of a diagnostic fracture injection test analysis, hydraulic fracture modelling and reservoir simulation can better characterise PDP behaviour in order to evaluate stimulation effectiveness in coals (Johnson et al. 2020). The present work aims to improve the recently developed model by including multilayer and permeability anisotropy effects. A reservoir model with multiple coal layers is established in a pressure-dependent reservoir simulator, based on the image log interpretations. Permeability anisotropy in the formation is realised by introducing heterogeneous distribution of permeability in different directions. Modelling results indicate effects of aspect ratio between multilayers on the pressure distribution and production history. A lower permeability anisotropy ratio yields better well productivity, and higher stimulation is required to increase the stimulated reservoir volume to maximise gas recovery. The improved model and workflow are applicable to other CSG fields for defining key variables where hydraulic fracturing performance has been unable to overcome limitations based on pressure dependency, often accompanied by low-permeability behaviour. This workflow has applications in Australia and many areas (e.g. China and India) exhibiting low-permeability and PDP behaviour and where only typically collected field data is available.

New Integrated History Matching Approach for Vertical Coal Seam Gas Wells in the KN Field, Surat Basin, Australia

In order to obtain a reliable production forecast for the coal seam gas wells, a history matching was usually conducted to calibrate the simulated water and gas rates to the observed values. This paper presents a case study of history matching vertical coal seam gas wells from the KN Field in the Surat Basin, Australia via a new integrated approach. This approach includes two steps, i.e., determining the key parameters for history matching on the basis of the uncertainty and sensitivity analyses first, and then history matching the observed production data starting from the field level to the local area level to the individual well level. This approach has two significant technical novelties: (1) the range of parameters was defined as the constraint and (2) the direction and extent of production response were considered when modifying the parameters in the history matching. In the study area, satisfactory history matching results were achieved for all 66 wells, which have been produced for 10 or more years, after running only 34 simulation cases. Some practicable strategies were also proposed in this study to overcome the challenges of the history matching task for a coal seam gas field. Results show that the distributions of the final parameters from history matching are consistent with the actual reservoir conditions of this area. These strategies can provide reference for the simulation work of other unconventional gas reservoirs.

Controls on Gas Domains and Production Behaviour in A High-Rank CSG Reservoir: Insights from Molecular and Isotopic Chemistry of Co-Produced Waters and Gases from the Bowen Basin, Australia

This paper uses hydrochemical and multi-isotope analysis to investigate geological controls on coal seam gas (CSG) saturation domains and gas well production performance in a high-rank (vitrinite reflectance (Rv) > 1.1) CSG field in the north-western Bowen Basin, Australia. New hydrochemical and stable isotope data were combined with existing geochemical datasets to refine hypotheses on the distribution and origins of CSG in two highly compartmentalized Permian coal seams. Stable isotopic results suggest that geographic variations in gas content, saturation and production reflect the extent of secondary microbial gas generation and retention as a function of hydrodynamics. δ13C and δ2H data support a gas mixing hypothesis with δ13C-CH4 increasing from secondary biogenic values to thermogenic values at depth (δ13C −62.2‰ to −46.3‰), whereas correlated methane and carbon dioxide carbon isotope compositions, Δ13C(CO2–CH4) values and δ13CDIC/alkalinity trends are largely consistent with microbial CO2 reduction. In addition, below 200 m, the majority of δ13C-CO2 values are positive (δ13C: −1.2‰ to 7.1‰) and δ13CDIC shows an erratic increase with depth for both seams that is characteristic of evolution via microbial activity. The progression of carbon isotope values along the CO2 reduction fractionation line suggests progressive depletion of the CO2 reservoir with increasing depth. Faults clearly segment coal seams into areas having significantly different production, with results of geochemical analysis suggesting that pooling of biogenic gas and waters and enhanced methanogenesis occur north of a faulted hinge zone.

Development of a highly automated mobile rig for the Australian CSG market

In Q2 2020, a fully automated rig will enter the coal seam gas fields of Queensland, to work for a major operator. It is expected to be 20–30% faster than current operations. This document describes the upfront iterative design process with local potential users. Following discussions with various contractors and operators it became evident that there was a gap to bridge between operator and contractor targets and in what current operations have to offer. Both strive for the highest safety levels and operational efficiency, reducing the overall time per well, completed by minimising environmental impact. The above fits in the overall industry trend of transformation from mechanised rigs towards fully automated hands-free operated rigs. It was with these ingredients that the basis of a new iterative design process was formed, in which input from the operator field lieutenants, contractor rig crews and the supporting office was translated into a technical design. The target was set to reduce 20–30% of time per well. Key elements were the choice for road legal trailerised loads with no loose items, which resulted in rig moves of 4–6 h. Fully automated sequenced pipe tripping and casing running contributed to big improvements in efficiency and safety level (no people on the floor during standard operations). Performance can be real-time evaluated and optimised by collecting all rig and downhole data on the OPC server. The server also controls the mud system, downhole data and other important systems. This enables through-life time optimisation.

Technology Focus: Gas Production

Technology Focus While it is easy to see the local gas bubbles and shortages forming, we always seem surprised when it actually happens. The summer of 2019 has been rife with media reports about negative gas pricing in the Permian and, given the propensity of our industry to pick a favorite horse and then all pile on it at the same time, it is not surprising when we create our own boom and bust cycles. Is it the nature of capitalism or crowd psychology or just human nature that we repeatedly drill ourselves into negative cashflow territory and then wonder how we got there? Meanwhile, politicians and environmental activists in the northeast US have stalled pipeline permits, which has led to blackouts and construction cancellations. Gas meant for those markets has to find another home. Surpluses create dynamics like a river overflowing its banks during a flood; old channels are scoured clean and new outlets are created. There is disruption and unwelcome change but also new opportunities. Soon, nearly a billion cubic feet per day of gas will be flared in Texas alone, and innovators are looking for ways to recover value from that excess associated gas. Several operators are expanding gas enhanced-oil-recovery projects in the Eagle Ford, while others are testing the same process with less success in the Bakken. Small-scale gas-to-liquid plants can turn a few million cubic feet per day into high-quality diesel for local consumption. That shipping container full of power-hungry computer processors on a remote oil lease is turning associated gas into Bitcoin. The Jones Act was enacted nearly a century ago to protect US shipbuilders, but now it keeps waterborne liquefied natural gas (LNG) originating in Texas from being sold to any other US customer, prompting New Englanders to import Russian LNG instead. On a more commonsense note, LNG transport by rail is a simple way to deliver gas to LNG-powered ships and those affected by pipeline constraints. One resource is always consumed to create another, but can we manage the pace of development to avoid overshooting demand or store secondary products for a rainy day? Can we do better next time and not be a victim of our own success? Those who find ways to create value from what others consider a waste product will be respected by both entrepreneurs and environmentalists alike. Recommended additional reading at OnePetro: www.onepetro.org. SPE 192114 Increasing Coal Seam Gas Field Productivity With Horizontal Well Technology: A Case Study by Xuejun Lin, Sinopec, et al. SPE 192853 Boosting Condensate Recoveries of a Mature Retrograde Gas-Condensate Field in Pakistan by Sheraz Ahmed, Pakistan Petroleum, et al. URTeC 83 Intrawell Interference in Tight Oil Reservoirs: What Do We Need To Consider? Case Study From the Meramec by Mouin Almasoodi, Devon Energy, et al. URTeC 264 A New Method for Production Forecasting: Predictive Analytics vs. Conventional Methods in the Montney by Melanie R. Popp, Geologic Systems, et al. URTeC 402 Experimental and Numerical Investigation of Diffusion-Based Huff•‘n’•Puff Gas Injection Into Lower Eagle Ford Shale Samples by Qinwen Fu, University of Kansas, et al.

Discrete-NTG Truncated Gaussian Simulation: An Alternative Modeling Approach for Coal-Seam-Gas Unconventional Reservoirs, Bowen Basin, Eastern Australia

Summary Building a representative static model for predicting and monitoring the performance of coal-seam gas (CSG) fields presents several complex and unique challenges. The individual reservoirs possess different coal architectures, often with highly complex seam splitting, amalgamating, and structural deformation. Our objective was to develop an alternative approach that honored log and core data capturing both the lateral heterogeneity and the vertical signature of the Bowen Basin coals in Central Queensland. In some areas of the Bowen Basin, coals can be thick and laterally continuous; picking the top and base of each seam works well in small models with homogeneous coals. As seam geometries begin to increase in complexity and coals become more heterogeneous in nature with thinner seams in multiple packages, then a net-to-gross (NTG) approach is often more appropriate. Each method has its merits. The former approach describes the reservoir architecture but implies a certain degree of confidence in coal correlation. In a vast field with complex seam splitting and merging with abundant drilling data, it might not be a practical technique. The NTG method disregards coal-seam architecture and reservoir connectivity. The proposed workflow is a hybrid approach using discrete modeling algorithms and data-analysis tools on continuous NTG properties. The process operates on a relatively coarse chronostratigraphic framework in which coal is captured as contiguous discrete-NTG “facies.” The use of the truncated Gaussian model ensures the ordering of NTG facies and mimics transitions between coals and the surrounding interburdens. With the adoption of facies vertical proportion trends, we are able to replicate a similar coal-seam signature laterally away from the wellbore. The definition of a categorical coal model allows the proper scaling of seams with different coal-quality characteristics. With the successful geocellular-model construction and history match of two historical CSG fields in the Bowen Basin, the discrete-NTG truncated Gaussian simulation (TGS) approach has proved to be a valid alternative CSG-modeling technique.

Comparison of a novel coupled hydro-mechanical model with typical analytical models in subsidence of coal seam gas extraction

Although the influence of conventional oil and gas extraction on surface subsidence has been widely recognised and studied, few studies are carried out on the surface subsidence in coal seam gas fields and its impact on surface infrastructure and the environment. In predicting land subsidence caused by coal seam gas extraction, the hydro-mechanical behaviour of geological strata are different and their hydraulic connections to the coal seams are not well-understood, which makes the analytical models are difficult to be applied in the prediction of land subsidence. This paper develops a coupled fluid flow-geomechanical model which can consider the interrelation of fluid flow and geomechanics of the ground. By comparison of dewatering and degassing with typical analytical models including the disc-shaped reservoir model and the uniaxial compaction model, the typical analytical models cannot estimate the potential pressure distribution and predict the real subsidence induced by coal seam gas extraction; however, the coupled fluid flowgeomechanical model is capable of describing the transport properties of coal seam, including water flow, gas flow and desorption and rock deformation. Therefore, the proposed coupled model can be better used in analysis of subsidence of coal seam gas extraction. [Received: April 15, 2017; Accepted: October 17, 2017]

Comparison of a novel coupled hydro-mechanical model with typical analytical models in subsidence of coal seam gas extraction

Although the influence of conventional oil and gas extraction on surface subsidence has been widely recognised and studied, few studies are carried out on the surface subsidence in coal seam gas fields and its impact on surface infrastructure and the environment. In predicting land subsidence caused by coal seam gas extraction, the hydro-mechanical behaviour of geological strata are different and their hydraulic connections to the coal seams are not well-understood, which makes the analytical models are difficult to be applied in the prediction of land subsidence. This paper develops a coupled fluid flow-geomechanical model which can consider the interrelation of fluid flow and geomechanics of the ground. By comparison of dewatering and degassing with typical analytical models including the disc-shaped reservoir model and the uniaxial compaction model, the typical analytical models cannot estimate the potential pressure distribution and predict the real subsidence induced by coal seam gas extraction; however, the coupled fluid flowgeomechanical model is capable of describing the transport properties of coal seam, including water flow, gas flow and desorption and rock deformation. Therefore, the proposed coupled model can be better used in analysis of subsidence of coal seam gas extraction. [Received: April 15, 2017; Accepted: October 17, 2017]

Lined tubing performance in CSG wells operated in Australia

One of the major challenges with progressive cavity pump (PCP) applications in Australia is the production of highly concentrated solids. Large volumes of solids entering the production string cause both high torque issues and holes in tubing, resulting in lost production and the need for intervention with a flush-by unit or service rig. On account of these issues, it is reported that up to 40% of PCPs in the Australian coal seam gas (CSG) fields can be down at any given time. Coho Resources has introduced lined tubing as an engineered solution. The proprietary lining the tubing has a lower friction factor compared with conventional steel tubing, resulting in lower operational torque and reduced operating costs. The added lubricity from the lower friction coefficient in lined tubing allows solids to flow more freely to surface where they are captured and discarded from the system. Lined tubing allows producing companies to realise bottom-line operational savings in several ways. The largest of course is minimal downtime and reduced well service costs due to the elimination of our previous tubing related problems. With reduced work over costs, savings become visible very quickly. Rig costs, bottom hole pump, tubing and sucker rod replacement costs are all reduced. Application of lined tubing in CSG wells in Australia results in: • 15–25% less torque on the drive system, • An 70% increase in run times between workovers (lined tubing versus un-lined tubing), and • Compatibility with existing field equipment and handling methods.

From the Beetaloo to West Texas: similarities, differences and lessons learned from water management in coal seam and shale field developments on either side of the Pacific

Water management presents a host of challenges and opportunities for operators developing unconventional onshore gas fields. Water supply, recycling and disposal issues affect each stage of field development and operation. Sourcing water and production of produced and flow back water has important implications for water availability and management of the unique environmental risks. All water source and produced water decisions come with costs. From the treatment and reuse of coal seam gas (CSG) produced water, through to the storage and ultimate disposal of water containing elevated salinity and organic loads in shale fields, the costs for water management fundamentally contribute to the economics of unconventional gas developments. In this paper, we will draw on experience in both CSG and shale field water management to compare the respective water management challenges and opportunities faced by operators in these industries. A series of case studies will be used to highlight the differences between the CSG and shale fields. This will include assessment of a West Texas shale field development, where field specific data, such as well-to-well distance and travel time between them, has been used to identify and compare produced water management options. We will use these indicators to demonstrate how alternative ways to assess produced water options, based on economics, can reveal creative management strategies that achieve a variety of goals at every stage of field development, including maximising reuse and minimising disposal.

An integrated approach to the Surat Basin stratigraphy

The stratigraphy of the Surat Basin, Queensland, has historically been sub-divided by formation and unit nomenclature with a few attempts by other authors to apply sequence stratigraphy to existing formation boundaries. At a local- to field-scale, lithostratigraphy may be able to represent stratigraphy well, but at regional-scale, lithostratigraphic units are likely to be diachronous. To date, this lithology-driven framework does not accurately reflect time relationships in the sub-surface. An entirely new integrated methodological approach, involving well tied seismic data and sequence stratigraphic well-to-well correlations compared with published zircon age dates, has been applied to hundreds of deep wells and shallower coal seam gas wells. This method sub-divides the Surat Basin stratigraphy into defendable 2nd order to 3rd order sequence stratigraphic cycles and has required the use of an alpha-numeric sequence stratigraphic nomenclature to adequately and systematically label potential time equivalent surfaces basin-wide. Correlation of wells is the first step in building models of aquifers and coal seam gas fields for numerical simulation of fluid flow, which is necessary for responsible resource management. Lithostratigraphic correlations will overestimate the extent and hydraulic connectedness of the strata of interest. The result may be fluid flow models that do not represent a realistic pressure footprint of the flow. The present sequence stratigraphic method more accurately reflects the disconnectedness of sub-surface coals and sandstones (aquifers) on a field-to-field scale, adjacent field-scale, and basin-wide scale. It forms the basis for improved and more representative modelling of the sub-surface.