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Collaborating Authors
Results
Integrated Modelling Workflow for Life Cycle Development of a Large Scale Coal Seam Gas Field
Sharma, Vikram (Arrow Energy Ltd PTY) | Davies, Josh (Arrow Energy Ltd PTY) | Vella, Benjamin (Arrow Energy Ltd PTY) | Jiang, Jesscia (Arrow Energy Ltd PTY) | Sugiarto, Isan (Arrow Energy Ltd PTY) | Mazumder, Saikat (Arrow Energy Ltd PTY)
Abstract Development of coal seam gas fields is conceptually simple but complexity arises with: the stochastic nature of coal reservoirs continually changing work scope the large number of wells required to meet gas contracts. In the current environment, the cost of developing thousands of wells and hundreds of kilometres of associated gathering is a key driver to the success or failure of CSG projects. Continuous reduction in cost/funding with limited resources drives companies to derive an integrated approach to the field development. Subsurface models now form an integral part of production forecasting and decision making. Companies have benefited from the computation technological advances in the recent past, whereby it is possible to run large-scale models in a reasonable timeframe. Several tools and approaches are available today to integrate complex 3D reservoir models with surface networks to generate an integrated production forecast. In this paper we focus on using advanced geospatial applications with integrated system models to derive a development concept which is optimal, realistic and capable of adapting to changes in work scope as the development progresses. Gathering routes and associated material take off (MTO) points are generated in geographic information system (GIS) tools, using constraints and criteria such as: access and approvals sub-surface data (scope of recovery maps, net coal and permeability) maximum use of existing infrastructure (Roads, Tracks, etc.) environmental constraints (overland flow, vegetation, etc.) well spacing. Seamless integration of GIS tools and sub-surface modeling tools is what makes this workflow unique. GIS tools acts as a key integrator, forcing different disciplines and departments to work together in a common platform. It also functions as a common database used across an entire organisation. GIS toolbox gives a significant head-start to the project by first defining what is achievable. It is then finessed with the best value sub-surface outcome and a final forecast is derived in a significantly shorter time scale. With the approach presented in this paper, the forecasting cycle, involving full economic run, is substantially reduced– from several months to just weeks, if not days. The final outcome is an achievable well sequence which is derived along a realistic gathering route. With this, the MTO and the production forecasts are aligned and the associated costs can be easily traced to source. This workflow is automated and can be easily repeated if scope or project premise changes. Last but not least, this approach can be applied to any onshore unconventional or conventional plays.
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
- Oceania > Australia > Queensland > Central Highlands > Bowen Basin (0.98)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 563 > Warrior Field (0.97)
Abstract Unconventional gas exploration in the Cooper Basin, Australia, has historically concentrated on fracture stimulation of tight gas sandstones within mapped structural closures. In drilling these sandstones, and other clastic reservoir targets, it has been recognised for many years that the Permian coal measures of the Toolachee, Epsilon and Patchawarra Formations record high levels of gas, often in excess of 4000 units, encountered at depths between 2500 and 3500m. Unlike shallower Coal-Seam-Gas reservoirs, which rely on de-pressuristion through de-watering to liberate adsorbed gas from the kerogen surface, deep coals are a "dry" system in which the free gas component is produced via kerogen and fracture permeability. However maintaining a consistent and commercial flow rate from deep coals alone remained enigmatic until the first dedicated fracture stimulation program of deep Permian coals was commenced in the Moomba Field in 2007. Understandings of Permian source-rock reservoirs, the roles of the coal type and rank on sorption capacity and porosity, the influence of effective pressure and depth on coal permeability and the interrelation of coal fracture permeability with in-situ stress and mechanical stratigraphy has now advanced. The deep Permian coal fairway in the Patchawarra and Nappamerri Trough of the Cooper Basin has been defined and mapped using a generative potential approach within a comprehensive 3D basin model. Net coal thicknesses from log electro-facies for 879 wells has been combined with available well maturity, TOC, HI and kerogen kinetic data, and calibrated against corrected temperatures in a basin-wide Trinity retention model which incorporates 14 mapped regional horizons. Play fairways have been overlain with observations of in-situ stress direction and fracture orientations from 3D seismic curvature volumes, FMI data and stress states from Mechanical Earth Models (MEM). Within the basin, this approach has defined a P50 in-place resource of 14.6 TCF of gas and a P10 of 20.7 TCF of gas within the deep coals of the Permian Toolachee, Epsilon and Patchawarra Formations in Senex permits, of which 8-11 TCF is within the North Patchawarra Trough. MEM's have also demonstrated that deep coal seams are consistently in a normal stress state and therefore provide excellent scope for both propagating and constraining vertical fracture growth. Work is now underway to define further those areas, within the mapped resource parameters, which provide the best opportunity to site pilot lateral wells for multi-stage fracture stimulation within deep coals.
- Oceania > Australia > South Australia (1.00)
- Oceania > Australia > Queensland (1.00)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Oceania Government > Australia Government (0.46)
- Oceania > Australia > Western Australia > Perth Basin > Carynginia Shale Formation (0.99)
- Oceania > Australia > South Australia > Warburton Basin (0.99)
- Oceania > Australia > South Australia > Cooper Eromanga Basin > Moomba Field > Toolachee Formation (0.99)
- (42 more...)
Abstract Historically, openhole barefoot completions used in conjunction with cavitation and surging or underreaming techniques, have proven to be an effective way to stimulate coal seam gas wells to increase effective permeability. (Logan et al, 1989). However, despite having a positive impact on production, the unpredictable time required to cavitate and surge the wells can be substantial, sometimes requiring up to 4 weeks to execute required scope. This time consuming technique leaves the operator vulnerable, working in an unstable borehole where fishing operations are common and the outcome of delivering scope is not guaranteed. The main challenges of accurately predicting cost to keep the projects economical, continuing to produce coal fines during cavitating and surging, and continual sloughing are some major drawbacks. The other alternative on the market is underreaming, which has its own limitation in relation to the maximum possible enlargement of the borehole or more specifically, the size of the underreamer that can be utilized. Faced with these limitations, there was a significant need for an innovative way to stimulate wells to increase production while minimizing costs. This paper introduces the ingenious use of a newly designed jetting tool, with specialized nozzles, to enlarge a borehole size using a combination of air and mist. This case study conducts a lookback on design parameters, cost, and safety improvements introduced by this new technology.
- Oceania > Australia > Queensland > Central Highlands > Bowen Basin (0.99)
- North America > United States > New Mexico > San Juan Basin (0.99)
- North America > United States > Colorado > San Juan Basin (0.99)
- North America > United States > Arizona > San Juan Basin (0.99)
Abstract The Australian coal seam gas (CSG)/coal bed methane (CBM) fields present multiple challenges (i.e., losses, naturally fractured formations, and highly depleted zones) typically addressed using various well design and cementing techniques (i.e., additional casing strings, stage cementers/tools, lost-circulation materials, lightweight designs, and additional cement volume) to manage the potential risk of losses. Foamed cement is a viable option to address these challenges; however, despite the documented benefits, its application within Australia has been minimal at best. The lack of application can be primarily attributed to misconceptions concerning cost, potential risk, excessive equipment footprint, and a limited proven track record, which increases the potential risk of execution. A recent 10-well campaign conducted within the Bowen Basin, Queensland, Australia, demonstrated that foamed cement can be used as an alternative to traditional lightweight and/or elastomeric cement slurries. Further, the benefits of foamed cement make it an economically and technically advantageous solution compared to conventional cementing techniques used to overcome CSG challenges. This case study details the campaign challenges, cement design, and detailed results of the 10 wells with the intention of providing other engineers a road map to better understand foamed cementing with a specific Australian context and how it could be applied to their projects.
Abstract Building a representative static model for predicting and monitoring performance of coal seam gas fields presents several complex and unique challenges. The individual reservoirs possess very different coal architectures, often with highly complex seam splitting, amalgamating and structural deformation. The objective was to develop an alternative approach which honoured log and core data capturing both the lateral heterogeneity and the vertical signature of the Bowen Basin coals, 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 may not be a practical technique. The later method (NTG) disregards coal seam architecture and reservoir connectivity. The proposed workflow is designed to take advantage of both NTG characterization and facies modelling technique using a combined hybrid approach. The process is operating on a relatively coarse layered chronostratigraphic framework in which coal is captured as contiguous discrete-NTG "facies". The utilization of the Truncated Gaussian model ensures the contiguity of facies and mimics transitions between coals and carbonaceous mudstones (or other transitional interburdens). With the adoption of facies vertical proportion trends we are able to replicate a similar coal seam signature laterally away from the well bore. The definition of a categorical coal model allows the proper scaling of seams with different coal quality characteristics. With the successful geocellular model re-construction of two historical Coal Seam Gas (CSG) fields in the Bowen Basin, the discrete-NTG Truncated Gaussian Simulation approach has proven to be a valid alternative CSG modelling technique.
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > Queensland > Central Highlands > Bowen Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
- (3 more...)
Abstract A full-field dynamic simulation model has traditionally been seen as the benchmark for assimilating all available static and dynamic data to develop robust production forecasts. Santos’ experience modelling the Walloon Coal Measures in its Surat Basin acreage has shown that the performance of individual wells producing from this CSG reservoir is governed by reservoir variability at a fine-scale. This presents a fundamental challenge in developing full-field dynamic models that can accurately describe and predict production performance down to the scale of individual coal seams. Current Queensland CSG projects have focussed on the most prospective acreage, however as subsequent developments move to more marginal areas a greater understanding of the subsurface will be required for optimum development. The target formations will increase in geological complexity, such as Santos’ Surat Basin acreage on the edge of the CSG fairway. Here wells produce from a greater number of distinct coal reservoir units, and how these reservoir units are structured and relate to each other governs reservoir connectivity and defines long-term production performance. Each reservoir unit is comprised of multiple coal plies, all with their own unique maceral distribution and cleating characteristics. These fine-scale properties define the reservoir's dynamic behaviour, and can be impossible to upscale such that these characteristics are preserved at a coarse scale. Consequently, accurately modelling individual well performance will require a fine-scale model to capture and characterise this variability. In development areas where the quantity and quality of reservoir data gathered from exploration and appraisal is sparsely populated, these fine-scale models will need to be populated geostatistically. Without model-scale appropriate control data from production and pressure measurement in the development wells to provide constraints however, a probabilistic model will not accurately define fine-scale behaviour of specific reservoir units. These data requirements can help shape the appraisal scope for new areas and define an appropriate level of surveillance for producing assets. Traditional full-field dynamic modelling has fundamental limitations for interrogating complex unconventional CSG reservoirs at a fine scale. Because of this, alternative workflows are required to answer the subsurface questions necessary to develop CSG assets such as the Surat Basin effectively. This paper details a selection of workflows explored to address this pragmatically, as well as their limitations and associated data requirements. This will also assist in identifying data gaps needed for optimum reservoir management and to aid in the development of these challenging CSG reservoirs.
- Geology > Rock Type > Sedimentary Rock (0.91)
- Geology > Geological Subdiscipline (0.68)
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > Queensland > Central Highlands > Bowen Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
- (2 more...)
Abstract A system for reducing solids production in Surat basin coal seam gas (CSG) wells was developed in the laboratory and tested in the laboratory and field trials. Several thousand CSG wells were completed in Surat basin in eastern Australia using what was considered an economic method at a time - an open hole with a predrilled liner. Although the majority of the wells are meeting production expectations, a many wells are producing a substantial amount of solids originating from an interburden rock representing approximately 90% of completed interval length and comprising mudstones, sandstones, and siltstones rich in illite/smectite and other water-sensitive clays. Relatively fresh water, with total dissolved solids (TDS) of approximately 4000 to 7000 mg/l, produced from multiple thin coal seams during dewatering and production phases is causing the interburden rock to swell or disintegrate. Prolific wells with high water rates or high gas velocity are capable of carrying solids to the surface where the solids are deposited in separators, flowlines, and water-treatment settling ponds. Higher solids concentration on lower-rate wells are causing issues with positive cavity pumps (PCP), the artificial lift method of choice in CSG wells. Pump intake plugging with solids, excessive torque and rotation seizure, and wear of tubing/rod strings are frequent causes of workovers and shorter-than-expected pump run-life. Some wells are able to flow freely; however, an extra monitoring program is required to ensure wellheads are not suffering from solids-induced erosion. Recompletion of the wells is not considered practical at this stage because pre-perforated joints form an integral part of the 5 ½-in. or 7-in. casing string, which is cemented above the Walloons subgroup coal seams. An external casing packer (ECP) is often used. Some coal seams were underreamed, thus further complicating recompletion. Plugging existing wells and drilling a pair of wells using same surface location and infrastructure have been considered. A chemical wellbore stabilization solution been developed to alleviate/stop solids production from the interburden rock. The treatment comprises two fluids separated by a spacer that contains clay stabilizer that is typically 3 to 7% KCl, the same as drilling mud base. Proprietary surfactant reduces the possibility of coal damage. Regained permeability testing performed using crushed and sieved coal pack plugs indicated a low level of damage. The wellbore stabilization system could be energized/foamed to reduce hydrostatic pressure and increase compressibility, hence increasing the chance of contacting rock surface in an enlarged wellbore.
- Oceania > Australia > Queensland (1.00)
- Oceania > Australia > New South Wales (0.83)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.96)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.89)
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > Queensland > Central Highlands > Bowen Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
Abstract In this paper we present an example of a Coal Seam Gas field evaluation that funnels multiple realisations of the subsurface forecast for different well spacing into a simple visual tool for economic screening of the development opportunities. The evaluation approach can be described as follows: consolidate the available data in a regional scale geological model; identify the prospective production seams and areas based on a combination of static properties; automatically populate the potential development areas with model wells of different types, completions and lateral spacing; and run the resulting multiple reservoir models in a dynamic simulator. Finally economic metrics, e.g. average gas produced per well, unit cost, or NPV, are applied to the predicted production, and the development options are compared when the metrics are plotted against the total produced gas or well count. Application of the workflow to an actual project evaluation demonstrated its robustness for the decision making process. The area of interest is about 100 km and contains several coal seams, which are proposed to be developed using surface to inseam, horizontal wells. Several well layouts with different spacing between lateral wells were evaluated using multiple subsurface realisations. Proposed wells in each development option were sorted by their median (P50) of predicted produced gas volume and their economic metrics plotted against the total produced gas. If the best wells are drilled first, the economic value of the project starts eroding after a certain number of wells are drilled. This happens because each new well delivers less gas while the cost of the well doesn't reduce at the same rate. The sweet spot is being exhausted. The cloud of well metrics as a function of the number of wells drilled or total gas produced provides an efficient tool for evaluating the optimal size of the project and its economic feasibility. Due to relatively low permeability of the coal cleat system and large area of interest, the static model had to be split spatially and by seams with the model grid being refined for dynamic simulation. Automation of this workflow made it possible to evaluate multiple development options with multiple subsurface realisations within a tight project timeframe. The workflow provides a structured framework for selecting economically feasible development options based on the pre-defined criteria while taking into account the subsurface complexity and uncertainty.
Abstract The operator's strategy is to maximise economic upstream gas production by drilling technically-mature sustaining wells in depleted areas of Surat basin in Queensland, Australia. To date the operator has drilled more than 2800 Coal seam gas wells with minimal well control issues. Historically wells drilled in Surat basin were normally pressured vertical wells with depths ranging from 600-1000m TVD. The wells are drilled with water + KCL (weighting agent) with mud weight in range of 8-6-9 ppg. However, few wells drilled in late 2016/17 in Central Surat area showed signs of significant depletion in terms of drilling fluid losses and multiple well control events which suggested that prolonged production from these coal seams have reduced the reservoir pressure & correspondingly fracture gradient. Those wells were controlled with conventional well control methods. But this had an impact on the well duration and the wells were drilled at considerable cost. This prompted the Well Engineering team to look for alternative mud systems which can reduce the losses to coals and any reservoir productivity impact. This paper represents the well planning and design process undertaken to drill these depleted wells with a Near balanced fluid system – Aerated mud (a combination of water and air). The author also has included operational results from four trial coal seam gas wells drilled with Aerated mud. The objective of the trial was to understand the impact of drilling the depleted coal seams with lighter fluid and any time/cost impact.
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline (0.95)
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
Abstract Coal seam gas (CSG) well operators typically follow an industry rule of thumb 0.5 ft/s liquid velocity to prevent the onset of gas carryover during CSG dewatering operations. However, there is very little experimental data to validate this rule of thumb with only a publication by Sutton, Christiansen, Skinner and Wilson [1] available in the open literature. A review of more general studies on two-phase gas-water flows in vertical pipes and annuli revealed that experimental conditions, especially pipe and annuli diameters, can have a significant impact on development of two-phase flow phenomena. As such, the limited available data may not be applicable due to differences in experimental conditions. This study experimentally investigates the onset of gas carryover using an experimental setup intended specifically for the study of CSG wells. The University of Queensland Well Simulation Flow Facilities were designed to replicate as closely as possible the production zone of a typical vertical CSG well in Queensland, Australia in transparent acrylic pipes to observe two-phase flow behavior in simulated downhole conditions. The annular test section in the rig was constructed of a 7-in casing and 2¾-in tubing. Modification of the experimental setup to include a vertical separator allowed for the detection of gas carryover. Conceptual demonstrations of gas carryover were captured and have been illustrated. The experiments in this study validate the industry rule of thumb of 0.5 ft/s liquid velocity as an appropriate guideline for onset of gas carryover in a casing-tubing annulus dimension similar to a typical CSG well in Queensland.