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Collaborating Authors
Reservoir Simulation
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)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- (2 more...)
Abstract Nanoparticle (NP) based enhanced oil recovery (Nano-EOR) has been considered as a promising future EOR strategy. However, although many mechanisms of Nano-EOR have been proposed, a lack of direct connections between the pore-scale mechanisms and the macro-scale oil recovery performance makes it hard to determine which mechanisms are dominant. In this work, we discovered a novel phenomenon of nanoparticle-crude oil interaction in pore-scale. Multi-scale experiments were conducted to connect this novel pore-scale phenomenon's role to oil recovery performance. A microchannel with dead-end pore was used to observe crude oil-NP interactions, on which crude oil can be trapped in the dead-end pore with a stable crude oil-aqueous phase interface at the pore-throat. A glass porous micromodel was used to conduct oil displacement experiments. ASW was used as the secondary flooding fluid, and 2000 PPM negatively charged NP in ASW was applied as the tertiary flooding fluid. Saturation profiles were recorded and analyzed by advanced image analysis tools. A coreflood through the sandstone sample was also conducted with similar conditions to the micromodel-flood experiments. A phenomenon that has never been reported was observed from the dead-end pore microchannel. It was observed that crude oil can considerably swell when contacting the nanoparticle aqueous suspension. In an ideal case (5 wt% NP in DI water), the oil volume more than doubled after a 50-hour swelling. The possible explanation for the crude oil swelling could be spontaneous formation of water droplets in the crude oil phase. NP can very likely affect the distribution of natural surfactants in crude oil (on the interface or inside oil phase), which breaks the water balance between aqueous phase and crude oil. This view has received support from quantitative experiments. It was shown from 2.5 D micromodel flood experiments that 11.8% incremental oil recovery comes slowly and continuously in more than 20 hours (40 pore volumes). From a saturation profile analysis, swelling of crude oil was found to improve sweep efficiency. Coreflood experiments also showed that the incremental oil was slowly and continuously recovered in about 20 hours during NP flooding. We propose that reduction of local water mobility by oil swelling in the swept region is the mechanism of sweep efficiency improvement. Swelling of crude oil under a NP environment was observed for the first time, with a systematic theory proposed and examined by quantitative experiments. The micromodel flood and coreflood experiments showed slow incremental oil recovery with a similar time scale to the oil swelling. Image analysis on the micromodel flood demonstrated improvement in the sweep efficiency during NP flooding. The mechanism for this sweep improvement is proposed.
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- (2 more...)
A Comprehensive Study on Ultimate Recovery and Optimum Production Strategy for Gas-Condensate Reservoirs under Aquifer Support in Nam Con Son Basin, Offshore Vietnam
Tran, Tung V. (Biendong POC) | Truong, Tu A. (Biendong POC) | Ngo, Anh T. (Biendong POC) | Hoang, Son K. (Biendong POC) | Trinh, Vinh X. (Biendong POC) | Dang, Tuan A. (Biendong POC) | Ngo, Hai H. (Biendong POC)
Abstract Despite the importance of determining the maximum recovery and optimum production strategy for gas-condensate reservoirs under aquifer support, a rigorous systematic methodology is not available in the literature. Instead, most existing studies relied on running reservoir simulations with fine grids or LGR constrained by simulation runtime, producing great uncertainty in the reliability of the results. In this study, a comprehensive and systematic study of gas-condensate reservoirs under aquifer support was conducted instead. This study focused on first benchmarking radial simulation models to available analytical solutions to within 1% of pore pressure prediction. Next, Cartesian grids were benchmarked against the calibrated radial model before applying to full field reservoir model. The full field reservoir model was then history-matched for all wells before various production regimes were simulated to determine optimum production strategy. Sensitivity analysis of water-breakthrough and total produced water volume were investigated under various aquifer sizes, formation reservoir properties, and production regimes. Optimum production strategy was selected to maximize the hydrocarbon recovery while reducing the water treatment costs. The approach focused on the construction of benchmarked models to describe the water breakthrough phenomena and to investigate the impact of aquifer on deliverability and ultimate recovery of a gas-condensate reservoir. Factors that could affect recovery such as withdrawal rate, aquifer size, formation permeability, and vertical-to-horizontal permeability were examined. Different production schemes were then simulated on a history-matched full field model to determine optimum strategy. It was found that for better reservoir quality (permeability greater than 100 mD), withdrawal rates do not have significant impact on ultimate gas recovery. On the other hand, with increasing withdrawal rate cumulative condensate recovery decreases and total water production increases. Aquifer size has large impacts on recovery factor, water breakthrough time, and total water production. For medium and strong aquifers, it was found that the field water handling capacity could impose a significant constraint on ultimate recovery and upgrading water handling capacity later in the field life may be instrumental in improving recovery.
- North America > United States (1.00)
- Asia > Vietnam > South China Sea (0.50)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
Abstract Despite decades of numerical, analytical and experimental researches, sand production remains a significant operational challenge in petroleum industry. Amongst all techniques, analytical solutions have gained more popularity in industry applications because the numerical analysis is time consuming; computationally demanding and solutions are unstable in many instances. Analytical solutions on the other hand are yet to evolve to represent the rock behaviour more accurately. We therefore developed a new set of closed-form solutions for poro-elastoplasticity with strain softening behaviour to predict stress-strain distributions around the borehole. A set of hollow cylinder experiments was then conducted under different compression scenarios and 3D X-Ray Computed Tomography was performed to analyse the internal structural damage. The results of the proposed analytical solutions were compared with the experimental results and good agreement between the model prediction and experimental data was observed. The model performance was then tested by analysing the onset of sand production in a well drilled in Bohai Bay in Northeast of China. Acoustic and density log along with core data were used to provide the input parameters for the proposed analytical model in order to predict the potential sanding in this well. The proposed solution predicted the development of a significant plastic zone thus confirming sand production observed by today sanding issue in this well.
- Research Report > New Finding (0.49)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.31)
- Oceania > Australia > New South Wales > Sydney Basin (0.99)
- Asia > China > Tianjin > Bohai Basin > Huanghua Basin > Dagang Field (0.99)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- (3 more...)
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...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
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...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- (4 more...)
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.
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (2 more...)
Extended Reach Horizontal Well Development with Downhole Flow Control and Gravel Packing Sand Control: First Pilot in S-Field with Production Success
Kamat, Dahlila (PETRONAS Carigali Sdn Bhd) | Kadir, Zairi (PETRONAS Carigali Sdn Bhd) | Kumaran, Prashanth Nair (PETRONAS Carigali Sdn Bhd) | Ibrahim, Ramli (PETRONAS Carigali Sdn Bhd) | Ahmad, Mior Yusni (PETRONAS Carigali Sdn Bhd) | Madon, Bahrom (PETRONAS Carigali Sdn Bhd) | A Aziz, Adam Hareezi (PETRONAS Carigali Sdn Bhd) | Ishak, Mohd Faizatulizuddin (PETRONAS Carigali Sdn Bhd) | Gordon Goh, Kim Fah (Schlumberger) | Ceccarelli, Tomaso Umberto (Schlumberger) | Tan, Chee Seong (Schlumberger) | Kalidas, Sanggeetha (Schlumberger) | Mohd Salim, Ahmad Syahrir (Schlumberger) | Maldonado, Jorge (Schlumberger) | Lei Min, Zhang (Schlumberger) | P Mosar, Nur Faizah (Schlumberger) | Gil, Joel (Schlumberger) | Abdul Rahman, Mohd Ramziemran (Schlumberger) | Watana, Kulapat (Schlumberger) | Chabernaud, Thierry (Schlumberger)
Abstract The first horizontal oil well was drilled through an anticline structure in the Block-7E of East Flank, S-field, penetrating three production sands Sand I, Sand II and Sand III. Based on a comprehensive pre-drill study through steady-state and 3D dynamic time lapse simulation, Inflow Control Device (ICD) with integral sleeve (on/off function) attached to the ICD's joint is the optimum development of the fault block that maximizes zonal control for contrasting water encroachments. Due to the unconsolidated nature of the target reservoir, this well is designed for Open-Hole Gravel Pack (OHGP) with specialty 3D filtration screen to manage sanding issue. This paper highlights 2-in-1 application of ICD with enabled zonal shut-off sleeves and the OHGP completions with external screen. A pre-drilled ICD dynamic modeling is constructed to evaluate the well performance with ICD configuration. The design criteria for an optimum ICD design configuration is based on number of compartments and size, packer placement, ICD nozzle sizes and numbers. This dynamic single well model was used to justify the technology value which resulted in production improvement (maximizing oil and minimizing/delaying water). However, during the drilling of this well, the pre-drilled model is then updated in real time with the input of actual petrophysical data from Logging While Drilling (LWD) measurements along the OH section. Actual well trajectory and structure adjustment encountered while drilling were also co-utilized to determine the final optimum ICD design for the field run-in-hole (RIH) completion. Target fault block in S-Field East Flank requires optimum development strategy for its economic viability (Kumaran, P. N et al. 2017). Only one open-sea discovery well proved the oil bearing sands to-date, but a lot of uncertainties remains: geological structure, fluid contacts, fluid characterization, existence and nature of an aquifer, etc. Hence, all these uncertainties are incorporated in the ICD optimization through sensitivity analysis and uncertainty range estimation. Oil production improvement with water reduction while delaying water encroachment are key in the optimization of the ICD design, which is achieved by evaluating the impact of ICD's influx balancing throughout the horizontal section. Study shows that water encroachment is effectively controlled with 9 compartmentalization zones along the horizontal section, each one separated using oil swellable packer. After 7 months of stable flow, well test is showing zero-water and zero-sanding to surface with well controlled production rate that can produce more if required. This is the testimonial of the deployment success from its initial conceptual design to its ultimate completion.
- Asia > Malaysia (0.46)
- North America > United States > Gulf of Mexico > Central GOM (0.25)
- Geology > Structural Geology > Fault (0.86)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
Abstract QGC's current full-field reservoir model comprises hundreds to thousands of CSG wells. This presents a considerable challenge from a history-matching standpoint compared to a conventional workflow where well-level adjustments may be made on one well at a time. In QGC, a model with an improved well-level match is desired as the resulting well forecast will enable decisions on a well-level to be made more confidently, such as the prioritization of well workovers. Previously a field-level history-match was deemed acceptable when the model was only used for field development planning. The method parameterizes the well-level relative error in simulated production from the model versus observed production. The workflow utilizes this data, known as well-level modifiers, to alter subsurface properties. This has been achieved with a semi-automated workflow to make the process efficient and repeatable, but also to enable engineering judgement to be incorporated in the history-matching process. The feedback loop is also an essential component of the workflow as it allows the well-level modifiers to be sense checked against the regional geological trends. This further encourages collaboration within a multi-disciplinary team. These well-level modifiers can also be used to create history-match metrics, which can be spatially mapped to help target specific areas for improvement in history-match quality. Some powerful use of visualization techniques discussed in this paper has not only minimized the mismatch but ensures the characteristics of the production history and geological trends are honoured to assure the robustness of the history-match and the resulting model predictability. The workflow has significantly reduced the time and efforts spent in delivering an improved well forecast when required. The technical development community in QGC has actively nurtured a culture of ideas sharing and innovation, which made the development of this workflow possible.
- Europe (1.00)
- North America (0.95)
- Asia > Middle East (0.94)
- Oceania > Australia > Queensland (0.29)
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
Abstract Many stakeholders are concerned about the effects of Coal Seam Gas (CSG) developments on aquifers. Well integrity issues are often mentioned as potential leakage pathways which could lead to aquifer contamination or depletion. This study involved the creation of simple models to represent the behaviour around a producing CSG well with a well integrity failure. A range of realistic scenarios were chosen, representing hypothetical well integrity failures at different stages of CSG production. Dynamic numerical models were built that represent each scenario, and simulations were run to forecast the flux of fluids around the wellbore. These models were parameterized based on data from literature related to well integrity studies, and should represent reasonable worst-case scenarios. The results of simulations using these models are then used to explain key concepts relating to well integrity in CSG wells in a manner which can be understood by interested parties from non-technical backgrounds. The simulation results based on these simple models indicate that well integrity issues in producing (or previously produced) CSG wells are unlikely to have any significant impact on overlying aquifers.
- North America > United States (1.00)
- Oceania > Australia (0.95)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (3 more...)