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Results
Abstract The demand for indigenous supplies of natural gas in the UK and other countries in Europe has driven operations in the unconventional gas arena since the 1990s. In Coal Bed Methane (CBM) there have been attempts in the UK, Belgium, Germany, France and Poland. Dart Energy and its heritage company, Composite Energy, have been active in CBM in the UK since 2004, drilling 25 CBM wells in the UK, including 10 appraisal and development wells on the Airth field in central Scotland. A further 4 appraisal wells were drilled by the previous operator of the Airth field in the 1990s. The local Carboniferous coal geology, as with most European coals of Carboniferous age, is characterised by thin, numerous, low permeability, undulating coal seams. A number of different well designs were tried over the 14 Airth wells to meet the challenges of the local geology: initially vertical fracture stimulated wells; moving to geosteered multi-lateral horizontal wells, either intersecting a vertical well at the end of the horizontal section or as ‘updip’ branches off a motherbore without an intersection and finally multilateral geosteered horizontal wells intersecting a vertical well at the start of the horizontal section. The evolution in well design incorporated learnings from drilling operations, reservoir geology and production operations for each type of well architecture and advances in drilling technology in other CBM provinces around the world, adapting them to answer the particular subsurface problems encountered in the Airth field. Eventually, through this evolutionary learning process, Dart Energy was able to announce a commercial flowrate of 0.7MMscf/d from Airth 12 in January 2013, a multi-lateral horizontal well with a vertical well intersection at the start of the horizontal section. This paper describes the journey to that success, charting the evolution of CBM production well design on the Airth field, recognising the geological factors that drive well design, an evolution that can be applied to Carboniferous coal systems with thin, numerous and structurally complex coal seams found in other parts of the UK and Northern Europe.
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- (16 more...)
Abstract Interest in European Coal Bed Methane (CBM), driven by an increasing demand for supplies of natural gas in Europe has been ongoing since the 1990's in the UK, Belgium, Germany, France and Poland. The nature of Carboniferous age European coals: multiple, thinner coal seams with lower permeability than coals seen in Australia or North America has resulted in a horizontal well or multi lateral wellbore architecture employing geosteering through the coal seams. Use of a conventional directional drilling Bottom Hole Assembly (BHA) in which the Logging While Drilling (LWD) sensors are usually 40ft or more from the drill bit, makes geosteering in structurally complex coals, with changing dip and rolling topography a major challenge. The cost sensitive nature of CBM wells makes the use of geosteering tools such as azimuthal resistivity tools uneconomic. This paper describes the experience of Dart Energy and its heritage company, Composite Energy, in introducing an instrumented mud motor with a near bit Azimuthal Gamma Ray and Inclination tool as a cost effective geosteering aid on the Airth CBM Field in Central Scotland. The use of an instrumented mud motor enabled Dart Energy to improve geosteering performance, increasing net coal in each geosteered section, near doubling of average Rate Of Penetration (ROP), and reducing the number of time consuming and costly sidetracks. The improvement in geosteering is a critical part of realising the commerciality of CBM wells producing from thinner, structurally complex Carboniferous age coals found in the UK and Northern Europe.
- Europe > United Kingdom > Scotland > Scottish Midland Valley Basin > Airth Field (0.99)
- Europe > United Kingdom > Scotland > Midland Valley Basin > Airth Field (0.99)
- North America > United States > New Mexico > San Juan Basin (0.94)
- (3 more...)
Abstract Indonesia according to research by Resource International Inc. Advance. (ARII) along with the Directorate General of Oil and Gas – Ministry of Energy and Mineral Resources has potential resource 453 TCF of CBM which is divided into 11 (eleven) basin on the island of Sumatra, Borneo, Java and Sulawesi. The results of CBM product is expected to be a solution to Indonesia's potential energy shortages in the future relying on energy sources from oil and natural gas. The utilization of CBM in Indonesia following the fiscal term of Production Sharing Contract (PSC) with a validity period of 30 years. CBM reservoir characteristics are different from conventional gas with smaller permeability, predominantly adsorbed gas and under-saturated conditions require draining the water content (dewatering) before the production period that requires careful planning to produce a viable project either in terms of technical, economic and commercial. Simulations conducted in Sumbagsel Field in Southern Sumatra, Indonesia, seeking development planning optimization by creating drilling scenarios of CBM wells with a certain amount of accumulation to get a good view of the economic indicators of Net Present Value (NPV), Internal Rate of Return (IRR), Profitability Index (PI) and Payback of Time (POT). The results showed that CBM development can not be done with conventional gas development model approach which uses ‘chuck management system’ to control the production, while the properly management is required in the development of CBM drilling where the number of production wells will be proportional to the increase of production. Knowledge of reservoir characteristics and production optimization management of the number of drilling development wells during fiscal term contract with the production sharing contract will result in the economic development of CBM.
Abstract Production from coalbed methane (CBM) reservoirs can often be challenging, particularly related to the dewatering process. Improper positioning and completion of wells can lead to increased complications during the production phase. Additionally, consistently high water levels (undeclined static reservoir pressure) can impede gas production. This paper describes well and production information from the Raniganj coal block. The pad completion discussed has a mother vertical well (V-well) in which three main coal seams were completed (of the total five main seams with interspersed local seams), and dewatering commenced in 2009. At the end of 2011, encircling the V-well, four deviated wells (D-wells) at different azimuths were positioned at horizontal closures of 263 to 364 m from the bottom seam of the V-Well, wherein five main coal seams, along with interspersed local seams, were completed and scheduled for dewatering in mid-2012. Despite consistent high water production rates from the V-Well, the water levels in the V-Well stood consistently higher (rising upward) than the water levels in the D-wells, unlike nearby V and D-well pads. Well spacing information, well stimulation plots, perforation plans, and overlying strata for all five wells on this pad were studied and conclusions were drawn. This paper discusses such conclusions as well as the analyses performed to understand these issues. An attempt has also been made to best optimize hydraulic fracturing (HF) treatment designs to obtain the maximum benefits from stimulation operations. The results reported in this paper will influence the operator's cost optimization, which could be a major positive influence on the low-cost CBM market in addition to increasing efficiency of the entire operation.
- Asia (1.00)
- Europe (0.93)
- North America > United States > Wyoming (0.46)
- North America > United States > California (0.28)
- Geology > Structural Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- 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)
- (12 more...)
Wellbore Stability Estimation Model of Horizontal Well in Cleat-featured Coal Seam
Ai, C.. (Northeast Petroleum University) | Hu, C.. (Northeast Petroleum University) | Zhang, Y.. (No.3 Production Plant of Daqing Oilfield Company) | Yu, L.. (Northeast Petroleum University) | Li, Y.. (Northeast Petroleum University) | Wang, F.. (Northeast Petroleum University)
Abstract Lots of cleats, fractures and other weak structures have developed in coal reservoirs, and as a result, there are relatively big difference between its mechanical properties and coal matrix. During the drilling process, the cleats and fractures near the sidewall are more prone to surfer damage than coal matrix under the ground stress, crack stress, fluid pressure and borehole fluid additional stress, and thus destabilizing phenomena such as borehole collapse and circulation loss would take place. This paper used elasticity and fracture mechanics theories, and took the time effect of sidewall rock drilling fluid seepage into consideration to deduct stress intensity factorIandIIat the cleat tip under the action of the fluid-solid coupling, to establish criterion for the failure condition of coal matrix and cleat fractures, and to establish the wellbore stability calculation model for the cleat-featured coal body. Applying the model can calculate the safe drilling fluid density during the drilling process in cleat-featured coal seam, get the influence law of the factors which affect the wellbore stability such as the length of cleats, horizontal inclination of cleats and opening time of borehole, etc, and it also can analyze the time-delay effect of wellbore destabilization during the drilling process in cleat-featured coal seam. The study achievement was the supplement and perfection of the existed estimation model for the wellbore stability of coal seam gas well.
- Europe > Austria (0.28)
- Asia > China > Heilongjiang Province (0.28)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Integrated Assessment of Pilot Performance of Surface to In-Seam Wells to De-Risk and Quantify Subsurface Uncertainty for a Coalbed Methane Project: An Example from the Bowen Basin in Australia
Zhao, Chaobin (Research Institute of Petroleum Exploration and Development, PetroChina) | Xia, Zhaohui (Research Institute of Petroleum Exploration and Development, PetroChina) | Zheng, Kening (Research Institute of Petroleum Exploration and Development, PetroChina) | Duan, Lijiang (Research Institute of Petroleum Exploration and Development, PetroChina) | Liu, Lingli (Research Institute of Petroleum Exploration and Development, PetroChina) | Zhang, Ming (Research Institute of Petroleum Exploration and Development, PetroChina) | Yang, Yong (Research Institute of Petroleum Exploration and Development, PetroChina) | Lau, Hon Chung (Arrow Energy Ltd.) | Sharma, Vikram (Arrow Energy Ltd.) | Liu, Xinying (Arrow Energy Ltd.)
Abstract This paper presents a detailed case study of using surface to in-seam wells to develop a major coalbed methane (CBM) field in the Bowen Basin of Australia. This study was novel in that special emphasis was given to quantification of subsurface property uncertainty and modeling of dynamic uncertainty. The result was the generation of recovery factor versus depth correlations which can be used to calculate the estimated ultimate recoverable. In this work, a 3D box model around three pilot wells was extracted from the regional static model. To quantify key subsurface uncertainties such as permeability, both the Percentile and Confidence Interval Methods were used. Trends of laboratory-measured parameters like gas content, ash, Langmuir volume, permeability were established. Reservoir properties without measurements such as cleat porosity, desorption time and relative permeability were estimated based on rules-of-thumb, basin-wide analogue or educated guesses. A reservoir simulation model was built and production data from pilot wells were manually history matched. Parametric analysis was conducted to determine key parameters that significantly affect model history matching and forecasting results. Given the complexities of the coal reservoir and the non-uniqueness of the history match, Experimental Design was used to generate a population of simulation models that sampled the uncertainty range of key reservoir properties. This ensemble was reduced to include only those that matched the pilot wells’ production. With different combinations of reservoir properties thus obtained, recovery factor versus depth correlations were generated. This study is a good example of early resource assessment critical to the field development planning of a major CBM field. It presents a systematic method to handle uneven distribution of often sparse subsurface data over a large geographic area which often confounds the CBM industry. Furthermore, this method may be extended to assess other well architectures like vertical, slant, horizontal, multi-branch, multi-lateral and hydraulically fractured vertical and horizontal wells.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > Evaluation of uncertainties (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Abstract Coalbed methane (CBM) reservoirs are a growing source of relatively clean energy in many parts of the world. CBM reservoirs are fundamentally different from traditional hydrocarbon reservoirs. Gas is adsorbed on the surface of the coal cleats and not stored in pores. Still, estimation of the permeability of the coal cleats is important in judging the potential producibility of a given coal seam. Traditionally, CBM reservoirs are surface tested using injection or production techniques to access reservoir permeability (Clarkson and Bustin 2011). Recently, pressure buildup and falloff tests using the straddle packer module of a wireline formation tester have been used in CBM reservoirs to assess reservoir permeability successfully. However, low permeability, limited station time, or both have, in some cases, reduced the quality of the interpretation results. Deconvolution techniques have been available for some time; however, few practical examples are available in the literature. The use of deconvolution will generally allow extracting more of the same data. The derivative response uncertainty is normally due to errors in estimating the reservoir pressure and the flow rate. Generally, wireline formation testers provide reliable measurements of the reservoir pressure and flow rate. We applied deconvolution to pressure buildup and falloff for the first time on data acquired in a CBM environment with a straddle packer. The use of deconvolution has improved the permeability estimation from the different tests. We were also able to identify the limitations of the technique and the uncertainties in the analysis results.
- Oceania > Australia (0.69)
- North America > United States > Texas (0.29)
- Geology > Geological Subdiscipline > Geomechanics (0.88)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.35)
- 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)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- (2 more...)
Mathematical Model for Stimulation of CBM Reservoirs During Graded Proppant Injection
Keshavarz, A.. (University of Adelaide) | Khanna, A.. (University of Adelaide) | Hughes, T.. (University of Adelaide) | Boniciolli, M.. (University of Adelaide) | Cooper, A.. (University of Adelaide) | Bedrikovetsky, P.. (University of Adelaide)
Abstract A modelling-based prediction of well productivity enhancement for recently developed technology for stimulation of natural fracture systems in CBM reservoirs is presented. The proposed technology can also be used for productivity enhancement of gas wells in other unconventional reservoirs, i.e., shales and tight gas reservoirs. Injection of proppant particles with increasing size and decreasing concentration results in deep percolation of proppant into the natural fracture system, expansion of the stimulated zone and increase of well productivity index. A modified mathematical model for well indices during graded particle injection, accounting for stress changes in coal beds, is developed. The model is based on analytical solution for quasi 1D problem with coupling of axisymmetric fluid flow and geomechanics. The results of previous computational fluid dynamic studies have been used to determine hydraulic resistance due to proppant placement in the fractured system. Explicit analytical equations were derived for stress, pressure and permeability distributions, as well as for the well index during injection and production. Results of previous computational fluid dynamics studies were used to determine the hydraulic resistance resulting from proppant plugging in the fractured system. By applying the effect of proppant concentration and fracture deformation, a critical stimulation radius is introduced beyond which proppant placement decreases coal permeability and well productivity index. This model has been applied for a real field case, and the effect of injection pressure on well productivity index and stimulation radius is presented. The results show significant increase in productivity index due to graded proppant injection in CBM reservoirs.
- North America > United States (0.46)
- Asia > China (0.28)
- Europe > Austria (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.68)
Stimulation of Unconventional Naturally Fractured Reservoirs by Graded Proppant Injection: Experimental Study and Mathematical Model
Keshavarz, Alireza (1Australian School of Petroleum, The University of Adelaide, Adelaide, Australia) | Badalyan, Alexander (1Australian School of Petroleum, The University of Adelaide, Adelaide, Australia) | Carageorgos, Themis (1Australian School of Petroleum, The University of Adelaide, Adelaide, Australia) | Johnson, Ray (1Australian School of Petroleum, The University of Adelaide, Adelaide, Australia) | Bedrikovetsky, Pavel (1Australian School of Petroleum, The University of Adelaide, Adelaide, Australia)
Abstract The coal permeability declines due to fracture closure during the production and pressure depletion. The recently proposed technique for stimulation of natural coal cleats consists of the injection of microsized high-strength particles into a coal natural fractured system below the fracturing pressure. Coupling this technique with hydraulic fracturing treatment resulted in particles entering cleats under leal-off condition. In the current paper it is shown that the particles must be deposited at specific conditions of the particle-coal repulsion, ensuring the absence of external cake formation. The new method was successfully validated through laboratory injection of microsized glass particles into fractured coal cores. Application of Derjaguin-Landau-Verwey-Overbeek (DLVO) theory resulted in determination of experimental conditions favourable for particle-particle and particle-coal repulsion; these conditions also immobilize the natural fines. At these conditions, no particle attachment to coal surface and no particle agglomeration were observed, thus the conditions exclude formation damage due to external cake formation, particle attraction to coal rock and fines migration. The previously developed mathematical model was used for determination of the duration of particle injection into a coal core at minimum effective stress. Particle placement resulted in almost three-time increase in coal permeability, thus confirming the mathematical model used. The curve for well productivity index-vs-stimulation zone radius reaches maximum at some critical value of stimulation radius; the maximum is determined by the mathematical model. Placing particles beyond this critical radius results in reduction of well productivity index, due to significant hydraulic losses experienced by suspension flowing through narrowing cleat apertures during production stage. Applying the proposed novel technology during hydraulic fracturing treatment leads to improvement in productivity of coal seam gas wells and other unconventional resources (shales, tight gas and geothermal reservoirs) through enhancement of interconnectivity among microfractures around the hydraulically induced fractures.
- Europe (1.00)
- Oceania > Australia (0.68)
- North America > United States > Texas (0.47)
- Research Report > New Finding (0.50)
- Research Report > Experimental Study (0.40)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.66)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
New Inflow Performance Relationship for Coalbed Methane Wells
Feng, Qihong (China University of Petroleum (East China)) | Shi, Hongfu (China University of Petroleum (East China)) | Zhang, Xianmin (China University of Petroleum (East China)) | Du, Peng (China University of Petroleum (East China)) | Zhang, Jiyuan (China University of Petroleum (East China))
Abstract The inflow performance relationship (IPR) plays an important part in well completion, well production optimization, nodal analysis calculations, and artificial lift design. The production of coalbed methane is different from the conventional gas. For coalbed formation, permeability is sensitive to changes in effective horizontal stress which includes a cleat compression term and a matrix shrinkage term that have competing effects on cleat permeability. Therefore, the conventional method to calculate IPR curve is not completely appropriate for coalbed methane. The production of under-saturated coalbed methane reservoir can be divided into three distinct stages-: single water phase, multiphase gas and water, and single gas phase. Previous literatures either neglect the matrix shrinkage which results in increasing production rate at a given bottom hole pressure or only focus on the last single gas phase stage. This paper presents a new method to calculate the IPR curve for coalbed methane reservoir in the presence of permeability dynamics with pressure based upon P&M or Shi model. A second objective of this paper is to develop an approach for multiphase flow which requires a relationship between relative permeability and pressure, analogous to Fetkovich’s method for oil and gas flow. The methodology is further validated with field data from Qinshui Basin in China. The results indicated that the tool proposed here provides reservoir enginners with a quicker and easier way to estimate the performance of coalbed methane well.
- North America > United States (1.00)
- Asia > China (1.00)
- North America > Canada > Alberta (0.28)
- Geology > Geological Subdiscipline > Geomechanics (0.90)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.32)
- Asia > China > Shanxi > Ordos Basin (0.99)
- Asia > China > Shaanxi > Ordos Basin (0.99)
- Asia > China > Qinshui Basin (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)