A integrated gas production system from methane hydrate layer by circulating hot water using a pair of dualhorizontal wells has been proposed. In the system, a dissociated region including the dual horizontal wells filled with hot water, named as hot water chamber, was generated to produce gas continuously. The gas production rate has the maximum peak just after breakthrough of injected water between dual horizontal wells, then it declined and gas was produced by almost constant rate. We have successfully developed the numerical model, and matched the history of physical gas production. Moreover, numerical simulations of gas production by the hot water injection into a Nankai Trough sediment layer model using a pair of dual horizontal wells 500m in length were carried out for a methane hydrate reservoir of 20 m in layer thickness, 46% of average methane hydrate saturation, 100 and 25 md in horizontal and vertical absolute permeabilities,
respectively. The cumulative gas production is simulated as 5×106 std-m3 for initial two years. Furthermore, a new gas production scheme, which uses four pairs of dual horizontal wells in radian arrangement in a methane hydrate sediment layer with area of 1km×1km located at Nankai Trough, has been presented and evaluated with the numerical simulation as the cumulative gas production for 15 years is 1.3×108 std-m3.
Coring with sponge liners is not a new technology. In some form it has been an industry offering for over twenty years but has been plagued by problems. The objective of sponge coring has been to determine separate in-situ oil and water saturations of the formation materials. The problem has been that the fluids would be expelled and lost from the core by expanding gas while bringing it to the surface, or by flushing due to filtrate invasion.
The solution to the problem has been to surround the core with a special oil absorptive (oleophilic) sponge material to capture the expelled oil and hold it in place for laboratory analysis. The challenge was to have the sponge fit tightly around the core to prevent confusing fluid migration and mud contamination in the sponge-core clearance annulus, and yet not experience core jamming and sponge damage.
Now a new, much more accurate sponge liner coring service has now been launched showing promising results. A balance seems to have been achieved between smooth core entry and a tight fit, pre-saturated sponge with virtually no fluid migration. This new service cuts and provides oil-absorptive sponge-encased 3½-in. diameter core in 30 ft. lengths.
In late 2012 Chevron utilized this new and previously unproven system to core nearly 300 ft. of sponge core in Lea County, New Mexico, USA. The coring program used a special low invasion coring fluid with a low spurt loss and a staged trip-out-of-the-hole schedule to minimize gas expansion/oil movement. The precision core bit which cut a tight-clearance core provided exceptional results with an average ROP of 10.4 ft/hr, 100% core recovery and observable oil saturation in the sponge; this indicates that the system worked as designed. This case study will be described in detail within this paper.
Resource plays present unique challenges. These large, continuous accumulations need to be assessed by mapping out variations in risks and prospectivity that divide the resource play fairway into discrete, contiguous segments. For the resource plays - such as shale gas, shale oil, Coal Bed Methane, the challenge is economic recovery. The assessment challenge is the same: Modeling how the resource play is explored and exploited.
Given the current focus on liquids, the challenge for shale-based resource plays is assessing the potential for shale oil in resource plays where there is most often both shale gas and shale oil.
This paper extends earlier work by applying an activity based model to exploration and exploitation of a shale based resource play. The model used a segmentation of the resource play into three types of areas: shale oil, shale gas and transition zones with uncertain proportion of shale oil and shale gas. The assessment model also includes learning and the relative impact of alternative completion solutions. The model generates stochastic performance metrics that capture alternative outcome scenarios, economic returns and the delivery schedule of production and reserves.
The performance metrics support both project-level and portfolio-level decisions related to resource plays. Project-level application is illustrated using data from an Eagleford-type resource play.
Sharma, Anoop (Schlumberger) | Yates, Malcolm E. (Schlumberger) | Pope, Tim (Schlumberger) | Fisher, Kelvin (Endeavor Energy Resource LP) | Brown, Randy (Endeavor Energy Resource LP) | Honeyman, Les (Endeavor Energy Resource LP) | Bates, Bradley (Endeavor Energy Resource LP)
Horizontal wells present a great opportunity for maximizing the potential of unconventional resource play developments by providing enhanced reservoir contact but also pose many challenges in the process due to the heterogeneous nature of the unconventional reservoir rock.
This study covers the implementation of an integrated completion and production workflow to optimize the horizontal well development in the Delaware Basin located in Reeves County, Texas. By undertaking a vertical well pilot logging program the acreage was logged for petrophysical and geomechanical properties using advanced geo-chemical and full-wave sonic tools to quantify reservoir quality (RQ) and completion quality (CQ), respectively. Detailed fracture simulations were performed at multiple depths to locate the optimum landing point that maximized reservoir contact. Incorporating the key findings of the wellbore stability analysis, the well was geosteered using a rotary steerable system and a logging-while drilling (LWD) resistivity tool that placed 100% of the lateral in the target zone. Further completion simulations were performed to determine a perforating and staging strategy which would optimize the number of stages. The flow-channel fracturing technique, which provides a novel approach for achieving fracture conductivity, was also implemented on the studied well to significantly improve the effectiveness of the fracture stimulation treatment. Fracture diagnostics, detailed post fracture modeling, and production analysis techniques, which utilized rate-transient analysis and history matching, were performed to provide better understanding of the effectiveness of the stimulation treatments (fracture lengths/conductivity), thereby allowing for further optimization of the stimulation program.
This study has demonstrated how the implementation of an integrated design and evaluation workflow can optimize the overall well production performance as well as reduce drilling and stimulation costs in unconventional resource play developments.
The exploration of shale gas resources in Europe is moving at a slow pace, despite the fact that drilling for reservoir characterization is essential for any further planning. Whether shale gas development in certain regions is economically feasible at all and what such development activities might entail can’t be determined in the absence of critical data. Yet, there is widespread public resistance that influences political decision making and permitting, and that sometimes doesn’t even allow for exploration. Most of the stakeholders concerns are related to perceived environmental risks for water by hydraulic fracturing. Main themes are concerns about the contamination of water resources by fracturing chemicals, methane or flowback water, or concerns about the depletion of groundwater and surface water. While some of the perceived risks may be overestimated or unsubstantiated, there are real risks that have to be addressed by thorough assessments of the environmental, health and social impacts, and by an integrated approach to water management from sourcing to final discharge. This includes the transportation and distribution logistics for water and wastewater movements. It is essential to establish relevant reference and baseline data on groundwater and surface water systems well ahead of project implementation, to assess risks in a fashion that is understood by interested stakeholders, to define proactive and reactive resource protection measures, and to monitor performance. This paper suggests an integrated approach that combines the elements of impact assessments, scientific and technical data gathering, and the monitoring of potential impacts across the life cycle of a shale gas project, along with communication strategies that satisfy stakeholder needs. It also discusses the benefits of quantitative risk assessments in improving the credibility of proposed exploration and development activities.
Indonesia according to research by Resource International Inc. Advance. (ARII) along with the Directorate General of Oil and Gas has potential reserves (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 potential energy shortages Indonesia 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 that are different from conventional gas permeability which has a smaller, predominantly gas adsorbed and the 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 the field SUMBAGSEL in southern Sumatra, Indonesia, seeking development planning optimization by creating scenarios drilling 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.
Gas hydrates will dissociate to gas and water provided the prevailing pressure is below the equilibrium pressure or the prevailing temperature is above the reservoir equilibrium temperature. Moreover, some hydrate reservoirs have considerable amounts of mobile gas and water coexisting with the hydrates in the formation. This implies, fluid diffusivity in such a reservoir system is predominantly multiphase and hence addressing multiphase flow for well testing in such reservoirs becomes very vital.
Conventionally, most well testing models address diffusivity in porous media by assuming a single/dominant flowing phase or addressing the fluid phases separately. If a huge discrepancy exists between the fluid saturations, the fluid with the highest saturation denotes the dominant flowing phase and the correction with the multiphase model becomes trivial, as also seen with most conventional gas reservoirs with low water saturation, illustrated similarly in this work. However, if the saturations of the different phases do not vastly differ from one another, multiphase well testing models give a more accurate prediction of reservoir behavior. The use of total mobility and total compressibility concepts become very essential in deriving a better estimate of the diffusivity of the fluids and for well test designs.
The multiphase flow model developed here is based on a mass balance system. The effective density, total compressibility and total mobility are derived from a mass balance model. The total mobility model developed by Perrine, used by most reservoir engineering calculations is not considered for this work, as this does not fulfill mass balance. Due to the non-linearity of the diffusivity equation, the multiphase diffusivity model addressed here includes pseudo-pressure integrals. The solutions to the multiphase model are compared to single phase well testing models with saturation sensitivity studies and the limitation of using the single phase models are highlighted.
Krzywiec, Piotr (Institute of Geological Sciences, Polish Academy of Sciences) | Malinowski, Michal (Institute of Geophysics, Polish Academy of Sciences) | Lis, Pawel (GeoFuture Consulting) | Buffenmyer, Vinton (ION Geophysical) | Lewandowski, Marek (Institute of Geological Sciences, Polish Academy of Sciences)
Recently the Lower Paleozoic basin located on the western edge of the East European Craton in Poland has become the focus of very intense exploration for unconventional hydrocarbons. Results of early exploration wells clearly demonstrate that there are still many unknowns regarding various aspects of the unconventional petroleum system, including structure and depositional architecture of the Lower Paleozoic succession. Seismic data from a recently acquired high-effort regional deep reflection survey has allowed for a better understanding of the complex tectono-sedimentary history of the prospective basins. The results of this regional seismic study will be reviewed and the impact on exploration objectives discussed.
The Cambrian - Lower Ordovician succession, deposited on the Baltica passive margin, is covered by the Upper Ordovician - Silurian succession of the Caledonide foredeep basin. Base of the foredeep succession is marked by “hot shale” interval. Large-scale seismically defined geometry of the foredeep infill reflects its progressive progradation towards the east-southeast.
Late Paleozoic and Mesozoic tectonics have resulted in compartmentalization of the Lower Paleozoic basin into the Baltic, Podlasie and Lublin sub-basins. Tectonic deformations documented using new seismic data include Late Triassic thick-skinned normal faulting in the Baltic basin, Late Devonian reverse / strike-slip faulting in the Podlasie and Lublin basins, and thick and thin-skinned Late Carboniferous thrusting and folding in the Lublin basin. Further consideration and a better understanding of these complex geologic issues should benefit exploration efforts in Poland.
Density, photoelectric, neutron, and gamma ray logs are key inputs to the evaluation of unconventional resources. Each has a finite vertical resolution, and the properties of beds thinner than this cannot be measured directly but are (in principle) available from inversion if the logs’ response functions are known, and the thickness of each bed is known from an independent high-resolution source. An inversion method is described for beds with apparent dip angles less than about 60 degrees which uses pre-computed response functions from measurement-specific nuclear particle transport code models, combined with bed boundaries picked automatically from high-resolution microresistivity images rendered using a new technique developed for high dynamic range data.
The method has application in thinly-bedded formations in general and has particular relevance in coal bed methane reservoirs where multiple thin high-contrast beds are common.
Inversion results are known to be sensitive to uncertainty in bed thickness values, and constraining the inversion with information from high-resolution images is found to be highly advantageous in producing reliable results in beds as thin as 0.075m; this compares to the resolution of about 0.6m for standard porosity logs, and 0.2m for the high-resolution field logs. Inverted density logs show good agreement with core density values, and the integrity of inverted photoelectric, neutron porosity and gamma ray logs is judged to be good based on the similarity between field logs and logs reconstructed from inverted results, plus the high degree of agreement with properties of known marker beds. Inverted logs are also shown to provide improved differentiation between litho-types defined from combinations of logs using principal components analysis.
The paper addresses an important source of uncertainty in the estimation of reservoir properties - namely finite spatial resolution - and in so doing reduces bias in volumetric calculations and associated net pay calculations.
Multi-fractured horizontal wells (MFHWs) are the most widely used technology for producing tight oil and gas reservoirs. Production data from a MFHW may exhibit multiple consecutive linear flow periods including linear flow in fracture, linear flow in the stimulated reservoir volume (SRV), and linear flow in the non-stimulated region of the reservoir. The existing analytical models for these flow periods have been developed based on the linearized form the flow equation. However, these models introduce considerable error in permeability estimation and production forecasts for tight oil reservoirs due to stress-sensitivity of these reservoirs.
In previous work by the authors, the stress-sensitivity of permeability was incorporated into production data analysis (PDA) of tight oil reservoirs during transient and boundary-dominated flow periods in single fractured wells. In this paper, the effects of stress-dependent formation permeability and fracture conductivity on the production data of MFHWs are studied. A new model is used to correct the conventional PDA techniques for these effects in permeability estimation and oil production forecast.
This study shows that the conventional methods give less accurate results for MFHWs producing under higher pressure drawdown in highly stress-sensitive formations. The results show that the new method reduces the error of the conventional techniques significantly and provides a reliable strategy for PDA of MFHWs.
This study fulfills two important requirements of the tools for PDA of MFHWs; simplicity and accuracy. The strategy is to keep the conventional analysis routine unchanged, with a correction factor applied to account for the effects of the nonlinearities. The value of the correction factor is that it shows how far the conventional analytical methods are from the exact solutions. Further, the correction factor is used to remove the considerable error in conventional analyses.