bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhanced Gas Recovery and CO2 Storage in Coal Bed Methane Reservoirs: Optimized Injected Gas Composition for Mature Basins of Various Coal Rank
Authors: Schepers Karine , Oudinot Anne , Ripepi Nino 
Published: February 2011

Abstract
Nitrogen (N2) and carbon dioxide (CO2) injection has been a subject of enhanced coal bed methane (ECBM) and carbon capture and storage (CCS) research during the past decade. N2 and CO2 injection produce substantially different recovery processes. Coal has a higher affinity for CO2 as compared to methane (CH4). Preferential adsorption of CO2, a larger molecule than methane, onto the coal surface results in a dramatic decrease in cleat permeability due to coal swelling. This ultimately induces a loss of injectivity creating a significant technical hurdle for CCS operations in coal. In contrast, N2 increases cleat permeability because of its lower coal storage capacity relative to methane. As a result, injectivity increases during N2-ECBM. Theoretically, the injection of a mixture of CO2 and N2 will result in ECBM and CCS without a loss of injectivity. This study presents an investigation of that concept.
To identify key geological and reservoir parameters driving ECBM and sequestration processes in deep unminable coal seams, a Monte Carlo probabilistic approach was implemented. Results from tornado plots confirmed the major role that coal rank (Langmuir isotherms) and pressure-dependent permeability data play in ECBM processes. As coal rank determines the maximum gas-in-place that could be stored per volume of coal, average fracture permeability, matrix and pore compressibility, and differential swelling factors are predominant in coal capacity to flow water and gas phases, impacting both incremental methane production as well as injectivity.
Additionally, cleat permeability will vary greatly in response to injected gas composition during ECBM process. To better understand the consequences of these permeability changes by coal rank, a parametric study was designed. First results show that, for a specific coal rank, ECBM can drastically improve by increase N2 content in the injected gas stream. However, methane incremental recovery due to high N2 content will increase up to a maximum N2 concentration, or threshold: besides this threshold, breakthrough occurs too rapidly to generate additional methane recovery. This N2 threshold varies between coal ranks, as pressure dependant parameters also vary relative to the rank.
Finally, 100%N2 injection scenarios per coal rank highlight permeability behaviors easily explained in theory but which would probably need additional laboratory measurements to better understand their physical meaning while encountered during "real world" problems.
Risk Assessment as a Framework for Decisions on Research and Data Collection for Nuclear Waste Repositories With Application to Carbon Sequestration Monitoring
Authors: Rechard R. P. , McKenna S. A. , Borns D. J. 
Published: February 2011

AbstractThe risk assessment approach has been applied to support numerous radioactive waste management activities over the last 30 years. A risk assessment methodology provides a solid and readily adaptable framework for evaluating the risks of CO2 sequestration in geologic formations to prioritize research, data collection, and monitoring schemes. This paper reviews the tasks of a risk assessment, and provides a few examples related to each task. This paper then describes an application of sensitivity analysis to identify important parameters to reduce the uncertainty in the performance of a geologic repository for radioactive waste repository, which because of importance of the geologic barrier, is similar to CO2 sequestration. The paper ends with a simple stochastic analysis of idealized CO2 sequestration site with a leaking abandoned well and a set of monitoring wells in an aquifer above the CO2 sequestration unit in order to evaluate the efficacy of monitoring wells to detect adverse leakage.
The Dynamic Aspect of Formation Storage Use for CO2 Sequestration
Authors: Winkler M.. , Abernethy R.. , Nicolo M.. , Huang H.. , Wang A.. , Zhang S.. , Simone A.. , Clark C.. , Crouch S , De Groot H.. , El Mahdy R.. , Smith M.. , Malik S.. , Bourne S.. , Pierpont R.. , Hugonet V.. 
Published: February 2011

Abstract
The Athabasca Oil Sands Project Joint Venture (AOSP JV) owners – Shell Canada Energy (Shell), Chevron Canada Limited (Chevron) and Marathon Oil Sands L.P. (Marathon) – are advancing front-end development plans of a fully integrated carbon capture, pipeline and storage project in Alberta called the Quest CCS Project. A Final Investment Decision for Quest is scheduled for 2012. Quest is designed as a fully integrated CCS project in the oil sands sector involving CO2 capture at the Scotford upgrader near Fort Saskatchewan, pipeline transportation northeast from Scotford and CO2 storage in a deep saline formation zone, the Basal Cambrian Sand. Over the expected lifetime of 25 years, the project will capture and store up to 1.1 Mt of CO2 per year from the steam methane reformer units at the existing Scotford upgrader and at the upgrader’s expansion currently under construction
Conventional volumetric methods for the pore space assessment of CO2 storage, such as the guidance provided by the 2008 Carbon Sequestration ATLAS of the United States and Canada, are good tools in estimating the pore space available, while also considering empirical DOE ranges for storage efficiency, such as area and vertical sweep efficiency, gravity contact efficiency and microscopic displacement efficiency. Such assessment would suggest a CO2 storage capacity of the Basal Cambrian Sand at Quest of approximately 7 Mt per township (6 miles x 6 miles). However, such an estimate is of a static nature, not taking into account dynamic system constraints such as required injection rates, bottom-hole pressure constraints and associated well count and well spacing, including pressure interference and regional pore pressure increase.
Dynamic reservoir simulation has been performed, for a variety of subsurface realizations, covering the full range of current subsurface uncertainties, with the aim to optimize the development while also estimating the required pore space for CO2 storage. Following the concept of linking the required pore space to pore pressure increase, rather than CO2 plume extension, resulted in a significant reduction of pore space utilization in the Basal Cambrian Sand from the initial 7 Mt per township to only 0.67 Mt per township and will have a potential impact on additional CCS developments in the region.
Efficient Investigation of Uncertainties in Flood Design Parameters for Coupled CO2 Sequestration and Enhanced Oil Recovery
Authors: Ghomian Y.. , Sepehrnoori K.. , Pope G. A. 
Published: February 2011

AbstractA compositional reservoir simulation study was performed to investigate enhanced oil recovery and sequestration of carbon dioxide. Maximizing profit from oil recovery and maximizing the amount of carbon dioxide stored in the reservoir are competing goals and both will be important in the future. Both depend on large number of parameters and the strategy used to flood the reservoir. A very large number of simulations are required to understand and evaluate different strategies for each reservoir and for each realization of the properties of a particular reservoir. In this study the effects of variety of flood design variables on both EOR and sequestration objectives were investigated in sandstone and carbonate reservoirs separately. Experimental design and the method of response surfaces were used as tools to perform this study in a systematic and efficient way. Design parameters such as well spacing, different injection and production schemes, various well control techniques, and different mobility control methods were selected for study. By applying fractional factorial design and D-optimal methods, simulation cases were selected to study the effect of the parameters for each scenario. The amount of CO2 stored at the end of the oil recovery process and the net present value of the each sensitivity case were considered as the two decision criteria. Economic analysis for all of these cases were performed based on the necessity to account for CO2 storage factors such as capture and transportation costs, and possible CO2 tax credits for storage. Response surface analysis was utilized to determine the best strategy based upon these decision criteria for different type of the reservoirs. The result using this approach was similar to the result from an exhaustive simulation study, but took much less computation time and effort. An approach that is both realistic and feasible, such as the one used in this study, will be needed for future simulation studies because of the increasing importance of CO2 geological storage, the extremely wide variety of reservoir conditions of potential interests, the need to understand and reduce uncertainties, the need to find better operational strategies, and the uncertainty in future economic and regulatory incentives.
Advanced Acoustic Applications for the Karachaganak Field, Kazakhstan
Authors: Hajiyev V.. , Solovyov Y.. , Einaudi F.. , Russo J.. , Chittick S.. 
Published: February 2011

Abstract
The Karachaganak field is giant oil and gas condensate reservoir. Data collected from numerous wells confirms it is very heterogeneous. Because conventional logs are not sufficient to fully characterize reservoir properties, new technologies and interpretation techniques are always considered worthy of a trial run when they become available in this remote region. In particular, the operator, KPO, is experiencing serious problems related to wellbore stability in deviated wells. Those problems occur mostly in the overburden and are related to uncertainty in stress direction and stress magnitudes. Excessive fluid losses while drilling are also a serious issue, and there is a need to identify fracture zones and understand fracture attributes. Finally, estimates of the extent of the formation damage zone (or radial extent of alteration in reservoir intervals) would provide useful information for the design of optimal well completions.
Recently, a new advanced-technology, wireline acoustic scanning tool was run in a new well in the Karachaganak field to provide 3D formation acoustic properties from all borehole modes (monopole, dipole, and Stoneley) and measurements for near-wellbore and far-field slownesses. Drilling and completion engineers at KPO used the interpretation of this data to help make decisions and identify key geomechanical parameters required for successful operations. Mild stress-induced anisotropy zones were detected in the formation. Some zones of formation damage were identified by monopole and dipole radial variation profiling. Prominent open fractures were detected using shear dispersion analysis and Stoneley propagation – and confirmed by the electrical borehole images.
KPO plans to use the acoustic anisotropy information to compute stress magnitude for new-well placement and mud-weight optimization, and for oriented perforation techniques to optimize hydraulic fracturing simulation. The estimation of radial formation alteration may help in designing optimal completions and identifying suitable depth intervals for fluid sampling.
Modelling and Simulation of a New Dual Porosity CBM Reservoir Model with an Improved Permeability Model through Horizontal Wells
Authors: Shiyi Zheng , Lili Xue 
Published: February 2011

Abstract
Low permeability Coal Bed Methane (CBM) reservoirs are characterized by their low porosity and permeability, which in turn induce their complicated permeability characteristics of gas and water during production. Numerical experiments and field applications proved that in low permeability CBM reservoirs there exists percolation non-linearity and fluid muti-variability. The percolation of fluid needs to overcome threshold pressure gradient; while klinkenberg effects will restrict the gas permeability. Thus the classic percolation mathematical model is not valid for problems of low permeability gas reservoirs.
On this basis, a three dimensional, dual porosity, single permeability, non-equilibrium adsorption, gas-water two phase flow, pseudo-steady state mathematical model was developed, which reflects the concrete influence factors in low permeability CBM reservoirs, such as high velocity non-Darcy flow, threshold pressure and slippage effect. This was followed by a new theoretical formulation of permeability and porosity including the effect of matrix shrinkage.
This new model was solved by a fully implicit numerical method and the block pre-conditioning orthogonal minimisation algorithm. A computer programme called COAFOR has been developed for this purpose. Comparison of gas production rate between those from Eclipse software and the current programme was made. Three synthetic cases were studied, which proved that the developed algorithm works well for solving the problem stated above.
Those case studies have revealed that there exist three stages in coal de-watering and production processes. The existence of threshold pressure gradient can largely reduce the gas production rate, while the gas slippage factor can increase the bottom-hole pressure at the initial stage of production. The agreement between COAFOR and ECLIPSE under the same physical parameters was better than expected. Matrix shrinkage effect can largely increase the gas production rate and gas concentration owing to the enhanced permeability caused by the existence of matrix shrinkage.
A Study to Evaluate the Impact of CO2-EOR on Existing Oil Field Facilities
Authors: Saadawi Hisham , Johns Andrew , Watler Ken 
Published: February 2011

Abstract
Abu Dhabi Company for Onshore Oil Operations (ADCO) has recently commissioned the first ever CO2-EOR pilot in the Middle East in its Rumaitha field. The main objective of the pilot project is to evaluate the feasibility of CO2 injection as a potential enhanced recovery technique. If the pilot is successful, ADCO will use CO2 to replace the hydrocarbon gas currently being injected in the field.
In order to assess the impact of large scale CO2 injection on the field’s facilities, an engineering study was conducted.
This paper discusses the methodology and main features of this study. Topics covered include: description of the field facilities; technologies for the separation CO2 from associated gas, key design parameters, study methodology, impact on existing facilities and the study findings.
Integrating Subsurface, Well and Surface Data as a Plan for Waterflood Project in Rantau Field
Authors: Simamora John Hisar , Ardianto Reza Nur 
Published: February 2011

Abstract
Rantau field operated by Pertamina EP since 1928 is currently producing from primary stage, and has been declining since 1972. The implementation of Waterflood in Pertamina EP was initiated by EOR Department. There were several major issues related to the waterflood implementation in Rantau Field. Among of these issues was the limited number of subsurface and well data. On the other hand, the management and government board urged that the implementation should be implemented as soon as possible due to oil & gas national production increasing program and zero discharge issue.
This paper presents the result of Pilot Waterflood Planning as the integrated analysis from limited subsurface, well and surface data for Geophysics, Geology, Reservoir, Production, Process Facility and Economic Evaluation integrated analysis. The main target of this waterflood project is Layer 400, 600, 770 and 800. The pilot stage was plan for layer 600. It shows that the most prospective candidate for waterflood pilot project was in C1, C1 and A1, A2 block, the pilot project was planned for inverted five (5) spot patterns and predicted breakthrough time was 90 days, it was also predicted a secondary peak of 1,500 BOPD. The pilot project which was proposed in two patterns and it was successfully executed in January 2009. This analysis is useful result as a part of integrating limited subsurface, well and surface data regarding to the plan of Waterflooding Project.
Damage Mechanisms in Unconventional Gas Well Stimulation - A New Look at an Old Problem
Authors: Shaoul Josef , van Zelm Lars , Pater C. J. 
Published: February 2011

Abstract
After fracture stimulation, production often rises slowly, instead of showing an early transient. This indicates either severe reduction in fracture conductivity or reservoir damage. There is still no agreement in the industry about the most important damage mechanisms. Work done by Pratts and Holditch in the 1970’s showed that fracture face damage from filtrate invasion is unimportant, unless there is permeability damage in the invaded zone of at least 99%. New ideas have been proposed which may better explain the behavior commonly seen in actual production data. These ideas include relative permeability with water and gas both immobile at a given saturation ("permeability jail"), small scale reservoir heterogeneity and stress sensitive matrix permeability at high drawdown.
Experience from the field has been contradictory. Sometimes no water is produced back, but gas production does not appear to suffer. In other cases, gas rate is significantly lower than expected, but significant fracture fluid is recovered. With the inherent coupling of fracture length and permeability in welltest interpretation, and the practical impossibility of achieving radial flow in tight-gas reservoirs with large fracture lengths, it has been difficult to prove any theory about the cause of poor performance from tight-gas fracture treatments. This paper shows simulation results of these effects on post-fracture production from an unconventional (0.001 mD) gas well. Furthermore, realistic assumptions about proppant pack cleanup show a connection not only between poor cleanup and short effective fracture length, but also reduction in contacted kh and connected reservoir volume. New reservoir simulation results are presented showing 50% reduction of production in the first years due to these effects in unconventional reservoirs.
A Multidisciplinary Approach to a Challenging Tight Gas Play in Sheetflood Sands, Sultanate of Oman
Authors: Aitken John F. , Fryberger Steven G. , Mahruqy Sultan H. , Curtino Joe A. , Mohiuddin Uzma 
Published: February 2011

AbstractThe Miqrat Formation (Cambrian) of North Oman is a deep, tight (low permeability) gas reservoir that was deposited in an arid to semi-arid continental setting. It is dominated by finely interbedded, red-brown shales interstratified with muddy, micaceous, fine-grained sandstones and siltstones. These were deposited in alluvial and playa/lacustrine to sabkha environments with minor aeolian intervals. The formation has a variety of geological, petrophysical and engineering challenges, largely related to its depositional setting and burial history.Geoscience challenges centre on reservoir productivity identification, involving a combination of depositional and diagenetic features, and ‘sweet-spotting’, particularly the pre-drill prediction of good quality reservoir facies (e.g. aeolian sandstones). Petrophysically the Miqrat is difficult, not only because of its tight nature, but also because it commonly contains low resistivity pay and is thin-bedded, making contact identification, porosity and saturation estimation challenging. Additionally, net pay determination is hampered by the thin-bedded nature of the reservoir and its high feldspar content, such that gamma ray logs consistently read high values, and, typically, neutron-density separation is poor. In terms of petroleum engineering, stimulation strategies are challenging, especially the choice of zones to stimulate, and the absence of barriers to fracture height growth means that hydraulic fracture treatments are performed across multiple non-pay intervals in order to have coverage for the interspersed pay intervals and to achieve the desired fracture length (penetration geometry) for a target interval.The Miqrat Formation tight gas play is a difficult and challenging play that requires close co-operation between geoscience, petrophysics and petroleum engineering disciplines to overcome these challenges and optimally exploit it as a gas reservoir. Only through such an integrated approach can the full value of the Miqrat Formation be delivered to stakeholders.
Tight Gas Modeling Frameworks for Improved Reservoir Management and Its Application to the Moxa Development Area
Authors: Gallego Felipe 
Published: February 2011

Abstract
This paper describes the efforts to compile the current understanding of recommended practices for static and dynamic modeling in tight gas sandstone reservoirs. One of the developed frameworks is applied in the Moxa Arch in southwestern Wyoming to generate a full field simulation model to guide informed decisions on well spacing and infill drilling locations while differentiating between incremental volumes and rate acceleration.
The proposed frameworks have been developed by a multidisciplinary group of experts from the technology group and the North America Gas business at BP. They are based on a range of business problems such as drilling and completions design, spacing, pattern and location of infill wells, and depletion planning. The frameworks provide step by step guidelines as to how a modeling study should be conducted in order to meet certain reservoir management objectives. A decision tree is initially suggested which guides the user through the different characteristics of the modeling study in order to select what framework to employ. Five general frameworks have been differentiated by geologic complexity and number of wells with an underlying business objective. Each framework is then subdivided based on the impact on productivity of gas condensate and water dropout and mobility in the reservoir or the well. It is expected that these frameworks can be used to provide guidelines in starting a modeling project from scratch and identify gaps between the recommended practice and ongoing modeling efforts that could yield erroneous results.
The framework corresponding to the multi-well, full field simulation model with complex geology has been tested and used to guide the progress of a modeling study in Moxa. The model integrates results of recent geological, petrophysical, classical reservoir engineering, and production performance studies with the simulator. 2D models of the Frontier and Muddy formations are run on predictive mode with wells controlled by rate based on decline curve analysis and remaining gas maps are generated to identify undepleted areas with infill drilling potential. These maps are then overlaid with first year average production rate (IP365) and expected ultimate recovery (EUR) contour maps to further refine the location of new drilling opportunities. Application of the modeling frameworks in the Moxa Arch has helped identify number, drilling sequence and approximate location of infill wells. It has also suggested that a particular development strategy could accelerate recovery as opposed to add volumes in certain parts of the development area.