bluuebunny/crossref_metadata_2025_split huggingface dataset:
Laboratory Investigation of Novel Oil Recovery Method for Carbonate Reservoirs
Authors: Yousef Ali A. , Al-Saleh Salah , Al-Kaabi Abdulaziz , Al-Jawfi Mohammed 
Published: February 2011

Abstract
The impact of brine salinity and ion composition on oil recovery has been an area of research in recent years. Evidence from laboratory studies supported by some field tests targeting mainly sandstones, has distinctly shown that injecting low salinity water has a significant impact on oil recovery. Although, the potential for carbonates has not been thoroughly investigated, some reported studies have excluded carbonates from this effect. The main objective of this paper is to investigate the potential of increased oil recovery by altering the salinity and ion composition of the injection water for carbonate reservoirs, define the recovery mechanisms, and eventually transform the emerged trend to full-fledged reservoir technology.
This paper presents the results of a laboratory coreflooding study conducted using composite rock samples from a carbonate reservoir to investigate the impact of salinity and ionic composition on oil/brine/rock interactions, and eventually on oil recovery. The experimental parameters and procedures were well designed to reflect the reservoir conditions and current field injection practices, including reservoir pressure, reservoir temperature, salinity and ionic content of initial formation water and current types of injected water. Also, this study provides detailed discussion and interpretation for potential mechanisms.
The experimental results revealed that substantial tertiary oil recovery beyond conventional waterflooding can be achieved by altering the salinity and ionic content of field injected water. The new emerged trend is distinct from what has been addressed in previous reported studies on topics of low salinity waterflooding for sandstones, or seawater injection into high temperature chalk reservoirs. On the subject of recovery mechanisms, the results showed that altering the salinity and ionic composition of the injected water has a significant impact on the wettability of the rock surface. This was also confirmed by nuclear magnetic resonance (NMR) measurements. The results, observations, and interpretations addressed in this study provided compelling evidence to suggest that the key mechanism for the emerged trend is wettability alteration.
Experimental Study of the Impact of Shear Dilation and Fracture Behavior during Polymer Injection for Heavy Oil Recovery in Unconsolidated Reservoirs
Authors: Zhou Jian , Dong Yufei , de Pater C. J. , Zitha Pacelli L. 
Published: February 2011

Abstract
Polymer flooding provides a better sweep compared with water flooding, but there is concern about maintaining sufficient injectivity. Longer fractures could provide injectivity, but pose a risk for early break-through and containment. In addition, shear dilation of unconsolidated sand is also expected to improve permeability and injectivity. Shear dilation causing absolute permeability enhancement was observed in tri-axial tests. The relationship between propagation pressure and confining pressure was determined in unconsolidated sands by a series of physical model tests. The accuracy of the minimum in-situ stress determination was also investigated in unconsolidated sands. The results demonstrated that there is a small enhancement of absolute permeability due to dilation of unconsolidated sand and they do have a difference in absolute permeability between stress states for increasing and decreasing effective stress. Besides, the geometry of fractures induced by viscous fluids in an unconsolidated formation is a dominantly planar fracture, although it is very tortuous. In view of isotropic stress in the horizontal plane, multiple fractures were induced in several directions.
Intelligent Oilfield Considerations for New Developments Offshore Abu Dhabi
Authors: Cobb David , Forster Matthew , Kirkman Matthew 
Published: February 2011

Abstract
ADMA-OPCO is currently pursuing the development of several undeveloped structures offshore Abu Dhabi. These fields, some of which have been appraised over the last 30 years, are currently being evaluated and moved forward for full field development. As part of this development we are actively incorporating Intelligent Oilfield concepts into these development plans and this paper seeks to highlight some of the key considerations and assumptions being integrated into ADMA-OPCO’s philosophy for these developments.
The next generation of oilfields is looking at these concepts to apply this advanced technology to: Enhance hydrocarbon recovery;Improve the safety for our Offshore Installations (by investigating new ways of working and opportunities to reduce the manning of these Operations);Reduce the Operating Costs (by improving the overall operating efficiency);
It has been documented (Dickens et al. 2010) that by improving the down hole surveillance and control we may significantly enhance our ability to improve recovery in these large offshore fields. The challenges ADMA-OPCO faces offshore Abu Dhabi is that we are dealing with a high number of complex wells, to ensure adequate drainage and optimum flux rates, to enhance overall recoveries, from these difficult reservoir intervals. The optimal utilization of technology (for the applications of down hole monitoring and control) is complex as the number of wells and increasing complexity in well construction, is driving the drilling Capex higher.
Current development plans in these fields show that a significant component of the field development capex is associated with the well construction costs, a significantly greater proportion of Capex than in conventional offshore developments. This is, due to the relatively lower facility costs associated with shallow water development in the Gulf. Hence optimization of well construction costs is a key component of successful delivery of the new fields. The rationalization of well complexity and organizational capability is an additional component in actively managing the increased risk associated with these non-traditional wells.
Additionally we screened the systems, processes and infrastructure required to ensure optimal delivery of the real time monitoring capability and decision making capability that this technology can unlock. This paper will seek to share how ADMA-OPCO plans to move the field development concepts forward in the project life cycle and how we look to leverage world-wide learning in bringing this technology into offshore Abu Dhabi and details some of the challenges and opportunities that occur as we move forward with these concepts.
Structural Characterization of Gas Shales on the Micro- and Nano-Scales
Authors: Curtis M. E. 
Published: February 2011

Abstract
The structure of shale samples from 9 different formations, the Barnett, Woodford, Eagle Ford, Haynesville, Marcellus, Kimmeridge, Floyd, Fayetteville and Horn River, has been investigated on the micro- and nano-scales using a combination of focused ion beam (FIB) milling and scanning electron microscopy (SEM). Using the FIB, a 10 nm thick cross-sectional slice (5 μm tall by 5 μm wide) is made into the shale. The newly exposed cross-section surface is then imaged using the SEM; this process is then repeated 300 - 600 times with each new slice progressing 10 nm deeper into the shale. The SEM images from this process form a 3-dimensional data set which is used to reconstruct a volume of the sectioned shale material. The reconstructed shale volumes show significant variations in the micro-structure (mineral content, micro-texture, clay platelet distribution, porosity, etc.) depending on the shale. Of particular importance to gas production is the variation in kerogen content and porosity within each shale. Assigning gray scale ranges to features, volumes can be constructed which show three dimensional distributions of these features. Some shale samples show significant kerogen content with connectivity of the kerogen observed throughout the reconstructed volume. Porosity in the shale samples is observed to be prevalent in either the kerogen, inorganic matrix, or both depending of the origin of the shale. When present, the kerogen in some shales has been found to have porosities of up to 50%. Observed pores within the shale samples range from a few to hundreds of nanometers in diameter, and the cross-sectional geometry of the pores varies depending on whether the pores are located in the kerogen or the inorganic matrix. Furthermore, the calculated porosity from the reconstructed shale volumes varies among the different shales. In addition to the calculated porosity, initial results for pore size distributions extracted from the reconstructed shale volumes will be presented in comparison to those found by mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) measurements. The SEM observed dimensions require consideration of new flow mechanisms for the transport of gas through shale.
Service Company Regulatory Issues in Unconventional Resource Play Exploration and Development
Authors: Theriau Rick 
Published: February 2011

Abstract
After the discovery of a new oil or gas play, many companies typically focus on both the potential of the resource and its development. Engaging the various interest groups who may have had previous use or aspirations for this area of land is often a forgotten consideration. The interests of these groups should be evaluated, and the groups should be involved to ensure that the development can proceed seamlessly. This consideration includes the careful planning of local regulatory and logistical issues while preparing for exploration and the subsequent development program of the unconventional resource.
A major oilfield company has operations that support unconventional resource development in Canada and has experience with the critical issues in these areas. This paper reviews operational considerations from a regulatory, personnel, infrastructure, and development-requirement perspective of an integrated service provider.
Key concepts include the following:
Stakeholder engagement, including indigenous people, regulatory bodies, landowners, and sub-surface competitors Personnel recruitment, orientation, training, and competency Hours of service and work scheduling for employees Facility, support, and equipment requirements Supplier network, procurement and logistics, and transportation of consumable items Considerations for sustainability and life cycle of the field Environmental effects and mitigation plans
As each of these areas is developed, specific issues can be resolved by the use of industry-sector associations and industry working groups to clarify and communicate expectations, thus leading to the codes of practice that may be required to develop the new technologies and techniques to enter into an unconventional resource play.
Reserves Management: A Concerted Effort
Authors: McMahan Nathan , Munoz Efren 
Published: February 2011

Abstract
Traditionally reserves management has been an exclusive function for Reservoir Engineers; however in mature fields the need to involve Production, Facilities, Geology, Operations Engineers and Financial Analysts is critical. This paper presents a suggested workflow to improve the way reserves are evaluated, supported, booked and documented with a concerted effort of a multidiscipline team. This paper is focused on tight gas reservoirs and the central idea is to reduce the uncertainty that is always present when dealing with reserves.
Most of the discussion is concentrated in understanding and verifying the hyperbolic decline “b” factor to be used for production decline analysis; we normally understand the mathematical meaning, but very rarely spend the time understanding the physical meaning and the consequences of using the wrong value. Once the “b” factor is defined, the proper documentation must be filed for each reserve record and the focus becomes the economic analysis of those reserves which is critical for future development especially in a very volatile economy in which prices are fluctuating a lot.
CCS: Opportunities and Obstacles for India
Authors: Raj P. , Mathur B. , Kumar S. , Jhalani S. 
Published: February 2011

Abstract
Carbon Capture and Storage (CCS) has become a popular catch phrase, both in scientific arena as well as on the political discussion. India, a country with a rapidly growing economy, where rise in economic growth goes hand in hand with an increase in energy demand which is currently met, as in many evolving economies, by fossil fuels. This ultimately leads to increase in GHG emissions. With the imminent threat of anthropogenic climate change in the coming decades, helping to control India's emissions will have to be a global priority. CCS can play a pivotal role in curbing India's emissions in the future, given its reliance on coal power and the large coal reserves. The main objective of this paper is to increase the understanding of the opportunities, issues and obstacles amongst the stakeholders regarding CCS in India. To achieve this objective, we have analyzed economic and institutional factors which encapsulate Indian power sector, challenges associated with the implementation of CCS, uncertainties linked with potential Co2 sources and sinks in India, needs and requirements for the future potential implementation of CCS in India. We have concluded our paper with relevant recommendations for the International Climate and CCS community to make conditions conducive for CCS in India.
Differences and Similarities in the Stimulation and Production of Shale Gas Reservoirs and Other Tight Formations
Authors: Economides M. J. , Wang X. 
Published: February 2011

Abstract
Production mechanisms and reservoir characteristics differentiate significantly in the exploitation of shale gas and other tight gas formations. In both cases, the use of massive hydraulic fracturing is essential and the reservoir characteristics, which include low to very low permeability (0.1 to 0.0001 md or even less), suggest very long and narrow fractures. It is clear that the choice of slick-water as fracturing fluid and the use of very small mass of proppant by the industry are the appropriate practices.
However, in tight reservoirs, gas is found in the pore space, requiring adequate porosity, and the initial gas-in-place (IGIP) can be readily calculated. Given the fractured well flow characteristics, recovery can then be estimated. Fracture design, taking into account the reservoir permeability, can be optimized to maximize the productivity index and ultimate recovery.
For shale gas, the IGIP is primarily in the form of adsorbed gas and far less of it is in the pore space. The volume of gas depends on sorption constants which describe the Langmuir adsorption/desorption isotherms. Because these constants are given in terms of gas per reservoir volume, the "stimulated volume," in other words, the volume contacted by the induced fractures, becomes critical. That is why horizontal wells with multiple transverse fractures, the latter with branches, have become the obvious geometry for shale gas production.
We present predictive models for production of both tight and shale gas reservoirs which include appropriate fracture designs taking into account reservoir characteristics. We also forecast well performance by considering well deliverability and ultimate recovery. The recovery for shale gas primarily depends on desorption. The results show distinct differences in production characteristics between tight gas and shale gas wells with the latter exhibiting far larger recoveries and sustainable production for far longer periods for similar reservoir permeabilities.
Numerical Simulation of the Solvent Drainage Process
Authors: Wong A. , Edmunds N. 
Published: February 2011

Abstract
Numerical simulations are widely used to predict and history match performance of reservoirs operating under various recovery processes. Simulators can offer quick answers however the answer should be validated against experimental/field data to verify its reliability. Many studies have been conducted to validate SAGD simulation results, but applying thermal simulators to solvent processes with confidence requires more studies and comparisons.
This paper will discuss the following topics on simulation of solvent process:
Comparing simulation results against the Nenniger and Dunn correlation on warm solvent drainage process Identifying the key input parameters(s) in solvent simulation Effects of grid block sizes on the results of solvent simulation
Nenniger and Dunn correlation (2008) provides good estimates of laboratory scaled simulation. Nenniger and Dunn recently mentioned the importance of rate limiting step and thickness of the solvent contact layer in the solvent drainage process. In order to understand the sensitivities of solvent simulation to the rate limiting step and thickness of the solvent contact layer, input parameters and grid block sizes were modified to observe their effects on the process.
Flow Regime Transfer Conditions for Two-Phase Flow in a Fracture
Authors: Shad S. , Maini B. B. , Gates I. D. 
Published: February 2011

Abstract
Overall, oil-laden fractured-rock reservoirs contain between 25 and 30 percent of the total known global petroleum reserves. In these reservoirs, fractures are the dominant flow path, therefore economic oil recoveries from fractured reservoirs rely on better understanding of the flow in fractures and networks of fractures. However, in contrast with gas-liquid flow in fractures, the flow of heavy oil and water has received less attention. Particularly, the flow regime map for two-phase immiscible flow in a thin gap and the transition boundaries are not well studied yet. In this research, a Hele-Shaw apparatus was used to study the flow of water in the presence of heavy oil in a smooth walled fracture. Different flow patterns were observed under different flow conditions and the effects of different fluid and fracture properties on flow regime transition boundaries for a thin gap were evaluated. The results of the experiments demonstrate that, flow regime boundaries strongly depend on fluid and fracture properties. The results also reveal that one correlation can be applied to predict different transition conditions under different fracture orientation.
Net CO2 Stored in North American EOR Projects
Authors: Faltinson J. E. , Gunter W. D. 
Published: February 2011

Abstract
One promising method for reducing CO2 emissions by storing the CO2 in oil reservoirs is CO2 Enhanced Oil Recovery (EOR). In order to make a significant contribution to mitigating climate change from emissions of GHG's, CO2 EOR must actually reduce CO2 emissions by storing net positive volumes of CO2. This requires that CO2 EOR schemes store more CO2 in the subsurface than the execution of the project emits (net positive storage of CO2). Fugitive emissions associated with CO2 EOR include primarily the burning of fossil fuels (fuel gas) to power CO2 injection compressors and the on-site consumption of electric power which results in CO2 emissions off-site where the power was generated. Evaluating the effectiveness of CO2 EOR in reducing CO2 emissions must be conducted in an unbiased way where only relevant fugitive emissions that are directly connected with the CO2 EOR project are deducted. It has been suggested that fugitive emissions from downstream oil refining and consumption of the transportation products should be deducted from the net CO2 stored by CO2 EOR projects. This presumes that these emissions (refining & consumption) are incremental to the EOR project and would not occur if the EOR project was not executed. World oil production is determined by world oil demand and if CO2 EOR projects were not undertaken, some other source of oil would step forward and fill the gap. Therefore, shutting down CO2 EOR projects will not lead to a decrease in incremental refining and consumption emissions. When downstream refining and product consumption fugitive emissions are correctly excluded from the calculation of Project Life-cycle CO2 EOR storage, it is clear that CO2 EOR does result in net positive CO2 storage.
An Unconventional Rate Decline Approach for Tight and Fracture-Dominated Gas Wells
Authors: Duong A. N. 
Published: February 2011

Abstract
Traditional decline methods such as Arps’ rate-time relations and their variations do not work for super-tight or shale gas wells where fracture flow is dominant. Most of the production data from these wells exhibit fracture-dominated flow regimes and rarely reach late-time-flow regimes even over several years of production. Without the presence of pseudoradial and boundary-dominated flows (BDF), neither matrix permeability nor drainage area can be established. This indicates that matrix contribution is negligible compared to fracture contribution and the expected ultimate recovery (EUR) can not be based on a traditional concept of drainage area.
An alternative approach is proposed to estimate EUR from wells where fracture flow is dominant and matrix contribution is negligible. To support these fracture flows, the connected fracture density of the fractured area must increase over time. This increase is possible due to local stress changes under fracture depletion. Pressure depletion within fracture networks would reactivate the existing faults or fractures, which may breach the hydraulic integrity of the shale that seals these features. If these faults or fractures are reactivated, their permeabilities will increase, facilitating enhanced fluid migration. For fracture flows at a constant flowing bottomhole pressure, a log-log plot of rate over cumulative production vs. time will yield a straight line with a unity slope regardless of fracture types. In practice, a slope of higher than unity is normally observed due to actual field operations, data approximation and flow regime changes. A rate-time or cumulative production-time relationship can be established based on the intercept and slope values of this log-log plot and initial gas rate.
Field examples from several super-tight and shale gas plays for both dry and high liquids gas production were used to test the new model. All display the predicted straight line trend, with its slope and intercept related to the type of fractured flow regimes. In other words, a certain fractured flow regime or a combination of flow types that dominate a given area or play due to its reservoir rock characteristics and/or fracture stimulation practices all produce a narrow range of intercepts and slopes. An individual well performance or EUR can be derived based on this range if the best-three-month average or the initial production rate of the well is already known or estimated.
The results show that this alternative approach is easier to use, gives a reliable EUR, and can be used to replace the traditional decline methods for unconventional reservoirs. The new approach is also able to provide statistical methods to analyze production forecasts of resource plays and to establish a range of results of these forecasts, including probability distributions of reserves in terms of P90 (lower side) to P10 (higher side).