bluuebunny/crossref_metadata_2025_split huggingface dataset:
Instantaneous 4D Seismic (i4D) - An Innovative Concept to Monitor Offshore Water Injector Wells
Authors: Stammeijer J.G.F. , Davidson M. , Hatchell P.J. , Lopez J.L. 
Published: March 2015

Introduction
Time-lapse, or 4D, seismic is frequently used in the offshore to monitor fluid movement processes such as waterflood or aquifer drive. These processes happen at relatively slow timescales (years). As a result, proper monitoring of these effects requires repeat surveys to be acquired every 3 to 5 years or so.
Recent examples in industry show that fast reservoir changes (~months) are also taking place. The observed changes are often associated with water injector wells. For example, Alsos et al (2009) show an example of a water injection well that produced large time-lapse signals in less than 1 year after its startup. Due to cost and other considerations, it is not feasible to repeat field-wide 4D surveys often, nor install permanent monitoring systems in many of those fields. Yet there is a need to monitor such phenomena more frequently, and also with short reaction times.
In the offshore, we propose a new method for time-lapse seismic surveys focused on water injector wells. Our so-called "Instantaneous 4D (i4D)" method aims to acquire dedicated high-quality 4D data with short turn-around time at cost levels low enough to make it affordable to repeat such data acquisition programs reasonably frequently. We have implemented the method as a variation on surveys that use ocean-bottom seismometers. We suspect that our method can also be combined with other ways of seismic data acquisition (for example, permanent reservoir monitoring systems; vertical seismic profiling systems in wells).
Our method is not intended to replace full-field surveys. Rather, it adds small surveys more frequently in between regular full-field surveys to enable better observation of fast 4D reservoir effects along with slow changes (Figure 1). It can be seen as filling the "gap" between the current practice of infrequent full-field surveys, and the installation of the permanent reservoir monitoring system, which can be expensive.
Application of Gibbs Ensemble Monte Carlo to Phase Equilibria of CO2/Hydrocarbon Mixtures
Authors: Iwasaki Satoshi , Liang Yunfeng , Matsuoka Toshifumi , Takahashi Satoru , Okuno Ryosuke 
Published: March 2015

Abstract
Gibbs Ensemble Monte Carlo (GEMC) is a molecular simulation method to predict phase behavior of fluids, such as crude oil and natural gas. It enables us to visualize microscopic structures of fluid phases. In this study, we apply GEMC to phase behavior of CO2/oil systems, where the CO2-rich liquid (L2) phase can coexist with the oil-rich liquid (L1) phase and vapor (V) phase. The L2 phase can have comparable density as the L1 phase. When the L2 phase is dense enough to extract light and intermediate hydrocarbons, CO2 flooding can achieve high displacement efficiency of more than 90%. A clear understanding of the L2 phase will help us design CO2-solvent injection processes. However, little is known about its microscopic structures and corresponding dynamic properties (i.e., viscosities and diffusion coefficients), apart from densities and phase compositions. The GEMC method is used to calculate phase equilibria of CO2/C16H34 mixtures at different pressures at 305 K, which are close to the critical point of CO2. Vapor-liquid phase equilibrium is predicted at pressures lower than 75 bar and liquid-liquid phase equilibrium at higher pressures up to 170 bar, where the density of the L2 phase is around 0.868 g/cm3 and that of L1 phase around 0.871 g/cm3. These results are in good agreement with the previous experimental data. By further adding CH4 and C2H6 into the mixture, liquid/liquid/vapor equilibrium was observed. The mole fraction, density and structural properties such as pair distribution function (which is directly related to the X-Ray diffraction), molecular clustering, and aggregation status of the three different phases are presented. Currently, we are extending our calculations to other CO2/hydrocarbon systems and calculating viscosities of two different liquid phases using Molecular Dynamics simulations with the atomic model used for GEMC.
Enabling Large Model of Reverse Time Migration
Authors: Lu Ligang 
Published: March 2015

Abstract
The extreme computational complexity of modern seismic imaging techniques has led to a decades-long search for the most efficient algorithms, the best optimization techniques and the most suitable hardware platforms on which to run these algorithms. The purpose of our study is to advance this search by exploring the potential of the new Blue Gene/Q (BG/Q) supercomputing system for Reverse Time Migration (RTM) imaging. Our study analyzes BG/Q's performance scalabilities over both imaging model size and number of computing nodes. Our end-to-end RTM implementation includes a 3D isotropic model, absorbing boundary conditions, a 9x9x9 stencil, forward and backward passes with application of source and received terms, snapshot storage and imaging condition. Our implementation uses domain partitioning of a single model over hundreds of nodes, which allows us to run models much larger than are common today. For example, we can easily run a 3D model of 20483 points. For the models tested, we have observed nearly perfect performance scaling over hundreds of nodes and are exploring scaling beyond that point. Even with initialization, data input, and image output, we have achieved an end-to-end throughput of 580 million stencils per second per node (or 590 billion stencils per second per rack). Furthermore, we achieved a 14.93x rack-to-rack performance improvement over the previous generation, BG/P. Our implementation exploits all levels of parallelism available, including MPI, OpenMP for multithreading, and built-in intrinsics for vector operations. We avoid the need for scratch space on disk by storing snapshots in memory. Our paper shares insights and experience on how to efficiently make use of BG/Q's HW resources to advance the state-of-the art of industry practice. It provides a guiding example for enabling seismic imaging algorithms using BG/Q to achieve an unprecedented level of performance.
The Shale-Gas Permeability Measurement Considering the Rarefaction Effect on Transport Mechanism in the Nanopores
Authors: Gao Cheng , Xu Ruina , Jiang Peixue , Xue Huaqing 
Published: March 2015

Abstract
The pulse-decay technique is a well-established laboratory method for measuring the permeability of hydraulically tight rocks. Nitrogen or helium is routinely used in measurement of pulse-decay method, but the main components of natural gas reservoirs are hydrocarbons such as methane. In addition, nitrogen or helium has greater access to the fine pore structure of shale than larger molecules such as methane. Utilizing gas such as methane other than N2 or He to measure permeabilities requires corrections for gas rarefaction effect to be incorporated in the analyses.
Knudsen number (Kn), the ratio between the gas free molecule distance and the pore diameter, is one of the key parameters to evaluate the rarefaction effect on the transport mechanism in micro/nano channels or porous media structure. When 0.001&lt;Kn&lt;0.1, the velocity slip cannot be ignored in the channel and the permeability will decrease. Due to the Knudsen numbers which indicate the interaction between gas molecules and micro-pores for helium, nitrogen and methane in the same micro-structure of tight rock are significantly different; the permeability measurements are specific for individual working gases. However, our analysis shows that neither of these pulse-decay approaches takes into account the differences in transport mechanisms in shale due to different Kn numbers caused by different working gases.
In this paper, we conducted a series of experimental studies to investigate different pulse-decay permeabilities measured using helium, nitrogen and methane for the same specimen under the same reservoir conditions. Specifically, the importance of estimating accurate Kn numbers of different working gases in rock samples directly impact permeabilities of rock samples was demonstrated. In reviewing these approaches, we also would propose the need and possible direction of new models that will be required for making evaluations more accurate and accurate. The new theoretical model was indicated to illustrate the inherent relationship between the microscopic parameter Knudsen number and the macroscopic parameter permeability of a tight rock.
The results showed that Knudsen number would strongly affect the pulse-decay permeabilities measured under the same in situ confining-stress state reservoirs because of these existing pulse-decay models of gas flow in nanopores was inapplicable to measure permeabilities since the original assumption of no-slip boundary conditions in the Navier-Stokes equation was incorrect at nanoscale. It would be highly recommended using methane to measure permeability of micro-structure tight rocks (i.e. shale).
Environmental Liabilities in Oil and Gas Industry and Life-Cycle Management
Authors: Zhao Lian , Wells Joseph , Dong Benjing , Jin Qiuying , Tang Xu 
Published: March 2015

Abstract
This extended abstract provides an overview of the environmental liabilities of oil and gas assets, asset retirement obligations (AROs) and environmental reporting requirements under the regulatory regimes in Alberta, in Canada and International Financial Reporting Standards (IFRS). Lifecycle asset liability and environmental management processes are associated with abandonment, remediation and reclamation, decommissioning and closure. Alberta's production of conventional oil and gas and oil sands projects has resulted in increased concerns related to climate changes and environmental liabilities of oilfield assets. More stringent regulatory compliance and standards have been developed and are likely to continue. Operators are responsible for the costs to comply with environmental regulations and take sufficient social responsibilities. The industrial experience of discharging liabilities has indicated that planning at early stages of the operation and managing asset liability bring a reduced cost and risk. Full lifecycle cost-effective and efficient environmental management begins with planning and successful acquisition. The best estimate calculation can be based on internal or external costs, depending on which is most likely.
A Model for Wettability Alteration in Fractured Reservoirs
Authors: Andersen Pal Ostebo , Evje Steinar , Kleppe Hans , Skjaeveland Svein Magne 
Published: March 2015

Abstract
Many of the world's oil reservoirs are naturally fractured. Injected water will flow into this highly permeable network and not sweep the matrix containing most of the oil. Spontaneous imbibition can drive oil into the fractures by capillary forces. However the wettability of the reservoir is critical for the ultimate potential of oil recovery. Experimental results indicate that exposing chalk cores to seawater or similar brines may alter the wettability towards a more water-wet state. In a fractured reservoir this exposure will happen by molecular diffusion and by water imbibing into the matrix. The injected brine is not in chemical equilibrium with the in-situ rock, water and oil so that chemical reactions occur. Experiments have shown that for chalk rocks the relevant processes are adsorption/desorption of ions on the mineral surface, precipitation/dissolution of minerals or ion exchange. We have developed a model where a reservoir is defined by a fracture surrounded by matrix on both sides. The injected brine contains a component that can adsorb on the matrix surface. These changes of the mineral surface are assumed to alter the wettability towards a more water-wet state. The wettability alteration is described by shifting curves for relative permeability and capillary pressure from curves representing oil-wet conditions towards curves representing more water-wet conditions. The model can make predictions regarding the effect of matrix properties such as wettability and external parameters such as schedule of brine compositions and injection rate. The understanding of the coupling between wettability alteration controlled by water-rock chemistry and fracture-matrix flow is highly relevant for gaining more insight into the observed high recovery in the North Sea chalk field Ekofisk.
Unconventional Reservoir Fracture Evaluation Utilizing Deep Shear-Wave Imaging
Authors: Patterson Doug , Mekic Natasa , Bolshakov Alexei , Harrison Charles , Tang Xiaoming 
Published: March 2015

Abstract
Unconventional shale reservoir evaluation and development are extremely challenging. One of the most dominating aspects is permeability, which is measured in the nano-darcy range. Although these wells are stimulated to enhance production, the presence or absence of natural fractures can have a large impact on the production results. In addition, the fracture variation across a reservoir can be substantial, leading to large production variations, even in adjacent wells. Gaining insight about the natural fracture system, both intersecting and around the borehole, is crucial and can often help determine the economic success of a well and/or reservoir.
The standard means of fracture evaluation, such as borehole imaging, Stoneley permeability analysis, and azimuthal shear-wave anisotropy evaluation from cross-dipole, provide valuable information when evaluating fractures. These standard methods, however, can only investigate a limited area around the borehole—imaging looks at the borehole wall and the other borehole acoustic methods rely on refracted and guided modes that respond to an area as large as 2 to 4 ft out into the formation. The flexural wave from the dipole is one of the guided modes that generally reads the deepest and is used in the standard cross-dipole analysis. In addition to flexural mode, the dipole source creates shear body waves that radiate away from the borehole and into the formation. When these shear waves impinge on a fracture their energy reflects back to the borehole, enabling the facture to be imaged. The reflection strength is a function of the shear-wave polarization and the nature of the fracture, with the strongest response occurring from the shear waves intersecting a fluid/gas-filled fracture and polarizing in the fracture's strike direction.
Another important aspect is that these shear waves have azimuthal sensitivity, providing a means to determine the fracture direction. These features enable the evaluation of fractures over a much larger area around the well, often in excess of 60 ft from the borehole, and even detecting major fractures that do not intersect the well.
We will look at the application of this deep shear-wave imaging technology in several unconventional reservoirs across North America. Our review includes conventional methods and the deep shear-wave imaging analysis, showing its value in gaining important insight about the natural fracture system around the borehole, especially non-intersecting fractures. In addition, we will look at its application in mapping geologic structures in horizontal wells, demonstrating the ability to detect sub-seismic faults.
Modelling Sub-Seismic Reservoir Discontinuities: Integrating Production Data with Seismic Data and Geological Analogues
Authors: Barr D.C. , Kalu M.U. , Musa F. , Flynn M.J. 
Published: March 2015

Abstract
The "Z" Field, located in Block A-18 of the Northern Malay Basin, has been producing gas from complex, multiple-stacked sandstone reservoirs for approximately four years. Most reservoirs are located between around 3600 and 4300 ft TVDSS, and generally exhibit Class III AVO response, with better-quality zones exhibiting low acoustic impedance resulting in a high amplitude seismic expression. Consequently, the success rate for targeted production wells is high, with 100% of seismic anomalies drilled at these levels encountering commercial gas deposits.
Well "X" targeted one such amplitude anomaly and consistently produces gas at a rate of more than 20 MMscf/d. Two years later, another well, "Y", was drilled approximately 1 km away. Both wells lie within the same seismic anomaly, share similar electric log profiles and were originally thought to lie within the same sand body. However, reservoir pressure in well "Y" was found to be around 160 psi greater than in well "X", and CO2 concentrations were 7–8% higher, indicating the reservoir was compartmentalized.
Paleoenvironment is believed to be estuarine, with most sands interpreted as tidal bars. Analogue studies show that such deposits are frequently heterolithic, containing thin shale beds that can act as baffles or barriers. The zone of interest was subjected to a chemostratigraphic study, which revealed that the provenance of the sand differed between the two wells. This difference in provenance indicates that the reservoir is likely to be divided into at least two genetically distinct sand bodies.
After closer examination, several narrow zones of high acoustic impedance were identified in seismic attribute extractions. These zones were defined as permeability barriers in the static geomodel, which was subsequently used as the basis for the dynamic simulation model. The dynamic model was then history-matched to production data, and the position and extent of the modeled shale barriers were adjusted until an optimal history-match was achieved.
Complex, compartmentalized reservoirs are never easy to model. However, by incorporating multiple geological, geophysical and reservoir engineering data sets, geologically consistent models of static and dynamic reservoir behavior can be achieved.
Advanced Analytical Capabilities for Optimising Exploitation of Unconventional Resources
Authors: Hippler S.J. , Neal J.E. , Alramahi B. , Becker S. , Klimentidis R.E. 
Published: March 2015

Abstract
Unconventional resources (tight gas, shale gas, and tight liquids) have become a transformative energy source in North America largely through trial and error field experimentation. Low gas prices in North America and the expansion of unconventional developments internationally are driving a need for more rapid and lower cost assessments of potential. Operational efficiency will always be the critical success factor in unconventional resource development, but a holistic understanding of the system from plates to plays to pores can enhance that efficiency, achieved by integrating results from a variety of advanced laboratory analytical techniques with stratigraphic models that enable mapping of key play parameters.
Geochemical analysis of core and cuttings is used to determine organic matter type, richness, and thermal maturity, from which hydrocarbon yields and fluid properties can be predicted. With unconventional resources, the hydrocarbon source rock is often also the reservoir. To understand storage capacity, the new generation of scanning electron microscopes enables nanometer-scale imaging of pores in the mineral matrix and organic matter, and generation of three dimensional volumes of the pore network that provide insight into hydrocarbon habitat and shale permeability. Finally, geomechanical experiments are performed to measure compressive strength and elastic properties, which are used to calibrate log-scale measurements to understand the variation of these rock properties across a play. Proppant embedment tests are used to understand the mechanical interaction between rocks, proppants and stimulation fluids at simulated downhole pressure conditions.
Putting the results of these laboratory analyses and experiments into a play-scale stratigraphic framework provides an understanding of the geologic factors driving past successes and failures in a range of unconventional resource types. This has enabled assessment of basin potential in new plays before investment, and rapid evaluation of play-scale sweet spots.
HSE Management for China Offshore Drilling Project
Authors: Cheng Zhong , Cheng Kun , Yang Guang , Mou Xiaojun , Huang Xiaolong 
Published: March 2015

Abstract
According to the International Drilling HSE (Health, Safety, and Environment) management standards and advanced management experience as well as hazard management techniques, CNOOC (China National Offshore Oil Corporation) constantly improves HSE management objectives of offshore drilling platforms, HSE organizations and HSE operating specification in compliance with its particular drilling operation and development features, with the aim of in-place management and effective measures. During more than 30 years' drilling operations, CNOOC has already learned and summarized a set of drilling project HSE management systems, which have achieved good results. This article introduces the CNOOC Offshore Drilling HSE management organization and management system. Specifically, it presents the offshore drilling HSE guarantee measures from five aspects, which include field operation risk control, traffic safety, staff health, environmental protection, and emergency measures. Through the implementation of these management methods and measures, the CNOOC offshore drilling projects have gradually achieved the HSE management objectives: minor damage, low accident rate, and zero pollution.