bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Application of an External Casing Perforating Completion Process in the Wilshire Devonian Field of West Texas - A Case History
Authors: Krawietz Thomas E. , Hobbs Greg , Rodgerson James L. 
Published: December 2007

AbstractA new External Casing Perforating Technique (EXCP) has been utilized in the Wilshire Devonian Field in West Texas. By applying the new technology, we have been able to improve well performance, worker's safety, environmental quality and the time from rig release to first sales while holding costs within expectations. The technique was applied on all completions for the Wilshire development program in 2003.On conventional Wilshire completions, 850' of gross pay was fracture stimulated with 2 to 3 large treatments, at high rates and pressures. The conventional technique consists of perforating on wire line, isolating each zone with bridge plugs, and selectively stimulating each zone. A conventional completion takes 3 to 4 days, with multiple trips to the location, multiple sequences of rigging up and down of service company equipment and flowing back each zone. Numerous people are required on location for the entire process.With the EXCP system, perforating guns with isolation flappers and a hydraulic control line are attached to the outside of the casing, placed on depth and cemented in place. By applying pressure on the hydraulic control line at the surface, the guns are individually fired and the zones isolated with the flapper valves in one step. This system has allowed for more effective stimulations of up to seven individual zones within 14 hours, with immediate flow-back capability. Eliminating post-rig completion work has mostly offset the incremental EXCP cost increase. Production rates are improved while additional value is added due to a safer operation and a reduced impact on the environment.
The History and Future of China Oil and Gas
Authors: Li Dacun , Du Yuqi 
Published: December 2007

Abstract
China is the most populous country in the world. The booming economy with a high-percentage annual growth in GDP in the past twenty years has boosted its energy demand. Before 1993, China oil demand could be met by its own supply. After 1993, China oil demand exceeds its supply and the gap increases. As a result, more and more oil has to be imported to meet its demand. Now, about 40% of its oil consumption has to be imported, and the gap is still increasing. China surpassed Japan as the world's second-largest petroleum consumer in 2003. Even the Chinese government underestimated today's oil consumption in the 1990s. In this paper, we derive correlations based on solid oil and gas data reported in the past 20 years and then make predictions up to 2025 by using the correlations. In addition, we compare our predictions with those made by the US Energy Information Administration (EIA). Oil demand predicted by us is much higher than that by EIA, and even higher than the prediction made by EIA under the assumption of high economical growth scenario. The gas demand predicted by us is close to the reference case predicted by EIA. Gas consumption in China will increase by 500% from 2000 to 2025 while oil consumption by 200% from 2005 to 2025. A lot of oil and gas will have to be imported to meet boosting demand, creating tremendous opportunities in marketing oil and gas to China.
Constraining a Complex Gas-Water Dynamic Model Using 4D Seismic
Authors: Pannett Stephen , Slager Sven , Stone Greg , Dekker Sanne 
Published: December 2007

Abstract
The Maui C Sands reservoir contains most of the remaining gas-condensate reserves in the mature Maui Field. Technical and commercial management of a hydrocarbon producing field such as Maui relies heavily on the confidence in the forecasted production and reservoir performance predicted by dynamic reservoir models. This paper describes how the complex dynamic model of this reservoir has been constrained by detailed information gained from the interpretation of a timelapse 3D seismic survey (4D). Firstly, the paper briefly discusses the reasoning for acquisition of time lapse seismic at this stage of field life. Next, the interpretation results are presented, highlighting the level of detailed vertical and areal resolution achievable in the timelapse response in a stratified gas-water system such as the Maui C Sands reservoir. These results are supported by evidence of correlation between the timelapse seismic results and timelapse saturation well logging. The paper then discusses the methodologies applied to incorporate these interpreted results into the history matching of the dynamic model, and how this has constrained the quantification of remaining reserves. A check of how closely the model matches the seismic data is made by comparing synthetic timelapse seismic generated from the dynamic model with the actual timelapse seismic. Finally, further insights are presented on the implications of timelapse seismic results on the current structural understanding of the field, and the impact on future development planning.
A New Gravimetric – Swelling Test for Evaluating Water and Ion Uptake in Shales
Authors: Zhang Jianguo , Chenevert M. E. , AL-Bazali Talal , Sharma M. M. 
Published: December 2007

Abstract
The primary cause of wellbore instability is the interaction of water-based muds with shales. The movement of water and ions into or out of a shale can result in large changes in pore pressure in the vicinity of the wellbore, potentially leading to wellbore failure.
A new method, the Gravimetric – Swelling Test (GST), for determining the compatibility between shales and drilling fluids is presented in this paper. An experimental protocol and equations are presented that describe how such measurements can be conducted and interpreted with relative ease. The mass of water and ions entering or leaving shale samples is determined. With additional swelling measurements, the impact of the water and ions uptake on swelling pressures generated can also be obtained.
In this paper, results are presented for two preserved shale samples obtained from the field. The influence of different types of ionic solutions on water and ion movement is presented for each shale. It is shown that water uptake and swelling of shales is controlled not only by differences between shale water activity and water activity in the mud (as assumed in the past), but ion type and concentration also play an important role. In these tests the water uptake decreases, while the ion adsorption increases with increasing salt concentration. Different types of cations are shown to have a large influence on water/ion movement.
This paper presents a data set showing the influence of ion type and concentration on water uptake by shales. The role of capillary pressure, osmotic effects and ionic diffusion on swelling behavior of shales is also discussed. The technique presented herein may possibly be used at the rig-floor to determine the compatibility of shales with salt-water drilling fluids.
Drift-Flux Parameters for Three-Phase Steady-State Flow in Wellbores
Authors: Shi H. , Holmes J. A. , Diaz L. R. , Durlofsky L. J. , Aziz K. 
Published: December 2007

Abstract
Drift-flux models represent multiphase flow in wellbores or pipes in terms of a number of empirically determined parameters. Because of the lack of data for two and three-phase flow in large-diameter inclined pipes, existing parameters are commonly based on small-diameter pipe experiments, which can lead to significant errors when the models are applied to wellbore flows. In this work, we use recent large-diameter experimental data for the determination of drift-flux parameters for oil-water-gas flow. The parameters are computed through application of an optimization procedure. It is shown that gas holdup in three-phase systems can be estimated using a two-phase flow model by viewing the system as an effective gas-liquid system, with oil and water comprising the 'liquid' phase. This approach is, however, generally inaccurate for the determination of oil and water holdups, in which case the effect of gas must be taken into account. Specifically, for pipe inclinations away from horizontal, even small amounts of gas can act to eliminate the slip between oil and water. As the pipe deviation approaches horizontal, however, oil-water slip persists, even in the presence of gas. We develop and apply a unified two and three-phase flow model to capture this gas effect. The new model is shown to provide much more accurate predictions for oil and water holdups in three-phase systems than were achievable with previous models.
Effect of Grid Size in Risk Assessment of Petroleum Fields
Authors: Ligero Eliana L , Schiozer Denis J , Maschio Célio 
Published: December 2007

AbstractIt was shown recently that it is important to evaluate risk through probabilistic methodologies that involve a high number of simulation models because of the number of uncertain attributes. Geological modeling yields reservoir models that are represented through fine grids with millions of blocks. A probabilistic risk evaluation based on such grids would require a very high computational effort. Therefore, an upscaling procedure is necessary to reduce the grid size but it is difficult to select a grid size that could represent an adequate balance between precision of risk assessment and computational effort.The methodology applied to quantify risk involves a sensitivity analysis in order to reduce the number of critical attributes and the simulation of reservoir models obtained through all possible combinations of these attributes. After the simulation of the models, a statistic treatment is used to evaluate the risk involved in the process. Several procedures can be used to speedup the process; however the number of simulation runs may be very high. Upscaling of the simulation models can decrease significantly the computational effort and global time of the risk analysis process but it can also yield an inadequate risk assessment.In this paper the effect of the grid size on the process is evaluated. It was developed a methodology (1) to select an adequate grid size and (2) to speed up the risk analysis process. The choice of geological representative models from coarse grid risk evaluation can to be useful to represent the risk on fine model, avoiding the simulation of all fine models, yielding a significant speedup up of the process.Practical applications of upscaling in a probabilistic risk assessment, that use the concept of representative models selected to characterize geological uncertainties, are shown through calculations performed in a petroleum field represented by a fine grid simulation model with geological uncertainties.
A Comparative Study of Laboratory Techniques for Measuring Capillary Pressures in Tight Gas Sands
Authors: Newsham K. E. , Rushing J. A. , Lasswell P. M. , Cox J. C. , Blasingame T. A. 
Published: December 2007

Abstract
This paper presents results from a laboratory study comparing capillary pressure measurement techniques for tight gas sands. Included in our evaluation are the more traditional high-speed centrifuge and high-pressure mercury injection methods as well as the less conventional high-pressure porous plate and vapor desorption techniques. The results of our study show significant differences between the mercury injection data and composite capillary pressure curves constructed with data from the other three methods. Consequently, we have concluded that high-pressure mercury injection can be used to quantify pore size distribution, but often inaccurately characterizes capillary pressures, particularly at the irreducible water saturation. Moreover, our study suggests that a composite capillary pressure curve constructed from a combination of the vapor desorption data for the low water saturation range and high-speed centrifuge or high-pressure porous plate data for the high saturation range provides the most accurate capillary pressures for tight gas sands.
Generalized Capillary Pressure and Relative Permeability Model Inferred from Fractal Characterization of Porous Media
Authors: Li Kewen 
Published: December 2007

AbstractThe Brooks-Corey capillary pressure model has been accepted widely in the petroleum and other industries. However the Brooks-Corey model cannot represent capillary pressure curves of some rock samples such as those from The Geysers geothermal field. In fact, few existing capillary pressure models work for these rock samples. To this end, a more general capillary pressure model was derived theoretically from fractal modeling of a porous medium. It was found that the more general capillary pressure model could be reduced to the frequently-used Brooks-Corey capillary pressure model and the Li-Horne imbibition model when the fractal dimension of a porous medium takes a limiting value. This also demonstrates that the Brooks-Corey model and the Li-Horne model, which have been proposed empirically, have a solid theoretical basis. The results demonstrated that the new capillary pressure model could represent the capillary pressure curves of The Geysers rock while the Brooks-Corey model cannot. A relative permeability model was also developed from the new capillary pressure model. Fractal dimension, a parameter associated with the heterogeneity of the rock, determines the shape of relative permeability curves according to the new relative permeability model. The model can also be reduced to the Brooks-Corey relative permeability model.
Estimates for the Growth of a Condensate Bank from a Simple Compositional Model
Authors: von Schroeter Thomas , Gringarten Alain C. 
Published: December 2007

Abstract
This paper studies the growth of a region of liquid drop-out in gas condensate reservoirs. For this purpose, we develop a line source solution for a two-phase compositional flow model in which the thermodynamic properties of the phases are modelled by a cubic equation of state with zero binary interaction coefficients, gravity and capillary pressures are neglected, the formation is assumed to be laterally unbounded and homogeneous, and the production rate constant over time. The absence of fixed time or length scales allows a similarity transformation under which the governing equations reduce to a system of coupled ordinary differential equations in the similarity (Boltzmann) variable with two fixed and two free boundary conditions. As an example, we include simulation results obtained with data from a gas condensate field in the North Sea.
Analytical Modeling for Two-Phase EOR Processes: Splitting between Hydrodynamics and Thermodynamics
Authors: Pires A. P. , Bedrikovetsky P. G. , Shapiro A. A. 
Published: December 2007

Abstract
Compositional models describe chemical flooding and gas-based IOR processes. It is possible to show from the known analytical solutions of multicomponent polymer/surfactant flood, that the concentration "part" of the solution is completely defined by adsorption isotherms and does not depend on relative permeability and phase viscosities. Analytical models for 1-D displacement of oil by gas have been developed during last 15 years. It was observed from semi-analytical and numerical experiments that several thermodynamic features of the process (MMP, key tie lines, etc) are independent of transport properties.
In this paper, we introduce potential coordinates that allow for splitting of the compositional model into a thermodynamics auxiliary system and one transport equation. The number of auxiliary equations is less than the number of equations in the compositional model by one. Explicit projection and lifting procedures are derived. The splitting is valid for either selfsimilar continuous injection problems or for non-self-similar slug injection problems. Analytical models for displacement of oil by a polymer slug and for oil displacement by rich gas slug with lean gas drive were developed by the splitting procedure.
With respect to 3-D flows, splitting takes place only for the case of constant total mobility.
Subsidence and Horizontal Earth Surface Movement During Reservoir Depletion for 3D Reservoirs With 3D Earth Surface
Authors: Suzuki Ikkou , Morita Nobuo 
Published: December 2007

Abstract
Oil or gas production causes reservoir depletion. It induces reservoir compaction and subsidence and earth surface lateral movement. Gas and oil are found in 3D shape traps such as anticline traps, and inclined fault traps. In addition, the earth surface above such 3D reservoirs, where we observe subsidence and lateral movement, may not be flat, that is, mountains or valleys may exist above the reservoirs. The subsidence and horizontal movement are affected by the size and the location of mountains above reservoirs and also they are affected by the 3D reservoir shape. This paper analyzes 3D reservoir and earth surface geometry effects on subsidence and horizontal earth surface movement during reservoir compaction.
Asphaltene Precipitation in a Saturated Gas-Cap Reservoir
Authors: Kokal Sunil , Al-Dokhi Mohammad , Al-Zubail Makki , Al-Saeed Saeed 
Published: December 2007

Abstract
Asphaltene deposits were obtained from three high gas/oil ratio (GOR) wells in an offshore field in the Arabian Gulf. The reservoir is saturated and there is a gas-cap present in the field. In many wells the gas cones into the producing wells and causes precipitation of asphaltenes from the crude by stripping. These asphaltenes deposit in the wellbore and have the potential to create plugging problems.
This paper describes the results of an investigative study that was initiated to determine the precipitation mechanism and ways to alleviate the deposition problem. Asphaltene precipitation experiments were conducted at reservoir conditions in a special pressure-volume-temperature (PVT) apparatus. The effect of GOR on asphaltene precipitation was determined by titrating the reservoir oil with gas-cap gas. Bulk deposition tests were also performed at different GORs with reservoir fluids. The results demonstrate that the onset of asphaltene precipitation occurs at relatively low GOR values. The amount of asphaltene precipitated at the onset is small. Asphaltene precipitation and deposition increase with increasing GORs. Asphaltene deposition envelopes are provided for the reservoir oil as a function of pressure and temperature. Recommendations were made to alleviate the problem by controlling the maximum producing GORs to less than 1000 scf/stb. Recipes for solvent treatment including asphaltene dispersants are also described in the paper and are currently being considered for implementation in the field.
Predicting the Impact of Non-Newtonian Rheology on Relative Permeability Using Pore-Scale Modeling
Authors: Lopez Xavier , Blunt Martin J. 
Published: December 2007

Abstract
Polymers are frequently used in waterflooding to ensure stable displacement and to control excessive water production. The viscosity of the polymer is a function of shear rate. Typically they are shear-thinning fluids whose apparent viscosity in a porous medium decreases with increasing flow rate.
We use pore-scale network modeling to predict the single-and multi-phase properties of shear thinning fluids in porous media. The model uses networks that represent the disordered topology of real rocks. For single-phase flow we can accurately predict experimentally measured relationships between apparent viscosity and flow rate.
We simulate two-phase primary drainage and secondary imbibition in a water-wet system, where the wetting phase (polymer in aqueous solution) is non-Newtonian (shearthinning) while the non-wetting phase (oil) remains Newtonian. We can predict the relative permeabilities for Newtonian fluids in Berea sandstone accurately. We then use the pore-scale model to predict trends in relative permeability as a function of flow rate in Berea sandstone for a non-Newtonian wetting phase. The relative permeability is defined as the ratio of the flow rate in multi-phase flow to the corresponding flow rate in single-phase flow with the same pressure gradient with the same shear-thinning fluid. The non-Newtonian phase relative permeability initially decreases with increasing pressure gradient before increasing again, while always remaining below the Newtonian values. This effect is most pronounced at low wetting phase saturation. When the wetting phase is confined to layers in the pore space, the shear rate is less than that experienced in single-phase flow when the pore is completely filled with fluid. This leads to higher effective viscosities and an apparent decrease in relative permeability.
Revisiting Ekofisk and Eldfisk Wettability
Authors: Hamon G. 
Published: December 2007

Abstract
The Ekofisk and Eldfisk fields, located in the North Sea, are currently waterflooded to increase the oil recovery of these naturally fractured, low matrix permeability, chalk reservoirs. The wettability of these reservoirs has long been a concern due to the extensive fracture network and was widely studied. However, the large and unexplained scatter in wettability index, the discrepancy between laboratory and water injection results questioned the representativity of laboratory data. Recently, a review of 370 wettability tests has been performed. The effect of a large number of parameters has been investigated, including reservoir data and core handling and laboratory procedures.
The main results of this review are: A strong relationship in both the Ekofisk and Eldfisk fields between the water wetness and the elevation above the free water level, whatever the laboratory experimental conditionsA clear tendency of increasing water-wet characteristics with depth,A significant noise regarding this main trend due to experimental conditions
In the second part of this paper, the method used to generate the matrix water-oil relative permeability curves using pore network modelling is described. This approach allows incorporating the variations of both the rock characteristics and of the depth dependent wettability and complements the experimental core floods when no data is available for a given combination of lithology and wettability.
Optimizing Fracturing Fluid Cleanup in the Bossier Sand Using Chemical Frac Tracers and Aggressive Gel Breaker Deployment
Authors: Sullivan R. , Woodroof R. , Steinberger-Glaser A. , Fielder R. , Asadi M. 
Published: December 2007

Abstract
Proper fluid and proppant placement are critical to a successful propped fracture stimulation treatment. Despite effective placement of the treatment, well performance is often detrimentally affected by incomplete gel breaking and fluid recovery. A technique employing a family of environmentally friendly, fracturing fluid compatible chemical tracers has been employed for quantifying segment-by-segment fracturing fluid recovery. Utilizing this technology, it is demonstrated that individual fluid segment cleanup and recovery can be enhanced by optimizing fracturing fluid selection and by using aggressive gel breaker deployment schemes. The validation of improvements in fracturing fluid cleanup and the resultant effects on well performance are presented using Bossier Sand case histories. Comparisons between crosslinked gel systems and between conventional and aggressive gel breaker deployment schemes are highlighted.