bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effects of Reservoir Parameters and Operational Design on the Prediction of SAGD Performance in Athabasca Oilsands
Authors: Nguyen Huy X. , Wisup Bae , Tran Xuan V. , Ta Dung Q. , Nguyen Danh H. 
Published: June 2012

Abstract
The efficiency of the SAGD process depends on two important factors: reservoir properties and operating conditions. SAGD performance was investigated based on the variables of reservoir properties such as thickness, porosity, permeability, oil saturation, viscosity, rock thermal conductivity, along with operating variables as including preheating, injector/producer spacing, injection pressure, steam injection rate and subcool temperature. In addition, the economic risks associate to the high capital and operation expenditures, and uncertainties of oil and gas prices in the market. In order to manage the uncertainties of oilsands project, we need the quantitative analysis of concerned parameters affecting returns. Then, we can propose optimization design for operating conditions.
The previous studies conducted sensitivity analysis and optimization of SAGD performance by classical methods. Therefore, there was a lack of confidence level because they did not determine the significance level of parameters and ignored interactions effects between considered parameters, lead to low efficiency issues in a field operation. Furthermore, the economic models were not comprehensive enough with limited consideration on few factors. These restrictions of classical method can be avoided by applying D-optimal design and response surface methodology to find the best regression model for SAGD performance.
There were a total of 75 cases for screening reservoir and operational parameters with the NPV responses based on the D-optimal design. The results showed that reservoir properties have a greatest influence on the SAGD performance with ranking order of porosity, thickness, oil saturation, permeability, viscosity, respectively. The optimization design of operating conditions obtained the maximum NPV when vertical well spacing 9m, injection pressure 5,000kPa.
New Flattening-Based Methodology for More Accurate Geostatistical Reservoir Populating
Authors: Poudret Mathieu , Bennis Chakib , Dumont Cyrielle , Lerat Olivier , Rainaud Jean-François 
Published: June 2012

Abstract
In the domain of oil exploration, geostatistical methods aim at simulating petrophysical properties in a 3D grid model of reservoir. The main input comes from drilled wells data in the geographic space. Lithofacies and petrophysical properties as porosity and permeability are measured along these wells trajectories. These data are then assigned to every cell of the 3D grid model which intersects a well trajectory. At this step, only a small amount of cells are populated with petrophysical properties. Roughly speaking, the question is: which properties we should give to cell c, knowing the properties of n cells at a given distance from c? Obviously, the population of the whole reservoir must be computed while respecting the spatial correlation distances between petrophysical properties. Thus, the computing of these correlation distances is a key feature of the geostatistical simulations.
In the classical geostatistical simulation workflow, the evaluation of the correlation distance is imprecise. Indeed, they are computed in a Cartesian simulation space which is not representative of the geometry of the reservoir. Thus, depending on the deformation degree of the lithostratigraphic units in the geographic space, significant errors may be introduced in the geostatistical simulation. This lack of accuracy has prompted us to work on and devise a new methodology in order to increase the reliability of the parameters required by the geostatistical simulators.
We propose a new methodology in order to better estimate the correlation distances between wells. Our methodology is based on the isometric flattening of lithostratigraphic units. Thanks to this flattening process, we accurately reposition the initial populated cells in a flat simulation space, before computing the correlation distances. In this paper, we introduce our methodology through study case representing different deposit modes of the sub-surface models. We finally present some preliminary results.
Vertical Lift Models Substantiated by Statfjord Field Data
Authors: Fevang Øivind , Fossmark Marthe Gilje , Nordaas Kulkarni Kari , Lauritsen Håvard Thomassen , Skjaeveland Svein M. 
Published: June 2012

Abstract
The Statfjord field entered into the blow down phase after 30 years of production. Production of injection gas and gas liberated from residual oil is the main production target in this phase. In some areas, the gas cap has been produced and the wells are producing mainly water until the solution gas is mobilized. These wells have gone through large changes in gas-liquid-ratio (GLR) and water-cut (WCT). Production tests from wells located in such areas have been used when analyzing the ability of multiphase-flow correlations to model vertical lift performance (VLP). Accurate modeling of the VLP is critical to predict a realistic production rate during the blow down phase.
Measured wellhead (THP) and downhole pressures from about 80 production tests, from four wells, were used to analyze the accuracy of VLP correlations at widely varying flow conditions (GLR, WCT, and THP). Altogether 17 multiphase pressure drop correlations incorporated in the program Prosper were tested by comparing observed and calculated downhole pressures.
Based on the production tests the ability of the different correlations to predict the VLP varies with the following top 4: Hagedorn Brown, Petroleum Experts, Petroleum Experts 2, and Petroleum Experts 3. These correlations are recommended if no measured data is available.
In general a somewhat low pressure drop is predicted at low gas-liquid ratio (GLR), and a somewhat high pressure drop is predicted at high GLR. After tuning, accurate predictability was observed for the different correlations for limited ranges in GLR e.g. 50-300 Sm3/Sm3. However, for larger ranges in GLR it was not possible to achieve an accurate VLP correlation, even after tuning. Hagedorn Brown and Petroleum experts seem to be the most accurate correlations for a wide range of producing GLR.
The error in the predicted production performance when a single VLP correlation is used can be substantial for highly productive wells with large variations in producing GLR. It is recommended to shift the tuning following the GLR development.
Analysis of Surface and Downhole Microseismic Monitoring Coupled with Hydraulic Fracture Modeling in the Woodford Shale
Authors: Neuhaus Carl W. , Miskimins Jennifer L. 
Published: June 2012

Abstract
The work presented in this paper analyzes surface and downhole microseismic data for a horizontal well in the Woodford Shale in Oklahoma and compares those results with calibrated hydraulic fracture modeling. Hydraulic fracture models were created for each of five stages with a three-dimensional modeling software, incorporating available petrophysical data in order to match the recorded treatment pressure and the fracture geometry obtained from the microseismic data. Further analysis investigated the congruency of the downhole and the surface microseismic data, what differences they produced in a match if used exclusively, the influence of the number of events on the fracture geometry obtained from the microseismic data, the error of event location, the degree of complexity of the created fracture network, and the relationship between the magnitude of events and the time and location of their occurrence.
The fracture models produced good matches for both pressure and fracture geometry but showed problems matching the fracture height due to cross-stage fracturing into parts of the reservoir that were already stimulated in a previous stage. Surface and downhole microseismic data overlapped in certain regions and picked up on different occurrences in others, giving a more complete picture of microseismic activity and fracture growth if used together. However, they deviated in terms of vertical event location with surface data showing more upward growth and downhole data showing more downward growth. In general, the downhole microseismic data showed that the stimulation treatment was successful in creating a fairly complex hydraulic fracture network for all stages, with microseismic recordings making flow paths visible governed by both paleo and present day stresses. Plots showing the speed of event generation, the cumulative seismic moment, and the event magnitude versus the event-to-receiver-distance identified interaction with pre-existing fault structures during Stages III and V.
Determination of the In-Situ Polymer Viscosity from Fall-Off Tests
Authors: Laoroongroj Ajana , Zechner Markus , Clemens Torsten , Gringarten Alain 
Published: June 2012

Abstract
Laboratory experiments and simulations showed that for an Austrian oil reservoir, oil recovery can be significantly increased using polymers. One of the key design parameters for optimizing displacement efficiency while minimizing costs is the in-situ viscosity of the polymer solutions.
Whereas the viscosity of polymer solutions can be measured at surface, the viscosity in the reservoir is difficult to estimate due to degradation of the polymers during the injection process. In addition, polymers exhibit non-Newtonian behaviours resulting in different viscosities of the polymer solutions depending on the shear rate in the reservoir.
For the Austrian reservoir, water injection fall off tests were available. A simulation model was calibrated with these tests, and used to simulate injections of polymer solutions followed by fall offs. Simulation results indicate that water injection and fall off tests followed by a series of polymer injection and fall off tests can be interpreted to determine the in-situ viscosity of polymer solutions and the radius of the polymer front with reasonable accuracy, even in the case of non-Newtonian shear-thinning behaviour.
Being able to determine the in-situ viscosity allows modifying the injection programme (changing pumps, modifying perforations) if the degradation of the polymer viscosity is found to be significant, and adjusting the polymer concentration to improve stability and efficiency of the displacement process.
Multi-phase Well Testing to Calibrate Relative Permeability Measurements for Reservoir Simulation
Authors: Green Alistair J. , Gringarten Alain C. , Whittle Tim M. 
Published: June 2012

Abstract
Special core analysis (SCAL) is the standard method for estimating relative permeabilities. These, however, must be upscaled for reservoir simulation and the upscaling process creates uncertainties that are propagated to field performance forecasts. This paper describes a six-stage well testing procedure to calibrate relative permeabilities for reservoir simulation and to reduce uncertainties in relative permeability end points and curvature.
The well test includes: (1) single phase oil production; (2) buildup; (3) single phase water injection; (4) falloff; (5) two-phase oil and water production; and (6) a final buildup. The final buildup is initiated at minimum well productivity. Transient pressure analyses of the first buildup (2) and the falloff (4) provide the single phase mobility for each fluid at respective saturation end points. These yield an estimate for endpoint water relative permeability. Analysis of the second buildup yields an estimate of the minimum mobility. Uncertainty in oil and water relative permeability curvature is reduced using all three mobility estimates, while uncertainty in end point saturations can be reduced, for example, by comparing resistivity logs before and after water injection.
The procedure is demonstrated by simulating a newly drilled well in a homogeneous oil reservoir. Relative permeability is shown to significantly impact water breakthrough and oil production in an oil field developed by water flood. Sensitivities to reservoir heterogeneity, water cut during the flow back period, numerical dispersion, and capillary pressure have also been explored.
Information provided by the proposed test and interpretation procedure allows improved field development decisions early in field life.
Chalk Reservoir Management Through Rock Physics Diagnostics - Field Examples from the Danish North Sea
Authors: Gommesen Lars , Hansen Hans Peder 
Published: June 2012

Abstract
This paper illustrates the value of an integrated approach to management of chalk reservoirs and aims to provide the reader with 3D and 4D seismic examples that takes offset in the key parameters controlling elastic behaviour of chalk without discussing theories or models in depth, and only include well logs or laboratory derived models to support the examples.
The examples of this paper show how quantitative geophysical analysis through integration with well-established reservoir engineering and geoscience processes has impacted reservoir management and field development significantly. The diagnostics have led to optimized drilling and near field appraisal, maturation of wells, identification of remaining potential and insight to water flooding dynamics.
The paper concludes that an integrated approach to field development and reservoir management includes quantitative geophysical interpretation and that rock physics is an excellent enabler for integration between geoscience and petroleum engineering.
Characterization of Direct Fractures Using Real Time Offshore Detection of Deuterium Oxide Tracer
Authors: Poulsen Allan K. , Lafond Kim Bousquet , Voigt Niels V. , Lundgaard Thomas , Pedersen Lars Malcolm 
Published: June 2012

Abstract
Induced or natural fractures in waterflooded reservoirs can have a negative impact on oil recovery. Direct connections between injectors and producers allow otherwise recoverable oil to be bypassed by the injected water, reducing the sweep efficiency and the pressure support to the reservoir. Knowledge about the number of connections, their location and size is essential to properly design a reliable conformance treatment. The Danish Technological Institute has together with Maersk Oil developed a deuterium based tracer technology which can provide information about high conductivity fractures in tight reservoirs. The method has been proven on several studies in the North Sea and allows quick and direct analysis offshore. Immediate actions based on real time results offshore can be taken and minimum response time is needed for planning further operations.
The tracer used is deuterium oxide which is safe to handle and brings no environmental issues, as it is already naturally present in water. It is completely miscible with water and does not dissolve in the oil phase. The returns are analyzed directly from the produced water stream after separation using a mass spectrometer. This portable equipment allows a quick and reliable analysis with minimal sample preparation.
The concentration of tracer is analyzed to give information such has breakthrough time, concentration profile and volume of tracer returned. This data is then used to determine the number of fractures, their conductivity and their relative position in the wellbore using an injector-fracture-producer model.
Non-Darcy Flow Numerical Simulation for Low-Permeability Reservoirs
Authors: Xu Jianchun , Jiang Ruizhong , Xie Lisha , Wang Ruiheng , Shan Lijun , Li Linkai 
Published: June 2012

Abstract
With further progress of oilfields&#39; development all over the world, more and more low permeability reservoirs are being put in production. However, fluid flow in low permeability porous media no longer obeys Darcy&#39;s law and instead conforms to the one of low-velocity non-Darcy seepage. Most commercial numerical simulation software may cause inaccuracy in simulating development performance of low permeability reservoirs. So the non-Darcy flow numerical simulation software has been developed.
In this paper, non-Darcy flow mathematical model was presented. Then, on the basis of practical field and laboratory experiment data, an ideal model of five-spot well pattern was established. Under the same reservoir condition, the non-Darcy simulation, Darcy simulation and quasi-linear simulation were conducted. At last, the simulation results of pressure gradient distribution, accumulative oil production and remaining oil distribution for Darcy flow, quasi-linear flow and non-Darcy flow were given. Research shows that flow of most regions in low permeability reservoir belongs to the curve segment which indicate the rationality of the non-Darcy software; compared with the results of Darcy flow, when considering non-Darcy flow, the accumulative oil production is lower, and the quasi-linear flow is the lowest, so Darcy flow model overstates the reservoir flow capability, and quasi-linear flow model overstates the reservoir flow resistance; analysis of remaining oil saturation indicates that for non-Darcy flow model simulation and quasi-linear flow model simulation, different flow regions exist including dead oil region and flow region which makes the flow patterns more complex in low permeability reservoir.
Assisted Seismic History Matching of the Nelson Field: Managing Large Numbers of Unknowns by Divide and Conquer
Authors: Stephen Karl D. , Kazemi Alireza , Sedighi Farzaneh 
Published: June 2012

Abstract
Automatic history matching may be used to condition reservoir simulation models by including time-lapse seismic data. Stochastic optimization algorithms are used to ensure a good search of the parameter space to ensure proper determination of the best models. These approaches can require many thousands of simulations for large dimensional problems. Divide and conquer is an assisted history matching approach that enables deconvolution of the parameters so that they can be searched more efficiently and also leads to better uncertainty analysis.
We present an application of this approach on the Nelson field. Nine years of production history data are used along with baseline and monitor surveys. Localised variations were made to permeability and net:gross. The reservoir was divided into separate parameter regions by combining experimental design and proxy model analysis. The former enabled insignificant parameters to be discarded while the latter showed that each region could be treated as a separate history matching sub-problem. Each sub-problem was then solved simultaneously using an adapted stochastic genetic algorithm.
The results showed that a forty-two dimensional problem could be reduced to a combination of three 9D problems and a 3D problem due to the spatial deconvolution of parameters and misfits. An improved match was obtained for the production and seismic data. Compared to a full stochastic search of the parameter space, the number of models was several orders of magnitude smaller. Further, improved uncertainly analysis was made possible resulting in better understanding of the future behaviour of the reservoir.
An improved match to reservoir models leads to better confidence in their prediction and thus they can be used more effectively in reservoir management. The method presented here to improve the match retains the benefits of stochastic searching without the penalty of requiring an impractical number of simulations.
Reducing Surface Tension To Improve Clean Up Efficiency Of Hydraulically Fractured Wells: Does It Really Work?
Authors: Ghahri Panteha , Ramli Muhamad Shwaz , Jamiolahmady Mahmoud 
Published: June 2012

Abstract
The main purpose of applying surfactants for hydraulically fractured wells is to reduce fracturing fluid surface tension during the leak-off process and hence improve its cleanup efficiency. Significant research has been devoted to developing such chemicals that can effectively reduce capillary forces between fracture fluid and resident rock and fluids. However, in a recent numerical study (SPE-14414), we have shown that, for some cases, reducing surface tension tends to decrease the cleanup efficiency.
Following our previous study, we have conducted a comprehensive sensitivity study to identify conditions in which reduction of surface tension improves cleanup efficiency. During this exercise, the impacts of matrix permeability (km), fracture permeability (kf) and fracture fluid injection volume were investigated. Over 200 simulation runs were performed covering a wide range of variation of of these pertinent parameters for a single fractured well model.
The results indicate that at the early stage of production the cleanup efficiency is relatively poor and almost independent of IFT, km and kf. At late stages of production and when kf is low, reducing surface tension decreases the cleanup efficiency. For high kf values, on the other hand, cleanup efficiency improves with such a reduction. For the cases with km values greater than 0.001, cleanup efficiency is more effective if IFT increases. Furthermore, as km decreases, the damage due to fracture fluid blockage becomes more severe. It is interesting to note that when km is less than 0.0001, cleanup efficiency always decreases with increasing surface tension, for all different kf values. The amount of gas production loss for such cases is relatively high, indicating the severity of fracture fluid damage for very tight gas reservoirs. Increasing the fracture fluid injection volume did not significantly change the above trend.
The results presented here aim to help the industry in properly evaluating the added value of using surfactant to improve the cleanup process of the hydraulically fractured wells.
Affecting Parameters in Density Driven Convection Mixing in CO2 Storage in Brine
Authors: Soroush Mansour , Wessel-Berg Dag , Torsaeter Ole , Taheri Amir , Kleppe Jon 
Published: June 2012

Abstract
After injecting CO2 into subsurface brine for storage, it will be trapped in the reservoir through various mechanisms. In the beginning, the geological trapping mechanism dominates and the CO2 plume is moving upward below a cap rock. Then brine will imbibe the formation and some parts of the CO2 will be trapped in the pore paces. Later on injected CO2 will dissolve in the brine and increases its density. As a result, the heavier brine will move into deeper parts of the reservoir and density driven convection mixing will occur. This is known as the solubility trapping mechanism.
Here in this study, density driven phenomena in CO2 storage in brine and the influencing parameters are the prime targets. We find particularly interesting results for this through Hele-Shaw cell experiments and numerical simulations. Hele-Shaw flow is defined to occur between two parallel flat plates separated by a small gap. In each experiment the cell is filled with fresh water and a shim prevents it to leak. Then liquid with higher density is placed on top. Several tests including water of varying salinity at the top of the cell have been conducted, and the results are interpreted separately and compared with the base experiment.
More extensive studies and sensitivity analysis is done based on a simulation model constructed on the reservoir properties of a brine formation, with wide range of affecting parameters, including density differences, permeability variations and the effect of diffusion coefficients. It has been also attempted to investigate the effect of anisotropy and heterogeneity on the CO2 state after injection.