bluuebunny/crossref_metadata_2025_split huggingface dataset:
Chemical Flood Simulation of Laboratory Corefloods for the Mangala Field: Generating Parameters for Field-Scale Simulation
Authors: Pandey Amitabh , Kumar M Suresh , Beliveau Dennis , Corbishley Douglas W. 
Published: April 2008

Abstract
Detailed laboratory experiments were carried out to evaluate the potential for various chemical flood processes (polymer, alkali-polymer, and alkali-surfactant-polymer) in Mangala, a large oilfield in India containing waxy crude with viscosity of 7–20cp. Experiments included fluid-fluid and fluid-rock interaction studies, followed by a series of linear and radial corefloods.
Simulation of the corefloods was carried out using STARS, the advanced compositional simulator available from CMG. The main coreflood simulation objective was to shed light on the various process mechanisms and to generate chemical flood parameters for field-scale simulation forecasts. Primary matching parameters included performance of the base waterflood, injection pressures to define shear-thinning polymer behavior, chemical flood performance to define interpolations between appropriate relative permeability curves based on capillary numbers, and produced chemical concentrations to define adsorption parameters. Sensitivity studies on the matching parameters examined the impacts of heterogeneity within the large-diameter radial cores, chemical adsorption, and capillary pressure and gravity effects.
The coreflood simulations provided significant insights into the chemical flood process mechanisms and eliminated uncertainties such as the effect of gravity in radial coreflood experiments; although some issues including the role of capillary end-effects have not as yet been completely resolved. The modeling showed that in situ saturation monitoring (scanning) of the cores is critical for future planned corefloods. The study also showed some of the current limitations in modeling these complex processes.
Chemical flood parameters fine-tuned during the coreflood simulations have been used in field-scale simulations to evaluate expected performance and to aid in design of a field-scale pilot project. Extensive field-scale simulations have been used to design an appropriate chemical flood implementation strategy. These works indicate potential field-scale incremental recoveries over waterflooding of ~7% STOIIP for a polymer flood and ~15% STOIIP for an alkaline-surfactant-polymer flood.
Calculation of a Critical Steam Injection Rate for Thermally-Assisted Gas-Oil Gravity Drainage
Authors: Al-Rabaani Abdul S. , Blunt Martin J. , Muggeridge Ann H. 
Published: April 2008

Abstract
Heavy oil contained in naturally fractured reservoirs is becoming an important resource as conventional oil reserves are depleted. However, maximizing recovery from such reservoirs is problematic due to the low flow rate of oil and the poor understanding of recovery mechanisms. One EOR method that is of particular interest is Thermally Assisted Gas-Oil Gravity Drainage (TA-GOGD). In this process, steam is injected into the reservoir. This heats the rock matrix blocks through the higher permeability fracture network and improves oil recovery principally by reducing the oil viscosity and thus increasing the rate of gravity drainage through the matrix.
This paper shows that there is a critical steam injection rate for TA-GOGD in fractured reservoirs. If the injection rate is below this critical rate, the time to heat the matrix will increase and oil recovery increases with the square of steam velocity in the fracture. If the steam injection rate is greater than the critical rate then there is no significant increase in oil recovery with rate.
A simple formula for calculating the critical steam rate in the fractures is derived analytically. We show that it correctly predicts the critical injection rate for detailed simulations of steam injection into an element of a fractured reservoir containing live oil. The predictions are shown to be correct for all fluid and rock properties investigated
Capillary Alteration of Caprocks by Acid Gases
Authors: Shah Virenkumar , Broseta Daniel , Mouronval Gerard 
Published: April 2008

Abstract
The safety of acid gas geological storage is to a large extent controlled by the capillary properties of the caprock. This low-permeable (e.g., clayey) porous media usually saturated with water acts as a capillary barrier to the underlying stored acid gas, provided its water-wettability is preserved and water/acid gas interfacial tension (IFT) is high enough. The displacement or capillary breakthrough pressure, above which the stored acid gas intrudes into the caprock, is directly related to those two interfacial properties. Water/acid gas IFTs have recently been thoroughly characterized. However, little is known on the effect of acid gases (CO2, H2S and their mixtures) on the water-wettability of caprocks.
We present an experimental setup and procedure for measuring contact angles on mineral substrates in the conditions of geological storage. Measurements have been carried out in a range of pressures extending up to 150 bar, both with CO2 and H2S, and with mineral substrates representative of caprock minerals such as quartz and mica, as well as with a substrate sampled from the caprock of a depleted gas reservoir. We observed that the wettability alteration of mica is moderate in the presence of dense CO2, but pronounced in the presence of dense H2S. In contrast, the wettability of quartz and of the ‘real' caprock substrate is not altered by dense CO2 or H2S.
In addition to those substrate- and acid gas-dependent wettability effects, the much lower water/acid gas IFTs as compared to water/hydrocarbon gas IFTs are responsible for a loss in capillary-sealing potential of a given caprock when a hydrocarbon gas is replaced with acid gas, especially when the acid gas is rich in H2S. This potential, as evaluated by the displacement or capillary breakthrough pressure, should be determined very carefully when planning an acid gas geological storage operation.
Foam Modeling in Heterogeneous Reservoirs Using Stochastic Bubble Population Approach
Authors: Zinati F. Farshbaf , Farajzadeh R. , Zitha P. L. J. 
Published: April 2008

Abstract
Foam is an attractive option in EOR for increasing oil recovery in mature water-flooded reservoirs. In this paper we use stochastic bubble population model and complex power law rheological model, to integrate foam physics into a flow simulator. Foam displacement is examined in layered reservoirs with and without isolating shale barrier between the layers and in stochastically distributed permeability fields. It is demonstrated that in isolated layers foam propagates faster in the high permeability layer and sweeps the low permeability layer only modestly. In communicating layers, sweep efficiency is improved significantly due to cross flow. In stochastic random permeability field, foam injection increases the liquid recovery by a factor of two in comparison to gas injection.
Summary of Gulf Coast Sandstone CO2 EOR Flooding Application and Response
Authors: Holtz Mark H. 
Published: April 2008

Abstract
Today the oil market is experiencing high production demand from mature oil fields in a possibly near-future carbon-constrained world. This demand will result in numerous new anthropogenic CO2 sources near oil fields currently producing under primary production. Many of the new areas for CO2 EOR application will lie where sandstone reservoirs dominate, with their higher-quality petrophysical characteristics. A review of today's and previous experiences in the Gulf Coast could help when new floods are designed and implemented in pioneer areas.
To characterize Gulf Coast sandstone CO2 EOR experience, information from both full floods and pilots was assembled. Published and publicly available data were used in the study, emphasizing geologic setting of the reservoir, flooding methods, slug size, CO2 utilization, and other measures that indicate flood results.
CO2 EOR is applied in reservoirs deposited as barrier/strandplain, submarine-fan, and fluvial/deltaic sandstones. Solvent gases are predominantly combinations of CO2, N2, and CH4, and are applied as WAG, gravity-stable, continuous injection, and huff n' puff flooding methods. Tools such as pulsed neutron and pressure and sponge cores measure pre-EOR residual oil saturations to be between 0.2 and 0.38, averaging 0.25. Expected recovery efficiency for all flood types range from 17 to 23% of OOIP, with permeable Gulf Coast floods typically displaying 5 to 6 months' breakthrough timing. Applying recovery characteristics from the projects summarized and applying CO2 screening criteria resulted in delineation of an oil-resource target of 4.7 BSTB of miscible floodable oil along the Gulf Coast.
Chemical Flooding of Fractured Carbonates Using Wettability Modifiers
Authors: Najafabadi Nariman Fathi , Delshad Mojdeh , Sepehrnoori Kamy , Nguyen Quoc P. , Zhang Jieyuan 
Published: April 2008

Abstract
Waterfloods performed in carbonate and naturally fractured reservoirs frequently suffer from relatively poor sweep efficiency by virtue of geological heterogeneity and preferentially oil-wet rock surface commonly seen in these reservoirs. The application of chemical-based wettability modification in such problematic formations has become one of the most potential enhanced oil recovery techniques for the worldwide abundance of fractured carbonates with significant amount of remaining oil.
Chemical stimulation with surfactant or electrolyte to alter the wettability towards more water-wetness has the potential to enhance water imbibition to expel more oil from matrix to the fractures. The countercurrent interaction at matrix-fracture interface involves interplay of capillary, gravitational and viscous forces. A clear understanding of these processes is required for an optimum oil recovery design and field implementation in fractured carbonate reservoirs. To this end, we have developed a systematic experimental and modeling approach on the combined benefit of wettability alteration for enhanced water imbibition and interfacial tension reduction.
Both natural and forced imbibition experiments were performed in mixed-wet rocks where oil volume produced was recorded for sequential injection of water, alkali, and surfactant/alkali mixture. The alkali was effective in wettability modification and enhanced water imbibition. Additional oil was recovered by injection of surfactant/alkali mixture following alkali injection due to interfacial tension reduction and oil mobilization. A wettability alteration model based on these mechanisms was developed and implemented in a compositional chemical flooding simulator. The experiments were successfully modeled with the enhanced simulator.
A better understanding of mechanisms involved in improved recovery of oil from fractured carbonates using wettability modifier will aid in identifying and implementing future field demonstration projects.
A Novel Foam Concept with CO2 Dissolved Surfactants
Authors: Le Viet Q. , Nguyen Quoc P. , Sanders Aaron W. 
Published: April 2008

Abstract
CO2 injection has become the most attractive solution for enhanced oil recovery (EOR). However, this process frequently suffers from viscous fingering, gravity override, and channeling of CO2 in heterogeneous formations and the inefficient displacement of oil in below-miscibility-pressure reservoirs. These challenging issues are closely related to the very limited ability to control CO2 mobility. CO2 foam stabilized with CO2 soluble surfactants has exhibited more economical and technical advantages in effective control of CO2 mobility in porous media than the existing direct methods of CO2 viscosification. An integrated research framework was developed to strengthen the role of molecular design for these features as wells as provide a better understanding of foam behavior with complex formation of viscous water/oil or oil/water emulsions. A simple block model was developed in CMG/STARS to demonstrate the advantages of the novel foam concept over the conventional foam processes in the field.
We proposed a novel injection strategy which involves dissolving the surfactant in the CO2. This method drastically lowers the injection costs, reduces the loss of surfactant onto the rock surface due to adsorption, and improves in-situ foam generation to significantly increase oil recovery. Two different novel methods, continuous CO2-dissolved-surfactant injection and water-alternating-gas with CO2-dissolved-surfactant injection, have been studied in this paper.
Foam corefloods performed with carbonate core show that CO2-dissolved surfactants greatly reduce the mobility of the injected gas compared to conventional injection strategies. This is consistently observed in the numerically simulated foam process at the field level.
Cement Core Experiments With A Conductive Leakage Pathway, Under Confining Stress And Alteration Of Cement's Mechanical Properties Via A Reactive Fluid, As An Analog For CO2 Leakage Scenario
Authors: Huerta Nicolas J. , Bryant Steven L. , Conrad Lauren 
Published: April 2008

Abstract
Unsuccessful zonal isolation and occurrence of sustained casing pressure indicate transport of fluids along a conductive pathway in a well's cemented annulus. Conductive pathways in cement can be grouped into three general classes: separation of the cement and formation or casing to form a micro annulus; micro fractures in the cement; and gas/mud channels in the cement matrix. In geologic storage of CO2 similar conductive paths are most likely to be responsible for CO2 leakage out of the reservoir along a wellbore. Moreover, cement is reactive with both CO2 gas and acidified brine (a product of CO2 dissolution into formation water) and the resulting cement product is of lower mechanical strength than the intact cement.
Recent research indicates that in neat cement the reaction rate is slow and long term degradation of intact cement is not a risk. Reaction at surfaces of conductive pathways raises a new set of issues, however. In any field situation a cemented annulus, and conductive pathways within it, support the effective stress of surrounding rock and pore fluid. If the mechanical properties of the opposing faces of the conductive pathway are altered by chemical reaction, or if the effective stress changes, then relative displacement (opening or closing) of the faces will occur.
Our lab has developed a system to i) create a fracture in a cement core that is representative of what one would expect in a conductive pathway within a cemented annulus and ii) measure the hydraulic conductivity of the fracture under confining stress. We use this apparatus to characterize how increasing the confining pressure controls the size of the aperture. We reacted the surfaces of the fractured cores and repeated the stress/aperture measurements. The results are consistent with the points of contacts between the core halves becoming mechanically weaker after reaction.
Our observations support the possibility that conductive pathways can be self-sealing. Degradation of the cement's mechanical properties by reaction with acidic aqueous phase at the surface of the fracture would lead to a narrower pathway, if effective stress is unchanged. Further work is underway to measure the extent of irreversible (plastic) deformation in these experiments. Our ultimate goal is to project the core scale relationship onto the well scale to determine the conditions (earth stresses, cement exposure to reactive fluids, and leak source pressure) under which a conduit tends to seal.
Pore Network Modeling of Multiphase Flow in Fissured and Vuggy Carbonates
Authors: Erzeybek S. , Akin S. 
Published: April 2008

Abstract
Carbonate reservoirs have more complex structures than silicate reservoirs because of depositional and digenetic features. Secondary porosity enhancements due to fracturing or dissolution processes result complex porosity systems and thus complex flow patterns. Carbonates may contain not only matrix and fracture but also the vugs and cavities that are irregular in shape and vary in size from millimeters to centimeters in diameter. Although many of these vugs appear to be isolated from fractures, the mechanism of oil recovery from vugs in such a system is highly dependent on the location of the vugs and connections of the vugs to the fissure/fracture system.
Two phase flow in fissured and vuggy carbonates was studied by developing a novel pore network model that consists of several sub-networks including matrix, vug and fissure sub-networks. Matrix blocks were constructed by pores with triangular and pore throats with square cross-sections respectively. Fissures and vugs were represented by square cross sections. In order to obtain a spatially uncorrelated model, pore radiuses, which were obtained from previously conducted thin section analysis of a carbonate rock, and pore throat radiuses with a uniform distribution were randomly distributed. It was observed that the developed model can successfully simulate primary drainage, and secondary imbibition processes like snap-off, piston like advance and pore body filling. Comparison of pore network results and several published experimental results showed the uses and applications of the proposed pore network model. It was concluded that this novel pore network model design successfully represents two phase flow in a fissured and vuggy carbonate rock.
Capillary Pressure and Relative Permeability of Small Cores
Authors: Olafuyi O. A. , Cinar Y. , Knackstedt M. A. , Pinczewski W. V. 
Published: April 2008

AbstractThis paper presents the results of drainage capillary pressure and relative permeability measurements made on cores of different size – bulk volumes ranging from 0.5 to 12 cm3. The aim of the measurements was to obtain reliable experimental data which can be used to validate the predictive value of micro-CT based network models for capillary pressure and relative permeability. Micro-CT based network models typically use realistic networks constructed from the X-ray images of the rock samples representing bulk volumes of the order of 0.3 cm3.Experimental data for drainage capillary pressure were obtained using the centrifuge technique. The results for the largest cores were comparable to data obtained on the same sample using the porous plate technique. Relative permeability data were obtained by history matching unsteady state displacement data. Homogeneous outcrop sandstones (Berea and Bentheim) and carbonate (Mt. Gambier) were used in the experiments. Air-brine and oil-brine fluid-systems were used for drainage capillary pressure and relative permeability measurements, respectively. The relative permeability data were compared with those predicted from empirical and geometry based models using capillary pressure data.Good agreement was obtained for the drainage capillary pressure measured on all samples used. The residual saturations obtained from the cores used in the displacement experiments were also in good agreement. The models were found to predict relative permeability of oil and water with varying degrees of success. For water relative permeability, the Pirson model predicts the experimental data successfully while the Corey, Corey-Brooks/Burdine and van Genuchten/Burdine models provide the best predictions for oil relative permeability. The results demonstrate for the first time that reliable drainage capillary pressure and relative permeability measurements can be made on small sandstone and carbonate cores of size similar to that used for micro-CT-imaging.
Effect of Depressurization on Trapped Saturations and Fluid Flow Functions
Authors: Nyre A. N. , McDougall S. R. , Skauge A. 
Published: April 2008

Abstract
Production below bubblepoint will generate free gas, first as discontinuous gas up to the critical gas saturation and thereafter free or mobile gas. The level of critical gas saturation is affected by pressure decline rate, interfacial tensions, pore structure, etc. The gas relative permeability is strongly reduced when trapped gas is present. Recent experimental studies have proved that gas relative permeability can be several orders of magnitude lower for an internal gas drive process (gas liberation during depressurization) than for an external gas drive process (gas injection). The critical gas saturation may indirectly influence gas breakthrough, gas cut, and also oil production.
Network modeling has been used to investigate physical relations to factors influencing the formation of critical gas saturation and the corresponding flow functions. The rock matrix composition determines, together with irreducible water saturation, diffusion paths, and therefore the degree of supersaturation in the medium. This mechanism combined with depletion rates, describes how trapped and mobile gas saturation evolves and determines factors influencing critical gas saturation.
We observe that bubble generation is strongly dependent on depletion rate, which in turn affects the critical gas saturation. The gas relative permeability is found to be two orders of magnitude lower than for gas injection even at relatively high gas saturations. We discuss the importance of including the physics of depressurization and advice on correct implementation of depressurization in reservoir simulations.
The results show that lower coordination number leads to higher critical gas saturation. The variation of critical gas saturation with pore structure diminishes at higher depletion rate. The significance to field application of depletion is that near the production well the pore structure has little influence on the critical gas saturation, while at low depletion rate in the reservoir (far from the well) the pore structure may be an important factor for the critical gas saturation.