bluuebunny/crossref_metadata_2025 huggingface dataset:
Viscous Oil Displacement with Aqueous Associative Polymers
Authors: Aktas F. , Clemens T. , Castanier L. M. , Kovscek A. R.
Published: April 2008

This study investigates the pore-level displacement of medium viscosity oil (200 cP) by brine and aqueous solutions of associative polymers. Associative polymers result in greater aqueous phase viscosities at the same concentration as conventional polymers. Studies are conducted in two-dimensional etched-silicon micro-models under a reflected light microscope. The pore network pattern of the micro-model replicates Berea sandstone. Results include the sweep pattern, oil recovery, and the pore-level distribution of residual oil. Generally, we find that brine and conventional polymer solutions at low concentrations result in severe fingering of the displacing fluid through the oil phase. Associative polymers lead to more stable displacement characteristics, apparently due to greater phase viscosity. Additionally, injection of associative polymers after breakthrough of brine mitigates fingering and improves viscous oil displacement. Experimental results show that associative polymers are a promising method to improve the displacement efficiency of viscous oils.
Effective EOR Decision Strategies with Limited Data: Field Cases Demonstration
Authors: Manrique Eduardo , Izadi Mehdi , Kitchen Curtis , Alvarado Vladimir
Published: April 2008

Enhanced-Oil Recovery (EOR) for asset acquisition or rejuvenation involves intertwined decisions. In this sense, EOR operations are tied to a perception of high investments that demand EOR workflows with screening procedures, simulation and detailed economic evaluations. Procedures have been developed over the years to execute EOR evaluation workflows.

We propose strategies for EOR evaluation workflows that account for different levels of available information. These procedures have been successfully applied to oil property evaluations and EOR applicability in a variety of oil reservoirs. The methodology relies on conventional and unconventional screening methods, emphasizing identification of analogues to support decision making. The screening phase is combined with analytical or simplified numerical simulations to estimate full-field performance while maintaining rational reservoir segmentation procedures.

This paper fully describes the EOR decision-making procedures using field case examples from Asia, Canada, Mexico, South America and the United States. The type of assets evaluated includes a spectrum of reservoir types, from oil sands to light oil reservoirs. Different stages of development and information availability are discussed. Results show the advantage of flexible decision-making frameworks that adapt to the volume and quality of information by formulating the correct decision problem and concentrate on projects and/or properties with apparent economic merit.

Our EOR decision-making approaches integrate several evaluation tools, publicly or commercially available, whose combination depends on availability and quality of data. The decision is laid out using decision-analysis tools coupled with economic models and numerical simulation. This allows integrated teams to collaborate in the decision making process without over-analyzing the available data. One interesting aspect is the combination of geologic and engineering data, minimizing experts’ bias and combining technical and financial figures of merit rationally. The proposed methodology has proved useful to screen and evaluate projects/properties very rapidly, identifying whether or not upside potential exists.
CO2 IOR Evaluation for the U.S. Rocky Mountain Assets
Authors: Kulkarni Madhav M. , Chen Hung-Lung , Brummert Allen C.
Published: April 2008

CO2 flooding has become the fastest growing gas injection EOR method, contributing 4.8% of U.S. oil production. An integrated approach was undertaken to evaluate the CO2-EOR feasibility for Marathon's Rocky Mountain (RM) region assets. The RM assets of the Wind River and Big Horn basins were evaluated using detailed geological and compositional reservoir models imposed with multiple development scenarios. The fractured nature of the RM assets posed a challenge for reservoir modeling, which prompted combinations of approaches such as production ranking to facilitate fracture descriptions. Extensive laboratory CO2-oil PVT tests were also conducted to tune a representative equation-of-state fluid model to confidently quantify reservoir fluid behavior. CO2 injection scenarios for two oil fields were evaluated using compositional dual-porosity and dual-permeability reservoir models. Performance evaluation under multiple sensitivities, namely WAG ratio, fluid properties, injection pressures, and fracture characteristics were also investigated to quantify their impact on oil recovery factors. The simulation recovery results were non-dimensionalized to generate distinct type-curves, which were then applied to areas that have similar fracture and geological characteristics.

The unique workflows generated during this study were verified and benchmarked by using them to history match the performance of an analogous RM field currently under CO2 injection. This paper describes the integrated approaches applied to maturing RM assets, which in addition to identifying significant IOR potential, have helped enhance the reservoirs’ characterizations, standardize subsurface workflows, aid facilities design, and scale-up performance data for optimal reservoir management.
Analysis of the Wettability Alteration Process during Seawater Imbibition into Preferentially Oil-Wet Chalk Cores
Authors: Yu L. , Evje S. , Kleppe H. , Kårstad T. , Fjelde I. , Skjaeveland S. M.
Published: April 2008

Improved oil recovery from fractured oil-wet carbonate reservoirs is a great challenge. The water-flooding efficiency will be low because of higher permeability in fractures than in matrix, and negative capillary pressure retains oil inside the matrix blocks. Studies of oil-wet chalk have shown that sulphate ions in the seawater may alter the wettability towards increased water-wetness.

One-dimensional spontaneous imbibition tests of seawater into preferentially oil-wet chalk cores are performed. To get a better understanding, a numerical model has been developed which includes effects of wettability alteration.

The experiments are carried out on cylindrical, sealed core plugs with only top open or with both ends open. Only countercurrent imbibition takes place for cores with top end open. For cores with both ends open, both countercurrent and cocurrent imbibition take place, and oil recovery rate is obviously accelerated. Taking formation water as the base case, higher oil recovery is observed with seawater imbibition. To simulate the wettability alteration process caused by seawater, a model is developed which includes molecular diffusion, adsorption of wettability alteration (WA) agent, gravity and capillary pressure. The WA agent diffuses into the formation water initially present in the core, adsorb onto the rock surface and induce wettability alteration. Consequently, the capillary pressure curve is shifted to higher values. In particular, the capillary pressure at the initial water saturation changes from negative to positive values and seawater is imbibed into the core. The shapes of relative permeability curves also depend on the wettability. The simulation results can fairly well match the experimental data.

With the experimental and modeling work we explore the interplay between capillarity and gravity, and especially the importance to consider wettability alteration process is again confirmed.
Development of Surfactants for Chemical Flooding at Difficult Reservoir Conditions
Authors: Barnes Julian R. , Smit Johan P. , Smit Jasper R. , Shpakoff P. Gregory , Raney Kirk H. , Puerto Maura C.
Published: April 2008

The production and properties of two families of anionic surfactants (internal olefin sulfonates and branched C16, 17 alcohol-based alkoxy sulfonates) are described for chemical flooding of oil reservoirs at high temperatures and/or high salinities. Surfactant properties measured include oil/water micro-emulsion phase behaviour obtained using new glassware-based procedures appropriate for higher reservoir temperatures. The results obtained relate to oil/water interfacial tension behaviour and give the"operating window" of the surfactants in terms of their optimal salinity and ability to solubilise oil in the micro-emulsion. The phase tests also give information on the quality of the micro-emulsions obtained where low viscosity and absence of gels is desirable. The surfactants described are promising for EOR and can be produced in commercial quantities. Different IOS products are available with different carbon chain cuts (with range C15 to C28) allowing matching of the IOS to the temperature, salinity and crude oil type of reservoirs. In addition, both IO carbon chain (degree of branching) and the degree of sulfonation influence the surfactant properties of the IOS mixture formed which provides a means for tailoring an IOS surfactant for optimal performance.
Phase Behaviour Methods for the Evaluation of Surfactants for Chemical Flooding at Higher Temperature Reservoir Conditions
Authors: Barnes Julian R. , Smit Johan P. , Smit Jasper R. , Shpakoff P. Gregory , Raney Kirk H. , Puerto Maura C.
Published: April 2008

Accurate laboratory screening of surfactants for their ability to give ultra-low interfacial tensions in oil/brine systems is important as a pre-cursor to laboratory core flow tests and surfactant flooding processes in the field. Screening is usually judged by visualisation of middle-phase micro-emulsions in oil/brine systems. Three laboratory methods are described which enable the phase behaviour of oil/water systems containing surfactants to be more safely visualised and measured in glassware at higher temperatures. Higher temperature test conditions result in significant vapour pressures from crude oil and water, and some glass tube test methods currently used in the industry may not be appropriate from a laboratory safety standpoint. The new methods have been verified in our laboratories for higher temperature use and provide useful screening methods for higher temperature reservoirs (up to 150°C).
Colloidal Dispersion Gels Improve Oil Recovery in a Heterogeneous Argentina Waterflood
Authors: Diaz D. , Somaruga C. , Norman C. , Romero J.
Published: April 2008

The Loma Alta Sur Field is a mature waterflood in the Neuquén Basin of Argentina. The productive formation (Grupo Neuquen) consists of numerous fluvial, multi-layer sandstone packages. Extensive diagnostics, including tracers, injection profiles, review of historical production and reservoir fluid analysis corroborated the combined effect of reservoir heterogeneity and an adverse mobility ratio.

High concentration polymer gels, sometimes called "bulk gels", can be effective in reducing water channeling in naturally fractured formations or in reservoirs with multi-darcy permeability anomalies. However, the Loma Alta Sur Field produces from a multi-layer unfractured matrix rock reservoir and is not a candidate for traditional bulk gel treatments. Uncrosslinked polymer is an alternative for improving an adverse mobility ratio, but is most effective in relatively homogeneous reservoirs in order to minimize polymer breakthrough in offset producing wells.

The primary objective of the the operator in this pilot was to improve volumetric sweep efficiency. CDG's were selected for the Loma Alta Field for several reasons: (1) CDG's offer significantly higher adsorption and residual resistance factors than uncrosslinked polymer (2) CDG's can be injected in matrix rock and (3) fresh water was not required for gel formation at low polymer concentrations.

Extensive diagnostics were applied before and after the CDG injection, including tracers, injection profiles and analysis of historical production data. Post treatment analysis of the CDG treatments indicate positive oil and water trends in the pilot area.
Line Tension-Based Modification of Young's Equation for Rock-Oil-Brine Systems
Authors: Saini Dayanand , Zheng Yu , Rao Dandina N.
Published: April 2008

The two-century old Young's equation has been widely used in petroleum engineering to depict wettability through contact angles and surface free energies. In order to address it's inadequacies, including the unaccounted vertical component of liquid-vapor interfacial tension and to accommodate the imbalance of intermolecular forces experienced by the three-phase confluence zone, the Young's equation has been modified in the recent literature to include a line tension term in case of solid-liquid-vapor (S-L-V) systems. In this paper, we would like to report on the results of our attempts to experimentally investigate the applicability of the line tension-based modification of the Young's equation to solid-liquid-liquid (rock-oil-brine) systems of interest to the petroleum industry.

Both the ambient and reservoir condition optical cells have been used, with stock tank oil and live oil respectively, to determine the drop size dependency of dynamic contact angle subtended by the oil-brine interface against the rock surface. The experimental data have been correlated with the modified Young's equation to determine the magnitude of line tension in rock-oil-brine systems. To the best of our knowledge, this is the first attempt to apply the modified Young's equation to rock-oil-brine systems and to measure line tension for a rock-live crude oil-brine system at reservoir conditions of pressure and temperature.

The measured line tension for solid-liquid-liquid (S-L-L) systems, while being positive and of the same order of magnitude as in solid-liquid-vapor (S-L-V) systems, correlates well with the water-advancing contact angle and the adhesion number, a ratio of adhesion force to capillary force. This experimental study indicates that the extent of deviation from the Young's equation exhibited by rock-oil-brine systems may be directly related to the adhesion phenomenon. This study reinforces the need to include the rock-oil adhesion forces in our consideration of rock-fluid interactions, wettability and their impact on improved oil recovery processes.
Reservoir Condition Measurements of Compositional Effects on Gas-Oil Interfacial Tension and Miscibility
Authors: Sequeira Daryl S. , Ayirala Subhash C. , Rao Dandina N.
Published: April 2008

Minimum miscibility pressure (MMP) is an important design parameter for enhanced oil recovery processes involving gas injection (carbon dioxide, nitrogen, or hydrocarbons). Hence an experimental approach called "vanishing interfacial tension (VIT)" has been developed, to determine gas-oil miscibility, based on the fundamental definition of zero gas-oil interfacial tension (IFT) at miscibility. In this study, gas-oil interfacial tensions were measured between CO2 and a live crude oil from a depleted Louisiana oil field at varying pressures and at reservoir temperature (238°F) using the pendant drop and capillary rise techniques to determine the MMP. The gas-oil ratios have also been varied (both on molar and volumetric basis) widely in the high-pressure and high-temperature optical cell to examine the compositional path effects on IFT and miscibility. Detailed compositional measurements of both vapor and liquid phases were carried out using a gas chromatograph, and densities of both phases were measured using a digital densitometer.

The experimental results indicated that the gas-oil interfacial tensions measured at various gas-oil ratios at reservoir temperature, although displaying different relationships with pressure, converged to almost the same end-point pressure at zero-IFT. In spite of the large variations in the initial mixture compositions, only negligible changes in VIT miscibility pressures, from 6142 to 6216 psig (1.2% maximum difference), were observed thereby establishing the compositional path independence of the VIT technique. The compositional analyses of gas and oil phases at different gas-oil ratios showed that the gas phase is predominantly CO2, while the CO2 in the liquid phase continuously increased with pressure, which indicates condensing drive characteristics of CO2 to be responsible for miscibility development in the selected reservoir case. The density-pressure plots showed the evidence of approach to critical mixture formation near VIT miscibility. This experimental study confirms the robustness of the VIT technique for accurate, quick, and cost-effective determination of gas-oil miscibility conditions.
Combining Bulk Gels and Colloidal Dispersion Gels for Improved Volumetric Sweep Efficiency in a Mature Waterflood
Authors: Muruaga E. , Flores M. , Norman C. , Romero J.
Published: April 2008

The Golfo San Jorge (GSJ) is located in the southern Argentina provinces of Santa Cruz and Chubut. This hydrocarbon basin occupies a surface area of approximately 170,000 km2, approximately 1/3 of which is offshore. Waterflood oil recovery in many GSJ reservoirs does not exceed 10% OOIP due to the combined effects of reservoir heterogeneity and, in many fields, an adverse mobility ratio. The most significant hydrocarbon accumulations of the basin occur in a series of fluvial and shallow lacustrine reservoirs with significant tuffaceous content. A typical GSJ hydrocarbon reservoir includes a series of relatively thin sandstone packages that are not believed to be naturally fractured.

In an effort to distribute water injection more uniformly, most injection wells are equipped with injection mandrels. However, heterogeneity within the productive layers limits the effectiveness of near wellbore selective injection. A recent field pilot combining two types of gel technologies in the Comodoro Rivadavia Formation, one of the most prolific GSJ reservoirs, is encouraging. Based on tracer studies, historical production data and reservoir characterization, approximately 15,000 barrels of MarcitSM gels were injected in each of two adjacent injection wells. Seven months after the Marcit gel treatments, the operator began a colloidal dispersion gel (CDG) pilot in the same two patterns, injecting a total CDG pore volume of approximately 18% in certain layers of the Comodoro Rivadavia Formation. A chemical injection plant was connected at a point upstream of the two injectors so that both wells could be treated simultaneously, with the flexibility to vary the rate and polymer gel concentration in each well. A discussion of the reservoir characterization will be presented as well as the chemical treatment designs, subsequent modifications in the course of the pilot, and recommendations.
Statistical Model of Dispersion in a 2-D Glass Micromodel
Authors: Ghazanfari Mohammad Hossein , Kharrat Riyaz , Rashtchian Dawood , Vossoughi Shapour
Published: April 2008

Microscopic Visualization of the porous media can provide valuable information to enhance understanding of pore-scale transport phenomena. Here, a micromodel which its grains and pores are non-uniform in size, shape and distribution is considered as porous medium. The pore size distribution as well as pore length distribution was extracted by applying an image analysis technique. A two-dimensional random network model of the micromodel has been constructed which the non-uniformity is considered by assigning measured distribution functions. The random particle method was applied for correlating and predicting dispersion coefficients based on probabilistic approaches. Statistical derivations result in a new functional dependence for the longitudinal and transverse dispersion coefficients in terms of pore velocity and ensemble averages. Prediction from derived model for both longitude and transverse dispersion is in close agreement with the experimental data. Despite the simplicity of the proposed network model, its accurate prediction provides some confidence that it can be considered as a reasonable approximation of the complex nature of porous media with reliable predictive capability.
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

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

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

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

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

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

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

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

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

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

This 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

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.
Application of Bayesian Networks for Predicting the Performance of Gel-Treated Wells in the Arbuckle Formation, Kansas
Authors: Ghoraishy S. M. , Liang J. T. , Green D. W. , Liang H. C.
Published: April 2008

Polymer-based gels have been used extensively to reduce water production and improve oil productivity in the Arbuckle formation in central Kansas. One of the most important steps required for successful gel-polymer treatments is to identify candidate wells. Traditionally, the selection of wells to be treated has been based on subjective screening guidelines which may result in inconsistent treatment outcomes and poor economic performance. The objective of this study was to develop a method to identify candidate wells in the Arbuckle for gel-polymer treatments using individual well data readily available to an operator.

The approach was to use Bayesian networks applied to a data set derived from a number of gel-treated wells in the Arbuckle. Bayesian networks (Belief Networks) are probabilistic graphical models that represent a set of variables and their probabilistic dependencies. For this study two different Bayesian networks, Naïve and Augmented, were trained using pre-and post-treatment well data from 45 wells. The trained networks were then used with pre-treatment data from 14 additional wells to predict the post-treatment well performance economics of those wells. Well performance was evaluated using a discounted cash flow and net present value (NPV) economic analysis.

The results indicate that both the Naïve and Augmented Bayesian networks can accurately predict post-treatment well performance economics. For the 14 wells for which predictions were made, the average accuracy in NPV prediction was 77% and 84% respectively for the two Bayesian methods used. The analysis identified completion thickness from the top of Arbuckle and water-oil ratio as the most important parameters for the success of gel treatments in the Arbuckle formation.

Compared to other methods of candidate-well selection, which either rely on complicated reservoir models or unreliable anecdotal screening guidelines, Bayesian networks are relatively easy to implement and can accurately predict the post-treatment well performance economics. Results from this study demonstrated that Bayesian networks can be a very powerful tool for candidate-well selection for gel treatments in the Arbuckle formation. The same concept can be applied in other areas where enough data are available to train the Bayesian networks.
Wettability Alteration of Fractured Carbonate Reservoirs
Authors: Gupta R. , Mohanty K. K.
Published: April 2008

Oil can be recovered from fractured, initially oil-wet carbonate reservoirs by wettability alteration with dilute surfactant and electrolyte solutions. The goal of this work is to study the effect of salinity, surfactant concentration, electrolyte concentration, and temperature on the wettability alteration and identify underlying mechanisms. Contact angles, phase behavior, and interfacial tensions were measured with two oils (one model oil and one field oil). There exists an optimal surfactant concentration for varying salinity and an optimal salinity for varying surfactant concentration at which the wettability alteration is the maximum for anionic surfactants. As the reservoir salinity increases, the extent of maximum wettability alteration decreases for a surfactant, but the surfactant concentration needed for the maximum wettability alteration decreases. IFT and contact angle were found to have the same optimal salinity for a given concentration of anionic surfactants. As the ethoxylation increases in anionic surfactants, the extent of wettability alteration increases. Wettability of carbonates can be altered by divalent ions at high temperature (90°C and above). Sulfate and calcium ions play a more important role in altering wettability than magnesium ions. Wettability alteration increases the oil recovery rate from fractured carbonates.
Anisotropic Relative Permeabilities for Characterising Heavy-Oil Depletion Experiment
Authors: Ezeuko C. C. , McDougall S. R. , Bondino I. , Hamon G.
Published: April 2008

In recent years, the use of pore-scale network models has greatly advanced our understanding of solution gas drive processes by accounting for the complex dynamics operating at the microscopic scale. Moreover, it has also been demonstrated that a pore-network model, when suitably anchored to core material is able to provide both qualitative and quantitative descriptions of relative permeability and hydrocarbon recovery. In contrast, many so-called "experimental" depletion drive relative permeabilities are not measured directly but are generally obtained by history-matching laboratory production data with reservoir simulators, often resulting in very low gas relative permeabilities that are difficult to explain from a physical viewpoint. Although pore-scale network models have been successfully used in the past to match raw production data, the steady-state relative permeabilities calculated from such models commonly predict much slower gas saturation build-up than that found experimentally. Some previous authors have related this low gas saturation build-up to the difference in the definition of critical gas saturation between reservoir simulators and pore-network models. However, the dentritic nature of gas-cluster topology in network models, especially in the presence of other forces, such as gravity or strong viscous pressure gradients, clearly suggests that significant anisotropy may exist in relative permeability due to the balance of forces at this scale.

In the present work, we describe how the naïve process of scaling up steady-state relative permeabilities obtained from pore-scale network models to the laboratory scale may contribute significantly to the difficulty in history-matching experimental production. By considering the influence of the various forces (capillary, gravity, viscous) on the topology of the growing gas clusters and by accurately incorporating anisotropic network-model relative permeabilities, we show that high gas saturation build-up, consistent with experimental observations can be obtained from reservoir simulation.