bluuebunny/crossref_metadata_2025_split huggingface dataset:
Buffalo Field High-Pressure Air Injection Projects: Technical Performance and Operational Challenges
Authors: Gutiérrez D. , Miller R. J. , Taylor A. R. , Thies B. P. , Kumar V. K. 
Published: April 2008

Abstract
The Buffalo Field air injection units, located in northwest South Dakota, are the oldest High-Pressure Air Injection (HPAI) projects currently in operation.
In mid 1977, realizing the rapid production decline under primary recovery, the operator initiated an IOR program including laboratory tests, feasibility studies, and a pilot air injectivity test. Because the pilot results were promising, the original 3.5-section Buffalo Red River Unit (BRRU) was formed in September 1978. The results continued to be encouraging and the unit was enlarged to nine sections in September 1980 and to twelve sections in May 1981. Based upon the success of the BRRU HPAI project, the South Buffalo Red River Unit (SBRRU) of 30.5 sections was formed in June 1983 and began to respond to injection in 1985. Furthermore, given the success of the BRRU and SBRRU HPAI projects, the 7-section West Buffalo Red River Unit was formed and started air injection in November 1987.
This paper summarizes the performance of the three projects and the overall experience gained by the operators after nearly 30 years of air injection. It covers almost every aspect of the entire operation since its inception; it discusses general management practices, technical and operational challenges encountered, injection and production facilities and drilling and well completion practices. It also includes estimates of incremental oil recovery due to air injection and discusses how the air utilization has changed over time
To date, the three HPAI projects in the Buffalo Field continue to be a commercial success. In the last three years, horizontal laterals have been drilled out of over 40 old vertical wells to enhance production, to take advantage of accumulated reservoir energy and to improve sweep efficiency. Drilling injection wells out of old vertical wells was not possible because the open hole laterals cross a porosity zone that would have taken away some of the injection into non-productive reservoir.
Retention of CO2-Foaming Agents Onto Chalk: Effects of Surfactant Structure, Temperature and Residual Oil Saturation
Authors: Fjelde Ingebret , Zuta John , Hauge Ingrid 
Published: April 2008

Abstract
Injection of CO2 is a well known enhanced oil recovery (EOR) technique. Formation of stable foam inside the reservoir can improve macroscopic sweep efficiency. On the other hand, retention of surfactants decreases the cost-efficiency of the EOR process. This paper presents flow-through retention experiments with CO2-foaming agents onto outcrop Liege chalk plugs. Two branched ethoxylated (EO) sulphonates with different ethoxylation degree, S1 (EO=7) and S2 (EO=12) were used. The aim was to investigate the effect of ethoxylation degree on surfactant retention. Furthermore, the effects of temperature and residual oil on surfactant retention were studied. The effect of waterflooding followed by CO2 flooding on surfactant retention at reservoir conditions was also evaluated. Partitioning of the foaming agents between water and oil phases was studied.
Results show that increasing the ethoxylation degree of the surfactant decreases the retention onto chalk cores saturated with formation water at 55°C. S2 (EO=12), which was found to give the lowest retention at 55°C, was found to have a higher retention at 70°C. The presence of residual oil saturation after waterflooding (Sorw) decreased the retention of S1 (EO=7) and increased the retention of S2 (EO=12) when compared to the absence of residual oil. The retention of S2 (EO=12) after waterflooding followed by CO2 flooding at 340 bar and 55°C was in the same range as retention on 100% water saturated core, but significantly lower than retention in residual oil saturated cores. The experiments have shown that not only surfactant structure and temperature are important for the retention of surfactants, but also the presence of oil.
Viscous Oil Displacement with Aqueous Associative Polymers
Authors: Aktas F. , Clemens T. , Castanier L. M. , Kovscek A. R. 
Published: April 2008

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

ABSTRACT
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

Abstract
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.