bluuebunny/crossref_metadata_2025_split huggingface dataset:
Implementation of Relative Permeability Modifiers in Krasnoleninskoe Oil Field: Case Histories
Authors: Parkhonyuk Sergey , Levanyuk Olesya , Oparin Maxim , Sadykov Almaz , Mullen Kevin , Lungwitz Bernhard , Enkababian Philippe , Mauth Kevin , Alexander Karpukhin 
Published: April 2012

Abstract
Excess water production is a major concern for Russian oil companies. Maturing fields are producing at ever-increasing water cut resulting in problems such as the cost of disposal and environmental issues. In recent years, operators have shown a rising interest in Relative Permeability Modifiers (RPMs) as a potential solution to reduce water production.
RPMs are designed to disproportionately reduce the relative permeability to one phase (water) over the oil phase. RPMs are a preventive approach to reduce water production. Ideally, they should completely block water flow without affecting oil flow. While RPMs are used worldwide, they must be adjusted to the reservoir conditions. This becomes even more important in the case of hydraulic fracturing of formations with nearby water-saturated layers.
Commonly, service companies recommend one type of RPM which fits all reservoirs. This paper demonstrates how RPM selection on reservoir cores is critical for successful application in the field. We describe laboratory testing and review field trial results of RPMs in a low permeability (2 to 14 mD), highly laminated formation. Because RPMs are typically used only in high-permeability reservoirs, this application is unique. We evaluated chemically different RPMs on actual core material and found strong performance variations of the tested RPMs. We selected a suitable RPM following both core flow testing and compatibility testing.
For the field test, wells in the Krasnoleninskoe oilfield were selected for RPM treatments. Oil production was increased in most cases while the water cut was reduced or only slightly increased by up to 5% during 6 months following the treatment. These results show that with proper evaluation, RPMs can also be successfully used in low-permeability reservoirs. We demonstrated also that otherwise proven successful RPMs may not fit every reservoir and proper evaluation and monitoring is critical for success.
Beaver Creek Madison CO2 Enhanced Oil Recovery Project Case History; Riverton, Wyoming
Authors: Peterson Charles A. , Pearson Edward J. , Chodur Veronica T. , Periera Carlos 
Published: April 2012

Abstract
The Beaver Creek Madison project is the most recent CO2 EOR project in the state of Wyoming. Having pre-project oil production of 43 MMBO, this flood is projected to increase recovery by 11.1 MMBO or 10% of the estimated 109 MMBO OOIP. Early CO2 flood response has yielded production increasing from a pre-flood rate of 280 BOPD to its current rate of 5100 BOPD since July, 2008. Since project initiation, the reservoir has realized 2.6 MMBO of incremental oil.
The Madison reservoir, located in the Beaver Creek Field, 14 miles SSE of Riverton, Wyoming, is found at an average depth of 11,235’ placing it among the deepest CO2 EOR projects in the United States. Reservoir temperature is approximately 234° F. in this limestone/dolomite reservoir. The Madison is a highly structured, fault bounded reservoir encompassing just under 1000 acres with an average net pay of 212’, and an oil column thickness of 740’. The CO2 flood is a mixed design peripheral and gravity stable flood incorporating localized continuous gas injection and water alternating gas (WAG) processes which takes advantage of the reservoir's geometry and structural relief. The flood incorporates 32 wells.
This report provides a case study for a deep carbonate CO2 flood. It includes the Beaver Creek Madison's geologic and reservoir characterization, flood design, early production performance, and reservoir management. Also included in this presentation is a discussion of the pre-flood evaluation and design which incorporated a 3 phase evaluation process progressing from preliminary scoping and screening to more costly laboratory testing, detailed reservoir modeling and flood design. Early life reservoir management includes some minor, yet functionally significant, changes to the injection pattern and WAG cycles intended to optimize the reservoirs performance compensating for early deviations from the field's anticipated responses.
Anomalous Foam Fractional Flow Solutions at High Injection Foam Quality
Authors: Roostapour A. , Kam S. I. 
Published: April 2012

Abstract
A thorough understanding of foam fundamentals is crucial to the optimum design of foams for improved/enhanced oil recovery. This study, for the first time, presents anomalous foam fractional flow solutions which deviate significantly from the conventional solutions at high injection foam qualities, by comparig Method of Characteristics and mechanistic bubble-population-balance simulations.
The results from modeling and simulations based on coreflood experiments revealed that (1) there exist three regions: region "A" with relatively wet (or high fw) injection conditions where the solutions are consistent with the conventional fractional flow theory; region "C" with very dry (or low fw) injection conditions where the solutions deviate significantly; and region "B" in between which has a negative dfw/dSw slope showing physically unstable solutions; (2) for dry injection conditions in region "C", the solutions require a constant state (IJ) between initial (I) and injection (J) conditions, forcing a shock from I to IJ by intersecting fractional flow curves, followed by spreading waves or another shock to reach from IJ to J; and (3) the location of IJ in fw vs. Sw domain moves to the left (or toward lower Sw) as the total injection velocity increases for both weak and strong foams until it reaches limiting water saturation.
Even though foams at high injection quality are popular for mobility control associating a minimal amount of surfactant solutions, foam behaviors at dry conditions have not been thoroughly investigated and understood. The outcome of this study is believe to be helpful to successful planning of foam field I/EOR applications.
New Insights on the Mechanism of Displacement Efficiency of Natural Cores by Chemical Flooding and Its Influence on the Development and Selection of Chemicals for EOR
Authors: Demin Wang , Gang Wang 
Published: April 2012

Abstract
Results of Newtonian Fluids flooding very homogeneous porous media show that the Displacement Efficiency (ED) of a certain system is determined by the Capillary Number (Nc) of the driving fluid.
The experience gained from Chemical Flooding natural cores and reservoirs that are all micro (pore scale) heterogeneous to some degree show that ED is influenced, besides Nc, by many other factors as explained below.
Newtonian Fluids do not have elastic properties; emulsions and gas bubbles are not formed; when flooding, there is no change in the wettability of the system; there is no imbibition; and there is no alteration in the geometry of the pores.
However, when chemical flooding, elasticity markedly effects the ED; emulsions and gas bubbles (especially when gas is injected) will often show up, which from core and field tests, could significantly increase the recovery; both w/o and o/w emulsions markedly change the phase permeability behavior and water cut; the wettability will often change and imbibition will occur; pore geometry alteration by solution and precipitation will happen, which influences the permeability, imbibition and recovery. The above factors all markedly influence the ED of the system, especially when many factors act jointly.
From the above understanding, some directions on the development and selection of chemicals for EOR are put forward.
The concept of ultimate ED and economic ED and its affect on the selection of actual field flooding systems is analyzed (many papers analyze ultimate ED, however, in the field, usually economical ED is more important).
Besides Nc, the above factors should be considered when developing and selection chemicals and flooding systems. The above insights can further deepen our knowledge of the mechanism of chemical flooding, promote further research in this area and form better selection criteria for EOR chemicals and flooding systems in the field.
Water Shutoff at Ultralow Temperatures Using Organically Crosslinked Polymer Gels
Authors: Reddy B. R. , Crespo Freddy , Eoff Larry 
Published: April 2012

Abstract
Use of crosslinked polymer gels employing polymeric base materials and crosslinkers for shutting off water production in a variety of situations has been amply documented at formation temperatures ranging from ambient to &gt; 400°F. However, there has not been much work reported on chemical systems that can provide adequate gel times and gel strengths at temperatures less than 80°F. The reaction rates and gel-strength-development rates are significantly lower at low temperatures, resulting in long gel times and weaker gels. Additionally, in offshore applications, the gelling compositions must be designed to be mixable without crosslinking at warmer surface temperatures, and yet provide sufficient gel times at temperatures as low as 40 to 50°F near the ocean floor, for example, in shallow water/gas zones. Similar limitations might exist in areas known to contain gas hydrates.
In this paper, a recently developed water-shutoff system designed from polyacrylamide base polymers and polyamine crosslinkers, which provide sufficient gel times at temperatures less than 80°F, is presented. Challenges encountered in designing such a system included optimizing base polymer to crosslinker ratios and gel-strength-development rates. This paper describes optimization of gel times for the intended applications using activator chemicals and retarders, which allow designing gelling compositions that provide adequate gel times at subambient temperatures while permitting mixing at warmer surface temperatures. The activator and retarder systems also allow control of the development of rigid gels at different crosslinker concentrations.
Several practical issues and considerations for designing conformance treatments at low and ultralow temperatures are discussed. Improved temperature modeling and laboratory-testing designed to simulate the fluid-temperature profile during the operation from the wellhead to the formation bottom are also addressed.
Impacts of Timing of Crosslinker Addition on Water Shutoff Polymer Gel Properties
Authors: Shriwal Prashant , Lane Robert H. 
Published: April 2012

Abstract
In preparation of a gelant solution for making crosslinked polymer gels for water shutoff applications, unpublished experiments and chemical intuition suggest that, unless hydrolyzed polyacrylamide (HPAM) polymer is fully hydrated before addition of crosslinker, the final gel will have lower than optimum mechanical strength, presumably because polymer chains need to be fully unfolded before proper crosslinking can occur. When using dry polymer, which is usually the lowest cost form on a delivered basis, this may require more equipment and a large tankage footprint. However, if conditions exist where crosslinker can be added to wetted but not fully hydrated polymer, then dry polymer and crosslinker can be blended in a small continuous flow unit, with full hydration occurring as the gelant flows downhole prior to gelation.
We have evaluated gel strengths of "flowing" gels for water shut off in natural fractures and other non-matrix features as a function of time of addition of crosslinker relative to time of hydration of polymer. Gels were prepared from moderately high molecular weight HPAM crosslinked with chromium(III) acetate (CrAc) or polyethyleneimine (PEI). Crosslinker was added after either (1) initial wetting of solid polymer particles or (2) complete dissolution of the polymer.
Gel strengths were determined using a common qualitative coding system. Comparisons were made for gels prepared in an identical manner, except for the timing of crosslinker addition. Samples were prepared either in fresh water or 4% NaCl brine and then hydrated either at an ambient temperature or 122 °F. Gelant viscosity and crosslink time were also characterized with a viscometer.
Results of this work demonstrate that for most field applications using CrAc as crosslinker, optimum quality gel can be obtained using dry polymer and a small continuous mixing system for initial wetting of the polymer, after which the crosslinker can be added to the polymer solution on-the-fly. This practice can decrease the footprint and cost of large volume flowing gel treatments.
Foam Mobility Control for Nanoparticle-Stabilized CO2 Foam
Authors: Yu Jianjia , An Cheng , Mo Di , Liu Ning , Lee Robert 
Published: April 2012

Abstract
For miscible displacement under most reservoir conditions, due to the very low viscosity of the CO2 phase, poor volumetric sweep efficiency is a critical weakness of CO2 enhanced oil recovery (EOR). In this paper, a dynamic process for generating nanoparticle-stabilized CO2 foam is presented, which is expected to reduce CO2 mobility during CO2 EOR. This paper also describes the factors of nanoparticle concentration, CO2/brine volumetric ratio, and total injection rate effects on dynamic CO2 foam generation and foam mobility.
Dynamic supercritical CO2 foam was generated by the shearing of supercritical CO2 and nanoparticle dispersions in a glass- bead packed column. The foam image was observed in an online sapphire tube. Particle size was determined to be in the range of 60–90 nm. The experimental results showed that stable dynamic foam was generated at a shear rate higher than 1419s‒1 at 1500 psig and 25°C. The pressure differentials along the glass bead packed column and capillary tube were used to characterize the CO2 foam mobility and the corresponding apparent foam viscosity. It was found that the yield shear rate increased from 1419s‒1 to 3312s‒1 as the injection rate increased from 3.0ml/min to 7.0ml/min, and the apparent foam viscosity with nanoparticle dispersion was 1.5 to 2.5 times higher than that without the dispersion. The corresponding mobility was nine times higher. With increasing nanoparticle concentration, the normalized mixture viscosity increased and related mobility decreased. Furthermore, the apparent viscosity decreased slightly as the CO2/brine ratio was varied from 2 to 11 at the constant flow rate of 6ml/min.
Study of Adsorption and Transportation Behavior of Nanoparticles in Three Different Porous Media
Authors: Yu Jianjia , An Cheng , Mo Di , Liu Ning , Lee Robert 
Published: April 2012

Abstract
The revolution in nanotechnology has called attention to its many potential applications in the oil and gas industry. Nanoparticle-stabilized emulsions and foams have been proposed for enhanced oil recovery application. Understanding the transport and retention of nanoparticles in porous media is critical to their application. This paper presents the results of a study on the adsorption and transport behavior of nanosilica particles in three different porous media: sandstone, limestone, and dolomite. The results revealed that the equilibrium adsorption of the particles on sandstone, limestone, and dolomite were 1.272 mg/g, 5.501 mg/g, and 0 mg/g, respectively, in 5,000 ppm nanosilica dispersion. Coreflood tests were performed to investigate nanosilica particles transport behavior in different cores. It was observed that silica nanoparticles could easily pass through the sandstone core without changing the core's permeability. A little adsorption was noted as silica nanoparticles flooded limestone core, but the core permeability was not changed. A high particle recovery was obtained with the dolomite core. However, pressure drop across the core was observed to continuously increase, indicating core plugging occurred and core permeability was changed.
A New Look at the Minimum Miscibility Pressure (MMP) Determination from Slimtube Measurements
Authors: Amao Abiodun Matthew , Siddiqui Shameem , Menouar Habib , Herd Bob L. 
Published: April 2012

Abstract
Slimtube measurement is one of the standard experimental techniques used for determining the minimum miscibility pressure (MMP) of an oil and injection gas system prior to the initiation of an enhanced oil recovery (EOR) project. It is preferred because it involves actual fluid displacement in a porous medium. However, the specific criterion for determining the cut-off point during the measurement is not uniquely agreed upon in the literature. Different criteria have been proposed by researchers and this has been one of the setbacks of using Slimtube measurements.
The most commonly used criterion is the 1.2 PV criterion, which uses the recovery after injecting 1.2 pore volumes of the displacing gas as the cut-off. However, experimental observations show that even at supercritical condition, the volume of a gas is a strong function of the experimental pressure. Therefore, there is a need to develop an alternative means of determining the MMP that is not subject to particular pore volumes injected during Slimtube measurements.
This work presents different means of determining the MMP, based entirely on recovery and the particular displacement phenomenon. In this approach, two new parameters are defined - the instantaneous recovery rate (IRR) and the oil recovery rate (ORR). The maximum values for these parameters for each experiment are used as the cut-off value.
This new criteria was used in analyzing nine experimental data using oil from the Permian Basin. The results were compared with MMP prediction based on maximum recovery from each of the runs and the results were found to be in agreement.
These new criteria will provide consistent cut-off point for experimental runs because Slimtube measurements take a long time to complete. The new procedure ensures that adequate data have been gathered during each experimental run, sufficient for a consistent experimental analysis.
Calculation of Minimum Miscibility Pressure Using Fast Slimtube Simulation
Authors: Yan Wei , Michlesen Michael L. , Stenby Erling H. 
Published: April 2012

Abstract
Minimum misciblility pressure (MMP) is a critical parameter in designing a miscible gas injection process. It is expected that 100% displacement efficiency on the microscopic scale can be achieved provided the injection pressure is above MMP. Two approaches are usually employed for equation of state (EoS) based MMP calculation. The slimtube simulation approach is a numerical simulation of the physical slimtube experiment, which is commonly accepted as the most reliable experimental method for MMP determination. This approach carries out slimtube simulation runs at a series of pressures and determines the MMP from the recovery-pressure curve, just as in the experiment. The global approach, which is based on the method of characteristics analysis of 1D gas injection, finds the MMP by locating the pressure where a key tie-line becomes critical. Although the global approach is faster, the slimtube approach is still a necessary complementary method especially when the injection process involves complex phase behavior caused by CO2 or heavy oils. This study addresses how to improve the computational efficiency of slimtube simulation for MMP calculation. Firstly, a robust and efficient algorithm for rigorous flash forms the basis of the whole strategy. Secondly, a tie-line distance based approximation (TDBA) method has been introduced on top of the rigorous algorithm. In the TDBA method, if a new feed composition in a grid block is close enough to a tie-line previously calculated in the same block, the previous tie-line results can be used with slight adjustment. The approximation affects the final recovery very little but greatly increases the speed. Thirdly, a higher order method can be employed to use a fewer number of grid blocks to get the same accuracy in recovery. Finally, a MMP search strategy is poroposed to reduce the number of slimtube simulations needed. In addition, it is also discussed how to parallelize slimtube simulations for modern computers with multiple CPU cores to further chop the computation time.
Scale-Up of Effective Mass Transfer in Vapor Extraction Process for Heterogeneous Reservoirs
Authors: Leung Juliana Y. 
Published: April 2012

Abstract
Vapex (vapor extraction) is a non-thermal process using vaporized solvents with promising potential to reduce steam consumption in heavy oil recovery. The key recovery mechanism is molecular diffusion enhanced by velocity variations at different scales; i.e., dispersion. The efficiency of diffusion/dispersion depends significantly on reservoir heterogeneities, which exhibit a wide range of length scales. This paper demonstrates a procedure for quantifying the scaling characteristics of effective mass transfer accounting for heterogeneities based on the volume averaging approach.
Volume averaging is a mathematical technique to derive continuum equations at coarse scales given representative transport equations at fine scales. Although treatment of transport problems has been published in the past, application to stochastic geological systems is lacking. In the proposed procedure, results from a fine-scale numerical flow simulation reflecting the full physics of Vapex over a small element of the reservoir is integrated using the volume averaging technique to provide effective description of mass transfer at the coarse scale.
Scaling characteristics of effective mass transfer are systematically investigated for different heterogeneity distributions. Results show 1) spatial variability of effective mass transfer coefficients increases as solvent chamber advances through the reservoir; 2) mean and variance of effective mass transfer vary with length scale in a fashion similar to that of recovery statistics; 3) variability in effective mass transfer is a strong, non-linear function of heterogeneity.
An original contribution is to provide a general framework for developing scaling relationships of effective mass transfer in Vapex accounting for reservoir heterogeneities. It also presents an important potential in modeling of other solvent injection applications. Results demonstrate that effective mass transfer vary with length scale and heterogeneity; hence it should be properly represented for accurate prediction of recovery performance in simulations using scaled-up reservoir models.