bluuebunny/crossref_metadata_2025_split huggingface dataset:
CO2 Low Salinity Water Alternating Gas: A New Promising Approach for Enhanced Oil Recovery
Authors: Dang Cuong. T. , Nghiem Long. X. , Chen Zhangxin , Nguyen Ngoc. T. , Nguyen Quoc. P. 
Published: June 2014

Abstract
It has been recognized that there are significant advantages on combining low salinity waterflooding (LSW) with other enhanced oil recovery (EOR) techniques such as polymer or low tension surfactant flooding. This paper proposes a novel concept of low salinity water-alternating-CO2 (CO2 LSWAG) injection under CO2 miscible displacement conditions. While LSW is an emerging EOR method based on alteration of wettability from oil-wet to water-wet conditions, WAG is a proven method for improving gas flooding performance by controlling the gas mobility. Therefore, LSWAG injection promotes the synergy of the mechanisms underlying these methods (i.e., ion-exchange, wettability alteration, and CO2 miscible displacement and mobility control) that further enhances oil recovery and overcomes the late production problem frequently encountered in the conventional WAG. These features are demonstrated in this work based on a field case study.
To investigate the advantages of CO2 LSWAG, a comprehensive ion exchange model associated with geochemical processes has been developed and coupled to the multi-phase multi-component flow equations in an equation-of-state compositional simulator. Laboratory core flood simulations of different CO2 LSWAG schemes are conducted to understand the combined effects of solubility of CO2 in brine, dissolution of carbonate minerals, ion exchange, and wettability alteration. CO2 LSWAG performance is then evaluated on a field scale through an innovative workflow that includes geological modeling, multi-phase multi component reservoir flow modeling and process optimization. The simulation results indicate that CO2 LSWAG has the highest oil recovery compared to conventional high salinity waterflood, high salinity WAG, and low salinity waterflood. A number of geological realizations are generated to assess the geological uncertainty effect, in particular clay distribution uncertainties, on CO2 LSWAG efficiency. Finally, CO2 LSWAG injection strategies are optimized by identifying key WAG parameters.
The proposed workflow demonstrates the synergy between CO2 WAG and LSW. Built in a robust reservoir simulator, it serves as a powerful tool for screening, design, optimization, and uncertainty assessment of the process performance from laboratory to and field scales. CO2 LSWAG is a promising EOR technique as it not only combines the benefits of CO2 injection and low salinity water floods but also promotes the synergy between these processes through the interactions between geochemical reactions associated with CO2 injection, ion exchange process, and wettability alteration. This paper demonstrates the merits of this process through modeling, optimization and uncertainty assessment.
Conformance Improvement Using Polymer Gels: A Case Study Approach
Authors: Lantz M. , Muniz G. 
Published: June 2014

Abstract
Poor conformance is a problem that has plagued most operators of water and enhanced oil recovery (EOR) floods. Conformance improvement has been shown to significantly improve oil recovery; however, effectively selecting and implementing the correct conformance improvement technique still remains a complicated proposition. The selection of the correct technique is only becoming even more important as the industry advances EOR floods where it is critical in these capital intensive projects to effectively sweep the reservoir.
Traditionally many operators have relied on mechanical or cement solutions to deal with poor conformance. Although these methods certainly have their place in conformance engineering they deal more with wellbore issues rather than reservoir flow dominated situations. The latter situation can be characterized as flow through highly conductive reservoir features such as fractures or highly permeable thief zones. In such situations it is advantageous to use a technology that can penetrate into the offending feature providing sustainable results. In water or EOR floods, the treatment of injection wells with polymer gels has been shown to be an effective technology in addressing such reservoir conformance issues. Extensive research has gone into characterizing polymer gels and numerous field case studies have been published. However, few references aid in understanding when polymer gels should be used and the critical aspects of designing and implementing such treatments.
This paper will focus on diagnosing those conformance issues where it is most appropriate to use polymer gels. Further, it will explain how reservoir characterization should drive the design and implementation of this technology. Four injection well case studies will be used to develop a Polymer Gel Conformance Improvement Matrix that will provide heuristics for designing a polymer gel treatment. Finally, lessons learned from the case studies will be presented to give guidance on diagnosing conformance issue along with the design and implementation of conformance improvement polymer gel treatments.
An Overview of Conformance Control Efforts for the West Sak Field on the North Slope of Alaska
Authors: Peirce J. W. , Hutcherson M. R. , Jensen M. D. , Brice B. W. , Vasquez J. E. , Woods A. 
Published: June 2014

Abstract
This paper presents a field case study of conformance engineering efforts completed in the West Sak field throughout the past eight years. The West Sak field is a shallow viscous oil reservoir with poorly consolidated sand that has been under waterflood since 1998. Because of the nature of the formation and the completion techniques used, the field has experienced some severe conformance issues. Conformance candidate identification and selection criteria are reviewed followed by an overview of additional problem characterization efforts. A variety of solution designs considered and attempted are discussed with a summary of lessons learned from both failures and successes during this effort. This review discusses treatments that range from pumping graded CaCO3, molten wax, special cement blends, and, finally, preformed particle gels (PPGs) or water swelling polymer (WSP) crystals. A majority of these treatments were executed on horizontal wells, which required adjustments for some challenging placement control dynamics. A review of the efforts to control those placement dynamics is presented, discussing some potential problems associated with that control. The principle objective of this work was the elimination of open channels connecting water injection wells with oil producers. This connection eliminated matrix flow between the wells and threatened secondary recovery potential. Ultimately, the evolution of current solution treatments is provided with a brief benefit summary of the overall performance of this effort.
Minimum Miscibility Pressure Studies in the Bakken
Authors: Adekunle Olawale , Hoffman B. Todd 
Published: June 2014

Abstract
The Bakken is among the shale reservoirs which have been discovered to hold a vast amount of oil resource contributing to the production boom in the US. This unconventional reservoir, like most others, displays favorable initial production rates due to stimulation by hydraulic fracturing, but production rates quickly decline after few months. Due to the extremely low permeability and low recovery factors, miscible gas injection is considered for improving the recovery of oil in the Bakken formation. Feasibility of miscible gas injection in the Bakken depends on the analysis of minimum miscibility pressure (MMP) experiments.
The Rising Bubble Apparatus (RBA) has been chosen for the purpose of these experiments. The RBA provides results in a short amount of time using small amounts of fluid samples. The RBA consists of a cell gage containing a flat glass tube where oil samples are placed and an injection needle where gas is injected into the flat glass tube. To simulate reservoir conditions, the glass tube is pressurized using de-ionized water and heating plates surrounding the cell are used to regulate temperature. Visual observation of the injected gas bubble behavior is captured by a camera as it rises and moves upward along the oil column. The MMP occurs when the gas bubble dissolves into the oil before reaching the top of the oil column.
MMP results from a Bakken crude sample show a range from 2340 to 3000 psia at a temperature of 215 °F using CO2 as the injection fluid. Other injection fluids such as nitrogen and hydrocarbon gases have been tested and provided MMP values from 3500 to over 5000 psia depending on the gas. MMP results from Bakken crude oil samples were compared to existing correlations and more correlations were found to produce unreliable MMP results. Further comparison using an equation of state phase-behavior program has shown similar results with the RBA MMP results.
The impact of different injection fluids, inclusive of CO2 and enriched hydrocarbon gases is the subject of this study. MMP results are influenced by the choice of injection fluids, providing valuable information for economic production and increased recovery in the Bakken formation. The results from this study provide MMP data for a range of injection fluids that can be used in planning pilot tests for miscible gas injection in the Bakken.
Crude Oil/Brine Interactions and Spontaneous Formation of Micro-Dispersions in Low Salinity Water Injection
Authors: Mahzari Pedram , Sohrabi Mehran 
Published: June 2014

Abstract
Low salinity water injection (LSW) has recently attracted much attention as a technique for improving oil recovery. Several mechanisms have been put forward for oil recovery by LSW, however, their contribution to the observed additional oil recovery has not been well established and currently a consistent mechanism that can adequately explain both successful and unsuccessful results of LSW is lacking. Most of the proposed mechanisms attribute the low salinity effects to wettability alteration towards more water-wet conditions. This has resulted in many studies of LSW being mainly focused on the role of rock and its constituents whereas the role of fluid/fluid interactions has been largely ignored. We have recently reported the results of a series of direct flow visualization of LSW, which have revealed spontaneous formation of micro-dispersions of water in oil when a crude oil comes in contact with low salinity brines (Emadi and Sohrabi 2013).
In the current work, we further investigated interactions between crude oil and brine by performing a series of fluid characterization tests. Five different crude oil samples were used to individually bring them in contact with brines with various salinity levels to identify experimentally subtle changes in the oil composition. The process of contacting the crude oils and brines was designed and performed very carefully to avoid physical agitation between the two phases in order to replicate reservoir flow conditions. Then, samples of the oil were taken for qualitative and quantitative analysis including ESEM, FTIR, and Karl Fischer Titration. The results demonstrate spontaneous formation of water-in-oil dispersions when salinity of the brine is reduced to below 2000 ppm. This phenomenon is associated with detectable changes in oil composition, which occurred consistently in the tested crude oils. Our quantitative analysis shows that the concentration of micro-dispersions varies depending on the SARA content of the oil and there is a brine salinity threshold at which microdispersion concentration in the oil changes sharply. These new findings coupled with our micromodel visualizations (Emadi & Sohrabi 2013) reveal some new aspects of LSW and may lead to the development of relatively simple screening tests to identify suitability of a crude oil for LSW.
A Successful Story Of An Integrated Geologic And Reservoir Engineering Approach Of The Gandu Unit
Authors: Yaguaracuto Alfredo , Bowser Peter , Sands Ken , Gamez Amy , Keiser Leslie 
Published: June 2014

Abstract
This paper presents the success story of an integrated approach to optimize the production performance of the Goldsmith Andector Unit (Gandu) in West Texas. All production is from the Clearfork formation, a typical carbonate reservoir characterized by large and discontinuous pay intervals with low reservoir energy and high residual oil saturation. Re-development of this mature field began as a 20-acre infill drilling program in 2001 and has been under waterflood expansion since 2008.
A multi-disciplinary team was commissioned to improve production in Gandu. The team used an aggressive approach towards development practices of all aspects including reservoir engineering, geologic, and operational practices. Reservoir characterization and numerical simulation work in conjunction with classical methods validated the 650 MMSTB of original oil in place (OOIP) and the 64 MMSTB estimated waterflood reserves in the reservoir. The team focused on optimizing the base production, monitoring well performance, and identifying opportunities to increase production through workovers, returning-to-production (RTP) jobs and recompletions.
This paper details the systematic approach that was followed in order to achieve waterflood expansion success including geological characterization, reservoir engineering, data acquisition, production monitoring, well automation, field optimization, and program development for subsequent years. Details of the workflow implemented under the technical approach, best operational practices, and lessons learned are discussed.
As a result, the production of the field increased approximately 70%, with a total increase of 2,800 BOEPD by 2009. The field continues to produce significantly more than it did prior to the waterflood expansion in 2008.
Data Analysis and Novel Screening Criteria for Polymer Flooding Based on a Comprehensive Database
Authors: Saleh Laila Dao , Wei Mingzhen , Bai Baojun 
Published: June 2014

Abstract
Screening is considered the first step in evaluating potential enhanced oil recovery (EOR) techniques for candidate reservoirs; therefore, it is important to update the screening criteria as new technologies are developed. However, most recently published screening criteria regarding polymer flooding were based on data collected from the bi-annual EOR surveys published by the Oil & Gas Journal. These data recorded valuable information for finished and ongoing polymer flooding worldwide, but they are constrained in two ways. Firstly, they do not include some important information, such as the formation water salinity, divalent concentration, and polymer type and concentration. Secondly, the field data do not reflect recent polymer technology developments that are still in the laboratory evaluation and pilot testing stages. To overcome these limitations, a comprehensive dataset that provides the overall picture of polymer flooding research and application is presented in this paper. A total of 865 polymer flooding projects were considered to construct the dataset, including 481 field projects from the Oil & Gas Journal (1974-2012), 329 laboratory experiments (1964-2013), and 55 pilot test projects (1966-2011) recorded in the literature. After enhancing the data quality, graphical and statistical methods were used to analyze and describe the dataset. The distribution of major parameters important to polymer flooding design is presented using histograms, and the range of all parameters and their statistical values are presented using box plots. New screening criteria are presented based on these statistics of the defined parameters. Compared to published screening analyses, the new dataset and criteria provide more information critical to the design of a successful polymer flooding project, such as data pertaining to the formation water salinity, polymer molecular weight and concentration, polymer viscosity, and slug size.
Effects of Hardness and Cosurfactant on Phase Behavior of Alcohol-Free Alkyl Propoxylated Sulfate Systems
Authors: Puerto Maura C. , Hirasaki George J. , Miller Clarence A. , Reznik Carmen , Dubey Sheila , Barnes Julian R. , vanKuijk Sjoerd 
Published: June 2014

Abstract
The effect of hardness was investigated on equilibrium phase behavior in the absence of alcohol for blends of three Alcohol Propoxy Sulfates with an internal Olefin Sulfonate having C15-18 chain length. Hard brines investigated were synthetic Sea Water, 2*SW, and 3*SW, the last two having double and triple the total ionic content of SW with all ions present in the same relative proportions as in SW. Optimal blends of the APS/IOS systems formed microemulsions with n-octane having high solubilization suitable for EOR at both ~25°C and 50°C. However, oil-free aqueous solutions of the optimal blends in 2*SW and 3*SW, as well as in 8 wt% and 12 wt% NaCl solutions with similar ionic strengths, exhibited cloudiness and/or precipitation and were unsuitable for injection. In SW at 25°C the aqueous solution of the optimal blend of branched alcohol C16,17 7PO sulfate and IOS15-18 was clear and suitable for injection. A salinity map prepared for blends of these surfactants illustrates how such maps facilitate selection of injection compositions where injection and reservoir salinities differ. The same APS was blended with other APSs and Alcohol Ethoxy Sulfates in SW at ~25°C, yielding microemulsions with high n-octane solubilization and clear aqueous solutions at optimal conditions. Two APS/AES blends were found to form suitable microemulsions in SW with a crude oil at its reservoir temperature near 50°C. Optimal conditions were nearly the same for hard brines and NaCl solutions with similar ionic strengths between SW and 3*SW. Although the aqueous solutions for the optimal blends with crude oil were slightly cloudy, small changes in blend ratio led to formation of lower phase microemulsions with clear aqueous solutions. When injection and reservoir brines differ, it may be preferable to inject at such slightly underoptimum conditions to avoid encountering upper phase conditions produced by inevitable mixing of injected and formation brine.
Compositional Surveillance Program for Assessing Prudhoe Bay Vaporization Process
Authors: Jhaveri Bharat , Steen Becky , Connolly Michael 
Published: June 2014

Abstract
Prudhoe Bay field, the largest oil and gas accumulation in North America, has a large gas cap in communication with the oil rim. In addition to the liquid condensate held in the gas phase, the original gas cap contains relict oil that exists in the liquid phase at low saturations and is remnant of the oil migration - spill history of the reservoir. One of the key recovery mechanisms at the Prudhoe Bay field is the use of lean gas injection to increase recovery through vaporization of relict oil and dropped-out condensate in the original gas cap, and residual oil in the expanded gas cap. The lean gas vaporization project was implemented with an initial installed gas handling capacity of 2 BCF/D which was successively expanded to 8 BCF/D in several Gas Handling eXpansion (GHX) projects making it the largest hydrocarbon gas injection project in the world. After processing the produced gas to manufacture NGLs and Miscible Injectant, the lean gas is reinjected into the Prudhoe Bay gas cap for pressure support and vaporization of liquid phase hydrocarbons. In addition to estimates of black oil benefits, design and commercial evaluation of each stage of the gas handling expansion required accurate prediction of vaporization benefits from lean gas injection.
A compositional surveillance program was designed and implemented to assess the efficiency of the vaporization process in the field. This paper describes the surveillance program in which the routine separator tests conducted at the specified well locations for fluid allocation and production optimization are modified to include additional measurements of extended separator gas compositions and separator oil API gravity. The paper also presents details of an analytical procedure in which the measured compositional information from the well tests is used together with other relevant field data to deduce the effectiveness of the vaporization process. The compositional surveillance data analysis procedure is demonstrated by application to the gravity drainage area of the Prudhoe Bay field. Deliberate application of the compositional surveillance data acquisition and analysis by the Prudhoe Bay Reservoir Management team will significantly impact the optimization of the vaporization process in the field.
Geochemical Interpretation of Low Salinity Water Injection in Carbonate Oil Reservoirs
Authors: Al-Shalabi Emad W. , Sepehrnoori Kamy , Pope Gary 
Published: June 2014

Abstract
The advantages of using the low salinity water injection (LSWI) technique to improve oil recovery in carbonates have been reported in the literature; however, the mechanism behind it is still uncertain. In this paper, a geochemical/thermodynamic interpretation of the mechanism controlling oil recovery in carbonates by LSWI is proposed based on a recently published experimental study. The geochemical modeling was performed using two geochemical simulators (UTCHEM and PHREEQC). For the carbonate case considered in this paper, it was found that the wettability alteration was caused mainly by changing the surface charge of the rock rather than by dissolution. The findings cannot be generalized as the LSWI technique is case dependent.
Taking CO2 Enhanced Oil Recovery to the Offshore Gulf of Mexico
Authors: DiPietro Phil , Kuuskraa Vello , Malone Taylor 
Published: June 2014

Abstract
This paper evaluates the recoverable crude oil resource associated with applying carbon dioxide enhanced oil recovery (CO2 EOR) to reservoirs in the offshore Gulf of Mexico (GOM). Using data maintained by the Bureau of Ocean Energy Management (BOEM), a database containing 531 oil fields with a total original oil in-place (OOIP) of 69 billion barrels was used for the study. A total of 391 fields, representing 35% of the OOIP, were screened out at as not amenable to CO2 EOR based on size, residual oil saturation, and/or well-spacing. For the remaining 140 oil fields (containing 696 reservoirs), the data elements required to model a CO2 EOR flood, such as sweep efficiency and heterogeneity, were derived using a variety of methods. Crude oil production and CO2 demand profiles were produced from stream-tube finite-difference simulations for each oil-bearing reservoir. The study assumes that groups of proximate fields will be served by an anchor CO2 supply pipeline (one billion scf per year CO2) at a levelized transportation cost of $1.06/MscfCO2 (equivalently 20$/mtCO2). The economic determinations are based on a crude oil price of $90/bbl, CO2 price of $1.59/Mscf (30 $/MtCO2) at the capture facility plant gate, 18.75% royalty, and a 20% rate of return before taxes. BOEM projects that 182 billion barrels of OOIP remain undiscovered, two and a half times the discovered resource. Data from the analysis of discovered oil fields was used to estimate the expected CO2 EOR oil recovery from the undiscovered oil fields. Under the current CO2 EOR Technology scenario, the economically recoverable resources (ERR) is 0.8 billion barrels, a small fraction of the technically recoverable resource (TRR) of 23.5 billion barrels. The average efficiency of CO2 use in the ERR oil fields is estimated to be 7.2 Mscf/bbl and the associated demand for CO2 supply is 5.8 TCF. Under a scenario with Next Generation CO2 EOR performance, the ERR increases significantly to 14.9 billion barrels and 74 TCF of CO2 demand, consistent with an improved use efficiency of 5.0 MscfCO2/bbl.