bluuebunny/crossref_metadata_2025_split huggingface dataset:
Low Salinity EOR in Carbonates
Authors: Romanuka J. , Hofman J. P. , Ligthelm D. J. , Suijkerbuijk B. M. , Marcelis A. H. , Oedai S. , Brussee N. J. , van der Linde A. , Aksulu H. , Austad T. 
Published: April 2012

Abstract
Modifying the chemistry of injection water yields improved wettability behavior on carbonate rock surfaces. Previous work has focused on demonstrating the effect of modified brine formulation on particular carbonate samples. Here the results of a more general screening study consisting of Amott spontaneous imbibition experiments on the samples from oil-bearing zones and from outcrops of different carbonate formations are reported.
Tertiary incremental oil production due to increased water-wetness was observed upon transition to brine of lower ionic strength. Additional oil recovery from the spontaneous imbibition tests ranged from 4 to 20% of OIIP (Oil Initially In Place), reflecting a large variability in the response and indicating a high complexity of the mechanism(s). Consistent with numerous published reports, Stevns Klint outcrop chalk samples were a clear exception and exhibited increased oil recovery with increasing sulfate ion concentration. These did not respond to lowering the salinity of the imbibing brine. Tertiary oil recovery from samples containing evaporites occurred simultaneously with dissolution of salt minerals, as evident from brine analysis. However, incremental oil recovery in the same range was measured for samples without evaporites but from the same geological formation. Hence, mineral dissolution as a mechanism for enhanced oil recovery could not be confirmed.
The results show that injection of low salinity brine into carbonate reservoirs has potential as an EOR technology. However, additional research is needed to improve the understanding of the underlying chemical and physical mechanisms and improve a priori predictability.
Development of a Tool to Predict Technical Success of Polymer Flooding Applications
Authors: Rai Khyati , McComb Thais , Rodriguez Elena , Withers Robert 
Published: April 2012

Abstract
Quick qualitative comparison between different fields is often necessary in early phases of Chemical EOR studies when there is limited data. The tool described in this paper helps to bridge the gap between pass/fail screening techniques and more sophisticated simulation techniques, to facilitate the screening and ranking of potential candidates for polymer EOR flooding. Several studies have examined screening models for polymer flooding (PF). The models that exist in literature only assign a pass/fail response for suitability of reservoirs to polymer flooding and are insufficient for the purposes of comparative ranking. The analytical tool presented here is capable of quickly producing qualitative estimates of ‘Probability Of Technical Success’ (POTS) for polymer flooding for a set of candidate fields. This tool is useful for identifying candidates most likely to be successful polymer floods in a portfolio.
POTS number is solely a property of the reservoir characteristics and is based on parameters inherent to the field. Project design or execution parameters (such as polymer type, concentration, slug size, etc) and field implementation issues have not been taken into consideration.
POTS for polymer flood was developed using the following approach:
Important non-controllable parameters for PF were identified. A database was created with field and pilot successes and failures. The weight of parameters from step 1 was calculated based on their coefficient of variation value in the database. The weights of the parameter and parameter values are combined to give the POTS value for the field.
The results from the tool have been validated with past polymer flooded fields.
Experimental and Numerical Simulation of Surfactant-Assisted Oil Recovery in Tight Fractured Carbonate Reservoir Cores
Authors: Alamdari Baharak B. , Kiani Mojtaba , Kazemi Hossein 
Published: April 2012

Abstract
This paper presents experimental and numerical simulation results of oil recovery from short fractured and unfractured carbonate cores using a high speed centrifuge. The short cores are 1.5-inch in diameter and 1.5-inch long. The experiments are designed to decipher oil recoveries contributions from rock matrix in presence and absence of fractures, with and without surfactant.
This research demonstrates that surfactant oil recovery can be a viable enhanced oil recovery process in fractured carbonate reservoirs when fracture distribution and connectivity are favorable. These carefully designed experiments improve our understanding of how oil mobilization can be enhanced in fractured carbonate rocks and how the process can be modeled and solved numerically.
Three cores were selected from a Middle East carbonate reservoir, saturated with field brine, displaced with a 9-centipoise field crude, and aged to promote oil-wetness. Three different core designs were used in these experiments. One of the cores was fractured along the vertical axis and sealed with epoxy resin on the outer vertical surface. The second core was fractured and sealed on all outer surfaces except for the fracture opening. The third core was unfractured and sealed on the outer vertical surface. Using a centrifuge, these cores produced 43%, 33% and 42% in waterflood and 40%, 28% and 24% in surfactant flood, respectively.
We matched the experimental oil recoveries using two different numerical approaches: a transfer function and a 2-D finite-difference model. The results of these experiments, numerical modeling, and field observations have given us a better understanding of the mechanism of enhanced oil production in fractured carbonate reservoirs by dilute surfactant and micellar solutions. The results of this research are intended to promote field trials.
A Pilot Carbon Dioxide Test, Hall Gurney Field, Kansas
Authors: Willhite G. P. , Byrnes A. P. , Dubois M. K. , Pancake R. E. , Jyun-Syung Tsau , Daniels J. R. , Flanders W. A. 
Published: April 2012

Abstract
A pilot carbon dioxide miscible flood was initiated in the Lansing Kansas City C formation in the Hall Gurney Field, Russell County, Kansas. The reservoir zone is an oomoldic limestone located at a depth of about 2900 feet. The pilot consisted of one carbon dioxide injection well and three production wells. Continuous carbon dioxide injection began in December 2003 and continued through June 2005 when 16.19 MM lbs of carbon dioxide had been injected into the pilot area. Injection was converted to water on June 2005 to reduce operating costs to a breakeven level with the expectation that sufficient carbon dioxide was injected to displace the oil bank to the production wells by water injection. By March 2010, 8,736 bbl of oil were produced from the pilot. Production from wells to the northwest of the pilot region indicated that oil displaced by carbon dioxide injection was produced from five wells outside of the pilot area, to the northwest. About 19,166 bbl of incremental oil were estimated to have been produced from these wells as of March 2010. There was evidence of a directional permeability trend toward the NW through the pilot region. The majority of the injected carbon dioxide remained in the pilot region, which was maintained at a pressure at or above the minimum miscibility pressure. Although the 4-well pilot was uneconomic, the estimated oil recovery attributed to the CO2 flood is 27,902 bbl which is equivalent to a gross CO2 utilization of 4.8 MCF/bbl.
An Integrated Solution to Effective Waterflood Surveillance and Pressure Maintenance: A KOC Pilot Project of Greater Burgan Field, Kuwait
Authors: Rahman B. Abdul , Al-Naqi M. , Rajan S. , Ameen A. , Oyemakinde S. , Al-Zadjali M. , Ofrabor J. , Ali Z. 
Published: April 2012

Abstract
The Greater Burgan Field, in Kuwait, is the second largest field and contains the largest clastic reservoir in the world. The reservoir pressure in the Wara sands have been falling below bubble point due to insufficient pressure support from aquifer in parts of the field. As a result the Early Wara Pressure Maintenance Project (EWPMP) was begun in 2009 to pilot test the effectiveness of water injection for pressure support. The Early Wara consists of a small sector in the Southwestern portion of the field with 33 wells made up of 7 injectors, 15 producers and 11 observations wells.
A fully integrated monitoring and surveillance solution has been developed that starts with the capture, conditioning and automation of production and injection data. The surveillance solution utilizes a scalable workflow that automatically computes the required waterflood surveillance KPIs. Data from the reservoir, well and layer level are all integrated to provide feedback as to the efficiency and performance of the pilot program. The objective of this paper is to show how the waterflood surveillance workflow oriented solution has been developed to provide monitoring and analysis tool for waterflood surveillance system including appropriate inputs from the various disciplines and utilize the experiences gained towards full peripheral injection in 2014.
The end product is a multi-layered decision support system that includes data integration, workflow management, engineering analysis and diagnoses as well as visualization and performance monitoring in a collaborative environment.
The paper describes the integrated waterflood surveillance solution with the data integration, workflow automation, visualization and diagnosis layer. It illustrates how the system has become part of the daily routine and helped to promote a collaborative work environment.
Surfactant Formulation Evaluation for Carbon Dioxide Foam Flooding in Heterogeneous Sandstone Reservoirs
Authors: Bian Yu , Penny Glenn 
Published: April 2012

Abstract
Supercritical carbon dioxide (CO2) flooding is a widely used method in tertiary oil recovery; however, there are many challenges such as inefficient gas utilization, poor sweep efficiency and low oil recovery due to viscous fingering and gravity segregation. One recent development is the application of CO2 foam in order to reduce the CO2 mobility, especially in high permeability zones of the reservoir. However, the efficiency of the CO2 foam often decreases sharply during flooding as a result of contact with crude, adsorption of surfactants, high salinity in formation water and high reservoir temperature. Surfactant formulations which have better tolerance to these factors can greatly enhance the CO2 utilization, reduce the cost of surfactant, and improve the oil recovery. A series of formulations, including various surfactants and corresponding micro-emulsions, were evaluated as CO2 foaming agents in lab-based heterogeneous sandstone equipment at reservoir temperatures and pressures. This paper describes formulating high temperature CO2 foaming agent with co-surfactants and in a micro-emulsion system to improve crude, salt and temperature tolerance and minimize adsorption in order to place the foamer further into the formation.
Performance Evaluation of Thermally-Activated Polymers for Conformance Correction Applications
Authors: Salehi M. , Thomas C. P. , Kevwitch R. M. , Manrique E. , Garmeh R. , Izadi M. 
Published: April 2012

Abstract
A comprehensive laboratory study was performed to look at a thermally activated polymer (TAP) for conformance correction applications. The focus of study was to see if BrightWater® (a TAP polymer) could perform in high permeability porous media by creating flow resistance to injected fluid, hence enhancing the sweep efficiency. Furthermore, the possibility of enhancing the TAP performance by increasing the solution concentration was investigated. A set of 20-inch long slimtubes packed with acid-washed quartz sand were used to evaluate the performance of two TAP grades at 85°C in a range of 1 to 5 Darcy. Additionally, another set of short slimtubes were used to examine the performance of two low-temperature activation TAP grades at 30°C in the range of 200 to 1300 md.
Results showed that residual resistance factor (RRF) values of 2 to 12 could be achieved at 5000 ppm active concentration for the range of permeability tested here. RRF values increased by increasing the concentration to 10,000 ppm active polymer. Low-temperature activation polymers showed RRF values of 10 to 50 depending on the permeability of the short sandpacks tested at 30°C. TAP simulation approaches are also described.
Katz (Strawn) Unit Miscible CO2 Project: Design, Implementation, and Early Performance
Authors: Smith David J , Kelly Troy R , Schmidt David L , Bowden Cindy E 
Published: April 2012

Abstract
A miscible CO2-solvent flood has commenced at the Katz (Strawn) Unit (KSU) located in Stonewall County, Texas, on the Eastern Shelf of the Permian Basin. The reservoir is comprised of three distinct Pennsylvanian-age Strawn fluvial deltaic sandstones. CO2 injection into the KSU began in December 2010 with definitive flood response seen seven months later. Project design was challenged by severely limited geologic, production, injection, and wellbore data. The following paper is a summary of the methods used to evaluate, design, and implement this miscible CO2 project. This project is significant in that it provides a lengthy extension of the CO2 pipeline network outside of the Permian Basin which creates an entirely new basin for CO2 projects.
Limited data sets will become more prevalent as tertiary recovery projects extend from major producing basins to next tier targets. Typical parameters usually provided by reservoir simulation, such as total recovery, WAG ratios, slug sizes, etc. were determined using analog data and analytical techniques due to the lack of subsurface data and detailed performance information.
The design techniques presented in this paper provide a means to implement tertiary recovery with limited data sets from smaller target lower tier assets which remain in the Permian Basin. Many other assets may be plagued by a lack of data (production/injection, petrophysical, geophysical, wellbore), and present a significant challenge to engineers and geoscientists. The discussion outlines a methodology used and the results generated.
A Successful Pilot of Dilute Surfactant-Polymer Flooding in Shengli Oilfield
Authors: Li Zhenquan , Zhang Aimei , Cui Xiaohong , Zhang Li , Guo Lanlei , Shan Liantao 
Published: April 2012

Abstract
The first pilot of dilute surfactant-polymer flooding in the world was carried out by Shengli Oilfield Company in Ng54‒61 reservoir of West 7 Block, Gudong oilfield in Sep. 2003, the daily oil production increased and the water cut decreased significantly. The daily oil production in Central Block increased to 11.3 times, from 127.5 t/d to 10.4 t/d,; the water cut decreased by a factor of 37.9%, from 98.3% to 60.4%. Up to Dec. 2011, the oil recovery increased by a factor of 16.7%. The estimated ultimate oil recovery can be up to 18% of OOIP. The performance on the pilot was analyzed. The results showed that the flow resistance and the swept volume increased due to the polymer while the displacement efficiency was improved due to the surfactant. The amplitudes of water cut decrease and daily oil production increase during dilute surfactant-polymer flooding in the pilot area were higher than single polymer flooding.
Thermally Activated Particle Treatment to Improve Sweep Efficiency: Pilot Test Results and Field Scale Application Design in El Borma Field (Tunisia)
Authors: Galli Giuseppe , Morra Daniela , Ghaddab Fethi , Sitep Marcello Tesconi , Manrique Eduardo , Tiorco Glyn Freeman 
Published: April 2012

Abstract
El Borma is a mature oil field located onshore in the Northern Sahara Desert, Tunisia. Oil production commenced in 1966 and is currently supported by water injection; the high water cut (96%) and permeability contrast in the main reservoir (Level "A") indicated thief zones with less than optimum sweep efficiency prompting the evaluation of a tertiary method for improved oil recovery. In January of 2010 a pilot project (injector-producer) was implemented to evaluate a thermally activated particle (TAP) system as a strategy to improve the sweep efficiency of ongoing water injection program.
This paper will summarize TAP pilot implementation and will describe methodology and results of project monitoring and injection-production performance. The evident good results of this TAP application (decrease in water cut with consequent increase in oil recovery up to 55%) in the last fourteen months justified a larger scale application in the field.
The field scale application design was performed in two different steps: 1) Comprehensive production-injection data analysis of injectors based on the number of connected (offset) producers and channel volume estimations and; 2) The numerical simulation studies of most promising patterns calibrated with information generated during the first TAP pilot. Screening of patterns candidates and simulation approach of TAP will be also presented.
El Borma pilot results validate the potential of TAP as an in-depth conformance strategy that can improve sweep efficiency of mature waterfloods. El Borma workflow to screen and rank patterns candidates combined with pilot project implementation, monitoring and evaluation can be used as a reference to evaluate the benefits of TAP technology in waterflooded oil reservoirs.
Improving Heavy Oil Recovery Using an Enhanced Polymer System
Authors: Fletcher P. , Cobos S. , Jaska C. , Forsyth J. , Crabtree M. , Gaillard N. , Favéro C. 
Published: April 2012

Abstract
This paper introduces the benefits of a hybrid polymer system for enhanced heavy oil recovery (EOR) that contains viscosifying anionic polyacrylamides (HPAM) and a recently developed, low toxicity, low molecular weight, dispersing polymer (LMwDP).
Conventional EOR polyacrylamides increase sweep efficiency, but are not thought to mobilize residual oil since they have limited effect on wettability and interfacial tension. To improve displacement efficiencies, costly concentrations of surfactants are added to polymer solutions to increase capillary numbers. These surfactant concentrations are designed to accommodate the high level of adsorption within the porous medium. Surfactant dosage can be reduced from 0.5% to 1% down to 0.05% to 0.2% using alkalis, but this often requires expensive water softening systems and higher polyacrylamide concentrations to reach the required viscosity.
The LMwDP in the hybrid polymer system mimics the surfactant role without some of their disadvantages, at concentrations between 0.2% and 0.5%. Indeed, the LMwDP affects neither the viscosity of the HPAM solution, nor the injection and production facilities. The system is particularly beneficial to the recovery of medium to heavy oil, i.e., above 200 cP. Several HPAM chemistries have been tested at concentrations between 0.03% and 0.2%.
This paper presents experimental oil recovery factors, using HPAM and 20,000 g/mol LMwDP, in 9 to 12 darcy sandpacks with porosities of approximately 40%. The oil viscosity was 3,000 cP at 50°C, 16,400 cP at 30°C and 40,700 cP at 20°C.
In these reported studies, oil recovery factors with the hybrid polymer system were 70% higher than a brine alone baseline and 20% higher than brine plus HPAM. Trends in recovery factors indicated that each polymer in the formuation mutually enhances the performance of the other, i.e., there is a synergy between the components. The sand pack results generated essential data required for history matching, which then allowed up-scaling using an industry standard reservoir simulator.
Additional studies are in progress to optimize the dosages, and the cost of this hybrid polymer system, for a field implementation of this EOR technology to the recovery of medium to heavy oil.
Stabilization of Interfacially-Active-Nanohybrids/Polymer Suspensions and Transport through Porous Media
Authors: Baez Jorge L. , Ruiz M. Pilar , Faria Jimmy , Harwell Jeffrey H. , Shiau Ben , Resasco Daniel E. 
Published: April 2012

Abstract
Novel amphiphobic nanoparticles based on functionalized carbon nanotubes (CNT) have shown promising applications for enhanced oil recovery, by lowering the water/oil interfacial tension upon adsorption or chemical reaction catalyzed by these nanoparticles. Challenges for this novel approach include a) stabilizing aqueous suspensions of the nanoparticles in the presence of brine, b) propagating these suspensions through a porous media, c) conducting reactions at the interface.
It is well-known that it is difficult to suspend CNT in liquids since they are amphiphobic. Thus, surfactants or polymers are needed to create stable suspensions. Here, several polymers have been tested to disperse CNT in water. Even though some of them produced very stable nanohybrid suspensions in deionized water, when brine was present in the medium, in most cases the suspension destabilized and the nanohybrids settled out.
We were successful in stabilizing nanohybrids suspensions in brine, by using polyvynil-pyrrolidone (PVP). However, in propagation experiments of these suspensions through a porous media (crushed Berea sandstone, 75-250 μm particle size, k = 4.2 D, Φ = 35%), it was observed that the PVP strongly interacted with the sand in the presence of elevated brine (10% solution), leading to low particle recoveries (&lt; 10 %). Conversely, with PVP in deionized water, the particle recovery was higher than 90 %. After trying to get a good particle recovery of brine nanohybrid suspensions, we discovered an effective binary polymer combination that produced very stable nanohybrid suspensions that propagated through the Berea sand, with a particle recovery of 80 %. This polymer combination consisted of a sequential addition of PVP and a proprietary high salinity-resistant polymer, which reduces the rock/polymer interaction.
We envision these engineered nanoparticles having a great impact in the characterization of the reservoir and enhancement of oil recovery.
Optimization of Viscosifying Surfactant Technology for Chemical EOR
Authors: Morvan M. , Degré G. , Beaumont J. , Dupuis G. , Zaitoun A. , Al-Maamari R S. , Al-Hashmi A R. , Al-Sharji H H. 
Published: April 2012

Abstract
Recent publications indicate injection of polymer solutions at concentration larger than conventional polymer flooding can result in higher recovery at field scale. Typically more than 20% OOIP compare to waterflooding have been reported (Wang et al; 2011). However injectivity issues have to be considered when injecting such concentrated polymer solutions. This work describes an alternative approach based on surfactant-based fluids. The technology we have developed matches the rheological properties of polymer solutions in a broad range of reservoir conditions (temperature & salinity) without any injectivity limitation even when considering very viscous surfactant solutions (ie up to 1000 cps) and low permeability cores.
Average first normal stress difference measurements have been used to compare the elastic properties of surfactant and high molecular weight polymer solutions. The Degrée of non linearity in the mechanical properties for both fluids has been expressed by Weissenberg number. The surfactant solution has much larger Weissenberg number than the polymer solution at a shear rate corresponding to the fluid propagation in the reservoir.
The potential of this surfactant-based technology is illustrated through a specific reservoir case involving heavy oil. A series of core-flood experiments has been performed in reservoir cores. The surfactant slug can be combined with a conventional low-concentration polymer flooding to further improve the process. Reduction in residual oil saturation in the range of ΔSw = 10-15% has been obtained. Complementary simulation study giving rise to economic analysis have been performed.