bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Reservoir Management Case Study of a Polymer Flood Pilot in Medicine Hat Glauconitic C Pool
Authors: Batonyi Alice , Thorburn Liana , Molnar Sarah 
Published: March 2016

Abstract
The Medicine Hat Glauconitic C Pool is located partially inside the city limits of Medicine Hat, Alberta, Canada. This 15-18° API oil pool is under waterflood. Reservoir management strategies in the pool are limited by the reservoir quality, wellbore architecture and business environment. Surface land access due to the expanding Medicine Hat city limits and pre-existing wellbore orientations have constrained the waterflood pattern and infill drilling options. Current estimates indicate 21% of the oil in place will be recovered at the end of the waterflood.
The polymer flood pilot was started in 2012 with a goal to achieve 6% incremental recovery with a one year initial response time. The pilot's designed injection rate was 6,300 bbl/d (1000 m3/d) in 5 injectors, each representing different reservoir conditions and injection patterns. Following injection, pre-existing water channels and high permeability streaks resulted in rapid polymer breakthrough in as little as 48 hours in some cases.
To increase the efficiency of the polymer flood and reduce cycling polymerized water, a new approach to reservoir management had to be considered:
– Each of the 5 patterns inside the pilot was monitored and managed individually, with a fit-for-purpose strategy in mind. – Although 1 year to response was estimated, after four months, oil rates and oil cuts increased unexpectedly. However, after reaching peak production, the expected steep decline was observed. – New reservoir management strategies were implemented in order to slow the decline and attempt to increase the incremental recovery from 6% to 10%: attempts to block water channels in the injectors, producer shut-ins and frequent injection target changes proved beneficial.
The polymer pilot has exceeded expectations to date.
This case study provides an outline of the changes that were made and the results that have been observed.
The Thermal Stability of Polyacrylamides in EOR Applications
Authors: Swiecinski Frederick , Reed Peter , Andrews William 
Published: March 2016

Abstract
The prediction of polymer degradation under reservoir conditions is critical to EOR polymer selection. NMR studies were used to monitor the changes in the anionic content of acrylamide containing polymers. The monomer sequence distribution of hydrolyzed polyacrylamide polymers (HPAM) was monitored during lab test to improve our understanding of HPAM stability. The results suggest that accelerated aging of a polymer at reservoir conditions at elevated temperatures will result in a polymer with structure similar to the polymer resulting from extended aging at lower temperatures.
Ethane-Based EOR: An Innovative and Profitable EOR Opportunity for a Low Price Environment
Authors: McGuire Patrick L. , Okuno Ryosuke , Gould Thomas L. , Lake Larry W. 
Published: March 2016

Abstract
This paper summarizes the current state of the ethane industry in the United States and explores the opportunity for using ethane for enhanced oil recovery. We show both simulation data and field examples to demonstrate that ethane is an excellent EOR injectant.
After decades of research and field application, the use of CO2 as an EOR injectant has proven to be very successful. However, there are limited supplies of low cost CO2 available, and there are also significant drawbacks, especially corrosion, involving its use. The rich gasses and volatile oils developed by horizontal drilling and fracturing in the shale reservoirs have brought about an enormous increase in ethane production. Ethane prices have dropped substantially. In the U.S., ethane is no longer priced as a petrochemical feedstock, but is priced as fuel. Also, substantial quantities of ethane are currently being flared.
Ethane-based EOR can supplement the very successful CO2-based EOR industry in the U.S. There simply isn't enough low-cost CO2 available to undertake all of the potential gas EOR projects in the U.S. The current abundance of low-cost ethane presents a significant opportunity to add new gas EOR projects. The ethane-based EOR opportunity can be summarized as follows; CO2-based EOR works well, and is well understood.Ethane is better than CO2 for EOR.Ethane is simpler than CO2 for EOR.Ethane is now inexpensive, and will likely stay inexpensive.Ethane-based EOR has become a viable option in the Lower 48. Large volumes of low-cost ethane are available. Recent additions to the growing ethane infrastructure now deliver ethane to locations where ethane-based EOR targets are plentiful.
Waterflood Sweep Improvement at Prudhoe Bay, Alaska
Authors: Thrasher David , Nottingham Derek , Stechauner Bernhard , Ohms Danielle , Stechauner Gerda , Singh Praveen K. , Angarita Monica Lara 
Published: March 2016

Abstract
Waterflood conformance control due to reservoir heterogeneity is a common challenge to many oilfield developments. This paper describes the application at-scale of a thermally-activated polymer particle system (TAP) for improving waterflood sweep efficiency in the Prudhoe Bay field, Alaska. Since 2004, the technology has been successfully deployed 91 times in Prudhoe Bay Unit on the North Slope of Alaska as part of an approved Enhanced Oil Recovery (EOR) program. A total of 1.6 million gallons of chemical polymer particles have been injected into approximately half of the available waterflood patterns.
Once the polymer particles activate deep in the reservoir, they provide resistance to water flow in the thief (swept) zones. The treatment design workflow applies a thermal model which accounts for the impact of the temperature distribution in the reservoir on activation of the polymer particles. Challenges associated with performance evaluation of the treatment program in a normal operational setting (as opposed to field trial) have been addressed, particularly in relation to interferences to interpretation resulting from the ongoing application of miscible gas EOR in the waterflood areas.
Of the 44 treatments deployed between 2008 and 2012, 22 were sufficiently mature to have performance data which was not adversely impacted by interferences from well work, changes to operating conditions, or miscible gas breakthrough. So far, only one of the 22 patterns has not indicated an incremental oil response, while in two patterns the response had started too recently to be able to extrapolate the overall response magnitude. The analysis showed overall positive responses from the treatments that are competitive with other well work on cost/bbl and project economics. Results from this study provide insights on key controls on waterflood sweep improvements, and inform future candidate selection and optimization of treatment designs.
The production performance analysis was corroborated by wellhead injectivity, repeat pressure fall-off tests, and reservoir modeling. This paper documents a good case history of waterflood sweep improvement.
Comprehensive Guidelines for the Application of In-Situ Polymer Gels for Injection Well Conformance Improvement Based on Field Projects
Authors: Aldhaheri Munqith N. , Wei Mingzhen , Bai Baojun 
Published: March 2016

Abstract
Polymer gels are increasingly applied to improve sweep efficiency of different IOR/EOR recovery processes. Three in-situ polymer gel systems including bulk gels, colloidal dispersion gels, and weak gels are often used to mitigate water production caused by reservoir heterogeneity and unfavorable mobility ratio of oil and injected fluids. Selecting the most appropriate gel system is a key component for a successful conformance improvement treatment. Screening criteria in terms of reservoir and fluid characteristics have been widely used to identify potential technologies for a specific reservoir. Despite the large number of polymer gel projects, only five, limited-parameters, single-agent criteria or surveys have been sporadically accomplished that suffer from many deficiencies and drawbacks.
This paper presents the first complete applicability guidelines for gel technologies based on their field implementations in injection wells from 1978 to 2015. The data set includes 111 cases histories compiled mainly from SPE papers and U.S. Department of Energy reports. We extracted missing data from some public EOR databases and detected potential outliers by two approaches to ensure data quality. Finally, for each parameter, we evaluated project and treatment frequency distributions and applicability ranges based on successful projects. Extensive comparisons of the developed applicability criteria with the previous surveillance studies are provided and differences are discussed in details as well.
In addition to the parameters that are considered for other EOR technologies, we identified that the applicability evaluations of polymer gels should incorporate the parameters that depict roots and characteristics of conformance issues. The present applicability criteria comprise 16 quantitative parameters including permeability variation, mobility ratio, and three production-related aspects. Application guidelines were established for organically crosslinked bulk gels for the first time, and many experts' opinions in the previous criteria were replaced by detailed property evaluations. In addition, we identified that the applicability criteria of some parameters are considerably influenced by lithology and formation types, and thus, their data were analyzed according to these characteristics. Besides their comprehensiveness of all necessary screening parameters, the novelty of the new criteria lies in their ability to self-check the established validity limits for the screening parameters which resulted from the inclusion and simultaneous evaluation of the project and treatment frequencies.
Efficient Removal of EOR Polymer from Produced Water Using Magnetic Nanoparticles and Regeneration/Re-Use of Spent Particles
Authors: Ko Saebom , Lee Hyunjae , Huh Chun 
Published: March 2016

Abstract
Polymer flooding is a proven technology to improve sweep efficiency, while being one of the most economical enhanced oil recovery (EOR) processes. Partially hydrolyzed polyacrylamide (HPAM) has been widely used for polymer flooding. As the HPAM usage for EOR increases, the challenge of produced water management is also raised because residual HPAM in produced water could increase total chemical oxygen demand and unwanted viscosity in discharging or re-injecting the water. As the environmental standards and regulations get more stringent, it is difficult for the conventional methods to meet the requirement for discharging. Use of magnetic nanoparticles (MNPs) to remove contaminants from produced water is a promising way to treat produced water in an environmentally green way with minimal use of chemicals. The main attraction for MNPs is their quick response to move in a desired direction with application of external magnetic field. Another attraction of MNPs is versatile and efficient surface modification through suitable polymer coating, depending on the characteristics of target contaminants. In this study, we investigate the feasibility of polymer removal using surface-modified MNPs and regeneration of spent MNPs for multiple re-use.
MNPs, in-house synthesized with prescribed surface coating, were superparamagnetic with an average individual particle size of ~10 nm. The removal efficiency of HPAM from water using the MNPs depended on the type and concentration of brines, concentration of amine-functionalized MNPs, surface coating of MNPs, molecular weight of polymer, and how many times the MNPs are regenerated and re-used. Virtually 100% removal of HPAM from water was feasible, depending on the reaction conditions. The regeneration of spent MNPs, using pH adjustment to recover the reactive sites, maintained above 90% removal efficiency for three-time repeatitive usages.
The electrostatic attraction between negatively charged HPAM polymer and positively charged MNPs controls the attachment of MNPs to HPAM molecular chain; and the subsequent aggregation of the now neutralized MNP-attached HPAM plays a critical role for accelerated and efficient magnetic separation.
Injection of Nitrogen Foam for Improved Oil Recovery in Viscous Oil Reservoirs Offshore Bohai Bay China
Authors: Liu Y. M. , Zhang L. , Ren S. R. , Ren B. , Wang S. T. , Xu G. R. 
Published: March 2016

Abstract
Foam injection is a proven technique for improved oil recovery in both light and heavy oil reservoirs, especially for those with high heterogeneity, in which foam can improve the displacement and sweeping efficiency effectively. In this study, the feasibility of nitrogen foam injection for IOR from viscous oil reservoirs are investigated via laboratory experiments and field pilot analysis. The targeted oilfield is located offshore Bohai Bay (China), featured with high oil viscosity (up to 924 mPa.s) and severe heterogeneity of pay-zones. Water flooding has been applied in the oilfield, but the recovery factor is less than 20% and high water cut (over 85%) has been observed. Nitrogen foam injection was proposed in order to solve the problems and improve oil recovery. In this study, laboratory evaluation of nitrogen foam was conducted via foam testing and sandpack flooding. The results indicate that polymer enhanced foaming agents can greatly increase foam's performance. High blocking capability and displacement efficiency were observed in enhanced foam flooding experiments, indicating that nitrogen foam injection can mitigate the problems of heterogeneity and increase oil recovery in low permeability zones. A field pilot with 2 injectors and 13 producers involved has been conducted to verify the feasibility of the foam technique. The wellhead injection pressure was effectively increased after foam injection, and nearly all producers exhibited good response with incremental oil recovery and the average water cut dropped by 6.3% over 8 months of the field operation. The field pilot demonstrates the effectiveness of the nitrogen foam injection technique as an effective IOR method for the targeted oilfield and other similar oil reservoirs.
Timing of ASP Injection for Viscous Oil Recovery
Authors: Aitkulov Almas , Mohanty Kishore K. 
Published: March 2016

Abstract
Alkaline-surfactant-polymer (ASP) flooding of a viscous oil (100 cp) is studied here in a two-dimensional (2D) sand pack. An ASP formulation was developed by studying the phase behavior of the oil with several alkaline-surfactant formulations. The effectiveness of the ASP formulation was validated in a 1D sand pack by conducting a water flood followed by a stable ASP flood. Reservoir sand was then packed into a 2D square steel cell similar to a quarter five-spot pattern. Several ASP floods were then conducted in this 2D cell to study both the displacement and sweep efficiency of ASP floods. First, the polymer concentration was varied to find an optimum polymer concentration. Then the waterflood extent was varied (0–1 PV) after which the ASP flood was initiated. The oil recovery, oil cut, effluent concentration and pressure drop were monitored during the floods. The tertiary ASP flood was very effective in 1D and validated the ASP formulation. The 2D tertiary ASP flood also recovered most of the oil (~98% of OOIP) when the ASP slug viscosity exceeded the oil viscosity, but the pressure gradients were high at ~ 1ft/d injection. When the ASP slug viscosity was lowered to ~1/3 of oil viscosity, oil recovery dropped slightly to 90% OOIP. However, it also decreased the pressure gradient 5 times, which would give good flow rates in the field conditions. As the extent of waterflood preceding ASP got shorter, the oil was recovered faster (for the same pore volumes injected), but the pressure gradient was higher for the ASP flood than the water flood. The ultimate recovery was independent of the extent of waterflood.
A Study of Factors Influencing Polymer Hydrodynamic Retention in Porous Media
Authors: Chen Zhao , Du Cheng , Kurnia Ivan , Lou Junjie , Zhang Guoyin , Yu Jianjia , Lee Robert L. 
Published: March 2016

Abstract
Hydrodynamic retention is one of the contributors to polymer loss in porous media. In this study, effects of flow rate, polymer molecular weight, and core permeability on hydrodynamic retention were investigated. To quantify hydrodynamic retention, injection of two identical polymer banks at different rates separated by 100 pore volumes of brine flushing was performed. Three HPAM polymers with molecular weights of 6–8 million, 12 million, and 20 million Daltons were tested in a 135 mD sandstone core and xanthan polymer with molecular weight of 2–2.5 million Daltons was tested in an 87 mD sandstone core. The retention of 6–8 million Daltons HPAM in a 1,650 mD sandstone core was also measured. Polymer retention in a fresh core was first measured at low injection rate of 3.11 ft/day. Then, 100 PV of 2% NaCl brine was injected to displace all the mobile polymer molecules in the core till pressure drop across the core became stable. Hydrodynamic retention at elevated flow rates was determined after the completion of retention at lower rates and comparisons with the initial polymer retention were made.
Retention of 96.1 μg/g in the 135 mD core was detected for the 6–8 million HPAM at a flow rate of 3.11 ft/day. Increase of flow rate from 3.11 ft/day to 6.22 ft/day and 12.4 ft/day resulted in incremental retention of 2.27 μg/g and 5.38 μg/g, respectively. The injection of a higher molecular weight polymer at the same rate was performed after retention was satisfied with a lower molecular weight polymer. It was found the degree of hydrodynamic retention was greater when higher molecular weight polymers were injected. When core permeability was changed from 135 mD to 1,650 mD, both the initial and hydrodynamic retention were dramatically decreased. The initial retention of xanthan was 66.7 μg/g in an 87 mD sandstone core, which was smaller compared to the retention of HPAM in the similar core. However, hydrodynamic retention measurements of xanthan gives 3.26 μg/g and 6.38 μg/g increments with the increase of flow rate from 3.11 ft/day to 6.22 ft/day and 12.4 ft/day, which suggested that the retention of xanthan is slightly more sensitive to the change of injection rate than HPAM. This study also implied that measurement of residual resistance factor after polymer injection should be completed after sufficient brine flushing (around 100 PV), otherwise, an overestimated residual resistance factor might be provided.
Pore Scale Displacement Mechanism of Bitumen Extraction with High Molecular Weight Hydrocarbon Solvents
Authors: Stape Philip , Ovalles Cesar , Hascakir Berna 
Published: March 2016

Abstract
Solvent Aided-Steam Flooding (SA-SF) focuses on maximizing the oil production by reducing the economic and environmental challenges created by steam generation. However, the solvent selection is vital due to the interaction of solvents with asphaltenes. Moreover, the polar nature of asphaltenes also enables asphaltene-steam interaction which may result in emulsion formation. This study investigates solvent-asphaltene-steam interaction during SA-SF with low and high molecular weight asphaltene insoluble solvents.
Two different solvents were tested; n-hexane (E1 and E4) and a commercial solvent (CS) (E2 and E5) with four flooding experiments; two miscible flooding (E1 and E2) and two SA-SF (E4 and E5) experiments. Results were compared with steam flooding (E3) experiment. The performance evaluation of different enhanced oil recovery methods was accomplished by comparing the oil recovery rates. The asphaltene content of produced oil samples was determined by standard methods. The asphaltene-steam interaction was analyzed with microscopic images, and the water content of produced oil samples was measured by Thermogravimetric Analysis (TGA).
Even though similar cumulative oil productions were obtained by the end of E1 (n-hexane-flooding) and E2 (CS-flooding), the produced oil quality varied due to asphaltene and clay contents. While higher clay content was measured for E1, E2 had a lower quality, due to higher asphaltene contents. This finding is due to the heavy dearomatized hydrocarbons composition of the CS which ranges from C11 up to C16 and enables more asphaltene production. Even though, E5 yielded the highest liquid production among all experiments; the produced liquid was composed of emulsified oil. The solvent aided-steam flooding (SA-SF) experimental results, which have been conducted with n-hexane/steam (E4) and CS/steam (E5) injections, suggest that as the asphaltene content increases in produced oil samples, more hard-to-break emulsions are formed. The unusual stability of these emulsions can be attributed to the nature of the asphaltene present in the produced oil.
From the results presented, it is recommended the use of lower carbon number solvents to leave the larger amounts of asphaltenes in the reservoirs. The solvents differed in their interactions with the asphaltenes present in the oil and with the steam that has a direct impact not only on the quantity of oil produced but the quality as well. Hence, the wise selection of the appropriate solvent cannot be ignored during solvent aided-steam flooding processes.