bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gelation Time Optimization of an Organically Crosslinked Polyacrylamide Gel System for In-Depth Fluid Diversion Applications
Authors: Alhashim Hassan W. , Wang Jinxun , AlSofi Abdulkareem M. , Kaidar Ziyad F. 
Published: March 2018

Abstract
Conformance improvement is crucial for heterogeneous reservoirs to ensure injected water and any EOR chemicals optimally contact the remaining oil with minimal throughput. Gel-based conformance control has been successfully applied on both sandstone and carbonate reservoirs. In this work, a laboratory study was conducted to investigate the applicability of an organically crosslinked polymer gel for in-depth fluid diversion practice at high-salinity and high-temperature conditions. The evaluated gel system was a polyacrylamide polymer crosslinked by organic crosslinkers, hexamethylenetetramine (HMTA) and resorcinol. The effects on gelation performance of polymer and crosslinker concentrations, brine salinity, and pH were investigated. Results showed that the gelation time of the studied gel system reached around three to four days at 95°C, with sufficient gel strength and long term stability. Gelation time became longer with decreasing either polymer or crosslinker concentrations, but there were lower concentration limits to form gel. The gel had a wide range of tolerance to brine salinity, but was sensitive to solution pH value. Decreasing pH resulted in faster gelation rate, and gel tended to be stronger. The gelation time slightly increased with increasing brine salinity in low pH range (&lt; 6.0), or with decreasing brine salinity in neutral pH (6 to 8) environment. Varied laboratory techniques, dynamic rheology and low-field nuclear magnetic resonance (NMR) measurements, were also used to evaluate the gelation time of bulk gel. Rheological measurement and NMR technique, with minimum or no disruption to the gel structure, can determine the gelation time of a bulk gel sample that might be difficult to detect by bottle test. The determined gelation time by these two methods tended to be shorter than bottle test result.
Successful Implementation of a One-Spot Alkaline-Surfactant-Polymer ASP Pilot in a Giant Carbonate Reservoir
Authors: Al-Murayri M. T. , Al-Kharji A. A. , Kamal D. S. , Al-Ajmi M. F. , Al-Ajmi R. N. , Al-Shammari M. J. , Al-Asfoor T. H. , Badham S. J. , Bouma C. , Brown J. , Suniga Hernandez P. 
Published: March 2018

Abstract
A one-spot pilot was successfully performed in the Sabriaya-Mauddud (SAMA) formation in Kuwait to demonstrate the feasibility of using alkaline-surfactant-polymer (ASP) injection to increase oil recovery from a giant carbonate reservoir. Two Single Well Chemical Tracer (SWCT) tests were performed on the SAMA test well (Well A) to measure the effectiveness of ASP injection in mobilizing waterflood residual oil saturation. The first SWCT test (Test #1) measured the waterflood residual oil saturation (Sorw) after a 10 PV seawater injection. This was followed by the second SWCT test (Test #2) to measure the oil saturation (Sorc) remaining after ASP chemical injection, comprised of: a 0.12 PV alkaline pre-flush; a 0.22 PV injection of ASP; a 0.68 PV injection of polymer in alkali solution; and a 1.00 PV injection of polymer.
The difference in residual oil saturation from Tests #1 and #2 quantitatively determines the overall displacement efficiency of ASP injection. Tests #1 and 2 were performed post water and ASP flooding by injecting dilute SWCT tracer chemicals, including a hydrolyzing, partitioning ester (ethyl acetate) and two alcohols (n-propyl alcohol and isopropyl alcohol) that serve as a cover tracer and material balance tracer, respectively. Residual oil saturation post seawater injection was around 28% (+/- 3%) and following ASP flooding it was reduced to 4% (+/- 3%). These encouraging results confirm the effectiveness of ASP flooding in improving incremental oil recovery relative to waterflooding using seawater.
This paper demonstrates the feasibility of applying ASP flooding to increase oil recovery from carbonate reservoirs. The reported findings will be used to optimize and de-risk the implementation in multiwell/pattern ASP injection.
Nanoparticle-Fortified Emulsification of Heavy Oil
Authors: Arab Danial , Kantzas Apostolos , Bryant Steven L. 
Published: March 2018

Abstract
Chemical flooding has been suggested as an efficient conformance control technique to develop many of thin post-CHOPS heavy oil reservoirs in Western Canada. In-situ formation of oil in water emulsions due to the effect of surfactant/natural soap has been reported as the main mechanism behind chemical EOR. In this work, the effect of surface-modified silica NPs to enhance the efficiency of surfactant to emulsify heavy oil (14,850 mPa.s and 980 kg/m3 at 25 °C, from the Luseland field) in water has been investigated.
Bulk fluid screening experiments were conducted using different surfactants and surface-modified silica NPs for selecting the best heavy oil emulsifier. Complementary experiments such as interfacial/surface tension, NP zeta potential and size measurements, and elemental analysis were conducted to understand the interactions between NPs and surfactant molecules.
In the absence of NPs, concentration of both anionic and cationic surfactants should be tuned within a narrow window, near CMC, to create stable heavy oil in water emulsions. It was found that there is a threshold for IFT, obtained at the CMC, which should be met to have stable oil in water emulsions. The created oil in water emulsions break easily at surfactant concentrations higher than the CMC, yielding IFTs higher than the threshold. This observation was also seen in a system containing dodecane. At the CMC of both anionic and cationic surfactants, the IFT between dodecane and an aqueous phase is negative, producing stable dodecane in water emulsions for over three months.
In the presence of surface-modified silica NPs heavy oil emulsification is achieved at surfactant concentrations much lower than the CMC. In this case, IFT is remarkably (54 %) reduced, well below the threshold value, due to the combined effect of 2 wt. % negatively-charged silica NPs and only 0.1 wt. % anionic surfactant. These results suggest that the repulsive interaction between negatively-charged NPs and anionic surfactant may result in pushing the surfactant molecules back towards the oil-water interface to enhance IFT reduction.
Commercial Implementation of Chemical Flooding in Daqing Oilfield, China, and Its Future
Authors: Zhong Xun , Wang Yuhe , Pu Hui , Li Wei , Yin Shize , Ling Kegang 
Published: March 2018

Abstract
Chemical enhanced oil recovery(EOR) such as polymer flooding and alkali/surfactant/polymer(ASP) flooding have been applied throughout the world for more than several decades. However, few large-scale successes of these technologies have been reported, except in China. The annual crude oil production rate by chemical EOR in Daqing Oilfield has been kept over 10.0 million tonnes (~73.5 million barrels) per year for 16 consecutive years. Considerable experience has gained and lessons have learned on large-scale chemical flooding, including major factors that influence the recovery factor and methods to increase the oil recovery; measures to obtain the highest economic efficiency; and how to minimize the costs.
To date, incremental oil recovered by polymer flooding is over 10.0% OOIP. Due to some disadvantages of polymer flooding, like the existence of inaccessible pore volume and lack of the EOR mechanism of ultralow interfacial tension, some substitute technologies are needed, and ASP flooding is a promising one, which was reported and proved to have an ability of recovering more than 20.0% extra oil over water flooding. However, negative scaling problems caused by alkali are severe and problematic, as a result, weak-alkali ASP (WASP) and even surfactant-polymer (SP) flooding were developed or are under development. To alleviate the bad effets of scale and further improve the performance of ASP flooding, some new technologies such as refracturing and application of new anti-scaling chemicals like compound scale removal agent were applied. SP flooding is a theoretically feasible EOR technology, but there are few field test data available, and more effective surfactants are required.
In this paper, the development of commonly used chemical flooding technologies, normal problems that may merge during commercial implementation, together with the updated solutions are included. All the valuable experience obtained from commercial-scale application of chemical flooding in Daqing Oilfield is not only of great significance for the expansion of Daqing Oilfield itself, but also worth learning by other countries.
Polymer Injectivity Analysis and Subsurface Polymer Behavior Evaluation
Authors: De Simoni M. , Boccuni F. , Sambiase M. , Spagnuolo M. , Albertini M. , Tiani A. , Masserano F. 
Published: March 2018

Abstract
A robust analysis of a polymer flooding inter-well pilot has been performed. The main objective was to analyze the polymer injection performance and to confirm the in-situ designed viscosity of the polymer injected, necessary to estimate the expected EOR effect.
The adopted workflow focused on the integration of different sources of data and analyses. Indeed, several phenomena may occur during polymer injection, such as complex injectivity behavior due to polymer non-Newtonian rheological nature, formation damage caused by particles adsorption, fractures opening, and mechanical degradation of polymer. The injection performance analysis focused the following aspects: previous case history, polymer laboratory tests, shear stress through perforation evaluation, diagnostic plots, injectivity test interpretation, well test analysis, and fracturing investigation. Lastly, numerical simulation allowed us to integrate the different analysis, thoroughly capturing the subsurface polymer behavior. Main result is that injection under fracturing conditions occurred during pilot start-up. These small-scale fractures, localized in the near-wellbore zone, are not detrimental to polymer flooding and rather increase the well injectivity. Furthermore, no evidence of mechanical polymer degradation was detected.
The evaluation of the subsurface polymer behavior during an inter-well pilot is crucial to verify the correct polymer injection process. In this work different source of data and analysis have been integrated to understand the injectivity behavior. Robust reservoir monitoring is ongoing and preliminary promising effects are now being shown.
Overcoming Artificial Lift Failures in Polymer Flooding Oil Field in the South of Oman
Authors: Al-Sidairi Nada , Osman Mahmoud , Oritola Nasir , Ahmed Farsi , Zuhaimi Khalid , Amri Mohsin , Hinai Ghalib , Al-Mahrooqi Majid 
Published: March 2018

Abstract
Polymer flood as a mean of enhanced oil recovery was applied in a large sandstone heavy viscous (22API & 90cP) oil field located on the South of the Sultanate of Oman. The polymer flooding was commenced in 2010 with phase I covering 27 patterns, by means of inverted 9-spot pattern. In 2015, Phase I was followed by Phase II with additional 19 patterns. Full field polymer flooding is planned in the coming years.
Over 250 oil producers are benefiting from changing the recovery mechanism water flooding system to the increased viscosity flood system (polymer). Significant oil gain was achieved by improving the recovery factor. Around 92% of the total wells in the field are completed with the two main artificial lift systems, beam pumps BP and Progressive Cavity Pump PCP.
After circa three years of introducing the polymer flooding in the field, new trend of well failure rate was observed in which the artificial lift failure rate was increased by around 40% by end of 2014. This has massively increased work-over job frequencies and cost, and has significantly increased the crude oil production deferment. New type of failure mode was seen in the sucker rod and tubing of the BP & PCP. Severe eccentric wear of sucker rods and tubing in many vertical wells with pumping unit have accrued in which the coupling was worn out and broken from one side i.e. most of phase I & phase II wells experienced premature or frequent failure.
By end of May-2015, 83% of failure were associated to pump failures and it is more related to well conditions. Material analysis of the damaged sucker rod & plungers were conducted & the failure mechanism of both parts of the beam pump was investigated. Around 73% of the pump failures were found to be due to solids handling (sand, scale solids) & corrosion issues or combination of both, erosion & corrosion mode of failure. On the other hand, around 60% of rod failures of the polymer flooded wells were due to wear.
Set of trials and initiatives were conducted to improve the sucker rod run life and reduce the failure rate. For example, centralized molded sucker rod, continuous rod (pro-rod), GRE lined tubing and long stroke pump (roterflux).
Some good success was achieved in arresting the failure rate and improving sucker rod run-life. Material analysis studies & trials were also conducted to improve the barrel life. Evaluation of the various trails are currently ongoing and still at early stage to draw clear conclusions.
This paper will discuss the material analysis studies and the main practical trials that were conducted to reduce the pump and rod failures, and therefore improve well run-life in the field.
Surfactant Based EOR for Tight Oil Reservoirs through Wettability Alteration: Novel Surfactant Formulations and their Efficacy to Induce Spontaneous Imbibition
Authors: Patil Pramod D. , Rohilla Neeraj , Katiyar Amit , Yu Wanglin , Falcone Susan , Nelson Christopher , Rozowski Peter 
Published: March 2018

Abstract
The strongly oil wet nature of tight carbonate or shale reservoirs leads to rapidly declining oil rates during production stages. For fractured tight carbonate reservoirs, chemical flooding with surfactants has been shown to enhance oil production from water flooding (huff and puff method) due to spontaneous imbibition of water into oil-rich matrix, leading to oil displacement from tight pores and increased recovery. Success of such surfactant based EOR technology depends heavily on developing the optimal surfactant formulation for the field. The objective of this work is to identify the key mechanisms responsible for the improved performance of surfactant formulations and to characterize the interactions that can induce imbibition into an originally mixed-wet, tight, hydraulically fractured shale reservoir via laboratory evaluations. Wettability alteration formulations are first developed and screened for aqueous stability and phase behavior at reservoir conditions. Tailored hydrophobic surfaces are used to evaluate selected formulations for their potential to shift rock wettability through contact angle measurements. Water-oil interfacial tension behavior is investigated to elucidate the mechanism of oil recovery. Adsorption behavior of the chemicals is investigated on various rock minerals to identify formulations with minimal retention and component separation under static conditions. Finally, the candidates are comparatively tested for oil recovery performance in spontaneous imbibition experiments at simulated reservoir conditions.
The key factors considered in developing an optimal surfactant formulation are favorable phase behavior in reservoir fluids at reservoir conditions, the ability to shift the rock surface wettability to a more water-wet state, and minimal chemical losses on reservoir minerals. Also, the formulation should not form a stable emulsion which may pose an oil-water separation difficulty in oil production. The designed formulation was tested using forced imbibition test (core flood) and show significant incremental oil recovery. As part of our rigorous approach to design optimal surfactant formulations for improving oil recovery, we perform surfactant phase stability, surfactant retention and rock-surfactant interaction related to wettability alteration. Surfactant formulations designed in this work are unique and provide high temperature stability (above 70 °C and up to 120 °C) and high salinity tolerance (&gt; 12% TDS and up to 22%). This study also highlights the underlying mechanism of surfactant induced wettability alteration of tight carbonate rock due to novel surfactant formulations.
Asphaltene Predictions Using Screening Methods and Equations of State
Authors: Boesen Rasmus Risum , Sørensen Henrik , Pedersen Karen Schou 
Published: March 2018

Abstract
Asphaltene data for 36 reservoir fluids from different geographical regions has been used to evaluate and compare the ability of four commonly used screening methods and three equations of state to identify fluids likely to present asphaltene problems during production. The screening methods are the de Boer method and three SARA based methods. The data covers asphaltene onset pressure data with and without gas injection at a wide range of temperatures. The evaluation showed that the Asphaltene Stability Index method is the most reliable of the tested screening methods, but all screening methods may fail to identify fluids with asphaltene problems. Analyzing asphaltene onset pressure data, it was seen that fluids precipitating asphaltenes by depressurization consistently seem to be causing asphaltene problems during production. The three equations of state tested were the SRK equation, the CPA equation and the PC-SAFT equation. None of the equations was able to predict asphaltene onset pressures in the absence of measured data, but all three equations could be tuned to match the development in asphaltene onset pressure with temperature and the impact of gas injection on the asphaltene onset pressure. The more complex CPA and PC-SAFT equations showed no advantage over a classical cubic equation of state. A newly developed algorithm for generating complete asphaltene phase diagrams helped explain why different trends in asphaltene onset pressure with temperature may be observed.
Squeezing Out the Last Drops - Long and Colourful EOR History of MOL
Authors: Ördög Tibor , Szelényi János 
Published: March 2018

Abstract
In 2017 MOL celebrated the 80th anniversary of the first HC discovery of Hungary within the current territory of the country. This long history is coupled with also a long history of different EOR experiments and projects. Laboratory tests already started in the fifties followed by field applications in the sixties. The objective of this paper is to introduce the currently ongoing EOR related projects based on MOL's EOR history by highlighting the key technologies and projects.
Investigation and Application of an Associative Polymer-Surfactant Binary System for a Successful Flooding Pilot in a High-Temperature, High-Salinity, Ordinary Heavy Oil Reservoir
Authors: Guo Yongjun , Zhang Jie , Zhang Xinmin , Hu Jun , Wang Wei , Liang Yan 
Published: March 2018

Abstract
Due to poor temperature resistance and salinity tolerance of conventional polymers, the chemical flooding for high-temperature and high-salinity reservoir faces enormous challenges. This work studies the comprehensive performance of a polymer-surfactant system based on an associative polymer and verifies its availability and feasibility in Guan-109 fault-blocked reservoir, Dagang (China), which is a typical high-temperature, high-salinity, ordinary heavy oil reservoir.
The viscosifying property of different polymers (including two associative polymers), interfacial activity of different surfactants and the interaction and compatibility between the polymers and surfactants are investigated to initially determine an associative polymer (AP-P7) and the petroleum sulfonate surfactant (PS-985) as suitable candidates. Then, the adsorption, shear resistance, aging stability, injectivity, and oil displacement capacity of the combination system containing AP-P7 and PS-985 are further studied to obtain the optimal binary flooding system. Moreover, the field application scheme for Guan-109 reservoir is further obtained through optimizing injecting concentration, slug size and slug combination of binary flooding system.
The lab tests show that, under the reservoir condition of 26983 mg/L salinity and 78 °C, the viscosity of associative polymer varies from 31.7 to 88.5 mPa·s in a concentration range of 1500~2500 mg/L, and the oil/water interfacial tension of the petroleum sulfonate is up to 10-3 mN/m order of magnitude in a concentration range of 0.05wt%~0.5wt%. At fixed polymer concentration (2000 mg/L) and surfactant concentration (0.3wt%), the binary system presents significant viscosifying capability, interfacial activity, adsorption resistance, shear resistance, aging stability, etc. Meanwhile, the system has good injectivity at a gas permeability of 210×10-3 μm2 and can generate a high resistance factor (105.1). After optimizing injecting parameters, in laboratory, the binary system can improve the oil recovery by 26.37% after water flooding. During the binary flooding pilot in Guan-109 reservoir (7 injectors and 12 producers), from December 2016 to December 2017, the system has been injected for 0.102 PV. Thus, the pilot achieves expected results. The liquid production enhances from 364 to 521.1 m3/d, oil production enhances from 27.7 to 51.7 m3/d, and the water cut decreases from 92.3% to 90.1% (the maximum decreasing amplitude is up to 3.4%).
Both lab tests and field pilot show that the binary system based on the associative polymer is hopeful to solve the challenges faced by chemical EOR in high-temperature and high-salinity reservoir. In addition, the pilot also provides much practical experience for the successful application of this novel system.