bluuebunny/crossref_metadata_2025_split huggingface dataset:
Chemical EOR Economic Evaluation in a Low Oil Price Environment: Sabriyah Lower Burgan Reservoir Case Study
Authors: Al-Murayri M. T. , Al-Mayyan H. E. , Moudi Kamal , Al-Ajmi F. , Pitts D. , Wyatt M. J. , French K. , Surtek J , Dean E. 
Published: March 2018

Abstract
Chemical EOR (CEOR) can be economic in a low-price environment, but it requires economic insights be integrated into the initial reservoir screening, laboratory and numerical simulation evaluations, and continued review through field implementation. The CEOR economic evaluation for the Sabriyah Lower Burgan (SALB) using this integrated process found that surfactant-polymer and alkaline-surfactant-polymer flood had different economic potentials due to different oil recoveries, facility costs, and operating costs. Initial reservoir screening of the SLAB indicated that LoSal and CO2, flooding might also have economic potential. Laboratory corefloods injecting field proportioned volumes of chemical solutions using dead oil and reservoir rock resulted in chemical cost average $3.12 per incremental barrel of oil for alkaline-surfactant-polymer formulations and $18.61 for surfactant-polymer formulations. Live oil corefloods for corresponding chemical formulations cost per incremental barrel estimates were $3.70 and $7.83. LoSal process provided no incremental oil based on laboratory coreflood results. Numerical simulation forecast economics included chemical costs, estimated operating costs, facilities cost, drilling of wells, and other capital costs. 2.2, 5.4, and 60 MMbbl pilots forecast by numerical simulation indicated that alkaline-surfactant-polymer cost per incremental barrel of oil was $28.63, $10.42, and $10.95 for the respective pilot sizes. Smaller pilots show a greater impact of fixed costs such a facilities and new wells. 5.4 and 60 MMbbl pilots paid out at 3.4 years or less. Corresponding discounted rates of return were up to 14%. Sensitivity analysis indicated that crude oil price has the greatest effect on chemical enhanced oil recovery economics, regardless of pilot size. This paper summarizes how economic applications at each phase of a chemical flood evaluation are performed and how those evaluations can be understood and applied to prevent adverse project selection. Economic parameters should be evaluated at various phases of project evaluation, influencing decisions to move forward. Methods of evaluation at each phase are documented and discussed using the Sabriyah, Lower Burgan study as a basis.
1.1 Acre Thermal EOR Pilot & Field Testing Best Practices, Sultanate of Oman
Authors: Al Shibli Abdullah , Al Bahri Sultan , Al Yazidi Rashid , D' Amours Kevin , Belghache Abdesslam , Al Yahyai Ahmed , Putra Pristi H , Duggan Tim , Saileh Abdulsalam , Al Busaidi Faisal , Al Abri Rahma , Lombardi Jorge 
Published: March 2018

Abstract
The A West heavy oil reservoir in the South of Sultanate of Oman is a very attractive target for thermal EOR considering its low primary oil recovery of 20%. The field development plan proposed Vertical Steam Drive as a development concept for Phase 1 that included drilling and operating a total of 80 3.3 Acre inverted 7 spots patterns. Vertical and areal steam conformance has been highlighted as one of the main challenges in one of the most complex and thick heavy oil reservoirs in the world. As a result, the plan has proposed executing and operating a smaller spacing 1.1 acre pattern in parallel with full field development of the 3.3 acre patterns. The main objective of the trial is to run a full lifecycle in situ steam flood in 2-3 years compared to 15 – 20 years at field scale spacing. This will accelerate learning on steam breakthrough management in combination with understanding how to improve vertical and areal sweep conformance.
A fully integrated surveillance plan using advanced technologies including down hole DTS temperature fiber cable, covering the whole wellbore have been installed in all producers. In addition to that real-time wellhead temperature monitoring is a key surveillance element to sense the impact of steam break-through in the producers. Multi-tracers injection will also be executed to monitor the areal sweep efficiency and estimate the preferential movement of the steam within the subsurface by measuring the concentration of the tracer in the producers. Along with that, mechanical conformance applications have been installed in the steam injectors to add an additional control on vertical steam conformance and test the effectiveness of such application on addressing steam break-through issues.
The trial will provide direct experience in managing steam injection and production after steam breakthrough that can later be implemented on a larger scale. The integrated data from the trial will aid in calibrating the simulation models to anticipate the time to steam breakthrough and build confidence in the power of the model for short/long term forecasting. In addition, it will also provide early indications of the effectiveness of some of the new technologies and surveillance in predicting and addressing steam conformance challenges and hence optimize the steam flood process.
Novel Anionic Surfactant Formulation for High Temperature Carbonate Reservoirs
Authors: Montes J. , Blin N. , Alvarez A. E. , Barrio I. , Panadero A. , Rodriguez R. , Coca M. , Trujillo F. 
Published: March 2018

Abstract
Improving oil recovery in mature carbonate reservoirs is challenging due to inherent harsh conditions, i.e. high temperature, salinity and divalent ion concentration. This paper reports the development of a surfactant formulation that injected in sea water resulted in an incremental oil recovery higher than 20% at 120°C in carbonate field rocks.
A systematic study comprising blend and salinity scans of a lineal alkyl benzene sulfonate (ABS) and a co-surfactant was done in order to select a suitable formulation optimized to be injected in sea water. The formulation performance was evaluated by measuring the solubility, interfacial tension (IFT) and phase behavior. The robustness of the formulation was assessed by changing the surfactant concentration and the brine salinity.
Sandpack experiments with the addition of tracers were performed to determine the dynamic adsorption and coreflood experiments in low permeability reservoir cores were conducted to determine the injectivity, incremental oil recovery and surfactant adsorption/retention.
The formulation was designed by blending at different ratios lipophilic surfactants that reduce the oil/water IFT with more hydrophilic co-surfactants that improve the solubility. The obtained formulation, comprising an ABS and a co-surfactant, was stable at ambient temperature and 120°C. It was optimized to be injected at sea water salinity providing ultra-low IFT (&lt;0.005 mN/m) and creating a microemulsion. The designed formulation was tested by injection in a previously water flooded low permeability core. Promising results were obtained in terms of incremental oil recovery (+20%) and injectivity, but too high adsorption/retention produced a delay on oil production.
In order to reduce surfactant losses, an optimization step consisting on the addition of a mineral oil and/or a low MW polymer was faced. A substantial reduction on adsorption/retention, maintaining incremental oil recovery values, was achieved by adding a specific amount of a specific mineral oil and/or a low MW polymer.
The results presented show a robust formulation able to produce high incremental oil recovery under harsh carbonate reservoir conditions.
Long Term Thermal Stability of Chemical EOR Surfactants
Authors: Hocine Sabrina , Pousset Baptiste , Courtaud Tiphaine , Degré Guillaume 
Published: March 2018

Abstract
Chemical enhanced oil recovery techniques progressively emerge as a means to increase mature oil fields production. In particular, surfactant flooding allows increasing oil production by lowering the interfacial tension between injection water and crude oil. The effectiveness of surfactants depends on their chemical stability over an extended period of time, which could be impaired by reservoir conditions in terms of temperature, salinity and oxidative conditions.
Within the frame of this work, we monitored the chemical stability of several families of anionic surfactants in water, including alkyl ether sulfates, alkyl glyceryl ether sulfonates, alkyl benzene sulfonates and internal olefin sulfonates. Analytical methods were first developed to evaluate the chemical stability of these surfactants, including high pressure liquid chromatography (HPLC) and mixed-indicator titration techniques. The thermal stability of industrially representative surfactants was then monitored as a function of time at high temperature.
Anionic surfactants designed to withstand high temperature conditions proved to be stable in oxygen controlled environments over a very long storage time. Alkyl benzene sulfonates, internal olefin sulfonates and alkyl glyceryl ether sulfonates (or alkyl alkoxyl glyceryl sulfonates) notably showed a very good stability over a year–long storage at 100°C. Alkyl ether sulfates (or alkyl alkoxy sulfates) showed by contrast a poor stability at 100°C as all the active contents were degraded in twenty four hours in deionized water and around four months in an alkaline buffer. The hydrolysis of the sulfate moiety at high temperature is probably responsible for the limited stability of alkyl ether sulfates at high temperature.
This study highlights the strong benefit of using sulfonated anionic surfactants in EOR processes applied at high temperatures. In particular, it demonstrates the advantage of replacing alkyl ether sulfates by alkyl glyceryl ether sulfonates in order to insure the long term stability of a formulation developed to be injected during several years.
Experimental Study on the Transport and Improved Oil Recovery Mechanism of Submicron Particle Gel
Authors: Almohsin Ayman , Ding Haifeng , Bai Baojun 
Published: March 2018

Abstract
Excessive water production could cause rapid decline in well deliverability and may lead to early well abandonment. Submicron polymer particle gel is a relatively new remedial treatment for excessive water production problems. This novel water control system can be adjusted according to formation pore throat sizes, particularly for deep profile control. However, current publications only introduced their physical properties and field applications. Moreover, no lab results have been reported about their transport behaviors and oil recovery improving abilities. This work investigated the transportation of a submicron particle gel system into porous media to block high permeability water flow channels. Coreflooding experiments on Berea sandstones were conducted not only to examine the water blockage mechanisms, but also to understand the potential improvement in oil recovery. Concentrations of submicron particle gel and brine are the two major factors that can potentially affect the efficiency of the water blockage and oil recovery improvement. Therefore, effect of these two parameters were thoroughly investigated in this experimental study. Meanwhile, to observe the in-depth transport of the submicron particle gel, the core holders with multiple pressure taps were used to monitor pressure drop at different sections and identify where the particles were transported. In the first part of the research, three different submicron particle gel concentrations were involved. The injection volumes of submicron particel gel dispersion were kept same in all coreflooding experiments. Result shows that the particle gel can transport deeper into the core, yields better impact on the efficiency of water blockage and result in higher oil recovery improvement when the gel concentration was higher. The second part of the research studied the impact of brine concentration. With difference in salinity environments, submicron particel gel had different swelling ratios and strengths: swollen particles were bigger and weaker with lower salinity. Unlike previous research, submicron particle gel was injected until a stable injection pressure in all sections of the core. Results indicate that high salinity environments could result in better plugging efficiency however low salinity environments could result in better oil displacement efficiency. The reasons behind the results have been analyzed by evaluating the submicron gel physical and rheology properties in lab. By studying the impacts of these two factors, this work provides a better understanding of submicron particle gel transportation and oil recovery improvement mechanisms, which is of major importance for an optimized design of a successful submicron particle gel treatment.
A Generalized Continuous Carbon Dioxide Injection Design and Screening Tool for Naturally Fractured Reservoirs of Varying Oil Compositions
Authors: Hamam Hassan , Ertekin Turgay 
Published: March 2018

Abstract
Carbon Dioxide (CO2) injection is one of the more effective EOR methods in oil reservoirs. Continuous CO2 injection is a viable technique that could yield high oil recoveries when employed effectively in naturally fractured reservoirs. Screening, evaluating, and designing optimized continuous CO2 injection projects require extensive computational power for the concerned reservoirs. Although reservoir fluid composition is the most important parameter when it comes to EOR, it can be particularly challenging to account for different reservoir fluid compositions in any workflow. In this study, a new workflow is developed that helps evaluate and design CO2 injection in naturally fractured reservoirs for different reservoir fluid compositions. Reservoir rock properties are also evaluated as part of this study to assess the impact on recovery. Continuous CO2 injection schemes with variable injection design parameters are constructed using a two-well, two-layer, dual porosity, miscible compositional reservoir simulation model. Representative scenarios are then used to train and develop two Artificial Neural Network (ANN) based proxy models: 1) A performance prediction proxy that predicts reservoir performance for a specific injection design, 2) An inverse ANN for injection applications that determines injection design parameters for the desired performance. ANN's predictability is evaluated and measured through its accuracy to predict blind testing data sets. The proposed proxies are found to be capable of predicting within an acceptable degree of error against the blind testing scenarios. The developed proxies have the potential of overcoming existing limitations and setting up a new benchmark for future studies.
SmartWater Synergy with Chemical EOR: Effects on Polymer Injectivity, Retention and Acceleration
Authors: AlSofi Abdulkareem M. , Wang Jinxun , Kaidar Ziyad F. 
Published: March 2018

Abstract
The synergy between various enhanced oil recovery (EOR) processes has always been raised as a potential optimization route for achieving a more economic and effective EOR application. In previous work, beside the established positive impact of SmartWater on polymer rheology, we have demonstrated polymer positive impact on SmartWater effects through measurements of surface potential and contact angles. The results were also supported by forced oil-displacement experiments. In this work, we further investigate this SmartWater/Polymer synergy focusing on the possible impact of SmartWater on polymer floods specifically polymer injectivity, retention and acceleration. For this purpose, a set of thoroughly designed single-phase displacement experiments were performed at reservoir conditions. The results demonstrate that SmartWater has: (1) a slight negative impact on both polymer and chase water injectivity, (2) a positive impact on polymer retention, and (3) a negligible impact on polymer, hence oil bank, acceleration. Given the minor negative impact on injectivity, we conclude that SmartWater/Polymer flooding exhibits an overall favorable synergy that reduces chemical consumption and improves sweep.
A Novel Ultra-Low IFT Spontaneous Emulsification System for Enhanced Oil Recovery in Low Permeability Reservoirs
Authors: Li Zhe , Lu Yao , Wu Hairong , Yang Meng , Feng Haishun , Xu Derong , Hou Jirui , Kang Wanli , Yang Hongbin , Zhao Yilu , Bai Baojun 
Published: March 2018

Abstract
Emulsion, as an oil displacement and conformance control system, provides essential contribution for enhanced oil recovery (EOR). However, conventional flooding systems, which form large emulsion droplets compared to the pore size of porous media in formation, usually encounters problems including high capillary pressure and poor displacement efficiency in low permeability reservoirs. Thus, it is necessary to find a new flooding system that has high displacement efficiency and no capillary pressure.
In our reseach, effects of combined surfactant and alkali on interfacial tension and spontaneous emulsification capacity for the surfactant solution were evaluated to determine the optimum formula of the flooding system. Then, the oil/water interfacial rheology and environmental influence on the spontaneous emulsion stability were performed to study the enhanced mechanism of spontaneous emulsification system. It was proposed that the solution with alkali and surfactants not only could achieve ultra-low interfacial tension, but also exhibited an excellent spontaneous emulsification behavior at a reservoir temperature of 45 °C. The average size of formed spontaneous O/W emulsion droplets was about 0.2 μm which was smaller than average size of the low permeability throats. The presence of the optimum system can further improve the interfacial rheological properties. Ultimately, the oil displacement tests, using outcrop cores with permeability in the range of 25-35 mD, indicating that EOR slug can improve approximately 12.4% as compared to the initial oil in place (IOIP) through the strikingly spontaneous emulsification flooding after water flooding, better than that of the conventional surfactant flooding. The laboratory research suggested that the newly formulated spontaneous emulsification system can be applied as an ideal EOR system and efficiently overcome the constraint of high capillary pressure in conventional chemical flooding for low permeability reservoirs.
Effect of Initial Wetting on Smart Water Potential in Carbonates
Authors: Mjos Jon Endre , Strand Skule , Puntervold Tina , Gaybaliyev Heydar 
Published: March 2018

Abstract
To evaluate the feasibility of "Smart Water" injection, reproducing representative initial wettability in laboratory experiments is essential. Experimental studies have confirmed that adsorption of polar organic components from crude oil to the rock surface is a main contributor in establishing initial wettability. This study intends to examine the effect rock surface accessibility, by altering the initial water saturation (Swi), has on the adsorption efficiency of polar components in carbonates.
The adsorption study of polar components was performed by flooding several pore volumes of crude oil through outcrop Stevns Klint carbonate cores at different Swi. To observe the amount of adsorbed polar components, the acid and base numbers of the effluent were examined regularly using titration. Core wettability was thereafter investigated by spontaneous imbibition, forced imbibition and by the chromatographic wettability test.
The study illustrated the importance of the acidic components in the crude oil on wettability alteration in carbonates. It was observed that 1) increased adsorption to the pore surface of acidic polar components lead to less water-wet conditions. 2) The adsorption process occurs immediately as the oil contacts the porous media, having the highest rate of adsorption during the first pore volumes of injection. 3) Increasing the surface accessibility for polar components by reducing the initial water saturation has strong influence on the initial wettability. 4) Adsorption of acidic components is more pronounced than that of basic components.
Aging of cores has for a long time been regarded as the primary method for establishing initial wettability in the laboratory. This study demonstrates that the adsorption of polar components occurs almost instantly, and that aging is not necessary to obtain mixed wettability.
Experimental Study of Surfactant Polymer for a Heavy Oil Field in South of Oman
Authors: Al-Jabri R. , Alkindi A. , Al-Mjeni R. , Al-Azri N. , Rousseau D. , Renard S. , Miralles V. , Delamaide E. 
Published: March 2018

Abstract
Heavy oil reservoirs remain challenging for surfactant-based EOR, particularly in selecting fine-tuned chemical formulations which combine high performance and guarantee trouble-free operations. This requires substantial laboratory work and a solid methodology. This paper reports a laboratory feasibility study aiming at designing a surfactant-polymer pilot for a heavy oil field in the South of Oman.
The workflow was organized as follows: (i) oilfield initial assessments; (ii) selection and preparation of the rock and fluids; (iii) initial design of the surfactant-polymer formulation involving an extensive screening of surfactants and polymer combinations using a robotic platform; (iv) pre-qualification tests involving in-vitro adsorption and assays for emulsion risk at surface conditions; (v) demonstration coreflood test aiming at determining the ultimate oil recovery achievable with the formulation and (vi) optimization study involving coreflood test and formulation fine tuning to design the most adapted injection strategy.
An extensive screening study was carried out to select representative core and fluid materials. To enable comparative coreflood tests, an analogue granular porous medium was built, with mineralogical composition mimicking that of the reservoir rock. The design of the surfactant-polymer formulation relied on hundreds of automated salinity screening phase behavior and solubility assays. Polymer selection was achieved by membrane injection tests performed under imposed velocity conditions to determine resistance factors versus pore size, velocity, concentration and salinity. This procedure resulted in the successful design of a surfactant-polymer formulation that provided o/w IFT of less than 10-2 mN/m at 50°C over a relatively broad range of salinities, including the injection water salinity. A first coreflood test performed on a reservoir rock plug demonstrated that injecting the formulation as an infinite slug in post-polymer flooding conditions led to 100% recovery of the remaining oil with a very good in-depth propagation of the formulation. The optimization study was then carried out and led to designing injection sequences that allowed minimizing the surfactant losses due to both retention on the rock and dissolution in oil.
The results demonstrate that a surfactant-polymer formulation can successfully be designed and evaluated for heavy oil reservoirs. They also provide practical guidelines for the pilot implementation and pave the way for the next stage of the feasibility study which will focus on generating data for reservoir simulation, operational design and improving the economics.