bluuebunny/crossref_metadata_2025 huggingface dataset:
Novel Surfactants without Hydrocarbon Chains for Chemical EOR
Authors: Sharma Himanshu , Panthi Krishna , Ghosh Pinaki , Weerasooriya Upali , Mohanty Kishore
Published: March 2018

Enhanced oil recovery (EOR) techniques involving surfactants such as surfactant floods, foam floods, and wettability alteration have been studied to recover remaining oil after primary and secondary floods. In these processes, a surfactant solution is injected to promote one (or more) of the following: lowering of capillary forces, improvement in sweep efficiency, and wettability alteration. Although significant advances have been made in designing surfactant molecules to achieve the above mentioned objectives efficiently, surfactant price is often the key limiting factor for a field-scale operation. Most surfactant molecules have a hydrocarbon chain (for example alkyl chain) or an aromatic ring as the main hydrophobe. The hydrocarbon chain (or ring) imparts hydrophobicity (and surface activity) to the surfactant molecule. However, these hydrophobes also result in additional cost. In this study, we discuss low-cost surfactants developed without hydrocarbon chains (or rings) for chemical EOR processes in general. The focus of this paper, however, is on their application in surfactant floods. These novel surfactants were developed by using methanol as the starting material, followed by the addition of propylene oxide (PO) and ethylene oxide (EO) groups, and an anionic head group. The surface tension and critical micelle concentration (CMC) values of these surfactants were measured. A screening study was performed to identify promising candidates; which showed ultralow interfacial tension (IFT) with various crude oils as well as aqueous stability at reservoir conditions. A comparison between novel surfactants with traditional surfactants was made based on the screening study. Oil recovery corefloods were performed in Berea and Boise sandstone cores to test the ultralow IFT formulations. These surfactants were found to have very low CMC values, and lowered the surface tension to about 32 dynes/cm. Their aqueous stability at a given temperature was found to be dependent on the number of PO and EO groups. Phase behavior experiments showed low IFT formulations with different crude oils by using these surfactants by themselves as well as in combination with internal olefin sulfonates (IOS). Moderate oil recoveries were obtained in coreflood experiments using these surfactants.
Polymer Flood Field Implementation - Pattern Configuration and Horizontal versus Vertical Wells
Authors: Sieberer Martin , Clemens Torsten , Peisker Jörg , Ofori Solomon
Published: March 2018

A polymer pilot in the 8 TH reservoir in Austria showed promising results. The Utility Factors were below 2 of kg polymer injected / incremental barrel of oil produced (polymer cost are 2 – 4 USD/kg). Furthermore, substantial incremental oil was produced which might result in economic field implementation. The results triggered the planning for field implementation of polymer flooding.

To optimize the economics of field implementation, a workflow was chosen ensuring that the uncertainty was covered. 1200 geological models were generated covering a variety of different geological concepts. These geological models were clustered based on the dynamic response into 100 representative geological realizations and then used for history matching.

For infill drilling, probabilistic quality maps can be used to find locations. However, injection and production well optimization is more challenging. Introducing probabilistic incremental Net Present Value (NPV) maps allows for selection of locations of injection and production well patterns.

The patterns need to be optimized for geometry and operating parameters under uncertainty. The geometry was optimized in a first step followed by operating parameter optimization. In addition, injectivity effects of vertical and horizontal wells due to the non-Newtonian polymer rheology were evaluated. The last step was full-field simulation using the probabilistic NPV map, optimized well distance and operating parameters.

The resulting Cumulative Distribution Function of incremental NPV showed a Probability of Economic Success (PES) of 91 % and an Expected Monetary Value of 73 mn EUR.
Simulation of Water and Condensate Blockage and Solvent Treatments in Tight Formations Using Coupled Three-Phase Flash and Capillary Pressure Models
Authors: Neshat Sajjad S. , Okuno Ryosuke , Pope Gary A.
Published: March 2018

Water and condensate blockage near production wells in unconventional reservoirs can significantly reduce oil and gas production rates. This paper presents a new approach for more accurate modelling of liquid blockage in tight oil and gas reservoirs and investigates the use of solvents for blockage removal. A cubic equation of state is used to model the phase behavior of three-phase mixtures of solvent, hydrocarbons and water. The three-phase flash model is coupled with a rigorous three-phase capillary pressure model to account for the effect of capillary pressure. The capillary pressure function includes the impact of several important petrophysical properties such as pore size distribution and wettability. A compositional simulator is used to simulate the effectiveness of using methanol, dimethyl ether or CO2 to remove liquid blockage and increase production rate.
Miscible Hydrocarbon GOGD Pilot in the Yates Field Unit
Authors: Valdez R. , Pennell S. P. , Cheng A. , Farley T. , Boring P. A.
Published: March 2018

A miscible injectant was used in a single injection well pilot in the Yates field to mobilize remaining oil in the gas cap and accelerate gravity drainage. Nitrogen, CO2 and recycled gas injection, all immiscible with Yates oil due to low original and current reservoir pressure, have been used historically to assist the gas-oil gravity drainage (GOGD) development. The result of immiscible injection has been a lowering of the gas-oil contact, a thinning of the oil column, and leaving a remaining oil saturation in the gas cap of up to 40 percent. A hydrocarbon mixture rich in ethane and propane and miscible with Yates oil was injected in a CO2 injector for six months after which the well was returned to pure CO2 injection.

Data collection during the pilot included repeat saturation logging of a newly drilled observation well, well tests of nearby horizontal producers, frequent gas and oil sampling, and chromatographic analysis. Phase behavior PVT experiments were also conducted which confirmed miscibility of the injectant and improvement over CO2 injection. Numerical simulation of pilot performance was also used as part of the interpretation.

Pilot results to date show a doubling of oil rate at peak over base oil decline, breakthrough in horizontal producers within 3-5 months matching an a priori prediction from numerical simulation, 10 percent reduction in oil saturation in the target interval in the gas cap, and the return of two wells to continuous production after having been shut-in due to high gas-oil ratios. Early interpretation of pilot results showed that most of the incremental oil and back produced enriched hydrocarbons came from one well. During the follow-up CO2 injection phase, one of the horizontal wells completed in the gas cap (unlike other pilot producers), was redrilled deeper into the oil column to improve the pilot areal and vertical sweep.

The pilot design, results, and interpretation will be discussed. Results from the pilot will be used to support evaluation of a field wide development, which could lead to substantial incremental reserves and extension of the field life.
Evaluating the Effect of Temperature on Surfactant Phase Behavior and Aqueous Stability to Forecast Optimum Salinity at High Temperature
Authors: Pinnawala Arachchilage Gayani W. , Spilker Kerry K. , Tao Emily Burdett , Alexis Dennis , Linnemeyer Harold , Kim Do Hoon , Malik Taimur , Dwarakanath Varadarajan
Published: March 2018

Conducting surfactant phase behavior experiments above 100°C is challenging and requires specialized methods to minimize health and safety risks. Shifts in optimal salinity can be correlated to temperature. However, data above 100°C is sparse and the correlations have not been extensively validated above 110°C. In addition, aqueous stability changes with temperature and is often not characterized. We systematically present shifts in optimal salinity and aqueous stability with temperature and use results from both experiments to optimize co-solvent concentrations at high temperatures
Systematically Optimized Surfactant Formulation and Injection Design to Reduce Chemical while Maintaining Performance
Authors: Arachchilage Gayani W. , Alexis Dennis , Kim Do Hoon , Davidson Andrew , Malik Taimur , Dwarakanath Varadarajan
Published: March 2018

Chemical costs dominate surfactant enhanced oil recovery (EOR) processes. A measure of chemical usage is the pore volume of chemical injected multiplied by the concentration of the chemical in the formulation (PV*C). Recent developments have reduced PV*C to about 30 units for conventional surfactant processes and to about 10 units for ASP processes. Our goal was to demonstrate high oil recovery using conventional surfactant processes at PV*C of 10 units. Under these conditions surfactant polymer flooding becomes just as viable an alternative for oil recovery as the more complex ASP processes.

In this paper, we conducted several phase behavior experiments with the goal of minimizing microemulsion viscosity and maximizing oil solubilization ratios. In addition, we focused on maintaining aqueous stability of both the surfactant slug and dilutions with polymer chase fluids. Both surfactant and co-solvent compositions were optimized to achieve low microemulsion viscosity. The microemulsion viscosity was also measured using three-phase relative permeability experiments. Once an appropriately low microemulsion viscosity was achieved, a series of corefloods at different PV*C units of surfactant were conducted in Bentheimer sandstone. Our baseline formulation included 2 wt% surfactant and 2.8 wt% co-solvent and recovered more than 95% oil in a surrogate Bentheimer coreflood using 30 units of surfactant. The existing surfactant formulation was optimized to match the new crude oil sample and it also recovered more than 95% oil in a Bentheimer coreflood using 30 units of surfactant.

By incorporating large hydrophobe surfactants, we achieved good phase behavior with 1.25% surfactant and 2% co-solvent. The optimized formulation recovered 98% oil with 20 units and 91% with 10 units of surfactant, which translated into a retention of <0.1 mg/g of surfactant. These results indicate that high-performance surfactant formulations have the potential to significantly reduce chemical cost and compete with conventional SP processes in terms of PV*C. Consequently, we illustrate the ability of recovering more than 90% oil with only 10 units of surfactant in conventional surfactant-polymer flooding with high performance surfactants. Such an approach can potentially compete with ASP processes and allow for rapid deployment due to reduced complexity.
Novel Switchable Alkyl-Amine Surfactants for CO2 Emulsion
Authors: Cui Leyu , Klimenko Alexandra , Dubos Fabienne , Lagorse Marine , Bourrel Maurice
Published: March 2018

CO2 emulsion/foam is a promising method for controlling the mobility and improving the volumetric sweep efficiency in CO2 enhanced oil recovery (CO2-EOR) process. Recently, amine surfactants attract the attention of the researchers as CO2 emulsifiers/foamers, because of their switchable property: the surfactants are nonionic and CO2 soluble at high pH, and are cationic and water soluble at low pH. However, the efficiency of the commercial switchable amine surfactants is usually suppressed at high salinity (> 200 g/L TDS) and temperature (> 100 °C). Thus, novel switchable alkyl-amine surfactants are designed in house based on the hydrophilic and CO2-philic balance for rapidly generating strong and stable CO2 emulsions at high salinity and high temperature. These novel surfactants are evaluated and compared to a commercial one with respect to the solubility in brine and CO2, and emulsifying ability in bulk and in porous media at high temperature, high pressure and high salinity.

The novel surfactants show outstanding performance: soluble in 220 g/L NaCl brine at pH≤8 from room temperature to 120 °C, soluble in CO2 at relatively low pressure (91 bar) and high temperature (110 °C). The surfactants are thermally stable at 110 °C and pH=4 in the absence of O2. Strong CO2 emulsion/foam is observed in both bulk test and in silica sandpack with 0.2 (wt)% of the surfactant in brine. Additionally, the apparent viscosity of the CO2 emulsion/foam at 110 °C is significantly higher than that at lower temperatures. Comparing to the commercial surfactants, the CO2 emulsion/foam is stronger and generated faster by the novel surfactants. These novel surfactants can be synthesized using commercially available feeds and simple industrial processes. Thus, the novel surfactants are promising for generating the CO2 emulsion/foam, especially in the hot and salty carbonate reservoirs.
Evaluation of Polymer Flooding Performance Using Water-Polymer Interference Factor for an Offshore Oil field in Bohai Gulf: A Case Study
Authors: Yang Gang , Jiang Ruizhong , Li Xiaoli , Jiang Yu
Published: March 2018

Polymer flooding has been applied to the development of an offshore oil field S18 located in Bohai Gulf, China, where the water and polymer injection wells are alternately distributed. Field tests have indicated that the oil production and economic profit are significantly affected by the interference between alternately injected water and polymer. Therefore, it is of great importance to quantify the water-polymer interference (WPI) and thus improve the oil production. In this paper, the polymer flooding performance for the offshore oil field S18 has been evaluated by using a newly proposed WPI factor. The developed model provides a new way to evaluate the polymer flooding performance for the offshore oil field. More specifically, onshore and offshore polymer injection processes are thoroughly compared in terms of field performance, reservoir properties, and polymer flooding parameters. Then, a conceptual model is developed to analyze and quantify the interference between the injected water and polymer. The WPI factor is firstly introduced and quantified by a water cut funnel prediction method. The WPI factor is found to increase with the water injection rate and decrease with the polymer concentration. Subsequently, the reservoir simulation model of S18 oil field is well developed including 50 injectors and 93 producers with well-matched field production data. The WPI factor is accordingly optimized by tuning the water injection rate and polymer concentration at different blocks of the S18 oil field with the assistance of orthogonal design method. Consequently, the overall WPI factor of the S18 oil field is decreased by 8.20% after the optimized polymer & water injection scheme is applied, resulting in an increased oil recovery by 0.24%.
Coupled Capillary Pressure and Relative Permeability Using an Equation-of-State Approach
Authors: Li Liwei , Johns Russell T.
Published: March 2018

Accurate and continuous capillary pressure (Pc) and relative permeability (kr) models are key relations in modeling of enhanced oil recovery (EOR) processes. Current commercial reservoir simulators tune empirical models for relative permeabilities and capillary pressures to experimental data based solely on a limited set of data under immiscible conditions. These empirical models attempt to represent very complex compositional processes, even though they are only a function of phase saturation and type. Thus, "fully" compositional models that use these empirical relations are not fully composition and discontinuities in compositions and saturations result. These discontinuities lead to failed simulations, significant inaccuracies and increased computational time.

This paper develops a coupled equation-of-state (EoS) kr-Pc model that can reproduce important features of the current empirical models, but also yield physically consistent predictions that cannot generate discontinuities. The model parameters use the same inputs for both relative permeability and capillary pressure and are tuned simultaneously. We focus here on capillary hysteresis and understanding the components of the EoS from measured data using saturation, phase distribution (Euler characteristic or phase contact area), and wettability as inputs. The new EoS Pc model maintains a similar functional form as the common Brooks-Corey correlation, and can predict capillary pressure away from the tuned experimental data. The results using CT scans of imbibition and drainage processes show excellent agreement once contact angle hysteresis is included. A quadratic response surface is used to understand better the functional form of the EoS, i.e. partial derivative expressions. The new coupled kr-Pc approach could improve compositional simulation by making it faster, more robust, and accurate since these key parameters are more continuous and physical.
Ultralow-Interfacial-Tension Foam Injection Strategy Investigation in High Temperature Ultra-High Salinity Fractured Carbonate Reservoirs
Authors: Dong Pengfei , Puerto Maura , Ma Kun , Mateen Khalid , Ren Guangwei , Bourdarot Gilles , Morel Danielle , Biswal Sibani Lisa , Hirasaki George
Published: March 2018

Oil recovery in many carbonate reservoirs is challenging due to unfavorable conditions such as oil-wet surface wettability, high reservoir heterogeneity and high brine salinity. We present the feasibility and injection strategy investigation of ultralow-interfacial-tension (ultralow-IFT) foam in a high temperature (above 80°C), ultra-high formation salinity (above 23% TDS) fractured carbonate reservoir.

Because a salinity gradient is generated between injection sea water (4.2% TDS) and formation brine (23% TDS), a frontal-dilution map was created to simulate frontal displacement processes and thereafter used to optimize surfactant formulations. IFT measurements and bulk foam tests were also conducted to study the salinity gradient effect to ultralow-IFT foam performance. Ultralow-IFT foam injection strategies were investigated through a series of core flood experiments in both homogenous and fractured core systems with initial two-phase saturation. The representative fractured system included a well-defined fracture by splitting core sample lengthwise and controllable initial oil/brine saturation in the matrix by closing the fracture with a rubber sheet at high confining pressure.

The surfactant formulation showed ultra-low IFT (10-2-10-3 mN/m magnitude) at the displacement front and good foamability at under-optimum conditions. Both ultralow-IFT and foamability properties were found to be sensitive to the salinity gradient. Ultralow-IFT foam flooding achieved over 60% incremental oil recovery compared to water flooding in oil-wet fractured systems due to the selective diversion of ultralow-IFT foam. This effect resulted in crossflow near foam front, with surfactant solution (or weak foam) primarily diverted from the fracture into the matrix before the foam front, and oil/high-salinity brine flowed back to the fracture ahead of the front. The crossflow of oil/high-salinity brine from the matrix to the fracture was found to make it challenging for foam propagation in the fractured system by forming Winsor II condition near foam front and hence killing the existing foam.

Results in this work demonstrated the feasibility of ultralow-IFT foam in high temperature, ultra-high salinity fractured carbonate reservoirs and investigated the injection strategy to enhance the low-IFT foam performance. The ultralow-IFT formulation helped mobilize the residual oil for better displacement efficiency. The selective diversion of foam makes it a good candidate as a mobility control agent in fractured system for better sweep efficiency.
Improving the Performance of EOR in Unconventional Oil Reservoirs Using Advanced Completion Technology
Authors: Konopczynski Michael , Dowlatabad Mojtaba Moradi
Published: March 2018

This paper describes the use of advanced completions employing passive inflow control devices (ICD) and autonomous inflow control devices (AICD) in multi-zone horizontal wells to improve the distribution of gas injection and to restrict premature production of gas in gas injection soak EOR process for unconventional oil wells.

The recovery efficiency of unconventional oil reserves is very low due to the micro-permeability of these reservoirs and rapid depletion of pore pressure proximal to the fractures and wellbore. Several enhanced oil recovery schemes have been proposed to stimulate production and increase recovery efficiency in these reservoirs by injecting gas or carbon dioxide in fracture stimulated, long horizontal wells, and either producing oil from adjacent wells (gas injection flooding drive mechanism), or by back-producing the injectant and reservoir fluids in the same wellbore after a suitable "soak" period (huff and puff).

The effective distribution of the injected gas in these wells and the ability to keep the gas in the reservoir to maintain energy can greatly affect the recovery efficiency that can be achieved. Advanced completions utilizing appropriately designed ICDs and AICDs can enhance the performance of these EOR schemes.

ICDs can be used to balance the distribution of gas injection along the length of the wellbore, while AICDs can help control the early back-production of gas. The Autonomous Inflow Control Device (AICD) is an active flow control device that delivers a variable flow restriction in response to the properties (viscosity) of the fluid flowing through it. Water or gas flowing through the device is restricted more than oil. When used in a horizontal well, segmented into multiple compartments, this design prevents excessive production of gas after breakthrough occurs in one or more compartments.

The implementation of advanced completions in EOR applications has been studied by reservoir and well performance simulation. This proper use of ICDs and AICDs in these applications can significantly improve recovery efficiency without further well intervention.

To evaluate the performance of the AICD, a comprehensive multi-phase flow model of the autonomous performance has been developed and workflow created for simulation of performance within the reservoir. This paper will describe the experience with the technology and modelling prediction for EOR projects.
Laboratory Evaluation of Novel Surfactant for Foam Assisted Steam EOR Method to Improve Conformance Control for Field Applications
Authors: Mukherjee Biplab , Patil Pramod D. , Gao Michael , Miao Wenke , Potisek Stephanie , Rozowski Pete
Published: March 2018

Steam injection is a widespread thermal enhanced oil recovery (EOR) method to increase oil mobility. The introduction of steam heats the reservoir, ultimately lowering oil viscosity and in turn enhancing heavy oil recovery. In the steam injection process, recovery of oil is limited by steam channeling due to reservoir heterogeneities. Early breakthrough implies that there is a large consumption of steam and incomplete reservoir drainage. Injection of surfactant with steam and a non-condensable gas such as nitrogen can generate foam in situ. Foam will redirect steam, increase apparent viscosity and reduce steam channeling. Although the technology is promising, it is not always economically attractive due to the large volumes that must be injected continuously, high adsorption of surfactant on reservoir rocks, and limited thermal stability of the surfactant. The opportunity exists to design steam foam surfactant formulations with improved performance at high temperature.

In this paper, a systematic approach to screen surfactants for field applications at high temperature is presented. A feasibility test was conducted with the surfactant formulation (HSF-X) at target reservoir conditions to understand the thermal stability and adsorption behavior of the surfactant. Investigation found that the thermal decomposition and adsorption of the surfactant on sandstone rock under static conditions was mimimum at 200°C. In core flood testing conducted using silica sand and natural sandstone cores, foam generated by injecting N2 and HSF-X surfactant solution was able reduce steam mobility between 40 to 100 times at 100°C and 10 to 15 times at 200°C more compared to steam mobility in the absence of the foam. Finally oil recovery experiments at 200°C using silica sand cores indicated the ability of the HSF-X surfactant to foam in the presence of oil and enhance recovery of oil (a +20% increase in the original oil in place (OOIP) was observed).
A New Way of Compositional Simulation Without Phase Labeling
Authors: Khorsandi Saeid , Li Liwei , Johns Russell T.
Published: March 2018

Current relative permeability models rely on phase labeling, and cannot accurately capture the effect of compositional variations on relative permeabilities and capillary pressures in enhanced oil recovery (EOR) processes. Discontinuities in flux calculations not only cause serious convergence and stability, but also affects the estimated recovery factor. We developed a fully compositional simulation model using an equation of state (EoS) for relative permeabilities to eliminate the unphysical discontinuities in flux functions caused by phase labeling. In addition, we extended our relative permeability EoS to three phases. The model can capture complex hysteresis effects on three-phase relative permeability. The tuned model is used for simulation of multi-cycle WAG injection. The approach allows for a new search scheme to improve initial estimates for flash calculation. The results show increased robustness of high-resolution compositional simulation for both front calculations (recovery estimates) and convergence of flash algorithms.

This paper provides a novel way forward to develop a fully compositional reservoir simulation based solely on continuous and robust equation-of-state relative permeabilities. In addition, this paper provides a detailed analysis of the effects of discontinuous phase labeling on simulation performance and accuracy for 1-D and 2-D water-alternating-gas flooding and three-hydrocarbon-phase flow. The results demonstrate the significant benefits of using an EoS for relative permeabilities.
An Advanced Electrochemical System for EOR Produced Water Desalination and Reduced Polymer Consumption
Authors: Sparrow Ben , Ebsary Adrian , Mandel Derek , Man Malcolm
Published: March 2018

Pilot testing results and economics from a novel electrochemical desalination technology for enhanced oil recovery (EOR) produced water are presented. The pilot objectives were: (1) economically desalt produced water to improve hydrocarbon recovery and lower polymer consumption costs for chemical flood EOR; (2) inform full scale plant development with a field pilot; and (3) optimize pre-filtration, chemical consumption, and energy use to realize a greater than 20% return on investment through reduced polymer consumption.

The paper will present EOR operators with a novel option to reuse produced water as low salinity injection water and recycle polymer to reduce chemical EOR flood operating costs.
Recent Developments in Hybrid Surfactant-Gas EOR Mechanisms with Advanced Modeling
Authors: Lashgari Hamid R. , Taghavifar Mohsen , Pope Gary
Published: March 2018

This paper presents numerical modeling of low tension surfactant gas based EOR method. In this process, slugs of various surfactant solutions and gas are alternated injected to mobilize remained oil left from water flood. The objective of this paper is to model the mechanisms behind the process by history matching the experimental data and simulation of a field-scale reservoir pilot. A four-phase chemical flooding reservoir simulator (UTCHEM) was used to history match a published core flood experiment and simulate a pilot-scale case. The results from the history match reveale that interfacial tension (IFT) reduction between oil and water by surfactant, displacement of oil by gas, and the mobility control of gas are the main mechanims lead to a substantioal increase in oil recovery. Based on these key findings, modeling of the low-tension surfactant-gas flood shows that such a process is very positive for low permeability reservoirs with a 90% oil recovery of the initial oil saturation (Sio=0.56) in a coreflood experiment and a range of recovery factors between 50% to 70% of the water flood in large scale cases.
Mechanistic Study for the Applicability of CO2-EOR in Unconventional Liquids Rich Reservoirs
Authors: Alfarge Dheiaa , Wei Mingzhen , Bai Baojun
Published: March 2018

In shale oil reservoirs, Improved Oil Recovery (IOR) methods are relatively considered as new concepts compared with in conventional oil reservoirs. Different IOR techniques have been investigated by using lab experiments, numerical simulation studies, and limited pilot tests. Unconventional IOR methods include injecting CO2, surfactant, natural gas, and water. However, CO2 injection is the most investigated option due to different reasons. CO2 has lower miscibility pressure with shale oils, and has special properties in its supercritical conditions, and CO2 injection also solves greenhouse problems. In this paper, numerical simulation methods of compositional models were incorporated with LS-LR-DK (logarithmically spaced, locally refined, and dual permeability) reservoir models and Local Grids Refinement (LGR) of hydraulic fractures conditions to investigate the feasibility of CO2 injection in shale oil reservoirs. Different mechanisms for CO2 interactions with organic surface, shale brine, and shale oil were implemented in different scenarios of numerical models. Molecular diffusion mechanisms, adsorption effects, and aqueous solubility effects were simulated in this study. In addition, linear elastic models and stress-dependent correlations were used to consider geomechanics coupling effects on production and injection processes of CO2-EOR in shale oil reservoirs. Some of the results for this simulation study were validated by matching the performance of some CO2 fields’ pilots performed in Bakken formation, in North Dakota and Montana portions.

This study extremely found that some of the CO2-EOR pilot tests have a match with the typical simulated diagnostic plots which have CO2 molecular-diffusion rate that is significantly low. Furthermore, this research indicated that CO2 molecular diffusion mechanism has a clearly positive effect on CO2-EOR in huff-n-puff protocol; however, this mechanism has a relatively negative effect on continuous flooding mode of CO2-EOR. Both of dissolution and adsorption mechanisms have a negative effect on CO2 performance in terms of enhancing oil recovery in unconventional formations. Geomechanics coupling has a clear effect on CO2-EOR performance, and different geomechanics models have a different validity in these shale plays. Stress dependent correlations give the best match with CO2-EOR pilots in Bakken formation while linear elastic models would give the best match in Eagle Ford formation. This study explains the effects of different nano and macro mechanisms on the performance of CO2-EOR in unconventional reservoirs since these plays are much complex and very different from conventional formations. Also, general guidelines have been provided in this study to enhance success of CO2-EOR in these types of reservoirs.
A Continuous and Predictive Viscosity Model Coupled to a Microemulsion Equation-Of-State
Authors: Khodaparast Pooya , Johns Russell T.
Published: March 2018

Surfactant floods can attain high oil recovery if optimum conditions with ultra-low interfacial tensions (IFT) are achieved in the reservoir. A new equation-of-state (EoS) phase behavior model based on the hydrophilic-lipophilic difference (HLD-NAC) has been shown to fit and predict phase behavior data continuously throughout the Winsor I, II, III, and IV regions. The state-of-the-art for viscosity estimation, however, uses empirical non-predictive models based on fits to salinity scans, even though other parameters change, such as the phase number and compositions. In this paper, we develop the first-of-its-kind microemulsion viscosity model that gives continuous viscosity estimates in composition space. This model is coupled to our existing HLD-NAC phase behavior EoS.

The results show that experimentally measured viscosities in all Winsor regions (two and three-phase) are a function of phase composition, temperature, pressure, salinity, and EACN. More specifically, microemulsion viscosities associated with the three-phase invariant point have an "M" shape as formulation variables change, such as from a salinity scan. The location and magnitude of viscosity peaks in the "M" are predicted from two percolation thresholds after tuning to viscosity data. These percolation thresholds as well as other model parameters change linearly with alkane chain length (EACN) and brine salinity. We also show that the minimum viscosity in the "M' shape correlates linearly with alkane chain length (EACN) or viscosity ratio. Other key parameters in the model are also shown to linearly correlate with EACN and brine salinity Based on these correlations, two and three-phase microemulsion viscosities are determined in five-component space (surfactant, two brine, and two oil components) independent of flash calculations. Phase compositions from the EoS flash calculations are input into the viscosity model. Fits to experimental data are excellent, as well as viscosity predictions for salinity scans not used in the fitting process.
An Experimental Study of Enhanced Oil Recovery EOR Using a Green Nano-Suspension
Authors: Wei Bing , Qinzhi Li , Wang Yanyuan , Gao Ke , Pu Wanfen , Sun Lin
Published: March 2018

In this work, a novel nano-suspension (NS), which was mainly composed of a surface functionalized nano-cellulose, was successfully developed for "green" chemical EOR use. The rheological analysis indicated that this NS was a pseudo-plastic (shear-thinning) fluid and presented noticeable viscoelasticity. The oil displacement behaviors of this NS were thoroughly examined using core flooding methods. The EOR efficiency dependence of the NS on permeability, oil viscosity and injected volume was included. The experimental results showed that the NS flooding (NSF) further improved the oil recovery by 3-17% on the basis of water flooding. Furthermore, micro flow tests were conducted in a visual micro-model to study its flow behaviors in porous media and EOR mechanisms. Through the micro-model, the displacement behaviors and mechanisms including emulsification, dragging/squeezing and wettability alteration, were visually observed. These properties promise this NS as a green displacement agent for chemical EOR.
2018 EOR Survey in China-Part 1
Authors: Guo Hu , Dong Jiayu , Wang Zhengbo , Liu Huifeng , Ma Ruicheng , Kong Debing , Wang Fuyong , Xin Xiankang , Li Yiqiang , She Haicheng
Published: March 2018

This paper provides field scale EOR survey in China which is in line with biennial worldwide EOR survey published by Oil& Gas Journal (OGJ). The EOR progress in China is not available due to language difference and other reasons in OGJ EOR survey. From 2018, EOR survey in China will be published biennially. The first part of this survey mainly focuses on basic information. Chemical flooding, unconventional heavy oil, green recovery and natural gas recovery progress in China will be surveyed and discussed in detail in the other four parts elsewhere. The EOR projects including field tests and field applications in China are summarized in the same pattern as OGJ to the largest extent for better readership outside China. Most data is collected from published journal papers and reports. Different from other countries, there are only four major oil companies in China: CNPC, SINOPEC, CNOOC and Yanchang Oil. The 28 branch companies of these four companies are both operator and owners. Oil and gas production from CNOOC is all offshore. CNPC is the largest oil company in China and its oil production in 2016 accounts for 54% oil production in China. EOR survey in China includes chemical flooding (polymer, SP and ASP flooding, gas flooding (CO2, nitrogen and air), thermal production, MEOR, and foam flooding. EOR production in China in 2016 accounts for 18% total oil production, while chemical EOR accounts for 10 %. Up to present, there has been more than 34 ASP flooding projects in China, most in Daqing. The total ASP oil production in 2016 is 407 million tons. More than 30 SP flooding projects have been carried out, with incremental oil recovery factor of 7%-18% OOIP. More than 170 polymer flooding projects have been carried out. Polymer flooding has been used widely in Daqing, Shengli, Xinjiang, Liaohe, He'nan and Bohai. The incremental oil recovery from polymer flooding and ASP flooding is 7%-15% and 18%-30% OOIP respectively. Gas flooding in China is not as successful as chemical EOR. Polymer flooding production in the largest offshore oilfield in CNOOC accounts for 25% total oil production in 2016. While EOR production in China accounts for 15%-18% in recent years, however, the world EOR oil production only accounts for about 3.3% total oil production. EOR is greatly affected by oil price, as indicated from 26 years EOR content change in America. It is the first time that detailed EOR survey in China in line with worldwide EOR survey in OGJ is given. The EOR survey in China provides valuable and helpful information for engineers and researchers in oil and gas industry.
Impact of Miscibility Enhancing Additives on the Flooding Scheme in CO2 EOR Processes
Authors: Rommerskirchen Renke , Bilgili Harun , Fischer Julian , Sottmann Thomas
Published: March 2018

Favorable interactions between injection gas and crude oil are crucial for successful carbon dioxide (CO2) recovery processes. The miscibility behavior and thereby the flooding scheme changes with the pressure applied. Although first contact miscibility (FCM) flooding schemes result in most efficient recovery processes, in many cases multiple contact miscibility (MCM) provides economically viable recovery rates already at lower injection pressure. Thus, the determination of the miscibility pressure is a key step in the lab evaluation for CO2 EOR. Miscibility enhancing additives are able to improve the interactions between CO2 and crude oil leading to reduced miscibility pressure.

This paper illustrates an easily applicable procedure to identify the pressure required for full miscibility. Using a pressure resistant sapphire cell the phase behavior of mixtures of different crude oils and CO2 with and without additives was investigated at common reservoir conditions. The effect of the additives on the physical phase behavior of CO2/crude oil mixtures and the benefit that can be achieved by their application will be discussed.

The miscibility gaps are determined by measuring the phase behavior of CO2/additive/crude oil mixtures as a function of pressure and temperature. The pressure required for full miscibility (physical minimum miscibility pressure (MMPP)), coming along with an FCM scheme, can easily be detected as the pressure above which the miscibility gap closes and a homogeneous mixture is obtained. Another important point, which was determined in this study, was the critical point of the miscibility gap. Its corresponding pressure is the maximum value of the minimum miscibility pressure (MMP) from a thermodynamical viewpoint, above which MCM schemes take place. Hence, knowledge of the critical point of the mixture is an easy to use method to estimate the maximum value of the MMP for a specific reservoir. Adding proper additives to the CO2 improves the miscibility of injection gas and crude oil. By this the miscibility gap shrinks and both the MMP and the MMPP will be reduced significantly compared to the pure CO2/crude oil system.

The method presented is a proper, quick, and low-cost alternative to the time-consuming and expensive slim tube experiments commonly used in the oil industry to measure the MMP. Since at pressures above the MMP an MCM procedure is ensured by physics it is the lowest injection pressure that needs to be applied to ensure miscible CO2 EOR. Reducing the MMP and the MMPP using proper additives can lead to a more economical CO2 flood or can even make reservoirs accessible for this technology, which are naturally not.
Steam Injection in Tight Oil Reservoir
Authors: Ross T. S. , Rahnema H. , Nwachukwu C. , Alebiosu O. , Shabani B.
Published: March 2018

Steam injection—a thermal-based enhanced oil recovery (EOR) process—is used to improve fluid mobility within a reservoir, and it is well known that it yields positive results in heavy-oil reservoirs. In theory, steam injection has the potential of being applied in light-oil reservoirs to enable vaporization of in-situ reservoir fluids, but field developments and scientific studies of this application are sparse. Conventional displacement methods like water-flooding and gas-flooding have been applied to some extent, however, oil extraction in such reservoirs relies on recovery mechanisms like capillary imbibition or gravity drainage to recover oil from the reservoir matrix. Furthermore, low-permeability reservoir rocks are associated with low gravity drainage and high residual oil saturation.

The objective of this study is to evaluate the potential of steam injection for light (47°API) oil extraction in naturally-fractured reservoirs. It is theorized that this method will serve as an effective tool for recovery of light hydrocarbons through naturally-fractured networks with the benefit of heat conduction through the rock matrix. This research investigates the application of light-oil steamflood (LOSF) in naturally- fractured reservoirs (NFR).

A simulation model comprised of a matrix block surrounded by fracture network was used to study oil recovery potential under steam injection. To simulate gravity drainage, steam was injected through a horizontal well completed in the upper section of the fracture network, while the production well was completed at the bottom of the fracture network. The simulation included two different porous media: (1) natural fractures and (2) matrix blocks. Each of these porous media was assumed to be homogeneous and characterized based on typical reservoir properties for carbonate formations. This study also analyzed the impact of different recovery mechanisms during steam injection for a light-oil sample in NFR, with reservoir sensitivity examined, based on varying amounts of vaporization, injection rate, permeability, matrix height and capillary pressure. Of these, vaporization was found to be the dominant factor in the application of LOSF in NFR, as described in detail within the results.
Wettability Alteration and Flow Coupling in Gas Flooding of Asphaltenic Reservoirs
Authors: Abouie Ali , Tagavifar Mohsen , Sepehrnoori Kamy
Published: March 2018

Mixing of an asphaltenic oil with light gases (e.g., CO2) and/or depressurizing such a crude oil can lead to phase separation in which a second liquid phase L2 -highly concentrated in asphaltene- is formed. Asphaltene may precipitate or deposit out of the second liquid phase. This causes formation damage, wettability alteration, and recovery reduction. While asphaltene phase behavior have been studied under static conditions (where equilibrium is imposed), the behavior of asphaltene under dynamic flow conditions is relatively unexplored. Here, we investigate the coupling of asphaltene phase behavior and flow in porous media. As such, two asphaltenic crudes are characterized using the PC-SAFT equation-of- state. The fluid models were then used to fit the experimental asphaltene deposition data under static conditions. Subsequently, asphaltene flow and deposition was studied during miscible gas flooding where four phases (water, oil L1, gas, and second liquid L2) are present. Our results show that (i) wettability alteration increases the mixing zone and decreases both the displacement and sweep efficiencies; (ii) asphaltene deposition, hence wettability alteration and formation damage are maximal near the producer.
Deployment of Large Scale Surfactant Manufacture for EOR Projects
Authors: Barnes J. R. , Regalado D. Perez , Crom L. A. , Doll M. J. , King T. E. , Covin D. Y. , Crawford J. N. , Kunkeler P. J.
Published: March 2018

Surfactant quantities increase dramatically moving from small field tests (e.g. single well tests) to multiwell pilots to full scale EOR projects. This paper is a companion paper to SPE-190453, presented at the SPE conference in Oman in March 2018, and shows how best practices from existing large-scale surfactant manufacture (for household and industrial applications) can be applied and adapted for manufacture and delivery of EOR surfactants as field projects are upscaled.

Surfactant concentrates can be viscous, making them difficult to pump and mix. This paper presents improved methods to manufacture and handle them. In addition, dilution of the concentrate in the field to the working (injected) formulation needs to be carried done in a manner which avoids the formation of viscous phases that are common with surfactants.

The main learnings from this paper are: For small field projects, it is usually advantageous to ship less concentrated products (e.g. ≤ 30% active matter, AM) as, for the small volumes involved, the advantages of ease of mixing and dilution in the field tend to outweigh the cost savings in transporting a highly concentrated product.An additive (viscosity modifier), applied during manufacture, reduces viscosity and improves handleability of highly concentrated products (e.g. ≥ 65% AM). This viscosity modifier is benign for sub-surface performance of the surfactant.For large projects, two strategies can be used to reduce logistics costs: Supply a concentrated product with viscosity modifier (to reduce the percentage of water shipped), and/orManufacture the product (or part of the product) in country/region and near the field.A realistic supply chain was used to estimate the logistics costs to transport low and high %AM products from a USA point of manufacture to an EOR project destination in South America. This calculation assumed an equal manufacturing cost for the low and high %AM products and transportation by 20 ton ISO-tanks, a standard bulk industry container. The transportation cost for the high %AM product is around 57% of the low %AM product. Additional logistics savings are achievable through manufacturing the product (or part of the product) in country/region, and the logistics cost for high %AM product manufactured near the field can be reduced to 33% of of that for the low %AM product manufactured in the USA.

More general learning for EOR projects are: Experience from the wider, bulk chemicals industry can be usefully applied for EOR projects.It is important to align surfactant manufacture/supply logistics with reservoir management and the field life plan as significant lead time is required for supply of large surfactant volumes.