bluuebunny/crossref_metadata_2025_split huggingface dataset:
Identification, Problem Characterization, Solution Design and Execution for a Waterflood Conformance Problem in the Ekofisk Field - Norway
Authors: Aamodt G. , Abbas S. , Arghir D. V. , Frazer L. C. , Mueller D. T. , Pettersen P. , Prosvirnov M. , Smith D. D. , Jespersen T. , Mebratu A. A. 
Published: March 2018

Abstract
This paper discusses a field case review of the processes used to identify, characterize, design and execute a solution for a waterflood conformance problem in the Ekofisk Field that developed in late 2012. The Ekofisk Field is a highly-fractured Maastrichtian chalk reservoir located in the Norwegian sector of the North Sea. Large scale water injection in the field began in 1987 and overall the field has responded well to waterflood operations. However, fault reactivation coupled with extensive natural fractures and rock dissolution has resulted in some challenging conformance issues. In late 2014, a solution was executed to control this problem. Details of the diagnostic efforts and how this data was used to identify, characterize and mitigate an injector/producer connection through a void space conduit (VSC) will be outlined and discussed. These diagnostics include pressure transient analysis (PTA), interwell tracers, injection profiles, seismic mapping, fluid rate analysis, fluid composition and temperature monitoring. The importance of this data analysis is the key element necessary to select an effective solution.
The selected approach involved pumping a large tapered nitrified cement treatment into the offending injector, which is believed to be the single largest nitrified cement operation ever pumped within the oil industry. Because of extremely rapid communication with an offset producer, a protective gel was used to reduce the risk of cement entry into that producer. A brief review of alternative mitigation options and the reasons for selecting the nitrified cement treatment will be discussed. Additionally, a complete review of the shutoff technique, product, damage mitigation strategy, and complications associated with timing and coordination in an offshore environment will also be discussed. Finally, a summary of lessons learned, job execution observations, post-treatment performance results over the past three years, and forward plans will be presented. Based on these results it is believed that there are a number of opportunities to add strong value through conformance engineering.
Underlying Mechanisms of Tight Reservoir Wettability and Its Alteration
Authors: Luo Peng , Li Sheng , Knorr Kelvin D. , Nakutnyy Petro 
Published: March 2018

Abstract
The wettability of tight reservoir rock plays a critical role in affecting relative permeability and in turn oil recovery. However, the link between wettability and its effects on oil recovery remains poorly understood, and the potential to boost oil recovery by varying the wettability has not been fully explored. This work was an attempt to conduct a systematic experimental study to improve our understanding of wettability of tight oil reservoirs and the mechanisms of its alteration on oil recovery improvement. Contact angles of individual rock-forming minerals and reservoir rock samples were first measured in brines with different salinities. Then the minerals were aged separately with a medium crude oil with sufficient polar components to investigate their tendency for wettability alteration. As well, oil and water distributions inside tight core samples were scanned by a synchrotron-based computed tomography scanner. Contact angle measurements for all minerals and reservoir rocks showed initial water-wetting behavior. After aging with crude oil for over two months, polar components from the oil adsorbed onto the solid surfaces to alter their wettability to less water wet. Consequently, this wettability alteration contributed to oil and water redistribution and saturation change in reservoir cores.
The experimental findings suggested that the wettability in tight reservoirs is a strong function of rock mineralogy, formation fluid properties, and saturation history. Preliminary numerical simulation revealed how rock wettability alteration could contribute to improved oil recovery through waterflooding.
Novel Insights into Low Salinity Water Flooding Enhanced Oil Recovery in Sandstone: The Clay Role Study
Authors: Al-Saedi Hasan N. , Brady Patrick V. , Flori Ralph , Heidari Peyman 
Published: March 2018

Abstract
The ever-growing global energy demand and natural decline in oil production from mature oil fields over the last several decades have been the main incentives to search for methods to increase recovery efficiency. This paper quantifies the clay role and the important role of pH in the water flooding of low salinity water in sandstone with and without clays as a function of temperature. Four chromatography columns containing different amounts of sand, illite, and kaolinite (100% sand; 5% Illite, 95% sand; 5% kaolinite, 95% sand; 2.5% Illite, 2.5% kaolinite, 95% sand) were water flooded with various salinities at four different temperatures 25, 70, 90 and 120 °C. Effluent concentrations of Ca2+ and CH3COO−, and pH were measured. The system was pre-aged for a week at 70 °C with 0.01 molar (M) sodium acetate to simulate the bonding of oil-bound carboxylic acids with the reservoir. Desorption of carboxylic groups from reservoir clay surfaces is thought to be an important control over low salinity EOR water injection and its extent should depend on pH. To quantify the impact of the presence of the clay, a clay-free sample was also used, the acetate release and Ca2+ desorption were in some cases higher than those observed in non-clay free samples. Typically, cores with higher clay content saw a great rise in pH, but the clay-free samples also saw a rise in pH, as great as that of the clay-containing cores.
Novel Surfactants without Hydrocarbon Chains for Chemical EOR
Authors: Sharma Himanshu , Panthi Krishna , Ghosh Pinaki , Weerasooriya Upali , Mohanty Kishore 
Published: March 2018

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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 &lt;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

Abstract
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 (&gt; 200 g/L TDS) and temperature (&gt; 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

Abstract
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

Abstract
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.