bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Novel Epoxy Resin Composition as a Lost Circulation Material: Formulation, Lab Testing and Field Execution
Authors: Alanqari Khawlah , Wagle Vikrant , Al-Yami Abdullah , Mohammed Ali 
Published: November 2021

Abstract
The novel resin composition described in this paper has been designed to treat moderate to severe losses. The resin composition comprises an epoxy resin and a chemical activator that undergo a polymerization reaction without any addition of water. The polymerization was designed to delay and successfully controlled to gel up and form the target resin composition after the fluid goes inside the wellbore. This is very important to avoid early setting of the fluid. The objective of this paper is to discuss the formulation of epoxy resin as a lost circulation material and also detail the lab testing and field execution.
In this study, we used two different epoxy resins to study the development of the novel loss circulation material. One contains two epoxy groups and the other contains only one epoxy group. Two different chemical activators have been used in this study as well; each of them differs in the number of amine groups and geometry. The effect of these differences on the polymerization in terms of time and properties were investigated. In addition, the effect of the chemical activator concertation on the setting time of the resin composition was investigated to accomplish a controlled and a delayed polymerization. Also, the chemical conditions were evaluated to simulate a variety of downhole conditions to prove the effectiveness of this novel resin composition as a loss circulation treatment. The lab testing includes thickening time measurements.
The novel resin composition is designed to have a controlled thickening time under a variety of downhole conditions. This is important to have an accurate placement of the fluid inside the wellbore; thus, avoiding an early setting of the fluid. We found that the thickening time of the resin composition can be controlled by mainly varying the concertation of the chemical activator. We found as well that changing the type of epoxy resin or chemical activator produce different gelling time and properties. We designed the loss circulation composition to provide a predictable and controlled pumping time. This novel resin composition can remain in a liquid phase from a few minutes to several hours based on the desired conditions. This is favorable in order to have an accurate placement of the fluid inside the wellbore over a predictable and controlled period of time. The final and target resin composition, will appear and gel as a solid thereby preventing loss circulation.
The resin was pumped from the BHA in a single stage which helped mitigate and reduce the dynamic losses from 260 bbl./hr. to 200 bbl./hr. using only 25 bbls and eventually to zero.
Screening Friction Reducer Performance Using Zeta Potential
Authors: Ayazi Philip , Peregoy Nathan , Monreal Gabriel , Zamora Frank 
Published: November 2021

Abstract
Friction reducers (FRs) are essential additives for water used in hydraulic fracturing treatments for shale reservoirs. These polymers swell and unfurl in the frac water so that polymer chains align along the direction of flow to inhibit turbulence thereby reducing friction at high flow rates. Source water ion content, application pH, and compatibility with the formation are key drivers in deciding which FR chemistries are fit-for-purpose for the operation, balancing desired fluid performance with treatment economics. This investigation explores zeta potential measurement as a novel and meaningful analytical metric to correlate chemical and rheological properties of FRs in a range of source water qualities with their friction reducing performance. The approach of this investigation involves measuring zeta potential of frac fluids formulated using anionic or cationic FRs in waters with varying ionic activity over a range of FR concentrations and pH. The evaluation encompasses a variety of FRs spanning general purpose materials to more sophisticated additives designed to function in fluids with higher concentrations of salt. Dry FR materials as well as corresponding slurry or emulsion forms of the additives are tested. Monovalent and divalent salts and mixtures thereof are used in brine formulations. FR characterization is performed including rheological sweeps, viscoelasticity measurements, and flow loop tests. Results from this study support the conclusion that zeta potential measurement can be used during the FR screening process as a viable supplement to industry standard tests for assessing FR performance in brine.
Modeling Acid Fracturing Treatments in Heterogeneous Carbonate Reservoirs
Authors: Dong Rencheng , Wheeler Mary F. , Su Hang , Ma Kang 
Published: November 2021

Abstract
The goal of acid fracturing operations is to create enough fracture roughness through non-uniform acid etching on fracture surfaces such that the acid fracture can keep open and sustain a high enough acid fracture conductivity under the formation closure stress. A detailed description of the rough acid-fracture surfaces is required for accurately predicting the acid-fracture conductivity. In this paper, a 3D acid transport model was developed to compute the geometry of acid fracture for acid fracturing treatments. The developed model couples the acid fluid flow, reactive transport and rock dissolution in the fracture. We also included acid viscous fingering in our model since the viscous fingering mechanism is commonly applied in acid fracturing to achieve non-uniform acid etching.
Carbonate reservoirs mainly consists of calcite and dolomite minerals but the mineral distribution can be quite heterogeneous. Based on the developed model, we analyzed the effect of mineral heterogeneity on the acid etching process. We compared the acid etching patterns in different carbonate reservoirs with different spatial distributions of calcite and dolomite minerals. We found that thin acid-etched channels can form in carbonate reservoirs with interbedded dolomite layers. When the reservoir heterogeneity does not favor growing thin acid-etched channels, we investigated how to utilize the acid viscous fingering technique to achieve the channeling etching pattern in such reservoirs. Through numerical simulations, we found that thin acid-etched channels can form inside acid viscous fingers. The regions between viscous fingers are left less etched and act as barriers to separate acid-etched channels. In acid fracturing treatments with viscous fingering, the etching pattern is largely dependent on the perforation spacing. With a proper perforation design, we can still achieve the channeling etching pattern even when the reservoir does not have interbedded dolomite layers.
Chemical Flooding in Western Canada – Successes and Operational Challenges
Authors: Renouf G. , Bolton G. , Nakutnyy P. 
Published: November 2021

Abstract
Over the last 30 years, chemical flooding of oil reservoirs has been broadly adopted as a technique for enhanced and incremental oil recovery around the world. Western Canadian oil producers have embraced polymer flooding to recover heavy oil, but have applied other forms of chemical flooding more sparingly. This study examines 31 chemical floods - ASP, AP, SP, alkali, and nanosurfactant floods - from mostly heavy oil fields (20 heavy oil, 10 medium oil, and one light oil). The success of the chemical floods was related to over forty reservoir and operating parameters, including water quality. We also discuss the operational challenges common in western Canada.
Chemical flooding projects were identified through searches of government documents. Production and injection data were gathered using Accumap software; and reservoir and operating parameters were gathered from government documents and literature. Incremental recovery was calculated by performing decline curve analysis of the waterflooding production. The incremental recovery was the difference between the actual production during chemical flooding, and the predicted production had waterflooding continued rather than shifting to chemical flooding. Multivariate analysis was used to determine the most important parameters to the success of the chemical floods.
The incremental recoveries ranged from 0 to 22% of original oil-in-place (OOIP), or 0 to 44% of OOIP per pore volume. Twenty-three of the 31 floods improved their water-oil ratios (WOR) after the start of chemical flooding. Water quality was a significant issue to the success of the chemical floods, leading to problems that were not anticipated in the planning and development stages. Some case histories are discussed to better illustrate the best practices for chemical recovery of heavy and medium oils. Water sources, management, treatment and chemistry all pose significant challenges that are often not fully assessed before starting the chemical flood projects. The review highlights challenges common to chemical flooding of heavy oil, and discusses common effects experienced as a result of water and chemistry compromises.
Water-Based Nanofluid-Alternating-CO2 Injection for Enhancing Heavy Oil Recovery: Underlying Mechanisms that Influence its Efficiency
Authors: Cao Changxiao , Song Zhaojie , Su Shan , Tang Zihan , Xie Zehui , Chang Xuya 
Published: November 2021

Abstract
The efficiency of CO2 water-alternating-gas (WAG) flooding is highly limited in low-permeability heavy oil reservoirs due to the viscosifying action of W/O emulsification and high mobility contrast between oil and CO2. Here we propose a new enhanced oil recovery (EOR) process which involves water-based nanofluid-alternating-CO2 (NWAG) injection, and investigate the synergistic effect of nanofluid and CO2 for enhancing heavy oil recovery. Firstly, the oil-nanofluid and oil-water emulsions were prepared, and the bulk rheology and interfacial properties of emulsion fluid were tested. Then, core flooding tests were conducted to examine the NWAG flooding efficiency and its underlying mechanisms. The results showed that the bulk viscosity and viscoelasticity of oil-nanofluid emulsion reported much lower than those of oil-water emulsion, and nanofluid presented a positive contribution to the phase inversion from W/O to O/W emulsification. Compared with oil-water emulsion, the interfacial storage modulus of oil-nanofluid emulsion was obviously increased, which confirmed that more of crude oil heavy components with surface activity (e.g., resin and asphaltene) were adsorbed on interfacial film with the addition of silica nanoparticles (NPs). However, the interfacial viscosity of oil-nanofluid emulsion was much lower than that of oil-water emulsion, showing the irregularity of interfacial adsorption. This implied that the self-assembly structure of crude oil heavy component of the oil-water interface was destroyed due to the surface activity of silica NPs. During the core flooding experiments, NWAG injection could reduce the displacement pressure by 57.14% and increase oil recovery by 23.31% compared to WAG injection. By comparing produced-oil components after WAG and NWAG injection, we found that more of crude oil light components were extracted by CO2 during NWAG flooding, showing that the interaction between CO2 and crude oil was improved after oil-nanofluid emulsification. These findings clearly indicated two main EOR mechanisms of NWAG injection. One was the phase inversion during the nanofluid flooding process. The addition of silica NPs promoted phase-inversion emulsification and thus improved the displacement efficiency. The other was the enhanced interaction between CO2 and crude oil after oil-nanofluid emulsification. Because of the enhanced adsorption of crude oil heavy component on the oil-water interface, the proportion of light hydrocarbon increased in the bulk phase, and so the interaction between CO2 and oil phase was improved. This work could provide a new insight into the high-efficiency exploitation of low-permeability heavy oil reservoirs.
Ranking Anti-Agglomerant Efficiency for Gas Hydrates Through Molecular Dynamic Simulations
Authors: Mohr Stephan , Hoevelmann Felix , Wylde Jonathan , Schelero Natascha , Sarria Juan , Purkayastha Nirupam , Ward Zachary , Navarro Acero Pablo , Michalis Vasileios K. 
Published: November 2021

Abstract
Computational and experimental methods were employed to assess the capacity of four surfactant molecules to inhibit the agglomeration of sII hydrate particles. Using both steered and non-steered Molecular Dynamics (MD), the coalescence process of a hydrate slab and a water droplet, both covered with surfactant molecules, was computationally simulated. The experimental assessment was based on rocking cell measurements, determining the minimum effective dose necessary to inhibit agglomeration. Overall, the performance ranking obtained by the simulations and the experimental measurements agreed very well. Moreover, the simulations gave additional insights that are not directly accessible via experiments, such as an analysis of the mass density profiles or the orientations of the surfactant tails. The possibility to perform systematic computational high-throughput screenings of many molecules allows an efficient funnel approach for molecular optimization and customization.
Facile Fabrication of Nanoemulsions through the Efficient Catanionic Surfactants for Spontaneous Imbibition in Tight Oil Reservoirs: Experimental and Numerical Simulation
Authors: Wei Bing , Mao Runxue , Tang Haoran , Wang Lele , Wang Dianlin , Wang Yiwen , You Junyu , Lu Jun 
Published: November 2021

Abstract
Spontaneous imbibition (SI) is an essential method for accelerating mass exchange between fracture and matrix in tight oil reservoirs. However, conventional systems such as brine and surfactant solution have limited imbibition effects, so there is still abundant remaining oil in the matrix. Nanoemulsion holds the most promising potential in improving tight oil recovery owing to the favorable surface activity and nanoscale droplets, but it still lacks economic and facile methods to fabricate nanoemulsions. Therefore, in this paper, we prepared a kind of O/W nanoemulsion of catanionic surfactants with a low dosage of surfactant and energy consumption, which was then used to assess spontaneous imbibition performance in Changqing outcrop cores by experimental and numerical simulation. We have fully considered the possible imbibition mechanisms of nanoemulsion including wettability alteration, IFT reduction, solubilization and emulsification, etc., and successfully applied to the nanoemulsion imbibition model. The model and experimental data were found to be in good agreement. The results showed that the imbibition rate and oil recovery factor of the nanoemulsion in the first 100 hours are lower than that of brine. In the late stage, we observed a longer equilibrium time and a faster and higher oil imbibition process in nanoemulsion with ultralow IFT. Finally, we confirmed that solubilization and emulsification is one of the domiant mechanisms for nanoemulsion imbibition by comparing with the modelling without considering solubilization and emulsification.
Research on the Relationship Between Crude Oil Composition and Asp Flooding Effect
Authors: Sun Zhe , Kang Xiaodong , Zhang Shanshan 
Published: November 2021

Abstract
In recent years, ASP flooding has been widely applied and obtained the remarkable effect. During the ASP flooding process, the oil composition has a great effect on the interfacial tension, which plays a vital role in the oil displacement effect. However, through literature research, few have made a profound study on the effect of oil composition on the recover rate. As a result, it is very important to carry out relevant research.
For the oil sample (I) and sample (II) from two different regions in DQ, the crude oil composition analysis is first carried out. After the mixing of oil system and ASP system, the distribution ratio of agent is obtained. Furthermore, the oil composition does have an impact on the interfacial tension and recovery rate, and its influence law is explored. Finally, its application is introduced and analyzed.
Research results show that, compare with sample (II), the sample (I) has more heavy components. After the mixing of oil samples and ASP, more surfactant and alkali enters into the oil phase of sample (I). Therefore, based on the similar miscibility principle, the surfactant is more likely to leave the oil water interface and enter into the oil phase of sample (I), which has a negative effect on reducing the interfacial tension. Furthermore, the phenomenon of chromatographic separation aggravates the adsorption of surfactant on rock surface. Therefore, combining the above factors, the oil increment effect of sample (I) becomes worse. In additional, the results of field test verify the laboratory experiments.
From the above research, we canconclude that the relationship between crude oil composition and ASP flooding is of great significance. As a result, this paper has carried out a lot of related research work and revealed the internal relationship between the two, which has important practical significance to improve the effect of increasing oil and reducing water in ASP flooding technology.
Development of Fluorescence Tagged Scale Inhibitors for Squeeze Applications in Gulf of Mexico
Authors: Liu Ya , Lee Dong , Lu Haiping , Russek Jeffrey 
Published: November 2021

Abstract
Fluorescence tagged (F-tagged) scale inhibitors are drawing more interest in the oil industry and are being applied in the field. One main reason is being easily detectable and differentiable from other scale inhibitors. However, when applied to a new oilfield, it is necessary to evaluate their thermal stability, limit of detection (LOD), and fluorescence measurement interference from other chemicals. Two F-tagged scale inhibitors were tested in this study. They are the same polymeric inhibitors with different and differentiable fluorescent tags. Both F-tagged inhibitors were able to be detected in synthetic brine and field brine from a Gulf of Mexico (GoM) field, with LOD of 1ppm. A coreflood test was also conducted for inhibitor squeeze treatment evaluation. The residual scale inhibitor in core flooding samples was measured by both fluorescence method and high performance liquid chromatography (HPLC). The results from two methods generally match with each other. This strongly indicates that the F-tag is stable on scale inhibitors and fluorescence measurement is a reliable method for scale inhibitor detection. Thermal aging test and long storage test were conducted. For both F-tagged scale inhibitors, the thermal aged samples and samples with different storage lifetime did not show significant difference on scale inhibition performance and fluorescence measurement. The two F-tagged inhibitors tested can tolerate high temperature up to at least 130°C (266°F). With proper storage, F-tagged inhibitors after long shelf storage were still as effective as fresh inhibitors. Based on all the test results in this paper, these two scale inhibitors are ready for squeeze application in GoM.
How Does EOR Polymer Impact Scale Control During ASP Flooding?
Authors: Liu Ya , Vilain Rebecca , Shen Dong 
Published: November 2021

Abstract
Polymer based enhanced oil recovery (EOR) technology has drawn more and more attention in the oil and gas industry. The impacts of EOR polymer on scale formation and control are not well known yet. This research investigated the impacts of EOR polymer on calcite scale formation with and without the presence of scale inhibitors. Seven different types of scale inhibitors were tested, including four different phosphonate inhibitors and three different polymeric inhibitors. Test brines included severe and moderate calcite scaling brines. The severe calcite brine is to simulate alkaline surfactant polymer (ASP) flooding conditions with high pH and high carbonate concentration. The test method used was the 24 hours static bottle test. Visual observation and the residual calcium (Ca2+) concentration determination were conducted after bottle test finished. It was found that EOR polymer can serve as a scale inhibitor in moderate calcite scaling brines, although the required dosage was significantly higher than common scale inhibitors. Strong synergistic effects were observed between EOR polymer and phosphonate scale inhibitors on calcite control, which can significantly reduce scale inhibitor dosage and provides a solution for calcite control in ASP flooding. The impact of EOR polymer on polymeric scale inhibitors varied depending on polymer types. Antagonism was observed between EOR polymer and sulfonated copolymer inhibitor, while there was weak synergism between EOR polymer and acrylic copolymer inhibitors. Therefore, when selecting scale inhibitors for polymer flooding wells in the future, the impact of EOR polymer on scale inhibitor performance should be considered.
Long-term Strategy Optimization of Scale Squeeze Treatment in a Carbonate Reservoir Under CO2-WAG Water-Alternating-Gas Injection
Authors: Azari Vahid , Rodrigues Hydra , Suieshova Alina , Vazquez Oscar , Mackay Eric 
Published: November 2021

Abstract
The objective of this study is to design a series of squeeze treatments for 20 years of production of a Brazilian pre-salt carbonate reservoir analogue, minimizing the cost of scale inhibition strategy. CO2-WAG (Water-Alternating-Gas) injection is implemented in the reservoir to increase oil recovery, but it may also increase the risk of scale deposition.
Dissolution of CaCO3 as a consequence of pH decrease during the CO2 injection may result in a higher risk of calcium carbonate precipitation in the production system. The deposits may occur at any location from production bottom-hole to surface facilities. Squeeze treatment is thought to be the most efficient technique to prevent CaCO3 deposition in this reservoir. Therefore, the optimum WAG design for a quarter 5-spot model, with the maximum Net Present Value (NPV) and CO2 storage volume identified from a reservoir optimization process, was considered as the basis for optimizing the squeeze treatment strategy, and the results were compared with those for a base-case waterflooding scenario. Gradient Descent algorithm was used to identify the optimum squeeze lifetime duration for the total lifecycle. The main objective of squeeze strategy optimization is to identify the frequency and lifetime of treatments, resulting in the lowest possible expenditure to achieve water protection over the well's lifecycle.
The simulation results for the WAG case showed that the scale window elongates over the last 10 years of production after water breakthrough in the production well. Different squeeze target lifetimes, ranging from 0.5 to 6 million bbl of produced water were considered to optimize the lifetime duration. The optimum squeeze lifetime was identified as being 2 million bbl of protected water, which was implemented for the subsequent squeeze treatments. Based on the water production rate and saturation ratio over time, the optimum chemical deployment plan was calculated. The optimization results showed that seven squeeze treatments were needed to protect the production well in the WAG scenario, while ten treatments were necessary in the waterflooding case, due to the higher water rate in the production window.
The novelty of this approach is the ability to optimize a series of squeeze treatment designs for a long-term production period. It adds valuable information at the Front-End Engineering and Design (FEED) stage in a field, where scale control may have a significant impact on the field's economic viability.