bluuebunny/crossref_metadata_2025_split huggingface dataset:
Geochemical Impact on Rock Wettability in Injection of High-Concentration Formate Solution for Enhanced Geologic Carbon Storage and Oil Recovery
Authors: Oyenowo Oluwafemi Precious , Wang Hao , Okuno Ryosuke , Mirzaei-Paiaman Abouzar , Sheng Kai 
Published: June 2023

Abstract
Aqueous formate (FM) solution has been studied for geologic carbon storage, in which highly concentrated FM solution as carbon-bearing water is injected into the target formation. The literature shows that aqueous FM solution may cause geochemical interactions with carbonate rocks, but no experimental data exist for high-concentration FM solutions. This paper presents a new set of data focused on core-scale wettability alteration of carbonate porous media with varying FM concentration (up to 30 wt%) in NaCl brine. Experimental data from Amott wettability tests and core floods with limestone cores were analyzed to mechanistically understand the wettability alteration observed in the experiments.
Static calcite dissolution tests showed that the degree of calcite dissolution increased with increasing FM concentration in the NaCl brine even with the initially neutral pH. For example, the calcium concentration in the 30-wt% FM case was 15.9 times greater than that in the NaCl brine case with the initial pH of 7.0. Furthermore, reducing the initial solution pH from 7.0 to 6.1 for the 30-wt% FM solution caused the calcium ion concentration to increase by a factor of 3.2. Geochemical modeling indicated that the increased calcite dissolution could be caused by the formation of calcium FM complexes that reduced the activity coefficient of the calcium ion and therefore, drove the calcite dissolution.
The 30-wt% FM solution with the initial pH of 6.1 yielded 4.7 times greater oil recovery than the NaCl brine case in the spontaneous imbibition. The resulting Amott index clearly indicated the wettability alteration to a water-wet state by the FM solution. The 30-wt% FM solution with the initial pH of 7.0 yielded only 30% greater oil recovery than the brine case in the spontaneous imbibition; however, it reached nearly the same amount of total oil recovery (spontaneous and forced) with the 30-wt% FM solution with the initial pH of 6.1. This is likely because the in-situ solution pH could be sufficiently lower than the calcite isoelectric point consistently during the forced imbibition, unlike under the static conditions during the spontaneous imbibition.
Increasing the FM concentration in the injection brine (pH 7.0) delayed the water breakthrough in core floods. Numerical history matching of the core flooding data showed that increasing the FM concentration in the injection brine rendered the initially oil-wet core to a more water-wet state as quantified by Lak and modified Lak wettability indices. Results in this research collectively suggest the importance of in-situ solution pH in wettability alteration by aqueous FM solution in carbonate media, in order to cause the rock surface to be positively charged in the presence of FM and calcium ions.
Fate and Transport of Sulfonated Polymeric Inhibitors in the Reservoir: Studied by Column Experiments With Calcite Media
Authors: Yao Xuanzhu , Wang Xin , Ko Saebom , Leschied Cianna , Shen Yu. Yi , Pimentel Daniel , Navarathna Chanaka , Ye Yuqing , Reiss Amit , Kan Amy T. , Tomson Mason B. 
Published: June 2023

Abstract
Sulfonated polymers are frequently used in the oil and gas industry to prevent inorganic scale damage, but studying their fate and transport in reservoirs has been difficult due to the challenges in analyzing them at effective concentrations. Recycling inhibitors in reservoirs necessitates inhibitors that do not adhere strongly to mineral surfaces, making polymeric inhibitors a promising option. This research aims to examine the sorption and transport of sulfonated polymeric inhibitors in calcite-packed columns using the Brine Chemistry Inhibitor (BCIn) technique, with the goal of recycling the inhibitors, specifically in the Permian basin.
The BCIn method was used in this study to determine concentrations of sulfonated inhibitors, which had been shown to be reliable for measuring polymeric inhibitors at near ppm levels. The study began with conducting batch experiments on barite and calcite salts to gain initial insights into the adsorption properties of inhibitors. Next, flow-through experiments were performed where sulfonated inhibitors were injected into a column packed with calcite, followed by a flow-back test. Different sulfonated polymeric inhibitors were tested under various temperatures in the lab’s synthetic brine matrices. The concentrations of sulfonates versus injected time were plotted to assess the retention of inhibitors on rock surfaces. A commonly used phosphonate scale inhibitor (DTPMP) was included for comparison of adsorption characteristics.
The experimental findings suggest that sulfonated polymeric inhibitors exhibit limited adsorption capacity but strong binding between inhibitor molecules and mineral surfaces. An inhibitor treatment scenario is proposed, where the first injection is used to saturate the surfaces of rocks, and subsequently, produced water containing low-concentration inhibitors can be recycled.
The research expands our understanding of sulfonated polymeric scale inhibitors’ fate and transport in reservoirs, overcoming the challenge of analyzing polymeric inhibitors at low concentrations. The results provide evidence supporting the potential of applying polymeric inhibitors via injection wells for safeguarding production.
A Novel AMD Nanosheet and Surfactant Synergy System to Increase Oil Production under Harsh Reservoir Conditions
Authors: Cao Dongqing , Han Ming , Fahmi Mohanad , Alsofi Abdulkareem 
Published: June 2023

Abstract
Amphiphilic molybdenum disulfide (AMD) nanosheet is a novel flake type nanomaterial for increasing oil production. It shows unique behaviors on oil/water interface as the flake nature compared with particulate nanomaterials. However, nanosheet solution in high salinity water at elevated temperature had poor compatibility, which limited the applications at harsh reservoir conditions. An improved nanosheet system synergetic with a cationic surfactant was developed and showed good compatibility improvement at 95°C and salinity as high as 57,670 mg/L. The interfacial tension (IFT) of the developed nanosheet and surfactant system with crude oil was not ultra-low, but it showed excellent interfacial activities in emulsification tests and phase behavior tests even at low concentrations. Nanosheet produced much stable emulsion than surfactant. Mixing nanosheet and surfactant increased emulsion stability. The hydrophilic and lipophilic balance of the nanosheet and surfactant system could be controlled by surfactant concentration. Winsor III type microemulsion was formed at nanosheet/surfactant concentration ratio of 1:2 to 1:8. For the performance in porous media, the surfactant component reduced the retention of nanosheet and decreased the plugging to the cores. Corelfooding tests in limestone and carbonate cores demonstrated the good incremental oil production performance of the nanosheet and surfactant system at 95 °C. Both oil bank at early stage of nanosheet injection and a long-lasted emulsified oil contributed to the oil production. The oil production performance of nanosheet/surfactant system was affected by both concentration and concentration ratio of the two components. A 50 mg/L nanosheet and 2000 mg/L surfactant formulation showed highest oil production after waterflooding compared with other combinations.
Demystifying Amine Inhibitor Chemistry
Authors: Khramov Dimitri , Panamarathupalayam Balakrishnan , Barmatov Evgeny 
Published: June 2023

Abstract
Amine shale inhibitors are an integral part of high-performance water based mud (HP WBM). There are many commercially available amines with similar claims regarding performance as shale inhibitors. Most performance comparisons are made relative to KCl-polymer muds, making the shale inhibitor differences very apparent. Unfortunately, a comparison between several good-performing inhibitors is rarely performed and reported. There are few systematic comparisons of amine shale inhibitors with each other based on their structure and conditions under which testing is performed. The relationship between amine structure and performance as an inhibitor is not well understood. This paper presents design of an experimental methodology to compare the effectiveness of 30+ amines as shale inhibitors under a broad range of testing conditions. Shale hydration, dispersion, and bulk hardness were measured after exposure to drilling fluids to determine which test parameter can most efficiently distinguish amines. Additionally, the adsorption or desorption of amines from a clay were measured to determine which amine is the strongest absorber. Statistical data treatment was applied to separate signal from the noise of measurements. The results of this investigation verified that amine inhibitors do not affect shale moisture content and shale dispersion is primarily affected by fluid viscosity. Furthermore, a bulk hardness test that measures cuttings hardness is a good differentiator of amine inhibitors. Supplementary functioning for amine inhibitors was confirmed with adsorption or desorption test that showed good correlation with a bulk hardness test. In summary, these measurements established a structure-activity relationship between the amines tested and determined that an effective shale inhibitor should contain more than 1 nitrogen atom/molecule. Additionally, linear structure is preferred over branched structure, and supplementary hydrophobic amines function better than hydrophilic amines provided the amine remains water soluble. Amines were further differentiated by their acid-base dissociation constant (pKa). The reason some amines perform in broader pH range than others is also presented. For the first time, a statistically validated study has been conducted to assess the results of different tests and to compare the effectiveness of different shale inhibitors. The results of these comparisons provided a way to understand the shale inhibition mechanism and develop better practices focused on developing next-generation aqueous fluid systems.
Successfully Optimizing Performance of Friction-Reducer Boosters for Slickwater and High-Viscosity Fluids
Authors: Kitchen Jarrett , Kakadjian Sarkis , Vu John , Hundt Nadia , Qin Qicon 
Published: June 2023

Abstract
Polyacrylamide-based friction reducers (FRs) and high-viscosity friction reducers (HVFRs) are designed to reduce friction losses in tubulars and improve proppant placement. Low-cost anionic FRs are suitable, and are often the standard, in mild-salinity environments. However, to perform in high-salinity environments, anionic FRs require one of the following: 1) an increase in polymer activity/concentration/molecular weight, or 2) the introduction of sulfonated/cationic monomers. This study presents the screening process of commercial boosters used to improve the performance of low-cost conventional FRs and HVFRs.
Conducted at room temperature, as well as the various bottomhole temperature conditions encountered in the Permian, Bakken, Haynesville and Eagle Ford shale plays, the study is designed to investigate the boosters’ effects on the performance on FRs, whether these FRs are in liquid or dry form, by introducing different nonionic or charged surfactant species. The study presents impact on drag reduction, yield viscosity and viscosity at different sweeps (including the ultralow shear rates encountered in the fractures). Further, the study tests viscoelasticity and creep behavior; this is to determine if the friction-reduction effect is due to faster dispersion or to improved hydration due to changes to colloidal distribution.
Impact of FR boosters is limited by the makeup of the boosters, as well as the delivery form of the FRs or HVFRs. The study team observed that, when conventional anionic FRs are delivered in the invert emulsion form, proppant transport properties improve with the addition of specific nonionic- and/or cationic-based surfactants.
Unlike traditional methods used to predict the impact on the performance of FR boosters, this new testing methodology more effectively predicts the impact of small tweaks in the booster's molecular structure, which reduced pumping pressure in this study by approximately 500 psi.
A Coupled Model of Phosphonate Scale Inhibitor Interactions with Carbonate Formations
Authors: Kalantari Meybodi Mahdi , Sorbie Ken S. , Vazquez Oscar , Jarrahian Khosro , Mackay Eric J. 
Published: June 2023

Abstract
In this study, a chemical model has been developed for the simulation of the scale inhibitor (SI) interactions with carbonate systems (calcite), where the aqueous phase may contain free calcium and magnesium ions. The resulting model couples together the equations of (i) the carbonate system, (ii) the speciation of the SI, modelled as a weak polyacid, HnA, (iii) the metal (Ca2+, Mg2+) binding – SI chelant interactions and (iv) the subsequent precipitation of SI-Ca-Mg complex. These reactions are considered in conjunction with the charge balance and mass balances for calcium, magnesium, scale inhibitor and "carbon" (i.e. the carbonate system aqeous components HCO3-, CO32- and CO2 and solid CaCO3). This full equation set, with suitable reduction, results in a system of 3 non-linear equations which can be solved by the Newton-Raphson method to find the final equilibrium state of the system.
The experimental results for the DETPMP/Calcite/Ca-Mg brine system from a previous study were used to check the reliability of the proposed model. The model calculates the equilibrium concentrations of all species (SI, Ca2+, Mg2+, HCO3-, CO32-, CO2, H+, and the components of the SI-Ca-Mg complexes etc.) based on their initial values and reaction constants, i.e. equilibrium constants, stability constants and solubility constants. The model can be applied either assuming a closed chemical system, or an open system and simuilation conditions were chosen in order to match the actual experiments which were matched. The model results show good quantitative agreement with the experimental results, although some assumptions must be made on the system input constants. To elucidate the precise effects that these various parameters are having in this very complex coupled system, an extensive sensitivity analysis was performed. This is especially important for uncertain parameters like stability constants of the complexes of scale inhibitor with calcium and magnesium, which are not reported in the literature.
In future, this model be coupled with the adsorption model (based on the isothermal adsorption curve) and the coupled model will be incorporated into a transport model to develop a complete coupled adsorption/precipitation squeeze treatments simulation model. To our knowledge, no such model currently exists.
The Impact of EOR Polymers on the Adsorption of Phosphonate Scale Inhibitors
Authors: Silva Célia , Beteta Alan , McIver Katherine , Sorbie Ken 
Published: June 2023

Abstract
Enhanced oil recovery (EOR) is critical to optimally produce existing reserves with a minimised carbon footprint. However, it is essential that the EOR process does not impact ongoing production chemistry treatments. Here, the focus is placed on the interactions between EOR polymers and scale inhibitors in terms of adsorption. The adsorption of both EOR polymer and scale inhibitor is assessed using static adsorption tests to understand and analyse the competitive adsorption between the two species. The study also clarifies some features of the adsorption kinetics of the EOR polymer used in this study, HPAM (partially hydrolysed poly acrylamide).
Static adsorption bottle tests were performed under conditions of fixed pH and mass/volume ratio (m/V); m = mass of substrate and V = volume of solution. In these experiments, HPAM and DETPMP were used as the polymer and as the scale inhibitor, respectively. The adsorption levels of HPAM and DETPMP were tested under a range of conditions, viz. adsorption was measured separately, in combination initially (at t = 0), and in sequential addition experiments (at t = t1). A series of experiments was carried out to construct the HPAM adsorption isotherm in order to have a better understanding of the results. All tests were conducted at 70°C as this is the typical upper temperature at which HPAM would be applied in the field and is a common mid-range temperature at which DETPMP would be used.
The main experiments were conducted for 72 hours with sampling every 24 hours. For the same concentration in North Sea seawater, it was possible to observe that the adsorption was constant over time for the DETPMP (i.e. at equilibrium). However, over this period the HPAM adsorption values increased with time indicating that the system was not at equilibrium. In combination experiments, HPAM appears to have a lower adsorption in the presence of DETPMP – or is kinetically retarded by DETPMP – regardless of the order in which the chemicals are combined. In order to better understand these observations, a detailed kinetic study of HPAM was performed, which showed that adsorption equilibrium was only reached after about 14 days.
This study suggests, that (i) competitive adsorption between DETPMP and HPAM can result in reduced HPAM adsorption (and possible kinetic modification), and (ii) that the adsorption of HPAM occurs kinetically slowly in terms of well production time scales. These results are amongst the first observations of this type in the literature, and they highlight the need for the industry to develop a better understanding of the competitive interactions between scale inhibitor treatments and EOR polymers. The implications of our experimental findings for field applications is highlighted in this paper.
Novel Environmentally Responsible Solvents for Sulfur Removal in Oil and Gas Applications
Authors: Ekoue-Kovi Kekeli , Murugesan Sankaran , Ugono Onome , Pinappu Sai , Weers Jerry 
Published: June 2023

Abstract
The removal of unreactive or non-acidic sulfur species to meet fuel specifications remains a challenge in the oil and gas industry. This is especially the case with the recent introduction of IMO 2020 restrictions in the use of marine fuels to those that have sulfur contents from 3.5% down to 0.5%. This has led refiners to seek alternative sulfur removal technologies that can be used in addition to the conventional desulfurization process. Formulations of cyclic organic carbonates (COCs) were developed in combinations with environmentally friendly lactones and glycol ethers and are shown to facilitate the removal of unreactive organosulfur compounds such as thiophenes, disulfides and mercaptans. This study utilizes different sulfur-containing hydrocarbon streams consisting of crude oil, heavy hydrocarbon (fuel oil), lighter hydrocarbon, naphtha from various refineries and field operations. Model hydrocarbon blends were prepared by dosing with different sulfur compounds and analyzed for sulfur removal efficiency using COC formulations. The use of sulfur containing heavy hydrocarbons from the field were also assessed to demonstrated that the sulfur removal was applicable to a wide range of hydrocarbons. Furthermore, a process for the recovery and reuse of solvent was developed to extend the lifetime of the solvent and reduce the cost of operations. The regenerated solvent shows extended efficiency and the process for its regeneration, recycle and reuse offers many advantages. The newly developed solvent formulation showed enhanced performance over caustic or other specialty chemistries by 30-100% depending on the nature of the sulfur species.
Use of Mutual Solvents to Improve Injectivity Prior to and During Waterflooding
Authors: Jordan Myles , Mackay Eric James , Al Hajri Ahmed 
Published: June 2023

Abstract
While Mutual Solvents have been widely used to improve contact surface area between rock and chemicals applied for scale inhibition or acid stimulation purposes during squeeze treatments, the literature does not identify study of their impact on injectivity enhancement for water injection wells.
This paper examines the impact of using solvents prior to water injection to displace otherwise residual oil from the near injector formation, and thereby improve injectivity while under matrix injection conditions. The work described includes both experimental studies - evaluating mutual solvents in sandstone core floods - and near-wellbore modelling to demonstrate the benefit and to explore the impact of chemical concentration and volume.
Experiments involved measuring effective brine permeability before and after application of a mutual solvent solution, vs water injection only, into cores at initial water saturation at both reservoir and room temperature.
A radial reactive transport model was used in which interpolation between relative permeability functions is dependent on the concentration of the solvent, as well as on salinity and temperature. The model also accounts for the impact of injection rate on the balance between viscous and capillary forces in the very near well formation. Sensitivity to solvent concentration, solvent volume, and the implication of application temperature for this waxy crude oil were investigated.
The consequence of mutual solvent injection is that the aqueous phase injected thereafter would have access to greater pore volume (oil saturation in core will be below normally defined Sor), and hence the effective permeability to the aqueous phase would be increased. Measurements identified 98% removal of oil at reservoir temperature with mutual solvent vs only 17% improvement in brine permeability with seawater alone. For the room temperature coreflood, emulating cooling of the near wellbore with water injection, the recovery of brine permeability was again better for the mutual solvent treatment.
Similarly, the modelling study identified that for a given injection pressure limit and under the reservoir conditions assumed, a 2.5 ft slug of 20% mutual solvent in water would improve injection rate within the first year of injection by over 11% leading to an incremental volume of water injected of over 1.26 MMstb.
This study highlights the potential for a simple chemical treatment to improve waterflood injection performance while under matrix flow conditions, with ensuing economic and environmental benefits of greater injection capacity without drilling additional wells.