bluuebunny/crossref_metadata_2025_split huggingface dataset:
Supercritical Carbon Dioxide Foam Performance for Enhanced Oil Recovery: Challenges and Solutions
Authors: Abdelaal Ahmed , Alsabaa Ahmed , Gajbhiye Rahul , Mahmoud Mohamed , Al-Shehri Dhafer , Patil Shirish 
Published: June 2023

Abstract
Foam enhanced oil recovery (EOR) techniques commonly use N2 and CO2 gases. Previous studies have compared the foam generated by these two gases, and it has been found that CO2 becomes weaker and less stable at its supercritical conditions, reducing its effectiveness in creating stable foam. In contrast, N2 forms stronger foam at these conditions. Limited research has investigated the use of a CO2/N2 mixture foam in bulk media. It was found that adding N2 to CO2 has shown potential in producing more stable foam in oil-free porous media. This article reviews the advantages and disadvantages of CO2 foam and potential methods of improving its use in oil production. In addition, the performance of mixed CO2/N2 foam in crude oil-saturated sandstone cores was studied and compared to pure CO2 foam, with optimization of total injection rate, CO2/N2 ratio, and foam quality to achieve maximum oil recovery and stable foam. Results showed that the mixed foam gave a higher recovery than the CO2 foam. The addition of N2 to CO2 improved foam stability and enhanced oil recovery up to a 20 % by volume N2, but beyond this range, oil recovery was adversely affected. Increasing foam quality up to 80% produced a finer-textured foam, improving stability and recovery, but beyond 90%, the foam becomes coarser and less stable, likely due to the formation of dry foam. Increasing the injection rate affected stability of foam and recovery of oil, as higher rates of injection produced high shearing rates that may cause collapse of foam. The study suggested useful outcomes for addressing supercritical CO2 foam instability in sandstone reservoirs and advancing understanding in the developing area of foam behavior research.
An Innovative and Sustainable Portland Cement Alternative for Oil and Gas Wells
Authors: Yakovlev Andrey , Lafitte Valerie , Kapoor Saurabh , Meade Mark , Smith William , Fischer Nathan , Parton Chris , Richter McDonald Veronica , Nenjerama Yeukayi , Wei Xia , Landry Geoff 
Published: June 2023

Abstract
The manufacturing process of oilfield cement is one of the largest contributors to carbon emissions. Thus, finding sustainable alternative materials has become the main focus globally. Geopolymers are low carbon cement alternatives that have been used in the construction industry for many years, yet their applicability for oil and gas wells remains unproven.
For geopolymers to be successfully implemented in the oilfield industry, a customization of the formulation is critical to eliminate logistical constraints and ensure compatibility with oilfield pumping equipment. Geopolymers are typically prepared with liquid alkaline activators, which render them impractical for onshore applications due to the complicated logistics of transporting liquids to a wellsite. Dry blending of the various components and handling constraints is an important condition for field use.
A comprehensive lab study of geopolymer activator and functional additives was conducted. In the end, unique chemistries were identified that are compatible with dry blending and continuous live mixing for field application. A key focus was given to achieving parameters needed from operations, and compliance perceptive, and those which are comparable to the oilfield cements currently in use. Introducing an innovative geopolymer solid activator package enables mixing and pumping of geopolymer slurries without any modification of the current equipment or the job execution method and eliminate the need to handle corrosive liquids. After extensive lab studies, mixability, and pumpability of the newly designed geopolymer system was validated via yard trials.
The current work has opened new avenues to make geopolymers adaptable to cementing land equipment while meeting the requirements needed to sustain performance under well conditions. This is a step change toward field deployment of a sustainable well integrity technology.
Long Interval Chemical Consolidation of Failing Clay Laden Formations: A Departure from Epoxy-Based Resins
Authors: Recio Antonio , Benoit Denise N , Sanders Michael W , Nguyen Philip D 
Published: June 2023

Abstract
Thermally-activated, single-component resin formulations in which the catalyst is included in the resin composition can be challenging to place over intervals longer than 30 feet (9.1 meters). Despite the proven consolidation performance observed with epoxy-based systems, initial viscosity and rapid reactivity leading to short placement times have resulted in the industry seeking alternative chemistries to enhance formation integrity. Herein we report the development of a 2-stage formation consolidation system entailing a hetero-aromatic-based resin composition that, once placed downhole, will only begin curing with subsequent introduction of an activation fluid. The latent property of the updated resin formulation allows for extended lateral applications, and incorporating a new surface modifying agent allows for the treatment of formations with an excess of 20% wt—clay mineralogy.
Calcite Scale Mitigation in a Very Low Watercut, Low Salinity, HPHT Environment: Lessons Learned in Surveillance, Mitigation and Scale Inhibitor Performance Monitoring for an Onshore Field
Authors: Wylde Jonathan J. , Thornton Alexander R. 
Published: June 2023

Abstract
This prolific field has enjoyed mineral scale free production for many years but has lately experienced a series of unexpected (and harsh!) calcium carbonate scaling events. Well watercuts are barely measurable yet mineral scale deposits accumulate rapidly within wellhead chokes and flowlines. This paper describes the scaling experience and the challenges of mitigation in an extraordinarily low water cut environment.
A detailed analysis of the scaling experience is presented: plant layout, scaling locations, scale surveillance and monitoring programs, laboratory testing, product selection and implementation, and scale inhibitor efficacy surveillance and monitoring programs (and details will be provided on each of these topics). The surveillance and application techniques for scale inhibitor deserve mention as very important lessons were learned for low water cut scenarios. For instance, a heavily diluted scale inhibitor was necessary to be effective and the detailed laboratory and field implementation process is described that led to this key lesson learned.
Laboratory testing for chemical selection was performed using classical techniques and identified a polymeric scale inhibitor suitable for the scaling scenario. This is reported in detail, however what could not be tested easily in the laboratory was the effect of &lt;1% water cut and how the product would perform in that environment. A risk managed field surveillance program was initiated to determine field efficiency of the polymer, and involved trialing the chemical on a single well pad using temporary installation of a restricted orifice plate (ROP) to help modify the scale inhibitor residence time (and impact of product dilution) for dispersibility and optimum inhibitor action. The lessons learned from this trial were subsequently rolled-out field wide with very positive results.
This paper demonstrates a unique scale formation and control situation that utilized a previously unreported and analytical surveillance approach. The cumulative performance derived by improving not only chemical selection, but the way the wells were managed via surveillance and chemical management decision making processes is compelling and of value to other production chemists working in the scaling arena.
Multi-Functional Flow Assurance Inhibitors : Three Birds With One Stone?
Authors: Kelland Malcolm A. , Pomicpic Janronel 
Published: June 2023

Abstract
Due to the presence of produced water, several fouling problems such as gas hydrates and scale, as well as corrosion can occur in unprocessed subsea production flow lines. Several treatment chemicals often need to be injected simultaneously at the well head into these flow lines. Among them are hydrate, scale, and corrosion inhibitors. However, some combinations of these chemicals can be antagonistic. We have investigated the possibility to combine all three properties into one molecule. We used kinetic hydrate inhibitor (KHI) polymers as the developmental starting point for use in cold flow lines with low to medium gas hydrate subcooling potential. We focussed on maleic-based polymers as they offer a low cost - high performance solution with great flexibility to also incorporate functionality for scale and corrosion inhibition. A set of low molecular weight maleic homo- and copolymers were synthesized and synergists added to improve the CO2 corrosion inhibition performance. The KHI performance was determined in high pressure steel rocking cells, scale calcite inhibition in static jar and dynamic tube blocking test equipment and sweet corrosion inhibition in a CO2 bubble test cell. The difficulties of achieving the "triple", three different inhibitors in one molecule, will be highlighted.
Effect of Hydrophobic/Hydrophilic Groups of Surfactants on Wax Deposition Studied by Model Waxy Oil System
Authors: Bian Yu , Chiang Pinn-Tsong 
Published: June 2023

Abstract
It is well known that surfactants can be used as a wax dispersant, however, with properly adjusted ratios between the hydrophobic and hydrophilic groups of non-ionic surfactants, they can not only reduce the waxy oil pour point, but also reduce the detected wax appearance temperature (DWAT) and thus reduce wax deposition. Non-ionic surfactants with different numbers of hydrophobic/hydrophilic groups were studied as wax inhibitors using a model waxy oil system.
Two model oils with different amounts and distribution of wax in dodecane were used in this study. High temperature gas chromatography (HTGC) was used to analyze the wax distributions. Surfactants with varying levels of ethoxylation and saturation were studied to find the most efficient structures for wax inhibition. A pour point tester was employed as an initial screening tool to determine the oil pour point and DWAT. A Turbiscan was used to evaluate the wax dispersing capabilities of the surfactants. Capillary flow through (CFT) wax deposition tests were then performed to verify the wax deposition reduction efficiency and to study the effect of the test parameters on wax deposition.
The results showed that a surfactant with a moderate number of linear saturated alkane chains at an optimized dosage level can interact with the wax in dodecane, and thus reduce the pour point and DWAT. More alkane chains make the surfactants perform as a wax inhibitor (WI) but cause the solubility issues. Hydrophilic groups on the surfactants improve their solubility and interfere with the formation of wax crystals; however, having too many results in the surfactant self-assembling. The interaction between surfactants and wax changes with wax molecular weight (MW) and content. By optimizing the balance of hydrophobic and hydrophilic groups, the surfactant's wax inhibition performance can be improved.
From this systematic study on the kinetic and dynamic behaviors of wax deposition, it was demonstrated that surfactants can be optimized to inhibit wax crystallization. By better understanding the relationship between their chemical structures and their performance, surfactant selection can be optimized with purpose-designed lab screening tests. Surfactants which are effective at wax inhibition could further mitigate wax deposition and keep the formulated WI package cost effective.
Injectivity Aid Qualification to Field Application for Produced Water Reinjection. A North Sea Case Study
Authors: Jordan Myles Martin , Bennett Brian , Mokogwu Ike 
Published: June 2023

Abstract
Produced water re-injection (PWRI) for maintaining reservoir pressure and sweeping hydrocarbon towards production wells uses water separated from the produced fluids at the surface facilities which is then re-injected into the same (or possibly alternative) hydrocarbon bearing formations. In addition to the environmental benefits of PWRI, there are other potential benefits including making cost, space and weight savings through the optimization of water treatment facilities and produced water re-injection systems throughout the life of a field.
Many factors influence produced water re-injection well performance. In this paper production chemistries are examined that when applied can improve PWRI effectiveness by reducing the known negative impact of the following:
impact of oil in water (increasing pore saturation, binding carried over solids) back pressure induced by fractional drag within injection lines/near wellbore
The paper focuses on laboratory evaluations leading to field applications within a North Sea field where an operator had a history of injectivity decline in 4 wells believed to be taking produced water under matrix flow conditions.
This paper will share the steps taken that resulted in the initial recommendation to address the reduced injectivity; Specifically, how the chemical options were evaluated via coreflood studies on reservoir core with field crude oil and synthetic produced water that led to the application of a batch treatment of mutual solvent and organic acid treatments to the three wells. Following the batch treatment, the production declined over time. Evaluation was then carried out to determine if continual injection of a chemical could be applied to reduce the near wellbore oil saturation and modify interfacial tension (IFT) such that the enhancement in injectivity could be maintained.
Chemicals with a known ability to impact oil/water interfacial tension were evaluated via IFT measurement studies leading to coreflood evaluation to determine what improvement in brine permeability could be expected to be observed in a field application. The chemistry that showed the lowest effective treatment rate at 10's of ppm vs percent levels of mutual solvent was a formulation of corrosion inhibitor and non THPS iron sulfide dissolver. This product offered multiple benefits of corrosion control, reduced IFT leading to oil mobilization and relative permeability modification of the sandstone minerals such that brine permeability increased by 150% with a dose of 25 to 50ppm product applied to the produced water.
Application of remediation programs via continual injection of correctly selected production chemicals that impact reservoir wettability present an opportunity for significant savings in terms of chemical cost/production downtime over batch cleaning chemical applications.
Detection of Four Discretely Tagged Scale Inhibitors in a Single Produced Water
Authors: Russek Jeffrey , Leontieff Andre , Barclay-Dunbar Michelle , Pupponen Salla , Sihvonen Stina , Honkanen Tapio , Griffin Rick , Hay Ian 
Published: June 2023

Abstract
Accurately monitoring scale inhibitor (SI) residuals, following a squeeze treatment, is an important part of scale management. Where multiple wells are co-produced into a single flowline, identifying the scale inhibitor residuals from each well using conventional approaches may not be possible. This work demonstrates that through the application of discretely tagged Sulphonated Co-polymer (VS-Co) scale inhibitors, detection of residuals, from four individual wells, can be made within a single produced water.
The use of tags is a field proven method to monitor the residual of VS-Co, following squeeze treatment. This concept is further expanded to the theoretical deployment of four tagged SI's, simulated by preparing a field brine with 1 Phosphorus (P)-tagged SI and 3 Fluorescent (F)-tagged SI's. Each F-tag emits light / fluoresces at a unique wavelength which allows detection via traditional fluorescence techniques. The detection of the P-tag is achieved via ICP-MS. Field residual monitoring data from 2 comingled wells produced into a topside system will be provided.
The tagged SI's were all detected to very low levels in the field brine, in the presence of Iron. The scale inhibition performance of the four products towards barium sulfate scaling was assessed by dynamic scale loop and demonstrated that fluorescence and phosphorous tagging does not impact the SI's performance. Field data will be presented demonstrating the value of the tagged scale inhibitors bring to help risk manage downhole scaling and validating the detection methodology for multiple (2) wells. Further lab works clearly demonstrates that the detection of the 4 tagged inhibitors is now possible in produced brine.
The ability to detect multiple SIs at low concentrations in a single fluid allows for more effective scale management. The ability to monitor and detect inhibitor concentrations to low minimum effective concentration (MEC) in co-mingled fluids will help to better manage risk and produce better data to help extend scale squeeze lifetimes thus lowering operational costs and maximizing production rates.
Protecting the Reservoir from Diminishing Productivity Caused by Downhole Biofilm Growth in Shale Plays
Authors: Wunch Kenneth , Silva Veronica 
Published: June 2023

Abstract
Hydraulic fracturing of shale in unconventional oil & gas recovery is accomplished through the addition of large volumes of water and biodegradable additives to reservoirs, creating environments conducive for microbial contamination. Contamination of reservoirs by sulfate reducing organisms often leads to biogenic souring, the biological production of hydrogen sulfide (H2S), which devalues crude, corrodes metallic assets via microbially influenced corrosion (MIC), and creates dangerous health and safety conditions for field personnel (Ferrar et al. 2021). Often overlooked is the impact of this downhole contamination on formation damage and hydrocarbon recovery.
Microbes introduced into a hydraulically fracked reservoir form biofilms by attaching to the rock or proppant surfaces and secreting a lipopolysaccharide "gel" that protects the microbial colony. These biopolymers are dynamic and have the potential to effect reservoir permeability and conductivity in tight shales. Furthermore, biofouling can impact the reservoir pore mineral cementation via biomineralization and the production of iron sulfide scale. Bottero et al. (2010) modelled formation damage and the impact on gas flow caused by biofilms growing within proppant packs of hydraulically fractured reservoirs. They concluded that in the presence of 10% biofilm volume, the gas production flow rates were reduced by half and that the biofilm growth on proppants affected the gas flow rate due to the differential change in the medium tortuosity and flow patterns.
Evaluation of Long-Term Scale Control for Shale and Tight Assets with Presence of Formation Rock
Authors: Yan Chao , Wang Wei , Wei Wei 
Published: June 2023

Abstract
Buildup of inorganic scales in O&G fields can cause significant production loss due to clogged near-wellbore formation and constrained production tubing. For Shale and Tight (S&T) assets, the damage in downhole formations can be rapid and permanent since the nanoscale pores cannot be recovered once filled with scale deposits such as barite. Production loss due to scale deposition can be up to 90% of total production compared to analog wells. Scale inhibitors (SI) are ideally used for scale control at nucleation and growth stages before its deposition. They can perform very differently depending upon application conditions, target scale types, treatment duration, treatment type, adsorption behavior, etc.
Bottle tests are utilized to screen SI for various scale types and risk at selected conditions (up to 10 weeks) and to select best candidates. Adsorption studies (up to 12 weeks) were performed on the chosen chemicals to understand temporal change of SI residue concentration after contacting with formation rock during test period. In addition, a scale dissolver performance was evaluated for barite scale under different temperature and soaking times for scale remediation.
Two phosphonate-based SI outperformed five other SI products in screening tests and were selected for adsorption studies. Formation rock samples from two wells which experienced production loss were mixed with SI treated fluid. SI residual continuously decreased in the first 2 days for all dosages between 50 ppm and 500 ppm. After 30 days, only ∼28% of added SI adsorbed on rock surfaces at 50 ppm. However, ∼50% adsorption of added SI was observed at 100, 250 and 500 ppm. For 250 ppm dosage, adsorption reached equilibrium in 7 days after which there was not a significant change in SI residual concentration. Performance of the tested scale dissolver improved when temperature and soaking time was increased, dissolving up to 82.6 Wt.% of barite mass. Correlation between temperature and dissolved Wt.% was generated to estimate performance at various temperatures.
This study's SI adsorption results show that SI residual concentration at equilibrium is typically 30-50% of initial dosed SI. The results help improve our understanding of the interaction between chemicals and rock to better tune their dosage for long term scale control at subsurface. Scale dissolver results validated its performance and provided potential field application opportunities for scale remediation.
Novel High Salinity and High Temperature Tolerant Surfactant-Based Fluids for Mitigation of Water Entrapment in Dry Gas Formations
Authors: He Kai , Tran Trinh , Moradi Mehrnoosh , Balsamo Vittoria 
Published: June 2023

Abstract
For hydraulic fracturing of low permeability dry gas formation, capillary discontinuity at the matrix-fracture interface and fluid entrapment in the hydraulic and natural fractures can impact the effective fracture half-length and thus result in loss of fracture conductivity. Adding surfactant-based novel fluids can reduce the capillary trapping of fluids by lowering the surface tension and modifying wettability to less water-wet condition and thereby improve the relative gas permeability and well productivity. In this work, a novel surfactant-based fluid was developed to be effective in reducing water entrapment. The surfactant formulation was evaluated in various reservoir conditions including Eagle Ford, Permian, Duvernay, Kansas St. Louis, and Bakken. The new formulation showed excellent stability under harsh reservoir conditions up to 150 °C and 27% TDS. Additionally, a laboratory workflow was developed to evaluate the efficiency of surfactant formulations in the mitigation of water entrapment using two-phase coreflood (CF). Our results show that three formulations (A, B and C) reduce the surface tension comparably. However, in the liquid recovery test using CF, formulations B and C outperformed A, resulting in much higher recovery of the aqueous fluid compared to the control case of formation brine. Wash-off tests were further performed by flushing the cores with fresh brine after treatment with novel formulations. The core treated with formulation C outperformed B after 5 pore volume (PV) flush of brine. Notably, for the core treated with formulation C, even after flushing with 140 PV of brine, the fluid recovery is still much higher compared to the brine case without treatment. Interestingly, formulation C performs even better in the harsh reservoir condition with high salinity brine, which can be explained by the three different adsorption patterns governing the interaction energy between surfactant and rock surface. This work demonstrates that tailoring fluid-rock interactions is crucial to reduce the water entrapment and thereby improve gas productivity for dry gas wells. Our workflow provides a comprehensive process to understand the mechanisms behind water entrapment and how to tailor novel formulations to reduce water entrapment in dry gas wells.