bluuebunny/crossref_metadata_2025 huggingface dataset:
Pengembangan Modul Pembelajaran Fisika Berbasis Kearifan Lokal Pada Materi Suhu dan Kalor
Authors: Safitri Azizah Nur , Sarwanto Sarwanto , Harjunowibowo Dewanto
Published: June 2023

The purpose of this research is to find out the characteristics of local wisdom-based physics learning modules on Temperature and Heat material, and to find out the feasibility of local wisdom-based physics learning modules on Temperature and Heat material so that it can be continued at the next test stage. The research method, namely Research & Development (R&D), uses the ADDIE instructional development model. In carrying out its development, the researcher carried out the first to third stages of the five development stages including the stages of analysis, design and development. The data sources included 2 experts, 2 reviewers, 10 students and 128 students who assessed the module from the material, media and language aspects. Referring to the results of the research and development of the module, the following conclusions are obtained: (1) the characteristics of the module being developed, printed modules that raise the phenomenon of local wisdom in the environment around students, are equipped with identification of initial abilities, descriptions of material, assignments, sample questions, and evaluations are then developed according to the nature of the module, namely self-instruction, self-contained, stand-alone, adaptive and user friendly; The physics module based on local wisdom on temperature and heat material is expected to make it easier for students to study physics material. This local wisdom-based physics learning module presents a description of the material as well as student activity sheets which are expected to make it easier for students both individually and in groups when formulating the concept of Temperature and Heat. (2) the feasibility value of the module has a very good category referring to expert validation with an average value of 93.2; reviewer validation gets an average value of 97.8; student validation obtained an average value of 97.8; the one-to-one trial obtained an average score of 93.8; small-scale trials 90.5; and field trials get an average value of 86.8.
MATHEMATICS-BASED TEACHING MODEL AND INSTRUCTORS’ FINANCIAL ACCOUNTING PERFORMANCE: AN EXPERIMENTAL STUDY
Authors:   Universitas Gadjah Mada, Warsono Sony , Rohma Frida Fanani ,   Universitas Trunojoyo Madura, Pranesti Arin ,   Universitas Negeri Yogyakarta, Rumiyati Rumiyati ,   Universitas Gadjah Mada
Published: June 2023

Double entry bookkeeping (DEB) and the rules of debit and credit (RDC) are first contained in a mathematical book. Using this basic premise, this study develops a mathematics-based teaching model (MBTM) and examines its impact on instructors’ financial accounting performance. This study employed a quasi-experimental method with 43 accounting instructors as participants. The findings indicate that the implementation of the MBTM resulted in a significant improvement in instructors' performance. Furthermore, the teaching experience had a positive effect on instructor performance, particularly when combined with the MBTM approach. Previous empirical research has aimed to compare traditional (preparer) and innovative (user) teaching approaches for the introductory accounting course. In line with this objective, the present empirical study introduces the MBTM as an innovative teaching model and assesses its effectiveness. This study is the first of its kind to implement the innovative mathematics-based teaching model (MBTM) specifically designed based on the history of accounting. It is worth noting that the study also utilized accounting instructors as research subjects, a less commonly employed approach in previous research endeavors.
Research on the Characteristics of Acoustic Emission Activities of Granite and Marble under Different Loading Methods
Authors: Sun Yongshuai , Yu Fei , Lv Jianguo
Published: June 2023

At present, there is no corresponding standard for the engineering application of rock acoustic emission technology. To better apply acoustic emission technology to engineering practice, in this paper, the acoustic emission characteristics of different rock samples of marble and granite under uniaxial compression were analyzed by indoor acoustic emission test, the factors affecting the acoustic emission characteristics of rocks are studied, and the failure mechanism and damage characteristics of rock are discussed. The research contents include analyzing the curve fitting relationship between the acoustic emission event rate, the number of events, the stress time, and study of the similarities and differences of acoustic emission characteristics of marble and granite; analysis of damage characteristics of marble and granite based on acoustic emission parameters; by analyzing the relationship between the Felicity ratio of different rocks and the stress level during cyclic loading, the applicability of studying the Kaiser and Felicity effects of rocks; variation of acoustic emission event rate and rock peak intensity under different loading methods and loading rates. The results show that the acoustic emission of marble and granite has experienced the initial compaction zone, the rising zone, the peak zone, and the falling zone, and the two kinds of rocks have different acoustic emission phenomena in different stages, and the duration of each stage is also different; before the instability of the two kinds of rocks, there is a quiet period of acoustic emission, and the higher the rock strength, the longer the duration of this quiet period, which means that the calm period can be used as a precursor feature of rock mass instability for disaster prediction; during the cyclic loading process of rock, the damage development law is divided into three stages: initial stage, stable stage, and instability stage. When the Kaiser effect did not appear for the two rock stresses before 20%, between 20% and 70% of the peak strength, the Kaiser effect is obvious. When the stress exceeds 80% of the peak value, the Kaiser effect fails, and the Felicity effect appears; the variation of the loading rate affects the variation of the acoustic emission event rate, and the increase of the loading rate leads to aggravated rock damage. The theoretical stress-strain curve can reasonably reflect the actual stress-strain characteristics of rock by combining the number of acoustic emission events with the rock damage model. The results are consistent with the acoustic emission test, which verifies the inevitable relationship between acoustic emission and damage to the rock.
Economía social y desarrollo territorial en Chefchaouen (Marruecos): el papel de las cooperativas en el marco de la Iniciativa Nacional para el Desarrollo Humano
Authors: Laghdas Mohamed , Cejudo García Eugenio , Navarro Valverde Francisco Antonio
Published: June 2023

Se estudia la significación de las cooperativas en el desarrollo territorial de la provincia de Chefchaouen Marruecos, a partir de las actuaciones ligadas a la Iniciativa Nacional para el Desarrollo Humano (INDH) entre 2011–2018. Se utiliza tanto metodología cuantitativa, para analizar variables como el número de cooperativas, proyectos implementados, inversión realizada o subvención recibida o su distribución territorial, como cualitativa a través de la información obtenida de 12 entrevistas en profundidad realizadas sobre el terreno. Los resultados cuantitativos muestran la escasez de cooperativas y de proyectos subvencionados, así como su concentración en las comunas más dinámicas, quedando marginados los territorios más pobres. Las respuestas de los entrevistados revelan la importancia de estas ayudas tanto para llevar a cabo los proyectos como para mejorar su competitividad. Otros aspectos relevantes son, entre otros, la identificación de los obstáculos y las limitaciones que aún persisten impidiendo el desarrollo del tejido cooperativo. Se concluye que la zona de estudio no se ha beneficiado suficientemente de estas ayudas por la falta de acompañamiento y dinamización de las diferentes instituciones, proponiéndose la creación, a nivel provincial, de oficinas de desarrollo y cooperación con los recursos humanos y logísticos necesarios para ello.
Investigating the Feasibility of Reusing Lower Salinity Produced Water for Waterflooding of Carbonate Reservoirs Containing Hypersaline In-Situ Brine-A Study Using Field Samples
Authors: Tetteh Joel T , Barati Ghahfarokhi Reza , Thompson Stanley , Pham Anthony , Hutchison Justin M , Peltier Edward
Published: June 2023

Synthetically prepared low-salinity brines are usually used for mechanistic and improved oil recovery studies in carbonate rocks. However, in actual onshore field applications, using nearby produced water with low or seawater-like salinities could potentially yield optimized waterflooding economics. In this work, field samples from Central Kansas Uplift oil production formations were acquired and tested for the potential increase in oil production from mature oil reservoirs. Geochemical compatibility testing of fluid-fluid interaction between the hypersaline produced water (PW-1) from Lansing Kansas City reservoir and seawater-like produced water (PW-2) from the Arbuckle formation showed no evidence of potential scale formation. Furthermore, seawater-like PW-2 altered the limestone rock wettability represented by lowering the contact angle from 148° (oil-wet) for PW-1 to 119° (intermediate wet) for PW-2. Wettability alteration was further supported by the Amott-Harvey index. At the oil-brine interface, equilibrium interfacial tension slightly increased from 8.35 mN/m2 for PW-1 to 10.87 mN/m2 for PW-2. However, the surface elasticity was calculated to increase from 43.3 mN/m2 to 74.8 mN/m2 for hypersaline PW-1 and seawater-like PW-2, respectively, indicating better stability at the oil-brine interface, which could reduce crude oil snap-off and improve sweep efficiency. Approximately 6.7% incremental recovery due to the injection of seawater-like PW-2 was observed in the secondary mode. Therefore, the use of geochemically compatible seawater-like produced water with carbonate rocks hosting hyper-saline water could improve oil recovery by altering the rock wettability and suppressing crude oil snap-off, hence serving as a viable economic option for mature oilfields.
Carbonate and Sulfide Mixed Scale: Corrosion, Prediction and Control
Authors: Wang Xin , Li Wei , Ye Yuqing , Navarathna Chanaka , Reiss Amit , Yao Xuanzhu , Leschied Cianna , Shen Yu-Yi Roy , Pimentel Daniel , Kan Amy , Tomson Mason
Published: June 2023

Sulfide and carbonate mixed scales are ubiquitous in oilfield production and injection system with low corrosion resistant carbon steel equipment and pipeline. Previously, such conditions were generally treated as a corrosion problem rather than a scale problem, and the interactions between steel corrosion and mineral scale formation remain unclear. In this study, the iron sulfide and iron carbonate mixed scaling and corrosion behaviors were investigated simultaneously under simulated produced water environments. The influence of carbonate to sulfide ratios and calcium concentration in the brine was investigated. It was found that the iron sulfide (FeS) scale was always formed on the mild steel surface under various brine compositions due to the fast kinetics of the sulfide scale precipitation and sour corrosion. While with the presence of calcium, the carbonate scale was easier to form, and this carbonate scale layer would be crucial to promoting calcium carbonate deposition. The iron carbonate (FeCO3) precipitation kinetics was a diffusion-controlled reaction that can be accelerated by higher temperature and calcium concentrations. The conventional scale inhibition and corrosion inhibition methods were also tested. The combination of scale inhibitor, corrosion inhibitor, and dispersant chemical combos successfully prevents the deposition formation on the mild steel surface and significantly reduces the corrosion rate. This study demonstrated the complicated interaction between the sulfide and carbonate scale and also bridged the scale and corrosion, which could help to develop a better scale and corrosion control strategy under complicated field conditions.
A Novel Star Polymer based Fluid Loss Control Additive for Non-Aqueous Drilling Fluids
Authors: Jian Guoqing , Santra Ashok , Patel Hasmukh A. , Atilgan Ahmet
Published: June 2023

Non-aqueous fluids (NAF) are considered as efficient and reliable drilling fluid systems for challenging wellbore conditions, such as high-temperature drilling operations. NAFs require fluid loss control additives to reduce filtration loss into the formation with minimum filter cake thickness. Polymer developed in this work demonstrated exceptional properties such as high dispersibility, good thermal stability and low plastic viscosity, when compared with traditional natural and synthetic-based fluid loss control additives (e.g., gilsonite).

We have utilized a synthetic molecular optimization process to precisely adjust the hydrophilic-lyophilic balance (HLB) by altering the ratio of hydrophilic to hydrophobic monomers. This has allowed us to achieve an HLB that facilitates easy dispersion within NAF formulations. The star polymer was produced using a controlled/radical polymerization technique called Reversible Addition Fragmentation Chain Transfer polymerization (RAFT). The properties of the NAFs, such as rheology, fluid loss, mud cake thickness, and emulsion stability, were evaluated and compared with commercially available fluid loss control additives under simulated downhole pressure and temperature conditions. The chemical structure and thermal stability of the star polymer were analyzed using spectroscopy and thermogravimetric analysis.

The spectroscopic studies confirmed the formation of desired polymeric structures and the molecular weight desired. Star-polymer synthesized herein has excellent thermal stability up to 450 °F with great fluid loss control and ultrathin filter cake for NAF systems for mud weight ranging from 10 to 17 lbm/gal. The star polymer also improves emulsion stability. Plastic viscosity (PV) is usually increased with the addition of commercially available fluid loss control additives; however, star-polymer had a negligible effect on PV. Results for both diesel and mineral oil-based mud systems will be presented. High-temperature high-pressure viscometer (Fann 77) was used to study rheological properties at up to 350 °F and 10,000 psi.

Our recent work has resulted in the creation of a cutting-edge star polymer (NSP) for use in the industry's next-gen high-performance fluid loss additives. The polymer network can be efficiently synthesized and scaled up for commercial production, providing engineers with an improved solution for drilling high-temperature wells (up to 350°F) with reduced plastic viscosity and increased emulsion stability, while also providing excellent fluid loss control.
Micro-Heterogeneous Solvent Mixtures for Removal of Organic Deposits from Various Surfaces
Authors: Varadaraj Ramesh , Fontenot Kristina
Published: June 2023

The technical feasibility of using oxygenated solvent mixtures as an environmental and ecological friendly alternative to aromatic hydrocarbon and terpene solvents for removal of organic deposits from surfaces has been demonstrated. Micro-heterogeneous solvents were prepared using mixtures of di-alkyl ethers and 2-alkyl alkanols. These micro-heterogeneous solvents exhibit unique properties and are effective in solubilizing and removing organic asphaltenic hydrocarbon deposits from surfaces. The main applications of micro-heterogeneous solvents are in organic deposits removal from wellbores and near wellbore regions, heavy oil recovery from oil sands and oily sludges, and heavy oil processing equipment cleaning.
Analytical Techniques Unveil the Nature of Waxphaltenes Interactions in Solution and with Carbonates and Sandstones
Authors: Samouei H. , Yong H. C. A , Tooker K. , Mahmoudkhani A.
Published: June 2023

Several studies have demonstrated the nature of wax and asphaltene interactions and their impact on crude properties, including deposition characteristics. Laboratory and field studies have confirmed organic deposits from offshore oil wells containing asphaltenes and paraffins coprecipitated together to form solid aggregates. These can be described as "Waxphaltenes." This study used different techniques to understand better the properties of waxphaltenes from an offshore operation and how they interact with different rock mineralogy. It was found that mixing crude oil with acetone or methyl ethyl ketone (MEK) is highly efficient in the precipitation and isolation of heavy organics and other polar fractions than the traditional use of pentane or heptane from bulk hydrocarbon fluid. GC, FTIR, NMR, and elemental analysis revealed the composition characteristics of isolated organic solids. ATR-FTIR and AFM-IR methods were used to monitor the deposition of oil and organics on the surface of carbonate and silicate rocks. Water imbibition and solvent wash could remove some of the waxphaltenes dominated deposit from the surface but leave a key monolayer of organics adhered to the surface via hydrogen- or ionic bonding, which act as hydrophobic film. A plausible mechanism of such film formation may include di-or multivalent ions as bridging agents to bind with carboxylate and hydroxyl groups present in organic fractions.
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

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

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

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

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 <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

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

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

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

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

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

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

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.
Laboratory Testing to Assess Suitability of Geological Storage Prospects and the Associated Risks of CO2 Hydrates During CO2Injection (III) – Assessment of Thermal Hydrate Inhibitors
Authors: Peat Stephnie , Mehraban Mohammad Fattahi , Boyde Daniel , Frigo Dario Marcello , Graham Gordon , Jellema Raymond , Perez-Fernandez Maria
Published: June 2023

Most emerging techniques for laboratory evaluation of Carbon Capture Utilization and Storage (CCUS) projects refer to traditional geoscience core analysis methods of porosity, permeability, mineralogy caprock integrity, etc. However, analytical programs must go beyond typical oil and gas reservoir evaluation workflows when assessing injectivity impairment and measurements to control it. This work aims to highlight key operational challenges related to CO2 injection into low-pressure target formations and provides a new approach to assessing injectivity impairment caused by CO2 hydrates formation in the near wellbore.

Newly built core flooding apparatus, designed specifically for low temperature conditions, has been used to measure permeability changes during injection of liquid or gaseous carbon dioxide across a range of formation water compositions, fluid saturations, temperatures (-25 °C to + 30 °C) and pressures to demonstrate the effect on injectivity of various formation damage mechanisms, including formation of CO2 hydrates, scale and ice. This work required design of a new test rig and approach for the range of conditions expected in CO2 injection into depressurized hydrocarbon reservoirs (mainly low-pressure gas fields). Controlled, repeatable generation of the damage mechanism is required to evaluate preventative and remediation options, such as chemical inhibitors.

Initial testing of the apparatus involved injection under hydrates-forming conditions by varying pressure while flowing CO2 into a core at various brine saturations, where severe blockages were observed to form. Altering the input parameters, enables the locus of CO2 hydrates to be located in this porous medium as well as determining their formation kinetics and likely plugging mechanism. Reproduction of injectivity impairment under a variety of conditions demonstrated the ability to form, dissipate and re-form hydrates, which then allowed the performance testing of inhibitors, which were shown either to limit or eliminate injectivity impairment. The current paper presents use of the equipment and methodologies to assess the application of the thermodynamic hydrate inhibitor, monoethylene glycol (MEG), to circumvent this impairment and to determine the minimum required dose of the inhibitor to prevent CO2 hydrates within a porous medium. By quantifying the MEG dose requirement in this manner, this hydrates-suppressing chemical can be used either to design well treatments using it either as an inhibitor or for remediation of a partial blockage caused by a CO2 hydrate in the near-wellbore of a CCUS well.
Modelling Drawdown Induced Salt Precipitation in Gas Producing Reservoirs: A Field Case Example
Authors: Ogundipe Oluwatosin Matthew , Mackay Eric James
Published: June 2023

Halite scaling in natural gas production systems may cause formation damage, particularly in zones immediately surrounding the well and perforations. The clogging of flow paths has induced the loss of productivity (and injectivity in CO2 injection wells) and, in some cases, total abandonment of wells. This paper captures the process of drawdown as the main driver of the salt precipitation phenomena under specific field conditions.

Calculations were performed using reactive transport compositional reservoir simulation software to model the impact of drawdown on the change in water solubility in the gas phase during low water-cut gas production in a specific field. 1D and 2D radial models with small near-well blocks and large outer blocks were developed to account for water vaporization at irreducible and mobile water saturations, considering capillary pressure effects (horizontal and vertical imbibition) and gravity segregation. Changes in the values of critical parameters such as absolute permeability, production rate, and initial reservoir pressures were inputted to test their impact on salt precipitation.

Calculations confirm that the steepest pressure gradients occur closest to the wellbore. Consequently, there is an increase in water solubility in the methane as the gas approaches the well, which causes an increase in the rate of evaporation and a greater propensity toward drying out in the near-wellbore region. For the 1D model at irreducible water conditions, the dry-out zone increases as the permeabilities, and initial reservoir pressures decrease. In contrast, there is reduced salt deposition as the production rate is reduced. Under mobile water conditions and horizontal imbibition, the dry-out zone is extended, but only a slight increase in formation damage occurs. Horizontal imbibition causes an increase in pressure gradient because it reduces gas mobility. The Kozeny-Carman porosity-permeability relationship meant a 16% reduction in porosity resulting in a ~35% reduction in permeability near the well. The 2D modelling suggests a similar trend to 1D, but with a much stronger localized effect in the lower parts of the well due to vertical imbibition, resulting in up to 95% porosity loss locally. In contrast to the horizontal imbibition, this is due to the vertical imbibition causing a greater mass of salt to be transported into the dry-out zone.

The information presented in this study provides a platform for operators by which the theory and concepts underlying salt precipitation may be better understood. Improved reservoir management decisions may then be made, and methods of optimally producing the wells in this field could be adequately deployed. Depending on economic considerations, reducing flow rates and managing well bottom hole pressures could be considered, in addition to the application of wash water treatments whilst the problem remains localized.