bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field Crystallization of MEA-Dithiazine: Identifying Materials, Leveraging H–Bonding Synthons, and Opportunities for Crystallization Inhibition
Authors: Everett Tom , Holtsclaw Jeremy , Schultheiss Nate 
Published: June 2023

Abstract
The operational production of crude oil inevitably involves the co-production of unwanted materials that must be resolved, e.g., produced brine, solids, gases, hydrogen sulfide, etc. Hydrogen sulfide is a particularly noxious and hazardous gas often encountered in oil production, and various methods, including chemical, engineering, or combinations thereof, have been developed to address the challenge. Despite the longevity of the H2S scavenging problem, practical and economical solutions for treating H2S are still sought by the industry.
MEA-triazine (1,3,5-tris(2-hydroxyethyl)hexahydro-s-triazine) is a routine chemical scavenging treatment for removing H2S in production operations. MEA-triazine readily reacts with H2S under field conditions to form MEA-dithiazine as a H2S scavenged product. Operationally, the resultant MEA-dithiazine is removed from the system and disposed of in an injection well. However, under certain conditions, the MEA-dithiazine is known to form crystalline masses that can result in significant fouling within piping, separators, and even static mixers.
Field crystallization of MEA-dithiazine was observed, and the material was collected. The crystals were unambiguously identified as the MEA-dithiazine dimer through single-crystal x-ray crystallography (Schultheiss et al., 2022). As an alternative to solvent or hot water washes to remove the problematic crystallized MEA-dithiazine, a concept was envisaged to leverage molecules that are disruptive to the H-bonding patterns that result in the crystallization of MEA-dithiazine. A series of hydrogen-bonding donor-acceptor small molecules, along with various polymeric materials, were identified and evaluated as disruptors to aid in mitigating field crystallization.
This initial study describes identifying and testing a series of small organic molecules and larger polymeric materials as network disruptors to inhibit MEA-dithiane crystallization. Identifying cost-effective molecules that can disrupt the H-bonding and prevent MEA-dithiazine crystallization holds promise to prevent MEA-dithiazine fouling in field operations. In addition, such a solution may provide a cost-effective alternative to labor-intensive solvent and hot water washes.
Temperature Activated Modified Natural Polymer for High Temperature Cement Slurry Rheology Control
Authors: B. Hernandez Mario , Cadix Arnaud , Zhang Shaopeng , Petrowsky Jeremy , Molina Jean , Parker Cameron 
Published: June 2023

Abstract
A well-known challenge in high-temperature well cementing is to prevent settling within cement slurries during placement. Many suspension additives lose their properties with temperature. However, increased loading of the suspension additives to offset the thinning would lead to unmixable slurries at the surface. Herein this paper discusses the use of a new Modified Natural Polymer (MNP) technology to address the high-temperature slurry stability challenge. This MNP was designed to aid in the suspension of solids and free water once the slurry reached an activation temperature. Below the activation point, the MNP shows a very limited impact on the slurry rheology. But once activated by temperature, the MNP can provide very effective slurry suspension even beyond the commonly seen high-temperature limit of natural polymers. MNP is also compatible with commonly used additives and has no other significant impact on the slurry properties besides suspension.
A series of tests have been conducted to demonstrate the effectiveness of MNP in various sets of conditions. A comprehensive set of tests was conducted on a 16.4 ppg Class H design where the triggered activation of the MNP is critical for mixability at the surface. BP settling tests on this slurry design were conducted from 300 to 375°F with a significant reduction of top-to-bottom density variation. A high-precision rheology study is conducted with slurries containing MNP to develop a better insight into its working mechanism. It is here demonstrated that MNP suspension capability is developed through marginal interactions between the polymer and cement particles which makes it less impacting on other additives interactions and reduces the risk for antagonistic effects.
Rejuvenation of Watered-Out Fractured Carbonate Horizontal Well by Microgel/Gel Injection
Authors: Gaillard Nicolas , Omonte German , Bouillot Jerome , Zaitoun Alain , Duboin Francois André , Bertrand Charles 
Published: June 2023

Abstract
In a world where oil production declines and where investments in fossil resources are lower and lower, operators are looking for solutions to optimize the production of existing wells. This is the case for horizontal wells in carbonate formations suffering from channeling with strong bottom aquifer. Such problem occurred for well MRS-1H located in France. Its production started in 2001 with high water-cut (80-85%) that increased rapidly with time to reach 99.7% in 2022 for a gross production of 5000 bpd. Even with a barrel at 80 USD, the extraction of oil in such conditions is not economical due to the high OPEX required for pumping and water disposal. A Water Shutoff (WSO) treatment was designed having as target to decrease water production by, at least, a factor of 2, while keeping the volume of oil production at same level.
The bottom aquifer is located in the very permeable Upper Bathonian formation, just below Lower Callovian formation. Oil in place is 36° API with a viscosity of 3.3 cp. Reservoir temperature and pressure are 70 °C and 186 bar respectively. Reservoir water salinity is between 5 to 10 g/L TDS.
The main problem is the presence of a channeling connection between the well and the aquifer by a fracture network localized close to the heel of the horizontal drain. WSO treatment consisted in injecting by bullheading a first slug of microgel followed by a slug of elastic gel followed by a third slug of microgel. The total volume of the chemical treatment was 300m3.
During the injection, wellhead pressure increased and remained stable below 60 bar for an injection rate of 3bpm. The fact that pressure did not build up (especially during the injection of the gel slug) indicates that the treatment penetrated in low resistance flow areas (fractures). After 15 days of shut in, the well was put back on production, showing a dramatic drop of gross production rate, reaching 630 bpd while it was 5000 bpd before the treatment. The oil production reached 17 bpd corresponding to an oil cut of 2.5% (compared to 0.3% initially). The well has kept this behavior with time, making its production economical.
The bullhead treatment combining microgel and gel proves to be a good WSO strategy for wells suffering from strong bottom aquifer channeling and should have many applications in fractured carbonate reservoirs.
Stabilization of Drilling Foams Using Nanoparticles
Authors: Salih Mohamed , Ahmed Ramadan , Amani Mahmood 
Published: June 2023

Abstract
Foam is the preferred fluid for underbalanced drilling due to its superior hole-cleaning capacity and reduced liquid requirements. However, it must have reasonable stability to function as a drilling fluid under borehole conditions. Unstable foam loses its viscosity and generates drained liquid that causes slugging flow, resulting in temporary overbalance that can damage the formation. This study aims to improve foam stability of aqueous foam using nanoparticles with unique surface properties.
Due to their small sizing and large specific surface area, nanoparticles exhibit unique properties. In addition, their surfaces can be modified to display the desired properties for a given application. In this study, bare (NS1) and coated silicon oxide nanoparticles (NS2, and NS3) have been utilized to enhance the stability of foams. A foam circulating flow loop with horizontal pipe viscometers and a vertical drainage testing cell was used to create foams and analyze their characteristics. At 1000 psi, foams with different nanoparticle concentrations and foam qualities were generated. Their rheology and stability were then investigated. A sonicator and laboratory blender were used to mix nanoparticles with water and anionic surfactant to prepare the liquid phase of foams. The hydrostatic pressure distribution at different column depths as a function of time was measured after trapping a fully generated foam in a vertical test cell. Initially, baseline foams without nanoparticles were tested. Later, two types of nanoparticles (bare and coated) were tested at different nanoparticle concentrations (1 to 3 wt%).
Increasing the baseline foam quality (in-situ gas volumetric concentration) from 40 to 60% resulted in a significant increase in apparent viscosity and a reduction in liquid drainage. Nanoparticles containing foam also showed similar trends of property changes with foam quality. Besides this, experiments demonstrated the impact of nanoparticles on the characteristics of foams. The viscosity and stability of foams increased with the addition of nanoparticles. Also, the drainage of foams noticeably decreased while their half-life improved with the concentration of nanoparticles. The effectiveness of nanoparticles is also influenced by their type. Silica nanoparticles that are coated (functionalized) with an amino group (NS2) provide better foam stability than regular nanoparticles (NS1) and nanoparticles treated (coated) with silane (NS3). This study contributes to the formulation of a new generation of drilling foams that can be used in harsh borehole environments where foam instability becomes a major concern.
Controlling Asphaltene Deposition in Ageing Wells
Authors: Grutters Mark , Alshamsi Mohammed , Punnapala Sameer , Abdallah Dalia , Al-Ali Aamna 
Published: June 2023

Abstract
ADNOC Onshore produces asphaltene-unstable crudes subject to severe wellbore deposition, which is exacerbated by miscible WAG injection. In one of the oilfields, commissioned in 1973 and producing approximately 400,000 BPD from 4 key reservoirs a cluster of approximately 20 wells experienced severe asphaltene deposition. Over time field conditions changed, reservoir pressure declined and water cut increased from 0% to 30%. With these changes the number of shut-ins due to asphaltene deposition started to change. Regular well intervention by gauge cutters or PLT tools confirmed that little to no asphaltene build up occurred in wells with high water cut.
In this paper it was evaluated whether changes to asphaltene deposition severity can be linked to water production, or that other production factors might contribute. Field data were reviewed for the period 2003 to 2022, for a total of 12 wells with a history of moderate to severe asphaltene deposition. The field data included PVT data and stock tank oil properties, well testing data, production allocation data, wireline inspection data, field lab analysis of wellbore deposits and chemical soaks. The review indicated that changes in asphaltene deposition were not influenced by a gradual decline in reservoir pressure or gas break through causing changes to the AOP location. A scoring matrix was developed to determine the ‘deposition severity’ for each well for every year and plotted against the average water cut of that year. From this scoring matrix it was concluded that there is a weak correlation between the severity of asphaltene deposition and water cut. Even at water cuts around 40% asphaltene deposition has not stopped completely, but the number of required interventions has dropped.
Or long-term goal is to develop correlations that can be used to predict future behavior of asphaltenes, for optimization of field development plans in reservoirs subject to WAG and surfactant/polymer flooding. A correlation can help to understand whether asphaltene deposition will be permanent or reduce over time for different development scenarios and whether mitigation by inhibitor injection or periodic cleaning with solvents is most effective and economical.
A Novel Experiment Setup to Model the Effects of Temperature on Halite Scaling and Inhibition
Authors: Navarathna Chanaka , Leschied Cianna , Wang Xin , Reiss Amit , Ye Yuqing , Pimentel Daniel , Shen Yu-Yi , Yao Xuanzhu , Kan Amy , Tomson Mason 
Published: June 2023

Abstract
Halite is a common scale in oil/gas production. Freshwater is widely used to combat halite scaling, but this is costly. Therefore, halite inhibitors have also been examined in laboratory and field tests. However, there are certain flaws in the laboratory studies of halite inhibitors, the temperature decreases were so abrupt, or the experiments are limited to lower temperatures. As a result, inaccurate results and unrepresentative field conditions are produced. Our new precisely temperature-controlled method simulates halite precipitation at high temperatures up to 120+ °C with real-time monitoring using a laser and a video camera. This method uses batch reactor convection cooling to gradually increase the saturation index (SI) to trigger the halite nucleation observed by turbidity laser measurements. The cooling rate is commonly set at 0.5 °C/min to simulate a real-world downhole to surface hot brine movement, typically 25-35 °C of cooling. Low to high Ca2+ values were used to validate the experimental data with thermodynamic predictions. The experimental data and ScaleSoftPitzer™ (SSP) predictions are very close and with high precision. The high temperature inhibition properties of halite inhibitors are not well-known, and lack of information can lead to overtreating the scale with higher inhibitor concentrations than needed. By simulating the temperature drop that occurs when brine is transported from the downhole to the surface, this approach can establish the effective SI range for a specific inhibitor. Our data shows that even at low 0.1-100 mg/L concentrations, some inhibitors with carboxylate, sulfonate, and acetamide moieties can effectively treated halite scale and dramatically extend the stability range. Despite the weak thermal stability and incompatibility with high Ca2+ concentrations, potassium ferrocyanide demonstrated outstanding inhibitory effectiveness. The longer the inhibition period or brine transit distance, the lower the scaling temperature. By treating the scale with the least amount of inhibitors and combining it with less water dilution, production can continue uninterrupted at significantly enhanced cost savings. Overall, this approach is reliable while remaining straightforward. In addition, it can model field conditions in an oil/gas production system to evaluate the risk of halite scaling at higher temperatures than any previous method.
Development of a New Chemical Formulation for Heavy Oil Viscosity Reduction and Displacement
Authors: Chen Shaohua , Han Ming , AlSofi Abdulkareem , Huang Tianping 
Published: June 2023

Abstract
A novel polycyclic aromatic hydrocarbon (PAH) based water-soluble viscosity reducer (VR) formulation was designed to reduce heavy oil viscosity for enhancing heavy oil production by chemical flooding. The polyaromatic structures such as benzene, naphthalene, and pyrene units in the VR formulation target asphaltene and resin components in heavy crude oil via π-π interaction to hinder formation and self-assembly of asphaltene aggregates and to reduce the viscosity of heavy oil accordingly. Two main chemical components in the VR package were synthesized from the reaction between poly(ethylene glycol) and naphthalenemethanol or pyrenemethanol to yield amphiphilic molecules. The chemical structured were confirmed by 1H NMR spectra. Heavy oil displacement evaluations were conducted through two experimental setups – a coreflooding equipment and a visualized micromodel. In the coreflooding experiments, a commercially available benchmark VR (BVR) and the synthesized VR (SVR) solutions at the optimized concentrations were injected to displace the heavy oil saturated in carbonate cores. The residual oil distribution pattern after injection of chemical slug and the profile change of saturated oil during chemical flooding with the BVR and SVR were observed using a micromodel equipment. At 0.2 wt%, the SVR package formed oil-in-water (O/W) emulsions with heavy oil at an oil-to-water ratio of 7:3 and dramatically reduced the viscosity of heavy oil by 84% at 50 °C. Visualized micromodel displacement tests showed that the injected SVR solution gradually emulsified the heavy oil at the oil/water interface to form emulsion droplets, which were subsequently deformed and stretched into long and narrow emulsion strips to pass through the smaller pores and throats along with injected fluid, thus facilitating the mobility of heavy oil and enhancing the oil production eventually. Coreflooding testing indicated that the injected SVR fluid significantly decreased the injection pressure due to viscosity reduction of the heavy oil. The oil production was enhanced by around 11% on the basis of water flooding. As a comparison, the heavy oil production by injection of the BVR solution was improved by 8%. The performance of the SVR on heavy oil viscosity reduction and oil displacement was found more pronounced than the BVR. Therefore, the formulated SVR package exhibits a great potential in heavy oil production.
The Impact of Variations in Water and Gas Flow Rates on Scaling Potential of Carbonate Reservoirs Under CO2-WAG Injection
Authors: Braga Gusmao Patricia , Mackay Eric James 
Published: June 2023

Abstract
This paper uses reactive transport modelling to analyse the impact of variations in the water and gas injection flow rates from a geochemical perspective on the scaling potential of carbonate reservoirs under CO2-WAG injection. A sensitivity analysis of the calcite saturation index is performed for different water and gas injection flow rates. Geochemical properties of the injection fronts are analysed through the reservoir.
The study is carried out using a 1D model of water-alternating-gas injection, assuming a light oil with 1.2% CO2 concentration, desulphated seawater injection and calcite as the rock substrate. The reactive transport modelling is performed using a commercial compositional reservoir simulator with the WOLERY database. Pressure, temperature, formation water (FW) and injected water (IW) compositions are based on published data. The scale potential is measured by calculating the saturation index and water production rates.
Results show that calcite dissolution occurs continuously in the block closest to the injection well, and equilibrium is not reached in this region during water injection, but it is reached during CO2 injection. The extent of the reaction decreases from the injector to the producer well because the fluid becomes more saturated with CO2 as it flows through the reservoir. The reaction also decreases as the water and gas injection flow rates decrease, mainly due to the reduced volume throughput. The reactions during the water injection part of the cycle occur further away from the waterflood front as the water injection rate declines, and the reactions during the CO2 injection part of the cycle occur further away from the gas flood front as the CO2 injection rate declines. The system takes longer to reach equilibrium at lower flow rates, and so the water composition varies for longer. In the highest water flow rate model, it takes a very short time to reach equilibrium after the water breakthrough in the producer well. In the lowest water flow rate model, it takes more than five times as long.
This work indicates the previously unreported finding that the water and gas injection flow rates may affect the geochemical equilibrium in the reservoir, specifically demonstrating that the reactions during the non-equilibrium stage may occur further away from the water and gas flood fronts, depending on the water and gas flow rates.
The Study and Application of Seepage Reconstruction for Water Plugging in High Permeability Sandstone Reservoirs
Authors: Zhang Yanna , Li Liangchuan , Yan Fei , Wang Yucai 
Published: June 2023

Abstract
In the medium/high permeability sandstone reservoirs, long-term water flooding led to large pore channels formed in the reservoir, and the injected water quickly breaks into oil wells along the large pore channels, resulting in water cut increase rapidly and a significant reduction in water flooding efficiency. The traditional water shut-off by chemical or cement squeeze cannot reduce water cut for a long time and cannot increase oil production because they don't change the existing seepage characteristics of the reservoir.
The seepage reconstruction is a combination of chemical water shut-off and fracturing technology. It involves innovation on intelligent water control materials and fracturing injection process. There are three plugging slugs, a strong plugging slug, a seepage reconstruction slug, and a tail plugging slug, should be filled into reservoir one by one. The strong plugging slug adopts inorganic polymer to shut-off the large pore by low speed injection. The seepage reconstruction slug is composed of 70-140 mesh quartz sand, 50-80um ceramist and intelligent water control materials with a ratio of 6:3:1, which is carried by low-concentration guar. The tail plugging slug is made of self-consolidated material to prevent sand returning from formation.
The technology is used in G111-6 located in J oil field, which is successful in increasing oil production from 3.08bopd to 56.28bopd and reducing the water cut from 96.64% to 78%. The validity period was 492d, and the total oil production was 22624bbls. The technology of seepage reconstruction for water shut-off could effectively reduce the water cut and greatly increase the daily oil production. It effectively improves waterflood development efficiency of medium/high permeability sandstone reservoirs in high water cut stage.
The innovation of this technology is the effective combination of fracturing technology and traditional chemical water shut off technology. The goals of water shut-off and oil increase are realized by innovative design of three plugging slugs. It provides a new approach for water shut-off in medium/high permeability sandstone reservoirs with high water cut.