bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Study of Asphaltene Precipitation and Deposition During Immiscible CO2 - EOR Process
Authors: Espinoza Mejia Julia Emilia , Li Xiaoli , Zheng Ruyi 
Published: February 2022

Abstract
The Enhanced Oil Recovery (EOR) assisted with CO2 injections has been widely addressed. However, limited experimental work has been done for studying the asphaltene precipitation arising during the immiscible CO2 injection processes. This investigation presents experimental phase behavior analyses of asphaltenes instability, determination of asphaltene onset pressures (AOP), characterization, and description of asphaltene precipitation and deposition particles under different reservoir conditions. An advanced fully visual Pressure-Volume-Temperature (PVT) instrument and a Solid Detection System (SDS) are utilized to perform all the measurements in this work. Saturation pressures are measured for the gas and crude oil mixtures with different compositions under different reservoir temperatures in the PVT cell. Changes in pressure, temperature, and volume at each equilibrium state are recorded. The same mixture composition is charged into the SDS. The AOP is then determined by reducing the pressure in the SDS. The upper asphaltene onset pressure (UAOP) is found to increase with the CO2 concentration in the system from 25 to 35 mol% CO2. For 45 mol% CO2, the UAOP is found to be lower than UAOP at 25 mol% CO2. In contrast, the lower asphaltene onset pressure (LAOP) is found to increase with CO2 concentration in all cases. The reversible process of asphaltene precipitation during the de-pressurization process at constant temperature is corroborated with the experiment at 60, 90, and 120 °C for the composition of 25 mol% of CO2 and at 90 and 120 °C for the composition of 35 mol% of CO2. The rest of the cases presented asphaltene deposition, which is considered an irreversible process because the asphaltene particles cannot be re-peptized into the liquid phase by the effect of pressure. By contrast, the complete re-peptization of asphaltenes during the re-pressurization is more effective at lower gas injection fractions (25, 35 mol% CO2) and higher temperatures (90, 120 °C). The maximum quantity and size of asphaltene particles are found near the bubble point pressure for all cases. The asphaltenes particles do not have a specific shape, and their colors vary from brown to black. The amount of asphaltene precipitation increase with the gas fraction by the effect of the micro-aggregates-clusters formation being able to reach the stage of aging or irreversible asphaltene deposition. Conversely, lower asphaltene precipitation is shown with the increment of temperature for 25 mol% CO2. This experimental work attempts to analyze the asphaltene precipitation phase behavior and particles observation relationship when CO2 is injected at different gas proportions and under different reservoir temperatures. The results from this effort provide significant support to the areas of asphaltene phase behavior characterization and formation damage control.
A Novel Single-Stage Sandstone Acidizing Fluid
Authors: Zhao Haiyan , Ziauddin Murtaza , Abivin Patrice , Yusuf Temiloluwa , Karazincir Oya , Williams Wade , Comeaux Bruce 
Published: February 2022

Abstract
Sandstone acidizing operations usually include solvent and acid preflush, main acid treatment, and post-flush stages. However, the acid preflush stage needs good design and execution to prevent formation damage. Moreover, multiple-stage operations require large-volume fluids and pumping time. Therefore, it is challenging to stimulate sandstone formations, especially those with high clay and carbonate content. A novel single-stage acid has been developed to overcome these challenges and improve the stimulation success rate in a cost-effective manner.
The application of the new acid system has been studied in laboratory testing. Core flow tests were performed to evaluate the stimulation performance with Berea Gray and Bandera Gray from 160° to 300°F. An inductively coupled plasma (ICP) instrument was used to analyze the ions in the spent acid effluent. The performance was compared with mud acid and organic mud acid. The acid-rock reactions were studied by batch reactor tests. Compatibility with crude oil and mutual solvent was also tested.
The results of core flow tests have shown that the new acid was used to treat the sandstone cores effectively at temperatures from 160° to 300°F. The regained permeability range varies from 115% to 400% under different conditions. The new acid provided similar or better performance compared with the combination of acid preflush and mud acid or organic mud acid. High concentrations of Al and Si were observed in the spent acid effluents by ICP analysis, indicating the high dissolution capacity of clays by the new acid. The new acid is highly compatible with carbonate, which was supported by the high concentrations of Ca and Mg in the spent acid. Both core flow tests and batch reactor tests have shown that the new acid stabilizes the problematic ions (Al, Ca, Mg and Fe) in the spent acid. The new acid is compatible with mutual solvent from the core flow tests; therefore, the mutual solvent preflush can be eliminated. The new acid also has good corrosion control due to the relatively high pH compared with mud acid.
Overall, the new single stage acid has been used to stimulate the sandstone cores successfully without acid preflush and solvent preflush. A differentiating characteristic of the fluid is that it greatly reduces the risk of treatment failure by reducing primary, secondary, and tertiary precipitation, while maintaining high dissolving power for clays. It uses a different, more cost-effective chemical pathway to stabilize problematic ions compared to traditional single-step sandstone acidizing systems. The new fluid simplifies operation by reducing the total treatment fluid volume, the total number of fluid stages, and the number of fluid types needed at the wellsite.
Performant Non-Emulsifiers for High-Brine and Acidizing Applications
Authors: Stanciu Cornell , Fernandez Jorge M. , Sokhanvarian Khatere 
Published: February 2022

Abstract
Oil production is accompanied by water production in various ratios. This poses additional challenges to the industry as oftentimes the typically immiscible liquids form stable emulsions that need to be broken further and the two phases separated, incurring supplemental production costs. In stimulation operations such as hydraulic fracturing or acidizing, emulsions can form due to the presence of aromatic and naphthenic compounds in the crude oil along with surfactants present in the pumped fluid. Additional complications arise in the acidizing treatments since the acids used can further stabilize the emulsion with crude oil, making the phase separation even more difficult. This paper discusses simple 3- and 4-component formulations based on non-ionic surfactants and solvent/co-solvent that were successfully used as demulsifiers (DE), non-emulsifiers (NE) and weakly emulsifiers (WE) over a range of medium and heavy crude oils.
A range of 3 medium and heavy crude oils were emulsified in a 1:1 ratio with either synthetic seawater or with 15-20% HCl. A composition analysis was run on the selected crude oils to determine the likelihood of the best formulation candidates to maintain their effectiveness in other crude oils. A comprehensive solvent/surfactant screening was performed aiming to find the best formulation that would work in each case. The best performers from the screening were further optimized and tested against commercial demulsifiers and their performance evaluated and discussed.
The study resulted in the design of a few successful formulations that showed great performance over the range of crude oils utilized. The top candidates consisted of a 4-component formulation for the high brine and a 3-component formulation for the acidizing application and they worked well both as NE and as DE. Other formulations showed good performance as WE. The NE/DE compositions met the general performance criteria of providing complete phase separation within 5 minutes and with no emulsification. The WE formulations provided similar performance with the only difference that some emulsification occurred, as evidenced by the water layer taking up a slight color.
The formulations discussed in this paper provide the operator with a series of benefits, among which: on par or better performance with similar commercial products, do not involve use of polymers that can have adverse effects on the downhole formation or pose supplemental challenges during downstream processing and have a better environmental profile, as they are not based on phenol, amine or sulfonate derivatives.
Stimulation Treatment Design Compatible with Glass Reinforced Epoxy Lining
Authors: Bird Anastasia , Espinoza-Perez Judith , Mahadev Karthik , Sixt John 
Published: February 2022

Abstract
Glass reinforced epoxy (GRE) lining is a polymer composite material, the main components of which are a thermosetting resin and a fiberglass reinforcement. The combined properties of its components result in a material with excellent chemical, thermal and mechanical performance. GRE lining is typically used as a coating on production tubulars in oil wells to protect metallurgy of tubulars from corrosive environments, thereby extending the life of tubulars and realizing cost savings. GRE lining is chemically compatible with many acids used in well stimulation to restore productivity. Typical acids such as hydrochloric, formic, acetic etc. involve carbonate removal followed using hydrofluoric (HF) based acids for removal of small formation particles. However, the use of HF is typically not recommended in GRE lined tubulars due to potential interactions with HF. Yet, in most sandstone reservoirs, HF fluids contribute greatly to restoring well productivity due to formation damage removal related to fines and clays. While GRE lining is a well-known technology, its chemical compatibility with acids is challenging to predict due to its heterogenous nature and requires specific testing to understand potential for mechanical degradation.
Prior studies at BP focused on evaluation of GRE performance with 9% HCl: 1% HF under ambient boundary conditions of 77°F for 24 hours. These tests caused unacceptable levels of mechanical degradation to GRE and plans to execute stimulation treatments in GRE lined wells were abandoned. However, an increasing number of GRE lined underperforming water injector well stock necessitated a less aggressive acid design involving 0.5% HF. Therefore, 0.5% HF was assessed for GRE lining compatibility, mechanical and physical property changes under specific well boundary conditions at elevated temperatures of 120°F and 140°F and extended times of up to 72 hours. Core flow tests were also carried out to evaluate the effect of GRE exposed acid to any potential for formation damage.
This study demonstrated that exposure of GRE lining to 0.5% HF resulted in acceptable retention of mechanical properties and did not show any formation damage impacts. These results were also reflected in field performance where a significant injectivity index improvement of &gt;4 was achieved, thereby opening the door to a significant increase in number of GRE lined wells to be treated across multiple regions.
Deepwater Gas Injector Wells: Overcoming the Challenge of Achieving Matrix Injectivity
Authors: Manzoleloua Cedric , Nguyen Chau , Okhrimenko Albert , Traboulay Vaughn , Gamargo Mauro , Li David 
Published: February 2022

Abstract
As fields mature, they start depleting and require assistance to help extend production and enhance hydrocarbon recovery. The introduction of injector wells in producing fields is a commonly used pressure maintenance method which consists of injecting water or gas to maintain reservoir pressure and/or sweep hydrocarbons toward producer wells. Injector wells, requiring matrix injectivity, are typically drilled using reservoir drill-in fluids (RDIF) as they minimize near wellbore damage while drilling and lay down a high-quality acid-soluble filtercake (Dick et al. 2003). The slow and uniform dissolution of the filtercake is achieved by spotting a delayed breaker solution to allow time for pulling out the lower completion running string and closing the formation isolation valve (FIV) without causing losses.
For two deepwater gas injector wells recently drilled in the Guyana Surinam Basin, a 11.9 lbm/gal RDIF was necessary and presented a design challenge of meeting both the deepwater reservoir drill-in and post-completion matrix injectivity requirements.
A reversible non-aqueous RDIF system using a calcium bromide brine as the internal phase and formulated at 50/50 oil-water ratio (OWR) was selected to meet the drilling challenges. Such challenges included maintaining wellbore stability while drilling interbedded shale and controlling equivalent circulating density (ECD) below the fracture gradient at the desired rate of penetration (ROP). They also included depositing a thin, ultra-low permeability and acid-soluble filtercake. A newly developed breaker was customized to provide a 4-hour delay at bottom-hole temperature (250°F) permitting a safe pull out of the inner string above the FIV and then slowly dissolve the filtercake to restore near wellbore permeability and enable matrix injectivity.
Both the recommended RDIF and delayed breaker formulations were d used in the field during reservoir drill-in and lower completion operations of the two deepwater gas injector wells. Post-completion well tests confirmed that the two wells have achieved maximum gas injectivity below fracture gradient, meeting customer expectations.
This paper discusses the results of extensive laboratory tests that were necessary for the selection and the customization of both the RDIF and the delayed breaker and the field performance of the two fluids.
Formation Damage by Fines Breakage and Migration
Authors: Hashemi Abolfazl , Borazjani Sara , Dang-Le Bryant , Yin Loi Grace , Nguyen Cao Cuong , Badalyan Alex , Bedrikovetsky Pavel 
Published: February 2022

Abstract
Fines migration is one of the most drastic causes for formation damage - the detached clays migrate and impairs well productivity. Two types of damaging clays are encountered in petroleum reservoirs: authigenic clays that grew on the grain surfaces during geological times, and detrital clays that have been broken off the grains by local stresses. Detailed laboratory and mathematical modelling have been carried out for detrital-clay formation damage. The theory for formation damage by authigenic clays is not available. The aim of this work is the development of a laboratory procedure to estimate formation damage by authigenic clays and the derivation of a mathematical model for core scale. We performed two test of corefloods using Castlegate core samples. In the first test, injection rate increased in a stepwise manner up to 100 mL/min and in the second one up to a 200mL/min to make sure both detrital and authigenic particles are detached. The pressure drop across the overall core and the concentration of the fine in the produced fluid have been measured. We have derived equations for authigenic-fines detachment using the beam theory and the von Mises failure criteria to obtain analytical solutions for linear system of equations. Matching the laboratory data by the analytical model allows determining the percentage of authigenic and detrital clays in the cores. The laboratory data exhibit a good match with the mathematical model for the two coreflood tests. The non-monotonic change of the concentration of the detached fine, with the initial and final risings, determines the type curve that evidence the mobilization of both, authigenic and detrital clays. The treatment of the measured data in test#2 shows that 82% of the initial attached particles are authigenic. The model parameters in order of decrease of their sensitivity are contact-bond radius, pore radius, particle size, lever-arm ratio, tensile strength and aspect ratio. A novel experimental procedure to determine fines-migration formation damage by authigenic and detrital clays was developed. A newly derived mathematical model allows determining the model coefficients from the laboratory tests and predict future detachment rate of authigenic and detrital particles.
A Case Study: Improvement in Asphaltene Remediation by Focusing on Zonal Coverage and Flowback Efficiency
Authors: Houchin Lanne R. , Granizo Dorian , Conine Joseph 
Published: February 2022

Abstract
As fields in the Deepwater and Ultra Deepwater areas in the Gulf of Mexico have matured, the frequency of asphaltene deposition within the reservoir has increased significantly. Operators reported that solvent treatments show initial production response but diminishing results and shorter treatment life with subsequent treatments. A field case study was undertaken to examine current best practices and identify opportunities for improvement. Areas needing improvement included targeting the less soluble age hardened asphaltene deposits, zonal coverage, and extending treatment life. This case study showed that measurable improvements were achieved on high asphaltene produing wells by utilizing new novel chemistry, better placement to facilitate longer soak times, effective diverting, and optimizing mechanical techniques.
Novel Approach in Deploying Filter Cake Breaker Post Open Hole Gravel Pack with Non-Aqueous Gravel Pack Carrier Fluid in Reservoir with Reactive Shales
Authors: Aung Tint Htoo , Djenani Romain , Byrd Aaron , Beavers Matt , Manzoleloua Cedric , Green Sarah , Gadiyar Balkrishna 
Published: February 2022

Abstract
Non-aqueous gravel pack carrier fluids (GPCF) have been introduced into the industry to eliminate the risks associated with the water-based carrier fluids in the presence of reactive shale interbeds in the reservoir. However, non-aqueous GPCF pose a significant barrier to the effective deployment of post-gravel pack filter cake breaker (FCB) application because all FCB systems are water-based. Therefore, a novel approach was developed for FCB application in non-aqueous GPCF environment to improve the efficiency of the FCB and the overall well performance.
The non-aqueous GPCF was redesigned from ground up to promote the better diffusion of the FCB. This was accomplished by introducing a reversible emulsifier package into the non-aqueous GPCF design which allows the gravel to change wettability from an oil-wet state to a water-wet state when a low pH solution i.e., breaker is spotted inside the sand screens after the open hoel gravel pack (OHGP). To complement this, the FCB design was deconstructed, and the in-situ breaker component was blended with the gravel. The concept was to incorporate the in-situ breaker component into the gravel pore space which would promote better diffusion of FCB through the reversible non-aqueous GPCP. The in-situ breaker component is inert to the carrier fluid until it is activated by the temperature and water posing no threat to the stability of the carrier fluid while pumping.
The innovative approach was tested in the laboratory setting using ceramic disks and return to flow method to prove the concept before conducting an elaborate return permeability testing with the reservoir core plugs for the final validation. Return to flow method indicated that the novel approach could improve the results by at least 10% compared to the baseline test with no breaker application. In the return permeability tests with reservoir core plugs, the novel approach resulted in 76% of the initial permeability whereas the baseline test was only 50%. Both the tests with ceramic disks and full-sequence formation damage tests with actual reservoir cores highlighted the benefits of the novel approach for gravel packing with non-aqueous GPCF and post-gravel pack FCB scenario.
Non-aqueous GPCFs are relatively new to the industry and no record of the filter cake breaker application in such environment exists. This novel approach makes the filter cake breaker application possible in non-aqueous environment and pushes the existing boundaries of filter cake breaker chemistries.
Real-Time Performance Optimization to Prevent Productivity Decline in Deep Offshore Producers
Authors: Izgec Bulent , Kalfayan Leonard 
Published: February 2022

Abstract
This paper presents a continuous well performance analysis technique that identifies formation damage and/or productivity loss real-time. It also provides insights into expected damage mechanisms enabling successful and efficient stimulation treatments.
The analytical technique recognizes damage patterns at inception. The diagnostics to drive operational decisions are then presented as simple cartesian plots that grant easy access to users of all levels of experience. During initial well ramp-ups, the diagnostic plots can be automated with high frequency data. After reaching target drawdowns, low frequency data provides optimum surveillance.
Case studies from several deepwater Gulf of Mexico wells demonstrate how the technique has been successfully operationalized to eliminate productivity loss, gain early insight into damage mechanisms, and investigate the impact of well interventions. Comparisons with pressure transient analysis and numerical history matching studies with all completion details corroborate the robustness of the method.
Shutting in the wells is not required for the analysis, therefore lost production and additional stress cycles on the completion are eliminated. The analysis also identifies the maximum drawdown limit, thereby helping the operator optimize well performance real-time.
High Viscosity Friction Reducer that Minimizes Damage to Conductivity
Authors: Vazquez Zoraida , Smith Clayton S , Emery Nathan , Babey Andrew , Kakadjian Sarkis , Trego Keith 
Published: February 2022

Abstract
Friction reducers (FRs) are commonly used in Slickwater fracturing operations to enhance oil and gas production. They are essential in reducing the frictional forces that develop along the pipe wall while pumping at high flow rates while placing proppant into fractures created in reservoirs. Standard friction reducers were historically designed for potable water and to carry proppant into the reservoir by pumping fluids at a high flow rate. They were designed to utilize turbulence for transport, however their proppant carrying capacity is limited. To maximize proppant loading into these unconventional wells, High Viscosity Friction Reducers (HVFRs) have been successfully introduced. They have the ability to reduce water consumption, minimizing chemical usage and require less operating equipment on location. Most importantly, they have better proppant transport capability which keeps the fractures in the rock open for long term production. However, some concerns remain of potential conductivity damage that might occur when using these high molecular weight polyacrylamide-based fluids, that constitute a HVFR, at higher concentrations. All current friction reducers are polymers with C-C backbones, which have historically been difficult to degrade on their own. Test show that these polymers can cause conductivity damage even in the presence of oxidizer breakers if not properly selected for the reservoir conditions.
A novel HVFR design was developed to minimize formation damage when fracturing designs call for the use of HVFRs. The chemistry was engineered to be self-breaking at low concentrations, causing the bonds in the polymer to hydrolyze with elevated temperature and exposure over time. This approach results in a reduction of the residue left in the proppant pack upon flowback for a better clean-up process. This HVFR was used in a Permian field, where the operator saw an increase of 150% over the expected production that continued through the writing of this paper 90+ days. This paper will discuss the laboratory work done to evaluate the reduction of conductivity damage to the proppant pack as well highlight how this new engineered design translated into improved estimated ultimate recovery (EUR) on field trials in the Permian basin.