bluuebunny/crossref_metadata_2025_split huggingface dataset:
Lab Study of High WAT Wax Deposition Reduction with Wax Inhibitors and Dispersants
Authors: Bian Y. , Chiang P. T. , Kiran S. , Wiebe D. , Oswald D. 
Published: October 2023

Abstract
Canadian crude oil and pigged wax from the Montney formation show high wax appearance temperatures (WAT) and experience severe deposition issues during production and transportation. Several commercial wax inhibitors and wax dispersants were studied in the crude oil and reconstituted oils (pigged wax added back to the crude oil and dodecane model system), to minimize the wax deposition by a systematic lab screening protocol. Suitable wax inhibitors (WI) and dispersants were selected and formulated at optimized dosage to efficiently reduce the wax deposition at close to field condition.
The crude oil and reconstituted oils were utilized to study the high WAT wax performance with different types of wax inhibitors and dispersants. This included ethylene vinyl acetate (EVA), alkylphenol formaldehyde resin (AFR), acrylic copolymer (AC), α-olefin maleic anhydride copolymer (AOMAC) and several surfactant-based wax dispersants (WDs). A pour point tester was employed as the initial screening tool to determine the pour point and detected wax appearance temperature (DWAT). Multiple Light Scattering (MLS) was used to evaluate the dispersions of wax in the oil. Dynamic wax deposition tests by capillary flow through (CFT) and dynamic flow loop (DFL) systems were used to verify the wax deposition reduction efficiency, and to study the effect of the test parameters on wax deposition.
The reconstituted oils had higher WAT (&gt;55 °C) than produced oil. The screening tests showed that EVA significantly reduced the DWAT and pour point of the crude oil but was not very efficient in the reconstituted oil. Both AFR and AC reduced the DWAT and pour point but were not as efficient as AOMAC. AOMAC provided the lowest DWAT in the reconstituted oil. It was interesting to find that surfactant-based dispersants also reduced the DWAT of the reconstituted model oil. The top performing WIs and dispersants were then tested by CFT wax deposition system at a flowrate of 1.5 cm3/hr. For the crude oil at 10 °C, 225 ppm AOMAC WI was needed to efficiently reduce the wax deposition in the CFT system. A lower dosage was required in the DFL system. It was also found that wax inhibitor and dispersant together further reduced the reconstituted model oil wax deposition in the CFT system. MLS and bottle tests showed that the WDs helped to disperse the wax in both oil and aqueous phases.
From this systematic WI study on kinetic and dynamic behaviors of high WAT wax deposition, a synergy was observed between wax inhibitors and dispersants. Further investigation is needed to understand how they work together. The specially designed laboratory screening protocol helped to understand the structure and performance relation, efficiently formulate the WIs/dispersants, and optimize the treatment dosages. The inclusion of surfactants/dispersants with WIs could further mitigate wax deposition and be a more cost-effective approach.
Reconsider Your Unpreserved Core: Resurrecting Impactful Data via Closed Retort Thermal Extraction
Authors: Zumberge J. A. , Piper N. C. , Milovac J. 
Published: October 2023

Summary
Over the past decade and spanning many disciplines, significant progress has been made in the discovery and understanding of unconventional hydrocarbon plays, both through laboratory studies and in-situ analysis. As a result, most operators and researchers still have access to large amounts of residual core material in various states of preservation (wax sealed, foil wrapped, chilled, unpreserved, etc.). This core was originally collected to answer specific questions related to the assets being evaluated, but there is now growing interest in reusing and reexamining this legacy material to explore new ideas, opportunities, and understandings, as well as to increase the potential for enhanced oil recovery. In this study, we show the potential of legacy unpreserved core material providing resurrected datasets via advancements in core extraction methodologies (e.g. closed retort). Results from these preserved/unpreserved core comparison experiments demonstrate the impact that running legacy rock volume can have in terms of additional learnings, calibration and knowledge gain.
Deformation, Damage, And Fracture in Hot Dry Rock of Geothermal Reservoir Under Uniaxial and Diametrical Compression Using 3D-DIC
Authors: Nath F. , Aguirre G. , Vazquez E. C. , Portillo O. , Gindic R. , Cuellar A. 
Published: October 2023

Abstract
Geothermal resources have attracted global attention because of their renewability, cleanliness, and universality. The U.S. Department of Energy estimates that harnessing just 0.1% of the Earth's geothermal energy can power humanity for 2 million years. An improved geothermal system (EGS) efficiently extracts heat from deep hot dry rock (HDR). However, EGS is battling to assure safe drilling and appropriate fracturing to extract heat potential. Conventional laboratory techniques cannot detect fine-scale variability in HDR structures during loading. Due to its inherent heterogeneities, it is especially crucial to characterize deformation and frac-face damage during induced fracturingto unlock heat energy from HDR. This study uses three-dimensional digital image correlation (3D-DIC) to examine damage and deformation in HDR samples.
HDR samples from the DOE Utah FORGE project's Well 16B(78)-32 were studied under uniaxial and diametrical compression using a precise 100kN electro-mechanical load frame with a continuous displacement of 0.05mm/min. The samples had a wide range of minerals. During the uniaxial and diametrical compression tests, a3D-DIC image capture system was set up to watch the samples without touching them at a rate of 5 frames per second. A black-and-white speckle pattern is affixed to the specimen to monitor its deformation under load. The 3D-DIC system is used for image processing, visualization, and analysis of the HDR damage process under various load circumstances.
Our preliminary results of DIC-generated quantitative full-field strain maps (tension, compression, and shear) exhibiting all sequences involved in the damage process of HDR samples. To evaluate the sample damage, damage factors are measured using DIC maps; the tension-compression ratio is obtained at 5%-10%. The damage evolution process of HDR specimens is separated into four stages, which are evaluated by damage variables: initial damage stage, linear elastic, elastic-plastic, and plastic damage stage.
The findings have a major impact on our ability to predict the damage process in EGS. DIC outperforms micro-Computed Tomography(µ-CT), Scanning Electron Microscope (SEM), andAcoustic Emission(AE) in terms of test range, affordability, accuracy, and monitoring of the entire field. This method overcomes the laboratory limitations for evaluating HDR damage heterogeneity. This image-based algorithm is better at understanding anisotropic and heterogeneous HDR fragmentation and predicting stimulated reservoir volume (SRV). Thus, the results of this study will enhance the effectiveness of hydraulic fracturing in HDR and heat recovery from EGS.
In-Reservoir Mixing Dynamics Over Geologic Time of Separate Gas and Oil Charges in Well-Connected Reservoirs
Authors: Mohamed Tarek S. , Kristensen Morten , Pan Shu , Wang Kang , Betancourt Soraya S. , Torres-Verdín Carlos , Mullins Oliver C. 
Published: October 2023

Abstract
Many reservoirs experience separate gas and oil charges that can lead to a variety of different outcomes of fluid type and distribution. There has been fundamental uncertainty even as to which charge fluid can arrive first, let alone what fluid dynamic processes can result over geologic time. For high-pressure basins such as the Gulf of Mexico, this mixture can lead to increased solution gas, large GOR gradients and sometimes cause formation of viscous oil and tar at the oil-water contact, impacting aquifer support. In some reservoirs, the present-day outcome of oil and gas mixing over geologic time is clearly established by detailed chemical evaluation of reservoir fluids from many reservoir locations. Our objective is to understand the dynamics of the gas and oil mixing processes. Chemical measurements show that the extent of mixing includes thermodynamic equilibration in young reservoirs by 1) FHZ equation of state (EoS) asphaltene gradients and cubic EoS modeling of solution gas for reservoir fluids, 2) analysis of liquid-phase geochemical biomarkers, and 3) methane carbon isotope analysis. Specifically, in the common charge of primary biogenic gas and oil into reservoirs, methane isotope analysis is unequivocal. We employ reservoir simulation of a point gas charge into oil with various geometries and charge rates to establish parametric conditions which lead to excellent mixing vs those conditions that lead to large, disequilibrium gradients. The roles of compositional diffusion vs. momentum diffusion induced by forced convection are explored both in simulation and overall fluid mechanics analysis, which helps both to validate the results and extend the range of applicable parameters. Modeling results and simple fluid mechanics estimates also establish that there is no possibility that these reservoirs could have a gas charge followed by an oil charge; in the selected reservoirs, oil must have arrived first, followed by a biogenic gas charge. Seismic images of gas chimneys offer guidance regarding how the latter process can take place. Second, modeling results clearly establish a surprisingly wide range of charge conditions that can lead to excellent mixing and equilibration even for a point gas charge. Modeling results also show that for a very fast charge, results are consistent with those expected for CO2 injection and sequestration. The evaluation of geodynamic processes of separate biogenic gas and oil charges into reservoirs has rarely been accomplished. Even the result that biogenic gas charge must occur after oil charge challenges widely-held conventional thinking. In addition, the rapid and thorough mixing (less than 2 million years) of gas and oil charges is unexpected yet readily reproduced by reservoir simulation. The ability to connect CO2 sequestration to a wide range of reservoir studies is a novel way to constrain CCS modeling.
Machine Learning Based Automatic Marker Clustering
Authors: Katole Atul Laxman , Abubakar Aria , Hoekstra Edo , Ryali Srikanth , Zhao Tao 
Published: October 2023

Abstract
Accurate information pertaining to the markers or well tops is critical to define the key formation boundaries in the regional stratigraphic frameworks. The information with respect to the markers in larger basins is spread across multiple sources as the various tools utilized in the Oil and Gas industry, public data repositories and the well logs provided by data vendors. Collaboration across such multiple sources of information is essential if we need to develop subsurface models for the larger basins. However, such collaboration is non-trivial and is accompanied by challenges. The well tops information is interpreted uniquely by interpreters across different organizations, probably using different stratigraphic columns. The multitude of well top information sources, interpreters and stratigraphic columns introduce inconsistencies in the well top information.
We propose deep learning based unique interpretation of the various marker log patterns which can consistently map them across the wells in a region. The transformer model is trained using a self-supervised learning approach to predict the randomly masked well log values in the input. This allows the transformers to learn the feature hierarchy in the marker log patterns which is manifested in the latent space representations. The proposed approach utilizes transformer latent space to represent markers in a lower dimensional feature space which are further projected using Uniform Manifold Approximation and Projection (UMAP) to two dimensional embeddings. We apply Gaussian Mixture Models (GMM) based probabilistic clustering on the embeddings to automatically separate the marker representations. We evaluate the transformer latent space based automatic marker separation models using Bakken open-source dataset and choose six markers for the evaluation. We find that the proposed approach can separate the markers with very high accuracy, giving us excellent precision and recall for all analyzed markers. This approach enables automatic separation of the marker patterns and maps them consistently across the wells in a basin.
Research on the Method of Multi-Agent and Multi-Slug Combined to Achieve the Reservoir Equilibrium Displacement
Authors: Chen Xin , Li Yiqiang , Zhang Jian , Li Xianjie , Liu Zheyu , Liu Shun 
Published: October 2023

Summary
The reservoir and fluid properties determine that a single injected fluid will inevitably undergo channeling during displacement. Whether it is water flooding, gas flooding, or steam flooding, it is necessary to control the injection-production profile. This paper aims to design the multi-agent and multi-slug combination displacement to achieve the equilibrium production of reservoirs. Considering the heterogeneity and median permeability of the reservoir, six three-parallel core models were designed. Polymers, hydrophobic association polymers, microspheres, and PPG are multi-agent profile control systems. The displacement equilibrium factor (DEF) was established by comprehensively considering the profile improvement, oil increase, and oil recovery. The optimal switching time can be determined according to the relationship between DEF and the variation coefficient of oil recovery of each layer. Finally, the five-parallel cores displacement experiments were used to verify the EOR effect under the guidance of DEF. Three-parallel core flooding experiments show that the best EOR efficiency can be obtained by plugging from the high permeability layer to the low permeability layer based on fully producing high-permeability layers. Water flooding - associated polymer flooding - microsphere flooding can increase oil recovery by 25.8% after water flooding. Calculate the DEF of 24 single-slug displacements, and draw a scatter diagram with the variation coefficient of the three layers’ oil recovery. The chart has an obvious inflection point that when the DEF is lower than 45%, the difference in the oil displacement effect is enhanced. Therefore, DEF reduced to 45% is the best time to switch the injection slug. The five-parallel core flooding experiments with the DEF&lt;45% as the switching guidance can increase the oil recovery by 17.79% based on association polymer flooding, which is 9.68% higher than that of the conventional profile control method. Slugs combination mode and switching time of each slug are critical problems in applying multi-agent and multi-slug combination displacement. This work forms a combination idea of prioritizing the full use of high-permeability layers and then plugging them step by step. Meanwhile, a method of using DEF to dynamically guide the switching timing of each slug is formed. This paper can provide theoretical and experimental support for the optimal design of polymer injection parameters in oilfields.
An Application of Superhydrophilic Coating to Enhance the Water Film Retention for Core Annular Flow
Authors: Wang W. , Li Z. Z. , Wang X. L. , Xue Q. , Liu M. R. , Yang J. , Wang P. X. , Ding K. , Sun X. Z. 
Published: October 2023

Abstract
The tremendous viscosity of heavy oil presents significant challenges to the pipeline transportation and efficiency improvement of oil gathering systems, thus prompting the execution of numerous studies that aim to reduce drag. The core annular flow is regarded as one of the most efficient and eco-friendly methods for drag reduction, but its commercial application is limited by the inadequate stability of the water film. In this work, a concept of water film retention enhancement at the pipe wall through superhydrophilic coating is presented, to increase the stability of core annular flow in heavy oil flowlines. Furthermore, a novel measuring method that efficiently evaluates the water film retention enhancement performance of superhydrophilic coating using a rheometer is proposed. This method is more effective, oil-saving, and sensitive compared to conventional flow loop tests. The influence of temperature, shear rate, and water film thickness on water film retention are studied. It was found that the viscosities measured with superhydrophilic coating decreased by approximately 40% at 50 °C and showed a reduced temperature-dependence, compared to the inherent viscosities of heavy oil. This decrease in viscosity was attributed to the lubrication provided by the water film. The viscosities measured with coating were also found slightly decrease with increasing shear rates from 10 to 120 s−1, indicating that the water film retention is enhanced by coating and the emulsification of heavy oil and water film is prevented even under strong shear. Moreover, it was observed that the water film thickness had a negligible impact on the measured viscosities as long as the water was sufficient to fully wet the coating. These results verify the feasibility of using superhydrophilic coating to enhance water retention and show a promising possibility of practical application of superhydrophilic coating in core annular flow for transporting heavy oil.
Statistical Aggregation - A Simple Tool in the E&P Industry for Estimating the Economic Value of a Complex Project
Authors: Khan I. , Aslam M. A. , Hasan A. , Palekar A. H. 
Published: October 2023

Economic evaluation is an important decision-making tool for drilling an exploratory well. The paper is focused on a well drilled in the Mesopotamian basin in Iraq. Before its drilling, it needs to be passed through the technical and commercial gates. The prospect contains multiple (five) reservoir targets. To properly evaluate its technical and commercial potential, it was prudent to give weightage to each reservoir. To assess the Expected Monetary Value (EMV) of the prospect, a total of 32 economic cases needed to be built in the decision tree which makes the working & decision complicated for the management.
It may be noted that in Iraq most companies operate under Service Contracts which itself is not common in the industry to assess commerciality. To cater for the above, a statistical aggregation methodology was adopted in which hydrocarbon volumes (HCIIP) and the chance of success (CoS) of five individual reservoirs were transformed into one number. Accordingly, the economics was performed on this number and the corresponding prospect EMV is calculated. The results were presented to the technical and commercial gates and were accepted by the management and approval was granted.
It may be noted that results from statistical aggregation were rechecked by performing the economics on 32 cases and both results were found comparable. Therefore, this technique was used to quickly assess the EMV of a complex project for decision making and the same technique can be helpful in commercial decision-making of any scale.
The fit-for-purpose approach was utilized in view of the complexity of the project. This work will serve as a reference for statistical aggregation in the oil industry, to evaluate the commerciality of the project with multiple reservoirs. The findings can also be used to gauge the feasibility of any farm-in block where multiple leads and prospects are available, and a quick decision is required to ascertain its value.
Consistent EUR Forecast in Permian Multiphase Unconventional Reservoirs with Pressure Normalized Rate Method
Authors: Xie Xueying , Liu Shunhua 
Published: October 2023

Abstract
Consistent Estimated Ultimate Recovery (EUR) forecasting has been a much-studied topic for the development and reserves estimation of unconventional resources. It is widely known that unconventional well EUR forecasts using Arp's Decline Curve Analysis (DCA) are not very accurate in early time. This is because Arp's empirical equations were originally defined for constant operating pressure and unconventional wells have significant early-time variations in operating pressure. Consequently, EURs based on early DCA are often overestimated. This paper develops the Pressure Normalized Rate Decline Curve Analysis (PNR DCA) method and demonstrates its ability to provide consistent EUR forecasts for Permian multiphase unconventional wells through multiple case studies and dynamic reservoir simulation.
The authors developed PNR DCA method by normalizing actual oil rate to a rate at constant flowing pressure (PNR) and then applying decline curve analysis using the PNR to forecast EUR of Permian unconventional wells with limited production history. This method was first developed for a single-phase gas reservoir, the Haynesville shale (Xie et al., 2012). Lacayo and Lee (2014) introduced this method to forecast wells in four different shale plays (Eagle Ford, Woodford, Marcellus, and Bakken) for more accurate early forecasts, mostly for single-phase oil or gas reservoirs. This paper describes how the method was modified for more complicated Permian reservoirs, in which the resource contains mobile water and many wells feature early gas/oil ratio (GOR) increases, resulting in multiphase flow in the reservoirs.
The method was validated with the data from over 100 wells with significant history (1-5 years) in the Bone Spring, Spraberry, and Wolfcamp formations in both the Midland and Delaware basins. The EUR estimated using the PNR DCA method was also found consistent with forecasts using history-matched dynamic reservoir simulation. The validation results show the PNR DCA method can provide relatively consistent EUR forecasts with limited production data, whereas Arp's DCA method can only forecast consistent EUR after flowing pressures stabilize, which can take a year to achieve. Results indicate that the PNR DCA method works for several sub-regional areas of the Permian Basin, including areas where water cut is as high as 80-90%.
Evaluation of Synergetic Rheological Behaviour of Polymer and Silica Nanofluids for Enhanced Oil Recovery
Authors: Joshi D. , Maurya N. K. , Mandal A. 
Published: October 2023

Abstract
Reservoirs with partially hydrolyzed polyacrylamide (PHPA) aqueous displacing injected fluids improve the amount of oil produced noticeably. However, the medium's temperature and salinity significantly impact the viscosity of these fluids, which is critical in specific reservoir conditions for oil recovery. Thus, adding nanomaterials in PHPA solutions to prepare nanofluids has been shown to be a promising alternative to increase viscosity and improve performance in enhanced oil recovery. The dispersion of NPs in the aqueous polymer solution was characterized by DLS and zeta-potential measurements for stability. The contact angle measurement was also performed of silica nanofluid for examining the ability to wettability alteration. In the rheological studies, it was observed that there was an improvement in the viscosity by adding Silica Nanoparticles in the polymeric solution by 20%. Along with the improvement, silica polymer nanofluid also reduces the viscosity losses at reservoir temperature over 28 days. The experimental results showed that Silica Core flooding experiments were performed to observe the synergetic efficacy of the nanofluids with polymer in barea sandstone core at 90°C. The Silica NPs Assisted Polymer EOR Agent exhibit superior stability characteristics, to a lesser extent, viscosity losses after ageing and good stability, which are desirable for functional application in enhanced oil recovery (EOR) processes, which was confirmed by the result of EOR core flooding with maximum Incremental Oil Recovery of 28 % after water flooding.