bluuebunny/crossref_metadata_2025_split huggingface dataset:
Profiling Asphaltene Inhibitor Performance Using Asphaltene Dispersion, Particle Growth, and Onset Point Methods with Packed-Bed and Capillary Deposition Tests
Authors: Chiang Pinn-Tsong , Bian Yu 
Published: September 2022

Abstract
Asphaltene inhibitors (AIs) are commonly used to mitigate asphaltene deposition issues. AIs are believed to change asphaltene growth behaviors, including dispersion, aging, electrostatic interaction, and/or more parameters, and thus collectively impacting deposition rate. In this work, AI performance was profiled by different methods to identify the responsible mechanisms.
Particle growth profiles were first obtained based on traditional Turbiscan method (ASTM D7061) for larger particle dispersions. Subsequently, a modified Turbiscan method was used to assess the asphaltene growth kinetics. The indirect method was used to detect onset point. Packed-bed (5″ length; 0.334″ ID; 1.5 mm dia. bead) and capillary (100 ft length; 0.03″ ID) deposition tests were done at the same deposition flow rate (0.15 mL/min), time (20 h), and temperature (75 °C). Non-deposited residue was removed by cyclohexane at experiment flow rate. An extra fast flow rate (0.5 mL/sec) wash was applied on packed-bed setup to differentiate between loose and firm deposits.
Untreated sample, along with 150 ppm AI-1, and 150 ppm AI-2 samples were tested with a variety of methods. Overall, both AI-1 and AI-2 show great dispersion and delayed asphaltene particle growth compared to the untreated. The changes of asphaltene growth kinetics were reflected on packed-bed and capillary deposition results as deposition masses for AI-1 and AI-2 treated crudes decreased significantly compared to the blank. Capillary tests yielded less deposition compared to the packed-bed test counterparts. Some asphaltene particles are pushed out of the capillary before deposition due to the higher shear rate but deposited in when compared to packed-bed experiments. By adopting the fast flow rate wash on packed-bed column, we found high correlation between firm asphaltene deposit weight to capillary deposit weight.
By combining different test methods, AI effectiveness is determined at different kinetic stages. The performance profile can provide a systematic method to build structure-property relationships. We believe the testing protocol can facilitate new molecule development.
Wellbore Stabilizing Nanomaterial Assist to Drill Over-Pressured Formations
Authors: Addagalla Ajay , Moroni Luigi , Hoxha Besmir , Gad Ahmed 
Published: September 2022

Abstract
As the oil and gas industry looks for more prolific opportunities, the complexities of drilling have become more sophisticated and consequently there is more risk associated with borehole stability, differential sticking, and mud losses. Some wells, despite their very narrow operating window, require high mud weights to prevent borehole collapse. Therefore, wells are drilled with inherent risks of stuck-pipe, fluid losses, and possible set contingency casing string - all of which can be very expensive in terms of equipment, and lost time.
Drilling through shale is inevitable. Shale tends to be characterized as high in-situ stresses, fissile, laminated, with low permeability. It has been observed that wellbore stability problems occur due to lack of appropriate inhibition from drilling fluids. The most important variable in maintaining shale stability is the prevention of pressure invasion into the shale matrix. Shale stability is achieved when fluid invasion is reduced, and differential pressure support is maintained using pressure reducing additives that provide borehole support. There are many additives currently being used for this application, but all have their limitations, and not all are properly used for appropriate applications.
The latest development in Nanotechnology offers the opportunity to utilise the features of nano-sized particles (sub-micron) in drilling fluids where conventional products fail to deliver required wellbore stability at the target zones. The stabilizing nanoparticle is a dry solid with a particle size of approximately 100-200 nano-meters, deformable, stable, and with a dispersed zeta potential -10 to -20mV. The product can mechanically ‘seal’ micro-fractures and possibly large pore throats in shale thus assisting in forming a semi-permeable membrane. Additionally, the application of these particles could be extended to stabilize weak-bedding planes in geomechanically sensitive formations.
This paper will discuss a product that is suitable for use in both water base and oil base muds that functions to improve wellbore stability at high over-balance pressures. Herein, detailed laboratory work will demonstrate the product behaviour in different mud systems while reducing pore pressure transmission. Additionally, the product has shown to have great stability in high salt and high pH environments while being inert with respect to rheological property changes.
What Can Fluid Properties Do for You: Quantifying the Impact of Downhole Fluid Properties in Reservoir Petrophysical Characterization
Authors: Machado Patrick , Vasconcelos Adna , Bertolini Andre , Carneiro Giovanna , Dantas Marianna 
Published: September 2022

Abstract
Fluid composition has a direct impact on predicted petrophysical properties, mainly on those related to reserves estimation, such as total porosity, water saturation and volume of oil. However, most formation evaluation workflows use properties from literature or black oil models with built-in fluid properties, not considering the effects of different fluid compositions.
This study analyzes petrophysical answers of a target Brazilian carbonate presalt well using a well-established multiphysics inversion workflow with three different approaches for determining fluid properties. The source of the benchmark data used for the fluid properties is a wireline formation tester which can acquire ultra-clean samples from several depths and estimate fluid properties.
The scenarios for assessment of fluid properties are: (a) standard/usual values for presalt fields, (b) properties estimated from a black oil model, (c) and properties estimated from a properly calibrated thermodynamic package. The impact of fluid properties uncertainty is quantified using petrophysical properties estimated using PVT (pressure-volume-temperature) derived fluid properties as the benchmark.
The goal of this study is to quantify the impact of downhole fluid properties throughout petrophysical evaluation workflows and production estimate, mainly for complex fluid composition, such as high CO2 (carbon dioxide) content or light fluids.
Perf Guns, They’re Not Just for Holes Anymore! Perf Cluster Tracer Injection
Authors: Squires Christopher , Leonard Brad , Geerts Shaun , Clay Matthew 
Published: September 2022

Abstract
Oilfield water and oil tracers have historically been pumped into the fracturing fluid during well stimulation. This paper will introduce an alternative method of injecting oilfield tracers that utilizes perforating guns with energetic propellant to force the tracer into a perforation cluster prior to fracturing operations. Direct tracer injection from perforating guns offers several advantages to operators that are interested in oilfield tracer diagnostics, they include:
Monitoring a wells oil or water returns down to an individual cluster level of resolution. Energetic propellent assisted perforation cluster breakdown. Direct tracer injection into clusters for wells that are: Perforated but not hydraulically fractured. Bullhead refracturing treatments with long open intervals of newly fired perforations. Not sufficiently isolated between stages from poor cementing or leaking plugs. Not isolated or experimentally isolated between stages.
Oilfield tracers in solid form were first injected into perforation clusters with energetic propellants on two Marcellus Shale wells. The primary purpose of this experiment was to determine if Perforation Gun Tracing (PGT) could be used to provide flow-assurance diagnostic information to the well operator. Additionally, standard liquid water tracers were also injected into the flowstream during the corresponding fracture treatment stages and used as a control for the PGT. Both tracer injection methods indicated that the toe side of the wellbore was contributing to the fluid returns profile and also showed similar trends in tracer response over time. This experiment showed that PGT could provide valuable diagnostic information to well operators.
Several additional field trials that exploit the unique benefits of PGT were completed after the success of the initial experiment and are included in the case studies section of the paper. In each case, PGT was able to provide the intended diagnostic which included flow-assurance, flow-profiling, fracture driven interactions and/or refracturing effectiveness.
In refracturing, PGT has tremendous benefits because the energetic propellent can help the new perforations breakdown and compete with the existing broken down and eroded perforations. Additionally, unique tracers are injected at several known cluster depths throughout the lateral. Any returns of the unique tracers in the flowback water will correspond to fracturing fluid that has contacted the depth of that specific traced cluster. This provides an operator valuable diagnostic information to determine how deep their refracture treatment was able to reach into the lateral. PGT also delivers information on the returns of an individual cluster, without post-frac well intervention or permanent hardware installation.
Deep-Learning-Based Direct Forecast Approach for Fractured Shale Gas Reservoir Under Geological and Hydraulic Fracture Parameter Uncertainty
Authors: Xiao Cong , Zhang Shicheng , Ma Xinfang , Zhou Tong 
Published: September 2022

Abstract

Summary
Accurate ultimate recovery prediction and uncertainty quantification are of significance during the process of unconventional shale resources development field development plan formulation. The uncertainties related to characterization of geological parameters and especially hydraulic/natural fracture system are not readily quantified through conventional model-based history matching procedure in practical applications. Data-space inversion (DSI) is a recently proposed data-space analysis and rapid forecast approach that easily samples the posterior predictions based on an ensemble of prior predictions and historical measurements. This paper presents a novel methodology based on a hybridization of DSI and a vector-to-vector residual neural network, referred to as DSI-DL, for well production forecast in unconventional shale reservoirs. A data-augmentation strategy that has been exploited in the literature is employed to generate a large number of training samples from a relatively small ensemble of shale reservoir model simulations. The DSI-DL method treats the shale gas production in our expected future time as target variables, which are directly predicted from pre-trained deep-learning model given historical data. This method enables us completely avoid the time-consuming history matching process where the characterization and inversion of hydraulic/natural fracture topology are highly complicated. We demonstrate the performances of this new approach on a synthetic vertically fractured well and a multi-well production scheme in naturally fractured shale formation. Some comparison with conventional DSI procedure and model-based history matching have shown that DSI-DL method achieves relatively robust results in estimating P10-P50-P90 values of shale gas time-series production against to data noise and prior ensemble size. DSI-DL algorithm will greatly contribute to the real-time prediction and optimization of shale gas well production rapidly given the streaming online observation data and have a wide range of practical application prospects, while a high computational efficiency remains. The proposed DSI-DL approach definitely will be useful for petroleum engineers to assess the value of information and manage the uncertainty of unconventional resources development.
Detectable Radius of Investigation for One Flow Period with Bourdet Derivative
Authors: Jiang Lei , Chen Li , Yu Hua , Kristensen Morten , Gisolf Adriaan , Dumont Hadrien 
Published: September 2022

Abstract
A new definition of the radius of investigation (ROI) is proposed to overcome the ambiguity present in the results from conventional ROI quantification methods.
The term ROI is commonly used to quantify the minimum reservoir size or the distance to a potential boundary evaluated through pressure transient testing. However, the various methods that exist in the literature to quantify ROI provide different answers stemming from varying assumptions and thus often lead to confusion in terms of the appropriate definition to choose. Although the ROI method developed by Van Poolen is well recognized in the industry, there is a debate about its general applicability because it is limited to a constant-rate flow period and is insensitive to flowrate and flow sequence, to gauge resolution or measurement noise level. This contrasts with operational experience, where a higher flowrate, higher gauge precision, and a lower level of measurement noise generates higher quality pressure transient testing data from which reservoir boundaries, or other features, can be identified farther away from the wellbore. In other words, higher flowrates, better gauges, and lower noise levels can lead to larger achievable ROI.
We propose a new definition of ROI, that is the detectable ROI for each drawdown or build-up flow period and is derived from the actual pressure derivative response and not from a generic model assumption. By defining a derivative noise envelope, the new method clearly identifies the time when the derivative deviates from an unbounded model due to the presence of a boundary and thus provides an estimate of the detectable ROI for the analyzed period.
This method overcomes the limitations of most conventional methods and provides ROI predictions that depend on flowrate and gauge noise while maintaining a consistent result with current pressure transient interpretation.
Lessons Learned in a Decade of Automated Reservoir and Production Engineering Surveillance
Authors: Fair Chris , Flores Ricardo 
Published: September 2022

AbstractIntroducing new technology in the oil patch is not for the faint of heart. Introducing automation, which some perceive as threatening their jobs, as opposed to making their jobs easier and their decision process more efficient, requires some form of irrationality. With this in mind, the authors would like to take the readers through their journey of the last ten years, with the hope that others can learn from their experience.Without making any claims about the efficacy of the technology (Fair, 2014) to solve every problem an operator has, and without badmouthing any potential competition (Lesson 1: Never do this! It makes YOU look bad!), the authors introduced the technology via the ‘drug dealer’ method: The first time is free…When people come back for more, start charging. The technology was introduced and trialed at most majors and many of the larger independent companies, with a surprising amount of early adoption. There was then a significant bifurcation in the way the majors and the independents behaved.Amongst the independent operators or majors with operating units that acted like independents, acceptance of the technology in the U.S. Gulf of Mexico and North Sea was very binary. Either it was accepted as plausible and at least tried-out, or it was declared impossible and outright rejected.Amongst the majors and the independents that act like majors, the entry path to a trial was byzantine. A couple of majors never accepted free trials. Amongst the others that did go to a trial, once the trial was completed, it never led to implementation…rather, it led to years-long internal R&d (that’s right…Big R, small d) efforts, usually resulting in nothing. This inevitably led the holders of the purse strings to declare that since their internal experts couldn’t duplicate or even understand the technology, it was therefore impossible and/or does not work.The reason the engineers and managers at the independents adopted the technology was that they were ‘closer to the coal face’. It didn’t matter if they understood all of the details of the technology. What mattered was simple: Can using this technology make the company more money (or save it more money)? Quite frankly, the technology implementation was more successful the less the company management cared about understanding the minutia.This paper presents a firsthand account of how technology is absorbed or rejected by different company types in the oil & gas industry and seeks to explain the reasoning behind their decision-making. It also provides some guidance to others who wish to bring new tech to the oil patch.Note: This will not be a formal technical paper. This will be more akin to an editorial/advice column, presented in a way that hopefully helps the reader use their time more efficiently and promote their ideas more successfully. As such, a good portion of the article will not be written in third person.
Analysis of Tidal Behavior of a Horizontal Well to Determine Reservoir Properties
Authors: Lu Xunfeng , Sato Kozo , Horne Roland 
Published: September 2022

Abstract
Tidal analysis requires only continuous pressure monitoring data and therefore is a cost-effective technique for estimating reservoir properties. Previous tidal analysis work focused on vertical wells. This study developed and solved tidal response models for a horizontal well considering skin effect and wellbore storage in three classical reservoir types: confined reservoir, semiconfined reservoir, and reservoir with mixed boundaries.
Green's function, source functions, Laplace transform, and Duhamel's principle were used to solve the models and obtain analytical solutions in Laplace space. Then, Laplace transform numerical inversion was utilized to invert the Laplace space solutions to time-domain solutions. Variable condition analysis was conducted to analyze the effects of different parameters (wellbore storage, skin effect, well length, well direction - horizontal or vertical, and vertical leakage) on tidal behavior:
For confined reservoirs, the influence of skin effect and wellbore storage (under the condition of positive skin effect) both tend to decrease the tidal amplitude ratio and increase the tidal phase lag. Longer wells lead to a smaller tidal amplitude ratio and lead to a larger tidal phase lag for small wellbore storage, and smaller tidal phase lag for large wellbore storage.
For reservoirs with mixed boundaries, the effect of wellbore storage depends on the value and sign of skin factor. A horizontal well with larger skin effect will have larger tidal phase lag and tidal amplitude attenuation.
For a semiconfined reservoir, the tidal amplitude ratio first increases with increasing vertical leakage but then decreases when there is a large vertical leakage. Vertical leakage tends to decrease the tidal phase lag or increase the tidal phase advance.
Successful CO2-Foam Field Implementation for Improving Oil Sweep Efficiency in EVGSAU Field at Permian Basin: Expansion Phase
Authors: Hassanzadeh Armin , Katiyar Amit , Kalaei Hosein , Pecore Doug , Schofield Ephraim , Nguyen Quoc , Gilchrist Corey 
Published: September 2022

Abstract
A successful CO2-foam technology has operated at the East Vacuum Grayburg San Andres Unit (EVGSAU) since Jan 2018 by ConocoPhillips in cooperation with Dow. In early 2020, scope of the technology was expanded from one pattern to three patterns. The expansion phase was implemented to evaluate scalability of this technology to patterns with diverse conformance issues and productivity inefficiencies. Severe vertical and areal conformance issues were initially identified in these patterns, resulting in early gas breakthroughs and poor oil sweep efficiencies. Due to the outstanding performance of the first phase, the same surfactant with high foaming tendencies, high gas solubility, and low adsorption characteristics was implemented in the new patterns.
In contrast to the first foam pattern, gas injectivity was reduced by 20 to 50% after only 2 foam cycles in the new patterns. Based on injection profile logs (IPL), no out-of-zone injection was identified before the surfactant injection for the two new patterns, which can be the reason for such rapid injectivity responses. Similar to the first pattern, deep conformance corrections were confirmed as gas was redirected from highly connected producers to other producers within the new patterns. A lower surfactant dosage was applied to one of the new patterns to optimize chemical consumption, while sustaining the performance. The surfactant concentration was also reduced in the first pattern to study the effect of a lower dosage on a known performing pattern. During the foam implementation, the gas to water ratio (GWR) at the pattern injectors was increased to maintain the patterns at the baseline fluid throughput. This adjustment resulted in more than a 50% reduction in water consumption and a 17% improvement in gas utilization. Overall, a sustainable increase in oil production rate (30 to 40% over the baseline for the last two years) was achieved in the three foam patterns as a result of the foam implementation.
This three-pattern CO2-foam field result is an outstanding example of how proper implementation of a novel surfactant in a conventional reservoir with mild-to-severe deep conformance issues can improve oil sweep efficiency. The application of this foam technology has demonstrated the extension of the life of a mature asset like EVGSAU by arresting the historical decline in the oil production rate. Reduction in energy and water consumption per barrel of oil produced, and further CO2 sequestration are other benefits of this technology.