bluuebunny/crossref_metadata_2025_split huggingface dataset:
Solvent-Loaded Microspheres for Permeability Enhancement in Heavy Crude Oil Reservoirs
Authors: Yegin Cengiz , Temizel Cenk , Akbulut Mustafa 
Published: September 2021

ABSTRACT
With their abundancy and high-quality, it is predicted that fossil fuels will remain as the main resource that will meet the global energy demand in the several upcoming decades. Developments in hydrocarbon recovery technologies, both from conventional and unconventional reservoirs, have substantially contributed to the overall production levels in recent years. However, recovery factors obtained by using the current methods are still considered to be insufficient, and the companies have been looking for new materials and methods to enhance the efficiency and amount of recovery.
One of the major issues related to low recovery factors is low permeability of reservoirs. Existence of blockages in pore throats and high level of heterogeneity lowers the mobility of hydrocarbons. In this study, we discuss development of an innovative material to be used as an additive in reservoir injection fluids to remove pore blockages in order to enhance the recovery levels.
This additive material is made of pressure-sensitive microspheres loaded with solvents, which can (i) easily disperse in the injection fluid and travel to the low-permeability regions, (ii) break under pressure and confinement to release solvents, and (iii) remove blockages by targeting surroundings, especially asphalt-based particles and grains. This approach relies on the breakage of microcapsules in the confined region and release of the solvents to target blockages in porous media. In other words, the developed microspheres improve permeability of reservoirs as a result of pressure- and confinement-dependent breakage and release of solvents. Preparation of these microspheres was achieved by the encapsulation of solvent (toluene) emulsions in silica-based solid shells. Structure and stability of the solvent-loaded microspheres were examined using a variety of analytical techniques including UV-vis spectroscopy, optical microscopy, scanning electron microscope (SEM) and dynamic light scattering (DLS). It was found that the prepared microspheres possessed smooth surfaces with shell thicknesses in the range of 100-150 nm. Additionally, sand column tests were performed to evaluate the recovery potential of injection fluids in presence of solvent-loaded microspheres. It was shown that the use of solvent encapsulated in microspheres doubled the recovery factor of heavy oil compared to that of free solvent dispersed in the injection fluid. Such enhancement in the recovery factor was related to the release of solvents in localized areas, i.e., confined regions, as a consequence of breakage of microspheres. This novel approach of delivering solvents to low-permeability regions provides a significant driving force to eliminate pore blockages to facilitate mobilization of hydrocarbons trapped in confined spaces.
Multizone Openhole Gravel Packing with Enhanced Shunt Screens and Zonal Isolation in High-Rate Gas Wells
Authors: Markham Ross , Michell Alastair , Noblett David , McCartan Bernard , Sugiarto Septiandi , Huynh Tony Trung , Kumar Amrendra , Gadiyar Bala , Gupta Susheel , Rudic Aleksandar 
Published: September 2021

Abstract
A reliable single-trip openhole multizone completion can significantly lower capital expenditure (CAPEX) by reducing rig time and well count. Recent improvements in openhole packers and enhanced shunt screen technology have enabled multizone openhole gravel pack completions with complete zonal isolation. A multizone openhole gravel-pack completion was installed in the Julimar Field with an enhanced shunt screen system, shunted mechnaical packers (SMP) and shunt tube isolation valves (STIV), to provide improved operating pressure envelope and erosion tolerance. Well design was tailored to derisk the installation and optimize performance of the multizone completion. Extensive reliability testing was undertaken on all new technology for this project.
Completions were installed as planned, and the main objectives of sand control integrity, production attainment, and complete zonal isolation with selective production were validated through post-job gravel-pack analysis and subsequent well unloading. The successful implementation of these technologies significantly reduced project CAPEX and enabled access to reserves that would otherwise have been uneconomical to recover.
This paper discusses design, execution, and evaluation of the multizone openhole gravel pack (OHGP) completions installed in the Julimar Field. This includes methodology followed for multizone completion selection, development of a new high-temperature formate-based viscous gravel-pack carrier fluid, detailed completion equipment qualification tests, post-job gravel-pack evaluation, and initial well performance from well unload. It is the industry's first field case study of enhanced shunt screens with novel shunt tube isolation valves and high-temperature xanthan-based gravel-pack carrier fluid.
New Wellbore Proppant Transport Model Improves Prediction of Multiple Fracture Propagation in Horizontal Wells
Authors: Sinkov Konstantin , Shrivastava Kaustubh , Kresse Olga , Abbas Safdar , Knyazev Egor , Spesivtsev Pavel 
Published: September 2021

Abstract
Completion optimization in hydraulic fracturing operations requires understanding the interaction between simultaneously propagating multiple fractures and the distribution of fluid and proppant among the fractures during the treatment. Diagnostic methods often reveal that propagation of fractures within single stage is quite uneven. Nonuniform growth is caused by a complex interplay between fracture mechanics and hydrodynamics of proppant transport in wellbore and perforations. A recently developed numerical model simulates the transient proppant slurry flow in the wellbore, considering proppant transport and settling, including bed formation, fluid rheology, perforation erosion, rate- and concentration-dependent pressure drop, and variable efficiency of proppant transport through perforations. The model is numerically coupled to an advanced fracture simulator that models fracture growth, fluid flow, proppant transport inside complex hydraulic fracture networks, and mechanical interaction between adjacent hydraulic fractures. The coupled model enables comprehensive simulations and captures the mutual influence of the transport of proppant in the wellbore and the propagation of fractures. Integration of the model into the proprietary stimulation-to-production workflow allows leveraging available data and applying the model to optimization of completion strategy and design. The coupled model is shown to agree with the results of analytical models in special limiting cases. It also qualitatively reproduces patterns of proppant distribution observed in the field with the help of various fracturing monitoring techniques. Parametric studies demonstrate that the combined influence of proppant inertia causing higher concentration of proppant in toe clusters, erosion of perforations, and transient pressure response of fractures leads to the nonuniform and transient distribution of the injection rate among fractures. Simulation results show that the nonuniform proppant transport efficiency induced by proppant inertia and broad proppant size distribution can be superposed on the stress shadow effect and lead to the uneven growth of fractures within a stage. The integrated model is efficient and allows routine optimization of fracturing treatment designs. An example of the design optimization illustrating wellbore proppant transport effects on treatment dynamics and showing the value of the coupled wellbore-fractures simulations is also provided.
Development and Evaluation of Ultra-High Temperature Resistant Preformed Particle Gels for Conformance Control in North Sea Reservoirs
Authors: Schuman Thomas , Salunkhe Buddhabhushan , Al Brahim Ali , Bai Baojun 
Published: September 2021

Abstract
Preformed particle gels (PPGs), a type of hydrogel, have been widely applied to control the conformance of reservoirs owing to their robust gel chemistries. Traditional PPGs are polyacrylamide-based hydrogel compositions which can withstand neither higher temperatures nor high salinity conditions. There are many deep oilfield reservoirs worldwide which demand PPG products with a long term hydrolytic and thermal stability at the temperatures of higher than 120 °C. Current PPGs neither remain hydrated nor retain polymer integrity at these temperatures. A unique high temperature-resistant hydrogel composition (HT-PPG) was developed with exceptional thermal stability for greater than 18 months in North Sea formation temperature (~130 °C) and formation water environments. HT-PPG described herein can swell up to 30 times its initial volume in brines of different salinity for North Sea. The effects of salinity and temperature on swelling, swelling rate, and rheological behavior was studied. These HT-PPGs exhibit excellent strength with storage modulus (G’) of over 3,000 Pa at the swelling ratio of 10. Thermostability evaluations were performed in North Sea brines with variable salinity at temperatures of 130 °C and 150 °C and found to be stable for 18 months with no loss of molecular integrity at the higher temperature. Laboratory core flooding tests were conducted to test its plugging efficiency to fracture. HT-PPGs showed good plugging efficiency by reducing the permeability of open fracture and did not wash out during waterflooding. Overall, HT-PPG is a novel product with excellent hydrothermal stability that make it an ideal candidate for conformance problems associated with reservoirs of high temperature and salinity conditions.
Innovative Technologies Deliver Operational Objectives in a Multi-Well, Ultra-Deepwater, Managed Pressure Drilling and Completions Campaign
Authors: Fisher Andrew , Kaura Jiten , Kratzer Matthew , Oyler Ken , Reutzel Ron , Teoh Michael , Thomassen Scott , Vives Javier 
Published: September 2021

Abstract
The deepwater development field in the western Gulf of Mexico (GoM) presents an array of complex challenges for ultra-deepwater drilling operations. The four well campaign was particularly challenging due to extreme water depths, remote location, well trajectory and a narrow pressure environment, 350-100 kpa (50-150 psi), for extended reservoir laterals. The authors highlight the use of innovative technology employed to drill and complete wells in the western GoM deployment, coupled with the first-ever use of controlled mud level (CML), managed pressure drilling technology in the Gulf of Mexico. The approach of selecting the fluid systems to achieve the objectives and the use of hydraulics modeling software with CML modeling capability in the design, planning and execution phases of the project allowed for fluid design optimization. The results were a successful drilling and completion campaign managing multiple fluids systems and operations on an ultra-deepwater, dual-activity drill ship in water depths more than 8,500 ft (2,591 m). The authors discuss the initial use of a low equivalent circulating density (ECD), flat-rheology synthetic based fluid (SBF) designed for narrow margin drilling applications and the transition to the deployment of a newly developed high-performance water-based mud (HPWBM) optimizing the operations to drill the intermediate intervals for final two wells. The authors also will discuss use of the reservoir drill-in fluid (RDF) and solids-free screen running fluids (SF-SRF), designed specifically for use in these open holes, gravel pack completions at hole angles upwards of 90°. Operational efficiencies derived from use of these fluids include ECD management, hole cleaning, directional performance, reduction in downhole losses, and the elimination of non-productive time (NPT) in a narrow margin environment with no loss of rate of penetration (ROP). Additional efficiencies include the seamless transition from derived from use of water-based fluids for drilling and completion phases. Use of the CML technology allowed for precise control of the hydrostatic pressure on wells that previously would not have been technically feasible to drill or complete. The novel use of the newly developed HPWBM on this campaign enabled reduced health, safety and environmental (HSE) exposure impact, increased tank and rig cleaning efficiency, and the elimination of a wellbore cleanout run since the entire well was drilled with only water-based fluids. The fluids were successfully employed in the four wells drilled and completed in a managed pressure environment utilizing CML technology.
A New Experimental Method for Measuring Improved Oil Recovery in Shales
Authors: Quintanilla Zach , Russell Rod , Sharma Mukul 
Published: September 2021

Abstract
Improved Oil Recovery, IOR, in shales is a topic of growing interest due to the low oil recovery observed in shales. Evaluating different IOR chemicals at the lab scale has proved difficult and time consuming due to their ultra-low permeability and low porosity. Conventional core procedures (such as core floods) are often not practical to use with such samples since they take too long.
In this study, we introduce a new laboratory method for measuring the oil recovery in a huff-and-puff IOR process in shales. In huff-and-puff IOR, a treatment additive and a gas are typically injected in combination into the reservoir. Oil production is initiated after a shut-in period. Our experimental protocol starts by saturating preserved shales with oil by exposing them to the reservoir oil under pressure for an extended time. To speed up this process the preserved shale sample is crushed and sieved to 5-10 mesh. The pressure vessels are then loaded with these oil-saturated 5-10 mesh shale particles and the desired IOR fluid is injected into the pressure vessel. The vessel is rotated to ensure full contact with the shale. The samples are heated to ensure that the fluid is at reservoir pressure and temperature. Several tests were done to ensure that the fluid temperature and pressure inside the vessels were at the desired conditions throughout the 72-hour test period. T2 NMR scans were carried out before and after treatment to determine the amount of incremental oil recovery from the treatment. In tests where the two fluid phases were indistinguishable, deuterium was used in the treatment fluid in lieu of water. Excellent reproducible results were obtained with this method. This new method has been used to test a number of different treatment fluids, gases and solvents under a variety of conditions. The test can be completed in a matter of a few days as compared to several weeks that would be required for a core flood. Several tests can be run simultaneously, further speeding up the process. The results of the laboratory tests can be scaled to the field by using suitable surface-to-volume ratios in the lab and comparing them to the field.
With this new method we have a fast and robust method for conducting these huff-and-puff experiments in a repeatable, and precise manner. This allows us to quickly evaluate different IOR fluids for a particular shale-fluid system at reservoir conditions.
A Smart Classification Framework for Enhancing Reliability in Downhole Gas Bubble Sensing
Authors: Katterbauer Klemens , Schoepf Virginie , Marsala Alberto , Abbassi Linda 
Published: September 2021

Abstract
Production logging tools (PLTs) and formation testing, even in logging while drilling (LWD) conditions during underbalanced drilling, are key technologies for assessing the productivity potential of a gas well and therefore to maximize recovery. Gas bubble detection sensors are key components in determining the fluid phases in the reservoir and accurately quantify recoverable reserves, optimize well placement, geosteering and to qualify the production ability of the well. We present here a new nonlinear autoregressive - breakdown artificial intelligence (AI) detection framework for PLT gas bubble detection sensors that categorize in real-time whether and which sensors become unreliable or have broken down during the logging measurements. AI tools allow the automatization of this method that is critical during data quality control of post-drilling PLT, but it is essential when the measurements are performed in LWD as data assessment and processing need to occur in real time. This AI framework was validated on both a training and testing dataset, and exhibited strong classification performance. This method enables accurate real-time breakdown detection for gas bubble detection sensors.
Interval Density Analysis From a Distributed Absolute Pressure Array
Authors: Hewlett Richard , Pink Stephen , Goswami Jaideva , Debrosse Daniel , Wright Charles 
Published: September 2021

Abstract
The objective of this paper is to evaluate the effectiveness of a distributed pressure sensor array along the drillstring in identifying and quantifying fluid influx into the wellbore.
As part of a real-time wired drillpipe (WDP) network, distributed sensors can be spaced along the network at varying intervals. In the fall of 2020, a test well was drilled where such a WDP network was utilized, involving 11 discrete sensor packages. These distributed sensors consisted of absolute annular and internal pressure transducers. From these distributed sensors, analysis of various intervals was examined for fluid effects including density analysis. This paper summarizes the findings of the tests and analyses.
The WDP network (Craig, et al. 2013) is the underlying technology that allows for the distributed sensor array and the real-time processing of measured data. Each discrete sensor package is a node on the network. The industry-leading telemetry bandwidth of the WDP network allows for many sensor nodes. The test well drilled in the fall of 2020 gave an opportunity to place 11 sensor nodes along the drillstring. The real-time absolute pressure data collected from these nodes was analyzed for various intervals, calculating differential pressure between pressure sensor nodes and further calculating interval fluid density.
The results of the distributed absolute pressure data provided many interesting observations. The effectiveness of the interval density for quick-look monitoring was greatly enhanced from the more traditional view of the raw pressure data alone. The effects of sensor spacing and sensitivity were easily observed. Tracking variations in fluid density as it transitions through the wellbore can provide insight into fluid mixing, fluid velocity, and transmission time. Transmission time through the various intervals can further provide insight into wellbore conditions. The slope and peak of interval fluid transitions help understand volumetric and specific density details of fluid transitions from events such as drilling mud pills and influx materials.
This novel dataset showcases the power of a real-time distributed sensor array. Multiple intervals of interest can be examined, leading to a new level of wellbore understanding. Information concerning the wellbore fluid can aid in real-time decision making to optimize the wellbore and associated operations, while providing a new level of risk avoidance and safety factor.
Mitigation of Gas Condensate Banking Using Thermochemical Fluids and Gemini Surfactant: A Comparison Study
Authors: Hassan Amjed , Mahmoud Mohamed , Kamal Muhammad Shahzad , Al-Majed Abdulaziz , Al-Nakhli Ayman , Shakil Hussain Syed Muhammad , Patil Shirish 
Published: September 2021

Abstract
Accumulation of condensate liquid around the production well can cause a significant reduction in gas production. Several methods are used to mitigate the condensate bank and maintain the gas production. The most effective approaches are altering the rock wettability or inducing multiple fractures around the wellbore. This paper presents a comparison study for two effective approaches in mitigating the condensate bank. The performance of thermochemical fluids (TCF) and gemini surfactant (GS) in removing the condensate liquid and improve the formation productivity is studied.
In this work, several experiments were carried out including coreflooding, capillary pressure, and relative permeability measurements. The profiles of condensate saturations show that GS can mitigate the condensate bank by 84%, while TCF removed around 63% of the condensate liquid. Also, GS and TCF treatments can increase the relative permeability to condensate liquid by factors of 1.89 and 1.22 respectively, due to the wettability alteration mechanism. Capillary pressure calculations show that GS can reduce the capillary pressure by around 40% on average, while TCF leads to a 70% reduction in the capillary forces.
Overall, injection of GS into the condensate region can lead to changing the wettability condition due to the chemical adsorption of GS on the pore surface, and thereby reduce the capillary forces and improve the condensate mobility. On the other hand, TCF injection can improve rock permeability and reduce capillary pressure. Both treatments (GS and TCF) showed very attractive performance in mitigating the condensate bank and improving the formation production for the long term. Finally, an integrated approach is presented that can mitigate the condensate damage by around 95%, utilizing the effective mechanisms of GS and TCF chemicals.