bluuebunny/crossref_metadata_2025_split huggingface dataset:
Understanding the Dynamics of Matrix-Fracture Interaction for Suitable Fracturing Fluid Design and Chemical EOR in Unconventional Oil/Gas Recovery
Authors: Lin Lixing , Babadagli Tayfun , Andy Li Huazhou 
Published: March 2024

Abstract
The effects of chemical additives on mitigating water-blocking and improving oil recovery were experimentally examined for gas-water and oil-water systems in spontaneous imbibition cells. In these attempts, two factors are critically important: (1) Understanding the physics of the interaction, whether it is co- or counter-current, and (2) characteristics of the chemical additives to suitably orient the interaction for specific purposes (accelerate/decelerate matrix-fracture interactions). Co- and counter-current imbibition experiments were conducted on sandstone rock samples using various oil samples (viscosities between 1.37 and 54.61 cP) as well as gas (air). The selected new-generation chemical additives include deep eutectic solvents, cationic/anionic/nonionic surfactants, inorganic and organic alkalis. We observed that the functionality of the chemicals varied depending on the fluid type, interaction type (co- or counter-current), and application purposes. For instance, chemicals such as cationic surfactant CTAB significantly reduced water invasion into the gas-saturated sandstone cores during fracturing, while chemicals such as a nonionic surfactant (Tween 80) provided considerable oil recovery improvement in the oil-saturated sandstone cores. The surface tension and wettability of the rock surface are crucial factors in determining the suitability of chemicals in mitigating water blockage. In terms of the oil recovery, certain chemical additives, such as O342 and Tween 80, may result in a lower recovery rate in the early stage because their strong ability in IFT reduction but could lead to a higher ultimate recover factor by altering the wettability. Additionally, the introduction of chemicals resulted in notable spontaneous emulsification, especially in counter-current imbibition, thereby enhancing oil recovery. The spontaneous emulsification and its stability are influenced by factors such as oil drop size, boundary condition, interaction type, IFT, wettability, as well as rock surface charges. The results have implications for understanding the physics and dynamics of matrix-fracture interactions in co and counter-current conditions. Additionally, they offer practical insights for selecting appropriate chemical additives in hydraulic fracturing fluid design and enhancing oil recovery in unconventional reservoirs.
Dielectric Property Measurements in Frequency Domain of Water Saturated Clean and Oil Sands at Elevated Thermobaric Conditions
Authors: Kuznetcov I. , Kantzas A. , David S. 
Published: March 2024

Abstract
Electromagnetic (EM) irradiation is a relatively nascent, but promising oil recovery method. It is well-positioned to enable carbon-free oil production from heavy oil- and bitumen-rich formations. Unfortunately, this method has not been widely adopted yet due to a lack of understanding of the dielectric properties of oil-bearing rocks at elevated thermobaric conditions. The present work aims to bridge this gap by conducting dielectric property frequency spectra measurements of heated and pressurized "native" core samples.
A patented system was commissioned and a series of dielectric measurements of saturated oil sand core samples were performed in two successive heating-cooling cycles within the 20°C to 220°C range. The pore pressure was kept constant above steam saturation point for the first cycle and was purged by the second cycle's end to induce evaporation. Moreover, every measured sample was compacted by a load of 1000 psi (6.89 MPa). In addition, a comprehensive database management system was designed to facilitate automatic data acquisition of the time- and temperature-series of the relative dielectric constant and conductivity frequency responses.
The relative dielectric constant and the conductivity frequency spectra were found to be directly proportionate to temperature with some level of hysteresis between the heating and cooling cycle trends. To better visualize and interpret this behavior, three-dimensional maps of the dielectric properties in frequency-temperature domain were constructed. Singularities were observed in the results for the saturated clean and oil sand samples at certain resonant frequencies. Those frequencies signify extremums in the EM energy transfer to the formation. Increased values in the relative dielectric constant and decreased values in the conductivity at frequencies smaller than 1 MHz were attributed to the electrode polarization effect, which becomes more prominent at higher temperatures and concentration of dissolved solids. In all heating experiments of water saturated clean sands a full evaporation of the pore fluid was achieved, and the dielectric properties would approach the properties of air. However, no steam desiccated zones were observed in the oil sand samples. As a result, the local concentration of ions, minerals and other solids present in the pore fluid increased, which was further confirmed by the increase in the measured dielectric properties.
To the best of the authors’ knowledge this was the first time the dielectric measurements of "native" oil sand sample cores that make up most heavy oil- and bitumen-bearing formations in Athabasca region, were performed in variable temperature-pressure-steam quality environments. These measurements should provide better means to modelling of electromagnetic energy dissipation in different parts of the formation and forecasting oil production by relevant EM heating methods.
Scaled Physical Modeling of Cyclic CO2 Injection in Unconsolidated Heavy Oil Reservoirs Using Geotechnical Centrifuge and Additive Manufacturing Technologies
Authors: Perez Daniel Cartagena , Shokri Alireza Rangriz , Zambrano Gonzalo , Pantov Dymtro , Wang Yazhao , Chalaturnyk Rick , Hawkes Chris 
Published: March 2024

Abstract
The success of CO2 injection in shallow reservoirs such as CHOPS (Cold Heavy Oil Production with Sands) entails an understanding of the complex interplay of mechanics of gaseous solvent interaction, reservoir deformation, and borehole collapse. This paper provides the design of a highly-instrumented scaled laboratory experiment inside a 2-meter radius beam geotechnical centrifuge, capable of simulating the cyclic CO2 injection into an unconsolidated sandstone specimen at reservoir conditions.
Given that sand production during CHOPS creates high-permeability channel-like structures, additive manufacturing technology (i.e. 3D printing with actual sand particles) was used to fabricate the physical model specimen of a scaled reservoir. A centrifuge cell was designed and constructed to simulate the multi-phase cyclic CO2 injection process at the reservoir scale. Scaling factors for stress, time, height and density were used to determine the centrifuge operation. A loading system was included in the centrifuge cell to emulate the vertical stress from the overburden rocks at the top of a shale caprock layer. Stress anisotropy in horizontal stresses were applied through an 8-arm horizontal loading system, similar to a true triaxial cell. A sand trap and a production unit were used to collect the collapsed sands and the produced fluids.
To establish residual water saturation, the reservoir prototype was first saturated with water, followed by dead canola oil and live oil (prepared by dissolving CO2). The experiment was started by spinning the 500 kg setup inside the geotechnical centrifuge until it reached a steady rotational speed of 120 revolutions per minute (equivalent to 30 times the gravitational acceleration). The perforations of a scaled wellbore within the reservoir prototype were opened to initiate fluid and sand production. It appeared that the increase in the cohesion of the 3D printed rock in regions away from wellbore reduced rock failure during production cycles even with large seepage forces and pressure gradients. The structural changes around high-permeability zone and near-wellbore region were related to stress concentration.
The result of our scaled physical experiments delivers insights on fluid displacement and rock deformation during CO2 saturated oil production from a reservoir prototype. The application of a geotechnical centrifuge and additive manufacturing technology provides a platform to experimentally explore the multi-scale, multi-physics processes of sampling, flow, and deformation issues observed in subsurface systems including H2 storage and safe disposal of radioactive waste.
Geomechanical Modeling and Minimum Fracture Pressure Prediction of CO2 Storage Reservoir Caprock in the Lloydminster Area
Authors: Shen Chen , Li Ze , Chang Yuanhao , Zhang Baoxin , Zeng Fanhua 
Published: March 2024

Abstract
Acknowledging the critical imperative to reduce CO2 emissions globally, there is a heightened drive towards adopting the preferred CCUS technology to achieve sustainable greenhouse gas reduction. CCUS requires a reliable caprock integrity to prevent CO2 migration and ensure the success of the injection program. Nevertheless, the impact of mineralogical alterations on caprock integrity continues to elude comprehensive understanding through research. This study investigates the evolution of caprock integrity resulting from long-term CO2 storage-induced mineralogical changes. A 2D Voronoi model is developed to predict the minimum fracture pressure of sideritic shale caprocks with varying mineral compositions in the Waseca heavy oil formation, Canada. The numerical simulations are validated against geomechanical test results, showing good agreement. Sensitivity analysis reveals visible variations in the plastic deformation process due to CO2-water-rock reactions and mineral transformations. Results indicate that caprocks with higher hard minerals, such as quartz, exhibit higher minimum fracture pressures. Additionally, positive interactions between siderite and feldspar intensify cementation within the pore structure. This study provides valuable insights into the mineralogical change effects on caprock integrity and offers a reliable framework for assessing caprock integrity during long-term CO2 storage.
Identification and In-Depth Investigation of External Casing Corrosion in an Exploration Well Prior to Field Development
Authors: Chikh Selma , Govil Amit 
Published: March 2024

Abstract
External corrosion in new casings on the Norwegian Continental Shelf (NCS) is rare. An exception to this was discovered when reentering an exploration well that had been temporarily plugged and abandoned for 2 years. A pressure test showed the 9 5/8-in. liner was leaking. A multidisciplinary investigation was done to find the precise depth of the leak and its root cause. The proper logging technologies were carefully selected for this purpose. Due to the relatively low leak rate, it was suspected that holes in the liner were small. To locate these holes, noise, temperature, ultrasonic high-resolution corrosion, and multifinger caliper logs were recorded. One of the hypotheses for the root cause of the leak was corrosion resulting from the corrosivity of the formation fluid combined with crossflow between the depleted formations. To test this, a water-flow log was run to find any potential crossflow behind the liner. Modular dynamic tester sampling was performed to extract formation water samples from the interval for chemical composition analysis.
The high-resolution corrosion data obtained from azimuthal and ultrasonic measurements showed the presence of multiple depths of external casing corrosion. These depths coincided with sections of the liner that were uncemented and therefore directly exposed to surrounding formation water. Analysis of the temperature data and the water-flow log during static well conditions enabled finding the precise location of the leak along with the detection of upwards water (or oxygen) movement behind the casing.
Additionally, a detailed examination of water samples taken from the 12 ¼-in. section of the sidetrack well revealed that the formation water had a low pH and a high CO2 content, which were considered significant for the context of the NCS. Based on these observations, the corrosion rate was estimated at about 4 mm/year. This conclusion relied on the confirmation of the formation water flow from the depleted formations.
This work helped to find the true root cause, which was found to be related to the selected well design, where the "overburden" was in communication with the reservoir section of a nearby field. As a preventive measure to avoid the recurrence of such issues in future similar wells in the NCS, the well design was changed during early field development.
Record-Setting Workover Saves Extended Marcellus Lateral
Authors: Lesnick C. W. , Kirk J. A. , Luckey E. , McClanahan D. J. , Saltel N. , Lian R. , Lim S. 
Published: March 2024

Abstract
An erroneous production string cement job often leaves an operator with a tough decision to make; the technical and economic feasibility of a successful intervention must be considered and compared to sidetracking or, at worst, abandonment. CNX Resources, collaborating with Thru Tubing Solutions (TTS) and SLB, was able to develop and execute a unique (and record-setting) workover to save a 19,381 ft lateral in the Marcellus shale.
An incorrect mixture of cement slurry left CNX Resources with 20,489 ft (of 27,510 ft MD) of 51/2-in 23ppf P110 production casing cemented off. A cement lead was pumped without issue. However, while pumping the cement tail and displacement, pressure gradually increased until it reached the pressure limitations of the rig equipment, resulting in a premature shut down. Utilizing a combination of traditional drilling and completions philosophy, a series of past lessons learned, and new-age technology, CNX, TTS, & SLB managed to clear the casing of nearly 20,500 ft of cement, perf and squeeze cement 6,019 ft into the lateral, and set the deepest (from KOP on US Land) casing patch ever set by SLB. This successful, more sustainable implementation offered upwards of 17% savings compared to the alternative.
Bottom Hole Assembly (BHA) selection, solids control, and fluid system management played a vital role in the cement drillout portion of the workover. Rates of penetration of up to 85 ft/hr were achieved and maintained throughout the job. In total, it took 19 days (approximately 17.5 days in hole) to drill the 20,489 ft of cement. Perforation depths were carefully determined at 14,130 ft via ultrasonic imaging and cement bond logging. Circulation was established and cement was squeezed to exceed state regulatory requirements. Due to the unique circumstance, a custom, fit-for-purpose expandable casing patch was designed and successfully installed to isolate the squeeze perforations while returning the casing to mechanical properties fit for fracturing operations. A casing integrity test to 10,500 psi was achieved post-installation of the casing patch.
This case study features the deepest 20,000+ ft drillout of cement for TTS (27,510 ft MD), a detailed look into a complicated extended lateral perforation and squeeze operation, as well as the deepest set (from KOP) casing patch for SLB on US Land (14,154 ft MD).
Milling the Unmillable: Design, Testing and Execution for Milling Non-Rotationally Locked Frac Sleeves
Authors: Burke J. , White M. , Schmohr A. 
Published: March 2024

Abstract
As drilling and completions operations continue to push the boundaries of extended lateral lengths and demand increases for higher stage density, technology is evolving, and new technologies are being developed to enable unlimited stage count. In the frac sleeve design space, one technology that has adapted to meet the increasing demand of these operations is unlimited sleeve systems. Unlimited frac sleeves allow sleeves to be preinstalled during the drilling phase and can be configured for uncemented and cemented completions. During subsequent multi-stage stimulation operations, darts are deployed from surface and rely on a range of methods (depending on the system) to count sleeves and activate to open only a specific sleeve or set of sleeves. All the sleeve profiles are uniform, so unlike graduated ball drop technology, sleeve ID remains constant regardless of the stage count (Davis et al. 2023) (Gibson, 2022). However, some unlimited sleeve designs feature an ID restriction relative to the nominal ID of the host casing. Even though the ID reduction is subtle and constant for all installed sleeves, this can limit future well intervention access for certain applications. In a few of these systems, once the sleeve shifts open and the well is stimulated, the restricted sleeve insert is no longer rotationally locked in place. In addition, some of the restricted sleeve inserts are constructed out of high strength chrome moly steel.
The mentioned design factors present a unique challenge when it comes to milling out to accommodate certain intervention needs. This paper outlines key steps that were taken to create a successful method for milling out restrictions that wouldn't have been possible using traditional equipment and techniques. This paper highlights the process in which a mill was designed, tested on surface, then tested downhole, and ultimately optimized through subsequent downhole runs. This led to the successful removal of a non-rotationally locked sleeve, clearing a pathway to allow a retrofit ﬂow control system to be installed.
ICD Completion Stimulation and Water Shutoff Using Inflatable Straddle Packers
Authors: Fajardo Sergio Rondon , Slama Hedi , Sunagatov Rustem , Badrawy Kareem 
Published: March 2024

Abstract
This study describes how the deployment and operation of an inflatable straddle packer combined with a real-time coiled tubing (CT) downhole measurement system improved the productivity of a well by optimizing an intervention that required selective treatment of multiple zones. The objective was to have the selected products reach only the targeted inflow control device (ICD) while isolating the other ones.
The inflatable, resettable, configurable, CT-conveyed straddle packer was set up to isolate a portion of the production ICD completion and allowed precise injection of stimulation and water conformance chemicals in one run. This system is more precise than other methods of selective placement (e.g., chemical diverters) and only requires a slight amount of tension and/or set-down weight to operate under its different configurations (inflation, spotting, and injection). Its combination with real-time downhole measurement capabilities enabled rapid response and adjustments to the actual downhole conditions throughout the operation.
The assembly was run successfully and managed to selectively stimulate and shut off two different zones in one trip, thus avoiding the use of multiple plugs to isolate the different sections. The real-time downhole measurement casing collar locator module permitted accurately placing the straddle section in front of the ICD port, while inflatable packers and a flow control module isolated mechanically the rest of the completion to facilitate fluid placement. Using the software specifically designed for this application, in combination with a memory logger tool that enabled a more accurate post-job evaluation, it was confirmed that all treatment fluids were injected into the targeted ICD zones, preventing more-permeable sections from absorbing it and adding the flexibility to avoid injecting the fluid used for the inflation of the packers.
This case study proposes an innovative approach to integrating CT conveyance, telemetry, and mechanical wellbore isolation tools to enhance production in wells with challenging configurations. While a thorough design identifies the optimized execution strategy, this methodology allows reducing the time of operation execution and using the treatment chemical fluids in a cost-effective manner.
From Zero to Hero: A New Breakthrough of Stimulation Method by Combining Acidizing and Cyclic Extended Breakdown in Sawah Field
Authors: Ilfi _ , Setiyawan Hanif , Masyhuri Ali , Rusli _ , Mileota Christian Eliezer , Ramadhan Iftikar Luthfi , Nugroho Rinenggo , Afton M 
Published: March 2024

Abstract
The Sawah field, a waterflood field, currently produces approximately 130,000 BFPD with an average 96% water-cut. The Fluid In Fluid Out (FIFO) stands at only 0.6, resulting in suboptimal waterflood performance. One cause of the low injection rate in Sawah field is injector plugging due to solid content and/or scale, and characteristics of the reservoir itself. Pressure Transient Analysis (PTA) further validates significant skin and permeability reduction.
To improve the injection rate, workover activities are conducted on the targeted well using a combination of the Acidizing and C-EBD (Cyclic Extended Breakdown) methods. This involves a chemical and mechanical effort, where the acid dissolves scale, and the C-EBD creates fractures. Compatibility tests are conducted between acid and water production, as well as acid and water injection. A 15% HCl simple acid is injected with a 3-feet penetration near the wellbore using coiled tubing. Following soaking, the treatment continues by injecting water into the reservoir in 6 cycles, with 350-700 bbls of water for each cycle.
During workover activities, improved injectivity was observed through Step Rate Tests (SRT). After acidizing, a rate of 2.5 bpm at 1,600 psi was achieved, followed by 3 bpm at 1,350 psi after the first 3 cycles of C-EBD. Further injectivity improvements occurred during subsequent C-EBD cycles, with the first 3 cycles reaching 2.4 bpm at 1,300 psi, and the next 3 cycles achieving 3.5 bpm at a similar pressure. Post Put on Injection (POI), the injection rate increased from 0-30 to 5,100-8,500 BWIPD, marking the well's highest injection rate in history. This notable success opens opportunity for Sawah Field, facilitating the reactivation of trade-off wells and increased capacity to handle additional fluids from size-up jobs or new wells. The collaborative efforts of the Subsurface, Research, and Workover Teams in the Sawah field were vital in achieving this remarkable result, contributing to longer injection well lifetimes, preventing overflow at surface facilities, and enhancing employee satisfaction.
A lesson learned emphasizes the need to verify flow meter readings before and during execution, facilitating the prompt identification of problems or areas for improvement. Additionally, conducting an extra Step Rate Test (SRT) before acidizing serves as an added baseline. This successful approach is currently being implemented in other injectors within the Sawah field facing similar plugging issues, showcasing its ongoing effectiveness in enhancing operational practices.