bluuebunny/crossref_metadata_2025_split huggingface dataset:
Tackling Well Productivity and Sustainability in a Jurassic Horizontal HPHT Well with the First Multistage Unconventional Hydraulic Fracturing in MFS Formation: A Case Study of an Exploration Well
Authors: Bosalhah A. , Al-Mulla S. , Duggirala V. , Ayyavoo M. , Al-Saqabi M. B. , Mubarak A. , Salem A. , Enkababian P. , Peiwu L. , Fituri M. , Pochetnyy V. 
Published: February 2024

Abstract
The unconventional Lower Najmah Limestone MFS fractured reservoir is a nanodarcy rock located below the Najmah Kerogen source rock. The first horizontal well drilled across the MFS is in North Kuwait and was drilled to explore the hydrocarbon potential. The 3D seismic interpretation and several seismic attributes indicate that the well location is likely to encounter a high fracture corridor area to support production after multistage hydraulic fracturing.
The lateral length is approximately 1,900 ft placed in the MFS after reaching the planned total depth (TD), 18,900 ft. The well was completed using a 15,000-psi-rated openhole multistage completion (MSC) system to place six hydraulic proppant fractures and access most of the nearby natural fractures in the reservoir. Over 20 well interventions were conducted by coiled tubing (CT) to shift the MSC frac ports, log the well by caliper and spinners, perforate stages, attempt milling out the inner completion seats, and, finally, perform nitrogen lifting of the hydraulic fracturing treatment fluids to the surface.
Due to the high-pressure nature of the reservoir and multiple additional completion challenges, it was difficult to initiate hydraulic fractures into the formation below the maximum allowable working pressure of completion. Therefore, 20 ft of 12 shots per foot (SPF) perforations were added per stage for four stages, which significantly lowered the fracture initiation pressures. Complete data fracturing analysis was conducted in each stage to redesign stimulation treatments. Four unconventional hydraulic proppant fracturing stages were successfully completed, sequencing high-viscosity slickwater and a crosslinked fluid system placing 110,000 lbm of proppant per stage into the formation. Multiple milling attempts were conducted with CT to reach TD but were unsuccessful due to uncertain obstructions. However, an unconventional method was applied and finally succeeded in accessing the full lateral and flowing back the well.
This work highlights the operational and technical challenges and solutions to design, execute, and evaluate the first horizontal well in the MFS reservoir, Kuwait. The developed workflow presents solutions for future horizontal wells drilled through the unconventional Najmah and similar formations across Kuwait. The work provides valuable lessons learned, insights, and perspectives for the complexity of the MFS to optimize production from challenging reservoirs.
Formation Damage During CO2 Storage: Analytical Model, Field Cases
Authors: Shokrollahi Amin , Prempeh Kofi Ohemeng Kyei , Mobasher Syeda Sara , George Parker William , Zulkifli Nazliah Nazma , Zeinijahromi Abbas , Bedrikovetsky Pavel 
Published: February 2024

Abstract
This study develops analytical models and explicit formulae to characterize well injectivity and reservoir behavior during CO2 injection in layer-cake aquifers and depleted gas fields, while considering formation damage. The methodology involves deriving 2-phase flow equations incorporating permeability damage mechanisms and upscaling. While formation damage reduces injectivity, in situ permeability decreases in swept areas redirect gas to unswept zones, enhancing storage capacity. The developed models are also applied to three real reservoirs—A, B, and C located in the formation L in Malaysia. The results indicate that as the damage factor d transitions from 1, representing a damage-free reservoir, to the critical value dc where the well impedance remains constant during injection, there is a notable increase in sweep efficiency for reservoir A, rising from 3% to 53%. Similarly, in the case of reservoir B, the sweep shows a significant increase from 7% to 50%. Additionally, for reservoir C, the sweep undergoes a substantial rise from 1% to 52%. The study introduces explicit formulae reflecting these processes and contributes novel insights by creating a fast-analytical tool, providing a valuable addition to understanding CO2 injection processes in diverse geological settings.
Experimental Study of Self-Degrading Diverting Agent Particles Used for Improving Hydraulic Fracture Placement
Authors: Trif V. Cosmin , Ganea V. Aurelian , Foidas I. 
Published: February 2024

Abstract
Fluid placement is essential to obtain a successful stimulation treatment. Formation heterogeneity, varying stress distribution among formations and irregular fluid injectivity via perforations may lead to uneven fracture propagation along the formation net thickness. Isolation techniques provide solutions to such issues and can range from using mechanical restrictions that redirect the fluid flow, up to the use of specially designed particles placed in the flow stream to divert the treatment. Mechanical methods can include packers, bridge plugs and sand plugs which are used to mechanically separate the stimulation process into multiple stages pumped along the wellbore path. Ball sealers are part of the same category, designed to seal individual perforations during the pumping process and completely isolate a section of the wellbore to divert the injected fluid to subsequent zones. Another method that is widely used in large pay zones is coiled tubing in which accurate frac generation and fracture growth adjustments can be monitored in real time. Non-mechanical isolation designs consist of soluble or insoluble particles, with different sizes and compositions, mixed within the stimulation fluid that accumulate at the wellbore wall to form a low permeability cake, forcing fluid flow into areas with lower injectivity. Such particles are known as diverting agents and dissolve as a function of temperature and type of the injected or produced fluids. The study presents the main isolation techniques used during multi-stage fracturing operations and the laboratory investigation results affecting the selection of solid diversion agents such as material chemistry, particle size, particle shape, particle size distribution, temperature and type of carrier fluid.
Producer Acid Stimulation to Remove Near Wellbore Damage in Unconsolidated Sandstone Reservoirs: Lessons Learned, Best Practices and Challenges in Penglai Oilfield, Bohai Bay
Authors: Zheng Jv , Zhang Yanxu , Dai Xianghui , Wang Yuejie , Li Wentao , Fu Yangyang , Gou Xinjun , Cao Jun , Zhao Ning , Li Changwei , Liao Zuan , Cui Qingzhen 
Published: February 2024

Abstract
This study investigates the evolution of acid stimulation to remove the near wellbore damage in producers at Penglai Oilfield which is the largest offshore oilfield in China. The near-wellbore plugging has been observed in certain wells within the unconsolidated sandstone reservoir. So far, producer acid stimulation has been performed in over 200 wells. This paper will review the design change, lessons learned, current best practices and challenges in acid stimulations.
Producer acid stimulation in Penglai Oilfield was first executed in two wells through coiled tubing in 2007 with positive outcomes. Since then, acid stimulation designs have improved as more studies were performed and field trials were made, such as larger acid volume to increase the treated radius, customized acid recipe for effective removal of solids, modified procedures for flowback into FPSO, and improved execution methods through selective production string, coiled tubing, sliding sleeve, or ESP-bypass, etc. An acid stimulation database is created to aggregate well parameters, formation properties, stimulation design variables, and productivity matrices.
Various designs were evaluated using the integrated database to guide the future improvements. This study shows that both hydrofluoric (HF) based acid system and a new chelant fluid system prove to be effective in removing the near wellbore plugging for the Penglai field. Laboratory evaluation of acid systems serves its purpose for initial benchmarking; but it loses fidelity in testing conditions that are not realistic to reflect the complicated environment of rapidly varying lithology, scales, waterflooding, etc. Therefore, continuous evaluation, summarization, and optimization of the results of the previous treatments are vital factors contributing to the ongoing improvement of acidization effectiveness in the Penglai Oilfield.
This study also highlights the continuous optimization of handling emulsion issues after acidizing. The flowback stream right after stimulation is depressurized and filtered, then directed into the injectors. This practice mitigates the issues in FPSO caused by the acid stimulation and has no impact to the designated injectors.
This study showcases significant advancements in acid diversion techniques, specifically emulsion diversion, resulting in improved acid distribution across intervals exceeding 500 feet in thickness. These advancements have been implemented since 2022 and have yielded highly encouraging production outcomes. This study presents an innovative method that solved the emulsion challenges after acid stimulation through flowing back into water injectors after processing the stream.
Gravel Pack Optimization in Frade Field Through Bottomhole Data Analysis
Authors: Latini C. , Govinathan K. , Tibbles R. , Jain S. , Wassouf P. , Pereira E. B. , Neumann L. F. , Rodrigues V. F. , Andrade T. 
Published: February 2024

Abstract
Proper design of sand control completions is critical for maintaining well integrity and achieving productivity objectives. This is particularly important in Frade, a deepwater field situated 120 km offshore Brazil, where wells to be completed with gravel packs have narrow pressure operating windows. This paper demonstrates the optimization process of gravel pack operations in the field through detailed data evaluation.
The continuous improvement process involved pre-designing the gravel pack placement, conducting comprehensive post-job data analysis, optimizing models, and redesigning subsequent wells. To enhance and standardize these processes, an industry standard software was utilized, facilitating an integrated workflow encompassing all stages of the operation, including wellbore displacements, step rate tests, and gravel pack treatments.
Sand control completions are intricate, and many variables can jeopardize the integrity of a gravel pack, especially in challenging environments like the Frade Field. This paper introduces instances of issues encountered during sand control installations in the field, such as screen plugging, severe losses, fracturing, and complications with the pumping equipment. The automated processing of surface and downhole gauge data allowed for timely and detailed evaluations, maximizing the value of the acquired data. Furthermore, it facilitated the effective implementation of lessons learned and model calibration within the same campaign, ultimately leading to successful gravel pack treatments.
This paper presents examples that highlight the significance of collecting and thoroughly analyzing bottomhole data. It demonstrates how data analysis and incorporation of lessons learned can optimize gravel pack operations to maximize the success of future treatments.
Mechanisms of Degradation of Cement in CO2 Injection Wells: Maintaining the Integrity of CO2 Seals
Authors: Mura Miki , Sharma Mukul M. 
Published: February 2024

Abstract
The degradation of cement due to CO2 exposure affects its transport and mechanical properties, resulting in potential fluid leakage from wells used for CCUS. This study focused on investigating the mechanisms of cement degradation in CO2 injection wells. We employ a fully integrated 3-D reservoir simulator that incorporates fluid flow, geomechanics, and geochemistry, along with a new model designed to accurately replicate the changes in rock properties resulting from cement degradation. Chemical reactions, including dissolution and precipitation, between CO2-rich brine and cement minerals are modeled, allowing for changes in rock and cement properties. Porosity is recalculated considering volume changes due to chemical reactions, and permeability is reevaluated using the Kozeny-Carman equation. Based on the simulation results, the chemo-mechanical composite layer model reassesses mechanical properties, considering the mineral composition of cement. According to the simulation results, the chemical changes in cement exhibited three stages: 1) dissolution of primary minerals, 2) precipitation of carbonates, and 3) re-dissolution of carbonates. While reactions 1 and 2 played a major role, they led to a decrease in rock porosity and a degradation of mechanical properties. However, as the dissolution of primary minerals diminished and the transition from stage 2 to stage 3 began, the porosity increased, accompanied by an increase in mechanical stiffness. The predicted values of porosity were compared to experimental data obtained from prior studies, confirming their consistency for short-term CO2 exposure, which can be reproduced in experiments. These mechanisms of cement degradation and the alteration of mechanical properties that occur in CO2 injection wells agree well with experiments. Our numerical simulator that fully integrates flow, geochemistry, and geomechanics with a chemical reaction model can be used to model more complex cement geometries to evaluate the risks of CO2 escape along the wellbore annulus.
Polymer Induced Permeability Reduction: The Influence of Polymer Retention and Porous Medium Properties
Authors: Abdelgawad Khaled Zidan 
Published: February 2024

Abstract
Polymer injection finds wide application in enhancing oil recovery (EOR) for heterogeneous reservoirs containing viscous crude. While injection of polymer effectively reduces mobility ratios toward favorable levels and enhances sweep efficiency, it necessitates consideration of potential drawbacks, notably the risk of significant permeability reduction induced by polymer injection. This reduction arises from interactions between the injected polymer and the reservoir rock, occurring either deeper in the reservoir or near the wellbore. In addition, the extent of permeability reduction is influenced by diverse factors, including rock mineral composition, oil saturation, temperature, salinity of formation brine, formation pore structure, polymer type and molecular weight, shear rates within porous media, and the quality of injection water. Accurately assessing permeability reduction holds paramount importance in polymer selection, allowing a comprehensive evaluation of the benefits of polymer flooding for specific reservoir conditions while mitigating potential losses in polymer injectivity during field operations. Severe permeability reduction induced by polymer injection may result from factors such as excessive polymer retention within the reservoir rock, fluids/rocks incompatibility, pore throat clogging due to accumulation of large polymer molecules, shear-induced thickening near the wellbore, improper polymer solution preparation.
Within this study, we delve into the utilization of coreflooding data as an evaluative tool for permeability reduction due to polymer injection. A novel interpretation method is introduced, establishing a correlation between polymer retention and the resulting permeability reduction observed in coreflooding experiments. This approach effectively couples the aspects of polymer retention and the rock quality index, leading to a proficient alignment with permeability reduction trends derived from existing data, particularly concerning sandstone and carbonate rock samples. Recognizing the pivotal role of permeability reduction in the polymer selection process, this approach underscores its significance as a pivotal design parameter. While prior methodologies have been proposed, many exhibit limitations in terms of scalability. Through precise evaluation of permeability reduction utilizing empirical data, this approach facilitates a comprehensive understanding of polymer behavior within deeper reservoir layers. Furthermore, it enables the anticipation of potential injectivity challenges and contributes to the refinement of project design, thus enhancing overall operational outcomes.
A Deep Learning Framework for Thermal Enhanced Oil Recovery Optimization of Hydrogen from H2S – A Maari Reservoir Study
Authors: Katterbauer Klemens , Qasim Abdulaziz , Shehri Abdallah Al , Yousef Ali 
Published: February 2024

Abstract
A particularly corrosive and poisonous by-product of a range of feedstocks, including fossil resources like coal and natural gas as well as renewable resources, is hydrogen sulfide (H2S). H2S is also a possible source of hydrogen gas, a significant green energy carrier. Our business would greatly benefit from the recovery of H2 from chemical compounds that have been classified as pollutants, such as H2S. Due to the large volumes of H2S that are readily accessible across the world and the expanding significance of hydrogen and its by-products in the global energy landscape, attempts have been undertaken in recent years to separate H2 and Sulphur from H2S using various methods. In addition to deep gas reservoirs, hydrogen sulfide may be found in a wide range of other reservoir types. Due to their low use, these gas reserves often have little economic viability. Thanks to novel strategies for converting hydrogen sulfide into hydrogen and its remaining components, it has become possible to efficiently recover hydrocarbons and its hydrogen sulfide components.
This paper introduces a unique deep learning (DL) architecture for improving field recovery over time based on thermal-enhanced recovery. We investigated performance of the framework on the Maari Field in New Zealand. The ultimate goal is to optimize recovery and, within the limits of processing, reach a specific volume of H2S. The optimization results indicate the ability to increase oil and natural gas recovery while constraining H2S levels within the reservoir and converting the associated H2S into hydrogen. The deep learning architecture that has been built provides a technique for developing field strategies to improve sustainability for thermal-enhanced recovery strategies. The framework is flexible enough to incorporate additional reservoir and production parameters.
Enhancing Dispersion Test Analysis for Shale Drilling: Particle Size Distribution and Cation Exchange Insights
Authors: Lai Bitao , Wang Jihong , He Wenwu , Wan Zhipeng 
Published: February 2024

Abstract
Dispersion, which poses a significant challenge to wellbore stability during shale drilling, is influenced by various factors such as shale petrological and mechanical properties, as well as shale-fluid interactions. The effectiveness of shale inhibitors in alleviating these interactions has traditionally been evaluated using the standardized conventional dispersion test. In this test, measured quantities of sized shale particles are exposed to formulated fluids in a roller-oven cell for a specified duration. Subsequently, the shale particles are washed, dried, and the recovery percentage is determined, with higher rates indicating improved inhibitor performance. While the conventional dispersion test is widely used due to its simplicity, the test provides limited, and at times, misleading information.
This paper presents an enhanced dispersion test method and analysis by incorporating particle size analysis and inductively coupled plasma optical emission spectroscopy (ICP-OES) tests before and after the conventional dispersion test. Three standard shales exhibiting diverse reactive and dispersive characteristics are selected along with three fluids containing different chemicals and inhibitors for conducting these advanced dispersion tests and analyses.
The study highlights the capabilities of the new method for obtaining comprehensive data, not only the recovery rate at a specific particle size but also the particle size distribution curves before and after the dispersion tests. Analyses of particle size distribution provide valuable insights into the particle size shift after shales interact with different fluids. This detailed understanding of the dispersion properties contributes to a more effective design and optimization of shale inhibitors and enhances borehole cleaning processes. Additionally, the application of ICP-OES analysis enables the identification of cation exchanges between the drilling fluids and shales and the exploration of the relationship between cation exchange and dispersion. A higher release of Ca2+ indicates potentially stronger dispersion.
An Analytical Model for Water Evaporation During CO2 Injection for Geological Storage
Authors: Russell T. L. , Bedrikovetsky P. 
Published: February 2024

Summary
Formation damage during CO2 injection into depleted gas or oil reservoirs, or in aquifers, is highly affected by connate water evaporation into injected gas. For example, precipitated salts accumulate into dried-up zone around the well. Dried rock liberates fine clay particles. The aim of the work is creation of an analytical model for connate water evaporation into injected CO2 during coreflood and injection in vertical well.
The mathematical model considers non-equilibrium evaporation accounting for changing interfacial area. The interfacial area is derived separately from approximating the porous media as a sphere pack and from the averaging of individual water patches. The resulting model is solved analytically using the method of characteristics, permitting the calculation of the water saturation and vapour concentration profiles during the evaporation process. Finally, we match 5 laboratory tests, determine the typical form of evaporation interface, and upscale the results for injection well conditions.
Tuning of laboratory data exhibits high agreement for 5 laboratory tests and allows for characterization of field-scale evaporation dynamics from laboratory testing. The total evaporation time is provided explicitly by the model, and a criterion is presented for determining whether evaporation occurs within finite time. This work provides key insights into the behaviour of CO2 injection wells and can contribute to producing explicit formulae to predict mobilisation of fine clays and precipitation of salts due to rock drying.