bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using Worst Case Discharge (WCD) Estimations to Prevent Underground Blowouts After Well Capping
Authors: Khouissat Abdelhakim , Michael Andreas 
Published: April 2024

AbstractAs part of post-blowout contingency planning, it is mandated by U.S. laws to perform "worst case discharge" (WCD) flowrate and volume calculations a-priori to spudding an offshore well. During well capping attempts following loss-of-well-control, an underground blowout (tensile-fracture initiation) may occur, leading to reservoir hydrocarbons broaching the seafloor. To prevent such scenarios, WCD estimations coupled with critical discharge flowrates, used in order to assess potential capping stack (CS) shut-in strategies vis-à-vis the number of shut-in steps and their duration.Development of workflows for calculating the critical discharge flowrate, below which fracture initiation takes place during post-blowout capping, also used to determine the optimal CS shut-in strategy. Assuming a robust casing architecture, the casing shoe depth is the primary line of defense against loss of control-induced fracturing. Fracture initiation and subsequent broaching, although narrowly avoided during the Macondo disaster, is a real possibility in overpressurized, stacked sequences encountered in deepwater drilling operationsReservoir depletion models are coupled with wellbore geomechanics to derive closed-form expressions for critical discharge flowrates used to indicate whether the wellbore pressure buildup induced by a specific CS shut-in schedule will exceed the local fracture initiation pressures. Sensitivity analyses are conducted to evaluate the impacts of several in-situ geomechanical parameters, acting as independent variables, along with the casing-shoe depth. Hence, basin-agnostic physics-based models can be derived that describe the dependency of the critical-discharge-flowrate values on parameters (such as the number of steps and the time duration-per-step of the CS shut-in), controlled by these practitioners on the surface are presented. These models can assist contingency planning via comparisons between these critical discharge flowrate values (variable with respect to the extent of the post-blowout reservoir depletion and casing-shoe depth) and the law-mandated, pre-spudding WCD estimates with the help of modern data analysis tools for building useful tables and figures.
3D Ground Model: An Alternative Approach for the Treatment of Heterogeneously Distributed Spatial Data
Authors: Imitazione G. , Zolezzi F. , Murianni A. , Giovacchini F. , Miola M. 
Published: April 2024

Abstract
This paper emphasizes the significance of adopting a robust approach for effectively handling spatially heterogeneous distributed data. We present a dedicated workflow focusing on enhancing the processes involved from acoustic reflectors data to surface and mesh definitions. Results derived from the robust approach are compared to the ones generated following a "reference approach". These distinct approaches are then employed as inputs for separate 3D subsurface models for a reciprocal comparison.
The data on which this study is based pertains to the interpretation of specific acoustic reflectors from a geophysical survey typically related for subaqueous and sub-seabed engineering assessment. Generally, these data exhibit a significantly uneven distribution, characterized by abundant data along the acquisition lines and data absence in the space between lines. This distinctive distribution emphasizes the need to carefully consider the appropriate strategy during the surface creation phases.
The workflow commences with robust data simplification applied along seismic lines, followed by mesh refinement to improve surface definition. The resulting mesh exhibits a non-uniform resolution, avoiding uncontrolled sub-sampling, accommodating higher data density in areas with greater spatial variability and vice versa.
Comparing proposed approaches output reveals a strong level of correspondence, underscoring the reliability and efficacy of the proposed methodology. The benefits of employing proposed ad-hoc meshing criteria are evident in more robust sub-sampling of original interpreted reflector data, resulting in lighter mesh files and reduced computational time during mesh editing and successively 3D modelling phases, all without sacrificing crucial original information.
Geotechnical Site Investigation Over 3500 Meters Depth
Authors: Charnaux P. , Perez I. A. , Silveira C. A. B. , Braga V. P. C. 
Published: April 2024

Abstract
This paper aims to present a survey executed in 3000 meters depth, to support the design of subsea structures in exploration blocks located in Sergipe/Alagoas basin, Brazil, with geotechnical work made over 3500 meters depth, using a Piston Corer for sampling and a gravity CPT for testing. The vessel used for this project was R/V Seward Johnson, a Research/Survey vessel. The Piston Corer used for the survey, to work in depths above 3000 meters, was configured with a core head weighing 1,500 kg, with a maximum length of the sampling tube of 12 m and a 3.5 meters free fall. The samples were recovered in a 102 mm inner diameter plastic PVC (liner) coating within the 112 mm outer diameter steel tube. In addition to being stationary, the Piston Corer have a piston immobilizer, that protects the sample from disruptive forces during pull-out. The gravity CPT that was used in this campaign was coupled on Piston Corer structure, to function in the pressure of deep water. For this Project, gCPT tests was conducted to verify the soil resistance and Piston Corer samples collected, to analyze tactile-visual Classification, determination of moisture content, determination of apparent specific weight, evaluation of the content of Calcium carbonate (CaCO3) and determination of Undrained Shear Strength (Su) by pocket penetometer test, torvane test and laboratory mini vane test. Through the piston core sampling and tactile visual classification, it was possible to define the soil content in the area, consisted of normally consolidated clays. This geotechnical survey has few locations to make a more accurate assessment of what may have occurred geologically in this area. Despite few evidence, analyzing the Piston Core samples onshore, along with gCPT results, the layers of deposition of the sediment were identified, with the general soil composition of the area being described as light brown clayed SILT with fine sand and shell fragments in the superficial sediments and dark gray silty CLAY with fine sand in the deeper sediments. The data produced from this campaign shows the possibility of geotechnical studies in areas of deep water, over 3500 meters depth, with reliable results. In order to work in a deep area, there were some alterations needed in the equipment, such as assembling the CPT in Piston Corer structure, and using a Piston immobilizer on the piston corer sampler. The improved equipment provided good quality data of the region.
Development of Machine Learning Models for Predicting Bubble-Point Pressure of Crude Oils
Authors: Nekekpemi Prosper , Totaro Michael , Olayiwola Olatunji , Esenenjor Pascal 
Published: April 2024

Summary
Bubble-point pressure is a crucial parameter in reservoir and production engineering in the oil and gas industry, but its accurate determination through experimental methods is both costly and time-consuming. Alternative approaches, such as equations of state and empirical correlations like Al Marhoun, Dokla and Osman, Glaso, Standing, and Vazquez and Beggs, are commonly used but suffer from limitations including their inability to capture complex, non-linear relationships and adapt to new or high-dimensional data.
This study aims to address these shortcomings by developing and evaluating a range of machine learning models—including Decision Tree, Linear Regression, Random Forest, Support Vector Regression (SVR), K-Nearest Neighbors (KNN), AdaBoosting, Gradient Boosting, Stacked Super Learner, and Multilayer Perceptron Neural Network (MLPNN)—for predicting bubble-point pressure as a function of the reservoir temperature, gas gravity, solution gas-oil ratio, and oil gravity (API).
Utilizing a comprehensive dataset derived from different published papers, a total of 776 data sets were used in this study which were divided into 80% for training and 20% for testing. The study employed performance metrics such as Average Percentage Relative Error (APRE), Absolute Average Percentage Relative Error (AAPRE), Root Mean Square Error (RMSE), and Coefficient of Determination for evaluation. The Gradient Boosting model emerged as the most effective, with an RMSE of 364.027 and an R2 of 0.924 on the test data, outperforming the existing correlations used in this study.
The results demonstrate the potential of machine learning models, particularly the Gradient Boosting model, in offering advantages such as capturing complex relationships thereby contributing to more effective reservoir management strategies.
Methods of Oil Spill Cleanup: A Comparative Review
Authors: Efendi E. J. 
Published: April 2024

Abstract
Oil spills present significant environmental, economic, and public health threats, necessitating effective cleanup strategies. The prompt and effective cleanup of oil-contaminated areas is crucial to mitigation of the damage caused by these spills. Over the years, a variety of cleanup methods have been developed and employed to address different types and scales of oil spills. This paper provides a comparative review of the major established response methods used for continuous and batch oil spills offshore, including in-situ burning, mechanical recovery and use of chemical dispersants. Each method's advantages, limitations, and environmental impacts are discussed, along with computer models simulating their application, such as National Oceanic and Atmospheric Administration's oil weathering model ADIOS2® (Automated Data Inquiry for Oil Spills) and Bureau of Safety and Environmental Enforcement's response system planning calculators. In conclusion, we provide recommendations for the use of the techniques described based on event conditions, for optimal results.
Alternative Method to Achieving Rock-To-Rock Barrier for Plug and Abandonment Using Hydro-Mechanical Perforating Tool
Authors: Rahman S. , Beazer D. , Butcher S. , Baiej O. 
Published: April 2024

Abstract
This paper outlines our experience with a hydro-mechanical perforating tool in the abandonment process of a Chevron exploration well in the Mediterranean Sea. The objective of the abandonment was to safely secure the well in accordance with industry standards and local regulatory requirements. The abandonment plan and verification methods were designed to ensure full zonal isolation of formation fluids within the well and from the seabed. Hydro-mechanical perforating techniques were employed to successfully execute the objective.
To isolate potential flowable units properly, the abandonment plan was broken down into three zones. The first, or lower zone covered the open hole with cement plugs across Oligocene age sands to prevent crossflow and secure reservoir integrity. The next, or middle zone, covered the Miocene age gas sand behind 14" casing. It included two verified barriers (primary and secondary) that were placed to ensure the isolation of the uncemented Miocene gas sands behind the 14" string. The primary barrier was established by placing 150-m (MD) of cement above the Miocene sand within a hydro-mechanically perforated interval of 14" casing and was verified to provide a rock-to-rock barrier via a bradenhead block squeeze. The secondary barrier was established via a Cut & Pull 14" operation and placement of a rock-to-rock cement barrier with a mechanical base. The last, or upper abandonment zone, covered shallower sands and included two independently verified 100-m barriers placed via the block squeeze method with cement plugs leveraging 200-m of explosive free, mechanical perforations.
In this paper we will share best practices and lessons learned when using a hydro mechanical perforation tool in a complex deepwater P&A operation.
Unlocking Offshore Brownfield's Oil Reserves: A Pioneering Approach with Acid Stimulation and Diversion Methods - Insights from the Gulf of Suez
Authors: Hegazy Amr , Hakim Emad Abdel , Ramadan Ahmed , Saleh Khaled , El Hawy Ahmed , Al-Mansour Mansour , Galal Mahmoud 
Published: April 2024

Abstract
Handling the complexities of carbonate formations poses significant challenges in boosting oil production, especially in offshore brownfields dealing with water breakthroughs in commingled completions. While the commonly used mechanical diversion with straddle packers ensures effective zonal coverage and selective matrix acidizing treatment, it's important to note that these methods are more expensive than chemical diverters.
This paper outlines a comprehensive strategy for enhancing production in such demanding scenarios. The approach considers various factors, including addressing the root causes of water breakthroughs, formulating appropriate acid chemicals, selecting effective chemical diversion methods, and optimizing the overall process execution. To illustrate the application of this approach, three candidates from the Gulf of Suez Basin, a complex and heterogeneous region in the Eastern Desert of Egypt with carbonate reservoirs, are examined as case studies.
A viscous pill underwent laboratory testing before transitioning to field applications. This pill was designed to temporarily isolate fractures or fissure networks, diverting the primary treatment away from water and/or thief zones before the acid treatment. The results of this innovative chemical diversion technique demonstrate a remarkable four-fold increase in well productivity and a reduction in water cuts.
This paper introduces the workflow and laboratory test results of a purpose-built acid and diversion technique explicitly tailored for fractured and watered-out carbonate reservoirs. Furthermore, it shares valuable insights and practical guidelines from the lessons learned while applying these methods, providing valuable guidance for future cases with similar challenges.
Elevating Workover Rig Intervention for Well Integrity Using Instrumented Coiled Tubing and Through-Tubing Inflatable and Retrievable Packer: A South Kuwait Field Application
Authors: Chandrakar Yajuvendra Kumar , Al-Sarraf Abdullah , Slama Mohamed Hedi , Al-Ajmi Abdullah , Gupta Pravind , Badrawy Kareem , Sunagatov Rustem , Sebaih Mohannad Adel , Fajardo Sergio Rondon 
Published: April 2024

Abstract
This paper delineates a groundbreaking intervention in South Kuwait Field, where the integrity of a well for workover rig operations was successfully reinstated by harnessing instrumented coiled tubing (CT) combined with a through-tubing inflatable and retrievable packer (TTIRP).
In the described scenario, mechanical obstructions at the Christmas tree tubing hanger posed significant challenges for the conventional installation of the blowout preventer (BOP) on the workover rig. This necessitated the adoption of a tailored approach to establish the essential pressure barriers for well intervention.
The implemented intervention strategy utilized instrumented CT for the dual purposes of well killing and temporary suspension. The real-time downhole telemetry of the CT played a crucial role in guaranteeing the precise deployment and activation of the TTIRP within the production tubing. Following a comprehensive pressure test of the packer from both ends, the CT was removed. Subsequently, a sand plug and an acid-soluble cement plug were strategically positioned above the TTIRP. After verifying the integrity of the cement plug, the workover rig was engaged to fit the BOP. The instrumented CT was then redeployed into the well to dissolve the cement plug, remove the sand, and extricate the TTIRP back to the surface.
The targeted well for this advanced intervention workflow was characterized by a maximum potential wellhead pressure of about 1,500 psi and a plug-back true depth (PBTD) of 4,000 ft. The well's completion involved 3 1/2-in. production tubing installed up to approximately 3,500 ft measured depth (MD) and 8 5/8-in. casing extending to the PBTD. Prior to the initial CT operation, an e-line through-tubing puncher was utilized in the production tubing to facilitate the circulation of the killing fluid. The TTIRP's setting depth was meticulously prepared using the instrumented CT and a high-pressure rotary jetting tool, achieving a shut-in wellhead pressure close to zero psi.
The outcomes of this cutting-edge intervention workflow were remarkable, conserving an estimated 195,000 barrels of deferred production as the well had been shut-in for a minimum duration of ten months. The insights and experiences accrued from this case study are poised to act as valuable guidelines for operators in the Middle East faced with comparable well challenges.
Innovative and Technological Approaches to Mitigate Produced Water Reinjection Losses in Mature Fields: Challenges and Solutions
Authors: Carvalho F. F. , Junior A. O. , Freiman B. M. , Furtado C. A. , Paulo E. , Moraes G. , Pereira H. L. , Pereira J. C. , Junior L. C. , Rachid M. A. , Costa M. , Chaves R. A. 
Published: April 2024

Abstract
In 2017, a change in the environmental agency IBAMA's understanding of Total Oil and Grease (TOG) analysis for produced water discharge into the sea mandated the reinjection of produced water in six production units in Marlim Sul and Roncador fields. Platforms not originally designed for reinjection underwent topside adaptations for additional treatment and necessary interconnections to blend produced water with sea water for injection into wells. Failure to achieve this goal could result in production losses of up to 250 thousand barrels per day, leading to platform restrictions and shutdowns due to the inability to dispose of produced water. When injected into the reservoir, produced water impurities cause injector well plugging, resulting in reduced field injection capacity. Hence, platform adaptations included a project that reconciled platform limitations with reservoir requirements. Acid treatment of injector wells and restoration of injection capacity involved installing supports and connections on the platform's side to perform acidification by directly connecting stimulation vessels to the production unit. This adaptation allows interventions without the need for a rig, substantially optimizing costs and downtime of injector wells. Innovatively, geomechanical studies and simulations were conducted to enable mechanical well stimulation operations through pressure pulses. This maneuver, independent of external platform resources, incurs no additional costs. By manipulating flow and pressure variations in wells, controlled reservoir fracturing is induced, resulting in a significant 50% increase in injectivity in many cases. This measure yielded approximately USD 10 million in savings by optimizing acidification costs with vessels and preserving the potential of producer wells through sustained injection. This work illustrates the outcome of a proactive field management approach, the application of technologies, innovative practices, and the optimization of production/injection in Petrobras' Marlim Sul and Roncador mature fields.
Chemical Solution Mitigates Stuck Inflow Control Devices (ICDs) in Horizontal Completion
Authors: Sayed Mohammed , Chang Fakuen , Luce Tim 
Published: April 2024

Abstract
Horizontal open holes covering long reservoir sections can be benefitted by installing inflow control devices (ICDs) along the lateral to even the production contribution from the entire heterogeneous permeability profile. During the drilling and completion process, the well can be shut in for prolonged periods of time. Though the ICDs are designed to withstand the buildup of debris, they are still subjected to the accumulation of weighting and bridging materials existing in the drilling fluid, such as calcium carbonate (CaCO3). This debris deposits on the internal diameter of the valves or the flow control device, preventing proper shifting against the seats, or blocking the flow path of the devices. Recovering the function of the ICDs requires a chemical treatment. In high permeability formations, it is undesirable to have acid contact the rock to compromise the mechanical integrity of the formation or trigger further solids buildup in the ICD's. Therefore, an acid designed to dissolve the solid deposits on ICDs but not penetrate the formation is required.
In this study, a modified coreflood setup was designed and an acid-based chemical treatment was formulated to remove solid deposition on the ICD. The goal was to dissolve the calcium carbonate scale on the ICD with minimal penetration into the formation to avoid formation softening. The core assembly simulates the geometry of the ICD completion system with core matrix behind the ICD operating space. Calcite marble was used to represent the scale deposited on the ICDs, while Indiana limestone was used to represent the reservoir rock.
Several acid formulations were tested using the custom designed coreflood setup. One acid blend composed of a strong organic acid mixed with hydrochloric acid (HCl) and a second blend of HCl and mutual solvent showed the desirable effect of dissolving the scale deposits (calcite marble in this case) with minimum to no penetration into the formation matrix. The success of the two acid systems in dissolving calcium carbonate deposits on the ICDs was confirmed by analyzing the pressure data during the core flooding experiment, as well as from analyzing the post-treated core samples using X-ray tomography.
Simulation of completion design in the laboratory is a key factor to test and design acid treatments to overcome scale problems in the field. Single phase acid systems containing no gelling or emulsifying agents were tested and proved capable of dissolving the solids deposited on the ICDs with minimum formation contact. This will result in an economical and easier one-step treatment in the field, avoiding the complexity encountered with pulling the whole completion string out of the wellbore to be treated with acid, then reinstall it back into the well.
Enhancing Results - Stimulation Impact on Pre-Salt Reservoirs Productivity
Authors: D. N Silva , A. Z. I Pereira , C. T Azevedo , N. J Denadai , M. V. O Scariot , S. C Kupski , S Medeiros, I. , M. P Schwalbert , V. L Teixeira , A. F. M Oliveira Jr. 
Published: April 2024

Abstract
Since the beginning of pre-salt exploration, Petrobras has been using matrix acidizing to stimulate carbonate reservoirs, resulting in significant increase of productivity.
Over time, the learning curve has depicted the techniques improvement, leading to lower operation duration and costs and productivity increase. First well tests were performed without previous stimulation, revealing considerable amount of damage and, in some cases, it wasn’t even possible to flow the well without prior acidizing, both situations demanding a second test to assure evaluation objectives achievement. Considering acid job impact, it was decided to always stimulate the wells prior to well testing or production. Operation average duration continuously decreased from 15 days to hours. Treatment volumes, acid systems and chosen strategies were refined while well completion techniques have been developed.
Despite high productivities, as completion intervals got longer and higher permeability contrasts were exposed, well designers were still concerned about Recovery Factor reduction due to inefficient acid diversion. Therefore, stimulation requirements have been influencing well completion design.
Petrobras has developed a database to keep acid operation information, which made possible to get to relevant analysis presented in this paper, connecting information from different fields and well completion designs. Also, estimates of the impact of diversion in stimulation on Recovery Factor are presented along with improvement strategies, considering Pre-Salt scenario.