bluuebunny/crossref_metadata_2025 huggingface dataset:
Using Integrated Computational Materials Engineering for Oil and Gas Applications
Authors: Whelan G.
Published: April 2024

Integrated Computational Materials Engineering (ICME) is an approach to materials design, optimization, and insertion as well as solving challenges on implementation and selection of existing materials using a combination of physics-based modeling and machine learning methods. In the present work QuesTek will demonstrate how ICME can be used to improve mechanical properties, corrosion properties, and processability of common structural materials used in oil country tubular goods (OCTG).

This work uses QuesTek's ICMD® software platform including thermodynamics- and kinetics-based databases and modeling as well as physics-based analytical modeling and simulation approaches to predict process-structure-property relationships in structural alloys. Using these predictive modeling tools, the composition and processing are optimized to achieve improved performance.

QuesTek will demonstrate results of composition and heat treatment optimization on mechanical and corrosion properties. Specifically, stress-corrosion cracking susceptibility and strength of alloys was explored and the sensitivity within specification ranges was examined. The results showed that these methods can be used to tighten specification ranges and adjust heat treatments to improve robustness of material performance for a given application.

Integrated computational materials engineering (ICME) is a relatively new approach to materials engineering which leverages the many advancements in both physics-based modeling and computational speed over the last couple of decades. The materials genome initiative has pushed for the utilization of ICME to improve novel materials design and development as well as improving alloy optimization, qualification, and troubleshooting of materials challenges for insertion of existing materials into new applications. This methodology has been growing in use in many industries (e.g., aerospace, space, defense, biomedical, automotive, nuclear, etc.) but its use in the Petroleum industry is still relatively limited. This work outlines how this approach could be adopted for practical oil and gas applications, and what the benefits would be.
Integrity Management for Lifetime Extension of Offshore Structures
Authors: Hauge M. , Jensen Ø.
Published: April 2024

Offshore structures are designed for safe operation until the end of a pre-defined design life. However, the value of a life extension beyond the original plan can be very large. Continued production from existing facilities has potentially lower cost and reduced carbon emissions compared to replacement of facilities. This is indeed the case for oil and gas production where additional near-field resources can be unlocked by tie-ins to existing facilities, but also for offshore wind projects where the energy production will be maintained over a longer time. Longer life will therefore increase the energy output and make the renewable energy more competitive.

Integrity management for structures subjected to fatigue loading, and corrosion attacks, has traditionally been based on ‘safe life’ design principles. This design philosophy require that the integrity shall be maintained over a certain time interval under normal operational follow-up and without condition monitoring or integrity assessment during operation. The design life can be updated if more precise design data can be introduced, e.g. environmental loading conditions based on real data from operation. If the experienced loading is lower than assumed in design, the life can be somewhat extended. Lifetime extension beyond this will require a measure of the current condition of the structure as basis for an integrity assessment. This approach is termed ‘condition-based’ integrity management where we initially assume that the structure has infinite life if the condition can be monitored, and integrity maintained. The condition monitoring can either be continuous measurements or discrete inspections where the inspection interval is managed as part of the integrity assessment.

As offshore structures are large, inspection, maintenance and repair are challenging tasks. The technology development required to support life extension and late life integrity management is therefore divided into three tasks: Improved inspection and condition monitoring technologiesImproved determination of the representativity of inspection results to assess overall integrity (including uninspected locations)Improved accuracy of fatigue calculations, both in terms of S-N and crack growth analysis.

A major obstacle for improvement is the large variation in the current standards and recommendations for fatigue assessment. To ensure safe assessments that can be verified by independent parties, a common platform is needed. This platform should include aligned principles for all relevant technical aspects of the assessment. For fatigue assessment this includes variable amplitude loading, sequence effects, balance between initiation phase and propagation phase as well as environmental effects. For corrosion assessment the corrosion propagation model and the related environmental effects must be well defined.
Bonga FPSO – The Key Levers in Ensuring Reliable Performance of Critical Rotating Equipment
Authors: Akinyemi Oluwaseun , Odebeatu Chike , Nwajiuba Chigozie , Agugua Godbey , Atebe Orobome
Published: April 2024

This paper is a critical review of the application of the apposite brownfield total equipment care (TEC) principles and concepts largely contributory to the higher rotating equipment reliability and availability figures in the Bonga Deepwater operation. The approach defines how the performance of an ageing fleet of rotating machinery susceptible to myriads of production challenges including changing production fluids chemistry, reservoir pressure decline, equipment obsolescence and reliability reduction of ancillary equipment, supply chain disruptions effect of COVID – 19 and its aftermath and others has been unlocked in a cost-effective manner to support the bottom-line business aspirations and achieve 1 billion barrels milestone. This paper is one of a series of Bonga themed papers proposed for OTC 2024.

The Bonga field journey to One Billion Barrels started with the launch of the Bonga Business Improvement Plan (BBIP) in 2016 with keen focus on improving on four (4) critical systems per year through End-to-End system reliability improvement, Asset register update, Reliability centered maintenance, Critical Sparing reviews, Surveillance refresh and Preventive Maintenance Optimization. Key strategies deployed are: Embedding Proactive Technical Monitoring (PTM) to aid in early identification and mitigation of threats prior to becoming big issues, by leveraging on technology tools such as Exception Based Surveillance (EBS), SmartConnect, Plant Information, Solar InSight, and System-1 amongst others, Deepening Failure Investigations by deploying Causal Reasoning methodology across business (including HSSE type events) to understand root causes and systemic issues, and driving Maintenance Efficiency, capacity & capability building through strong collaboration with major rotating equipment manufacturers during planning and execution of major overhauls, utilizing onsite workshop and corporate workshop onshore for major maintenance activities not limited to valve overhauls, electric motor repairs, and pumps, and improved execution strategies resulting in optimized maintenance costs.

With our Proactive Threat Management approach, daily surveillance, strong collaboration with equipment OEMs during planning of major equipment overhauls, improved execution strategies and execution efficiencies, Bonga FPSO have been able to achieve significant improvement in plant availability of >95%, reliability >96%, and significant reduction in greenhouse gases (GHG) emissions through reduction of flares and fuel emissions, which has overall contributed to the 1 billion barrels export milestone achieved.

This paper presents the benefit of digitalization, robust Asset Management processes and competence development as key enablers to improved plant and equipment Reliability, Availability & Utilization in any production facility.
Enhancing Value Generation from Reservoir Brine via an AI-Driven Lithium Recovery Optimization Methodology - A Volve Field Reservoir Benchmark Analysis
Authors: Katterbauer Klemens , Patil Pramod , Al Shehri Abdallah , Yousef Ali
Published: April 2024

In the pursuit of more sustainable resource use, lithium has emerged as a useful resource for a range of uses, including batteries. Due to these difficulties, there is a growing need for improved field operations that preserve output levels while also making the operations more sustainable. The Fourth Industrial Revolution are greatly impacting the oil and gas sector, and as the need for lithium to be used for batteries and energy technologies grows, hydrocarbon reserves are becoming a more desirable source of these precious minerals. Lithium has been found in considerable amounts in the generated brines of a number of reservoirs worldwide. In this study, we provide a novel artificial intelligence (AI) optimization strategy for optimizing lithium recovery from reservoir operations while preserving reservoir oil production goals. A deep learning LSTM algorithm is integrated into the AI framework to estimate water injection amounts based on oil, brine, and lithium recovery. After that, a global optimization framework using the deep learning model is integrated to optimize the water injection levels in order to maximize lithium recovery while preserving reservoir oil production levels. For the purpose of recovering lithium from reservoir brine in an oil and gas reservoir, we have presented a novel AI optimization framework. The framework allows hydrocarbon recovery rates to be maintained while optimizing lithium recovery. The framework, which highlights the potential for a large improvement in lithium recovery rates from an enhanced injection procedure, was successfully demonstrated on the Volve field. This paradigm has the potential to yield substantial benefits for optimizing the use of reservoir brine, which might lead to improved sustainability in reservoir operations.
Going Deeper: Inspecting Subsea Live Assets by Means of an Advanced AUV Solution
Authors: Nevoso C. , Cavallini F. , Massari G. , Bernini T. , Watanabe T. , Britto A.
Published: April 2024

Data has always been the key: more data, at higher frequency, with better quality and, possibly, always cheaper. Data, if properly handled, means knowledge and knowledge allows better performance and with less risk. In this context, offshore IMR is not different compared to other business segments, with the addition that, in 2023, it appears to be somehow obsolete the need to mobilize a diesel propelled vessel with circa 60 people onboard with the purpose of taking some pictures and videos of subsea facilities. In order to respond to this challenge, several players in the market have launched their development programs, with the objective of developing and qualifying a new generation of subsea vehicles, or better drones, capable to match the industry needs in terms of cost efficiency and environmental footprint as well.

Focusing on pipeline inspections, AUVs are the preferred choice for long range activities while optimizing the need for support vessels in constant control of the subsea operations. However, the complexity of the subsea domain resides in the non-linear objects such as subsea XTs, manifolds, etc., i.e. all those subsea assets requiring detailed inspections at frequent interval mainly to assess the status of valves, cathodic protection, flanges and connections in general. Doing this with a standard AUV is fairly impossible, therefore a new generation of advanced AUV solutions is required, capable of DP and hovering modes, thus adding the flexibility to stop-by at given location and perform a detailed assessment of the target point, including search and localization of possible hydrocarbon leaks. This functionality implies a rethinking of the subsea vehicle which -as anticipated- is then commonly redefined by the offshore industry as "subsea drone".

After extensive qualification programs such subsea drones are currently being introduced by different suppliers and service providers to the market, promising substantial achievements in terms of inspection effectiveness. The focus of this paper shall then be in sharing the direct experience made by Saipem while bringing FlatFish to deepwater, in what it is believed to be a unique subsea campaign setting a number of industry firsts: autonomous deepwater inspections of flowlines, XTs, structures and risers.

Such deepwater operations, carried out offshore Brazil at the beginning of 2023, have been an essential achievement in the subsea drone development and qualification plan, unlocking the next stage of FlatFish continuous development while marking a milestone for the offshore energy industry. Saipem intends to share, from its privileged viewpoint, the main outcomes and lessons learnt from such deepwater pilot operations.
Using Worst Case Discharge (WCD) Estimations to Prevent Underground Blowouts After Well Capping
Authors: Khouissat Abdelhakim , Michael Andreas
Published: April 2024

As 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 operations

Reservoir 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

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

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

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

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

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

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

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

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

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

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.
Feasibility Demonstration of Key Concepts for Reducing Diesel Consumption and GHG Emissions Using Hydrogen in Drilling Rigs
Authors: Machado R. C. , Oliveira I. , Castro A. G. , Torres E. R. , Brito C. H. G. , Zanella I. Z. , Leonardi F. , Ayad S. M. M. E.
Published: April 2024

This paper describes the maturation of the product development of an onboard hydrogen production system for diesel engine generators in the offshore industry. This product will optimize combustion, thus increasing engine efficiency and reducing diesel consumption and GHG emissions. In particular, this paper demonstrates the feasibility of the key concepts of the proposed solution.

The approach breaks down and tests the main concepts for an onboard hydrogen production system into key concepts. Different experimental methodologies, including tests on an optical access engine and performance and emission tests on a diesel generator, are used to explore the main hypotheses related to the proposed hydrogen production system. The energy balance between hydrogen production requirements and diesel efficiency benefits was estimated and evaluated. The study also employs thermoeconomic analysis using the SPECO methodology and utilizes machine learning models for predictive analysis and to develop optimized hydrogen injection maps.

The project substantiates several hypotheses about hydrogen's positive impact on diesel combustion, fuel consumption, and emissions and validates key concepts related to our proposed solution's product development. Hydrogen enrichment improves combustion quality and efficiency, reducing fuel consumption and greenhouse gas emissions in low and medium engine loads. The solution proved cost-effective from a thermoeconomic perspective, and the energy offset was favorable. Machine learning methodologies accurately predicted performance and emissions, leading to optimized hydrogen injection strategies. The research highlights the need to carefully consider hydrogen flow rates and load parameters for optimized performance. It demonstrates the potential of our proposed solution to reduce fuel consumption and GHG emissions.

This paper provides novel insights into the integration of hydrogen into diesel engines and extends the current body of knowledge. It bridges theoretical understanding and practical application, providing valuable guidance for enhancing engine performance through hydrogen technology. This paper demonstrates our project's maturation and feasibility, and investing in it will enable the industry to lead in addressing climate change and contributing to a sustainable future.
The Importance of Geology in Geothermal Development and Critical Minerals Development
Authors: Nash Susan Smith
Published: April 2024

This paper provides a summary and overview of the geological features and processes vital in the identification and development of geothermal reservoirs, with special consideration to different categories of geothermal systems, and the relationships to critical mineral-rich brines. The methods used in this investigation included the review and evaluation of geological aspects of known reservoirs that have data consisting of well logs, cores, microseismic, and geochemical analysis of fluids. Specifically, faults and fracture networks, primary and secondary porosity, and diagenetic alteration (dissolution, precipitation, cementation, and more) were evaluated, including work with scanning electron microscopy to evaluate the timing, sequence, and processes in the diagenetic alteration.
Towards Standardized Integration of Seafloor Mapping Tools for Offshore Benthic Characterization
Authors: Jones C. , Doolittle D. , Revelas E. , Rebuck N.
Published: April 2024

Offshore energy development requires a thorough understanding of the seafloor and benthic environments to inform the potential risks to infrastructure and assess the potential environmental impacts of the project. In this paper, we present a novel method for generating quantitative benthic maps using integrated seafloor SPI-PV imagery and MBES data. We use a predictive processing framework that extracts physical and biological metrics from the SPI-PV images and combines them with MBES bathymetry and backscatter data. The framework is demonstrated at a permitted energy site off the Pacific Coast of the United States. The resulting maps provide valuable information for environmental assessments, geohazard assessments, and monitoring of offshore sites. The method can help evaluate site suitability, monitor environmental changes, and enhance the safety and efficiency of offshore operations. The method also reduces risks and costs associated with offshore energy production by enabling rapid and consistent seafloor surveys.
Reduced Carbon Load and Increased Value-Applying Renewable Energy to Deepwater Tiebacks
Authors: Robinson R. , Engelmann G. , Leung P. , Furtado I. , Choudhary A.
Published: April 2024

As oil and gas look to reduce the carbon impacts of their offshore production, consideration is being given to incorporating offshore renewable energy into their offshore assets. Incorporating green energy into oil production reduces their Scope 1 emissions and potentially positions oil and gas fields to transition to green energy production when the reservoirs play out.

What this paper will show is that there are also ways for this to result in direct economic benefits, even while the renewable technologies are in their infancy.

A key enabler to this outcome could be Enhanced OTEC or EOTEC, which is a novel marine renewable energy system that produces continuous power, eliminating or reducing the need for back-up power. The main power production equipment for this system concept is seabed located, reducing the topsides requirements of typical systems, allowing for the possibility of brownfield retro-fit. Combining EOTEC with proven subsea factory components will allow the development and production of fields currently thought to be located too far from existing facilities via subsea tie-back. As a minimum, incorporation of such systems can reduce the cost and carbon load of the produced oil and gas. It may also allow faster development cycles and will extend the useful life of existing assets.

The paper presents a comparison of 4 different methods or producing a marginal field, two of which are conventional development approaches and two which are renewable energy enhanced. Developing the field as a new production facilityA long tieback powered from the existing facilityA long tieback with subsea factory components powered by wind and batteriesA long tieback powered by EOTEC.

Both immediate and long term benefits of such a system will be considered.
Using a Mechanical Whale to Test Automatic Whale Blow Detection with Applications to Offshore Wind Development
Authors: Eaton R. S. , Prisco J. C. , Everson J. J. , Riedel J. E. , Randall Y. M.
Published: April 2024

Marine mammals have the potential to be harassed by exposure to loud sounds caused by survey or construction activity and even killed by collisions with fast moving vessels. Thus, vessels supporting offshore wind projects must maintain an effective lookout for large cetaceans to prevent harm and comply with relevant Federal regulations. Currently, trained human protected species observers (PSOs) maintain a lookout using binoculars or the naked eye, but this approach requires many trained personnel to maintain a constant lookout and only works during daylight hours. Recent advances in deep learning algorithms, processing hardware, and training data availability have made the prospect of automated marine mammal lookout systems more feasible. Furthermore, thermal infrared (IR) cameras offer the possibility of maintaining a reliable lookout 24-hours per day. Whale blows are often the most prominent feature of a whale on the surface due to their large vertical profiles, and IR cameras can also take advantage of the blow’s high thermal contrast to improve the chances of detection. However, before these automated detection systems can be widely adopted, their efficacy must be proven, which requires numerous test samples in varied conditions. While real-world data collection can provide some instances of whale blows, the exact range to the blow remains uncertain, and replicating the blow for effective and statistically-significant testing across conditions is infeasible. In this paper, we describe the design of an artificial whale blow and a camera-based whale blow detection system, as well as initial results of testing the detector on the artificial blow. In particular, we demonstrate the feasibility of blow detection in IR and begin the process of characterizing detection performance as a function of weather conditions, sea state, and range.
Real Time Choke Erosion Prediction Using Real-Time Advisory Tool
Authors: Al-Kadem M. S. , Daanyal M. , Bayounis R. A. , Alghamdi A. A.
Published: April 2024

Wellhead choke valve is commonly used to control flow rate in production and injection wells in oil industry. Wells producing high solids content can cause erosion resulting in production loss and potential safety concerns due to choke failure. In such cases continuous choke valve monitoring has become crucial to detect issues at the onset. In this paper, a well digital twin was developed to monitor choke erosion and predict when it might happen.

An advisory tool was developed to monitor choke valve erosion in offshore High Pressure High Temperature (HPHT) offshore gas wells. The tool uses real-time surface wellhead parameters and choke correlations using industry standard steady-state production engineering design application to identify any anomalies in choke valve performance on real-time basis. The tool also provides a quantitative estimation of the chokes mean time to failure under actual production conditions which would open the way for improved design and increased life-span.

Ten thousand data points were used for wells completed in gas reservoirs. The tool identified the start of erosion each time as it started until the choke was replaced in the selected wells over 7-year period with an accuracy of greater than 95%. The methodology provides a choke erosion indicator which compares actual and calculated choke size where a positive value gives the signal of choke erosion events as they start to happen. The results enable engineers and operators to avail the replacement of chokes in a period of three to five months where it took more than a year prior to the tool development. Moreover, the analysis further highlighted the safe rates to limit the erosion and how much time and production rate it shall take for the choke to erode once the erosion starts.

The developed tool has aided in minimizing the safety related issues and risk of production loss due to choke failure. Additionally, it has also helped the engineers in making timely decisions by identifying the onset of erosion leading to better management of the material lead time for replacements. It is deemed to be useful not only to minimize production deferment but also mitigate any safety related issues and manage the procurement of long lead items especially in offshore fields.