Offshore Technology Conference Research Articles

Revitalization Project Promises New Production Plateaus for Campos Basin Fields

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35457, “Marlim and Voador Fields Revitalization Project,” by Mateus T. Paula, Daniel H.M. Lage, and Aldemir B. dos Santos, Petrobras, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ The complete paper presents an overview of the operator’s Marlim and Voador fields revitalization project, highlighting achievements so far in the context of Campos Basin redevelopment. The project includes two mature fields discovered in the 1980s in the eastern portion of the Campos Basin. The main purpose of the revitalization is to renew production systems by means of decommissioning nine existing platforms and installing two new floating production, storage, and offloading (FPSO) vessels. Marlim and Voador Fields Overview Fig. 1 depicts shallow and deepwater hubs in the Campos Basin. Marlim is offshore the state of Rio de Janeiro, approximately 150 km from the city of Macaé, with water depths ranging from 650 to 1050 m and covering an area of nearly 258 km2. Voador is northwest of Marlim, with water depths ranging from 400 to 700 m, covering an area of nearly 82 km2. Because Voador is a smaller complementary oil field located at the same Marlim Field ring fence, this revitalization project is commonly referred to as REVIT Marlim. Therefore, in this paper, the mention of REVIT Marlim also considers the Voador field. Reservoir Characterization The Marlim Field was discovered in January 1985 through Well 1-RJS-219A, drilled in a water depth of 853 m. Its primary objective was to test the Oligocene amplitude anomaly. The Oligocene reservoir was found to have a porous oil-bearing thickness of 55 m, a porosity of 32%, and connate water saturation of 11%. This reservoir, named Marlim Sandstone (ZP-MRL200-RJS219A), is the main reservoir in the Marlim field, with an average permeability of approximately 5000 md and oil ranging from 19 to 24 °API. The Voador field was discovered in 1987 through Well 4-RJS-377, which revealed a total reservoir thickness of 39 m filled with oil. The drilling of Well 4-RJS-403 in 1989 confirmed the presence of a stratigraphically correlated reservoir with a thickness of 33 m like the one found in Well 4-RJS-377. These reservoirs have 21 °API oil, an average porosity of 30%, and an average permeability of 2000 md. REVIT Marlim Primary Goals With the launch of the first production system in 1992 and the last in 2000, the initially planned strategy for the fields was that the platforms should be able to produce until the end of the concession, which at that time was set to be 2025. Over the years of production, however, the basic sediment and water in the wells increased, leading to a corresponding rise in water production that required treatment on platforms. Additionally, environmental restrictions and a desire for increasingly environmentally conscious projects prompted the operator to consider adjustments to its plants. Added to the fact that existing units were already reaching the end of their useful life, with some equipment and operational control systems requiring more maintenance, this combination of factors resulted in an increase in operational costs.

European and US Efforts To Develop Geothermal Energy Are Headed in Different Directions

_ Writing about emerging geothermal technology requires dealing with the fact that it is emerging in different forms in different places. A common thread of what’s new are methods based on drilling wells into hot rock to deliver fluid into hot formations to harvest energy. Chances are that sentence is not exactly an accurate description of any particular method because of the significant differences among them. Some use hydraulic fracturing while others do not. One pumps water from well to well, another into the fractures of a single well, and the third keeps the fluid inside the wellbore. And the end product varies as well. In the US, the big early developments are aimed at generating electricity for the grid and storing energy in developments where wells are fractured. In Germany, the big target is providing hot water to district heating systems that deliver it to a wide range of customers in urban areas. New technology there must avoid fracturing. In Germany, they are testing a new geothermal method that harvests heat in deep well loops using a fluid that brings energy to the surface with minimal pumping. “In Utah or Nevada, the use case is they do electric only versus in Europe where it is more heat plus electricity,” said Florian Mueller, a PhD candidate doing research on geothermal at the Energy and Technology Policy Group in Zurich, Switzerland. In both cases these methods were developed by startups whose early commercial applications require adapting to a mind-numbing list of external factors. As a result, “Geothermal will look different everywhere,” said Ken Medlock, the senior director of the Center for Energy Studies at Rice University, during a panel session at this year’s Offshore Technology Conference (OTC). Adaptation The differences reflect a common challenge faced by innovators. A practical solution to a pressing problem, engineered to be reliable and cost-competitive, is just the starting point. Growth from there will depend on how they adapt to the market. In the US, Fervo Energy’s first large-scale commercial project in southern Utah is heating water by pumping it from injection wells to production wells through rock fractured from both sides. Produced water will need to be around 400°F—higher is better—to ensure it can be used to efficiently generate electricity for consumers in southern California. In southern Germany, Calgary-based Eavor Technologies is building a series of 12 flow loops with cased vertical wells linked by a long, uncased lateral that is treated to ensure the fluid remains in the wellbore and is heated efficiently. When built, each loop will be filled with a fluid formulated to conduct geothermal energy to the surface where it will be used for home heating during the cold months, and electric generation during warmer ones. The differences often reflect the vagaries of regulation. Fervo is building its 400 MW geothermal electric plant, Cape Station, 500 miles from its initial customers at a site in southern Utah where the quality of the formation was already known because it adjoins the US geothermal test site commonly known as FORGE. Also, the remote desert site minimizes the likelihood of opposition to drilling and fracturing, which is not the case in California which has banned fracturing.

Ground Robots Bring Potential for Efficiency, Safety in FPSO Operations

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32872, “Evaluation of the Potential Impact of Ground Robots on FPSO Operations,” by Gustavo L.L. da Silva, Maurício M. Cordeiro Jr., and Maurício Galassi, Petrobras, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ The objective of this paper is to present the operator’s learnings in evaluating the processes by which the asset crew of a floating production, storage, and offloading (FPSO) vessel identifies scenarios for the application of robotics in day-to-day offshore activities. The studies reveal a glimpse of the addressable market size of ground robots for routine offshore verification tasks. An initial analysis suggests that 30–50% of the theoretical equivalent of hours per year could be freed. Introduction In the complete paper, the hypothetical use of ground mobile robots to carry out operational activities is considered. For that goal, the capability of robotic platforms to move along an offshore facility (an FPSO, for the purposes of this paper) has been explored. This includes the ability to overcome obstacles, move up and down stairs or ramps, and walk on uneven floors or gratings while being piloted remotely or even doing so autonomously. Some of the considered equipment may have coupled robotic manipulators that also enable them to interact with the environment, allowing them to open or close doors, turn handles, and activate commands. These robotic platforms, in general, include actuator mechanisms and sensors that enable visual inspections, thermography, dimensional analysis, area mapping, gas measurements, noise and vibration analysis, and other operations requiring specific sensing. Operational Requirements A paramount requirement for a robot to be widely used in an FPSO is its ability to operate in hazardous areas. Robotic platforms for hazardous zones are not widely available. However, some companies are quickly advancing in the development and commercialization of these platforms. A Swiss company has already made available a quadruped robot with high mobilization capacity, including the ability to navigate stairs and carry out autonomous missions that have been preprogrammed. An Austrian company has marketed a caterpillar robot that can carry out inspections autonomously in classified areas. Every such activity will demand thorough analysis to properly define technical and process requirements. On FPSO platforms, the procedure for planning any service takes place at least a few days before its execution, a task already demanding many hours. Subsequently, a permit to work (PTW) is issued to perform the service. Sensors and Actuators for a Robotic System Some of the main data-acquisition or processing sensors used in robotic systems are detailed in the complete paper. In this context, “data” means everything that can be processed online or is capable of producing useful information in the future. Cameras for Acquisition of Images and Videos. These can be very useful in the visual inspection of systems or equipment, the visualization of the workspace, or the generation of input for image processing with the purpose of identifying patterns of interest, segmentation, classification, or other aspects related to computer vision.

Machine-Learning Approach PredictsGel Strength of Drilling Fluid While Drilling

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35433, “Novel Machine-Learning Approach for Predicting the Gel Strength of the Drilling Fluid While Drilling,” by Ahmed Gowida, SPE, and Salaheldin Elkatatny, SPE, King Fahd University of Petroleum and Minerals. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ Accurately estimating gel strength is paramount for optimizing drilling operations and preventing cuttings from settling at the wellbore’s bottom. Traditional methods rely on rotational viscometers, which are time-intensive, equipment-dependent, and lack real-time monitoring capabilities. This study underscores the feasibility of leveraging machine learning (ML) as a practical tool for predicting drilling-fluid gel strength, offering real-time monitoring and precise predictions to enhance drilling efficiency, safety, and automation initiatives. Background The gel strength of drilling fluid is assessed using a viscometer, focusing on the 3-rev/min reading obtained after agitating the fluid at 600 rev/min to disrupt any gel formation. Initially, the measurement is taken when the mud reaches a static state for 10 seconds. Subsequent readings are conducted at 10- and 30-minute intervals. The rationale behind the 30-minute reading lies in its ability to indicate whether the mud forms a substantial gel during prolonged static periods, such as when tripping out a bottomhole assembly. Elevated gel strength may result in increased pump pressure required to restore circulation after extended static conditions. Additionally, a consistent upward trend in the 30-minute gel strength suggests the accumulation of ultrafine solids. Consequently, appropriate measures such as chemical treatments or dilution with fresh base fluid are necessary to address this issue. The frequency of measuring various fluid properties is tailored to their respective effects on well-control and drilling operations. These frequent evaluations allow for timely adjustments and monitoring of rheological measurements, offering valuable insights into rock sensitivity and the performance of mud activity and stability after exposure to drilled formations. On the other hand, a complete mud test (including all mud rheological properties) is performed twice a day because it consumes considerable time. It has been observed that mud rheological properties exhibit a significant correlation with two fundamental mud properties: mud weight and Marsh funnel (MF) viscosity. To the best of the authors’ knowledge, a dearth of research exists in the literature aimed at predicting the gel strength of drilling fluid using ML techniques. Consequently, this research endeavor introduces a novel ML model designed specifically for forecasting the gel strength of synthetic oil-based mud systems. Such predictive models are poised to enhance drilling performance by optimizing mud functions. Leveraging MF and mud-density measurements, the developed models aim to forecast the rheological properties of drilling fluid, thereby facilitating improved monitoring of mud functionality during drilling operations at the rig site.

President’s Column: SPE Finances

_ Editor’s Note: The November edition is a written column only, with the vodcast set to resume next month. _ SPE finances are not the most interesting or exciting topic for most members, and you will be forgiven if you pass this column. You may not be interested at all if you only want to know what SPE does. However, you may be interested in this column to understand how SPE functions financially. SPE is not a commercial business, but it has an events business that de facto finances most of its other services to members—direct membership fees are a relatively small part of SPE’s revenue. In the current model, if the events business fails, SPE collapses. Finances are always important, but they have become critical in the current context, including the 2015 downturn and the 2020 COVID-19 pandemic, especially the latter, which have brought an existential threat to our Society. As shown in Fig. 1, between 2014 and 2023, we lost 65% of our revenue, 200% of our profit (Net Operating Income), and 50% of our net assets. Even last year, 3 years after the pandemic, we still had an operational deficit of $3.6 million, and this was expected to be a “good year” with Offshore Europe and two Offshore Technology Conference events. Operationally, we are still hemorrhaging money. SPE’s finances are public, but I thought it would be good to present this information in plain English and with illustrative graphs to explain how we operate financially and how SPE can prevail while its traditional business model is being challenged. I have occasionally heard and read severe statements about SPE’s financial management, allusions to staff being oversized and overpaid, our lack of willingness to adapt, etc. So, it is also a good opportunity to clear up some of these misunderstandings. Conventions and Definitions Until 2024, SPE’s fiscal year (FY) started in April and ended in March. For example, FY24 started on 1 April 2023 and ended on 31 March 2024. This has recently changed and will be explained below. The numbers presented in this document are consolidated in USD (SPE has several offices handling different currencies) and corrected for US inflation using factors listed in Fig. 2. The reference is the USD from the middle of FY24, i.e., October 2023. One important result to gauge our operational results is our Net Operating Income (NOI), which would be equivalent to profit if SPE were a commercial venture.

Geothermal Power, and a Battery as Well

One of geothermal energy’s key advantages is that it’s always on. But making money selling power increasingly requires being able to react to shifts in electric prices by adjusting production up and down. The fact this is a concern now is an indication of the ambition of a new generation of companies that have shown it is possible to use horizontal drilling and fracturing to build subsurface heat exchangers to harvest large amounts of geothermal energy. The geologic potential is huge—there are a lot of places with hot rock at a drillable depth. But monetizing that potential will require grabbing a sizeable share of the market in big states such as California and Texas where the price of electricity can sink toward zero when sunny conditions allow maximum solar power production, and then rebound as the sun sets. This is a pressing concern for Houston-based Fervo Energy because it is one of the first firms in a small pack of innovators to reach the point where it is building a large scale power plant using this emerging technology. Unlike wind and solar, it can deliver power on demand, similar to coal, gas, and nuclear-powered plants that supply baseload power to the electric market. Fervo’s founders play up its ability to deliver power on demand, but they resist the label baseload power provider because, as Jack Norbeck, chief technology officer and cofounder of Fervo, said, “In the future, baseload power will be a thing of the past.” Baseload power plants are not yet an endangered species. There are still large, mostly old fossil-fueled plants providing baseload power that are still around because they were paid for long ago. However, their numbers are declining as they wear out and are hit with demands for costly emission reductions. The initial sales by Fervo’s Cape Station project in Utah will provide baseload power to southern California power suppliers, complying with a unique California rule that requires them to source low-carbon power supplies that are available 24/7. But for new geothermal companies to sell enough power to become significant players in US power markets, they will need to provide what the electricity business describes as “more flexible, dispatchable power.” Big baseload plants ruled the power universe back when regulators set rates high enough to maintain a sizable surplus of generating capacity—ensuring the lights stayed on. Now, in markets such as Texas and California, power pricing rises and falls based on supply and demand, with selling at all times sometimes resulting in very low payments during peak production periods for solar and wind. This is particularly true during seasons where days tend to be sunny and windy with moderate temperatures. “If you are consuming electricity, particularly in the spring and fall, it is an extremely clean grid you are pulling from,” said Christian Gradl, vice president of operations for Fervo during a panel at this year’s Offshore Technology Conference.

Application for Predicting Vessel Motion Enhances Operability in Offshore Drilling

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35341, “Enhancing Energy Efficiency and Operability in Offshore Drilling Operations: Validation and Benefits of a Machine-Learning-Based Vessel-Motion-Prediction Application,” by Daniel A.C. Canache, Massimiliano Russo, and Rune Haakonsen, Kongsberg Maritime, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ This paper delves into the framework of a new application that leverages advanced machine-learning (ML) techniques in conjunction with metocean forecasts to predict vessel motions and thruster loads. The discussion encompasses the key role of diverse input factors in shaping prediction accuracy and outlines strategies to address inherent uncertainties associated with methods, weather forecasts, and the stochastic nature of the underlying problem. Methods, Procedures, and Process Traditional Physics-Based Vessel Model. A physics-based model of the vessel is used to train the ML model. As such, the accuracy of the physics-based model is critical to the success of the ML model. The model is built using vessel-specific hydrodynamic data, mass data, and thruster-control software. The thruster-control software is extracted from the actual vessel to ensure that the same settings are being used in the model. The model is used to execute time-domain simulations, which include second-order effects, from which prediction targets [six degrees-of-freedom (DOF) motions and thruster usage] are extracted. As shown in Fig. 1, four environmental components are typically considered: wind waves, swell waves, wind, and current. To train an ML model capable of predicting in any given weather condition, environmental parameters are varied over thousands of simulations. Physics-Informed Neural Network (PINN) Architecture. The adopted architecture for the ML model is a PINN, a model architecture that offers several advantages. By integrating vessel-specific hydrodynamic data, the model becomes grounded firmly in the underlying physical phenomena. Furthermore, the architecture facilitates the model’s comprehension and assessment of the environment by enabling the compilation of individual loads into an overall load acting on the vessel. Ultimately, the analysis of resultant loads on the vessel provides a means to compare various environmental load cases directly in relation to the vessel’s response. Optimizing the Training Matrix. The optimal training matrix should span the environmental parameter space up to the vessel’s station-keeping capacity while minimizing the number of necessary load cases. Given the computational expense and prolonged execution times associated with time-domain simulations, it is important to maintain a manageable number of cases. While resultant loads facilitate the comparison across different environment load cases, a systematic algorithm is needed for case selection. To address this requirement, a similarity metric incorporating cosine similarity and Euclidean distance was implemented. The downside to the Euclidean distance is that, at low magnitudes, the distance will be low regardless of direction. This is mitigated to some extent by combining the measure with the cosine similarity. The cosine similarity will be high if two vectors are close in direction regardless of their magnitudes. For the specific problem described in the complete paper (vessel responses), it is desirable that the similarities at low loads stay high because the response also will likely be low.

Drilling Automation Serves as Engine of Change for Risk Prevention Offshore

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35137, “Drilling Automation: An Engine of Change for Risk Prevention Offshore,” by Brennan Goodkey, SPE, Andrew Fabo, and Francois Le Buhan, SLB, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ This paper delves into the evolving landscape of drilling automation, emphasizing the imperative for these systems to go beyond novelty and deliver quantifiable financial value. The complete paper presents an examination of several offshore drilling operations that exemplify the successful implementation of a closed-loop drilling-automation solution and the positive effect these technologies can have on the bottom line. Introduction In the dynamic landscape of drilling technologies, the conventional discourse on rig mechanization, robotics, and drilling automation is no longer a new topic, having nearly a decade of active discussion, development, and deployment. However, these systems, despite their longstanding presence, are still working toward substantiating their anticipated value. To navigate this challenge successfully, a clear understanding of where and how exactly the deployed solution will deliver value is required. The criteria of success inevitably will vary based on the customer, region, and objective. One of the clearest examples is obvious in the dichotomy between the priorities of high-volume drilling in onshore operations compared with offshore drilling. While the overarching goal of automation remains consistent—maintain safety while maximizing production and minimizing operational expenditures—the path to delivery in these spaces looks quite different. Offshore drilling introduces a myriad of complexities and must prioritize not only efficiency but also risk reduction and the minimization of nonproductive time. The complete paper examines the collaborative journey of several oil and gas organizations to deploy and improve a drilling-automation system aimed at the priorities and challenges of offshore drilling. Definitions The authors offer the following definitions to delineate scope as they describe an integrated system that combines domain drilling automation, rig-floor mechanization, and directional-drilling automation into a cohesive and comprehensive solution: - Domain Drilling Automation—This refers to the process of leveraging sensor data to interpret downhole conditions and react with the appropriate domain response, mimicking an experienced driller’s expertise with high accuracy and precision. - Rig-Floor Mechanization—This is the implementation of automated technologies and robotic systems on the rig floor to limit manual human involvement in tasks situated within the hazardous red zone. - Directional-Drilling Automation—This term refers to the use of automated systems and technologies to control and navigate precisely the trajectory of a drilling borehole, enhancing accuracy and efficiency in achieving specific wellbore paths and target zones. - Planning Drilling Automation—The use of advanced technologies and automated systems during office-based well planning is leveraged to optimize resources, enabling precise and efficient decision-making for the entire drilling process. - Real-Time-Monitoring Drilling Automation—The use of advanced automation technologies can monitor and analyze drilling operations continuously in real time, providing instantaneous feedback and adjustments to optimize performance, efficiency, and safety.

Study Evaluates Long-Term Corrosion Risk of Load-Bearing, High-Power ESP Cable

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 34898, “Long-Term Corrosion-Risk Evaluation of Load-Bearing, High-Power Electrical Submersible Pump Cable,” by Serko A. Sarian, SPE, Alkhorayef Petroleum, and Hattan Banjar, SPE, and Chidirim Ejim, SPE, Saudi Aramco, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ In this study, a fit-for-purpose electrical submersible pump (ESP) load-bearing power cable was deployed inside the production tubing of a sour oil well for an extended period of service. Project economics required the power-cable metallurgy to survive long-term exposure reliably for up to 15% hydrogen sulfide (H2S) and high-salinity production fluids. Laboratory tests simulating varying sour well and extended galvanic corrosion conditions have been performed to determine the adequacy of the selected armor metallurgy in downhole corrosive environments. Introduction In recent years, various types of load-bearing power cable-deployed ESP (CDESP) systems have been introduced, eliminating the need to install or remove a conventional ESP along with the completion and reducing ESP changeover time by more than 80%. More recently, live-well CDESP systems have been developed and tested to eliminate the need for a well-kill operation. The most-critical and costly component of such a system is the load-bearing power cable. The cable has the dual purpose of conveyance and long-term powering-up of the ESP. In a conventional artificial lift operation, the ESP is conveyed using the production tubing with a non-load-bearing power cable strapped to the outside of the tubing. This operation requires a workover rig to remove and reinstall the entire completion and a killed-well operation that might permanently damage the reservoir. The main advantages of a CDESP system include operational efficiency gain and cost reduction, no reservoir skin damage, and production-loss minimization. However, a few challenges exist with the use of CDESP. These cables must have significantly different structures from commercial oil and gas power cables. These differences are detailed in the complete paper. Cable-Design Requirements CDESP system criteria include multiple-year continued service in adverse oilwell and reservoir conditions such as sour fluids, high gas/oil ratios (GOR) and temperatures, and abrasion caused by solids production. The following product acceptance requirements were set in advance: - Three redeployments or retrievals after the initial deployment - Single deployment continued runtime to meet or exceed the regional conventional ESP system runtime Based on regional statistics, a conventional ESP system single-deployment average run time is 2.5 years. The effective CDESP power-cable service life target then becomes 2.5 years × four total deployments = 10 years, which served as the basis for all cable-associated testing and reliability metrics.

Autonomous Inflow Control Devices Help Maximize Life of Wells in Deepwater West Africa

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35418, “Design Execution and Evaluation of Advanced Completions in Deepwater West Africa,” by Piyush Pankaj, SPE, Matthew S. Jackson, and Lokesh, ExxonMobil, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ Deepwater wells offshore West Africa traverse a complicated faulted block with sand bodies that can feature thicknesses of tens of meters. The study described in the complete paper provides insight into designing advanced well completions under various challenging reservoir conditions with autonomous inflow control devices (AICDs) that enable maximizing the producing life of the wells. Introduction The study area for this paper has been a challenging brownfield. Wells have been drilled in difficult deepwater conditions, and the target reservoirs have been lenticular sands with interbedded shale layers. To further complicate production, the sand bodies are poorly consolidated. Openhole wells with standalone screen and gravel packs have become a common approach to address sand control. Water- and gas-injection programs have been used actively in the field during the past 25 years, which further augments production and reservoir management challenges. Water and gas breakthrough in the infill wells has been a major concern for reservoir management. To address the gas buildup in the near-wellbore region and early water production, AICDs have become a popular feature in the lower well-completion designs in high-angled wells that intersect multiple sand bodies along the lateral completion interval. Two case studies are provided in the complete paper; one is included in this synopsis. Flow-Control Technology Although technology that empowers the ability to control the flow of unwanted fluids from zones in the well has been in use since the 1990s, flow-control technology has rapidly evolved, with advancement fueled by the need for long, complex well designs. The two broad categories of these approaches include active and passive flow control. The decision to use inflow-control technologies can be driven by the following economic values: - Balance drawdown along the wellbore - Increase recovery factor and reserves - Improve well cleanup - Reduces risk of erosion or hot-spotting of sandface completion Choice of Inflow Control for West Africa Field of Study Fluidic-diode AICDs were chosen because of their applicability to encountered fluid properties and reservoir conditions and their robustness of design in providing reliable long-term solutions. The reliability is prolonged in such AICDs because they work without any moving parts. Upon changes in viscosity, density, and rate, the fluid flow path will vary to gain the required control of flow rates. This AICD design, with its special geometry, alters the flow path or pattern for preferential fluid restriction. Operational Execution Ultimately, the AICDs were deployed on an inner string. This allowed the standard wire-wrapped screens and gravel pack to function as the traditional sand-control mechanism, while the inner string, deployed inside the lower completion, provides resistance to flow from unwanted gas production.

Multidisciplinary Approach Underpins Development of Marginal Presalt Reservoir

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35273, “Sururu Central: Appraisal and Development Plan for a Marginal Presalt Reservoir,” by Thiago E.S. Azevedo, L.M. Hayashi, and Rodrigo R.S. Leal, SPE, Petrobras, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ The complete paper presents a multidisciplinary view of the evolution of the concept of a development project for the central area of the Sururu reservoir and the method applied to address challenges and propose solutions. The central area presents distinct characteristics from typical Brazilian presalt fields, with low permeabilities despite high porosity. Sururu Reservoir The reservoir is in the Santos Basin 230 km offshore Rio de Janeiro at water depths ranging from 2000 to 2300 m. The wildcat in the reservoir, 1-BRSA-618-RJS (1-RJS-656), is in the central area of the field, which is the main subject of the present work. The well exhibited reasonably high average porosity while presenting low permeabilities and low productivity when compared with other presalt wells. The second well, 3-BRSA-891A-RJS (3-RJS-682A), was drilled in 2011 in an area known as Iara Horst, also in the central area of the Sururu reservoir and presenting the same challenges faced by the wildcat. The third well, 3-BRSA-1181D-RJS (3-RJS-715D), was drilled in 2013 as a high-angle multifractured well consisting of an alternative architecture. Productivity results, however, were similar to the ones obtained in the previous wells. Investments were made in acquiring and reprocessing seismic data, ultimately leading to the drilling of the fourth well, 9-BRSA-1212-RJS (9-RJS-726). This well, in the Sururu Oeste area, revealed characteristics more similar to other Brazilian presalt fields and cleared the path to the later drilling of other Sururu Oeste wells. These good results paved the way for floating production, storage, and offloading (FPSO) vessel Petrobras 68 (P-68), which has produced both the Berbigão and Sururu reservoirs since November of 2019. P-68 is a 150,000-BOPD, 6-million std m³/d gas processing “replicant” FPSO that includes 10 producers (five from Berbigão and five from Sururu) and seven injectors (four in Berbigão and three in Sururu). However, the idea of developing an alternative for producing the Sururu Central area was never abandoned. In 2020, the ninth Sururu well and the fourth well in the central area, 9-SRR-5-RJS, was drilled near some of the main Sururu Central faults, aiming to test the existence of better reservoir quality or the presence of conductive in-situ fractures. The results from the well were in line with the results from the previous three wells drilled in the area, confirming the challenging nature of Sururu Central productivity. A suitable development strategy for the area was increasingly dependent on the attainment of long-term dynamic data that could support a modeling hypothesis for this unique presalt reservoir.

Study Finds Compact Carbon-Capture Modules Feasible on Offshore Production Facilities

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 34825, “Implementation of Compact Carbon-Capture Modules on Offshore Hydrocarbon Production Facilities,” by Jaime H. Tan and Rizal A. Hassan, Technip Energies, and Umberto Cornelis, KANFA, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ Carbon capture and storage has been implemented onshore successfully by different industries, including utilities and waste treatment, to capture CO2 from flue gases after the combustion of fossil fuels. Duplicating this success for offshore hydrocarbon processing facilities can be challenging because of deck-space constraints and marine environmental conditions. The complete paper describes the development of a compact carbon-capture module design for post-combustion carbon capture and its potential implementation on typical offshore hydrocarbon production facilities. Solvent Absorption Technology for Post-Combustion Carbon Capture The process technology at the core of the compact carbon-capture module is based on a solvent-absorption technique and a proprietary amine-based solvent. First, feed gas is quenched and saturated in a circulated water prescrubber. The gas contacts the lean amine solution in a countercurrent mass-transfer packed absorption column, and CO2 is absorbed while the treated gas exits to the atmosphere. Midway through the column, partially loaded amine is removed from the tower, cooled, and reintroduced over a layer of mass-transfer packing. CO2-rich amine from the absorption column is pumped through a lean-rich amine heat exchanger and then to the regeneration column. The rising, low-pressure saturated steam in the column regenerates the lean amine solution. CO2 is recovered as a pure, water-saturated product. Lean amine is pumped from the stripper reboiler to the absorption column for reuse in capturing CO2. Finally, the CO2 is directed to byproduct-management systems. The pure CO2 streams produced from the system may be sequestrated or used for applications such as enhanced oil recovery. Design of Offshore Carbon-Capture Modules For offshore applications, the carbon-capture modules must be more compact and lighter compared with carbon-capture systems developed for onshore applications. The absorber column is the critical component of the carbon-capture module because of its weight, footprint, and height. To reduce the overall height of the absorber for offshore application, an innovative configuration has been adopted: The bottom section of the absorber is placed on top of the prescrubber/direct contact cooler (DCC), and the top section of the absorber and the wash-water section comprise the second column. With this arrangement, the maximum height of the columns is limited to approximately 25 m. Because the lower absorber section is placed on top of the prescrubber/DCC, the in-between chimney tray is designed to be totally leakage-free to avoid losses of amines into the DCC water loop. A patent-pending compact absorber column design has been developed. The column wall construction will be a part of the overall module support structure, with cantilevered platforms for supporting carbon-capture equipment. The equipment for compression, injection, and treatment of CO2 is placed on a separate submodule. This module design benefits from footprint and weight savings of potentially more than 20% compared with typical cylindrical absorber column designs.

Shear-Wave Velocity Data Assists Modeling for Offshore Windfarm Development

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35354, “Pseudo-3D Underwater Multichannel Analysis of Surface Waves for Offshore Windfarm Development,” by Stephan Unterseh and Luis McArthur, TotalEnergies, and Edouard Mouton, SismOcean. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ In the course of a research and development (R&D) project dedicated to quantitative ground modeling, underwater multichannel analysis surface-wave (UMASW) data were acquired within an offshore windfarm area currently in development in the North Sea. The goal of the project described in the complete paper was to test the added value of the shear wave velocity (Vs) interpreted from the UMASW, particularly as a propagation tool of geotechnical information. While UMASW, together with seismic refraction, is regularly used to characterize the ground for burial or trenching purposes, it appears also to bring valuable design parameters for offshore wind turbine foundations. Introduction To investigate the value of Vs in the performance of quantitative ground modeling studies, an internal R&D initiative was launched aimed at acquiring Vs data and the associated uncertainties of foundation depth of an offshore windfarm currently in development. These data will be tested at a later stage for the propagation of geotechnical parameters used in foundation design. The acquisition consisted of obtaining Vs data through UMASW methodologies around two distinct geotechnical boreholes and along a corridor tying the two areas. The UMASW commonly is used in combination with seismic refraction to perform burial assessment analysis of cable or pipeline or to characterize ground conditions before performance of horizontal deviated drilling. Thus, the data acquisition did not require extensive hardware development. A unique pseudo-3D processing technique nevertheless was implemented to allow for 3D data visualization and ground characterization. Site Conditions The selected site lies in the North Sea in water depths ranging from 20 to 30 m. The area was first investigated with standard geophysical techniques. Preliminary geotechnical investigation included 6-m-deep vibrocores and 60-m-deep drilled boreholes, with alternating cone penetration tests and push sampling and coring. P-S logging also was performed at key geotechnical locations to gather 1D primary wave velocities (Vp) and Vs. The seabed generally consists of a thin cover of Holocene dense sand, occasionally with boulders, overlying quaternary subglacial formation deposits, including moraine, gravelly sand, and clays of variable thicknesses. The bedrock is generally Jurassic and includes dense sand; hard clay; weak claystone; and, locally, strong limestone bands. The test locations were selected within the coverage of the geophysical data set in areas where variable lithologies occur and where the seabed was found free of boulders and outcrops because these are detrimental to UMASW acquisition. The lithology of the two boreholes performed within the test area is indicated in Table 1 of the complete paper.

Industrial Cybersecurity, Process Safety, and Human Factors: A 360° Approach

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35396, “Industrial Cybersecurity, Process Safety, and Human Factors: A Comprehensive 360° Approach,” by Pedro F. Vieira, Lenissa P. Hilgert, and Ilton Majerowicz, Petrobras. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ The complete paper presents an integrated view of three key areas of knowledge that are typically addressed individually—cybersecurity, process safety, and human factors—from the perspective of cybersecurity. It discusses information technology (IT) and operations technology (OT) dimensions during the phases of a project: engineering design, procurement, construction and assembly, commissioning, and operation. It also proposes a strategy for implementing such an approach in the oil and gas industry. _ With the aim of forming a holistic safety and security vision, the authors propose a unified analysis integrating cybersecurity, process safety, and human factors, focusing on their interfaces and opportunities presented by risk analysis and the convergence of business procedures. This is referred to in the proposed approach as a high-level integration layer, or the “strategic (outer) circle.” The combination of two concentric circles—strategic (outer) and operational (inner)—forms what the authors term a 360° approach. The Strategic (Outer) Circle The outer circle illustrates the strategic-level interfaces between key processes of cybersecurity, process safety, and human factors from a cybersecurity perspective. Cybersecurity/Process Safety Interface. Integration of Cybersecurity Into Process Safety Management Risk Analyses. One of the most practical examples of integration of cyber/physical attack scenarios into classical risk analyses is the use of layers-of-protection analysis and awareness of degradation of safety integrity level (SIL) barriers. An SIL is used to determine the required performance level of safety-instrumented functions (SIFs) to achieve the required risk reduction. The SIL of an SIF produces a risk-reduction factor that helps calculate the final total risk of a given scenario. Another opportunity to make this integration visible from the beginning of the engineering design is during the hazard and operability (HAZOP) study. The HAZOP study uses guidewords, standardized terms used to stimulate thinking about possible deviations in the established process. The idea is to create new words related to cybersecurity issues in the industrial-automation substrate, such as “data uncertain” (the data may have been corrupted) or “data unavailable” (the last available data is old). Special Cybersecurity Zone for Production-Critical Equipment. It is advisable that the zone and conduit analysis within the ISA/IEC 62443 framework consider segregating assets into distinct cybersecurity zones based on their operational continuity significance within the facility. For instance, a gas-export compressor, typically lacking redundancy, can halt a plant’s production, requiring secondary shutdowns of other systems. Therefore, by establishing a production-critical systems zone within the cybersecurity analysis, the availability of critical equipment and general operational availability can be ensured, and potential secondary effects of shutdowns and restarts can be mitigated. Cyber/Physical Integrated Incident-Response Program. Typically, incident-response programs are disjointed between cybersecurity and process safety, resulting in delays in digital responses to issues that have physical consequences. The formal inclusion of cybersecurity as a technical discipline in any process-safety incident-response program is essential and should be achieved even if it is discarded in the beginning of the analysis of a particular incident.

Study Analyzes Selection of Subsea System Architectures for Offshore CCS

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 34987, “Selection of Subsea System Architectures for Offshore CCS,” by Ana Requejo Olivan, OneSubsea; Andrew Ripley, Subsea 7; and Ian Pringle, OneSubsea, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ Different subsea-control-system architecture scenarios that could be used to inject CO2 offshore from a carbon capture plant onshore were assessed. Each scenario represented a qualification step toward a minimalist, fit-for-purpose configuration, with the final system featuring simple and all-electric subsea architecture. The authors adopted a holistic approach to a hypothetical subsea carbon capture and storage (CCS) project, evaluating the effect of subsea-control-system equipment technical readiness, CCS regulatory requirements, umbilical sizing, and installation strategy. Introduction Experience indicates that one of the more-common types of offshore CCS developments comprises a coastal-based carbon capture and compression plant (generally located in a region with high industrial emitters) and an offshore reservoir selected for CO2 injection, typically a depleted hydrocarbon reservoir or an aquifer, which requires a long tieback to shore, often in excess of 100 km.

Evaluation of Geohazards Research in the World and Pacific Region: A Comparative Bibliometric Study

Geohazards are natural phenomena that endanger infrastructure, the environment, and human activity. Understanding and mitigating them is crucial for public safety, disaster preparedness, and sustainable land and resource management. This research objective is to analyze geohazard research trends globally and then compare them with countries around the Pacific Ring. Ninety-six geohazard publications were analyzed using bibliometric analysis and the VOSviewer application. The general trend of geohazard research increased slightly. It is critical in dealing with the expanding threats posed by geohazards, adapting to changing conditions, protecting vulnerable people, and leveraging technological improvements for more effective hazard management and disaster risk reduction. The Annual Offshore Technology Conference Proceedings and Engineering Geology are the most popular scholarly journals for authors to publish research on geohazard. The most popular topic area for geohazard papers is Earth and Planetary Sciences, followed by engineering, environmental science, and computer science. It is consistent with the growing use of technology in geohazard research. This study also includes an authorship profile. This research implies enhancing disaster risk reduction strategies and contributing to global efforts to address the challenges posed by geohazards

What You Don’t Know About Chevron’s New 20K Anchor Project

_ After overcoming the impacts of the COVID-19 pandemic and closing significant technology and regulatory gaps, Chevron’s $5.7 billion Anchor project in the US Gulf of Mexico (GOM) is nearly ready to start producing oil. When it finally does, it will mark the start of the “20K” era for the deepwater oil and gas industry. The term 20K refers to the project’s core technologies, designed to handle wellhead pressures of up to 20,000 psi—a first for the subsea market. The advancement opens the door to previously inaccessible reservoirs by stretching the boundary of deepwater technology beyond the technical limit of 15,000 psi established in the past decade. In particular, the drive to reach such extremes is a response to the demands posed by the Lower Tertiary Wilcox play which Chevron pioneered the development of in 2014 with its Jack/St. Malo project. Output from the high-pressure, low-permeability, and ultradeep formation is expected to rise from last year’s 270,000 B/D to around 750,000 B/D by 2028. This would represent a shift from 13% to nearly 40% of the US GOM’s total of roughly 2 million B/D, according to Enverus Intelligence Research. The success of just a handful of projects like Anchor is crucial for achieving these projections. Located approximately 140 miles offshore Louisiana in about 5,000 ft of water, Chevron holds a 62.8% share in the project, with TotalEnergies owning the remaining interest. The initial phase includes seven wells targeting reservoir depths between 30,000 and 34,000 ft. Chevron has drilled three so far. Anchor’s semisubmersible floating production unit (FPU) arrived in the GOM last year after its hull was built in South Korea and topsides integrated along the Texas coast. The FPU has nameplate capacity of 75,000 B/D but upon delivery, Chevron determined it could make small modifications to boost the facility’s peak throughput to 86,000 B/D—an almost 15% increase. At this year’s Offshore Technology Conference (OTC) in Houston, Chevron’s Anchor project team offered a behind-the-scenes look at their journey to the precipice of first oil. Drawing from several papers they presented, here are some of Anchor’s biggest challenges and achievements. A Project of Firsts The nature of the Anchor project is such that it involves a number of industry firsts and records. At the top of that list is Transocean’s Deepwater Titan drillship which Chevron inked a 5-year $830 million contract for while it was still under construction in 2018. The rig began operations in the GOM in June 2023 as the second eighth-generation drillship ever built but holds claim to being the first ever rated for 20K operations. Originally planned to be a 15K-rated vessel, the Deepwater Titan was upgraded on Chevron’s request to host two NOV-supplied 20,000-psi blowout preventers (BOPs). Combined with the lower marine riser package, the BOP stack weighs in at more than 1.1 million lbs. Chevron points out in OTC 35148 that the BOPs were not needed to drill the wells—for that, 15,000-psi BOPs would have sufficed—but they were required for well control during the completion phase when hydrocarbons are most likely to flow to surface.

Downhole Hydrogen-Generation System Stimulates Challenging Formations in Kuwait

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 34832, “Successful Trial of Innovative Downhole Hydrogen-Generator System To Stimulate Hard-to-Recover Formations: First in Onshore Kuwait,” by Mustafa Al-Hussaini, Hamad S. Al-Rashedi, and Nada Al-Saleh, SPE, Kuwait Oil Company, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ The objective of the pilot trial described in the complete paper was to provide an economic solution to develop tight and hard-to-recover formations within the operator’s fields. These assets represent a major challenge because of their low recovery factor (1–3%), the high cost of available conventional stimulation technologies, low revenue, and inability to sustain production rates. Introduction To establish an integrated stimulation solution for tight and heavy oil formations, the concept of using active single-atom hydrogen power to enhance near-wellbore permeability was evolved. This technology is based on downhole hydrogen generation from an in-situ exothermic multistage chemical reaction between two unique hydroreacting agents (HRAs). This reaction generates a huge amount of thermal energy, active hydrogen, and other hot active gases and acid vapors. The selection of HRA compounds, and their amount and concentration, is customized for each field. Development of Business Cases West Kuwait (WK) Business Case. The M formation in the WK region is a carbonate, multifractured tight reservoir that had been producing for years but had begun experiencing a low recovery factor. Some of its wells had low-productivity issues related to tight formation characteristics and low pressure. Production could not be sustained for long periods of time even after conventional acid stimulation. The reservoir featured a carbonate reservoir thickness of 300 ft, with 70% of oil in place at the top section. The reservoir is classified as tight (less than 0.1–10 md average permeability and 10–25% porosity), with 10 fractured multilayers. Only 1–3% recovery could be achieved despite many vertical, horizontal, and multilateral wells having been drilled in the M formation. Oil is considered nonviscous (28 cp, 21 °API). Current stimulation approaches included conventional acid stimulation, which elicited a poor response, and multistage fracturing, which encountered mixed results at best. North Kuwait (NK) Business Case. The tight T formation in this region featured poor reservoir connectivity. Minimal aquifer support led to a rapid decline in reservoir pressure. In general, low mobility of oil, poor API gravity, and low permeability were the main obstacles in draining oil from the T formation, in addition to reservoir heterogeneities such as facies distribution, fracture patterns, and pressure regimes. The formation consisted of tight limestone deposited on a carbonate ramp. The reservoir is divided into three main stratigraphic units (Upper, of approximately 110 ft; Middle, of approximately 60 ft; and Lower, of approximately 16 ft). The reservoir exhibits porosity of approximately 14% and permeability of approximately 14 md and is filled with relatively-low-API hydrocarbon (19–22 °API).

Geopolymer Implemented in Primary Casing Cementing

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32218, “First Global Implementation of Geopolymer in Primary Casing Cementing,” by Mark Meade, SPE, Yeukayi Nenjerama, SPE, and Chris Parton, SPE, SLB, et al. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference. _ Portland cements are integral components in the oilfield well-construction process; however, the confluence of various business drivers have created the need to find sustainable alternative materials. The complete paper presents the evaluation of geopolymer cementing for use in oil and gas wells, specifically the primary cementing of liner strings in the Permian Basin. Geopolymer cementing offers a unique opportunity for the oilfield industry to decrease CO2 emissions related to well construction and reduce dependence on the constrained supply of Portland cements. Introduction Manufacturing Portland cement emits approximately 1 ton of CO2 for every ton of cement produced. Additionally, the manufacturing of Portland cement is a complex process requiring specialized equipment. Thus, during spikes in demand of Portland cement, the supply of cement cannot be rapidly increased to meet demand. Geopolymers are slurries that set to become a hard, durable solid that can withstand stresses and strains and are resistant to corrosion. Moreover, geopolymers can be made from a broad range of aluminosilicate raw materials sourced from waste products from other industries, mined materials, and biowaste. The low manufacturing and processing requirements reduce the carbon footprint of geopolymers to a fraction of that of manufacturing Portland cement. Whereas Portland cement chemistry is driven by hydration of calcium aluminates and calcium silicates, geopolymer chemistry is based on the polymerization of aluminosilicates initiated by activators. The creation of geopolymers starts with dissolution of the aluminosilicate raw material into monomers by an increase in the pH of the fluid from the activator. Then, the activator provides a site for covalently bonded chains to form, and these chains undergo polycondensation to form the set 3D network of polymers. Implementation of this new material with such a different chemistry into the complex oilfield-construction process presents challenges that must be overcome. Challenges Existing geopolymer formulations typically are characterized as either two-step or one-step geopolymers. In two-step geopolymers, the activators are added into the mix fluid, whereas, in one-step geopolymers, the activators are dry blended with the aluminosilicate source. Implementation of two-step geopolymers would come with operational and logistical constraints impairing their scalability, along with increased service quality and health, safety, and environmental (HSE) risks. On the other hand, common existing one-step geopolymers are formulated with activator types that dissolve rapidly and disperse in the slurry. Therefore, development of novel chemistries for one-step geopolymers are required to introduce geopolymers into oilfield well construction. Such applications expose geopolymers to temperatures and pressures significantly above ambient for extended periods of time during slurry placement within the wellbore. To ensure quality assurance of job placement, hydraulic simulators should be reliable predictors of the top of the placement, and geopolymers set within the wellbore must be detectable using established sonic logging tools.

Uncertainty Study Aids Development-Plan Optimization in Deepwater Gulf of Mexico

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32622, “Development-Plan Optimization and Uncertainty Study in a Major Deepwater Field in the US Gulf of Mexico,” by Mohsen Rezaveisi, SPE, Jennifer L. Campbell, and Paula L. Wigley, Woodside Energy Group, et al. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference. _ This paper describes development-plan optimization and a probabilistic uncertainty study using Latin hypercube experimental design constrained to production performance in Lower Miocene (LM) reservoirs of the deepwater Gulf of Mexico Shenzi Field. The purpose of the development-plan optimization was to identify, rank, and characterize future development opportunities (i.e., infills and injectors) in the LM reservoirs to arrest field decline. The study uses history-matched dynamic simulation models. Introduction The Shenzi discovery is approximately 122 miles off the coast of Louisiana in a water column approximately 4,400 ft deep (Fig. 1). This part of the field is a partially filled three-way closure against a salt-cored anticline. The discovery includes four main sand units (A, B, C, and D) that exhibit various degrees of hydraulic connectivity based on pressure data and production history. The area of interest in the current study is the Eastern part of the field. Static Model Build The geomodel covering the area of interest was built from two seismically interpreted horizons and approximately 180 faults. The model is subdivided into 13 zones using well-based true stratigraphic thickness maps. The average cell height is 2–3.5 ft thick with heterolithics driving the lower end of the range. Sequential indicator simulation was used to populate facies using well-based net sand trend maps by zone. In zones with evidence of channelization, a second nested facies model was used to build channels into the model. Shenzi East reservoir properties are good because of the high-quality sand deposited in the field. Lower reservoirs (C and D) have slightly more depositional complexity because of the varying paleotopography and a lower average net-to-gross (NTG) of approximately 53%. Upper reservoirs (A and B) had a larger sediment supply and were more continuously deposited, which resulted in a larger average NTG of approximately 67%. Dynamic Model History Matching The Shenzi East reservoir has been on production since March 2009, providing abundant production data for history matching. Of seven producers, six are still active, and the reservoir also features three water injectors. Producers and injectors are identified with letters P and I, respectively, followed by well numbers. Well P7 was drilled after 6 months of production from other producers; formation pressure data showing reservoir depletion are available for history matching. The water injectors were drilled in 2012–2013, but only two have formation pressure testing data available. Well P1 was completed in all sands; Wells P2, P3, and P6 were completed in three sands (D, C, and B); and the rest of the producers were completed in two sands (D and C). Production is commingled in all producers, resulting in allocation uncertainties between sands. Water production has been observed in five wells, with the current water cut in the range of 35–65%. The two most updip wells, P1 and P7, are still producing at zero water cut.