Offshore Technology Conference Research Articles

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 The paper has not been peer reviewed.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

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

Study Reviews Multilateral Installation Improvements on the North West Shelf

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32910,“A Decade of Multilateral Technology Installation Improvements Down Under,” by Stefano Cappiello and Adam Pasicznyk, SPE, Halliburton. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference. _ Multilaterals wells on the North West Shelf of Australia have been installed for over a decade. An overview of the well architecture, technology evolution, reliability, and efficiency of these operations is presented in the complete paper. The study is focused on subsea multilateral campaigns, where multiple global and regional first installations took place in mature fields. Introduction Multilateral developments in Australia mainly have been completed off subsea installations, with fewer performed from jack-up rigs. These multilateral completions mostly have been installed with the junction located in the producing reservoir sands. Technology Advancement of Multilaterals (TAML) Level 5 completions have successfully been deployed. The authors classify related systems as follows, with the most attention paid in the synopsis to the final two classes: - Generation One (Field A) - Generation Two (Field B) - Generation Three (Field C) - Generation Four (Field A) General Multilateral Well Design Because of sand production within the reservoir, these applications typically require a TAML Level 5 completion system. These systems deliver hydraulic and mechanical isolation at the junction through the completion. The junction is isolated above and below by production packers and by swell packers in the lateral. The junctions typically are installed horizontally within the reservoir. The original general requirements to construct Level 5 multilateral junctions included the following: - Ability to construct a Level 5 Junction in the 9⅝-in. casing or liner - Ability to run a landing profile or coupling as part of the 9⅝-in. production casing or liner - Ability to run and orient a premilled window at depth - Drill-out 8½-in. openhole section into the mainbore and into the lateral - Junction installed within the reservoir at high angle - Window milling to be performed in one trip - Lateral completion to be installed in one trip - Compressive strength rating capable of running screen sections over 2 km As the operators began to adopt multilateral technology in Australia, the following requirements were incrementally added: - Ability to deliver a Level 5 multilateral system in an existing well - Ability to deliver a trilateral well - Improve efficiency and reduce installation time

High-Pressure Separation: New Technology in the Subsea Toolbox

_ Subsea production systems have come far in the more than 60 years since the first deployment in the US Gulf of Mexico, helping many countries unlock their offshore hydrocarbon riches in the years that followed. For Brazil, it was a combination of advances in subsea technologies and floating production, storage, and offloading vessel (FPSO) designs that supported the growth of its offshore oil and gas prowess. From those first forays into the Sergipe-Alagoas basin in the northeast during the 1970s, the country’s offshore oil and gas footprint has grown significantly, with today’s production from the pre-salt Campos and Santos basins—located farther from shore and in much deeper water—launching state-run oil company Petrobras to a top spot among the ranks of global producers. The ongoing development of its offshore fields will continue to boost the country’s oil and natural gas production in 2024. Since December 2022, five FPSOs have been brought online, with four installed in 2023 delivering record output. The fifth one—the FPSO Sepetiba—delivered a New Year’s Day surprise when it came online at Mero 2 oil field on 31 December 2023. HISEP, a new subsea technology currently being readied for pilot testing, could potentially ensure continued future production of the Mero field and others by capturing CO2-rich dense gases directly from the wellstream and reinjecting it into the reservoir. The technology also frees up much-needed space and reduces weight on the FPSO’s topside by moving the separation process to the seafloor. Challenges and Solutions Brazil’s challenging offshore pre-salt region—first explored by Petrobras in 2005—contains estimated reserves of 30 to 40 billion BOE and comes with an extensive list of development challenges. Its Santos Basin, for example, lies in ultradeep water with hydrocarbon reservoirs located at extreme depths ranging from 5500 to 7600 m below sea level and under salt layers more than 2000 m thick. But the challenges do not end there. Managing the basin’s high gas/oil ratio (GOR) and CO2 content leaves a significant operational footprint. In OTC 29762, authors from Petrobras noted that developing the pre-salt reservoirs requires “large production facilities with complex gas processing plants that limit the oil processing and storage capacities.” In the paper presented at the 2019 Offshore Technology Conference (OTC) Brasil, the authors said that the gas processing plants for some pre-salt fields with high production indexes, GOR, and CO2 content account for nearly 60% of the total FPSO topsides area. The Santos Basin is home to the Mero oil field, the country’s third-largest pre-salt field and the first under a production-sharing contract awarded to the Petrobras-led Libra Consortium. The field is considered one of the largest hydrocarbon discoveries in the past decade, covering about 320 km2 of the Libra block and with a net pay zone reaching 420 m filled with 29 °API oil and high productivity, according to Ana Luiza Neder, et al. (OTC 32784).

Q&A With Dennis Denney, JPT Technology Focus Creator

_ In 1997, JPT debuted a monthly feature that represented an unconventional approach in meeting SPE’s goal of disseminating technical information to its members. Soon titled “Technology Focus,” the feature brought together subject-matter experts (SMEs) in a range of important industry topics to review technical-paper abstracts gathered from the previous year of SPE meetings, as well as the Offshore Technology Conference. Its architect, engineer, and pilot was Technology Editor Dennis Denney, who would become a familiar presence to SPE members and staff alike over a 17-year career, although his industry roots extended to his college days. Dennis helped recruit SMEs for review service; sent them hundreds of abstracts and full papers (monthly, that is; the cumulative count of papers he handled is likely a six-digit figure); answered their questions and concerns with prompt, supportive guidance; and then, once papers had been selected, synopsized them for publication in the magazine with the longtime help of Assistant Technology Editor Karen Bybee. As this writer well knows, condensing a 10,000-word paper on, say, distributed quasi-Newton derivative-free optimization methods for field development optimization into a 1,500-word summary that captures the novelty and technical sophistication of its authors’ work can be a daunting task. Applying his own background as a petroleum engineer to methodically analyze and trim each chosen paper, Dennis did just that dozens of times a year, transforming these texts into svelte packages that included only one table or figure to deliver the highest possible quantity of quality to JPT readers. When Dennis retired in 2013, I initially split his eyebrow-raising workload with fellow Technology Editor Adam Wilson (now JPT’s Special Publications Editor). It was immediately clear from the way that reviewers spoke about Dennis, and his contributions to the magazine and SPE itself, that he was held in the same high regard outside of the organization as he was within it, a testament to the reputation he had earned while working with so many members and SMEs. It was entirely fitting that, for JPT’s 75th anniversary celebration, we caught up with Dennis to reflect on his achievements in the industry and with the groundbreaking Technology Focus feature he created. Dennis lives with his wife Linda in Rockwall, Texas—not too far from SPE headquarters in Dallas, but not too close, either!—enjoying his retirement and his family. (Note: For more on the development and history of the Technology Focus features, read the companion piece to this article, “Technology Focus Topics Reflect Industry Growth, Evolution Over 25+ Years.”) Why did you decide to go into the field of petroleum engineering? I worked several years as an engineering tech, testing gas wells, tracking well and reservoir pressures, and writing computer programs to analyze pressure data. The department manager encouraged me to finish my degree and become a petroleum engineer. So, after I received a scholarship from J. Harold Dunn (at age 28), my wife and I sold our house, packed our things into a U-Haul truck, and loaded two young kids into the car to move to Bryan/College Station to attend Texas A&M University.

Technology Focus Topics Reflect Industry Growth, Evolution Over 25+ Years

No matter your field of expertise or geographical area of operations, JPT’s Technology Focus feature addresses your career and research paths. During the more than 25 years of its appearance in the magazine, the feature has presented synopses of important papers in summarized form. A review of the Technology Focus topical calendar through the years reflects milestones in industry developments and innovations, and the magazine’s ability to adapt to meet the needs of its readers. Indeed, the inception of the feature was a response to such a challenge. Each year, thousands of high-quality technical papers are presented at SPE conferences and the Offshore Technology Conference (OTC). These papers are the embodiment of SPE’s mission to collect, disseminate, and exchange technical knowledge about the world of upstream E&P. In the late 1990s, JPT staff recognized a need to expand the intersection of SPE’s members with the crucial work outlined in the technical papers written by their colleagues. While SPE’s stable of peer-reviewed journals had always played a critical role in its mission, the rigorous review structure meant that these papers, published in full, might not see audiences for some time. Annual proceedings volumes collected the year’s research literature, but time constraints also limited the number of members who could explore these publications. The solution was the Technology Focus feature, in which conference papers dedicated to a broad spectrum of industry topics were chosen by subject-matter experts and condensed by SPE staff to convey key findings and illustrative case studies. The Tech Focus concept meant that SPE readers could find the best research and industry innovation at their fingertips each month. These papers were not peer reviewed, but the members of the JPT Editorial Review Board charged with their selection were recognized experts who reviewed hundreds of abstracts in order to choose only a few papers for inclusion. Since the feature’s launch, hundreds of SPE members from a wide range of major operators, service companies, technology specialists, academic institutions, and research facilities have served as reviewers. Tech Focus’ first decade-plus of publication, from 1997 through 2010, established and refined the pattern by which tech papers were selected, synopsized, and organized for presentation. Before 1997, JPT had run Technology Briefs that had the same idea, but these were irregular, applied only to tech papers with a length that would make publication in JPT impractical. For the first couple of years of the Tech Focus, however, each issue of JPT contained between two and three topical groupings of synopsized papers. The initial topics were broad, familiar ones (EOR, Drilling Technology, Fracturing, Offshore Development, Stimulation, and Reservoir Management, for example) as JPT Technology Editor Dennis Denney, who was responsible for the development of the feature, tested the waters and built a review board of industry volunteers to assist with the task of reviewing abstracts, reading full papers of interest, and selecting papers for synopsis.

AI-Based System Automates Textual Classification of Daily Drilling Reports

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32978, “Development and Implementation of an AI-Based System To Automate Textual Classification on Daily Drilling Reports,” by Stephan Perrout, Aliel F. Riente, and Guilherme S.F. Vanni, SPE, Petrobras, et al. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference. Reproduced by permission. _ Structured daily drilling reports (DDRs) are a rich source of information that allows better planning, more-accurate risk analysis, and improved key performance indicators and contracts. However, such information is originally stored in a free-text and unstructured format, which becomes difficult for efficient data mining. With the advance of artificial intelligence (AI) technologies, particularly AI language models, applying such techniques over unstructured data has become critical to digital transformation. The complete paper presents an approach for automatic DDR classification that incorporates new techniques of AI. Introduction This work addresses the complex task of automatic classification of DDRs according to a newly proposed ontology. The ontology follows a hierarchical model that classifies actions into three or four levels depending on the intervention, considering drilling, completion, and abandonment. Each event has an ontology built and reviewed by experts in oil and gas. Classifying DDR constitutes a demanding task, and effectively exploiting AI-based models represents a promising solution. This work bridges the gap by proposing a classifier based on transformers along with recurrent neural networks (RNNs) to classify reported events described in unstructured text related to drilling, completion, and abandonment interventions. A large number of DDRs was used for training and validation of the proposed classifier, yielding promising results for key processes in the company. Neural-Network Techniques Bidirectional Long Short-Term Memory. Early neural-network models are characterized by inputs of fixed length. This is a drawback when working with texts, however, because sentences vary in their number of words. To overcome such an issue and to process data sequentially, RNNs were proposed. The RNNs are characterized by a set of parameters inherent from the early models plus an internal memory (a hidden or internal state) responsible for storing the context of the sequence being processed. Long short-term memory (LSTM) is a variation of RNN proposed to mitigate two problems: Information can be easily lost when processing very long sequences, and the gradient can become quite low because of the high number of mathematical operations performed during the processing while remaining far from reaching the threshold. LSTM consists of a set of parameters called the input gate, forget gate, and output gate that control information flow through the network. This set of additional parameters helps to maintain only what is important for the internal state of the network besides controlling the output. BiLSTM is a variant of LSTM that comprises two LSTMs. One processes texts from left to right, and the second one processes texts from right to left. This feature allows “future” elements to be part of the model’s decision process for “past” elements. The final classification is the combination of the output of both LSTMs.

Approach Maximizes Marginal Field Value by Going Back to Basics

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32379, “Marginal Field Value Maximization by Going Back to Basics With Design-to-Value Enhancement,” by Yen P. Chan, Muhammad Y.S.M. Yasin, and Ahgheelan S. Thurai, Petronas, et al. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference. Reproduced by permission. _ Value is defined by a quantum of functions or returns received from resources invested. In extremely marginal oil and gas fields, returns hardly meet invested resources profitably. Stranded, widely scattered resources add to the complication. The complete paper shares an approach to notional well- and facility-development concept generation for such fields by shifting emphasis to designing for value to improve project viability rigorously. Problem Statement Based on Case Study Case study Field X, located offshore Asia, is one of many oil resources in the region with virgin reservoir pockets and layers that are marginal in volume yet can provide a considerable recoverable volume if developed collectively. However, being horizontally scattered and shallow, with a reservoir true vertical depth (TVD) of less than 2000 m, the field was designed initially with up to 12 wells to maximize reach, thus requiring a large wellhead platform (WHP) at the surface. Gas lift was required from the first day of production, leading to two pipelines at a minimum. Given the number of wells and surface facilities required, this led to a highly negative economic outcome. To quantify the extent of cost reductions and increase the recoverable targeted resources required to meet targeted economic indicators for a business case, the project team performed a series of sensitivity analyses. Despite efforts to phase out field development, minimize surface facilities, and simplify well design where possible, the project remained negative in net present value because reducing the number of wells and facilities will lead to a dramatically lower estimated ultimate recovery (EUR), which is the key driver in any oil and gas development. The project team thus was presented with an almost unworkable situation where scope and cost reduction to satisfy economic returns simply meant that installation of neither wells nor facilities was viable. The authors refer to the approach they describe in the complete paper as “going back to basics.” This approach, coupled with a design-to-value (D2V) approach, was effective in countering seemingly irreversible economic results. This approach is a systematic way to develop an optimal concept for maximum value realization because the agile approach questions every aspect of concept development to achieve minimum technical requirements while providing better clarity in cost/risk tradeoff through concept evaluation in a staircase manner. The process of executing D2V for marginal field development while managing technical risks is detailed in the following subsections for both well design and in facility-concept design.

Experimental Data-Analysis Methods Analyze Multiphase-Flow Data Sets

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32170, “Performance Mapping of Multiphase-Flow Model—Connecting the Dots From Experimental Data,” by Auzan A. Soedarmo, SPE, Eduardo Pereyra, SPE, and Cem Sarica, SPE, The University of Tulsa. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference. Reproduced by permission. _ In the complete paper, the authors present exploratory data analyses to evaluate comprehensively the performance of a steady-state multiphase-flow point model in predicting high-pressure, near-horizontal data from independent experiments. This effort provides wide-ranging insight that can reflect the current state of the art of multiphase-flow modeling and pinpoint areas where improvements are needed. Much of the complete paper is devoted to the literature relating to the authors’ work; these specific citations are not included in this synopsis. Introduction The emergence of “big data” has encouraged the use of data from various sources to enhance the decision-making process. The authors write that, unfortunately, multiphase-flow studies often are performed in theoretical silos, within which specific experiments were performed and upon which certain model improvements were proposed. Therefore, it is easy to lose sight of the larger context in terms of current understanding and modeling capability. This disconnected approach also has produced an ever-growing, potentially unmanageable list of closure relationships, which can be counterproductive for model development. Experimental Data-Analysis Methodology For their study, the authors collected near-horizontal (–5° to +5°) gas/liquid data from literature with a gas density of 5 kg/m3 or greater. Atmospheric data were excluded because gas and air at such conditions are typically very compressible, meaning that superficial gas velocity can vary considerably along the pipe. One also can argue that high-gas-density cases are more relevant to typical high-pressure field applications. The authors collected more than 2,000 data points for pressure drop, holdup, and flow patterns. This accumulated data set by no means can be categorized as “big data” in a traditional sense; however, the authors write that it is sufficient for demonstrating how exploratory data analysis may extract actionable insights from data sets from various independent sources. This data set is henceforth called the “HP data set.” No high-viscosity liquid (10 cP or higher) is included in the HP data set. When comparing experimental data collected under different conditions, it is helpful to reduce the problem’s dimensionality (down from 10 dimensions in two-phase gas/liquid flow, excluding the gravitational acceleration constant). A traditional approach would be to use dimensionless numbers such as Reynolds and Froude numbers. A single dimensionless number, however, can only account for limited parameters. For example, the Reynolds number only considers the inertia and viscous effects, while the Froude number only considers the inertia and gravity effects. Therefore, a mechanistic multiphase-flow model is used in this study that accounts for all dimensions of the multiphase-flow problems and reduces them into one dimension, namely the discrepancy between the predicted value and experimental data.

Retrofitted Autonomous Inflow Control Devices Optimize Completions Design

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31301, “Optimized Completions Design Using Retrofit Autonomous Inflow Control Devices,” by Ezinne A. Nnebocha, Schlumberger; Akinola Akinbola, NPDC; and Omagbemi G. Kayakor, First Hydrocarbon Nigeria, et al. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. _ Discovered in 1964, the Beta Field in the Niger Delta sedimentary basin consists of 25 stacked hydrocarbon-bearing reservoirs between 5,500 and 12,000 ft true vertical depth subsea (TVDSS). Oil production peaked at 8,900 STB/D shortly after field startup and has been on the decline. Two horizontal wells, Beta 7 and Beta 8, were planned in the field, but a production forecast of the planned wells showed potential early water breakthrough and high water cut. Autonomous inflow control devices (AICDs) were deployed successfully in the Beta Field for the purpose of minimizing water production and maximizing oil recovery. Introduction After history matching, the two new horizontal wells were simulated to target the sweet spots in the reservoir using constraints of oil saturation, porosity and permeability limits, and distance to the oil/water contact (OWC). The history-matched model was then used in forecasting the production profile for the new wells using a target liquid production rate of 2,000 STB/D. The production forecast without inflow control showed water breakthrough in the new wells within the first month of production, reaching to 45% within 3 months of production. Cyclonic AICD completions then were simulated for Beta-7 and Beta-8 horizontal wells, which showed improved oil production and delayed water production. AICD Retrofit Design Cyclonic AICDs were selected for application in the Beta Field to improve production performance. However, the short lead time required for the job execution and border closures caused by the COVID-19 pandemic created restrictions in mobilizing personnel and equipment from outside the country. It did not appear that the equipment could arrive in time for the job. The conventional nozzle-based passive ICD joints were available in country. Therefore, leveraging engineering skills and operational knowledge, a solution to retrofit AICD nozzles in existing ICD screen joints was conceived. The engineering team developed a design of machined components that could be quickly manufactured at the facility of the original equipment manufacturer (OEM) and shipped to the location. Failure-mode and effects-analysis assessment, and subsequent risk-management procedures, became useful to manage the process locally with the help of the remote OEM team. A step-by-step procedure on the retrofit was devised. Fig. 1 shows a flow chart used to guide the retrofitting process and the retrofitted AICD joints after modification. Upon completion of the screen retrofit, the joints were quality-checked and inspected to verify their preparedness for well completion.

Potential Revealed for Hydrogen Production From Offshore Wind in Uruguay

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31879, “Assessment of the Potential for Hydrogen Production From Bottom‑Fixed Offshore Wind in Uruguay,” by Juan Tomasini, SPE, Pablo Gristo, SPE, and Santiago Ferro, SPE, ANCAP, et al. The paper has not been peer reviewed. Copyright 2022 Offshore Technology Conference. Reproduced by permission. _ With almost the entire electricity matrix having been decarbonized, the next step in the Uruguayan energy transition includes the development of a hydrogen economy. In the complete paper, the authors present the results of the assessment of two regions suitable for bottom-fixed offshore wind energy (OWE) technologies. Results are encouraging and could lead to new possibilities in supporting the development of a hydrogen economy. Introduction For Uruguay, hydrogen is expected to play an important role in tackling the various challenges of the second phase of decarbonization; it holds the potential for use in the transport sector and in raw materials and chemical products. Having no oil production, Uruguay is a net oil importer; therefore, the extensive use of hydrogen in the domestic market may have a profound effect on the national economy and energy sovereignty. Preliminary findings show that Uruguay may have hydrogen production costs between $1.2 and $1.4/kg, placing the country among the world’s net exporters. Green Hydrogen Production From Offshore Renewable Energy Compared with onshore wind, OWE presents several advantages, including a greater capacity of each turbine (fewer turbines required for the same wind-farm capacity) and the availability of larger areas (allowing larger wind-farm capacity). Even if bottom-fixed is the predominant technology for OWE projects, floating technology is attracting increasing investment and public policy support because of its potential to access wind resources at water deeper than 40 m, where bottom-fixed may be less feasible technically, economically, or logistically. Green Hydrogen Production. Contrasting with blue or gray hydrogen (produced from fossil fuels with or without carbon capture and storage, respectively), green hydrogen provides the lowest near-zero-emissions option. Green hydrogen can be produced through the gasification of biomass or the electrolysis of water powered by renewable electricity. Alkaline electrolysis and proton-exchange-membrane (PEM) technologies are widely available commercially. Alkaline electrolysis is a fully mature technology that represents the lower-cost option, but its operational load limits are not as broad as those for PEM; therefore, its coupling with variable renewable sources should be carefully managed. On the other hand, PEM electrolysis is not yet a fully mature technology, with higher costs that are expected to be reduced in the coming years.

Qualification Approach Detailed for Offshore Hydrogen Pipeline Systems

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32158, “Offshore Hydrogen Pipeline System Qualification: Design and Materials/Welds Testing in Hydrogen Environment,” by Angelo Santicchia, Elvira Aloigi, and Salvatore Terracina, Saipem, et al. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference. Reproduced by permission. _ The qualification of a pipeline system for hydrogen transport, important in the transition to a decarbonized energy system even if strictly related to offshore pipelines, is a broad field that requires a systematic approach from basic material knowledge to complex physical models and fracture and fatigue assessments. The authors’ analysis of qualification requirements, including available test types and testing protocols, led to a matrix of potential tests, detailed in the complete paper, to be conducted in hydrogen and air environments for the steel base material, seam weld, and girth weld of offshore pipelines. Offshore Pipeline Materials Requirements vs. Hydrogen Transportation The authors’ work outlines many challenges, including the following: - Although hydrogen pipelines installed and operating onshore are common, at the time of writing, none exist in the offshore environment. - The blending percentage of hydrogen into natural gas in the future-transport scenario is still under discussion. - Small amounts of hydrogen can have a substantial effect on fatigue and fracture on high-strength materials. - The effect of hydrogen on pipe-material fatigue and fracture properties correlates directly to the specificity of the offshore environment, which will be very demanding in terms of longitudinal stress and fatigue. Another important aspect to consider is the effect of hydrogen on weldments both longitudinal and circumferential that are part of pipe-material fabrication and pipeline fabrication. A dedicated engineering team analyzed key standards and the available literature in terms of theoretical studies and experimental tests of materials in hydrogen environments. This activity indicated that, in addition to theoretical and design considerations, characterization of primary material and welding properties in hydrogen environments that will affect the failure modes of offshore pipeline design is a critical step. Testing Protocols and Equipment Slow Strain Rate Test (SSRT). Smooth cylindrical specimens were tested in inert gas (nitrogen), pure hydrogen, and a hydrogen/natural gas mixture for comparative purposes. This testing was aimed at evaluating the susceptibility of the pipeline materials (base material and weld metals) to hydrogen embrittlement when subjected to typical conditions envisaged for future hydrogen service. Tensile cylindrical specimens were tested at room temperature (24°C) in a high-pressure gaseous atmosphere. Tests were carried out in displacement control mode. In the initial part of the tensile test, in the plastic regime, after attainment of material yielding but before reaching the maximum tensile strength of the specimen, the strain distribution along the specimen was approximately uniform.

Approach Allows Safe, Environmentally Sound Well Abandonment in Urban Setting

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31394, “An Electrifying Integrated Solution Toward a Safe and Environmentally Sound Well Abandonment in an Urban Setting,” by Syah I. Mohamad and Lambertus C. Joppe, SPE, Baker Hughes. The paper has not been peer reviewed. Copyright 2022 Offshore Technology Conference. Reproduced by permission. _ In the Netherlands, many onshore wells are near urban areas or close to forests where emissions and noise reduction are important to consider. A depth of collaboration is required to ensure minimal impact upon the local community and the environment. The operator, together with Baker Hughes as the project management lead, formulated a low-impact solution with fully electrified equipment that mostly uses grid power. Scope of Work The project consists of plugging and abandoning (P&A) onshore oil and gas wells in 23 locations across the Netherlands. The main objective is to abandon all planned wells without any remaining liabilities; reduce cost burdens upon taxpayers; and minimize the impact on people, environments, and assets (PEA). Before the execution phase, the wells are categorized as simple or complex. The work may consist of a range of services such as slickline, electric line, cementing, pressure pumping, and downhole fishing and can include cutting, pulling, and milling. These services are provided as an integrated well-abandonment campaign with a single point of contact—the project manager. A typical well consists of a single 3½-in. or 4½-in. production tubing, 7-in. or 7⅝-in. production 9⅝-in. intermediate casing, and 13⅜-in. surface casings. Wells are approximately 3000 m deep, with some having well-integrity issues requiring annular remediation. Because these wells are more than 50 years old, the wellheads generally have a distinct set of challenges before well entry. A typical well P&A sequence would require installing a mechanical plug by slickline and setting a cement plug to provide the primary barrier. A second phase of well P&A may consist of cutting and retrieving tubings and casings. In some wells, cement remediation is required before retrieving the conductors to restore well integrity and establish a competent barrier envelope during P&A. The latest annular remediation methods were applied to this project, such as perforate, wash, and cement; and perforate, circulate, and cement and section milling. This subsurface work is not possible without the use of a hydraulic workover unit (HWU). The HWU capabilities for this project must meet the criteria of well P&A activities to be conducted while several optimizations are considered at the same time, such as footprint reduction; quick, efficient site-to-site and well-to-well moves; and minimal tripping time. The Case for Electrification A well P&A design often involves contingency measures to minimize any chance of failure within the primary design. For example, a secondary well-barrier envelope is prescribed in addition to the primary envelope in the unlikely event that the primary envelope is compromised at any point after execution.

Design-to-Cost Approach Increases Project Value of Troll Phase 3

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30954, “Troll Phase 3: The Next Step for a Groundbreaking Giant,” by Bjørn Laastad, Knut Ellevog, and Roger Oen Jensen, Equinor, et al. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. _ An important driver for maximizing value creation for the Troll Phase 3 gas project offshore Norway was to identify ways to reduce the pressure drop in the value chain from the reservoir to the onshore terminal. Using a design-to-cost approach in the concept-selection phase has affected design of the wells, subsea production system, pipeline, and a new inlet separator on the platform. The final design has enabled a significant increase of project value by accelerated gas deliveries, reduction of energy consumption, and lowered CO2 emissions. Troll Phase 3 Business Case and Development Concept The Troll Phase 3 business case is to develop the vast gas reserves in Troll West, thus recovering approximately 340 billion std m3 gas over a 40‑year period. Production from Troll West will be commingled with Troll East gas production at Troll A. The Troll West volumes will supply approximately 40% of the total Troll A delivery and enable a 5‑year continuation of the current high plateau production level of 36 billion std m3/yr and an extension of field lifetime by 15 years until 2062. A prerequisite for the Phase 3 project is that the annual summer/winter swing production will be from the Troll A wells. Consequently, Troll West production will be stable and not affected by seasonal variations in market demand. Following a comprehensive concept‑selection analysis made from the perspective of the field’s life cycle, it was decided in May 2017 to develop Troll Phase 3 as a subsea tieback to the Troll A platform. The subsea design facilitates possible future Troll West gas building blocks. The first section of the complete paper is devoted to a discussion of the flow‑assurance aspects of the development; this component is not included in this synopsis. Troll Phase 3 Well Design During the feasibility and concept‑selection phases, an important opportunity to maximize value creation was found to be improving individual well performance by enlarging the tubing size. The standard 7‑in. tubing would have been a considerable production restriction. By enabling a larger tubing size, the production from each well could be increased and the required number of wells could be reduced. The big-bore completion design was new to the operator but had been implemented successfully in other high‑rate gas fields in the industry. Using a design‑to‑value process, the tubing size for Troll Phase 3 was increased to 9⅝ in. Comparison of a big‑bore well to a standard 7‑in. well in 2030 gives a reduced pressure drop of more than 12 bars/well, with an increased production potential for the big‑bore well of greater than 1000 std m3/d. Consequently, the required number of wells could be reduced by approximately 40% (from 14 to eight). Factoring in the total cost of the final gas producers, six saved wells equals a total cost savings of $150 million ($300 million including the subsea facilities).

Underwater Drones Promote Sustainability of Offshore Natural Resources Exploitation

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32481, “How Underwater Drones Can Promote the Environmental Sustainability of Offshore Natural Resources Exploitation,” by Giovanni Massari, Cristina Marras, SPE, and Francesco Cavallini, Saipem. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference. Reproduced by permission. _ The goal of the complete paper is to offer an overview of underwater intervention/inspection drones (UIDs) and provide the necessary elements to take full advantage of this technology, supporting environmental sustainability of future offshore projects and activities. The investigation provided in the complete paper explores conventional applications for oil and gas and extends to future energy, mining, and CO2 capture and storage projects. UID Technology Subsea robotics is rapidly evolving from conventional remotely operated vehicles (ROVs) and autonomous underwater vehicles (AUVs) to services delivered by a new generation of vehicles with hybrid capabilities. UIDs present distinct advantages and technical challenges, including the following: - UIDs are battery-powered robotic solutions capable of interchanging data through water communication modems (acoustic or optical). - UIDs have hybrid AUV and ROV capabilities; as an ROV, they can be operated by a pilot using a remotely controlled console that also can be located onshore, while, as an AUV, they can execute complex tasks or missions automatically. - Underwater drones can efficiently and safely operate in total darkness, with poor or no communication links. For this reason, UIDs typically are provided with an advanced set of sensors (sonar, cameras, and lasers) capable of providing information about the vehicle’s orientation, altitude, depth, and the absolute or relative position. - UIDs can be deployed from a topside offshore facility, launched from shore, or deployed inside a subsea garage. Although these descriptions underline some of the technical challenges related to UIDs that require additional steps to achieve full maturity, the use of UIDs nevertheless clearly presents advantages that are almost independent from the application scenarios, including reduced operational risks, intervention time, CO2 emissions, and cost. Environmental Sustainability of Offshore Projects The notion of environmental sustainability embodies maintaining an ecological balance in the natural environment for the benefit of current and future generations; promoting responsible and respectful management of natural resources; avoiding their depletion and the degradation of the environment; and extending the concept to encompass social, human, and economic considerations. Robotic subsea technology offers pivotal assistance in accessing critical information so that all stakeholders can execute and operate offshore projects responsibly, satisfying essential projects’ commercial, environmental, and social criteria. The authors write that, while offshore companies and technology suppliers have already jointly explored the introduction of UIDs within conventional integrity-management campaigns of oil and gas fields, confirming the benefits of this choice for derisking and cost efficiency, a deep analysis on how UIDs can be used to boost environmental sustainability of complex offshore projects is still missing. Their work investigates relevant examples in this domain.

Study Explores Integration of Subsea Optical Distribution Systems

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32645, “All-Optical Subsea Sensing and Communications,” by Glenn Wilson, SPE, Halliburton, and Mauricio Uribe and Sigurd Moe, TechnipFMC, et al. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference. Reproduced by permission. _ Subsea control systems use electric or optical communication channels within subsea optical distribution systems for redundant, duplex telemetry between topside facilities and subsea control systems. Downhole fiber-optic sensing (DFOS) systems use the same subsea optical distribution systems for establishing transmission paths between the same topside facilities and downhole sensing fibers. At the time of writing, subsea fiber-optic control and sensing systems have been operated on independent subsea optical distribution systems. This redundancy introduces complexity and cost into the overall subsea optical distribution system required for subsea developments. In the complete paper, the authors describe the systems that combine fiber-optic communications for subsea control systems and DFOS systems into the same subsea optical distribution system. Need for Systems Integration While maturity of, and demand for, DFOS technology has grown for offshore projects with dry-tree installations, operators have expressed the need for solutions to address fiber-optic technology gaps for subsea development projects. To this end, the topside DFOS interrogation of subsea wells requires optical engineering solutions to compensate for the insertion losses and back-reflections accumulated through umbilicals, multiple wet- and dry-mate optical connectors, splices, optical feedthrough systems (OFS), and downhole-sensing-fiber and optical wet-mate connectors (Fig. 1). To obviate these problems for distributed acoustic sensing (DAS), the authors previously introduced a subsea fiber topology with two transmission fibers from the topside to a remote optical circulator deployed in the optical flying lead (OFL) at the subsea tree. This limits the sensing fiber portion of the total fiber length to the fiber located below the remote circulator and eliminates all back-reflections from the multiple subsea connectors in the subsea infrastructure above the remote circulator. The DAS pulse-repetition rate is constrained only by the fiber length below the remote circulator, thus enabling dry-tree equivalent pulse-repetition rates (i.e., acoustic bandwidth) regardless of the tieback distance. This yields significant signal-to-noise ratio improvement through stacking and selective amplification while further enabling sensing of high-frequency acoustic events occurring inside, or in the vicinity of, the wellbore. The initial application for subsea DAS was installing fiber from the tubing hanger to the production packer for vertical seismic profiling. The ability to maximize acoustic bandwidth irrespective of tieback distance, however, enables a wider range of interventionless reservoir diagnostic applications. This has increased operator demand for installing fiber across the reservoir section.

Subsea Injection Systems Enable Carbon Capture and Sequestration

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32460, “Subsea CO2 Injection Systems for CCS Applications: Themes, Challenges, and Opportunities,” by Julian P. Tucker and Kamaldip Randhawa, Baker Hughes. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference. Reproduced by permission. _ The complete paper presents a discussion of challenges and opportunities relating to subsea system design for CO2 injection in carbon capture and storage (CCS) applications. The scope of the text includes field development considerations, systems operation and control, intervention, monitoring, and barrier testing. A global review of existing and planned CCS developments is used to identify common system characteristics and core functional requirements. The paper reviews topics associated with CO2 transportation, injection, and storage across multiple disciplines to provide holistic guidance and commentary specifically for subsea system design relating to CO2 injection for CCS applications. Value Drivers For widespread adoption of CCS, dedicated geologic carbon storage (GCS) must be a commercially viable activity. Simply put, the cost of storage per tonne of CO2 must be less than the price that can be charged for storage as a service. Financial incentives also must be present to support the carbon price for development to take place. Transitional incentives to close the gap between costs and the low value of CO2 emissions reduction also may be required to support development. In all cases, however, the common denominator is that the cost of storage per tonne must be as low as possible. This is driven by the capital expenditure and operating costs of a project (as well as post-injection-period obligations), which include the cost of CO2 transportation and injection systems and associated equipment. Types of Transportation and Storage Networks For dedicated GCS, several types of offshore storage systems are available that are linked to different types of emitters, transportation networks, and value chains. Storage systems linked to natural gas processing facilities may be considered single-point emitters. The overall architecture of these systems, however, will depend on where the CO2-rich production stream is processed and separated before reinjection. The most common method of CO2 transportation to offshore locations is through a subsea pipeline, which enables a continuous flow of CO2 and a high system availability. It is worth mentioning that some developments also have considered transportation to offshore storage sites by ship, with injection through an intermediate floating storage vessel. Once installed, a pipeline provides continuous injection with high availability, whereas a vessel will be affected by transit time, weather conditions, downtime caused by maintenance, and high operating costs owing to fuel use. Furthermore, challenges with field expansion also may result.

Have Offshore Operators Cracked the Code on How To Successfully Run a Megaproject?

_ Offshore oil and gas companies have been told for years that when it comes to delivering on megaprojects, they’re not doing that great of a job. The experts have pilloried piecemeal approaches to contracting and scheduling, blaming them for cost inefficiencies and delays. Analysts have raised concerns that the various teams involved are too siloed, or not brought into the fold at the right time. And lamented on from many a conference podium are the rarely realized benefits of standardization. However, two recent case studies from different sides of the Atlantic suggest that large offshore producers have paid heed to these issues. At this year’s Offshore Technology Conference (OTC) in Houston, Equinor and Murphy Oil Corp. shared details about their latest multibillion‑dollar projects. In separate conference papers the companies said they avoided overengineering new production systems by trying to borrow the blueprints from existing facilities. They also claim to have fully embraced the idea of integrated teamwork and proactive project execution. For Equinor, the result is known as the Johan Sverdrup field which stands in roughly 375 ft of water on the Norwegian continental shelf. Output from the project’s phase one and two facilities topped out in May at 755,000 B/D with one of the industry’s lowest breakeven prices of less than $20/bbl. Meanwhile, Murphy is celebrating the new King’s Quay floating production system (FPS) which delivered first oil less than 3 years after sanctioning. The three‑reservoir deepwater Gulf of Mexico project also bested expectations as it ramped up to 100,000 B/D within its first year of operation. Highlights from these case studies and the strategies that led to successful outcomes are below. Johan Sverdrup: A European Giant In May, Equinor’s Johan Sverdrup field soared past its originally planned nameplate capacity of 720,000 B/D as it hit a plateau rate of 755,000 B/D. The peak figure represents about 7% of European crude demand. The milestone for the majority‑state‑owned oil company came a little over 6 months after it completed a $4.4‑billion phase two expansion project. In OTC 32552, authors from Equinor outline the key strategic decisions that enabled the company to deliver the 29‑well phase two project on time and under budget despite pandemic‑related barriers, equipment failures, and employee strikes. Keep Contractors Close. Equinor emphasized the role of its newest iteration of integrated teamwork—or what it calls the “one team” approach. Vibeke Lossius, a coauthor and project manager for Equinor, described the idea as the glue that held together the operator with its global network of contractors and suppliers. “Our philosophy was that if one fails, we all fail,” she said. “So, it was important to us that the contractors succeeded.” The one team approach grew out of phase one but only involved Equinor’s team leaders. Then as the operator began phase two, it pushed harder to align its goals more closely with those of its contracting partners, which meant bringing them into the tent.

Miniaturized Annular Sensor Aids in Well Integrity, Production Monitoring

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31160, “Intelligent Pipe: A New Monitoring Solution for Your Wells,” by Francois-Xavier Bulard, Vallourec; Emmanuel Tavernier, OpenField Technology; and Antoine Deroubaix, Vallourec, at al. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. _ The integration of a pressure and temperature sensor element in tubulars is possible as the result of microelectromechanical systems (MEMS) technology. Low-power consumption combined with an adapted transmission technology allows use of this technology inside an oil and gas well. Operators can use embedded sensors to access previously inaccessible well areas in real time. The qualification of this technology is completed to ensure the integrity of the system and its long-term viability. The complete paper presents the development, qualification, and applications of an intelligent tube solution using the described technology. Technology Description The development of this solution was the result of a partnership between OpenField Technology and Vallourec. While one section of the complete paper is dedicated to qualification tests performed during the development of the intelligent-pipe solution, this synopsis concentrates on the design of the solution and its potential deployment. The concept involves positioning a microsensor on the outside of a mandrel that can measure nearby annulus pressure, temperature fluids, or formation behavior. This system is composed of a pressure and temperature sensor connected to a battery module and a transmitting coil. This system (sensor, battery, and coil) is doubled to meet customer requirements for redundancy. Each mandrel contains two distinct monitoring modules. Positioned in each string of a well, this monitoring module tracks pressure and temperature changes at different depths throughout the well life cycle. This module is simple to install and is run with the casing string like any other oil and gas tubular-goods pipe. This module is set up for the entire life of the well, with two options for data retrieval: a temporary option with the use of a logging tool and a permanent option with the use of a specific tubing-transmission mandrel (Fig. 1). This tubing-transmission mandrel is connected to the surface by an electrical cable and designed to permanently supply power to the other casing module located at the same depth. The tubing-transmission mandrel furthermore ensures data retrieval from each sensor. The operating principle of the solution is based on the fact that each casing module is connected by an electromagnetic field to a logging tool or a tubing-transmission mandrel. This electromagnetic link is ensured by using a nonmagnetic (high-alloy) material for the casing module. This nonmagnetic material allows the electromagnetic field to pass from the tubing string up to the larger casing where monitoring is performed. It defines the horizontal transmission of the solution (as opposed to the vertical transmission) that is ensured by the use of a permanent downhole electrical cable connected to the surface. This cable brings power from the surface to the tubing-transmission mandrel in the case of deployment of the permanent option for data retrieval and allows data retrieval from the monitoring devices connected to this tubing mandrel. Horizontal transmission is only ensured if the different tubing and casing mandrels meet certain horizontal alignment tolerances.

Offshore Decommissioning: Planning for the End at the Beginning

_ It is the $100 billion elephant in the room. It is the last item on a never-ending list of things to do that gets delayed until it can no longer be deferred. It is the decommissioning of mature offshore oil and gas fields, and—like death and taxes—it is an unavoidable certainty. Decommissioning, the safe and environmentally sound removal, disposal, and repurposing of obsolete infrastructure, marks the end of a field’s operational life cycle. A critical part of the process is the plugging and abandonment (P&A) of wells to ensure that hydrocarbons, other fluids, and gases do not escape the wellbore. As the world grapples with the need to transition towards cleaner energy resources for the future, the decommissioning of mature or inactive offshore oil and gas wells has become a growing concern. These wells, which have been in some state of operation for decades, now present a range of environmental, economic, and social issues that must be addressed. While many factors delay decommissioning activities, advance planning is one way to manage the risk and expenditures associated with it, speakers said during the “Starting with the End in Sight: Planning for Decommissioning to Ensure Long Term Success” opening keynote at the 2023 Offshore Technology Conference (OTC) in May. Accumulating Liabilities In areas like the Gulf of Mexico (GOM), for example, oil and gas production has been the cornerstone of the region’s economy for more than half a century. According to the US Bureau of Safety and Environmental Enforcement there are about 1,885 active production platforms on the GOM Outer Continental Shelf, with over 60% of these facilities more than 25 years old. Over the past decade, the offshore energy industry has averaged 200 platform removals per year. “IHS Markit forecasted that the global offshore decommissioning spend will reach almost $100 billion in 2021 through 2030,” said Ryan Lamothe, director of decommissioning at Hess, adding that it is “an increase of over 200% from the prior 10-year period.” He noted that the 2021 survey found Europe with the largest market, with 33% of spending, followed by Asia Pacific and North America with 23% and 17%, respectively. Decommissioning in the GOM is expected to grow at a compound annual growth rate of about 6.89% from 2020 through 2030. “There’s not been an update on the numbers since 2021,” Lamothe said. “However, based on the size and magnitude recent bankruptcies in the Gulf of Mexico and the number of assets being returned to predecessors in title, I sense that the North American market is greatly understated.” As bankruptcy causes more asset liabilities to boomerang back to previous owners, so do the risks and costs associated with decommissioning. These boomerang assets are the result of what Lamothe said “is the lack of a full understanding of the chain of title obligations for the federal leaseholders, the discounting effect of net present value.” He added that “the cost is always cheaper in the future and sometimes coupled with the ‘not in our careers’ mentality. Assets that are no longer the shiny penny in many companies’ portfolios and not necessarily getting the attention they deserve.”