This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30172, “A Streamlined Multidisciplinary Work Flow for Pipeline-Slugging Assessment,” by Jeff Zhang, Saurav Jha, and Tim Matuszyk, Wood, prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2–6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Free spans exist in subsea multiphase pipelines laid over undulating seabed profiles or across continental scarps for offshore field developments. Slug-flow-induced fatigue damage on the free spans can have a significant effect on project economics. Slug-flow assessments can prove time-consuming. The complete paper describes an integrated iterative approach between the flow-assurance and pipeline-engineering disciplines to streamline the work flow based on the value or cost associated with changes in input parameters that affect pipeline fatigue-assessment outcomes. Slug-Flow Assessment Work Flow The complete paper further details key goals for each step. Step 1: Plan Project Slug-Flow Design Requirements. Key to this step is to create a close interface between flow-assurance and pipeline engineers to discuss and align overall timing, critical decisions, and hold points that are required as part of the slug-flow assessment and any specific project-design considerations. Step 2: Execute Slug-Flow-Prediction Assessment. Slug-flow prediction typically is conducted by engineers using industry-standard multiphase dynamic-flow simulators. The step requires significant time and effort because of long simulation times and large data post-processing requirements. Step 3: Generate Slug-Flow Interface Data. The two methods typically used for converting flow-assurance slug-flow results into formats that can be used readily by pipeline engineers are the time-history approach and the time-dependent-matrix approach. Step 4: Execute Slug-Flow Response Assessment. This assessment typically is conducted by pipeline engineers to assess the effects of predicted slug-flow interface data on proposed pipeline con-figuration designs. Industry-standard finite-element-analysis (FEA) tools are used for this step. Step 5: Finalize Design Through Iteration and Optimization. Where the slug-flow response assessment results show excessive fatigue damage that affects feasibility of the proposed design, iteration and optimization are performed. Step 6: Consider Operational Monitoring Requirements. Operational fatigue monitoring can be considered if operational restrictions are required or if some level of risk or concern remains with the final design.

- 4 August—Halliburton announced the successful deployment of an advanced, e-fleet spread on a pad of horizontal wells for Chesapeake comprising more than 140 stages in the Marcellus shale. This followed an announcement in January that Halliburton had successfully completed 340 stages for Cimarex in the Permian across multiple horizontal wells, using electric grid power. - 29 July—US Well Services (USWS) announced it would deploy an e-fleet to support Pioneer Natural Resources’ Midland Basin completion operations for the fourth quarter of this year using locally supplied natural gas, including field gas sourced directly from the wellhead. - 27 July—Seneca Resources and USWS announced their collaboration on an upcoming six-well field trial in the Appalachian Basin for Seneca’s first completions using all-electric fracturing technology. - March—NexTier Oilfield Solutions and NOV announced completion of the first phase of field testing of NOV’s electric fracturing pump, comprising 172 stages at pumping rates of up to 22 bpm and an average pumping time of more than 18 hours per day. Were these the latest barrage in a swift takeover of the North American hydraulic fracturing market by e-fleets? No, but they are evidence of the growing interest among operators, fracturing companies, and service and technology companies in developing and implementing solutions to sustainable shale development that satisfy the “three e’s”—economics, environment, and efficiency. ESG-Driven Change The rise of e-fleets is being driven by the US shale sector’s growing concerns over greenhouse-gas (GHG) emissions, noise levels, fuel and maintenance costs, and carbon footprints, all of which impact environmental, social, and corporate governance (ESG) compliance scores and thus, funding for the major operators who now dominate North American shale development. E-fleets are increasingly seen as an environmentally and socially responsible fracturing option that minimizes sound, fire risk, fueling costs, and GHG emissions, offers clean and simple rigup, and significantly increases power density vs. conventional diesel-powered fleets while maintaining the redundancy that efficient frac operations require. Traditional hydraulic fracturing operations use pumps powered by Tier 2 or lower-emitting Tier 4 diesel engines. The diesel is trucked to the wellsite, then distributed to each pump. While fuel use depends on the specific pressure and flow requirements of each job, it has not been uncommon for high-pressure, high-flow-rate jobs in Texas to consume 4,000 gallons of fuel per stage, requiring 12 or more truckloads per day. Pump units purchased between 2007 and 2015 generally use higher-emitting Tier 2 diesel engine technology. Cleaner Tier 4 engines became available in 2011 but only became the norm after the US Environmental Protection Agency (EPA) regulations made lower-emission Tier 4 standards mandatory for frac pumps in 2018. In July 2014, the first fully electric, fully mobile hydraulic fracturing fleet completely fueled by natural gas was deployed in West Virginia for the Marcellus Shale. “Electric-powered hydraulic fracturing is an important step towards conducting well stimulation in a more environmentally responsible manner,” wrote J.M. Oehring of USWS in paper SPE 177308 in 2015.

2022 SPE President Kamel Ben-Naceur Kamel Ben-Naceur is CEO of Nomadia Energy Consulting, where he advises on sustainable energy policies and global and regional energy economics and outlooks. He has worked as the chief economist for a major oil and gas company and for an oilfield services company. Ben-Naceur has also worked as a director of the International Energy Agency and as the industry, energy, and mines minister for the Tunisian government. He has chaired several SPE global committees, including Business Management and Leadership, the International Forum Series, and CO 2 Capture, Utilization, and Storage. He has also taught several SPE courses on global energy and strategic thinking and planning. He was technical director for the Management and Information discipline on the SPE International Board of Directors from 2008 to 2011. Ben-Naceur was also an SPE Distinguished Lecturer during the 2009–2010 season and received an SPE Distinguished Member Award and SPE Distinguished Service Award in 2014, the AIME Charles F. Rand Memorial Gold Award in 2019, and the 2020 Sustainability and Stewardship in the Oil and Gas Industry Award. He has coauthored more than 150 publications and 17 books. Ben-Naceur holds the Agrégation de Mathématiques degree from the École normale supérieure and a master’s degree in engineering from École Polytechnique in Paris. What key issues will you emphasize as 2022 SPE President? Our industry, along with many other economical sectors, has experienced a major impact from the pandemic. The magnitude of the drop in oil demand in 2020, both in absolute and relative terms, is unprecedented. It led also to a major reduction in oilfield investment activity around the world, in the order of 30% compared to pre-COVID-19 levels. The fast-track development of vaccines and their availability, even though progress is still required to ensure that they are distributed fairly around the world, is raising hope that the worst may be behind us. SPE members have also been impacted in their ability to meet at technical conferences and exhibitions and participate in workshops or forums. As 2022 SPE President, the theme I wish to develop is the “sustainable recovery” for our industry and for SPE. The industry has experienced in 2020–2021 a major loss of valuable employees ranging from young professionals to senior members. This has followed a major downcycle in 2014–2015. After a 30% drop in Capex in 2020 compared to 2019, 2021 should see a modest recovery in activity (6–8% increase). The next year should welcome a 10–12% activity surge, providing an increase in employment opportunities for our members in transition, as well as for our student members. Barring new negative developments in the pandemic, the recovery in activity should strengthen to reach pre-COVID levels by 2025, albeit 15–20% below the level that was expected before. The recovery of demand and activity should also be linked to a more sustainable trajectory of energy demand and supply. Sustainability will be my second area of focus, with SPE having already engaged significantly. I had the opportunity to participate in the startup of the SPE GAIA Sustainability Program, which is now developing into many different directions, thanks to the efforts of SPE volunteers. 2019 SPE President Sami Al-Nuaim had put sustainability at the heart of his presidency, and I am pleased to see several of his initiatives materialize. The third area of focus will be a gradual restart of physical meetings, where we will transition with the increase of hybrid (in-person/virtual) events, which is eagerly anticipated by our members. The fourth area of focus is related to the development of the new SPE Strategic Plan. Last but not least, is the proposed merger between SPE and the American Association of Petroleum Geologists (AAPG).

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31284, “Greater Tortue Ahmeyim Project for BP In Mauritania and Senegal: Breakwater Design and Local Content Optimizations,” by Alexis Replumaz, Yann Julien, and Damien Bellengier, Eiffage Génie Civil Marine, prepared for the 2021 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. During summer 2017, the authors’ company was invited by BP to bid for the construction of a concrete caisson breakwater protecting an offshore liquefied natural gas (LNG) floating terminal at a water depth of 33 m on the Mauritanian/Senegalese maritime border. As a result of subsequent front-end engineering design (FEED) studies, including 3D model testing, the company was able to reduce the amount of concrete required by 40% compared with the initial design, leading to financial and environmental benefits. Introduction The BP Tortue development comprises a subsea production system tied back to a pretreatment floating, production, storage, and offloading (FPSO) unit, which transfers gas to a near-shore hub for LNG production and export. Phase 1 will provide sales gas production and domestic supply and will generate approximately 2.5 mtpa of LNG to Mauritania and Senegal. The Phase 1 FPSO, in 100–130 m of water, will process inlet gas from the subsea wells located across several drill centers by separating condensate from the gas stream and exporting conditioned gas to a hub, where LNG processing and export will occur. The hub, 10 km from shore, comprises a breakwater to protect marine operations, including LNG processing and carrier loading. A single floating LNG vessel will condition the gas for LNG export. Hub construction began early in 2019 and should be completed in 2021 for a first-gas target in 2022. The breakwater design was conceived during the bidding stage of the project at the end of 2017 by proposing an alternative design for the breakwater adapted to project-specific conditions and regional facilities. The design has been improved continuously and optimized during the FEED stage based on a collaborative approach between the client and the contractor. Client Preliminary Design Optimizations During pre-FEED and bidding stages, the client performed an intensive geotechnical campaign based on several shallow and deep boreholes and a large-area geophysical survey. In water depths greater than 18 m along the maritime boundary between Mauritania and Senegal, a significant layer of soft soil exists, except around the outcrop located on the west side (10–11 km offshore in approximately 33 m of water). Although rock quantities could be slightly higher in the western location, the reduction of the dredging quantities and the reduction of the effect on the nearby coastal community of Saint Louis (lighting, noise, and vessel traffic) led to selection of this location for the hub terminal. The initial breakwater type was a rubble-mound structure. However, a composite breakwater (caisson on berm foundation) allowed for optimization of dredging and rock quantities. The change in breakwater type allowed a rock-quantity drop from 5.8 million to 1.1 million m 3 .

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199003, “Subsea Systems Innovations and the Use of State-of-the-Art Subsea Technologies Help the Flow Assurance of Heavy-Oil Production in Ultradeep Water,” by Carlos Alberto Pedroso, SPE, Geraldo Rosa, SPE, and Priscilla Borges, Enauta Energia, et al., prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, Bogota, Colombia, 17–19 March. The paper has not been peer reviewed. Flow assurance in ultradeep water is a major issue for production. The Atlanta field, which produces heavy oil in ultradeep water, is a project combining several challenges: hydrates formation, emulsion tendency, scale formation, foaming, and high viscosities. The complete paper discusses innovations and technologies applied to make Atlanta a successful case of ultradeepwater heavy-oil production. Introduction Discovered in 2001, the Atlanta field is in the presalt exclusion area in the north of the Santos Basin, 185 km southeast of Rio de Janeiro, at a water depth of 1550 m. The postsalt reservoir is contained in the Eocene interval and is characterized by high net-to-gross sands (82–94%) with a high average porosity of 36% and high permeabilities in the range of 4–6 Darcies. These excellent rock properties, however, are offset by the poor quality of the Atlanta crude, which is heavy (14 °API), viscous (228 cp at reservoir conditions), and highly acidic. The development of the field took place in two phases, an early production system (EPS) and a definitive production system (DPS). First oil occurred in May 2018. The EPS is expected to last from 4 to 5 years, producing from three horizontal wells to a floating production, storage, and offloading vessel (FPSO) with a processing capacity of 30,000 BOPD. The DPS will consist of 12 horizontal producers tied to a larger-capacity FPSO.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 21441, “First-Time Worldwide Application of Glass-Reinforced Epoxy-Lined Tubing for Prevention of Asphaltene Deposition in Tubing in Oil Wells: A Case Study From Kuwait,” by Reji E. Chinnappan, SPE, Milan Telang, SPE, and Riyad Quttainah, SPE, Kuwait Oil Company, et al., prepared for presentation at the virtual 2021 International Petroleum Technology Conference, 23 March–1 April. The paper has not been peer reviewed. Copyright 2021 International Petroleum Technology Conference. Reproduced by permission. Asphaltene deposition in production tubing represents a major flow-assurance challenge. Common strategies to mitigate asphaltene deposition downhole include mechanical or solvent cleanouts and chemical inhibition. These are associated with production deferment, high job costs, safety and environmental risks, and operational issues. An operator has addressed this challenge using production tubing lined with glass-fiber-reinforced epoxy (GRE). This technology was implemented in two trial wells. The paper describes the different mitigation strategies employed by the operator and presents the findings of successful trials. Background Jurassic wells of a Kuwait Oil Company asset are producing light crude from a tight matrix-type reservoir located at a depth of 13,000–15,000 ft. Reservoir pressure has depleted from approximately 9,500–10,000 psi to approximately 6,000 psi because of sustained production in the absence of any significant pressure support. Oil production rates per well have diminished to the 500- to 1,000-BOPD range. The oil features high asphaltene onset pressures (4,000–5,000 psi). When considering time-lapse plots of caliper logs from a well where asphaltene deposition used to occur, the plot indicates that significant asphaltene deposition in the well took place below 4,500 ft and progressively increased over time. In approximately 5 months, the average internal diameter of the tubing reduced from 2.75 in. to less than 2 in., thereby constricting the flow significantly and requiring cleaning of the tubing. In extreme cases, the tubing string could be fully plugged. Many field trials with different tools and chemicals using batch and continuous treatment have been conducted in past years to solve this problem but without satisfactory results. Application of GRE-Lined Tubing for Asphaltene Control The operator decided to apply a novel strategy of using tubing internally lined with GRE based on its established ability to retard, and even eliminate, scale nucleation and deposition. The technology uses a thin-walled, solid-filament-wound GRE/fiberglass tube run inside carbon steel production tubing. Cement is pumped into the annulus between the steel tubing and the GRE liner. The ability to prevent asphaltene from sticking to the inner wall of the tubing is attributed to the smoother internal surface. It is also corroborated by a higher Hazen Williams coefficient value of 150 for GRE as compared with 110 for carbon steel pipe, which provides for lesser frictional pressure loss during flow. The GRE liners used by the operator have a surface roughness of 0.00011 in., which, unlike bare steel, is retained over the life of the GRE. The GRE-lined tubing proved to withstand temperatures of up to 280°F and hydrogen sulfide concentrations of up to 50%. This is comfortably more than the process conditions for the trial wells in consideration.

This issue marks the debut of the Hydraulic Fracturing Operations feature in JPT. While hydraulic fracturing has long been a feature topic, this year, we are branching this major area of interest into both this feature and a Hydraulic Fracturing Modeling feature, which will appear in the November issue of the magazine. For this issue, reviewer Nabila Lazreq of ADNOC has selected three papers that reflect industry efforts to achieve new goals in production and sustainability. Paper 201450 investigates the potential of natural gas (NG) foam fracturing fluid to reduce the major water requirements seen in stimulation. The authors write that such requirements can be reduced up to 80% in some cases by the use of NG foams. Although modeling is used to reach their conclusions, the authors point out that NG foam fracturing fluids have great promise in operational scenarios in areas such as the Duvernay Shale. Paper 203226 reviews the challenges and conclusions reached by an operator implementing multistage fracturing for the first time in a horizontal well in a UAE tight carbonate reservoir. A cross-disciplinary approach proved effective when conventional stimulation methods were not successful in this challenging formation. Finally, paper 201611 returns to the topic of NG foams, investigating their utility as an alternative to fracturing fluids composed of nitrogen and carbon-dioxide foams. The pilot-scale study leads the authors to conclude that NG foams are effective fracturing fluids that exhibit stable viscosity at elevated pressure and temperature conditions. We hope that you enjoy the inaugural Hydraulic Fracturing Operations feature. Feel free to access the complete papers, and others that reflect recent achievements of SPE conference authors, in the OnePetro online library. Recommended additional reading at OnePetro: www.onepetro.org. SPE 204190 Optimization of Coal-Seam Connectivity by Multiseam Pinpoint Fracturing Operations in the Walloons Coal Measures, Surat Basin by Vibhas J. Pandey, ConocoPhillips, et al. SPE 204140 An Eagle Ford Case Study: Monitoring Fracturing Propagation Through Sealed Wellbore Pressure Monitoring by Kourtney Brinkley, Devon Energy, et al. SPE 202760 Tight Oil From Shale Rock in UAE: A Success Story of Unconventional Fracturing by Nabila Lazreq, ADNOC, et al.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30397, “Deepwater Flowlines and Risers Decommissioning,” by Azam Syah Jaafar, Ahmad Taqiyuddin Obaidellah, and Khairul Anuar Karim, Petronas, prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2–6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. The complete paper reviews an operator’s deepwater field project offshore Mauritania, for which several techniques were considered with respect to decommissioning a subsea pipeline system at water depths of 700 to 960 m. Options included preservation for potential future use, leaving in situ, and full recovery. The paper covers only the operator’s deepwater subsea flowline and riser decommissioning experiences and reviews activities from planning and concept to operational activities such as pigging, flushing, cleaning, disconnection, and retrieval. Case Study The operator’s deepwater field is 80 km from the Mauritanian coastline. It has been in production since 2006 but has become uneconomical. The operator decided to cease production and subsequently conducted a field abandonment and decommissioning (A&D) study. The field was developed using subsea wells, manifolds, umbilicals, flexible flowlines, and flexible risers tied back to a permanently moored floating production, storage, and offloading (FPSO) vessel at a depth of approximately 800 m. The FPSO was moored by an external turret connected to three clusters of mooring lines attached to piles in the seabed. All subsea wells were connected to the FPSO by five flexible pipeline systems (including dynamic flexible risers) and one umbilical system. All flexible pipeline systems were meant for the transportation of production fluids, water injection, gas injection, and gas-lift services. Because the FPSO is a turret-moored type, in which the turret is externally positioned at the FPSO’s bow, all flexible risers were designed to decouple the load and motion at hangoff from touch-down point with a lazy-wave configuration. The lazy-wave configuration was obtained by clamping sets of buoyancy modules on the risers. The execution of abandonment and decommissioning work has been divided into two main scopes: restoration of well integrity by installation of deep and shallow set plugs and FPSO disconnection and demobilization, which covers subsea facilities, risers, umbilical and flowline flushing and cleaning, topside process plant flushing and cleaning, pipeline systems and mooring-lines disconnection and retrieval, and FPSO sailaway. A plan for disposal of all resulting waste also was incorporated. Guidelines, Rules, and Regulations No universal statutory requirement, standard, or recommended practice existed to fully address pipeline decommissioning. Nevertheless, countries with more-established offshore industries (e.g., Norway, United Kingdom, US) have developed local legislation and practices that have been implemented in these respective jurisdictions.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 30794, “Digitalization Deployed: Lessons Learned From Early Adopters,” by John Nixon, Siemens, prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. With full-scale digital transformation of oil and gas an inevitability, the industry can benefit by examining the strategies of industries such as automotive, manufacturing, marine, and aerospace that have been early adopters. This paper discusses how digital technologies are being applied in other verticals and how they can be leveraged to optimize life-cycle performance, drive down costs, and decouple market volatility from profitability for offshore oil and gas facilities. Barriers to Digital Adoption Despite the recent dramatic growth in use of digital tools to harness the power of data, the industry as a whole has remained conservative in its pace of digital adoption. Most organizations continue to leverage technology in disaggregated fashion. This has resulted in an operating environment in which companies can capture incremental inefficiencies and cost savings on a local level but have been largely unable to cause any discernible effect on operating or business models. Although the recent market downturn constrained capital budgets significantly, an ingrained risk-averse culture is also to blame. Other often-cited reasons for the industry’s reluctance to digitally transform include cost of downtime, cyber-security and data privacy, and limited human capital. A single offshore oil and gas facility failure or plant trip can result in millions of dollars in production losses. Therefore, any solution that has the potential to affect a process or its safety negatively must be proved before being implemented. Throughout its history, the industry has taken a conservative approach when adopting new technologies, even those designed to prevent unplanned downtime. Although many current technologies promise increases of 1 to 2% in production efficiency, these gains become insignificant in the offshore industry if risk exists that deployment of the technology could in any way disrupt operations. Cybersecurity and data privacy are perhaps the most-significant concerns related to adoption of digital solutions by the industry, and they are well-founded. Much of today’s offshore infrastructure was not designed with connectivity or the Internet of Things in mind. Digital capabilities have simply been bolted on. In a recent survey of oil and gas executives, more than 60% of respondents said their organization’s industrial control systems’ protection and security were inadequate, and over two-thirds said they had experienced at least one cybersecurity attack in the previous year. Given this reality, it is no surprise that offshore operators have been reluctant to connect their critical assets. They are also cautious about sharing performance data with vendors and suppliers. This lack of collaboration and connectivity has inevitably slowed the pace of digital transformation, the extent to which it can be leveraged, and the value it can generate.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 202251, “Transforming the Mindset To Drill Ultra-ERD Wells With High Tortuosity,” by Barry Goodin, SPE, Duane Selman, and Andy Wroth, Vermilion Oil and Gas, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. The complete paper describes the extensive integrated engineering collaboration and optimization process that allowed an operator to push the drilling and completion envelope to drill a pair of complex, ultra-extended-reach-drilling (ERD) wells in the mature Wandoo field in the Carnarvon Basin offshore Western Australia. The shallow reservoir depth, extreme ERD profile, and high tortuosity requirement for the wells posed significant challenges. These were overcome with extensive planning; integrated engineering designs; application of new technology; good-quality, real-time data interpretation; and strong execution support from both rig site and town. Introduction The Wandoo field, in 56 m of water off-shore Western Australia, was discovered in 1991 and subsequently developed and placed on production in 1993. The shallow unconsolidated sandstone reservoir consists of a heavily biodegraded oil column overlain by a gas cap and supported by a strong aquifer drive. Field infrastructure consists of a 15-well-slot manned production facility, Wandoo B, and a five-slot monopod, Wandoo A, which is tied back to Wandoo B by subsea in-field pipelines. In late 2018, the operator planned and executed a two-well drilling campaign consisting of two complex, ultra-ERD wells, Wandoo B15 and B16. Both wells were planned to be batch drilled for the top hole and intermediate hole sections, with the production hole sections to be drilled and completed sequentially. The primary objective for the B15 well was to recover unswept oil along the western flank of the field and track the well along the main Wandoo fault to the north to assess the structure and reserves from the northern tip of the field. The B16 well objective was to access unswept reserves through the center and down to the south of the field, essentially twinning the B11ST1 well, another ERD well drilled on an earlier campaign, to its eastern flank. To maximize recovery, both wells needed to be placed approximately 1 m below the top of the reservoir, except where overlain by the gas cap, in which case the wells were to be placed approximately 2 m below the gas/oil contact to avoid gas coning. Drilling Challenges and Solutions The first half of the complete paper presents a detailed discussion of the drilling challenges and solutions, illustrated with schematics, maps, charts, and graphs. Both Wells B15 and B16 were classified as ultra-ERD wells because the shallow true vertical depth (TVD) of the reservoir resulted in extreme stepout ratios and required highly complex well paths to access the remaining reserves. The complete paper lists various specific drilling- and systems-related challenges.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 198970, “Casing Rotating Cement Heads: A Custom-Fit Solution To Improve Zonal Isolation Results In Colombia—A Field-Proven Case,” by Jose Vela, SPE, Henry Arias, and Edwin Sanchez, Ecopetrol, prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, held virtually 27–31 July. The paper has not been peer reviewed. In the current challenging drilling environment, effective annular zonal isolation is required for long-term integrity. Among proven cementing practices, casing rotation has been widely applied to liners but not as commonly to full casing strings. The complete paper describes the use of custom-fit rotating cement heads (RCH) to improve cementing results. Cementing Practices in Colombia The following methods of cementing, described in detail in the complete paper, are applied currently in Colombia: - Preflushes and spacers - Slurry design - Casing standoff - Borehole conditioning - Mud circulation and conditioning - Casing movement during the cement job - Monitor job parameters compared with design - Pressure testing and surface-equipment installation Most of these best cementing practices have been followed on a daily basis for all production and intermediate casing. Rotation practice has been widely applied to liners but not for casing strings. This observation led to the introduction of RCH, a technology that arose as the most- appropriate link to connect the top drive or rig prime mover with the casing so that rotation for a full string of casing could be achieved. RCH Use and Implementation Before the implementation of RCH, cement evaluation logs did not show the expected response. Evidence of fluid channeling and fluid contamination was very common, and fair casing to cement bonds was a concern, particularly in washed-out sections and very long cement columns. RCH provides a technical solution for the need to rotate the casing strings while maintaining best practices common to all cement jobs. Rotation has shown to be mandatory for intermediate and production casing to obtain a better log response by enhancing displacement fluid efficiency and mud removal. Well-design and cement objectives vary according to regional sedimentary basins around the country. In the Llanos Basin, the intermediate casing shoe integrity and the isolation of the T1 sand unit are primary objectives; the most-common wellbore problems are the presence of very washed-out sections in front of the E3 and E4 shale formations. The T1 sand unit is located between them and is prone to water or gas influx. Next, the production section is drilled with a lighter mud so that a high negative differential pressure is induced around the casing shoe once the shoe track is drilled. If shoe integrity is not suitable, an influx can be promoted when drilling the productive zone.

The blending of digital and physical worlds has been happening all around us at a rapid pace for many years. In the early days of digital transformation efforts, it would show up incrementally and sporadically, with varying levels of success. I remember my first email address, my first mobile phone, my first iPod, and my MySpace account page. Those all seem so long ago now. As time moved on, digital and physical connections seemed more real, and progress became clearer with more tangible benefits. And it was all happening more and more quickly. Fast-forward to a current, pandemic-clouded existence. Can anyone imagine not being connected to the internet or digital ecosystem around us less than 24/7 these days? Over the past year, we could barely keep up with how important our interactions between the digital and physical landscapes had become. As we have been forced to rethink in every way how we interact with people, places, and things, our connection to digital tools in our altered physical world has become a lifeline for individuals to connect with each other. These tools have also been critical for companies to connect to their customers and the greater market. We no longer speak or think about what it will be like to go back to “normal.” Our use of different digital tools to connect with people and data is now normal and will not be going away. Historically, the oil and gas industry has been grounded in fundamentals of science, technology, and intelligent people working at the outer edge of what was thought possible to produce hydrocarbons. Even with this forward thinking and adventurous spirit permeating the entire industry, we have been very slow to pick up digitally transforming how we work. It has become apparent over the past few years the requirement to move in this direction, or risk obsolescence. Even though this digital space is not new in our personal lives, we still act as though it is new to us in our working lives. To think of that in a real-time scale, I purchased my first mobile phone 24 years ago, yet I sometimes still need to wait for a daily drilling report through email to understand what is happening on a location half a world away. It is taking our phenomenal and advanced industry way too long to catch up, but it appears that most of our membership are now on board. From this point, the digital transformation of upstream oil and gas production will fundamentally change how our business is conducted and measured with a clear and targeted focus on optimizing each part of the customer journey. We will smartly and efficiently use data and technology to help create frequent, low-friction, and positive experiences throughout the connected customer relationship. This industrywide digital transformation will be a long path that is difficult and takes time. The market may be altered, but the path to a successful digital transformation is fluid and the core principles of success have not changed. It starts with digitizing. This is the foundation the rest of the digital transformation is built upon.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 30425, “Innovative Asset-Integrity Management To Drive Operational Effectiveness,” by Danny Constantinis and Peter Davies, EM&I, prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, Malaysia, 17–19 August. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. While the focus on the growing floating gas industry is firmly on output, the industry needs to ensure safety, compliance, and profitability of high-value, complex, floating gas assets, some of which operate close to high population densities. Effective asset-integrity programs are a key part of such an effort, and it is widely agreed that better use of data and robotics will help reduce unnecessary work and human risk. The complete paper describes a joint industry approach for addressing asset-integrity management challenges that has proved successful for floating production, storage, and offloading vessels (FPSOs). Introduction Managing the integrity of offshore, near-shore, and berthed floating oil and gas assets faces numerous challenges, including the following: - Long service lives - The need to cut operating costs - Varying asset-integrity requirements of marine and process equipment - Growing global demand for gas - Increasing requirement to drive down carbon emissions - The need for enhanced sustainability Traditional cost-reduction strategies of prior lean market periods are no longer accepted by the industry, which the authors say needs to implement permanent cost reductions, increased sustainability and efficiency, and improved safety. These can be achieved only by new ways of managing asset integrity, targeted at consistent low price and efficiencies and developed, supported, and accepted by all sectors of the industry. Role of the Joint Industry Project (JIP) The Hull Inspection Techniques and Strategy (HITS) JIP has encouraged such innovations. The complete paper describes new methods facilitated by HITS that include diverless inspections of hulls and mooring systems and remote, unmanned methods of inspecting confined spaces such as cargo and water ballast tanks. Organizations such as the HITS JIP, whose membership includes oil majors, service providers, classification societies, and regulators, and the FPSO Research Forum, of which HITS is a part, have helped define the direction for improvements in inspecting, maintaining, and repairing floating production assets. These organizations have encouraged the development of new technologies that have improved safety and reduced operational costs. According to the paper’s authors, this direction has also shaped the drilling sector, can do the same for floating liquified natural gas (FLNG) and floating storage and regasification units (FSRU), and could potentially expand into floating renewable-energy-production assets. These and similar concepts are now being taken forward in a floating gas (FloGas) JIP.

The time needed to eliminate complications and accidents accounts for 20–25% of total well construction time, according to a 2020 SPE paper (SPE 200740). The same paper notes that digital twins have proven to be a key enabler in improving sustainability during well construction, shrinking the carbon footprint by reducing overall drilling time and encouraging and bringing confidence to contactless advisory and collaboration. The paper also points out the potential application of digital twins to activities such as geothermal drilling. Advanced data analytics and machine learning (ML) potentially can reduce engineering hours up to 70% during field development, according to Boston Consulting Group. Increased field automation, remote operations, sensor costs, digital twins, machine learning, and improved computational speed are responsible. It is no surprise, then, that digital twins are taking on a greater sense of urgency for operators, service companies, and drilling contractors working to improve asset and enterprise safety, productivity, and performance management. For 2021, digital twins appear among the oil and gas industry’s top 10 digital spending priorities. DNV GL said in its Technology Outlook 2030 that this could be the decade when cloud computing and advanced simulation see virtual system testing, virtual/augmented reality, and machine learning progressively merge into full digital twins that combine data analytics, real-time, and near-real-time data for installations, subsurface geology, and reservoirs to bring about significant advancements in upstream asset performance, safety, and profitability. The biggest challenges to these advancements, according to the firm, will be establishing confidence in the data and computational models that a digital twin uses and user organizations’ readiness to work with and evolve alongside the digital twin. JPT looked at publications from inside and outside the upstream industry and at several recent SPE papers to get a snapshot of where the industry stands regarding uptake of digital twins in well construction and how the technology is affecting operations and outcomes. Why Digital Twins Gartner Information defines a digital twin as a digital representation of a real-world entity or system. “The implementation of a digital twin,” Gartner writes, “is an encapsulated software object or model that mirrors a unique physical object, process, organization, person or other abstraction.” Data from multiple digital twins can be aggregated for a composite view across several real-world entities and their related processes. In upstream oil and gas, digital twins focus on the well—and, ultimately, the field—and its lifecycle. Unlike a digital simulation, which produces scenarios based on what could happen in the physical world but whose scenarios may not be actionable, a digital twin represents actual events from the physical world, making it possible to visualize and understand real-life scenarios to make better decisions. Digital well construction twins can pertain to single assets or processes and to the reservoir/subsurface or the surface. Ultimately, when process and asset sub-twins are connected, the result is an integrated digital twin of the entire asset or well. Massive sensor technology and the ability to store and handle huge amounts of data from the asset will enable the full digital twin to age throughout the life-cycle of the asset, along with the asset itself (Fig. 1).

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 201763, “Exploiting the Full Potential in Automated Drilling Control by Increased Data Exchange and Multidisciplinary Collaboration,” by Kristian Gjerstad, SPE, and Ronny Bergerud, Sekal, and Stig Tore Thorsen, SPE, Equinor, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5-7 October. The paper has not been peer reviewed. The complete paper describes challenges that must be overcome to reach the goal of drilling systems automation (DSA). The authors explore steps necessary to realize the full potential of performance-enhancing functionalities in automated drilling control (ADC) software, highlight current gaps, and present relatively easily achievable goals that can enable significant cost reduction and improvements in automation and safety. They also emphasize that automation is a multidisciplinary task, and that success requires collaboration between different sectors of the drilling industry. Overview The 19-page complete paper includes detailed technical discussion of topics ranging from the basic principles of an ADC system and practical challenges experienced with a model-based digital twin approach to suggested solutions and improvements. Each topic is divided into numerous related discussions. Because delving into each of these discussions is not possible in this synopsis, these have been outlined, with a few supporting points included for each. The Potential of ADC Systems Dedicated software applications - referred to by the authors as ADC systems - for protecting the well, increasing safety, automating repetitive operations, and optimizing the drilling process, have been available for some time. Several projects in which sophisticated ADC systems evaluate downhole conditions to assist the driller with judgments and decisions have been reported, with promising results including noticeable improvements in cost savings, reduced incidents, and improved safety. However, the number of rigs with sophisticated ADC systems running actively in real time is not high, and even on rigs where an ADC system is in use, the potential of the system generally is not fully leveraged. One reason is that these ADC systems are based on models of the drilling process running in parallel with the real process, with each requiring the exact same inputs in real time to work optimally. Many of these inputs are entered manually because the instrumentation, equipment, and infrastructure needed to automate the data transfer are not in place. The inputs that are automated may not be sufficiently accurate or reliable, so manual interactions are needed. Experience shows that even on relatively new rigs with modern instrumentation, a large untapped potential exists. An underlying reason for this lack of automated inputs is that different parties involved in establishing the required instrumentation and automated signal transfer are not well aligned. Thus, increased automation and repeatability can introduce increased staffing and cost for operating the ADC system. To overcome this paradox, better collaboration is required among the vendors in the complete production loop.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 30715, “Floating Production Systems: What’s Next?” by William Judson Turner, SPE, Welligence Energy Analytics, prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4-7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. The complete paper provides insight on the commercial drivers that significantly changed floating-production-system (FPS) design philosophy after 2014, with a particular focus on the US Gulf of Mexico (GOM). The paper explores near-term and longer-term outlooks for FPS design, touching on technology and automation that can relocate staff onshore to increase safety, reduce capital expenditure (CAPEX) and operating expenses (OPEX), and increase return on investment (ROI). The authors note that the commercial analyses presented in the paper are indicative and are subject to revision. Introduction The drastic fall of oil prices in late 2014 forced a harsh but necessary overhaul to the design philosophy of deepwater projects. Bigger was no longer better; the industry set to work using methods such as lean design and standardization for commercial improvement. Through a slow recovery in commodity prices and a steady persistence in innovating and implementing improvements, the deepwater sector made significant strides in commercial and operational efficiency. This overhaul was a rough 4-year journey as investment capital, and even some operators, retreated from deep water for lower-cost and faster-cycle onshore projects - at least, that was the perception at the time. Deep-water projects were delayed or canceled, and the industry saw consolidation among operators and the service sector. While the period may have been uncomfortable, it was a much-needed turnaround for an industry with average breakeven costs at $70 per barrel. The rework resulted in an industry fit to compete with onshore production, with breakeven costs reduced by half in some cases.

Managed-pressure drilling (MPD) as the simple but effective principle that by managing downhole pressures, critical performance indicators such as risk, safety, efficiency, and cost are also controlled. As the energy world works to balance supply, demand, and the environment, efficient solutions such as MPD can help drive the promise of a compatible relationship. Globally, MPD is increasingly seen as an option to move drilling toward a “green” future. Beyond putting in place an adaptive drilling process to precisely control the annular-pressure profile throughout the well, MPD has consistently shown it can support green credentials for the wells where the application is utilized. This article discusses real-world examples of the less often considered but valuable environmental benefits delivered via MPD which include the following. Lowering the risk of spillage and blowouts Reducing mud chemicals; increasing use of simpler drilling fluids Optimizing drilling operations by reducing nonproductive time (NPT) from geopressure-related events and enabling a reduction of drilling carbon footprint through earlier achievement of well objectives Consuming fewer materials (casing, etc.) through streamlined well architecture These MPD benefits are well documented in the technical literature of the industry. In fact, a basic search for the exact phrase “managed pressure drilling” in OnePetro, the online library of technical literature for the oil and gas industry, shows 1,775 results. A majority of these papers was written in the past 10 years with each year averaging more than 100 technical papers and the average over the past 5 years increasing to 150 papers per year. The numbers tell the story of the growing technical interest in MPD technology which has been sustained even through the recent economic downturns. A further search of these MPD papers shows that 1,117 (63%) papers mention “safety,” 849 (48%) mention “efficiency,” and 47 (3%) specifically mention “environmental impact.” With the recent interest in green and environmentally friendly technologies, there is a need to highlight that the safety and efficiency benefits MPD applications already provide are also reducing environmental impact. Generally speaking, choosing MPD vs. conventional drilling methods is a step toward carbon neutrality. The following case studies showcase the improvements MPD has provided in land, shallow-water, and deepwater applications as seen from the perspective of environmental-impact mitigation. Mitigating Environmental Impact For land rigs, particularly in the US, where the majority have for decades now constantly deployed rotating control devices (RCD) that enable operations involving MPD and underbalanced drilling (UBD) methods, RCD technologies have consistently proven to reduce the risk of spillage and blowouts. Studies have shown that the use of a fit-for-purpose RCD has been statistically proven to “reduce the risk of a well-control event when drilling with an essentially incompressible fluid and not inviting the well to flow in the process,” underscoring the safety and environmental benefits of MPD in terms of minimizing unintentional hydrocarbon release.

Despite uncertainties related to oil and gas industry dynamics and new requirements to reduce CO 2 emissions, energy demand is expected to continue to grow. It is also expected that the mix of energy shares will change significantly in the next 10-20 years. Natural gas and renewables (wind and solar) gradually will represent a larger part of the energy mix, balanced by a drop in reliance upon fossil fuels such as oil and coal. Some of the largest reserves of natural gas are located under deep waters, far from shore or any other existing infrastructure. Examples of areas where such field development is under way include western Australia, the North Sea, the Mediterranean, and southeast Africa. Among the many challenges often experienced in such fields is the requirement to transport gas in ultralong pipelines back to shore; in some instances, tie-backs are 100- to 250-km long and water depths can reach more than 2000 m. Subsea gas-compression technologies have been developed, tested, and successfully deployed in recent years, and operators now are using these technologies to make remote subsea gas fields profitable. Systems for subsea gas compression have reached Technical Readiness Level 7. After being in operation at the Gullfaks field and at the Åsgard field in the North Sea for several years, these technologies are now being considered for future field developments, not only in the North Sea but also in other parts of the world. In the Åsgard subsea-compression system, the gas condensate is separated subsea so that the gas can be compressed by a centrifugal compressor and the liquids can be pumped. Gas and liquid then are commingled downstream of the compressor station, and the mix travels in a pipeline to a processing facility 40 km away. The Gullfaks compression system uses a multiphase compressor technology that has been developed to handle mixtures of gas and liquid; hence, no separation or liquid pumps are required subsea. The result is that the weight and volume per unit of compression power are greatly reduced and the system becomes relatively small and less complex. Both operational experience and studies of future offshore gas-field developments are showing that subsea gas-compression systems not only reduce investment costs but also increase recovery significantly. New solutions, supported through relevant field studies, will be analyzed in the studies presented in this section.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199456, “Environmental Management in the Oil and Gas Industry, Second Edition - A Guide to Environmental Management Good Practices in the Upstream Oil and Gas Industry,” by Wendy Brown, IOGP, Artemis Kostareli, IPIECA, and Ian Sealy, SPE, Schlumberger, prepared for the 2020 SPE International Conference and Exhibition on Health, Safety, Environment, and Sustainability, originally scheduled to be held in Bogota, Colombia, 28-30 July. The paper has not been peer reviewed. Environmental Management in the Oil and Gas Industry was first published in 1997 by the E&P Forum [the predecessor of the International Association of Oil and Gas Producers (IOGP)] and the United Nations Environment Programme (UNEP) as a guide to best practices in environmental management throughout the lifecycle of upstream oil and gas projects. Since then, the industry has made substantial changes in environmental risk management and mitigation. IOGP’s Environmental Committee determined in 2016 that a revision of the publication (also known as IOGP 254) was required. The complete paper describes the development of, and summarizes the major changes and additions to, the guide’s content.

As I think about this year’s Coiled Tubing feature, we are all in the midst of the effects of COVID-19 social distancing, an oil-price crash, and high levels of oil in storage. What will the world - and the oil industry, in particular - look like in a couple of months? Certainly, cash flow is going to be king among the various financial metrics. What can deliver results quickly and at a comparatively lower cash requirement? In many ways, these factors have played into the coiled tubing segment’s growth over the past couple of decades (i.e., delivering value). Will tomorrow be the same as just a few short months ago? In one sense - market size - no, but in another sense - as a segment that has always sought out and applied innovative, cost-effective solutions - yes. The papers summarized in this year’s feature demonstrate the application and versatility of coiled-tubing-based solutions to different phases of a well’s life-cycle, from exploration through production and, finally, to abandonment. In an exploration well, using coiled tubing to perform a drillstem test (DST) and potentially stimulate a zone of interest has long been a desire because it is perceived to be a cost-effect method over more-traditional methods. Paper SPE 199853 details the development and initial use of such a system that includes surface real-time readout, always desirable in a DST. Moving into the later days of a well’s production phase, artificial lift typically is used to overcome the limitations of falling bottomhole pressure. In paper IPTC 19930, a detailed overview of a coiled tubing gas-lift installation is given, together with some of the production analysis used to determine the installation’s configuration. This technique has been used for several years around the globe, and some useful insights are shared by the authors. Finally, coming to the end of a well’s life-cycle, is well abandonment. This is always a cost-sensitive lifecycle phase, even before today’s paradigm. The final paper of this year’s selection demonstrates how a coiled-tubing-based approach enabled a cost-effective plug and abandonment to be achieved while still meeting local regulatory requirements. Remember, you may need to distance physically but you can stay connected by making use of, and participating in, your Society of Petroleum Engineers. Stay well, everyone.