Subsea Tieback Research Articles

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 The paper has not been peer reviewed.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).

Transient modelling of water condensation rate for top of line corrosion

Top of line corrosion (TOLC) is typically a concern in the first few kilometres of wet gas pipelines where water in the warm gas condenses on the cold pipe walls. With the introduction of a subsea tieback to existing infrastructure, the changing fluid composition and temperature profiles may increase condensation in sections not previously expected to have condensation. Accurate prediction of the water condensation rate (WCR) becomes essential to support reliable corrosion modelling. Transient flow simulation of pipeline operating conditions and detailed heat transfer modelling is required to calculate the WCR. This calculation is complicated because the mass of water condensation is very small compared to the fluid mass in the pipeline, and sensitive to glycol that is often present in the aqueous phase for hydrate management purposes. This paper introduces a method to calculate WCR by using detailed transient modelling of the pipeline operating conditions. The fluid thermal hydraulic behaviour and hydraulic pressure drop in the pipeline are considered in the model. The fluid composition in the pipeline and glycol component in the aqueous phase are calculated by using a PVT software package. A few sensitivity studies will also be presented. The implications of Equation of State (EoS) and transient flow module on WCR calculation will be quantified. The WCR sensitivity results will be analysed based on varying inlet temperatures, glycol concentrations, and pipeline heat transfer coefficients. A WCR calculation method will be recommended for TOLC modelling.

Gulf of Mexico Operators Transition to Faster, Cheaper Developments as Production Decrease Looms

The US Gulf of Mexico (GOM) has long been a sound investment opportunity for operators looking for world-class oil fields, stable government regimes, and predictable regulatory requirements. Since the 1980s, the region’s deeper waters have been populated by fresh infrastructure as commercial discoveries were made, appraised, and developed. Today, more than two dozen floating production platforms and miles of export and transport pipelines populate the area, with more on the way as producers continue successful exploration programs in the area. There have been nearly 90,000 offshore wells drilled in the GOM to date. The GOM arena has experienced a few bumps in the road over the past few years due to both COVID-19 and the challenges to the most recent lease sale that was revoked, then later reinstated. While GOM oil production dipped from its peak in 2019 due in part to the global pandemic, the area is still an appealing region for operators. Operators used that period to focus on short-cycle and low‑cost recompletions, infills, and tiebacks rather than larger, capital‑intensive projects. According to a report released by the US Bureau of Energy Management (BOEM), GOM production is expected to experience growth and multiple record years of total oil production, despite off‑trend production levels in 2020 and 2021. Gas production is expected to experience moderate increases but is not expected to rebound near previous highs. The growth in annual oil production predicted in the following years is supported by a strong project queue as deferred projects will now be executed. From 2022 through 2024, oil production is forecast to have strong growth, followed by a relative plateau (until 2027) and a gradual decline through 2031, the end of the forecast period (Fig. 1). Around 70% of new GOM production in 2023 is expected to come from just three projects: BP’s Argos, Shell’s Vito, and Murphy’s King’s Quay. The predicted decline may be due in part to the number of new wells being drilled in the area. The well count for the GOM in general had a decade’s peak back in 2018; however, the count has trended down ever since. According to analysts at Enverus, industry averaged almost 30 ultradeepwater wells per quarter during 2018 and 2019. Last year, that number was around 15. With fewer wells come fewer discovery opportunities. With fewer discoveries backfilling the queue of potential developments, the GOM could be headed for a lull in new project commitments. Additionally, Wood Mackenzie research found that net discovered resource by company in the GOM fell from more than 1 billion bbl in 2017 to around 250 million bbl in 2021. Research from Rystad Energy showed just two deepwater GOM hub-based developments received a green light in 2021 (Shenandoah and Whale), while so far in 2022, only one (Salamanca) has been approved (Fig. 2). Counter to that, several subsea tiebacks are in the queue. While these historically represent smaller production volumes, they also represent significantly reduced cycle times from inception to first oil.

Technology Focus: Subsea Systems (August 2022)

As goes the offshore market in general, so follows the subsea arena, and both are experiencing an upturn because of an increase in commodity prices and the potential that offers to operators focused on optimizing existing assets. In current offshore operations—with an emphasis on environmental, social, and governance performance—subsea has an increasingly important role to play. Subsea tiebacks in particular offer opportunities to increase asset productivity while minimizing environmental impact on an incremental production-per-barrel basis. With that in mind, the papers selected provide an overview of interest and immediate relevance to SPE members and JPT readers, regardless of where those operations are taking place. Some of the longstanding issues currently of greatest concern are the jumping-off point for a review intended to focus on optimizing subsea developments. Speed of asset delivery, system reliability, data and information management, and project repeatability are the general wish list for subsea engineers looking to improve efficiency, and all are covered in the papers presented. Within the industry, the push for a standard approach—not so much with hardware and components but more so with overall subsea project management—is a high priority. Additionally, building on the learnings from mature subsea areas pushes development with a focus on subsea reliability, increasing the global nature of these challenges yet maintaining a specific focus on local issues. Finally, with a nod to the future, the electrification and automation of subsea assets is presented, the intention being that the industry is ready to combine state-of-the-art system and project management with cutting-edge technology to fully deliver on the potential of subsea. Recommended additional reading at OnePetro: www.onepetro.org. OTC 32010 - Novel Concept Approval and Technology Qualification of Systems and Vessels for Deep‑Sea Extraction of Polymetallic Nodules by Tyson Breedlove, American Bureau of Shipping, et al. OTC 32028 - Key Technology Qualification of a Full‑Scale Subsea Chemical Storage and Injection System by Art J. Schroeder, Subsea Shuttle, et al. OTC 32100 - Unlocking Resident Underwater Inspection Drones or Autonomous Underwater Vehicles for Subsea Autonomous Inspection: Value Creation Between Technical Requirements and Technological Development by Matteo Mattioli, Saipem, et al.

E&P Notes (August 2022)

E&P Notes (August 2022)

Technology Focus: Subsea Systems (August 2021)

Flow assurance in subsea oil and gas fields often presents significant challenges. Every field has its own combination of difficulties, and no universal process or system can be used to mitigate these. Detailed knowledge across a broad range of competencies, therefore, is required to find solutions that can minimize the risk of not getting the hydrocarbons safely to the process facilities. Many subsea fields that are being developed today are long tiebacks, taking advantage of existing offshore infrastructure or producing directly to shore. These developments must deal with the long-distance transport of hydrocarbons in deep cold water, commonly increasing the risk of hydrate formation and wax deposition, for example. In addition, large elevation changes from deep water to surface and topographical challenges along the pipeline can create flow-regime effects that can hinder production. The loss of temperature in a long subsea pipeline also creates challenges for fields that produce heavy oil because the oil viscosity in some cases increases dramatically at low temperatures, in addition to effective viscosities increasing because of oil and water emulsions. Other phenomena such as scale deposition, foaming, sand production, erosion, and corrosion must be considered and dealt with as well. Various smart-technology innovations for subsea oil and gas production contribute to reducing the risk of these flow-assurance issues. Some of them are described in this month’s selected SPE papers. A good example is as follows: When wells start to produce water, the operator needs to understand where the water is coming from and quantify volumes in order to start a mitigation program to avoid hydrate formation. This is one of the reasons why subsea multiphase flowmeters have become an essential feature in all new subsea fields. The most common remedy for flow-assurance problems is probably the use of chemical additives. A sensor technology that can directly determine the ratio between produced water and chemicals such as monoethylene glycol has been recently introduced in subsea production systems. This measurement enables the optimization of chemical-injection rates, thereby contributing to significant savings in capital expenditure (reduced design margins) and operational expenditure (reduced overdosage margins). Another effective way to prevent hydrates and wax is to keep the process temperature above critical limits by applying active flowline heating. New technologies for highly reliable and efficient subsea electrically heat-traced flowlines have recently been qualified, industrialized, and installed. Technologies as described here can play an important role in future subsea field developments. The recommended readings for this feature date back further back in time than usual, but are relevant to the theme of this year’s main selections. Recommended additional reading at OnePetro: www.onepetro.org. OTC 29232 Real-Time Subsea Hydrate Management in the World’s Longest Subsea Tieback by Christophe Vielliard, OneSubsea, a Schlumberger Company, et al. OTC 31078 Electrically Heated Trace Flowline on the Ærfugl Project—A Journey From Product Qualification to Offshore Campaign by Guy Mencarelli, Subsea 7, et al. SPE 195784 A New Flow-Assurance Strategy for the Vega Asset: Managing Hydrate and Integrity Risks on a Long Multiphase Flowline of a Norwegian Subsea Asset by Stephan Hatscher, Wintershall Norge, et al.

E&P Notes (June 2021)

E&P Notes (June 2021)

Flow-Assurance-Management Strategy Considerations for a Deepwater Gas Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202254, “Flow-Assurance Challenges for China’s First Deepwater Gasfield Development in South China Sea,” by Lawrence Khin Leong Lau, Kun An, and Xian Di Tang, CNOOC, 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 key flow-assurance challenges for a deepwater gasfield development in the South China Sea and the considerations and steps taken to achieve an overall flow-assurance-management strategy. The discussion covers early-stage feasibility studies through the stage of project execution at the time of writing. In addition, flow-assurance analysis is highlighted as a key input for startup and commissioning guidelines as well as operating procedures. Project Background This gasfield development consists of a semisubmersible more than 100 km offshore in the South China Sea. The water depth is approximately 1500 m, with a minimum seabed temperature of less than 4°C. The design incorporates Eastern and Western production loops spanning more than 40 km of the subsea production system (SPS) in total. Line size for the Eastern and the Western production loops are selected according to the total of production wells located in respective areas. The entire production system, including topsides facilities, subsea flowlines, risers, and other key SPS elements such as subsea manifolds, is designed with potential future development tie-ins in mind. Long subsea tiebacks, coupled with typical deepwater characteristics, require a robust flow-assurance- management strategy. A dedicated flow-assurance team was assembled across sectors such as subsurface, drilling and completion (D&C); subsea umbilicals, risers, and flowlines (SURF); control and instrumentation; and topsides process engineering. During the feasibility-study stage, more than 10 deepwater subsea production wells were grouped by characteristics. Analysis was performed for the most-representative wells selected from each group during this development stage to determine the range of the operating envelope and to identify all related risks. As development progressed into the detailed engineering-design stage, a detailed flow-assurance-scope analysis was completed for each well to ensure full coverage. This analysis considered scenarios including well unloading, well testing, precommissioning, first gas, steady-state production, planned and unplanned shutdowns, and hot and cold restarts. Any risks identified were assigned mitigation strategies and then were incorporated into design philosophy and operating guidelines or were specifically detailed in operating procedures. Primary Flow-Assurance Challenges Region-Specific Flow-Assurance Challenges. Flow Assurance as an Independent and Integrated Discipline. The creation of a cross-disciplinary flow-assurance team differs significantly from previous management approaches in which flow-assurance scopes were embedded in different disciplines and managed separately by teams such as subsurface, D&C, SURF, and topsides. The team described in the paper had the goal of implementing flow-assurance design and strategy with a truly integrated approach to maximize efficiency, optimize costs, and minimize impact on the environment.

E&P Notes (December 2020)

E&P Notes (December 2020)

Developing Technologies Can Lower Subsea Tieback Cost

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 30667, “How Technology Enables a Lower Cost for Subsea Tiebacks,” by Fabrice Bacati, Giorgio Arcangeletti, SPE, Bruno Breuskin, Saipem, et al., 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 traditional subsea tieback model is evolving, supported by advances in flow assurance that allow tiebacks over much longer distances and by the introduction of new technologies that increase overall cost effectiveness. Paper OTC 30667 discusses several of these technologies, their maturity status, and how they can be integrated economically. Introduction During the past 15 years, operating companies have relied increasingly on effective subsea field-development solutions to eliminate the need for traditional platforms or vessels with topside processing facilities, particularly in geographically remote areas and small-pool developments of maturing brownfield areas. Technical and economic challenges include flow assurance and the cost of the umbilical and flowlines, which increase with length. These aspects, together with others independent of length, such as power and space availability, affect project economics significantly. Technologies developed recently or in their final stage of qualification can help not only in solving technical challenges but also in finding cost-effective configurations, either through reduction or re-apportioning of capital and operational expenditures, extension of reserves recoverability, or reduction of associated risks. The complete paper outlines several configurations, beginning with those enabled by conventional technologies, and compares them to those enabled by the new technologies. Each section of the complete paper discusses the subject technology’s composition, application, maturity, and impact on cost effectiveness. Subsea Boosting Subsea boosting systems that ensure pressure to enable production flow for the life of the field have matured during the last 10 years. Boosting can reduce backpressure at wellheads, and also can transport the production fluid at higher pressure to minimize flowline diameter and control possible instability issues. For gas fields, recovery can be increased by allowing the reservoir to deplete and then using compression to produce the field over a longer time. Currently, several boosting systems operate internationally. The type of pump technology used depends on the fluid to be boosted and the performance required. Single-phase pumps are used for water injection and oil boosting up to 15% of gas/volume fraction (GVF). Hybrid pumps are used for GVF up to 30%, and multiphase pumps for up to 95%. Subsea compressors are used for higher GVF.

Modeling of Smart Pigging for Pipeline Leak Detection

Summary Although leak incidents continue, a pipeline remains the most reliable mode of transportation within the oil and gas industry. It becomes even more important today because the projection for new pipelines is expected to increase by 1 billion barrels of oil equivalent (BOE) through 2035. In addition, increasing the number and length of subsea tiebacks faces new challenges in terms of data acquisition, monitoring, analysis, and remedial actions. Passive leak-detection methods commonly used in the industry have been successful with some limitations, in that they often cannot detect small leaks and seeps. In addition to a thorough review of related topics, this study investigates how to create a framework for a smart pigging technique for pipeline leak detection as an active leak-detection method. Numerical modeling of smart pigging for leak detection requires two crucial components: detailed mathematical descriptions for fluid-solid and solid-solid interactions around pig and network modeling for the calculation of pressure and rate along the pipeline using iterative algorithms. The first step of this study is to build a numerical model that shows the motion of a pig along the pipeline with no leak (i.e., at a given injection rate, a pig first accelerates until it reaches its terminal velocity, beyond which the pig moves at a constant velocity). The second step is to construct a network model that consists of two pipeline segments (one upstream and the other downstream of the leak location) through which the pig travels and at the junction of which fluid leak occurs. By putting these multiple mechanisms together and using resulting pressure signatures, this study presents a new method to predict the location and size of a leak in the pipeline.

Offshore Enters Uncharted Waters

Someone once said, “It is the thing we least expect that hits us the hardest.” For the offshore oil and gas industry, which has become somewhat accustomed to being hit hard by unforeseen circumstances during its 70-plus-year history, the events of March are unprecedented. Within the space of 3 weeks, coronavirus became a worldwide pandemic; demand—and with it, prices—for oil plummeted; and Saudi Arabia and Russia decided to flood the world market with oil instead of agreeing on an amount by which to curtail production. For the offshore sector, the latest oil-price rout came just as the market was beginning to look up after some operators had cut costs by more than 50% since 2016, and industry executives and analysts were forecasting annualized revenue growth of 9% from 2019 to 2023. “We’re only thinking about survival now,” said the chief financial officer of one Scandinavian offshore major after the price of Brent crude dropped 23% in a single session, to $35.01/bbl. (At the time of writing, Brent was $32.62.) Deutsche Bank analyst Chris Snyder said his company was exposed because it was banking on an acceleration in deepwater drilling. “This is a very unlikely proposition in the current landscape,” he told the Wall Street Journal on 9 March. The Saudi policy would be especially negative for deepwater development, Snyder explained, because developing these projects requires significant upfront capital expenditure (capex) and, thus, confidence in the commodity price outlook. As this article goes to press, the flooding of the world’s total oil production with an estimated extra 2.5 million B/D looms, leading toward one of the biggest oil supply gluts the world has ever seen. Rystad Energy predicts that the negative impact of COVID-19 on oil demand could amount to between 12 million and 16 million B/D over the next months as more people will have to be quarantined for a longer period, causing an even more dramatic impact on oil demand through the year. In its final March forecast for oil demand, Rystad projected a decrease of 4.9% for 2020, or 4.9 million B/D year-on-year, from a yearly total of 99.9 million B/D in 2019 to 95.0 million B/D in 2020. The consultancy said it expected the month of April to take the biggest hit, with demand for oil falling by nearly 16 million B/D year-on-year, almost a 16% drop (Fig. 1). January Optimism As 2020 opened, the offshore sector was celebrating 2019 as its third-best year on record, with free cash flow reaching nearly $90 billion. Offshore regions had dominated the highest volume of new resource discoveries since 2015. Break-evens for pre-final-investment-decision (FID) deepwater projects had fallen to an average of $50/bbl, and increased use of phasing and subsea tiebacks had cut time to first production. Re-thinking “business as usual” and bringing costs down had led to a resurgence in activity in 2019 and estimates of a moderate rise of 4–7% in 2020 exploration activity over 2019. The optimism was heightened by the expectation that nearly $60 billion of greenfield offshore commitments for 2020 would be for fields with breakeven prices below $40/bbl.

A Look at the Aasta Hansteen Norwegian Deepwater Spar FPSO

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 29222, “Aasta Hansteen Spar FPSO—A Pioneer in Norwegian Deepwater,” by Torolf Christensen, Stig Arne Witsøe, and Helge Hagen, Equinor, et al., prepared for the 2019 Offshore Technology Conference, Houston, 6–9 May. The paper has not been peer reviewed. Copyright 2019 Offshore Technology Conference. Reproduced by permission. The complete paper describes the overall project execution of the Aasta Hansteen field development on the Norwegian Continental Shelf (NCS) north of the Arctic Circle. It is the deepest field yet developed on the NCS in 1300 m of water. In a harsh environment, with no other offshore installations in the area, the field is being developed with a spar floating, production, storage, and offloading (FPSO) structure using steel catenary risers and polyester mooring lines. Business Case The field is 300 km off the coast of northern Norway and 140 km from the nearest offshore installation. The field was discovered in 1997, with investment decision taken in December 2012 and production begun in December 2018. Total investment in facilities and infrastructure (including pipeline and modifications at Nyhamna) is approximately $7 billion. Equinor operates the field on behalf of its partners, Wintershall (24%), OMV (15%), and ConocoPhillips (10%). The field’s rich gas is exported through a 482-km-long, 36-in. pipeline to an on-shore processing plant at Nyhamna for further processing to sales gas. From there, the gas is exported to the European market. Stabilized condensate is stored in the spar FPSO and offloaded to shuttle tankers. The development of the field with the platform facilities and the Polarled pipeline was a strategic decision to open a new gas region in the Norwegian Sea and connect it to Europe by the NCS gas infrastructure. The development solution will serve as a gas hub enabling tie-in of future production from discoveries and prospects in the area. The objective of the Aasta Hansteen development is to maximize the recovery of the Aasta Hansteen reserves and to achieve maximum value creation in the value chain. Estimated recoverable reserves are 51 billion scm rich gas and 0.6 million scm condensate. The reserves consist of three separate discoveries—Luva, Haklang, and Snefrid Sør—all in the Nise formation and within the same production license. The development of Aasta Hansteen has been executed as a parallel development of the Polarled pipeline project to establish a new gas transport pipeline from Aasta Hansteen to Nyhamna. The pipeline has several tie-in points from Aasta Hansteen to the Nyhamna gas-processing plant. Snefrid Nord, the first subsea tieback development, is already being developed. The complete paper provides a brief description of the Polarled project.

The Hewett Field satellites: Big Dotty, Little Dotty, Deborah, Della, Dawn and Delilah, Blocks 48/29a, 48/30a, UK North Sea

Abstract Six satellite fields have been developed through the Hewett Field facilities: Big Dotty, Little Dotty, Deborah, Della, Dawn and Delilah. Little Dotty has produced from both the Leman Sandstone Formation (LSF) and Bunter Sandstone Formation (BSF) whilst the other satellites are exclusively LSF developments. The LSF reservoir quality exhibits a marked contrast across the Dowsing Fault Zone, which separates the inboard satellites to the SW from the outboard satellites to the NE. The inboard satellites, Big Dotty, Little Dotty and Dawn, display the best reservoir quality, reflecting their lesser depth of maximum burial. These fields share a strong aquifer, exhibited a rapid water-cut development and are now shut-in. The greater depth of maximum burial experienced by the outboard satellites, Deborah, Della and Delilah, is reflected in poorer reservoir quality along with weaker aquifers that are also more compartmentalized. These remain in production and will achieve higher recovery factors. Big Dotty was developed from a wellhead platform whereas the other fields were developed as subsea tie-backs. Collectively, these satellite fields have produced some 0.9 tcf of gas, playing an important strategic role in offsetting the production decline in the Hewett Field and extending the life of the asset.

The Starling, Scoter and Merganser fields, Blocks 22/30a and 29/3a, UK North Sea

Abstract The Shearwater Field is located 242 km east of Aberdeen in the Central North Sea (CNS) and has three satellite fields, Starling, Scoter and Merganser. Acting as the hub for the gas-condensate-producing normal-pressure–normal-temperature (NPNT) satellites, Shearwater, which produces high-pressure–high-temperature (HPHT) Jurassic reservoirs, comprises a bridge-linked wellhead jacket to a production platform. The satellites, developed as subsea tiebacks, target Paleocene turbidite reservoirs, with the Starling Field most distant at 33 km from the host while Merganser is tied in via Scoter through a 15 km pipeline. Each satellite consists of a subsea manifold connected to two production wells at Merganser, and three production wells each at Scoter and Starling. All reservoir traps at the satellites are due to Permian-age Zechstein salt diapirs. Starling and Scoter produce Forties Sandstone Member reservoirs via three deviated wells targeting anticline structures. At Merganser, two long horizontal production wells cross over 4000 ft of faulted Paleocene reservoir intervals to produce under salt diapir overhangs. The satellites have been instrumental in maintaining the Shearwater facilities given early main field well failures, whilst recent challenges have developed as the satellites mature, requiring infill wells and well interventions to maximize economic recovery.

The Perth Field, Blocks 14/25a, 15/21c, 15/21e, UK North Sea

Abstract The Perth Field was discovered in 1983 and appraised from 1992 to 1997, but has remained undeveloped due to the lack of a suitable export solution for the sour fluids. The field is a combined structural–stratigraphic trap on the southern edge of the Tartan Ridge in the Outer Moray Firth. An oil column of >1000 ft is developed in the turbiditic Upper Jurassic Claymore Sandstone Member which is mostly 500–800 ft thick in the proven appraised Core Perth area. Reference case oil in place within Core Perth is estimated at 197 MMbbl. An undrilled northern terrace may contain a similar amount of oil, with an additional 40 MMbbl estimated to be in place in a separate, proven northeastern fault panel. Potential development by subsea tieback to the Scott platform became an option in 2017. P50 reserves for 15 years’ production from Core Perth (five producers and two water injectors) are estimated at 47.3 MMbbl (24% recovery factor). The preferred concept is for oil and gas to be processed on a new self-contained sour module located on a standalone structure at Scott with oil exported in the Forties Pipeline System. Sour gas would be incinerated in a dedicated flare with recovered hydrocarbon gas exported to Scott.

The Laggan and Tormore fields, Blocks 206/1 and 205/5, UK Atlantic Margin

Abstract The Laggan and Tormore fields are found within the Flett sub-basin of the Faroe–Shetland Basin. Situated 120 km west of the Shetland Islands in 600 m water depth, they are part of the deepest subsea development in the UK to date with a 143 km subsea tie-back to onshore facilities. The reservoirs are found within the T35 biostratigraphic sequence of the Paleocene Vaila Formation and comprise sand-rich turbiditic channelized lobes with good reservoir properties, separated by metric to decimetric shale packages. Laggan is a gas-condensate field, whereas Tormore fluid is a richer gas with a saturated oil rim. Seismic reservoir characterization is a key to the field development where differentiation of fluid type proved challenging. Both fields came on stream in 2016 as part of the Greater Laggan area development scheme.

The Juliet Field, Block 47/14b, UK North Sea

Abstract The abandoned Juliet gas field is a small, highly compartmentalized, accumulation situated south and east of the Amethyst Gas Field. It was discovered in 2008 by well 47/14b-10 and flowed first gas on 5 January 2014. The field consists of at least two culminations within a very low-relief east–west-orientated fault-bounded anticline. The reservoir comprises aeolian sandstones of the Permian, Rotliegend Group, Leman Sandstone Formation. Reservoir quality varies from good to moderate, with a high production rate achieved from horizontal wells. Seismic time-to-depth conversion is affected by Quaternary seabed channels, chalk burial history and a rapid thickening in the Basalanhydrit Formation located over the east of the field, associated with the edge of the Zechstein Basin. Gas-in-place at pre-development was expected to be 105 bcf, with reserves of 67 bcf. The field was developed using two horizontal wells and a subsea tie-back to the Pickerill Field, 22 km to the east. Since development, the field appears to be more compartmentalized than initially expected.

Technology Focus: Flow Assurance

Technology Focus Flow assurance and multiphase-flow design, engineering, operations, and maintenance technical concerns have presented interesting and challenging issues requiring safe, economical solutions over my 20+ years of project experience around the world in both onshore unconventional and offshore conventional production facilities as an engineering, procurement, and construction contractor; major operator; manufacturer; and consultant. While gas-hydrate prediction and handling typically dominates the thermohydraulic design, the subsequent long-term mitigation of slugging and various flow-assurance phenomena, along with prevention of wax, erosion, asphaltenes, corrosion, and salt deposition, are all challenging issues.• First, severe slugging, frequently observed in pipeline and riser systems, is an important flow-assurance issue. The consequences of slugging usually involve flooding of downstream pipeline and production facilities and an overall decrease in field and system productivity. On the basis of experimental observations, severe slugging prediction models were developed and verified. Second, regular intervention activities to improve flow assurance, such as frequent pigging and injection of chemical inhibitors or drag-reducing agents, all require operational expense and require safety oversight and downtime. Internal pipeline coatings and liners are available solutions that could provide long-term benefits. Third, access to real-time production data on a desktop computer could improve an operations/pipeline engineer’s efficiency and system performance greatly. A smart management system is described that is capable of retrieving and evaluating flow-assurance-related data from multiple wells. This system can allow the operator to make better-informed decisions on the basis of a consistent data set with less time spent gathering and analyzing the data. The papers presented here discuss slightly different issues and approaches to multiphase flow continuity and production flow assurance. Severe slugging consequences typically include flooding of pipeline and production facilities and a subsequent decrease in production rate. Such severe slugging was previously thought to be limited to systems with upward, inclined pipeline or vertical, catenary or lazy-S-shaped risers. However, paper SPE 191611 presents the results of an experimental and modeling study that demonstrates the existence of severe slugging in systems with upward, inclined lateral flow paths such as a toe-down well, similar to that observed in a large-scale experimental facility specially constructed for studying flow behavior in horizontal wells.••• Pipeline internal deposits, such as corrosion and scale, can reduce the flow efficiency and design capacity of a transport system greatly. The use of interior pipeline coatings and liners is a potential long-term design solution that could provide long-term refurbishment benefits. The work described in paper SPE 193109 involves a novel material designed to interact specifically with highly corroded and weathered pipe, thus enabling in-place application and refurbishment.•••••• Paper SPE 191951 describes a smart management system used for retrieving and evaluating all flow-assurance-related data for more than 700 wells in both onshore and offshore fields. The paper discusses system architecture, interface details, system design, functionality, visualization, application, and the benefits of the system.• The papers presented here, including the additional reading papers on the potential novel applications of subsea tieback technology, focus on developing new analytical tools and new materials while providing safe, cost-effective, and reliable operations for flow assurance. I hope you find them as interesting as I did, and I greatly appreciate this opportunity to disseminate these new technology options to you in this and future Technology Focus sections. In addition, I invite you to join the Flow Assurance Technical Section. Recommended additional reading at OnePetro: www.onepetro.org. SPE 191748 Single-Flowline Tiebacks: Flow-Assurance Considerations From Appraisal to Operations by Juan I. Monge, Gate Energy, et al. OTC 29232 Real-Time Subsea Hydrate Management in the World’s Longest Subsea Tieback by Christophe Vielliard, OneSubsea, et al. OTC 29319 Subsea Long-Distance Tieback by Douglas Peter Wiles, TechnipFMC, et al.

Evaluation of a Riser After 10 Years of GOM Service Life

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 28908, “Ten Years in the Water: Observation and Detailed Evaluation of a Riser After Extensive Service Life,” by Mike Tricarico, Vallourec; Chris O’Neil, Anadarko; and Thomas Peter, Vallourec, prepared for the 2018 Offshore Technology Conference, Houston, 30 April–3 May. The paper has not been peer reviewed. Copyright 2018 Offshore Technology Conference. Reproduced by permission. As part of an effort to evaluate existing riser systems, an operator launched an inspection and testing program to investigate risers retrieved following well abandonment after a service life of nearly 10 years in the Gulf of Mexico (GOM). This represented a rare opportunity to evaluate the state of the threaded and coupled risers after such a long service life and assess the remaining longevity of the riser system. Specifically, it was a chance to observe and measure the effects of actual service life as opposed to calculated service conditions on the pipe and connections. The findings provided valuable insights into the future viability of similar riser systems. Introduction The Constitution truss spar was first placed in service in 2005. The spar featured six dry tree production risers with two subsea tiebacks. It operates in the Green Canyon region of the GOM in almost 5,000 ft of water. The production risers were run in 2006. In 2015, the decision was made to abandon several of the production dry tree wells. There was a high degree of interest in investigating the risers to assess remaining life. Special attention was paid to evidence of corrosion, cracking, or wear on the outer diameter (OD) or inner diameter (ID) of the pipe, along with water ingress into the connection causing any corrosion from seawater on the bare metal of the•connection. The complete paper includes a detailed discussion of the original design, testing, and first running; this synopsis will concentrate on post-service testing and assessment. Riser Pulling, Evaluation, and Testing Pulling and Review. In late 2015, on the basis of internal evaluation, the operator pulled several of the production risers. In order to validate the remaining life of the risers and to help in-form future decisions on the longevity of threaded and coupled risers, the operator then initiated a detailed review of the risers. The stress joints, tension joints, and first connectors after those joints were kept, along with several of the risers from the middle of the string. During the pulling operations, little evaluation of the state of the risers was possible; however, photographs of several of the connections were taken as they were pulled. Most notable was the lack of corrosion on the connection.