Lean-designed semis still platform of choice for deepwater Gulf

June 1, 2022
Standardized, repeatable FPS design helps accelerate cycle times.

Richard D’Souza * Richard B Offshore

Shiladitya Basu * KBR 

Lean-designed, standardized semisubmersibles are now the FPS design of choice for the deepwater Gulf of Mexico. In many cases, the design best meets the requirements of a universal host in terms of water depth and payload bandwidth; flexibility for phased development; ease of integration and installation; and contracting flexibility.

Post-2014, seven greenfield developments with a newbuild floating platform have been sanctioned in the US Gulf of Mexico. These developments cover a broad swath of GoM lease areas. Water depths range from 1,200 m (Vito and King’s Quay) to 2,600 m (Whale). Nameplate production capacities range from 80,000 boepd (Anchor) to 175,000 boepd (Appomattox).

The reservoirs include the Norphlet, Miocene and Lower Tertiary (Paleogene) plays. Estimated recoverable resources range from 250 mmboe (King’s Quay) to 650 mmboe (Appomattox). The first post-2014 development to be sanctioned was Appomattox, and the most recent are the 2021 sanctioned Whale and Shenandoah developments.

A brief case history of these projects is provided below. This information can be useful for summarizing field development plans, platform particulars, contracting strategies, engineering and fabrication contractors, and critical milestone dates.

Appomattox development

Shell discovered the Appomattox reservoir in Mississippi Canyon (MC) Block 392 in March 2010, about 120 km (80 miles) off the Louisiana coast in 2,200 m of water. The discovery well was drilled to a depth of 7,643 m, followed by several appraisal wells drilled in the next three years. The Vicksburg field was discovered in July 2013 in the adjacent block MC 393. The two fields cumulatively have an estimated ultimate recovery of over 650 mmboe. The reservoirs are in the Norphlet geological formation characterized by high temperatures and pressures and the presence of corrosive gas. These had a significant impact on the size and weight of the topside and platform. Shell made two additional discoveries within 16 km of Appomattox in 2014-2015.

Shell selected a large semisubmersible hub platform to develop Appomattox and Vicksburg with a production capacity of 175,000 boepd from 15 production wells and 5 water injection wells. A semisubmersible platform was chosen based on a combination of its ability to support a large topside weight, flexibility for future expansion and Shell’s prior experience with the design and execution of large semisubmersible and TLP projects.

Development engineering was well advanced by 2014, when the price of Brent crude fell by 44% from June 2014 to December 2014 and continued to decline in 2015. In January 2016, the price of oil fell below $30 per barrel, which was less than a third of the price when Appomattox development planning began. To sanction the Appomattox project, the Shell team assessed hundreds of cost-saving ideas, eventually realizing several billions of dollars in capital expenditure (capex) savings. The biggest saving came from halving the cost of drilling the 20 wells by negotiating a substantial reduction in drilling rig day rates and adopting batch drilling techniques. Shell reduced capex by about 20% pre-sanction and another 20% post-sanction by simplifying scope and specifications of the platform and subsea systems. As an example, substantial savings were attained by drawing source water to cool the massive 150 MW power generation plant, from 600 m below the water line.

Shell sanctioned the Appomattox development in July 2015. The Appomattox semisubmersible was to be the last of the giant platforms in the GoM, with the hull displacing 125,000 mt, and supporting a 27,000 mt topside operating weight. It was designed for a 40-year service life needed to deplete the known and yet to be discovered reserves that would be tied back to the platform. It was Shell’s second semisubmersible platform in the GoM after Na Kika; that project had been sanctioned in September 2000. Shell used their time-tested project execution model using handpicked topsides and hull engineering contractors that had worked on most of their previous GoM semisubmersible and TLP projects. Hull and topside fabrication contracts were negotiated with preferred contractors Samsung Heavy Industries (SHI) and Kiewit Offshore Services (KOS).

Shell awarded the 42,700 mt lightship hull to SHI shortly after sanction. SHI had fabricated the 108,000 mt displacement Olympus TLP hull some five years earlier. On completion, the hull was floated onto one of the largest heavy lift dry transport vessels, COSCO’s Xin Guang Hua, outrunning a super typhoon, that was aiming for SHI’s Geoje shipyard, by a day.  It arrived at the KOS Ingleside yard about two months later in October 2017, shortly after hurricane Harvey had ravaged the area.

KOS fabricated the four major topsides modules (150 MW Power, Process, Utilities, and 180 Person Quarters) and lifted them onto the hull with their 10,000 mt capacity heavy lift device (HLD). Following about ten months of integration and pre-commissioning activities, the platform sailed to the Appomattox site and was hooked up to the pre-installed 16-point chain-polyester-chain mooring system in August 2018. Export pipelines and production risers to the subsea drill centers were then hooked up to the FPS by Heerema Marine Contractor’s (HMC) Balder deepwater construction vessel (DCV). Appomattox achieved first production in May 2019. Shell is already considering debottlenecking options for future tiebacks.

Mad Dog Phase 2

BP discovered the Mad Dog field in Green Canyon (GC) Block 780 in 1998. Production began in 2005 from a Spar platform installed in about 1,300 m of water, 304 km (190 mile) south of New Orleans. The platform was designed to produce 80,000 bopd and 60 mmscfd gas. Appraisal drilling in 2009 and 2011 in surrounding leases doubled the resource estimate of the greater Mad Dog field to more than 4 billion boe in place, justifying the need for a second platform in the field.

In 2010 BP began work on a second hub facility, a large wet tree Spar platform dubbed Big Dog, to develop Mad Dog Phase 2. BP recycled the Mad Dog Phase 2 development in 2013, as the field development plan they were progressing was uneconomic even before the 2014 oil price collapse. This time BP selected a semisubmersible host platform over a TLP and Spar, based in part on the excellent execution and operational performance of the BP-operated Atlantis semisubmersible platform that began producing in 2007 in the Green Canyon area. A key to the selection of the semisubmersible FPS was the acceptance of steel lazy wave risers (SLWR) by BP riser engineers.

BP achieved a 60% capex reduction from the scrubbed development plan while producing the same resources. Much of this was achieved by simplifying and standardizing the host platform, subsea systems and well construction. Reservoir recovery factors were greatly improved by implementing ocean bottom nodes and advanced enhanced recovery technologies (Low Salinity or LoSal water injection) while reducing well count. Significant savings were also realized from industry collaboration and standardization.

The revised Mad Dog Phase 2 development plan includes a Kellogg Brown and Root (KBR) designed box-deck semisubmersible hull with the capacity to produce 140,000 bopd from 14 production wells and inject 140,000 bwpd LoSal water into 5 water injection wells. The platform, named Argos, a reference to Odysseus’ loyal dog from the Odyssey, is moored about 10 km southwest of the original Mad Dog truss spar. The project was sanctioned in December 2016 at an estimated break-even cost of $40/boe. Planned first oil at sanction was the fourth quarter of 2021.

BP deviated from the prevailing segmented execution model for large host platforms at the time, by awarding SHI a turnkey Engineer Procure Construct (EPC) contract to fabricate and integrate the FPS (topsides and hull) in their Geoje yard. The award followed several rounds of competitive bidding involving multiple contractors. Construction began in March 2018. The completed platform was loaded onto the BOKA Vanguard heavy transport vessel, setting sail for the KOS yard on February 8, 2021. After a 26,000 km voyage from South Korea, the Argos FPS was offloaded at the KOS yard on April 13, 2021. It underwent final preparatory work and regulatory inspections before being wet towed to the site and hooked up to its pre-installed moorings in November 2021, after battling a strong, persistent loop current. It is currently undergoing final hook-up and commissioning to the subsea wells and export pipelines. First oil is anticipated in the second quarter of 2022, about six months later than planned. Much of the delay is attributable to the global Covid pandemic.

King’s Quay development

The Khaleesi and Mormont reservoirs were discovered by LLOG in 2017 in GC blocks 390 and 478 in about 1,200 m of water. They are Miocene reservoirs 9,300 m below the seabed. Murphy Oil assumed operatorship of the Khaleesi/Mormont field development, following their acquisition of LLOG’s Green Canyon assets in May 2019. The reservoirs are estimated to contain a combined 165 mmboe of recoverable reserves. Murphy discovered the Samurai field in 1,060 m of water in GC 432 with recoverable resources estimated at 90 mmboe.

LLOG initiated the King’s Quay project as a seven well subsea tieback from Khaleesi/Mormont to a Semisubmersible FPS host located on GC block 433. Following the acquisition of LLOGs assets, Murphy added Samurai as a four well, 10 km subsea tieback. Murphy formally sanctioned the King’s Quay development in August 2019. In January 2020, Murphy entered into a memorandum of understanding with energy investment firm Arclight Capital Partners to sell its 50% ownership in the FPS, replicating a strategy employed by LLOG for the Delta House development.

The FPS is an Exmar standardized OPTI-11000 design, much like the Delta House FPS operated by LLOG that began production in 2015. The topside nameplate capacity is 80,000 bopd and 100 mmscfd gas, with peak capacity of 100,000 bopd and 240 mmscfd gas. It has the flexibility to host future subsea tiebacks. The hull is a four-column, ring pontoon configuration with a truss deck connecting the column tops. The deck offers a flat area that facilitates installation, hook-up and pre-commissioning topsides modules. The deck and topsides are fabricated and integrated at ground level and installed onto the hull in a single heavy lift.

Exmar Offshore provided engineering and construction supervision services for the hull, while Audubon Companies was awarded a contract for topsides engineering and procurement services. LLOG negotiated a turnkey EPC contract with Hyundai Heavy Industries (HHI) to fabricate and integrate the topsides and hull, which they later assigned to Murphy. The deck and topsides were placed on the hull in a dry dock in a single lift. This was a departure from the Delta House project execution, where HHI fabricated the hull in Korea and KOS fabricated and integrated the topsides and deck with their HLD in a single lift at their Ingleside facility in Texas. The completed FPS was dry transported on the COSCO heavy lift vessel Xiang An Kou and delivered to the KOS shore base in September 2021 for final commissioning prior to sail away. First oil was achieved in April 2022, following hook-up of the moorings and risers and final commissioning.

Vito development

The Vito discovery well in the subsalt Miocene sands was drilled by Anadarko in July 2009 at a depth of 9,750 m below the mudline. Shell assumed operatorship in September 2009. After a four-year appraisal program Shell estimated that the field held recoverable resources of 300 mmboe, sufficient to support a stand-alone host platform.

Shell intended to sanction Vito in 2015, shortly after Appomattox, but the 2014 oil price collapse caused Shell to put the brakes on. A roughly three-year redesign exercise from the subsurface up followed. Shell succeeded in reducing the capex estimate by more than 70% from the original concept, which was a semisubmersible FPS comparable in size to the Appomattox FPS. This was achieved in several ways: reduced well count, improvements in drilling efficiency, a smaller, fit for purpose FPS with limited spare capacity, and competitively bid fabrication. The leaner FPS design incorporated automation technology that reduced manning significantly. With this development plan, Shell estimated that they could develop Vito for a forward-looking breakeven price less than $35 per boe. Shell announced the final investment decision on April 24, 2018.

The Vito topsides is supported by a structurally efficient modular support frame (MSF) with knee-braces. The approximately 10,500 mt topsides can process 100,000 boepd setting a benchmark for topsides design efficiency. The lightship weight of the four-column, ring pontoon hull, including the MSF, is about 13,000 mt. Hull displacement at a 27.5 m operating draft is 38,000 mt, like the OPTI-11000.

Shell broke from their traditional split construction contracting practice for prior GoM floating platforms by tendering to a broad selection of EPC fabrication yards. Shell awarded a turnkey EPC contract to Sembcorp Marine (Sembcorp) to deliver the Vito FPS. The yard installed the topsides onto the hull in a single lift in a dry dock with twin gantry cranes. Shell awarded the contract in May 2018. Sembcorp handed over the FPS to Shell in the final weeks of 2021. Dry transport of the Vito FPS onboard Boskalis’ Mighty Servant I, from Singapore to Texas began in the first week of 2022. The delivery was delayed by several months because of the Covid pandemic. The FPS arrived at KOS’ Ingleside yard in March 2022. Shell has advised that first oil from Vito is expected in the second half of 2022.

Anchor development

Chevron discovered the Anchor field in late 2014 on block GC 807 in 1,400 m of water. It lies about 225 km off the Louisiana coast and due North of their giant Jack and St. Malo fields, which began production in December 2014 from one of the world’s largest semisubmersible FPSs. The reservoir is in the Lower Tertiary Wilcox formation, about 10,300 m below the mudline. At an operating pressure of 20,000 psi, it is one of the first ultra-high-pressure projects in the world. Industry had begun the design and qualification of 20,000 psi subsea and drilling equipment several years earlier in anticipation of producing several of these massive, high-pressure reservoirs.

The timing of the discovery was not propitious as it coincided with the 2014 oil price collapse. Chevron, strongly committed to growing its already material production in the GoM, drilled two appraisal wells in the next two years to confirm reservoir productivity and recoverable reserves. From the appraisal program they estimated that the Anchor field had at least 440 mmboe of total recoverable resources, sufficient for them to begin Select phase activities for the Anchor development with a floating production platform in 2016.

Anchor is a staged development with an initial seven subsea production wells tied back to a semisubmersible FPS. Chevron estimated it would take 250 days to drill and complete each deep, ultra-high pressure well. The FPS nameplate production capacity is 75,000 bopd and 28 mmscfd gas.

The Define phase kicked off in early 2017 with Wood designing the topsides and integrated deck and the hull designed by KBR. These were the same contractors that designed the successful Jack St. Malo Semisubmersible. Topsides operating weight, including the integrated truss deck, is 17,000 mt. The hull lightship weight is about 20,000 mt, displacing 69,500 mt at a 35 m operating draft. Chevron greenlighted the $5.7 billion development in December 2019 having reduced development costs for new projects in the GoM by nearly a third, compared to their last generation of greenfield deepwater investments. Anchor is a phased development with the FPS designed to accommodate future subsea tiebacks. The initial phase targets the southern fault block of the reservoir. The second phase targets the northern fault block with a four well drill center. The performance of the southern wells will inform the decision to move forward with the next phase.

Chevron opted for a traditional segmented project execution approach for the FPS i.e., hull built in the Far East and topsides built and integrated in the GoM. In December 2019 Daewoo Shipbuilding and Marine Engineering company (DSME) of South Korea was awarded a contract to build the hull. The award ended a five-year drought in new offshore platform orders for the yard. At the same time, KOS was awarded the topsides fabrication and integration contract. First oil date at project sanction is the second quarter of 2024. As of this writing, it appears that the project is on schedule.

Whale development

Shell, the operator of the Whale development, made the discovery in 2017 in Alaminos Canyon (AC) Block 773. The discovery, in 2,600 m of water, is approximately 16 km from their Perdido development, 320 km southeast of Houston. Perdido began production in March 2010 from a drilling-production spar platform. Whale is a Paleogene reservoir some 9,000 m below the mudline. Shell labelled the find as one of its largest in the GoM in the past decade. Following several years of appraisal activities, Shell estimated a recoverable resource volume of 490 mmboe, sufficient to support a standalone greenfield platform. Well productivity, one of the biggest uncertainties in a Paleogene development, was largely derisked by their ten-year operating experience at the Perdido and Silvertip developments. In April 2020 Shell decided to postpone sanctioning Whale because of supply chain constraints and economic uncertainty created by the pandemic. However, they continued to advance a development plan that closely resembled the Vito development, sanctioned some two years earlier. The hull is a 99% replication and the topsides an 80% replication of the Vito platform.

The development plan features fifteen subsea production wells tied back to the semisubmersible FPS. Shell describes the Whale FPS as a “simplified, cost-efficient host design” like the Vito FPS, as it is configurationally and dimensionally identical to Vito. Like Vito, the nameplate production capacity is 80,000 bopd and 100 mmscfd of gas, the topside operating weight is 10,500 mt and the displacement is 38,000 mt. To lower greenhouse gas intensity, Shell is utilizing energy-efficient gas turbines and compression systems.

Anticipating a final investment decision (FID), and to accelerate first production, Shell contracted Sembcorp to build and integrate the Whale FPS topsides and hull in November 2019. Shell had earlier contracted Sembcorp for the same scope on the Vito FPS (EPC of the FPS and deliver to a shore base in the GoM). By taking advantage of the synergies from the Vito FPS supply chain and construction processes Shell estimated that they could achieve first oil 7.5 years after discovery. Shell sanctioned the Whale development on July 26, 2021, at a forward-looking breakeven cost below $35/boe. Whale will be Shell’s 12th deepwater platform in the GoM and is currently scheduled to begin production in 2024.

Shenandoah development

The Shenandoah field is located on Walker Ridge (WR) Blocks 51, 52 and 53. The discovery well was drilled by Anadarko in February 2009 in about 1,700 m of water. The reservoirs are in the Upper and Lower Wilcox sands about 9,500 m below the mudline. Like Anchor, the reservoir is ultra-high pressure, requiring 20,000 psi rated equipment.

There was considerable excitement surrounding the discovery, as the initial appraisal wells suggested the potential for upwards of 1 billion boe in place. After drilling five appraisal wells from 2012 to 2017, Anadarko concluded that the reservoir was highly compartmentalized, with recoverable reserves considerably lower than originally anticipated. Concurrent with appraisal, Anadarko had initiated a competitive FEED for a semisubmersible and spar FPS as the host facility and selected a semisubmersible. Anadarko relinquished the field in 2017 after spending a reported $1 billion from 2009 to 2017 on exploration and appraisal.

The project was revived in 2018 when LLOG became operator after Anadarko withdrew from the project and partner Cobalt Energy divested their interest in the project. Based on the results of the extensive appraisal program, LLOG concluded that recoverable resource from Shenandoah was about 280 mmboe. They quickly settled on a phased development plan, with the first phase consisting of tying back four producing subsea wells to a Semisubmersible FPS. The development plan drew heavily from LLOG’s experience with Who Dat and Delta House developments. The second phase would add four more producers, informed by the performance of the four initial wells. LLOG contracted TechnipFMC to provide the 20K subsea trees in October 2019.

On July 28, 2020, Beacon Offshore (Beacon) acquired LLOG’s stakes in Shenandoah and Yucatan, the latter being a discovery just southwest of Shenandoah that will eventually be included in the Shenandoah development. Beacon was formed in 2016 by private equity group Blackstone with the goal of building a significant, high-quality portfolio in the deepwater GoM.

Beacon sanctioned the Shenandoah development, as envisioned by LLOG, on August 27, 2021. The semisubmersible FPS is an Exmar OPTI-11000, similar to LLOG’s Delta House FPS and Murphy’s King’s Quay FPS, with a nameplate production capacity of 100,000 boepd. Shortly thereafter, they awarded HHI an EPC contract for delivery of the FPS following a competitive bid.  HHI had delivered the King’s Quay FPS in July 2021. HHI plans to start constructing the hull at its Ulsan yard in the third quarter of 2022. Work on the FPS is scheduled to be completed by September 2024, with installation in the field expected in fourth quarter of 2024. Beacon anticipates first production from Shenandoah in the first quarter of 2025.

FPS selection trends

Of the ten pre-2014 sanctioned projects, there were three TLPs, three semisubmersibles, three Spars and one FPSO. The average displacement of the four projects executed by major Operators (Jack St. Malo, Olympus, Big Foot, Stones) was about 140,000 mt and average water depth about 1,900 m. The average displacement of the six projects executed by independent Operators (Who Dat, Tubular Bells, Lucius, Delta House, Heidelberg, Stampede) was about 45,000 mt and average water depth about 1,500 m.

Just seven deepwater greenfield projects were sanctioned in the seven years since Hess sanctioned the Stampede TLP in October 2014. Significantly, all seven platforms are Semisubmersible FPSs. Of these, five (Appomattox, Argos, Vito, Anchor, Whale) were sanctioned by three major operators (Shell, Chevron, BP) with average displacement about 75,000 mt and average water depth about 1,800 m. Average displacement of the two Semisubmersible FPSs (King’s Quay, Shenandoah) sanctioned by independent operators (Murphy, Beacon) was about 38,500 mt and average water depth about 1,350 m.

The selection of a semisubmersible FPS for all post-2014 sanctioned platforms is not coincidental. In 2018, the authors presented the case for a semisubmersible FPS as a universal host for future GoM platforms (OTC-28970). It is informative to revisit the rationale for this selection as it has become a reality. In the run-up to the dramatic oil price drop in late 2014, deepwater projects witnessed a spectacular growth in investment, production and capex inflation. Much of the latter was attributable to inflation in drilling, equipment and labor cost, and lack of capital discipline. Oil prices in 2012-2013 averaged over $100/bbl and were expected to continue rising. Breakeven costs of deepwater projects in the GoM often exceeded $70/boe. Most deepwater projects were late and over budget.

In the wake of the 2014 oil price collapse, the industry was confronted with a stark choice: to enable sanction of future deepwater projects, break-even costs had to be reduced to $40/boe or less. By 2015, breakeven costs had fallen to between $50-$60/boe, driven largely by commercial gains extracted from the supply chain. Shell reduced capex of the Appomattox project, sanctioned in July 2015, by 40% without altering the development plan. They did this principally by halving the cost of drilling and completing the twenty wells.

To realize an additional $10-$15/boe reduction in breakeven costs, the industry had to do more. Significant break-even cost compression was achieved by simplifying and standardizing designs and specifications of everything from drilling and completions, subsea systems, and the floating platforms. Operators realized that by picking a universal FPS building block they could reap the benefits of greater project delivery certainty, accelerated cycle time to first oil and reduced capex, thereby achieving the harder to obtain cost reductions. The question was which of the four major platform types deployed in the GoM deepwater best fit the requirements of a universal host, i.e., water depth and payload bandwidth, flexibility for phased development, ease of integration and installation and contracting flexibility. The semisubmersible FPS checked all the boxes.

BP sanctioned the Mad Dog Phase 2 development in December 2016 at an estimated breakeven cost of $40/boe. They achieved a 60% reduction from the original development plan while maintaining the same production rates by utilizing many of the cost reduction levers at their disposal. One of the levers was to replace the spar with a semisubmersible FPS, building upon their successful execution of and lessons learned from the Atlantis FPS.

Shell rewrote their deepwater GoM development playbook with the Vito development. They delayed a presumptive 2015 sanction and spent three years on a revised plan that could be developed at a break-even cost of about $35/boe. A key was scaling back the topside nameplate capacity, simplifying the topsides processing facilities and reducing manning with automation. This combination led to an enhanced production rate to topsides weight ratio and a semisubmersible that displaced about a third that of the Appomattox FPS. The tradeoff came at the expense of limiting flexibility for future expansion. Buoyed by the success of Vito, Shell sanctioned the Whale development about three years later with a near replica of the Vito semisubmersible design and project execution.

King’s Quay and Shenandoah are being developed by independent operators Murphy and Beacon. They are following the successful template developed by LLOG (a partner on both projects) for their Delta House project by utilizing the lean, standardized OPTI-11000 semisubmersible design. The efficient topsides throughput (100,000 boepd) to topside operating weight (11,000 mt) ratio results in a compact and efficient hull (39,000 mt displacement). By standardizing and repeating the FPS design and using the same engineering and fabrication contractors (design one build two), the operators were able to accelerate cycle times and realize significant cost efficiencies, much as Shell hope to do for their Vito and Whale projects.

Shenandoah, however, is a frontier development that falls into the ultra-high-pressure category (20,000 psi), requiring high-specification subsea and drilling equipment. To manage the uncertainty in well productivity, Beacon has opted for a phased development where the second phase will be predicated on the performance of the first phase wells.

Chevron also opted for a phased approach for their ultra-high-pressure Anchor development that faces many of the challenges as the Shenandoah development. This provides the dual advantages of a) optimizing the second phase well designs based on information from the first phase and b) specifying a lower nameplate production (80,000 boepd) resulting in a leaner platform. The 17,000 mt topsides is about 50% heavier than the Shell Vito and OPTI-11000 semisubmersibles partly because of the inclusion of subsea boosting to enhance ultimate recovery.

Cycle times

The average discovery to sanction cycle time is 75 months, sanction to first production, 46.6 months and thus discovery to first production, 121.6 months, or about 10 years and 2 months. First oil dates for six of the seven projects are current best estimates as the projects are still in execution. Contrast these with the ten pre-2014 sanctioned deepwater project corresponding cycle times, which are 46.4, 34, and 80.4 months respectively. The average topside operating weight of the post-2014 sanctioned FPSs is about 16,000 mt, whereas the average topside operating weight of the pre-2014 sanctioned FPSs is about 16,500 mt. It is instructive to assess why the cycle times for the post-2014 cycle times are so much longer than the pre-2014 cycle times, even though the average topside operating weights are similar.

Generally, the discovery to sanction cycle time is dictated by the appraisal programs. Deeper, high-pressure, Lower Tertiary reservoirs require more extensive appraisal drilling to derisk the reservoir and increase confidence in the expected recoverable resource. Four of the ten pre-2014 sanctioned developments were in the Lower Tertiary with an average 78-month cycle time. The five developments in the Miocene reservoirs averaged 28 months. Tubular Bells was an outlier as there was a change in Operatorship seven years after the discovery.

Four of the seven post-2014 developments were high or ultra-high-pressure and/or high temperature reservoirs (Appomattox, Anchor, Whale and Shenandoah) requiring either extensive appraisal drilling or technology qualification of subsea and drilling equipment. Shenandoah (152-month cycle time) is an outlier because Anadarko spent eight years in appraisal before relinquishing their stake to LLOG, who two years later sold it to Beacon. The project also had to deal with the 2014 price collapse. Considerable time for technology qualification of ultra-high- pressure (20,000 psi) equipment was required. Average discovery to sanction cycle time for the other three high pressure developments is about 58 months, about 20 months faster than the corresponding pre-2014 sanctioned high-pressure projects.

Average discovery to sanction cycle time for the three Miocene discoveries (Mad Dog Phase 2, Vito, King’s Quay) was 64 months, almost three years longer than the corresponding pre-2014 sanctioned projects. The Mad Dog Phase 2 development plan was recycled three years into Select/Define activities, as the capex had ballooned to $20 billion. The recycled plan was executed in 36 months, despite being affected by the mid-2014 oil price collapse. Shell queued up the Vito project for sanction shortly after sanctioning the Appomattox development, about six years after the 2009 discovery. They then spent an additional three years redesigning the development from the subsurface up to drive the break-even cost below $35/boe because of the 2014 oil price collapse. The King’s Quay discovery to sanction cycle time of 20 months was consistent with operator Murphy’s aggressive approach to developing projects.

FPS contracting strategies

Most FPS projects sanctioned from 2005 to 2014 followed a familiar template: build the hull overseas and fabricate the topside in a Gulf Coast yard. Topside integration to TLP and Semisubmersible hulls were mostly done quayside by KOS with their HLD. Topsides integration on spar hulls was done on site with SSCVs. With a few exceptions, contracts for topside, hull fabrication and integration and installation were awarded separately. Shell, Anadarko and BP installed a majority of the FPSs during this period. They typically negotiated engineering, fabrication, integration and installation contracts with preferred contractors. There was the occasional EPC contract (Red Hawk Spar) or a lease-operate contract (Gomez and Thunderhawk Semisubmersibles, Stones FPSO).

Post-2014, operators were under relentless pressure to substantially reduce capex. The big breakthrough was to design leaner, standardized, repeatable FPSs. As the number of sanctioned projects fell, competition from Korean and Singapore fabricators became more intense, creating an opportunity for further cost reductions. By then many yards had established track records for EPC delivery of large integrated FPSs or sixth and seventh generation semisubmersible drilling rigs. In addition, the capabilities of heavy lift dry transport vessels kept growing, with the BOKA Vanguard (introduced in 2013 with Chevron’s Jack St. Malo FPS as its first cargo) capable of transporting a large FPS with a dry weight exceeding 100,000 mt. This combination of events led to a rethink of contracting strategies of post-2014 sanctioned FPSs.

When Shell sanctioned Appomattox in July 2015, they had already committed to their traditional contracting approach of awarding segmented fabrication contracts for the hull (SHI), topsides (KOS) and integration (KOS). Their radical rework of the Vito development included the FPS contracting strategy. They awarded a turnkey EPC contract for the Vito FPS to Sembcorp following a round of competitive bidding. They repeated the contract strategy for the Whale FPS delivery but negotiated the contract with Sembcorp to take advantage of the efficiencies derived from the Vito FPS learning curve.

BP was the first major operator to depart from the traditional contracting approach for a major FPS when it sanctioned the Argos FPS. After several bidding rounds with multiple contractors, they awarded a turnkey EPC contract for the FPS delivery to SHI. The 70,000 mt FPS was dry towed from South Korea to the GoM on the BOKA Vanguard.

Chevron, however, elected to stay with the traditional segmented contracting strategy for the Anchor FPS: hull fabricated in South Korea by DSME, and the topsides fabricated and integrated by KOS in Texas.

Murphy (King’s Quay) and Beacon (Shenandoah) chose a contracting strategy similar to that adopted by Shell for Vito and Whale, to take advantage of the efficiencies of building two similar hulls back-to-back. HHI was awarded an EPC contract for turnkey delivery of both FPSs.

The jury is still out as to whether a turnkey EPC contracting approach yields a superior commercial/operational result than the traditional segmented approach. The issue has been complicated by the pandemic that has caused unforeseen delays and distorted sanction to first production cycle times.


The dramatic oil and gas price drop in mid-2014 had a profound impact on deepwater developments in the GoM. Anticipating persistent low oil prices, the industry dialed back the number of sanctioned projects to about one a year. The focus shifted to greater capital discipline and shorter cycle times. The bar for project sanction was set at a breakeven cost of $40 per boe. Much of the early reductions came from capex deflation of the supply chain. A step change came from vastly improving drilling efficiencies and simplifying and standardizing designs and specifications of subsea and floating production systems. Further reductions were achieved by designing smaller, more efficient, repeatable platforms. By doing so, operators gave up flexibility for future expansion and enhanced recovery. The semisubmersible platform was selected for all seven of the post-2014 sanctioned developments.

Contracting strategy for FPS fabrication shifted from the traditional segmented approach to a turnkey EPC approach, in part to take advantage of Far East fabrication yards desperation for work. Discovery to sanction cycle times suffered as Operators reset and revised development plans to lower prices. An additional factor, in some cases, was developing high pressure Paleogene and Norphlet reservoirs that required qualifying drilling, completion and subsea equipment for these ratings and extensive appraisal programs. Unfortunately, sanction to first production cycle times increased relative to pre-2014 sanctioned projects because of the global pandemic that affected six of the seven projects causing delays up to twelve months.

The next capex and opex breakthrough will be from reducing or eliminating manning. Most operators have committed to or will be required to reduce carbon emissions for their next tranche of projects. Over the years, the offshore industry has shown great resilience in responding to oil price and external shocks by being flexible, adaptable and innovative. These qualities have been amply demonstrated by the post-2014 FPS projects sanctioned in the deepwater Gulf of Mexico.


            Based on a paper presented at the 27th Offshore Symposium held by the Texas Section of the Society of Naval Architects and Marine Engineers on Feb. 22, 2022, in Houston, Texas.