April 2024
SPECIAL FOCUS: Offshore technology

Wellbay innovation supports lower-cost, lower-risk phased approach for HP DW discoveries

Unlocking the promise of America’s Great Lower Tertiary Play by adopting a safer, more profitable dry tree approach.
Roy Shilling / Frontier Deepwater Appraisal Solutions LLC Chuck White / Frontier Deepwater Appraisal Solutions LLC Vamsee Achanta / Frontier Deepwater Appraisal Solutions LLC Paul Hyatt / Frontier Deepwater Appraisal Solutions LLC Terrance Ivers / Frontier Deepwater Appraisal Solutions LLC

Frontier Deepwater has published six World Oil articles in 2020, 2021 and 2022 that introduced the movable wellbay concept, Fig. 1. These articles covered the savings, value and environmental advantages provided by adopting a phased “dry tree” development with direct vertical reservoir access for Lower Tertiary reservoirs, rather than the risky and expensive hub-spoke subsea (“wet tree”) development schemes extrapolated from industry’s Miocene experience. 

Fig. 1. Five-slot movable wellbay fitted in a 6th-generation semisubmersible.

These articles are titled:    

  • “Innovative strategy increases profitability of ultra-deepwater fields” – February 2020 
  • “Assessing industry performance in America’s Great Lower Tertiary Play” – April 2021 
  • “Rediscovering the promise of America’s Great Lower Tertiary Play” – June 2021 
  • Understanding full life cycle performance of WET (Subsea) and DRY tree systems for big, complex reservoirs in ultra-deep waters (Parts 1, 2 and 3) – October 2022, November 2022 and December 2022. 

Lower Tertiary wells are the deepest, most complex, and highest-pressure wells in the Gulf of Mexico (GOM). High-pressure Paleogene reservoirs are in extreme water depths (4,000 to 10,000 ft) and exhibit mudline pressures that can exceed 15,000 psi. Wells drilled into these formations can reach total measured depths of up to 40,000 ft.  

Significant reservoir uncertainties, which stem from a lack of production history, and poor seismic imaging, due to overhanging salt canopies, have further challenged project sanction.  BSEE databases reveal that operators have, on average, drilled over 11 costly appraisal wellbores per prospect prior to project sanction. Except for Chevron’s expensive extended flow test on the Jack field, the appraisal wells have produced only static information from logs and cores. 

Operators need dynamic reservoir performance insights from production data required to accurately estimate reserves and de-risk full-field subsea development. Consider BP’s Kaskida as a prime example of the challenge. Discovered in 2006 with an estimated 4 Bbbl of oil in place, it has yet to be developed, in spite of its massive resource potential.

A phased field development, using dry tree tie-backs on permanently moored floating platforms, can greatly reduce the cost of profitable 1st phase peak production enough to justify its early sanction—thus, eliminating much challenging (and costly) appraisal drilling. When/if results from phase one justify it, a second phase can be sanctioned to complete full-field development. Total CAPEX and OPEX for this phased, full-field dry tree development will end up being billions of dollars less than an all-in-one, wet tree, subsea-hub option while generating billions of dollars more in gross and net revenues. 

The movable wellbay of a “Frontier Production System” (FrPS) can be the core of a purpose-built new semisubmersible or be retro-fitted to an existing 6th- or 7th-generation semisubmersible that is converted to become an FrPS. A production rate of 65,000 bopd from five dry tree wells on the FrPS easily justifies a first phase of development for massive Lower Tertiary reservoirs (Part 1, 2022).  The FrPS provides the operator with a robust Phase 1 dual-barrier completion system with direct reservoir access to gather dynamic flow information to better determine: 

  • Faulting and connectivity, 
  • Completion performance,   
  • Future well locations, 
  • Reservoir mapping and, hence, recoverable oil, and 
  • Future cost-effective full-field development options—while making a profit.   

Rather than the existing industry practice of 11+ expensive subsea appraisal wellbores, requiring many years and billions of dollars of sunk costs to justify full-field development, the relatively low cost of a Phase I with five dry tree wells on an FrPS means that fewer appraisal wells are required for its sanction, saving billions of dollars and significantly accelerating full field development (see 2020 article).   

The FrPS allows operators to profitably move forward with fewer appraisal wells to obtain dynamic reservoir information more quickly—even at oil prices below $50/bbl. The total installed cost of the Phase 1 FrPS is substantially less than half that of a new full-field subsea-hub development, so first oil can be accelerated by several years.  The second development phase can include subsea tie-backs or even another FrPS to maximize resource recovery.  An interesting variant could have just minimal topsides production facilities on the FrPS with tie-back to a nearby production facility (e.g., a “wellhead FrPS,” combined with an FPSO). 

As clarified in these most recent World Oil articles, the benefits of two FrPS units (five wells, each), compared to 10 wells in a 20-Ksi subsea-hub development, include: 

  • Savings of at least $1 billion and five years spent on reservoir appraisal (Part 2) 
  • Savings of $2.5+ billion on the facilities, SURF, and initial drilling and completion (Parts 1 and 2) 
  • $10+ billion LESS spent on MODU operations over the life of the project (Part 3) 
  • $6+ billion MORE in oil revenue, realized over the core years of production (assuming $60/bbl, Part 3) 

These are HUGE financial incentives that can reinvigorate profitable exploitation of the massive Lower Tertiary resource, while at the same time providing a measured phased development approach that minimizes operator risk. 


As reviewed in our 2021 articles, about half of the publicized 40-Bbbl resource in the high-pressure (HP) Lower Tertiary Wilcox trend has been discovered. Yet, only a small fraction of the “oil in place” (OIP) for the few discoveries actually developed is now being reported as recoverable. None of the efforts to develop Wilcox reservoirs with subsea schemes has successfully unlocked full life-cycle economics. The numerous high-cost wellbores drilled by the world’s most sophisticated and expensive MODUs (as detailed in Table 1), combined with generally poor performance and maintenance of their costly subsea completion and tie-back systems (SURF) have rendered these once-promising discoveries commercial disappointments. 

The biggest reasons for the high cost (and lack of profitability) are revealed by closely examining Table 1 and Table 2 together.  Table 1 shows the surprising number of wells and sidetracks required by lengthy full-field appraisal and development programs, as well as the very long drilling and completion times for each of these wells. Table 2 clarifies why the subsea drilling and completion (and tie-back) systems at these fields have high pressure ratings, typically 15 Ksi and, in some cases, mudline shut-in pressures are close to, or may exceed, 15 Ksi, so that operators have selected 20-Ksi subsea development systems.   

At the end of 2019, Chevron announced its Anchor prospect was sanctioned at ~$5.7 billion as a “20-Ksi field” with high-cost, “Serial #1” 20-Ksi equipment and a dedicated 20-Ksi DP MODU, resulting in a field “fully loaded” drilling and completion day rate that will noticeably exceed what industry has been paying for 15-Ksi fleet MODU’s for Miocene developments. 

The calculated, maximum, dry tree, surface shut-in pressure shown in Table 2 reveals one distinct advantage of using the FrPS approach for the water depth at most of the HP Lower Tertiary Wilcox discoveries. The maximum shut-in pressure at the surface is actually less than 15 Ksi. This means that much-less-expensive, existing surface equipment can be used, eliminating the need for costly and risky 20K subsea equipment and rigs.  


Figure 2 provides further insight into why vertical surface access makes more sense for the Wilcox.  As shown in Table 1, Lower Tertiary development project economics are controlled by subsea drilling and completion times. These costs are dominated by the Well Systems (MODU drilling & completions) and SURF equipment, not the semisubmersible production facility.  Focusing on reducing this 71% slice of the cost pie clearly makes the most sense. This can best be achieved by implementing a phased dry tree solution with an innovative tool, such as the FrPS. 


A key feature of the FrPS design is that the production riser system has the same apparent weight to the riser tensioners over a wide range of water depths. This is achieved by using external buoyancy, much like what is used on MODU drilling risers. This results in a large amount of the riser weight for these heavy riser systems being carried by the installed buoyancy. In turn, this results in the ability to use the same top tensioner system over a larger number of operator prospects, allowing potential for relocation and reuse. 

To establish technical viability, Frontier has performed time domain analysis for a converted 6th generation Freide & Goldman ExG semisubmersible in 6,000 ft of water, with a total 40-ft stroke and leading marine analysis software, Orcaflex, under100-year and 1,000-year Gulf of Mexico hurricane conditions. Since the ExG is not a deep-draft, low-heave semisubmersible design, analysis indicates that the risers will contact the up-and-down stops during maximum heave.  

Still, maximum stresses are less than 80% of yield, and the risers only stretch about 5 ft. It is important to remember that all top-tensioned risers are stretched several feet when they are installed and tensioned up for operations. A simple, static elastic-stretch calculation demonstrates that the FrPS riser can stretch by more than 20 ft in 6,000-ft waters before it reaches yield. Therefore, with proper riser/wellbay/rig interface design, an existing 6th generation conversion is feasible.   

Adopting a deep-draft, low-heave, purpose-built semisubmersible may avoid what is clearly acceptable amounts of “riser stretching” for premium high-strength riser strings. However, the unit will end up being larger, as the columns of a low-heave semisubmersible must be made tall enough to limit concerns about wave impacts on the deck structure.   

A further advantage of the movable wellbay is that it allows the drilling rig/derrick to be secured relatively low into the deck structure of the platform. This compares to a towering skid base structure that moves around on the very top deck, as has been done on most spars and tension-leg platforms (TLPs) in the past. Having the drilling rig secured centrally and much lower (as is typical for semisub MODUs), significantly reduces platform accelerations during survival events, thereby reducing deck/vessel structural steel and mooring requirements. For a spar with a big drilling rig located high on the platform (200+ ft above the waterline), the pitching accelerations in extreme events become a significant cost driver. 

It should be noted that spars have been evaluated for this application but were found to be unsuitable, due to the size of the topsides payload. The big drilling rig required for Lower Tertiary wells, combined with just minimal production facilities, forces a spar to be sized larger than bp’s massive Holstein spar platform in the GOM. 

The dual-barrier production riser configuration provides orders of magnitude more safety and reliability, compared to the subsea systems currently being used to develop the Lower Tertiary.  Not only does the system use existing technology at much lower cost, it also provides: 

  • Surface BOP with direct hydraulic controls 
  • Access for ease of inspection and maintence of surface BOP and trees 
  • More reliable well control, as a result of direct hydraulic control and elimination of “loss of station” events, due to Dynamic-Positioning failures 
  • With risers rated for full pressure, kicks can be bullheaded directly into the formation if needed, and 
  • By eliminating the 6,000 ft of unrated pressure drilling riser above a subsea BOP and having a fully rated wellbore to the surface BOP, the Macondo scenario is eliminated 
  • Direct vertical access from rig onboard the FrPS, so that completions can be much simpler, with well maintainance, surveillance, and re-completions made much less costly and much more robust 
  • Easier, more effective ability to implement artifical lift. including downhole ESP’s 
  • Historically and, as noted in our 2022 World Oil articles, significantly more oil is recovered, due to the increased efficiency of low-cost vertical reservoir access. This is especially important for Lower Tertiary reservoir development with: 
  • Very long pay zones with alternating shale and sand intervals that require zone isolation 
  • Potential need for sand control with associated maintainance requirements 
  • Somewhat poorer reservoir fluid properties that may require more tubing clean-outs and downhole maintainance 
  • More recompletion requirements, due to all of the above. 


All of these advantages mean much more oil at much lower cost and a much less risky, more sustainable project. Part 2 of our 2022 article goes through the results of a 30-year advanced operations simulation of drilling, completion and production in more detail, comparing a 10-well subsea-hub development to a phased concept having two FrPS units supporting five dry tree wells, each. The statistical modelling covered: 

  • A 100-year time history of winds, wave and loop currents at a known block in the GoM 
  • These time histories are generated from hindcast data and GEM loop current models, and can be performed for any operator’s block of interest in the Lower Tertiary 
  • Downtime and efficiencies associated with MODU mobilizations  
  • BOP failures and repair 
  • Downtime associated with wind, wave and currents 
  • Downtime associated with hurricane abandonment 
  • Downtime associated with NPT of drilling and completion tasks,\ 
  • Downtime associated with: 
  • Tubing cleanout operations 
  • Production logging 
  • Acid stimulation 
  • Sidetracks and re-drills.  

The FrPS with a movable wellbay was shown to recover 31% more reserves, as compared to the analogous WET tree subsea/hub scheme within 20 years after start of production at much lower cost. Figure 3 shows the mean of the monthly average production rate from the operational simulation. For the FrPS case, there are four distinct peaks, corresponding to completing all wells at each drill center and, later, sidetrack/recompletion of the wells.  

Fig. 3. Comparison of simulated Lower Tertiary production profiles.

Production for each FrPS never exceeds 65,000 bopd (at the assumed initial rate of 15,000 bopd per well and using decline curves based on actual Lower Tertiary production from the BSEE database). With two FrPS’s installed, the combined maximum production rate is less than 90,000 bopd. For the subsea case, there are no such distinct peaks, and peak production occurs much later at a much lower rate. The production rate for the subsea-hub scenario remains suppressed, due to the inability of the single dedicated 20K MODU to keep up with the drilling, completion and maintenance requests by the 10 wells (see Parts 1 through 3, published in 2022).   

Figure 4 shows the resulting comparative recovery, where the FrPS with the movable wellbay has achieved 109 MMbbl of additional oil recovery over the first 20 years of production (note production did not start until at least five years after FID). It should be highlighted that the recovery differential is based on operational efficiency only.  

Fig. 4. FrPS v. WET cumulative production at years 15 and 25.

While BOP reliability is modeled, the modeling does not reflect any difference in downhole equipment or SURF equipment reliability, compared to the simplicity of dry trees. Given the additional equipment and controls for high-pressure subsea developments, there are many more failure points in the SURF system that cannot be accessed as readily as the directly accessible surface and downhole equipment used for dry trees. If the subsea completion equipment and SURF reliability were to be modelled and included in the simulations, the recovery differential in favor of the FrPS can be expected to increase. 

Figure 5 shows one of the very interesting results that can only be revealed through a statistical 30-year full life cycle simulation. For a 10-well development, the 20K MODU ends up working a total of 9,374 days, as compared to just 6,560 days worked by both FrPS rigs (in total).  As described in detail in the November 2022 (Part 2) article, the subsea case with the MODU experiences: 

  • More operational activities taking longer 
  • More BOP repair downtime 
  • More mobilization/demobilization downtime 
  • More hurricane abandonment downtime 
  • More riser running and retrieval downtime 
  • Emits much more pollution, day after day. 
Fig. 5. Comparing cost of rig operations.


As clarified in Frontier’s most recent World Oil articles, the drawbacks of a 10 well 20 Ksi subsea-hub development versus 2 x FrPS units (5 wells each) include: 

  • At least $1 billion more and 5+ more years spent in appraisal (see Part 2 article) 
  • At least $2.5 billion in higher costs for the facilities, SURF, and initial drilling and completion (Parts 1 and 2 articles ) 
  • At least $10 billion more spent on MODU operating time over the life of the project (Part 3 article) 
  • At least $6 billion less in oil revenue over the core years of production, assuming $60/bbl (Part 3 article) 
  • The deficiencies of the subsea option in recovery and revenue would appear even more pronounced, if SURF reliability versus dry tree reliability were to be modeled due to:  
  • Some of the subsea interventions and future sidetracks not ever even being attempted, due to high costs and poor economics. 
  • The ability of the FrPS to accomplish more sidetracks and interventions than allowed by the “logic / rules” imposed for the simulation. 
  • Enhanced oil recovery methods (like downhole lift systems) being more efficiently implemented with surface access trees. 
  • Dry trees providing better access and zone isolation to allow adoption of simpler completions. 

The ability of the FrPS riser system to be flexibly deployed over a wide range of water depths can mean a reduction in front-end engineering on future projects by using standardization on both the semisubmersible and the production riser system. This has the potential to improve future project delivery timelines and economics. 

One of the other advantages brought to light in Frontier’s 2022 study is the opportunity to dramatically reduce greenhouse gas emissions by eliminating years and years of operations by a DP MODU and other surface vessels needed to support the wells and maintain the SURF equipment, long term. For a purpose-built FrPS, all electric power and further automation may be an option in the future to further reduce emissions with offshore operations that are more operator- and environmentally friendly. 

Operators are also aware that choosing subsea wells drilled by DP MODUs means that they are accepting an order of magnitude higher physical and environmental damage risk (e.g., as with Macondo), compared to fully rated, dual-barrier, dry tree surface systems with direct hydraulic controls on a permanently moored facility. In fact, a study for the Norwegian Offshore Directorate reported that, compared to moored platforms, DP MODUs are two orders of magnitude more likely to lose position control, resulting in damage to facilities. 

It is clear the industry needs to be deploying better concepts and new tools from its toolbox to develop reservoirs like those in the challenging, ultra-deepwater, high-pressure Lower Tertiary Wilcox play.   

New tool: “Yes!” What Frontier proposes is innovative, but there is no truly “new tech” in the FrPS concept. The riser systems have been fully qualified, and the wellbay is just an engineered truss structure that is fitted in the semisubmersible moonpool. The movable wellbay uses off-the- shelf riser tensioners and existing 15-Ksi (or 20-Ksi) surface equipment. The innovation lies in the configuration, itself, that can be reliably designed and analyzed with current industry technology. 

About the Authors
Roy Shilling
Frontier Deepwater Appraisal Solutions LLC
Roy Shilling is president of Frontier Deepwater Appraisal Solutions, LLC with over 40 years of deepwater development experience at BP America, including assignments as the delivery manager for GOM HPHT floating systems, risers and topsides. He was a key leader on BP’s Project 20KTM and also worked on the Lower Tertiary project team. Mr. Shilling later worked extensively with Anadarko and Chevron on their 20K development efforts. He was an engineering or delivery manager on a number of BP’s deepwater projects including Horn Mountain, Holstein, Mad Dog, Thunderhorse and Atlantis. He has extensive drilling and completion experience and worked as a Senior Principal Drilling Engineer offshore on both jackups and floaters. During the BP Macondo incident, Mr. Shilling patented the first freestanding riser subsea containment system installed in 51 days and successfully operated with the Helix Producer I. In 2018, he received U.S. patents on the moveable wellbay, which can be installed on a converted or newbuild semisubmersible MODU to create a multi-well dry tree drilling and production system, targeted primarily as a Phase 1 development to de-risk and substantially reduce costs for Lower Tertiary discoveries. Frontier provides consulting services for deepwater projects worldwide. Mr. Shilling graduated with a BS degree in mechanical engineering from Vanderbilt University and earned an MS degree in ocean engineering from Texas A&M University.
Chuck White
Frontier Deepwater Appraisal Solutions LLC
Chuck White Frontier’s EVP and co-founder, is a naval architect (University of Michigan, 1975), who earned a master’s degree in mechanical engineering from University of Houston in 1983. He is a Fellow and past chairman of SNAME Texas. Mr. White worked for IOCs for 20+ years as a project manager and deepwater technology leader. Since 2000, he has worked primarily on technology development and deepwater and natural gas industry projects. He has led several large joint industry projects, as well as the API global task forces in writing the FPS and riser design RPs.  He also co-chaired creation of the first probabilistic riser design code. He holds multiple U.S. and international patents. 
Vamsee Achanta
Frontier Deepwater Appraisal Solutions LLC
Vamsee Achanta is Frontier's vice president of engineering and owner of AceEngineer. He is an upstream engineer with strong experience in the offshore sector. Mr. Achanta has 21 years of experience and holds a masters degree in mechanical engineering from Texas A&M (2003). His project experience spans facilities design, including SURF, moorings and floaters. Mr. Achanta specializes in data science O&G asset lifecycle automations from cradle to grave. 
Paul Hyatt
Frontier Deepwater Appraisal Solutions LLC
Paul Hyatt is Frontier’s vice president for drilling and completions and managing director of TD Solutions Pty Ltd. He is a wells specialist in all phases of well design and operations, from exploration to full-field development. His experience has stretched the globe for 43 years, including technical and project management roles in offshore, deep water, arctic operations, remote heli-rig exploration, HTHP completions, extended-reach design and installations, and decommissioning for various major operators and clients. Mr. Hyatt has a BS degree in petroleum engineering with honors from the University of Texas at Austin and is a life member of the Society of Petroleum Engineers. 
Terrance Ivers
Frontier Deepwater Appraisal Solutions LLC
Terrance Ivers is Frontier’s founding chairman. He launched his career at Brown & Root (later KBR), where he developed a comprehensive and extensive knowledge of the oil and gas industry during his 27 years with the company. He retired in 2004 as a KBR Officer and vice president of Global Offshore Engineering. From 2004 to 2007, Mr. Ivers served as the chief operating officer of Alliance Wood Group Engineering. During 2007 to 2011, he served as President of Amec Paragon, Inc., and was responsible for Amec Natural Resources Americas’ oil and gas operations. With Siemens from 2011 to 2013, Mr. Ivers served as the CEO of the Oil and Gas, Compression and Solutions Business Unit. From 2013 through 2015, he was a member of the executive leadership team of SNC-Lavalin’s Resources, Environment & Water group. As the executive vice president of that group, he was responsible for leading oil and gas regional centers and providing perspective on the company’s strategic vision, development and execution. Most recently (2016 through 2020), Mr. Ivers served as executive president of the Bilfinger North America Division and as a member of the divisional management board. He departed in 2020 after completing a one-year extension to his initial contract. He is a 1980 BSME graduate from UH. He is a registered professional engineer in the State of Texas.
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