December 2022

Understanding lifecycle performance of wet (subsea) and dry tree systems for large, complex reservoirs in ultra-deep water

This last article of a three-part series completes the full life cycle operations assessment, comparing a subsea (wet tree) hub-and-spoke scheme against a phased (two-step) approach using a dry tree concept to develop a complex reservoir in ultra-deep waters. This final article adds analyses of field appraisal and abandonment while reflecting on the ALARP and AHARP concepts.
Chuck White / Frontier Deepwater Appraisal Solutions LLC Roy Shilling / Frontier Deepwater Appraisal Solutions LLC Paul Hyatt / Frontier Deepwater Appraisal Solutions LLC William Brendling / BMT

Frontier Deepwater’s three World Oil articles in 2020 and 2021 introduced the savings and value created by adopting a phased dry tree development concept rather than a risky and expensive hub-spoke subsea (wet tree) development scheme extrapolated from industry’s Miocene experience. Frontier presented research that used public domain information from the Bureau of Safety and Environmental Enforcement’s (BSEE’s) Gulf of Mexico database to clarify how, and why, the industry’s efforts to exploit massive discoveries in the once-promising but deeply challenging Lower Tertiary Wilcox trend have failed commercially.

The first article in this current series (World Oil, October 2022) presented the method, modeling assumptions, and high-level results of operations simulations for a 10-well ultra-deepwater field development. The simulations were generated by BMT’s SLOOP software, using realistic system and metocean models to cover a 30-year project life. The results led to a somewhat surprising conclusion:

  • The dry tree option (using a phased approach, with five wells on each of two Frontier Production
    Systems, FrPS) provides at least $20 billion of higher net revenue because:
    • The dry tree field phased approach is expected to recover approximately 31% more of reserves from the modeled reservoir in the first 20 years of production, yielding >$10 billion more revenue (at $100/bbl) during that period, as compared to the analogous wet tree subsea/hub scheme.
    • While Frontier’s FrPS dry tree development is generating at least $10 billion more revenue, the wet/subsea tree scheme is spending almost $10 billion more on operations, because a costly, new, 20-Ksi Dynamically-Positioned (DP) MODU is required for all operations, once well completion begins.

The 2nd article strengthened the argument for using a permanently moored dry tree concept by presenting and discussing detailed performance statistics of the DP MODUs and platform rigs employed for well drilling, completion, tieback, maintenance, sidetracking and recompletion operations. Causes for delays to, and interruptions of, the necessary operations as impacting well downtime and field production were charted and clarified to support the shocking conclusion cited in Part 1.

Why is this study needed? On behalf of its citizens, the U.S. government already requires that operators document how their proposed offshore field development plans reflect the ALARP (as-low-as-reasonably-practical) principle with regard to hazards and risk management. BSEE is concerned with human and environmental hazards and risk, while the Bureau of Ocean Energy Management (BOEM) is charged with managing development of our nation’s offshore resources in an environmentally and economically responsible way.

This means that, in addition to having some environmental clout, BOEM must ensure that resources are being developed efficiently and effectively—thus, BOEM should only approve field development plans that also reflect the AHARP (as-high-as-reasonably-practical) principle regarding maximizing the value of the resources being exploited. ALARP and AHARP principles are the twin foundations of a more sustainable offshore oil and gas industry.

Frontier has published clear evidence that operators are not adopting ALARP or AHARP principles for many of the largest ultra-deepwater field developments in the Gulf of Mexico. Frontier’s previously published case studies used publicly available data and quality decision-making analysis to expose poor performance of these complex major projects that depend on subsea production systems. Our recent study reinforces the argument for adopting a low-cost dry tree option by performing detailed “event domain” simulations of offshore operations to examine differences in financial and environmental impact.

As the U.S. government tightens its oversight with increasing emphasis on carbon footprint, field development plans that do not reflect both of these “reasonably practical” principles will, and should, face strong headwinds. The good news is that Frontier’s dry tree concepts pose significantly less environmental impact/risk and are much more fiscally prudent.

While our case studies and articles highlight the U.S. Gulf of Mexico’s deep waters, the permanently moored dry tree drilling and production facility technology introduced by Frontier has global applicability. The opportunity to provide “green power” to such a facility for all operations is a giant step away from dynamically-positioned mobile offshore drilling units (DP MODUs) and service vessels that burn thousands of gallons of diesel every day. So, environmentally responsible nations and operators with reservoirs in very deep waters can be glad that a much less costly and greener field development option exists.


Appraisal programs. It is not necessary to simulate the appraisal drilling programs to establish a meaningful comparison between the wet tree (subsea) and dry tree options. Data from the U.S. government (presented in our 2021 World Oil articles) provides clear insights into what has actually been reported.

Our investigation of “asset exploitation” starts with the first appraisal wells. Frontier’s research has found that, on average, the ultra-deep high-pressure Wilcox fields sanctioned for development have required approximately 11.4 wellbores, each. For comparison, Kaskida and N. Platte (now called Sparta), which through 2020 were still awaiting sanction, had already sunk 12 and 11 bores, respectively. Shenandoah had 15 appraisal wellbores. Averaging about 200 drilling days/well, the Wilcox field operators have been sinking about $2.3 billion (per field) into technology development and appraisal programs lasting many years. Of course, TotalEnergies shocked the industry and their partner, Equinor, when they announced they were giving up their interests in N. Platte at the beginning of 2022 after so many years of effort and expense.

Due to the relatively low cost of the dry tree wells and each platform, Frontier’s phased approach to exploitation of major discoveries requires only two appraisal wells with sidetracks (i.e., 4 reservoir penetrations) prior to sanctioning the first FrPS (a 5-well dry tree drilling/production unit). So, the current approach taken by operators typically involves at least seven more appraisal holes, meaning their appraisal programs have cost $1.7 billion more on average.

Frontier has already documented how sanctioned field development plans for the ultra-deepwater high-pressure (HP) Wilcox have not provided a positive ROI, once the cost of appraisal programs is included in full asset life economics. Even more importantly to the theme of the current study, the average appraisal program puts people and the environment at risk during the additional 2,000 days of drilling operations. For some portions of the drilling activities (especially the deeper horizons), the risks are extremely high.

To avoid wasting so much money and resources, it seems a fundamental change in mindset is required. The negative aspects of more than five years of additional drilling time are amplified when considering the day-to-day pollution of the DP MODUs and support vessels involved, in addition to the much higher risk for loss of well control from DP MODUs with HP subsea BOPs. The DP MODU, alone, consumes around 13,000 gal/day of diesel, exhausting over 100,000,000 lb of CO2 per year. Exhaust from DP support vessels significantly increases the total pollution from offshore operations, once development begins. This information is summarized in Table 1.


Field abandonment. It is also not necessary for us to simulate the field abandonment programs to understand important differences between the two options. The following lists highlight the main actions needed to abandon the field for each of the competing field development concepts, clearly indicating the increased activity required for abandoning the hub/subsea system.

  • Dry tree case (FrPS development)
    • Each well is entered and plugged for permanent abandonment (according to U.S. government and company requirements), using the rig on each of the two FrPS units.
      • If recovery of tubing joints is required, they are transported to shore by workboats for recycling.
    • All ten direct well access risers (buoyancy supported TTRs) and mudline wellhead connections are retrieved by the FrPS rigs.
      • Recovered components are transported to shore for recycling or reuse (depending on condition).
    • If required by BSEE, all ten wellheads are cut below mudline and retrieved by the FrPS rigs, but in ultra-deep waters, wellhead removal has not been required.
      • Recovered components are transported to shore for recycling.
      • If wellhead removal is not required, then protective caps are set to allow emergency reentry.
    • The two sets of flexible pipe export risers are recovered by a DP service vessel and transported to shore for disposal.
    • Mooring lines for the two FrPS units are cut at the anchors and retrieved by workboats.
      • Recovered components are transported to shore for recycling or reuse (depending on condition).
    • The two FrPS units are towed to shore, where they can be prepared for redeployment or disposal.

  •   Wet tree case (Hub/subsea development, assuming vertical monobore 20 Ksi trees like the FMC/One Subsea tree engineered and approved for Chevron’s Anchor field).

    • The 20 Ksi DP MODU (or a 15 Ksi rig) recovers the subsea tree (and tubing head), pulls tubing as required, plugs back and removes the subsea wellhead from each well for permanent abandonment (if required).

[See details of these operations following the estimated time required for completing abandonment of each well.]

      • The DP MODU is released from service at this field after all 10 wells are safely abandoned.
    • A DP service vessel recovers subsea manifolds, flowlines and controls at each well site.
      • Recovered components are transported to shore for recycling or reuse (depending on condition).
    • Flexible pipe tieback flowline risers and umbilicals are recovered by a DP service vessel and transported to shore for disposal.
    • Flexible pipe export risers are recovered by a DP service vessel and transported to shore for disposal.
    • Mooring lines for the hub FPS are cut at the anchors and retrieved by workboats.
      • Recovered components are transported to shore for recycling or reuse (depending on condition).
    • The hub FPS is towed to shore where it can be prepared for redeployment or disposal.

It is assumed that abandoned pipelines and flowlines on the seafloor can remain in place after having been flushed clean of pollutants. Pipelines and flowlines (and flexible pipe risers) will have been flushed clean by the production platforms (FrPS units and hub FPS) early in the abandonment process.

Since the FrPS units are permanently connected to the wells they are flowing, the time to permanently P&A each dry tree well is about 22 days. By comparison, the time to permanently P&A each wet tree well is approximately 37 days, because each wet tree well abandonment requires the following tasks:

  • Mobilize DP MODU into position over the wellhead (with well test/bleed-off package placed onboard for hydrocarbon fluids management and flaring during well clean-up).
  • Run intervention riser, connect to the tree (and test), and set plugs to isolate the reservoir.
  • Remove the tree.
  • Run the drilling riser, connect to the tubing head and test BOP.
  • Pull isolating plugs.
  • Pick up workstring and displace with kill weight mud.
  • Cut and pull tubing, if required by BSEE.
  • Set multiple cement plugs to abandon well.
    • Let cement cure.
    • Test for successful cement plug (and await official confirmation of success).
  • Disconnect BOP and recover drilling riser/BOP.
  • Cut and recover subsea wellhead/conductor, if required by BSEE.
    • If wellhead removal is not required, then protective caps are set to allow emergency reentry.
  • Mobilize to the next subsea well.

[Note also that this entire process is subject to higher probabilities for delays, due to the complexity and metocean sensitivity of subsea well operations.]

Since the platform rig has ready access to the dry trees on the movable wellbay, it is easy to see that abandonment for the dry tree case involves fewer assets and will be completed more quickly than is possible for the WET Tree (hub/subsea) Case. With both FrPS units working in parallel, field abandonment can be completed in less than half a year (actually, less than 4 months to permanently abandon the wells).

For the WET Tree Case, DP units must position themselves and hold position over each well individually to permanently abandon them. In this case, a serial process can be expected to take about one year to fully abandon the field. It may be possible to have multiple high-capacity DP MODUs and service vessels mobilized to the field to perform the tasks in parallel to avoid hurricane season interruptions.

The DRY Tree / FrPS units offer additional advantages:

  • Unlike the DP MODU, each FrPS has production facilities onboard. So, it is not necessary to mobilize any additional equipment for handling hydrocarbons from wells during abandonment.
  • If one of the FrPS rigs is idle later in life, it may perform a second sidetrack/recompletion (if justified) or it may perform early well abandonment on a depleted well (while others continue to produce) and not wait until the field life end (cessation of production) and final field abandonment. This will save time when abandoning the field.

Since the dry tree field abandonment requires deployment of fewer assets and requires much less onsite working time for the assets involved, it is expected that the wet tree case field abandonment will cost much more. Further, the emissions generated by DP assets working to complete abandonment of the hub/subsea development will far exceed that of the dry tree option. Indeed, if the wet tree case is assumed to only require six months of additional work at the field for abandonment (a best-case scenario), the DP MODU, alone, will end up emitting approximately 30,000 mt more CO2 to the atmosphere.


In 2021, Frontier decided to perform what we called a “Green Ops Study” to investigate whether a dry tree field development would be more efficient and less polluting than the subsea wet tree hub-spoke field development schemes currently adopted and still favored by operators for deepwater fields in the U.S. Gulf of Mexico. As revealed in Part 1 of this series, we were a bit surprised that Frontier’s dry tree field development plan (using two FrPS platforms) should be expected to provide at least a $20 billion increase in net revenue to the asset owners Fig. 1.

Fig. 1. Comparison of simulated production profiles.
Fig. 1. Comparison of simulated production profiles.


The second article provided a deep dive into results of the SLOOP simulations covering 25 years of well operations, (Fig. 2 and Fig. 3) to clarify and support that conclusion while confirming the expected reductions in pollution. The significant increase in value does not fully reflect the difference in expected net present value that comes with full consideration of the time value of money or the big improvement in risk management. It also does not include the increase in expected ultimate recovery from the field that is provided by Frontier’s concepts for dry tree field development,Fig. 4.

Fig. 2. Mean total annual NPT per cause (core years).
Fig. 2. Mean total annual NPT per cause (core years).


Fig. 3. Mean well operations non-productive time—rig NPT (all causes).
Fig. 3. Mean well operations non-productive time—rig NPT (all causes).


Fig.4. Frontier’s core technology is the patented movable wellbay installed in place of the subsea drilling systems on a semisubmersible MODU. Outboard well positioned under rotary (a). Wellbay centered and locked for hurricane (b).
Fig.4. Frontier’s core technology is the patented movable wellbay installed in place of the subsea drilling systems on a semisubmersible MODU. Outboard well positioned under rotary (a). Wellbay centered and locked for hurricane (b).


By including consideration of appraisal and abandonment, this study has documented how much more pollution can be expected over the full life cycle when an operator adopts a wet tree subsea hub-spoke field development scheme instead of the staged dry tree option proposed by Frontier. Further, because operators are not practicing the ALARP and AHARP foundations of sustainable development, billions of barrels of discovered oil in the Lower Tertiary Wilcox are being left behind. These valuable resources will remain stranded unless corporate leadership and government commit to adopt safer, more efficient, more profitable, and greener dry tree concepts. WO

About the Authors
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. 
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.
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. 
William Brendling
William Brendling WILLIAM BRENDLING has a PhD in Applied Mathematics and is a Fellow of the Institute of Mathematics and its Application. He has been employed by BMT or predecessor companies for 40+ years. During that time, he has worked on many offshore projects looking at environmental loading and its impact on operational performance. Among other software projects, Dr. Brendling is the primary architect of BMT’s SLOOP software for quantitative simulation and assessment of the performance of offshore operations.
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