America’s promising Lower Tertiary frontier: Two decades, what has industry achieved—Part 1

ROY SHILLING, CHUCK WHITE, VAMSEE ACHANTA, PAUL HYATT and TERRANCE IVERS, Frontier Deepwater Appraisal Solutions LLC 

INTRODUCTION AND CONTEXT 

Since Frontier Deepwater’s first World Oil article in February 2020, the team has used public domain data, operational modeling, and event-domain simulations to explore actual resource recovery and economic performance versus FID commitments for the massive discoveries in the Lower Tertiary Wilcox trend. Each successive article in the seven-article series reinforced a rather distressing conclusion.  

To validate and extend those findings, the Frontier team conducted a new and extensive quantitative analysis, using the U.S. Bureau of Safety and Environmental Enforcement’s (BSEE) Offshore Data Center’s public database.¹ This dataset compiles production, well construction, and cost information across all known Lower Tertiary developments and discoveries, normalized using assumptions verified through current project data research. 

The Lower Tertiary is an enormous national asset—much larger than Prudhoe Bay—and it deserves a development approach that can fully unlock its potential. Frontier Deepwater’s research conclusively reveals that industry’s reliance on costly ultra-high pressure subsea hub-and-spoke systems has locked these once-promising resources into uneconomic, technically constrained developments. In contrast, development architectures that preserve direct, repeatable reservoir access—such as dry-tree systems—have demonstrated materially higher recovery and stronger long-term economics. The question raised by this analysis is not whether the Lower Tertiary reservoirs are commercially viable—they are—but whether the development architecture selected over the past two decades has structurally constrained their performance. 

This three-part series argues that the core issue is not geology, drilling capability, or pressure rating. It is system architecture—specifically, the degree to which development concepts preserve direct, repeatable reservoir access over multi-decade field lives. 

The Frontier Production System (FrPS), examined in detail in Parts 2 and 3, was conceived from this perspective. Its defining feature is the Movable Wellbay™, which allows full dry-tree access to each well without requiring the hull to carry high riser top-tension loads. By combining free-standing buoyancy-supported risers with an extended-draft semisubmersible, the system decouples riser loads from hull sizing and removes water depth as the primary driver of host escalation. 

This architectural shift matters, because it reframes the development challenge. Instead of asking how to scale subsea systems to ever-higher pressures and depths, the question becomes how to standardize a host platform while preserving continuous reservoir access. The Movable Wellbay™ allows wells to be indexed beneath a fixed drilling system, maintaining direct intervention capability throughout field life while avoiding the structural penalties traditionally associated with dry-tree systems in ultra-deepwater.

Table 1

The analysis that follows, documents where current Lower Tertiary developments stand—and why a different architectural path is required. Parts 2 and 3 in upcoming months will then demonstrate how a standardized, scalable dry-tree architecture can convert reservoir size into recovery—and recovery into durable capital efficiency. 

INDUSTRY PERFORMANCE SNAPSHOT (BSEE-BASED SUMMARY)

Tables 1 and 2 show the results of the analysis by incorporating the actual monthly WTI oil price history from 2009 through 2024, to generate time-weighted revenues, with all costs obtained from project research and normalized using inflation-adjusted indices. Production, drilling and completion data were compiled directly from BSEE WAR and OGOR-A databases.¹ To date, more than 20,000 rig days and over $20 billion have been spent on MODU drilling and completions across the Wilcox trend, with billions in losses already written off.   

Table 2

Looking ahead, recent activity at Shenandoah illustrates how value is increasingly being harvested through late-cycle acquisitions and selective exploitation, rather than full resource development. Shenandoah was discovered by Anadarko in 2008 and later transferred through the Anadarko–Oxy transaction before being acquired and advanced by Beacon. By the time these assets reach smaller independents, they often carry the benefit of years of appraisal, subsurface interpretation, and regional learning funded by the original major operators.  

The subsequent development strategy is typically a disciplined, limited-phase “sweet spot” program designed to meet near-term financial hurdles and demonstrate cash-flow durability—often leaving substantial in-place volumes undeveloped. Similar patterns can be seen in LLOG’s Salamanca acquisition and the subsequent development of Repsol’s Castillo and Leon fields: the operator’s success is measured less by ultimate recovery than by efficient monetization of the most economic portion of the reservoir, frequently with an eye toward an eventual corporate transaction—as illustrated by Harbour Energy’s $3.2 billion acquisition of LLOG (announced Dec. 22, 2025; completed Feb. 11, 2026). 

One should note that the costs in Table 1 exclude the billions spent by industry to develop and qualify 20K technology over the past 20 years. 

APPROACH VALIDATION AND SIGNIFICANCE 

Project assessments have considered all the production, well construction, and cost information to determine the performance. 

Methodology validation. The BSEE dataset confirms the findings from Frontier’s earlier modeling and BMT lifecycle simulations.² While prior analyses relied on operator disclosures and performance modeling, this public record substantiates those results with actual production and cost data, Table 3.  

Recovery factor interpretation. Industry “recovery factor” values usually reference the recoverable resource base, not the total stock-tank oil initially in place (STOIIP). This practice hides the true performance gap of the project and the associated subsea systems. BSEE data show that existing Lower Tertiary subsea projects—Jack/St. Malo, Julia, Stones and Cascade–Chinook—have recovered only 1% to 10% of total oil in place, on average much less than half of what the operator projected at sanction, Table 4. 

Table 4

The fundamental limitation lies in the subsea development model itself, which targets only a small “recoverable” core of the reservoir and then loses access to the remaining hydrocarbons, once initial wells water out or decline. High-cost sidetracks and recompletions—routine on surface-accessible systems—are simply uneconomic when wells are subsea. Julia illustrates the problem clearly: while ExxonMobil originally cited roughly 6 Bbbl of oil in place, the sanctioned development targeted only 1 Bbbl recoverable. After more than nine years onstream, cumulative production totals just 71 MMbbl—barely 7% of the sanctioned recovery and less than 1% of the original stock tank oil in place, once touted by the industry. 

By contrast, dry-tree systems such as Mars, Ursa, Mad Dog and Horn Mountain routinely achieve 30% to 40% recovery, largely through sidetracks and recompletions that can be performed efficiently from onboard drilling facilities.  BSEE production data confirm that over half of total field recovery from those TLP and Spar developments comes from such secondary interventions—an advantage that subsea projects simply do not exhibit. 

Systemic implications. Subsea developments exclude a huge amount of potential value because intervention costs—often exceeding $100 million per well—prevent recovery optimization. Operators are forced to accept limited, declining recovery, due to their inability to economically remediate, sidetrack or recomplete wells. Subsea systems are more applicable for homogeneous sand body reservoirs and smaller field tie-backs.  Their application to the complex multi-zone reservoirs of the Lower Tertiary seems to be more a project delivery decision than an informed reservoir asset value optimization decision.   

In contrast, dry-tree systems sustain higher recovery by allowing simpler surveillance, intervention and maintenance directly from the host facility. Applying a dry-tree configuration can raise recovery from less than 10% to more than 35% of STOIIP—a three-fold improvement worth hundreds of millions of barrels and tens of billions of dollars across the Lower Tertiary.

Fig. 1.  Example subsea completion zone perforations.

IMPACT ON FIELD PRODUCTION AND PROFITABILITY  

The aggregated BSEE dataset reveals a clear pattern: despite more than $50 billion invested, economic performance is truly disappointing. Only Jack/St. Malo has achieved a positive cumulative cash flow that still results in a negative Net Present Value (NPV) for its investors at a 10% discount rate. The real problem is not geology but the development scheme and system architecture.  BSEE data showed: 

• System Inefficiency: Subsea wells have averaged only 67% uptime, with just 25% to 30% of logged hydrocarbon zones perforated, Fig. 1. 

• Operational inflexibility: Workovers and recompletions that routinely boost output in dry-tree systems are rarely performed subsea, due to very high intervention costs. Many zones go unproduced, due to cost-prohibitive recompletions.  

• Historical challenge: On Cascade–Chinook, wells with failed safety valves were left idle for years, as the cost of MODU intervention outweighed the production benefit. Similar inefficiencies now plague most of the subsea systems on the complex, high-pressure Lower Tertiary Wilcox play, compounding downtime and reducing recovery. 

Case study—bp’s Kaskida and Tiber: Project delivery over maximizing recovery. bp’s decision to proceed with hub-subsea developments at Kaskida and Tiber—together representing over 6 Bbbl of oil in place—illustrates how corporate and regulatory incentives have kept the 20,000-psi subsea model alive, despite persistent economic disappointment. 

After the 2006–2009 discoveries, bp created Project 20K as the industry’s next frontier—an initiative to design and qualify 20,000-psi subsea hardware instead of critically assessing which development architecture best suited the reservoir. bp’s launch of this initiative effectively delayed field development for more than a decade, since at the time, 15K dry tree equipment was available and could be used at Kaskida. Over the following decade, industry spent more than a billion dollars on equipment qualifications and endured years of delay. The program ultimately achieved two outcomes: 

• It validated the new high-pressure hardware; 
• It enabled bp to secure BSEE-granted lease extensions without drilling up to two additional—and very costly—appraisal wells per year. 

That move saved more than a billion dollars in appraisal costs but also locked the company into an architecture that data now show delivers poor recovery and weak economics. 

With BSEE no longer granting lease extensions, bp and its partners found themselves at a crossroads, once Chevron successfully qualified the industry’s first 20,000-psi subsea system at Anchor field. Results from Jack/St. Malo, Julia and Stones had already dampened enthusiasm for these Wilcox plays, leaving few interested buyers and narrowing bp’s strategic options to two unappealing paths: 

• Abandon the discoveries: Relinquishing the leases and removing booked reserves. This would have been a severe blow to corporate credibility after years of promoting Project 20K as the future of deepwater development. Such a reversal would likely have forced a major reserve write-down, shaken investor confidence, depressed share value, and increased the company’s vulnerability to takeover. 

• Proceed with development: Using the 20K subsea concept already qualified under Project 20K, despite clearly negative economics. 

bp chose the latter—preserving its booked reserves, leases and independence, but committing itself to a massive, high-risk investment with little prospect of profitability, while likely taking more than 20+ years from discovery to first oil. 

These repeated decisions lay bare a fundamental flaw in the industry’s incentive system. Reserves reported to investors are based on “technically recoverable volumes”—a number that is dependent on the selected development technology and not total oil in place. With the hub-subsea schemes being adopted for the Lower Tertiary, those “recoverable” figures represent only a few percent of the actual resource; however, they are treated as if they reflect genuine commercial reserves.  

The result is a cycle where operators defend paper reserves to satisfy regulators and markets—even when the underlying development plan destroys value.  In short, bp’s choice was not about maximizing recovery or asset value; it was about maintaining alignment within a corporate and regulatory structure that rewards compliance over results that truly benefit investors. 

The Kaskida and Tiber announcements, therefore, underscore a key takeaway: the industry continues to commit billions to a subsea paradigm that has consistently undermined value, while dry-tree solutions remain the only architecture capable of delivering commercial recovery in this reservoir class. 

SUMMARY AND CONCLUSIONS 

Two decades of BSEE data leave no doubt: the Lower Tertiary’s poor performance is self-inflicted by an industry that has ignored the means for maximizing profitability and recovery of a critical American resource. Excessive appraisal, long timelines, limited well access, and high downtime define the subsea paradigm. Despite more than $50 billion invested, these projects recover only a fraction of their resource potential and yield negative “true” NPVs (wherein actual total investment is tracked with write-downs and asset sales excluded). 

By contrast, dry-tree systems can achieve practical schedules, higher recovery, and sustained production through direct well access, low-cost intervention with inexpensive sidetracks and recompletions, as shown in the actual BSEE data from existing dry tree projects. The evidence supports an important conclusion—development architecture governs ultimate recovery. 

While industry has been willing to ignore the high risks and failing economics of hub-subsea schemes on the Lower Tertiary Wilcox play, it is time to recognize that surface access is the only economically viable path forward.   

The forthcoming Part 2 will explore options that bring logical evolutions of dry-tree efficiency into ultra-deepwater assets. This next-generation architecture directly addresses the inefficiencies quantified here, opening the path to enhanced resource recovery and commercial viability in the Lower Tertiary.  

REFERENCES 

1. BSEE (Bureau of Safety and Environmental Enforcement) Data Center [Online], U.S. Department of the Interior. Available at: https://www.data.bsee.gov[Accessed: December 2024]. 
2. Brendling, W., R. Shilling and C. White, “Performance of WET (Subsea) and DRY Tree Systems for Lower Tertiary Reservoirs in Ultra-Deep Gulf of Mexico Waters,” BMT (Official) report, Customer: Frontier Deepwater Appraisal Solutions LLC, Version 5, April 20, 2022. Available at: https://worldoil.com/magazine/2022/october-2022/features/lifecycle-performance-of-wet-subsea-and-dry-tree-systems-for-lower-tertiary-reservoirs-in-ultra-deepwater-gom/

ROY SHILLING is president of Frontier Deepwater Appraisal Solutions, LLC with over 40 years of deepwater development experience at bp America, including assignments as delivery manager for GOM HPHT floating systems, risers and topsides. He was a key leader on bp’s Project 20K^TM 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, 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’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 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 University (2003). His project experience spans facilities design, including SURF, moorings and floaters. Mr. Achanta specializes in data science and O&G asset lifecycle automations from cradle to grave.    

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 44 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 SPE.   

TERRANCE N. IVERS is Frontier’s founding chairman. He launched his career at Brown & Root (later KBR), where he developed a comprehensive knowledge of the oil and gas industry during his 27 years with the company. He retired in 2004 as a KBR officer and V.P. of Global Offshore Engineering. From 2004 to 2007, Mr. Ivers served as the COO 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 executive V.P. and a member of the executive leadership team of SNC-Lavalin’s Resources, Environment & Water group. 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 is a 1980 graduate of University of Houston, with a BS degree in mechanical engineering. He is a registered professional engineer in the State of Texas.