Enhancing Lower Tertiary recovery and profitability: The options – Part 2

OFFSHORE TECHNOLOGY 

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

INTRODUCTION AND CONTEXT 

The Lower Tertiary Wilcox trend in the U.S. Gulf of America/Mexico is one of the largest deepwater petroleum systems ever discovered, yet more than two decades after its first major discoveries, overall field recovery remains far below early expectations. Reservoirs are laterally extensive and rock quality—while variable---is sufficient to support long-term production. Yet recovery factors and capital efficiency have consistently fallen short of early expectations, Table 1. 

This article examines offshore development architectures suitable for the complex, high-pressure Lower Tertiary reservoirs and explains why development architecture—not reservoir quality or incremental subsea technology—ultimately governs reservoir access, recovery efficiency, and long-term economic performance. 

The Lower Tertiary trend emerged in the early 2000s as a transformative opportunity for U.S. offshore production. Early discoveries, such as Jack, St. Malo, Shenandoah, Kaskida, Tiber, and others, confirmed the presence of large, laterally continuous turbidite reservoirs at extreme depths and pressures. These discoveries coincided with major advances in deepwater drilling, floating platforms, and subsea production systems. 

Industry expectations were high. Many reservoirs appeared ideally suited for long-life developments capable of delivering substantial reserves over multiple decades. In practice, however, results have been uneven. Production rates have been lower than anticipated, recovery factors disappointing, and development costs—particularly drilling, completion, and well servicing—exceptionally high (and resistant to meaningful cost reduction). 

When compared to fields developed with surface-completed (“dry tree”) wells, even the best of the deepwater fields that depend entirely on subsea schemes end up leaving behind many millions of barrels. Many dry-tree developments in the deepwater Gulf of America/Mexico have achieved recovery factors in the >30–40% range, while early Lower Tertiary subsea developments appear to be trending closer to the low single digits, Table 1.   

Worldwide experience shows that direct and efficient well access provided by drilling facilities on the platform fundamentally changes the economics and effectiveness of long-term reservoir management. 

THE CENTRAL CHALLENGE: RESERVOIR ACCESS AND RECOVERY 

Lower Tertiary reservoirs differ fundamentally from many of the earlier large Miocene deepwater plays in the Gulf of America/Mexico. They are typically deeper, subsalt, laterally extensive, and stratigraphically complex, with long multi-layered pay intervals and pressure regimes that demand robust well construction and completion designs. Maximum anticipated pressures at the mudline can exceed 15,000 psi, and in some cases require 20,000-psi well systems. 

The disappointing performance of Lower Tertiary developments is often attributed to reservoir uncertainty, well complexity, or extreme pressures. While these challenges are real, they are not the dominant constraint. The fundamental constraint lies in the architectural choice of subsea wells.  Once wells are placed on the seafloor and tied back to distant facilities, the cost and complexity of production operations, flow assurance, intervention, and maintenance increase dramatically.  

Over time, this effectively locks the reservoir into the assumptions embedded in the initial development plan. When those assumptions prove incomplete—as they often do in complex subsalt reservoirs—the system lacks the flexibility required to adapt economically. In addition, subsea architecture introduces greater system complexity, with control systems, flow assurance challenges, and reliability considerations contributing to reduced operational performance with increased environmental and HSE risk. 

Despite these challenges, Lower Tertiary developments to date have relied primarily on hub-and-spoke subsea architectures. In these systems, wells are drilled and completed subsea by expensive, high-capacity state-of-the-art MODUs and tied back to a remote floating production host—typically a semisubmersible—through a distributed network of subsea infrastructure including flowlines, manifolds, chokes, valves, control umbilicals, pumps, and production risers. 

While subsea systems can reduce host platform size and simplify topside facilities, they do so by transferring much of the production system to the seafloor and substantially increase system complexity. The result is a geographically distributed network of subsea equipment, greatly expanding the number of components that must operate reliably for the system to perform, as intended. 

In contrast, dry-tree wells maintain direct access to the reservoir. The wellbore, completion equipment, and production tubing form a continuous dual-barrier system extending from the producing interval to the platform. Production control, monitoring, and intervention, therefore, occur directly through the wellbore, rather than through distributed and dispersed subsea infrastructure. 

As a result, subsea developments introduce significant operational constraints that often dominate long-term field performance, due to: 

• Layout complexity, flow-assurance challenges, and extremely high drilling / completion costs imposing practical limits on the number of wellbores per subsea hub.  
• Expensive intervention operations requiring mobilization of high-capability drilling rigs—often including specialized 20K MODUs. 
• Restricted reservoir surveillance and monitoring capability, as subsea wells cannot easily accommodate routine wireline logging, coiled tubing, or workover operations. 
• Reliability issues over extensive subsea infrastructure including flowlines, manifolds, umbilicals, pumps, and control systems. 

The result is a structural cap on recovery that cannot be overcome through incremental subsea system improvements alone. Once initial production declines, reservoir behavior deviates from expectations, or there are hardware failures, the costs and complexity of intervention typically render additional recovery uneconomic. 

The Lower Tertiary combines extreme well costs and reservoir uncertainty with the greatest value of intervention—precisely the conditions under which subsea architecture is least attractive over the long term, Table 2. 

DRY TREES AND THE CASE FOR DIRECT RESERVOIR ACCESS 

Dry-tree developments offer a fundamentally simpler development architecture. By placing wellheads and trees on the host platform, operators gain direct, continuous access to the reservoir throughout the life of the field. 

Deep water also provides an important well-design advantage for dry-tree systems. When wells are produced through a vertical tubing string extending from the seabed to the host facility, the hydrostatic column created by 5,000 to 10,000 ft of water depth reduces the shut-in pressure observed at the surface wellhead, relative to the pressure at the seabed. In many Lower Tertiary cases, a reservoir requiring 20K-rated subsea equipment at the seafloor may impose less than 15K pressure at a surface tree located thousands of feet above the seabed, allowing the use of conventional surface wellhead equipment. 

With direct access maintained by the host facility, dry-tree developments offer several operational advantages: 

• Continuous reservoir surveillance and rapid, low-cost well intervention 
   – Onboard wireline production logging and zone monitoring 
• Reduced flow assurance risk through dual-barrier insulated production risers that provide a direct, continuous vertical flow path from the reservoir. 
• Flexibility to re-complete zones or sidetrack wells using conventional, simpler drilling equipment. 
• Easier adaptation for secondary recovery options, such as downhole pumps or gas lift. 
• Much lower-cost sidetracks and recompletions by eliminating the need to schedule and mobilize high-capacity MODUs, instead of using the onboard platform drilling. 

Dry-tree systems also preserve greater flexibility in completion design over the life of a field.  Because wells remain accessible from the host facility, operators retain the ability to modify completion configurations, upgrade artificial-lift systems, and even deploy larger tubing strings as reservoir understanding evolve. 

Dry-tree developments have historically delivered recovery factors far exceeding those of subsea systems. In a Lower Tertiary analog examined in earlier Frontier studies,¹ recovery improvements exceeding 30% were demonstrated through operational simulation, solely by enabling sidetrack capability and continued well access.¹ These estimates did not include additional recovery gains from zonal management, production logging, water shutoff, or artificial lift, suggesting that ultimate recovery potential may be significantly higher than the 2% to 10% recovery observed in subsea developments documented in Part 1 of this series. 

Fig. 1. Floating production systems used in deepwater installations.

Despite these advantages, dry‑tree systems are not being deployed in the Lower Tertiary, due to perceived limitations related to water depth, such as riser tensioning load and host facility size. Contractor bias to continue selling more expensive and complex subsea hardware under established project delivery models also reinforces operators’ commitment to subsea development schemes. 

REVIEW OF HOST SYSTEM OPTIONS 

Several floating host concepts have been considered for Lower Tertiary developments, Fig. 1. Each has distinct strengths and limitations when assessed against the demands of deepwater, high‑pressure, and long‑life reservoirs. 

Spar platforms. Spars represent the most mature class of dry-tree platforms for ultra-deep U.S. waters and have demonstrated excellent performance where deployed. Their size and deep draft provides superior motion characteristics, making them well-suited for conventional top-tensioned production risers and continuous drilling and intervention operations.  

However, when applied to Lower Tertiary developments in deep water, spar systems face fundamental scaling challenges. Extreme well depths, high-pressure well systems, and the requirement to support a full-capability, high-capacity drilling rig—located high on the spar’s top deck—drive hull diameters and drafts to very large dimensions.  

As payload requirements increase to accommodate drilling, well systems and processing facilities, spar displacement begins to exceed the scale of installations, such as Holstein, pushing fabrication, transportation and installation toward the practical limits of industry infrastructure. Spar designs also offer limited flexibility for phased development or later reconfiguration once installed. While spars remain a technically sound dry-tree solution, their increasing size, cost and logistical complexity under Lower Tertiary conditions significantly reduce their economic attractiveness, relative to more modular alternatives. 

Tension-leg platforms (TLPs). In moderately deep waters, vertically restrained tension-leg platforms have historically provided excellent dry-tree performance, offering attractive motion characteristics and direct well access from the host. In locations with suitable water depths, TLPs have enabled efficient drilling, completion and intervention operations with relatively compact hulls for many years. 

However, beyond 4,500 ft of water depth which encompasses most Lower Tertiary target reservoirs—TLPs rapidly approach both technical and economic feasibility limits. At these depths, tendon systems become exceptionally long and heavy, making fabrication, transportation, and installation increasingly complex. Tendon tension and the loads of high-pressure production riser systems parasitically dominate platform displacement, driving much larger hulls, while installation tolerances tighten dramatically with depth, increasing execution risk and weather sensitivity.   

Chevron’s Big Foot project highlighted these challenges at 5,200 ft of water depth, where tendon installation complexity, schedule risk, and cost escalation became central drivers in that project’s well-documented problems. In addition to installation concerns, increasing water depth exacerbates dynamic response issues inherent to TLP systems. Tendon axial stiffness, platform natural periods, and coupled platform–tendon resonance effects become increasingly difficult to manage, as tendon length increases, driving higher fatigue damage accumulation and more restrictive design margins.  

As a result, while TLPs remain technically sound within a constrained depth envelope, they should not be considered a viable solution for most Lower Tertiary developments, where water depths extend beyond practical system limits. 

Large floating hulls and buoy-type concepts. Very large barge and buoy-type concepts have occasionally been proposed as potential dry-tree hosts, due to their size. While such platforms can provide acceptable motion performance in milder metocean environments, their applicability in U.S. Gulf conditions remains uncertain.

Supporting dry-tree wells on these structures introduces many of the same challenges encountered with spars and TLPs. Conventional top-tensioned riser systems impose large vertical loads that require either extremely large hulls or complex tensioning systems, pushing fabrication, transportation and installation toward practical limits. Some buoy-type concepts incorporate significant internal oil storage; however, this capability is generally unnecessary in the Gulf of America/Mexico, where extensive pipeline infrastructure already exists. As a result, these concepts do not provide economically compelling solutions for Lower Tertiary developments when conventional dry-tree riser systems are employed. 

Semisubmersibles and deep-draft semisubmersibles. Semisubmersible production platforms have become the preferred host for many recent Gulf of America/Mexico deepwater developments, due to their favorable motion characteristics, fabrication familiarity, and flexibility in topside integration. Over time, industry designs have evolved toward increasingly simplified platform configurations that minimize hull steel, reduce fabrication complexity, and lower capital cost, facilitated by a deliberate shift away from onboard drilling and intervention capability. 

Deep-draft semisubmersible (DDS) and extended-draft semisubmersible (E-DS) designs have been developed to improve motion response, so dry trees might gain consideration.  Despite these refinements and units being deployed internationally, no semisubmersible units installed in the U.S. Gulf of America/Mexico have supported dry-tree wells.  

They have historically been viewed as impractical hosts for dry trees because their relatively large wave-induced motions were assumed to require complex long-stroke riser tensioning systems. In deep water, the combination of long-stroke tensioning requirements and heavy, high-pressure riser payloads reinforces the perception that adapting semisubmersibles for dry-tree service would drive excessive hull scaling and cost.  

As a result, semisubmersibles have remained coupled to subsea well systems, inheriting the associated limitations on reservoir access, monitoring and intervention. Shenandoah represents the most recent example of this evolution in the U.S., utilizing an extended-draft semisubmersible configuration to enhance motion performance while retaining a subsea well architecture.  

Extended-draft semisubmersibles do improve motion performance, achieving responses comparable to spars. However, improved motion performance has not been perceived to resolve the fundamental challenge posed by high-pressure riser loads and stroke, which continue to impact hull size, displacement, and structural complexity. The unresolved challenge, therefore, remains clear: how to retain the operational advantages of dry-tree wells without forcing host platforms to scale with increasing water depth and riser loads. 

Fig. 2. Movable wellbay on dry tree E-DS (the FrPS by Frontier Deepwater).

The gamechanger is combining improved platform motions with the removal of dry tree loads from the floating structure altogether. In a floating dry-tree production system employing free-standing risers, the platform no longer provides buoyancy or tension for the risers. Instead, the platform’s role is limited to supporting drilling, completion and processing facilities. By decoupling top tension riser loads from the platform, this architecture enables a standardized HOST semisubmersible design that can be deployed across a wide range of water depths with minimal, if any, modification.   

This principle forms the foundation of the Frontier Production System (FrPS), in which production risers are structurally self-supporting and the Movable Wellbay™ functions primarily as a guide structure to maintain riser alignment and spacing rather, than carrying top-tension loads, Fig. 2.  Moving individual wellheads beneath a fixed drilling rig only when access is required, means the rig no longer needs to translate across a large well-slot matrix above the platform top deck. This allows the drilling rig to be positioned lower within the structure—like MODU semisubmersibles--substantially reducing platform center of gravity, wind exposure, drilling deck area, and overall payload.  

As a result, platform size becomes driven primarily by topside processing, drilling, and utility requirements, rather than water depth or riser tension capacity, enabling a standardized and repeatable host facility deployable across a wide range of water depths. The FrPS configuration and its application to Lower Tertiary developments will be examined in detail, in Part 3 of this series. 

COMPARATIVE ASSESSMENT OF DEVELOPMENT OPTIONS 

When evaluated against key criteria—reservoir access, intervention capability, scalability, lifecycle recovery, cost control, and profitability — the wet versus dry field development architecture diverges sharply. Subsea‑centric systems score well on minimizing the host size but poorly on long‑term operability, recovery, performance and reliability. Traditional dry‑tree systems score well on reducing drilling and completion costs, improving well reservoir maintenance and increasing recovery but have faced perceived scaling challenges in ultra‑deep water. 

The optimal solution for Lower Tertiary developments must, therefore, combine the reservoir access advantages of dry-tree wells with a host architecture that remains scalable and repeatable across the extreme water depths of the play. The Frontier Production System (FrPS) addresses this challenge through a fundamentally different system architecture that decouples production riser loads from the floating host. This approach enables a dry-tree system that retains full-well access while eliminating the hull-scaling constraints that have historically limited dry-tree development in ultra-deep water. 

The architecture supports flexible wellbay configurations—such as five-well arrays for phased developments or 10- to-12-well arrays for full-field build-out—allowing operators to match infrastructure scale to reservoir knowledge and development timing. 

CONCLUSIONS 

The Lower Tertiary remains one of the largest offshore U.S strategic resources. Realizing its full potential will require a shift in development philosophy. Incremental improvements to subsea systems cannot deliver step-change results. Instead, operators must reconsider foundational assumptions about field architecture and place greater emphasis on reliable well access and long-term reservoir management. 

The industry’s continued reliance on subsea development systems is not simply the result of technical preference. Subsea architectures benefit from a high degree of supply-chain standardization, repeatable equipment packages, and well-established project delivery models. These characteristics have made subsea developments attractive from an execution standpoint, even when they impose long-term limitations on profitability and resource recovery. 

The industry, however, does not need to choose between standardization and dry-tree reservoir access. It needs a development architecture capable of delivering both. Achieving this requires a fundamental shift in how dry-tree risers interact with the host. 

The optimal solution must combine the reservoir access advantages of dry-tree wells with a host architecture that remains scalable and repeatable across the extreme water depths of the play. The Frontier Production System (FrPS), to be covered in Part 3 of this series, addresses this challenge through a fundamentally different riser architecture that decouples production riser loads from the floating host.  

Avoiding the problem of continuously scaling floating structures by adopting modular riser systems built from standardized components, the FrPS preserves full reservoir access while eliminating the hull-scaling constraints that have historically limited dry-tree development in deepwater. The result is a standardized, repeatable development architecture with a simpler supply-chain model than conventional subsea systems. 

By simplifying intervention operations and reducing reliance on large offshore construction and intervention campaigns, such architecture offers the potential for improved operational safety and a smaller environmental footprint over the full life of the development. A global benefit is gained when operators and investors realize that the FrPS provides improved economic performance and lower risk for discoveries outside the Lower Tertiary Wilcox play–in deep water worldwide. 

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

Editor’s note: The final installment in this series, Part 3, will examine in detail the FrPS configuration and its application to Lower Tertiary developments.  

REFERENCES 

1. Brendling, W., Shilling, R., & White, C. (2022). 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, 20 April 2022.  

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.