June 2021
Features

Rediscovering the promise of America’s Great Lower Tertiary play

Part 2: In April, the first half of this two-part feature documented industry’s failure to profitably exploit the massive Wilcox Lower Tertiary trend in the ultra-deepwater Gulf of Mexico. This second article evaluates how alternative technologies and strategies can make those failing assets profitable while reducing human and environmental risk.
Chuck White / Frontier Deepwater Appraisal Solutions LLC Roy Shilling / Frontier Deepwater Appraisal Solutions LLC Vamsee Achanta / Frontier Deepwater Appraisal Solutions LLC Jeremy Walker / Frontier Deepwater Appraisal Solutions LLC Terrance Ivers / Frontier Deepwater Appraisal Solutions LLC

Following up the article by Frontier Deepwater Appraisal Solutions in World Oil’s February 2020 issue, an April 2021 feature presented an assessment of public domain information that clarified how, and why, industry’s efforts to develop the massive Lower Tertiary Wilcox have failed commercially. This sequel reveals a profitable way to “rescue” the producing fields that are failing economically and add billions of barrels in reserves to the holders of assets in the Gulf of Mexico’s ultra-deep high-pressure play. While this game-changer has global viability, the authors have determined that the technology and methods discussed can unlock up to $240 billion in new value to the Wilcox play, alone.

LOWER TERTIARY WILCOX: HELP NEEDED AND AVAILABLE

About half of the publicized 40-Bbbl resource in the ultra-deep, high-pressure (HP) Wilcox trend has been discovered, but 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 resulted in a successful, full, life-cycle business case. The numerous high-cost wells drilled by the world’s most sophisticated drilling units rated for HP drilling operations (detailed in Table 1), combined with generally poor performance of their costly subsea completion and tie-back systems, have made these once-promising discoveries commercial failures.

Today, operators need strategies and engineering solutions that greatly reduce the cost and risk per barrel of oil recovered to justify further investment in the “promise” of the Wilcox. After substantial cost-cutting, there is little chance for big reductions in ultra-deep, HP, subsea field development and operating costs. Frontier’s innovative adaptation of proven technologies, and a new strategic approach to field development, dramatically lowers costs and risks while increasing reserves recovery per well. Even in today’s oil price environment, this engineering solution will provide a profitable, lower-risk future for the Wilcox fields that are currently underperforming, and bring back into play a handful of massive discoveries that have been cast aside.

SETTING THE STAGE FOR A CASE STUDY

The main reasons for the high cost (and lack of profitability) for the Wilcox field developments are revealed by closely examining Tables 1 and 2. Table 1 shows the surprising number of wells and sidetracks, as well as the long drilling times, for these wells. Table 2 clarifies why drilling and completion (and tie-back) systems employed at these fields required high-pressure (typically, 15Ksi) ratings. For many of the years when these wells were being drilled, total (fully loaded) daily costs for drilling these HP wells from 15Ksi-rated dynamically positioned drilling units (DP MODUs) were over $1.1 million/day.

 

Now, Anchor has been sanctioned at $5.7 billion as a “20Ksi” field with a high cost first-of-kind 20K DP MODU, which will result in even higher day rates.

The study described in April’s article reveals that none of the subsea developments are recovering enough reserves per well to have justified the initial investments.  Re-completions, sidetracks, and interventions can increase the recovery, but DP MODU-based subsea remedial well work in the Lower Tertiary is too expensive.  This situation is exacerbated, if the field depends on a high-cost 20K MODU and subsea equipment— like Anchor and North Platte.

Solutions that have proven successful for the huge Miocene sands are failing in the complex Wilcox. The following section explores a strategy-building process that unlocks real value in the struggling Wilcox through the introduction of an innovative dry tree adaptation of proven technology.

A PROMISING MEANS FOR “RESCUE”: THE FRONTIER PRODUCTION SYSTEM

In February 2020, World Oil featured an article examining the value of a new dry tree greenfield development system, based on Frontier’s patented movable wellbay technology, Figs. 1 and 2. A “rescue” would place a permanently moored wellhead version of the Frontier Production System (FrPS) over a cluster of existing wells or a set of five new wells at an underperforming field as a brownfield application. The FrPS then re-completes or sidetracks existing wells and/or finishes drilling and completing new wells with direct surface access and dry trees.

Fig. 1. Movable wellbay centered position in moonpool.
Fig. 1. Movable wellbay centered position in moonpool.
Fig. 2. Movable wellbay outboard position in moonpool.
Fig. 2. Movable wellbay outboard position in moonpool.

 

Frontier’s movable wellbay concept opens the way to establishing a low-cost floating drilling, completion and production platform with fully rated dry tree wells. The movable wellbay can be retrofitted into the moonpool of an existing late-generation semisubmersible DP MODU or designed into a newbuild. Table 2 calculations highlight a key benefit for operators adopting a facility with dry trees and surface well access in deep waters— neither 20Ksi-rated BOPs nor trees are required at the surface for any of the fields listed.

In water depths beyond 4,000 ft, a cluster of subsea wellheads on the sea floor can usually be reached directly by top-tensioned risers, using dry trees at a single surface location. However, Fig. 3 shows that Stones has two distinct widely separated subsea well clusters. Figure 4 shows the wellbores and some of the significant directional drilling deviations already being used, confirming the industry’s capability to achieve large directional step-outs for deeply buried reservoirs.

Fig. 3. Stones field subsea wellhead locations (units in feet).
Fig. 3. Stones field subsea wellhead locations (units in feet).
Fig. 4. Wellbores from Stones BSEE data.
Fig. 4. Wellbores from Stones BSEE data.
Fig. 5. Comparing costs of ultra-deep HP Wilcox dry vs. wet wells.
Fig. 5. Comparing costs of ultra-deep HP Wilcox dry vs. wet wells.

 

The investment needed for rescuing a failing HP Wilcox field with a tool like the FrPS can be justified as:

  • Eliminating the need for a dedicated and expensive high-pressure-capable MODU

  • Avoiding the need for additional, expensive, high-pressure subsea equipment, including controls, HIPPS, HP mudline pumps and HP well intervention systems

  • Providing real cost-savings on drilling, sidetracking, and completing wells while increasing safety, due to having an onboard rig with a surface BOP and direct (dry) access to wells from a permanently moored floater

  • Paving the way for future profitable development phases.

A cost comparison is presented (see Fig. 5), assuming:

  • $800,000/day for an operator’s total daily cost (rig rate plus loaded services)) to drill with a world-class DP MODU, with a 15Ksi subsea BOP

  • $400,000/day for an operator’s total daily cost to drill with a world-class rig onboard the FrPS, using a 15Ksi surface BOP (based on existing spar and TLP data),

  • $1.5 million/day for an operator’s total daily cost to drill with a new DP MODU, with a 20Ksi subsea BOP (includes all 20Ksi tool rentals like the HP fully rated intervention riser),
  • $40 million for D & C tangibles per well (e.g., casing, tubing and miscellaneous hardware)

Using industry data from BSEE in Table 1, the costs in Fig. 5 are summarized as:

  • Cost of D&C for an HP subsea well is $256 million for 15Ksi wells (or $445 million for 20Ksi wells) vs. $184 million for dry tree wells, assuming

  • 170 days drilling and 100 days completing subsea wells, versus

  • For new wells prior to FrPS installation, 90 days pre-drilling with a fleet 15Ksi DP MODU, plus 80 days drilling “dry” from the FrPS.

  • 100 days completing “dry” from the FrPS (NOTE – Total D&C time is assumed to be equal, even though, on a long campaign over years of drilling, DP MODUs will suffer many more days of downtime than will the platform rig drilling system on the permanently moored FrPS, due to loop currents, hurricane abandonments, drift offs/drive offs, and mobilization times.)

  • The 270 days used here are a relatively problem-free duration without significant sidetracks. It should be noted that including additional sidetracks in the average number days to “hit the right target” (as noted last month) only makes the subsea case much more costly.

  • Tying back a 15Ksi subsea well with all the associated equipment costs $200 million per well (ref. 2016 EIA Lower Tertiary Costs study by IHS); $260 million for 20Ksi subsea wells vs. $15 million for the dry tree option with dual-barrier risers and surface equipment.

  • Cost for sidetracking/completing a HP subsea 15ksi well would be about $220 million (or $400 million for 20Ksi wells) vs. $100 million for dry tree wells.
  • Assuming 243 days for pulling existing completion, re-drilling & completing wet, versus 200 days to re-drill and complete dry from the FrPS (mobilization time and cost not included for a DP MODU, because the onboard rig is readily available)

Thus, Frontier’s dry tree solution is seen to provide total savings of:

•  ~$2.6 billion on ten 15Ksi wells

•  ~$5.0 billion for ten 20Ksi wells

Beyond these huge cost reductions, further benefits include:

  • Reducing human and environmental risk

  • Improving maintainability and uptime, due to having direct vertical access to wells for production logging, interventions, clean-outs and zone isolation.

—>more bbls/yr and, thus, more revenue every year

  • Dramatically reducing OPEX by having a rig on the platform using simpler surface equipment, with a loaded day rate one-half that of a DP MODU

—>much higher net profit per barrel produced

  • Increasing recovery (EUR/well) because operators can take advantage of downhole ESPs and afford to do what is needed, when it is needed, by having a dedicated rig and much simpler, lower-cost surface access to wells
  • Compare average of <5% recovery in HP Lower Tertiary subsea systems versus well-documented ~25% recovery advantage from dry tree wells (as per Norwegian Petroleum Directorate and BOEM sources);

Halving the cost per well and a potential doubling of EUR/well means that $/bbl cost drops so much that a rescue can make sense, even at low oil prices.

STONES “PHASE 1 PLUS” CASE STUDY: THE “RESCUE”

Selecting Stones as an example, a “rescue” plan could place a five-wellslot FrPS over four of the seven wells, with a fifth well added from scratch (considering the large offset/deviations seen in Fig. 4, it may even be worthwhile to drill five new wells from scratch). Having five wellheads beneath the FrPS allows the addition of many new sidetracks, completions, and even downhole lift to “Drill the Cube” and greatly increase recovery from the field. So, assuming that a “rescue” only doubles the recoverable reserves, the additional lifetime revenue would be ~$3.2 billion, with oil pricing noted in April’s article at $53/bbl (less $6/bbl OPEX charge for a dry tree system versus $15/bbl for subsea systems). This big jump in lifetime revenue can be achieved with the CAPEX for building and installing a converted FrPS estimated as follows:

  • New Investment of ~$1.3-2.0 billion (while the field continues to produce ~25,000 bopd for two years means ~$330 million/yr to help offset the cost of the rescue):

  • Designing/building/installing/commissioning a wellhead version of the FrPS costs $900 million to $1.2 billion and takes about two years (the FPSO is already installed, so a minimal production kit is needed on the FrPS)
  • Recompleting or cleaning up four wells costs $244 million (98days @ $400,000/day, each, plus $20 million in completion tangibles per well)

  • Drilling one new well at the cluster adds ~$200 million

  • Sidetracking and completing any of the existing wellbores to reach new portions of the reservoir can take 200 days and cost $102 million per well

Of course, if oil prices increase in the coming years, this additional profit would increase substantially.

Once the FrPS is proving its worth, a second FrPS unit can be installed on the field to further increase recovery and output. As confidence grows in the effectiveness and profitability of this low-cost, low-risk system, additional units may be deployed to fully exploit the Stones resource in phases. In such a scenario, total recovery from Stones could grow to several times the reserves currently indicated in the BOEM database, yielding many billions of dollars in new value creation.

The other producing fields in this play can also adopt the FrPS as a permanently moored wellhead platform with simplified topsides process kit, because each one already has a central processing facility. This “wellhead platform” option will simplify the conversion of the FrPS (or the construction of a newbuild version) and keep down the cost of their rescues.

A GAME-CHANGING DECISION

It is good to be aware that a robust dry tree development system can be deployed and that a simple economic “quick check” shows that it is possible to rescue failing Lower Tertiary assets. However, a major strategy change for a multi-billion-dollar venture usually requires a structured decision-making process called “Decision Quality (DQ).” Many practitioners recommend keeping the exercise as simple as possible for clarity. A straightforward probabilistic Decision & Risk Analysis (D&RA) evaluation has revealed the value of the “rescue” option in a case study for Stones field.

Fig. 6. Path forward strategy table for failing ultra-deep HP Wilcox field mega-asset.
Fig. 6. Path forward strategy table for failing ultra-deep HP Wilcox field mega-asset.

 

Brainstorming generated a meaningful collection of issues, factors, and strategic decisions that were organized in a traditional Decision Hierarchy. A relatively wide range of strategic path forward options was considered. Then, before building a Strategy Table, the options list was streamlined to include only truly distinct options. A result of this exercise is shown in the simplified Strategy Table of Fig. 6 for the following options:

  1. STAY THE COURSE… minimize investment [assume all BOEM reported reserves recovered]

  2. ENHANCE the subsea system… limit new investment into the subsea scheme between $1 billion and $2 billion

  3. SELL it… or, as much as possible

  4. RESCUE with FrPS.

“Abandonment” is not included as an option, because it would not be allowed for a producing field with reserves of 50 MMbbl.

The D&RA results clearly justify a RESCUE (details available on request):

  • STAY THE COURSE takes the least effort but provides no real upside, and the high cost of well intervention may result in early abandonment and significant financial loss.

  • The ENHANCE strategy’s Expected Value (EV) is much lower than that of STAY THE COURSE ($333 million less)… meaning that money invested to improve the subsea systems’ performance will be lost, as it brings no commercial benefit to the operator, due to the inability to deliver sufficient reservoir performance.

  • SELLING the asset can free up capital to allow the operator to seek better opportunities, but it is likely that the operator will face a big write-down [SELL EV = $1 billion vs. $1.5 billion for STAY]. This has been with the sales of Cascade Chinook and Shenandoah assets.
  • If RESCUE only improves recovery by 25%, then it adds ~$0.5 billion in new value (that is, EV ~$2 billion vs. $1.5 billion for STAY—> hypothetical >30% ROCI for a decision to change the game).

  •  However, if a doubling of reserves can be expected, due to efficient sidetracking and re-completions (assuming P10-P90 range of 33%-200% recovery improvement), then RESCUE would have an expected value at least ~$1 billion higher than STAY THE COURSE.

CONCLUSIONS

This two-part study has documented how industry attempts to exploit the once-promising Lower Tertiary play in the Gulf of Mexico have failed, because operators have depended solely upon extremely expensive and complex subsea systems. The high cost and poor performance of subsea development schemes are driving operators to abandon (or indefinitely set aside) many Lower Tertiary discoveries that were announced with much fanfare. After noting causes for those costly disappointments, the authors have introduced the Frontier Production System (FrPS) with its movable wellbay technology as a robust means for “rescue,” by offering the advantages of fully rated dual-barrier dry tree wells at a much lower cost and risk.

A simple decision analysis revealed that, instead of “hanging in there” or selling out, it pays to invest in these game-changing concepts to profitably re-discover the promise of the Wilcox. Spending money to enhance existing subsea wells and systems is not justified. However, very reasonable improvements in recovery afforded by a direct access, dry tree option provide a solid business case for a “rescue,” thus, opening a low-risk path to highly profitable exploitation of the entire resource.

The subsea systems deployed into the ultra-deep HP Wilcox play are expected to recover, on average, less than 5% of oil in place (OIP). Such low recovery is sub-economic, even at much higher oil prices, so a significant change in exploitation strategy is needed. Providing affordable sidetracks, when needed, makes doubling recovery from these Wilcox reservoirs a very practical objective—much like “Drilling the Cube” has been successfully exploiting shale reserves onshore. Doubling EUR drives the Expected Value for an FrPS “rescue” of Stones above $2.5 billion, indicating potential for a highly respectable ROCI. This return would significantly increase, if oil prices rise and the concept is adopted to fully, and more safely, exploit the resource.

It is worth noting that this simplified “total expected net revenue” model does not reflect the fact that Frontier’s dry tree solution will increase average daily and annual production rates, accelerating recovery and cashflow.

Frontier’s February 2020 World Oil magazine article introduced the great savings and value created by adopting the FrPS as a greenfield development tool, instead of the ultra-risky and expensive 20Ksi hub-subsea scheme sanctioned for Anchor field in 2019 ($5.7 billion). As a follow-up to that article, this study has revealed a way to employ the FrPS in a “brownfield rescue” of those failing ultra-deep HP Wilcox fields that are already proving to be wholly uneconomic, as well as to “re-discover” a handful of massive discoveries that have been tossed aside.

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.
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. 
Jeremy Walker
Frontier Deepwater Appraisal Solutions LLC
Jeremy Walker Frontier Deepwater Appraisal Solutions LLC.
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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