Assessing industry performance in America’s great Lower Tertiary play

Last year’s World Oil article (February 2020, page 63) by Frontier Deepwater Appraisal Solutions (Frontier) introduced the great savings and value created by adopting the Frontier Production System (FrPS) as a “greenfield” development tool. It would be used instead of the financially and environmentally risky and less-reliable subsea hub schemes employed on all existing ultra-deepwater Lower Tertiary developments.

As a follow-up, Frontier now presents an assessment of public domain information to clarify how, and why, industry’s efforts to develop the massive Wilcox Lower Tertiary trend in the ultra-deep waters of the Gulf of Mexico with subsea hub-spoke systems and strategies have failed commercially. In June’s issue, the second of two articles this year will reveal a way to “rescue” the producing fields that are failing and add billions of barrels in reserves to the holders of those Lower Tertiary assets.

In today’s energy market, operators need solutions that dramatically reduce the cost per barrel recovered to justify further investment into the once-promising Wilcox resource. After decades of cost-cutting, there is little chance to further reduce the capital and operating costs of subsea wells and facilities. Now, industry needs innovation—with proven technologies and a new strategic approach to field development—as the means to realize lower costs and risk while greatly increasing the recovery per well. Even in today’s oil price environment, such innovation can generate true profitability for the Wilcox fields that are under-performing, and thus resurrect a handful of massive discoveries that have been cast aside.

BASIC STATE: WILCOX LOWER TERTIARY PLAY

When the first discovery wells put the Wilcox in the headlines, the promise of this ultra-deepwater play attracted huge investments in Gulf of Mexico leases. Early reports credited the Wilcox with holding 40 Bbbl of oil-in-place (OIP). However, to date, none of the massive Wilcox discoveries has turned out to be worth the billions of dollars and years spent on appraisal and technology / field development—not even Jack-St. Malo (JSM), which has produced at more than 100,000 bopd. Why has this happened? The problems go much deeper than the collapse of oil prices, indicating the need for a simpler, safer, and much-less-costly strategy.

In spite of the fact that the sub-salt formation is very difficult to image seismically, and the reservoirs are complex, tight, and highly pressured, all operators have adopted very expensive and risky subsea field development schemes for their Wilcox discoveries. In attempts to reduce commercial risk, billions have been spent on appraisal programs, including the famous high-dollar extended well testing program on Jack field. Other attempts to limit risk include the Phase 1 subsea developments at Julia and Stones that were sanctioned at ~$4 billion, each, after years and over a billion dollars were spent on appraisal and technology development.

About half of the publicized ultra-deep HP Wilcox OIP has been discovered and, of those discoveries, only a small fraction of the OIP is now considered recoverable with the subsea approach. None of the efforts to find a commercial path to developing Wilcox reservoirs has resulted in a successful business case, even during the years when oil prices were relatively high. Since none of these efforts are generating real, full life-cycle value for investors, a total reliance on subsea wells and production systems for this vast resource must be wrong.

The offshore industry is clearly in for another difficult slump. However, the Lower Tertiary’s Wilcox formation has been in a critical state for years, despite the early promise of providing a massive new domestic oil resource. When compared with the EIA’s total U.S. oil reserve estimate of ~100 Bbbl, the scale of the Lower Tertiary “potential” attracted many established and new investors, even at extremely high entry costs.

However, soon after some early discoveries, the daunting challenges and risks facing commercial development of the deeply buried HP Wilcox discoveries became well-publicized. Exploration wells were found to cost over $250 million and take over half-a-year to drill and log. According to BSEE’s online database, one operator spent over a year and more than half-a-billion dollars appraising one well in Keathley Canyon without obtaining dynamic reservoir performance data. Unfortunately, except for JSM, none of the appraisal efforts acquired dynamic production insights into reservoir/completion performance before huge and risky FIDs.

Decision-makers were thus forced to deal with extreme commercial risks in pushing the discoveries toward sanction due to:

•   Very long appraisal and development well drilling times for HP wells, and very high well costs

•   Critical reservoir uncertainty and unknowns

•   Subsalt locations yielding poor seismic imaging

•   Thick pay intervals with multiple, layered tight zones (connectivity unknown)

•   Limited appraisal well data (due to high drilling costs)

•   Little production/completion history to clarify

o   Faulting and connectivity

o   Reservoir drive mechanisms

o   Sand control & completion

o   Intervention frequency.

In addition, some of the discoveries appeared to be so highly pressured that there were no existing subsea solutions available. So, industry has spent over a billion dollars to create and test a 20Ksi subsea kit. In spite of the risks and the safety issues with high-pressure DP subsea drilling, completions, and tieback systems, leaseholders have invested tens of billions of dollars and a couple decades exploring, appraising, and attempting subsea field developments in the HP Wilcox play. While painful cost-cutting by manufacturers and service providers has yielded substantial savings since 2015, none of the producing discoveries is providing an attractive return on total capital invested (ROCI).

There have been more than a dozen discoveries, with four developments involving six fields in the HP Wilcox play. By the end of 2019, two more fields had been sanctioned with FEED announced for another. Table 1 provides a summary of Lower Tertiary discoveries, appraisal, and development efforts so far.

Table 1. Overview of ultra-deep HP Wilcox discoveries

WHAT HAPPENED TO ALL THOSE EXCITING DISCOVERIES?

A simple answer to this question can be seen by a comparison of total investment versus total revenue for the producing fields—NO adjustments for tariffs, royalties/taxes, or “time value of money.” The following includes estimates from public sources for costs to lease & hold, explore, appraise/test, engineer (pre-FID), and develop. The cost to operate through recovery of all BOEM-cited total recoverable oil resource is reflected as a $/bbl cost element subtracted from the average oil price per barrel. For these complex, ultra-deep subsea fields, this Opex subtractor is set at $15/bbl. The average value of a barrel of oil is set as the average of WTI prices for the five years from 2015 through 2019 at $53/bbl.

This simple analysis is not burdened by export costs or the current price slump, nor by predictions of “peak oil demand” holding down future oil pricing prospects. Such burdens would just paint an even bleaker picture than that shown here:

•   Cascade / Chinook…discovered 2002/2003

•   Cost ~$4 billion, including nine-year $1-billion+ appraisal program

•   Final NET Revenue ~$2.4 billion from ~62 MMbbl of “original oil” (BOEM data published Aug 2020)

Result: -$1.6-billion indicated loss

•   Jack / St. Malo (JSM)—discovered 2004/2003

•   Cost ~$14 billion, including eight-year appraisal program

•   Final NET Revenue of $15.6 billion (~411 MMbbl, total reserves/”original oil,” per
BOEM 2020)

Result: +$1.6-billion indicated gain (but non-viable return when time value accounted)

•   Julia, Phase 1—discovered 2003

•   Cost ~$5 billion, including nine-year appraisal program

•   Final NET Revenue of $2.4 billion (~63 MMbbl, total reserves)

Result: -$2.6-billion indicated loss

•   Stones, Phase 1—discovered 2005

•   Cost ~$6 billion, including 11-year $1.1-billion appraisal program and purchase of Turritella FPSO

•   Final NET Revenue of $2.6 billion (~68 MMbbl, total reserves)

Result: -$3.4-billion indicated loss

If current oil pricing and/or the time value of money were accounted in this calculation, all these investments in the “Wilcox promise” would be seen to be clear losers—even JSM.

Table 2. Wilcox field drilling and completion times

The BSEE data in Table 2 provide a real sense of the heavy front-end investment that operators have made in the Lower Tertiary fields. One gets a clear view of how many wellbores have been drilled during appraisal to create enough confidence to sanction development of these challenging subsalt reservoirs. On average, industry is completing less than 40% of the wells drilled.

Fig. 1. Julia field’s monthly average daily production, bopd.

Yet, including all the sidetracks, the average total rig days per completion is 350 days ($390 million per well). This does not include days with other subsea construction vessels and the additional SURF equipment that adds another $200 million, resulting in a total of about $600 million per well completed (ref. SURF costs in 2016 EIA Lower Tertiary Costs Study by IHS). A closer look at two of the failing HP Wilcox assets clarifies how decisions to adopt the wrong appraisal/exploitation scheme from the very beginning prevents opportunity for commercial success.

Fig. 2. Julia field’s average daily production rate per well, bopd.

When Julia was announced to have ~6 billion bbls of oil-in-place, some saw it as the most significant oil find in the Gulf of Mexico. However, after achieving first oil in 2016, the asset has continued to disappoint. While the Julia production system was designed to deliver 34,000 bopd, BOEM data in Fig. 1 show that the average production rate from start-up through the end of 2019 was well below 30,000 bopd, after drilling eight wellbores with four completions. Figure 2 shows that wells JU104 and JU105 (brought onstream in late 2017) have been solid contributors to field output through 2019.

Fig. 3. Stones field’s individual well production, bopd (showing substantial downtime).

By comparison, Stones field appears even worse, with more than 20 wellbores yielding just seven completions. In addition, Stones has had a state-of-the-art 6th-generation dynamically-positioned drillship (a “DP MODU”) dedicated to adding/servicing wells and subsea systems since start-up. Unfortunately, as Fig. 3 and Fig. 4 show, the subsea production scheme has not performed. Figure 3 shows how little uptime the wells have achieved despite continual support of the expensive DP MODU. Figure 4 shows simplified cashflow through 2019, with oil at $53/bbl minus the Opex charge, as well as costs for the FPSO, shuttling, and new wells—but NOT burdened with pre-FID costs.

A more complex answer to the opening question is needed to explain why all the producing ultra-deep HP Wilcox fields are experiencing the kind of performance presented in Fig. 5.

Fig. 4. Stones field Phase 1 cumulative cashflow (post-FID through 2019).

Norway’s Johan Sverdrup is included as a contrasting example in the chart, because this field is expecting >70% recovery of OIP with dry trees. Except for Jack St. Malo, the two OIP bars for each of the fields in U.S. waters, “OIP-press” and “OIP-BOEM,” indicate a big difference between what was announced soon after discovery versus what is officially reported to the U.S. BOEM.

However, there is a handful of reasons as to why operators are experiencing low recoveries from the Wilcox subsea field development schemes:

• They are tight, with long layered multi-zones challenging completions technology and operations.
•  To keep down the time and cost for completion of these wells, complex single-trip multi-zone (STMZ) completion strings have been employed.
• If there are any real problems with the performance of STMZ completion strings, it can be prohibitively expensive to repair them in a low oil price regime.
•  For producing wells, maintenance and intervention frequently require the mobilization of an expensive state-of-the-art DP MODU, making simple jobs complex and costly:
• Thus, it is difficult to justify re-entering, sidetracking, and recompleting a non-performing well.
• It is extremely expensive to service/replace complex and costly subsea system hardware failures.

Therefore, when oil prices are low, these fields will have difficulty attracting the budget share needed to stem the rate of production decline or loss. All of these issues were predictable; yet, subsea systems were selected by project organizations, because the dry tree options with built-in platform drilling rigs considered during pre-FID investigations were seen as too costly and challenging from a project delivery perspective.

Fig. 5. Comparing EUR recovery for wet versus dry tree development (ref. BOEM data 2019).

Over the last two decades, as operators have continued to outsource engineering and technology expertise, major project delivery organizations have increasingly focused on “standardized supply chain” solutions that separate drilling and completion activities from the central hub platform. Field development planners often focus on facilities costs and ease of delivery, rather than total life cycle costs and the final cost per barrel of oil recovered. Such perspective has proven to be very costly for the Wilcox operators, leading to massive losses that clearly signal the need for a new, better way to achieve full life cycle asset profitability.

Operators are also aware that choosing subsea wells drilled by DP MODUs means that they were accepting an order of magnitude higher physical and environmental damage risk (e.g. 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 Petroleum 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.

CONCLUSIONS

This article has documented how industry efforts to exploit the once-promising Lower Tertiary play have failed commercially, because operators have depended entirely upon extremely expensive and complex subsea systems for asset exploitation, post-discovery. While such an exploitation strategy has worked for the Gulf’s deepwater Miocene fields, it is clearly not suitable for the very different Lower Tertiary Wilcox reservoirs. The high drilling and completion 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.

At present, the subsea systems deployed into the ultra-deep HP Wilcox play are expecting to recover, on average, less than 5% of estimated oil-in-place (OIP). Clearly, such low recovery is sub-economic–even at much higher than 2020 oil prices, so new exploitation strategies and technologies are needed. The next article considers how the Frontier Production System (introduced as a “greenfield” development tool in World Oil February 2020) can be employed to rescue failed, deferred or discarded Wilcox assets.

Editor’s note: The second article in this two-part series will appear in the June issue. It will evaluate the means for profitably rescuing those failing assets in the Gulf of Mexico.