Multi-purpose drilling and production system aims to address challenges of Lower Tertiary

The Lower Tertiary is characterized by water depths that range from about 5,000 to 10,000 ft (1,524 to 3,048 m)
and reservoir depths of more than 30,000 ft (9,144 m). (All images courtesy Frontier Deepwater Appraisal Solutions LLC)

After drilling numerous appraisal wells to gather static information from electric logs and cores, the industry has been unable to define basic but critical factors about the Lower Tertiary, including:

• Faulting and connectivity

• Depletion drive mechanism

• Sand control needs

• Intervention requirements

• Reserve recovery per well

• Optimal well number per development.

Without dynamic reservoir information, these questions remain, making it difficult for operators to take on the expensive and high-risk investments to exploit this deepwater resource. As a result, despite estimates of 40 Bboe reserves in place, the Lower Tertiary remains essentially undeveloped.

In response to the hurdles that have so far stalled development of the Lower Tertiary, Frontier Deepwater Appraisal Solutions LLC has designed a simpler, adaptive, and standardized system that provides a phased development strategy that allows operators to capture critical dynamic reservoir data.

The deepwater Frontier Production System (FrPS) is a converted sixth-generation MODU capable of drilling Paleogene wells from top to bottom and includes a production module and movable wellbay. As such, the new system is a drilling, completion, intervention, workover, side track rig on a production platform.

The new system reduces risk and costs and builds on the precepts that worked successfully for the onshore “Shale Revolution,” including:

• Use of simple, reliable completions and technology

• Provide inexpensive drilling, completion, long-term maintenance and intervention

• Use of the “pad” concept to drill and develop a ‘cube,’ which in this case is more reservoir acreage than is contained in one outer continental shelf block.

Extensive studies performed for operators such as BP and Anadarko have demonstrated that 20K subsea developments are not economic and that a very different solution will be required to develop the Lower Tertiary. The patented FrPS meets that challenge by creating billions of dollars in economic advantages over more expensive and less reliable 20K subsea developments. It can be delivered and installed in about half the time and cost of a purpose-built subsea “hub” system. In addition, because it is a phased approach, operators can confidently and profitably sanction initial field developments with just a few wells and subsequently add future phases faster and at less cost.

Further, the system is a dry tree solution; dry tree completions have historically delivered about 25% higher reserve recovery than have wet trees. For a 400-MMbbl resource, this advantage may mean as much as 100 MMbbl of added production, which, at $50/bbl is equivalent to more than $5 billion in added revenue compared with a subsea system. Due to the speed at which first and peak production can be achieved by implementing the FrPS development scheme, this revenue “bonus” comes at the front end of the project, doubling the value of early adoption.

The movable wellbay includes high-pressure dual-barrier riser systems installed with syntactic foam buoyancy to reduce the top tension.

Because dry trees allow surface access to wells, they are the preferred option for deepwater well intervention and maintenance. In the Lower Tertiary, where drilling and completion costs account for 70% of total expense, developments are not as much about the facility cost as they are about well construction, well intervention operating costs, and increasing recovery per well (artificial lift). This is a paradigm shift that has yet to be recognized by many operators seeking to deliver a commercial 20K subsea development. Frontier’s solution addresses these cost challenges, while providing a phased entry strategy.

The FrPS provides this solution using:

• A purpose-built or converted sixth-generation semisubmersible

• A 60,000-b/d production module

• A movable wellbay structure supporting five or more dry tree wells

• A permanent taut-leg mooring system

• Oil and gas export risers with pipeline tie-ins to regional infrastructure.

Innovation using proven technology

The system provides operators with the means to move forward faster with fewer appraisal wells while obtaining the dynamic reservoir information profitably at oil prices of less than $50/bbl. The core of the system is the patented movable wellbay that can support five dry trees atop dual-barrier fully rated dry tree riser systems.

To convert an existing rig to an FrPS, all subsea drilling and dynamic positioning systems are removed, which creates space and payload capacity for prefabricated 60,000-b/d production modules and the movable wellbay.

The main and lower decks support the movable wellbay, which is restrained from vertical movement but may be moved laterally to position each well slot under the rotary table. The wellbay includes a slot structure that extends downward to accommodate the stroke of the risers. Tension rings are guided and remain within the slot structure. A flexible production jumper is attached to each tree and to a manifold built onto the movable wellbay. Chokes produce a pressure break at the movable wellbay production manifold so that low-pressure jumpers may be attached to the manifold on the rig. High-pressure dual-barrier riser systems are installed with syntactic foam buoyancy to reduce the top tension requirements to about 750 kips in 6,000 ft (1,829 m) water depth, allowing the use of four standard 250-kip tensioners (with one spare tensioner).

The dry tree configuration takes advantage of the water depth that reduces the surface pressure to well below that at the mudline, thus allowing the operator to use proven surface well control and production components.

The system uses existing technology and equipment that is available from multiple equipment suppliers today. The movable wellbay is a novel solution for development of the Lower Tertiary because installation of a 2.5-million-pound drilling unit on a spar requires a platform larger than that at the BP Holstein development. Because dry trees offer numerous advantages over subsea completions for well surveillance and interventions, they allow operators to gain critical data necessary to evaluate well performance and maximize recovery from new geologic horizons, particularly in complex stratified reservoirs like the Lower Tertiary.

The core of the FrPS is the movable wellbay installed in place of the standard subsea drilling and dynamic positioning systems
of converted sixth-generation MODUs.

A study performed by Equinor and the Norwegian Petroleum Directorate (NPD) showed that in relatively homogeneous reservoirs, the recovery factor from subsea wells is 15% to 20% lower than from wells with direct vertical access. This lower recovery factor is magnified in reservoirs like the Lower Tertiary. Accessing completed subsea wells is more difficult and incurs significantly larger costs than do wells drilled from a dry tree installation. Typically, even for minor intervention operations, a MODU mobilization is the only practical option and because this is often an uneconomic solution, recoverable reserves are left behind.

Therefore, the NPD study concluded, production from dry tree wells is typically 20% to 25% better than from subsea wells drilled in the same geologic environment. The primary cause of this difference is easy well access, which facilitates significantly less costly light interventions and wireline work in dry tree wells than in subsea wells. In addition, the ease of surveillance operations such as production logging, production inflow, and multi-rate production logging of individual reservoir layers, contributes to better data gathering, which results in increased production performance of dry tree wells.

Dry trees and safety

Dry tree development is strongly aligned with the principles for maintaining simplicity, reliability, and safety. The use of permanent mooring systems rather than dynamic positioning (DP) vessels eliminates the need for emergency disconnection of the drilling riser, the risk of loss of position due to drive-off or drift-off, and the need to retrieve risers, which can result in weeks of hurricane and loop current abandonment in the Gulf of Mexico. Another study conducted as part of the NPD program indicated that position excursions that are likely to lead to physical damage are about two orders of magnitude less likely on moored versus DP rigs.

Further, the FrPS dry trees are designed to handle the full wellbore pressure and eliminate the need for complicated subsea high integrity pressure protection systems (HIPPS). In addition, a surface BOP is much simpler and more reliable than a subsea BOP. The surface BOP uses simple, reliable hydraulic controls, while the subsea BOP requires electronic controls and large high-pressure subsea accumulators to function the system. The surface BOP is readily accessible for maintenance and in many cases can be repaired in place. This eliminates the expensive and risky task of pulling a MODU marine riser and subsea BOP back to the surface for repair and testing—an operation that requires weeks and cost tens of millions of dollars.

Dry tree developments have two other important safety advantages compared with purpose-built 20K subsea developments. Dry trees require significantly fewer manhours offshore and for delivery and installation of equipment and have much lower exposure to loss of well control. In an Exprosoft 2017 report, “Loss of Well Control Occurrence and Size Estimators,” for the BSEE, the well integrity, data modeling and simulation company said the frequency of loss of well control (LOWC) for dry tree wells is slightly less than for subsea wells.

According to 2000 to 2015 data in the report, one can estimate an average dry tree LWOC release of about 4,000 bbl, while using the same methodology for subsea results in about 400,000 bbl (including Macondo). Using an average damage cost of about $15,000/bbl calculated from the BP Macondo incident, the expected damage loss associated with a 10-well FrPS full field development would be about $3.6 million. By contrast, for a 10-well 20K subsea development, the risk is more than $360 million, or a factor of 10 higher cost exposure than when using the system. Much of this increased risk stems from the reliability issues associated with the subsea BOP and from the fact that thousands of feet of marine drilling riser extending from the BOP to the MODU is not fully pressure rated as it is with dry trees. Dropped objects on high-pressure subsea infrastructure is also a concern.

In planning 20K purpose-built subsea developments, operators must ensure access to two 20K MODUs throughout the course of the project. The MODUs must be newbuilds, meaning the operator not only must build the floating production system, but also must fabricate and deliver the 20K MODUs for the project. Both units are staffed with 150 to 200 personnel. In addition, installation vessels are required to install subsea equipment such as manifolds, flowlines, control umbilicals, HIPPS, etc. By comparison, the new system requires only one unit versus three for a 20K subsea solution. The drilling crew on the new system can run the production risers, which eliminates extra vessels and crew to install subsea infrastructure. Considering all manpower resource requirements over the life of a 20-year project, it requires less than 50% of the man-years associated with a purpose-built 20K subsea system, which greatly reduces the risk of injury to personnel.

Phased development

To more clearly illustrate the commercial case for the FrPS, Decision Frameworks LP was commissioned to perform several case studies. The study compared Lower Tertiary development economics using the new system with those of a purpose-built semisubmersible and 20K subsea wells option with various numbers of wells and initial well rates. Both concepts were evaluated at $50/bbl and $75/bbl flat oil prices, with no inflation or oil price escalation.

The studies focused on a project schedule comparison of the two concepts in which an initial discovery well and second appraisal wells are drilled with a commodity 15K MODU. In the case of the 20K subsea approach, FEED and 20K engineering begins with the third appraisal well and carried through the fourth and fifth appraisal wells, which are drilled as keepers.

The subsea hub project sanction and detailed engineering and procurement start after the fifth well results have been analyzed, resulting in the facility and equipment being delivered about 40 months later. The facility is installed and commissioned with first oil for the 20K wells about one year after facility installation. The subsea wells are completed using the new 20K MODU.

The above scenario is similar except that a phased development scenario is employed in which the third appraisal well and all other wells are drilled as producers. The operator drills the first two wells, which are the third and fourth appraisal wells, and cements production casing using a commodity 15K MODU. The 15K MODU then drills the remaining three wells to the 14-in. casing cementing point and cements the casing, which is angled in the direction of the desired bottom hole locations. While these wells are being drilled, the system is converted and then installed over the five pre-drilled wells. The operator then installs dual barrier production risers and completes the first two wells for first oil. The remaining three wells can then be drilled and completed using the rig on the system.

An initial well production rate of 15,000 b/d was selected for both the dry tree and subsea cases based on existing BSEE production data from Lower Tertiary production at Jack/St. Malo, Julia, Cascade and Chinook. The analysis concluded that because of its significant cost savings and schedule improvements, the system is a much more valuable development.

Four specific aspects drove the value benefits, including:

• Lower infrastructure capex— it is less expensive to design and build and enables use of dry trees

• Lower rig rates and operating costs

• Faster schedule delivery and earlier first oil because of shorter facility lead time

• Significantly reduced opex—lower workover costs because 20K MODU mob/demob cost is eliminated.

With dynamic reservoir information obtained in Phase 1, operators may proceed with Phase 2 in possession of a much higher degree of reservoir certainty. Frontier’s phased approach provides operators about $8 billion more value than a traditional subsea development scenario. If the additional reserve recovery from dry trees, as referenced in industry studies, is considered the difference increases to more than $11 billion.

Conclusion

As the industry moved to ever deeper water and more hostile and complex environments, it has repeatedly turned to innovation to meet evolving technological and economic challenges. To exploit the vast reserves of the Lower Tertiary, the industry must once again turn to engineering innovation using proven technology rather than attempting to mutate a supply chain solution built for the Miocene and other reservoirs. The FrPS is such an engineering innovation. This step change is centered on the realization that, unlike in the past, it is the cost of well construction as well as access to dynamic reservoir data, and not the production facility and supply chain, that must drive development decisions in the Lower Tertiary.

Although the initial driver was to create a technical and economic solution to unlock the deepwater Tertiary plays in the Gulf of Mexico, the system is a viable solution for development opportunities in shallower water and normally pressured. That is because its dry trees offer higher reserve recoveries than subsea completions, which raise the economic limit and thwart late in life reserve recovery efforts, and because the operator can relocate the unit once the initial installation reaches its economic life.

The movable wellbay technology is also applicable to purpose-built TLPs and deep draft floaters, such as spars, because the rig may be built lower into the platform, eliminating the heavy and expensive rig skidding systems on the top deck. In doing so, the drilling systems and utilities become simpler and the overall platform size and complexity can be reduced. As such, the new system has worldwide applications beyond the Gulf of Mexico. •