Historically, as the oil and gas industry developed Gulf of Mexico deep-water discoveries, operators viewed economic risk in terms of production facility and infrastructure costs.
While more expensive and complex than those performed onshore or in shallow water, drilling and completion operations represented a smaller fraction of the overall expense of deep-water field developments.
However, recent discoveries in Paleogene reservoirs are presenting operators with a new set of challenges that are upsetting that relationship.
These Paleogene reservoirs are in extreme water depths and have potential mudline shut-in pressures of more than 15,000 psi, requiring new subsea technology.
In addition, whereas Miocene development wells were 15,000-20,000 feet in total measured depth (TMD), Paleogene wells are often more than 30,000 feet long. Directional wells through these reservoirs may reach 40,000 feet TMD.
Operators typically require nearly a year to drill, complete, and tie back each Paleogene well.
Exploration wells can cost over $300 million and take more than six months to drill and log. Consequently, drilling and completion costs have replaced facilities costs as the dominant factor in development concept selection.
In response to these technology and cost challenges, which today are compounded by weak oil prices, some Gulf of Mexico operators are reducing or selling their holdings in these plays, once considered highly attractive, long-term deep-water resources.
The solution to the Paleogene dilemma, say Roy Shilling and Howard Day, is to replace subsea completions with dry trees in a phased development approach. The two have joined other long-time deep-water experts to form Frontier Deepwater Appraisal Solutions.
The company claims that the use of dry tree completions, combined with its own Appraisal Production System (APS) can reduce the cost and schedule for Paleogene developments by 50% compared with subsea completions tied back to a massive central production facility.
The APS, also suited for use with subsea completions, facilitates a timely and effective appraisal, which provides critical dynamic production data not available through the current strategy of using static core and log data from appraisal wells.
Shilling points to BP’s Kaskida and Anadarko’s Shenandoah discoveries in the US Gulf as leading examples of the difficulties confronting oil company decision makers in Paleogene projects.
Kaskida was discovered in 2006 and Shenandoah in 2009. Despite encountering reserves estimated to be billions of barrels in place, neither discovery has yet been sanctioned.
Anadarko spudded its sixth appraisal well during the fourth quarter of 2016, more than seven years after making the initial discovery.
Data collection
The obstacles to progress in many Paleogene discoveries are the challenges of unproven 20K subsea technology and lack of reservoir and completion performance data.
Information that can only be obtained by flowing the well through an appraisal production system is required to understand faulting, connectivity, reservoir drive and other fundamental issues, such as the need for sand control.
Compounding the problem is the Bureau of Ocean Energy Management, Regulation & Enforcement rule that requires operators to perform well operations every 180 days to hold a lease beyond its primary 10-year term.
In most cases, says Shilling, the appraisal period may cost a company $1 billion dollars, while not providing the necessary dynamic reservoir data.
After the initial 10-year lease period operators must continue appraisal operations until they sanction a development or decide to relinquish the asset.
To substantially reduce this extended and costly appraisal period while still gathering the data necessary to make informed development decisions operators need an appraisal production system that is deployable early in the appraisal process, says Day.
This phased approach allows operators to produce the reservoir and gather dynamic completion data.
“Importantly, they are also generating revenue towards positive project economics while greatly decreasing their risk exposure,” he says. “This is the core strategy behind Frontier’s Appraisal Production System.”
Frontier intends to take advantage of the current rig market oversupply to acquire a high capacity ultra-deepwater semi-submersible mobile offshore drilling unit at relatively low cost.
The company plans to convert the unit into a drilling, completion, intervention and production facility with a moderate but profitable throughput capacity of up to 60,000 barrels per day of oil.
Rig modifications call for a movable well bay structure supporting up to five dry tree wells with buoyancy-supported top-tensioned tieback risers.
While the shut-in reservoir at the subsea mudline may be more than 15,000 psi, the oil column in deep water will result in shut-in pressure at the surface wellhead on the APS of less than 15,000 psi.
Therefore, the system can be equipped with standard, existing technology surface well control and production components. The floating unit will be held on station through extreme events by a fixed polyester spread mooring system.
Frontier recommends dry tree wells because they provide efficiencies that significantly reduce drilling and completion costs without compromising safety.
They also allow efficient well access for surveillance, maintenance, and enhanced reserves recovery operations.
“Dry trees for the Paleogene provide fully pressure rated dual barrier production risers with a permanently moored facility and a much simpler and more reliable surface BOP that can be easily monitored and maintained,” says Day.
“The surface BOP eliminates the problem of gas in the marine drilling riser above the BOP, which is a significant safety concern post-Macondo.”
Shilling says: “The APS also allows operators to gather useful dynamic production data while operating at a profit. This, in turn, allows them to drill wells that are ready to be put on production so that they can avoid wasteful years of drilling very expensive non-producing appraisal wells.”
Dry trees also ease well surveillance, wireline logging and interventions, and the ability to run and more easily service downhole electric pumps, which can significantly increase well rate and reserve recovery when compared with subsea wells.
Combined, these attributes of dry tree technology, says Frontier, significantly drive down the cost of Paleogene developments while enhancing production profiles, reserves recovery and net revenue.
Using the Frontier APS with dry trees, says Shilling, reduces the economic limit on Paleogene reservoir wells from the current $80-plus per barrel to less than $50 per barrel, while providing operators with the dynamic data needed to optimise the development long term.
Frontier is in talks with operators, drilling contractors and equipment suppliers to develop the system.
Current estimates are that the system can be delivered in about three years using existing technology at less than half the cost of a purpose-built semi-submersible facility with a complex array of 20K subsea well tie-backs.
石油圈
