A host of new game-changing technology solutions is advancing the oil and gas industry’s capabilities in deep and ultradeep waters.
Advances have been noted in technologies for deepwater drilling, floating production, subsea wells, deepwater pipeline construction and protection, risers, subsea separation, controls, tie-ins and tiebacks, flow assurance, and hub design, among others.
Even with the most innovative technology advances, however, it’s important to keep in mind practical considerations in this hotly competitive market, according to Eric H. Namtvedt, president of FloaTEC.
“I am sure the deepwater challenges will continue to produce astonishing achievements,” he says. “But, as we say at FloaTEC, with our unique support by our parent companies J. Ray McDermott and Keppel FELS, no concept or technical breakthrough has any real value unless it can be coupled with a credible and doable delivery model, where the elements of project deliveries are managed by capable contractors who can handle the risks of the complete supply chain.”
Deepwater drilling/completion/intervention
Brian Skeels, emerging technology manager, FMC Technologies, ticks off these technology needs for deepwater drilling: “Dealing with deep well and deepwater kicks, especially when a deep well kick is undetectable until sometime later, as the kick is circulated out; accepting expandable casing for more of the well’s casing strings-eventually getting closer to the monodiameter well concept; and continued efforts in slimbore-surface BOP drilling to help keep the rig size down.”
Gary Shaw, technology leader, VetcoGray, a GE Oil & Gas business, notes that the technology solutions and innovations for deepwater drilling come primarily from time and weight savings, citing “time savings to cut rig and installation costs, and weight savings to extend the depth capabilities of older, less costly rigs and solutions such as TLPs. Recent examples in the drilling area would include the new drilling riser connector VetcoGray has developed, which runs in a fraction of the time of older designs, has high strength capabilities, and offers the added benefit of not requiring a person on the rig floor, making it inherently safer.”
In the subsea completions arena, most of the game-changing equipment consists of the technologies needed to complete subsea processing systems, which includes equipment such as separators, pumps, compressors, and most importantly, the power equipment to make it all happen, says Shaw.
“Beyond equipment, new materials and coating technologies in areas like composite materials could have a significant impact,” he says. Shaw also foresees needed improvements in the ability to access and control a large number of downhole functions through the subsea tubing hanger, tree, and associated installation tools.
Regarding subsea intelligent wells, one challenge is to be able to process and interpret the information in a timely manner, preferably in real time, contends Shaw: “Another key issue is the ability to maintain reliability of the complex devices, or provide an efficient method to mitigate [problems].”
But Skeels offers a caveat on the intelligent well solutions.
“Oil companies that favor intelligent wells feel they are ‘designing out’ the need for future interventions, citing intelligent wells as their ticket for low-cost changes to recomplete as the reservoir depletes,” he says. “Others feel this is a foolhardy endeavor and should make some plans for easier, more cost-effective intervention into a well regardless of the well design.”
Skeels says, “The debate will be determined by economics and how subsea wells behave as the global subsea well count ages and how quickly the service sector can respond to a ‘sick’ well.”
Noting that new solutions in light well intervention will play a part in that scenario, Skeels notes the technique’s growing popularity and contends it should be commonplace in all global deepwater theaters by 2010: “I really like the idea of AUVs ferrying out ROVs to remote sub-ice fields, plugging into a power docking station, performing subsea interventions, then traveling back from under the ice.”
Control systems
Longer offsets imposed by subsea-to-beach scenarios, and the push for a “green” control system will influence future control system designs, predicts Skeels.
“Electro-hydraulic and electro-hydraulic-fiber optics will continue to be around for some time to come because of the greater mechanical power-to-size ratio that hydraulic systems will always be able to provide,” he says. “However, all-electric systems will eventually come into their own for subsea fields beyond 10,000 ft water depths and/or subsea fields with a significant subsea separation/boosting infrastructure associated with it.”
He also notes that there is little all-electric downhole equipment currently controlled by electrics: “Research is going on, but downhole temperatures above 300° F may limit its reliability.”
Shaw looks for a reduction in production umbilical diameters, as the all-electric technology will remove the need for hydraulic lines in the umbilical.
Tie-ins and tiebacks
The clustered-well field architecture is here to stay, according to Skeels: “The question now is whether the flowline connection is horizontal or vertical, and how can one put an insulating jacket (dog house) around it afterwards to prevent heat loss when the rest of the manifold and pipeline is insulated.”
As for long-distance tiebacks, they will “keep getting pushed longer and longer, but not without the assistance of subsea separation and boosting,” Skeels says. “[Operations] under the arctic ice will hasten longer-offset technology.”
Uri G. Nooteboom, vice-president, field development projects for INTEC, contends that continuing development and maturation of subsea processing and monitoring technologies (such as pumping, compression, separation, electric flowline heating, metering, etc.) will have a positive effect on industry efforts to extend long-distance tiebacks.
“Improvements in power delivery and control systems, both long-distance and in-field, will lead to improved economics,” he says. “The evolution of operator views on project risk acceptance may also have an effect.”
Non-hydraulic (electrical) controls systems will help improve the reliability and economic viability of long- distance tiebacks, Nooteboom adds.
Long tiebacks is an area of heightened focus for Vetco Gray, notes Shaw.
“We have just completed work on the Statoil Snovhit project in the Barents Sea, the first subsea-to-beach completion in the world,” he points out. “The power and communications equipment was qualified and tested to an offset distance of 205 km, a new industry record.”
Riser installations
In the case of drilling risers, Shaw thinks there are great opportunities in not only improving riser installation time, but also riser retrieval time.
“It is easy to relate to the economic savings associated with riser trip time in a fifth-generation rig with a hefty daily rate,” he says. “There is, however, another driver for reducing riser trip time. In deep water it could take well over a day to trip out a 21-in. drilling riser. In the case of an unforeseen environmental condition, such as a rapidly strengthening hurricane, the contractor may not have a day or two to trip the riser out and move away from location. In certain events, it may be safer to ride out the hurricane with a connected riser than ride through a hurricane-force wind with half the riser hung off on the spider. The reduction of riser trip time, in some situations, could make the difference between one of the above two unattractive scenarios and one that permits full retrieval of the riser and relocation of the drilling vessel to safer waters.”
Skeels notes that the debate over whether to use steel catenary risers vs. free-standing or tensioned vertical production risers will be decided by the materials and welding issues encountered while working in ultradeep waters.
Flow assurance
One of industry’s knottiest challenges in the deepwater theater is that of flow assurance.
Nooteboom contends that current deepwater designs employ a considerable conservatism due to uncertainties in flow assurance strategies resulting from uncertain input data.
“This conservatism often results in increased [capital and operating expenditures] in the form of materials (e.g., insulation), chemicals, and back-up strategies to manage hydrates,” he points out. “The operational systems put in place to manage hydrates during shutdown conditions (e.g., depressurization, dead oil circulation) and cold restart conditions, as well as to manage hydrate blockages if they occur, are operationally complex and can dictate the entire development architecture.”
A cost-effective and proven-reliable electrically heated flowline (EHF) system could change all this, Nooteboom says: “Knowing that an EHF system could be run continuously or switched on during an unplanned shutdown or restart, if a hydrate blockage occurred, would eliminate the capex, opex, and operational complexities associated with conservative ‘belt-and-suspenders’ solutions.”
Further down the line is the concept of cold flow, a notion that has been much discussed of late in the flow assurance community, Nooteboom points out.
“The typical flow assurance approach is to preserve the heat energy in the fluids to prevent wax deposition and hydrate formation,” he explains. “ Cold flow would allow the fluids to cool such that wax and hydrate particles are allowed to form and are transported to a host as a slurry without forming blockages. This technology does not currently exist.
“The ability to employ cold flow in deepwater and/or long distance tiebacks has the potential to save significant costs and operational complexity in the form of eliminating insulation, reducing or eliminating chemical use, and decreasing operational complexity.
In the end, subsea processing facilities themselves are flow assurance solutions in that “by separating phases, hydrate formation becomes reactant-limited, while cold flow solutions become enabled for the hydrocarbon liquids and direct water disposal is a possibility,” says Shaw. “Otherwise solutions, such as VetcoGray’s HeatBank, can be expanded to items beyond coldspots, valves, and connectors.”
Shaw adds, “As a driver for e-field options, flow assurance software can be used to stabilize unstable operating conditions, provide needed input to condition monitoring software, and otherwise provide options for reduced risk while operating at, or near, minimum safe operating conditions.”
Nooteboom concurs, adding that subsea processing technology has made great gains in the past decade, and the pace of advancement is increasing: “Advancements in the capabilities of subsea processing, pumping, and compression are changing the way we look at flow assurance for subsea developments and will help to increase technically viable tieback distances to economically develop remote oil reservoirs.”
Boosting/pumping
Another area of game-changing technology advances in deepwater operations is that of subsea boosting and pumping.
“Continuing development, application, and maturation of subsea separation systems technologies will allow installation of subsea pumping/compression systems that are more compact, more efficient, and better able to accommodate changing GVF over field life,” Nooteboom says. ”Improvements in power delivery and control systems, both long-distance and local field, will lead to improved economics.”
Flexible solutions and power are the critical issues in subsea boosting, according to Shaw.
“The operating envelopes for many fields are large-high production early in life and low production late in life,” he notes. “Finding solutions-for instance, changing out of equipment and/or operating with varying redundancy to effectively produce throughout the life of the fields-is one key factor to facilitate field development and/or improve the economics.
“Power is also a limiting factor. The demand for both higher power and longer step-outs is increasing. Higher power might reduce the number of pumps running in series or parallel and a subsea VSD and distribution system might increase the step-out distance.”
The big challenge in multiphase pumping is high differential pressure, says Shaw: “Low reservoir pressure, in combination with deepwater installation, demands high delta pressure. By being able to supply high delta pressure, running pumps in series can be avoided.”
In the end, Skeels thinks that multiphase pumping will stay a niche market, “because customizing a pump/impeller system for every GOR will be one-of-a-kind designs for each project. Accurate, ‘fiscal-quality’ multiphase metering also still has a ways to go but is making great strides and, hopefully, it will eventually eliminate the need for a test pipeline.”
Subsea compression
Subsea compression is considered to have a significantly lower investment and operational cost than the platform compression alternative, with the same core functionality of compressing gas for transportation purposes to shore for further processing and export, contends Shaw, adding, “In a nutshell, subsea compression has the potential to increase the ultimate gas recovery.”
Working with Aker Kvaerner, GE Oil & Gas has completed the conceptual design of a 12-Mw subsea compressor, the Blue-CTM, the largest ever developed for subsea applications, and is set to begin construction of the compressor to be tested in the pilot project in Ormen Lange field off central Norway.
- Gary Shaw, GE Oil & Gas Vetco Gray
“The aim of the pilot project is to evaluate whether a subsea compression station, at approximately 900 m of water depth, is a viable alternative to an offshore platform,” Shaw says. “This project represents a major milestone in the development of subsea compression technology. If the project produces the expected results, the Ormen Lange partners will have a cost-effective alternative to the originally planned offshore platform. This technology could then be applied to other subsea field developments, eliminating the need for offshore platforms.”
Subject to the Ormen Lange partners’ final approval, Aker Kvaerner’s subsea compression station pilot project will undergo controlled endurance tests during 2009-2011 at a gas treatment facility in Nyhamna, Norway.
Deepwater pipelines
Construction methods for deepwater pipelines have logged significant progress, but line pipe materials issues still need to be resolved.
“J-lay is well established,” contends Skeels. “The question is back to the pipe design, its mill quality, and the efficacy of its fabrication in the field.
“I think we’re coming to a point where it’s the fabrication methods and the material that we have to design in for the pipeline itself, not the installation vessel. Wall thicknesses are getting too great for pipe mills to handle with consistent quality, and conventional weld approaches are becoming more and more suspect, requiring difficult pre- and post-heat treatment, not to mention understanding the complicated weld metallurgy involved. Welding rod material and welding procedures are being taxed to their theoretical limits. Insulation and insulation integrity (not cracking or absorbing water) is becoming a growing concern as subsea facilities continue to move farther out in 40° water. HIPPS [high-integrity pipeline protection system] will also play a big part in keeping riser material choice and wall thickness to reasonable limits.”
With water depths getting deeper and deeper, pipeline infrastructure has also had to change to accommodate harsher environments, according to Shaw.
“For example, wall thickness has increased to handle the ultra-high pressures,” he points out. “This has, in turn, posed a challenge for offshore pipeline inspection service capabilities, as many conventional in-line tools are no longer up to the task.”
Hub design
Nooteboom sees a long-term advantage for deepwater hubs.
“As declining reservoirs will create excess capacity on existing facilities, (long-distance) tiebacks will allow remote reserves to be economically produced to these existing facilities,” he says. “This will, on one hand, extend the economic lifespan of the existing (hub) facilities and, on the other hand, bring the development cost of remote deepwater reservoirs within economic reach.
“Where such hub facilities don’t exist and the development of a small reservoir with a standalone production facility is not economically viable, an economic solution may be found by developing several smaller remote reservoirs concurrently and producing them to a common new-built hub. Several operators may collaborate and collectively develop their respective reservoirs as tiebacks to a jointly owned hub or encourage a third party to build and operate this facility. Independence Hub, in Mississippi Canyon Block 920, is an example of such a joint development among Anadarko, Kerr-McGee [now part of Anadarko], Dominion, Spinnaker, Devon, and Enterprise.
“We are likely to see more of these collaborative developments with jointly owned/operated hub infrastructure; or where third parties develop hub facilities to accommodate multiple operators where these operators would otherwise not have been able to economically produce their reservoirs as standalone developments.”
Subsea hubs also will be designed for retrofit of subsea separation, pumping, and compression modules, as needed to suit changing production scenarios. ]
