Solution for subsea tiebacks can lower reserves hurdle rate

Deepwater operators conventionally focus on identifying fields in the area of 100 million bbl or greater. It takes such large reserves to justify the expense of producing with local surface process facilities in great water depths. This scenario works as long as there are enough large fields to fuel the cost of development, but only around 40% of deepwater finds today are in the range greater than 100 million bbl of recoverable oil equivalent.

By comparison, only 10% of the fields in the Gulf of Mexico shelf are greater than 100 million bbl of recoverable oil equivalent. How can current and future marginal fields be produced economically - is the question being posed by oil companies.

While not billion bbl world beaters, 50-100 million bbl fields would be considered very respectable if they were located in conventional water depths, said Jim O'Sullivan, Director of Technology for Brown & Root Energy Services (BRES) Deepwater Operating Unit. The problem is not the reserves, because they follow the classic log normal distribution of field size. Rather, the problem is the cost of recovering them using traditional approaches.

Subsea tiebacks

Surface production facilities in deepwater and ultra-deepwater are prohibitively expensive for all but the largest of finds. The accepted method of production, in many cases, is the subsea tieback. Using this system, a well is completed and production is piped from the subsea wellhead to an existing platform for processing and export. This is by no means an inexpensive process. There are a variety of factors involved in a deepwater tieback that makes it a costly endeavor. Too costly in fact to justify most deepwater finds. To overcome this high cost, O'Sulliven said the most expensive and troublesome aspects of an extended subsea tieback were revisited.

Twin pipelines, either pipe-in-pipe or insulated are typically used to tie wells back to production platforms on the shelf in order to provide a pigging route. The temperature at the deepwater wellhead is near the freezing temperature of water at the surface, while the production coming out of the ground is under very high pressure with a temperature near the boiling point of water at the surface. When the hot production fluids encounter the cold temperature at the seabed two classic problems quickly develop. First, as the production temperature drops to below the cloud point, paraffin wax drops out of solution, bonds to the cold walls of the pipeline, restricting flow and causing plugs. As the production continues to cool the water in the produced fluids begins to form ice crystals around natural gas molecules forming hydrates and flow is slowed or stopped.

To combat these problems insulated pipe, pipe-in-pipe, towed bundles with heated pipelines, and other "hot flow" solutions are installed. This does help ensure production, but the cost is very high and some technologies, such as tows, have practical length limits. Such lines can easily cost $1 to $2 million a mile, putting it out of reach of a marginal field budget.

Another problem with extended tiebacks, which is what would exist in ultra deepwater where conventional facilities are easily 60 to 100 miles inshore, is communication with the subsea and subsurface equipment. Communication and control are traditionally achieved either by direct hydraulics or a combination of hydraulic supply and multiplex systems that uses an electrical signal to actuate a hydraulic system at the remote location. Direct hydraulics over this distance would require expensive, high-pressure steel lines to transport the fluid quickly and efficiently over such long distances and even then the response time would be in the order of minutes. There also is a problem with degradation of the electrical signal over such lengths. This also interferes with the multiplex system and requires the installation of repeaters along the length. While these problems can be overcome the solutions are not inexpensive.

A third major hurdle to cost-effective deepwater tiebacks is well intervention. A floating rig that can operate in ultra deepwater is not only very expensive, as much as $200,000 a day, but difficult to secure since there are a limited number of such vessels. It doesn't take much imagination to envisage a situation in which an otherwise economically viable project is driven deep into the red by an unexpected workover. Anticipation of such expensive intervention has shelved many subsea projects.

Novel solutions

These are the major issues BRES' newly formed Halliburton Subsea Services group was charged with addressing. O'Sullivan said the goal was to cut costs so deepwater fields, which would not be given a second look today, could be developed profitably.

"BRES wants fields with reserves as low as 25 million barrels to be economical to develop," O'Sullivan said. To achieve this, the basic components of the standard tieback must be either redesigned or eliminated altogether. For instance, the tieback pipeline could be reduced from two lines to one and be installed as a bare pipe if it were not for the flow assurance problems caused by paraffin and hydrate formation. To address this, BRES developed a Cold Pipe technology that reduces the temperature of the production stream rapidly as it flows from the wells. O'Sulliven said the device is basically a heat exchanger that rapidly lowers the temperature of production to the ambient temperature at the seabed. The goal is for paraffin and hydrates that are formed to be kept in suspension and transported to the production facility as a cold slurry.

The most difficult part of the process, according to O'Sullivan, was keeping the paraffin from attaching to the inside of the line while it is cooling. This process for making paraffin slurries was successfully demonstrated. The demonstration unit was built at Kellogg Brown & Root's (KBR) downstream test facility in Houston. The facility can handle both very hot produced oil and very cold water chillers to simulate the deep ocean bottom. Paraffin slurries were formed and transported through a simulated flowline with no wax build-up in the slurry maker or the flowline.

The hydrate formation issue is now the challenge, O'Sulliven said. There are no chemicals involved in the slurrification of the paraffin, and our goal is to form stable hydrate slurries with no chemicals, or minimal chemicals. Still in the development stage at Halliburton's Westport Laboratories in Houston, the coupling of the hydrate and paraffin slurry technologies would not only eliminate the expense of pipe-in-pipe or insulated pipe, but also dramatically reduce chemical usage. The resulting slurries do increase the viscosity of the fluid, but deepwater fields in the Gulf of Mexico have so far had relatively high wellhead flowing pressures. The biggest penalty will probably be a one-size increase in pipe diameter.

Pigging such a single line system could be accomplished using a subsea pig launcher and/or gel pigs. The gel pigs can be circulated down a riser from a work vessel that mixes the gel and through the pipeline system to the host platform. BRES is jointly developing with a major operator a 10,000 ft. subsea pig launcher.

In the case of a planned shut in, the downhole tubing and flowline can be treated with methanol, or glycol, to avoid hydrate formation in the stagnant flow condition. It the case of emergency shut-ins, there will be a time span after which untreated fluids will begin to form hydrate aggregations that will eventually lead to blockages. The solution may be planned remediation. Technology today allows very exact flowline surveys. Coupling these surveys with improving multiphase flow predication methods could allow the areas of probable hydrate formation to be predicated. These areas would be equipped with heaters or other equipment to break up the hydrates, possibly activated by ROVs. Further, it may advantageous to intentionally create an area where hydrates would form, such as a low spot, or trap, in the flowline in order to know where to remediate or insulate.

Control buoy

Within a new low cost architecture, the source of the methanol and the gel pigs would be an unmanned control buoy moored above the subsea wells. This buoy design is similar to those used in the oceanographic meteorological industries. The design is circular with a very low profile, about 75-ft in diameter with 30-ft of draft. This low profile allows the buoy to conform to the motion of the waves. The buoy will have the capacity to hold up to 6,000 gallons of fluids for injection or to fuel the electric power generators. The buoy also contains the hydraulic and electric communication and control system, their associated telemetry systems, and chemical injection pumping system for the subsea and downhole production equipment. O'Sullivan said it is less expensive to install this buoy system than to tieback a subsea well 20 miles to a surface facility. For distances over 20 miles the savings is even greater because the buoy costs no more. Additional savings are realized from the fact that pumping and controls equipment will not be needed on the host surface facility.

Diesel generators will power the first generation of buoys. O'Sullivan said in the future it would be possible to apply fuel cell technology to the concept. These cells would be similar to those currently being tested by the automotive industry. When this becomes possible, the buoy may run on methanol fuel cells, drawing from the methanol supply stored on the buoy for injection. The generated electric energy could also be used to power seafloor multiphase pumps in deepwater regions with low flowing pressures such as found in the South Atlantic.

There will be direct access to and control of the wells and flowline from the buoy via a hybrid riser umbilical. The flexible hybrid riser will run from the buoy to the seafloor with a 4-in. high-pressure bore in its center and electrical, fiber optic, and fluid lines on the outside. The main axial strength elements are wrapped around the high pressure bore rather than the outside diameter, making the riser more flexible and lighter. This high-pressure bore can be used to melt hydrate plugs by de-pressurizing the backend of the flowline. The riser bore can also transport gel pigs to the flowline, or perform a production test on a well. Use of the riser bore will require manned intervention in the form of a work vessel moored to the buoy. The vessel supplies the health and safety systems necessary for manned intervention, and the associated equipment such as gel mixing and pumping or production testing.

The buoy would be held in place by a synthetic taut mooring system. The synthetic mooring lines are buoyant so they do not put a weight load on the buoy. This allows the same buoy to be used in a wide range of water depths. The physical mobility of the buoy will make it a viable solution for extended well testing. This would allow a company to conduct such tests before committing to a long-term production solution. The buoy offers all the basic components needed in an extended test scenario including access, control systems, chemical injection systems, and the ability to run production through a single pipeline.

"Until you produce for a while you really don't know what you have," O'Sullivan said. If the well is proved to be a producer, then the buoy could be left in place for the life of the field.

Market potential

The initial push for this concept will be marginal fields in the more mature, deepwater markets such as the Gulf of Mexico and Brazil. There is future potential offshore West Africa, but O'Sullivan said there are still so many large deepwater plays off Africa that have not been produced that it will take time for the focus to shift to marginal fields.

While the cost savings will make this an attractive option for marginal fields, O'Sullivan said he thinks the concept can be expanded to produce large fields as well. The system has the potential to produce fields with a number of wellheads in a manifold arrangement.

The proposed concept is novel, but with the exception of cold pipe technology, it is an application of existing technology. The combination of a high-pressure, small-bore riser with umbilical wrapped around it is an existing technology, but O'Sullivan said the machinery will soon be available to use a composite pipe as well as a flexible riser for the central bore and strength member.

In addition to marketing this system and possibly leasing the buoys, Halliburton is interested, through an operating lease, in the service side of this concept, supplying the chemicals, and fuel to these buoys and performing intervention work on the buoy and on the well/flowlines through the high-pressure umbilical.

Adoption

While it may be a lot to ask that an oil company adopt two novel solutions, the control buoy and cold pipe, O'Sullivan said the key will be to introduce these systems in series starting with the buoy and umbilical. The buoy and umbilical can operate as a floating control system to relieve some of the impact on host platforms where subsea fields are tied back. At the same time it will allow the industry to gradually adopt the new concept. He said the buoy and umbilical are a more comfortable extension of existing technology than the cold pipe concept. Along the same lines, synthetic mooring lines are also a new technology, but are receiving growing acceptance in the industry. Once the buoy is brought onto the market, the system will expand to include the cold pipe technology.

The goal is to have this concept in the field test phase within 18 months, O'Sullivan said. "What we're looking for is a pilot test opportunity for the cold pipe technologies in the field," he said.