Subsea wellheads may soon be all electric.
The value added by the ever-increasing sophistication of subsea completions and multilateral technologies were critical completion issues at the 1997 Offshore Technology Conference. Both concepts are born of the need to make the most of every completion investment.
Subsea completion configurations allow wells drilled in deep, and inevitably ultradeep, waters to be produced through existing host platforms miles away, rather than through new floating structures whose cost of construction and deployment adds immensely to the economic burden each well must carry.
The attraction of multilateral completions is as much for the future as the present. Now they offer, theoretically at least, a method for exploiting any number of zones from fewer wellbores. Multilaterals are different from barefoot, high-angle ancestors that are little more than a series of sidetracks.
Instead, multilaterals (ML) aim for mechanical isolation of each branch from every other branch or from the main well bore. Each branch of a true multilateral is lined and can be easily re-entered for servicing. And, finally, true multilateral completions are hydraulically isolated, meaning they can be selectively produced without interfering with other branches.
Multilaterals beget "intelligent wells"The goal now in sight for multilateral proponents is "smart well" technology with which downhole functions can be manipulated from the surface through electrohydraulic controls, virtually eliminating the high cost of rig intervention. Several companies are already laying claim to at least modest accomplishments in this area by marrying such downhole tools as isolation packers and sliding sleeves to surface controls.
Halliburton's Clark E. Robison discussed those efforts in "Overcoming the Challenges Associated With the Life Cycle Management of Multilateral Wells: Assessing Moves Towards the Intelligent Well" (OTC paper 8536).
His conclusion is that widespread acceptance of multilaterals offshore will come with smart well technology. In other words, offshore, where risks are higher than on land, the ability to control the commingling or isolation of the various flow streams from the surface and perform other tasks without the large intervention costs associated with a rig will tip the risk versus benefit scales in the favor of multilaterals.
Wells employing surface controlled isolation packers have been installed and touted as firsts in smart well completions. But they are only the initial steps towards the future of the technology. "The economic advantage that can be derived from the application of this new technology will not be fully realized until a system that can provide realtime control over commingled production streams from the respective lateral wellbores is available," Robison said.
Those systems are undoubtedly near at hand, some closer than others. But such futuristic tools as downhole sensors capable of viewing into the formation to track fluid movement and wireless telemetric control over data gathering and downhole tool actuation are still in early development. Reliable electro-hydraulics to replace wireline and other intervention tools to move downhole controls and telemetry control to hardwired systems, on the other hand, are a reality.
The principles of multilateral completions have barely been described, but already engineers are looking for new concepts. An OTC paper presented by Anadrill Schlumberger's Mark Stracke and Eric Neme, Camco's Dwayne Leismer, and Jean Buytaert entitled "Integrated Drilling Services - A New Concept for Multibranch Technology " (OTC paper 8539) describes a system "designed to provide a prefabricated sealed connection between the branches and the main trunk of the well."
The assembly is run in the hole in the closed positioned in a casing sub. Once positioned in an underreamed section of the hole, the outlet is articulated outward on a hinge, like a trap door opening in the side of the casing, and locked open. The result is a casing section with the start of a cased, sealed branch.
Once casing is cemented a deflection tool is run into the outlet to orient drilling. A cap at the end of the extended branch, located to facilitate cementing around it, is drilled out to begin the lateral borehole.
The system, which provides a mechanical connection and seal between the main casing and the lateral liner, also permits through-tubing accessibility to all branches while leaving the main bore unrestricted. The positive mechanical main-lateral connection is "complimented by a retrievable liner hanger packer design" for hydraulic isolation of the lateral. But just as importantly, the system eliminates rig milling time.
Multibranched wells as simple multiple wellbores drilled at angles from the main wellbore are not new. However, the ability to access and affect each completion without interfering with others in the main or other lateral well bores is. And it is evolving quickly.
In their paper entitled "Development & Application of a Through Tubing Multi-Lateral Re-entry System " (OTC 8538), Robert Brooks of Pressure Control Engineering and J. Jay Stratton Jr. of Occidental Petroleum of Qatar say "the selective entry, and re-entry of single, or multiple lateral wellbores is an engineering problem that is still being addressed."
To effect a dual lateral offshore Qatar and to add to the literature on the subject, Brooks and Stratton documented development and installation of a tubing nipple/access window located across the casing exit. They were able to successfully divert coiled tubing out of and back through the access port five times while making 19 coiled tubing runs during the completion, stimulation, and logging of the laterals and main branch.
Subsea completions on the frontierWhile many deepwater subsea completions center around high production rates, Petrobras' R. Camargo, I. Alves, and M. Prado analyzed such artificial lift for subsea applications as gas lift, electrical submersible pumps, hydraulic jet pump, and progressive cavity pumps. Their paper - "Advances in Artificial Lift and Boosting Systems for Subsea Production" (OTC 8475), discusses Petrobras' effort to analyze alternatives to gas lift before the need arises.
Because of its familiarity through years of onshore application, the authors said, gas lift is the only artificial lift method used extensively for subsea completions. It also holds several technical attractions, such as excellent flow rate range, operational flexibility, and it is the only method with a history of success in subsea completions.
But circumstances may arise for which gas lift may not be the best first choice. For instance, as in the latest Gulf of Mexico deepwater subsea installations, injected gas could increase flowline pressure when wellheads and platforms are separated by great distances. Gas lift systems also require additional facilities to recycle and compress the gas, adding costly weight to offshore platforms. Gas injection could also add to cooling, wax, and hydrate problems.
To address these problems Petrobras is proposing to add gas lift only at the riser base. They are currently searching for a shallow test well, preferably in more than 1,000 meters water depths, and at a significant distance from the host platform.
Electrical submersible pumps offer excellent flow rate range and have an efficiency in the 500 hp range of about 40% - well exceeding gas lifts 20% general efficiency rating. On the downside, ESPs need a variable drive and do not handle high gas-oil ratio fluids or formations that produce sand. Petrobras is currently working on necessary adaptations of ESP fittings and cables to long distance and deep water to install an ESP in a well in their East Albacora field in 1,109-meter water depths 6,500 meters from the host platform. The authors note that the first subsea completion ESP, installed at the 4-RJS-221 well in the Carapeba Field in Oct. 1994 is still running.
Petrobras is also working with two consortia (Reda/BMW and Centrilift/Geremia) on the main obstacle to progressive cavity pumps in subsea completions - adaptation of the system to work with a submersible motor. By the end of 1997, they hope to be field testing them in the Pargo Field.
Something of a specialty in the subsea hardware industry is subsea controls. As ABB Seatec's John Allen explains in his presentation "Cost Effective System Solutions for Deepwater Production Controls" (OTC paper 8480), since the acceptance of multiplexed electro-hydraulics in subsea production controls, the technology has made significant progress. As a result, umbilicals are being minimized and transmission distances extended.
Lightweight subsea control modules have made ROVs easier to handle, minimizing costly interventions. These and other new electrical subsea applications have led to the need for distributed intelligent control systems. The approach, said Allen, is modeled on that used in industrial process control applications in which sensors and actuators are intelligent out-stations of a distributed control and instrumentation system.
The upshot of that approach is smaller, interconnected packages in an architecture that can be expanded or swapped out easily by ROVs. Eventually the approach could lead to all electric systems, which are an attractive option in deep water where subsea completions are widely separated from the control panel.
Finally, sensors are being developed for pipeline monitoring to assist operators in stemming blockage or pipeline failures. Continuous fiber optic monitoring and acoustic techniques are some of the monitoring options being studied. Understanding the extent of paraffin or hydrate buildup at a specific time means pigs can be launched at their optimumly effective time, saving unnecessary shut-ins and lost production or too long delayed runs that result in immovable blockages.
Subsea connectors another specialtyH.B. Skeels of FMC, M.H. Dupre of Shell Oil Products, and Hydro Tech System's O.D. Tarlton, chronicled the combining of decades-old diver operated subsea connector technology with new ROV technology.
As the industry moved beyond divable depths, simple spool piece connections were replaced with numerous diverless methods, said the authors in their paper, "Novel Use of the Diverless Hard Pipe Jumper Connection Method for Individual Well Completions" (OTC paper 8476). That required additional hardware or structural bracing on the subsea facility. The same is true for diver installed umbilical connections replaced by multi-bore connectors.
Now, say the authors, the cycle has come full circle back to simpler connector procedures. The first diverless, spool piece flowline connections between separately installed flowlines, umbilicals, and individual subsea trees, report Skeels, et. al., has been done at Shell's Gulf of Mexico Tahoe field. According to the paper, the approach was driven by "the need for reduced project cycle time, the push toward equipment standardization, and the expanded capabilities of ROVs and their toolings."
The field will have between six and ten subsea satellite completions in about 1,800 ft of water, connected to a 12-mile distant host platform. Each completion required flowlines which accommodate paraffin, hydrate, and corrosion remediation while differing in such things as flowline size, insulation, multiple or future well connections, and interventions.
In a related paper, "Multiple Channel Wet-Mateable Electro-Optical Connectors: Qualification Testing" (OTC paper 8483), Ocean Design's Stewart Barlow described proving up innovative connectors for rugged subsea use. The connector passed four single-mode optical circuits and four 10-amp electrical circuits. It is built in driver-mate, stab-plate, and ROV configurations.
Qualification tests, done in conjunction with Kvaerner FSSL, included high and low temperature, thermal shock, hydrostatic pressure, mating and demating in sandy, silty seawater at one-atmosphere and at 6,000 psi, mechanical shock, and vibration.
The connectors, according to Barlow, "are a novel and unique product which provides enabling technology for the use of fiber-optics in the subsea environment." As of the paper's publication the connectors had been used on two subsea projects and have been specified for many more.
The first installment was a Phillips well in the North Sea and used 39 wet-mateable connectors. They were deployed in January 1997. The second, also in the North Sea, this one for Shell used 54 connectors and 13 jumpers to support downhole gauge technology.
Subsea completions and multilateral well technology are but a few of the rapidly expanding technologies of the past few years. The pace of development of these and other technological breakthroughs will likely continue as long as operators continue to seek oil and gas in more difficult environments while trying to hold costs in check.
Copyright 1997 Oil & Gas Journal. All Rights Reserved.