For 19 years, the Deep Offshore Technology International Conference & Exhibition (DOT) has offered a forum to address technical issues, introduce pioneering technology, and discuss lessons learned while exploring, developing, and producing oil and gas in deep and ultra deepwater basins around the world. DOT will continue this trend Oct. 10-12, 2007, as it presents Deepwater & Arctic Ocean of New Opportunities.
Over the past two decades, DOT has striven to provide a conference where knowledge is shared and captured electronically to be distributed within the industry. Through this sharing, the industry increases its understanding of the challenges in frontier areas and mature basins. Industry trends are identified as well.
DOT 2007 will bring the world’s brightest technological minds together at the Stavanger Forum in Stavanger, Norway. Statoil will host this event, which will focus on the complexities of arctic drilling as well as new challenges in harsh conditions experienced in Norway and Russia and around the world. The conference will focus on the technology needed to succeed in these environments.
New opportunities are present in mature basins as well, where conventional fields have served as the testing ground to qualify new technology for use in frontier areas.
The DOT technical program serves as the major highlight of the conference year after year. The three concurrent tracks will focus on (Track 1) floating facilities, risers, and construction and installation; (Track 2) subsea technology, well construction, and flow assurance; and (Track 3) arctic technology, lessons learned, and special sessions.
DOT will kick off on Wednesday, Oct. 10, with a networking breakfast, followed by an opening plenary session, which will include a welcome and introduction from Eldon Ball who represents PennWell Corp., welcome to Stavanger from Mayor Leif Johan Sevland, the chairman’s remarks from Statoil’s Arnt Olufsen, and a keynote address given by Statoil’s Helge Lund. Dag Jenssen, president, Aker Kvaerner Deep Water Business Unit will give the contractor’s perspective, and Geir Aune, chairman of the board for Ocean Rig will provide the drilling contractor perspective.
Sneak peek
This preview of selected papers from each of the DOT tracks serves as a sampling from the more than 90 presentations that make up the conference program. Some scheduling change is possible.
Roberto Oliveira, Petrobras, will present his paper, “Subsea Oil/Water Separation: Overview of the Main Processing Challenges,” in Session 2, Track 2.
Due to the increase of Petrobras’ deepwater oil reserves and considering that a good part of the reserves are made up of heavy oil, there is currently a focus on improving technology for primary processing facilities, especially those related to subsea processing. According to Oliveira, there is a need to develop and qualify more compact and efficient separators for subsea application to replace the huge traditional systems based on gravity separators.
For deepwater processing, Oliveira says it is essential to use robust and efficient equipment that is compact and as close as possible to being maintenance free. This is an important point of discussion involving engineers from different areas. There exists a compromise between compactness and efficiency. In general, he says, simple and robust equipment has limited performance and is not able to achieve the desired separation efficiency. This is a major problem for any subsea processing system, especially those designed for heavy oil separation in deepwater.
According to Oliveira, demand for compact subsea processing equipment has spurred initiatives for several R&D projects at Petrobras. Pursuing primary processing compactness, Petrobras’ R&D team has worked on many initiatives, such as qualifying hydrocyclones for oil/water separation involving high oil content and testing new compact electrostatic devices. Because compact separation systems are too sensitive to feed fluctuations (slugs, for instance), Oliveira says that Petrobras also is making a significant effort to develop and improve intelligent control systems to minimize performance deterioration on this equipment.
Petrobras’ experience has shown that reducing the shear imposed when the flow passes through valves, pumps, and lines is beneficial for the separation process. Lab tests also have proven that adding a demulsifier through the gas-lift injection line can optimize its performance and has a huge impact on oil/water separation efficiency. According to Oliveira, both recommendations were considered as part of the premise adopted for the subsea processing design.
Extensive modeling and experimental work have been conducted using static and dynamic simulations aimed at developing mathematical models for the newly developed processes. Coupled simulations of multiphase flow with the dynamic separation equipment modules have allowed researchers to identify possible upsets to the system. Experimental lab research has been developed to characterize the type of oil/water dispersion existing in subsea operational conditions, and oil-in-water content meters are being developed. The presence of foam and solids has also been investigated, Oliveira says. According to Oliveira, these will be crucial for controlling the subsea separation process because the oil-in-water concentration in re-injected water is the main controlling parameter.
Processing heavy oil subsea is much more than just installing separation facilities on the seabed, Oliveira says. Many bottlenecks exist, and they need to be resolved to reach the necessary level of performance.
Petrobras’ subsea processing design adopts new technologies and concepts based on a scenario in which any kind of dispersion, including stable water-in-oil emulsions, could be processed in any range of water cut. Oliveira will discuss these advances in detail in his presentation.
“Sand Production Management for Snorre B Subsea Development: Lessons Learned and Actions Taken” is scheduled for Session 2, Track 3.
Kjell Lejon of Statoil will talk aboutSnorre B, a combined drilling, production, and injection semisubmersible that has been in operation since 2001. The development consists of two subsea production templates each supplied with eight well slots and two manifold modules. Production from the subsea template is routed through flexible production risers to the Snorre B topside for processing, Lejon says.
Inspection and evaluation carried out in 2005 revealed severe erosion in topside chokes onSnorre B.
In 2005, inspection and evaluation revealed several concerns related to sand production:
- Severe erosion in topside chokes
- Subsea erosion probes reached maximum service life and could not be replaced without pulling the christmas tree. This had direct implications for the sand management strategy
- Potential for erosion in subsea chokes
- Detailed erosion modeling indicated higher erosion potential on the subsea piping compared to erosion probes
- Subsea christmas tree and manifold piping was not easily accessible for inspection because of piping complexity and thermal insulation
- Plans for extending the service life of the field beyond 20 yrs (IOR project).
Lejon explains the work performed and actions taken to establish the status of the production system, particularly the subsea components. His presentation also highlights problems associated with controlling and monitoring sand production and erosion at a subsea development, and focus on the actions taken to ensure that the system can be operated at optimal production rate.
Lejon believes Statoil’s experience on theSnorre B semisubmersible production unit will be relevant for all subsea developments with potential sand production.
Statoil will continue in Session 2, Track 3 with “Environmentally Friendly Production Drilling in the Barents Sea - Experiences from the Snøhvit Field Development.” Georg Vidnes will present this paper.
The Snøhvit field development was the first production drilling and completion campaign performed in the Barents Sea on the Norwegian Continental Shelf, Vidnes explains. The Snøhvit field is 143 km (89 mi) off the coast of Hammerfest in northern Norway. Snøhvit field is a subsea development, producing through a dedicated pipeline to the Snøhvit LNG plant based on Melkøya Island. The field is scheduled to be in commercial production in the fall of 2007.
The field is remotely operated from shore. The CO2 from the wellstream is extracted onshore and transported back to the field in a separate pipeline for reinjection in a separate CO2 injection well.
The production drilling and completion campaign began in Dec. 2004 and was completed in June 2006 with the semisubmersiblePolar Pioneer. The project developed and implemented several new technologies and methods to ensure an effective and environmentally friendly drilling operation.
Through thorough planning and preparation, the project delivered wells positioned correctly, drilled effectively, and completed without any harm to the external environment, Vidnes says. The environmental demands and expectation from Statoil, NGOs, and the government were strict and required a new approach in the pre-operational phase. The project took onboard the environmental challenge and strived to push the limits in all parts of the project concerning environmentally friendly solutions, Vidnes says.
All discharged chemicals fell in the non-toxic for environmentally friendly category (yellow and green chemicals). A new oil-based mud had to be developed to achieve this level of discharge as did a new green BOP control fluid and a yellow drillpipe dope. Wells had to be cleaned with mechanical tools only. All of the casing and tubing, ranging from carbon steel to duplex materials, were run without thread dope.
For the last part of the field development, all of the drill cuttings in the sections drilled with the riser were collected for onshore disposal. The rig was prepared as a tight drilling and completion rig. An environmental awareness day was held for all personnel to ensure the correct focus prior start of operations.
Technical drilling challenges included well design, well positioning, and directional drilling in a new area with unstable formations and little knowledge of rock behavior. Logistics posed an additional challenge.
M. G. Starkey and C. S. Horan, ExxonMobil Development Co., will present “Achieving Reliability through Deepwater Subsea Equipment Standardization: Outline of Key Pro-active Processes and Tools” in Session 3, Track 3.
According to Starkey and Horan, subsea equipment standardization can result in improved reliability as well as significant cost and delivery schedule reduction through vendor and operator efficiencies. Using well understood, familiar equipment designs and implementation processes improve quality and reliability. Standardization also improves installation efficiencies and facilitates development of local content capabilities. For standardization to meet these objectives, however, it must be supported by key pro-active processes that address technical definition, qualification, quality assurance, and management of change, Starkey and Horan say.
According to the authors, ExxonMobil is pursuing equipment standardization for its future deepwater subsea portfolio. Toward that end, the company has identified and developed several principles and tools for achieving success. These were based on lessons learned from recent deepwater projects, vendor input, and a review of previous standardization initiatives.
The presentation will explain the principles and processes put into place and will provide details about tools being used that could benefit others in the industry.
Also to be presented in Session 3, Track 3 is a Statoil paper titled “Technology Qualification in Tordis IOR Project.” Rune Mode Ramberg will be the presenter.
According to Ramberg, the objective for the Tordis IOR was to accelerate and increase oil recovery from the Tordis field from 49% to 55%. To manage this, Statoil had to change the production strategy to low-pressure production and to introduce a subsea processing station with water removal and disposal. The unit (Tordis SSBI) includes subsea oil/water separation, water injection, sand handling, and multiphase metering and boosting.
Startup of the Tordis SSBI is scheduled for 4Q 2007. An extensive technology program was begun prior to project startup and will be carried into the project execution phase.
In his presentation, Ramberg will outline technology qualification activities and how they have been carried out with respect to the Tordis IOR project schedule. The author also will discuss the pros and cons of conducting technology qualification activities within the project schedule.
Tim Farrant will present “Drilling Riser, Wellhead, and Conductor Structural Integrity Management in New and Remote Offshore Regions” in Session 6, Track 3.
According to Farrant, assuring structural integrity of the drilling riser, wellhead, and conductor at new sites and remote locations requires a careful approach to risk management. Uncertainty about environmental conditions, practical constraints such as equipment and accessibility, and optimization of life-cycle costs for potential future developments has led to a range of risk management strategies that have been tailored to local conditions and project requirements.
Risk management ensures structural integrity for the drilling riser through the entire construction and installation process.
Farrant will discuss the risk management process and factors such as the ocean current climate, soil conditions, conductor strength, the well’s life cycle, and mitigation measures such as hardware upgrades, operating procedures, riser monitoring, and VIV suppression devices. Farrant also will talk about future trends, focusing on advances in hardware design and modifications to existing equipment.
Farrant’s conclusions are based on BP’s experience drilling conventional wells in regions such as Sakhalin Island and West of Shetland. Additional experience considered in the presentation includes HP/HT wells in the Caspian Sea and Egypt’s West Nile Delta.
Session 7, Track 2 will include a paper by Leonid Dykhno, Shell Global Solutions (US) Inc., “From Deepwater to the Arctic with Flow Assurance Technology.”
Over the past decade, flow assurance applications have been extremely successful in many offshore deepwater oil and gas project developments where the cold ambient sea-bottom temperature and water depth pose enormous technical challenges, Dykhno says. There are many similarities between the severe operating environment in deepwater and the harsh winter conditions that exist in arctic offshore and onshore fields.
The objective of this work, Dykhno says, is to demonstrate that flow assurance technology developed for the deepwater environment shares challenges and solutions that are equally applicable in oil and gas fields in onshore and offshore arctic regions. Flow assurance issues in arctic regions can be integrated into a holistic system design that will be critical to achieving successful developments of arctic fields, Dykhno says.
Although preventing problems from occurring is the principal objective in developing operating strategies, Dykhno explains, the integrated approach also includes risk assessment, mitigation techniques, and remediation alternatives in the case of blockage.
Dykhno’s presentation shows how an integrated approach to upstream developments should apply from the time of planning exploratory drilling through production and surveillance.
“Overview of the USA Department of Energy Ultra Deepwater R&D Initiative” will be presented in Session 7, Track 3.
Chris Haver of Chevron ETC, reveals a new program of research, development, demonstration, and commercial application of technologies for ultra deepwater (UDW) is under way in the US. The initiative links industry, suppliers, researchers, and government in a cooperative, focused effort to increase hydrocarbon reserves and production. According to Haver, the initiative is similar to the successful Norwegian DEMO 2000 program, which will also be discussed in this Session.
The program identifies four generic Gulf of Mexico fields that frame current opportunities, facility requirements, operating limitations, and technical gaps that challenge developments today. These challenges have been matured and jointly prioritized by the Research Partnership to Secure Energy for America (RPSEA) and DeepStar subject matter experts into a promising ultra deepwater program portfolio.
Another Session 7, Track 3 paper will be presented by Morten Wiencke, DEMO 2000, Research Council of Norway. His paper, “DEMO 2000 Stepping up in Deepwater and Arctic” explains the DEMO 2000 program.
Weincke explains that the DEMO 2000 program provides field testing of new technology from innovative solution providers in Norway developing new equipment, systems, or processes for the offshore petroleum industry. Piloting actual operating conditions is key to obtaining “field proven” status and bridging the gap from R&D to commercial success. The cost and risk of piloting are shared by a three-way partnership among the supplier, oil companies, and the government.
Weincke cites recent examples, including deepwater satellite development using seabed processing, water management, boosting, and long multiphase tiebacks; subsea-to-beach with large scale subsea gas compression; and new technology for permanent in-well or seafloor seismic instrumentation offering high-definition reservoir performance monitoring.
Weincke says DEMO 2000 aims to step up the program further by using field trial opportunities on Norwegian offshore installations as well as other continental shelves, notably the GoM, Brazil, and West Africa, which are important export markets for Norway, with similar technology demands. Weincke will present an outline of DEMO 2000 achievements.
Session 8, Track 1 will feature a paper from Saipem titled “The Bundle Hybrid Offset Riser, a Novel Riser Tower Concept for the Development of Rosa Field.”
Speaker Giulio Fatica discusses deepwater field development using FPSOs offshore West Africa, which has required the definition and the implementation of a new generation of complex riser systems to meet stringent flow assurance requirements and ensure long-term structural integrity. As an example, Fatica says the congested layout atGirassol FPSO has led to the selection of a single riser tower to accommodate the large number of risers for the subsea tieback of the Rosa field.
The Bundle Hybrid Offset Riser (BHOR) is a tower concept that was developed by Saipem and successfully installed on the Rosa field. The Rosa BHOR consists of a vertical bundle of risers tensioned at the top by the combined action of the bundle buoyancy foam and a decoupled buoyancy tank. The Rosa BHOR also implements four pipe-in-pipe production bundles, where the production and the associated gas lift risers share the same dry insulation and are contained in a water-tight carrier to meet stringent thermal requirements.
The strategic geographical position of the Petromar Yard in Soyo, Angola, resulted in a key element for the project’s success, Fatica says, noting that a significant upgrade investment has allowed smooth execution of the complex BHOR fabrication procedure, meeting the required quality levels within the tight project schedule.
Finally, Fatica explains, a new set of installation procedures was designed specifically to cover the complete BHOR installation campaign to control and minimize the fatigue damage during transportation and to allow the complex up-ending and docking operations in proximity of an existing and producing FPSO.
Brendan Campbell, Force Technology, will discuss the challenges in developing remote, arctic locations during Session 8, Track 3 with his paper, “Long Arctic Subsea Tie Back Control Buoy.”
According to Campbell, two major challenges of arctic development are the remote location and the risk of ice collisions. Total, in conjunction with Force Technology, has reviewed options for production facilities for arctic conditions, one of which is full subsea development.
One of the primary objectives for this full subsea concept, Campbell says, was to design an unmanned surface buoy moored in the Shtokman field. The buoy has to be capable of controlling and supplying uninterrupted power to the subsea installations through umbilicals.
The full subsea concept is based on similar projects in production, for instance Canyon Express and ongoing projects in Norway like Snøhvit and Orman Lange. For future developments, the distance to the onshore receiving facilities is getting longer. To date, Snøhvit is the longest at 140 km (87 mi). This design addresses the first and second phases of an arctic development.
Campbell says remote control and command of the subsea equipment is an absolute necessity. Owing to the distance, Campbell suggests a surface unmanned floating buoy concept rather than incorporating all of the hydraulic functions in long umbilicals for both phases. Subsea development of the field is based on moderate power demand during the first 10-11 years of production (Phase I), followed by a period where the power demand is substantially larger (Phase II).
This floater will be a “not normally manned” installation, Campbell explains. Access to the floater for maintenance will be possible in good weather. For all other conditions, the floater will be designed to operate without intervention.
Total and Force Technology designed the floater with the following constraints:
- Unmanned system
- Capable of withstanding environmental loads (ice ridges)
- Single modular design adaptable for both phases I & II
- Ability to disconnect and reconnect in extreme ice conditions.
Roberto Di Silvestro, Saipem, will present “Multi-Pipe Separators, a Novel Approach to Deep Water Subsea Separation,” during Session 9, Track 2.
Subsea separation and boosting of produced liquids from associated gas is recognized as an efficient way to deplete Oligocene heavy oil reservoirs in deepwater fields, Di Silvestro says. In fact, the wellhead pressure can be reduced significantly, the recoverable reserves increased, and the field flowline and riser system simplified as a consequence of relaxed flow assurance requirements.
Traditionally, separators are thought of as pressure vessels that grant some residential time to the multiphase flow to allow gravity separation of the different phases. Design and installation of such large vessels in deepwater can become a real issue because of the shell wall thickness required to withstand the hydrostatic pressure.
The company has developed two subsea separator concepts using a system of pipes rather than one or more large vessels. The multi-pipe separators allow standard or rolled pipes with reasonable wall thicknesses to be used, reducing procurement and manufacturing costs as well as lead time. The multi-pipe separators also are well suited for local fabrication, Di Silvestro says.
