Deepwater Projects Research Articles

Overview: Deepwater Exploration and Production (June 2007)

Offshore operators and contractors continue to accept and meet new deepwater challenges. As shown in the following articles, the apparent limits of deepwater technologies are extended every year, and new records and "firsts" are achieved to meet projects' increasingly ambitious requirements. Subjects covered this year include the first operational use of a new major equipment type, one of the first secondary-recovery projects in a deepwater environment, and two very different major deepwater projects. The projects and technologies described in the articles entail significant risks, and some of the articles discuss the risk management strategies used. The technical and commercial success of these projects depends on accurate risk assessment, risk mitigation strategies, and the continued progressive development of cutting-edge technologies. The use of new technologies, however, does not always result in increased risks. In some cases, technologies are devised to mitigate an identified risk, as indicated in the articles' discussions of "improved reliability," "enhancements in functionality," "optimization," "standard interfaces and interchangeability," "increased data quality," "improved durability," "improved facility uptime," and other key themes. Management of project risks is one of the most important tasks in project management. Rather than a one-off activity that is addressed only with a workshop facilitated by an outside expert and filed away, risk management should be an ongoing process that starts with project initiation and continues through the end of facility operation. Deepwater Exploration and Production additional reading available at the OTC Library: www.otcnet.org OTC 18768 "Polyester Mooring Lines on Platforms and MODUs in Deep Water," by John F. Flory, Tension Technology, et al. OTC 18493 "Extreme Wave Effects on Deepwater Floating Structures," by Bas Buchner, Maritime Research Institute Netherlands, et al. OTC 18797 "Combined Tow Method for Deepwater Pipeline and Riser Installation," by Alf Roger Hellestø, Subsea 7, et al. OTC 18844 "Special Session: AUVs: Groundtruthing High-Resolution AUV Side-Scan-Sonar Contacts for Unexploded Ordnance in a Deepwater GeoHazard Assessment," by Lynn B. Samuel, C&C Technologies, et al.

大水深（ｄｅｅｐ ｗａｔｅｒ）の深鉱・開発の成果と深海成堆積物（ｄｅｅｐ‐ｗａｔｅｒ ｓｙｓｔｅｍｓ）との関連，および大水深の石油システムにおける重要な要因について

E&P (exploration and production) activities in deep water (area with water depth more than 500m, today) have expanded greatly during the past 20 years, along with the innovation of offshore technology for drilling, development, and production. Water depth in exploration and production drillings reaches around 3,000m and 2,300m, respectively, and many fields in deep water have been discovered and developed in the Gulf of Mexico, Offshore Brazil, Offshore West Africa, etc. Today more extensive E&P activities in deep water are recognized throughout the world and exploration in deep water has become a valuable choice of the exploration strategy for oil companies.Reviewing previous works in deep water, two geological settings have highly contributed to hydrocarbon occurrence. One is deposition of sandstone in deep-water systems such as turbidite with high porosity and high permeability as reservoir. Nearly 90% of discovered reserves so far in deep water fields are from turbidite sandstones. The other is movement of mobile strata such as salt and over-pressured shale. These mobile strata have contributed to formation of traps and also have induced faults, through which hydrocarbon migrated from source to reservoir.Also deep-water projects are characterized by following aspects ; (1) Application of modern seismic technology such as Seismic Imaging and Direct Hydrocarbon Indicator (DHI), has increased geological and economical success ratio. (2) Productivity of reservoir is critical factor to justify huge investments, and a final decision for the investments is easier and faster for reservoirs with higher flow rate and higher ultimate recovery.Exploration potential in deep water is still high, and further E&P activities will be continued. For the success in deep water, synthetic study carried by integrated teams with geologist, geophysicist, and specialized offshore engineers (reservoir, drilling, production and facility) is essential.

Precommissioning to Startup: Getting Chemical Injection Right

Summary This paper details lessons learned from practical field experiences concerning the design, construction, and commissioning of a production-chemical program for a green (new) field development. A competent program requires the interaction of various specialty-products and -services suppliers, including experts in flow assurance, modeling, fluid analysis, and specialty chemicals. All are engaged in the early stages of the project and retained as resources throughout. Areas addressed for the design and implementation of a chemical-injection system (CIS) include the following:Exploration. Collected bottomhole samples are used for fluid characterization and risk assessment of any flow-assurance issues. From these initial data, prevention and mitigation strategies, including but not limited to chemical inhibition, are developed. Chemical products can be developed and/or screened for effectiveness and applicability from this initial assessment. This includes performance screening, chemical/chemical-compatibility testing, chemical/material-compatibility testing, and product stability (which is particularly important for umbilical applications).Facility design. Specifications for the processing system and equipment are detailed, materials of construction are screened for chemical and fluid compatibility, volume and deliverability requirements are determined, and the CISs are designed.Facility construction. Monitoring and oversight throughout the construction process are performed to maintain the integrity of the initial design.Operational strategies. Strategies will be developed that address initial flowback, startup, steady-state, and shut-in techniques.Logistic strategies. Strategies will be developed that address logistical concerns (e.g., product transfers and handovers).(Pre) Startup commissioning and testing of equipment. Cleanliness and operability of the system are an absolute must. The chemical day tanks and injection lines are flushed to specification. Chemical-injection issues can be safely and successfully managed in new (deepwater) projects by proper fluid characterization and risk assessment; a field-development strategy that includes design, specialty treating chemicals, and operating plans; the involvement of specialists and specialty providers; and training and communication. Introduction As a result of location and/or depletion, petroleum resources have become harder to obtain. This difficulty has created a demand for newer and more sophisticated techniques for the recovery of oil and gas. As a function of this demand, chemical injection has become an important part in the proper performance of newly designed production systems, particularly in the deepwater area of the Gulf of Mexico. Production chemicals play an important role in the enhancement of oil and gas production—they control corrosion, prevent organic and inorganic deposits (e.g., paraffin/wax, asphaltenes, and mineral scales), enhance flow characteristics, and aid in phase separation. These chemicals can be applied through a variety of techniques, including topside chemical-injection equipment and capillary/downhole injection. Regardless of type, any CIS must be designed to be effective, reliable, forgiving, and redundant. Chemical injection used in conjunction with system design can maximize the production capacity of the system. For new, or green, fields that are in the design phase, the incorporation of chemical injection is valued because of the resultant tradeoff of capital expenditures (CAPEX) for operating expenditures (OPEX). The idea of trading CAPEX for OPEX is illustrated in Fig. 1. During project design and construction, maximum value can be achieved in minimizing CAPEX by use of proper chemical-injection techniques and procedures. Minimizing CAPEX is achieved by properly anticipating flow-assurance problems through risk assessment during design and by incorporating appropriate mitigation techniques into the construction of the facility. At facility startup, maximum value is achieved through efficient commissioning and troubleshooting. Proper planning for the remediation of any difficulties will ensure success. Training and communication will be essential to the success of any project. This paper discusses issues related to the incorporation of chemical injection into the design of a new project. In addition to design issues, suggested actions will be presented that will ease the commissioning and startup of the CIS. Throughout, lessons learned from practical experience will be presented where appropriate. It is the authors' hope that the suggestions presented here will prevent the statement "on the next platform…" and aid in getting chemical injection right on this platform.

Overview: Wellbore Integrity, Sand Management, and Frac Pack (September 2006)

Geomechanics tools are used to forecast, and then gauge, asset performance over time. Wellbore integrity, sand management, and frac-pack engineering design and execution practices are linked by characterizing the geological section in terms of rock mechanical properties. Often, seemingly unrelated events that can plague high-risk, high-cost developments can be understood best when the geological environment, the geology and geophysics, is described as an engineering material (i.e., the rock mechanical properties that include formation strength and stress). A consistent characterization of formation stress and strength with the geological structure, lithology, and seismic attributes used to recognize the prospect ensures that the explorationists' vision is linked to the well engineers' design. Further, a consistent mechanical-property model for the field can be used to create a full-cycle asset-development plan from appraisal through abandonment, helping to reduce the risk of missed future opportunities resulting from well-systems-design constraints. Two examples come to mind.Reservoir-pressure depletion and subsidence can affect borehole stability to the extent that complex well designs are necessary to exploit the asset fully. Well placement depends on the subsiding reservoir section and on the reaction of the overlying geological section that must be drilled through to reach the reservoir.Sanding-potential risk usually increases with depletion. For compartmentalized reservoirs with varying depletion schedules, sand-risk mitigation often leads to one-size-fits-all completions that usually result in sand control. This method can limit re-entry options and decrease recovery. An accurate forecast of sanding tendencies for individual reservoirs, including the field production-management practices that affect sanding, can result in a more selective fit-for-purpose approach to completion design. For land-based operations, the consequences of well complexity may be addressed more easily; the downside is a poor estimate of field recovery that can either reduce opportunities for outlying prospects or, in the worst case, cause the asset to seem uneconomic. For major-capital projects such as deepwater subsalt fields, the capital outlays are immense, with single wells costing U.S. $100 million. For these deepwater projects, it is required that fewer wells produce reliably for longer periods of time. Well engineers need to get it right the first time. Wellbore Integrity, Sand Management, and Frac Pack additional reading available at the SPE eLibrary: www.spe.org SPE 95715 "Prediction of Sand-Production Rate in Oil and Gas Reservoirs: Field Validation and Practical Use" by P.J. van den Hoek, SPE, Shell Intl. E&P B.V., et al. SPE 98252 "Prediction of Sanding Using Oriented Perforations in a Deviated Well, and Validation in the Field" by I. Palmer, Higgs Technologies, et al. SPE 95514 "Evolution of Frac-Pack Design, Modeling, and Execution in the Ceiba Field, Equatorial Guinea" by C.L. Cipolla, Pinnacle Technologies, et al.

Overview: Deepwater Exploration and Production (June 2006)

Deepwater oil and gas projects are some of the most challenging of human endeavors. The sheer size of many of these efforts—and the impressive new technologies used—is truly amazing. Deepwater projects also entail great risk, however, and things sometimes do go wrong. Of course, things go wrong on all types of projects, but the deepwater environment itself and the large-scale nature of many projects exacerbate the severity of any problem. Costs can increase to many times the budget, the details associated with implementing new technology can be overwhelming, and schedules easily can slip enough to jeopardize the commercial success of the project. Some problems are related to project decisions that are made to maintain schedule before all of the needed facts are available. On a complex project, decisions are made that, in retrospect, are clearly wrong. Other problems arise simply as a result of mistakes made by the project management or technical teams. To be successful, the project team must be willing to recognize mistakes as early as possible and take corrective action. Knowledge of how mistakes were addressed on previous projects, both successfully and unsuccessfully, can be invaluable in selecting an appropriate corrective action. Examining lessons learned from previous projects provides one of the most important methods for improving project execution. Barry LePatner, an attorney testifying before a U.S. House of Representatives Science and Technology Committee on disclosure of information from building failures, made the following observation: "Good judgment is usually the result of experience. And experience is frequently the result of bad judgment. But to learn from the experience of others requires those who have the experience to share the knowledge with those who follow." The sharing of project-management lessons learned on deepwater projects, however, is a relatively recent development. Project management is as important to the success of deepwater projects as technology. The continued sharing of project-management lessons learned would help project teams meet the myriad nontechnical challenges associated with deepwater projects. Deepwater Exploration and Production additional reading available at the OTC Library: www.otcnet.org OTC 17971 "Albacora Leste Deepwater Field: Improvements on Well Construction," by E. de Melo Sanches, Petrobras, et al. OTC 17806 "Combined Effect of Flowline Walking and Riser Dynamic Loads on HP/HT Flowline Design," by M.S. Brunner, Technip U.S.A., et al. OTC 18311 "K2 Topside Facilities—Design Challenges," by F. Colbert, OFD Engineering LLC, et al. OTC 17655 "The Significance of Gas Hydrate as a Geohazard in Gulf of Mexico Exploration and Production," by M.A. Smith, U.S. Dept. of the Interior, Minerals Management Service, et al.

Making Choices When Opportunities Arise

YEPP PerSPEctive - Eni engineer Andrea Rimoldi ponders whether a transfer to Angola is worth it.

Water Injectivity-What We Have Learned in the Past 30 Years

Abstract This paper reviews the field-scale water-injection experiences from the early Barkman and Davidson's water quality study in the 1970s to one of the latest Gulf of Mexico offshore field studies. It summarizes what petroleum engineers have learned during the past 30 years and provides a concise compendium to the current understanding of the water injectivity issue. Both onshore and offshore projects have been included and various water injection cases are presented, showing both successes and failures. The main objective of this paper is to help operators to develop operation and design strategies for current and future waterflooding projects. Introduction Waterflooding has a lengthy history of application in the petroleum industry(1–2). In the early years of waterflooding, it was mainly applied as an improved oil recovery technique after the reservoir pressure had fallen below its bubble point pressure in mature onshore fields. However, with the development of offshore fields around the world, waterflooding has come to the forefront and has been applied from the outset in offshore fields. As more and more of the world's major oil fields mature, oil wells begin to produce more water because of aquifer encroachment and widely applied waterflooding. Currently, it has been reported that the oil industry has to handle more water than oil which makes it seem like a "water industry." How to wisely handle the tremendous amount of unwanted produced water therefore is a crucial task the industry has to face. Water injection in reservoirs and the disposal of produced water are becoming increasingly important issues in the reservoir management process. The re-injection of produced water into the subsurface is a potentially attractive option to lower environmental pollution, especially for offshore fields, although considerable uncertainty about the costs of implementation and the consequences still exists. During the past 30 years, many waterflooding projects, including many offshore deepwater projects, have been started and lots of valuable experiences have been gained on water injectivity. Therefore, the purpose of this paper is to present lessons learned and best practices on water injectivity from published literature, and to provide a compendium to the current understanding of water injectivity to help operators better manage their current and potential waterflooding projects. Water Injectivity Observation During the literature search, we found only a dozen or so papers on water injectivity studies among the thousands of technical papers on waterflooding. It seems that petroleum engineers paid less attention to water injectors than producers, although waterflooding has been practiced worldwide for about a century in the industry. One of the reasons that water injectors were not fully studied was that oilfield operators do not have time to conduct water injectivity studies, especially for mature onshore fields with large numbers of wells. Another reason is that the improvement of water injectors usually takes weeks or even months before the increased volumes of injected water show an effect on oil production.

A Resourceful Industry Lands the Serpent

In 1997, Norsk Hydro cast a line with wildcat well No. 6305/ 5-1 and hooked a big fish even for the North Sea. In 2000, the industry stepped back and gave pause to the enormity of the undertaking. It had become clear that the Norwegian serpent, Ormen Lange, would be a heavyweight in all respects. The project takes its name from the ship of Viking King Olav Tryggvasson. Charting the course to landfall is a group of star licensee/operators—Hydro, Shell, Petoro, Statoil, Dong, and ExxonMobil. The giant serpent, stretching across four North Sea blocks, is destined to become a major European gas source, covering 20% of U.K. gas requirements for 40 years. The U.K. gas market is the largest in Europe, with annual consumption of 3.9 Tcf. From geologic and climatic perspectives, main subsea installations and pipelines will be subjected not only to mountainous terrain created in the scar area of the Storegga avalanche slide, but also to cold polar currents driven by the Gulf Stream, generating some of nature’s most brutal forces. Water temperatures on the seabed are below freezing for most of the year—perfect conditions for hydrate development. The ocean surface is thrashed by fierce winds and waves. Beyond these challenges, Ormen Lange is seen from Hydro’s vantage point as three concurrent projects—development of the reservoir with templates and pipelines to shore, design/construction of the Langeled pipelines (one with 42-in.-diameter and another with 44-in.-diameter pipe), and construction and operation of a processing plant. This intensely faulted reservoir (one study reports that more than 1,000 faults have been interpreted and included in simulations) is the second-largest gas discovery on the Norwegian shelf (the Troll field is the largest) and will be Europe’s deepest subsea development. Ormen Lange will contribute to a doubling of Hydro’s gas exports by the year 2010, making Norway the world’s second-largest gas exporter. The project is the largest in Norway’s history. With main gas reserves located in the Vale formation, drilling has already confirmed resources of 11 Tcf of gas; production is planned at 2.5 Bcf/D of gas and 53,463 B/D of condensate will be stored. The climatic and oceanographic conditions in the region of the find present severely challenging conditions, and forces created by wind and waves are as challenging as any other deepwater project. Some long-time veterans of the North Sea development call Ormen Lange the most challenging offshore project ever. In cooperation with internationally recognized Norwegian expertise, extensive studies have been conducted regarding the stability of seabed masses and slide safety along with future natural conditions, including potential tsunamis, and conditions resulting from project activities. The associated subsea-export-pipeline project is one of the largest undertaken by the industry. Gas will be transported more than 1200 km from Nyhamna via the Sleipner platform in the North Sea (Fig. 1). Total investment cost is estimated at U.S. $10.2 billion, including $7.2 billion for development and $3 billion for the transport system. A hotel built for workers at Nyhamna, where the gas-processing plant is being built, is larger than any other hotel in Norway (three times larger than the Oslo Plaza Hotel).

Charging of Elk Hills reservoirs as determined by oil geochemistry

Crude oils from Miocene and Pliocene reservoirs from the Elk Hills field in California's San Joaquin basin were analyzed for stable carbon isotopes and biomarkers. Cluster analysis of geochemical variables defines five principal oil families, all derived from different organic-rich facies of the Miocene Monterey Formation. Carbon isotope analysis indicates no contribution from the basin's other major source rock, the Eocene Kreyenhagen Formation. Oil families show a strong correspondence to stratigraphic intervals. Oils from pre-Monterey reservoirs were probably generated from the lowermost organic-rich facies of the Monterey and are the most thermally mature. Upper Miocene Stevens zone turbidite reservoirs contain oils of various thermal-maturity stages, but mature light ends are abundant and are likely generated from the floors of the adjacent subbasins located north and south of Elk Hills. The relatively minor presence of low-thermal-maturity biomarkers that are typically characteristic of Monterey oils may indicate that Stevens traps did not form until after the source intervals were at a higher level of thermal maturity. All oils in Stevens porcelanite reservoirs contain a higher concentration of low-maturity biomarkers, which may indicate derivation from more localized areas on the flanks of the Elk Hills anticlines. The shallow Pliocene oils have suffered biodegradation to different degrees, and the lowest API gravities occur on the flanks of the anticline. The carbon isotopic composition of these oils suggests yet another Monterey source facies that charged the Pliocene reservoirs and is not simply the result of vertical leakage from the older Miocene reservoirs. John E. Zumberge has been vice president and cofounder of GeoMark Research in Houston since 1991. He was manager of geochemical and geological research for Cities Service–Occidental, general manager for Ruska Laboratories, and director of geochemical services for Core Laboratories. He has global experience in petroleum geochemistry, focusing on crude-oil biomarkers. He obtained a B.S. degree in chemistry from the University of Michigan and a Ph.D. in organic geochemistry from the University of Arizona.Judy A. Russell is a senior geological advisor for Occidental and works on worldwide exploration and production, with an emphasis on the integration of geochemistry. She has extensive experience in many of Occidental's projects in Latin America, Far East, the United States, and the Middle East. She has a B.S. degree from Phillips University and an M.S. degree from the New Mexico Institute of Mining and Technology. Stephen Anthony Reid is a senior geological advisor for Occidental and works on international exploration, with an emphasis on deep-water projects. He has extensive experience in California's San Joaquin basin, including the Elk Hills field, where he conducted studies on Stevens turbidite and Monterey porcelanite reservoirs. He has B.S. and M.S. degrees from California State University, Northridge.

Techbits: Drivers of Deepwater Development in the Asia Pacific Region

Ramlan Malek, Petronas General Manager—Petroleum Management Unit, and Ricardo Beltrao, Petrobras General Manager, set the stage for discussion among 78 participants representing numerous countries at the SPE Applied Technology Workshop (ATW) “Managing Deepwater in the Asia Pacific Region.” Held in Bangkok, Thailand, the ATW featured two keynote speakers: Malek on “Challenges in Managing Deepwater Field Development in Malaysia” and Beltrao on “New Technologies for Field Development in 3000-m Water Depths.” Water depth in the Asia Pacific Region is defined as follows. - Shallow water—depth less than 200 m. - Deep water—depth greater than 200 m but less than 1000 m. - Ultradeep water—depth greater than 1000 m. Highlighting some successful deepwater operations/development projects in the region and future projects on the horizon including Unocal’s Gendalo Subsea, Shell’s Gumusut/Kakap and Malikai, and some China Natl. Offshore Oil Corp. (CNOOC) ventures, production in the Asia Pacific Region will increase 60% by 2020, with most of the energy resources coming to production from deepwater assets. The challenge will be to develop these projects reliably, affordably, and in a timely manner, requiring close cooperation among host authorities, oil companies, and service providers. Speakers noted that a paradigm shift in mindset is needed to accommodate current operating experience in shallow water to the new potential deepwater environment. Commentary called for investment portfolios to be reshaped to address the need for technical proficiency and for efficient operations requiring a highly focused group to develop, build, and integrate deepwater business. The topic of “value erosion” in gas-handling projects and the industry’s need to invent and apply novel market solutions were other pertinent topics on which speakers and audience members presented their views. Also, cost reduction in Asia Pacific’s deepwater projects will come from the impact of new technology. While much of the technology is remotely operated, people will have a significant impact on how that technology is leveraged and in combining these technologies to create full-life-cycle savings. In addition to exploring the different corporate strategies for managing deepwater field development and operating experiences of the various regional operators, such as Shell in the Philippines, Unocal in Indonesia, and Petronas in Malaysia, the workshop focused on technical and commercial challenges. Participants conferred on eight technical challenges, from obtaining accurate metocean data for design development to geohazards.

Overview: Offshore Completions (August 2005)

Last year, in this space, I commented on innovations being implemented on recent offshore completion projects and how offshore completion practices have undergone major changes. Our industry, regarding offshore developments, apparently has an unlimited ability to amaze the world with new advances. Projects that were considered not feasible 5 years ago now are being implemented. Driven by various reasons, including depletion of conventional reserves and increasing oil prices, oil and gas production in deep water became customary in many regions around the world, and it was not a surprise that, during the 2005 Offshore Technology Conference, oil companies started to reveal plans aiming at production of fields under 3000 m of water. Use of intelligent-well completions is spreading globally, not only for large deepwater projects, but also for small offshore discoveries where its use in subsea satellite wells may bring profitability to an otherwise uneconomical project. Smart systems, with remotely operated valves, allow operators to control various producing zones, shutting down those not responding as expected without expensive well interventions. All of that can be achieved while data for each independent zone are simultaneously acquired and recorded. Developing fields that present complex geology and deep reservoirs that have high pressures and temperatures still present challenges for the industry, mainly when unconventional-trajectory wells are used. Some of the issues being investigated involve completion of long horizontal sections in unconsolidated reservoirs; flow assurance, mainly for deepwater conditions; and subsea processing, including gas compression and gas/liquid and oil/water separation. Some of these challenges are addressed well in the papers featured in this issue. Available from the SPE eLibrary: www.spe.org SPE 90552 - “Gravel Packing Deepwater Long Horizontal Wells Under Low Fracture Gradient,” by Chen, Zhongming, SPE, BJ Services, et al. Available from the OTC Library: www.otcnet.org OTC 17399 - “Subsea Gas Compression—Challenges and Solutions,” by Fantoft, R., FMC Kongsberg Subsea A/S OTC 17397 - “Hybrid Riser Towers From an Operator’s Perspective,” by Sworn, A., BP plc

Overview: Deepwater Exploration and Production (June 2005)

In recent years, the industry has met some amazing deepwater technology challenges. Drilling and production in water depths that just a few years ago would have seemed impossible now are considered routine. Not long ago, a site in water depths greater than 150 m was considered deep, and the Cognac Project—at more than 300 m—was considered a remarkable feat of technology. Today, the feasibility of a project in 2000-m water depth is not an issue. Instead, project efforts focus on topics such as design robustness, effective project-execution strategies, reliability of operations, and cost-effectiveness. It is a tribute to technical innovation that, for most deepwater projects in less than 2000 m of water, several different acceptable methods often are available to solve specific technical challenges. Operators, designers, constructors, and installers continue to improve deepwater technologies and reduce cost and schedule risks. Areas such as well testing, reservoir evaluation with minimal data, riser systems, and flow assurance are being addressed to improve project execution and delivery. Meanwhile, new projects are benefiting from the application of lessons learned from previous efforts. Recent work has achieved promising results in special projects for which water depths reach 3000 m. Today’s challenge is to make the issues at that depth as commonplace as those in less that 2000 m. From a historical perspective, it is truly startling that work on these challenges is proceeding in an almost routine manner, with complete confidence that viable solutions will be found. Additional Deepwater Exploration and Production Technical Papers Available at the SPE eLibrary: www.spe.org SPE 92616 Mooring and Riser Management in Ultradeep Water and Beyond SPE 91012 Incorporating Uncertainties in Well-Count Optimization With Experimental Design for the Deepwater Agbami Field Available at the OTC Library: www.otcnet.org OTC 17292 Holstein Truss Spar and Top Tensioned Riser System: Design Challenges and Innovations OTC 17683 Lessons Learned From the Evolution and Development of Multiple-Line Hybrid Riser Towers for Deepwater Production Applications

Comments: Offshore Advances

This year marks the 50th anniversary of the first use of the jackup drilling rig, one of many advances in the second half of the 20th century that revolutionized offshore exploration and production. The jackup rig opened up newer and deeper offshore areas to production. Previously, offshore drilling was limited to primarily fixed platforms embedded in the seafloor that greatly limited mobility and were costly. The few mobile platforms operating at the time were supported by sunken refloatable vessels and were ill-equipped for use in rougher waters. According to LeTourneau Inc., a subsidiary of drilling contractor Rowan Companies, R.G. LeTourneau was the first to envision a stable and secure mobile platform that could be used in deeper waters. LeTourneau was an inventor best known at the time for pioneering advances in earth-moving machines and for being the first to develop all-wheel electric drives for heavy-duty machinery. With financial backing from Zapata Offshore Co., then headed by former U.S. President George Bush, construction on LeTourneau’s mobile offshore platform began in 1954. The result was a large, shallow-draft barge with three electromechanically operated lattice-type legs. The rig was first used offshore Port Aransas, Texas, then off the coast of Galveston, Texas, and then out in the Gulf of Mexico (GOM). Other offshore advances soon followed, including subsea blowout-preventer systems, moored drillships, and semisubmersible drilling rigs. Significant offshore innovations continue, and many of them were on display at this year’s Offshore Technology Conference (OTC) in Houston. The Spotlight on New Technology awards highlighted many of them, and others were unveiled during the conference. ExxonMobil debuted its subsea well-intervention-module technology, which offers a riserless way to deploy a seafloor coiled-tubing unit from a specially designed support vessel. That technology is now entering the detailed design and construction phase, and it will be licensed to BJ Services and Otto Candies through a joint venture. A detailed look at the subsea well-intervention system can be found in this month’s Technology Update, beginning on page 20. The mood at this year’s OTC was understandably upbeat after a year of U.S. $50/bbl oil prices. The outlook for offshore E&P appears favorable in the short term. The U.S. Minerals Management Service released a new report, noting that 15 deepwater projects were brought on stream in the GOM last year, with a record four spar units installed, including the world’s largest spar. GOM deepwater output could rise 300,000 BOPD this year and another 100,000 BOPD next year. A total of 107 deepwater projects are now on production in the GOM, accounting for approximately 922,000 BOPD and 3.9 Bcf/D of gas at the end of last year. More than 2,400 leases will expire next year and in 2007 in all areas of the GOM, which may lead to some highly competitive auction bidding. Many of those could be high-quality leases that have never been tested. With those lease expirations looming, many companies have recently increased deepwater exploratory drilling. High oil prices and renewed offshore activity are putting a strain on the drilling-rig market. Construction of new offshore jackup rigs may not be able to keep up with demand over the next decade, particularly given the attrition rate of older rigs. The pace of utilization of jackup rigs to drill in shallow waters accelerated sharply last year. A rig shortfall could be particularly detrimental to development of the GOM continental shelf, especially with a shortage of high-specification rigs needed to drill deeper zones. Others are predicting a shortage of the more technologically advanced rigs developed in the 1990s for use in deep water.

Comments: OTC Winners

Congratulations are due this year’s winners of the Offshore Technology Conference (OTC) awards. The recipients will be honored during OTC, which runs 2–5 May at the Reliant Center in Houston. The OTC Distinguished Individual Achievement Award will recognize J. Kim Vandiver, a professor at the Massachusetts Inst. of Technology. He is being honored for his technical breakthroughs in the dynamics of vortex-induced vibration, which have enhanced the design of structures to with-stand high ocean currents, enabling oil and gas production to occur in progressively deeper water. The 2005 OTC Distinguished Achievement Award for Organizations goes to Kerr-McGee Oil and Gas Corp. and Technip for their pioneering efforts in the Gulf of Mexico in delivering three generations of spar floating production systems in 9 years. This is the second OTC award for Kerr-McGee in recent years. In 2002, the company won the same award for its Neptune Spar project, the first spar production platform. Kerr-McGee and Technip have developed a total of five production spars, using three different designs, over the past decade. The collaboration resulted in the world’s first production spar—now referred to as a “classic” spar design—which was installed at the Kerr-McGee-operated Neptune field in the eastern Gulf of Mexico in 1997. In 2001, the companies developed the world’s first application of truss spars at the Kerr-McGee-operated Nansen and Boomvang gas fields in the East Breaks area of the Gulf of Mexico. Nansen lies in 3,678 ft of water, while Boomvang is in 3,453 ft. Another truss spar for the Gunnison field began production in 2002. Last year saw another world’s first with the development and delivery of the third-generation spar, called a “cell spar,” for the Kerr-McGee-operated Red Hawk field in the Gulf’s Garden Banks Block 877. Kerr-McGee holds a 50% interest in the field, with Devon Energy also taking a 50% share. Red Hawk is a two-well subsea development in 5,300 ft water depth. A sixth spar, using the truss design, is currently under construction for another deepwater project at Kerr-McGee’s Constitution field. The cell spar is designed essentially as an alternative to a long-distance tieback. The design consists of a vertical configuration of seven cylinders that are 20 ft in diameter and form a giant column that supports a 4,700-ton production platform. The spar is anchored to the seafloor by polyester moorings that are lighter, less expensive, and less corrosive than steel cables. Red Hawk’s production is at 120 million ft3/D of gas with expansion capacity of up to 300 million ft3/D. The breakthrough with the Red Hawk spar was its economy and small size. The less expensive cell spars will enable producers to look at deepwater reserves that in the past might have been too small to develop. Reserves previously required approximately 100 mil-lion BOE to justify development, but with smaller production platforms, reserves of less than half that size are now viable. Other producers have begun to adopt Kerr-McGee’s and Technip’s groundbreaking technology. Thirteen spars have been installed in the Gulf of Mexico, and Technip has built 10 of them and is currently constructing another. Technip also just signed a contract with Murphy Oil for the construction of a spar for the Kikeh field in Malaysia, which will be the first spar installed outside the Gulf of Mexico.

CorrOcean awarded a NOK 15 milliom subsea sensor contract for deepwater project

CorrOcean awarded a NOK 15 milliom subsea sensor contract for deepwater project

Assessing Uncertainty in Channelized Reservoirs Using Experimental Designs

Summary It is well established that uncertainty exists in simulated recovery forecasts because of the ambiguity in the measurement and representation of the reservoir and geologic parameters. This is especially true for immature projects, such as deepwater reservoirs, where the high cost of data limits the information that is available to build reservoir models. We present two strategies based on Experimental Design (ED) to quantitatively assess this uncertainty in recovery predictions for primary and waterflood processes. We apply the ED methodology to channelized sandstone systems because of their relevance to many deepwater projects. We choose to study synthetic geological analogs of channelized systems that are built from a panoply of relevant parameters while taking into account the uncertainty that exists in the estimation of their ranges. We use the results of this study to generate type curves with neural networks. The trained neural networks can be used to predict reservoir performance rapidly where field data are very limited. We discuss applications of this methodology on field cases from western Africa.

Benefits of a 3DHR survey for Girassol Field appraisal and development, Angola

Can management and partners be convinced to acquire a new 3D high-resolution survey (3DHR) less than three years after acquiring a high quality, conventional 3D? This is what was proposed in 1999 in the deepwater (>1300 m) Girassol Field, offshore Angola block 17—one of TotalFinaElf's largest deepwater projects. The business objective: To make a tangible impact on appraisal and development programs, and ultimately use the new seismic as a baseline survey for 4D monitoring. This article describes the key steps to prepare, acquire, process, and interpret the 3DHR. Preparation included a feasibility study to determine if a new survey was the best economic and scientific route and then to define the optimal acquisition design. CGG was awarded the contract for the 3DHR seismic acquisition and processing. Acquisition required enhanced onboard quality control by CGG and TotalFinaElf, optimal control of acquisition parameters because the source was at a shallow depth, and efficient logistics. Processing included a first pass, 300-km2 fast track volume of four million traces delivered five weeks after the last shot, and final volumes (near and far) with standard poststack time migration after DMO. Special attention was given to preserving the large frequency bandwidth at all stages of processing. Interpretation generated a reservoir model that was more heterogeneous than initially foreseen because the 3DHR nearly doubled spatial and vertical resolution, enabling the interpreters to construct a refined geomodel from inverted impedances and other seismic attributes. Impact: The design of appraisal and development wells was optimized in the field, reducing the total number of wells by 25% compared to field planning with the original 3D seismic. The key ingredients of this success are: (1) solid technical arguments and performance focused on operational and business issues; (2) close interaction between the operator and the geophysical contractor with a detailed QC …

Deep-water penaeid shrimps (Crustacea: Decapoda) from off the Portuguese continental slope: an alternative future resource?

The traditional crustacean fishery along the continental shelf and slope off Portugal mainly targets the Rose shrimp ( Parapenaeus longirostris, Lucas, 1846), Norway lobster ( Nephrops norvegicus, Linnaeus, 1758) and its associated species, Red shrimp ( Aristeus antennatus, Risso, 1816). In recent years, the commercial trawl fishery has been intensive and has resulted in an overexploitation of these species, down to depths of about 500 m. Since 1994, the Portuguese Marine Research Institute (IPIMAR) Deep-water Project has carried out research on the deep-water penaeids, Red shrimp, Scarlet shrimp, Aristaeopsis edwardsiana, Johnson, 1867 and Giant Red shrimp, Aristeomorpha foliacea, Risso, 1827 that occur at depths >400 m and far from the coast. The aim of this study was to find an alternative crustacean fishery to the traditional one and to describe the distribution pattern and some biological aspects of these three deep-water shrimps. The Red shrimp was more frequent off the southwest coast of the Portuguese mainland. The Giant Red shrimp had a patchy distribution with aggregations in specific areas. The Scarlet shrimp was not as abundant as the other species. In Portuguese waters, the spawning period of Red shrimp and Scarlet shrimp was mainly in the spring, while for Giant Red shrimp it was in the spring and summer.

Meeting the Challenge of Deepwater Spill Response

ABSTRACT Close to 25% of all oil and gas produced in the United States comes from offshore production. A new era for the Gulf of Mexico has begun with intense industry interest in deepwater (> 300 m) areas. Production from deepwater now represents about 46% of all U.S. offshore oil and 17% of U.S. offshore gas. Spill response plans and capabilities must be upgraded to meet the challenges of this new remote activity. This paper outlines a joint research effort underway between government and industry to address needed research on deep spill plume and trajectory behavior and surveillance. Major topics discussed include the application of results from a June 2000 deepwater experimental release of oil and gas offshore Norway, findings from several laboratory studies on plume characterization, and an upgraded numerical model for deep spill trajectories. There is much interest from the offshore industry as to how these research findings will be incorporated into federal review of oil spill response plans for deepwater projects.

Future Coast Guard Cutter (FCGC): An Engineering and Feasibility Conversion Study for an Oliver Hazard Perry Class Frigate

AbstractThe Coast Guard wants to replace their aging cutter fleet. The new construction Deepwater Project would like to integrate their efforts with the DD 21 family of ships, but the Coast Guard does not want to wait for the Navy program to mature. This study investigates the engineering feasibility of an alternate near term solution—conversion of the decommissioning Oliver Hazard Perry class frigates into Future Coast Guard Cutters (FCGC). Detailed analyses for combat system selection, propulsion plant and endurance range limitations, and manning and automation issues form the foundation for new ship arrangements capable of supporting a mixed gender crew. Additional analysis reviews small boat operations, habitability requirements, ship stability, structural loading, and a cost estimation technique. The converted Oliver Hazard Perry class frigates were shown to provide a technically feasible interim solution to replace decommissioning Coast Guard cutters while meeting or exceeding the Coast Guard requirements for a conservatively estimated cost of $141M (FY98).