Ultra-deep Water Research Articles

Deepwater gas kick simulation

Important gas and light oil reserves have recently been found in the Tupi field of Santos Basin, Brazil. The Tupi is formed by subsalt hydrocarbon reservoirs 6000 to 7000 m deep, with water depths up to 3000 m, subjected to high pressure and high temperature bottomhole conditions. The investigation of well control aspects during exploratory and development drilling in that field requires kick simulators that can handle the pressure and temperature range encountered in deep and ultra deepwater scenarios. Safety issues associated with well control situations demand precise predictions of wellbore pressures and liquid/gas volumes as well as flow rates at the surface. The possibility of blowout occurrence needs to be mitigated in order to avoid human casualties, financial losses (production stop and equipment losses) and environmental damage. Several kick simulators have been developed during the last four decades in order to address well control problems during the drilling operation. The simulators have an important mission that involve: i) helping the drilling engineer to make decisions during well control procedures and kick situations, ii) personnel training and certification and iii) better understanding and interpretation of field observations. The evolution of the codes has been driven by the increasing challenges in exploration and development of the remaining hydrocarbon reserves. Increasing complexity of well geometry (diameters and trajectory), well location (land and offshore) and bottomhole conditions (increasing pressure and temperature severity with depth) has required more precise two-phase flow models and more representative rheological as well as compositional models. This work presents the mathematical modeling of a proposed gas kick simulator, the comparison between simulated and measured results for a test well located in Brazil, and a sensitivity analysis regarding the effect of water depth in well control parameters.

Pressure loss in core-annular flow: Modeling, experimental investigation and full-scale experiments

The use of core-annular flow pattern, where a thin fluid surrounds a very viscous one, has been suggested as an attractive artificial lifting method for heavy oils in the current Brazilian ultra-deep water production scenario. This paper proposes a more refined pressure-loss prediction model for core-annular flow which includes a slip ratio term that implicitly accounts for the buoyancy of the oil core. Frictional pressure-gradient measurements in upward-vertical and horizontal core-annular flows in a 28.4-mm-i.d. 2.5-m-length glass tube (tap water and crude oil of 500 mPa s and 925 kg/m 3 at 20 °C) and 77-mm-i.d. 274-m-length steel pipeline conveying an ultra-viscous crude oil (36,950 mPa s and 972.1 kg/m 3 at 20 °C), respectively, are reported. The model shows very good agreement with the present data and data from the literature, improving some correlations previously developed. Regarding the onshore-field experiments, two pressure-gradient reduction factors are proposed. The observed improvement of oil production rates and pressure-loss reductions are remarkable.

An Automatic Approaching Control for the Petroleum Well Re-Entry Operation in Ultra-Deep Water

Abstract Offshore Petroleum Industry regularly uses automatic control to keep the positioning of floating drilling platforms and, with a few exceptions, floating production platforms. This positioning control system is commonly denominated Dynamic Positioning System (DPS). This automatic control measures the platform position through a gyrocompass for the heading, and a Differential Global Positioning System (DGPS) and/or an Acoustic Positioning System for translational displacements. Further, the thrusters installed on the platform hull are the actuators bringing the platform to the reference position. This work presents the dynamics of semi-submersible drilling platform equipped with DPS and coupled with a drilling riser in 3000 m water depth. In addition, a special attention is paid on the drilling operation called well re-entry. During the re-entry, a safety equipment named Blow Out Preventer (BOP) is lowered down attached to the drilling riser, and the BOP shall be connected onto the wellhead. This approaching of the BOP to the wellhead is carried out controlling the floating platform manually, with the help of a camera attached to a Remote Operated Vehicle (ROV) which shows how far the BOP is from the wellhead. Then, the engaged personnel estimates this distance and changes the reference position of the DPS in order to reduce this distance. In this paper, numerical simulation results for the coupled platform and riser dynamics are featured and discussion about an extra feedback loop that could control the BOP approach automatically in the re-entry operation is presented.

泥水技術の現状と課題

Drilling fluid technology has been developing as a part of drilling technology to cope with a lot of problems facing with various kinds of drilling operations.In this paper, main functions of drilling fluid are reviewed, and the five issues below regarded as recent key technologies; 1) Hydration and swelling of shale, 2) Resistance to high temperature, 3) Highly deviated or horizontal drilling, 4) Ultra deep water drilling, and 5) Environmental responsibilities, which Telnite has been executing as Research and Development missions to date, are described.

Technology Focus: Subsea Technology (August 2008)

Technology Focus The 2008 Offshore Technology Conference (OTC) was a record-breaking event: Attendance (75,000+, the highest in 26 years), participating companies, and, as a friend noticed, iron on the ground (I do not believe there are statistics on this issue, but…). Technical-session attendees were treated with projects and technologies for regions that ranged from the Arctic offshore to the deep water of east Asia—a rather broad array of applications. The StatoilHydro subsea-to-shore gas development, Ormen Lange, received an OTC award for overcoming significant technical challenges to become Norway's deepest offshore development (800–1100 m). Although a subsea-compression system is yet to be developed to solve the challenges completely, Ormen Lange offers pioneering innovative solutions that will enlarge the industry's knowledge and improve confidence to face demanding tasks ahead that will test our ability to implement technological advances. As of the first week of June, we reached record oil prices and an overall cost escalation in the oil industry. The implications are diverse. However, I believe it underscores how the ever-growing costs of drilling/completion/intervention rigs will put a very high burden on the development of any field, mainly subsea, that is heavily dependent on mobile offshore drilling units. Overcoming such cost escalation is a major challenge. At the same time, it is also a major opportunity for improvement. To contemplate this quest for innovate solutions and the state-of-the-art technology in exploration and production, the highlighted papers vary from classical developments by Petrobras in its Roncador field offshore Brazil to Murphy Sabah's Kikeh field in Malaysia. In the case of Roncador, you will get to know an innovative pendulum method for installing manifolds in ultradeep water; in Kikeh, you will get an idea of the innovations necessary that were implemented to overcome the challenges of Malaysia's first deepwater development. In addition, a paper from BP outlines its successful track record of subsea developments, challenges facing the next generation, and the company's approach to technology to ensure success. It is definitely an impressive collection of papers for their scope, content, and effect on the industry. I feel especially pleased to invite you to read them. Subsea Technology additional reading available at the SPE eLibrary: www.spe.org SPE 108970 • "Ormen Lange Subsea-Condition and Leakage Monitoring" by Jens Abrahamsen, Bjørge A/S, et al. SPE 112723 • "Requirements for a Full-Drill-Through Subsea Wellhead and Tree System" by Sterling Lewis, SPE, ExxonMobil, et al. Additional reading available at OnePetro: www.onepetro.org OTC 19139 • "Managing Flow Assurance and Operation Risks in Subsea-Tieback System" by Shanhong Song, Chevron

Developing Subsea Facilities for the Roncador Field

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 19274, "Development of Subsea Facilities in the Roncador Field (P-52)," by Jose Mauricio T.G. Lima, Mariele Lima Kuppens, Paulo Ferreira da Silveira, and Pedro Felipe K. Stock, Petrobras, prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed. The second phase, Module 1A, of the Roncador field, offshore Brazil, was developed with a large semisubmersible floating production unit (FPU). This paper explains the strategies adopted by Petrobras to overcome the challenge of starting oil and gas production at a water depth of 1800 m in a short period of time, which required starting the platform construction early, almost simultaneously with the design of the riser system. Introduction Campos basin is offshore Rio de Janeiro State, southeastern Brazil. It covers approximately 100 km2 ranging from 20 to 3400 m water depth (WD). Roncador field lies in 1500 to 1900 m of water in the basin and was discovered in 1996. Development of Roncador field was planned with four production modules. Module 1A comprises two phases of exploitation: Phase 1 began production in 2002 with floating-production-storage-and-offloading (FPSO) vessel Brasil moored in approximately 1300 m WD, to operate some of the wells temporarily. By the end of 2007, the second phase of Module 1A (Phase 2) started to produce to the FPU P-52, which has a total displacement 80,000 t, moored stage of development and knowledge, operational issues, and available resources (e.g., installation vessels). The semisubmersible platform was selected to mitigate the risks of riser development. However, the desire to start Phase-2 production 4 years later required designing and contracting platform construction before the riser system was defined. Problems faced during qualification testing of flexible-pipe flowlines and risers for Phase 1 raised concerns about the capability of this traditional riser solution for applications in ultradeep water. Therefore, other riser concepts were assessed. The steel catenary riser (SCR) was determined as appropriate technology for the design WD. An in-house technical feasibility study confirmed the SCR as the primary gathering system, while the flexible riser remained an alternative requiring approval in a prequalification program. The SCR system and flexible risers, after prequalification of the latter with full-scale offshore tests, were both included in the subsea bid for the construction phase. Even though some changes were necessary in the FPU to allow the use of flexible risers, all the provisions for SCRs were kept operational for contingency purposes in the future.

Technology Focus: Offshore Drilling and Completion (April 2008)

Technology Focus I do not yet consider myself an old-timer. However, I remember when I started studying petroleum engineering; our teacher was telling us that drilling was a technology that had not progressed in years, not since its last revolution—the introduction of rotary drilling. The word "revolution" here definitely seems the right one. Since those days, we have seen the introduction of new technologies, such as measurement while drilling, steerable systems, top drives, more-reliable dynamic-positioning systems, dual handling, smart completions, new equipment, new chemicals, new metallurgy, and an exhaustive list of others. These advances enabled success of wells that were increasingly difficult, and we now are drilling horizontally (again, I remember: "It is impossible to drill horizontally, because it is impossible to transmit weight on bit horizontally") and underbalanced, we are drilling high-pressure/high-temperature (and soon very-high-pressure/very-high-temperature) reservoirs and in deep and ultradeep waters, and we are drilling slim or ultraslim wellbores, multilateral and extended-reach wellbores, and combinations of these. Future wellbores will be even more exotic. We complete wells with smart technology or sophisticated multilateral connections, produce gas from tight or ultratight sands, and heat silts in-situ to produce heavy bitumen. Simultaneously, we are making tremendous progress to protect people from incidents and diseases and our environment from unbearable or irreversible damages, especially when using nonaqueous-based mud. Again, this list of recent advances is not complete, but it gives the strong feeling that all of us are engineers dealing with a moving and expanding technology. Actually, it gives me the strong belief that we will overcome new challenges and that, peak oil or not (whenever it may happen), there still is a lot to engineer, a lot to invent, and a lot to progress to move the limits of feasibility in drilling and well engineering further and further. Offshore Drilling and Completion additional reading available at the SPE eLibrary: www.spe.org SPE 105212 • "Deployment of a Riserless Mud-Recovery System Offshore Sakhalin Island" by J.D. Brown, CJSC Elvary Neftegaz, et al. SPE 110359 • "Subsea Slimhole Completions in Deepwater Gulf of Mexico: Case Histories" by J.R. Sanford, Eni Petroleum, et al. Additional reading available at the OTC Library: www.otcnet.org OTC 19077 • "First Jackup Drilling Operation on Grand Banks of Newfoundland—Lessons Learned" by G.C. Bagnell, Rowan Companies OTC 18496 • "2-Million-lbm Slip-Based Landing-String System Pushes the Limit of Deepwater Casing Running" by James N. Brock, Grant Prideco, et al.

Drillstring Technology for World-Class Extended-Reach Drilling

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18512, "Drillstring Technology Vanguard for World-Class Extended-Reach Drilling," by M.J. Jellison, SPE, and R.B. Chandler, SPE, Grant Prideco; M.L. Payne, SPE, BP; and J.S. Shepard, SPE, GlobalSantaFe, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May. Projects that will expand the extended-reach-drilling (ERD) envelope are in the planning stage in various parts of the world. Drilling engineers no longer are wondering if 50,000-ft ERD wells can be drilled but how this can be accomplished safely and efficiently. It has been estimated that the last 10% of the drilled interval can account for 50% of the total drilling cost. The full-length paper discusses the latest drillstring technologies that are essential to achieve the ERD targets planned for the future. Advanced Material Technologies Industry publications have presented the idea of using nonsteel drillstrings for reduction of torque and drag loads in extended-reach (ER) wells. Other torque- and drag-reduction and management tools and techniques that have proved successful are lower in cost, thus being the preferred methods for meeting current ER torque and drag challenges. The competition of these alternative technologies has inhibited the development of commercially available nonsteel drillpipe. The direction toward longer-departure ER wells has led to increased consideration recently for commercially available nonsteel drillpipe. Generally, three advanced materials should be included in this consideration—carbon-fiber-based composites, titanium, and aluminum. Each has been used in drillstrings with varying degrees of success. Each material has strengths and weaknesses relating to its use for drillpipe to drill ER wells and other critical applications such as ultradeep drilling and deep water. Carbon-Fiber-Based Composites. Composite drillpipe (CDP) is manufactured by winding carbon fibers over a mandrel while applying an epoxy matrix to encase the fibers and seal the assembly. CDP manufactured to date has had steel pin-and-box tool joints similar in design to conventional steel-drillpipe connections. The steel tool joints are attached to the composite tube during the winding process in which the carbon fibers are placed over specially designed ends of the tool-joint members to bond with the composite tube and resist fatigue in service. Currently produced CDP is approximately three times the cost of conventional steel drillpipe. As the technology improves and the capabilities of carbon-fiber manufacturers advance, this price differential may decrease. CDP offers several potential advantages over conventional steel drillpipe that could make CDP particularly well suited to ERD and other critical drilling applications.

Espirito Santo: The New Deepwater Frontier in Brazil

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 19082, "Espirito Santo: The New Deepwater Frontier in Brazil," by Marcio Felix Carvalho Bezerra, SPE, and Nery Vicente Milani De Rossi, SPE, Petrobras, prepared for the 2007 Offshore Technology Conference, Houston, 30 April–3 May. Petrobras has been active in five simultaneous exploration and production frontiers in the Espirito Santo basin, namely gas in shallow water, light and heavy oil in deepwater, and light oil in ultradeep water and onshore. Petrobras has invested in new infrastructure projects including pipelines, processing plants, and a new port to support offshore operations. The company also has participated in research projects in partnership with the Federal University of Espirito Santo. Introduction Petrobras' activities in the state of Espirito Santo, in southeastern Brazil, encompass the Espirito Santo basin (onshore and offshore) and the northern portion of the Campos basin (offshore). Activities began in 1957 with an onshore focus. In 1968, Brazil's first offshore well was drilled in the Espirito Santo basin. In 1978, the Cacao field was the first offshore commercial discovery in the Espirito Santo basin, in a water depth of 19 m. Onshore production began in 1973, reaching maximum production of 25,000 BOPD in 1984, declining to 9,000 BOPD in 1998, when new fields were discovered by use of new technologies (e.g., 3D seismic). In early 2001, the first commercial deepwater discovery was the Jubarte field in the northern Campos basin, followed in 2003 by the discovery of light oil in deep waters in the Espirito Santo basin (Golfinho field). Projects Jubarte. Production began with a 2-month extended well test (EWT). This field produced approximately 20,000 BOPD through the Seillean floating production, storage, and offloading (FPSO) vessel. Phase-1 field development began December 2006 through FPSO P-34 with a production capacity of 60,000 BOPD. Phase 2 is planned for 2010 through FPSO P-57, with a capacity of 180,000 BOPD. Heavy-oil-production technologies include use of long horizontal wells to increase the production, use of electrical submersible pumps (ESPs) installed on the seabed as the main artificial-lift method with gas lift as backup, and the conversion of the FPSO P-34 to process heavy oil. Neighboring the Jubarte field, Cachalote, Baleia Franca, and Baleia Ana fields were discovered in 1500-m water depth. Production is scheduled to begin in 2012. The Baleia Azul field (1300 m water depth), south of Jubarte, may begin operation in 2014. The Caxareu, Pirambu, and Manganga fields were discovered in 2006 and are in the study phase to define the production systems. The Nautilus, Abalone, Ostra, and Argonauta fields are being developed in two phases, with the first phase in 2009, through an FPSO with capacity for 100,000 BOPD. Catua. The Catua field (in water depth of 1800 m), is 50 km southeast of Jubarte and contains 42°API oil in a carbonate reservoir. Discovered in 2005, an EWT is planned for 2008 to define the technical and commercial feasibility.

Operations Management Extends Field Life of a Long-Distance Subsea Tieback in Ultradeep Water

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18830, "Innovative Operations Management and Flow-Assurance Strategies Extend Field Life and Increase Ultimate Reserves of a Long-Distance Subsea Tieback in Ultradeep Water," by Aditya Singh, SPE, and Kevin Hannaford, Total E&P USA, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May. In 2004, the subsea fields comprising the Canyon Express system were declining and water-production rates were increasing. To halt the fast decline and extend the life of the field, flow-lines were reconfigured to separate the depletion-drive wells from waterdrive wells. A real-time production-management tool for enhanced production planning, monitoring, and trouble-shooting was implemented. Introduction The Canyon Express transportation system consists of two 12-in. flowlines running parallel from Camden Hills through Aconcagua and Kings Peak to Canyon Station platform. The three subsea fields—Camden Hills, Aconcagua, and Kings Peak—are in 6,200 to 7,250 ft of water. The Canyon Express subsea tieback, at 56 miles from Camden Hills to Canyon Station platform, is one of the longest subsea tiebacks in the Gulf of Mexico. Production from the fields is predominantly gas with condensate and produced water. The wells are tied together by means of a daisy-chain arrangement. Fig. 1 shows a Canyon Express schematic. During midlife operations, increasing water production from waterdrive reservoirs (Aconcagua AC1 and AC2, Camden Hills CH1 and CH2, and Kings Peak KP1 and KP2) and declining reservoir pressures of depletion-drive reservoirs (Aconcagua AC3 and AC4) led to high liquid rates and lower gas rates. The declining depletion-drive wells were restricted by higher water rates and liquid holdup in the flowlines. To optimize production during this period of increasing water rates and declining gas rates, several production options were considered. Detailed flow-assurance analysis was performed for each of the proposed options, and a recommended solution was reached on the basis of clearly identified advantages and disadvantages for each operating scenario. Flow-assurance evaluations were used on a continuous basis for operations planning to optimize and maintain production during this period. Evaluation of Late-Life Options Scenarios of the operating conditions to be studied were defined. Sensitivities on arrival pressures, gas-production rates, and water-production rates were developed from time points in the production forecast for evaluating the possible late-life operating techniques. A matrix of cases to be evaluated was developed.

Numerical investigation on the hydrodynamic performances of a new spar concept

Recently, the spar platform concept develops quickly in the offshore oil and gas exploitations, especially in deep and ultra-deep water, owing to its benign motion performance, excellent stability and adaptation to wide range of water depth. Many new spar concepts have been put forward with the purpose of reducing fabrication difficulty and cost, while meeting the requirements of exploitation in the meantime. Based on the aims mentioned above, a new spar concept was presented in this article and its hydrodynamics both in operating and survival conditions was studied by means of numerical simulation. Basic model tests were also conducted to calibrate the numerical approach. Following aspects are highlighted: (1) new spar concept, (2) global performance of the spar concept and (3) mooring line analysis.

Horizontal-Openhole Gravel-Packing Operations in the Campos Basin

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 106364, "The 200th Horizontal-Openhole Gravel-Packing Operation in Campos Basin: A Milestone in the History of Petrobras Completion Practices in Ultradeep Waters," by L.C.C. Marques, SPE, L.C.A. Paixao, V.P. Barbosa, M.O. Martins, A. Calderon, SPE, C.A. Pedroso, SPE, L.H.C. Fernandes, J.A. Melo, C.M. Chagas, and N.J. Denadai, Petrobras, prepared for the 2007 SPE European Formation Damage Conference, Scheveningen, The Netherlands, 30 May-1 June. The full-length paper presents an overview of the evolution of openhole gravel-packing practices and experience after 200 wells have been completed successfully with this technique in the Campos basin. A comprehensive description of the main steps taken to improve horizontal-openhole gravel-packing (HOHGP) practices in unconsolidated oil-bearing turbidites is presented. Since the first HOHGP job in 1988, completions have moved progressively from shallow- to ultradeepwater scenarios. Along this path, a series of innovations has been incorporated into the sand-face-completion practices. Introduction The most prolific reservoirs in the Campos basin are the Upper Cretaceous and Tertiary turbidites. The high-permeability (approximately 1,000 to 8,000 md) stacked and amalgamated reservoirs are spread over shallow, deep, and ultradeep water within the basin. Dictated by the depositional model associated with turbidites, the sand uniformity of these poorly- or unconsolidated sand lenses varies significantly. The presence of reactive-shale streaks is recurrent in some of these turbidites. As in many other offshore basins in the world, the first oil discoveries (early in the 1980s) were in shallow waters. These good exploratory results propelled the move progressively from shallow to ultradeep water. However, since the original oil discoveries, it has been realized that a sand-management strategy was necessary to achieve desirable production levels. Sand control is an umbrella term comprising different approaches to dealing with sand-production problems. Sand-control methods include frac pack, chemical consolidation, screens, and gravel packing. The Petrobras philosophy is one of zero tolerance for sand production. Should there be the slightest chance of sand production, a sand-control method is installed in wells. This preventative approach stems from wellbore-integrity concerns, prohibitively high well-intervention costs, the need to maximize production rates, safety concerns, and the inability of topside equipment to handle sand. Gravel packing is considered the best alternative for sand control in horizontal-openhole wells with good vertical permeability, nonuniform sands, and no lamination. In addition, filling the screen/wellbore annulus of an openhole horizontal well with properly sized gravel creates a secondary barrier to the migrating sand grains, thus increasing the longevity of the gravel-pack screens.

Analysis of Energy Harvesting Positive Displacement Motor

Drilling operations in deep and ultradeep water are increasing around the world. The development of these substantial prospects provides many challenges and requires the integration of knowledge with prudent designs at different stages of the well development. Also, more wells are drilled in rotary steerable mode and other instrumented bottom-hole assemblies. All of these tools need power, which is stored in batteries. Because the downhole power supply is limited for these tools, an alternate mode of energy supply is needed so that these tools can remain downhole for long hours. This paper examines a new energy source extraction method using the hydraulic energy obtained from the circulated drilling fluid when downhole motors are used.

Experimental study of the compression behaviour of syntactic foams by in situ X-ray tomography

Syntactic foams (hollow glass microspheres embedded in a polymeric matrix) are being used increasingly for thermal insulation purpose in ultra-deep water. A better understanding of the damage mechanisms of these materials under such a hydrostatic loading condition would be useful in determining actual material limits, improving phenomenological modeling and developing novel formulations in the future. To achieve this goal, a study based on X-ray microtomography was performed on various syntactic foam materials (epoxy/PP/PU matrix). Spatial resolution of (0.7 μm) 3 and in situ non-destructive scanning allowed unique qualitative and quantitative analysis of the composite microstructure during stepwise confined compression testing in the dry state. It is shown that in the three materials, the thickness of the spheres is rather constant while their diameter is strongly distributed. The adherence is strong between PU and glass and rather weak between both PP and epoxy and glass. In the two foams where the matrix is more compliant (PU and PP), damage is homogeneously distributed and affects mainly the larger spheres, while in the stiff and strong epoxy material, damage is localized in bands.

Overview: Reserves/Asset Management (December 2006)

Looking through the abstracts of approximately 65 papers, and needing to select relevant papers for this feature, proved the following to me.My selections will leave some important and useful papers "behind."There is a wealth of experience to be shared among SPE members worldwide.The topic of risk and dealing with uncertainty continues to be a major theme—as well it should, because it is what we do on a daily basis as petroleum engineers. To address my first issue, I simply tried to identify the papers that would have the broadest appeal to benefit the most readers. I would encourage you to search online (SPE's eLibrary) to find papers that are not listed here. As for issue two, there were plenty of papers illustrating best practices or promising results and conclusions from case studies. Take note of the selected case studies, because the authors' experiences and observations can add to your repertoire of knowledge to improve the management of your own assets and projects, however different they may be from those highlighted. As for risk and uncertainty, the selected papers help provide a better understanding of the topic by highlighting the latest developments and practices. Finally, keep in mind that what we lack in experience (both successes and failures), we must make up for in terms of acquiring knowledge and risk/reward and uncertainty management. Our predecessors were able to conduct business based heavily on experience and the best understanding of the inherent uncertainties. This method may have been appropriate at that time, regardless of the project. Unfortunately, we have moved to the cutting edge of "mega scale" projects such as harsh environments or deep and ultradeep water that are so significant in terms of economic scale, human resources needed, and the complex interrelated components, that in some cases overall project management is almost beyond comprehension. Therefore, acquiring knowledge and understanding risk and uncertainty become as important as a lifetime of experience. Reserves/Asset Management additional reading available at the SPE eLibrary: www.spe.org SPE 97269 "Risk and Uncertainty Management—Best Practices and Misapplications for Cost and Schedule Estimates" by S.K. Peterson, SPE, J Murtha & Assocs., et al. SPE 102505 "The Selection, Application, and Misapplication of Reservoir Analogs for the Estimation of Petroleum Reserves" by J.E. Hodgin, SPE, Ryder Scott Co., et al. SPE 100607 "U.K. North Sea and Alaska North Slope: A Comparative Analysis of Petroleum Provinces" by J.A. Walker, SPE, ConocoPhillips Alaska Inc., et al.

Filling the gap: integrating nodes and streamer data for geophysical monitoring

E. Ceragioli, A. Kabbej, and A. Gonzalez Carballo of Total, and D. Marin of CGG, discuss how sparse distribution of seabed node receivers can complement conventional marine seismic streamer technology in the surveying of sensitive or obstructed targets with an example from an ultra deep water oil and gas field project.

Overview: Subsea Technology (August 2006)

Once again, OTC thrived with projects, new technologies, and presentations that met the highest standards and expectations. This year, boosted by the steady increase in oil prices—having surpassed U.S. $70/bbl—attendance reached 59,236, the highest since 1982. Attendees from more than 110 countries were able to exchange their expertise on the development of offshore resources in the fields of drilling, exploration, production, and environmental protection. Subsea technology, more than ever, was a key factor in the huge success of this "Engineering Celebration." As such, it is the focus of the papers selected for this feature, by means of which JPT seeks to present state-of-the-art technology in the quest to find and produce offshore oil and gas. Highlights include the development of two gigantic fields in western Africa and Brazil. These two fields will provide invaluable knowledge on how to use floating production, storage, and offloading vessels in the Gulf of Mexico (GOM), our next technological frontier. Another highlight is the technical challenges and opportunities for subsea processing and boosting. Several companies are investing in these technologies, aiming at applying them in the North Sea, GOM, Brazil, and western Africa. Such technologies, when put together, will be able to tackle the water-production challenge and will allow the production of new heavier-oil discoveries; they also will enable development of long tiebacks for oil and will play an important role in the subsea-to-shore challenge. The efforts of our industry to overcome challenges in the development of subsea fields are well evidenced by the "Spotlight on New Technology Awards" at this year's OTC. From the 13 new technologies recognized with the award, one was for subsea boosting and another for subsea separation. In the near future, most certainly, new- or old-field developments will adopt a combined solution of sub-sea processing and boosting. The benefits seem very clear. Therefore, I am especially pleased to invite you to read this impressive collection of topics for their scope, content, and effect on the industry. I hope you enjoy it. Subsea Technology additional reading available at the SPE eLibrary: www.spe.org SPE 100662 "Scale-Inhibitor Testing for Multiphase Pipelines in a Subsea-to-Shore Development With a Closed MEG-Loop System" by E.N. Halvorsen, Hydro Oil & Energy, et al. Available at the OTC Library: www.otcnet.org OTC 17810 "NDP Review of State of the Art in Riser Monitoring: Lessons Learned and Experiences Gained," by M. Chezhian, Det Norske Veritas, et al. OTC 18318 "Evaluation of Low-Dose Hydrate Inhibitors (LDHI) for a Long-Distance Subsea Tieback in Ultradeep Water," by A. Singh, SPE, Total E&P U.S.A. Inc., et al.

Stand Tall and Speak Up: Beyond Technology—Our Commitment to Social Responsibility

New opportunities will increasingly involve heavy oil, or stranded natural gas, or resources in ultra-deep water. Large investments in infrastructure will be required to bring these resources to market, so it will take years just to recover the initial investments. While we are accustomed to thinking of our industry as being built on long-term relationships, the rise in the percentage of projects with huge investments in facilities will increase the importance of maintaining good relationships. For relationships to withstand the tests of time, they must be win-win for all the stakeholders, not just those who sign the contracts. In long-term relationships, many issues that are covered by the broad category of social responsibility will take on greater importance. Definitions of social responsibility vary, but generally embrace ethical business practices, community economic development, human rights, indigenous-population care, worker rights and benefits, and a broad range of environmental issues (including climate change, water management, waste disposal, and biodiversity). Social responsibility is an umbrella term that can be considered to encompass all of what we now classify as health, environment, and safety matters. Public perception of how we perform on the broad portfolio of social-responsibility issues has a major impact on our industry's image and plays a major role in maintaining our industry's ability to operate. In comparison with other multinational industries, the public tends to rank the petroleum industry very low. Some oil and gas companies have placed a larger emphasis on social responsibility than others and indications are that the public recognizes the commitment these companies have made. However, when major problems erupt, the industry as a whole suffers. Trade associations have taken the lead on social responsibility issues. The Intl. Assn. of Oil & Gas Producers (www.ogp.org.uk) and the Intl. Petroleum Industry Environmental Conservation Assn. (www.ipieca.org), both of which were founded in 1974, are notable examples. Their memberships include private and state-owned petroleum companies, oil and gas associations, and upstream service companies. While these trade associations are providing valuable services, I believe that individual-member organizations such as SPE can also make major contributions. We can leverage our access to our almost 70,000 members worldwide. Just as for safety, where we have learned that knowledge and accountability are everyone's business, the other social responsibility issues must not be viewed as primarily the responsibility of experts. With social responsibility issues, liability extends far beyond the confines of our company facilities. The issues that host communities consider most urgent vary widely. We need everyone to serve as a sentinel, alert to the potential opportunities and threats associated with social responsibility concerns.

Technology Update: New Options, Improved Economics from Aerogel Insulation

The challenges facing oil and gas operators seeking to develop new fields in hostile environments such as deep and ultradeep water are well documented and continue to increase. One important requirement for operators developing subsea fields is the ability to transport unprocessed hydrocarbons, which are frequently at high pressure and high temperature, over longer distances along the ocean floor. Without sufficient insulation, the hydrocarbons will cool and create hydrates/wax buildup that can eventually clog flowlines at significant cost to operators. Cabot Corp. has developed Nanogel aerogel, a nanoporous insulation product, to address associated economic and efficiency issues. Sometimes called "frozen smoke," aerogels are light insulating solids. Nanogel is a hydrophobic aerogel produced as particles, each of which consists largely of air (≈95%) trapped in nanosized pores that severely inhibit heat transfer through the material. A proprietary manufacturing method imparts mechanical benefits (NanoSprings) to the aerogel particles in addition to characteristics that make them useful for thermal insulation. The aerogel performs across a range of temperatures (from –200 to +250°C) making it applicable in systems ranging from liquefied natural gas (LNG) to high-pressure/high-temperature settings. Four products have been developed for the oil and gas market—the Expansion Pack, Compression Pack, Particle Pack, and Thermal Wrap systems. The first two are pipe-in-pipe products and use half-shells made with Nanogel aerogel particles compressed and packed under vacuum. In field application, a series of half-shells is positioned in a pipe-in-pipe or other assembly and activated (vacuum is breached), resulting in form fitting of compressed particles into a desired shape, either filling the entire annular space (Expansion Pack) or, under higher compression, filling a predetermined portion of the annular space (Compression Pack). Operating Economics There are two ways in which improved economic impact is created during development of subsea fields—by allowing the use of smaller jacket pipes and by enabling the construction of longer tieback lines. In the case of smaller jacket pipes, substituting Nanogel for other insulation forms (such as polyurethane [PU] foam/rock wool) allows operators to reduce the size of outer pipes without compromising system performance (U-value), resulting in:Material savings on pipe steel.The ability to fit more pipe sections on a barge or reel, thereby reducing the number of barge trips.The ability to use smaller lay barges that have lower day rates. For example, to achieve a target U-value of 0.7 W/m2·K with an 8-in. flowline, an outer pipe of approximately 14 in. would be required if the insulation were PU foam. With the Expansion Pack system, the size of the outer pipe could be reduced to approximately 11 in. (Table 1).

Flow-Assurance Lessons: The Mica Tieback

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18384, "Flow-Assurance Lessons: The Mica Tieback," by A.L. Ballard, SPE, BP America Inc., prepared for the 2006 Offshore Technology Conference, Houston, 1-4 May. Flow assurance plays a significant role in asset development. In the case of ultradeep water, the role is major. The Mica field uses the longest tieback in the Gulf of Mexico and has been in operation for more than 4 years. The Mica wells are tied back through two 29-mile flowlines (one for gas and one for oil) to a major facility (Pompano). A review of Mica, comparing original flow-assurance-design strategies with current operational strategies, revealed several learnings, particularly involving paraffin, corrosion, erosion, hydrates, and slugging. Introduction The Mica field is in 4,350 ft of water. First production was in 2001. It was decided early on that the Mica wells would be tied back to an existing platform. Three zones in the reservoir were deemed producible. The shallowest zone is a saturated-gas and -oil zone with a gas/oil ratio (GOR) of 1,330 scf/STB, oil gravity of 32°API, and a wax cloud point of 93 to 100°F. The middle zone is a near-critical fluid with a GOR greater than 3,000 scf/STB, oil gravity of 37°API, and a wax cloud point of 90 to 94°F. The deepest zone is a dry gas with a condensate yield of 5 STB/MMscf and condensate gravity of 44°API. Peak capacity from the reservoirs was expected to be 150 MMscf/D of gas and 15,000 STB/D of oil. Pompano Tie-In. Pompano is a steel-jacket structure in 1,290 ft of water. Weight on the platform was not a major issue, so it was decided to construct a new process system for the Mica wells. Because a relatively small amount of oil was expected compared to gas, a separate gas-export pipeline was built for the gas while the oil was tied into the Pompano crude treater. New equipment built for the Mica wells includes a high-pressure (HP) separator, intermediate-pressure (IP) separator, low-pressure (LP) separator, turbine-driven centrifugal compressor, glycol-dehydration system, and turbine-driven generator. Fig. 1 shows the process system. The compressor suction is drawn from the IP separator at 450 psig and discharged to the gas-export line at 1,300 psig. The LP separator feeds into the Pompano compressors at 150 psig. Design Challenges Paraffin. With the cloud-point temperatures of the oil, paraffin issues were expected in the wells and in the insulated oil flowline. For a tieback of this length, it was not feasible to keep the fluids in the flow-line above the wax-appearance temperature during production. Pipe-in-pipe (PIP) insulation was designed for the oil flowline to spread out the deposited paraffin in the flowline as the oil cooled.