Ultra-deepwater Fields Research Articles

Deepwater Artificial Seabed (DAS) Production System: An Innovative Approach to Cost-Effective Deepwater and Ultra-Deepwater Field Developments

The prevailing offshore field development solutions, i.e., dry tree and wet tree systems, are confronted with serious technical and economic challenges in deep and ultra-deep waters resulting from the large depth of water, far offshore distance, and harsh ocean environmental conditions, as well as high cost. In response to these challenges, an innovative Deepwater Artificial Seabed (DAS) production system is proposed in this article. The DAS production system concentrates on well access and riser design, which enables shallow-water-rated subsea production systems to develop Deepwater (DW) and Ultra-Deepwater (UDW) fields. First, DW & UDW field development drivers are discussed and presented. This is followed by a detailed discussion of the merits and demerits of the prevailing dry tree and wet tree field development solutions. On this basis, the design philosophy and main characteristics of the DAS production system are presented and discussed in detail. Dynamic survival analysis for the fully coupled Floating Production Storage and Offloading (FPSO)-DAS production system is carried out. The artificial seabed stability is systematically investigated for both intact and damaged conditions. The global analysis results indicate that the DAS production system as developed experiences quasi-static responses even under extreme storm conditions, due to the location of the artificial seabed and the decoupling effects of the flexible jumpers. The new DAS production system is considered to be a competitive and cost-effective field development solution in depths of up to 3000 m.

Overcoming challenges in field development plan optimization with integrated Production Modelling (IPM): an example of a Giant ultra-deepwater oil field

Overcoming challenges in field development plan optimization with integrated Production Modelling (IPM): an example of a Giant ultra-deepwater oil field

Hybrid Ultradeepwater-Riser Configuration Saves Costs, Pushes Depths

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 29389, “Single Independent Riser: A Cost-Efficient Ultradeepwater Riser,” by François Lirola, Eric Revault, and Jean-François Lunven, Saipem, prepared for the 2019 Offshore Technology Conference, Houston, 6–9 May. The paper has not been peer reviewed. Copyright 2019 Offshore Technology Conference. Reproduced by permission. The single independent riser (SIR) is a hybrid riser configuration optimized for ultradeepwater field development. The SIR is composed of a flexible jumper and a rigid part vertically tensioned by means of distributed or continuous buoyancy. This configuration features improved dynamic behavior under fatigue and extreme environmental conditions for the rigid riser section thanks to its compliant shape. The design is versatile and can be staggered easily to comply with design constraints or congested layouts. Introduction The SIR is adapted to both turret-moored and spread-moored vessels as well as most other types. The configuration is also suitable for a wide spectrum of environments, from the mild conditions of west Africa to those in the Gulf of Mexico or the North Sea. The configuration can be designed for production risers, whether single-pipe or pipe-in-pipe, and injection and export risers. The strength of this configuration lies in its compliant, fatigue-resistant behavior. Its steep-wave configuration facilitates the mitigation of potential interference; the relative position of the sag and hog of each neighboring riser can be adjusted while reducing the load at the hang-off location. Overview The SIR features a steep-wave shape. The upper part is a flexible jumper, and the lower part is a rigid, steel-pipe string maintained in a near-vertical position either by means of continuous buoyancy or distributed buoyancy modules. These methods are used instead of a conventional air can in order to provide the up-thrust necessary to keep the riser vertical. The use of continuous or distributed buoyancy implies that each section compensates for its own weight, meaning that the concept is applicable to any water depth for which buoyancy materials are qualified. The transition between the rigid and the flexible parts is achieved with a sub-sea connector. An overview of the SIR configuration is given in Fig. 1. The SIR features the following technical advantages: The design relies on field-proven technology such as rotolatches to connect the rigid section to its anchor or standard shallow-water flexible-jumper technology to perform the transition between the rigid section and the floater. Though the SIR can be deployed in any water depth, the cost of the flexible jumper limits the suitability of the SIR for water depths below 1000 m, which should be considered the minimum applicable water depth. The SIR is compatible with any installation method. The fabrication process of the SIR can be reversed fully, meaning the system can be retrieved for relocation or maintenance purposes. The SIR features a small dynamic response, thus leading to less-stringent fatigue and welding requirements.

Atlanta Field: Producing Heavy and Viscous Oil in Ultradeepwater

SummaryAtlanta Field is a post-salt heavy-oil field located 185 km off the city of Rio de Janeiro, in Santos Basin, Brazil, at a water depth of approximately 1550 m. Atlanta, however, is not just another ultradeepwater heavy-oil field. Several additional challenges had to be overcome for its development, such as low reservoir overburden (800m), highly unconsolidated sandstone reservoir (36% porosity and 5,000 md permeability), heavy and viscous crude flow assurance (14 °API and 228 cp at initial reservoir conditions), high-naphthenic-acidity oil [total acid number (TAN) 10mg KOH/g], high-power artificial-lift pumping-systemrequirement (1,600 hp), and complex-topside crude facilities.The development of Atlanta Field was phased in two stages: an early production system (EPS), which is expected to last from four to five years and comprises three horizontal production wells; and a definitive production system (DPS), which will add nine wells to complete the development plan with 12 horizontal producers. The first two EPS wells were successfully constructed and tested during 2013 and 2014, proving the feasibility of surpassing the great challenges imposed by the field’s unique environment and enabling the beginning of the production phase of the field. The first oil occurred in May 2018 with these two wells producing to the floating production, storage, and offloading unit (FPSO) Petrojarl I. The third and last producer of the EPS was constructed in 2019 and began operation in June of the same year. More than five million barrels of oil were already produced to date.Marsili et al. (2015) described in detail the exploration and development phases of Atlanta Field, focusing on their challenges, the overcoming process, and solutions adopted. This current work intends to present an updated review of the paper, providing the most recent information related to the project with a subsequent focus on the production phase findings and results. Among others, the initial prediction and expectations will be compared with actual field performance. For all milestones achieved, the Atlanta project is considered a great success so far and a benchmark for the industry in this harsh and adverse environment.

The influence of thixotropy in start-up flow of yield stress fluids in a pipe

In oil production in ultra-deep water fields, difficulties can appear in the transport of oils with high paraffin content. If the production stops and the produced fluid cools down inside the pipeline, paraffin crystals may appear and form an interlocking gel-like structure, usually exhibiting a thixotropic yield-stress behavior. The restart of the production line should be designed with reasonable precision, taking into account the complex behavior of the gel formed. The start-up flow represents the transient response due to a differential pressure applied to a single fluid initially at rest, and is highly dependent on the fluid rheological behavior and other properties. In the present work, we present experimental and numerical results of the start-up flow of yield stress fluids in a horizontal pipe. The experiments are performed using a flow loop and two different fluids, one thixotropic and another non-thixotropic. Rheological data and velocity profiles are obtained and related to the pressure drop, yield stress and thixotropy. Secondly, numerical results are obtained using the finite volume method to solve the mass and momentum conservation equations. A constitutive model based on the Oldroyd-B equation for viscoelastic fluids, is used to describe the thixotropic fluid behavior. The numerical results captured the main physical features of the flow, and showed a fair agreement to the experimental results.

All-Electric Subsea Well Brings Benefits vs. Traditional Hydraulic Technology

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 27701, “World-First All-Electric Subsea Well,” by Thomas Schwerdtfeger, Total E&P Netherlands; Bruce Scott, Halliburton; and Jan van den Akker, SPE, OneSubsea, a Schlumberger Company, prepared for the 2017 Offshore Technology Conference, Houston, 1–4 May. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission. Currently, the state of the art for subsea well control is based on hydraulic technology. Hydraulic fluid is supplied from a host facility to the subsea wells through dedicated tubes within an umbilical and is distributed to the wells. Shifting that trend, K5F3, the world’s first all-electric well in the subsea industry, opened to production on 4 August 2016. This paper presents the benefits of electric subsea control compared with current state-of-the-art hydraulic methods. Rationale for Electric Production System Expenditure Savings. When looking at the introduction of a new technology such as an electric system, successful introduction is a direct consequence of a perceived reduction in capital expenditure (CAPEX) and factors such as operating expenditure (OPEX); health, safety, and environment (HSE); and future readiness also need to be addressed. To perform preliminary system engineering for the implementation of the electric system and provide a comparison with a conventional electrohydraulic multiplex system, a case with five oil-production wells, one gas-injection well, and three water-injection wells was used as a base case for cost. The study concludes that the electric system is likely to show a range of benefits over the equivalent electrohydraulic multiplex system. Improved System Efficiency. Electric subsea production brings advantages in most scenarios, particularly in an ultradeepwater field or with long-distance step outs. Electric motors maintain their high level of efficiency and full torque capability regardless of water depth, unlike hydraulic pressure, which must over-come seawater hydrostatic pressure. Use of high-voltage direct current for long-distance power transmission is far more efficient than use of either alternating current or hydraulic pressure. Removing hydraulic tubing from the umbilical and reducing the number of conductors bring several advantages. The electric umbilical has a smaller cross section, allowing longer continuous lengths to be manufactured and spooled. Overall weight is reduced, facilitating the use of a smaller installation vessel. And, on very long stepouts, splices in the umbilical can be either reduced or eliminated altogether. HSE Improvement. An all-electric system eliminates the discharge of hydraulic fluid to the environment and hydraulic-pressure safety issues. Future Potential and Readiness. Having much higher levels of electric power available at the subsea end of the system (compared with the electrohydraulic system) offers a greater scope for powering additional tools and sensors such as multiphase flowmeters. It also facilitates the addition of intelligent wells, new sensors, and digital flow-control valves.

Methodology for the Experimental Analysis of Offshore System in Deep and Ultra-Deep Waters in the Colombia Caribbean Sea

Historically, different methodologies of experimental analysis of naval and oceanic structures oriented to the execution of controlled experimental tests in facilities capable of reproducing environmental conditions specific to their operating locations have been developed. These methodologies enable the efficient design of oceanic structures, the minimization of production costs and the generation of scientific knowledge. This article details the design of an experimental analysis methodology for semi-submersible offshore systems for deep and ultra-deep water fields, obtaining satisfactory results, and the validity of the procedure as an important contribution to the phases of semi-submersible platform design, a concept selected as appropriate for the areas of interest of the Colombian Caribbean

Controlling Fatigue Damage during Deepwater Installation of Inline Components

AbstractThe exploitation of ultradeepwater fields often implies the use of large-diameter export pipelines. The installation of such large-diameter and long-distance export pipelines is commonly ac...

Comparative analysis of separation technologies for processing carbon dioxide rich natural gas in ultra-deepwater oil fields

Offshore oil production in ultra-deepwater, with associated natural gas showing high carbon dioxide content and high gas to oil ratio, poses stringent constraints to upstream gas processing technologies. Under such circumstances, oil and gas are processed in Floating Production Storage and Offloading rigs, whose topside facilities are limited in terms of weight and footprint of equipment. Energy demands, supplied by on-site generation, also reduce the availability of space and weight to oil and gas processing. This work evaluates carbon dioxide separation alternatives applicable to this challenging scenario in terms of technical, economic and environmental aspects, considering early enhanced oil recovery as the destination of carbon dioxide. The Brazilian Pre-Salt fields are used as case study due to their unusual high capacity gas processing on the production topside, a consequence of the high gas to oil ratio and carbon dioxide content. The set of studied carbon dioxide separation technologies encompasses membrane permeation, chemical absorption by aqueous methyl diethanolamine with piperazine, physical absorption with propylene carbonate and hybrid variants physical absorption and membranes, membranes and chemical absorption, and two stages membrane, technically assessed by process simulation. Due to the continuous injection of carbon dioxide to enhanced oil recovery, the reservoir content of carbon dioxide increases along production life-cycle, which means that the performances of technologies have to be compared under short-term, mid-term and long-term carbon dioxide content in the associated gas, respectively, of 10%, 30% and 50% (mol), for gas production of 6 million sm3/d. Chemical absorption exhibits the lowest hydrocarbon losses and the lowest specific electric power consumption at the expense of the highest footprint, for all investigated scenarios. The lowest life-cycle costs are for chemical absorption and two stages membrane, respectively $0.57 and $0.46 million/GJ of exported gas, while the largest cost belongs to the hybrid membrane and chemical absorption ($1.78 million/GJ of exported gas). Chemical absorption holds the lowest carbon dioxide emission per ton of injected carbon dioxide (0.15 t/t), seconded by membrane permeation (0.19 t/t). Hybrid membrane and chemical absorption inherits the small footprint of membrane permeation and, despite its highest life-cycle cost, is recommended for flexibility reasons due to increasing carbon dioxide content in the reservoir life-time in cases of ultra-deepwater fields with high gas to oil ratio, high carbon dioxide content and early carbon dioxide enhanced oil recovery. Contrarily to the widely acceptance of membrane permeation as a leading small footprint solution, the overall performance analysis, under the adopted premises, remarkably favors chemical absorption.

Riser-System Design in Water Depths Greater Than 3000 m

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 25840, “Frontier Deepwater Developments: The Impact on Riser-System Design in Water Depths Greater Than 3000 m,” by N. Saglar, B. Toleman, and R. Thethi, 2H Offshore, prepared for the 2015 Offshore Technology Conference, Houston, 4–7 May. The paper has not been peer reviewed. The offshore industry anticipates the need for production-riser systems in ultradeepwater fields. The development of these fields [this paper considers a field located in the central Gulf of Mexico (GOM)] leads to many challenges with respect to the selection of the riser concept; in some instances, such applications may require extending riser technology beyond its current limits. This paper evaluates the feasibility of a number of production-and export-riser configurations for ultradeepwater applications. Riser-Wall-Thickness Sizing Please note that riser-design criteria, methodology, and data (riser functions and associated pipe sizes; riser internal-fluid properties; and riser-strength assessment) are provided in the complete paper. Production Risers. Steel-catenary-riser (SCR) wall-thickness sizing is initially carried out when considering X65 line pipe. For a design pressure of 5 ksi, the wall thickness of the production riser is primarily driven by collapse because of external hydrostatic pressure. The maximum wall thicknesses required for 8-, 10-, and 12-in. pipes are 1.51, 1.85, and 2.17 in., respectively, and are driven by burst owing to the 15-ksi internal design pressure. It should be noted that these wall thicknesses are designed to resist only the burst and collapse pressures. The longitudinal-load and combined-load design checks are performed after the sizing is performed for collapse and burst. For ultradeep water, the longitudinal-load design criterion becomes a limiting requirement. For 3000-m water depth, the production risers meet both the longitudinal-load and combined-load design criteria. Buckling caused by combined bending and external pressure is also checked with the calculated wall thicknesses. The allowable bending strains of all the production risers are determined to be greater than the assumed maximum bending strain of 0.5%. The field-proven thickest wall to date for conventionally welded X65 single-pipe wet-tree production-riser systems is 1.65 in. In this paper, the maximum wall thickness that can be welded for offshore fatigue-sensitive riser systems is assumed to be 1.9 in., on the basis of existing tests. Only the wall thickness required for a 12-in. production riser with a design pressure of 15 ksi exceeds the 1.9-in. limit. Export Risers. SCR wall-thickness sizing is initially carried out considering X65 line pipe with a design pressure of 5,000 psi. The wall thickness of the export riser is first calculated to resist the burst and collapse pressures. It is determined that the wall thickness required for collapse is higher than the sizing based on burst for all water depths and outer diameters. However, the wall thickness driven by collapse does not meet the 0.5% allowable bending strain considering the combined bending and external-pressure criterion. The wall thicknesses of the export risers are increased to maintain the allowable bending strain of 0.5% in the pipe. Therefore, the wall thickness of the export risers is driven primarily by buckling because of the combined bending and external-pressure criterion. The wall thicknesses of the export risers are shown in Fig. 1. The maximum wall thicknesses required for 16-, 20-, and 24-in. pipes are 1.55, 1.95, and 2.32 in., respectively, and occur at a water depth of 4500 m. When considering the longitudinal load from the static tension in the flooded condition at the top of the riser in water depths of at least 3750 m, the effective tension exceeds the 60%-of-yield tension capacity. For ultradeep water, the longitudinal-load design criterion becomes the limiting requirement.

Role of Electrical Submerged Pumps in Enabling Asphaltene-Stabilized Emulsions

Many oilfield development projects require artificial lift systems, i.e., methods to enhance well fluid production that are needed when the reservoir pressure is too low to allow for the produced fluid to reach the surface. Such an approach is of particular interest for mature oilfields (such as those in the Middle East and North Africa) and for many of the upcoming deepwater and ultra-deepwater fields under development around the world. Artificial lifting can be achieved by gas lifting or through a pump installed into the well. For subsea downhole applications, a progressive cavity pump (PCP) or (centrifugal) electrical submersible pump (ESP) is employed. ESP systems are having, in particular, wide spreading, essentially as a result of the good efficiencies and high rates and depth. In search of means for maximizing the productivity of each well that sometimes leads to looking for producing the maximum in the shortest possible time, these pumps are seen as a sort of panacea. In this work, a dangerous pos...

Reassessment of Multiphase Pumps for Marginal-Field Development

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165587, ’Reassessment of Multiphase Pumps in Field-Case Studies for Marginal Deepwater Field Developments,’ by N. Abili, F. Kara, and I.J. Ohanyere, Cranfield University. This paper was peer reviewed and published in the February 2014 SPE Oil & Gas Facilities magazine, p. 56. This paper focuses on the applicability of subsea-processing technology (SPT) using multiphase pumps (MPPs) to develop marginal fields commercially. A technology selection consisted of a comparison of performances of several SPTs for effective development of marginal fields and was evaluated further with an analytical hierarchical process, resulting in the most effective innovative SPT for marginal-field development. The findings of this process were validated further in their applications to real fields, reflected in specific field-case simulation studies. Introduction Most of the world’s exploration-and-production companies have a significant number of unconventional and remote fields in their portfolios. Recent industrial effort has been focused on the accelerated development of SPT. One of the innovative solutions is the handling and treatment of produced oil and gas at or below the seabed for transport to topside facilities, to mitigate flow-assurance issues. Some of the notable benefits of subsea processing include mitigation of hydrate formation and management of pressure-related issues resulting from the production of heavy oil, increase in wellhead pressure, and increased hydrocarbon production from fields with low pressure profiles. In ultradeepwater and deepwater fields, subsea processing is the most effective solution because such fields are beyond human intervention (divers), and it is used to boost hydrocarbon production from green fields or brownfields, reducing production cost and the need for topside processing. This paper explores subsea processing in the development of offshore fields. From the concept selection, an optimal or near-optimal solution of SPT was then applied to an offshore-field development. The application of the optimal solution is simulated with a transient-multiphase-flow dynamic-model program, and the production profiles obtained from the simulation are compared with the reservoir’s production profile. The present paper considers results presented on subsea MPPs as a possible solution to develop marginal offshore fields commercially. Results and Analysis of Field-Case Study The simulation covers an 8-year production period simulated over two isolated cases (see the complete paper for discussions of four such cases) with varying water cuts and productivity index (PI). This simulation compared the most-innovative and -effective SPT found through analysis, which is multiphase pumping. The base case is modeled in a transient-multiphase-flow program without any form of subsea processing or gas or water injection. Field A is a typical example, and the current production profile uses an electrical submersible pump (ESP) to boost production; however, this is not modeled here because of the difficulty in handling free gas at suction conditions, because this reduces the efficiency of the pump and creates difficulty in modeling an advanced gas handler or gas separator for an ESP in the transient-multiphase-flow program. Hence, for each of the cases in the 8-year period, we ran concurrent simulations for different field-development profiles. The field-development profiles were simulated for two production cases: Case 1 produces fields without subsea processing (base case without SPT). Case 2 produces fields with subsea processing using multiphase pumping. Field A. The field is located in the North Sea, at a water depth of more than 180 m and a seabed temperature of 4°C. A 26 000-m length of pipeline at an uneven seabed is expected to create slugs in the flowline. The well that was considered was a deviated well with a vertical depth of 1848 m from the seabed and a horizontal distance of 800 m from the wellhead. This is a high-pressure field, with reservoir pressure in excess of 200 bar and temperature in excess of 70°C. Production is through water injection, tied back to a floating production, storage, and offloading vessel. Field B is discussed in detail in the complete paper. Two field-case studies from Field A will be outlined here; please see the complete paper for the results of two field-case studies from Field B.

Technology Focus: Deepwater Projects (May 2014)

Technology Focus In the kingdom of wet completion, Petrobras has just installed its first tension-leg wellhead platform, in the field of Papa Terra in 1190-m-deep water. It is going to be a revolution regarding how to operate such an installation and be able to produce the heavy oil of Papa Terra (14–17°API). For many years, Petrobras engineers have being analyzing the use of a tension-leg platform or a spar as a solution for their field developments, and, finally, it came through. I strongly believe that all the lessons learned from installation (completed by now) to operation will result in much better solutions for the future of dry completion in our industry. In past JPT reviews, I wrote about the effect for field developments of the first floating production, storage, and offloading vessel in the Gulf of Mexico installed by Petrobras in Cascade and Chinook. And I believe that, once again, Petrobras is creating the same impact now in its own backyard. In February 2014, Petrobras reached a production of 400,000 B/D in the Brazilian presalt 8 years after of the discovery of the first field. In this presalt cluster, the consortium led by Petrobras, including Total, Shell, CNOOC, and CNPC, will be developing the Libra field, one of the biggest discoveries in ultradeep waters in the world. The estimated reserves of 8 billion to 12 billion bbl of recoverable oil will demand a great amount of resources to cope with the challenges of developing this gigantic field. If you are an engineer looking for an opportunity for technological growth and learning experiences, do not miss this chance. Lately, I have been reading a lot about the shale gas/oil developments in the United States, and I am amazed to see the forecasts showing that this gas/oil production will lead the United States to be self-sufficient by 2020 and a net exporter by 2030. It is a good example of what technology can do for you when combined with entrepreneurship. I have been reading also that unconventional oil and gas has taken money out of deepwater developments and that some majors have deferred their projects because of economics compared with tight oil projects. Equilibrium will come, and I believe both will contribute to our oil/gas supply. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 166337 Water-Depth Record for Electric-Line Operations—Retrieving Asphaltenes With Riserless Light Well Intervention by Steven Ashcraft, Anadarko, et al. OTC 24529 Roncador Module IV: A Successful Case in Heavy-Oil Projects In Ultradeep Water by E. Bordieri, Petrobras, et al. OTC 24508 Scale Management in Deep and Ultradeepwater Fields by M.C.M. Bezerra, Petrobras, et al.

Technology Focus: Field Development Projects (October 2012)

Technology Focus During the past years, several discoveries have been made in deep and ultradeep waters around the world. Many development projects are ongoing, and exploratory campaigns are increasing in this type of play. This latter factor will certainly result in new discoveries; it has already been seen in the presalt in Brazil, the Lower Tertiary in the deep water of the Gulf of Mexico, and the fields off the coast of West Africa. One of the challenges faced by the operators is making the appropriate selection for a field development plan. This is certainly the key to a successful project, requiring several studies by the operators to allow the technical groups to understand the complexity of the reservoir. The drilling costs in deep water continue to increase every day and represent the bigger portion of the capital expenditures for deepwater-field development. Therefore, having a good knowledge of the reservoir will help define the well design and architecture, optimizing the costs and maximizing the oil recovery. The papers selected for this month’s issue are related to deep- and ultradeep-water field development projects and are good examples of how operators are working on studies to help make the correct decision for the development plan to be selected. Please enjoy your reading. Recommended additional reading at OnePetro: www.onepetro.org. OTC 22993 The Who Dat Development: Evolution of a Project From Lease Sale to First Production by Rick Fowler, LLOG Exploration, et al. OTC 23172 Pazflor, a Major Step for Angola by Gaspar Martins, Sonangol OTC 22997 Overcoming Field Development Challenges in Depleting Ultra-HP/HT West Franklin Field by Slobodan Jezdimirovic, Total E&P, et al. SPE 147956 Modeling of a New Field Development Plan for a Giant Offshore Oil Field in the UAE by S. Bachar, Zakum Oil Development, et al.

Water and Data and Wells - Three Keys To E&P'S Future

Higher energy prices have pushed exploration and production (E&P) into difficult places with enormous potential, from ultradeepwater fields offshore to unconventional reservoirs onshore. With every advance, though, new problems emerge.

Deepwater Gulf of Mexico Development Challenges

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 113011, "Deepwater Gulf of Mexico Development Challenges Overview," by Frank Close, Bob McCavitt, SPE, and Brian Smith, Chevron North America E&P Company, prepared for the 2008 SPE North Africa Technical Conference and Exhibition, Marrakech, Morocco, 12–14 March. The paper has not been peer reviewed. A high-level review of recent development challenges for the deepwater and ultradeepwater fields in the Gulf of Mexico (GOM) is presented. How these challenges were addressed and how Chevron plans to address even-more-demanding challenges in the future are summarized. Introduction Operating in all areas of the world presents many challenges. The GOM, although a long-established and prolific hydrocarbon basin, has, over the past 15 or so years, evolved into an arena where operations challenges have been encountered in ever-increasing water depths further from the coast. These challenges include seismic acquisition, drilling operations, completion operations, subsea operations, production operations, logistics support, and many more. Fields are being developed in the GOM that pose the greatest engineering challenges that the company has addressed. It is anticipated that developing resources in water depths of 10,000 ft will be fundamental to the continued long-term success of the GOM as one of the world's major producing basins. Challenges Many of the prospects in the ultradeep-water GOM have a unique combination of challenges. The combination of deep water (to 10,000 ft water depth), high pressure (>10,000 psi shut-in pressures), high temperatures (>350°F bottomhole temperature), problematic formations (e.g., salt or tar zones), deep reservoirs (more than 30,000 ft true vertical depth), tight-sandstone reservoirs (<10 md), and fluids with extreme flow-assurance issues separates many GOM deepwater and ultradeepwater wells from deepwater and ultradeepwater wells in other parts of the world. As Fig. 1 shows, much of the prospective GOM deepwater exploration area is in 4,000 to 10,000 ft of water. Most of this area is in a subsalt environment, with salt canopies ranging from 7,000 to 20,000 ft thick and target depths ranging from 25,000 to 35,000 ft true vertical depth. The vast salt zones inhibit deep-seismic resolution, presenting great challenges in exploration, appraisal, and development operations. Understanding the geology associated with the massive salt and, more importantly, the quality of imaging below the salt is paramount. A key technology being developed to address this challenge is wide-azimuth-towed-streamer technology. This technique allows better subsurface imaging for effective reservoir management and will dictate well placement and number of wells required to drain the reservoir optimally. The true vertical depths of some deepwater wells are in excess of 34,000 ft. Fig. 2 shows some of the drilling challenges.

Overview: Artificial Lift (May 2007)

Boosting ultimate recovery requires us to get more from each well and each reservoir. Clearly, while improving recovery is one of the best places to look for additional reserves, often the relationship between artificial lift and ultimate recovery has been forgotten. However, when artificial lift options are limited, as is the case for subsea wells, we quickly discover that recoveries drop to among the lowest in the industry. Today, selection of an artificial lift technique plays an increasingly important role in determining ultimate recovery. In addition to the challenges posed by subsea/deepwater production, unconventional reservoirs also require new ideas to improve recovery. For example, steam operations used to produce from heavy-oil reservoirs require downhole and surface pumps to operate at temperatures well beyond our experience base. Unconventional gas reservoirs, such as coalbed methane and ultralow-permeability sand/shale, also present unique challenges. In these cases, operating companies must solve problems associated with lifting liquids to the surface (i.e., liquid loading). The papers highlighted in this artificial-lift section illustrate some of the approaches applied in a wide variety of reservoirs. From installation of electrical submersible pumps in hot, high-gas/oil-ratio wells to rod-pumping applications for gas well unloading, these papers illustrate the adaptation of artificial-lift methods to keep wells producing and to extend field life. Work on improving the ability to predict the slug-to-annular-flow transition also is highlighted. This work is of great interest to the area of gas lift stability as well as predicting the onset of liquid loading. The recommended reading list highlights some of the latest thinking on the requirements and current state of the art in the rapidly evolving area of seafloor boosting. This particular type of artificial lift, by use of subsea multiphase pumps, is quickly becoming an integral part of the field-development plan for deepwater and ultradeepwater fields. Given the industry shift to deepwater and unconventional reservoirs, today's definition of artificial lift must encompass a much broader range of technologies than in the past. Also, the critical role that artificial lift plays in increasing ultimate recovery needs to be recognized up front so that effective artificial-lift solutions can be incorporated in field-development planning. Artificial Lift additional reading available at the SPE eLibrary: www.spe.org SPE 104037 "Stability Analysis of Gas Lift Wells Used for Deepwater Oil Production" by I. Guerrero-Sarabia, National Autonomous University of Mexico, et al. SPE 104314 "Economic Pumping Technology for Coalbed Methane (CBM), Stripper Oil, and Shallow Gas Well Deliquification" by Michael W. Dickey, SmithLift Available at the OTC Library: www.otcnet.org OTC 18261 "Subsea Processing and Boosting—Technical Challenges and Opportunities" by R.M. Bass, Shell International E&P OTC 17899 "Subsea Boosting of the Brenda Field Through Utilization of a Multipurpose Field Development Solution" by J. Elde, SPE, Framo Engineering, et al.

The Internal-Corrosion-Integrity Strategy on the Development of New Offshore-Production Areas in Brazil

SummaryThis paper illustrates the importance of internal-corrosion-management and -integrity strategy in the development of new offshore-production areas in shallow and ultradeep waters in Brazil, where there is no other production facility nearby. Starting production activities in these areas without any facility—especially pipelines—is a challenge because the investment necessary is high, particularly when the first area to be produced is a gas block. The financial feasibility of a small- or medium-sized gas field with very low condensate production is extremely delicate because this kind of project usually demands high initial investments, particularly with topside facilities, platform structures, and pipelines.The financial scenario worsens as the first investment must consider not only the area to be put into production, but also other potential areas nearby with exploration still under way. To foresee fluid composition and all flow-parameter scenarios is a complex but necessary exercise to reduce risk and keep the operating expenditure (OPEX) as low as possible.One of the aims of this paper is to show one experience in the design of offshore gas fields in the shallow waters of Espirito Santo, Brazil, where pipeline-corrosion management and integrity strongly affected the capital expenditure (CAPEX) and OPEX factors because the flow-rate capacity was overdesigned to transport future production from adjacent fields.This paper discusses some of the newer issues related to the CO2-corrosion-risk-assessment and -integrity strategies. The paper also briefly discusses some current key issues regarding the ultradeepwater fields related to areas of uncertainties caused by internal corrosion, such as pipelines operating under supercritical flow and steel catenary risers operating within a corrosion-fatigue environment.

Overview: Field Development (September 2005)

A couple of years ago, when I started this task of annual papers selection for this feature, the focus of my statement was about the so-called “digital company.” One year later, the concept that drove my attention was the capability of parallel and accurate planning strategy, starting from the discovery well, with the early involvement of all the concerned professionals and expertise. This year, papers, seminars, and workshops show clearly the common trend to develop technology faster and look for innovative solutions strictly fit for purpose to meet the local technical requirement as soon as possible and accelerate the first production. Although medium- to long-range R&D and technology innovation are still considered strategic issues, much effort appears to be on achieving the immediate result: technology solutions are designed and locally deployed to minimize the time to reach the market for a specific asset. Key elements of this current tendency are as follows. - Immediate understanding of technical gaps, technical requirements, and solutions. - Strong competency and capability of effective and efficient technology selection and deployment (make or buy?). - Excellent communication. However, without the third element (excellent communication), the value created by the other two elements could be much less. As a matter of fact, a successful fast technology development and application to solve a local need (as the current trend is displaying) is not a complete success if it is not shared quickly within the company. In this perspective, communication plays an important role from the perception of the technical gap to the field application of the solution and, finally, to the fast propagation of the experience. The wise use of today’s communication strategies (e.g., the community of practices) then is an important asset to further the success stories in a timely manner. Field Development additional reading available from the SPE eLibrary: www.spe.org. SPE 90434 - “Optimization of Well Placement and Improved Well Planning Within a Collaborative 3D Environment Employing Real-Time Data: A Case Study From the Visund Field, Norway,” by Girling, S. B., SPE, Landmark, et al. SPE 92895 - “Integrated Approach for Improving Development of a Mature Field,” by Xiaoguang, L., SPE, PetroChina Intl., et al. SPE 94206 - “Shifting the Gaussian Curve to the Right—A Fully Stochastic Approach to Marginal Offshore Field Development,” by Graf, T., SPE, Schlumberger, et al. SPE 97378 - “Technological Challenges for the Development of Ultradeepwater Fields,” by Saliés, J.B., SPE, Petrobras

Spar Vortex-Induced-Vibration Prediction

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 16343, "Advancement of Spar VIV Prediction," by T.-W. Yung, R.E. Sandstrom, S.T. Slocum, Z.J. Ding, and R.T. Lokken, SPE, ExxonMobil Upstream Research Co., originally presented at the 2004 Offshore Technology Conference, Houston, 3-6 May. Vortex-induced vibration (VIV) of spar hulls is an operational issue in high-current environments and an important consideration for mooring and riser integrity. On the basis of extensive analytical, laboratory, and field studies, ExxonMobil has developed a reliable methodology for predicting the VIV of classic spars that has been validated by field measurements. Introduction Spar technology continues to evolve and currently is experiencing wide application in deep- to ultradeepwater fields in the Gulf of Mexico (GOM). Eight spars have been installed in the GOM since 1996, and five more are in various stages of design and construction. These include classic spars [deep-draft caisson vessel (DDCV)], truss spars, and cell spars. A spar platform is characterized by a large, usually cylindrical, hull that extends deep into the water. In the GOM, the loop current and loop-current eddies (Fig. 1) have the potential to cause VIV on the spar hull. Speeds in these currents can remain high well below the surface, exposing the entire hull to large forces. In addition, hurricane currents also may cause VIV spar motion. Field measurements have shown that all of the three classic spars (Hoover, Genesis, and Neptune) have experienced VIV. From these experiences, it was observed that both loop/eddy currents and inertial currents (after a severe storm) could cause VIV. For the Hoover DDCV, eddy currents with speeds as low as 1 to 2 knots have caused VIV. Industrial experience with VIV started many decades ago with the development of VIV-suppression devices for smokestacks and chimneys. Over the years, there have been numerous studies on VIV physics as well as VIV-suppression devices for onshore and offshore structures. In recent years, there has been an increased interest in spar-VIV-design practice, highlighted by the first-ever industrywide workshop dedicated exclusively to spar VIV. The October 2003 workshop addressed a wide range of topics. In the workshop, the ExxonMobil spar VIV-design practice, based on work for the Hoover project, was presented. The design practice is based on a combined analytical, model-testing, and field-measurement approach. The discussion was focused on key factors for reliable prediction of classic-spar hull-VIV response and comparisons between model test results and field measurements.