As a general practice in the oil and gas industry, the well foundation, composed by the conductor and the surface casing, is designed with a strict tolerance regarding cement shortfall on the surface casing. However, in a pre-salt scenario, in order to reduce the costs of well construction, the surface casing shoe generally reaches the top of salt. In this case, it is quite hard to make the cement job reach the mudline due to problems like salt dissolution (generating high calipers) and presence of many geological faults in the post-salt zone (which can work as a lost circulation area). Besides that, an evaluation of the wellhead movement is necessary so that the structural restrictions of subsea equipment connected to the wellhead are not violated. This work had the goal of presenting a coupled structural model to analyze the foundation of a subsea well with a partially cemented surface casing, where the safety factors of surface casing are evaluated in the whole well life cycle along with the wellhead movement due to the loads related to each step of this cycle. A sensitivity analysis on the top of cement (measured from the casing shoe) is made, varying it from 300 m to 800 m. The results showed wellhead movement consistent with what is observed in the field, once no axial movement has been reported. Additionally, it was highlighted that the foundation design depends on the operations during the well construction and its future purpose, production or injection, because the thermal loads associated with operations have different impacts.

This paper is part of the special OTC session "Floating Memories-Look Back to Leap Forward" intended as a historic retrospective of the evolution of the four major types of floating production platforms: Floating Production Storage and Offloading (FPSO), Semisubmersible (FPS), Tension Leg Platform (TLP) and Spar, from their inception to the present day. The session includes a look ahead to the future of these floating platforms and what it will take to sustain their commercial viability as they adapt to headwinds from continuous volatility of oil and gas prices and competition from onshore tight oil projects. This paper's focus is the Semisubmersible Floating Production System (FPS). It chronicles the forty five year progression of FPS technology from its humble beginnings in 1975 as a converted Mobile Offshore Drilling Unit (MODU) deployed on the Argyll field in the North Sea in 80 m of water, to Appomattox, the most recent FPS, that began production in 2019 in 2250 m of water in the Gulf of Mexico (GoM) . It also touches briefly on the evolution of the FPS hull, mooring and riser systems and addresses future trends and prospects. From Argyll to Appomattox

Systems-Theoretic Process Analysis (STPA) is a recently developed hazard identification technique that is based on control and systems theory. Previous studies on STPA emphasize two major strengths of the method: (1) STPA provides a systematic top-down approach that enables early identification of system flaws, and (2) STPA covers a wider scope of hazards compared to traditional methods. Despite these advantages, there are only a limited number of studies that have applied the method to subsea systems. It is therefore of interest to investigate how STPA can be used to formulate new or verify existing requirements to safety-critical systems for subsea facilities. One example is the isolation of subsea wells initiated by the platform emergency shutdown (ESD) system. The purpose of this paper is to apply STPA to this function, and to discuss opportunities, challenges and possible implications of the results obtained from the analysis. The paper starts with a thorough literature study and includes an analysis of the insights and recommendations made from other industry sectors and application areas. This review is followed by the STPA analysis of the proposed system, with focus on the identification of the unsafe control actions and safety constraints for subsea well isolation. It is investigated how STPA is able to address specific design philosophies and subsea operating conditions, like fail-safe function of subsea ESD valves, long distance between top-side control system and subsea valves, and dynamic behavior of the control structure. The paper concludes with discussions and suggestions on how the STPA procedure may be improved for application to subsea systems.

Spacing out production tubing and landing the tubing hanger in subsea completions is particularly challenging in wells with extreme well depths or in highly deviated well bores, as rig heave can significantly challenge space-out operations. Another problem also can occur when attempting to enter the casing at the subsea blowout preventer (BOP) in deep water, since the subsea currents can initiate a bending motion to the riser, causing the bottom of the completion to enter the subsea blowout preventer (BOP) at an angle. If the angle is too high, set-down weight or compression must be applied to push the completion through, placing shearable travel joints at risk of prematurely shearing. Even after pushing the travel joint through the subsea BOP, the completion design must manage friction induced by well deviations or ‘S’ curve well bores. Also, the travel joint must remain rigid enough to land seals into production packers at the formation. Often, these challenging scenarios with high angles can be further complicated by limited available slack-off weight. This paper will discuss how the development of new travel-joint designs were capable of resolving challenges such as those mentioned above that were encountered on the the first deepwater subsea development for an operator in Malaysia. This was also the first entirely deepwater subsea development in Malaysia, and at the time of the commencement of its development, an average production of 135,000 barrels per day of hydrocarbon was expected from the project. To address the completion obstacles discussed above, a service/engineering company developed a long, space-out travel joint (LSOTJ) designed to telescope downward in response to a timed application of a compressive load rather than a shearing event as in standard designs. The LSOTJ slowly scopes downward during lowering of the production tubing until the hanger is landed. Equipment development was comprised of two versions of the long space-out travel joint; one version is a non-continuous sealing (NCS-LSOTJ) version, and the other is a continuous sealing (CS-LSOTJ) version This paper will discuss the design and development of the two LSOTJ versions, and the first usage of the continuous sealing version in Malaysia, which was also its first usage world-wide.

Subsea processing (SP) technologies and host facilities are distinct building blocks in offshore oil and gas field development; they can be regarded as complements or alternates depending on the given scenario. This paper will present a unique insight into these scenarios including applicable interactions. It will highlight the key parameters in this rarely investigated correlation which influence concept selection and full field development (FFD). The paper will also shed some light on key FFD drivers such as reservoir size and (qualitative) economics. This paper is based on thoroughly conducted secondary research covering 72 past, present, and potential-future related projects around the world. A multidisciplinary approach leveraging expertise in field development, topsides and subsea processing was developed to highlight the trends and possible future applications. The study reveals a direct correlation between subsea processing systems and host selection which plays a vital role in concept feasibility studies and full field development. Numerous subsea processing parameters have been considered during this study and a few have shown significant effects on host selection - reservoir size, water depth, field typology, etc. The generated trends reveal interesting winners and losers for various technical configurations, including a slight technology limitation dependence on geographical region. Although it may be possible to predict future applications of subsea processing technology and optimize designs based on the host's interaction with the subsea processing system, the market uncertainties still remain high; nevertheless, recommended areas of focus are presented in this paper based on identified gaps. There are not many publications on this subject; therefore some of the observations presented in this paper are novel.

The Mars B Development is by IPA definition an " Industrial Mega Project" that is within the execution phase. The development is focused on the addition of new infrastructure to the Mars Field located in the Mississippi Canyon protraction area of the Gulf of Mexico. The development operated by Shell (71.5%) with BP as a Working Interest Owner (28.5%) can be summarized into three major infrastructure components: The Olympus Tension Leg Platform (TLP) West Boreas/South Deimos Subsea Tie-back Dedicated oil and gas export pipelines and the West Delta 143C Shallow Water Platform. The Mars B Development is a first for Shell in the deepwater GOM, in that it represents the first occasion that a second significant production and drilling facility (Olympus TLP) has been installed to complement existing infrastructure (Mars TLP). The Mars Field is a true deepwater giant with close to 4 billion boe hydrocarbons in place. The Mars TLP was brought on production in 1996 and to date (01.01.14) has produced over 700mln boe. The Mars TLP, a 24 well slot Tension Legged Platform with multiple subsea tie-backs, has a significant track record in developing the field. Constraints, such as the number of available well slots and capacity for future subsea tie-backs, limited its expansion. The structural limitation of the Mars TLP was a main driver for the need to install a second TLP, the Olympus TLP. Once the Olympus TLP is brought on production in 2014, the Mars Field Depletion plan can be characterized by the following numbers and the unique challenges of integrating the following: One Deepwater Giant Field 50+ discrete Hydrocarbon reservoirs Two Tension Legged Platforms 48 Platform well bores + 6 subsea wells Field life extended to 2050(+) This presents the unique challenges of developing a holistic and evergreen Mars Field Depletion plan that captures the synergies provided by two production and drilling facilities on a single field; and further the ability to extend the Mars Field life to 2050(+) results in a depletion plan that will ensure that we maximize the recovery from a key GOM resource base.

Abstract The high cost of subsea intervention makes in-well monitoring its greatest value. Even if interventions are possible it may not be at optimal well condition with the traditional technology. There also will be SIMOPS and operation issues. Real time in-well monitoring can be done at full well rates to operate well at maximum safe rates and thus lead to higher recovery. Acquiring key reservoir productivity and continuity data early can decrease risk for subsequent well decisions and help in development decisions. In-well monitoring will provide flow rates by sand layer, provide gas breakthrough and water breakthrough information and pinpoint exact location. All this information to engineers can help in decreasing production deferment from these producing wells. In case of injectors, warm back data helps in identifying zones where maximum water is getting injected and may identify out of zone injection. However significant challenges remain in selection, qualification and deployment of these technologies in deepwater subsea wells. The paper will provide an operator's view point covering some of the key challenges below: All components must be rigorously qualified to meet the stringent safety and operational requirements. The subsea tree interface between the tree and tubing hanger and between the lower upper completion creates a significant technical challenge. While there are potential solutions, dispersed capability in supplier base creates an integration challenge. The scope is further challenged by implementing across diverse reservoirs, flow and production characterization, completion type and enormous integration across various product groups. There is no point deploying state of the art advanced sensing if the resulting data is not easily accessible and interpreted. Especially in the subsea environment where costs are high, the entire value chain (hardware, data management and interpretation) needs to be in place to bring value. Resolution, accuracy and sampling time are interrelated and we are not able to achieve all with the current technology at the desired depth and offset distances. For certain operation such as planned well shut-in, buildups and press temperature analysis we need higher sampling rate which are easily and remotely configurable Operator needs to overcome internal hurdles – various functional teams (wells, subsea, IT) have to work together; this requires significant effort in terms of working the interfaces, integration and ultimately moving towards standardization. In-well monitoring can improve quality of surveillance in subsea wells enabling low cost, non intrusive, well and reservoir surveillance provided the industry overcomes the technical challenges/gaps and improves the reliability of the system.

Abstract Permanently installed fiber optic systems have been commercially available in the oilfield since the early 1990's, with the bulk of the deployments providing fiber-optic distributed temperature. Over 1200 installations have been deployed by one service company alone. Such installations have reduced the need for intervention via logging tools and have given crucial insights into wellbore integrity and reservoir production. Consequently, a prime application of fiber technology should be in deepwater fields, where intervention can be prohibitively expensive, if not impossible - but that has yet to prove true. The reluctance to incorporate downhole fiber appears to be because of limitations of technology relating to cables, deployment, acquisition and interfacing. These barriers are slowly being eliminated and a small number subsea wells have now been implemented with in-well fiber. Specific technology breakthroughs have been pertinent to subsea: cables that withstand hydrogen darkening; fiber connectivity interfaces to subsea trees; and increased deployment options for acquisition hardware. Deployed subsea solutions have included optic monitoring for cementing, integrity and clean-up. A roadmap to eliminate some remaining obstacles includes the needed interfaces for power and telemetry to the SPS and the interpretation of temperature data on complex subsea fields. That roadmap needs to take into account the full range of hardware opportunities available for subsea applications and not exclusively fiber-optic. Indeed, the optimal completion solution need not involve sandface fiber at all. Introduction Permanently installed fiber optic systems have been commercially available in the oilfield since the early 1990's, with the bulk of the deployments providing fiber-optic distributed temperature based upon Raman backscattering, (Brown, 2009). This Raman DTS measurement system provides continuous data along the length of the completion without the need for intervention and without introducing restrictions in the ID of the completion tubulars: restrictions that could impede subsequent wellbore access. Typical DTS spatial resolution is better than one data point per meter and with a temperature resolution 0.01oC. Applications of the distributed temperature data have included calculating flow contributions across the sandface, evaluating water-injection profiles, diagnosing the effectiveness of fracture jobs, finding cement tops behind casing, and identifying cross-flow between producing zones. The growth of fiber installations for dry-tree (land and platform) applications is increasing exponentially. Over 1200 installations have been deployed by one service company alone. The bulk of those installations were single-stage completions, often for thermal or SAGD application, and relied upon the ability to pump fiber along a control line to convey the sensing fiber. About 20 of those wells have fiber pumped along sandface of dual-stage OHGP completions. A significant advantage of the pumped fiber was that if the fiber should degrade over time, then it could be pumped out and replaced. This was particularly important before the discovery of how to construct fibers with some immunity to darkening from H+ and OH- ions, (Ramos et al., 2008). With hydrogen resistance, came the possibility of longevity of fixed-fiber cables and, since 2006, an alternate to pumped fiber has been available that combines multiple hydrogen-resistant fibers with an electronic line to create a hybrid cable (e.g. Fig. 1). This cable can power high-accuracy quartz gauges and also give the benefits of fully distributed Raman DTS. (Algeroy et al., 2010). More than 60 such systems have been deployed to date. The combination of these pumped and hybrid fiber installations have proven to reduce the need for intervention via logging tools, and provided crucial insights into reservoir production, performance of artificial lift systems, wellbore integrity and production optimization.

Abstract Commercially available fiber-optic sensors provide key information for well, reservoir and infrastructure surveillance. These fiber optic systems are now considered robust and see routine application in onshore and platform wells. Engineering, economic and project management challenges, however, delay the extension of these monitoring systems into the subsea environment. We illustrate the value of fiber optic monitoring, describe where fiber optic technology has significant potential in subsea development projects and identify the significant technology gaps which challenge subsea implementation of existing in-well fiber-optic sensing systems. We then define an approach to systematically address these gaps within the time frames of many current subsea projects, while preserving the necessary integrity of the subsea system and associated project delivery. The approach borrows from the Agile project management method and focuses on staged delivery of the fiber optic technology, maturing the technology by deploying select portions and then advancing in subsequent stages to the deployment of more-complex or more slowly evolving technologies, rather than attempting to fully mature the technology off-line prior to any deployment. It operates according to the following principles: – Deploy the more easily or readily adaptable portions of the technology first. – Ensure that each incremental deployment economically provides significant benefits, meeting business and technical surveillance targets. – Ensure that each deployment delivers technology maturation learnings that can be used to evaluate newly developed technology, with direct actionable feedback into further development plans. – Ensure that project plans contain sufficient adaptability and capacity for incorporating late-breaking or unforeseen technology advances, as well as contain contingencies to back off from portions of the technology deployment should best judgment dictate. In addition to accelerating technology advance, this approach assures further progress and technology acceptance along the way. We take inspiration from an historic application of such a method: NASA's journey to safely land men on the moon. In the staged development-deployment of the Gemini and Apollo programs, NASA consistently delivered tangible results with each launch, thus capturing and maintaining the support of the public, their primary stakeholders, throughout the program, as well as quickly making significant technical strides which ensured the accomplishment of their goal. Introduction Subsea wells represent expensive, high profile and high risk investments. It's no surprise that any suggestion to include new technology, such as fiber optic monitoring, in a subsea well is quite frequently rejected almost immediately despite value recognized by subsurface engineering and geoscience experts. Like all proponents of new technology, we share in the frustration that many people experience when greeted with this response. We acknwledge and appreciatethat the rationale for such strong resistance stems from the primary commitment of project managers, technical authorities, and subject matter experts to deliver the subsea project without delay, cost overrun or addition of unmanaged or unmanageable risk. We also observe that while the in-well technology advocates might seem to be at odds with installation project management, both groups actually have the same goal: to see the installation succeed in every respect while deliverying a well with high value.

Abstract In recent years, the number of subsea wells has increased steadily; a 2011 report estimated more than 5,500 worldwide. One of the key challenges the industry faces with subsea wells is generally lower recovery factors compared to wells with surface access. A key reason for this difference is because workover activities to improve recovery rates in subsea wells has traditionally required use of large rigs, risers, jointed pipe or coiled tubing (CT), with high operating rates. The high costs of these operations can make it difficult to achieve the necessary increases in production rates and revenue to justify the workover investment, even with increasing oil prices; therefore, operators often forgo production-improvement workovers. However, a growing global population and soaring energy demand means that operators are facing increasing pressure to maximize production and value from mature assets. These challenges have spurred development of alternative, lighter weight, more cost-effective intervention methods to enhance recovery rates in deepwater, subsurface wells. These alternative technologies include electric-line tools that can be run from smaller, dynamically positioned light well intervention vessels, instead of large workover ships with risers. These rigless and riserless light well interventions (RLWI) improve scheduling flexibility and reduce costs, thereby reducing barriers to performing subsurface well interventions and enabling subsea operators to realize oil recovery rates of 50% or more. Today many industry companies have a clear tendency to migrate towards lightweight, more cost-effective alternative solutions. But for some, misperceptions still exist and skepticism remains for using RLWI for deepwater subsea wells. However, over the past decade, RLWI has achieved a solid track record of demonstrated value and is an inherently safer method for subsea well interventions, compared to conventional heavier methods. This paper describes the opportunities to improve recovery rates in subsea wells using the lighter, more efficient and ultimately more productive RLWI methods. Using these techniques has enabled operators to conduct routine planned access to subsea producing assets, improve surveillance and management of interventions, and, ultimately, increase recovery rates. Several case histories and examples are presented. Introduction Challenge: The Need to Increase Production from Existing Assets to Meet Growing Global Demand for Energy. Looking at peak oil production from a number of the major oil producers shows that many of them have reached peak oil production over the last ten years (Table 1) the industry is striving to find new resources to replace diminishing reserves and to meet increasing global demand; these factors are moving exploration and development into deeper water offshore, where currently more new fields are being developed subsea than from platforms (Strategic Offshore Research Ltd. 2012).

Abstract BP policy specifies requirements for well barrier management throughout the life cycle of a well. Well barriers are specifically required to isolate energy sources within the earth from each other, the surface environment, and people. Annulus pressure management is fundamental to maintaining healthy well barriers and active monitoring assures the barriers are in place. In subsea wells, the only annulus that can be monitored in real time is between the tubing and production casing (aka A-annulus). When an anomaly is detected in the A-annulus, then a diagnostics and intervention program must be implemented to repair the suspected well integrity issue. In deepwater environments, repairing a well integrity issue with a rig can be costly and the traditional tools for well diagnostics and repair, such as wireline and coil tubing, are complex to deploy into subsea completions. Alternatives such as pressure-activated sealants have a proven track record repairing well integrity issues in dry tree wells. This technology is now being deployed to repair well integrity issues in subsea wells. This paper presents two case studies where pressure-activated sealants were used to successfully repair tubing by A-annulus (T × A) communication in a subsea wells. BP had utilized this technology with great success in its Alaska fields (SPE Papers10895 and 120978) and saw an opportunity to extend those learnings to subsea wells. These operations utilized innovative delivery techniques to enable sealant injection, placement, and activation downhole. Rigorous testing, simulation, and planning prior to starting the job increased confidence in the operational technique and reduced safety risks to the environment and the wells. Both efforts resulted in a successful repair of the well integrity issue. There were several benefits for using a pressure-activated sealant for these two interventions. The less complex non-rig interventions presented fewer safety and environmental risks and were completed with no HSE incidents. The non-rig repairs were completed for a small fraction of the cost of a conventional rig repair and rig time was kept available for drilling and completing new wells. Given its effectiveness and these benefits, the application of this technology may be especially useful for subsea wells with marginal remaining reserves where the relatively lower cost may help to optimize productive life and ultimate recovery. The integrity of a sealant repair can be monitored during the life of the well just like a conventional rig repair and a sealant repair does not preclude the ability to perform a conventional rig repair in the future.

Abstract The Liwan 3–1 gas field, situates in block 29/26 with an average water depth of 1,300m, represents the first major deepwater discovery in the South China Sea. The development scenario of Liwan 3–1 indicates potentially an efficient way for those gas fields around the continental slope of South China Sea. Before the first appraisal well being drilled, CNOOC Research Institute was commissioned to carry out Liwan 3–1 feasibility study on December 27, 2007. This paper provides an overview of several development scenarios based on the limited data of Liwan 3–1 such as wells information and assumed data such as reservoir profile and pressure. In view of those potential discoveries near Liwan field, regional development strategy is also taken into consideration. As a result, the suggested development scenario is subsea wells tieback to Boosting and Processing Center (BPC). Through BPC, the natural gas is processed and boosted via shallow water pipeline to onshore terminal plant. BPC is actually not only a feasible scenario to speed up Liwan 3–1 development, but also a regional solution for potential fields near Liwan 3–1. Introduction The Liwan 3–1 gas field is the first discovery in the deepwater of South China Sea and shared by CNOOC and Husky. Liwan 3–1 locates at a water depth of nearly 1500m and about 65km from PY30-1–1. The discovery of Liwan 3–1–1 well in 2006 showed that the gas production rate almost reaching 5 billion m3/a. Two appraised wells named Liwan 3–1–2 and Liwan 3–1–3 were also completed in the end of 2008 and in the middle of 2009 by West Hercules semisubmersible drilling platform respectively followed by another appraised well later. In this paper, several development scenarios of Liwan 3–1 gas field are demonstrated firstly. Then the scenarios of BPC (Boosting and Processing Center) are also studied based on a regional development view of potential fields near Liwan 3–1 and the scenario of one APP (accommodation and power platform) plus two PCPs (processing and compressing platform) is recommended. In view of minimizing investment and adopting regional development scenario, subsea wells tieback to BPC is suggested for the development of Liwan 3–1.

Abstract With the present deepwater developments on the increase it is foreseen that adedicated market will develop for vessels capable of intervening on subseawells at a lesser cost than existing deepwater drilling units. Thereby (I)extend the life of deepwater developments rendering additional profits and (II)adhere to minimum field production requirements as are being required by theauthorities more and more to date. The paper describes the development of the concept for such a Well InterventionVessel resulting from a combined effort between a Naval Architecture DesignBureau and a major rig equipment supplier with a focus on an open equipmentstructure facilitating the possible application of multiple levels of/andintervention solutions. The vessel will target Class B+/(II+) and Class C/(III)type interventions, based upon systems which will use risers and capable ofretrieving completions. Input of operators as well as equipment- and serviceproviders has been used in the development of the concept to develop the opensystem. The proposed paper shall present in detail the design approach and basis, theconcept design and the operational parameters of the deepwater well completionand intervention vessel. It will also address in detail the specific pieces ofequipment to be used on the vessel.

Abstract Electrical submersible pumping (ESP) systems have been an efficient method to boost production of oil wells for over half a century. In the past few years, ESP systems have been accepted for use in what once was considered unconventional types of applications, pushing the technology further than ever before. This technology push has encouraged ESP suppliers to devote more time and energy to research and development in order to meet the needs of the expanding application envelope. This paper will outline the results of the research and development as well as the advancements that have been made or are likely to be made to various components of an ESP system. New and innovative ways in which ESP systems have been deployed as well as the positive effects that these techniques will have on the ultimate well recovery and customer's return on investment for deepwater projects will be reviewed and discussed. We will highlight the specifics of ESP applications in off-shore and subsea projects, including seabed boosting. History of ESP system An ESP system is made up of a multi stage centrifugal pump; a seal section which protects the motor from well fluid, ab-sorbs the thrust from the pump and provides pressure equalization between the motor and the wellbore; and a three-phase induction type motor of a HP large enough to drive the pump. An ESP system is lowered into the wellbore on the end of a tubing string which is hung off at the wellhead. The ESP unit is self-contained and requires no additional lines for lubrication or cooling. While ESP technology may seem like an emerging area to some in the oil industry, ESP systems have been in use since 1926, when the first unit was installed near Burns, Kansas for the Phillips Petroleum Company. This unit was deemed to be a success because it ran 24 hours a day for 16 days before a failure. If you were to study some of the early patents, you would find that the basic technology hasn't changed much over the years. Today, the overwhelming majorities of systems are in-stalled in land based applications, with an average ESP in an oil application at a setting depth of approximately 5000 ft, and an average run life of between two and three years. It will typically produce at a flow rate range from less than 1000 BFPD to 30,000 BFPD or more. Contrast the above with the opportunities that we are being presented with today. ESP systems are now being deployed in offshore wells where extra lift or drawdown is required to maximize production. ESPs have been deployed and will continue to be deployed in subsea applications with ever increasing stepouts and water depths. Operators are being faced with increa-singly stringent HS&E requirements, economics are tighter, and return on investment is critical. We are constantly being pushed to new limits with water depths of 8,000 to 10,000 ft or possibly greater. What has changed over time to give us the confidence to install an ESP system in a well with extremely high cost of fail-ure, and where the cost of a workover will be in the millions of dollars? It is worth noting that for most of the world an ESP with a service life of two to three years is considered to be acceptable. While most operators will ask for longer run lives, when they weigh that against the additional cost of procuring such a sys-tem, the economics will not justify the added expense. However, when we look at the offshore—and particularly the sub-sea—environments, the economics drastically change. The cost of an ESP system is relatively small vs. the cost of a workov-er, so the additional upfront cost associated with a higher-end ESP becomes less significant. Additionally, the technology involved in the design, engineering and deployment of ESP systems has changed dramatically over the past few years. These changes have been driven by operators asking the ESP companies to push the equipment toward its operational limits and at the same time asking for longer run lives.

Abstract Perdido is located in the Western Gulf of Mexico in 7,817 feet of water. It is being developed with cutting-edge subsea technologies to mitigate the project's key development challenges, which include extreme water depth, rugged seafloor terrain, low-pressure reservoirs, and aggressive hydrate formation tendency. This paper provides an overview of the Perdido Development subsea and flowline system and its associated flow assurance strategy. This paper also includes reviews of the design, fabrication, and installation of key subsea equipment such as twophase separators, subsea trees, manifolds, top-tensioned production risers, umbilicals, and flowlines. In particular, the two enabling subsea technologies, subsea boosting system and surface Blow-Out Preventer (BOP) for drilling and completing of subsea wells, are discussed. Unique features of the Perdido subsea system include: All wells are subsea (wet trees operated by umbilicals) and consist of 22 local Direct Vertical Access (DVA) wells and 12 offset wells. The subsea DVA wells are drilled, completed, and intervened through a single high-pressure drilling/completion riser and a surface BOP with the host rig. All production will flow from manifolds into five subsea boosting systems where gas will flow naturally to the topside facility, while liquids will be pumped using electrical submersible pumps (ESPs). Introduction The Perdido Development, jointly developed by Shell, BP, and CVX, includes the Great White, Silvertip, and Tobago fields and is located in the Perdido Basin and Foldbelt, in the Alaminos Canyon Protraction Area. This area is located in the western Gulf of Mexico, 200 miles south of Freeport, only eight miles north of the Mexico maritime border. All three fields are developed with subsea wells tied back to the host, which is a Spar with full offshore processing capabilities and pipelines for export.

Abstract In-well monitoring systems have now been developed which utilise permanent optical fibre sensing and can be deployed in the subsea environment. These optical monitoring systems are well suited for subsea deployment in terms of extended temperature and pressure regimes, along with reliability and advanced optical multiplexing technology. Hundreds of optical sensors and millions of feet of optical cable have been successfully deployed in land and dry tree platform oil and gas wells since the early 1990's. In the last 1990's, a few prototype optical sensing systems were deployed subsea for single point pressure and temperature monitoring with partial success. However, over the last 10 years, optical sensing technology has progressed significantly, yet no subsea installations have been performed. This was not due to lack of interest but to significant challenges related to subsea deployment, and also in part due to projects cancelled for such reasons as perceived lack of data delivery infrastructure. This paper describes how the significant challenges of subsea optical sensing were overcome through close cooperation between the operator and other 3rd party companies, along with extensive project organisation, custom engineering, and qualification testing and system verification. Deployment of the system took place offshore Angola in Q1 2008. The major areas which we addressed in order to assure success were: Establishing standards to which the subsea instruments and components should comply with in order to build a robust test regime for qualifying the new optical sensing technology. Developing, qualifying and interfacing a subsea connector system for wellhead and tubing hanger penetration. Developing, qualifying and interfacing a new generation subsea optical instrument which would be deployed subsea in an atmospheric housing. Designing an in-well monitoring system which can deliver accurate reservoir pressure and temperature data from the sand-face to surface.

Abstract With the growing number of subsea wells needing some sort of intervention (repair, measurements, plugs, zone isolation, chemical treatment, scale removal etc.) there is an increasing demand for an efficient subsea light well intervention service. Such a service has been in operation on the Norwegian Continental Shelf for the past four years and is systematically being improved from year to year. Currently, a long term commitment has been made by Norwegian Operators to acquire a RLWI service from one provider for a 5 + 3 years period. In conjunction with this long-term commitment new and improved technology is developed to make this service more efficient wrt. HSE, cost and quality. This paper discusses the RLWI service in general, but focus will be put on some of the new technologies that are under development, technology that may be required to make this service move forward. These new technologies are: composite cable, deployment systems, coiled tubing from light vessels and new well control systems for RLWI. Background Currently there are more than 400 subsea wells in operation by Norwegian companies on the Norwegian Continental Shelf, a number that will increase to 500 on existing fields or fields sanctioned for development within the next few years. In addition, we believe that Norwegian companies will be operating subsea fields in deep waters and arctic areas through their international efforts. Currently the goal of Statoil's IOR R&D efforts is to increase recovery from our Subsea fields to 55% of OOIP, an increase corresponding to 200 MSm3 of additional oil. For the RLWI service to substantially contribute to this large volume, the establishment of an efficient subsea well intervention service is crucial. Historically, some sort of intervention is required every 4th year (or more often) in subsea wells. We see a large gap in well intervention frequency between wells on fixed platforms and subsea wells. This is mainly due to the lack of well intervention capacity and high cost for subsea wells. It has therefore been important to establish a Riserless Light Well Intervention (RLWI) service, which can operate across asset borders on the Norwegian Continental Shelf (NCS). In our case the service provider comprise a ship-owner, a well control company and a wireline company. It is essential that this service arrangement is long- term such that experience gained through operations is turned into improved technology and work processes. By moving well intervention work from expensive drilling rigs to light monohull vessels the well intervention cost should be reduced dramatically, thus enabling more intervention work and eventually increased oil recovery. Even with the long term contract there will be a need for considerable improvement in the operations due to the limited capacity. To create even more efficient operations and move work from expensive rigs to light vessels we have focused our technology development on the following: Make stronger, slick WL cables to be able to carry heavier tool strings and reach total depth (TD) of deep wells with complicated well paths; Extend the wireline (WL) tool string length to 40-60 m (currently 22 m lubrication length is available); New tools/methods for use on light vessels (coiled tubing); Improvements in RLWI stack (well control package) to simplify systems, reduce weight, increase flexibility by a modular system, improve running/pulling speed and HSE, as well as facilitate truly integrated operations (IO).

Abstract As Operator of Angola Block 15, Esso has completed several projects since November 2003, with production capacity totaling 590,000 barrels of oil per day. This paper will provide an overview of the projects from their development planning stages through start-up. Both the Kizomba A and B projects incorporate a surface wellhead, tension-leg platform that is close-moored to a floating production, storage, and offloading vessel (FPSO) in more than 1,100 m of water. Each project also includes offloading facilities and subsea wells and equipment. The FPSOs set records for size, each with processing facilities for 250,000 barrels per day throughput and more than 2.2 million barrels of storage. The Xikomba project, which incorporated an FPSO converted from a trading tanker, will also be described. The paper will address project management aspects of the various projects and highlight some of the unique aspects and challenges of these developments. Exploration Overview In August 1994 Esso Exploration Angola (Block 15), Ltd. (Esso) and its Coventurers acquired the rights to explore offshore Angola Block 15. Block 15 encompasses an area of 4,200 km2 in water depths ranging from 200 m in the east to over 1,600 m in the west. The Angolan national oil company, Sonangol, is the concessionaire of the block, which is approximately 370 km northwest of Luanda, Angola and 145 km west of Soyo, a coastal town at the mouth of the Congo River. Under a Production Sharing Agreement with Sonangol, Esso is the operator of Block 15 and holds a 40% interest. The other Block 15 Coventurers are BP with a 26.7% interest, ENI with a 20% interest, and Statoil with a 13.3% interest. The Kizomba developments, which comprise several reservoirs, are named for a popular Angolan dance. Each of the Block 15 reservoirs has been named for Angolan musical instruments. The initial exploration well on Block 15, Kissanje #1, was drilled in early 1998 to test three objectives in Middle and Lower Miocene age reservoirs. Results from this well confirmed oil in each of the objectives. In parallel to Kissanje #1, a second rig was employed to drill the Marimba #1 wildcat. This well, located 13 km west of Kissanje, also yielded a successful Miocene test. By the third quarter of 1998, two additional successful exploration wells had been drilled in the Hungo and Dikanza reservoirs, and in 1999 discoveries were made in the Chocalho and Xikomba reservoirs.

Abstract Subsea field developments are generally recognized as having lower recovery factors than fields developed by fixed installations. To increase the recovery factor from subsea developed reservoirs, new technologies that will reduce the costs of infill drilling and allow for more cost effective well interventions, must be developed. One potential technology is Through Tubing Rotary Drilling (TTRD). However, for the industry to perform extended reach TTRD from existing subsea producers using floating rigs, the way we manage pressure must be re-evaluated. TTRD combined with Managed Pressure Drilling (MPD) will be the key technologies needed to achieve the low cost, high performance drainage points. This paper describes several MPD methods that can be combined with TTRD and how these methods can be classified, evaluated and applied. Specific results from theoretical simulations will show how two different MPD methods can be used to drill longer departure drainage points than with conventional pressure control. Successful TTRD is believed to produce low cost drainage points for a fraction of the cost of a new subsea well. Introduction Some of the reasons behind the lower recovery factors from subsea developed reservoirs are: Reduced accessibility to the well for interventions, repair and workover purposes Lack of cost efficient well intervention tools and methods High cost of new wells for infill drilling purpose Escalating tangible costs and dayrates of Mobile Offshore Drilling Units (MODU) Effective well spacing and well placement in the producing reservoir is recognized as requirements for optimum reservoir drainage. The ability to access bypassed oil and gas reserves in mature fields has been gaining more and more attention in recent years. Mature fields have huge reserves that lie in multiple isolated pockets that would be uneconomic to produce using new wells. This may particularly be the case in subsea fields in deeper waters where the soaring dayrates for mobile offshore drilling units (MODU) will make the minimum economical reserve requirements hard to find. Through Tubing Drilling (TTD) is a method that eliminates the need for expensive conventional (new) wells or sidetracks. Avoiding drilling the "transport distance" down to the reservoir reduces the costs significantly. In addition, the re-use of the inplace completion equipment saves time for removing the old completion, time for running the new completion and CAPEX of the new completion. Coiled Tubing Drilling (CTD) has been the preferred and dominating TTD technique from fixed installations. However, when a drilling rig is available, the use of jointed pipe and rotary drilling operations has gradually become the more attractive option. The main advantage of using TTRD is the ability to rotate the drillpipe which improves hole cleaning, drilling mechanics, and ultimately increases the reach capability. Thus an obvious potential application of TTRD is infill drilling to access new reserves in subsea wells. TTRD in subsea fields faces several challenges. Many are associated with the narrow annulus between the production bore and the drillpipe, and to the variable formation pressures and lower fracture strengths in depleted formations.

Abstract Bullheading of methanol into deepwater wells is a commonly used method to protect wells from hydrates during long shutdowns. A safe, but conservative wellbore protection approach (based on wellhead cooldown alone), was adopted for many early deepwater wells. This bullheading approach generally required large bullheading volumes (often exceeding 50 bbl) for each well. However, for facilities with an increasing number of wells or with platform storage and weight limitations, this conservative approach may create significant operational problems, including crude and water quality concerns (due to the presence of methanol in the stream). Hence, in these cases, alternative operating strategies to minimize methanol usage are needed. This paper describes an optimal bullheading strategy based upon detailed transient assessment of cooldown times of the entire wellbore, as well as upon evaluation of gas-oil-water and gas-liquid segregation boundaries. Bullheading guidelines are developed that include methanol volumes and bullheading schedule, depending on well fluids, wellbore shut-in conditions, and production conditions prior to shut-in. This paper focuses on bullheading strategies for subsea wells; while not explicitly analyzed, the same approach can be applied to direct vertical access (DVA) wells. The paper will also address bullheading differences for subsea wells with uninsulated tubing and wells with vacuum insulated tubing (VIT). Experimental results and models on oil, water, and gas segregation in the wellbore are discussed. Field data are shown for comparison with the simulation results. Background Due to the high cost of subsea remediation and associated deferred production, protection of deepwater wellbores from hydrate 1 formation and plugging is a major flow assurance concern in offshore operations. Hydrate prevention strategies are usually developed to provide protection during normal operation, start-up and shutdown operations. These strategies are based on elements of the system design, an understanding of hydrate formation mechanisms, and rigorous thermal-hydraulic modeling. Generally, hydrate formation in the wellbore is avoided by maintaining the temperature of the produced fluids above the temperature at which hydrates can form: defined as the hydrate dissociation temperature (HDT). During normal production, reasonable production rates (> 1000-1500 bopd) usually provide enough heat from the reservoir to keep the wellbore temperatures above HDT. During an extended shut-in, the temperatures in the upper portion of the wellbore drop below the HDT. To avoid exposing produced fluids containing hydrocarbons and water to temperatures below the HDT, methanol (or another liquid) is bullheaded into the wellbore at the tree to push the produced water down to a lower portion of the wellbore that is at a temperature above the HDT. Wellbore bullheading for shut-in condition The bullheading hydrate-prevention approach is shown schematically in Figure 1. During a long shut-in, the temperature profile down the wellbore approaches the geothermal temperature profile, which is shown on the right side of Figure 1. With this temperature profile, fluids in the upper portion of the wellbore are at temperatures below the HDT, and fluids in the lower portion are at temperatures above the HDT.