Releasable Mooring Systems ("RMS") have been in use for over 35 years in the offshore industry, with an original purpose of rapidly releasing lines to avoid weather events, such as ice floes, hurricanes, or cyclones. With the recent introduction to industry of fully redundant release tools with higher release load capabilities, the RMS concept is now being used in well planning efficiencies. The objective of the paper is to show the effectiveness of the latest enabling tool and RMS concept in reducing the time to unmoor, removing the requirement for an Anchor Handling Tow Supply (AHTS) vessel, and assisting Dynamically Positioned (DP)/Moored semisubmersibles in lowering their carbon footprint, operational costs and HSE exposure.

Top hole construction is a critical part of any well design, especially for subsea wells. It is considered to be the foundation for the well, and it is crucial for ensuring well integrity. Uncertainties and conditions of the seabed and top layers could compromise the stability of the chosen solution. This paper describes the first implementation of the conductor anchor node (CAN ® ) technology in sand-based conditions and demonstrates its positive impact on the drilling performance for an offshore exploration well in the North Sea. The main challenges identified in the top-hole design for this well were the presence of boulders down to 65 m below the seabed, and hard soil that consisted mainly of very dense sand and high strength sandy-clay layers. Different solutions were evaluated using a risk-based approach, looking to optimize operational performance and decrease the environmental footprint. A technology which consists of a pre-installed short conductor within a CAN was chosen. This solution enabled the operator to establish a competent well foundation above the boulder interval and increase operational efficiency by reducing the critical rig time. However, the CAN technology had not been deployed in this type of soil previously. Thus, the feasibility of its installation became one of the main milestones of the project. This was made possible due to a set of contingencies and modifications that were the result of a strategic collaboration among the parties involved. The CAN was successfully installed by a crane vessel before the rig arrived at location, and the set of contingencies and modifications mentioned in this paper were decisive to ensure it reached the required penetration depth. Furthermore, this paper demonstrates that the CAN technology was crucial for the project to achieve top performance results and become one of the fastest exploration wells drilled in the Norwegian basin. This solution reduced uncertainties related to the conductor cementing, load and fatigue capacities, and deep surface casing cement. Improvement in the drilling performance is determined by estimating the decrease in drilling time, materials and consumables. Those results are then used to perform a cost comparison which demonstrates that the CAN technology reduced the top-hole construction cost significantly on this offshore well. In addition, the reduction in the well environmental footprint is quantified, and its contributions to the projects health and safety goals are highlighted.

The wellbore and formation temperature environment around a system of multiple wells in close proximity is complex. Temperature simulation and prediction for a single isolated well is simplified by axisymmetric assumptions. Realistic multi-well environments do not have obvious symmetry and are interactive given different operating states including possibly a mix of producer versus injector wells. A simulation model of thermal interaction between closely spaced wells has been developed in a collaborative project. A large-scale validation of the model is presented here. An important field application is presented for a subsea well template where movement tolerances must be tightly controlled. Large-scale validation was conducted for an offshore platform development where more than 30 wells were drilled and brought onto production over a period of 4-5 years. As each well was drilled and completed, temperature logs where recorded which thereby gave a digital signature of the complex thermal environment below mudline as it evolved over time. The simulation model temperature for each well was corroborated against well temperature logs. A simultaneous boundary-condition of flowing wellhead temperatures and pressures for each well was compared against the model predictions. Also, a detailed predictive case study is presented for a 6 well subsea template. Model temperatures were used to assess the impact of cement height on wellhead movement within the template structure which featured lockdowns and tight tolerances on allowable movement within the housing profile. Predicted temperatures from the multi-well model agree closely with logs and correlate closely with characteristic temperature excursions from geothermal below the mudline down to the well path kick-off zone. Since the logs occur over time and account for a changing well population, the model is shown to accurately capture the time evolution of the complex temperature environment. The model explains unusual temperature log signatures as the result of sidetracks and the radial extent of heat affected zones from the parent wellbore. The subsea case study highlights the importance of predicting the complex multi-well temperature environment by demonstrating its impact on the wellhead movement given the uncertainty of cement tops for deeper shoes of combined conductor/surface casings. This learning informs subsea template design and selection with port options for cement grout and top-up jobs. Although the multi-well temperature model has been presented previously along with some field data validation, the large-scale study presented provides further and significant model validation. Extensive data over time and corroboration with unusual temperature log phenomena demonstrate model accuracy. The utilization of the model in the design and specification of a subsea template development provides a real-world example and demonstrates practical application as well as its usefulness.

Deepwater wells historically have, and will continue to, push technological limits. Through the years, water depths and well depths have continued to increase. BOP's are now substantially larger than they were 20 years ago and casing string weights have also steadily and substantially increased. Additionally, since the Macondo incident 10 years ago, capping stacks have also been included in the design process. All of these developments have resulted in higher fatigue loads and an evolved conductor design, wellhead design and in some cases, inclusion of the 28″ pipe (secondary conductor) to support the 36″ conductor. But what about older wells? Wells that may need to receive a modern drill-ship for work-over, intervention or abandonment? The objective of this paper is to answer the question posed and in doing so create an awareness of the ability for historical well designs to receive a modern BOP and capping stack – or not. In answering, this paper presents a case study of fatigue analysis performed on generalized modern and historical designs and their ability to receive a modern subsea BOP and capping stack. This paper examines the need for full and proper multi-variate fatigue analysis of existing and newly installed subsea wellheads and conductor strings for a set of subsea equipment, top of wellbore architecture, met-ocean and soil conditions. In performing this work, soil and metocean data were considered for the Mediterranean Sea, the Gulf of Mexico and West Africa. In evaluating, a sample of well designs from 20 years ago through today was selected and a modern fatigue analysis workflow applied. It shows the engineering methodology for calculating and estimating the remaining fatigue life of existing and newly installed wellheads and conductors following the installation of a modern BOP and capping stack. The paper explores the important role of fatigue analysis and shares identified limitations. It also considers what physical factors may be modified to find an acceptable solution. In doing so, readers should get a sense for where potential issues may lie and consider the question of whether lighter BOP and / or capping stack solutions are a consideration for the future.

In 2017, the business plan set out was to deliver best-in-class wells in an upcoming deepwater drilling campaign offshore West Africa in 28 days (ca. 25 days/10000 ft) which is 10 days shorter than the average performance on the previous campaign, safely and within the budget by leveraging on the capabilities of the new rig. Historically, the scope of operations in the field cuts across drilling, completions, well intervention, work over and abandonment. These operations have been executed with various rigs over the years. The two types of Mobile Offshore Drilling Units (MODUs), namely drill ships and semi-submersibles, have been used extensively in the field. The rig planned for the campaign was a newly built, dual activity, seventh-generation drillship. This rig offers numerous offline opportunities and obvious advantages over the rigs used in previous campaigns which had limitations such as limited bulk storage space / tank capacity, limited deck/derrick space, single derrick/rotary, single BOPs, no Active Heave Compensated (AHC) crane etc. The dual activity capability of the rig enables open-water tripping, casing running and surface activities to be moved entirely offline. In addition to the huge savings from dual activity during batch drilling, development work also offers the opportunity to run the subsea Tubing Head Spools/Xmas tree offline using the active heave compensated subsea crane onboard the rig. However, the governing procedures for the field's Simultaneous Operations (SIMOPS) prohibited heavy lifting over open water at a drill center due to the risk of dropped objects on subsea infrastructure. Through a thorough risk assessment and DROPS assessment, the procedure was challenged, and approval was secured to perform heavy lifting operations at the drill centers. The scope of this paper is limited to heavy-lifting operations at the drill centres (also referred to as manifolds) which were hitherto impossible in previous campaign. The following operations have been implemented in the Drilling campaign and Intervention campaign respectively: Running the 20" or 20" x 13-3/8" surface casing offline while drilling the tophole from the main rotary which has significantly improved tophole performance. The average tophole performance has reduced from 5.4 days in the previous campaign to 3.9 days. The best field tophole time of 2.7 days has been recorded in the campaign. Deployment and Installation of the Tubing Head Spool (THS) prior to running the new technology Single Trip Completion. Previously, a Field Service Vessel (FSV) was used for this operation but this has been eliminated. This operation has also been performed more efficiently on the rig saving ca. 0.2 days (5 hours) per well. Recovery and Installation of Christmas trees during the Intervention campaign. This operation was previously performed with the FSV. Consequently, THS recovery for the upcoming Abandonment campaign is now planned to leverage on learnings and experience of the rig thereby reducing the project budget (ABEX) and eliminating the need for the FSV for this operation. Drilling the tophole from the auxillary rotary with the BOP suspended in the main rotary for non-batched single topholes. The utilization of the rig capabilities to optimize operations has significantly reduced the risk exposure of personnel, reduced well cost due to improved performance and enabled the deployment of new technology in the field.

Offshore Congo West Africa, one of the subsea field developments has been installed with subsea production equipment designed and manufactured by two different subsea equipment suppliers. Therefore, it is a major challenge to be able to perform subsea intervention and installation with just one drilling rig being available on this subsea development as the subsea equipment from different subsea equipment suppliers is not design compatible. The conventional approach would be to change out the topside installation and intervention equipment from one manufacturer to that of the other on the rig. As this solution is far too expensive and time consuming, a need for one universal subsea installation and intervention system became an operational requirement. This paper explains how one operator along with two subsea production equipment suppliers were able to design, manufacture and implement one universal drilling system refered to as –IDIMS (Interface for Dual Intervention Mode System). IDIMS increases the operational response while lowering the intervention cost on this field. Indeed IDIMS allows one single rig to intervene, drill and complete with two different subsea production equipment suppliers at a lower cost and with a shorter lead-time, which is a first in the oil industry. For operators, IDIMS XT and TH modes represent a major innovation to reduce costs and drilling times in all subsidiaries with mature submarine fields equipped with different subsea production systems and equipment. Over three years, this innovation allowed 107 MUSD of savings on this field. The IDIMS concept could be reproduced and developed to intervene and drill on other subsea field developments with even more than two subsea production equipment suppliers. A single rig would then be able to operate on all of the subsea wellheads, tubing hangers, subsea XT installed/to be installed in one area, significantly reducing project development costs.

Tubulars with gas-tight, rotary-shouldered connections are used as the conduit between the surface vessel (rig) and subsea wellheads in deepwater operations. Requiring no specialized tools and using standard rig equipment, they provide a fast, safe, and cost effective way to run completion landing strings and intervention pipe. Tubulars for these operations must provide a large internal drift diameter to allow for clearance of the wellhead crown plug and installation of completion components. These strings have been limited to 6-5/8 in. pipe allowing for a maximum drift diameter of 5-1/2 in., which is insufficient to run and retrieve the wellhead crown plugs of many large ID subsea trees. Trees with larger crown plugs require operators to use casing tubulars increasing deployment time, requiring casing running crews, incurring higher repair costs and time, thereby increasing overall costs. A completion landing string (CLS) was developed using a 7-5/8 in. pipe and a built-for-purpose, large drift, gas-tight, pressure-rated, rotary-shouldered connection (7-5/8 CLS). This new connection technology optimized the outside diameter and make-up torque to be compatible with the iron roughnecks and pipe handling equipment of the current Gulf of Mexico rigs. Product development and performance validation is detailed with a special emphasis on the enabling connection technology. The paper expands on manufacturing challenges and design choices made to assure ease of rig operations, including modifications to slips and elevators. Finite element analysis (FEA) and physical testing to validate performance are described. Steps taken before the initial deployment to assure compatibility with the rig equipment are explained. Finally, the paper will show data from the offshore field trials and initial deployments. Lessons learned are shared. This industry-first, purpose–built, gas-tight completion and intervention tubular provides 6-1/8 in. internal drift diameter and can be safely deployed using conventional pipe make-up and handling equipment reducing overall cost.

Reducing deepwater development costs involves thinking about alternatives to the most conventional techniques and increasing synergies among disciplines. For deepwater well conductors, replacing the conventional jetting installation method by subsea driving constitutes, in some applications, one such cost-effective alternative. On the Moho Nord Tension Leg Platform (TLP) development in Congo, all 27 conductors were installed in only a few days with an installation barge and using subsea hydraulic hammers, an operation that would have taken a few weeks and would have cost significantly more if jetting had taken place from a deepwater rig. This paper presents, from the perspective of an operator's drilling entity, some of the experience gained from this project. First, the reasons and development concept specificities which led to preferring this installation method are introduced. Then, the main engineering steps are addressed in some detail, from the geotechnical studies and the driving predictions to the fatigue engineering of both the conductor pipe and the conductor housing, and then recommendations relative to their specifications are made. The challenges regarding the engineering and procurement planning are highlighted and briefly discussed. The selected driving methodology, from the handling of the conductors to their driving to final penetration, is also addressed. Finally, the operations are debriefed in a post-job review. Whereas conductor or pile driving has been used extensively in other applications and/or industries (shallow water drilling, offshore construction, etc.), its use in deepwater drilling operations with subsea hydraulic hammers and wellhead systems is recent and the published knowledge is therefore scarce. This paper adds to the body of knowledge by providing offshore development project managers and engineers with first-hand information about this alternative to jetting conductors, its potential benefits, and key engineering and operational challenges to be considered to make it a success.

A tremendous amount of effort has been placed on subsea cap and containment in order to demonstrate the exploration and production industry's response to a subsea well control event. This paper will focus on the methods and processes planned to contain a subsea blow out beneath a Tension Leg Platform (TLP) in deepwater Gulf of Mexico. Response to a well control event of this type is divided into 3 major categories: 1) TLP Health and Stability Monitoring - Understanding the structure stability is key in planning the response and determining the time allowed to deploy containment assets, 2) Debris Clearing-a path must be cleared into the well pattern horizontally and vertically for the capping stack to be deployed and 3) Stack Deployment - with the TLP still floating above the well pattern the stack must be deployed laterally under the facility and onto the well. Several challenges were encountered during the design and approval of this containment method, leading to the development of alternative capping strategies, purpose built capping stacks, installation of permanent monitoring / response equipment and use of Delmar's Heave Compensated Landing System (HCLS) to accomplish these critical subsea tasks.

A large number of subsea production wells have been drilled, but to date there has been limited industry experience of redrilling subsea wells, whereas, redrills have become routine in platform and surface wellhead applications. The focus of this paper is to highlight some of the key aspects of redrilling a subsea production well to extend field life. The paper will describe how the unique challenges of redrilling three subsea wells were overcome in old and declining fields where the original wells were designed and drilled with limited consideration for redevelopment of the fields through reuse of existing wells. The paper will define the problems of and describe the solutions to: The mooring and BOP handling constraints in the crowded subsea infrastructure of a subsea field development. The riser and wellhead analysis for redrilling a well through a subsea tree, and the operational practices required to maintain tree and wellbore integrity. The analysis of the additional loads put on a subsea well through the extended period of riser and BOP loading. The casing exit and redrill constraints unique to operations from a semi-submersible rig; casing recovery operations, the management of window milling debris in a subsea BOP system. There has been limited industry experience to date of subsea production well redrills, and this paper will share the significant lessons learned which will be of wider application, as the number of subsea wells increase along with the requirement to maximize recovery and extend field life.

The design of a conductor casing is significantly different than that of the other tubulars in a well. Conductors are drag-dominated structures that enable conducting drilling operations from offshore fixed platforms or jack-up rigs through the seawater column. To date, the majority of technical papers concerning conductor design have focused on a particular aspect of the conductor pipe but very few of them have detailed the design of conductors in response to the combination of hydrodynamic loads, external and internal loads acting on this casing string as well as the soil-conductor interaction. This paper discusses the design of both platform conductors and jack-up supported conductors used in open water by first providing the essential steps (i.e. deriving and presenting equations) that need to be followed to ensure the structural integrity of the conductor casing along its entire length. Then, in order to illustrate the methodology, four case studies were performed to investigate the performance of well conductors at different shallow water locations (the Gulf of Mexico, South America, the North Sea and South-east Asia). For all analyses, the conductor pipe has been checked for three failure modes: strength, stability and fatigue and finite element analyses have been computed to solve the hydrodynamic loading, the statically indeterminate problem and the complex soil-structure interaction. The results show that, in general, stability controls the conductor design which means that the conductor will buckle before it yields; and therefore, there is a requirement to apply tension at the Texas Deck for a jack-up. Also, in some instances (i.e. rougher water environments) or with smaller size conductors (13.375-in. and 20-in.), the fatigue analysis may become the most important failure mode for both the conductor pipe body and the connectors.

For over thirty years, the design of platform and jack-up conductors has been based on Stahl and Baurs' famous hypothesis that internal string loads do not contribute to buckling (Stahl and Baur 1980). It is a vital result, allowing significant weight and cost savings. However, no derivation was ever given, and the result has remained a folk theorem: widely used, but never proved. The industry has therefore been at risk should the result prove to be a severe approximation, or to have unduly restrictive assumptions and/or limitations. This paper provides a rigorous proof of the hypothesis. It shows that it is an approximation, albeit an acceptable one, and gives a thorough exposition of its meaning, assumptions and limitations. Finally, it derives the exact counterpart of Stahl and Baurs' result. The improved result gives further minor weight and cost savings.

This paper will describe the planning and execution of an unusual project for driving pin/foundation piles underwater with hydraulic hammers, in water depths up to 155 meters [ 510 feet ] offshore Eastern Canada. The North Amethyst project is a series of tie-back satellites to the " Sea Rose " FPSO located in the White Rose area, approximately 300 miles [ 483 kilometers ] offshore from St.John’s, Newfoundland, Canada. This is in the so called " Iceberg Alley ". The operator was Husky Oil and the prime contractor for the installation was Technip Canada Ltd. The subsea equipment is located in excavated " glory holes " where the top of the seabed equipment is placed approximately 3 meters [ 10 feet ] below the surrounding sea bed level to protect against iceberg scour. The operations involved the installing of pin and foundation piles for both Manifold Support Frames [ MSF] and Subsea Distribution Units [ SDU ] from Technip’s support vessel, the " Well Servicer ", mobilized from Bay Bulls dock, near St.John’s, Newfoundland. Four piles were required for each of the Manifold Support Frames and four piles were required for each of the Subsea Distribution Units. A total of fifteen 24 inch piles were driven [ 24 inches OD X 1.5 inch wall X 52 feet long, 610 mm X 38.1 mm wall X 15.8m long ]. Also six 36 inch X 1.5 inch wall [ 915 mm OD X 38.1 mm wall ] piles were driven. Each pile was driven approximately 13 meters [ 43 feet ] below the mud-line in water depths ranging to 155 meters [ 510 feet ]. This paper will show how by careful design, pre planning, fabrication and the carrying out of a comprehensive Factory Installation Test [ FIT ] in Louisiana prior to the job, a successful operation was achieved in a very challenging operating area.

The paper describes field experience with a method for efficient anchor handling and rig move during North Sea exploration drilling campaigns with a semi submersible drilling rig requiring anchors for positional fix. A conventional anchor handling operation including a rig move operation is presented, followed by a detailed presentation of an innovative field operation including a method for combining anchor pick up, rig move and pre-setting. Four anchor handling boats were used to pick up anchors at an abandoned well. Thereafter the anchors and ground chains were sent off to next drilling location with three of the boats. These boats pre-set the anchors. The anchor pre-setting sequence was selected such that one boat was released after only a short period at the new location. The last anchor handling vessel, the smallest one, was used in the rig move operation as a tug. When the rig arrived at the new drilling location, the three remaining boats were involved in connecting the anchors. As a result of the pre-set anchors, the mooring operation could be performed in a weather window, being roughly one half of the weather window needed for normal mooring operations. The anchor handling boats were released sequentially as early as possible reducing the cost of the entire operation significantly. As will be described a traditional anchor handling operation would have resulted in two days waiting on weather in addition to the extra time spent on anchor handling because the weather conditions deteriorated. The paper also describes the challenges of retrieving pre-laid anchors tensioned to the anticipated maximum 100 years load.

Abstract The problem of delivering the required volume of hydraulic power fluid to subsea BOP control functions from gas-charged accumulator bottles has been well documented of late. Conventional nitrogen precharged subsea accumulator bottles currently require charging up to very high pressures to counteract the effect of seawater hydrostatic pressure in order to remain functional at the working depth. Research shows that when taking into account the effects of nitrogen compressibility, adiabatic expansion and temperature at these elevated pressures, the volumetric efficiency of the accumulator and available differential pressure are greatly reduced with increasing water depth. The reduction in fluid power availability has been typically underestimated, leaving conventional stack-mounted accumulator bottles unable to provide the required fluid volumes within specified response times to stack functions in the ultradeepwater environment. In addition, the subsequent installation of additional subsea accumulator banks to compensate for the loss of usable volume increases the weight and complexity of the subsea BOP stack. A new type of subsea gas-charged accumulator has recently been developed to tackle the deficiencies of conventional accumulators head-on. The constant differential accumulator (CDA) compensates for the increase in seawater hydrostatic pressure while being run to any depth, allowing it to function without requiring additional charge over and above the initial surface charge. In theory it should provide virtually the same usable volume of hydraulic power fluid at the same differential pressure, independent of depth. Subsea BOP design is becoming more complex as drilling contractors consider the options available for upgrading the operating depth of older generation rigs while equipping the latest generation rigs for ultra-deep waters. The following research aims to reduce the uncertainty involved in accumulator choice by defining the most effective working depth range of conventional and constant differential accumulators from the standpoint of fluid power availability. Introduction Background. The inefficiencies of conventional nitrogen pre-charged accumulator bottles for use in the subsea environment has been the topic of some discussion in recent years, with most authors on the subject, notably Sattler (2002) and Curtiss & Buckley (2003), attempting to improve both the understanding of accumulator discharge and accumulator sizing calculations. The consensus of opinion concluded that current calculation methods and the thermodynamic processes used to model the accumulator discharge were not wholly representative of the actual processes taking place at very deep to ultra-deep water depths. Industry regulations pertaining to usable volume calculations were found to be lacking in the required complexity and detail with which to design accumulator systems accurately. API Specification 16D, the most detailed regulatory document available at the time, came in for particular scrutiny. The API standards committees were aware of the shortcomings and Spec. 16D was updated (2 nd Edition, 2004) along the lines highlighted by several authors to improve its accuracy and relevance to the deepwater drilling industry. This was achieved to some extent, and with built-in safety factors provided an acceptable improvement in accumulator sizing calculations from the standpoint of usable volumes of hydraulic power fluid. Where Spec. 16D and recent recommendations by other authors fall short however, is in the consideration given to the non-ideal behaviour of compressed precharge gas. The effects of nitrogen compressibility have still not been fully addressed, leading to an overestimation of fluid power availability in conventional accumulator systems.

Abstract This paper presents the recent operational experience using a surface BOP system for both drilling and subsea completion activities offshore Brazil in the first phase of the Parque das Conchas development (block BC-10) that encompasses several reservoirs in up to 2,000 m of water. The Transocean GSF Arctic I, a moored rig capable of operating in 945 m of water using a conventional 18–3/4" subsea BOP stack and marine riser system was equipped with a pre-laid mooring system and surface BOP system especially designed for this project that could extended the rig's effective water depth capacity to as much as 2,250 m. Prior to the start of drilling operations a service vessel was used to pre-install the conductors for both the wells and the subsea pumps. In addition to taking these activities off the critical path, the precision achieved by using a subsea hammer to install the well conductors at each drill center minimized the time required to move from well to well for batch drilling and completion operations. The start up performance and learning's from the following new elements used in this project will be presented: Site specific pre-laid polyester taut-leg mooring system Slim-bore wellhead system (to land production casing hanger) Purpose built 16" OD high pressure riser system Pressure test hose line, strapped to riser (to press. test tubing hanger & packer) Lower shear ram in SID replaced with fixed 7–5/8" pipe ram (to seal on slick joint) Power and hydraulic lines added into the SID umbilical (to reduced ROV support needed) Vertical subsea tree, Tubing Head Spool and slim bore tubing hanger with hydraulic running tool Spacer Spool (same height as Tubing Head Spool) The start up performance of this uniquely equipped rig system will be presented to show how attention to detail and a strong learning culture have paid handsome dividends. Introduction Surface BOP (SBOP) technology extends the use of smaller, lower dayrate 2 nd /3 rd generation rigs into water depths they are unable to achieve conventionally. Following successful exploration drilling campaigns in South East Asia the technology was extended to more demanding metocean conditions offshore Brazil and Egypt with the implementation of a Seabed Isolation Device (SID). The technology had therefore advanced to the level of proven technology for exploration drilling operations in deep water. In 2008 SBOP technology was implemented for the first time for both drilling and completion operations for the Parque das Conchas deepwater development in block BC-10 offshore Brazil with a moored rig, using pre-laid moorings. This combination was found to be attractive for the relatively few drill centers planned as it facilitated the application of batch operations. See Figure 1 for location of the Parque das Conchas development. Each phase of the downhole completion (production hole drill-out, well bore mechanical clean-up, displacement to brine, sand control placement, upper completion installation) has now been done on the first batch of production wells using SBOP technology. The SBOP system configuration used was as previously described by Tarr et al (2008). Specifically, features were added to the previous SBOP system to permit the deployment and testing (including future intervention/retrieval) of the tubing hanger and its running tool.

Abstract The promising potential of prolific hydrocarbon reserves in the difficult Arctic ice environment has spurred accelerating lease activity in particularly the US & Canadian Beaufort and the Chukchi Sea. The obstacles are formidable: ○ The leases may only be ice clear a few months a year. ○ The fall and early winter months expose severe weather analogous to a North Sea wind and wave environment. ○ Winterization measures must consider potential of severe icing. ○ The vessel hull and exposed machinery must tolerate temperatures of -40° C. ○ The ice management strategy must anticipate operations in one-year ice (sheet ice to a 1.5 meter thickness with rubble fields, occasional multi-year inclusions, and modest ridges). ○ Logistic lines are long and tedious, motivating an unparalleled level of self-sufficiency. ○ Water depths range from 50 meters or less to extreme depth, confounding a station-keeping solution. ○ Heavy ice and formidable ridges compel an exodus mid-winter through mid-summer, and obligate consideration for off-season marketability and high speed open water transit. ○ Consideration must be given for wintering over … in contingency or with ambition to extend the season. ○ Extreme environmental sensitivity will be expected. Against these challenges, a fit-for-purpose vessel has been conceived … optimized for extended-season operations in the Arctic, and uncompromised ultra-deepwater off-season performance in a more hospitable environment. Introduction Strategies change with differing ice environments and water depths. Attentions to date have concentrated on floating applications in one-year sheet ice, with geographic bias for the US and Canadian Arctic. Though like environments prevail in the Sea of Okhotsk, East Siberian Sea, Laptev Sea, Kara Sea, and to a lesser extent the Barents Sea … it is the US and Canadian Beaufort and the Chukchi Sea that are currently attracting the greatest attention. Associated lease structures, history and recent activity are related in the accompanying Appendices. History of Offshore Activity in the USA and Canadian Arctic More than 150 wells have been drilled offshore in the Arctic waters of the US and Canada … all between the late 70's and early 90's. Most were in water depths of less than 22 m (72 ft) with bottom-founded drilling solutions (gravel and sandbagged islands, sacrificial beaches, ice spray islands, the SSDC, Molikpaq, and CIDS). A total of 53 wells were drilled in those years from floating vessels (four Canmar/Dome conventional moored drillships, the circular-hulled Kulluk, and one well from a barge). Water depths ranged from 18 ½ m (61 ft) to 67 ½ m (221 ft) on these programs. It is noteworthy that the Kulluk is the only surviving Arctic vessel of this era (now owned by Shell with ambitions in the US Beaufort).

Abstract Three phenomena dominate the mesoscale ocean variability in the Gulf of Mexico. These are the Loop Current, anticyclonic (warm core) eddies, and cyclonic (cold core) eddies. When the offshore oil industry ventured out into the deepwater Gulf in the 1980s, little was known about the adverse impact these features would have on offshore operations. In the early years, it was apparent that the Loop Current regularly shed anticyclonic eddies that drifted west across the Gulf. Original analysis and models assumed that these eddies have simple elliptical shapes and that they could be sufficiently described with a few geometric parameters. Observations, however, have proven that this is not the case. Each eddy is unique, varying in shape, structure, duration, movement, and intensity. Cyclonic eddies, which were generally ignored early on, have recently been found to play a significant role in the changing dynamics of the Loop and eddies. Cyclonic/anticyclonic pairs produce some of the strongest currents observed. Oceanographers are now incorporating these features in their dynamical models to produce more accurate forecasts. Acoustic Doppler Current Profilers (ADCPs) mounted on workboats are now commonly used for ocean current surveying to supplement existing data from drifting buoys, satellite remote sensing, and rig-mounted current meters in support of offshore construction and installation projects. Fine scale real-time monitoring of both near-surface and mid-water currents is necessary during critical phases to insure that these projects are conducted safely and efficiently. Strategically planned survey patterns are followed to best observe and forecast the encroachment of oceanographic features into areas of sensitive operations. Analysis of survey data reveals the unique properties of each feature. Not only can the data be used operationally on an hour by hour basis, but it can also be used to initialize a forecast model. Models initialized with the most recent data prove to be the most accurate and useful to offshore operators. Introduction The deepwater Gulf of Mexico is a complex, risky, and costly environment to conduct operations. The move into deeper and deeper waters (Loop Current and eddy territory) has presented operators and contractors with a variety of challenges during the development of deepwater fields in these demanding offshore environments. Challenges involving areas of safety, design, cost, environment, flow assurance, and equipment reliability need to be addressed to ensure the successful development of these fields. The potential impact of Loop and eddy currents, which can occasionally exceed 4 knots, must be taken into account as a significant factor that needs to be incorporated into planning operations. Loop and eddy currents are found in the upper 1000m with strongest currents at the surface. These currents can shift rigs off position, affect mooring behavior, and cause structural bending, vortex-induced vibrations (VIV), motions to drill strings, and excessive riser angle and fatigue. Anchoring operations, anchor cable tension, load distribution, and the installation of equipment by heavy lift vessels can be impaired. Diving, pipelaying, and ROV operations are often impossible. During a Loop or eddy event, downtime can last for weeks or longer as currents interfere with sensitive operations. And now, as production activity has moved into deeper, more eddy-prone regions, these strong currents are also impacting time-sensitive installation activities, delaying the date of first oil.

Abstract Esso Exploration Angola (Block 15) Limited (EEAL) has realized substantial improvements in the efficiency of subsea operations in the deepwater environment of Angola Block 15 (AB15). EEAL dedicated a work vessel primarily to subsea activities and further improved efficiency by continuously evaluating operations for potential improvement. Given the current higher cost environment that exists throughout the industry, EEAL has increased its efforts to evaluate improving efficiencies for subsea operations, specifically during simultaneous operations (SIMOPS). Improvements in efficiency and schedule certainty were seen as a result of dedicating a work vessel primarily to subsea operations. This paper will present case histories of the various operations such as Suction Embedded Plate Anchor (SEPLA) handling, close tolerance well positioning, and horizontal christmas tree (HXT) installation, both on and off the mobile offshore drilling unit (MODU) critical path. The relative impact on efficiency and the indirect benefits of a dedicated work vessel will also be discussed. Introduction Esso Exploration Angola (Block 15) Limited (EEAL) (along with concessionaire Sonangol and Co-Venturers ENI, BP, and Statoil) are developing several fields in Angola Block 15 (AB15). AB15 is located 90 miles west of Soyo, Angola, and approximately 240 miles northwest of Luanda, as shown in Fig. 1 . The water depths for AB15 wells range from 700m to 1,435m. The operator and Co-Venturers were awarded exploration rights in 1994 and began drilling shortly thereafter. AB15 is currently producing from five floating production storage and offloading (FPSO) facilities: Xikomba (2003), Kizomba A (2004), Kizomba B (2005), Mondo (2008), and Saxi-Batuque (2008). The Kizomba C development project, which supplies FPSOs Mondo and Saxi-Batuque, is underway and a Kizomba Satellites development project is in the planning stages. In order to bring these developments on-line in the timeliest manner possible, as many as six rigs have operated simultaneously on the different fields within AB15. Two of these rigs were the Kizomba A and Kizomba B Tension Leg Platforms (TLPs) and the remaining rigs were MODUs working on a drilling schedule of over 100 subsea wells distributed amid 18 subsea drill centers. This high amount of activity within the block created the potential for large schedule conflicts as a result of installation vessel and MODU SIMOPS. In response to these potential conflicts, EEAL evaluated their operations in an effort to identify which non-drilling tasks could be separated from critical path MODU operations. Removing these tasks from the MODU schedule increased schedule flexibility and decreased cost. Due to the type of equipment necessary to perform the identified tasks, other opportunities for flexibility and cost reduction were identified. SEPLA Installation Early in the project planning for the AB15 development, drill centers were planned in close proximity to one another in order to enable the most cost-effective subsea architecture. This reduced the length of flow lines, umbilicals, and jumpers required to connect satellite drill centers to the FPSOs. At this time, it was also decided that AB15 would utilize one or possibly more conventionally moored MODUs for its subsea development wells. In order to achieve such a subsea layout and its related cost savings, a conventionally moored MODU's anchor pattern must also become more compact. This more compact anchor pattern required the use of taut-leg mooring (TLM) systems to allow a MODU to safely moor over drill centers set relatively close to each other.

Abstract A surface BOP system with a seabed isolation device (SID) was successfully used to extend the water depth capability of the D.P. semi-submersible rig Stena Tay for exploration drilling activities in ultra-deep water to 2,887 m offshore Brazil and to 2,447 m offshore Egypt in 2003. This provided the necessary experience to take the next step towards reducing the cost of deepwater developments utilizing a surface BOP system deployed from an earlier generation, lower specification, deepwater rig. This paper presents the configuration and specifications developed for the surface BOP drilling and subsea completion system to be deployed offshore Brazil in the first phase of the Parque das Conchas development (block BC-10) that encompasses several reservoirs in up to 2,100 m of water. The rig selected for the project had to meet certain minimum requirements to safely deploy the planned surface BOP system, and these requirements led to the selection of the Arctic I, a moored rig capable of operating in 945 m of water using a conventional 18–3/4" subsea BOP stack and marine riser system. The new elements incorporated in the surface BOP system include: Site specific pre-laid polyester taut-leg mooring system Slim-bore wellhead system (to land production casing hanger) Purpose built 16" OD high pressure riser system (to replace casing riser) Added pressure test hose line, strapped to riser (to pressure test tubing hanger & packer) Replaced lower shear ram in SID with fixed 7–5/8" pipe ram (to seal on ported slick joint) Added power and hydraulic lines in SID umbilical (to reduced ROV support needed) Vertical subsea tree, Tubing Head Spool and slim bore tubing hanger with hydraulic running tool Development drilling operations with this surface BOP system are now expected to commence in the first quarter of 2008. Introduction Surface BOP (SBOP) technology extends the use of smaller, cheaper 2nd/3rd generation rigs into water depths they are unable to achieve conventionally. Following successful exploration drilling campaigns in South East Asia the technology was extended to more demanding metocean conditions offshore Brazil and Egypt with the implementation of a Seabed Isolation Device (SID). The technology has therefore advanced to the level of proven technology for exploration drilling operations in deep water. When the application of SBOP technology was investigated in the Well Concept Selection phase for the Parque das Conchas Field Development Plan, in block BC-10 offshore Brazil, it was considered technically immature with regard to interfacing with subsea completion hardware and subsea completion operations. However, the application of further risk assessment and opportunity analysis indicated the application of SBOP technology was not only feasible for drilling operations but also for completion installation and completion workover activities. Also, the use of a moored rig, using pre-laid moorings, was found to be attractive based on the multi-well drill centers planned that would facilitate the application of batch operations.