The Hook-up and Commissioning program for the BP operated Clair Ridge facility was conducted over a period of three years, starting with the accommodation platform in 2015/16, and then the Production and drilling platform over 2017 and 2018. The total topsides weight is 53,000 tonnes, and the field is located in the harsh waters of the Atlantic West of Shetland. Typically 750 persons were based offshore, but over the life of the program some 7000 individuals worked offshore at some point on the project. Recognizing the safety leadership challenges with such a major hook-up and changing workforce a huge amount of effort went into preparation and working with our contractors to onboard the workforce. Over the first months of the campaign the safety metrics were healthy and there was a good reporting culture, however an increase in incidents was seen, including one late in 2015 where a medical evacuation was required from the platform. The individual made a full recovery and returned to work however it caused the Operator and Contractor project leaders to reflect on their safety leadership and how they were working with and engaging with the workforce. It was a catalyst for change as the team was determined that no other serious incidents would happen during the project delivery. In this paper we will share the Clair Ridge safety leadership journey and the steps taken by the operator, with the support and collaboration of the main contractors, to set a new approach to safety through the development of a genuine Culture of Care. This included: Building of trust and credibility between leadership and the workforce Leadership openness and transparency in communication Empowering front-line supervision to be safety leaders and giving them the skills and tools to do this well As a result of the approach the Clair Ridge team is proud that, in the three years since the incident in 2015, over 9 million offshore workhours have been completed without any other Lost Time Incident, and a safe start-up was achieved with no process safety related incidents. Clair Ridge realised some of the highest participation in safety observations and near miss reporting across the Operator's global projects portfolio, a continual and significant reduction in all injuries and benefited from an excellent reporting culture. A Culture of Care has been owned by all, and been recognised and commended by the contractor workforce and visitors to Clair Ridge.

The Solan oil field is located offshore in the hostile north Atlantic ~135 kilometres west of the Shetland Isles, UK, in ~135 metre water depth. The field commenced production in 2016. The relatively remote field was developed by four subsea wells tied back to a single slim jacket with a minimum facility topsides. The development includes several innovative features such as full automation, which enables full remote control from an onshore control room in Aberdeen, UK, but strikingly, a world development first involving the installation of an independent steel subsea oil storage tank (SOST) located ~300 metres from the platform. The concept selection, design, fabrication, installation and operation of this novel feature are the subject of this paper. The concept selection of the SOST was driven by several factors including HSE, life cycle cost and operational considerations for this modest sized development in a harsh marine setting. An obvious competitor concept is a subsea well and FPSO alternate; the pros and cons of each approach are compared, using actual field performance now seen versus assumption at the time of concept select. The multiple-compartment SOST is capable of holding almost 300,000 barrels of stabilised oil; it has an in-air weight of ~10,100 tonnes and internal dimensions of 45m x 45m x 25m. The oil is offloaded to a shuttle tanker through a single anchor loading (SAL ™ ) system with the offloading hose stored on the seabed, which is picked up using a pennant line. Oil export to the tanker is driven by hydrostatic displacement by treated seawater from the topsides. This operation is conducted while still producing oil to the SOST. The tank design has novel features for installation, oil-water interface management and corrosion monitoring and subsea inspection. The tank's detailed design and construction phase involved some significant changes as the structural and fatigue life issues were fully analysed and implemented. The installation required significant pre-planning with the use of a very large lifting sling arrangement and a smart air venting and water ballasting system, to then land its eight skirt piles to a tight tolerance on the seabed. Following a commissioning program and trial tanker offload using treated seawater alone, over the past year the SOST has now successfully undergone numerous oil fill and tanker offload operations. There have been learnings regarding the offloading operation but to date the concept has worked in a manner very close to expectation with a full tank offload achieved in less than ~36 hours. The paper closes with a review of how the concept could be improved further considering the experiences now gained from both the project and operational phases.

This case focuses on the challenges regarding capacity building required to meet the huge increase of manpower demand by the offshore and shipbuilding sectors in Brazil and Rio Grande do Sul state. This arises from four key factors: end of monopoly of exploration and production of oil and gas in 1997, expanding the Brazilian offshore market; the Local Content policy adopted since 1999; national programs to stimulate the maritime industry such as the Fleet Modernization and Expansion Program created in 2004 to renew the fleet of Transpetro, a Petrobras subsidiary; and the expansion of Petrobras investments, partly due to the discovery of giant oil reserves in the Pre-salt layer in Brazil, in 2006. Since 2010, annual investments from Petrobras have reached US$ 40 billion/year, more than ten times the yearly investment in the 1997-2001 period. Consequently, offshore clusters have been developed in the country to build platforms, drilling ships and supply vessels, demanding massive training. In Rio Grande do Sul, three big shipyards and modules producers have installed. In this context, government created in 2003 the National Oil and Natural Gas Industry Mobilization Program (Prominp) and the National Plan of Professional Qualification (Pnqp) in 2006. Until 2013, circa US$ 120 million were invested to train nearly 100.000 people in 185 trades at several levels. In the state, training has been provided mainly by SENAI-RS, the state branch of the National Service of Industrial Apprenticeship, linked to the Federation of the Industries of Rio Grande do Sul. The large-scale actions undertaken for training have not been efficacious enough to meet the needs. Studies and discussions have raised factors that impact on shipyards’ productivity and competitiveness. We consider alternatives to develop talents to accelerate the learning curve, anchored in the following axes: SENAI methodology for professional training; pre-selection of people according to specific abilities; the concept of a “Living Lab” training environment; familiarizing workers with productiveness indicators; efficient management paradigm; workers training aligned with the project repeatability principle. The local industry must be internationally competitive when the local content policy ends and labour productivity plays a crucial role in this aspect.

During the period 2010-2012, two parallel gas pipelines (the Nord Stream Project) are being installed in the Baltic Sea, between Vyborg in Russia and Greifswald in Germany. The pipeline system will enable an annual transport of 55 bcm of natural gas from the large Russian gas fields to the European gas grid. Comprehensive environmental and safety studies were carried out already in the design phase. The outcome of these studies was used in iterations with the pipeline design process, ensuring that the final pipeline design has minimal impact on the environment as well as on human activities in the Baltic Sea. Also, due consideration has been given to ensuring the health and safety of construction personnel and minimizing the environmental impacts during construction. Major changes to the design were made in order to minimise project impacts, i.e. – An originally planned intermediate service platform was "engineered out", eliminating the risk of ship collisions in the operation phase, – The pipeline route was optimised to avoid sensitive nature areas and heavily used ship traffic routes, – Extensive geophysical surveys were carried out in order to identify and mitigate interaction with dumped chemical and conventional munitions and cultural heritage objects, – It was insured by theoretical analysis verified by measurements that the pipeline with the chosen route did not have a negative impact on inflow and mixing of water in the Baltic Sea, – Environmental monitoring and subsequent feedback to the construction vessels were carried out during seabed intervention works near sensitive habitats. Unique for this project is the major design changes that have taken place as a result of the HSE analysis. One outcome of this has been that all five affected countries have given permit to the project in a relatively short time period, even though it is the first major pipeline project in the Baltic Sea.

Abstract The E&P industry has up till today had two lightweight intervention methodologies for live production- and injection wells, being wireline or coiled tubing. A third methodology, being the Ziebel ZipLog™ solution which is based on pushing a spoolable specially constructed carbon "rod" into live and pressurized wells, has been successfully developed and deployed into horizontal wellbores in the Middle East as well as North America. This paper describes the background for the solution, the development and qualification program, the wellbore interventions performed and what the authors think the system can be further developed into. Background and solution description In 2004, a workshop was arranged by a major operating company on downhole fiber optic distributed temperature sensing (DTS), where the values and application of this were discussed with several technology providers present. The operating company representatives explained that they experienced substantial problems both using production logging tools (PLT) and installing DTS with their new well completions on offshore platforms. The operator then challenged the attendees to propose a method to perform DTS logging interventions in their wells, which had the restrictions of very limited space above for rig-up of a standard wireline lubricator system due to the drilling rig being in place the majority of the time. The founder of Ziebel and Sensornet then decided to design a DTS logging system that could operate in the limited headroom of this particular deck space and that was stiff enough to be pushed into the horizontal section but flexible enough to bend through a 90° bend through the x-mas tree. (Fig. 1) The IP for the manufacture of this specific carbon-fibre rod implementing fibre optic technology and method for the replacement of the crown plug was implemented into a patent application, where later a number of additional patent applications has been filed around the methodology and technologies.

Abstract The paper describes a process for constructing a risk register to be used to track the evolving perception of risk during a CO 2 storage project. A project-specific risk register is developed through a structured elicitation process to determine initial perception of risk and through discussion with experts. Regular updating of the register by experts is used to track changes in the assessment of risk as the project progresses and inform decision and actions during the project with the aim of reducing risk to an acceptable level. Introduction The current attention to climate change has increased the pressure on all nations to reduce emissions of greenhouse gases. Carbon capture and storage (CCS) is potentially an important technology to reduce emissions of CO 2 , one of the key greenhouse gases, particularly as fossil fuels are likely to continue to supply a major part of the world's energy needs for decades to come (Jepma et al, 1998; Bajura, 2001). In CCS the CO 2 generated by large point source emitters, primarily power plants, is captured and transported to a storage site where it is injective into the Earth's subsurface and stored in the pore spaces of rock. Potential storage sites include saline reservoirs, depleted oil and gas reservoirs, and coal seams. While the technology for CCS already exists (e.g. Moritis, 2003; Torp et al, 2004) and is currently used in enhanced oil recovery, the scale of CO 2 sequestration required to impact significantly on anthropogenic emissions, dwarves existing projects (Nordbotten et al, 2005). In addition, long term storage of CO 2 is required if negative climate impacts are to be avoided. Carbon dioxide injected into deep geological formations will initially be more buoyant than the existing formation fluids (Bachu, 2003). This will result in the migration of CO 2 upwards through the formation and offers a potential leakage pathway. In principle a sealing caprock over a storage reservoir should trap the CO 2 . However over-pressurisation of the seal, fractures, faults and injection wells all offer possible sites of failure of the containment system and hence routes for CO 2 migration away from the target reservoir (Celia et al, 2002). Leakage of CO 2 and displacement of the formation fluids may result in acidification and/or contamination of groundwater and soils, with uncontrolled leakage posing a risk to near-surface ecosystems (Celia et al, 2002; Farrar et al, 1995). There is also a significant financial risk in rolling out CCS on a major scale, with significant investment required both in improving technology and in identifying and characterising potential storage sites. To minimise these potential negative impacts a complete risk assessment of the full capture, injection and storage process is required for all CCS projects. We present a case study developed within a project, henceforth referred to as Case Study 1, in which a complete, simulated assessment process was carried out for two theoretical storage sites for CO 2 . We describe a risk assessment process designed to highlight high risk areas to the project, which feeds directly into the decision making process regarding future development and risk mitigation activities.

Abstract Controlling the trapping of CO 2 in the subsurface, i.e. storage containment, is of fundamental importance for a safe geological storage of carbon dioxide. During CO 2 injection, increasing fluid pressure, temperature variations, and chemical reactions between fluids and rocks inherently affect the state of stress inside the reservoir and in its surroundings. Besides, the mechanical properties of the rocks exposed to CO 2 may be altered. The impact of the resulting deformations on seal integrity must therefore be assessed in order to properly manage containment performance and leakage-incurred risks. The analysis starts with the construction and the calibration of a Mechanical Earth Model of the site, through joint analysis of geologic, seismic, logging, drilling, and laboratory test data. Such a model consistently describes ambient stresses, fluid pressures, and poro-mechanical and strength properties of the formations. It is linked to a reservoir model to achieve initial equilibrium and also to further simulate the coupled transport, chemical and mechanical processes occurring during CO 2 injection operations and the subsequent re-equilibration. The predicted stress path allows the evaluation of the mechanical stability of both cap-rock and faults (which may bound the reservoir, penetrate the cap-rock or intercept wells). The stability of wells in formations experiencing strain is also investigated. In addition, an accurate Mechanical Earth Model contributes to optimizing well construction and stimulation operations. Profiles of stresses and mechanical properties along a planned-well trajectory allow designing a drilling operation that will maximize subsequent hydraulic isolation of the well by optimizing the wellbore condition. Similar information along existing wells helps to control hydro-fracture propagation when injectivity enhancement is required. The Mechanical Earth Model can be used to develop operating envelopes for well placement, hydraulic fracturing, and CO 2 injection that best ensure containment while achieving injectivity and capacity requirements. Introduction The climate of the Earth is warming, with widespread changes in ocean salinity, wind patterns, precipitation and aspects of extreme weather. This is very likely forced by the increase in anthropogenic greenhouse gas concentration in the atmosphere. It is estimated that over 60% of this increase is due to carbon dioxide (CO 2 ) emissions alone[i]. Carbon Capture and Storage (CCS), that is the capture of CO 2 from industrial and energy-related sources, transport, and injection into the subsurface for long term sequestration purposes, is a viable means to keep a significant fraction of emitted CO 2 out of the atmosphere. CCS is thus recognized as a promising solution to mitigate climate change.[ii] Along with capacity and injectivity, containment is agreed to be a primary function in geological storage performance. As evidenced by oil, gas, and even CO 2 natural accumulations, rock formations can be impervious enough to act as flow barriers over geological periods of time. Delineating such a seal, safeguarding its integrity under operational conditions, and verifying whether isolation is effective or not are key objectives in achieving a successful storage project. In particular, seal integrity must not be impaired by the mechanical effects of storage operations. Indeed, rocks and faults permeability may drastically increase as they undergo stress changes and deformation[iii]. The mechanical response of the sealing components to the loads induced by well drilling and completion, CO 2 injection, and the corresponding effects on the risk of leakage must therefore be assessed when evaluating the suitability of candidate sites, designing operations, and planning monitoring schemes. This paper presents a methodology where characterization, modeling, monitoring, and construction technologies are integrated for containment performance and risk management. The first section frames the performance and risk management methodology under whose umbrella the geomechanical analysis takes place. The following sections describe the building of a Mechanical Earth Model (MEM) and how mechanical modeling is coupled with fluid flow simulation so as to forecast the dynamic response of the rock mass to fluid pressure increase, temperature variations, and fluid/rocks chemical interactions caused by massive CO 2 injection and subsequent re-equilibration. Implications in terms of risk evaluation and strategy for risk control are discussed in the last sections. Working Group I contribution to the Intergovernmental Panel on Climate Change Fourth Assessment Report " The Physical Science Basis ", 2007. Working Group III contribution to the Intergovernmental Panel on Climate Change Fourth Assessment Report " Mitigation of Climate Change - Summary for Policymakers ", 2007. Sibson, R.H.:"Brittle-failure controls on maximum sustainable overpressure in different tectonic regimes", AAPG Bull, v. 87(6), p. 901–908, 2003.

Abstract The provenance of the single-diameter well consists of over 350 commercial installations of solid expandable tubular systems and a concise, yet encompassing development plan. The maturation of expandable technology has led to successful design, construction and testing of individual components and the subsequent subsystem that will ultimately help realize the single-diameter well. This evolutionary step brings the energy industry that much closer to a fundamental change in wellbore construction. The single-diameter well represents a paradigm shift in the way wells are drilled and results in significant benefits that include conserving resources, saving time, and creating a smaller environmental footprint. All of these features result in considerable savings that reflect the practicality of this value-added technology. This paper will explain the overall scope, approach and implementation essential to realizing the single-diameter well. In addition, this paper will explain how the technical development of necessary tools for the single-diameter well brings significant savings to drilling operations. Using business cases, this paper will detail where the value of application is realized. In conclusion, this paper will outline future possibilities for the technology and how it will impact the industry. Introduction The legacy of single-diameter technology stems directly from the development of solid expandable tubulars. Extensive and progressive testing by Enventure and Shell has rapidly improved single-diameter technology. Manipulating the diameter of pipe downhole has taken these systems from an emerging technology to a viable wellbore construction option. Incorporating these systems into the drilling design retains wellbore ID and decreases the tapering effect. Developing a process to retain wellbore ID by using these systems in tandem virtually eliminates wellbore tapering. This concept constitutes the premise of the single-diameter wellbore advantage. Proving the Concept A proof-of-concept well, completed in South Texas by Shell Exploration and Production Company (SEPCO) in July 2002, used one single-diameter section that required two dedicated trips to complete the expansion. The system used conventional expandable technology for the first trip, hydraulically expanding from the bottom up, to achieve the required partial inside diameter (ID). A combination hydraulic and mechanical expansion trip from the top down followed, achieving the final required ID (Figure 1). With the basic construction principles proven, the challenge now was to translate these elements into a practical and more universally cost-effective working system. A project team, consisting of the operator's research group and asset team and the expandable service company, began to move the development beyond the proof of concept stage. First, the team refined the base concept to a slightly different configuration. The improved system concept expands a bell section on the bottom of the expandable casing creating an overlap. This section allows the subsequent string to be expanded and clad inside the bell for hanging and pressure sealing. The remaining liner length is then expanded using a basic pipe expansion method. Expanding the liner top into the previous bell section forms a metal-to-metal seal. The necessity for zonal isolation was identified as a key issue and addressed by underreaming the hole section to provide an adequate cement sheath. Next, team members concurred that the existing post-expanded casing specification and completion scenario were acceptable and turned their attention to system functionality. The numbers of trips to complete an installation and risk mitigation were identified as the two primary considerations directly related to the deepwater environment and spread rate cost. The bell section expansion, main liner section and overlap needed to be consolidated into one trip. Adequate self-contained contingencies also needed to be part of the design.

This paper was prepared for presentation at the 1999 Offshore Europe Conference held in Aberdeen, Scotland, 7–9 September 1999.

This paper was prepared for presentation at the 1999 SPE Offshore Europe Conference held in Aberdeen, Scotland, 7–9 September 1999.

This paper was prepared for presentation at the 1999 SPE Offshore Europe Conference held in Aberdeen, Scotland, 7–9 September 1999.

Abstract One of the main features that distinguishes an FPSO from a conventional ship, is the turret. The main aspects affecting the turret design are the functional requirements, the mooring loads and the integration of the turret geometry and loads into the ship structure. Once the general arrangement of the turret has been determined; the detailed design of the steelwork, the integration of the mooring lines, the support of the mooring loads, the detailed design of the bearing and hydraulic system and the design of the process pipework and transfer system has to be performed. On the Texaco Captain FPSO, these engineering functions as well as the construction of the turret were performed by the shipyard. This allowed the engineering and construction activities of the turret to be integrated with the overall engineering and construction schedule of the rest of the vessel. This ensured that the control of all aspects of the vessel remained with one entity i.e., the shipyard. This paper describes the engineering and construction techniques used related to the turret, when these activities were performed relative to other shipyard activities and how in this way, the turret engineering and construction did not impact the project critical path. Introduction The turret is generally one of the most critical systems in an FPSO. It represents the "heart" of the unit, which interfaces with the subsea equipment, the mooring and risers systems, the process plant, and the vessel systems. Due to this broad interaction with the other systems, the design of the turret and its associated systems must be 'frozen' at the very beginning of the project. Procurement of long lead equipment must be undertaken at an early stage to ensure a proper delivery at the construction yard for installation, hook-up and commissioning. In the following, the experienced gained by ASTANO on how to deal with this matter in order to keep the turret off the critical path will be described. Specifically, the description will be related to the last FPSO unit delivered by ASTANO: The Texaco Captain FPSO. Background Preliminary Engineering. An extensive Front End Engineering (FEE) work was carried out on the Texaco Captain FPSO prior to the contract award. After this engineering work was finalized, the design of the turret was completed (subject to final model test results), by using standard validated computer programs for the definition of the size of the mooring system components. The contract for the final design and construction of the FPSO was then awarded by Texaco and the project started on the above mentioned basis. Model testing and further computational work. Firstly, DMI (Copenhagen, Denmark) was committed to perform a model test programme (wind tunnel and basin tests), in order to confirm the main design parameters (i.e. - basically mooring chain diameter, maximum vessel offsets for the risers system, and turret induced forces and overturning moments). Other information to be used in the design of the unit such as the vessel self-weather vaning ability, the thruster capacity required for heading control and for unwinding of the transfer system, green waters on deck, etc., were also monitored. Unfortunately, the measured mooring line tensions, vessel offsets and turret induced loads, exceeded by far those predicted using 'the state of the art' computer programs. Due to the criticality of the impact derived from the results mentioned above, a second model test programme was committed to MARIN (Wageningen, Holland), as well as some analytical work using in-house developed fully dynamic computer programs. P. 509

Abstract BP's Harding Development employs a totally innovative concept for North Sea oil production. A large permanently installed jack-up platform, incorporating production, drilling and living quarters facilities, is positioned on top of a concrete gravity storage base tank which holds Harding's acidic heavy crude before export, via a submerged turret loading buoy, to shuttle tankers. The use of horizontal drilling techniques in the early 1990's coupled with adoption of the above concept transformed a very marginal prospect into a viable development which currently has one of the lowest development costs per barrel in the North Sea. The paper describes how the viability of the development has been achieved using an entirely new approach to project management by BP with a small integrated management team. The relationships created with design contractors, suppliers and fabricators are shown to represent the embodiment of the principles of the CRINE initiative and have secured for all parties benefits which can be used as benchmarks for future projects in a low oil price environment. Contractual arrangements are discussed and a new approach to Operations and Maintenance support contractors is highlighted. The concept has potential for reducing abandonment costs due to the relative ease of decommissioning and removal. Introduction The Harding Field, originally known as the Forth Field, is a Eocene accumulation located some 320 km north east of Aberdeen in block 9/23b of the northern North Sea. The field, which was discovered in 1988, comprises four reservoirs containing a heavy, naphthenic crude (18 – 28 API, TAN Number 2.8) with a low gas/oil ratio (240– 310 scf/bbl). The two largest reservoirs, Central and South, are being developed as part of the current project programme. The combined recoverable reserves amount to some 185 mmbbls. Following the initial discovery, a drilling programme was established and in parallel, a series of conceptual studies undertaken to identify viable development options for the Field. Based on the technologies available at the time, the indications from these studies were that an economical case could not easily be made for the field's development. A single, jacket-supported production facility drilling vertical wells over the Central reservoir with subsea tie-backs from the South reservoir appeared to be the only technically feasible concept. The successful application of horizontal drilling techniques in the early 1990's provided the trigger for a further round of concept reviews. A conventional single production and drilling platform located between the two reservoirs and accessing them via horizontal wells was deemed to be achievable but costs were still providing a barrier to a viable project. In the context of a falling oil price, a highly innovative scheme was required that would drive the development costs per barrel down to a level that was substantially lower than that which had been achieved at the turn of the decade. Eventually, the use of a large purpose-built permanently installed self-elevating jack-up platform was assessed and seen as a preferred solution to overcome the economic hurdles and meet the challenge of a development cost target of less than $4/barrel in a world of $14 oil. The characteristics of Harding's crude are such that it cannot be blended at peak design production rates of 63,000 bbls/day into the adjacent Forties Pipeline System. A totally submerged concrete gravity base tank (GBT) was identified as suitable storage for the crude until such time as it could be uplifted via shuttle tanker for transportation to refineries capable of handling its special characteristics. The GBT performs two roles in that it provides storage capacity for 580,000 barrels of stabilised crude prior to tanker shipment and acts as the foundation structure for the jack-up. The last major link in the development scheme is the 24" diameter export line, terminating in a Submerged Turret Loading (STL) system. P. 741

Abstract This paper describes the feasibility and construction of the landfall of a 20" gas pipeline and two 3" piggy-backed condensate pipelines at Point of Ayr, North Wales from BHP Petroleum's Liverpool Bay Development. The 4,340 metre long pipeline was constructed from pipestrings, each approximately 600 metres long using a construction site at Point of Ayr. The pipestrings were pulled into position by the bottom pull technique using an 800 tonne capacity winch spread on a marine barge. On completion of the pulling operation the pipelines were buried in the seabed using a submarine trenching machine operated from two work barges. The utilisation of the TM4 trenching machine was in preference to an extensive dredging and backfill operation. Introduction Land & Marine Engineering (LME) became involved in the landfall section of the Liverpool Bay Development project at a very early stage. In 1991 LME were awarded a pilot study by BHP Petroleum (BHP) to investigate and propose a potential landfall site for the pipelines. The brief was to find a suitable site between LIandudno on the North Wales coast and the Ribble Estuary on the Lancashire coast. The conclusions reached during the pilot study then led to a feasibility study for a landfall at Point of Ayr in North Wales. The feasibility study established that subject to satisfactory results from proposed survey and site investigation work, and successful consultation with the authorities then a landfall at this location could be satisfactorily constructed. Over the following months the survey and site investigation results and consultations with the Local Authority proved successful. BHP therefore issued invitations to tender for the offshore pipeline contract, which was to include the landfall works. McDermott-ETPM (MET) were awarded the offshore pipeline contract in 1993 for pipelines from the Douglas Complex to the Point of Ayr, also pipelines from Hamilton, Hamilton North and Lennox to Douglas. LME was awarded a sub contract by MET to construct the landfall section of the works. Site Location The selected landfall construction site was adjacent to BHP's new terminal at Point of Ayr (Photo. 1). The site runs through low lying agricultural pasture and the Gronant Dunes and the Talacre Warren Site of Special Scientific Interest (SSSI) comprising mainly coastal dunes and associated scrub land. (Photo. 2). The sandy beach that stretches seawards from the dunes to the edge of the Welsh Channel is approximately one kilometre in length. The Welsh Channel is a navigation channel serving the port of Mostyn. It is approximately 1.4 kilometres in width and a maximum of 8.5 metres deep below OD. The channel bed comprises a surface layer of sand approximately 2 metres thick overlaying stiff clay. Beyond the Welsh Channel is the West Hoyle Spit which is 1.2 km in width, and dries out at low water. The level at its highest point is +3.Om AOD. The geological make up of the spit is "pure sand". P. 165

Introduction Four years ago BP was forecasting production from the huge Forties Field in the North Sea would become uneconomic by the mid nineties and progressive shutdown would commence around 1995-96 with the last platform being decommissioned by the year 2000. A challenge was set to extend the life of the field through to 2010, and as a result of a major review by BP of the cost efficiency of its operations the challenge is beginning to be met. Forties production can now remain viable for much longer than expected in 1989, even after a fall in oil price from $25 to $18 per barrel. Not least of the influences making this extended life expectancy possible are the cost advantages promoted by an innovative Partnering venture between BP as operating company and Brown & Root as contractor. The Forties Oil Field was discovered in 1970, 110 miles ENE of Aberdeen in 110 metres of water. Recoverable reserves were then estimated at 1.8 billion barrels. Four platforms were designed, constructed and installed and first oil was produced in September in 1975. Peak production of 500,000 barrels per day was reached in May 1978. A fifth platform was installed in 1986 and the 2 billionth barrel of oil was produced in April 1989, an achievement far in excess of original predictions. The estimate for recoverable reserves today stands at 2.5 billion barrels with the current production rate being 140 mbd. With operating costs over the 10 years from 1980 to 1990 rising from $1 per barrel to about $5 per barrel and capital costs running at about $100 to $150 million per annum for the past 5 years, BP began to seek ways of reducing operating costs. It rapidly became clear the way forward was for the company to concentrate on its core activities of exploration and production and to buy in non core activities as services i.e. "to do what they did best and hire the rest". From this came the decision to reduce the number of service providers and to develop long term relationships with selected suppliers. One strategic consideration was to identify a contractor with proven capability for co-ordination and execution of integrated engineering and construction services. The long-standing successful relationship between BP and Brown & Root in the Forties Field, together with the shared conviction that traditional adversarial contractual methods and relationships could be substantially improved upon and lead to increased cost efficiency, provided the foundations for the Partnering agreement, signed in January 1991 between the two companies. THE PARTNERING CONCEPT Partnering can be defined as a contractual arrangement in which the client and supplier agree to work closely together to the increased benefit of both; it is a long term commitment between two organisations for the purpose of achieving specific joint objectives by maximising the effectiveness of each party's resources. The relationship is based on trust, dedication to common goals and an understanding of each others expectations. The way that BP and Brown & Root now work together on the Forties Field differs significantly from the traditional style of relationship, particularly in the following areas: Engineering Support Service Contract Agreement Organisation Structure P. 229^

Abstract This paper demonstrates work being conducted which will result in advances in the technology of offshore tethering products; steel wire rope, synthetic fibre rope, chain and welded tubulars. The work will have major implications for the improvement of operational safety and discard criteria for mooring tethers. The objective of the paper has been achieved by discussing NEL's current involvement in several major studies and presenting an overview of the research conducted. This research has generated testing of the highest quality through the development of test assessment criteria and gained an insight into the fatigue behaviour of the tether products through the widespread use of condition monitoring techniques. Introduction The development of tether technology is crucial for offshore construction as engineers take up the new challenges posed by hydrocarbon discoveries in ever increasing water depths and the very large engineering structures of the 21st century. This and the implications for safety requirements was recognised by NEL and the Tethers 2000 concept introduced. Tethers 2000 is a programme of research investigating the endurance, fatigue behaviour, discard, scale, material and construction effects of tethering products. At the present time, under the umbrella of products. At the present time, under the umbrella of Tethers 2000 there are four Joint Industry Studies in progress covering steel wire rope, synthetic fibre progress covering steel wire rope, synthetic fibre rope and chain and one single client project on welded tubulars. The paper is organised into two main sections. The first provides the background, objectives and NEL's participation within each of the studies. The second is participation within each of the studies. The second is an overview of the research NEL has been conducting. As confidentiality prevents details of all of the work, graphs showing load-endurance information are presented with non-dimensionalised axes. The overview provides an Insight as to the nature and quality of research being carried out to tackle the deep water challenges of the future. CURRENT STUDIES As already mentioned in the Introduction, four joint industry studies and one single client study fit within the Tethers 2000 concept. These studies investigate the fatigue performance and behaviour of the four main tether types. In order to discuss the origins, objectives and NEL's involvement in each of the studies, the fatigue loading conditions which mooring tethers are subjected to needs to be addressed. Load Regimes Three fatigue loading regimes are applicable to tethers used for mooring offshore structures; shown schematically in Fig. 1. a Tension-tension (T-T) fatigue. Fluctuating tension in the mooring line due to movement of the structure and including the effects of line dynamics in deep water. This will be the main form of loading for welded tubulars as used on TLPs. b Bending-tension (B-T) fatigue. Small amplitude movement of the tether over a fairlead in phase with fluctuating line tension. The bending length for mooring ropes around a fairlead pulley will be due to rope stretch under load and movement of the structure caused by wind, tide and current effects. P. 527

Abstract This paper outlines the potential for low cost, shallow water, oilfield development in Arctic waters with equipment that has been utilized in the Canadian Beaufort Sea. A bottom founded structure, Molikpaq, designed and used for year-round Arctic operations, is described along with highlights of previous deployments in the harsh Beaufort Sea environment. The operational flexibility and capability of this structure for use within a range of Arctic offshore development alternatives is discussed, including modifications to the structure for increased production capacity and various transportation options. Cost estimates for these Molikpaq deployment alternatives are also presented so that the application of this proven Arctic technology can be assessed across a range of reserves. Introduction The search for new sources of oil and gas has carried the petroleum industry into increasingly more hostile offshore environments. During the 1960's, permits to explore for oil and gas were issued for the majority of the continental shelf of the Canadian Beaufort Sea which extends some 120 km offshore to water depths of about 200 m. Ultimate potential hydrocarbon reserves in this area have been estimated to be 9.2 billion barrels of oil and 76 trillion cubic feet of gas (Procter et al, 1983). Since 1973, offshore exploration has been carried out with a variety of fixed and floating offshore drilling systems. Numerous discoveries have been made in the Canadian Beaufort Sea, the most significant of which is Gulf Canada's Amauligak field, with estimated reserves of 330 million barrels of oil and high daily well productivities. productivities. More recently, large areas of the Alaskan Beaufort shelf and Chukchi Sea have been leased for exploration activities. Here, several types of bottom founded structures, drillships and the conical drilling unit Kulluk have been used for exploratory drilling. Although no major discoveries have been announced to date, the hydrocarbon potential in this area is well recognized and further exploration is planned. On a world wide basis, various levels of exploration have also been undertaken in other Arctic and sub-arctic areas that are affected by ice. (Figure 1) These include offshore sedimentary basins from as far south as Canada's East Coast with its Hibernia oil field, China's Bohai Gulf, and the Soviet Sakhalin Island region to the northern reaches of the Barents and Kara Seas, lying off the Norwegian and Soviet coastlines. P. 1

Permission to copy is restricted to an abstract of not more than 300 words. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgement of where and by whom the paper was presented. Publication elsewhere is usually granted upon request provided proper credit is made. Abstract This paper describes the TRILITE Super Satellite Platform (TRISS), a light 3-legged costeffective fixed jacket substructure concept supporting a simple topside facility intended for unmanned operation. An overall objective has been to develop a realistic alternative to sub-sea concepts in water depths down to approx. 350 meters with the added advantage of having the wellheads located above sea level. The jacket concept incorporates all known and proven features contributing to weight proven features contributing to weight reductions. Furthermore, additional ideas conforming with this objective has been launched and studied, such as utilizing prestressed conductors and routing caissons inside the legs. Another novel feature is the installation method for cases where the installation weight exceeds the current SSCV lifting capacity, i.e. with use of a special purpose concrete bargeCONRAFT. The approach involves e.g. upending of the jacket jointly with the barge. The topside facilities studied ranges from the simplest possible sub-Sea type arrangement to a more elaborate concept including first stage separation, thereby avoiding multi-phase transportation to the processing facility. Special emphasis has been placed upon developing a layout adapted to a triangular support configuration and minimizing equipment within the frame-work of safety regulations in the Norwegian sector of the North Sea. Technical merits have been studied and estimates of weight, cost and schedule prepared for a case in 330 m water depth. Introduction In the search of means to reduce field development costs to meet the challenge of reduced oil prices, major attention has been towards less traditional platform concepts such as sub-sea installations, articulated/guyed towers, floaters and mono-hull concepts. This has been particularly pronounced for deep water sites, i.e. from approx. 200 m and deeper. Exceptions to this are however found such as the GBS alternatives studied for the Troll field and the already installed Bullwinkle jacket which are examples of extending fixed platform technology to deep waters. Jacket structures is the most common and conventional platform concept world-wide. Even in Norwegian waters where concrete platforms are also frequently preferred, altogether 16 jackets are installed or scheduled for installation in the period 1980–1990, see Fig.1. Actual water-depths ranges from 70 to 175 meters. The deepest jacket site world-wide is 412 meters. Apart from continued expanse into deeper water it is worth noting that various technical improvements in recent years have resulted in significant reductions in steel weights, a development which has been further enhanced by new installation methods, e.g. vertical piling and direct lift installation which is possible for jackets up to weights of approx. 10 000 tonnes. Adding to this is a very favorable unit price development in recent years related to both steel materials and construction, the latter largely caused by increased efficiency in the areas of welding and assembly. Consequently, jackets are now more competitive alternatives to e.g. concrete structures than ever before. In comparison with Concepts other than fixed ones, the competitiveness of jackets will very much depend on field specific data such as water depth, no. of wells, reservoir and drilling/process facility characteristics. Regardless of case however, jackets have an advantage in terms of being conventional and well proven, i.e. associated with low technological and cost risks. Moreover, in comparison with e.g. sub-sea completion there will be significant advantages associated with maintaining wells above sea-level as well as offering more flexibility with respect to future modifications. 2 TRISS CONCEPT DESCRIPTION The primary objective of the TRISS concept is to provide means to develop a deep sea, medium sized oil or gas field by using a simple fixed platform instead of a sub-sea installation. platform instead of a sub-sea installation. The basic element of the concept is the TRISS platform which comprises a TRILITE jacket and platform which comprises a TRILITE jacket and an UNMANNED TOPSIDE, see Fig. 2 and 3.

The technique of taking ultrasonic thickness readings as a basis for assessing corrosion and erosion damage on structures and pipework systems is an established means of obtaining condition data. To ensure that surveys carried out in this way are relevant and useful, several conditions must be met: Individual readings mat be accurate and the measuring system must be capable of ignoring paints and coatings at the test point. Test points must be appropriately positioned. Sufficient points must be taken to give a representative sample. Reporting must be in a format which is readable, flexible and capable of highlighting anomalies. Following extensive experience in onshore and offshore corrosion condition surveys, systems have been evolved which have improved the efficiency of this approach in all the above areas. 1. MEASUREMENT TECHNIQUES Measurements are taken by placing an ultrasonic probe on the surface at the test point, with a suitable gel couplant applied to exclude air and ensure transmission of the ultrasound into the test material. (See Fig. 1). The probe contains a pair of piezo-electric crystals, typically resonating at 1-4 MHz. For special applications, a single crystal format may be used, however, the concepts are best illustrated by the twin crystal construction. The transmission (TX) element delivers a pulse of ultrasound energy which is transmitted through the perspex shoe into the test material. Upon encountering the far surface (backwall) the pulse is reflected, to return to the receive side of the probe. Fig. 2 shows the signal/time relationship (A-Scan) and highlights the time delays due to passage of the ultrasound pulse through the perspex shoe and any surface coating which may be present.

Introduction The major fields in the North Sea are currently in production and the average size of prospective development fields will decrease with time. The smaller or 'marginal' field development technology will represent a major factor in the future of oil and gas development in the North West European Continental Shelf area. Worldwide the number of exploitable marginal discoveries to date is believed to exceed 800. In the North West European Continental Shelf it is forecast by Hoare Govett that more than 45 marginal developments will be underway before 1990 in this area. These will be chosen from a known potential of 200 discoveries. The sub-sea completion of marginal oilfield production facilities is simplified by the use of high pressure flexible pipes. Short pipes are used to 'Tie-In' rigid pipelines to sub-sea structures and continuous length pipes are used increasingly as a replacement for rigid, steel, pipelines. pipes are used increasingly as a replacement for rigid, steel, pipelines. OPERATING ENVIRONMENT The environment in which the flexible pipes are required to operate is aggressive. Crude, diphasic, oil especially where hydrogen sulphide, carbon dioxide and water are present, in contact with flexible polymeric materials, creates severe problems. These polar gases permeate into the polymer structure and become dissolved at high pressure. If rapid loss of pressure occurs in the pipeline, explosive decompression of the polymeric material and the pipe structure can occur. All polymers allow gases to permeate through pipe structure can occur. All polymers allow gases to permeate through them. Hydrogen sulphide and carbon dioxide in the presence of water will contact the steel reinforcement. Hydrogen embrittlement of carbon steel and pitting corrosion of austenitic and duplex stainless steels can occur. Where chlorides are present, then the probability of stress corrosion is increased. The external cover of the pipe must be resistant to marine growth, ozone, ultra-violet light, fire and heat transmitted from the oil travelling within the pipe. The interior and exterior surfaces of the pipe must be abrasion and cut resistant. In operation the pipe must be stable under fluctuating pressure conditions. Excessive portion, length change or bending of the pipe induced by internal pressure change are undesirable. The pipe may be under considerable pressure change are undesirable. The pipe may be under considerable tension and subsequent constriction of the bore cannot be tolerated. At 3000 ft ocean depth the hydrostatic pressure on the exterior of the pipe may reach 1500 psi. The pipe should not collapse. The oil industry requires high pressure flexible pipes which are chemically and physically stable in this demanding environment.