With the most recent industry downturn still fresh in many minds, the oil and gas E&P sector is approaching this recovery with a commitment to long-term cost discipline. As a result, augmented reality (AR) and virtual reality (VR) technologies are being adopted by operators and service companies alike as a means of cost savings while driving operational efficiency. AR technologies employ enhanced visualization hardware, techniques, and methodologies to create new environments wherein digital and physical objects and their data coexist and interact with one another, enhancing the user experience of the real world ( Kunkel and Soechti 2017 ). VR refers to the full immersion of the user intoand interaction with a completely digital environment. Together, these technologies form the core of immersive experience and a new paradigm in industrial interaction. Until recently, these technologies were primarily applied as enhanced entertainment products, most notably within the gaming industry. However, during the past several years, and thanks to the introduction of hands-free, head-mounted display (HMD) technologies, such as Microsoft ® HoloLens™ and now HoloLens 2, AR and VR are migrating into the enterprise sector. While the oil field has not been as quick to integrate AR and VR as other sectors, such as medicine, defense, and aeronautics, operators and service providers alike have increased adoption overthe past 12 months. Motivated by a mandate to keep operating costs low and improve efficiencies in terms of field processes, operators have begun implementing AR/VR applications as collaborative problem-solving, planning, and design tools. For example, some operators are initiating ARconcepts to promote internal use development and prototyping for both oilfield applications and remote refinery inspections. Additionally, service companies are embracing the use of smart glasses and wearable technologies to help improve remote work and collaboration to help increase in-field safety and reduce downtime. As part of its strategy to help drive the oil and gas industry's digital transformation, one major service provider is developing AR/VR applications to create digital representations of physical oilfield assets on the Microsoft ® HoloLens device. One area of focus is the planning, design, and deployment of solids control, fluid separation, and handling technologies for offshore drilling applications.

This paper describes the successful application of a rigless well abandonment method that isolated the well's production interval using resin-based sealant, without cement and without latching a conventional subsea blowout preventer (BOP). An offshore operator needed to permanently abandon a subsea well that had become uneconomic due to excessive sand production. Several subsea wellhead and downhole conditions would have made killing the well by conventional means difficult if not impossible. Wellhead fatigue and soil erosion around the wellhead meant that a conventional drilling BOP could not be used in the operation due to the equipment's weight. Fluids to kill the well and permanently seal the formation could only be pumped down the tubing, and an obstruction in the flow path would limit the injection rate. Typical wireline and coiled tubing intervention tooling and circulation could not be used. Cement and micro-cement have particles that could potentially bridge at the downhole obstruction, preventing it from sealing the formation. Considering these factors, the operator and service provider designed, tested, obtained regulatory approval, and successfully implemented a rigless abandonment operation using a service vessel and well stimulation tool to inject resin-based sealant into the well to seal the formation and enable safe final abandonment and tree removal using a light intervention vessel. These results suggest that this method can potentially be used during abandonment of subsea wells with smaller trees and wellheads that have experienced fatigue.

On the Solaris Ultra-High Pressure-High Temperature exploration well drilled in the NCS in 2016, a 15.0 psi rated rig, the Maersk Gallant jack-up (MSC-CJ62-120S design), was adapted to drill a reservoir with a Maximum Expected Wellhead Pressure (MEWHP) in excess of 16,600psi. The primary goal was to refit the rig to accept and operate in line with applicable PSA requirements, a 20.0 psi rated double BOP ram to be used in conjunction with the rig's 15,000 psi BOP. The scope included the installation of two different MPD annular pressure control systems. The modifications were to be carried out without stopping operations and within budget. An extensive, collaborative well-planning and equipment preparation process involving the operator (client), drilling contractor and service providers was critical to the success of the overall operation. Within the drilling contractor organization, the rig team, Technical Organization, Asset Team and Operations Drilling Support worked together to ensure all requirements and risk mitigating measures were in place and lessons learned from previous HPHT/MPD operations were incorporated. Some rig modifications were executed while in operation on another project under contract with another operator. Such jobs were limited to pulling cables and mechanical preparations to expedite hot work required at later stages. This paper describes the key planning considerations, preparations and creative solutions deployed to deliver a complex project which culminated in successfully drilling the deepest, hottest and highest pressure well in Norwegian history. It will serve as a reference for planning future Ultra HPHT projects. No confidential operational or subsurface data is revealed in this paper.

Plug and Abandonment (P&A) is the largest category in Decommissioning expenditures, representing 40-44 percent of the total investment that basically comes as mandatory cost with no expected return. If the well operator gets P&A inadequate, results may include water flows, gas or oil seeps from the seabed, or underground cross flow between formations with huge impact on environment and marine life. The objective of this paper is plasma-based technology for enhanced casing section milling addressing the P&A challenges. According to some oilfield service providers, two main P&A challenges are as follows: Time and expense of casing milling - for example, Norwegian regulations call for cementing two 50-meter sections of casing above and below each hydrocarbon-bearing zone. Each section may take more than 10 days to mill and may generate four tons of swarf. The second challenge is swarf damaging blow out preventer (BOP) - Milling generates swarf, which then must be removed before cementing. However, swarf removal can damage the BOP. To avoid well integrity issues, BOP has to be dismantled, inspected and repaired at considerable expense. The presented paper is focused on technology eliminating the P&A challenges. The core of the technology is based on plasma generator producing high temperature water steam plasma for rapid steel structural degradation. This approach brings a radical abandonment of the classic rotary approaches with connected tubes in long strings and generation of swarf which need to be removed. Besides elimination of aforementioned challenges, the technology advantages include also rigless operation since the system is designed for coiled tubing solution. This feature brings additional cost savings using Light Weight Intervention Vessel (LWIV). Moreover, fully automated coiled tubing goes hand in hand with enhanced safety of the operational staff. Impact and potential of the technology is to change, simplify the process of P&A and therefore significantly cut the time of whole P&A. The technology is currently under development with expected commercialization within three-year period.

Following the Macondo incident in 2010, industry has taken steps to improve response readiness in case of a subsea well control incident. This led to Oil Spill Response Limited's (OSRL) Subsea Well Intervention Service (SWIS) being formed. SWIS allows industry the capability to better respond to a subsea well-control incident by providing state of the art subsea well intervention equipment. This paper will provide an overview of SWIS and demonstrate how the equipment is stored and maintained in a response ready state, including information on periodic maintenance performed and logistics philosophy for mobilisation. In addition, it will provide an update on the Containment Toolkit, allowing for cap and flow operations. The equipment available includes 10K and 15K psi Capping Stack Systems (CSS) and Subsea Incident Response Toolkit (SIRT); comprised of Site survey, Debris Clearance, Subsea Dispersant and Blowout Preventer (BOP) Intervention System. The equipment is stored at strategic global locations, covering the main areas of oil exploration and production worldwide. It is transportable by land, air and sea and can be called upon by any OSRL SWIS Capping member. Further to this, the OSPRAG Capping Device will be discussed, which provides cover for the UK Continental Shelf. To enhance the capability of SWIS the Containment Toolkit will be delivered to OSRL during 2015. The equipment in the containment toolkit is designed to supplement standard industry well test hardware to create a containment system. It comprises long-lead equipment not readily available in the current industry and minimises response times by allowing a responding well operator to draw on existing resources.

Objectives/Scope As subsea oil & gas drilling and production continues to progress into deeper waters the demand for fast, safe, efficient, reliable, and cost effective equipment will continue to grow. Cam locking devices provide an innovative method to meet these requirements in a variety of applications within the oil & gas industry such as, but not limited to, anti-rotation of casing, tubing and riser connectors, and for locking of valves, cylinders, BOP rams, and rigging equipment. Methods, Procedures, Process During the development phase of the bite style cam device Finite Element Analysis (FEA) was utilized to perform design optimization in conjunction with a unique design of experiments approach. The results of this study have been used to optimize the high order of design variables that define the geometry of a bite style cam locking device. Results, Observations, Conclusions A novel bite style cam device has been developed and applied to threaded connections that employs hardened teeth rather than friction, as in typical cam functions, to provide a locking load capacity. In contrast to solutions currently utilized for connector anti-rotation, the innovative cam design requires no special tooling, hammers, or dangerous explosives to install, making it much safer than solutions on the market today. Installation requires only the use of a simple hex wrench, significantly increasing rig efficiency and drastically reducing installation time, a vital criterion for equipment offshore. Novel/Additive Information: Overall, the bite style cam device has proven itself an ideal solution for subsea and offshore applications. Easy and quick installation and reduced loose parts provide improved value and performance.

In the current climate of low oil prices and reduced revenue, Oil & Gas operators across the industry are being motivated to drive their costs down, which means –for many operators- a reduction in CAPEX and OPEX spend. Whilst operators are keen to reduce cost, maintaining production levels is required in order to remain profitable. Understandably, this has its own challenges, particularly when it comes to dealing with inspection, repair and maintenance (IRM). This paper demonstrates a project example of how embracing the innovative thinking in dealing with common matters could help reduce IRM costs, whilst maintaining safe and steady operation. It is based on an ongoing project activity to proactively repair a subsea Xmas tree defect at the flowbase, the defect is located within the flowbase connector downstream the choke insert. The paper explains the option select processes followed by the project team, and the innovative options that were assessed initially as opposed to the costly traditional option (that is simply replacing the Xmas Tree). The paper will briefly explain each of these options (6 in total), the technical challenges and the relative costs involved with each one of them. The paper then explains in details the selected repair methodology which makes use of an innovative technology, used to direct the hydrocarbon out of the Xmas tree structure (from the choke insert location) to the existing flowline, thus permanently bypassing the flowbase and the defect in its entirety. It will demonstrate the opportunities exploited to improve system maintainability, operability and reduce future OPEX. The paper will be an example of how innovative thinking is required in this current market condition, and how the use of existing and proven technologies- though in an innovative manner- and pushing the boundaries could help reduce CAPEX and OPEX for operators.

Currently available secondary intervention systems may not successfully operate critical subsea blowout preventer (BOP) safety functions such as closing pipe rams, blind rams, and shear rams. Failure may occur because sufficient hydraulic power (pressure times flow rate) is not available to operate these functions quickly in a flowing well, causing failure of sealing elements. This paper describes current shortcomings and identifies a novel ROV-based intervention. With numerous combinations of rams, bore pressures, bore flows, pipe sizes, and additional equipment inside the well, it is difficult to determine the right amount of hydraulic power required to meet closure times specified by the subsea industry and regulatory groups. This paper considers well conditions and determines the necessary power. Neither current ROV hydraulic pumping interventions nor hydraulic accumulator interventions can provide the necessary combination of large amounts of flow and pressure for successful secondary operation of BOP safety functions. Also, because current intervention systems are not integrated with ROV systems, they require significant deployment time. Hydraulic accumulator intervention systems provide maximum power at the wrong time—at the beginning of the ram stroke instead of the end—and also have depth limitations. Given the limitations of current hydraulic intervention systems, an ROV-based intervention system is being developed to reliably operate BOP safety functions. This intervention system, which is integrated with current work-class ROV electrical and hydraulic power functionality, uses novel power management designs.

This paper is concerned with human activities relating to offshore exploration and exploitation that have adverse effects on marine animals. It addresses noise pollution caused by tasks such as piling, drilling, exploration etc. Loud noise produced during offshore operations can seriously affect one of the main senses – hearing. The paper examines sources of noise and methods of mitigating it to tolerable levels. Research is focused on the use of bubble curtains for noise reduction. The main conclusion is that the bubble curtain is a recognised noise reduction/shielding method and its effectiveness is dependent on bubble size and water depth in addition to water temperature, density and salinity.

Overview The tragic Gulf of Mexico accident in April, 2010 can be marked as the defining moment which confirmed the idea for making a subsea Blowout Preventer (BOP) risk model. The accident showed that society is our biggest stakeholder with its own risk acceptance perception, enabled by the immediacy of social-media, the tenacity of the press, and today’s instantaneous technology for transmitting newsworthy and life-altering events. When thinking back to that day in April, we can ask: what does the majority of society remember about this tragedy? The most common answer to this question is the graphic photos of massive amounts of oil washing up on once pristine Gulf beaches, killing fish, birds, and other ancillary industries which rely on clean Gulf waters and beaches to survive. Although not pictured with such detail, the casualties will never be forgotten either.

Throughout the 1970s, 1980s and 1990s, many relatively shallow-water wells were drilled at water depths less than 600 ft. (183M) utilizing conventional Semi-submersible Rigs, Subsea wellheads and/or subsea templates. A goodly portion of this drilling was done in the North Sea, in both the Norwegian and UK sectors. Now, as those wells age to the point of requiring intervention to maintain, or enhance production, new generations of large Cantilever Jack-up rigs are available that can rework thes wells at a much lower day-rate than conventional semi-submersible rigs, be they anchor moored or dynamically positioned. Jack-up rigs hav not been, and were never intended to be able to attach to a subsea wellhead assembly. To date, this was the exclusive territory of Semi-submersible rigs or Drillships (but primarily Semi-submersibles). This basic equipment incompatibility needs to be addressed before detailed plans can be formalized. The most obvious solution to this problem is to install a subsea BOP Stack onto each of these new Jack-up rigs so that the connection to the subsea wellhead can be accomplished in a traditionally acceptable manner with relatively conventional equipment packages.

The general focus in environmental evaluation of offshore drilling is the discharge of cuttings and chemicals to local marine environment, in some cases including emissions to air from offshore turbines and engines. However, significant impacts occur as a result of processes upstream and downstream from drilling operations, in the manufacture of chemicals and materials, in supply and transport operations, and in treatment of drilling wastes. Life-cycle assessment (LCA) is the structuring, aggregation and evaluation of environmental impacts in a cradle-to-grave scope. We present an LCA model developed through a series of case studies for offshore drilling operations. Model components include a fleet of drilling rigs and supply vessels, a library of drilling fluids and chemical products, various cuttings treatment technologies, top-hole abatement techniques and well operations. The LCA model is used to evaluate technologies in historical, current and future best practice for offshore drilling. One measure under evaluation for the future is the development of smaller, fit-for-purpose vessels (Cat B), which are shown to potentially reduce emissions from the drilling vessel itself by 50 %. Slim-hole drilling is another technology with several potential benefits, including time savings, reductions in steel and concrete in installing and cementing casings, less drilling fluid required, and less cuttings waste logistics and treatment. In all, these provide 30-50 % reduction when compared with conventional well designs, in greenhouse gas emissions and other air emissions, and in harmful releases from manufacture of materials and chemicals and treatment of wastes. Relevant for operations outside European waters, the LCA shows that production and waste treatment of drilling fluid may pose a significant source for impacts unless fluids are managed properly by reuse of drilling fluid and recycling of oil from cuttings waste. These measures provide a reduction of 30 % of the total environmental footprint, illustrating the benefits from current best practice.

Now that the authorities have taken the infamous Deepwater Horizon BOP to the surface for inspection, the post mortem debate on the causes of the largest accidental marine oil spill in the history of the petroleum industry has begun. While a wide variety of experts are considering next steps to prevent this type of breakdown in the future, safety and reliability engineers are debating the basic premise; "Was the root cause of the Macondo incident a procedural problem or was this simply a series of failures that could not have been imagined prior to the incident? Analysis revealed that the BOP "operated as designed" however some reports suggest that the incident may have avoided by considering the following: What could have been done to predict this event? Would the employment of HAZOP principles have identified the potential failure? Was the Deepwater Horizon BOP properly sized, installed and tested? Would continuous on-line diagnostic testing of the BOP revealed a faulted state? Would the use of a performance based design specification provide a better safeguard design than the prescriptive API 16D?

Following the Deepwater Horizon incident the UK Upstream Oil and Gas industry formed Oil Spill Prevention and Response Advisory Group (OSPRAG) in May 2010. The Technical Review Group (TRG) within OSPRAG was tasked with reviewing relevant aspects of well design, examination, primary and secondary well control and to consider a UK capping contingency in the event of a loss of well control. This paper will examine the formation of the TRG and its approach to assessing whether the UKCS industry was performing in accordance with the regulatory requirements. It will examine the core TRG recommendations and assess how they are being implemented largely through the formation and work of Oil & Gas UK's Well Life Cycle Practices Forum (WLCPF). This includes the importance and relevance of assessing the future recommendations from the Macondo incident. Finally, the experiences and effectiveness of working within a cross industry team with members drawn from across industry including regulators, operators, contractors and trade unions will be discussed.

In December 2009, an unplanned operation during subsea operations caused substantial damage to a subsea wellhead, leaving the tree-hub, H-4 profile and Internal Tree Cap severely deformed. The wellhead was not in production at the time and well integrity was maintained. As part of an initiative to ascertain the extent of the damage and bring the well back online, Chevron contracted Welaptega to perform two 3D modelling photogrammetry surveys. Welaptega collected high quality digital still images of the tree-hub surface, and processed them to construct geometrically accurate 3D models representing the inside and outside geometry of the tree-hub. The 3D model was imported into OEM design software for comparison to as-built drawings, and then used to design a bespoke Internal Tree Cap hold-down tool to ensure well integrity during VX gasket removal. Using the 3D model, a phased work plan was constructed, involving customised cutting tools, to return the tree-hub to a condition which would allow the BOP to be run back onto the tree. In two separate DSV interventions, divers removed the damaged VX gasket with hydraulic arms, and cut the damaged area using a diamond rope cutter and Grayserv cutter. It was then possible to trial fit an H-4 connector over the tree hub, complete with a custom gasket which was designed to form a seal.

Abstract The industry has come a long way since the inception of drilling from cable too rig to rotary drilling. The method of drilling has not changed at all in the last couple of decades. The advancement of technologies have lead to development of high power lasers which can be used to blast through the rock at rates greater than 200 ft/hr. We would like to introduce the a new laser drilling system which can drill a mono diameter hole and simultaneously build a casing around the wellbore using high pressure spray devices to spray a heat setting resin which is then pressed using a heated drum roll to give a perfect smooth casing wall. A second jet with low temperature air is used to cure the resin thus setting it faster than the conventional way. The resin is capable to sustain pressure up to 4885 psi and thus making it a likely candidate for HPHT wells. It is highly resistant to chemical corrosion and is non-rusting thus enhancing the life of the completion. The complete drill string design would be discussed in detail providing the next 21st century tool for the drilling industry to drill through any possible formation encountered. Introduction Drilling has been the most influencing factor over the years in oil industry as it judges most of the technical and economical aspects of the project. Various methods have been enlightened to improve the efficiency of rock cutting with advancement of technology and experience over the last few decades. Rotary drilling is still the most satisfactory method although there are some disadvantages which have been overlooked due to its simple applicability. Immense research has been done on the removal of rock with the help of the application of laser assisted drilling by melting the rock several thousand feet below the surface of earth. Initially this technique was not found to be economical but over the years, the demand of oil and gas has been increasing constantly which means a faster and efficient technique for drilling has to be implemented.

Abstract The Magnus platform, UK Northern North Sea, has been producing since 1983 with all 20 original slots now occupied. Additional infill and ERD production targets were identified and a means of access was required whilst maintaining base field production. Platform modification was selected due to significant commercial advantage over alternative developments. The Magnus jacket was modified to permit running of four additional large conductors into which two smaller casings could respectively be installed. A tapered jacket profile necessitated preinstalled conductor guide frames to build to 4° inclination at seabed; requiring initial use of the large conductor as a conduit for drilling assemblies. Custom manufactured and specialist equipment was designed and procured to enable successful under-reaming to 54" and installation of 46" conductor. Drilling assembly design and initial pilot-hole profile were deemed critical to subsequent success in running rigid open-ended 46" conductor. Well-critical structural cement was pumped to seabed via world-first use of a 16" inflatable packer and inner string. World-first unguided installation of two 18–5/8" casing strings inside 46" conductor was then achieved. The 18–5/8" casing strings were cemented in place using light cement to preserve (shallow) casing shoe integrity. High resolution multi-shot gyro surveys and a newly developed 'gamma-wipe' survey technique were utilised to obtain critical 18–5/8" relative shoe orientation information prior to subsequent kick-off. Two wells were successfully batch-set to the 13–3/8" casing shoe via one conductor. To mitigate anti-collision risk, safety valve location has been deepened to permit future drilling of all planned trajectories from the new conductor slots (given shallow close approaches). Modification of existing wellhead technology for close proximity has proved successful. Access to additional Magnus resources via an otherwise full template has been delivered by this Conductor Sharing Wellhead (CSW) technology. Introduction Magnus is the most northerly presently operated field on the UKCS (Fig.1). Discovered in 1974, first production was established in 1983. Continual field development has resulted in over 90 penetrations including exploration, appraisal and development wells.

Abstract A working window of opportunity only presents itself from April to mid-September in the turbulent Atlantic waters off the northwest coast of Ireland. When this window opened in Spring 2006, Shell E&P Ireland Ltd began operations to evaluate newly acquired assets in the Corrib field dry-gas subsea development. Prior to acquisition, five wells had been placed in suspension, pending construction of the necessary subsea and onshore infrastructure. Shell had previously determined that only three wells were viable candidates for completion during the current season and commenced operations when the S711 semi-submersible arrived on location in April. The clock started ticking on favorable weather and time quickly became a crucial constraint issue. The project hit a critical mark when a leak was discovered in the 9–5/8 in. production casing on one of the early wells entered. With time running out, Shell approached Enventure to engineer a practical solution that was required within a period of six weeks. Possible solutions for recovery were identified and analyzed before the project management team decided on using solid expandable technology. The solution for this well needed to deliver a production casing string that effectively sealed off the hole. To accomplish this requirement with expandable tubulars, Shell decided to use the Enventure system elastomers for the gas-tight integrity, which required qualification. In approximately six weeks, Enventure and Shell planned and implemented the appropriate tests, coordinated logistical maneuvers to expedite expansions to create the test specimen for qualification and successfully installed the actual system in the production well. This paper will discuss the process used to bring the project to fruition within a tight timeframe. Details will include issues considered, ramifications of possible options, challenges of the operating conditions and circumstances and content and results of the qualification program. This paper will also discuss the philosophical approach of generating a workflow to successfully achieve the stated goals in a short amount of time. Introduction In June 2006, Shell encountered a leak in the 9–5/8 in. production casing in one of its West Atlantic, deepwater subsea wells. The dry gas well is capable of producing in excess of 100 million standard cubic feet per day. The leak, identified after taking the well out of suspension, disappointed the project team as progress to run completion and ultimately put the well in production came to an abrupt halt. After eliminating the possibility of it being in the liner lap, the leak was chased to approximately 1,500m (~4,920 ft) using a DLT packer. In order to progress the campaign, Shell temporarily suspended the well to decide whether to attempt to regain integrity of the production casing or put the well in long term suspension for possible abandonment. After putting the well into suspension, management considered the following four options to address the situation: Abandon and re-drill the well Cut and pull the 9–5/8 in. casing Use a tie-back liner solution Install a solid expandable cased-hole liner system Because of time restrictions and the lack of equipment availability with three of the options, Shell chose the solid expandable tubular solution that could be tested, delivered and installed in the timeframe and provide the most robust engineering solution. Although Shell had decided on a definitive approach to the casing leak, several issues needed to be addressed before the solid expandable solution could be implemented. The elastomer technology on the expandable liner selected, specifically Enventure 's 7–5/8 x 9–5/8 in. solid expandable system, had been used in similar scenarios 1,2,3,4 but was not qualified to Shell standards. Another issue identified was the lack of gas-tight connections for any expandable casing. Also, several load cases were outside the expandable envelope. Shell and Enventure personnel used innovative engineering to confront the obstacles and to successfully resolve the technical challenges.

Abstract Moving rigs across North Sea borders is costly and inefficient. Thus, area regulators requested IADC's N.Sea Chapter cooperate on a Northwest European HSE 1 Case. The framework illustrates substantial drill crew input to identify hazards, assess risks, and maintain controls based on a decade of experience in stringent HSE regimes. Introduction Since the early 1990's, drilling contractors in Europe faced the challenge of crossing coastal State boundaries in the North Sea and dealing with differing regulatory regimes. This inefficiency was costly and often acted to the detriment of good safety performance. NSOAF MOU Work Group 2 was aware of these issues as early as 1996 and in 1999 requested that IADC North Sea Chapter (NSC) investigate producing a more cost-efficient and consistent HSE case template to assist in free movement of Mobile Offshore Drilling Units (MODU's). There was also an intent to raise the bench mark for HSE case quality and focus by updating the IADC North Sea Chapter document Preparing a MODU Safety Case , Vols 1&2, 1992 [1]. Summary of the document The 144-page document entitled North West European HSE Case Guidelines for MODUs [2] (NWEHSE Case) produced by IADC NSC comprises six parts and four appendices. It adheres to a compact standard format which allows questions to be answered in a crew's own words, with the company philosophy in mind. This paper shows some of the ways the guidelines are of value to operators and regulators by giving them assurance drilling contractors can use the insights of their crews to identify hazards, assess the risks, and install sufficient appropriate controls, i.e. emphasize qualitative risk assesssment. It will illustrate good practice and experience with this method of analysis from over a decade of experience. It has already proven itself as the Netherlands' regulator has stipulated the NWEHSE Case as the strongly preferred format. The North Sea Chapter as an engine of accomplishment The NSC has gradually become a means for area drilling contractors to accomplish their specific local objectives. Why has the NSC developed in this way? It seems it stemmed from necessity, willingness to cooperate, and the European approach of the drilling contractors having their head offices in the region. In 1992, the NSC produced a Safety Case Template [1] in response to the UK HSE's issuance of the Safety Case Regulations [3]. Drilling contractors, nominally intense competitors, banded together to develop a common starting point for developing safety cases for acceptance by HSE. NSC repeated this exercise in 1996 in response to the DCR Regulations [4] by producing Guidelines for Preparing a MODU Verification Scheme [5]. This document demon-strated a substantial portion of the requirements of the UK for verification are covered by flag State and classification society rules. We are given to believe this document caught NSOAF's eye. The NSC carried out other projects in numbers that dictated the development of a yearly project budget. This was made possible by the presence of permanent NSC staff, a Director, Office Administrator, and Administrative Assistant. With this staff, project tracking and cost control was possible.

Abstract There are a number of developments where new dry tree platform drilling rigs are specified. In some cases the geographical location, number of wells to be drilled and the ongoing life of field intervention requirements lead to the need for a permanent rig installation. The majority of permanent offshore rig installations has in the main been confined to the N. Sea region. As a result there is a significant experience base related to how the rig interfaces with the production platform and the lessons learned from operations that can be used to ensure appropriate drilling facilities are designed. Compared to the overall project or field development cost the initial capital cost of the rig is usually a relatively small proportion of the project. However, when the operational cost of drilling and maintaining the wells is included it can account for between 30 - 40% of the overall development costs. Therefore the actual operational efficiency of the rig will have a significant impact on the overall project economics. During the initial stages of a project it is essential that the project requirements such as the regulatory requirements, well designs, platform interfaces and philosophies and the appropriate levels of mechanisation are understood. This allows a clear definition of the rig equipment selection and functionality to ensure the rig is not over or under rated in order to allow the drilling team to provide a rig that delivers the expected operational efficiency. Introduction For large EPC Projects where permanent drilling facilities are deemed the best solution it provides the operator a tremendous opportunity to get the ideal rig for the job. By extracting the full value of this opportunity the operator will be able to realize HSE and operational efficiencies and hence reduced wells costs. Production platform drilling rigs have different economic drivers compared to MODU's and can be designed for the specific well requirements. After the initial drilling campaign the rig may move to intermittent workover and sidetrack operations. The drilling equipment and utilities can be selected and designed to suit the programme. However, typically this opportunity has not been fully realized as in the past the approach to rig sizing has often been superficial and rigs tend to be incorrectly rated for the intended duty. The well requirements and maximum depth capability are seldom clearly defined as a result equipment tends to be over specified. There can be a tendency to develop rig specifications without operations and specialist input and base them on what was seen on previous rig designs. In some cases these may be based on arrangements that are not applicable to the planned platform operations, e.g. the newer deepwater drillships, which have numerous capabilities such as dual activity systems. If applied to a platform rig with the constraints of weight and deck space these systems may cause more problems than they solve. This often leads to drilling being the least defined of all the facilities of a production platform going into detail design, greatly increasing the risk of cost and schedule overruns to the project as well as the early performance of the rig. Yet the overall drilling costs including engineering, design, construction and drilling operations may well account for 40% of the total project cost. Similar inconsistencies appear across projects. Generally there is a reluctance or failure to recognize the value of placing operational drilling staff and specialist rig designers on the project teams during the early concept definition phase. This is evident by the disproportionate numbers of topsides engineering personnel to rig design personnel in the early stages of design.