We all identify the need to integrate climate change into corporate strategy, with a profitable Carbon Capture Utilisation & Storage (CCUS) business model the elusive goal. Today, CCUS forms 10% of the R&D program of Total, a founding contributor to the OGCI Climate Investments fund. Here in the North East of Scotland, UK and Scottish Governments, along with project developer Pale Blue Dot Energy and Total are providing match funding to the European Commission’s Connecting Europe Facilities fund to progress feasibility work on the Acorn CCS project. As society continues to drive an expectation beyond hydrocarbons, what proposal might the North East of Scotland offer in response? To meet ambitious emissions reduction targets, the UK must envisage radical changes to the energy economy. Already affecting power generation, these changes must drive further into transport and domestic/industrial energy consumption. Two technologies which may play a part in the decarbonisation of the UK energy business are CCUS and the use of Hydrogen as an energy carrier and energy store, with several studies showing that clean hydrogen is potentially the lowest cost route to meeting UK emission targets in multiple sectors. This builds on the UK’s world class gas network infrastructure, which can be repurposed to avoid becoming stranded, avoiding the enormous expense of increasing the capacity of the electricity transmission network, much of which would lie idle during the summer. The UK gas network carries approximately three times more energy than the electricity network, at one third the unit cost to consumers, and meets winter peaks that are five times greater. Different to previous CCUS projects, and having the Oil and Gas Authority (OGA)’s first carbon dioxide appraisal and storage licence award, ACORN is an opportunity to evaluate a brownfield CCUS solution to capture, transport and store post-combustion CO 2 , combined with an upside through emerging pre-combustion CO 2 capture technology relating to the production and sale of bulk hydrogen produced from natural gas with a zero-emission target. Located at the St Fergus Gas Terminal – an active industrial site where around 35% of all the natural gas used in the UK comes onshore. ACORN is designed as a "low-cost", "low-risk" CCUS project, to be built quickly, taking advantage of existing oil and gas infrastructure and well understood offshore storage sites. The Acorn Hydrogen project undertakes to evaluate and develop an advanced reformation process which will deliver the most energy and cost-efficient industrial hydrogen production process whilst capturing and sequestering CO 2 emissions. An initial phase offers a full-chain demonstration project, an essential step toward commissioning the concept and subsequent commercialisation of large-scale CCUS and Hydrogen deployment in the UK. SPE Offshore Europe represents an ideal opportunity to update both the region and industry on results, observations, and conclusions with respect to the evolving development architecture, selected process technologies, Government and gas transportation regulatory engagement as this, the leading Scottish CCS project continues its journey toward a final investment decision.

The Shetland Gas Plant (SGP) is a 500 MMSCFD capacity gas plant located at Sullom Voe on the Shetland Islands. It receives reservoir fluids, via twin 143km multiphase flowlines, directly from the Laggan-Tormore fields which are located 125km north-west of the Shetland Islands in approximately 600m water depth. Fluids arriving at the SGP are separated into gas and liquid phases. The gas is processed and then exported to St Fergus gas processing plant via the SIRGE and FUKA pipelines. The liquid phases are separated and the condensate is exported to the BP Sullom Voe facility for stabilisation and export by tanker. The aqueous phase (rich MEG) is regenerated at SGP to produce lean MEG for reinjection subsea, a by-product of the regeneration process is produced water. The produced water is then fed to the Effluent Water Treatment Plant (EWTP) for processing prior to being discharged to Yell Sound via a 3.75km pipeline. The effluent water treatment package was designed by SUEZ Eau Industrielle (patented design). The effluent water is required to meet strict discharge specifications as part of the operating consents, e.g. Biological Oxygen Demand (BOD), Chemical Oxygen Demand (COD), MEG, Benzene, Total Suspended Solids (TSS), etc. The Effluent Water Treatment Plant (EWTP) consists of 3 stages of treatment: physical, chemical and biological. The physical treatment contains; – A Corrugated Plate Interceptor, which uses gravity to separate the free oil from the produced water; – A Stripping Column, which removes BTEX (Benzene, Toluene, Ethylbenzene, Xylenes) and volatile hydrocarbons entrained in the water via transfer to fuel gas. The chemical treatment contains; – A Dissolved Air Flotation Treatment Unit, to remove any residual free oil and TSS utilising flocculants and coagulants. The biological treatment contains; – A Biological Aerated Flooded Filter (BAFF) Unit, which is an aerobic biological filtration process whereby a biomass (bacteria) give biological degradation of soluble organics while simultaneously removing suspended solids via filtration. The biological process removes the remaining MEG and BTEX and has the ability to handle varying loads of COD and BOD. The EWTP has been in operation since the start up of the SGP in February 2016. The paper will discuss: – The initial challenges faced during start up and the first year of operation and how these were overcome; – Current operation of the process including ongoing challenges and areas of success.

Remotely Operated Vehicles (ROVs) are complex systems that incorporate electronics, electromechanical assemblies, computing equipment and their associated software systems, structural assemblies, hydraulics, and a variety of commercial off-the-shelf components and accessories. ROVs operate in the most severe of environments, yet they must be highly reliable systems. One necessary element in the design and manufacture of a reliable ROV system is a rigorous qualification test program to prove the existence of a robust design. This paper discusses the design of the qualification test program for a new ROV product line, how it was executed, and how the test results were used to meet and exceed project reliability design goals.

Oil and gas reserves are in abundance, yet turning these into production cost-effectively is proving a challenge. The status quo is challenged and parties across the value chain are looking to bring best practices from other industrial sectors that have embraced innovation differently. Returns have been falling and the number of large capital projects is stretching operator capabilities beyond their limits. Despite several peripheral cost-cutting efforts, the industry continues to suffer from major cost escalation and schedule delays. Over the past years, the oil and gas industry has experienced a significant increase in upstream development capex and costs have more than doubled in the 2005-2013 time frame. The recent sharp oil price fall has exacerbated challenges and the need to execute differently. This paper will summarise the causes of this escalation, also focusing on what best practices can be applied from other mission-critical industries. Topics discussed include how to optimise and improve specifications, standards and qualifications, supplier ecosystems and project execution. Description and contrasts will be given on: How industry participants collaborate and manage major projects in other industrial sectors How these practices can be applied to an oil and gas context to improve project delivery and cost The scope includes the entire upstream oil and gas sector, but examples will be taken from other industrial sectors. This paper studies specific practices that other industries have adopted and to attempt to understand how the oil and gas industry could internalise them.

Abnormal annulus behaviour is an indication of a well integrity problem. Monitoring annulus pressure trends is a method of identifying abnormal behaviour, thus highlighting potential integrity issues. When a well is confirmed as having an annulus integrity issue one mitigating measure that may be put in place is to increase the pressure monitoring requirements associated with the well for possible escalation. It is recognized that the sooner an integrity issue is spotted the more opportunity there is to respond in an adequate manner by putting mitigating measures in place. For this reason the review of wells that do not have known integrity issues is equally important as any deviation from a normal or expected pressure trend may indicate the onset of an issue that could otherwise go unnoticed for some time. Therefore systematically analyzing all annulus pressures from the entire well stock is a powerful tool in the well integrity management toolbox. Carrying out the generation of annulus pressure plots for performing these analyses can be a laborious and time-consuming task, especially when the well stock contains more than say 50 or 100 wells. Therefore to carry out systematic reviews of all wells can a challenge. To aid in overcoming this challenge a tool was developed to automate the generation of annulus pressure trends, either by selected well or by selected asset. For each well a set of three plots is generated as standard. Each plot has a time axis and a pressure / temperature axis with scales that can easily be modified to zoom in for a detailed picture or to zoom out to get a good overview. Implementation of the tool has resulted in an increased surveillance of the annulus pressure trends. Depending on the asset, weekly or even daily reviews of all wells are now done. As a result the understanding of the integrity status of the entire well stock has increased considerably. New well integrity issues that result in a change in annulus behaviour are now detected much earlier than before. It has also resulted in the discovery of some integrity anomalies that were previously not recognized as such.

Introduction: The assessment of suppliers became recently a critical step in the supply chain organizations. Indeed the process is not new but the importance of assessing candidates tremendously increased due to several factors: Local content requirements, variety of local technical regulations, Language and cultural issues, relative weight of the Asian continent in the global worldwide production capacity all need be taken into account simultaneously in an assessment campaign. The conclusions indicated in this document result from the work done on more than 150 sites, 30% of which in the republic of Russia 60% in China, 10 % in other countries such as India, Turkey USA and Europe. As far as Russia is concerned reference is made to Total Russia willingness to perform in depth assessments of local resources in view of the Kharyaga Phase 3 development project. Supplier assessment, how to proceed : main steps * A first aspect of this Quality assurance tool is that the assessment is performed for a given plant / factory or site. Not of a Company or Brand, this results from the need to evaluate the design, purchase, fabrication, test etc.. facilities. Some examples of assessment led to the conclusion that two neighbouring buildings were fully acceptable for one of them totally unacceptable for the other. * Preparation Questionnaire: obtaining a detailed pre-visit questionnaire is often seen as a mandatory preliminary step. From experience and mostly due to specific, non western, cultural aspects (Asia, Russia) it is difficult to obtain these documents before the visit (long chain of approval, decision maker "on a trip", responsibility associated with signing such a complete document). The recommendation of the author is that the Site dossier while being a necessary complement to the assessment audit can be managed separately and should not be considered as a step needed before the visit. * Assessment preparation and methodology: Assessing a site needs be done versus "something" what does one wish to assess? The capacity to manufacture? Against which standard (local / international, both)? What production capacity required for a given project / item ?. The set of standards and technical specifications have to be clearly identified during the preparation. In the case of the Kharyaga project there have been up to 6 sets of specifications to be considered for a given product (design, type of flanges, temperature ratings, test procedures …). This demonstrates the paramount importance of creating a dedicated technical check list for a given plant / project / client. From experience this step is seen as impacting most the quality of the deliverable (report). From our experience 70% of the reports non conclusive were the result of inaccurate or incomplete technical check lists. Along with this situation let us stress the need for the assessing party to be familiar with "local" regulations since most of the calibration processes are covered by these rules (Gost, Technazor, State Directive).

Abstract For a number of years the E&P industry has sought to prove the feasibility of monobore expandable liner extensions as an advantageous alternative to the "telescoping" nature of conventional casing designs (Figure 1). Collaboration between an operator and a supplier has produced a system that accomplishes this purpose for a 9 5/8" or 9 7/8" parent casing string to maintain 8 ½" drift post-expansion. Utilization of this well construction product can be planned as either a basis of casing design, or as a planned contingency. The objective and value of the monobore extension enables the operator to implement one more casing string, without reducing hole size. As a basis of design, this technology provides the option for the operator to begin well construction with one smaller casing size, which may drive down costs significantly, especially in high cost drilling and "floater" drilling programs. As a contingency, the product can isolate trouble zones such as reactive shales, sub-salt rubble zones, and low fracture gradient transitions without being forced to reduce casing size and subsequent drilled hole size. This capability can yield immeasurable benefits when retaining hole size means being able to either evaluate the reservoir as fully as desired, or to produce wells at rates deemed commercially necessary and optimum. The technology development collaboration produced a one-trip, top-down expansion system that was developed, tested and proved the technical feasibility of the expandable monobore liner extension concept. This paper details: > Key System Features and Benefits > System Development Downhole recess shoe qualification Casing selection qualification Zonal Isolation Requirements Monobore liner extension selection, one trip system > Field Trial Pre-planning Expansion Process Post deployment results > Planned Contingency Applications > Casing BOD (Basis of Design) Applications > Summary Introduction In September 2006, BP and Baker Oil Tools achieved an industry milestone with the successful installation of the world's first true monobore expandable liner extension system, in a commercial well in BP's Arkoma asset in southeast Oklahoma, USA. Key system development milestones ( Figure 2 ) and key challenge milestones (Figure 3) are illustrated chronologically along with the associated responses. The successful installation and expansion of the 8.0-in. (pre-expansion) linEXX TM solid expandable system below the 9 5/8-in. parent casing proved the application of solid expandable tubulars to enable operators to plan and drill deeper wells with larger hole sizes at the reservoir. Earlier in 2006, the successful installation of recess shoes in four North Sea wells set the stage for future additional monobore contingency applications of solid expandable tubulars to isolate trouble zones, including reactive shales, subsalt environments and low-fracture-gradients, and then drill ahead without having to reduce critical hole size.

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.

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

There are many produced water deoiling hydrocyclone systems operating today that do not meet the required overboard discharge water quality specification. Common reasons for this include long term changes in field conditions, adverse interfacial chemistry (generally caused by a "cocktail" of chemical additives), small inlet drop sizes or sub optimal deoiling hydrocyclone liner types (e.g. large diameter geometries). The most common solution to these PWT problems is to implement a chemical injection programme which although can be successful, has a high operating expenditure requirement and can often be more harmful to the environment than the oil it was designed to remove. There is also a general industry initiative to minimise the use of production chemicals in a response to the belief that new legislation governing toxic chemical and dissolved hydrocarbon discharge is imminent. This paper describes a technology which has been developed by Cyclotech to significantly improve the performance of produced water deoiling hydrocyclone systems without resorting to chemicals. The concept is based on pre-coalescing the inlet oil dispersion to produce a coarser drop size distribution prior to hydrocyclone entry. Field trials have demonstrated that the technology can improve the deoiling performance by as much as 220%. It requires no external control or power source; displays a marked insensitivity to solids fouling and can be easily retrofitted into existing systems without the need for any major vessel or pipework modifications. The technology is aimed at existing systems which do not meet discharge specification, or require excessive chemical dosing to do so and at new-build systems by extending the applicability of hydrocyclone based solutions to heavy oil, condensate and other historically marginal applications.

Abstract A novel technique which offers scope for significant rig time savings has been successfully applied in the Brent Field in the UKCS. This technique involves running a memory production logging string containing spinners and pressure/temperature gauges in conjunction with electric line perforating guns. It has been applied in three Brent wells to date (two producers and one injector). In each case MPLT data was acquired both before and directly after firing the guns, without having to pull out of hole. Full memory data recovery was achieved for all runs; data quality was comparable to that of typical electric line PLT's. The three runs were performed with varying applications in mind: determine the extent of crossflow prior to obtaining a fluid sample, perform leak investigations on recently set Casing patches and determine gross production/injection splits. Each of these applications was carried out successfully. In addition, six to eight hours of rig time were saved in each case. This confirms the potential for significant cost/time savings, particularly if the technique is extended to coiled tubing operations. Similarly, the technique could be extended to include other PLT sensors and/or fluid sampling tools. Although this technique is unlikely to replace the logging of normal electric line PLT's, we believe that it holds great promise for fit for purpose production logging applications which don't require real time intervention. Introduction By applying tried and tested technology in a novel fashion, significant rig time savings can be achieved. An example of this is the application of standard memory production logging technology while perforating. Recent experience in the Brent Field in the UKCS has shown that it is feasible to run both memory pressure/temperature gauges and memory spinners below perforating guns and thus obtain MPLT information before and after perforating without pulling out of hole. By combining the surveys with the perforating operations, rig time can be saved without sacrificing data quality. In this paper we will discuss the technical details of the tools used and outline the results of the three operations performed to date. Tool specifications A schematic of the MPLT tool string as run in Brent is shown in Figure 1. Combined tools are, from the bottom: fullbore spinner (FBS), centraliser, in-line spinner (CFS), pressure/temperature sonde (SPLS), memory downhole recorder (MDR), adapter, sapphire crystal gauge (SLSR) and shock absorber. Tool selection was based on two criteria: robustness and reliability. Robustness is required because the tools are exposed to the shock of the gun detonation. Reliability is particularly important as, being memory tools, there is no means of knowing whether or not they have functioned properly until they are recovered at surface. It is for this reason that, in order to increase the chances of full data recovery, two spinners and two pressure/temperature gauges were run in tandem. The FBS and CFS that were used are identical to the spinners used in field-proven electric line PLT strings. There are several sizes available to cater for different casing sizes and flowrates. The specifications of the spinners used can be found in Table 1. The SPLS and SLSR gauges are two different types of pressure/temperature gauges. The SPLS consists of a Quartzdyne sensor, and is run in conjunction with the MDR (see below). The SLSR consists of a sapphire crystal sensor, and is a stand alone memory gauge (i.e. with its own recording facility). It is run both on slick line and during DST/TCP operations (in a gauge carrier above or below a packer). Specifications of both gauges are summarised in Table 2. P. 535^

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

Background There is a growing awareness that Whole Life Costing (WLC) principles offer benefits in assessing the coSt of projects, facilities and equipment before commitments are made. As a management tool they provide for options to be compared and for system cost-effectiveness and value-for-money to be optimised. Properly understood and applied, WLC principles provide a powerful analytical capability: coupled with logistic support and economic analysis techniques they provide the means by which cost drivers and dependencies can be identified, targeted and more effectively managed. Current Status Although individual operators have started to apply WLC principles as part of their own development studies, advancement has been constrained. This is mainly due to different interpretations of WLC methods, techniques and requirements. In order to develop a common and consistent WLC methodology specifically for the oil and gas industry a Joint Industry Project (JIP) has been formed by a number of operators, contractors and vendors. The JIP is utilising a consultant (BAeSEMA) in the development of WLC techniques and guidelines implemented and matured in the UK defence and aerospace industries. The skills and experience of the participants will allow the framework and WLC techniques appropriate to specific project phases to be established and these techniques are being tested through two case studies. The WLC guidelines arising from the JIP are designed for use by organisations to assist in the evaluation of and management of assets and will supplement existing evaluation methods. Whole Life Cost Approach Figure 1 shows how WLC methodology fits into the project life cycle. Benefits The application of WLC methodology offer the flowing benefits: Development of common objective WLC criteria for use by operators, contractors and vendors, against which business performance can be measured. Objective criteria that take account of revenue, Capex & Opex and against which business transactions can be managed and optimised. Reduced ownership costs by consideration of procurement and operating costs during design. Assistance to vendors in designing more cost effective equipment by establishing appraisal criteria. A mechanism to feedback experience from mature assets. Development and application of analysis techniques that are appropriate in detail and scope to project phases. A tool to align the objectives of project and operations staff. Programme The initial twelve month programme commenced with a series of interviews with JIP participants which were designed to capture best industry practice & experience and the participant's principal requirements. The data gathered has helped to formulate the structure and content of the guidance documentation. Work is now underway to develop the guidance documentation in conjunction with the JIP participants. In addition to the guidance documentation, two case studies have commenced that will test the adequacy and validity of the WLC guidance in specific areas. One of the case studies is based upon facilities option selection and shall investigate floating production and tie-back options together with sub-options for with and without water injection and/or gas lift. The second case study is designed to establish the whole life cost of a number of process options within a not normally manned facility. P. 239

Abstract Shell Expro was confronted with an unacceptable high cost attributable to drillstring failure in 1991. One specific drilling unit experienced 5 failures within a two month period. The cost of these failures alone was estimated to be more than 2 MM. A Drillstring Failure Prevention Quality Improvement Project (QIP) was instigated with the objective of reducing drillstring failure frequency, and hence Non Productive Time (NP') costs, by at least 50% in 2 years. This goal has been achieved by carrying out detailed autopsies of failed components to determine 'root cause' of failures. Analysis of the root causes and symptoms resulted in a series of improvement strategies which have been implemented to successfully reduce drillstring failure. NPT costs associated with drillstring failure have been dramatically reduced from 6.5 MM in 1992, to less than 1.0 MM in 1994. Introduction Starting in April 1992 the QIP, using Juran problem solving methodology was created to tackle drillstring failures in Shell Expro's North Sea operations. A multi-disciplined team was formed to pursue the drive towards continuous quality improvement. Prior to the start of the QIP, drillstring integrity failures accounted for 6.5 MM per year with 0.67 incidents per 10,000 ft of hole drilled, and an average ratio of twist-offs to total failures of 0.64. To reduce drillstring failure costs the following strategies were implemented: Inspection, Design, Procurement, Personnel Awareness, Contracts, and Operations. These strategies and their implementation are discussed in this paper. By the end of 1994 Twistoffs had been reduced by 75%. Total failures (washouts and twist-offs) had been reduced by 55%. This has resulted in a cost saving of some 8.5 MM to year end 1994. This success has attracted the interest of not only other Shell operating companies, but also other North Sea operators. Definition of Project Boundary Limits A diversity of failure types contributed to the individual events which led to NPT. Electronic failures in MWD systems as well as bearing failures in mud motors/turbines both contributed to the problem, although from very different root causes. It was clear that these problems could not be tackled in the same way as the mechanical failure of the connections on BHA components, or drillpipe tubes and tool joints. The QIP team therefore decided, for this reason, to 'park' problems that were specific to mud motor/turbine and MWD and concentrate on BHA/Drillpipe failures. For the purposes of this project the drillstring extends from the drill bit connection up to, but not including the top drive or kelly. Failure of drillstring integrity arises when there is a failure in the pressure containing conduit. This usually is manifested in the form of a catastrophic separation of the drillstring (twistoff) or a leak in the fluid circulation path through the drillstring (washout). Failure costs include IPT and equipment lost in hole, but do not include deferred production revenues. As part of the QIP team's learning process, a literature search was carried out to establish what work had already been done within the industry and where this could be of use to prevent unnecessary repetition of work. The QIP team suspected that deficiencies may exist in the way in which drill string components were acquired. An understanding was therefore required of the 'as is' process. This information was obtained by 'interviewing' individuals across the departments in Shell Expro and contractors, who are involved in buying, renting, certifying and maintaining drillstring components. This information was flowcharted and showed what specifications were requested and by whom, how compliance was checked and whether Shell Expro's own standards were met. P. 43

Abstract Fife is a small offshore field that is remote from existing infrastructure and offers the potential to recover some 34 mmbbls of 34 API crude oil over an anticipated life of 4 years. Capital investment in the full field development facilities cannot be amortised to provide an economic development in this timeframe. This paper addresses the application of leased production facilities to enable commercial development of the reserves and examines the relationship necessary between oil company and contractors to achieve a successful project. Background Fife is the most southerly oil field yet to be developed on the UKCS sector of the North Sea. The field located in blocks 3 l/26a, 27a, 39/1 and 39/2 lies adjacent to the UK/Denmark median line, 300 miles due east of Edinburgh in a waterdepth of 226 feet (Fig 1). Licensees of this acreage are Amerada Hess Limited (Operator) and Premier Oil plc and their equity interests in Fife are 85% and 15% respectively. In March 1991 the Fife discovery well 3 l/26a-9a was drilled, tested, suspended and a 3D seismic survey run to assess the possible extent of the reservoir. At this time blocks 3 l/26a and 3 l/27a were unlicensed and an appraisal well programme was not considered practical. After evaluation of the results from the discovery well test and seismic programme the Licensees submitted an 'out of rounds' application to the DTI for the two open blocks. The blocks were awarded in October 1992 and a two well appraisal programme began shortly thereafter. Given the experience of the Licensees in the successful development of the nearby Angus field (10.7 mmbbls) using the FPSO Petrojarl 1, owned by Golar-Nor, it might naturally have been assumed that a copycat development scheme was appropriate. However, it was clear from the early work performed by the sub-surface team that the reservoir would not have comparable qualities to Angus and that other development options would require to be assessed. In October 1993 Amerada Hess visited the floating production unit 'Deepsea Pioneer' which was for sale having just ceased production from the nearby Argyll/Duncan complex operated by Hamilton Brothers. The unit was considered suitable for a fast track development of Fife, but unfortunately before a deal could be done it was purchased by BHP for use offshore Vietnam. The Appraisal Programme and Results With the limited potential reserves base it was essential to ensure that all work performed in the appraisal/development of the field be cost effective. The appraisal programme was therefore based on (a) the minimum number of wells to confidently define the extent and physical properties of the reservoir and (b) the potential to re-use appraisal wells within any development scenario. A clear understanding of the reservoir and its production mechanism was essential input to the economic modelling that would be used to determine the commercial viability of field development. The questions to be answered were:- 1 What is the projected deliverability from the reservoir? 2 For how long can the plateau rate be maintained? P. 207

Abstract We are expecting that in future developments the smaller and marginal oil and gas fields will dominate the offshore oil and gas business. Engineering contractors will be more heavily involved at the early stages of such development, and in particular contractors will be expected to provide innovative technical and commercial solutions that can make more of the fields commercial. We believe that those contractors that have a wide technological foundation, and a significant engagement in providing new technical concepts, are best prepared for the future challenges. We also see new contract and cooperation models emerging between client and contractor, and the development of incentive schemes that secures the commitment of the main contractors to the overall economy of each project. Introduction After 25 years of activities in the Norwegian oil and gas business approximately 5400 million tons oil equivalent recoverable resources have been discovered. The current producing fields together with fields under development accounts for 60% of these resources. 30 new discoveries were made over the last 3 years (1990–1992), and 30% of the exploration wells drilled in 1992 have proven hydrocarbon resources. On the Norwegian continental shelf, the North Sea area still seems to be most attractive with regard to potential resources. New discoveries are, however, significantly smaller than those producing today. The challenges for the Norwegian oil and gas industry today are: * Development of smaller fields by cost effective field development concepts. * Reduce operating cost. * Enhance recovery from producing fields. * Attract oil company financing for new projects which compete for funds in a global oil and gas market. We believe that the continental shelf of the UK and Norway will still be attractive for investment over the coming years. An important criteria for consideration in this assumption is the short distance between the resources and the important energy market of Europe in conjunction with the political stability here compared to some of the major international competitors. To develop the potential available within the North Sea area, it is becoming more and more important to establish strategies that give high economic efficiency within all phases of oil and gas development. Utilization of existing infrastructure in combination with new technology and new contract models is therefore required. There will be a strong focus on the Engineering Contractor in developing these potentials. In particular the industry will expect - innovative technical solutions - efficient contract execution - new client/contractor relationship - through life cycle consideration P. 441^

Abstract This paper decrihes how Conoco planned and implemented downhole injection of oil contaminated drill cuttings on the Murdoch development project in sector 44/22 of the Southern North Sea. Five wells were predrilled through a template from December 1991 to March 1993. The first well, 44/22 D-1, was drilled as a producer and was also designed and used as the injection well for all subsequent wells. Injection was conducted via the 13-3/8"×9-5/8" annulus. The casings were designed to accomodate the injection loads. The injection interval was the Triassic Bunter, a sand/shale sequence between 6200'-7000'TVD, bounded by 200' of salt above and 1500 of shale below. Topside equipment consisted of a prototype Cuttings Processing Package (CPP), a screw conveyor, a slurry storage tank and a small triplex pump. INTRODUCTION UKCS regulations prohibit the discharge of oily drill cuttings, but exemptions can be obtained which limit oil on cuttings to 100 gm/kg by weight. As of January 1994, all exploration and apraisal wells will have to meet a 10 gm/kg limit and effective January 1997 all wells will have to meet the 10 gm/kg limit. For technical and economic reasons, Conoco chose to proceed with the use of oil based drilling fluids on certain projects. With the inevitable legislative constraints of the future the options for disposal of oily drill cuttings were evaluated. These included boxing and hauling the cuttings to shore for landfill disposal, cuttings wash systems, and cuttings reinjection. It was quickly decided that landfill disposal was not an option. This decision was based on safety (handling the boxes), weather (down time) and the increasing number of landfill closures. It was decided that bringing this environmental problem ashore was not environmentally or economically prudent. Cuttings wash systems were evaluated and proven to be ineffective at reaching the ultimate legislative limits of 10 gm/kg. Cuttings wash systems could only provide a reduction to 40-50 gm/kg and handling the dirty wash fluid compounded the problem. A process of slurrification and re-injection of oil base drill cuttings was examined and feasibility studies were initiated. It revealed that this option was economically as well as environmentally viable. The task at hand was then to identify the candidate or candidates for utilisation of cuttings reinjection. It was recognised that this would be the first time this technology would be employed on the UKCS for environmental conservancy. With this in mind a site was selected that could benefit from this technology, but also the project had to be able to economically justify this technology. In early 1991, Conoco evaluated the economic feasibility of the Murdoch development in the Southern sector of the North Sea (Fig 1). This project was planned as a 9 well development with 6 wells predrilled prior to jacket placement. Scheduling problems with completion of the drilling phase in time for first gas became of paramount importance. Depth, degree of difficulty, high angle wells (Fig 2) and the need for increased rates of penetration demanded that oil based fluids be used.

Abstract This paper describes the design and prototype testing of a 15,000 psi, next-generation surface wellhead for jack-up drilling. The system features metal-to-metal annulus seals and an adjustable mandrel hanger which allows space out and permits controlled pre-tensioning of casing strings above conventional mudline suspension systems. Introduction Jack-up wellhead systems are of conventional surface types that originally suspended the full casing strings on slips. When jack-ups moved to deeper water and greater well depths, mudline suspension systems were developed to suspend the casing weights at or below the mudline and provide a disconnection point. Surface wellhead systems provide a disconnection point. Surface wellhead systems were not redesigned at that time and the slip-type conventional wellhead remains the norm to this day. There are numerous operational disadvantages, the most obvious is the need to set slips at the surface above an absolute landing shoulder at the mudline hanger. The slips have to seat at the correct position for the desired amount of pre-tension to remain in the pipe. In practice, this may be an extremely difficult task as the pipe must move vertically for the slips to bite which will relieve pipe tension. Slips also have a problem biting and, therefore, hanging the higher grade casing materials. Slips have to be fitted by hand after the BOP's are disconnected and suspended above the heads of the rig crew. Once the slips are set, the pipe is cut and prepped to set and test an elastomeric seal. The next casing head is flanged up and the BOP stack fitted. These operations are time consuming and the rig crew are often working on a temporary platform directly above sea level (Texas Deck) and accidents are not uncommon. Various designs of surface wellhead systems have been modified for a single specific feature, such as metal-to-metal seals, split multibowls or adjustable landing shoulders, but until now, all these hybrids were just modified versions of conventional surface wellhead technology. Early in 1989, a detailed customer survey was made to determine requirements and preferences for a next-generation Jack-up Drilling System (JUDS). The outcome was a system designed to address the unique requirements of a surface wellhead for use over mudline suspension systems, and to design a standardised group of wellhead components for use on similar applications, such as tieback of subsea or mudline drilled wells. Draft specifications and layout designs were quickly produced, as was a marketing feasibility study. After a second round of customer visits, the specifications and layouts were updated and approved; the research and development team quickly assembled; and the JUDS project initiated. project initiated. SPECIFICATIONS The functional specifications covered all aspects of a complete jack-up drilling system and resulted in a lengthy, but well defined, set of requirements for each phase of drilling and decommissioning a well. The overall requirements of the system were: 2-stack BOP system: 21-1/4" × 5,000 psi and 13-5/8" ×10,000 psi or 15,000 psi and 30" diverter. Standard casing programme: 30" × 20" × 13-3/8" × 9-5/8". Casing pressure ratings: 20" × 3,000 psi; 13-3/8" × 5,000psi; 9-5/8" × 10,000 psi or 15,000 psi. P. 269

ABSTRACT. One of our core activities is the design and deployment of exploration and production wells. Since the technology in production wells. Since the technology in this area is advancing and therewith the variety of possible well designs it is of paramount importance to re-assess our well paramount importance to re-assess our well design methodology. This paper explains, in concept, the system components and their relationship in performing a well design in a systematic manner. This will provide optimization of the design as well as providing an audit trail for future providing an audit trail for future performance assessment of the well design. performance assessment of the well design. The business aspect and the management of the execution phase will be briefly touched upon in relation with the well design as a basis for technical terms and conditions of a contract as well as Quality Control during the execution phase. DEFINITIONS. Technical specification: (Ref: ISO guide 2) Document that prescribes technical requirements to be fulfilled by a product, process or service. process or service. Functional specification: Document that defines the total of needs expressed by features, characteristics, process conditions, boundaries and process conditions, boundaries and exclusions defining to which the performance of a product or service should performance of a product or service should comply, including the Quality Assurance requirements. Quality Assurance: (ref: ISO 9000) All those planned and systematic actions necessary to provide adequate confidence that a product or service will satisfy given requirements for Quality. Quality Control: (ref: ISO 9000) The operational techniques and activities that are used to fulfil requirements for Quality. Design Review: (ref ISO 8042) A formal, documented, comprehensive and systematic examination of a design to evaluate the design requirements and the capability of the design to meet these requirements and to identify problems and proposed solutions. proposed solutions. Fit for purpose: Compliance with the functional specification of a product, process or service. INTRODUCTION. historically wells have been drilled in which knowledge of the reservoir was inadequate. The result were dry wells or fields which could not achieve the optimum sweep efficiency owing to poor knowledge of the formation. There are within every oil company those famous near misses of a complete field or incorrect well configurations. Owing to a quantum leap in 3-D seismic interpretation techniques we are able to obtain a more precise 'picture' of our fields. precise 'picture' of our fields. The latter enables us now also to improve our well designs which then can be tailor made to the reservoir conditions and the objectives of our field development plans. To obtain the assurance that the set goals will be achieved the use of the concepts developed by ISO CASCO in the form of the ISO 9000 series will be discussed in this paper. paper. P. 91

Abstract High-temperature cementing (above 300 degrees F (149 degrees C)) remains a complex operation from job design and execution viewpoints. Temperature prediction is of crucial importance and is still a prediction is of crucial importance and is still a challenge. To design a slurry with excellent properties (thickening time, rheology, stability and fluid-loss) remains difficult in deep hot reservoirs. The execution of the job is also another critical step: accuracy in additive concentration and constant density are not always easy to achieve using normal cement mixing equipment. All these issues make the cementing of a high-temperature/high-pressure well a critical operation. A new global approach is proposed to minimize the risk associated with these operations. Emphasis is placed on quality control of the materials to be used as well as a quality assurance program for the laboratory testing to give confidence in the results obtained. Quality control of the job execution is also heavily emphasized. Introduction To achieve a successful primary cement job still remains one of the most critical steps while drilling a well. Not only must the data be accurate and up-todate but also all the materials used for the testing must be representative of those being used at the rig site. The execution of the job is also very critical. During this part of the cementing job, the concentration of all the uncertainties on the materials used, additive concentration, density and pumping parameters may result in a very poor job. pumping parameters may result in a very poor job. This paper shows how a quality-control programme can enhance the chances of success and eliminate some of the unknowns from the cementing operation. The paper will be divided into three sections: job design, execution, and evaluation. The risks associated with each of these operations will first be reviewed and illustrated by some examples. How a quality control/quality assurance programme can minimize the risks associated with each operation will also be discussed. The evaluation of the implementation of such programmes is briefly discussed in the conclusions. Job design All high-temperature cementing operations are performed using API Class G or H cements. The performed using API Class G or H cements. The specifications that these cements have to meet before receiving the API label are covered in the API specifications 10. The question can be raised as to whether these specifications are adequate for application on high temperature/high pressure wells. Table 1 shows the properties of a slurry designed for a BHCT of 300 degrees F (149 degrees C) obtained with two Class G API-approved cements. Figure 1 also shows the thickening time traces obtained on two batches of an API Class G cement measured at 300 degrees F (149 degrees C). Drastic changes in the thickening times are observed from brand to brand and also from batch to batch, even though all the samples meet the API specifications. These results show that the API specifications (even if it is not their purpose) cannot guarantee either the quality of an API Class G or H cement nor its consistency. P. 387