Presently, drilling riser joints are inspected every five years. This is usually accomplished by rotating 20% onshore every year to be dis-assembled and inspected. This requires extensive boat trips from a mobile operating drilling unit (MODU) to onshore and trucking of the riser to the inspection facility. Typically, 20 riser joints from each riser system are transported on a boat and one riser per truck to an inspection facility each year, making the logistics of performing a drilling inspection complex and costly. A laser-based measurement for inspection together with monitoring of riser systems has been implemented with a new standard process for collecting critical riser data that is ABS approved. The aim is to mitigate the costs and time associated with essential MODU drilling riser inspections, by empowering operators to reliably determine the condition of drilling riser joints, consistently predict when vital components will require service and accurately assess remaining component life. The approach utilizes a life cycle condition based monitoring, maintenance and inspection system that can be deployed on a MODU, enabling resources to be deployed only when necessary, instead of on a calendar interval. The solution consists of: Performing a baseline inspection on the riser joints to assess their present state, Collecting the environmental and operating data when the rig is on site drilling, Feeding the environmental and operating data into a digital twin. The tuned digital twin can be used to predict future damage. The approach removes uncertainties surrounding damage of riser joints and will allow the owner to determine whether riser should be redeployed or replaced. This is the only process that is ABS approved for condition based monitoring of drilling riser systems. The system is compatible with all present owners’ maintenance programs and ensures that maintenance requirements are supported with robust engineering.

Decommissioning activity will increase in the next nine years with a predicted £1.3 billion spent on decommissioning of subsea pipelines and associated subsea infrastructure in the North Sea from 2014-2023 [ REF 1 ]. Detailed preparation prior to the Cessation of Production (CoP) may significantly reduce this cost. Savings can be made during late in life operations on the platform and preliminary decommissioning planning. A Comparative Assessment tool assists the project team in selecting the most preferred decommissioning and abandonment option for subsea pipelines by using criteria such as safety, environmental factors, technical feasibility, economics and societal issues. These are then ranked by priority through matrix algebra. The introduction of new technology and advanced planning for decommissioning campaigns are the solutions for cost reduction, such as: Several applicable technologies and research areas are recommended as topics for further development, such as laser cutting, subsea lift claws and cutters and long-term effects of pipelines on fish habitats. A thorough checklist to incorporate decommissioning during the design phase would ensure decommissioning is given as much emphasis as input from the operations and maintenance teams during this important phase. Primary cost drivers are identified and include long term liability, cleanliness standards and national requirements for making the pipelines safe for potential re-use. Pipeline preservation for future use and/or leaving pipelines in place are the most cost effective solutions for pipeline decommissioning and if regulatory requirements change where pipelines must be removed, decommissioning costs could skyrocket.

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.

The UK Oil & Gas (O&G) faces significant challenges to ensure future economic potential is maximized. Current issues include escalating maintenance backlogs, facility unreliability; an inability to liquidate production-enhancing or important asset integrity workscopes and uncertainty of the rationale justifying existing maintenance programs. This paper presents the application of a novel maintenance optimization technology that has delivered performance improvement through the deterministic consideration of both commercial and reliability criteria when determining planned maintenance intervals. Real case studies are presented alongside the concomitant benefits. The technology was used to determine an optimized planned maintenance program for deployment in both existing operations and new facilities, and has delivered benefits when compared with traditional approaches to determining maintenance intervals. The technology marries both technical and commercial considerations when determining optimized planned maintenance and, in this way, the modulation of planned maintenance programs in response to changes in production, commodity value or equipment reliability is easily achieved. Based on results of the work carried out using the technology, it is proposed that there are significant benefits available to the UKCS through the adoption of similar techniques, as it is understood that many operators currently struggle to justify existing planned maintenance regimes, and to demonstrate a defensible means by which to alter these regimes in response to a changing economic and reliability criteria. Application of this new technology may provide a means of modulating maintenance in response to changing criteria and offer potential concomitant benefits in helping tackle backlog, bed space and production efficiency challenges.

This paper presents the recent analysis results of offshore hydrocarbon releases occurring on the United Kingdom Continental Shelf (UKCS) between 2008 and October 2010. The analysis includes the type of hydrocarbon released, the operating mode during which releases occurred, the release sites, age of installations, type of installations (manned and unmanned; Floating Production Storage and Offloading vessels [FPSOs], Floating Production Facilities [FPFs] and fixed installations) and the underlying causes of the releases. This paper aims to assist the industry to identify where it can best place its resources to reduce the number of hydrocarbon releases.

Abstract A unified approach to selection and qualification of sites for geological storage of CO 2 is being developed by key industry players in the CO2QUALSTORE Joint Industry Project. The partners represent companies with diverse roles within CCS; oil and gas companies (BP, BG Group, Petrobras, Shell and StatoilHydro); energy companies (DONG Energy, RWE Dea and Vattenfall); technical consultancy and service providers (Schlumberger and Arup); the IEA Greenhouse Gas R&D Programme; and two Norwegian public enterprises (Gassnova and Gassco). The project is coordinated by DNV, a major provider of independent verification and risk management consultancy services. CO2QUALSTORE aims to produce a guideline that shall help project developers pass internal milestones during the site selection stage of the project life cycle and simultaneously demonstrate compliance with regulations and stakeholder expectations. A primary objective of the qualification workflow is to assist operators, authorities, verifiers and other stakeholders in assuring that storage sites are qualified following a transparent, consistent and cost-effective process. The guideline should lay the groundwork for a risk-based approach where monitoring programs and contingency measures are derived from preceding risk assessments. Furthermore, the guideline aims to facilitate the following processes; identifying, characterizing and selecting the sites that are well suited for CO 2 geological storage among a list of candidates; defining qualification criteria and providing the evidence that the site and project will function reliably according to these qualification criteria; verifying that the selected site and its planned management procedures comply with given standards and regulations, and that the available data and management procedures as well as the contingency (remediation) plans provide sufficient confidence that the site will provide long-term storage of CO 2 . In this paper we present results and conclusions from five satellite projects that test and evaluate critical components of the main steps of the proposed qualification framework. The main objectives of these projects are described below. Site selection offshore Norway: Document the ongoing site selection process for storage of CO 2 from two gas-fired power plants, and assess if the documentation provided at the key milestones corresponds with the guideline framework. Site characterisation criteria: Develop site characterisation criteria for geological storage of CO 2 in saline aquifers or hydrocarbon reservoirs, and evaluate how to convert the criteria into recommendations. Site verification: Show how monitoring and verification has been carried out on projects in the injection phase, and evaluate how the verification process could be improved and completed. Site selection onshore Germany: Apply the qualification framework to the process of site selection for two planned onshore storage projects in Germany, and identify documentation necessary for regulatory approval processes in compliance with the German mining law, the EC CCS directive, and the upcoming German CCS law (KSPG). Risk assessment and communication with stakeholders: Perform a critical review of risk assessment work conducted for the In Salah project in Algeria and use lessons learned from the In Salah project as a basis for demonstrating effective communication of risk assessment for a CO 2 storage site between an operator and stakeholders.

Abstract The Norwegian Offshore Regulator requires top executives to confirm the safety of their installations with particular focus on established barriers towards large scale accidents. StatoilHydro has implemented a structured approach for assessing the technical safety condition of its key barriers. Performance Standards (PS's) are defined for each barrier and each PS defines a set of Performance Requirements (PR's) to be met by that particular system with respect to system function, integrity, survivability and management respectively. The set of PR's incorporates regulatory and internal requirements as well as best industry practice. Each PR is assessed in terms of the design, the condition and the operation of that particular part of the safety barrier. A combined in-depth shore-based and offshore assessment program reviews compliance with the PR's and assigns a common grading. The TTS process focuses on a systematic assessment of the actual technical integrity and condition of process safety barriers implemented in facilities in operation, as well as facilities under design and construction. TTS provides a powerful approach to: Measure and ensure safety performance Prioritize corrective actions and major accident hazard risk management improvement initiatives Build process safety awareness and competence Demonstrate regulatory compliance. Introduction and Background The TTS process for structured evaluation of technical safety systems or barriers at operating facilities have been developed over a number of years as a joint effort between DNV and Statoil, Norsk Hydro and subsequently StatoilHydro. Initially, a process for systematic and structured evaluation of technical safety systems in operation was developed by Statoil in 2000. The process was named Teknisk Tilstand Sikkerhet (Norwegian for technical safety condition) and focused on a systematic assessment of the technical integrity and conditions of the existing process safety barriers. DNV was engaged to provide support in Statoil's roll-out and implementation of the TTS process. Following successful implementation at Statoil facilities, Norsk Hydro showed interest for using a similar approach at their facilities. DNV was engaged to develop a similar process for Hydro based on TTS (with Statoil's consent). The TST (Teknisk Sikkerhetstilstand) process was launched in Hydro in 2003. Following the merger between Statoil and Norsk Hydro, StatoilHydro is still using the process under the name TTS, which in fact is a combination of the former TTS and TST processes. The methodology has been continuously improved and fine-tuned over the years to incorporate the experiences and the lessons learned from the implementation process on installations on- and offshore. All in all, the TTS process has so far been successfully implemented at 35 offshore and 8 onshore installations. The main objectives of the TTS process are: To keep control of the functionality and availability of the safety barriers To build process safety awareness and competence To manage the risks for major accidents To demonstrate regulatory compliance.

Abstract Severe slugging in an offshore riser pipeline imposes a major challenge to production and flow assurance in the oil and gas industry. Riser top valve choking has shown effectiveness in eliminating severe slugging. However, most manual choking and active control techniques were tuned by trial and error resulting in operation at a smaller than required valve position. This imposes unnecessarily high back pressure on the riser-pipeline which leads to reduction in production. One way to overcome this problem is to design the active control system to operate at a large valve position. However, at such an operating point, the riser pipeline system is naturally open-loop unstable associated with severe slugging flows. In this work, an approach to tune a robust PID slug controller at an open-loop unstable condition is proposed. Firstly, at an open-loop unstable operating condition, a reliable linear model is derived from the nonlinear simplified riser-separator model (SRSM) developed in previous work. Then, a robust stabilizing PID controller is designed based on the linearised model. The controller was successfully applied to a 2" laboratory riser at Cranfield University and a 8" generic industrial riser system modeled in the commercial simulator, OLGA. OLGA simulation on the industrial riser system shows that the proposed approaches not only can eliminate severe slugging but can also increase oil production. It also shows that the percentage improvement in oil production compared with manual choking will increase as the well pressure declines. This means that even more can be gained by adopting active slug control for mature oil fields than for relatively new fields. The result is very significant for mature fields which are susceptible to severe slugging and low oil production due to declining reservoir pressure. 1. Introduction Severe slugging in an offshore riser-pipeline system is one of the most undesired flow regimes due to its potential to initiate and sustain system instability. Due to huge variation in pressure and flow associated with it, its consequences in oil and gas production are of a very serious concern. Severe pressure and flow oscillations can cause depletion of reservoir performance and productivity, poor phase separation, compressor overloading, trips and production deferment. Conversely, a slug control system will eliminate or reduce the occurrence of these adverse conditions. The primary objective of a slug control system is to stabilise the riser-pipeline system by suppressing severe slugging. Conventional solutions to address this severe slugging issue include design modification of upstream facilities(Fargharly, 1987, Makogan and Brook, 2007), riser base gas lift(Alvarez and Al-Malik, 2003, Cousin and Johal, 2000, Duret and Tran, 2002, Al-Kandari and Koleshwar, 1999, Jansen and Shoham, 1994, Meng and Zhang, 2001, Pots et al 1987), gas re-injection(Tengesdal et al, 2002), homogenising the multiphase flow(Hassanein and Fairhurst, 1998), installation of slug catchers and riser topside valve choking(Schmidt et al, 1980). Among these solutions, choking transforms the unstable flow in the riser to stable flow; however, it induces extra back pressure on the pipeline. Active feedback, feed forward and cascade control systems have been applied to dynamic choking for slug control (Henriot et al 1999, Drengstig and Magndal 2001, Jasen et al 1996, John-Morten et al, 2005, Molyneux and Kinvig, 2000, Storkaas et al, 2001, Storkaas and Skogestad, 2004).

Abstract The Shuaiba formation is a highly fractured limestone reservoir. The use of conventional overbalanced drilling technology in this formation usually results in the complete loss of drilling fluids to the formation. These losses cause drilling problems and results in the masking of the potential for hydrocarbon production. Underbalanced Drilling Technology was proposed as an alternative drilling method in order to evaluate the Shuaiba formation for producible hydrocarbons while simultaneously eliminating fluid loss to the formation and improving drilling performance. The Shuaiba formation was successfully drilled underbalanced without any fluid loss during the drilling phase and a successful evaluation of the formation for hydrocarbons was completed for the first time. A multidisciplinary team contributed to the engineering, planning and execution of the first underbalanced drilling operation in Kuwait. This paper highlights the key factors in the underbalanced drilling design phase and the operational results of the first well drilled in Kuwait using underbalanced drilling technology. Introduction Controlled Pressure Drilling (CPD) technology has enabled the commercial development of numerous oil and gas reservoirs around the world that would have otherwise not been exploited due to technical and/or economic limitations. Controlled pressure drilling has only become possible as a result of the integration of many developing technologies that facilitate directional control of the well trajectory, control of the bottom hole circulating pressure and the safe handling of drilling fluids and drill cuttings on surface. Underbalanced Drilling (UBD) is a subset of CPD where the annular pressure profile is maintained below the expected reservoir pore pressure and is particularly beneficial in evaluating the productivity of prospective formations in their virgin state. This means that the formation can be evaluated without first subjecting it to drilling damage and requisite clean-up operations. The Shuaiba formation is a dolomitic limestone with significant fractures and massive losses of circulation are normally experienced in this zone. KOC believes that these massive losses have masked the potential evaluation in the Shuaiba by flushing any hydrocarbons beyond the reach of log evaluation. Similarly, drill stem tests may have also failed to reach the hydrocarbons due to the massive losses of drilling fluid to the formation and subsequent of plugging of the pore throats with drilled cuttings and drilling mud. The Shuaiba is also naturally sub-normally pressured formation due to its depositional environment, which further lends itself to losses of circulation when drilling with conventional drilling fluids. It was anticipated that the formation pressure in the Shuaiba is in the range of 7.1 ppg - 8.9 ppg. Due to the exploratory nature of this well and the depositional layers, these fractures could contain oil, gas or water, or any combination and in no particular orde ] . Therefore, it was proposed to drill this formation in an underbalanced state with the intention of identifying the potential for hydrocarbon production from the fracture permeability in the Shuaiba dolomite. Aproximately 250 ft of 8 ½″ open hole was planned to be drilled vertically out of 10 ¾″ casing. UBD Planning Underbalanced drilling technology is a very useful technique to drill wells in order to minimize formation damage that is common in conventional overbalanced drilling operations. In addition to minimizing formation damage, other benefits related to underbalanced drilling are an increase in penetration rate, the elimination of lost circulation and differential pipe sticking problems and permits the evaluation of production while the well is being drilled. When this technique is properly executed, the pressure in the column of the drilling fluid is, intentionally, maintained below the formation pressure. In the case of a reservoir where the pore pressure is less than the specific gravity of a column of static oil, the density of the drilling fluid is reduced by injecting gas into the liquid stream.

Abstract The Hassi Messaoud field (Figure 1), discovered in 1956, is the largest oil field in Algeria, covering about 2000 Km 2 and currently including over 1000 Wells. The field is divided aerially into 25 zones that are separated from each other by low permeability barriers, usually faults. The Cambrian Reservoir is subdivided into four lithological zones designated from base to top as R3, R2, Ra and Ri. The Ra sub reservoir shows the best petrophysical properties with a maximum thickness of 150 m in the western part of the field. The Ra is farther subdivided into five sub zones: D1, ID, D2, D3, and D4 based on reservoir properties and depositional conditions. Well F was the 6 th re-entry well in the Sonatrach Coiled Tubing - Underbalanced Drilling campaign. A total of 363 m from KOP (303 m from landing point) were successfully drilled in a continuous underbalanced condition inside D1 and ID formations. As a result, the well productivity while drilling and while production test, the reservoir characterization and rate of penetration was significantly improved, compared with offset wells, due to the positive impacts of UBD operations. The combination of Underbalanced and Coiled Tubing Drilling technologies has been proven to be a viable solution to successfully drill horizontal re-entry wells in mature fields where the reservoir pressure is adequate to induce underbalanced conditions using single phase or multiphase drilling fluid. The experience in this field has validated the benefits of the combination of these technologies and has been attributed to the excellent balance between drilling cost and improved productivity. For example, the drilling cost in the short radius re-entry wells drilled with coiled tubing are highly reduced due to the elimination of pipe connection procedures, the increase in rate of penetration, the prevention of conventional drilling problems such as fluid circulation loses and related differential sticking events, the increase in the bit life and reduction in time and drilled distance to reach the profitable production level. This paper describes the technical basis for the design and implementation of the Coiled Tubing Underbalanced Drilling project in Hassi Messaoud Field and highlights the operational key factors and challenges faced during this particular and successful application in Algeria. Introduction Drilling in the Cambrian Reservoir, in the peripheral zone of Hassi Messaoud field, specifically the 1A, 1B and 1C zones (Figure 2) is a real challenge, basically due the petrophysical reservoir complexity, the low reservoir pressure, the extremely hard and abrasive sandstone and quartzite formation (15000 - 35000 psi UCS) associated with numerous vertical and sub vertical fractures that connect the reservoir with deeper formations leading to major problems related with the salt saturated water production. Many of the vertical wells drilled in that zones have more than 30 years from completed and a large proportion of them have been shut in since being drilled. This is the first of its kind Coiled Tubing - Underbalanced Drilling project undertaken in Hassi Messaoud field. The candidates wells are from a pool of vertical shut in wells drilled in the western area of the field and have seized to produce with varying completion string and production casing. The increase in number of candidates for thru tubing re-entries added to the depletion of the reservoir have raised the importance of use the combined technologies Coiled Tubing - Underbalanced drilling in Hassi Messaoud field. The original reservoir pressure was 6860 psi and the average permeability ranges from 0.5 to 1.0 mD but can reach up to 1000 mD in cases where open fractures are encountered. Production is 43.7 - 45 º API oil with original average GOR of about 200 m 3 /m 3 and a formation temperature of approximately 120 ºC. Until 1964, the production mechanism was only depletion above bubble point. Gas injection and water injection started after that year to improve the production.

Abstract Many operators implement a conservative approach to sand management implementing a "Zero Sand Production" or "Maximum Sand Free Rate" Criteria. This is due to the potentially severe consequences associated with sand production i.e. erosion, and the fact that existing standards and guidelines /1/ do not provide sufficient practical advice on how to manage erosion issues during operations. These criteria generally put restrictions on the production rate (and revenue) to reduce sand production and decrease the risk of erosion leading to a loss of containment. These restrictions are in many cases unnecessary. This paper describes the development of an alternative approach which improves the production and safety performance of fields that are capacity restrained due to sand problems. The development of the approach started with a project for Conoco 1996 - 2000 /2/ and was further refined on a pilot project for Statoil in 2001 /3/, where it received the Statoil prize for the most successful R&D project in 2001. From an erosion perspective the amount of sand produced is only one of many factors that must be managed; equally important factors are sand particle velocity, impact angle and material grading. By gaining a better understanding of the specific erosion characteristics of a field through: well sand risk ranking, identification of erosion critical components and detailed erosion assessment including 3D computer modeling; a more sophisticated erosion management strategy can be implemented identifying specific asset operational criteria, erosion monitoring and inspection requirements. Implementation of this erosion management approach has provided operators with enhanced production, reduced inspection and maintenance costs without compromising safety and environmental targets and increasing/enhancing business performance. Introduction The mid / late 1990's saw a significant increase in unplanned hydrocarbon releases for Conoco in one of their UK North Sea operations. The releases occurred on manned installations and unmanned satellite installations with significant business and safety impact. The root cause of all incidents was an increase of solids production leading to accelerated erosion, see figure 1 for typical damage. The implemented solution of a revised Solids Management Strategy, the Maximum Allowable Solids Rate approach, has led to increased production, reductions in operating costs and enhanced safety performance. Challenges The key challenges in the implementation of the revised strategy can be broadly summarised as follows: Resistance to Change Operations personnel had over a long period of time assumed that adoption of a ‘solids free’ production would minimise failures. In reality the measures adopted to achieve this aim led to an escalation in the number and severity of unplanned failures. A key challenge was education and confidence building amongst the workforce to achieve a ‘sea change’ in the mind set and an improved understanding of the key issues. Regulatory Pressure The failures focussed regulatory attention due to their hazardous nature and the implication this resulted from ineffective management. A key challenge was addressing this pressure which, with further incident, may have resulted in enforcement action with associated loss of revenue and reputation.

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

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 During the past 15 to 20 years, duplex stainless steels have gained wide acceptance in the oil, gas, chemical, and refining industries. Because of their desirable mechanical properties of corrosion resistance, high strength, and light weight, the offshore oil and gas industry has been quick to recognize their usefulness. Engineering design firms have been using duplex stainless steels to greater advantage to further reduce topside weight. When using duplex stainless piping systems, thin-wall sections can pose serious dynamic problems. Even though their fatigue properties appear to be superior to most carbon steels, many fatigue failures involving duplex steels have occurred in North Sea operations. In systems experiencing little or no mechanical dynamic excitation, fatigue failures will not be a problem. Conversely, thin-walled systems exposed to flow-induced excitation due to low frequency random turbulence or high frequency sonic, or near sonic, flow conditions involving pressure control, recycle, or safety relief valves, can be highly susceptible to fatigue failures. These failures can occur at vibration amplitudes previously considered safe in thicker wall piping systems. Failures of this kind were experienced during the start-up of the Tiffany Platform in small diameter branch connections attached to thin-wall duplex steel gas compression piping and, although affecting only a very limited number of connections, they were symptomatic of the problems recently experienced by a number of North Sea operators. This paper describes the problems experienced and the approach used by AGIP (UK) Limited, together with Southwest Research Institute to investigate the causes of the failures and to identify simple remedies to allow quick restoration of safe production operations. The methodology used in obtaining data such as modal impact, vibration, noise, pressure pulsation, and dynamic strain are presented. Analysis to define the nature of the problems is also discussed. The solution of the fatigue failures is set forth along with suggestions for additional research that should be performed to develop guidelines and procedures for existing and new installations. Introduction The Tiffany platform for oil and gas production and processing is located approximately 250 kilometers northeast of Aberdeen, Scotland in the UK sector of the North Sea. The platform was designed to initially produce and process oil and gas from the Tiffany and Toni reservoirs with the Thelma reservoir to be developed in the future. The platform design consists of an eight-leg jacket secured to the sea bed by 16 vertical piles grouted into pile sleeves; a group of four piles at each corner leg. The topside modules consist of: – a process module – a utilities module – an accommodation module with helideck – an angled flare boom (supported from the process module) – a drilling deck and associated drilling services. Capacities of the facilities are: Oil: 105,000bpd Gas: 3.26 × 106Nm3/d (115 mmscfd) Injection Water: 125,000 bpd A 304.8-mm (12-inch) oil export line runs about 5 km to the Brae A to Forties oil pipeline. Similarly, a 254-mm (10-inch) gas export line runs nearly 34 km from the platform to the Brae A to Brae B gas pipeline. Installation of the platform is over a steel well guide template through which four predrilled production wells were drilled and completed before the platform was set. The total number of planned production wells is seven with four water injection wells. P. 329

Abstract Operational support functions are an important consideration in the development of offshore reserves and must be administered in such a manner that prevailing environmental regulations, personnel safety, and the local environment are not compromised. At the same time, the economic burdens imposed by their administration must be compatible with production forecasts. This paper will discuss a unique support approach that was codeveloped by BHP Petroleum Limited (BHP) and the engineering staff of an international oilfield servicing/manufacturing company to support the operational objectives for the Hamilton, Hamilton North, Douglas, and Lennox fields in the Liverpool Bay Development. A key component of the concept is a manned, self-elevating Operations Support Vessel (OSV) that can provide cost-efficient infield service to the offshore platforms in the developed locations while maintaining all safety and environmental requirements. The OSV concept has enabled the operator to develop fields in shallow water with unmanned, minimum-facility, standardized platforms that are consistent with the industry "Cost Reduction in the New Era" (CRINE) initiative, When multiple fields are within reasonable proximity, the economic advantage gained with this vessel is enhanced even further. The success of this approach brings a cost effective solution to the development of offshore reserves in shallow waters that cannot support the economic burdens of traditional North Sea manned platform designs. This approach to field development for the UKCS has resulted in a life-cycle operating contract between BHP and the servicing company. This interaction has not only enhanced current operational technology within the required parameters but also illustrates a practical example of an industry "win-win" relationship. Introduction Developmental philosophy for offshore fields in the U.K. has undergone significant change within the last few years, primarily from the need to address the depressed economic climate resulting from reduced oil and gas revenues at a time when operating costs have continued to escalate. In addition, environmental regulatory standards have become more stringent, further impacting operational costs. During 1993, it became apparent that without stronger emphasis on cost reduction, operational feasibility in the North Sea would be seriously impaired. Thus, the desirability of restructuring operating procedures to the practicable doctrines of the CRINE initiative gained new importance in operational strategies. BHP had begun exploration for oil and gas in the Irish Sea in 1990. Since then, both oil and gas discoveries have been made, and a substantial effort has been put into planning the development of these resources. With the impending development of the offshore Hamilton, Hamilton North, Douglas and Lennox fields in the Liverpool Bay Development and the changing economic climate, new support strategies were needed. P. 547

Abstract This paper aims to support the Offshore Industry to achieve truly cost-effective safety. It examines the new Framework for emerging Offshore Regulations, with its largely approach. Three main themes are presented: how to understand the HSE's requirements for acceptable Safety Case; professional project management planning, with "fit for purpose" quantitative risk assessment (QRA) and cost benefit analysis (CBA); and decision support for remedial action plans that are truly cost-effective and reduce risk demonstratably, as low as reasonably practicable (ALARP). An affirmative answer is given to the question posed in the title, acknowledging the massive efforts being made. Momentum must be maintained and the safety cases put to work, Using several recommended steps for future action. Introduction 2.1 Introduction to a "Goal Setting" Approach This paper examines a question that is often foremost in the minds of managers in the oil and gas industry and in government. This question is based on the precept that the adoption of a "goal setting" approach enables the management of safety to be more truly cost-effective, because it is tailored to the specific hazards at hand. The offshore industry has responded on an impressive scale and invested massive efforts and resources over the past few years with the central element being the new safety case for each installation. These safety cases must now be used, tested and reviewed to keep them useful. So the "one million dollar question" is posed in this paper: Has goal selling regulation, and its implementation so far, helped or hindered management in its mission towards truly cost-effective safety? In fact the jury is Still Out, but this paper assembles the issues, attempts to clarity understanding and to clear away some misconceptions. It aims to leave the reader with a summary of prime issues and outstanding, questions, to support future decisions and forecasts, in the management of business and safety. On the basis of previous and ongoing case studies, this paper presents methods that have proved most effective during the process of writing, and implementing the safety cases (References 4, 5. 6, 7 and 9). In particular the paper introduces new work to support management decisions, during planning and implementing remedial action plans to reduce risk. This latter area is where quantitative risk assessment (QRA) and cost benefit analysis have come into their own. This is both to improve cost-effectiveness and to demonstrate more quantitatively the justification for continued operation of an installation. The latest methods are used and will be explained in the next section. The paper attempts also to set these new activities in a wider context of a working "safety culture" which appears to be growing healthily, largely because of the encouragement afforded by a framework of "goal setting" regulations. First, the background is painted and the special usage of language is explored. P. 315^

Abstract The development and submission of installation safety cases is an activity which has and will in the future utilise a significant level of operators' manpower. The Amerada Hess Ivanhoe/Rob Roy fields safety case was prepared and submitted initially to the HSE as an early voluntary submission for a floating production system and then as the formal safety case submission in June 1993. This paper will detail how the safety case was developed starting from the 'Forthwith Studies' defined by the Cullen Report. It will detail the various development stages of the document and the changes that were carried out before a satisfactory format was reached. A particular strength identified in the voluntary safety case was the hazard identification and mitigation section, which also includes the hazard inventory. This section will be presented in detail with examples in some of the main hazard groups, namely (i) loss of containment, (ii) dropped object, (iii) marine impact and helicopter crash, (iv) marine system faults, (v) loss of structural integrity and (vi) environmental hazards. The methods used to justly identify the hazards associated with the installation, then qualitatively risk rank and finally, perform quantified risk assessment will be presented. Detailed information on the dropped object studies will be specifically highlighted. This paper will provide an insight into the development of a safety case which has been reviewed by the HSE, as part of the voluntary safety case exercise. The sharing of the Amerada Hess experience will be of great benefit to those involved in the development of installation safety cases, particularly in the area of floating production systems. Introduction The preparation of the AH001 Safety Case commenced in early 1991 with the voluntary case being presented to the HSE in January 1992. After additional work the formal safety case was submitted in June 1993. The format of the Safety Case was initially based on the UKOOA Guidelines since at that time guidance from the HSE was not available. It was subsequently altered to the current format following review and discussion. In general we had a good starting point - the AH001. The Ivanhoe and Rob Roy fields are located in Block 15/21a - 100 miles north-east of Aberdeen in a water depth of 140 metres. The AH001 is a conversion of a Sedco 700 series semi-submersible vessel which, for the purpose of certification, is now designated a fixed floating production facility (Fig. 1). P. 325^

Abstract The paper presents a methodology for optimising offshore hydrocarbon production developments, employing NPV/LCC as an economic selection criteria, including production revenue, throughout all project phases. Combining CAPEX, OPEX and Production Performance into Net Present Value (NPV) gives an opportunity to base decisions upon optimised economics over the field lifetime. In the early phases of a field development, the methodology analyse all possible solutions systematically. The method analyses the major functions necessary for field production, selecting functional solutions with highest economical potential, and combining the functions into total field development solutions. The methodology utilises aggregated data for CAPEX and OPEX (a top-down approach), and is often referred to as the 'Screening Methodology'. Introduction Downward trends in oil and gas prices implies reduced financial capacity in offshore oil- and gas field developments. As for the North Sea, the larger fields now seems to have been developed. The oil companies are moving towards the smaller, marginal fields. Optimising/utilisation of existing production facilities and infrastructure plays an important role in some of these developments. These two factors, low oil prices and smaller fields, have given the developers greater challenges. From being engineering and schedule dominated environments, the lower economic margins in the oil industry have encouraged field development teams towards multi- disciplined thinking, including economists as equal participants. Approaches such as Total Quality Management (TQM), Systems Engineering, Concurrent Engineering, Economic Optimisation and Minimum Facility Engineering have become an ever more important part of field development activity. Reducing total cost also implies more efficient field development projects. Reducing time and manhours spent in project developments have therefore led to search for efficient project execution methods. This paper deals with a methodology for optimising the main functions necessary to produce an oil or gas field, and to compile the total development scheme that gives the optimum rate of return on capital invested. 2. RECOGNISE THE NEED FOR ECONOMICS AS THE BASIS FOR DECISIONS. Economic measurement parameters, (such as NPV) allow the impartial and rational assessment of technical alternatives from all sources by a common criterion. Historically, difficulties in the use of such measures have arisen due to analysis resource limitations, Organisation and data flow constraints. P. 185^

Abstract A methodology for the rigorous assessment of pipeline freespans is described, together with a description of its application to the Beryl Field network of pipelines. The methodology is in two parts, each with two stages, and comprise preliminary stress and vibration frequency checks followed by detailed strain and fatigue life checks where appropriate. Comprehensive software, automatically linked to the inspection database, has been written to allow efficient use of the methodology. The use of a new ROV based freespan rectification technique is also described. Both the assessment and rectification techniques were successfully used in Mobil's Beryl field and the SAGE pipeline in 1992. Introduction The Beryl 'A' platform was installed in block 9/13 in 1973. Subsequent developments in the block include the Beryl B platform, the Ness, BWISS, Linnhe and NESS II multi-well subsea developments and 4 single subsea wells. A total of 25 pipelines are laid in the block; the majority are 6" diameter flowlines from the subsea wells to the platforms, but include 1 No. 16" and 1 No. 20" hydrocarbon transfer lines between the production platforms and 2 short 361, oil export lines to loading buoys. All the facilities noted above are operated by Mobil North Sea Limited (MNSL) on behalf of the block 9/13 co-venturers, Amerada Hess Ltd, Enterprise Oil plc, BG North Sea Holdings Ltd and OMV (UK) Ltd. In addition, the recently installed SAGE Gas export line runs 323 km from Beryl A to St. Fergus, and is operated by MNSL on behalf of the Beryl and Brae groups. Annual inspection of all the lines is undertaken in order to comply with regulatory and MNSL requirements and to ensure continued fitness for purpose. As with most pipelines, the annual surveys identify numerous freespans which have to be assessed and, if necessary, rectified. MNSL has now implemented a number of improvements to its methods for collecting and recording pipeline inspection data, and for automatically assessing the significance of freespans in relation to the service, pressure, temperature and orientation of pipelines. The methods of data storage and freespan assessment are based on user friendly PC-based programs for use both offshore and onshore. The basis for recording and displaying the inspection results is a database system (COABIS). Survey data can be entered into the system in real time on the inspection vessel as the inspection is performed. Further checks can be undertaken on the data in the office including graphical comparison of all features from one year to another. P. 253^

Attard, M., Amoco (UK) Exploration Co. SPE Member Abstract This paper discusses the occurrence of annulus pressures in the North West Hutton oilfield, offshore UK, and how the problems associated with these pressures have been addressed. Several wells have experienced annulus pressures in this field, where production is exclusively via gas lift. The causes of annulus pressures are discussed in the context of the mechanical configuration of the wells. An evaluation of the safety aspects and concerns associated with these pressures is then presented. Annulus pressure monitoring and operating procedures have been developed for use by offshore production personnel. These procedures contain a list of criteria which, when exceeded, require some type of action to remedy the problem in the well. Some of these criteria are based on a maximum pressure limitation for each well annulus. The derivation and application of these pressures is explained. The final section describes the changes made to the drilling and completion design of wells, in order to prevent or minimise the occurrence of annulus pressures. Introduction The North West Hutton oilfield, operated by Amoco (UK) Exploration Company ("Amoex") is located in the East Shetland Basin offshore UK, approximately 300 miles (483 km) north east of Aberdeen in licence block 211/27. Water depth is 475 ft (145 m). The reservoir is of Middle Jurassic Brent sandstone, and lies at an average depth of 11,500 ft (3 500 m) subsea. It is characterised by a series of tilted fault blocks and extreme lateral and vertical heterogeneity in its five major sand units. The field was discovered in 1975 and commenced production in April 1983 from seven pre-drilled wells, following the installation of a 40-slot fixed steel platform with two drilling rigs. Peak oil production of 86,000 BOPD (13 672 m3/d) was achieved the next month. Initially, reservoir pressure and oil production declined rapidly, and water injection was initiated in February 1984 to arrest this decline. In October 1984, gas lift was commenced to increase production rates, and by the end of 1985 all producing wells were on continuous gas lift. The current production rate from the field is approximately 20,000 BOPD (3 180 m3/d), and a continuous infill drilling program is currently underway to increase reserves and maintain production from the field. HISTORICAL OCCURRENCE OF ANNULUS PRESSURES The procedures for drilling and completing wells are designed such that no pressure should be seen on any well annulus. The exception is in gas-lifted wells, where gas is injected under pressure into the tubing-production casing annulus. Thermal expansion of the tubing and casing when wells are first placed on production may cause pressure to build up in one or more annuli; however these pressures should not recur once they are bled off and the well is in a normal production mode. P. 307^