North Sea Projects Research Articles

Cost Estimation Overruns in the North Sea

Recently, a Norwegian government report on the cost overruns North Sea projects was presented (NOU 1999:11). It concluded that there was a 25% increase in development costs from project sanction (POD, Plan for Operation and Development) to last CCE (Capital Cost Estimate) for the 11 oil field projects investigated. Many reasons like unclear project assumptions in early phase, optimistic interpolation of previous project assumptions, optimistic estimates, and underestimation of uncertainty were given as reasons for overruns. In this paper we highlight the possibility that the cost overruns are not necessarily all due to the reasons given, but also to an error in the estimation and reporting of the capital expenditure cost (CAPEX). Usually the CAPEX is given by a single cost figure, with some indication of its probability distribution. The oil companies report, and are required to do so by government authorities, the estimated 50/50 (median) cost estimate instead of the estimated expected value cost estimate. We demonstrate how the practice of using a 50/50 (median) CAPEX estimate for the 11 projects, when the cost uncertainty distributions are asymmetric, may explain at least part of the “overruns.” Hence, we advocate changing the practice of using 50/50 cost estimates instead of expected value cost estimates for project management and decision purposes.

A risk engineering approach to project risk management

This paper outlines an approach to the management of project risk which was initially developed for offshore North Sea projects and was subsequently adapted for a range of projects in the USA, Canada and elsewhere. It has been used for assessing issues such as reliability, preferred technical choices, and economic and financial viability, but the emphasis here is project planning and associated costing.

Lessons Learned In North Sea Oil Field Developments

Abstract Continued progress in matters of frontier resource development is dependent on avoidance of past errors. The development of oil and gas fields in the hostile North Sea environment represents a major pioneering effort which has witnessed the successful introduction of many new technologies. Evaluation of the success of North Sea ventures has, however, been confused by the impact of inflation and currency realignments.A recent analysis by Castle) of North Sea field Economic performance suggests that these fields would have been ‘underwater’ (due to technical under performance) if they had not been "bailed out" by the crude oil price increases, particularly of 1979. Examined are the technical factors responsible for Castle's observation for certain fields and it is concluded that greater care is needed in relating reservoir performance uncertainty to pre-development appraisal well data. Attempts are made to highlight some of the potential problem areas encountered when defining a development plan with the help of reservoir simulationmodels. Analyzed are published data for two typical North Sea fields: Thistle and Beatrice, which are amplified with observations from personal experience. Introduction Table 1 is partly extracted from a recent article by Castle(l) where an attempt was made to estimate how profitable 19 North Sea fields would have been if prices had remained flat from the time development was initiated. These "proforma" rate-of-return estimates, which ignore petroleum revenue tax as well as corporate taxes, and only deduct the 12 ? % royalty, indicated that only 14 fields in fact yielded a positive cash flow and of these only 7 yielded a rate of return in excess of 15%. At first glance Castle's analysis leads one to conclude that the performance of the oil industry in the North Sea was, in real terms, an economic disappointment. Table 1 has been enlarged with technical performance data extracted from the United Kingdom Brown Book(2). It is well known that the oil industry and various northwestern European National Treasuries have derived much benefit from the North Sea Oil Province. In terms of money of the day, the rates-of-return have been more than adequate to permit rapid payback of loans, a very large government "take", as well as to fund further developments. This is due, as Castle points out, to inflation and currency fluctuations ‘bailing out’ the North Sea projects most of which suffered from construction delays, cost overruns and production shortfalls. In this paper an attempt is made to identify the main technical reasons for under-performance of two of Castle's fields: Thistle and Beatrice (Fig. 1), These fields are rather well documented (see reference list) and thus provide much study material. This sample moreover includes a typical "Brent Province" Jurassic field representing one of the pioneering developments, as well as a later, non-Brent "marginal discovery" benefitting from five years of offshore technological progress. It is, therefore, a representative sample, and gives a fair insight into the technical risks inherent in offshore developments. Within the context of U.K offshore developments, both fields are successful.

Use of risk analysis in North Sea projects

Risk analysis, as applied to North Sea oil projects, is described. Two projects in particular are presented as examples: the Murchison and Hutton fields. The unpredictable North Sea weather conditions make risk analysis particularly suited to these projects. The advantages of the technique are outlined, along with some of its disadvantages.

Model and Situation Specific O.R. Methods: Risk Engineering Reliability Analysis of an L.N.G. Facility

A decision situation and model-specific O.R. method developed for reliability analysis of an Arctic liquid natural gas facility is outlined. It was developed by modifying a decision situation and model-specific O.R. method developed earlier for time (schedule or programme) risk analysis of offshore North Sea projects. The role and value of such methods is discussed in relation to general O.R. methods and specific techniques like C.P.M./PERT.

Application of Veritas Rules For Submarine PipeIines recent Experiences From North Sea Projects

Abstract Introduction The paper addresses four topical areas related to off shore pipelines.The philosophy behind VERITAS Rules for Submarine Pipelines.Statistical information on the operational reliability of land and offshore pipeline systems including North Sea pipeline performance to date.Property planned and executed in-service inspection programs constitute an effective technique for reducing the operational failure rates of offshore lines.Research and development work related to determination of safe (reduced) operating pressures for flawed and dented pipelines and risers. VERITAS Rules for Submarine Pipelines VERITAS Rules for Submarine Pipelines (introduced in (976) are generally accepted throughout the free world as the industry standard. These rules set out minimum requirements related to safety and reliability, but design optimization as such. Appendices contain methods for calculating environmental loads and other specifics. VERITAS Rules do not exclude other methods of assessment, but layout methods used by VERIT AS personnel for certification and inspection of design and fabrication. The nine major functional sections in VERITAS Rules deal with environment loads, strength and in-place stability, materials requirements for pipes and piping components, corrosion protection and weight coating, installation, operations and maintenance, and nondestructive testing. Five appendices pertain to methods for calculating various environmental loads, Buckling calculations, materials quality control and field welding specifications procedures, guidelines for corrosion control, and pressure testing criteria. VERITAS" certification services include: design reviews, risk analysis, fabrication and installation inspection and quality assurance, in-service inspection programs and major commitments to related R&D. This provides the ongoing knowledge used La maintain our Rules for Submarine Pipelines as a state-of- the-art engineering standard. Reliability of Pipeline Systems In 1979 VERITAS conducted a joint industry study to assess the reliability of North Sea pipelines(2). For comparative purposes the study included both major land and marine pipeline systems on a worldwide basis (see Table 1). Although significant differences amongst the data sets for the pipeline systems studied were difficult to compare, several interesting inferences can be drawn. Although failure rates for both land and submarine pipeline systems average well under 1 failure per 1000 km of pipeline per operational year, two causes, corrosion and damage by outside forces account for about 75% of all failures. One may also assume that a significant percentage of external corrosion is initiated by third-party damage and not reported as such. The data also suggests a negative exponential relationship exists between failure rate and pipeline diameter, i.e. as diameter increases, failure rate decreases exponentially. Age-related failures such as corrosion and third-party damage are more manifest in the older small diameter pipelines. Final Acceptance Surveys and In-Service Inspections Advancements in design methodologies, materials and their applications, fabrication and construction procedures, and quality assurance methods will continue to improve submarine pipeline reliability. However, periodic inspections are required for assessment of a pipeline's ongoing suitability for service. Unfortunately inspection programs often suffer from inadequate planning, misappropriation of efforts and inconsistent record keeping.

Risk Engineering: Basic Controlled Interval and Memory Models

Risk engineering models for decision making under uncertainty are illustrated by a succession of increasingly complex example applications. The approach is based upon simple arithmetic procedures which are easy to understand and use. Offshore North Sea projects are the basis for the example applications, but the approach has been used in a range of problem environments in the U.K., Canada and U.S.A. The emphasis is a flexible structure for viewing problems which allows modelling at a level of detail and with a degree of quantification tailored to the needs of the context. The concern is gaining useful insight, not model solution optimisation.

Project Management (North Sea) Basic and Variable Factors

Project Management (North Sea) Project Management (North Sea) Basic and Variable Factors Frankhouser, H.S.; Brown and Root (U.K.) Ltd. Introduction During the past 10 years there has been a major acceleration in size, technical complexity, and cost of North Sea energy development. It is interesting to note that only 14 years ago there were no offshore energy-related structures in the North Sea. Sudden major increases in the price of oil, coupled with periodic supply shortages, made it vital to produce periodic supply shortages, made it vital to produce North Sea oil and gas. With this acceleration in size and complexity, plus the pressure for early production, the U.K. and Norwegian governments production, the U.K. and Norwegian governments became more involved in the control and operation of the developments. The combination of all of these variable and complex factors presents a major challenge for the operators and project management contractors who must work together during the development phase. The effectiveness of cooperation between operators and contractors influences not only the front-end development schedule and cost but also the long-term costs for production, operations, and maintenance. Therefore, it is important to give high priority to an efficient organizational relationship between the operator and the project management contractor. To achieve this efficiency, a working knowledge of the basic elements of project management common to all North Sea projects is essential. These elements are reviewed under the following headings:Engineering,Procurement,Supervision of Fabrication and Installation,Project Control, andAdministration. The project management organization must be designed to provide the performance, coordination, and control of these performance, coordination, and control of these elements. How this is accomplished depends on factors that vary from project to project. Some variable factors are reviewed as follows:the operator's approach to project management, resources, and experience,the contractor's resources, experience, and organization, andschedule requirements. Some organizational relationships are considered under the following headings:Separate Operator and Contractor Teams,Integration, andSeparate Contracts for Management Services and Engineering. Project Management Activities Project Management Activities Engineering Engineering includes initial studies and investigations, conceptual work, detailed design, weight control, quality assurance and quality control, and coordination with and assistance to fabrication contractors and project documentation. Initial Studies and investigations These typically include soil surveys, sea-state and weather studies, pipeline route surveys and, in some cases, pipeline route surveys and, in some cases, preliminary model testing. preliminary model testing. Conceptual Work. Conceptual work involves arriving at a basic technical solution using input from the initial studies and investigations, along with established general specifications and previous experience. This includes specifying the process to be used for handling the oil or gas; the number, size, and type of platforms; the layout of the units on the deck; and the type of offshore loading system or pipeline configuration. pipeline configuration. JPT P. 1821

Chemical Treatments Associated With North Sea Projects

This paper discusses carbonate and sulfate formation in the Forties field and some of the laboratory inhibitor-selection techniques used to evaluate scale inhibitors for field use in the Forties injection and production systems. Two chemical treatments for stimulation injection wells also are described. Introduction Pressure maintenance in the Forties field began in Dec. 1976. Initial water sampling and core injectivity studies indicated that seawater would be a satisfactory injection fluid.Before commencing injection, the chemical treatment requirements for the seawater injection system were determined. The principal requirement at that time was for an effective microbiological treatment. This was discussed in detail in an earlier publication. Since that time the need has arisen for injection of suitable scale inhibitors into both the injection and production systems to prevent calcium carbonate and barium sulfate scale formation. This paper discusses scale formation in the Forties field and some of the scale-inhibitor selection techniques used. In particular, a novel test method is described that is used to monitor inhibition and flow pattern influence on formation scaling.The water quality aspects of North Sea injection water have been discussed in detail previously. In that study numerous core injectivity measurements were carried out, and the major core plugging mechanism was attributed to the organic portion of seawater. Although no similar plugging has been detected downhole, BP Research has developed a suitable well treatment product to remove organic debris. Some of the results of this study are discussed in relation to potential field application. Field Scale Problems Scale problems occurring in the Forties field can be attributed to two major factors:commingling of Forties formation and injection waters andprecipitation of calcium carbonate scale from formation water due to variations in pressure and temperature in production systems. A partial chemical analysis of Forties formation water and North Sea injection water is given in Table 1. It will be seen that the commingling of formation water and seawater can precipitate both barium and strontium sulfates, which probably are the worst types of scale found in oilfield situations. The solubility of barium sulfate has been calculated as a function of temperature and mixing composition. The results are shown in Fig. 1 and are presented as a stability index, which is the logarithm of the ratio of actual barium sulfate present to the barium solubility under the specified conditions. For example, a stability index of +0.3 indicates the actual barium sulfate present exceeds the solubility limit by a factor of 2 (10 (0.3)).The worst condition exists for relatively large amounts of formation water and small amounts of injection water. JPT P. 904＾