The two-stage condition monitoring approach takes account of the fact that, due to the advent of improved lubricant formulations and more efficient filter designs, conventional laboratory oil testing has recently become less useful for extracting timely condition monitoring information. The new approach uses the latest technological advances in imaging hardware combined with ASTM D7684-11 compliant wear debris particle analysis software containing an extensively researched knowledge base that has captured the diagnostic skills and experience of a number of expert wear debris analysts, each with decades of hands-on experience. It offers a cost effective, on-site diagnostic capability to rival that of most specialist labs. First stage testing uses the latest computer vision technology to visualise fine debris. This innovative digital imaging hardware enables on-site maintenance professionals not only to reliably size and count but also to analyse wear debris particles as small as 5 microns, offering timely equipment health information that few laboratories can match. The second stage consists of on-site, in-service filter analysis triggered by the appearance of abnormalities in the fine debris particles during first stage analyses. The innovative, diagnostic wear debris particle analysis software then uses the five level severity rating advocated by the ASTM D7684-11 standard guide such that timely alerts do not allow wear to escalate to a critical level. The paper includes the results of a forensic case study illustrating the way in which a catastrophic bearing failure, costing millions of euros in critical equipment down-time could easily have been avoided had the two-stage condition monitoring methodology been applied. This new approach has the potential to avoid costly, unscheduled, equipment down-time due to the unpredicted failure of critical equipment or equally costly false alarms when equipment is unnecessarily removed from service. This is accomplished by extracting information concerning equipment health from fine wear debris at an early stage in the wear process, where such information has previously only been available by the analysis of large wear debris particles at a much later stage in the equipment wear cycle.

Remote control and automated systems affiliated with Tubular Running Operations have been in use for the past 15 years with varied levels of success. Unsuccessful implementations have not elicited solutions, nor have successful implementations translated into a thriving industry standard. Though the oil and gas industry has changed much over the past 15 years, some of the same implementation challenges still exist. Service providers tend to have a "scattershot" approach to automating everything, rather than a concerted focus on exploiting small successes to realize specific company goals. This factor may be due to differing attitudes throughout the organization, ranging from upper management to business development to engineers. This can lead to the inability to cultivate a culture of technical progression among operators commensurate with the technical progression of equipment. From the service provider's perspective, an unwillingness to learn new technical concepts among operators may yield a general indifference about their own relevance within an automated industry, while the end customer may remain skeptical of the need for automation and become dissatisfied with the overall cost and time needed to implement automated solutions. Historically, industry insiders tended to mistake automation's inability to yield operational efficiency immediately as a failure. Overlooked is the fact that even the most cleverly implemented automation realizes better operational efficiency over time , with constant improvements and further integration. Additionally, some clients fail to realize that control systems are inconsistent from rig to rig. The absence of standardization may stem from corporations assigning more value to the retention of trade secrets than to an industry-wide focus on standardization. The following paper will examine—from the Tubular Running Services (TRS) provider perspective—the challenges associated with developing and deploying remote control and automated equipment. It will also give pragmatic solutions towards the successful implementation of this technology and prove that automation is not solely a technical hurdle for engineering to overcome.

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.

To model a variety of potential operating conditions in pure carbon dioxide (CO 2 ) injection wells we performed a multiphase transient well flow simulation study. A thermal reservoir simulator was also used to estimate the extent of reservoir cooling and the variation of injectivity index to be expected from injection of cold CO 2 . Depleted gas reservoirs are potentially attractive targets for CO 2 but their low pore pressure results in low bottomhole injection pressure and potentially two-phase flow regime in the wellbore. Other authors have noted the possible implications of this condition; however, none have addressed the issue using transient flow simulation. A vertical wellbore model was built in a multi-phase transient flow simulator, assuming representative Southern North Sea conditions. To investigate wellbore profiles of pressure, temperature and CO 2 liquid hold-up, parametric as well as thermal reservoir simulations were performed. The latter simulations integrated the bottomhole conditions observed in the wellbore model. Results show that pure CO 2 injected at the wellhead may vaporize or condense as it travels down the tubing, experiencing continuous changes in pressure and temperature as dictated by its change in enthalpy. However, sudden vaporization or condensation is not predicted by the simulator. Two-phase flow cases resulted in stable injection conditions. Well injectivity index varied significantly with injection fluid temperature and pressure, but the extent of reservoir cooling away from the wellbore was limited. This suggests that onerous processing to avoid a two-phase flow regime in CO 2 injection wells, such as pre-injection heating or downhole choking may not be necessary at the injection start-up into a depleted gas reservoir.

Abstract The first challenge on every brownfield project is to identify the current status of the plant. Drawings and engineering data for the plant are often out of date or unavailable, and many of the older plants have no 3D CAD data available. Various survey techniques have been used over the years, but they tended to be man-hour intensive, produced unreliable data, and were slow in making information available to the design team. Laser scanners delivering point cloud data (PCD) avoid these problems, and, with the ability to reference PCD in the 3D CAD world, make producing a clash-free design in brownfield projects much easier. After testing the Laser Model Interface (LMI) prototype from AVEVA in July 2005, AMEC has now used the LMI on projects offshore around the regions, bringing a new dimension to PDMS brownfield projects in the oil and gas industry. The use of PCD within the PDMS environment has given AMEC the opportunity to reduce project costs, shorten schedules, and improve safety. Introduction The uncertainty of the current status of existing plant has always been an issue on brownfield modification projects, and the lack of drawings and data for the plant compounds the problem. Engineers and designers can spend a lot of non-productive time at the start of a revamp project searching for information necessary to begin the redesign proper. As well as adding to the cost of the project, this delay can also have a serious impact on the schedule. Historically, the industry has not been dilligent in retaining and maintaining the as-built status of the plant, right from original commissioning and design changes, and then through the life of the plant. To bridge this information void, the first activity on brownfield modifications has always been to survey the affected area of plant to capture the current status. As this is a crucial phase of the project, there has been continued development of techniques to accomplish it over the years. Key drivers in this development have been dependency on the accuracy of captured data and the need to reduce the time taken to make this data available to project personnel. The latest innovative solution for capturing existing plant status is a phase-based laser scanner. With the availability of LMI software, which allows PCD to be referenced directly in the 3D design environment, AMEC has been able to save time and reduce both costs and the exposure of personnel to the hazardous offshore environment. The developmental history and principles of this new technology are explained in this white paper. The history of data capture of existing plant. Up to the early 1980s, brownfield modifications of oil and gas plants were designed without the aid of CAD systems. Surveys were also a manual process and very time consuming. Engineers from the project team would visit the asset with sketch pad, measuring stick, and tape measure to review the area of concern and capture as much information as they could. The main problems with these manual techniques were human error in taking measurements, the length of time taken to capture the data, and the probability that areas would be missed, leading to incorrect assumptions or return visits. By the late 1980s, the common practice was to engage a survey company to carry out the plant survey, taking single-point measurements with a theodolite and marking up drawings manually. Accuracy was improved, but this was still a very time-consuming process. In the early 1990s, as the use of CAD became common practice, software was developed to take measurement data directly from the theodolite into the CAD system, automating a previously manual process. Accuracy was maintained and some human error was removed, but the overall process was still time intensive. During the 1990s, there were a number of photogrammetry systems reviewed for use in the industry. Photogrammetry was not new technology, as it had previously been used for land and aerial surveys. The hardware and software was very expensive, and the time required to capture the pictures, scan them, bundle adjust the scans into a single database, and then make the information available to the designers was a very lengthy process. Very accurate results were achieved with photogrammetry, but the high cost and the long delay before the data became available led to little uptake of the technology in the offshore industry.

Abstract Floating units are an integral part of offshore field development schemes. This paper describes the tailor-made methodology developed by our Company for the integrity management of eight major complex floating units in operation worldwide and four units under construction. This program is being progressively implemented throughout 2004–05 with the assistance of selected service companies providing efficient modeling tools as a part of life cycle management and emergency response. These units cover converted and new built FPSOs, concrete and steel structures, shallow and deep water locations, moderate and severe environment conditions, ship and box shaped units as well as one TLP and one Liquefied Petroleum Gas unit. Introduction The aim of Floating Units Integrity Management is to ensure management and continuous follow up of floating units from a safety, environmental, operational, maintenance and quality management viewpoint. It includes recommendations on inspection, maintenance and repairs. This calls for: Structural and anchoring modeling and analysis (1st assessment and subsequent yearly re-assessments). Qualitative RBI implementation (Risk Based Analysis). Yearly reviews of the IRM plan (Inspection, Repair and Maintenance). Data management and storage (including reports). Assistance for Emergency Response. And gives the framework for exceptional analysis. Description and Application of the Floating Units Integrity Management programme First priority for implementation of the programme has been given to the most important assets, i.e. those being operated by our Company and having the function of storage, and/or production, and/or offloading (in short F(P)(S)Us). The F(P)(S)U is a generic term applying to (non exhaustive list) – FSU: Floating Storage Unit. – FPU: Floating Production Unit. – FPSU: Floating Production Storage Unit. – FSO: Floating Storage & Offloading. – FPSO: Floating Production Storage & Offloading. – FPDSO: Floating Production Drilling Storage & Offloading. – FSG: Floating Storage of Gas. – FSGO: Floating Storage of Gas & Offloading. – FPSG: Floating Production and Storage of Gas. – … These units can be ship-shaped or box-shaped or any other shape such as TLPs, SPARs, SEMIs, etc. They can be in steel or concrete and can handle various types of hydrocarbon products (oil, condensates, gas, LPG, LNG, …). The Floating Units Integrity Management programme also applies to the anchoring systems and to the offloading buoys, either coastal or associated with offshore units.

Abstract The paper will illustrate the application of asset-scale modelling and the benefits thereof, including an analysis of the effect of quantifiable risk on development strategy selection. While integration asset modelling (IAM) is not of itself a novel topic, practical applications of the technique applied from sub-surface calculations through to commercial/financial analysis are nevertheless uncommon and those including a rigorous treatment of uncertainty still rarer. Included in the paper will be a brief analysis of both the benefits of IAM and suggestions on why it is perhaps not more widely applied. The main body of the paper, however, will cover two case studies - descriptions of projects carried out using the RAVE (Risk And Value Engineering) IAM software. The first case study will be based upon the Brae asset, operated by Marathon Oil UK. The Brae asset is complex, both technically and commercially, and represents a huge infrastructural investment in the CNS. The paper will illustrate the means by which IAM was used to "see through" this complexity to assist in the forward strategic planning of the asset. The second case study will describe the development of a reserve as a third party tie back to an existing host platform. Use of the approach in this case allowed rapid, value-based analysis of competing development alternatives (such as host selection, artificial lift techniques and well count) including the sub-surface uncertainty inherent in pre-FEED development studies. From the case studies presented here and numerous similar projects, the authors will present the conclusions that risk-inclusive integrated asset modelling is both feasible and valuable in marginal and mature environments. Introduction Modelling and simulation are firmly embedded within the core business processes of upstream oil and gas assets. At every stage of asset development and production, simulation techniques play a vital role in supporting strategic, tactical and operational decisions. It is estimated that the hydrocarbon production industry spends in excess of $2billion annually on hardware, software and associated services, a figure that neglects spending on networks and communications infrastructure. There is a perception though, and a number of published surveys supporting it1, that the industry does not get particularly good value for this level of commitment. Some of the problems associated with IT have been historical; problems with large scale projects, interoperability and early obsolescence, for example. Other more fundamental problems, or opportunities, have arisen more recently. Working practices continue to evolve, placing less reliance on individual disciplines moving to a greater degree of integration within the workplace. IT developments have promised much in this respect but in reality have somewhat lagged behind the pace of change. One practical aspect of this is that while it is common practice to create an integrated development team to pursue opportunities, including subsurface, flow assurance, processing and financial disciplines, that team would be unlikely to have access to an integrated tool with which to work. Addressing this issue is the concept of "Integrated Asset Modelling" or IAM. The idea behind IAM is simple - to create a single model for the entire asset, from geological interpretation through to sales contracts and taxation. The rationale behind this approach is equally simple. After the criteria for health, safety and the environment have been met, a single benchmark for the comparison of operational decisions must include measures of monetary value as well as reserve management indicators and capital utilization.

Abstract Real Time is the new buzz in the upstream petroleum industry. So far, operators have been the main users of data measured at second or minute time increments to manage wells and keep them on production. Engineers usually see only a sub-set of the data - the daily production volumes and rates along with a few select- gauge pressure and temperature readings. The limited data means that they only see the result - the production volumes - and not the reason for a certain production parameter - e.g. choke size, pressures, temperatures. SCADA - Supervisory Control And Data Acquisition - is the system, which connects to the gauges, collects the measured data and stores it in a database. Operators on the platform have direct access to this data and use them to control the wells. If the engineers see this data at all, they usually get them through a web browser interface and in a format they cannot directly use for their analysis. One of the reasons for this is that many SCADA providers come from other industries where the needs are quite different and the network resources are much more substantial. This paper will introduce a new concept of integrating high frequency data up to the management level. Each level of the organization sees as much as they need or want to see of the high frequency data. The engineers have exactly the same view as the operators at the platform - at the same time. This might seem to be a problem at the first, but in the long term, it is an empowerment of the operators and brings engineers and operators closer together working as a team to manage the wells. The data also allowsmanagement to monitor the oil- and gas production leaving the platform to see if the target volumes are reached, or if a well is shut in. Murphy has implemented this system in all of their operated deepwater assets in the Gulf of Mexico. This paper will give insights on how drastically it transformed the way of doing their daily work, how it changed the way operators work together with engineers, and in addition, an outlook of further improvements to the system based on their experience so far. Note: All values in the figures at the end of the SPE paper are randomly generated and do not represent reality. Introduction Horizontal wells and 4D-seismic have been the last major technological advances in the upstream petroleum industry. Now, it appears, as the so-called intelligent field (also called Smart Field, e-field, i-field, etc.) will be the next major technological advance in the industry. But how is intelligent field defined? Phrases such as closed loop and self-controlled can be read in different publications. This is not what we will focus on in this paper, since a closed loop control still has a long way to go until it becomes reality. We will describe to the reader the basics for an intelligent field, starting with the following questions: What are the main problems in this domain What has to be done on the data management side How can high frequency data add value to the asset management process As the water depth of newly discovered reservoirs is getting deeper and deeper, the costs of drilling a well sharply increase. A deepwater well can typically cost USD $15MM to $50MM. The facility to support these wells may cost an additional $200–$1,000+MM. These costs have necessitated well performance monitoring to protect these investments. The wells and the platform are equipped with a variety of different sensors, measuring the performance of the wells and the platform's process train's with seconds to minute time increments.

Abstract High frequency reservoir surveillance data become available in an increasing number of oil and gas fields. Real-time data from both reservoir and surface facilities open the possibility to control and consequently optimize field production in real-time. This real-time control would be a step forward to the industry's next goal - The Smart Field. An integrated software and data approach is presented based on Data Mining methods 1 . In this paper, the "Automation Task" concept is discussed which allows automation of data processing, event detection and user notification. An Expert System interface enables the surveillance engineer to program the software in order to run on a 24/7 basis. Time savings in routine reservoir surveillance and accelerated production through faster and better reservoir management decision were identified as premium goals. Introduction Data Mining methods have been added to conventional reservoir surveillance tools. Methods like Neural Networks provide capabilities which are especially of interest to provide an automated reservoir surveillance tool: learning from data, i.e. deriving models fast execution of trained models (real-time) detecting trend violations in high-dimensional problems error tolerant can handle missing values no predefined model architecture Currently implemented spreadsheet solutions cannot provide a real-time solution. The huge amount of data, automation and time critical operations cannot be handled by such systems. Data handling work is still the doiminating time consumption in routine reservoir surveillance. Spreadsheet solutions can hardly be maintained in a way, that all engineers use the same data and the same software tools (programs) beside their limited storage capacities. Available SCADA systems provide information about individual parameter values. Nevertheless a single pressure gauge does not give the complete picture about field performance and cannot be used directly for production optimization. Therefore real-time surveillance models which include reservoir performance and surface facilities constraints are needed. Value loop in reservoir management SHELL's Smart Field group promotes the value loop concept as basis for the closed-loop control including the main steps of reservoir management data acquisition interpretation and modelling generate and evaluate options execution

Abstract Description : ChevronTexaco believes that global climate change is an important issue and is taking action to address it in a comprehensive way. We recently made publicly available our corporate-wide system for estimating greenhouse gas emissions and energy utilization. This paper specifically focuses on the advantages of using a systematic, auditable energy and greenhouse gas (GHG) management system in a mature oilfield. Material in this paper is based on our experience in using Chevron Texaco's SANGEA™ Emissions Estimating System at upstream locations in the North Sea and worldwide. Results, Observations and Conclusions : A credible, systematic approach, such as the SANGEA™ Emissions Estimating System, provides strategic value to mature fields that are facing increasing constraints on greenhouse gas emissions and increasing energy costs. By having a rigorous and verifiable inventory of greenhouse gas emissions, operators can demonstrate to government and nongovernmental organizations how greenhouse gas emissions change over time as a field ages. In addition, energy utilization and greenhouse gas emission information can be used to guide investments, in order to achieve the maximum energy efficiency and greenhouse gas emissions minimization per barrel produced. Applications : ChevronTexaco's new system, the SANGEA™ Emissions Estimating System, is an automated, electronic data management information system that is designed to gather monthly energy and greenhouse gas emissions data from worldwide exploration and production, refining and marketing, petrochemicals, transportation and coal activities. ChevronTexaco Corporation and its Chevron, Texaco and Caltex facilities enter data to calculate greenhouse gas emissions and energy utilization on a monthly basis. Energy and greenhouse gas emission estimates are reported to ChevronTexaco Corporation each quarter. Technical Contributions : The SANGEA™ Emissions Estimating System is now publicly available. ChevronTexaco is making the system available free of charge in order to promote standardization of methodologies, and to improve comparability of greenhouse gas inventory information across the petroleum industry worldwide. We believe that widespread use of the SANGEA(tm) software will help provide a standard methodology for our industry. The American Petroleum Institute and several petroleum companies around the world have requested review copies of the software system. Introduction Worldwide concern over global climate change has prompted governments and companies to take action to address emissions of greenhouse gases. One important source of greenhouse gases is production and use of fossil fuels. Oil exploration and production activities have come under increased scrutiny by government and nongovernmental agencies for their emissions of greenhouse gases. In order to address these concerns in a meaningful way, a systematic approach is needed. Meaningful, credible data are important both to manage energy utilization and emissions, as well as to provide a basis for common understanding of the unique issues associated with greenhouse gas emissions from mature fields.

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

Abstract Falling wellhead pressures drastically reduce the productivity and economics of a well. If there is a supply nearby of high pressure gas, the well productivity can be increased by using the high pressure energy in an ejector. An extensive programme of laboratory tests and offshore trials has been carried out to ove and optimise ejector design for onshore application. This has included the use of "flexible" multiple nozzles to allow continued effective operation as well pressures reduce. Existing design methods have been significantly improved and embedded into user-friendly software, which has been validated against the results. Ejectors were installed on two platforms in the Phillips operated Hewett Gas Field in the Southern sector of North Sea. Trials have proven very successful, with increases in gas production ranging from 15 to 25 MMSCF/D. In both cases a payback on investment of only a few weeks was achieved. Further opportunities for ejector installation are now being actively sought. Investigations for the use of ejectors for multiphase boosting are continuing. Introduction In 1987, Phillips Petroleum faced a potential shortfall in gas production from the Hewett field. In consultation with CALtec (the Oil and Gas operation of BHR Group), an ejector was identified as a viable solution, whereby the energy from a high pressure group of wells could be used to boost production of depleted wells. As a result, a joint programme of work between CALtec and Phillips Petroleum to improve design and operating knowledge of ejectors for offshore gas pressure boosting was carried out. This involved a combination of laboratory tests, offshore trials and the development of design software. The results of this joint programme, and the benefits achieved from it, are described in this paper. 2. OBJECTIVES To prove the feasibility of using ejectors for gas boosting, and hence increasing production levels. To develop and calibrate thearetical models for compressible flow ejector performance. To compare offshore performance against theoretical model results. To identify methods of improving ejector performance and flexibility. To develop ejector design software. P. 523^

Permission to copy is restricted to an abstract of not more than 300 words. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgement of where and by whom the paper was presented. Publication elsewhere is usually granted upon request provided proper credit is made. Abstract In September 1985, Shell Expro, operating on behalf of the Shell/Esso joint venture in the North Sea, initiated the Structural Integrity Project (SIP) to develop a modern, Project (SIP) to develop a modern, comprehensive, in-house structural analysis facility comprising detailed finite element models of some 15 installations and a database of analysis results. The SIP was established to enable high quality technical assessments to be made in a short period of time and to provide engineering support in the areas of safety, re-certification, emergency response, inspection and maintenance and to assess changes in operational requirements, such as increases in topside weight. Recent work with the completed models of all the steel, concrete and floating/compliant structures indicates that the structural analysis database will be a valuable and cost effective resource for Shell Expro's business needs for the next 10 to 15 years. Introduction Northern Operations Shell U.K. Exploration and Production is the operator (on behalf of Shell/Esso and other co-venturers in the North Sea) of 15 installations in the Central and Northern North Sea. The installations are located in the commissioned Auk, Brent, Fulmar, Cormorant, Dunlin, Tern and Eider Fields. Figure 1 shows the locations of these oil and gas producing fields in the North Sea and the pipeline routes for evacuation of pipeline routes for evacuation of hydrocarbons to shore. Oil exported from the Auk, Fulmar and in future Kittiwake fields is via offshore tanker loading while oil from the Brent field is exported either via pipeline or the Spar. These installations, pipeline or the Spar. These installations, summarised below, are further described with their main structural features in Table 1: – 7 fixed steel platforms; – 5 concrete gravity base platforms; – 1 compliant steel flare structure, fixed to the seabed; – 2 anchored steel floating loading units. Structural Integrity Support As an operator Shell Expro is required to maintain the structural integrity of all its installations in order to be allowed to produce hydrocarbons from the commissioned produce hydrocarbons from the commissioned fields. Regular underwater and above water inspection and maintenance programmes are undertaken to maintain a "Certificate of Fitness" during the in-service period. Also, structural integrity analysis would be undertaken if a structure was impaired by events such as a supply boat collision or in the event of detrimental inspection findings such as fatigue cracks in a critical weld. Timely expert structural engineering advice is therefore necessary to develop well-defined, comprehensive and cost effective programmes for these inspection, maintenance and repair activities. STRUCTURAL INTEGRITY PROJECT In-House Analysis Facility The Structural Integrity Project (SIP) was undertaken to develop an in-house re-analysis capability and structural analysis facility to provide state-of-the-art assessments for ongoing structural integrity management of all its existing installations in the Central and Northern North Sea, and to enable timely response to emergency situations that may arise. The essential features of this structural analysis facility are: – Finite Element Models of each installation developed using a consistent methodology; – Database of analysis results for each installation; – SESAM programs for the generation and analysis of the computer models, and code checking software; – A Structural Integrity Management System (SIMS), comprising user friendly software for storing, accessing, handling of data and running the computer models.

Abstract The paper presents an overview of Shell Expro's Northern Operations and the introduction of a Computer Assisted Operations (C.A.O.) system with the aim to coordinate and manage the offshore production platforms, the pipelines, and the onshore processing plants as an integrated production pipelines, and the onshore processing plants as an integrated production system. Introduction Shell Expro operates on behalf of Shell and Esso a number of oil and gas fields in the British Sector of the North Sea. In order to operate effectively the company has three work locations. See Figure 1. – LONDON : Head Office. – LOWESTOFT : The operations base for the gas fields in the Southern North Sea. – ABERDEEN : The operations base for the fields in the Middle and Northern North Sea.