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Abstract Stringent environmental regulations and higher costs of effluent treatments in oil and gas process industries have necessitated research into ways to improve the operating procedures in effluent treatment plant. In Gas-to-liquid (GTL) plant, a significant quantity of reaction water is produced and various chemicals are used as intermediate treatment chemicals. The reaction water is contaminated by these chemicals which impair the pH and the related properties of the water. The pH has to be controlled before the water is re-used or released to the environment. A laboratory-scale effluent neutralization unit for pH control was designed and built to demonstrate the feasibility of utilising produced carbon dioxide (CO2) from reforming reactions in both the synthesis and hydrogen production units in GTL plant for insitu effluent treatment. At the end of the reaction, the total volume of carbon dioxide used was recorded. This paper presents experimental neutralisation characteristics for different operating conditions. The prime advantage of this process can be thought to be less expensive than other published carbon capture and storage (CCS) processes. Moreover the carbon dioxide does not require further compression, dehydration and storage facilities before usage. Pipeline transportation is also drastically reduced since the captured carbon dioxide is utilised within the plant. This study demonstrated that, the neutralisation time increased by 3.15 minutes with increase in effluent volume from 40 to 60 litres and by 10.4 minutes as the temperature increased from 20oC to 50oC. The increase in the flow rate of carbon dioxide from 15 litres/min to 35 litres/min decreased the neutralization time from 19.15 minutes to 13.32 minutes. Finally it was estimated that about 64% of the daily carbon dioxide production which would have otherwise been emitted to the atmosphere was used in the treatment process. Introduction The fact that the concentrations of carbon dioxide in the atmosphere are increasing is known to environmentalists, researchers and government agencies. The causes of global change lie in the industrial activities of human society and ultimately in the population growth and increase in resource use by man. Human activities have increased carbon dioxide concentrations from approximately 280 to 355ppm since 1800 (Vitousek, 1994). This increase is likely to have climatic consequences on biota in all earth's terrestrial ecosystems. The need to reduce global climate change due to emission of carbon dioxide (CO2) and other greenhouse gases has led to research in carbon capture and sequestration (CCS). Several relatively small-scale carbon capture and sequestration approaches are currently in development and demonstration stages as highlighted by Hoekman, 2010. Direct injection into the oceans has also been suggested but there are a number of uncertainties over the ecological impact and equilibrium of the gas with the atmosphere. In the medium term, depleted oil and gas reserves, unmineable coal seams, and deep saline formations are the best options for carbon dioxide storage. Deep saline formations appear to offer the potential to store several hundreds of years' worth of carbon dioxide emissions. This must be validated, and site selection criteria must be developed and shared internationally to identify the most appropriate storage sites. Wider international collaboration and consensus are critically needed to ensure the viability, availability and permanence of carbon dioxide storage. However carbon capture and sequestration faces both technical and economic challenges. Therefore, there is the need to explore other methods to deal with carbon dioxide emissions. Transformation to chemical feedstock like methanol is a commercially proven technology, however carbon dioxide captured from flue gas from furnaces will not be economical for this purpose because of its low pressure. Recompression is required before the carbon dioxide could be processed to methanol (Ritter et al, 2007). Another well-known process - the Sabatier reaction, converts carbon dioxide to methane as shown in Eq. (1).

Abstract A large number of oil and gas fields in the Peninsular Malaysia basin are screened (masked) by shallow gas, resulting in wipe out zones of the underlying seismic amplitudes as well as push down and time delay (sag) of the structural closure of economical oil or gas fields. Such effects lead to significant uncertainties in resolving and mapping of the objective reservoir units below the shallow gas. On these premises, 3D 4C Ocean Bottom Cable (OBC) seismic survey has been acquired and processed in one of the gas and oil fields in the Malay basin with the objective of resolving the multi-layered reservoir intervals through mode converted shear component data. This paper will discuss the rock physics and properties model that has been developed as part of a 3D 4C PP-PS Joint Seismic Inversion project with the primary objective of delineating and characterizing the various reservoir intervals and depositional environments of the oil and gas accumulation, a first in Petronas Carigali experience in reservoir characterization. This paper focuses on synthesizing missing logs, log conditioning, seismic petrophysical evaluation, rock physics modeling, invasion correction and fluid substitution to the fullwaveform (P- and S-wave) and density logs to make ready for seismic inversion. A total of 10 wells with 8 measured P- and S-wave logs are available for this study. The overall qualities of well logs were adequate for the purpose of this inversion project. These data have been used in the generation of rock physics models. The methodology applied was to construct a rock physics model that is consistent with the petrophysical analysis and the elastic properties as given by the conditioned well log data. The model was then applied everywhere to generate synthetic elastic logs and full offset synthetic seismograms that were then compared and matched to the recorded data respectively. Introduction Well log data are used to understand the relationship between the reservoir properties and subsurface seismic data. Since well log data provide constraints and calibration in the inversion workflow, their quality directly impact the confidence and the accuracy of the inversion results for quantitative interpretation and follow-on reservoir modeling. Well log quality and consistency are subjected to various factors like variation in tool measurements, borehole rugosity, borehole fluids, elapse time between drilling and logging, invasion of borehole fluids into the formations, alteration of the formation properties due to the presence of the borehole and/or borehole fluids, casing points, and missing data. Therefore, the primary goal in processing well log data is to minimize measurement related errors, generate and fill in the missing data, and to obtain consistent and accurate logs between all the wells.

Abstract The term "competence" is generally understood to mean, "the combination of awareness, knowledge, skills and attitude that an individual must demonstrate in order to meet the performance standards required of his or her job." Although the primary use of competence in the international oil and gas industry has been and continues to be the identification and closure of skill and knowledge gaps, new and varied uses are being introduced and refined. Some of these new applications include recruiting (especially in cases where large numbers of nationals are needed for new projects), streaming trainees in entry-level training programs, proving employee competence to government regulators before being allowed to work in environmentally sensitive areas and planning and implementing nationalization of key managerial, administrative and technical positions. The expanded use of competence in various human resources activities comes after a steady refinement of the competency concept over the past three decades, from paper-based applications to sophisticated, multi-module computer software programs. Even the notion of "competencies" has evolved during that period, from a beginning as generic, broadly applicable characteristics, to "topics" and finally to the task-based models commonly used in the international petroleum industry today. This paper will begin by briefly tracing this evolution, highlighting examples in exploration and production organizations from the early 1980s to the present. It will then look at specific real-world examples of the "new" uses that have been introduced in recent years. Finally, it will try to gaze into the future to predict further evolution and future uses of competence in the learning and development of oil and gas industry personnel. Introduction The challenge faced by oil and gas companies around the globe is to achieve strong returns on their assets while maintaining the highest standards of operational safety and efficiency. This requires competent and skilled personnel, a task made all the more difficult because on an ageing workforce, a shortfall in the qualified labor pool and increasing government oversight (Donohue, 2013). Regulators are putting increased pressure on companies in the oil and gas sector to prove that their people are competent. Here competency management is about much more than an individual's personal development; it is one of the principal means to ensuring reduced environmental risks and for assuring the safety of others. In today's world, the imperative is not only to assure the competence of employees but also to prove it (Andrews, 2014). The term "competence" is generally understood to mean, "the combination of awareness, knowledge, skills and attitude that an individual must demonstrate in order to meet the performance standards required of his or her job." Since there are no universally accepted definitions related to competency management, for clarity of understanding we offer this brief glossary of terms used in this paper. Competence: The combination of awareness, knowledge, skills and attitude that an individual must demonstrate in order to meet the performance standards required of his or her job.

Abstract Discrete technology solutions, such as real time data acquisition, distributed temperature sensing, etc. applied on selected-well basis seem to serve field development engineers well sometimes. Nevertheless, for engineers continually to improve field-wide operations and attain the cost and production advantages necessary to stay competitive in an industry shifting to cost-effective applications, integrating workflows is a strategic imperative. Engineers will need to concentrate and excel not just on specific technologies but on holistic rigless operations success driven by more attention to integration than individual technology solutions. The challenge facing asset teams remains how to execute comprehensive plans to make significantly higher returns from capital technology spending in the field. The scope of this paper is to present how engineers have adopted technology integration and alignment of numerous technology solutions for the specific situation of successfully developing and managing a giant oil carbonate field in readiness for a major production milestone. The approach presented entails an all-inclusive project-based method that involves performance reviews, elimination or reduction of idle times through close monitoring of incremental project stages, optimizing operational efficiency through increasing the speed of material delivery to the well sites, and improvement of logistics of people and equipment. The approach involves unifying role-based, process-based, and production workflows throughout the operation and building on a learning curve with each successive rigless operation. From the safe job execution of over 100 rigless activities, a model or scorecard is available to control important variables, assess the effectiveness of specific technologies, and provide support for leading or lagging indicators. As a result of seamless and routine inclusion of technology-based exercises at a project level, rigless activities have been completed over 60% faster than when the campaigns started nearly five years ago. Monetizing this value of technology integration in auditable and quantifiable terms translate to significant gains over the course of the rigless campaign. Through integration, engineers can implement effective programs for improvement in service levels and improve operations. Eventually these gains translate to fewer obstacles to project delivery. Introduction Technology is core and central to Manifa field development. Achievements in the Manifa field are testament that the field development team is savvy about applying fit for purpose technological solutions for lasting/sustainable gains. As a result of measurable improvements and integration of workflows between core technology applications, several world firsts have been credited to the Manifa team (Arukhe et al., 2014). Some of these records include the world's largest extended reach project (more than 75% if the field's wells are ERWs) and the use of the world's first tandem 2.125" CT tractor for ESP open hole completions (Arukhe, Duthie, Al-Ghamdi, Hanbzazah, Almarri, Sidle & Al-Khamees (2014). The first oil industry use of a specialized reusable filtration unit system in a long-term injection test, utilizing primary seawater filtration and chemical treatment was conducted in the field. A reflection of the project, upon successful commissioning of the first phase, reveals that the most critical success factor includes the degree of technology integration into the team's basic strategic approach to field development. The amount of solutions for rigless well interventions and well testing have multiplied considerably lately – from optimizing CT reach, well stimulation, multilateral access, and profiling to well testing. At present, these solutions deliver gains with possibility of influencing more efficient field development. As shown in this paper, technology adoption in CT reach and stimulation treatments results in gains from accelerated job execution and client satisfaction becomes evident. Consequently many wells have been successfully stimulated onshore and offshore.

Abstract Located in the Partitioned Neutral Zone between Kuwait and Saudi Arabia, the South Fawares field has been producing from the Lower Cretaceous Ratawi reservoir since 1956. Several conventional coiled tubing acidizing treatments have been performed to restore productivity from the Ratawi formation. However, due to the formation heterogeneity, limited zonal coverage and inconsistent acid distribution, these treatments resulted in limited improvements to productivity. The objective of this study was to determine the most appropriate re-completion/stimulation technology that could achieve the following: Effectively and evenly stimulate the entire horizontal section,Benefit from the vast network of natural fractures within the formation matrix to further enhance production, andMaintain wellbore integrity. This paper presents a successful pilot project implementing horizontal open hole multistage completion systems for the first time in the South Fawares field. Existing lateral sections drilled across the Ratawi formation in the South Fawares field were segmented into several stages and each stage was fracture acidized separately to achieve optimum acid placement and maximize the net stimulated reservoir volume. The results show that effective wellbore isolation between stages coupled with efficient diversion of the stimulation fluid is key to improved well productivity. This paper highlights the planning, execution and challenges of the installation of these systems with comparisons of pre- and post-stimulation data and offset wells. The success achieved from the first deployment of open hole multistage completion systems in the South Fawares field has opened new opportunities for reviving the productivity of additional depleted wells. Introduction The South Fawares field is situated in the Partitioned Neutral Zone (PNZ) between Kuwait and Saudi Arabia, (Fig. 1), where the natural assets are shared jointly under the Neutral Zone agreement signed in 1922. Since 1949, Saudi Arabian Chevron, a 100% owned subsidiary of Chevron, the Kuwait Gulf Oil Company and their predecessor companies have operated four oil fields in the onshore PNZ. The fields are Humma, South Fawares, South Umm Gudair and Wafra. In 2009, the 60-year agreement between Saudi Arabia and Chevron predecessor, Getty Oil Company was amended and extended for another 30 years. Under this agreement, Chevron operates Saudi Arabia's 50 percent interest and the Kuwait Gulf Oil Company operates Kuwait's 50 percent interest in the PNZ.

Abstract Mature fields are the backbone of global oil and gas production. In fact, 70% of worldwide oil production comes from mature fields. A great deal of knowledge about how to exploit mature fields has been gathered throughout the years. However, as more areas become mature, new situations and new challenges arise. Revitalizing these fields extends their productive life and offers significant opportunity to expand worldwide reserves. New technology is critical when trying to increase hydrocarbons extracted from a field beyond the original expectations. This paper highlights emerging techniques associated with five key aspects of revitalizing mature fields. These are: energizing the reservoir using water and polymer flooding on viscous oil fluids, enhancing reservoir deliverability through pinpoint hydraulic fracturing techniques, assuring optimal injectant placement using lasting, functional smart well completions, and improving the rod pumps by using linear lift systems. Also, while technology plays an indispensable role in revitalizing a mature field, cost control, risk management, and optimizing economics are equally important throughout the decision-making process. This paper describes the impact of each emerging mature field technique and discusses recent advancements in technology that enable a new, distinctive approach to increasing production and recovery during the mature stages of the life of a field. Introduction Mature fields paradoxically average recovery factors as low as 35%. Increasing the recovery factor of these assets by just 1% would add a two-year global supply of oil and gas. While recovery factor increases might be obtained through production optimization techniques, maximized recovery from the reservoir cannot be achieved until improved oil recovery (IOR) and enhanced oil recovery (EOR) methods are implemented. In particular, EOR tends to increase the recovery factor by 5% to 15% and its contribution to mature field production is expected to significantly increase in the near future. Mature fields, when compared to green fields, offer a straightforward path to quick and relatively lower risk access to additional hydrocarbon supplies. Operators often have ample experience with the subsurface characteristics of their fields, i.e. they know where the oil is and likely, where the oil is not. Also, typically a large data base is available for input and history matching of production and reservoir models. In spite of these advantages, implementing a workflow for a holistic approach to solving mature field issues is relatively complex. This is due to the number of processes to be mastered and the number of options available. Assuming a good reservoir characterization and appropriate surface installation are in place, key processes for revitalizing mature fields addressed in this paper are:energizing the assets—options for achieving the required injectivitymaximizing oil sweeping by optimal injectant placement—chemical and mechanical solutionsassuring hydrocarbon delivery to the wellbore—pinpoint fracturing technologiesflowing oil from subsurface to surface—new and simpler artificial liftcorrect timing—a key economic driver In the 'Mature Fields Key Processes and Technologies' section, technologies and achievements for each of these five processes are described in detail.

Abstract While considering CO2 emission from a gas plant, native CO2 significantly contributes to the total amount. Capturing this native CO2 can reduce a lot the green house gases emission and captured CO2 can be valorized for Enhanced Oil Recovery. Due to this, Oil and Gas operators are more and more interested in improving native CO2 recovery technologies. Usually when natural gas contains both CO2 and H2S, they are removed together and sent to Sulfur Recovery Unit resulting in a tail gas containing mainly Nitrogen and CO2. CO2 can then be separated by use of solvent (using MEA e.g.). TOTAL and Air Liquide have developed and patented an innovative process scheme recovering native CO2 and reducing the operating and investment costs. Claus unit fed with pure oxygen instead of air leads to a tail gas stream, containing mainly CO2 and H2. Then, CO2 purification unit allows recovering a CO2 rich stream with purity even up to 99.9%. This purification unit can be either membrane, cryogenic or adsorption technologies, or a combination of them. This paper also discusses about the integration of Oxygen-based Claus technology (OxyClaus), tail gas treatment unit (TGTU) and CO2 purification. The scheme has been studied in detail for specific application to optimize the overall integration. It has been also compared to conventional CO2 capture scheme to highlight its benefits leading to significantly lower CO2 recovery cost. This scheme contributes in many aspects to the current technical knowledge which may include low-cost CO2 capture, use of pure oxygen in the Claus, CO2 purification for EOR etc. Other benefits also include the size reduction of the Claus/TGTU, production of nitrogen stream to be valorized and separated H2-rich stream from CO2 purification unit. This paper will comprise the overall scheme description and discuss some results for the specific case study.

Abstract This paper documents the outcome of an eight-year field study that confirmed how the consistent use of innovative conveyance methods and technologies significantly improved the success rate of fluid sampling programs while reducing the overall cost of the E&P projects in long-reach challenging wells part of the largest development project undertaken in the last 25 years in the UK, North Sea sector. The formation properties encountered by these wells along their trajectories, including long deviated sections, posed massive challenges to the acquisition of critical formation evaluation (FE) data, core samples and representative formation fluid-samples required in these wells. In the early stages of this field development, the most significant risks encountered were differential sticking of the wireline-conveyed sampling tools and differential sticking of the wireline in very permeable reservoir rocks. The direct consequence of a stuck sampling tool is the need to fish the sampling tool first and then recover the required fluid samples using pipe-assisted wireline conveyance methods, a sequence that typically takes five additional days. The additional cost to the Project Partners is $4.0 million, based on five days rig spread costs plus the deferred production revenue losses resulting from the five-day production delay of all development wells not yet drilled/completed from the same installation. During the first eight fluid sampling operations in the development phase of this field the fishing rate was as high as 25%. The development and adoption of modern methods and technologies to manage the conveyance risks identified when performing coaxial packer sampling in 2012 resulted in no wireline fishing jobs (0% fishing rate) and no pipe conveyed logging (PCL) operations required (0% PCL rate) on these UK North Sea projects. The structure of this paper follows:Overview of the oil fields and the development programs subject of this paperCharacterization of the conveyance hazards present in the wells where the wireline logging jobs subject of these paper were executedDetailed description of each of the key wireline risk-reduction technologies used through the duration of these field developments and the roles they played on the success of the wireline logging jobsConclusions and recommendations for similar field developments on wireline risk mitigation

Abstract Field tests of a real-time Drilling Advisory System (DAS) have demonstrated value in several drill well surveillance applications. This system receives drilling data and transmits recommended operating parameters to the driller using existing rig systems and Wellsite Information Transfer Specification (WITS) data records. Using this industry standard, DAS can be deployed to any suitable data acquisition system on the diverse rig equipment available in the industry. The DAS computer may also be connected to a company network to enable desktop viewing of the drilling recommendations in the office. The method embodied in the software comprises both a learning mode and an application mode. In learning mode, systematic changes in parameters are recommended to explore the operating space, and calculation of an objective function determines results. Complex decisions to change operating parameters such as weight on bit, rotary speed, and flow rate can also be made with the assistance of DAS via early detection of drilling dysfunctions which change with depth and formation. The operator's ROP (Rate of Penetration) management process is focused on MSE (Mechanical Specific Energy) surveillance, and the DAS process extends this methodology to a real-time operating system. DAS is designed to assist the driller by capturing and organizing real-time data without imposing on their judgment and control. It is intended to be a digital helper that enhances the driller's ability to interpret current drilling conditions and make effective decisions. Remote access capabilities and customized output to the driller's display were demonstrated in field trials, and key lessons from field trials have been implemented. The field trials included multiple hole sections in onshore and offshore wells across a wide variety of drilling conditions. In one example provided in this paper, the use of DAS provided 35% higher ROP when DAS was used to avoid drilling dysfunctions. Introduction In a recent paper by Dupriest and Koederitz from the 2005 SPE/IADC Drilling Conference ("Maximizing Drill Rates with Real-Time Surveillance of Mechanical Specific Energy": SPE 92194), Figure 1 was presented to illustrate the three basic regions on a drilling response curve. The chart shows that although operating above the founder point may provide slight increase in ROP, the system is operating in dysfunction and the WOB should be reduced to eliminate the dysfunction.

Abstract Deep water fields are subject to higher development costs than more conventional field developments and often have challenging topside and subsurface issues and uncertainties. The level of heterogeneity, compartmentalization, fault intensity, reservoir connectivity, pressure and flow communication across the field, sand/fine production, wellbore stability are commonly less understood at the time the development decision is made. The reservoirs may also consist of very thin beds (cm thick) to thick blocky sands and the reservoir properties / connectivity can vary significantly both laterally and vertically throughout the field. This paper describes a deepwater case study offshore Malaysia, and in particular the challenges of optimizing deepwater Reservoir Management / development in a changing development environment. As a result of some early well failures and associated sand production, TesTrak© pressure data acquired during re-drilling some of the wells has provided an invaluable insight into the complexities of deepwater reservoir development and thin vs thick bed recovery efficiencies. This has led to further development optimization such as the deployment of SMART water injection completions and dedicated thin bed high angle wells as required to solve specific by-passed oil targets. In this paper, the above challenges and reservoir management (RMP) requirements combined with the concerns of the optimized water flooding in a complex deep water field in Malaysia have been studied and discussed. Project Background The K field example is a deepwater development located in 1330 meters water depth offshore Sabah, Malaysia. The field was discovered by the K-1 well drilled to a depth of 3600m in 2002 and marked the start of deepwater development in Malaysia. Development was sanctioned and initiated at a time of relatively low oil price ( The field has been developed via combined subsea and SPAR (dry-tree) infrastructure, and has pressure support via combined water and gas re-injection. Production of first oil occurred on schedule in 2007. The K field has marked a number of firsts in the industry and for Malaysia oilfield development, in the areas of construction & use of facilities, these are documented together with some of more development and production challenges and solutions in earlier publications [1–5]. This successful deepwater development was achieved in collaboration between Murphy Oil Corporation, partners PETRONAS Carigali and PETRONAS Nasional Berhad (PETRONAS), plus all the service company personnel and has resulted in significant deepwater technology transfer into Malaysia. The FPSO, SPAR, FTL and subsea manifolds were all fabricated in Malaysia, in addition a portion of the subsea trees were assembled locally as well.

Abstract The Barzan Onshore Project is being developed by Barzan Gas Company Limited, a joint venture between Qatar Petroleum and ExxonMobil Barzan Limited, with RasGas assigned to develop and operate the facilities on completion. The Engineering, Procurement and Construction (EPC) work is being carried out by JGC as the prime contractor. JGC has sub-contracted the construction execution of the work to eight major sub-contractors. The project has achieved over 90 Million Safe Man-hours since July 2012 when the one lost time incident project to date occurred. The workforce is approaching 29,000 persons from multiple countries. The paper describes the overall SHE&S Management System as a three-tier model based on the EPC contract in which there are 211 SHE&S contract-related deliverables (in eight general categories) measured monthly via the SHE&S Work Activities Schedule. The system pertains to all parties (RasGas, JGC, sub-contractors, vendors, suppliers, et al.) and this rigorous monthly accounting helps drive overall SHE&S performance. The contract combines a highly prescriptive as well as goal-setting approach, which to date has delivered a great foundation to build and sustain SHE&S performance at site. Within the paper, some of the key leading and lagging indicators are reviewed to demonstrate the correlation between the scope of work, stage of project execution, progress and key injury trends occurring at the site. The indicators are actively utilised on the project, especially the leading indicators to drive and sustain SHE&S performance. Six stellar areas and six challenging areas are also reviewed. The stellar areas demonstrate some of the key best practices that are implemented on the project and are producing strong results. The six challenging areas demonstrate some of the complex problems on the project and the methods that are used to improve these problem areas and help ensure that sufficient risk reduction measures and actions are being implemented. Overall SHE performance on the project continues to be strong although there are daily challenges. These challenges are overcome by a strong management commitment as well as a worker-focused programme that continually demonstrates care and concern for the project's most valuable asset, the workforce.

Abstract The main objective of an Asset Integrity Management System (AIMS) is to ensure that the physical assets of facilities and pipeline system are operated in a reliable, efficient, and safe manner. Such motives can include the fitness to function safely and reliably; Consistency with all industry requirements and international standards; Compliance with company's AIMS Philosophy, Operating & Maintenance Philosophy & Engineering Standards/Specifications as well as industry regulations. The AIMS goals shall demonstrate the persona of the company where an inward look into the company's values and shall be subjected to evolution rather than revision. At Dolphin Energy Limited (DEL), the QHSE philosophy of - zero injuries, zero accidents, zero releases and no (minimal potential negative) impact to the public, the surrounding environment, and customers (Zero Leak Thresholds) was support by DEL's implementation of the most appropriate technology available in the world along with KPI development in areas of defect management; specified tolerances; assessing infrastructure fitness-for-purpose & measuring the effectiveness of AIMS activities. This review paper will demonstrate DEL's great focus on proactively understanding the type, extent, and the effect of all potential defects and by implementing a process where such learning is re-injecting and the results are structured and documented. The importance of regular internal reviews of the AIMS to ensure internal conformance, and the appropriate evolution of such approach as well as measuring its effectiveness are all important in making the right decisions in cases where emerging issues are supported and maintained. The AIMS approach shall be proactive where asset safety and reliability start with prevention by utilizing rigorous QA/QC related to design; materials, coatings, cathodic protection system infrastructure, and non-destructive examination. Participation in the initial project development teams & project approval processes and providing Integrity related input/approvals of projects design bases and construction activities are of an extreme value to Asset Management. Generally, aging infrastructure does become susceptible to the manifestation of time-dependent failure mechanisms where monitoring programs shall be structured usually into Operational Monitoring programs as well as large-scale monitoring programs such as (ILI) for pipelines. Any potential issue identified through risk assessment and/or monitoring activities shall be effectively mitigated to ensure Asset Integrity. Mitigation programs of AIMS shall also be addressed and may include regular preventative maintenance programs & repair activities. On the engineering Asset Integrity side, defect data validation studies and Failure Investigation & Root Cause Analysis, defect Assessments and feature growth analysis, risk based inspections (RBI) shall be considered within the AIMS overall structure. Another important component of AIMS is the utilization of application software that will assist in decision making which also can be based on a GIS based platform tool for integrity-related decision making. Such application can perform comprehensive Risk & Data Management capabilities. This review paper shall demonstrate how AIMS at Dolphin Energy Limited has been evolving in the UAE by highlighting the best practices in the industry.

Abstract This paper presents various techniques/ tools used to demonstrate the major Health, Safety and Environment (HSE) risks involved in the tight gas appraisal program, especially in designing the surface facility for the Trial Production Operation (TPO), has been reduced to As Low As Reasonably Practicable (ALARP). In the challenging environment of central Sichuan basin i.e. local hilly terrain and densely populated farm land, the paper looks at the local requirement and importance of the analysis right from the design phase for a safe and efficient operation of the TPO facility. The techniques covered include Hazard Identification (HAZID) Study, Hazard and Operability Study (HAZOP), Safety Integrity Level (SIL)/Instrumented Protective Function (IPF) study, Fire and Explosive Risk Analysis (FERA) and Fire Protection Analysis (FIREPRAN) study. The paper covers the documentation of ALARP demonstration into a Design HSE Case. Major Accidents Hazards (MAH) in the TPO facility are identified using the Risk Assessment Matrix (RAM). A systematic and structured Hazards and Effects Management Process (HEMP) is applied in the design of the TPO facility and the risks associated with MAHs are actively and systematically reduced to ALARP. The effectiveness of all barriers and controls for each MAH are evaluated and complied with the set criteria (Bow-tie assessment). If the HEMP assessment determines that a barrier or risk management of a MAH is only partially effective, further remedial action and effort is done to close the gap. Besides, Safety Critical Elements (SCE) and their performance standards are identified and developed as a key input to the Asset Integrity Process Safety Management (AIPSM) in the operations phase. Finally, the TPO facility design on a plot size of 70m x 70m pad was accepted for construction and trial production. Further improvement study and optimization has been ongoing including taking other unconventional gas (UCG) best practices and learning into the development planning.

Abstract This paper describes the implementation of an optimization advisory system by Sarawak Shell Bhd. on the integrated gas production system in Sarawak, to help monitor and optimize in real-time the more than 100 wells on 30+ facilities of the system, governed by different Production Sharing Contracts. We highlight how multiple disciplines are part of the solution, how the solution has been embedded to provide real-time advisory to planners and operators, and the challenges faced. The technology described in this paper provides real-time advisory on flow rates for individual wells and platforms to network coordination operators to achieve a gas supply that meets overall gas demand for the onshore LNG plants, maximizes revenue from condensates production and CO2 blending, and transparently shows the business value impact of giving preference to short- or long-term optimization objectives. It takes into account existing commercial and contractual constraints, as well as financial and economical elements. The optimization approach is data-driven and features multiple, mutually dependent objectives and constraints. The data-driven approach has proven significantly faster and more practicable than prior physical model-based approaches. Field trials have proven a condensate production increase of up to 7,000bbl/d while at the same time improving Ultimate Recovery of the sweet and sour gas blend of the production system by up to 2 months per 'year of applied optimizer advise'. At the same time, gas nominations are met as they were, and commercial and quality constraints are adhered to. The Return On Investment of this solution has been less than a month. This is one of the first successful attempts to implement truly-real-time optimization in a production environment of this size and complexity, including a complicated set of commercial and contractual constraints. The approach opens the door to application to a wide variety of real, complex, mixed-integer non-linear optimization problems, and their organizational application, such as emissions management and decision support systems for integrated IOR/EOR systems.

Abstract The motive force behind this advanced concept in implementing "Wireless Technology Using Solar Powered" instruments is to get hydrogen sulfide (H2S) and lower explosive level (LEL) signals from an unreachable location where hazardous waste is being handled to a safe centralized control room. Implementing this would reduce the cable cost and the maintenance. This solar power is eco-friendly. With wireless communication, allowing more sophisticated data to be transmitted to the centralized control room; appropriate steps have been taken to install wireless devices in remote location. Such technology plays a progressively essential role in up-to-date industries. The wireless solar powered sensors provide a cost-effective alternative and are being used increasingly for equipment and other applications in a diversity of industrial processes. In addition, its improved remote diagnostics makes plants and operations safer. In this paper, we will cover the benefits and challenges we experienced at the Haradh gas plant while implementing wireless technology to prevent massive threats and destruction to persons, property and equipment. Introduction Wireless technology has been growing exponentially over the years. Consequently, wireless technology developments are providing numerous advantages in gas plants and the operating plans for refineries. These developments are providing new opportunities for enhancing plant performance, reliability and safety while reducing installation and maintenance/operating costs. In Saudi Aramco's business, the safety of employees is at the top of its priorities. Since the lower explosive level (LEL) gas or hydrogen sulfide (H2S) could be present in most of Saudi Aramco's operation facilities, it is mandatory to install LEL/H2S sensors in every location where the hazardous gases are expected. For gas plants and refineries there are a lot of challenges related to monitoring H2S and LEL gas releases. The biggest challenge for monitoring releases of gas in plants is to cover isolated remote field locations such as the oily sumps area outside the plant fence. To overcome this challenge, a new solution was designed to fit this application. This solution can be achieved by installing standalone wireless H2S and LEL detectors powered by solar cells plus batteries, beacon and horn. The system consists of different equipment that is using Saudi Aramco standards as well as international standards. The International Society of Automation (ISA) standard for wireless systems - Process Control and Related Applications - is ISA 100.11a [3, 5]. This paper reviews the use of H2S and LEL solar powered wireless sensors for safe operation in gas plants and refineries. The paper also addresses the system design and integration.

Abstract Hawiyah Gas Plant at Saudi Aramco recently commissioned a thermal oxidizer. The thermal oxidizer unit has two main functions that shall be achieved. The first function is to oxidize and destroy the Acid gas which has minute quantities of BTX. The BTX shall be fully destroyed at a temperature above 1800 deg F. The second main function of the unit is to provide heating media for the hot water which is used in the re-boiler of the DGA stripper in sweet gas treating unit. The hot water temperature controller has a set point of 350 Deg F thus providing constant water temperatures to the gas treat process. Hawiyah gas plant will share through this paper the internal effort to rectify the original control philosophy design problems submitted by the equipment vendor of the thermal oxidizer that fail to accommodate both functions at the same time. The paper will shed the light on all of the new innovative major advance control loops configured to achieve the appropriate hot water temperature, combustion chamber temperature in addition to the Oxygen trimming advance control. The new control scheme helps the plant to achieve more reliable system to any process changes, it helps to maintain the targeted process parameters set points and optimize the fuel consumption. Hawiyah Gas Plant will present the actual reduced figures in the fuel consumption after the modification and shows the improved in the equipment reliability. In the first part of the paper, brief description of HGP process will be shown. And In this introduction, the role and function of the Gas Treating unit 6 and its thermal oxidizer units will be discussed. Then there will brief disciption of the basic start up and firing scheme for the thermal oxidizer. After that, the paper will discuss the refractory dry out and the heat up requirements and how this is achieved by the logic.

Abstract Over the past decade, the role of natural gas has become increasingly important in fulfilling the ever-increasing energy needs of the world. Natural Gas has not only become an integral part of the world's energy portfolio but also offers a cleaner and more efficient fuel to help reduce carbon emissions when compared to oil. Recently, Saudi Aramco has made three major offshore, high pressure, non-associated gas discoveries. A large bore completion design was selected for these fields in order to bring these discoveries on line quickly and cost effectively. The surface controlled, sub-surface safety valve is a critical component of the asset integrity management program for these gas wells. In order to meet the requirements of completion design and reservoir pressure, the world's first 9-5/8in 10,000psi rated TRSSSV were developed tested and qualified for these developments. As part of qualification testing, high rate slam closure testing of the TRSSSV was carried out at the Southwest Research Institute and at GL Nobel Denton facilities. The objective of the tests was to ensure that TRSSSV closes, seals and continues functioning after a slam at the highest anticipated flow velocity in the wells. Additionally, slam test results were used to design surface and subsurface components that are required to operate the TRSSSV and must be capable of withstanding the shock load produced by a slam closure. Two leading completion companies were selected to develop and provide the TRSSSVs for these projects. Both designs suffered initial failures, required significant modification, and underwent extensive tests before the final designs were successfully tested. This paper discusses the basis of design, test criterion, results and lessons learned from the slam testing of the world's first 9-5/8in, 10,000 psi rated TRSSSV. The paper also provides an overview of the two test facilities used, their limitations, and recommendations for future tests.

Abstract: Due to constructive role of technology developments in petroleum industry and their affects in reducing the costs of drilling, it is necessary to use future technologies. One of these new progresses taking very effective role in drilling industry is to get use of laser in drilling processes. The aim of this paper is to categorize and represent the different study results and also to analysis the principle and advantages of laser drilling. Compared to prevalent drilling, laser drilling is capable to augment the efficiency of drilling and solve its problems such as increasing the rate of penetration, monitoring the bottom hole, diminishing equipment and drilling process, but faces some problems such as laser beam transference, cleaning the down hole. As a result, the benefits of laser drilling overcome the problems and it can be replaced or combined in bits in early future. in this paper we showed the result of using laser technology during drilling operation. Also, In this paper we experiments on changing wavelength transmitted during fracturing and drilling.

Abstract Most wells and particularly high-pressure wells are susceptible to gunshock damage when they are perforated with inappropriate gun systems and/or under suboptimal conditions. This paper presents a simulation methodology to predict gunshock loads for tubing-conveyed and wireline-conveyed perforating jobs. When planning perforating jobs in high-pressure wells, engineers strive to minimize the risk of equipment damage due to gunshock loads. The methodology described here helps engineers to identify perforating jobs with significant risk of gunshock related damaged, such as bent tubing and unset or otherwise damaged packers. When predicted gunshock loads are larger than the admissible loads, changes to the perforating equipment or job execution parameters are sought to reduce gunshock loads. This methodology enables completion engineers to evaluate the sensitivity of gunshock loads to changes in gun type, charge type, shot density and distribution, tubing size and length, number of shock absorbers, rathole length, and placement/setting of packers, among others. Fast gauge pressure data from perforating jobs shows that when model specifications are representative of the actual perforating jobs, the predicted wellbore pressure transients are accurate both in magnitude and time. Peak sustained pressure amplitudes at the gauges are on average within 10% of simulated values. With the methodology presented in this paper, engineers can evaluate perforating job designs in a short time, and they can optimize perforating jobs by reducing gunshock loads and equipment costs. The ability to predict and reduce gunshock loads and its associated damage is very important because of the high cost associated with most wells, particularly high-pressure wells. With the software presented in this paper engineers can optimize well perforating designs by minimizing the risk of gunshock related damage and the associated rig time losses.

Abstract Peninsular Malaysia Operations (PMO) plays an important role in supplying gas demand throughout the region since the gas business commencement in 1980's. Currently about 600 MMscfd gas is supplied by PMO. At the moment, three non-associated gas (NAG) fields, namely DYG, RSK, and TBC contribute to about 50% of the total gas supply from PMO. Apart from producing NAG, the RSK and DYG fields also serve as network hubs to evacuate gas to the Onshore Gas Terminal (OGT) through two independent gas delivery systems: Joint Delivery System (JDS) and Resak Delivery System (RDS) respectively. The two JDS and RDS gas streams are mixed at OGT and then delivered to the customer processing plant, with a CO2 maximum limit of 8% by mole. Apart from the many operational challenges to sustain gas production, meeting the gas specification proves to be a difficult task, especially for the RDS where TBC gas (with about 30–40% CO2) is to be blended with RSK gas (itself producing about 23% CO2).The TBC gas was put on stream in 2011 and an Acid Gas Removal System (AGRS) was deployed to reduce CO2 content. Prior and upon commissioning of the AGRS facility, feed of CO2 level into the gas network was managed by optimizing the flow rate. This paper describes some major challenges in sustaining the gas production supply and meeting the gas quality requirement. The major operational challenges include subsurface uncertainty and problems, maintaining gas compression reliability, AGRS operations and optimizing the usage of gas pipeline network. To complete the analysis, some commercial aspects are also discussed in the paper. Introduction This section consists of two parts:overview of gas business in Peninsular Malaysia andoverview on RSK/DYG field operations. The first part would be introducing the gas market in Peninsular as well as the strategy of fulfilling the gas demand. The second part would be describing the RSK/DYG field operations as the focus of this paper.

Abstract Inception and General Principle of the paper: The oil and gas industry is an ever shifting paradigm with new happenings which is not only represented through its exploration practices, the inception of new technology, the corresponding implementation of this technology, but is also represented by subsequent and corresponding changes in the techno legal framework as well, which is also needed to be fully appreciated in order to understand the global demand of petroleum and its subsequent by-products which clearly are the driving force of any economy today, hereby enabling even the weakest of countries to determine the political, economic and trade related fate of other Developed countries. Application and Significance of the Proposed research paper: The research paper attempts at a comparative analysis between the various contractual regimes with respect to oil exploration and the subsequent production between developed countries such as USA etc. and developing countries such as China, India while also tracking the subsequent changes and global practices in other oil rich countries such as Iraq, UAE etc. who invariably shape the oil and petroleum needs of various countries. During this course we shall subsequently study successful operations engaged in various models by different countries such as Consessional models, Production sharing arrangement, joint ventures, Service agreements etc., Hereby manifesting and displaying various approaches taken by carious countries, analyzing the same and understanding certain constraints which can/could have been rectified.

Abstract With the increasing demand for natural gas, fracturing fluid technology needs to develop to enable optimized well completion operations with minimum ecological impact. The recent development of environmentally friendly polymer-free fracturing fluids — with superior operational performance —represents a major technological advance in the petroleum industry. The use of these new fluids during fracturing operations has the following benefits: minimized environmental footprint and formation damage, operational efficiency and simplicity, and maximized fracture conductivity. This paper discusses the first successful deployment, of an environmentally friendly polymer-free fracturing fluid, during on-the-fly proppant fracturing in Saudi Arabia. Also, the paper discusses the optimum layout of the fracturing equipment used during the job execution. The fluid was used to fracture a gas zone located between two water zones. Therefore, one of the main objectives of the treatment was to control the height of the fracture to not break through and contaminate the water-bearing zones. In addition, the fluid exhibited a low friction pressure and excellent proppant-carrying capacity. Moreover, the overall cost of this fracturing operation is in line with conventional, polymer-based fluid fracturing approaches. Evaluation of the post-treatment results demonstrated the following: very positive well productivity, improved fracture geometry (longer fractures with better height containment), and faster fracture cleanup time.

Abstract Geographically, coal-bed methane exploration or development has occurred on every continent with the exception of Antarctica. Worldwide, many different completion techniques have been utilized to develop coal-bed methane reservoirs. These techniques range from vertical well multi seam completions to multiple lateral wellbores drilled into a single coal seam. Stimulation techniques include open-hole under-ream, cavity creation, and hydraulic fracturing. A number of factors influence the selection of completion techniques including proximity to established oil and gas infrastructure, depth, number and thickness of coal seams, permeability, gas content, composition, and saturation, porosity, etc. The purpose of this paper is to survey the various techniques that have been utilized, to provide the rationale for utilization of each technique, to comment on the commercial success of the various techniques, and to propose a general selection criteria approach that may be useful in the selection of a drilling and completion technique. Introduction While CBM well drilling and completion permutations may be practically endless, the following summary descriptions will be covered in this paper: Vertical well, open-hole and under-ream completion, single seamVertical well, cased and open-hole, perforate and under-ream completion, multi-seamVertical well, open-hole cavity completion, single seamVertical well, cased perforated, hydraulic fracture completion, multi seam Plug and Perforate Ball and Baffle Multiple Zone Stimulation Technology (MZST)Vertical well, open-hole under-ream with intercepting single or multiple surface to in-seam open-hole horizontal well(s), single seamVertical well, open-hole under-ream with intercepting a surface to in-seam open-hole multi-lateral horizontal well Other techniques not listed here can generally be considered to be a variation or combination of one or more of these techniques. Many authors have proposed methods for determining the optimum drilling and completion method [1, 2, 3]. These methods have consisted of flow diagrams, empirical studies, and reliance on a few critical reservoir parameters and form the basis for conceptual understanding of the problem. This paper will present an overview of the various CBM drilling and completion techniques; reservoir parameters that need to be considered in the selection of drilling and completion techniques; and a proposed methodology for selecting optimum drilling and completion techniques will be proposed.

Abstract Developed amidst some of the most challenging offset brown fields in the S clusters offshore East Malaysia, SS field has undergone a rigorous drilling and completions campaign extending from Q4-2009 to Q1-2011(i.e. 15 months). 14 wells with downhole flow control solution plus 3 water injectors for long-term pressure maintenance were planned. A campaign of 12 'passive' Inflow Control Devices, ICD's wells and 2 'active' cost-effective surface-controllable intelligent wells was executed with success. All wells are horizontal to optimize well counts in penetrating more layers and drainage across entire reservoir of approximate 40m thick oil column. However as predicted in the dynamic reservoir modeling, under the huge threat of a large and expanding gas cap (i.e. m size of 2) coupled with the underlying moderate aquifer strength of imposing water encroachment; all the wells, if completed without downhole flow control, will get early gas and/or water breakthrough in a matters of days/months with huge oil bypassed. Hence, the notions of smart and/or advance completions for downhole inflow control solution are to promote this field development into solving the predicted sub-optimal production in order to achieve the target recovery factor of at least 30% in this challenging multi-stalked, very heterogeneous and highly-dipping reservoir. In this paper, all the twelve (12) ICD's wells plus the two (2) intelligent wells post-execution production analysis will be discussed. A post-mortem of the effectiveness of such innovative solution is performed to assess the production impact on SS field with some wells' production data available more than two years'. From the good success case studies of the high-performance wells, post-production profiles have indicated a huge transformation towards realising more oil incremental while reducing the cost of handling less water and gas. However, lesson-learnt can also be drawn from a few of the so-called "Could-have-been-better-performers". This is then highlighted with the way forwards plan to both further sustain production and look-ahead into applying the best practices of such technology pilots to other asset development and conceptual. This paper could provide an eye-opening insight into some of the best-kept value of downhole flow control application with actual production impact and data analysis.

Abstract Aiming at the requirement of pipelines' seismic design, the code of "Seismic Technical Code for Oil and Gas Transmission Pipeline Engineering" was published, and the code presented the seismic design method of pipelines subjected to active fault, and pointed out that finite element method is necessary when pipeline is axial compressed. Based on the strain calculation method proposed by the code, this paper discuss the influence factors such as pipeline-fault angle and pipeline buried depth, then presents pipeline strain variation trend when subjected to active fault movement. Meanwhile, this paper adopts finite element method to analyze pipeline strain distribution, and points out that pipeline strain is composed of axial tension/compress strain and bend strain, which could explain the pipeline strain distribution, and the elliptic phenomenon of pipeline should be considered in the future research works and code revision. This paper provides the technical reference for pipeline seismic design.

Abstract This paper presents a theory on layout PDC cutters in force-balanced groups. A group of cutters consists of two or three single-set cutters, which is able to efficiently remove a ring of rock. By carefully selecting the order of layout cutter groups, a new feature of a PDC bit is obtained: any three or four consecutive cutters on a bit profile may form a force-balanced cutter group, which ensures the efficient removal of any ring of rock. The concepts are verified by a core PDC bit and by a full-scale PDC bit in laboratory tests. Two field applications are provided in the paper to further validate the theory. Introduction It is well known that cutter layout on a PDC bit plays a key role in bit stability and drilling efficiency. In today's PDC bit, cutters are laid out according to two general principles: single set or track set. A single-set cutter layout is defined as having no cutters at the same radial or axial position after cutters are rotationally projected into a radial plane passing through bit axis (this is referred to as bit profile in the industry). On the other hand, a track-set layout is defined as having at least two cutters at the same radial and axial positions on a bit profile but on different blades. In most track-set designs, cutters on primary blades are single set, and cutters on minor blades are redundant to those on primary blades. An extreme version of track set is called track loc, where there is only one primary blade, and cutters on all other blades are redundant to those on the primary blade (Weaver and Clayton 1993). Fig. 1A, 1B, and 1C depict single set, track set and track loc, respectively. As can be seen from the figure, the major difference is the engagement area or width of indentation of cutters while drilling. The single-set cutter has the smallest indentation width, and the track loc cutter has the largest indentation width. According to lab and field tests, a PDC bit with single-set cutters drills much more efficiently than a PDC bit with track-set cutters (Besson et al. 2000). On the other hand, a PDC bit with track-loc cutters is extremely stable but extremely inefficient. Bit stability may be enhanced by laying out the cutters so that the bit lateral forces are balanced or minimized. This is called a "force-balanced" PDC bit (Glowka 1989, Behr et al. 1993, and Clayton et al. 2005). In some applications, cutters are laid out so that a large lateral imbalance force (as high as 15–20% of WOB) is created and directed toward a so-called low-friction gauge pad, which is located on one side of the bit. The bit is called an "anti-whirl" PDC bit (Brett et al. 1989 and Warren et al. 1990). Successful field applications of this technology have been reported (Warren et al. 1990). In this paper, it is found that the force-balanced condition of a PDC bit with single-set cutters may be violated during transit formation drilling. A new cutter layout procedure is proposed, which not only ensures the force-balanced condition during transit drilling, but also improves drilling efficiency significantly. The concepts developed in the paper are first verified by laboratory tests of a core PDC head and then a full PDC bit. Two case studies of the new bits in drilling through hard and transit formations are detailed in the paper.

Abstract Reservoir monitoring is an essential tool to optimize oil production. Among other techniques, water tracers are very useful to understand complex flow patterns that may arise between injection and production wells during waterflood operations. This paper proposes an innovative approach for developing new fluorescent tracers based on silica nanoparticles; it describes their synthesis and properties during coreflood experiments. The new nanoparticles can be coded with various fluorophores, which can be easily detected using on-site equipment offering direct tracer quantification and even on-line monitoring capabilities. Silica nanoparticles containing one or more organic dyes or lanthanide-based fluorophores were synthesized. The versatility of the synthesis procedure allows coding the nanoparticles with theoretically dozens of tagging combinations. The sol-gel synthesis technique yields 50-nm-diameter nanoparticles which are treated to tune their surface properties. The conservative tracer behavior of such nanoparticles is ensured by proper surface functionalization, and is demonstrated by coreflood experiments. This virtually large tracer library is combined to a unique time-delay fluorescence detection technique which allows simple on-site tracer quantification on multiple nanoparticle types with minimal sample preparation. Introduction InterWell Tracer Tests (IWTT) are routinely used in the petroleum industry (Du and Guan 2005). This technique allows gathering informations on well-to-well connections and subsurface flow paths. Aqueous tracers can be split in two main groups upon their function: passive tracers which travel at the same velocity as the injected water and partitioning tracers which are partly soluble in oil, leading to a delay in their breakthrough. Used along with passive tracers, partitioning tracers permit to evaluate the remaining oil saturation in the contacted zone (Tang 1991, Tang, 1992, Tang 1995, Wood 1990, Deeds 2000, Dwarakanath 1999, Jin 1995, Jin 1997, Mariner 1999). Tracers can be selected in the following families: naturally occurring tracers (isotopic or ionic composition footprints), radioactive isotopes, and chemical derivatives (Du and Guan 2005, Hutchins 1991). Each family possesses its own advantages and limitation: restricting regulation on radioactive tracers can make them difficult to implement on field in some areas; chemical tracers such as fluorobenzoic acids (FBAs) have become routinely used for field tracer campaigns as they can be detected with a low detection limit. However they require fine analyses which cannot be performed in standard labs. Moreover, in each family the number of available chemical tracers remains limited when repeated tracer campaigns are required on the same field over time. This paper describes the design of nanoparticles as tracers and coreflood tests to assess their propagation in porous media. Rare-earth based organometallic complexes are known to possess a long fluorescence lifetime. A low detection limit of the nanoparticles can be achieved by incorporating such complexes. Taking advantage of the fluorescence lifetime differences, background fluorescence from organic oil contaminant of the sample is suppressed using time-resolved fluorescence detection. The nanobeads associate the transport behavior of nanoparticles in porous media with the fluorescence properties of rare-earth elements complexes to give access to easily detectable passive tracer.

Abstract The Oil and Gas Gathering and Processing facilities at West Kuwait field of Kuwait Oil Compnay operates turbine driven multistage (LP/HP) centrifugal compressor for transportation of produced gas. The main challenge for these facilities is to operate it at lower production capacities at many instaces due to various reasons. The crude oil processing units of these facilities were able to operate smoothly for as low as 25% of design capacity. However, the turn down ratio for gas compressors was limited to 55%. This limitation was resulting in offloading of compressor and subsequent gas flaring when facility was operated at lower production rates. The main reason for compressor offload was availability of single Anti-surge control valve & control system to prevent surge and also to control capacity. This was limiting the lower operating range of compressor. The non-availability of required High Pressure or Low Pressure Gas was resulting in frequent opening of Anti-surge valve which was offloading HP stage of compressor. A modification was done to install a recycle valve in parallel to Anti-surge valve. Moreover, a control system was also modified for independent control of compressor capacity. This has significantly increased the turndown ratio of compressor. This paper shares a field experience of limitation of compressor operating range without dedicated recycle valve for capacity control and provides guideline for designing and installing independent recycle control system for capacity control to increase lower operating range of centrifugal compressor. It was observed that actual turndown ratio of compressor improved from 55%to 20% after installing an independent recycle valve for capacity control. This improvement has increased capability to operate Gathering Centre at lower production rates without gas flaring. The paper justifies need for installation of a dedicated recycle valve for capacity control in parallel to Anti surge valve to increase turndown ratio of multistage centrifugal compressor.

Abstract This paper describes the full cycle of 4D seismic data integration comprised of workflows related to 4D data analysis, quality control of reservoir models and reservoir model updating using both 4D seismic and well production data. These workflows are applied to a deepwater field, where high quality 4D seismic data is available. In the first step, we analyze 4D seismic data and extract multiple attributes to image changes in reservoir properties. Next, we apply different workflows which link 4D seismic data with the reservoir model. Finally, we update the reservoir model automatically by simultaneously honoring the 4D seismic and well production data. We use a novel approach which incorporates 4D seismic amplitude differences without explicitly modeling the full physics in a joint history matching workflow. Introduction Reservoir monitoring using 4D seismic data is becoming an increasingly important tool for reservoir management (Calvert, 2005). Nevertheless, the quantitative integration of both 4D seismic and historical production data into reservoir simulation models is a challenging task, which recently has become an active direction of research. Huang et al. (1997) applied a stochastic optimization method to minimize the mismatch between synthetic and observed seismic data over a reservoir to achieve simultaneous history-matching of 4D seismic and well-by-well production data. Landa (1997) proposed a gradient-based method to integrate both 4D seismic and pressure transient data. Stephen et al. (2006) developed a workflow for multiple-model history matching through simultaneous comparison of spatial information extracted from 4D seismic data as well as individual well-production data. Employing the Neigbourhood Algorithm (NA) as the sampling engine this workflow was applied to the North Sea Schiehallion field. Skjervheim et al. (2007) presented a version of the Ensemble Kalman Filter (EnKF) for continuous model updating capable to match a combination of production and 4D seismic data. They tested the method on a synthetic case and a North Sea field case. Jin et al. (2007, 2008) proposed the combination of the Very Fast Simulated Annealing (VFSA) method with pilot-point parameterization to solve the 4D seismic history-matching inverse problem and applied the workflow to a synthetic case. Castro (2006) proposed a probabilistic approach to perturb a high-resolution 3D geocellular model for integrating data from diverse sources, such as well logs, geological information, 3D/4D seismic, and production data. This workflow was successfully applied on a reservoir of the Oseberg field. Jin et al. (2011) also proposed a flood front based 4D seismic history matching workflow. In this paper, we present a case study of the full cycle of 4D seismic data integration ranging from basic and qualitative 4D attribute analysis to the advanced 4D seismic history matching workflow. 4D seismic attributes analysis This workflow provides an analysis of 4D seismic differences related to changes in reservoir properties. First, timeshifts between baseline and monitor 3D seismic volumes are computed through cross-correlation. Some initial data preparation usually takes place before the cross-correlation of the datasets, including automatic gain control and trace stacking for signal to noise ratio enhancement. Next, the computed timeshift is removed from the monitor survey in order to obtain meaningful 4D difference attributes. At that point, 4D seismic attributes can be extracted from a given gate around time horizons of interest - usually reservoir tops. For reservoirs with large lateral thickness change, top and base reservoir horizons should be used for attribute calculation. Different types of attributes can be extracted, such as the root mean square (RMS), the normalized RMS difference (NRMSD), etc.

Abstract This paper will review the leading indicator research findings drawn from analyzing a large Energy industry data set. The source of research includes QHSEmanagement system practices and data spanning over 100 countries involving some global industry leading companies such as ExxonMobil, ConocoPhillips, Shell, Chevron, OMV, and multiple others. From the analytical research and careful review with industry QHSE executives and Subject Matter Experts, the factors that were found to best predict the Safety outcome performance of an organization included measurements of (a) proactive event reporting (Reporting Culture), (b) the discipline and consistency in execution of QHSE processes, (c) the timeliness in closure of important corrective / preventive actions, and finally (d) the responsiveness of supervisors and line managers. In each of these key areas, solid performance can be attributed to the tone set by leadership and the influential day-to-day behavior of field supervision and line management. So, throughout this paper we will emphasize how engaging these leaders is imperative to improving the above factors and driving QHSE outcome performance. This paper will also review some actionable leading metrics which can be calculated to measure the factors that have been found to be uniquely strong in organizations who continue to sustain top-level Safety lagging performance. We will review some creative solutions to reach out to front-line workers and leaders to engage them directly in the process of continuously improving these factors. And finally, we will outline a sample process for implementing practical, "actionable" leading metrics in each key area to drive line manager / leadership behavior and ultimately improve QHSE performance outcomes. Background: Researching world-wide Energy data set to find Safety leading indicators The companies involved in the research project provided their data on a scale that spans thousands of operating facilities in over 100 countries. Engaged in this initiative are world-wide operations from multiple Energy companies which have world-class QHSE performance… as well as leading companies in Oil Field Services, Chemicals, Manufacturing, and other industries where managing operational risks is a material concern. Although most of the companies referenced in this study deploy unique company-specific programs for managing QHSE performance, they share one thing in common. Each of them is applying a common technology solution to collect and analyze data from a myriad of "risk reduction" events such as incident investigations, near miss reports, management system audits, risk assessments, assurance reviews, behavioral observations, field-level inspection programs, hazard analysis, and many other processes. As depicted in the below diagram, the intended scope of this database is to be the organization's collection of all events that result in risk reduction actions.

Abstract This paper provides an overview of the Deepwater Integrity Assurance program being developed by Shell for ensuring integrity and reliability of deepwater facilities at minimum technical and commercial risks through a prognostic and holistic suite of tools and techniques. The strategy and workflow processes for design and implementation of the program are described with focus on four major areas shown in Figure 1: 1) Riser Integrity Assurance (RIA) - developing a toolkit to inspect and monitor critical components of risers during the operations phase and ultimately recommending the operational strategies to assure the riser system integrity is maintained cost effectively, operationally safe and reliably, 2) Floating Structure Integrity Assurance (FSIA) - developing intelligent prognostic health management systems to accurately predict deterioration levels and estimate remaining useful life of floating structures, 3) Ultralight Material Application (UMA) - facilitating deepwater development by utilizing and identifying right integrity management technology with high fidelity for lightweight materials, such as high strength steel and composite. A fundamental understanding is required for these 'materials of the future' to ensure appropriate design guidelines and a lifecycle integrity assurance, 4) Subsea System Integrity Assurance (SSIA) - developing a non-intrusive screening tool to enable continuous monitoring of wall thickness of subsea pipelines. A long term outlook for the above main areas is maturation of the core technologies (see Figure 2) to achieve and maintain excellence in asset integrity through a systematic approach focusing on realizing 'Our assets are safe and we know it' and supporting extended life assessments for ageing facilities, whilst enabling less manning of offshore structures in the future. This will allow operators to assess the real time condition of their integrated deepwater production system and determine cost effective methods to maximize systems integrity. The principles and experiences outlined in this paper will be of direct interest to professionals interested and engaged in improving both the safety and the performance of deepwater facilities for oil and gas production.

Abstract In the past, a workflow was internally developed in eni for the field scale study of geomechanical effects induced by reservoir depletion. This workflow, however, included non-automated procedures as well as simplifications related to the geometry description, such as smearing of faults and a simplified treatment of layer pinch-outs. Recently, in the framework of cooperation between eni and Simulia, new features were implemented in the finite element simulator Abaqus. A fully automated workflow, completely manageable in Abaqus/CAE, is now available that significantly changes the approach and the capabilities of geomechanical reservoir modelling. Moreover, new iterative linear solvers were implemented in the code, allowing for increasingly larger models to be run on parallel machines, with grid resolution approaching that of reservoir static and dynamic simulation studies. In the present paper, the new workflow is described with reference to a field scale geomechanical study. The finite element grid is automatically built starting from the flow dynamic corner point model with the possibility of interactively adjusting elements and nodes, performing up- and down-scaling and detecting faults. The geostatic equilibration is automatically performed and the material properties and load history are applied within Abaqus/CAE to run the simulation. As shown in the example application, the capabilities developed in Abaqus/CAE are a significant innovation for reservoir geomechanical simulations: they allow overcoming the limitations of the previous workflow and simultaneously providing significant automation. 1.0 Introduction The study of field scale geomechanical processes in a hydrocarbon field mainly concerns the compaction of producing soil layers and the associated subsidence. These phenomena have a great impact on the field productive behavior in terms of variation of the reservoir properties, reduction of well rates, casing collapse and well failure and an impact on the environment in terms of land subsidence due to on shore withdrawal and land subsidence near the coast line. The evaluation of reservoir compaction and surface subsidence induced by hydrocarbon production then represents a big issue to oil companies and geomechanical analysis play a key role for monitoring and controlling the exploitation of the field. Geomechanical studies are mainly performed by eni through the finite element code Abaqus provided by Dassault Systèmes Simulia. Input data of these simulations directly come from the dynamic model built with Eclipse (Schlumberger, 2011) which is the flow simulator currently used. A workflow was developed internally by eni and described in (Capasso and Mantica, 2006) in order to study the geomechanical effects due to field scale reservoir depletion through Abaqus. The automation of this procedure and some improvements which allow for a more precise evaluation of stress and strain at reservoir scale is presented in this paper with reference to a test case. A reservoir modeler plug-in, which covers all the steps of this standard workflow for subsidence studies, has been implemented. Each task of the workflow is listed in a Guided User Interface (GUI): a few steps are performed outside of the plug-in, but their statuses are documented within the plug-in and they are properly executed in Abaqus/CAE. All information entered by the user is stored on the custom data base on a model-by-model basis and is persistent across sessions. This allows for providing significant automation and makes it easier to the user to complete all the steps for the creation of a geomechanical model.

Abstract In water depths greater than 150 meters hundreds of oil and gas discoveries have been made and deemed non-commercial for one reason or another. Many of these fields are in concessions or leases without any hope of near term development because the conventional approach for developing an offshore field requiring a MODU, subsea completions, and some type of floating production system is cost prohibitive. Also, many of the current concession holders without deep water experience feel deep water technology is too complex and risky to venture into without a super-major or major independent with deep water experience as their operating partner. Also, geophysical technology has delineated hundreds of high probability deep water oil and gas leads that will not be drilled because the indicated field sizes are too small. Yet the history of basin development clearly shows most of the big fields are found first and are few. Most of the further discoveries follow a log normal distribution where size of the field reduces but the frequency of the smaller fields increases. The challenge is how to make these marginal deep water oil and gas fields commercial. This paper presents the Self Standing Riser (SSR) technology as an enabling technology which could be the solution for commercializing non-economic deep water oil and gas fields. This paper describes the SSR and how it can enable lower cost drilling, achieve faster first oil, lower the required capital that is necessary to commission a project, and how the early production can be used to provide capital to complete the project. A field test of an SSR in 1000 meters of water for nearly four and a half years is cited as well as the next steps to use the SSR for a marginal field development (see Figure 1 showing the buoyancy device after 2 years). How the SSR provides a new way for intervention in deep water using coiled tubing, and the possibility for developing deep water heavy oil and other applications also will be discussed.

I Abstract This paper covers the recent developments of drilling systems automation and demonstrates that this technology application is at a tipping point; this is a point at which immense change is about to occur. The authors are key members of the SPE Drilling Systems Automation Technology Section; one organizes key industry workshops and panel sessions, the other implements autonomous drilling systems. Knowledge of the status and imminent growth of this revolutionary application of technology is vitally important to businesses within the upstream oil and gas industry. Understanding the recent history, the drivers and barriers and the expected future applications of automation in drilling and completion operations is critical to extracting maximum value from oil and gas field developments. Automated drilling of shallow multi-lateral wells using downhole directional data as surface equipment input has been demonstrated. Improvements in re-entry operations using automation of downhole processes have also been proven. Significant increases in reliability of downhole drilling tools (a doubling of mean time between failure) have been accomplished by improvements in drilling control systems. The paper provides a review of recent developments in drilling systems automation and describes how this technology is expected to evolve. This information is current, known to a small group within the industry and of huge value to everyone involved in reducing drilling and completion costs. The subject matter will enable customers to take good decisions on selecting new technology, reduce drilling and completion costs by applying a technology that can consistently operate at best in class performance and offset the limitations in the number of experienced industry personnel available for hire. II Introduction Automation of drilling systems offers significant value through many arenas: consistency in performance, maximizing performance, reduction in operating costs, improved safety. Pursuit of drilling systems automation is growing rapidly with many applications being published but equally as many or more going unpublished as companies seek to gain the advantage in application. This "hidden" growth will result in a faster adoption rate than the industry perceives from public knowledge. Drilling automation can be traced back to early applications in the 1970's / 80's. The earliest complete drilling rig automation application is the National Automated Drilling Machine (NADM) - a singles rig with hydraulic power under central control built and tested circa 1980. Although this early leader was not commercialized due to technical issues operating fragile sensors in a drilling environment, it was certainly a bold step in technology application. The significant application of variable frequency electric drives and the advancement in sensor technology provides the basis for rapid and successful application of automated control systems. In the 1990's, significant work has been accomplished in the application of control systems to surface equipment particularly in handling pipe. Rotary steerable systems also demonstrated closed loop control. While these progressed, areas of significant opportunity involving automation of drilling processes are only recently being addressed.

Abstract In this paper we describe the challenges and the techniques used to deliver zero perforation skin wells in the Blacktip gas field offshore Australia. We describe the software models used to evaluate both the well perforation design and the operational risks, and the approach used to reduce rig time. Software modelling based on historical experimental data and newly developed rock perforating models, showed that cleanup with dynamic underbalance would deliver the highest well productivity. Minimum rig time utilization was achieved with wireline conveyed guns. Two methods of deployment were used. To perforate long intervals quickly and safely guns were conveyed on wireline and anchored in the casing with a system that automatically dropped the entire string into the sump after firing. This technique requires less rig time, but it is only applicable to wells with a total gunstring weight lower than the wireline safe working load. The second technique for multiple spaced out payzones used conventional, multiple wireline trips. All relevant aspects of the perforating jobs, including gun carrier filling after firing, wellbore pressure waves, reservoir flow, and perforation tunnel cleanup were predicted. For each job, guns were custom loaded so as to produce enough dynamic underbalance (DUB) to remove the low permeability crushed rock zone around perforations, thus minimizing perforation skin and maximizing well productivity. The Blacktip wells were safely perforated for Eni Australia. In addition, we achieved the objective of zero perforation skin and saved more than one day of rig time. The technologies described in this paper can be applied worldwide, saving significant amounts of money and delivering highly productive wells. Introduction The Blacktip field is located in the Timor Sea, Australia, approximately 110 km offshore in the Bonaparte Basin, at a water depth of 50 meters.

Abstract The purpose of this paper is to present the DC power supply for unmanned remote wellhead platforms (WHP). In several recent WHP projects, there are a number of difference aspects in Bongkot and Arthit Fields in the PTTEP's Gulf of Thailand and one of them is the DC power supply. PTTEP by Wellhead platform department intends to standardize the design of DC power generation for Generic Wellhead Platforms (Generic WHP) for either Bongkot or Arthit fields. Offshore wellhead platforms have been powered by various power generation technologies such as Gas engine generator, Diesel engine generator, Closed cycle vapor turbogenerator (CCVT), Thermoelectric generator (TEG) including renewable energy technologies such as Solar power system and Wind turbine generator. Both Solar power system and TEG are widely used as DC power generation for offshore remote wellhead platforms to power platform DC loads such as PLC, SCADA, and Radio system. Technical evaluation for various DC power supply will be presented. The scope of this paper is to discuss and recommend the most suitable DC power generation configuration for the Generic Wellhead Platforms focus on techno-economic with consideration of optimum point of reliability, economy, and environment. In addition, all calculations of system equipment sizing for the selected DC power generation configuration for generic WHP will be detailed in this paper. 1. Introduction The existing wellhead platforms (WHPs) of PTTEP in Bongkot and Arthit field are equipped with various types and configurations of DC power generation system. The Bongkot WHPs in old phase (e.g. phase 3E, 3F and 3G) are equipped with Closed Cycle Vapour Turbogenerator (CCVT) as main DC power generation, while the recent development Bongkot WHPs phase 4A are equipped with Thermoelectric Generator (TEG). The TEG system has been also installed in Arthit WHPs phase 1A (i.e. AWP 2–6). During design development for Arthit WHPs phase 1B (i.e. AWP 7–10), the Solar & TEG hybrid DC power system was first introduced and implemented as main DC power generation system for PTTEP WHPs in order to improve platform power availability and reliability. The Solar & TEG hybrid DC power system has been continuously used for recent Arthit WHP development project such as Arthit North project.

Abstract Artificial Intelligence techniques have been used in petroleum engineering to predict various reservoir properties such as porosity, permeability, water saturation, lithofacie and wellbore stability. The most extensively used of these techniques is Artificial Neural Networks (ANN). More recent techniques such as Support Vector Machines (SVM) have featured in the literature with better performance indices. However, SVM has not been widely embraced in petroleum engineering as a possibly better alternative to ANN. ANN has been reported to have a lot of limitations such as its lack of global optima. On the other hand, SVM has been introduced as a generalization of the Tikhonov Regularization procedure that ensures its global optima and offers ease of training. This paper presents a comparative study of the application of ANN and SVM models in the prediction of porosity and permeability of oil and gas reservoirs with carbonate platforms. Six datasets obtained from oil and gas reservoirs in two different geographical locations were used for the training, testing and validation of the models using the stratified sampling approach rather than the conventional static method of data division. The results showed that the SVM model performed better than the popularly used Feed forward Back propagation ANN with higher correlation coefficients and lower root mean squared errors. The SVM was also faster in terms of execution time. Hence, this work presents SVM as a possible alternative to ANN, especially, in the characterization of oil and gas reservoir properties. The new SVM model will assist petroleum exploration engineers to estimate various reservoir properties with better accuracy, leading to reduced exploration time and increased production. 1. Introduction Petrophysical properties such as porosity and permeability are two important properties of oil and gas reservoirs that relate to the amount of fluid in them and their ability to flow. These properties have significant impact on petroleum field operations and reservoir management. They both serve as standard indicators of reservoir quality in the oil and gas industry (Jong-Se, 2005). Porosity is the percentage of voids and open spaces in a rock or sedimentary deposit. The greater the porosity of a rock, the greater its ability to hold water and other materials, such as oil. It is an important consideration when attempting to evaluate the potential volume of hydrocarbons contained in a reservoir (Schlumberger, 2007a). Permeability is the ease with which fluid is transmitted through a rock's pore space. It is a measure of how interconnected the individual pore spaces are in a rock or sediment (Schlumberger, 2007b). It is a key parameter associated with the characterization of any hydrocarbon reservoir. In fact, many Petroleum Engineering problems cannot be solved without having an accurate permeability value. Many reports such as Ali (1994) and Mohagheh (1994) have featured the successful application of Artificial Neural Networks (ANN) as the pioneer Artificial Intelligence (AI) technique in oil and gas reservoir characterization over the years. Despite this, ANN has been reported to have some drawbacks (Petrus et al., 1995). The recent introduction of Support Vector Machines (SVM) that is based on the concepts of Tikhonov Regularization and Structural Risk Minimization (SRM) was introduced to overcome some of the limitations of ANN. Many reports such as such as Anifowose and Abdulraheem (2010); and Helmy et al. (2010) have presented SVM as a promising predictive technique in a good number of applications. This paper focuses on the study and analysis of the comparative performance of ANN and SVM in the prediction of porosity and permeability of some Middle East and American oil and gas reservoirs. To achieve this aim, Section 2 presents a succinct survey of ANN and SVM. Section 3 describes the experimental methodology, structure of datasets and the evaluation criteria for the study. Section 4 presents the results of the study with a detailed discussion while conclusion is presented in Section 5.

Abstract For about 25 years the oil industry has disposed of waste into the deep underground (drill cuttings, mud chemicals, sludge, produced water and sand, crude-contaminated soils, etc.). Small-scale annular injection projects are typical for disposing of the waste produced in single drilling campaigns, but large-scale projects are also ongoing using dedicated injection sites, where oil companies are able to dispose up to hundreds of thousands of tonnes of waste every year. Most commonly, the technique consists of preparing a slurry comprising waste liquid and finely divided solid waste grains, and injecting it through wells into the deep underground. To ensure injectivity, the operations take place at pressures sufficient to induce hydraulic fractures in the target rock. Once injection ceases, pressures decline, fractures close, solid waste particles remain entrapped by stress, and the excess liquid dissipates through porous media flow. There are two critical feasibility factors. The first is geological suitability: injection should take place in tectonically passive regions into sedimentary strata of high porosity and permeability. The presence of impermeable strata above the injection zone will protect shallow groundwater from contamination with the injected fluids. The second factor is that the injection process is executed with advanced monitoring techniques and periodic well assessment to provide accurate and updated operational control while establishing best operating parameters, minimizing environmental risk, and complying with regulatory needs. This paper discusses these aspects along with suggested guidelines in the context of several field case histories. If such critical factors are resolved satisfactorily, wastes become isolated permanently with minimum risk to potable water sources, surface watercourses, or the sea. Furthermore, organic waste injection (e.g. human and animal biosolids, organic refuse) will also reduce CO2 emissions, and most of the carbon remains deep underground in solid form, the most secure approach to sequestration. Deep waste injection is seldom used outside the oil industry; however, there are strong economic and environmental incentives for application to other waste streams. The most desirable stratigraphic conditions are typical of hydrocarbon-containing sedimentary basins where impermeable layers overlying porous and permeable strata have kept hydrocarbons in place for millions of years. Thus, primary candidate sites are likely to be old depleted reservoirs. Also, in a hydrocarbon province, stratigraphic data, operational experience, and technological expertise are available for its implementation. This paper focuses on deep waste injection potential in new geographical areas, analyzing it as a disposal technique for different municipal and industrial waste streams. Although many of the technical and social issues are valid worldwide, the situation in Europe deserves particular attention:• The environmental pressure on most European countries is large and increasing because of many densely-populated and heavily industrialized areas;• Public awareness of the need to protect the environment has constantly been growing, driving the European Union toward approval of stricter regulations;• Many geographical regions corresponding to the major sedimentary basins and flatlands in Europe are likely to be suitable;• It is cost-effective compared to current disposal techniques used in Europe for most municipal and industrial waste streams;• Despite no specific country-scale regulations to date, European Union law already includes deep underground injection as a permitted waste disposal method.

Abstract This paper addresses hydrate mitigation in the presence of damaged insulation on production well jumpers in a Deepwater Field. The damage severity was sufficient to potentially require all well jumpers be replaced. The analysis described in the paper was performed to assess the viability of modifying the hydrate mitigation strategy instead of replacing the well jumpers or performing insitu repairs to the insulation. This work assesses the impact that insulation cracks have on well jumper cooldown time for Deepwater Operations. For this assessment, the estimated exposed surface area in the worst jumper did not exceed 4%. This is based on a field survey conducted in the fourth quarter of 2008. A safety factor of approximately two times the estimated exposed area was used to calculate the cooldown time. To represent the worst-case scenario, cooldown times were calculated assuming that the jumper would be gas-filled. Moreover, two extreme cases under forced convection heat transfer were assumed: first, that the fluid inside the jumper would be fully mixed and second, that stagnant fluid would be inside the jumper. Analysis by ExxonMobil indicated hydrate formation for the stagnant fluid case was not sufficient to form a blockage requiring hydrate remediation. For the fully mixed case, the shortest cooldown time observed was 3 hours for the worst damaged jumper. Based on these results, methanol displacement of the jumpers before cooldown time is exceeded, is recommended to avoid hydrate formation. In case of formation of a hydrate plug, depressurization followed by methanol displacement should be performed to dissociate the hydrate plug. Introduction The subsea architecture for this Deepwater Field consists of a number of subsea production wells that are tied into several subsea production manifolds via well jumpers. The production manifolds are connected to subsea flowlines and risers, which transport the production fluids to a Floating Production, Storage, and Offloading (FPSO) vessel. The wellheads, well jumpers, production manifolds, flowline, riser, and jumpers are sufficiently insulated such that production fluid temperature during normal operating conditions is maintained above the hydrate formation temperature (HFT) and the wax appearance temperature (WAT). During an unplanned shutdown, the insulation on the subsea equipment is sufficient to allow for an 8 hour time period for operations to correct the cause of the shutdown. This time period is known as the decision time. At the end of the decision time period, the flowline, risers, production manifolds, and associated jumpers are displaced by circulating dead crude through the production system. The subsea architecture is developed such that dead crude from the FPSO can becirculated down one production riser through production manifolds and back to the FPSO via a second flowline and up that flowline's corresponding riser. The cooldown time provided by the insulation is sufficient to allow for the decision time and displacement time before the production fluids cool to HFT. The wellhead and well jumpers must be mitigated before decision time in order to prevent hydrate formation in the wellheads and well jumpers. The hydrate mitigation of the wellheads and well jumpers consists of displacing them with methanol. The methanol is pumped through tubes in a service umbilical line from the FPSO to the wellheads and well jumpers. This process begins at the fourth hour of the shut-in (light touch time) and is completed by the eighth hour of the shut-in (decision time).

Abstract Over the last decade, TOTAL E&P Qatar had taken every opportunity to enhance the performance of Al-Khalij field while mitigating operational associated risks by implementing the new technologies offered by the Oil and Gas industry. The recent technology implemented by TOTAL E&P Qatar, in October 2008, is the DuaLife Pod system. The aim of implementing this technology is to gain the following benefits:·Reduce operational costs by decreasing the number of wells workovers.·Reduce deferred production by having a redundant ESP in case the main ESP fails.·Well-protected ESP, increasing the run life of the well completions.·Prevent further degradation of damaged or corroded production casing. This paper will discuss the processes implemented from conception, design, preparation and procedures for the successful completion of this DuaLife system implemented recently in one of TOTAL E&P Qatar wells. Also the paper will highlight the best practices and lessons learnt from this initial implementation for future implementations.

Abstract Significant performance improvement has been achieved by successfully managing drilling vibrations through bottomhole assembly (BHA) redesign. This effort has resulted in increased footage per day and reduced tool damage. Prior literature has described improvements in operating practices to manage vibrations(1,2) as a key component of this ROP (rate of penetration) management process. In a parallel work activity, the redesign efforts have provided additional performance improvements of approximately 36% in one drilling application. Dynamic modeling of the BHA has identified the key design changes leading to these improvements. The redesigned BHA has lower calculated vibration indices than the standard BHA. The BHA design evaluation process uses a frequency-domain lateral dynamic model in both pre-drill forecast and post-drill hindcast modes. BHA lateral vibrations are characterized such that alternative BHA configurations may be developed and compared directly with a proposed baseline assembly. In the hindcast mode, the BHA model can be operated at the recorded WOB and RPM to generate corresponding model results in time or depth, and these values can be compared to the measured performance data. In one case study, the redesign of a BHA with downhole motor and roller reamer is described, with corresponding field data for four original BHA's and four redesigned assemblies. In a second application, model and field drilling results for two rotary steerable assemblies are compared to evaluate the predictive ability of the model in smaller hole size and with different BHA types. Finally, the utility of the model to identify preferred rotary speed "sweet spots" is demonstrated in a motor BHA operating in larger hole. Introduction Two prior publications describe the basic methodology that has been developed to model BHA lateral vibrations. The first paper(3) provides a general description of the model and presents case studies of four field applications of this model. The second reference(4) is a study of 13 BHA runs in the same field, for which slightly different BHA designs and operating parameters were used. The Appendix of the second paper comprises a detailed mathematical description of the basics of this frequency-domain lateral vibrations model, known as VybsTM. The present paper illustrates the application of these methods to a new set of BHA design problems in a joint study conducted by RasGas and ExxonMobil. Briefly, the modeling process begins with an input panel that is populated with mechanical dimensions of the components of the BHA, usually up to the heavy-weight drillpipe (HWDP), with about the same level of detail as a fishing diagram. It is important that the positions of the contact point constraints are entered correctly, and that the stiffness and inertial properties of the assembly are a proper representation of the subject BHA. Then the desired operating parameters for drilling need to be provided, including the anticipated ranges of bit weight (WOB) and rotation rate (RPM). The linear modeling process considers a dynamic perturbation about the static state. The model employs two vibration modes to compare and contrast the response of each candidate BHA design: lateral bending and twirl. In the lateral bending vibration mode, an identical reference bit side force input is applied to each design, and the magnitudes of the response at other locations along the BHA are compared. In the twirl mode, an identical mass eccentricity is applied to each model element to investigate the stability of the BHA to eccentric mass and centrifugal force effects.

This reference is for an abstract only. A full paper was not submitted for this conference. Abstract The oil and gas upstream industries operate on its strength of its natural resources, its infrastructure, processing facility and technology, human resources and the most important energy products market demands. If one of the factors fluctuates, it affects the industry operations, planning and production. By nature everything is not gifted there are strengths and weakness, resources without capital, knowledge without management, will to do but lack of technology, strength in execution but with no quality no core know how, success with no sustainability, vision with no decision making, and so on so forth. To be a successful venture it is important to make use of best available resources and meet rest of shortcoming by best possible practical approaches. Every one could be a master in his own domain expert but to be a master of all in a particular capital venture one need to understand all available data collectively as teams and groups by analyzing, sharing experience, know how and knowledge. Data exists in various forms such as paper and electronic documents, charts, maps, tables, digital formats in drawings, maps, pixels, blog objects etc. The row / column formats of a relational database tables are widely used in structuring the data. Database Software based format like Ms Access, Oracle, Foxpro, DB2, MS Sql etc. There are a number of image/raster/pixel formats BMP, JPG, GIF, TIFF, Geotif, etc. with different compression techniques. The vector drawings and GIS Maps also have different formats viz. dwg, dgn, dxf, mif, shp, cov, gdb etc. To make optimal use of data a user need data delivery format has to be defined for every data collection methods with associated metadata. Data can be organized when a purpose for its usage are well defined. A user defined data format in operation will fetch ready to use data for analysis with no inconvenience. Data handling should cover various aspects of data evolution such as setting standard formats, procedures and its work flow for data collection to interpretation analysis, storage, archival, retrieval and access controls. Data is a representation of particular property of defined objects or entities, data has no knowledge in its raw form, Deriving useful knowledge from large mass of data may involve simple qualitative or quantitative assessments, statistical techniques, discrete algorithms, empirical methods, intensive computation and research application sciences. The process of data collection and its analysis, interpretation, usage application can be termed as Data to knowledge Engineering (DKE). A sound organization management will have a team of Data to knowledge Engineering experts (DKE) who stimulates the exchange of ideas, views, facts, and makes useful efficient decision. The DKE experts has to be derived from various domain specialization with multidisciplinary experiences so as to solve real world problems practically with at most efficiency. The DKE group of experts to operate in a multidisciplinary approach, integrating its research groups excellence in model, hypothesis, empirical equations, discrete algorithms, statistical techniques and application engineering sciences. For example, in our Geological and Geophysical (GG) Software portfolio we have Landmark software including: GeoGraphix for geological interpretation, Seis Vision for geophysical interpretation, ProMAX for seismic processing and GeoProbe for 3D visualization and interpretation Roxar RMS for reservoir modeling; Surfer for mapping; PrizM for Log Analysis, and many more. In petroleum upstream industry major capital decisions are made by the data analysis of Exploration & Production (E&P). The E&P involves a great deal of analysis of Geology and Geophysics data. The G&G data are being continuously produced in giga bytes and terra bytes, how to integrate various data formats, how to analyse, how to model and interpret, how to store and retrieve with simple equerry and search tools, how to display and visualize in 2D & 3D space and 4D space & time are all every day challenge problems in E&P data processing and management offices. There are a number of G&G software available commercially as tools to analyse Oil and Gas formations, reservoirs, well logs, bore holes, geology, geophysics, geochemistry etc. To a name a few GeoFramme, GeoGraphix, Roxar RMS, ProMax, Seis vision, Landmark, PrizM, GIS etc. This paper concentrates in the use geographic Information System GIS technology for Oil and Gas industries. This paper will show how GIS technologies can be used for various types of G&G spatial data and associated non spatial data management, processing, modeling, analysis, quering and presentation and extends how voluminous terrabites of data can be stored, retrieved, archived and managed efficiently for its knowledge management in oil and gas upstream industry. GIS technology is becoming a main stream tool for Facilities palnning and management, Enhanced oil recovery EOR studies, Reservoir modeling, Carbon sequestration. The paper involves reviewing various published work with citation slides. This paper's author is an Applied Geologist, works as GIS coordinators in Qatar Petroleum's Ras Laffan Industrial City, he has been using GIS for over two decades, this presentation will cover most of the examples produced using the ESRI's ArcGIS software tools, however the author recommends to use a blend of various other OGC compliance GIS software tools and maintain the data in industry interprobable formats.

This reference is for an abstract only. A full paper was not submitted for this conference. Abstract Description This paper describes the project management processes used to design and procure the topsides facilities for the Gumusut-Kakap project. Gumusut-Kakap is a "mega-project" to be installed in Malaysian deepwater to produce up to 150,000 bpd sales quality oil whilst injecting up to 220,000 bpd seawater and up to 300 MMscfd gas to the reservoir. The topsides facilities are thus world-class in scale. They will be supported on a new-build, moored semi-submersible, receiving production from subsea wells. Interfaces between the topsides and the hull, the subsea systems and the export pipeline are complex and are described in the paper. The topsides execution strategy is aligned to the project's drivers: Safety, Technical Integrity, Capability Development, Schedule and Cost. These drivers were enforced throughout the FEED phase which was executed in Shell's US design centre and the Detailed Design phase which was transitioned to a Malaysian EPC contractor to facilitate Capability Development, Schedule and Cost. The challenges, plans and learnings from this transition are described in the paper. The project management processes developed in Shell's deepwater projects group were adapted for the Gumusut-Kakap project and used to support the EPC contractor. Key processes implemented include: Design Verification, Weight Management, Interface Management and Flawless Start-Up, enabled through key Information Technology (IT) tools. These processes and their customisation are described in this paper. The results presented in the paper will be applicable to mega-projects, especially those in areas developing local capabilities. The conclusions are:Alignment of stakeholders on the project drivers is vitalContractor capability is a key areas to address in transition planning and capability developmentProject management processes need to be customised for the particular project The technical contribution of this paper is through:Base plan for transitioning a design from a company center to the host countryImproved techniques for developing capability of key contractorsEnhanced tools for managing complex project interfaces Acknowledgement The authors would like to thank the management of Sabah Shell Petroleum Company and their Gumusut-Kakap joint-venturers: Petronas-Carigali, Conoco-Phillips and Murphy Oil for their permission to publish this abstract.

This reference is for an abstract only. A full paper was not submitted for this conference. Abstract Description: Managing the safety of very large construction workforces (over 25,000) made up of workers from very diverse backgrounds and experience levels can be a major undertaking on any project. The Qatargas 2 Onshore Project experience involved building two mega LNG trains, each capable of producing 7.8 million tons of LNG per annum, and associated storage and export facilities in Ras Laffan Industrial City in the State of Qatar. At peak activity levels, the workforce exceeded 28,000 workers originating from more than 30 countries, with a majority having relatively low experience levels. Managing the safety of this workforce involved craft and safety training, proper personnel protective equipment, managed work schedules, multilingual communication programs, acclimitization and special programs to combat the harsh Middle East summers, and a comprehensive set of structured safety programs designed to be effective for a large number of workers. Underpinning all these was an uncompromising management commitment to safety characterized by the project goal "Nobody Gets Hurt." The first priority was to provide basic safety training and instill personal safety awareness and a strong safety culture in the workforce. This was especially important and challenging considering many of the workers came from non-industrial backgrounds. Also critical at a very early stage was proactively addressing the numerous worker health and welfare needs created by a diverse workforce of this size. With a relatively short project duration, it was imperative to reduce the chances of having worker injuries as quickly as possible. To achieve this goal, comprehensive, tailored training programs were required, as well as safety programs which were designed with two things in mind - 1) to allow individual supervisors and workers to more easily understand and relate to their job and related safety requirements, and, 2) to enable effective implementation of these programs, involving many workers across a large, high-activity site (at peak activity, there were more than 300 cranes on site). The QG2 Project has expended more than 250 million work hours to date and achieved safety levels of 0.02 Lost Time Injuries/200,000 work-hours. Management leadership and commitment at all levels of the organization in strong partnership with the Contrator leadership was instrumental in overcoming numerous challenges and achieving this safety performance. This paper will discuss the challenges faced and the key safety programs employed including Competency and Training, Heat Stress Prevention, Leading Indicators and Worker Welfare Programs. Application: Recommendations, lessons learned, and future opportunities for effective management of safety on future large-scale projects of a similar nature. Results and Conclusions: The key success factors for effective safety management of these types of large, onshore construction workforces include strong and visible management commitment and safety leadership between owner and contractors, continuous safety program 2 IPTC 12446 innovation and enhancement, a vigorous company/contractor partnership, structured programs targeting the essential elements of safety, concern for worker welfare, use of recognition programs, and commitment to learning from both internal and external project safety experiences. Technical Contributions Not applicable.

Abstract Non renewable groundwater resources in some dry areas are the unique source of water for all activities and sectors and therefore constitute strategic reserves for more than ever with the expected water shortage in the near future. Contamination due to the infiltration of pollutants coming from oil and gas industries is one of the major risks that are jeopardizing these valuable resources. Various systems of vulnerability evaluation have been developed so far. This paper discusses the widespread methods prior to introduce and discuss the new mapping method we propose for oil and gas upstream activities. The rationale for the DKR overlays mapping method is linked to time of travel and the quantity of contaminants that move from the surface to the aquifer. The vulnerability is linked to the arrival of a contaminant at the water-table. This easy-to-implement method assesses vulnerability with limited consideration of the specific characteristics of the hydrogeological system or the behavior of contaminants. The three key parameters considered are:Depth to water-table (D);Hydraulic conductivity (K) of the upper geologic layers in the unsaturated zoneThe retention capacity (R) of the geologic formations of the unsaturated zoneThis simple yet useful method is developed to be used as a decision making tool when dealing with groundwater protection in oil and gas activities. Introduction Algeria is facing water scarcity problems so that water resources are well below the threshold set by the World Bank1. The annual supply of water per capita is less than 35 m3 and demand is by far exceeding supply2. Thus, it is crucial to preserve and protect all strategic Groundwater Reserves (G.R.) not only for meeting the current demand, but mainly, to preserve them for coming generations. Since E&P activities in Algeria are mainly located in the Sahara where substantial G.R. spread out, aquifers vulnerability assessment is of high importance and a key step for an effective protection of these invaluable resources. Thus, one of the main objectives of this paper is to develop an index - based approach in assessing the sensitivity of the aquifers to potential pollution and to illustrate the process leading to vulnerability maps that can be used as a decision - making tool. The index - based approach developed along this paper mainly considers the intrinsic characteristics of the "Receptor" media (the aquifers) and the most likely contamination "Pathway" (the unsaturated zone). Algerian Sahara Non Renewable Groundwater Resources. The Non - Renewable G.R of interest belong to what is known as the North-Western Sahara Aquifer System (NWSAS) which covers an area of more than 1 million km² (1,800 km E-W, and 900 km N-S) and extends over Algeria, Tunisia and Libya3 (see figure 1). The NWSAS is essentially composed of continental deposits in which occurs two aquifer layers4:The Continental Intercalaire (CI) formation, which is the deepest, the thickest and has the greatest expanse,The Complex Terminal (CT) which is the upper part and is constituted of the Mio-Pliocene, Eocene, Senonian carbonate, and Turonian aquifers.

Abstract Fracture analysis is generally accepted as one of the main steps through better understanding and optimization of assessment to production in most of the carbonate reservoirs. Effects of fracturing on reservoir performance provides engineers and geoscientists with the information needed to make business decisions with a higher degree of certainty. There are a few methods, which give us tracks of the fractures and the main problem is that even these are obtained using considerable time and money. What is clear is the importance of these data. In the last decade the main obsession of reservoir professionals was to develop some methods to detect more exactly the fracture attributes as well as extending the domain of the obtained data by different ordinary practices among them borehole image logs, surface geological analysis, well tests, etc. In the current paper we will apply a method, by which we could estimate the position of the fractures and this method could be used for confirming the results of the borehole image logs or even used alone and we will show that the fracture positions would be determined as precise as any other available method(s). Five wells were selected in one of the Iranian gas reservoir for which we have already the result of seismic interpretation. Other information as some petrophysical logs (Sonic, Neutron Density, MSFL, RHOB, etc), mud loss and drilling data are available for all wells. One of these wells also has borehole image log. Applying these data we could determine the position of the fracture and roughly the fracture orientation. By determining the Wavelet detail coefficient of petrophysical logs, and velocity index, with considering to other data including Mud loss and Variable Density Log (VDL), we could establish the fracture positions along the wells. For fracture density determination in inter well space, first curvature analysis was done and, then fracture density along the wells correlated with structural curvature at well location. We use this correlation and Geo-statistical method for obtain fracture density map in the reservoir. Introduction Rock having low interstitial matrix porosities and correspondingly low permeability in the absence of fracture, may constitute commercial reservoir when fractures provide local short-range drainage for the matrix and effective transportation channels to the well bore. For this reason it is often desirable to obtain qualitative and quantitative indications of the presence, density and orientation of fracture system. Fracture zone play an important role in our understanding of fluid flow within the earth's crust, for example in hydrology, recovery of hydrocarbons or transport of contaminants. Knowledge of fracture distribution is also important for our understanding of fluid flow in the reservoir especially in fractured reservoir management, it is sure to be unsuccessful without good understanding to fracture characteristics. A lot of papers on fracture identification have been published so far. Through the implementation from the U.S. DOE's Slant-Hole Completion Test (SHCT) and other research, core fracture identification has achieved remarkable success. The imaging well logs developed by Schlumberger Company gave impetus to fracture identification. The methods of fracture identification by means of core and imaging log are direct and effective, but coring and imaging logging require great expenses. During reservoir developing, a lot of conventional well-logging (CWL) information is provided for us. It is important and beneficial to make full use of CWL information to identify fractures. In this paper we use a novel method which is represented by Sahimi & Hashemi for detection of fracture position along the well by using CWL. [13] However wavelet is a good tool in fracture detection along well but it seems that this method should be constrained by other data if we want to have more accurate result. In this paper we use several data sources such as conventional well log data, result of wavelet analysis on log data, Velocity index, Variable density log(VDL), Mud loss and Mud weight data, drilling and geological data and also petrophysical interpretation.

Abstract The gas transport system on the Norwegian continental shelf (NCS) consists of 7 800 km of pipelines and is the largest offshore network of its kind in the world. Natural gas is processed at treatment plants in Norway, and dry gas exported through pipelines to customers in the UK and continental Europe. These customers have the opportunity to make varying gas delivery nominations, and meeting such sales gas commitments is important. A major challenge is to operate the network at minimum cost, with minimum environmental emissions, fulfilling variations in contractual nominations and maintaining a sufficient pipeline inventory to provide operational flexibility. Optimum pipeline inventory and optimum operation of export compressors have been analysed in earlier studies. The scope of the work presented in this paper is to establish a model for optimum operation of a gas export system, including customer nominations and operation of pipelines and compressor stations. That implies improving system energy efficiency, reducing environmental emissions and maintaining sufficient availability and export deliverability. The model will provide guidelines which will be implemented in planning and operation of the gas export system. This model is based on analyses of operational data from the gas export system on the NCS. The data are analysed using statistical and simulation software. The paper describes the established model for optimum operation of the system, where specific power consumption is minimised. A case study which illustrates the use of the model is also presented. Furthermore, the paper reports on a cost-benefit analysis based on the established model.

Abstract This paper presents a new method and technology to create different types of fuels from water-fuel emulsions and multi-component mixtures as two potential solutions to the fuel-energy problem. The technology consists of specialized hydrodynamic devises that convert crude oils which can have high water cuts into homogeneous high-octane gasoline or diesel whilst not greatly degrading the octane number. The new method does not require thermal treatment and/or catalysts. As the process reaches 94–98% of product output, mazut or any other analogous heavy fuel is added prior to the sprayer/injector. The add-mixed fuels can consist of: gas/oil plus water; diesel plus water; mazut and waste products of chemical processing plus water; liquid fuel plus coal dust plus water, for just some possibilities. The specialized hydrodynamic devices can (i) create various emulsions, dispersions and suspensions; (ii) atomize liquids and include saturation with flammable/non-flammable gases (iii) resolve problems with enhancement of thermo-mass-transfer processes in multi-component, multiphase substances, and (iv) resolve the problem with utilization of heavy hydrocarbon fraction sediments in fuel storage tanks by means of mixing them with the tank fuel in required proportions. The paper provides the results of lab experiments and pilot implementations. Introduction At present there are theoretical and experimental studies showing the possibility to substantially intensify the mass and heat-transfer and chemical processes in multi-phase substances, i.e. fluid-gas-solid particle(s) mixtures. Such improvement is based on the effects of transforming wave and oscillatory motions of the fluid phase and solid particles into controlled motions of the whole system inclusive of its components and phases1. Various types of systems can be affected: emulsions, suspensions, aerosols, etc. used in technological processes included in power engineering, oil refinery and petrochemistry, are just some examples. Under conditions of non-linear resonance, small oscillatory motions of a multiphase system can affect changes on the main motion of such system or its equilibrium state. This in turn allows for control of the state of whole system. Such control can be provided by:either external periodical forces like low or high frequency vibrations,ac electric or magnetic fields orinternal (passive) means in devices wherein the required oscillatory motions can be induced, for instance, by the auto-oscillation phenomenon. One type of device that can create oscillatory motions is the hydro-dynamic generator (HDG) which uses the energy of fluid flow to generate vibrations. Besides non-linear oscillatory effects hydro-dynamic generators can affect treatment of multiphase substances in the regime of cavitation. In such regimes of caviation, at the molecular level, polymeric hydrocarbon chains are disrupted through electrolytic substitution. The process intensifies as cavitation bubbles collaspse causing local, very sharp increases in temperature to several thousand degrees Celcius and increases in pressure to hundreds of MPa.

Abstract The paper will give an overview of how health risk assessment as input to design can contribute to better and safer work places with low health risk. This is based on the current practice in the Norwegian petroleum industry, focusing on health risk assessment and challenges in the working environment from the early design phases. Furthermore the paper describes how possible health risk and future working environment conditions at the plant during operations are assessed systematically during design and construction. Experience from operational activities and development projects are used to reduce risk and create safer and more efficient solutions. The methods used are based on company standards, national and international standards and authority regulations. The paper will give a summary of the engineering practices and tools used in Statoil ASA1. The following issues will be addressed:Some facts about the Norwegian Offshore petroleum industry.Requirements to Health Risk AssessmentUse of standards and company requirements to the working environmentAn integrated follow-up during project developmentExperience from recent projects covering offshore field development and onshore LNG plant. 1. Introduction There is a strong focus on HSE matters in the oil and gas industry today and attention to indicators that measure our results. Safety and environmental issues related to prevention of major accidents gain the highest attention internally and from the media, but the focus on the employees' health is equally important and there are recent examples on how this focus has increased, especially related to chemical health risk. In our company we have a philosophy that zero harm to people is possible. We have still not reached this level, but we work towards this goal to control the health risk and avoid negative health effects, injuries, diseases, chronic diseases and death. 2. Some facts about the Norwegian offshore petroleum industry The oil and gas industry is the single most important industry in Norway and it has a high attention from the authorities also with respect to HSE results. The upstream activities are offshore based and field development on the Norwegian continental shelf started in the early 1970ties. The authorities have been aware of the importance of developing Norwegian expertise within all areas. Severe weather conditions were demanding advanced technological solutions and a strong focus on safety (HSE). The petroleum industry today has a very good reputation and record, despite some tragic accidents, severe incidents and a working environment which may represent risk of considerable exposure to noise, chemicals and heavy manual handling. In fact the offshore oil and gas industry has a considerable better HSE performance than the land-based industry in Norway. A worker protection act2 was launched in Norway in 1977 and was made valid offshore from 1979. It was a modern act with functional and goal setting requirements. The objectives of the Act are;to secure a working environment which affords the employees full safety against harmful physical and mental influences and which has safety, occupational health and welfare standards that are concurrent with the techno­logical and social development of society at any time,to secure sound employment conditions and meaningful work situation for the individual employee,to provide a basis whereby the enterprises themselves can solve their working environment problems in co-operation with the organizations of employers and employees and with control and guidance from public authorities.

Abstract The "Design One, Build Two" strategy has been employed for recent West Africa Deepwater Developments including the large Kizomba A and B developments in Angola and smaller EPS (Early Production System) Projects such as Yoho (Nigeria), Zafiro (Equatorial Guinea) and Xikomba (Angola).When properly managed and executed, the "Design One, Build Two" strategy reduces project cycle time and cost. Introduction The West Africa experience has identified key project conditions that are required for successful implementation of the "Design One, Build Two" strategy. These include use of the same:–Engineering design–Engineering and fabrication contractors–Fabrication yards–Vendors and suppliers–Project leadership teams–Project management systems From a project management point of view, the "Design One, Build Two" strategy requires different approaches as compared to traditional "stand-alone" projects. This paper explores some of these differences, including the:–Alignment of project schedules and execution plans–Required project management philosophy–Common safety and quality programs–A "No Design Change" philosophy–Use of duplicate engineering–Alignment of engineering and procurement deliverables with fabricator's construction methods–Use of real time capture of lessons learned The "Design One, Build Two" strategy, if properly planned, managed and executed, can optimize project economics for plays with multiple large developments that have similar geologic, geographic, economic and contractual elements. The learnings realized from West Africa Deepwater applications of the "Design One, Build Two" strategy can be applied in other large oil and gas development projects. Design One, Build Two Implementation The Kizomba A & B FPSO Example This paper uses construction of the Kizomba A & B Floating Production Storage Offload (FPSO) vessels as an example of the key success factors in making the "Design One, Build Two" strategy work. Cost and Schedule Impact For the Kizomba FPSOs, the "Design One, Build Two" strategy captured cost savings on the order of 10%. As illustrated in Figure 1, completion of Kizomba B tracked five months ahead of Kizomba A. Fabrication on the Kizomba A Project fell up to 30% behind schedule, resulting in multiple execution plan adjustments and multiple recovery plans. The Kizomba B FPSO consistently tracked the original execution plan, progress never fell behind the plan and no recovery plans were required.