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Abstract In this paper, the structure, conduct and performance of the West Virginia natural gas producing performance of the West Virginia natural gas producing industry is discussed. The competitiveness of the gas industry is measured empirically using the concept of concentration ratio and other features of industry structure. Trend analysis of the industry activities and outcomes shows no evidence of "market power" among West Virginia gas producers. The general drilling trends in West Virginia paralleled those of the entire U.S. Similarly, the trends in new gas discoveries, real wellhead price, gas exploratory drilling, to a large extent, are closely related. It was noted, however, that oil and gas operators in West Virginia took less risk in exploratory drilling between 1981-1987. It would appear that more exploration activities must be undertaken to reverse the current downward trends in new reserve additions in the 1990s. Introduction The development and utilization of natural gas resources from "in situ" deposits to end-users follow four sequential economic phases. These phases of natural gas development represent different aspects of a rather complex industry. Each aspect is a distinct, yet an interdependent economic stage with different regulatory environments and market conditions. The economic analysis conducted in this paper is focused primarily on natural gas exploration and production stages of the West Virginia natural gas production stages of the West Virginia natural gas industry. The exploration phase represents the supply aspect of the field market, and the production stage depicts the demand aspect. The exchange commodity is new gas reserves. The analytical framework used in this paper is based upon the concept of concentration ratio and other key characteristics of industry structure— those features of the business firm that conditions the firm's behavior. First, the concept of concentration ratio is operationally defined. Second, other key indicators of industry performance are evaluated to determine the existence/presence of any anticompetitive behavior among oil and gas producers in West Virginia. An investigation of the implication of vertical integration on gas resource accessibility, extractive capacity, and production outlet is conducted to detect any evidence of absolute monopoly power for integrated gas operators in the state. Finally, a market analysis of new natural gas reserves is performed. The key factors, market determinants and performed. The key factors, market determinants and exchange commodity in the reserve market are identified and examined. WEST VIRGINIA NATURAL GAS PRODUCING INDUSTRY The West Virginia natural gas producing industry is characterized by many small and middle-sized operators. Approximately 90-95% of industry activity in West Virginia is done by "independent" producers. The extent of industry competitiveness may, however, be ascertained empirically using the concept of concentration ratio and other elements of market structure. The concept of concentration ratio has been operationally defined as the percentage of assets, value added, or output accounted for by a specified number of the largest companies in an industry. The higher the concentration ratios for the top four or top eight companies in an industry the greater the monopoly power. In Table 1, the concentration ratios presented are defined in terms of cumulative exploratory footage drilled, cumulative completed wells, and accessibility to remaining petroleum resources. The reported activity for the top four and top eight oil and gas operators in West Virginia covers the period between 1977 and 1987.Table 1 shows that drilling and production activities in West Virginia have become less structurally concentrated. P. 197

Kuwait Oil Company (KOC) is developing Jurassic fields spread over 65 X 50 Km in North Kuwait, which are aimed to support the state's growing gas demands. The present contribution to Jurassic production is from Raudhatain, Sabriyah, NWRA, Um-Nigah & Dhabi fields of sour MM/NS reservoirs. Some of the wells and flowlines of these fields are located outside current KOC security fence very close to the existing public Farm Houses, posing great threat to public in the event of toxic H2S gas release. This paper mainly describes KOC's Production & Project Gas Group initiatives undertaken to mitigate the threat to public safety (potential Societal Risk) by implementing effective barriers to minimize the source and impact of any toxic gas release. Immediate safety measures undertaken include installation of field crash barriers along entire flowlines/corridors that prevent damage to existing surface flowlines. Mid-term protection by boundary fencing is in advance stage of installation for UN, NWRA, DA & Liyah fields and H2S warning signs are installed at well heads as well as along flowline routes. Long-term plans are underway to install required safety instrumented instrumentation for improved safeguarding systems of well heads, flow lines & the Early Production Facility (EPF-50) protection. The plan includes monitoring facilities of potential H2S release and public warning system (in two phases) for emergency preparedness and crisis management. The paper presents few specific cases of how by implementing the safety measures and barrier installations so far have yielded results in avoidance of hazardous condition and unsafe incident. In addition, the paper also presents process safety features like hazard analysis and risk assessment studies (HAZOP, SIL assessment, QRA etc.) carried out to identify potential risks associated with site specific situations (both for Jurassic field areas and EPF-50 plant) based on ALARP principle.

The Kiruna Ministerial Meeting of the Arctic Council in 2013 identified an action to develop an overview of the existing and potential technical and operational safety measures specifically designed to prevent oil pollution in the Arctic marine environment due to offshore petroleum activities. The Task Force on Arctic Marine Oil Pollution Prevention (TFOPP) was subsequently established and delivered its recommendations to the Iqaluit Ministerial Meeting in 2015. The report presented in this paper is a response to one of the recommendations. The report (Haver, 2015) was prepared by Proactima for the Norwegian Petroleum Safety Authority acting on behalf of the Norwegian Ministry of Foreign Affairs. The final report was delivered to the Ministry of Foreign Affairs for further processing within the Arctic Council. A comprehensive overview of measures has been established based on contributions from the industry and R&D institutions through a baseline survey in addition to reviewing open sources. The report endeavours to provide a broad overview, covering the most important areas subject to the scope of work. An objective of the report is to provide a catalogue of existing pollution prevention measures for petroleum activities in the Arctic and a basis for evaluating the need for development of new measures. The aim is to make best use of existing knowledge in operations and optimum use of resources when considering future research and development projects. The report demonstrates that extensive research and development initiatives have been ongoing for several decades related to enhancing the safety of offshore petroleum activities in the Arctic and cold climate regions. The report, although being a documentation of facts, presents observations, recommendations and suggestions for further work. The objective of this paper is to make the report known to the wider community of petroleum professionals with special interest in activity in the Arctic. The paper should provide sufficient information to motivate the community to review the report and make use of it where applicable. Note: This paper is an extract of the report (Haver, 2015) and the text is primarily taken directly from the report. The report has extensive references that are not included in this paper. The report is openly available for download at: http://www.ptil.no/getfile.php/PDF/Rapporter/Overview%20of%20measures_report_TFOPP.pdf

The TAML-5 intelligent extended reach drilling (ERD) offshore well was the first of this type in the North Caspian Sea. The initial preparation and detailed follow up allowed to complete the well in a timely manner, without non-productive time and without deviation from the plan. This paper discusses the methodology used to prepare for the well construction process including the thought process, risk management, contingency planning, challenges faced, engineering and management solutions, results obtained and lesson learned. To ensure an adequate level of readiness, the preparation started early in advance. The process included global offset analysis of similar wells from around the world. Then in depth engineering study of every operation was performed by splitting all activities in subtasks and reviewing all details. This resulted in strategy for well integrity and contingency plans for every operation and tracking of equipment and tools from the factory to the rig. To ensure the consistency of all phases, a multidisciplinary team was set up and followed the well from beginning to end. The detailed operational procedures led to a deep understanding of the process by all involved parties. This was a vital part of the process when initial plans had to be changed and re-worked. While, it was not possible to simply implement the results of the large offset analysis, it provided a solid engineering basis for all decisions taken. Even though the contingency plans were not used on this specific well, the post job analysis showed that it is necessary to keep the same level, or even higher, of contingency planning for future wells. The output from this paper is the thought processand the actual methodology, including the special aspects that needed to be taken into account for the proper preparation and execution of a trouble free TAML-5 ERD well. The methodology can be implemented in any field worldwide, specially on multilateral wells with high-level completions.

Trinidad and Tobago has been an oil producer for over a hundred years. The land based production has historically been the spine of the energy sector. Many changes in reservoir management philosophies, with respect to improved oil recovery techniques (IOR), in the past, can be pegged to economic ramifications, global market issues and technological practicality. What is for certain is that these issues will always have a cyclical presence, but should not be a deterrent in planning the role-out of IOR projects when the market conditions are right. During periods of low oil prices, when capital spending is usually at its lowest, is an opportune time to reassess how to treat with IOR projects. This paper provides an insight into the planning process which can be used as an instigating tool to create an IOR master plan for the land based acreage of Trinidad. Adding reserves is the ultimate objective but this can be only realized with fit-for-purpose planning and a multidisciplinary coordination of data. The first phase, which this paper addresses, will consider a local historical IOR review, candidate selection with reservoir and technology commentary. These activities would form the basis to drive the first phase action items and spur a second phase of study which would address costs, procurement, execution, KPI monitoring, safety and environment, logistics, risks, contracts, success definitions, approvals, fiscal allowances, technology providers and team building requirements. Conceptualizing the first phase of a master plan was conducted through data mining, report reviews, interviews and simulation modeling. This paper answers, in brief explanations, the experiences of the past and the methods of the future. Technology identification and application seems to be the principle guide that the reservoir management process needs to consider in developing an IOR master plan for Trinidad's onshore oil fields. An onshore IOR master plan would eventually serve as a manual that strives for an effective and structured manner of exploiting mature fields, regardless of changes in management or management philosophies. The guidance offered within should form the basis or foundation of an eventual master plan.

The audit of the natural gas reserves of Trinidad and Tobago neither provides complete knowledge of all the country's natural gas resources, nor does it provide a future industry production outlook. It does not take into consideration resources that are unknown, undeclared, or outside the scope of its audit ("Unaudited Resources"). These deficiencies are addressed through the Trinidad and Tobago Natural Gas Industry Long Range Forecasting Model. The Model starts with that subset of the gas resources that has been audited as at 31st December 2014. The unaudited resources are then added together with scenarios of annual rates of natural gas production, resource discovery rates, and different policy measures. The "model' then generates projected demand and production scenarios for the natural gas industry. Trinidad and Tobago is a vast, significantly under-explored and under-exploited hydrocarbon prone marine territory of over 70,000 square kilometers inclusive of 5,130 square kilometers of land. It has been a leader in the global hydrocarbon industry for over 400 years, which is 300 years more than the often quoted 100 years of commercial oil exploitation. It's current audited 3P reserves as at end of 2014 are ca. 23 TCF and the exploration resources are ca. 44 TCF. This paper asserts that at least a further 33 TCF of Unaudited Resources exist outside the scope of the audit a total of ca. 100 TCF. Based on this more comprehensive estimate, the Model predicts that the natural gas industry of Trinidad and Tobago has at least a further 100 years of life much longer than the R/P ratio of 8 or R/2P of 12. This paper presents changes to the size of a country, its history and its predicted future by synthesizing knowledge available from different sources. It concludes that there is a much longer future for the natural gas industry in addition to the belief that there is enough time to create new sustainable economic activities to replace the economic contribution of the natural gas industry.

Global warming and climate change have become major concerns to the Global Community over the past two decades. The aftermath of these two adverse phenomena pose a threat to human existence and the entire Biological Ecosystem. Over 150 years of industrialization have produced significant levels of waste gases (greenhouse gases) from fossil fuels use. The greenhouse effect, resulting from these emissions (chiefly CO2), have led to drastic upsurge in temperatures and other adverse climate changes.This paper, as part of the global efforts to curb greenhouse gas (GHG) emissions, reviews the already set out GHG mitigation strategies by the Kyoto Protocol and its consequences. It seeks to apply the ideas of the protocol to Nigeria, as a case study, for more energy and environmental security and economic development. Global successes and challenges of the protocol are highlighted also and the concept of carbon credits is concisely discussed. This paper shows that the protocol has generally been successful and could be more successful. It also shows that the application of the strategies in a country would provide better living conditions.

This paper presents a complete integrated asset model for gas planning and, in particular, the handling of stranded gas during exploration. Uniquely, it models a gas network from the reservoir, right through to product allocation based on contractual obligations. It back-allocates through the network from the market, to ensure accurate supply and product tracking. We show how this type of model provides unprecedented confidence in field evaluation and gas planning. The market-based approach to integrated asset modelling that we used includes an optimal amount of information to deliver a fast, accurate solution. Oil and gas exploration activities do not usually involve planning for stranded or associated gas. Many discovered gas reservoirs are left undeveloped due to a lack of scenario analysis during the exploration phase. A fully integrated gas planning approach is required for effective field development planning in a timely manner. This has been a subject of intense research and development in recent years. Stranded gas reserves can be effectively developed using proactive market planning and strategic gas exploration guided by an integrated gas planning approach. As such, our model includes reservoirs, platforms, facilities, pipelines and markets to effectively understand the network deliverability. In this paper we defined multiple scenarios for bringing up gas from reservoirs, through the facilities and delivery point, right up to allocation of resources to meet the market demand. The case study deals with a market-based approach for modeling 40 gas reservoirs and associated gas products from nearby platforms. The practical constraints such as condensate handling capacities, compressor systems, and contract gas quality are integrated into the model analysis. The unique, fully integrated reservoir to market approach to IAM we demonstrate in this study provides a real breakthrough in E&P companies’' ability to model and run scenarios against their complete gas network in a relatively very short time. In particular the back-allocation from the market provides confidence around their ability to meet their contractual sales obligations and enables product tracking through the whole network.

The key objectives of National Content Act (NCA) of 2010 in Nigeria aim to enhance operational efficiency and drive costs down in the medium to long term by encouraging indigenous participation and ownership of assets in the oil and gas industry. Its implementation in the industry is to facilitate the industrialization process by manufacturing and fabricating components and other requirements needed in the industry locally. The Act is expected to stimulate investments and create opportunities for Nigerians to participate in the oil and gas industry in Nigeria. The passage of the NCA in 2010 and the subsequent formation of the Nigerian Content Development and Monitoring Board (NCDMB) have facilitated the emergence of indigenous companies operating in both the upstream and downstream sectors of the petroleum industry. Certainly, some achievements have been made in terms of policy guidelines, usage of made-in-Nigeria pipelines, increased in-country fabrication tonnage, employment and training strategy to mention a few; yet about 90% of the industry annual budget is still spent abroad. This signifies that much more could still be achieved than accomplished thus far. This paper investigates the implications of foreign expenditure as proposed in the Petroleum Industry Bill 2012 (PIB 2012) in Nigeria. The paper also evaluates the likely impact of national content contribution to the national economy. Further, the paper examines the effects of the negotiable limit of deductible foreign expenditure on project performance using Discounted Net Cash Flow (DNCF) model framework. It is observed that as the expenditure domiciled locally increases, the contractor Internal Rate of Return (IRR) increases with a corresponding higher value added to the investment than otherwise, assuming the homogeneity of a dollar spent abroad and locally. The marginal increment to the contractor in terms of IRR or Net Present Value (NPV) is higher in comparison to the marginal effect to the mineral owner in terms of Discounted Government Take (DGT), ceteris paribus. It is, however, recommended that a range for the negotiable limit be specified to avoid an open-ended discourse. Investors are seemingly better off if they reduce foreign expenditures and purposefully engage and develop national capacity as evident.

This paper gives an overview of method development in quantitative risk analysis for marine terminals and transportation that have been applied to several of the planned LNG and LPG transportation projects in North America. The growth in natural gas production in North America has renewed interest in exporting natural gas, mostly in the form of LNG or LPG. However, this growth comes with transportation challenges as suppliers, and operators move products and equipment, to and from an expanding number of sites (many of them in remote locations). Maintenance of safety and security practices is increasingly important as operations become geographically dispersed and more diverse. Analyses of reliability and risk are potentially most valuable during the early stages of marine terminal projects in guiding the decision on siting, design, and operative risk controls to reduce the risk as low as reasonably practical in final development. An important development in quantitative risk analysis for marine transport is the ability to utilize "big data" resources like Automatic Identification System (AIS) tracking. Utilizing AIS data provides the best available picture of existing traffic in a waterway. Quantitative risk analysis applies historical data as the basis for estimating risk of future accidents. This paper gives examples of how to combine historical data and advanced failure mode modeling to better estimate risk for loss of containment from LNG and LPG carriers. Quantification of accidental release frequencies and consequences of a release are demonstrated in this paper. The risk level for gas terminals and transportation area expressed in terms of individual risk at the terminal and along the transportation route. Newly developed methods make it possible to show the risk along the sailing route, accounting for the variation in traffic and environmental parameters along the route. Understanding of the key drivers of risk is important for the decision-makers to establish adequate risk controls for new energy export projects.

Increasing seasonal ice free Arctic waters and market demand to expand hydrocarbon extraction to previously undeveloped Arctic offshore regions has accelerated an Arctic priority in national strategies and international forums. In this context, hydrocarbon development in the Kara Sea region lends itself to interdisciplinary study. The proposed paper will be based on current specific research on state and corporate compliance to international environmental standards in Arctic offshore hydrocarbon development, to contribute and support a larger project, an Interdisciplinary PhD dissertation currently in progress with the University of Alaska Fairbanks titled Russian Capacity to Develop Offshore Oil Reserves in the Kara Sea: Geopolitical and Regional Implications. The proposed paper will be based on a focused analysis for the Kara Sea region through 2030. It is hoped such a study will have contributing value for industry, policy makers as well as the broader international community with an interest in transparent international environmental standards for oil and gas development in the Arctic littoral. It is further proposed that the sheer size of the Kara Sea hydrocarbon reserves, particularly of oil, and the effort and resources required to bring them into production, warrants this assessment as to the nature of the governance regime which is, or may evolve, and contribute to secure, stable and environmentally sound Arctic development.

This paper describes the planning, execution, data acquisition and processing of Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS) conveyed by patented semi-stiff Carbon Rod (CR) in very long horizontal wells. The primary interest in CR starts from its dual nature as a conveyance method and an acquisition tool; it is able to access long horizontal sections and record meaningful flow profiling data. CR presents viable alternative to Coiled Tubing (CT) or tractor conveyed wireline logging tools. When a point pressure and temperature tool is required, it can be conveyed at the end of the CR. This paper provides information on the preparation and execution of a three wells campaign in the Halfdan field, the first in the North Sea Danish Sector. The CR-conveyed DTS and DAS technology has been successfully and safely tested for the first time in this field. The CR was run in two injector and one producer wells. The campaign has proven the technology advantages and highlighted some learning opportunities. This paper will also describe the processing and visualization of the Temperature and Acoustic profiles and the challenges involved in handling a large volume of data (Terabyte scale). The semi-stiff CR sensing tool consists of the CR (15 mm in diameter) itself and a bottom-hole assembly (BHA). Embedded in the CR are six optical fibers. Two multi-mode fibers are dedicated to DTS and one single-mode fiber to DAS. The three remaining single-mode fibers are dedicated to Point Pressure, Point Temperature and Vibration measurements. The Fiber Optic (FO) point Pressure (P) and Temperature (T) sensors are located in the BHA. The system provides temperature and acoustic profiles along the rod during the operation. These sensors, in conjunction with surface read out and bottomhole gauge data, provide a comprehensive tool for real-time surveillance and dynamic well analyses. Although hole conditions were challenging, with the first well exhibiting a great deal of scale that impeded a smooth descent, CR was successfully deployed into the three wells. The rod was pushed into the horizontal sections with a reach performance equivalent to that achievable by equivalent small diameter coiled tubing. The maximum reach of CR was more than 15,400 ft MD, with a record of more than 5,100 ft reach into the horizontal section, without using a well tractor or CT to assist deployment. The sensing campaign produced more than 50 TB of well data. The interpretation results will be presented in a subsequent publication. The aim of this paper is to serve as a reference in the planning of CR deployed DTS and DAS applied for well and reservoir surveillance.

To meet rising global energy demand, the oil and gas industry is growing at an unprecedented rate. As mature oil and gas fields reach end-of-life, safe and cost effective abandonment techniques are now and will continue to be a critical part of the industry. Ineffective abandonment methods are a serious economic and environmental liability to an operator, particularly one having wells with surface casing vent flows. The operator's Foothills fields, located in central Alberta, Canada, are home to some of the harshest downhole producing environments in the country. Foothills wells are deep (>3500 m true vertical depth), sour (5% to 90% H2S) and mature (1947 to present) with average well reserves of over 80 million standard cubic meters of gas. They experience sulfur, iron sulfide, calcium carbonate and sodium chloride deposition. Saline water influx causes corrosion of the production tubing strings. Most of the wells have low casing cement tops leaving multiple porous geologic formations uncemented. These factors present many challenges during well abandonment operations. A well abandonment campaign for these fields began in 2011 and will continue for many years. To date over 40 wells have been abandoned. This paper will describe best practices learned, as well as "game changing" strategies that have led to significant cost savings and reduced operational risk. These include bullheading foamed cement to abandon the producing zone prior to moving in a service rig. This is followed by a "one-trip" abandonment utilizing through-tubing perforating and bradenhead cement squeezes with high pressure, slow-rate pumpers. The percentage of total well abandonment cost savings will be presented for each strategy. The principles for choosing cement squeeze intervals for the isolation of porous zones, and the success rates of surface casing vent flow shutoff will be discussed. This paper will also present data from cement plug drillouts which show that cement platforms are not required beneath a balanced cement plug in near vertical wellbores. These practical applications will reduce costs, lower risk exposure and lead to improved results in downhole abandonments.

Desired production chemicals such as scale inhibitors, paraffin inhibitors and corrosion inhibitors can be adsorbed onto a proppant-sized solid particle for controlled release. This solid additive was first introduced for field application through a fracture stimulation operation in 2004. More than 25,000 (mostly in North America) wells have been treated with this solid inhibitor since then. In this strategy, the solid inhibitor additive is pumped with the proppant and distributed evenly throughout the created fracture. A prolonged protection for flow assurance problems can be achieved as the inhibitor slowly desorbs into the produced fluids. A conventional phosphonate-based liquid scale inhibitor treatment has been proven to be ineffective when deployed in North Dakota to prevent the formation of mineral scale in the downhole pump and production tubing. In 2010, a novel biodegradable scale inhibitor-based solid additive was developed, deployed successfully, and the application for one operator in this area was presented (Szymczak, et al., 2010). The present paper updates those results and discusses results from 14 additional operators with more than 500 treated wells. The discussion in this paper is mainly focused on the correlation between solid inhibitor loading, water/oil production and projected protection longevity based on the scale inhibitor residuals data monitored for more than 100 wells. The economic and environmental benefits of this new environmentally preferred product, and related lessons learned are also included.

The development of heavy oil accumulations presents difficult engineering, technological and geological challenges that need to be overcome to produce economically viable projects. Even a large oil accumulation can be deemed unattractive for development in cases that combine a high cost environment with complex geological setting and unfavorable fluid dynamics. This paper highlights the challenges and presents the subsurface solutions that unlocked the value of an offshore heavy oil accumulation, 32 years after it was first discovered. Within the context of the overall development plan, the paper describes: The design of the offshore well test that delivered 11,244 bbl/d 15.7°API oil and proved the production capacity of the reservoir and the conceptual well design. Workflow for confirming the existence of a compositional gradient and characterization of a biodegraded oil column. A novel approach to evaluation of inflow control devices (ICD) and its implementation in the well design. An ICD modelling tool developed specifically for direct comparison of different ICD geometries. The paper also presents the field history to date – from the early failures in recovering hydrocarbons using conventional methods, through to the enabling technologies that made Coniston and Novara a viable project.

The Doha Climate Change Conference marked the transition from an old climate change regime that focused on reducing GHG emissions from developed countries to a new climate regime that will focus on reducing GHG emissions from all countries. The new climate change discussion that is centered on the so called Durban Platform has brought into focus the importance of reducing GHG emissions in a cost-effective manner for all countries. Methane's unique role as a greenhouse gas and as the primary component of natural gas means that reducing methane emissions can yield significant economic, environmental and operational benefits. Working under the Global Methane Initiative (GMI) and with the support of the newly launched Climate and Clean Air Coalition (CCAC), the Natural Gas STAR International Program is a voluntary partnership between the oil and natural gas industry and the United States Environmental Protection Agency (US EPA) that promotes use of cost-effective technologies and practices to reduce methane emissions. This paper will highlight the unique opportunities available to Middle Eastern countries and more specifically members of the Gulf Cooperation Council (GCC) to reduce their methane emissions and develop Nationally Appropriate Mitigation Action (NAMA) plans. This paper will summarize a number of established methods to identify, measure, and reduce methane emissions from a variety of equipment and processes in oil and gas production and natural gas processing and transmission facilities. Furthermore; given that some of the top natural gas flaring countries are countries that belong to the GCC, special attention will be given to flaring reduction technologies and policies. Moreover; given that Qatar is currently the largest producer of LNG in the world, a case study discussing methane emissions from LNG facilities and potential emission reduction technologies will be presented.

When oil prospection and production started in the Niger Delta five (5) decades ago, the Local communities were not aware that the disposal of excessive Natural Gas through gas Flaring into the atmosphere posed any danger to both the local and global populations in the degree just becoming apparent now. It was in fact, assumed that the atmosphere was an infinite sink for gaseous pollutants, so what Industries and Oil Companies only needed were open pipes as Flare-stacks to discharge and flare away deleterious gaseous materials of their operations into the lower atmosphere. But in a study instituted by the Rivers State Government [under PPD's supervision] with the Institute of Pollution Studies (IPS), University of Science and Technology Port-Harcourt, it was our discovery that the capacity of the lower atmosphere to absorb gaseous pollutants is in fact limited. The finite capacity of the troposphere can only be dynamically balanced with its self-purification capacity. In order to maintain its integrity, the atmosphere initiates a "Self-purification process" from time to time to shed the atmospheric loads of pollutants as acid rains and other precipitations on the terrestrial environment below, and as OZONE-Layer hole-creation/hole depletion above (or in the stratosphere). The consequences of these adjustment processes are the potently dangerous phenomena of Ozone layer depletion. Greenhouse Effect and Global Warning which may lead to Climate Change, rising sea levels that constitute a threat to the coastal communities worldwide. The primary reason for preparing this paper for the 1st SPE-AFRICA HEALTH, SAFETY, SECURITY AND ENVIRONMENT CONFERENCE AND EXHIBITION in Nairobi Kenya, was to share learning and experience from the West African Sub-region(Niger Delta) with the rest of the World, and in particular, the New Oil and Gas frontiers of EAST AFRICA. By so doing, we would be avoiding those practices that were found to be inimical to, and constituted flash-points of conflicts in the Oil producing areas and thereby foster peace, progress and sustainable development of the Oil Industry and the Country concerned. It is therefore the object of this paper to explore and show case enough empirical facts and cognate scientific experience the way gas flaring equipment should be designed to minimize the emission of GHGs from the operation of the Oil fields of Africa and the World. When viewed against the highlighted overwhelming global environmental hazards, the idea of eliminating open-pipe stacks becomes an easy imperative for the sustainable development of the Oil Industry in the face of the Kyoto Protocols. The idea, though drastic, coincides strictly with the Theme of the Conference and the global perspectives on Green house Gas reduction in which Oil Industry Gas Flaring is a major contributor Locally, the experiences and knowledge gained through the above Pioneering Study by the Petroleum Pollution Department (PPD) and other Non-governmental Agencies(NDES) had led to the recent Gas-Flare-Out Project of the Oil Companies in Nigeria.

This study seeks to bring to the forefront among many other publications, the pernicious and inconspicuous hazards that the unguarded application of nanoparticles or nanotechnology may pose to the environment, as well as, the health of both humans and animals. The environmental and health implications of this new transcending technology differs not in many field where this technology is applied, but this work narrows down most of these identified risks in our oil and gas fields as an area of major concentration for this work. As part of the major work of resolving the emulsion problems in the oil and gas field using engineered nanoparticles, this paper analyses the risk and the reliable safety measures that must be followed from production to the application of the nanoparticles in the oil field as well as the disposal of the spent nanoparticles. This work is not only to increase the awareness of the health and environmental risks associated with the production and application of nanoparticles, but more also we showed in this work, the great benefits and the future impact of this technology as we produce and apply the nanoparticle under the proposed safe measures that we have described in this paper.

For the purpose of this paper, reserves growth is classified into three main categories: new pool discoveries, reserves revision and reserves extension. For each category, there are distinct factors affecting positive and residual reserves growth. The paper shows that fiscal/policy incentives, crude oil price and modern technology are necessary conditions to expand petroleum reserves, thereby prolonging the end of petroleum era in Nigeria. The deepwater remain the most promising area for further significant reserves growth. Therefore, the existing Production Sharing Contract (PSC) deepwater field development projects will undoubtedly impact positively to the country's production and reserves blueprint toward the 40 billion and 4.0 MMBBL per day targets by 2020.

The paper combines a brief case history of applications with supporting laboratory data, for using a new relative permeability modifier (RPM) in conjunction with a conventional acid stimulation treatment. This design was targeted at mature oil wells with high water cuts in Ecuador. The recommendation was proposed after mineralogical characterization of core samples, using scanning electron microscopy (SEM) followed by laboratory core flooding with treatment fluids. The methodology described in the paper comprises stimulation of certain areas of the sandstone formation with an acid followed by a RPM treatment to prevent the water from the stimulated water-bearing zones from entering the wellbore. Coiled tubing is used for effective placement of the treatment. Conventional stimulation treatments in the Hollin sandstone formation in Ecuador result in high water cuts because of encroaching water from an active aquifer. The acidizing technique with RPM improved the economic life of many mature wells in the field. Both laboratory and field data indicate excellent results from the treatments. The overall water cut in the treated wells decreased (by 8 to 15%), while oil production increased (~200%). Coiled tubing enables accurate placement of the acid and RPM into the desired zones, with the benefits from this targeted treatment far outweighing the cost of using coiled tubing units. Successful implementation of the laboratory core flood results in the field resulted in field-wide protocols aimed at oil wells producing water at unacceptable rates. The optimized stimulation treatment increases oil production and selective placement of RPM using coiled tubing decreased water cut, thereby prolonging the economic viability of mature wells.

Abstract The offshore environmental risk analyzes have been adopted in the environmental licensing processes related to the oil offshore drilling and production, in Brazil and Norway. From recent environmental accidents, especially what happened in Macondo, there is growing concern about consequences of accidents due to oil spills in the marine environment and, consequently, the environmental risk analysis have been gaining special attention of the licensing agencies and operators of offshore oil drilling, production and transportation, including offshore pipelines. This paper presents the development of the offshore environmental risks analyzing methodologies in Norway and Brazil, their applications in these countries, the legal requirements and a parallel between types of data. Quantitative environmental risk analysis has been discussed in Norway since 1990 and has undergone modifications through periodic reviews of the guidance published by the Norwegian Association of Oil Exploration industries (OLF). With regard to Brazil, the government has been discussing this issue since in the late 90's, focusing primarily in the emergency response plans. Since 2008, the environmental licensing agency is developing a Brazilian technical instruction focused on quantitative environmental risk analysis and since the first version of the methodology, it have already been implemented changes to better fit the goals of the results. In a quick review, these methodologies have similarities, but a more detailed study shows that there are crucial points in their approaches that may require greater efforts in preventing accidents by operators. The results of this study show the relevance of the main information used in this type of study and the sensitivity of each method relationships with their most important variables. The importance of the impact of the topics covered in this paper on offshore activities in Brazil and Norway is crucial in decisions making, regarding the growth of these activities in these countries. 1. Introduction The offshore environmental risk analyzes have been adopted in the environmental licensing processes related to the oil offshore drilling and production, in Brazil and Norway. From recent environmental accidents, especially what happened in Macondo, there is growing concern about consequences of accidents due to oil spills in the marine environment and, consequently, the environmental risk analysis have been gaining special attention of the licensing agencies and operators of offshore oil drilling, production and transportation. In Brazil, the concern about accidents due to oil spills in the marine environment has increased since 2000, when the accident caused by a failure in the PE II pipeline of Duque de Caxias, PETROBRAS, in Baia de Guanabara (RJ), caused spill of 1300 tons of oil. 2. Objective This paper presents the development of the offshore environmental risks analyzing methodologies in Norway and Brazil, their applications in these countries, the legal requirements and a parallel between types of data. The objective is to compare what is applied in Norway and in Brazil to try to contribute for the improvement of environmental risk reduction in both countries.

Abstract When produced water from offshore production is discharged to sea, it contains some oil (aliphatic and aromatic components), production chemicals and NORM (Naturally Occurring Radioactive Substances). These groups of substances are traditionally treated in different ways in the regulations and standards. Regulations of oil in produced water are mainly related to max concentrations and the total discharge of the aliphatic (dispersed) fraction. Regulation of chemicals is based on the environmental risk profile of each production chemical, although efforts are made towards regulations based on risk assessment of the discharge of the mixture of substances. For discharge of NORM dissolved in the produced water, no limit values are imposed. For NORM solids (scale, sludge, sand) from process equipment, discharge to sea is in general not allowed - it is re-injected or taken to a deposit onshore. Management of safety risks takes place based on the principle that risks shall be reduced to a level As Low As Reasonably Practicable (ALARP). The concept of environmental risk is not as unambiguously defined as safety risks. With respect to accidental environmental impacts, the parallel is relatively straightforward, but with respect to planned environmental impacts (e.g. emissions/discharges during operation) the parallel to the safety ALARP is not so clear; the consequence (the environmental impact) is not linked to a certain frequency - i.e. we cannot talk about risk as: likelihood times consequence. Costs are normally defined as money, effort and time. But what if the cost of a reduced HSE risk is an increase in another HSE risk? Produced water re-injection might cause increased CO2 emissions. Handling solid NORM when shipping it to shore causes health risks to the people handling the NORM. Can that risk be justified, based on the possible reduction in environmental risk by not discharging the solid NORM to sea instead? The paper highlights the above issues and proposes a method named integrated HSE ALARP assessment for supporting such analysis. The environmental risks of discharge with produced water to sea of oil, chemicals and NORM, respectively, are used to illustrate these principles. Introduction The development of the concept of risk has previously taken place with respect to safety risk. An important principle developed is the obligation to reduce risk to a level As Low As Reasonably Practicable (ALARP). The concepts of health risk and environmental risk are also widely used now - and as parallel to the ALARP principle, the principles of Best Available Technology / Best Environmental Practice (BAT / BEP) has been developed with respect to environmental impacts. These principles are to a wide extent analogous to the ALARP principle used in health & safety. In this paper, an overall common definition of HSE risk is sought. This makes weighting of different HSE risks against each other more transparent and objective. The ALARP principle traditionally weight safety risk reduction against the increased cost/effort required for achieving the risk reduction. In this paper, a concept for weighting safety risk against environmental and health risk is presented, using produced water as an example. Also a situation where increased environmental impact was weighted against reduced safety risk is presented.

Abstract The paper will describe the existing regulatory systems for the offshore inthe Arctic. Drawing from offshore disasters and the responses thereto bythe Coastal States around the world the paper will point to the arguments forand against international regulation of Arctic offshore areas. Organizations that might create such regulation are considered such as theArctic Council, the International Maritime Organization, The InternationalRegulators Forum, the oil company operators. Current debates concerninginternational regulation such as that of the EU (October 2011) proposal tocreate EU regulations for the offshore and the opposition by the Great Britainwill be reviewed, as will be the Helix Mutual Aid solution in the Gulf ofMexico, the new Canadian filing requirements for Arctic Oil and Gas (December2012) and others. Introduction The Titanic sank in the icy waters off the eastern coast of Canada in1912. It was only two years later that first steps were taken to put inplace an International Convention focusing on safety of life at sea(SOLAS). This Convention specifies standards for construction, equipment, and operation of ships. It includes a number of articles covering suchmatters as lifesaving appliances, radio communications, safety navigation, carriage of cargoes, carriage of dangerous goods, management for the safeoperation of ships and measures to enhance maritime safety. The 1978 sinking of the Amoco Cadiz resulted in the 1982 ParisMemorandum of Understanding on Port State Control (Paris MOU) as aninternational effort to better regulate flags of convenience, enabling ports todetain vessels found to not comply with international safety standards. The international community has responded to the threat of pollution with anumber of Conventions addressing the various issues arising from pollutioncaused by ships. In addition to Conventions addressing pollution itselfthere are other Conventions which focus on safety issues, which at least inpart are intended to manage the risks of being at sea.

Seven Generations Energy Ltd. (7Gen) has drilled several horizontal wells in the extremely liquids rich Montney formation in the Karr Kakwa area of central western Alberta. Over the last two years we have seen progressively shorter drilling times as well as a marked increase in production as a function of optimal hydraulic fracturing recipes and completion installations. This paper will discuss the systematic approach taken by well construction engineers to optimize drilling performance through bit selection coupled with vibration mitigation and hydraulics optimization. Further technologies that will be discussed and will/have been be implemented are torque mitigation technologies to mitigate stick slip and the use of managed pressure drilling techniques to decrease mud density and further increase ROP’s. This paper will also discuss the coincident work done to optimize fracture treatments as a function of rock strength and measured gas response while drilling.

This paper presents the results and the concept of increasing the efficiency of recovering remaining strongly watered hard-to-recover oil reserves based on the example of developing Upper Jurassic reservoirs of a typical field of TNK-BP in Western Siberia, Russia, that has entered the final stage of development. In particular, the paper describes the positive outcome of implementing such technologies as hydraulic fracturing at extremely watered wells, forced liquid withdrawal coupled with targeted focal waterflooding supplemented by flow diverting technologies in injection wells and water shutdown in producers, optimization of perforation intervals, with sidetracks targeting blind unrecovered zones. The work is different from previous projects in provisioning a comprehensive integrated flow production and injection regulation with low-cost technologies with an emphasis on reducing injection costs and producing liquids to the surface to optimize cash flows. As a result, the accepted recovery concept is described, which provides increased energy efficiency and production profitability, together with targeted production of remaining oil reserves.

Directly supporting the Global Methane Initiative (GMI), the Natural Gas STAR International Program is a voluntary partnership between the oil and natural gas industry and the United States Environmental Protection Agency (EPA) that promotes use of cost-effective technologies and practices to reduce methane emissions. In 2008 and 2009, the Oil and Natural Gas Corporation LTD (ONGC), the first Natural Gas STAR International Partner in India, undertook a desktop review and in-country methane emissions measurement study and analysis to identify and quantify baseline methane emissions levels for seven of its production, processing and transmission facilities. The measurement study was conducted using infrared camera technology to identify emission sources; and a combination of turbine meters, high volume samplers, and calibrated bagging techniques to measure their emission rates. This paper details the survey activities and quantitative measurements for the seven surveyed facilities. EPA's Natural Gas STAR International (NGSI) Partners are eligible to receive recommendations on technologies or practices, a facility-specific assessment of their technical feasibility, anticipated methane emission reductions, and the economic and environmental value of the proposed emission reductions. The paper further describes mitigation projects ONGC has deployed as a result of their collaboration with EPA. ONGC, acting immediately upon the Partnership's recommendations, and consistent with ONGC's corporate carbon management program, have to date reduced methane emissions in the studied facilities by 30 percent, achieving annual natural gas savings of more than 9 million cubic meters (MMcm). This paper also reviews ONGC's future climate protection plans.

Safety culture is one of the most-studied subjects in the safety literature today, although no agreement exists on exactly what it means. Most safety culture research has been conducted in high-hazard industries such as nuclear power, aviation, and offshore oil and gas production. Only limited research has investigated links between safety culture and the prevailing national culture. This paper proposes that efforts to build safety culture and improve safety performance in the oil and gas industry will be enhanced if the prevailing national culture is assessed and a location-specific plan is developed. Within Chevron, current safety culture initiatives include defining and advocating for "Operational Discipline" and focusing on "Behaviors to Support Managing Safe Work" in the upstream sector. Both of these approaches have distinctly North American cultural underpinnings. The HSE opportunity this paper addresses is building a strong safety culture across the many varied national cultures where Chevron operates. This paper reviews the key attributes by which national cultures are characterized with a particular emphasis on the areas most applicable to safety culture in oil and gas settings. For example, in a national culture characterized by high power distance and predominantly masculine traits such as those found in Latin America or the Middle East, techniques that work well in North America or Europe will likely not be as effective. It will argue that fit-for-purpose safety culture maturation plans are needed for each location. The paper should be of particular interest to leaders who are working in business units outside of their home country. Hopefully they will learn something that will help them to better understand key aspects of national cultures and allow them to customize and accelerate their safety culture development efforts back on the job.

The current paper provides a narrative of the Health Impact Assessment (HIA) of a greenfield project located in a remote part of Papua New Guinea. HIA, in the context of this project, is presented as one of the processes that a company needs to go through in order to develop a site-specific Health Management System (HMS). The objective of a narrative is to tell a story; in this case the story describes how the HIA was carried out. Many guidelines on HIA exist and HIA reports are available. However, very little information is published and presented about the challenges encountered during the delivery, as well as about the management issues that need to be addressed in order to deliver an HIA in remote regions. Up to now we have focused on creating rules and structures for HIA; however, not enough attention has been given to their implementation, and even less to the consequences for not complying with the recommendations. Furthermore, impact assessments are usually described on their own or within the life cycle of the project. However, there is little information on how this process links with the other ones in the development of a site-specific Health Management System and which kind of choices are made in this regard. Projects always interact with the external environment where they are located. This environment poses health, safety and security risks for the project. At the same time this broadly defined environment, where the project is located, is altered and impacted by the project itself. Therefore, the "project" and "environment/context" are two essential parameters to understand the health challenges that a company need to manage when starting a greenfield project. The paper concludes systemizing the experience of this HIA in key practical tips for people implementing HIA of complex projects in remote locations.

Abstract Lockheed Martin Corporation is conducting a multi-year technology developmentprogram to advance the state of the art of Autonomous Underwater Vehicle (AUV)inspection technologies for the offshore oil & gas industry. The scope ofthis project is to develop and demonstrate AUV technologies for conductingautonomous structural survey and inspection of subsea facilities for a widerange of applications, including pre/post-hurricane inspection of offshoreplatforms, pre/post-decommissioning structural survey, and deepwater facility /riser inspection. This paper will describe the results of Lockheed Martin'srecently completed technology demonstration project, Autonomous Inspection ofSubsea Facilities, including laboratory simulation, local offshore trials, andtechnology validation trials in the Gulf of Mexico against offshore productionplatforms. This project was jointly funded by the Research Partnership toSecure Energy for America (RPSEA), Lockheed Martin and sea trials weresupported by Chevron Energy Technology Company Capabilities demonstrated duringoffshore trials included (1) autonomous real-time three-dimensional (3D)imaging and modeling of an underwater facility, (2) detection and highlightingof changes to the facility in real time, and (3) feature-based navigation, theaiding of the AUV's navigation along its path based on feature detection andrecognition. The paper will describe the results achieved, and will highlightthe performance improvements over current platform inspection methods, including significant improvements in operating efficiencies, and thedevelopment of highly accurate 3D models for use in structural integritymanagement. Finally, the paper will outline the potential benefits of evolvingAUV and sensor technologies for applications such as structural survey, pipeline inspection, subsea facility inspection, and light intervention, including potentially game changing improvements in cost, performance, safetyand reliability that will enable more cost-effective operations in deepwaterand/or remote subsea fields. Introduction Subsea Integrity Management is defined by the Energy Institute Guidelines forthe Management of Integrity of Subsea Facilities as " the management of a subseasystem or asset to ensure that it delivers the design requirements, and doesnot harm life, health or the environment, through the required life." A keyelement in any integrity management program is regular in-service inspections. As the industry moves into deeper and harsher environments, challenges faced byoperators include the high cost of subsea inspection and the limited inspectionintervals available. Inspections provide a snapshot of the structural health ofthe system. Integrity management practices in deepwater fields rely heavily ongeneral visual inspection of subsea equipment. Remotely operated vehicles(ROVs) and divers are the primary means used today to conduct inspections -ROVs exclusively in deepwater (greater than 100-meter water depth) and diversgenerally limited to less than100-meter water depth. In both cases supportvessels larger than 70 to 100 meters with support crews numbering more than 30and with 100+ tons of equipment are required to collect the simplest visualinspection record. The quality and usefulness of the records are highlydependent on the seawater's visual clarity, illumination, camera and recordingequipment, and ROV or diver stability. An ROV inspection of a deepwaterfacility can provide visual evidence of structural degradation, impact damage, corrosion, valve damage, leaks, vibration, and other structural damage (Figure 1). Benchmarking the condition of subsea equipment following installation andtracking its status over time can provide a history of the deterioration rate. Video inspections include: well heads, valve positions, pipeline endterminations (PLETs), pipeline end manifolds (PLEMs), underwater terminationmanifolds (UTMs), flowlines, jumpers, moorings, risers, and associated cablingand equipment on the sea bed. This equipment is often spread over many squarekilometers requiring the support vessel to maneuver in DP mode for days. Inspection speed is totally dependent on the coordinated movement of the ROVand support vessel and the skill of the ROV pilot.

In an unconventional reservoir, the success of a project is driven by the completion. Unconventional plays have become the primary area of development in the US, and shale formations dominate the current rig activity. Most shale wells are drilled utilizing long horizontal wellbores, and completed using cemented or uncemented casing strings. To be economic, they require large hydraulic fracture treatments in multiple stages along the lateral. Total well costs are driven by the cost of fracturing, often representing as much as 60% of the total well cost. This requires the operator to select the best completion method which includes casing and wellhead selection that is based on stimulation needs. The stimulation is regulated by injection rates, treating pressures, the volume of the stimulation, type of fluid, proppant selection, perforations, and the number of stages. This paper focuses on several areas that are critical in a successful completion such as: casing size and pressure rating, wellhead selection, treatment design, spacing of the perforations and stages, linear verses cross-linked fluid, and the impact of proppant selection. With over 1800 wells completed and stimulated so far, a comparison of successful treatments and the cause of unsuccessful treatments will be provided. A review of actual field applications will be presented where possible, and a method for identifying best completion practices will be discussed. Those working in or considering developments in unconventional plays around the world will be able to compare their current completion techniques to those presented in the paper. In addition, while no two resource plays are the same, the findings in this paper can be used by engineers as a guide for moving up the learning curve more quickly in other unconventional plays.

The Immortelle gas and condensate field is located in the Columbus Basin,3540 miles off the southeast coast of Trinidad in water depths of 235 feet.It is comprised of highly faulted stacked reservoir units.The TP88 reservoir unit,the subject of this paper,was discovered to be gas bearing in 1975 by the exploration well,SEG10.The reservoir pressure is 3505 psi;with a temperature of 162F.This reservoir was developed with two wells.IA11 was the first producer from 1999 to 2002 and was completed as a 3.5 (inches) multizonal completion across 3 reservoir units,but selectively producing via sliding sleeves.IA14 is the second and current producer.It was completed updip to IA11 in the TP88 in 2001 as a cased hole completion with a gravel pack completion in the good quality upper sand lobes with 3.5 (inches) tubing. The TP88 reservoir has historically had close alignment between static and dynamic models.Pressure Transient Analysis and modelling studies in 2010 has resulted in significant misalignment of the static GIIP and the estimated dynamic GIIP.This paper will describe the modelling work flow and discuss the key lessons learnt from analysing and integrating old and new reservoir data that has led to a completely different understanding of the drive mechanism and future reservoir performance.This has resulted in the static model Gas Initially In Place (GIIP) now lagging behind the reservoir simulation model GIIP and has potential implications for the reservoir depletion plan. Field Overview Figure 1: Offshore Trinidad showing the Immortelle Gas Field location IPTC 14955 Adding value to a mature gas field by re-analysing and integrating old and new dynamic data Immortelle Gas Field, Trinidad and Tobago Iannie Roopa, BP Trinidad and Tobago Copyright 2011, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Bangkok, Thailand, 15–17 November 2011. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s).

Abstract In the aftermath of the massive oil spills in the Timor Sea and the Gulf of Mexico there is heightened wariness and many questions about the sustainability of offshore exploration for oil and its marine transportation. Traditionally, oil spill management has been a reactive rather than proactive process involving containment, dispersal, capture, and possibly beaching and clean up of oil spills. There was little forward planning on how to minimize and manage oil slicks to reduce the environmental impacts. This is no longer accepted by the public and so new proactive approaches are needed. A new risk assessment approach was developed and is being implemented in the Gulf of Thailand, but the method could be applied anywhere. The approach combines advanced computer modeling, integrated with geographic information systems and environmental sensitivity indices. In this paper a process for identifying, assessing and minimizing environmental risks from oil spills is introduced based on a recent work in Thailand. The paper includes maps and model predictions of risk areas from a hypothetical spill and a comparison of the results of the new approach with those of the currently accepted method of risk assessment in Thailand. The method will be beneficial in refining the mapping of risk areas in sensitive and confined areas such as bays. It will add rigour to the analysis of the oil spill risk component of environmental impact assessments that are mandatory for the exploration and transportation of oil. It will also be helpful in developing emergency response plans using window of opportunity to mobilize for a spill event. The novelty of the approach is the use of overlaying model projections from both a source and receptor perspectives. Introduction In the aftermath of the massive oil spills in the Timor Sea and the Gulf of Mexico there is heightened wariness and many questions about the sustainability of offshore exploration for oil and its transportation across the seas. Traditionally oil spill management has been a reactive rather than proactive process involving containment, dispersal, interception, capture, and possibly beaching and clean up of oil spills. There was little forward planning on how to minimize and manage oil slicks to reduce the environmental impacts until the major catastrophe of the Exxon Valdez event in Alaska over 20 years ago. Although planning has become much more thorough since, the recent catastrophic spill in the Gulf of Mexico has put renewed pressure on increasing the level of preventative planning for such events. Therefore, new proactive approaches are being called for which are more rigorous and provide greater environmental security and protection. In this paper an integrated process for identifying, assessing and reducing such risks is discussed. Types of Risks Risk Sources - Sources of risk include exploration wells, floating production storage and offloading facilities, shipping, oil containers and fuel releases from ships. Blow out of oil wells and accidents at the platforms are dramatic and headline news as was the case of the Deep Horizon event in the Gulf of Mexico. Spills during the transfer of oil to and from floating storage facilities or at docks usually involve less volumes, but they occur more frequently than well blow outs. The loss of fuel from ships, either through accidents, leakages or deliberate dumping, is by far the most common form of oil spill at sea. However they involve the least amount of spilt oil volumetrically. The key issue with risk sources is the need to understand the areas which may be affected by spills.

The recent agreement between Russia and Norway regarding the border between the countries in the Barents Sea offers unprecedented opportunities for Norwegian-Russian cooperation in developing oil and gas fields. In this paper we summarize information about the agreed state borders in the former disputed ("grey") zone of the Barents Sea, see Figure 1, and suggest possible scenarios for the oil and gas fields’ development. The "Grey Zone" area is about 175 thousand km2 in which, according to official estimates, is concentrated around 1% of world's undeveloped oil reserves. The resources of the former disputed territory are potentially about 410 million tons of oil and nearly 6 trillion cubic meters of natural gas. According to preliminary estimates the largest deposit is the Fedynskoe field. Its resources are expected to be around 10-12 billion boe or but may potentially be as high as 18 billion boe. The "Grey Zone" can be regarded as a key for development of hydrocarbons in. the Barents Sea area due to following circumstances: it has favorable environmental and geographical conditions such as being year-round ice free, relatively shallow water – 200-300 meters and short distance to shore about 100 km. Its location is appropriate for easy organization of export of oil and gas from the northern regions. The financial costs of the development of the "Fedynskoe raising" (Fedyn Arch) will be significantly lower than in other Barents oil and gas areas further North or East. There might be huge interest by investors in this area. The investments on the Shtokman field development could be reduced taking into account the possibility of a joint infrastructure solution for these fields’ development. It seems interesting to consider an integrated planning. In the present paper we are discussing possible options for development and arrangement of the Fedynskoe field in relation to scenarios of Shtokman field planning. Despite the favorable ice conditions in this region we cannot exclude the possibility of drifting sea ice and icebergs. Taking into account the tendency of ice melting it is needed to maintain ice drift forecasting. Furthermore, polar low pressures and sea spray icing are important operational and design considerations. An analysis of existing technical solutions and facilities gives ideas for creating extraordinary and sophisticated oil and gas centre(s) in the Barents Sea region.

Heavy oil carbonate reservoirs of the giant Wafra field located in the Kuwait - Saudi Arabia Divided Zone hold huge resource of heavy oil in 3 reservoirs, namely 1st Eocene, 2nd Eocene, and Maastrichtian. More than 50 years of primary production from these high porosity, moderate permeability carbonates has recovered less than 5% of this volume and the ultimate recovery is not expected to exceed 10%. Suitable EOR technology is needed to unlock these huge resources. In absence of any commercial analogs, application of EOR technology carries enormous risk in terms of technical viability, reserves recovery and resources commitment. Proper understanding of the reservoir and optimization of EOR technology are essential to mitigate these risks to a manageable level. This paper will discuss the process used to mitigate the risks of EOR application in the 2nd Eocene reservoir. Production in this reservoir is from dolomitized carbonates associated with anhydrite. Ultimate recovery from primary production is estimated about 12%. Low primary recovery in this highly porous and moderate permeability reservoir is attributed to oil gravity, viscosity and drive mechanism. Detailed screening study to select suitable EOR processes suggested the suitability of both waterflood and steamflood for this reservoir. The study indicated the opportunity to recover up to 20% with waterflood and 40% with steamflood. Economic Modeling work indicates similar NPV for both processes but higher profitability in water flood case due to substantially lower capital requirement. Both projects have serious challenges due to reservoir nature, uncertainty in reservoir characterization, non-availability of fresh water, lack of proven technology for processing produced water for steam generation, disposal of excess produced water, fuel for steam generation, and safe environment for workers, public and wild life. These challenges make the EOR projects very high risk ventures in the areas of oil recovery, return on investment, and health, safety and environment (HSE). These risks are being managed through extensive G&G and simulation studies, exhaustive screening work and properly designed pilot projects. Two pilot projects, steamflood and waterflood, are under implementation to resolve the number of uncertainties and manage associated risks in the high reward EOR process for this reservoir. This paper will share the work flow (reservoir to economic modeling) for planning, designing and evaluation of pilot projects and innovative technology being utilized to manage risks of EOR in carbonate reservoirs. Success in mitigation of such risks will help industry to enhance sustainable and economic energy resource for future.

The majority of enhanced oil recovery (EOR) projects are being executed in the the U.S., Canada, Venezuela, Indonesia and China. The volume of oil produced by EOR methods increased considerably from 1.2 MMBD in 1990 to 2.5 MMBD in 2006 (Sandrea and Sandrea 2007). Current total world oil production from EOR is approaching 3 MMBD representing about 3.5% of the daily global oil production (Sandrea and Sandrea 2007). Thermal and CO2 methods are the major contributors to EOR production, followed by hydrocarbon gas injection and chemical EOR. Other more esoteric methods, e.g., microbial, have only been field tested, without any significant quantities being produced on a commercial scale. In recent years, the number of EOR projects has increased with escalating oil prices.The number of EOR projects in the Middle East (ME) has also increased over the past decade. In some countries like Oman, there has been no choice but to implement EOR projects aggressively due to dwindling "easy oil." Other countries in the region have also started to think EOR, and are including them in their strategic short-, medium- and long-term development plans. Furthermore, there are many projects on the drawing board and appropriate screening studies and EOR pilots are being pursued region-wide. This paper reviews the current ME EOR projects from full-field development to field trials, including those on the drawing board. The option of advanced secondary recovery (ASR) — also known as improved oil recovery (IOR) — technologies before full-field deployment of EOR is also discussed. A case is made that they are a better first option before deployment of capital-intensive EOR projects. The ME’s general drive towards "ultimate" oil recovery — instead of immediate oil recovery — is highlighted in the context of EOR. Some of the enablers for EOR in the ME are also discussed in the paper. It highlights the opportunities and challenges of EOR specific to the region.

Abstract The Bureau of Ocean Energy Management, Regulation and Enforcement's (BOEMRE) Environmental Studies Program has funded more than $750 million in environmental studies since 1973 to support decisionmaking as it relates to offshore oil and gas and most recently, renewable energy production. Each regional office within the agency developed its own studies program to support environmental research for information needs specific to that region. The regions' studies programs evolve as new information needs and environmental concerns arise. The Gulf of Mexico Region's (GOMR) Environmental Studies Program funds studies related to air quality, biology, protected species, physical oceanography, oil spills, socioeconomics, and marine archaeology as well as other topics. This paper will discuss BOEMRE's Environmental Studies Program in the GOMR and highlight studies that focused on or included a marine archaeology component to illustrate how science is used to inform decisionmaking and ensure that industry activities do not impact sensitive resources. It will also discuss the program's continual evolution in response to changing information needs such as studying the impacts from the Macondo oil spill. Study results aid in the analyses incorporated into our environmental impact statements and environmental assessments required by the National Environmental Policy Act of 1969 (NEPA), and the development of survey requirements. Study results are also used to create or modify environmental mitigations that may be assigned to permits as a condition of approval where sensitive features such as live-bottom habitats, chemosynthetic communities, or archaeological resources could potentially be impacted by industry activities. The BOEMRE's Environmental Studies Program and the results of agency-funded environmental studies as they relate to analyses and management of offshore resources have not been previously presented at OTC. This paper will inform industry about the Environmental Studies Program and how study results are used to support agency decisionmaking. Introduction In 1973, the Environmental Studies Program (ESP) was developed to support the oil and gas leasing program administered by the US Department of the Interior (DOI). The Outer Continental Shelf Lands Act (OCSLA) of 1953 as amended, authorized the program and established its goals, while the National Environmental Policy Act of 1969 (NEPA) imparted additional statutory authority. The goals of the ESP, provided in Section 20 of OCSLA, are to:Establish the information needed for assessment and management of environmental impacts on the human, marine, and coastal environments of the Outer Continental Shelf (OCS) and the potentially affected coastal areas;Predict impacts on the marine biota which may result from chronic, low-level pollution or large spills associated with OCS production, from drilling fluids and cuttings discharges, pipeline emplacement, or onshore facilities; andMonitor human, marine, and coastal environments to provide time series and data trend information for identification of significant changes in the quality and productivity of these environments, and to identify the causes of these changes.

This paper summarizes methods, chemistries, and application results for a range of liquid foaming agents on a collection of wells applied at a single property in Northern Alberta. The paper goes on to summarize the philosophy, design criteria for selection of remediation chemistries, and methodologies used to counter the production decline occurring as a result of water production. Gas flow rates from these low pressure gas wells were being dramatically affected by production of free or condensed water. If allowed to collect to sufficient levels, the produced fluid killed production altogether. The shallow (500 to 750 meters) wells on this lease are particularly sensitive to fluid production as reservoir pressure was very low, approximately 700 kPa (102 psi), and production of only 0.5 m3 (3.15 bbl) of water per day could kill a well. Additional challenges were caused by high solids production and scale deposition. Additionally, further loading up the wells and lowering production as well as asphaltene precipitation, formed a very adherent and dense solid precipitate with sand produced by the well. Initially wells were cleaned with a combination batch asphaltene solvent. Subsequently, a very pervasive foam forming chemical was used to unload solids. Continuous injection of 2 liters per day of a liquid based foaming chemical into one particular well increased gas production by 3 e3m3 (0.1 mmcf) per day (a 50% increase). Other wells were successfully treated to remove water and solids that were blocking the perforated interval. Significant value was added by increasing production field wide by 33% with an insignificant associated chemical cost. The results and conclusions of this work are applicable to the shale gas and CBM fields being produced throughout North America and enable best practice chemical well enhancement to be applied.

Abstract Parque das Conchas is an ultra-deepwater heavy oil development located in the northern Campos basin offshore Brazil. The project is a joint venture between Shell, Petrobras, and ONGC. The first phase of the project is the development of 3 independent subsea fields tied back to the centrally located turret moored floating, production, storage and offloading (FPSO) host facility entitled the FPSO Espirito Santo. The phase 1 Abalone, Ostra, and Argonauta B west fields are small to medium in size, with low-pressured reservoirs, and range in oil gravities from 17O to 42O API. A fourth 16O API gravity heavy oil field requiring water flood, Argonauta O north, will be tied back as part of phase 2 and is planned to be ready for production in 2013. The phase 1 subsea infrastructure consists of 10 producing wells and 1 gas injection well connected via 140 kilometers of pipelines and flowlines ranging in size from 6?? to 12??, 15 flowline sleds, 2 production manifolds, 2 artificial lift manifolds housing a total of 6 vertical subsea separation caissons with 1500 hp ESP's, 25 jumpers, all of which are serviced by 30 kilometers of high voltage multi-circuit electro/hydraulic umbilicals and 20 kilometers of static electro-hydraulic umbilicals. The FPSO Espirito Santo is a converted 1975 VLCC moored in 1,780 meters of water and equipped to process 100,000 bopd, 50 MMscfpd, with 1.4 million barrels of oil storage capacity. The Parque das Conchas development is the result of a 9-year effort to understand the complex geology, identify sufficient reserves to support a development, identify an economic development concept, and to design, mature and apply the significant new technologies required to safely execute the project during an extremely volatile market period. This paper provides an overview of the development and execution of the project, highlights new technologies that have been developed and implemented and introduces the key challenges, achievements, and learning's in various parts of the project and the tight integration between all disciplines required to successfully deliver the Parque das Conchas project. Additional details can be found in the dedicated support papers have been generated and listed in the Reference section of this paper. History The Parque das Conchas development grew out of a substantial exploration and appraisal program commencing in 2000 in which 13 wells were drilled and 6 discoveries were made. The Declaration of Commerciality was signed with the ANP (the Brazilian National Petroleum Agency) in December 2005 and the project was sanctioned in November 2006. The four main reservoirs; Ostra, Abalone, Argonauta B west, and Argonauta O north were named after aquatic shellfish indigenous to the area. Together they form " Parque das Conchas?? or " Shell Park?? in Portuguese. This is the first project taken by Shell from exploration discovery to production. First oil from Phase 1 was achieved on the 12th of July 2009, just 9 years after discovery.

The Goliat field is the first offshore oil field in the Barents Sea planned for development and operation. The field is probably the worlds' northernmost offshore field being located at the 71.2 latitude (Figure 1). The oil field is located in an environmentally sensitive area with high political focus and strict environmental requirements. It will be the first field in Norway to meet the special environmental requirements for discharges to the sea for the Barents Sea, which is stricter than the general "zero harmful discharge" requirement for the Norwegian Continental Shelf (NCS). In addition, strict requirement for emissions to air will be met by transmitting electricity from shore to cover the power demand offshore. The paper will address how thorough and focused planning (the IA1 process) over several years has ensured that the zero discharge requirements and strict obligations on oil spill planning will be met. Further, the paper will address how the project successfully managed the stakeholder dialogue, involving key stakeholders already in an early planning phase and contributing to partly changing the negatively focused perceptions by fishermen, indigenous people and the society in general.

In Malaysia and other parts of Southeast Asia, haze is an annual problem that occurs from March through June and during September and October. The haze is caused mainly by fires in land clearing for cultivation activities, which seriously affect air quality and visibility in the region. The scope of the presentation will cover the health effects and safety concerns, precautions to be observed, actions/counter measures and responsibilities during haze hazard and emergency situations in the oil and gas exploration & production (E&P) and downstream activities of an integrated petroleum multinational Corporation with its headquarters in Malaysia. The Company has business in more than 30 countries worldwide. In the Southeast Asian region, it has E&P and downstream petroleum and petrochemical operations in Malaysia, Cambodia, Indonesia, Myanmar, Philippines, Thailand and Vietnam. During haze incidents, the Ministry of Health, Malaysia has monitored the disease trend and found a positive correlation between haze, air pollution indicators and Upper Respiratory Tract Infection and Bronchial Asthma. These disease trends will be reflected in the paper. Other surveys were also conducted and are discussed. In the paper, health effects caused by haze and precautionary health measures will be detailed out with corresponding reference to the Air Pollution Indicators. The paper will highlight the control and mitigation measures, the action plan and counter measures undertaken by the Company in managing haze hazard and emergency.

This paper describes an approach for developing a protocol for chemical exposure assessment in habitats. The aim was to develop a method for the working environment toolkit to be applied in chemical risk management. In general, no hot work can be performed on pipelines and equipment when a plant is in operation (hot plant). This is due to safety reasons, i.e. explosion and fire prevention. Introducing a habitat, typically a tent with overpressure, can fulfill the safety requirements and enable that hot work can take place on a hot plant if this is performed inside the habitat. However, habitat has not been considered with respect to working environment and health risk. High concentration of chemical contaminants and noise, difficult access and work positions, may be unwanted effects introducing health risk. This paper is focusing on chemical contaminants in real habitats that have not earlier been reported in the literature. Measurements are fundamental for the chemical risk assessment of work in habitat. A protocol was drafted, selecting appropriate sampling methods, direct reading instruments, operating procedures and data collection protocols. Instruments were checked and calibrated and the robustness for field measurements was in particular investigated. A setup in a, for the purpose, designed climate chamber was made to simulate a habitat. The climate chamber enabled measurements, training of personnel, test of protocol and instruments in advance. Finally, the method will be used at real habitat measurements, to be performed at hot plant installations. The method will be revised based on the experiences achieved from real habitat measurements, and then recommended as best practice. The method for the chemical exposure assessment in habitat will enable us to determine risk, and to implement suitable control measures.

Passive completions, comprised of inflow control devices and external packers, are usually considered in horizontal wells, located in risky or mature areas. These completions are proven techniques for reservoir conformance to mitigate water or gas-coning problems and ensure uniform production contributions along the horizontal section. After well completion or shortly after initial production, these wells may fail to sustain production, largely due to formation damage or plugging in the inflow control devices. The conventional acid program, applied on wells with non-passive completions, is not suitable on these wells, due to the risk of impacting the completion integrity to the extent that it will violate the installation purposes. The requirements of acid treating wells with the same completions become inevitable due to the increasing number of wells equipped with these completions in a major carbonate reservoir in Saudi Arabia. A smart approach has been developed through innovative thinking to stimulate wells equipped with passive completions. The new approach has successfully stimulated four wells and resulted in restoring well productivity. This smart stimulation approach demonstrates a competent method to clean out the ICD completion along the horizontal section and to remove formation damage. This paper presents in depth discussion of rigless acid stimulation operations on oil producers to remove formation damage and improve well productivity, at a reduced cost. This paper also outlines the successful application of the smart approach in acid stimulation of horizontal wells — equipped with passive completion — and discussed the post-treatment results. Background Water injection was started to boost up and maintain the reservoir pressure. All producers were initially drilled as vertical producers and with the advancement of the water front, a great deal of the vertical producers were converted to short radius horizontals (SRH) that targeted the thin oil column behind the flood front. The oil was sourced from Jurassic organic-rich lime mudstones, which were laid down in intershelf basins. The integrity of the thick anhydrite top seal is enhanced by the general absence of faults in the Jurassic section. The main oil reservoir is the Upper Jurassic Arab-D limestone, which improves upward from mudstone to skeletal-oolitic grainstone, reflecting successive upward-shoaling cycles. The excellent reservoir quality is due to the preservation of the primary porosity, the enhancement of permeability, and the presence of fractures in the deeper and tighter parts. The oil was sourced exclusively from Jurassic organic-rich mudstones and is effectively sealed beneath massive anhydrite. The general absence of faults at the Arab-D level maintained seal integrity.

This paper discusses the approach of Cairn Energy India Ltd. (CEIL) in the use of a state of the art technology that integrates all relevant data scenarios for designing and planning development wells in the Mangala field of Western Rajasthan, India. To improve the quality of the well planning process, CEIL has realized the importance of a collaborative well planning environment, which was implemented by means of its world-class 3D visualization center that enables multidisciplinary well planning workflows to take place in the subsurface environment. The environment includes physical infrastructure, new technology, and data. A fully functioning collaborative well planning environment enables the drilling team to plan wells using engineering tools, including drilling target definition and refinement, well pad positioning, and wellbore position uncertainty, based on company anti-collision policies, with geosciences team capacity to validate those designs against their subsurface data. The Mangala field development process has established the success of CEIL with rapid, multisolution iterations well planning to the entire asset team and improved wellbore positioning based on potential engineering constraints. This process takes the optimum reservoir drainage into account with possible geological hazards and reduces the operational cost by complementing technical expertise across the broad disciplines. The workflow aids wellbore and drilling optimization and improves decision making and collaboration throughout the field development sequence. The paper explains the detailed aspects of collaborative well planning and optimization of well placement methodology used for Mangala field, which includes 11 horizontal wells that were largely designed as shallow extended reach drilling (ERD) wells. It demonstrates how this method significantly improved the mutual workflow between departments and increased efficiency. This paper also describes the interactive design that dramatically decreased the cycle time in planning more than 160 wells in the field, which contributed to effective development plans and well placement based on geological, drilling, and completion requirements.

Abstract This paper presents the benefits of surveillance efforts adopted for monitoring a waterflood in a geologically complex reservoir that contains high-viscosity (90 cp) oil. The reservoir is part of a large brownfield in South Oman and has been on production for more than 25 years. The development of the reservoir has been carried out in phases and full-field water injection was started after approximately 18 years of primary depletion. The water-flood project is expected to increase recovery factor by about 10% over primary depletion. The current phase of development is focused more on well and reservoir management (WRM) to optimize production from the reservoir over a short-to-medium term without detrimentally affecting subsequent implementation of a polymer flood. The implementation of a surveillance program in adverse mobility scenario in presence of faults and fractures and the constraints of existing well completion called for innovation and adaptation of the conventional surveillance techniques to existing downhole environment. The paper presents field examples to illustrate benefits of tailor-made surveillance execution to optimize a high viscosity oil waterflood project. Introduction A methodical surveillance and monitoring process is critical to success of any water-flood project. In case of high viscosity oil water-floods, surveillance techniques used in normal water-flood reservoirs need to be adapted to yield meaningful information. Surveillance work in the discussed field posed a formidable challenge because of well completion that is not amenable to surveillance-data acquisition and subsequent remediation. All wells are completed with pumps (beam-pump, progressive cavity pumps or electrical submersible pump) and have some form of sand-control device (external/internal gravel pack or wire-wrapped screen) restricting direct logging access to specific production/injection zones. Routine surveillance logging such as production logs, cased hole resistivity, Pulsed Neutron logging for saturation etc. could not be run in these wells and even if managed the data obtained provided challenges to interpret results due to complexities arising from completion configuration and flow behind screen. This situation also restricted many conventional interventions like mechanical water shut-off, re-perforation or addition of perforations etc. The above mentioned completion types were in turn dictated by the objective of maximizing well productivity; given the formation properties, crude oil characteristics and reservoir pressures. Many options to overcome these restrictions were considered and a cost effective means implemented was to recomplete wells with dual strings with one string carrying lift pump and other used as observation string. This observation string enabled running of all necessary logs while well is producing. The observation string also enabled routine well intervention without the need for a workover unit and associated cost. As next improvement, all new wells are now completed with wire-wrapped screens using external swellable packers to achieve producing reservoir segmentation and intervention capability.

Water production from a deep, hot Gulf of Mexico well has led to the problematic deposition of lead and zinc scales in the near wellbore area and perforation interval. The well completion contains Incoloy 825 metallurgy. The exotic scale, high temperature, and exotic metallurgy contributed to expensive well repairs and limited prevention options. Prior to the squeeze application that is the subject of this paper, the subject well was experiencing rapid production decline which required frequent and uneconomical acid dumps and mechanical milling. This paper describes a novel technology that has prevented deposition of the scale. The application described has been used in the Mobile Bay area of the Gulf of Mexico. A well recently squeezed with a scale inhibitor developed for use at high temperatures (>420°F). Tube blocking lab testing showed it to be effective scale inhibitor for preventing sulfide scales. The squeeze application was pumped as a 20% active pill in KCl and displaced with nitrogen. Four treatments have been applied to the well over the last 13 months. The well was quickly, economically, and successfully treated to prevent the scale. Scale inhibitor residuals remain high six months after the second treatment. Two gauge-ring run with wire-line indicates scale-free tubing. Production rates and pressures have improved from pre-treatment values. It is the intent to continue monitoring residuals and re-squeeze the well when residuals drop below the effective level. The primary benefits of the chemical squeeze are long-term production and reduced mechanical intervention. Other benefits include the potential elimination of surface treatment equipment, reduced use of acid, ease of monitoring, and proven success. This novel technology brings an economic and technologically superior solution to the problem of high-temperature, exotic scale management in GoM wells.

This paper provides and over view of the risk management and ALARP considerations/theory as applied to the safety regime highlighting principles that can be applied to environmental ALARP. The paper introduces the concept of Best Available Techniques (BAT) as an equivalent and established concept to ALARP in environment. It provides advice on the approaches to be taken, level of study and accountabilities for organising, assessing and sign off. The approaches proposed focus on simple assessment where possible and a demonstration that the practices proposed meet ALARP criteria and allows flexibility in approach, and is therefore not over prescriptive. When considering ALARP it should be remembered that it is intended to deliver a process that demonstrates that we have challenged whether our current designs and operations are sufficiently protective of the environment.

This paper describes qualitatively the key factors driving deepwater petroleum exploration and development prospectivity worldwide, including but not limited to global petroleum supply and demand fundamentals, availability and accessibility to petroleum resources, technology innovations and infrastructure development, and geopolitics and fiscal arrangements. Quantitative indicators are estimated to analyze these factors with respect to deepwater activity and outcomes in Africa using number of fields discovered, the number of producing and on-stream fields, the estimated average size of discoveries, instantaneous production flow estimates, completion techniques and methods, and capital expenditure compontents and trends. The paper evaluates and compares the attractiveness and prospectivity of the deepwater in Africa using the above empirical indicators by country.

DescriptionThis paper discusses well-interventions in Colombia that use a new generation of polymeric selective-water-reduction (SWR) product for selected candidates, treatment definition, differences of composition, radius of penetration, stages according to formation petro-physical properties, and well-productivity response in the short and long term. The evolution and improvements in technology over the past five years and its application in Colombia will also be discussed.Previous papers have presented databases with information from interventions around the world, including case histories from Colombia (Dalrymple et al. 2007). This paper will focus on more detailed information for selection, treatment, and operational procedures in Colombian fields.ApplicationThere are hydrocarbon-producing formations in Colombia that have productivity limitations because of their high relative-permeability to water. This condition has generated increased tendencies to water-coning, historical and gradual water cut increases, and promoted a negative impact during the productive well life. This technological application includes new perforated wells (which are characterized for a potential rapid water-coning based on the geographical area or the formation) or producing wells in mature fields where the intervention still presents economical benefits. Information will be presented from wells with zones covering mid-to-high permeability, clean sandstones, and argillaceous sandstones at temperatures ranging from 125 to 250°F.Results, Observations, and ConclusionsThere are records of successful treatments, allowing for a reduction in the water to oil ratio, with increased productivity which has been maintained for more than three years. It has been possible to identify benefits from the technology, its evolution, and improvements during recent years. However, candidate-selection criteria have been continuously adjusted, which has generated more successful cases.Significance of Subject MatterSelective water reduction (SWR) is a viable technology with an extensive history of applications worldwide, and its usage has increased during the last five years in the productive basins of Colombia. A strong, continuous improvement effort has been in place for better reservoir characterization, understanding of water-production mechanisms, laboratory protocols, candidate selection, treatment design (volume estimation, placement techniques), and treatment follow-up.

Abstract Until now, offshore oil and gas production in the Republic of Congo has been restricted to the area covered by shallow water technology, up to water depths of around 200m. The Moho Bilondo development is the first deepwater development in these offshore Congolese waters and this paper presents the flow assurance issues that have been addressed during the design, construction, installation and start-up of this field. The development comprises of production from the two reserves of Mobim and Bilondo. To meet the challenging project schedule the flow assurance aspects of the process design had to play their part and had to be both functional and robust. This paper presents the flow assurance issues that have been addressed during the development of the project. The challenges for flow assurance fall into three categories. Firstly, the hydrodynamic issues had to be addressed. Bilondo oil is relatively heavy and requires gas lift injected downhole to achieve the desired recovery of reserves. At the same time, the down-sloping nature of the sea bed terrain from the Bilondo manifold can present the typical problems of induced slug flow regime. Management of the gas lift strategy was therefore key to the operating philosophy. The thermal insulation performance to provide the required cooldown time for preservation had to be achieved for the entire subsea production system, so as to avoid the formation of hydrates during prolonged shutdowns. Making matters worse is the downhole supply of cold lift gas via the Xmas tree, which has a cooling effect on the production fluid in the tubing. An additional risk identified here was that of wax formation on the inner tubing wall. Significant finite element studies were performed on the Xmas tree wet insulation to achieve the desired thermal performance. Thirdly, the risk to production by the formation of naphthenate soap deposits was also assessed. Steps were taken in the design of the topsides process and of the chemical injection strategy, dosing rates and injection points both subsea and on the topsides, to manage these risks.

Abstract The purpose of this paper is to present the main strategies adopted by PETROBRAS and to be submitted and decided together with its co-venturers in the Brazilian Industry, to develop the designs, contracts and construction activities for the latest offshore production units in Brazil, since 2003, and also present the development of this strategy for the future Pre-Salt layer, emphasizing the challenges of transforming the opportunity into the development of a World Class local supplier industry and therefore maximizing qualified jobs and employment in Brazil. The paper will be focused on the latest Projects and their lessons learned (ex. similarity applied to different Projects) that will contribute with the Pre-Salt development, deep water giant offshore oil and gas fields located at Campos, Santos and EspÍrito Santo Basins - Brazil. Conversions and new units will be presented in terms of their unique features and key Project decisions that affected their design, construction and installation. Massive investments in Brazilian oil & gas sector will be highlighted, such as new scale of goods and services demand, and the required initiatives to improve local supplier industry competitiveness such as professional qualification, industrial infrastructure and technologies providing scale gains and increasing productivity. In addition, we will be presenting the Brazilian Governmental Program, PROMINP, created to support the implementation of a local content policy. From the identification of the gaps related to the professional qualification, industrial infrastructure and supply of materials and equipment, and in collaboration with local industry main stakeholders, Government, O&G Operators and Suppliers Associations, PROMINP has developed and implemented a set of actions in order to increase local industry competitiveness. Since PROMINP's creation, the Brazilian industry participation (Local Content) in the oil & gas Projects increased from 57% in 2003 to 75% in 2007, what meant an addition of US$ 8.3 billion in acquisitions of goods and services in the national market. It also has generated more than 390,000 new jobs in this period. Introduction Before 2003, many important Units of PETROBRAS were built in other countries, such as Singapore, Korea, Spain, etc. During this period, the Brazilian naval and offshore industries lost great part of its capabilities to provide larger Projects, mainly the ones related to offshore operation. In 2003, the Brazilian Government has decided to revitalize this industry, including Minimum Local Content requirements in the offshore development Projects. To attend these minimum Local Content requirements, we had the following problems to solve:Lack of capacity of the main vendors, that has been caused by the long period of non-significant activities demanded by the National Offshore area;Yards and shipyards needed to be retrofitted. Many of them where totally closed;Little skilled labor and qualified people to provide services for all phases: Design, Procurement, Construction & Assembling and Commissioning.