Gas Development Projects Research Articles

Optimal planning of oil and gas development projects considering long-term production and transmission

This paper proposes an integrated model for making a group of strategic decisions about oil and gas development projects simultaneously over a long-term planning horizon. These decisions involve: selection of field and pipeline development projects, scheduling of selected projects, production planning, and upstream transmission planning. The proposed model is formulated as a linear mixed-integer-programming model. It is implemented in a case study to demonstrate its usefulness and applicability in practice. Finally, a number of sensitivity analyses are carried out to analyze the impact of most influential uncertainties on the solutions and the corresponding results are discussed.

Toward Project and Program Management Paradigm in the Space of Complexity: A Case Study of Mega and Complex Oil and Gas Development and Infrastructure Projects

The author published his research paper at 26th International Project Management Association World Congress in which he argued that the monodukuri industry, or broadly hard systems project industry, is being affected either positively or negatively by a variety of complexity categorized by P.E.S.T.L.E. (political, economic, social, technological, legal and environmental) factors and proposed a conceptual model of an enterprise viability system reinforced by meta program management. This paper is based on the author's continuing meta program management research and contextual analysis of the project industry, traces how the typical events discussed under each of the PESTLE factor categories have behaved thereafter to confirm the validity of impact descriptions, and presents a case analysis of current mega oil and gas development and complex infrastructure projects for dominant characteristics of project operations. Then new thoughts of project and program management in the space of complexity of the project industry are proposed as the first step to build a new management paradigm, which has been qualitatively induced by the cases under study and are deriving from existing research results on complex projects.The new thoughts include meta program management to balance multi objectives; knowledge and stakeholder integration to create complex projects; finance planning and structuring as an essential ingredient of materializing complex projects; management of extreme projects; and contingent risk management.

Prediction of mobile water in a tight gas sandstone reservoir using NMR and fractional flow model

One of the objectives of petrophysical interpretation is the estimation of the respective volumes of formation fluids. With traditional interpretation using conventional openhole logs it is only possible to determine the total amount of water. The challenge is to determine the volumes of bound water (clay-bound and capillary-bound) and free water. At the moment, NMR is the only measurement that can help distinguish the volumes of each water component (clay-bound, capillary-bound and mobile), using cut-offs on T2 (transverse relaxation time). However NMR interpretation also requires information on reservoir properties. Alternatively, steady-state relative permeability and fractional flow of water can be used to determine the potential of mobile water. The study area, located in the Cooper Basin, South Australia, is the target of a planned gas development project in the Patchawarra formation. It comprises multiple stacked fluvial sands which are heterogeneous, tight and of low deliverability. The sands are completed with multi-stage pin-point fracturing as a key enabling technology for the area. A comprehensive set of data, including conventional logs, cores and NMR logs, were acquired. Routine and special core analysis were performed, including NMR, electrical properties, centrifuge capillary pressure, high-pressure mercury injection, and full curve steady state relative permeability. A fractional flow model was built based on core and NMR data to determine potential mobile water and the results compared with production logs. This paper (SPE 165766) was prepared for presentation at the SPE Asia Pacific Oil & Gas Conference and Exhibition, held in Jakarta, Indonesia, from 22–24 October 2013.

Minimising the impact of shale and tight gas projects in Western Australia: an assessment of the existing regulatory framework

This paper analyses the WA legal framework that regulates the impact of shale and tight gas project development, especially during the extended appraisal phase. It assesses whether the existing regulatory framework in WA is more suited to conventional petroleum projects, particularly regarding the application of the Environmental Plan requirements, and triggers for referral to the Environmental Protection Authority (EPA) during the extended appraisal phase of project development. This paper not only seeks to understand whether the existing framework is suited to the commercial development of shale and tight gas resources in WA, it also provides information and points of discussion for industry and regulators so that there might be a consensus in the development of shale and tight gas (especially during the field appraisal and development phase) in the existing WA regulatory framework, and the development of shale gas resources in Australia generally. The paper initially considers the existing regulatory framework of shale and tight gas activities in WA, including an examination of the Western Australian Department of Mines and Petroleum as the lead agency in the development of unconventional gas resources. It also assesses whether the existing regulatory framework for shale and tight gas activities in WA is best practice for the appraisal phase of shale and tight gas activities.

Extracting Profits From Abu Dhabi's Sour Gas

Sour Gas An increase in local gas consumption in the UAE has caused Abu Dhabi National Oil Company to turn to development of the emirate’s sour gas fields, one of the most challenging types of fields. The development of the first sour gas field here, the Shah gas field in Abu Dhabi, is on track for 2014 startup with work on the project more than 70% complete at the end of 2012. The USD-10-billion project is proceeding under the direction of Al Hosn Gas, a joint venture between Abu Dhabi National Oil Company (ADNOC) and Occidental Petroleum Corporation (Oxy), where Oxy holds a 40% participating interest in a 30-year contract. ADNOC holds the remaining 60% interest. “The project involves construction of several gas-gathering systems, new gas and liquid pipelines, and processing trains. The development is expected to produce significant amounts of condensate and natural gas liquids [NGL],” said Saif Al Ghafli, chief executive of Al Hosn Gas. In 2012, Al Hosn Gas constructed plants and a pipeline network, and completed almost four of the 20 wells targeted in the drilling campaign. In addition, the joint venture took over full operatorship of the drilling program from Abu Dhabi Company for Onshore Oil Operations (Adco) in April 2012, and finalized contracting of required services and materials for the drilling program. The joint venture also obtained two rental drilling rigs that started drilling operations in July 2012, in addition to Adco’s assistance in lending a rig and drilling the first four wells in 2011 and 2012. Al Hosn Gas’ Development Division, which includes geologists, geophysicists, reservoir engineers, drilling engineers, and drilling health, safety, and environment (HSE) and field-implementation specialists, will help ensure that the continuously updated reservoir development and drilling plans can aid in maintaining uninterrupted availability of the anticipated volumes of gas at the wellheads during the project’s expected 30-year lifespan. The development team conducted the first well-production test on 5,000-ft lateral sections in the Arab C and D reservoirs in the Shah field. The subsurface group has continued to build and improve reservoir models based on the latest well data obtained to further optimize the ongoing drilling program. A seismic-data reprocessing pilot was successfully concluded, providing further technical insight for optimum well placement in the reservoir, and will move on to full field implementation later this year. The Shah Gas Development (SGD) project consists of four major elements: the gas-gathering system, the Shah processing plant, product pipelines, and the Shah sulfur station. The field’s high hydrogen sulfide content—23% in the well fluid—means that in addition to key HSE design and implementation considerations, it will pose certain unique challenges due to the sheer scope of work to be done. The SGD project will also have a total of four trains for the massive Sulfur Recovery Units (SRU) that will process the 1 Bcf/D of sour gas. The SRUs will have a capacity of 2,500 tons per day (T/D). The four main products expected to be produced from the billion-scf/day of feed gas at SGD, which lies about 180 km southwest of Abu Dhabi, are sales gas (500 MMscf/day), NGL (4,400 T/D), sulfur (9,200 T/D), and about 33,000 B/D of condensate.

Using Ethnography to Monitor the Community Health Implications of Onshore Unconventional Oil and Gas Developments: Examples from Pennsylvania's Marcellus Shale

The ethnographer's toolbox has within it a variety of methods for describing and analyzing the everyday lives of human beings that can be useful to public health practitioners and policymakers. These methods can be employed to uncover information on some of the harder-to-monitor psychological, sociocultural, and environmental factors that may lead to chronic stress in individuals and communities. In addition, because most ethnographic research studies involve deep and long-term engagement with local communities, the information collected by ethnographic researchers can be useful in tracking long- and short-term changes in overall well-being and health. Set within an environmental justice framework, this article uses examples from ongoing ethnographic fieldwork in the Marcellus Shale gas fields of Pennsylvania to describe and justify using an ethnographic approach to monitor the psychological and sociocultural determinants of community health as they relate to unconventional oil and gas development projects in the United States.

我が国の基盤海洋技術に関する一考察

In order to consider how to strengthen and foster core ocean technologies, current state of ocean technology in Japan is reviewed. The framing of ocean technologies used in the offshore oil and gas development is investigated, and linkage between these technologies and ocean technologies necessary for the ocean renewable energy utilization, the sea floor mining and the methane hydrate development which are expected to be industrialized in Japanese exclusive economic zone (EEZ) in the future. The history of development of ocean technologies in Japan is reviewed to know strength and weakness of Japan's ocean technologies. Summarizing these results, it is found that there is strong linkage between ocean technologies used in the offshore oil and gas development and future projects deployed in Japanese EEZ, and it is important to invest governmental funds in a comprehensive and systematic fashion for developing those core technologies. It is also emphasized that it is important to apply the environment technology and IT to the ocean technology for strengthening Japan's core ocean technologies.

Baseline survey of the terrestrial invertebrate fauna of Barrow Island

Barrow Island is Western Australia's second largest offshore island and its flora and fauna have been able to evolve without major human disturbances. Chevron Australia Pty Ltd and its Joint Venture Participants made an application to construct a plant to liquefy natural gas on the island in 2001. One of the conditions under which approval was granted was the implementation of a rigorous biosecurity effort to ensure that no non-indigenous species (NIS) are introduced or allowed to establish on the island. To fulfil this condition it was first necessary to characterise what was already present on the island. A series of surveys have been performed using a purpose-designed sampling protocol in order to provide baseline data on the existing terrestrial invertebrates on Barrow Island. A total of 1,873 morphospecies were sampled but subsequent surveys and taxonomic developments have increased the count to 2,397. This compares with an estimated species richness of 2,481 terrestrial invertebrate species on the island. Composition of the fauna varied considerably between the wet and dry seasons and between years, even when samples were taken during the same month. Composition also varied with distance from the coast, which may be associated with soil type and vegetation association. Twenty five non-indigenous species and seven putative non-indigenous species have been found, all of which are believed to have been present prior to commencement of the Gorgon Gas Development project.

Oil and Gas Industry Megaprojects: Our Recent Track Record

Summary Projects throughout the process industries--oil and gas, chemicals, and minerals--have become significantly larger and more complex over the past decade or so. The underlying reasons for increasing project size and difficulty are understood--we are developing natural resources in progressively more difficult circumstances simply because we have to. Moreover, the choice of oil and gas developments is influenced by the decisions of some large resource-holding countries to restrict or delay the development of some more easily accessible reservoirs. Eight years ago at the Offshore Technology Conference, the author reported on a distressing pattern that Independent Project Analysis (IPA) was seeing in offshore projects: Success, measured by how well we meet promises made at the time of the financial investment decision (FID), declines rapidly with project size (Merrow 2003). (Note: IPA benchmarks projects before FID and project systems in the oil and gas and other capital-intensive industrial sectors.) While projects in the USD 300- to USD 600-million range were largely successful, the success rate for the megaprojects--defined as exceeding USD 1 billion measured in constant start-of-2003 terms--was approximately 50%. Interestingly, megaprojects in other industrial sectors, such as downstream oil and gas, minerals, and chemicals, had approximately the same rates of success and failure. In this updated analysis with a much larger sample of both oil and gas and other process industry megaprojects, our conclusion is quite different for oil and gas projects. While non-oil and gas development projects increased in size and difficulty, they maintained a success rate of approximately 50%. This rate of success is certainly not good, but at least it had not declined despite the much more difficult projects market. Meanwhile, the performance of oil and gas megaprojects collapsed; only 22% of these projects could reasonably be called successful. While the successful projects were spectacularly successful, the other 78% were equally unimpressive with 33% real cost overruns, cost indices that averaged 1.37, and execution schedule slip of 30%. More importantly, a disappointing 64% of these projects experienced serious and enduring production attainment problems in the first 2 years after first oil or gas. The issue this paper addresses is why the relative performance of oil and gas megaprojects dropped so precipitously in the first decade of the twenty-first century.

Modeling epistemic subsurface reservoir uncertainty using a reverse Wiener jump–diffusion process

This paper develops a mathematical model of how subsurface reservoir uncertainty, in particular estimated ultimate recovery (EUR), can evolve over time. The model assumes that epistemic uncertainty reduces over time as information from seismic surveys, appraisal wells and production logs is used to improve EUR estimates. A reverse Wiener diffusion process with superimposed jumps is developed to capture the exponential decrease in estimate volatility due to learning but also the existence of sudden jumps in estimates due to unexpected discoveries such as reservoir fault lines or aquifer support. The model can be applied to quantify the evolution of reservoir uncertainty over time during appraisal and planning of new oil and gas development projects. Appreciation Factor data from 34 North Sea fields is used to calibrate and validate the model showing that the evolution of EUR estimates is predicted with 82.4% of validation data points within the simulated P10 and P90 uncertainty envelope, which should theoretically cover 80% of data points if there is no model error. The key parameters in the model are the initial EUR distribution, as well as the exponential decay rates for EUR volatility and the likelihood of occurrence of discrete jumps.

Breakthrough in 22-in.-Hole Drilling in Kuwait Deep Wells

Summary High-pressure/high-temperature exploration activities in Kuwait include the drilling of deep wells (approximately 16,500 ft) to search for high-quality oil from the Jurassic formations. Recent discoveries of commercial gas and light oil in six of the North Kuwait oil fields have resulted in the startup of the North Kuwait Gas Development Project. This project is a major venture with a planned production growth up to 1,000 MMscf/D of gas and 350,000 B/D of light oil, which requires a total of more than 90 new wells. For this new phase of development, the challenge was to change the approach to the drilling of deep wells to reduce overall project timing and cost. A rethinking of current drilling methods was required along with the application of new technology solutions to optimize drilling times. The North Kuwait deep-well design is complex and requires surface/intermediate casings to be set at maximum depths to reach target depth (TD) in a workable hole size. The 22-in. hole is drilled from 6,000 to 9,500 ft and was considered to have a potential for improvement. A conceptual project was set up that would attempt to replace multiple 22-in.-insert-bit runs, rotary driven, with a single polycrystalline-diamond-compact (PDC) bit design run on a downhole motor. The objective was to establish a partnership approach with the bit manufacturer and motor provider and to develop bit designs, equipment specifications, and operational parameters over the project period. The bit design team identified the main aspects on which the new PDC-bit design was to be based, and a prototype bit was manufactured. Results from the first run of the bit were analyzed, and the design was modified for the second run. A critical element was the development of the downhole motor, with a more-powerful 12¾-in. motor with precontoured stator being used for the second and subsequent runs. Bit designs and downhole-motor and rig-equipment specifications were developed and improved on over the project, resulting in the achievement of the project goal with the drilling of the entire 22-in. section with one bit from shoe to shoe. The performance improvements in the trial wells gave substantial increases in rate of penetration (ROP) and reduced drilling times.

氷海域における大型油ガス田開発 サハリン１プロジェクトチャイウォ構造Ｐｈａｓｅ‐１開発

The Sakhalin 1 Project is one of the oil and gas development projects located on the northeast shelf of Sakhalin Island, water depth is 10 to 60 meters and the thick ice covers the area 6 to 7 months a year. The project was declared commercial by the Sakhalin 1 consortium in October, 2001, and started development period from this year. Total recoverable reserves are estimated at 307 million tons of oil and 485 billion cubic meters of natural gas. This project consists of three fields, Chayvo, Odoptu and Arkutun-Dagi, which are planned and conducted to develop in phases 1 to 4, using both offshore and onshore wells.Many of these wells will be drilled using a new drilling technique called ERD (extended reach drilling), which allows oil and gas targets to be drilled by the rig located a great distance away.The first phase of development is focusing on the oil production of Chayvo and Odoptu fields, and the start of the oil production from Chayvo field was commenced in October 2005.The oil production reached to 250 Kbpd at peak rate in 2007. The produced oil is transported through the pipeline to the marine tanker terminal at Dekastri Located Khabarovsk province. Large marine tankers are escorted by icebreakers during winter season using a new developed ice passport concept for the year-round export operations.These advanced technologies were applied to reduce the overall cost of development and to minimize environmental impact.

Potential Impacts of Integrated Oil and Gas Plant on Ambient Air Quality

The ISCST-3 model has been used to study the ground level concentrations of carbon monoxide (CO), oxides of nitrogen (NOX), particulate matter less than 10.0 microns in diameter (PM10) and sulphur dioxide (SO2). The purpose was to predict air quality effects from an integrated oil and gas project (IOGP) proposed for the Niger Delta, Nigeria. The emissions of 12 elevated point sources for criteria air pollutants were considered with eight different scenarios. Both natural gas-fired and diesel (AGO) fired equipment were considered for the identified emission sources. Five years of hourly meteorological observations were used in the prediction of the ground level concentration of the pollutants. The model outputs show a general maximum ground level concentration between 0.5 – 3.5 km, with easterly and north-easterly receptors having the greatest concentration. The pollutants emitted in the greatest concentration in their order of magnitude were CO, NOx and PM10. Maximum ground level concentration for 1, 8 and 24 – hr periods for CO were below regulatory standards (less than 10 %) for scenarios 1 – 4 when the fuel is natural gas. The 8 – hr ground level concentrations were about 1.3 folds of the World Bank Standard in scenarios 5 – 8 when the fuel sources are switched to AGO. However in these scenarios, the Nigerian environment and petroleum ministries' emission limits were not breached for all the averaging periods. Modelled NOX concentrations were significant in all the scenarios except 3 and 4. Though NOX concentrations were within the standards for all the averaging periods in scenarios 1 – 4, except the 1 – hr limit that was breached in scenarios 1 and 2, these concentrations were about 1.1 – 2.8 folds in all the averaging periods of all the standards in scenarios 5 – 8. The predicted PM10 and SO2 concentrations are all below the guideline limits. If the use of AGO is completely avoided in the entire life of the proposed IOGP, the air quality of its immediate vicinity can be protected. Furthermore, the declaration of a radius 1.75 km natural forest buffer around the plant and continuous monitoring of ground level concentrations of CO, NOX, PM10, and SO2 may further assist in guaranteeing the safety of people in terms of air quality. The study shows the need for policy formulation that will integrate comprehensive cumulative impacts assessment of air quality in the environmental laws regulating the gas development projects in Nigeria.

An Integrated Decision-Management Process Shortens Time to First Gas

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 115251, "Reducing Time to First Gas: Lessons Learned in Expediting and Informing International Investment Chain Decisions," by Deborah D. Resley, SPE, and Christopher Reinsvold, SPE, Decision Strategies, originally prepared for the 2008 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 20-22 October. The paper has not been peer reviewed. The monetization of gas, particularly in liquefied natural gas (LNG) projects, requires large capital investment in most links of the gas value chain from production to end use. Companies that invest in a single component of the value chain, such as nonintegrated gas producers, must understand the value of and risks inherent in every link in the chain, because gas will be priced in relation to its final point of sale. Final sale price as well as the effects of processing and capacity limitations ripple their way upstream to alter the timing, demand, and viability of the upstream investment. Introduction LNG projects are good examples of complex global gas-development projects with large capital-investment requirements. To build a commercial LNG project from gas production to point of final sale requires investment in and development of several capital projects. These linked or integrated projects serve to produce, treat, transport, and sell the gas in specific markets. These projects are joined in a value chain by at least 16 major commercial contracts, beginning with a production-sharing contract at the wellhead and ending with a gas-sales agreement in the end-use market. The entire set of investment decisions in the LNG chain can be driven by objectives such as the ability to book gas reserves by a certain date, optimizing the entire gas portfolio of assets, and in the case of companies with a portfolio of LNG assets, the potential for arbitrage and the ability to leverage and trade each LNG asset. LNG projects now have even more complex business chains than 10 years ago, involving multiple investors in various parts of each chain. Successfully commercializing gas in integrated LNG projects and achieving acceptable returns requires numerous investment decisions. Building such a chain involves high-level coordination and integration of both technical and commercial processes, the option of reducing costs through increasing throughput, and leveraging economies of scale to reduce plant costs.

Evolving Subsea Technology Tackles Huge New Risks of Today's Projects

As oil and gas development projects tackle some of the world's most remote locations and extreme environments, pushing out into 8,000 ft water depths or beyond and going several hundred miles offshore, innovations in subsea technology will play a vitally important role in enabling the execution of these projects and will form the basis of future, even more-ambitious plans. Subsea technology comprises wellhead and related production infrastructure placed on the seafloor, rather than on a conventional surface platform, a spar, or a semisubmersible or other floating production facility. Subsea wells and infrastructure are tied back by flowlines, risers, and umbilicals to surface producing facilities that may be directly overhead or many miles away, possibly even onshore. While deploying subsea technology can be very expensive, as water depths increase, conditions grow harsher, and locations become more remote, the alternative of building a larger, heavier surface facility to hold the wellheads, pumps, separation equipment, and other infrastructure is often more expensive, sometimes prohibitively. "There are two things that drive much of the move toward subsea," said David Morgan, Director, Subsea Processing, Cameron. "One is cost, the other is the reservoir. Typically, you must have at least one surface facility for drilling, processing, or storage. But surface facilities are a huge expense, and reservoirs sometimes are very spread out, making it hard to drill from one surface facility. That starts to drive multiple drill centers or the move to subsea development. By minimizing the size and number of surface facilities, you can save your project a lot of money." On the one hand, when equipment is placed on a surface facility, maintenance and interventions typically are conducted from that facility, and costs are easier to project and control—compared with contracting costs for a rig or vessel to service subsea equipment. On the other hand, space is at a premium on any kind of floating facility, and the need for additional equipment (e.g., separation, water-handling, and compression facilities) as a project matures is difficult to accommodate by retrofitting late in field life. By installing the additional equipment subsea, the need for platform changes can be minimized. "How effective we are at developing subsea technologies and evolving existing technologies is going to be an indication of how successful we are in recoverable reserves and maintaining our increasing production globally," said Neil Holder, Vice President, Sales and Marketing, Aker Solutions. "More and more companies are looking at stranded gas, offshore oil, and resources in the Arctic with long tieback distances that without subsea technology can't be accessed at all. So it becomes a facilitator."

Technology Focus: Natural Gas Technology/Monetization (April 2008)

Technology Focus The natural-gas industry continues to grow on a global scale as the world's demand for energy increases, cleaner-burning fuels are sought after, and nations seek to maximize the value of their hydrocarbon resources. For the engineer, the production of gas involves multiple challenges such as a large but geographically dispersed resource base, complex reservoirs, difficult drilling conditions, and the selection of optimal completion and stimulation methods. For the commercially minded, getting gas to end-user markets involves developing strong project economics, complex commercial negotiations, crossborder transportation agreements, geopolitics, and long-term management strategies for pipelines and liquefied-natural-gas (LNG) facilities. Gas projects continue to be a mix of existing-field revitalizations, regional developments, and international megaprojects. One of the most important aspects of all successful natural-gas projects is deliverability. The economics behind producing, transporting, and distributing natural gas to end-user markets hinges on the size of producible reserves and selecting drilling and completion methods that promote high-rate and sustained production. The need for robust gas deliverability is emphasized when viewed within the context of the major gas-development projects being proposed or in progress around the world involving long-distance intercountry gas pipelines or large-scale LNG facilities. The articles selected for this month's feature focus on drilling and completion technologies that address improving and sustaining deliverability. Well completions and alteration of near-wellbore flow characteristics resulting from formation damage most often are the limiting factors in the gas-production and -transportation systems. Ultimate recovery and achieving maximum reservoir contact have been enhanced greatly in recent years by implementing and optimizing horizontal-well and multilateral-completion technologies. The formation-damage remediation technologies, both traditional and emerging, in use today offer several solutions to address various types of reservoir damage in varying reservoir conditions. Incorporating geomechanical data to optimize reservoir contact, improve wellbore stability, and minimize formation damage affords engineers additional tools to achieve robust deliverability solutions. I encourage readers not only to read the featured articles but also to look at the papers on the additional-reading list because they present many ideas and solutions on achieving greater deliverability from both existing and new fields. Together, they illustrate the great amount of effort placed on improving one of the keys to successful natural-gas development. Natural Gas Technology/Monetization additional reading available at the SPE eLibrary: www.spe.org SPE 105509 • "Design, Construction, and Optimization of Big-Bore Gas Wells in a Giant Offshore Field" by B.M. Clancey, SPE, RasGas Company, et al. (See JPT, May 2007, page 72.) SPE 111195 • "A Simple and Reliable Method for Gas-Well Deliverability Determination" by K. Aminian, West Virginia University, et al.

Single-Diameter Technology Capable of Increasing Extended-Reach Drilling by 50%

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 17828, "Single-Diameter Technology Capable of Increasing Extended-Reach Drilling by 50%," by R. Bell, R. McKee, and E. Zwald, Enventure Global Technology, and D. Lewis, SPE, and P.V. Suryanarayana, SPE, Blade Energy Partners, prepared for the 2006 Offshore Technology Conference, Houston, 1–4 May. The combination of single-diameter technology and extended-reach drilling (ERD) can have a positive effect on capital-cost structure. Single-diameter technology provides the foundation for a significant increase in the lateral reach of many extended-reach wellbores. This extended lateral reach results in increased reservoir contact that can lead to increased production per well, which can reduce field well counts. Introduction Solid expandable tubulars (SETs) have evolved over the last few years into a proven openhole-drilling-liner and cased-hole-remedial-liner alternative to conventional technology. A well-design feasibility study was conducted as part of the front-end engineering and design for a major North Sea operator. The study was performed to evaluate the relative merits of using conventional drilling technology vs. expandable-tubular technology for lateral reach and the effect on capital efficiency and potential field development. This well-design study indicated potential lateral-reach increases of 25 to 100%. Drilling-performance and cost studies indicated that existing and planned well costs and times in the same North Sea fields could be reduced by more than U.S. $40 million or 30 to 50% of the current drilling cost and time. Expandable ERD Well Design An existing North Sea oil development project and a planned subsea gas development project were used to evaluate and quantify the lateral-reach improvements possible with SETs. An in-house program was used for drillstring mechanics, stress analysis, and fatigue analysis that included operator-provided drilling and completion data, lithology, mud parameters, torque and drag, and well designs. Historical data provided a baseline for ERD in the subject fields and a context for estimation of trouble times and expected time to drill extended-reach wells as long as 50,160 ft. The current lateral-reach record in the North Sea field is approximately 26,400 ft, with significant drilling trouble. All aspects of SETs and single-diameter liners were considered in the context of ERD beyond conventional-technology limits, including the unique force transmission during expandable-technology operations. Optimal well paths were planned by use of constrained optimization methods. Wear analysis was based on an adhesive-wear model that is the basis of all industry wear-analysis programs. Casing integrity was evaluated with the working stress design approach (deterministic design) and supplemented by probabilistic design where appropriate. Drag risk was evaluated. The base well-design model evaluated the achievable lateral reach and drilling-trouble reduction with the following.Conventional drilling technology.Conventional technology with improved drilling practices.Installation of two SET liners to preserve the desired completion size.Installation of multiple, successive single-diameter drilling liners.

Estimation of Expected Monetary Values of Selected Oil Fields

As there is uncertainty in estimates of capital, reserves, and net present value in the petroleum industry; risk analysis is the key point for an oil company. It is easy to make decisions after quantifying the uncertainty with ranges of possible values and associated probabilities. Instead of deterministic models, probabilistic evaluations give a wide range of outcomes for decision making. Monte Carlo Simulation is a tool that presents different scenarios and yields probability and value relationships in reserve evaluations. In this study, an estimation of the reserves of two Turkish oil fields will be performed by using Monte Carlo Simulation and method of moments. Field data will be evaluated in two different programs. One of them is a Petroleum Risk Assessment program named CashPot, which is designed to assist in determining the economic feasibility of oil and gas exploration and development projects, and the other one is the Risk Analysis and Decision Making Program sponsored by U.S. Department of Energy. In the present work, predictions were made about how statistical distribution and descriptive statistics of porosity, thickness, area, water saturation, recovery factor, and oil formation volume factor affect the simulated original oil in place (OOIP) values. The current work presents the case of two different oil fields in Turkey. It was found that both techniques produce similar results for 95%. The difference between estimated values increases as percentages decrease from 50% and 5% probability.

Design One, Build Two - FPSO Experience in Deepwater West Africa

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 10956, "FPSO Experience in Deepwater West Africa - The Design One, Build Two Strategy," by L.B. Waters, ExxonMobil, prepared for the 2005 International Petroleum Technology Conference, Doha, Qatar, 21–23 November. The "design one, build two" strategy was used for recent West Africa deepwater developments including floating production, storage, and offloading vessels (FPSOs) for the large Kizomba A and B developments in Angola and smaller early-production-system projects such as those in Nigeria, Equatorial Guinea, and Angola. When properly managed, this strategy reduces project cycle time and cost. Introduction The West Africa experience has identified key project conditions required for successful implementation of the "design one, build two" strategy. These include use of the same engineering design, fabrication contractors and yards, vendors and suppliers, and project-leadership teams and -management systems. From a project-management point of view, this strategy requires approaches that differ from those of traditional standalone projects. This strategy, if properly planned, managed, and executed, can optimize project economics for plays with multiple large developments that have similar geologic, geographic, economic, and contractual elements. The learnings from the West Africa deepwater applications of this strategy can be applied in other large oil and gas development projects. Implementation The "design one, build two" strategy captured cost savings on the order of 10%. Completion of Kizomba B tracked 5 months ahead of Kizomba A. Fabrication on the A project fell as much as 30% behind schedule, resulting in multiple execution plan adjustments and recovery plans. The Kizomba B FPSO consistently tracked the original execution plan; progress never fell behind plan, and no recovery plans were required. FPSO Design. The FPSO designs were maintained as similar as possible while still meeting the infrastructure needs of different reservoirs. Both FPSOs will develop fields in Angola Block 15 in approximately 100 m water depth. Inlet conditions and production rates for the two FPSOs are essentially equal. Both vessels are new-build, double-sided hulls with single bottoms. They feature identical dimensions (935 ft long, 206-ft beam, and 105-ft depth) and 2.2×106-bbl crude-oil storage capacity. The topside comprises 10 process/utility modules and nine pipe racks. Each features two oil-separation trains for a 250,000-BOPD total oil capacity, 275-MMscf/D gas-handling capacity, and 340,000-BWPD water-injection capacity. Living quarters for 100 workers is at one end of each vessel, and a 320-ft flare is at the opposite end. The pipe racks run down the center of the vessel with the process and utility models set on either side. Each FPSO comprises 90,000 metric tons of steel, 40,000 pipe spools, 621 miles of electrical cable, 200 tagged equipment items, 120,000 fittings, and 84,000 supports. The primary modification for the Kizomba B design was addition of subsea production and related flow-assurance provisions. These changes were managed so they affected only a few modules and required addition of only one new module and one additional upper deck for subsea equipment.

Inverted Hockey Stick Method Quantifies Price Uncertainty in Petroleum Investment Evaluation

In this paper, we present a new method for quantifying the uncertainty of economic projections due to uncertainty in future oil prices. Traditionally, the petroleum industry has employed what are known as “hockey stick” price forecasts, i.e., monotonically increasing price profiles, in economic calculations to evaluate investment opportunities. Calculations are often run using most-likely, optimistic, and pessimistic price profiles in an attempt to quantify the uncertainty in the resulting economic indicators. These conventional hockey stick methods significantly underestimate uncertainty because they do not reproduce the volatility inherent in oil prices. Stochastic methods that attempt to model price volatility have been used successfully and indicate that there is considerably more uncertainty in oil and gas development projects than has been previously recognized. However, many operators do not use stochastic methods for modeling oil prices, most likely because they require more time and effort to implement than conventional methods. The Inverted Hockey Stick method presented herein is similar to conventional methods in that only three price realizations are run to quantify uncertainty. However, the high and low cases are designed to better capture the range of possible future price paths. Uncertainty ranges for economic indicators predicted by the new method are comparable to 70–95% probability ranges predicted by the stochastic bootstrap method, significantly greater than the 32–42% ranges predicted by conventional methods. This new method can be easily incorporated into existing economic modeling systems. Recognition of the greater uncertainty in oil and gas investment opportunities, both upside as well as downside, should improve investment decision making.