Shell International Exploration Research Articles

Impact of glacial-lake paleofloods on valley development since glacial termination II: A conundrum of hydrology and scale for the lowstand Brahmaputra-Jamuna paleovalley system

Research Article| August 08, 2018 Impact of glacial-lake paleofloods on valley development since glacial termination II: A conundrum of hydrology and scale for the lowstand Brahmaputra-Jamuna paleovalley system J.L. Pickering; J.L. Pickering † 1Department of Earth and Environmental Science, Vanderbilt University, Nashville, Tennessee 37235, USA †Present address: Shell International Exploration and Production, Inc., Houston, Texas 77082, USA; jennifer.pickering@shell.com. Search for other works by this author on: GSW Google Scholar M.S. Diamond; M.S. Diamond 1Department of Earth and Environmental Science, Vanderbilt University, Nashville, Tennessee 37235, USA Search for other works by this author on: GSW Google Scholar S.L. Goodbred; S.L. Goodbred 1Department of Earth and Environmental Science, Vanderbilt University, Nashville, Tennessee 37235, USA Search for other works by this author on: GSW Google Scholar C. Grall; C. Grall 2Lamont-Doherty Earth Observatory, Columbia University, Palisades, New York 10964, USA Search for other works by this author on: GSW Google Scholar J.M. Martin; J.M. Martin 3Shell International Exploration and Production, Inc., Houston, Texas 77082, USA Search for other works by this author on: GSW Google Scholar L. Palamenghi; L. Palamenghi 4Faculty of Geosciences, University of Bremen, Bremen 28359, Germany Search for other works by this author on: GSW Google Scholar C. Paola; C. Paola 5Department of Earth Sciences and St. Anthony Falls Laboratory, University of Minnesota, Minneapolis, Minnesota 55455, USA Search for other works by this author on: GSW Google Scholar T. Schwenk; T. Schwenk 4Faculty of Geosciences, University of Bremen, Bremen 28359, Germany Search for other works by this author on: GSW Google Scholar R.S. Sincavage; R.S. Sincavage 1Department of Earth and Environmental Science, Vanderbilt University, Nashville, Tennessee 37235, USA Search for other works by this author on: GSW Google Scholar V. Spieß V. Spieß 4Faculty of Geosciences, University of Bremen, Bremen 28359, Germany Search for other works by this author on: GSW Google Scholar GSA Bulletin (2019) 131 (1-2): 58–70. https://doi.org/10.1130/B31941.1 Article history received: 08 Oct 2017 rev-recd: 02 Mar 2018 accepted: 15 Jun 2018 first online: 08 Aug 2018 Cite View This Citation Add to Citation Manager Share Icon Share Facebook Twitter LinkedIn Email Tools Icon Tools Get Permissions Search Site Citation J.L. Pickering, M.S. Diamond, S.L. Goodbred, C. Grall, J.M. Martin, L. Palamenghi, C. Paola, T. Schwenk, R.S. Sincavage, V. Spieß; Impact of glacial-lake paleofloods on valley development since glacial termination II: A conundrum of hydrology and scale for the lowstand Brahmaputra-Jamuna paleovalley system. GSA Bulletin 2018;; 131 (1-2): 58–70. doi: https://doi.org/10.1130/B31941.1 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search nav search search input Search input auto suggest search filter All ContentBy SocietyGSA Bulletin Search Advanced Search Abstract To better define the base of the Brahmaputra River paleovalley, we analyzed an extensive borehole data set from the subaerial Bengal delta and a 255-km-long multichannel seismic survey along the modern river. The data reveal that the paleovalley floor is defined by a gravel unit containing boulder-sized clasts up to 30 cm in diameter, deposited after ca. 30 ka but before ca. 9 ka. Paleohydrology during that time and the previous glacial maximum was characterized by a weak monsoon and reduced river discharge, both of which are inconsistent with large valley formation. However, our work indicates that glacial-lake outburst floods sourced from the Tibetan reaches of the Brahmaputra were routed through the lowstand valley, producing megaflood-scale discharge capable of transporting gravel and cannibalizing the valley margins. The timing of these glacial-lake outburst flood–driven discharge events was coincident with valley development and explains the anomalously large width of the valley and basal gravel surface. Despite the underfit scale of Brahmaputra discharge following the last glacial period, a strengthening monsoon and high sediment discharge in the early Holocene subsequently contributed to the efficient infilling of the massive paleovalley by the mid-Holocene. In a sequence stratigraphic context, this work provides an example of a major unconformity that developed late in the eustatic cycle (i.e., during early transgression rather than an earlier, protracted response to sea-level lowering) and in response to a perturbation originating in the catchment instead of changing accommodation in the basin. As such, it represents a geologically instantaneous time surface that can be used as a marker for stratigraphic correlation but one that is not in phase with eustatic sea-level fall. You do not currently have access to this article.

Technology Focus: Cementing/Zonal Isolation (May 2018)

Technology Focus Zonal isolation achieved with cement remains fundamental to well integrity for the full well life cycle. As I read through the abstracts and papers that have been presented in the past year, I notice several key themes: verification of cement placement, development of new materials as a barrier, development of new additives to improve the cement barrier, and enhancement of existing techniques. The fact that we are still studying and improving the cement barrier underscores how important it is as wells are pushed to new limits. Cement-job-performance indicators are critical. From our surface observations, surface sensors, and equipment performance, we can anticipate where zonal isolation is expected. With a robust cementing process embedded in the drilling process, we can be confident in the placement of the barrier. Paper SPE 188295 includes a very complete case history. Many efforts have been made relating to measurement of the outcome of cement jobs. New, more-powerful logging tools; better algorithms; and novel explanations are explored for each scenario that we can imagine. Paper SPE 188274 includes an excellent summary of today’s state of the art. Our industry continues to challenge drillers to push to new limits, which requires cementing technology to reach those same limits so that annular isolation can be achieved in every well that is drilled. Extended-reach wells are reaching new lateral-reach records. Managed-pressure drilling is a technique that is spreading, which logically leads to the need for managed-pressure cementing (MPC). Paper OTC 28139 includes a case history of MPC in deep water. Zonal isolation continues to be enhanced. The recommended additional reading provides an insight into a few of these enhancements, including abandonment practices, reverse cementing, and nanotechnology. Recommended additional reading at OnePetro: www.onepetro.org. SPE 185938 Perforate, Wash, and Cement (PWC) Verification Process and an Industry Standard for Barrier-Acceptance Criteria by Laurent Delabroy, Aker BP, et al. OTC 27864 Development and Validation of a Hydraulics Simulator for Estimating Subsurface Reverse-Cementing Placement Pressures by C. Wreden, Weatherford International, et al. OTC 27893 Development of Nanotechnology Pipe Treatment To Improve Acoustic Cement Evaluation by James Heathman, Shell International Exploration and Production, et al.

Technology Focus: Deepwater Projects (May 2018)

Technology Focus Oil and gas companies are set to enter 2018 in their best shape since oil prices collapsed. It is a common belief that many operators will now focus on demonstrating that they can thrive at low prices. The outlook for the deep- and ultradeepwater market is positive, with a forecast capital growth rate of approximately 8% between 2014 and 2018. From an operator perspective, the upcoming 5 years are expected to see Petrobras’ dominant market share decrease as a result of the increase in activity by independent operators such as Anadarko and Noble. Now that the belt-tightening is done, companies are looking to deliver profitable growth and build for the future. We also expect to see signs that the investment cycle is starting to turn and the sector has reset itself to operate at lower commodity prices. By resetting their cost base (with big advances in 2016), the majors/national oil companies greatly expanded their opportunity set in a lower-for-longer scenario. Deepwater breakevens are frequently being pegged below $50/bbl now. Total expects to bring “a number” of projects to final investment decision over the next 18 months. Meanwhile, Shell said it has a decade of inventory in the sub-$40/bbl range, and in some cases sub-$30 range, in deep water. Shell also sees break-evens in Brazil well below $40/bbl across the board. Shell Chief Executive Officer Ben van Beurden said he is ready to grow in deep water now, not at some point in the future. “We need both characteristics in our portfolio,” he said. “What we like about the deepwater business is indeed the very high free-cash-flow generative nature of it, once you pass the investment hump, which gives a lot of resilience, of course, for the portfolio when it is stable … . [Compared with shale] they complement each other, and that’s why we want to have roughly comparable strength—I wouldn’t say equal strength—in both of them.” Companies will need to find the right formula to win back investors after a year of poor stock market performance in 2017. Demonstrating that free cash flow can grow in a low-price environment and fund higher shareholder distributions will be a core focus. Companies must also build a compelling case for long-term investment. This may not happen in 1 year, but they will need to show clear progress in 2018. Recommended additional reading at OnePetro: www.onepetro.org. OTC 27850 Stones Development: Best-in-Class Risk Reduction and Cost Improvement During Project Execution by Maria Pena, Shell Exploration and Production, et al. OTC 27947 Driving for Competitive and Affordable Projects in the Gulf of Mexico by David De Pledge, Shell International Exploration and Production, et al. SPE 180350 Integrated Drilling Strategy Leads to Successful Execution of the First Highly Deviated Deepwater Well in Mexico by I. Przhegalinsky, Schlumberger, et al.

Turritella FPSO - Design and Fabrication of the World’s Deepest Producing Unit

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 27663, “Stones Development: Turritella FPSO—Design and Fabrication of the World’s Deepest Producing Unit,” by Blake Moore, Andrew Easton, Jonathan Cabrera, and Carl Webb, Shell International Exploration and Production, and Babu George, SBM Offshore, prepared for the 2017 Offshore Technology Conference, Houston, 1–4 May. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission. The Stones Project is in the emerging Lower Tertiary trend in the Gulf of Mexico ultradeep water. A floating production, storage, and offloading (FPSO) unit was selected for the floating production system to address the stepwise development of the Stones Field. The Turritella FPSO (Fig. 1) is the deepest floating production system in the world and presented many challenges to successful execution of the surface host facilities. Overview The Stones development is along the Walker Ridge protraction area in the deepwater Gulf of Mexico, in water depths ranging from 7,500 to 9,500 ft. The field was developed using a disconnectable FPSO tied to a subsea development. Nominal production capacities will be 60,000 B/D of fluids, 30,000 B/D of produced water, and 15 MMscf/D of associated gas. The FPSO design was based on the conversion of an existing Suezmax-scale, double-hull tanker. Design Key design decisions during front-end engineering and design (FEED) and pre-FEED in 2012 and 2011 established many of the key design criteria that guided the design of the FPSO. Riser selection—lazy-wave riser to buoy vs. free-standing risers: An early study identified lazy-wave risers as preferable over free-standing risers because of technical concerns related to flexible pressure ratings and commercial considerations. Disconnectable buoy: Early engagement with regulatory entities (e.g., the Bureau of Safety and Environmental Enforcement) determined that a disconnectable turret to allow the FPSO to escape a hurricane would be required to achieve regulatory approvals. Hull size—Aframax vs. Suezmax: Shell/regulatory requirements for a double hull and the applicable environmental-impact statement for FPSOs in the Gulf of Mexico limiting FPSO storage capacity to less than 1 million bbl led to the limitation of potential hulls. Deck space to accommodate planned topside facilities and turret led to the selection of a Suezmax. FPSO throughput: Technical limitations on riser sizes at the water depth for Stones established maximum throughput. The system choke point was in the risers, and the capacity of the topside matched the riser throughput limit.

Technology Focus: Well Testing (February 2018)

Technology Focus Well testing and surveillance have always been, and continue to be, the foundations of reservoir management. Fundamental data, such as pressure, rate, and temperature, and fluid samples are collected during a well test and used to investigate the subsurface. With advancements in modern technology such as smart wells, distributed pressure/temperature, real-time measurements, and extended-reach drilling, we are facing conditions with increasing complexity and unprecedented amounts of data. In 2017, several key partnership announcements with major information-technology companies were noticed. The oil and gas industry is going through a digital transformation reinforced by data science; terms such as data cloud/lake, machine learning, Internet of Things, high-performance computing, automation, and model management are the new buzzwords. When analytics are applied correctly, they will provide valuable insights, especially in cases such as unconventional reservoirs with significant numbers of wells. In order to make the transformation a success, many of the industry’s leading experts agree that quality as well as quantity of data should be important. Experience teaches us that the subsurface is always more complex than we expect, feedback is not instantaneous, and issues are difficult to mitigate in the reservoir scale. Hence, essential and information-rich data such as exploration/production-well tests, proper fluid samples, and sufficient/periodic surveillance should still be used effectively as indicators to peel off layers of uncertainty in the complex subsurface. Thus, we conclude that reservoir-engineering fundamentals must still be applied and data should still be quality checked, especially when collecting and applying analytics from a massive amount of information. The age-old “garbage in, garbage out” mantra will continue to apply in the upcoming era of data science. The papers selected for this issue cover advances and opportunities in well testing. They also apply reservoir fundamentals as well as sound engineering judgment, using quantity but also quality data sets from conventional and unconventional assets. Recommended additional reading at OnePetro: www.onepetro.org. IPTC 18924 Current State and Future Trends of Wireline-Formation-Testing Downhole Fluid Analysis for Improved Reservoir-Fluid Evaluation by S.R. Ramaswami, Shell International Exploration and Production, et al. SPE 187348 New Variable Compliance Method for Estimating In-Situ Stress and Leakoff From DFIT Data by HanYi Wang, The University of Texas at Austin, et al. SPE 185795 Step-Rate Test as a Way To Understand Well Performance in Fractured Carbonates by A. Shchipanov, IRIS, et al.

How To Develop a Well-Specific Capping-Stack Blowout Contingency Plan

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 181393, “How To Develop a Well-Specific Blowout Contingency Plan That Covers Engineering Analysis of the Deployment, Installation, and Soft Shut-In of a Subsea Capping Operation,” by Ray T. Oskarsen, SPE, Morten H. Emilsen, SPE, and Amir S. Paknejad, Add Energy; Mike Cargol, Trendsetter Engineering; and Kwee Choong See, SPE, Shell International Exploration and Production, prepared for the 2016 SPE Annual Technical Conference and Exhibition, Dubai, 26–28 September. The paper has not been peer reviewed. The planning process for developing a well-specific subsea-capping contingency plan involves assessing the feasibility of deploying a capping stack from a floating vessel, determining the weight and stability of the capping stack to overcome the force of the blowout jet, and performing dynamic-flow simulations of closing the capping stack outlets without loss of well integrity. This process not only assesses the feasibility, complexity, and risk exposure of the capping operation but also may justify further planning, studies, or expenditure. Introduction Blowout-kill techniques can be classified as either surface-intervention or relief-well methods. Relief wells aim to kill a blowout from the bottom by injecting fluid into the wellbore until the influx of formation fluid is stopped and the well is static when pumping stops. In many cases, a relief well will be the safest intervention and have the highest likelihood of success, and often it is considered the last line of defense against a blowout. Surface interventions are kill attempts aimed at controlling the discharge at the wellhead or at the fluid-exit point. An example is to install a capping stack on top of the wellhead and close its openings, which can be gate valves, chokes, or rams. Blowout Contingency Planning. Blow-out contingency plans ensure that people understand and can manage risks, thus ensuring safe and sustainable operations at all times. All blowouts are inherently different; thus, it would be both impractical and impossible to attempt to cover every possible blowout scenario in a contingency plan. For source-control planning, an operator should, at a minimum, address a worst credible scenario to demonstrate how the well will be brought under control. This scenario may be different from the worst-case discharge, which is used to estimate spill potential and necessary resources for containment and cleanup. As an example, if there is uncertainty about the gas/oil ratio (GOR), a low-case GOR may cause more oil spill, while a high-case GOR may make source control more challenging.

Energetics Applications for the Oil and Gas Industry

Energetics Applications for the Oil and Gas Industry

Integrating PCA and Streamline Information for History Matching Channelized Reservoirs

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 170636, “Integration of Principal-Component Analysis and Streamline Information for the History Matching of Channelized Reservoirs,” by C. Chen, SPE, Shell International Exploration and Production; G. Gao, SPE, Shell Global Solutions US; J. Honorio, Massachusetts Institute of Technology; P. Gelderblom, SPE, Shell Global Solutions International; E. Jimenez, Qatar Shell GTL; and T. Jaakkola, Massachusetts Institute of Technology, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed. Although principal-component analysis (PCA) has been applied widely to reduce the number of parameters characterizing a reservoir, its disadvantages are well-recognized. A work flow was proposed to integrate cumulative-distribution-function-based PCA (CDF-PCA) and streamline information for assisted history matching on a two-facies channelized reservoir. The CDF-PCA was developed to reconstruct reservoir models by use of only a few hundred principal components. It inherits the advantage of PCA to capture the main features or trends of spatial correlations among properties, and, more importantly, it can properly correct the smoothing effect of PCA. Introduction Both object-based and multipointstatistics-based models generate relatively more geologically realistic channel bodies compared with conventional two-point geostatistics-based techniques. However, conditioning such models to production data and correctly sampling the posterior probability distribution are challenging problems. One of the major challenges is that the number of para meters to be tuned during history matching is too large to be handled effectively by available history- matching work flows, especially when the adjoint gradient is unavailable. Another challenge is that the models obtained after history matching generally violate or distort the geological and geostatistical characteristics of the original or prior models. One of the authors’ major objectives was to reconstruct channelized geological and reservoir models with much fewer uncertain parameters so that the models can be conditioned to production data through automatic/assisted history matching with use of model-based derivative-free optimization algorithms. The geological and reservoir models obtained by history matching have to capture major flow dynamics and are also constrained by the histogram of lithology distribution and the correlations between reservoir properties of the original model. The following four important questions must be addressed when regenerating geological realizations using new parameters: Are new parameters able to regenerate both static models and dynamic models? Are the models regenerated by new parameters still geologically realistic and relevant? In other words, do the new geological and reservoir models satisfy geologists’ requirements? Are the realizations generated from sampling the probability distribution of these new uncertain parameters equivalent to (but not biased from) the realizations generated from sampling the prior probability distribution? Is it feasible to history match production data by tuning these new parameters?

From Source Rock to Reservoir: The Evolution of Self-Sourced Unconventional Resource Plays

Research Article| August 01, 2014 From Source Rock to Reservoir: The Evolution of Self-Sourced Unconventional Resource Plays L. Taras Bryndzia; L. Taras Bryndzia *Rock Properties Characterization and Modeling Team, Shell International Exploration & Production Inc.Houston, TX 77251-7171, USAE-mail: Taras.Bryndzia@shell.com Search for other works by this author on: GSW Google Scholar Neil R. Braunsdorf Neil R. Braunsdorf *Rock Properties Characterization and Modeling Team, Shell International Exploration & Production Inc.Houston, TX 77251-7171, USAE-mail: Taras.Bryndzia@shell.com Search for other works by this author on: GSW Google Scholar Elements (2014) 10 (4): 271–276. https://doi.org/10.2113/gselements.10.4.271 Article history first online: 09 Mar 2017 Cite View This Citation Add to Citation Manager Share Icon Share Facebook Twitter LinkedIn MailTo Tools Icon Tools Get Permissions Search Site Citation L. Taras Bryndzia, Neil R. Braunsdorf; From Source Rock to Reservoir: The Evolution of Self-Sourced Unconventional Resource Plays. Elements 2014;; 10 (4): 271–276. doi: https://doi.org/10.2113/gselements.10.4.271 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentBy SocietyElements Search Advanced Search Abstract From a geological perspective, the exploration of shale source rocks is relatively straightforward. Advances in stimulation technologies, such as hydraulic fracturing, have made it possible to economically extract hydrocarbons, both liquid and gas, from their respective source rocks. However, the devil is in the details when it comes to “sweet spotting” which shale reservoirs are going to be the best producers. Organic-rich shales are fine grained and tend to be petrophysically challenging and mineralogically and geochemically heterogeneous on the nanoscale. The advent of focused ion beam – scanning electron microscopic (FIB-SEM) techniques now allows us to image the pore networks in the organic matter that generated the hydrocarbons we produce. Two types of pore networks exist in organic-rich shales. One type is water wetting and is associated with the inorganic component of the shale, mostly clays. The other pore network is hydrocarbon wetting and is associated with the porosity that develops in organic matter during maturation and hydrocarbon generation. You do not have access to this content, please speak to your institutional administrator if you feel you should have access.

Challenges of Tight and Shale-Gas Production in China

This article, written by Dennis Denney, contains highlights of paper IPTC 17096, ’Production-Technology Challenges of Tight and Shale-Gas Production in China,’ by Hon Chung Lau, SPE, Shell (China) Projects and Technology, and Meng Yu, SPE, Shell International Exploration and Production, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. Natural-gas production from tight and shale-gas reservoirs will be increasingly important in China as the country shifts from coal-based energy to cleaner energy sources. Recent Chinese sources have estimated that the gas-in-place resources from tight and shale-gas reservoirs in China are at least 12×1012 m3 and 31×1012 m3, respectively. In 2008, annual production from tight gas reservoirs reached 20×109 m3, approximately 23% of the natural-gas production in China. Commercial production from shale-gas reservoirs has not begun but is expected to grow rapidly. Introduction Since 2010, the consumption of natural gas in China has far exceeded domestic production. To bridge this gap, domestic production of natural gas, especially from unconventional resources [e.g., coalbed methane (CBM) and tight and shale-gas reservoirs], must be increased significantly. From a review of published literature and their own observations, the authors identified several relevant production technologies that could have a significant effect on tight and shale-gas production in China. Unconventional Gas Resources The US Energy Information Administration estimated that China had 0.289×1012 m3of proved CBM reserves in 2011, although other recent estimates of recoverable reserves are 9.9×1012 m3. Fig. 1 shows most of China’s gas-producing basins. CBM resources are in the north and northeast, the Sichuan basin in the southwest, and the Junggar and Tarim basins in the west. In China, tight gas resources total approximately 12×1012 m3. The Sichuan basin is one of the largest tight gas basins in China and is reported to have approximately 1.8×1012 to 2.25×1012 m3of natural gas. The Sulige gas field in the Ordos basin is the largest tight gas field in China. Most of China’s proved shale-gas resources are in the Sichuan, Tarim, and Ordos basins. Estimates of China’s total tight and shale-gas resources range from 36×1012 to 100×1012 m3. Although there was no commercial shale-gas production as of 2012, the Chinese Ministry of Land Resources has set aggressive targets of 6.5×109 m3/a by 2015 and at least 59.5×109 m3/a by 2020. Management of Hydrogen Sulfide (H2S) Risks Most of China’s sour-natural-gas fields are in the northeastern and western parts of the Sichuan basin (mostly conventional gas fields). An evaluation of shale-gas potential in the Weiyuan area showed significant shale-gas reserves. Therefore, it is important to determine the likelihood of penetrating sour reservoirs and to manage H2S risks. In general, a rigorous H2S safety-management plan will be needed if tight or shale-gas development will require drilling through or near zones containing H2S.

Perdido Development Project - Spar and Moorings

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 20885, ’Perdido Development Project - Spar and Moorings,’ by Curtis Lohr and Keith Smith, Shell International Exploration and Production, prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed. A spar platform was selected for the Perdido development during system selection in 2005 to provide a stable platform for direct vertical-access drilling and producing operations in nearly 8,000 ft of water. A combination polyester/chain mooring system was selected to place less vertical load on the floating structure (compared to an all-steel mooring system). Introduction The Perdido spar was Shell’s first spar-host production platform, but had the benefits of being developed as a joint venture with Chevron and BP. Technip was selected as the spar and mooring contractor. The spar comprises a cylindrical upper section (hard tank); a trussed midsection (truss) formed from tubular legs and braces with horizontal stiffened-plate flats, or heave plates; and a bottom section (soft tank) used to carry solid ballast and provide flotation during installation. Some key characteristics of the Perdido spar are listed below: Overall length—555 ft, draft 505 ft Hard tank—118-ft outside diameter (OD)×264-ft length, with 214-ft hard-tank draft Hull weight—approximately 20,000 tons including structural steel, appurtenances, and hull systems Nine mooring lines Two heave plates Three strakes A 46×46-ft moonpool Six riser slots Four-leg topside and truss Octagonal soft tank Six hydraulic tensioners supporting five production risers and one drilling/completion riser The spar was designed to accept a single-lift topside by limiting the spar’s OD to 118 ft and by placing storage tanks for diesel fuel, methanol, dead oil, low-dosage hydrate inhibitor, and drill water inside the upper compartment of the spar rather than on the topside. The spar was fabricated in Finland. Fabrication began in November 2006, dry transport to the Gulf of Mexico began in May 2008, and the wet tow offshore occurred in August 2008. One challenge that was unique to the spar fabrication was installation of components for the hydraulic riser-tensioning system in the main hull-fabrication yard. Tolerance for this system was extremely tight, and installation requirements were discussed well in advance to plan the work. Jigs to ensure that the installation of components was within tolerance were designed, fabricated, and used. Mooring System The Perdido mooring system uses nine polyester/chain lines averaging more than 2 miles in length, with the vast majority of each line’s length being polyester. The nine taut lines are oriented in a 3×3 pattern and consist of 9.68-in. polyester-rope main sections and short lengths of 5.28-in. chain at each end. The spar has an “active” mooring system to reposition it over drilling locations within an approximately 350-ft-diameter area. Because polyester is more difficult to handle in a winch, the top of each mooring line consists of a short length of chain, called the platform chain, which is connected to the spar. The platform chain runs through a below-water fairlead mounted on the outside shell of the spar. A dedicated chain jack controls each platform chain.

Shell accelerates Honorary Lecturer program

Shell International Exploration and Production B.V. recently announced a US$1.25 million commitment to fully fund the new SEG Honorary Lecturer program for five years, starting in 2009. This is the single largest corporate investment in the recent SEG Foundation campaignAdvancing Geophysics Today, Inspiring Geoscientists for Tomorrow. This leadership investment will enable SEG to offer six Honorary Lecturers each year to its professional and student constituencies around the world.

A new generation inflow performance modelling tool with improved capabilities

The inflow performance prediction of a completion is one of the most important tasks in forecasting production performance of a well. When selecting an optimum completion design it is essential to compare different options and perform parametric studies, one of the key completion decisions being the selection of a cased and perforated or barefoot well. In cased and perforated wells, key inflow performance parameters include gun type, perforation penetration depth, shot density, shot phasing, depth of mud invasion and dependence of their effects on reservoir properties. The open literature hosts a plethora of inflow equations for some classic completion practices; however, complex options are not adequately addressed. More importantly, when one compares inflow performance of various completion options or conducts a parametric study of certain parameters, the relative calculation results do not always make sense. In this paper, we describe an operator’s (Shell International Exploration and Production) in-house study to develop a consistent set of inflow performance equations that not only make sense in their own right, but also make good relative sense when comparing different completion options, particularly with regard to cased and perforated wells. Most of the significant open literature has been reviewed and a set of consistent inflow models have been compiled and developed. Many equations have been improved—e.g., perforation skin calculations, mechanical and total skin calculations, rate dependant skin for horizontal completions—and new equations have been derived for options not previously modelled in the literature (e.g., barefoot and perforated completions, double perforated completions, re-perforated completions and complex horizontal completions). All equations have been coded into the Shell Perforation Optimisation Tool (SPOTTM) software package, enabling engineers to easily and accurately predict and compare complex completion options for design decisions. Inflow performance calculation results of various completion scenarios and parametric studies are also presented.

Putting Blended Learning to Work: a case study from a multinational oil company

Blended learning can be operationalised in many different ways. At Shell International Exploration and Production, a form of blended learning focusing on learning while in the workplace through work-based activities within technology-supported courses has been evolving since 2000, with approximately 100 different learning events reflecting this form in 2004. After a review of the general approach to blended learning ('putting learning to work') that steers blended learning at Shell EP and the rationale for work-based activities that serve as the tools for 'putting learning to work' within these courses, a case study of the course 'Production System Optimisation', including a variety of types of evaluation data, is described. With this case as a point of reference, some reflections on the implications of work-based activities as a key tool for blended learning conclude the article.

Applying activity theory to computer-supported collaborative learning and work-based activities in corporate settings

Business needs in many corporations call for learning outcomes that involve problem solutions, and creating and sharing new knowledge within worksplace situation that may involve collaboration among members of a team. We argue that work-based activities (WBA) and computer-supported collaborative learning (CSCL) are appropriate components for courses in such learning situations. Via this approach, collaborative work situations become the core of a course. We further describe how activity theory can provide a framework for the design of courses that involve WBA and CSCL as part of a workplace-oriented activity system for learning. The use of this design approach for courses offered by the Learning and Leadership Development organization of Shell International Exploration and Production is described and an example is elaborated. Finally, we identify four main issues and challenges that arose during the use of the design approach.

WPI metal membrane research could fuel future H 2 economy

One of the challenges to creating an infrastructure for a fuel cell-based economy is refining a pure source of hydrogen to power vehicles. A chemical engineering professor at Worcester Polytechnic Institute (WPI) in Massachusetts believes the best way to do this is by using membranes made from palladium. With more than $1.5m in grant funding from Shell International Exploration & Production Inc, Yi Hua Ma is engaged in a three-year research study in this area through June 2004 to prove his assertion. This is a short news story only. Visit www.re-focus.net for the latest renewable energy industry news.

An aeroacoustically driven thermoacoustic heat pump

The mean flow of gas in a pipe past a side branch, closed at the far end, can excite the resonant acoustic modes of the cavity much like blowing across the top of a bottle. This aeroacoustic whistle can excite very high amplitude acoustic waves within the side branch (easily 10% of the mean pressure) at optimal gas flow rates and mean pressures within the main pipe. The aeroacoustic whistle uses no moving parts to convert part of the power in the mean flow into acoustic power. Likewise a thermoacoustic heat pump, utilizing this acoustic power, uses no moving parts to pump heat and establish (or maintain) a temperature difference across a porous medium. This new combination of an aeroacoustic sound source and thermoacoustic heat pump (with suitable thermoelectric elements) is part of an electric power generation feasibility study for natural gas wells. Reliable electrical power generation down-hole to provide electricity for sensors, communications devices or energy storage units is an important research and development goal. Experimental results will be presented that demonstrate the performance of a simple thermoacoustic heat pump when powered by an aeroacoustic sound source. [Work supported by Shell International Exploration and Production B.V.]

Systematic acoustic loading of an aeroacoustic whistle

Strong self-sustained acoustic oscillations may occur in a gas pipe network under certain gas flow velocities within the network. The pipe network under consideration consists of a main pipe, with a variable mean airflow, with two closed coaxial side branches of variable but equal length joined to the main pipe at right angles. Coupling between resonant acoustic standing waves and instabilities of the shear layers separating the flow in the main pipe from the stagnant gas in the closed side branches leads to strong acoustic oscillations (easily 10% of the mean pressure) at a frequency corresponding to the half-wavelength acoustic mode defined by the total side-branch length. The acoustic power available in the resonant mode has been measured to compare with theoretical predictions and previous two-microphone measurement techniques as well as to inspire confidence when designing an aeroacoustically driven thermoacoustic heat pump. The acoustic load consists of a variable acoustic resistance and coupled acoustic compliant volume, which is similar to devices used to measure power in thermoacoustic engines. Data will be presented which characterize the performance of the aeroacoustic sound source under variable acoustic loading. [Work supported by Shell International Exploration and Production B.V.]

How Shell refined its ASSET MANAGEMENT

Shell International Exploration and Production companies have developed an innovative new measurement approach based on asset management. By viewing all activities through an asset holder's eye, what began as an exercise to contain operating costs has enabled Shell to break the company into manageable inter‐related components.