A numerical modeling procedure was developed, using the finite-elementsimulator ABAQUS/Standard, to predict the local buckling and post-bucklingresponse of high strength pipelines subject to combined state of loading. Thenumerical procedures were validated using test data from large-scaleexperiments examining the pure bending and local buckling of high strengthlinepipe. The numerical simulations were consistent with the measuredexperimental response for predicting the peak moment, strain capacity,deformation mechanism and local buckling response well into the post-yieldrange.
A parametric study on the local buckling response of high strength plainpipelines was conducted. The influence of pipe diameter to wall thickness ratio(D/t of 40, 60 and 80), pipe segment length to diameter ratio (L/D of 3.5, 5, 7and 12), yield strength to tensile strength ratio (Y/T of 0.7, 0.8 and 0.9) andinitial geometric imperfections on the local buckling response was examined.The loading conditions included internal pressure and end rotation. Mechanicalresponse parameters examined included moment-curvature, ovalization, localstrain and modal response.
Marshall, P.W. (Department of Civil and Environmental Engineering, National University of Singapore) | Sohel, K.M.A. (Department of Civil and Environmental Engineering, National University of Singapore) | Liew, J.Y. Richard (Department of Civil and Environmental Engineering, National University of Singapore) | Jiabao, Yan (Department of Civil and Environmental Engineering, National University of Singapore) | Palmer, A. (Department of Civil and Environmental Engineering, National University of Singapore) | Choo, Y.S. (Department of Civil and Environmental Engineering, National University of Singapore)
There is a wide range of offshore structures which may be constructed byeither steel or concrete materials to be used in the arctic region, such assteel tower platforms, caisson-retained islands, shallow-water gravity-basecaisson, jack-up structures, bottom-founded deep-water structures, floatingstructures, well protectors, seafloor templates and breakwaters. One commonfeature of these structures is that they must be able to resist the highlateral forces from the floating ice and transmit these forces to thefoundation. This study explores the use of Steel-Concrete-Steel (SCS) curvedsandwich system for arctic caisson structures. SCS sandwich system, whichcombines the beneficial effects of steel and concrete materials, has promisingbenefits over conventional plates and stiffeners design and heavily reinforcedconcrete design because of their high strength-to-steel weight ratio and highresistance to contact and impact loads. Shear connectors have been proposed toprovide bonding between the external steel plates and high-performancecementitious core materials. Finite element analyses and large-scale testresults showed that SCS sandwich panels without mechanical bond enhancement arevulnerable to interfacial shear failure and impairment of structural integritywhen subject to shrinkage and thermal strains, accidental loads, and impact.The proposed SCS sandwich system features mass-produced mechanical shearenhancement and/or cross-ties. It can reduce structure complexity, particularlyin the number of weld joints which are prone to fatigue, hence increasingservice life, cutting down the cost of fabrication, and reducing the manpowercost to operate, inspect, and maintain the structure in the long run.Considering local ice load, the punching shear and shell bending strength ofthe SCS sandwich composite shell is studied experimentally. Test results showedthat the SCS sandwich panels, which are designed using the ISO ice load, arecapable of resisting the localized contact and punching loads causedthereby.
In recent years there has been substantial interest and growing demand forLNG Carriers to operate in cold regions. As a result there is a pressing needfor rules and standards to give clear requirements for shipbuilders to developsuitable designs for cold climate operations. In parallel to the systems andfeatures fitted for the safety of the LNG Carriers, is the preparedness andsupport of the crew for the challenges of operating in these harsh,cold-climate regions. Sources of hazard can include accidental immersion incold water, freezing and non-freezing cold injuries, unusual day or nightlengths, and weather conditions affecting visibility and the sea state. Thispaper provides an insight into the background and development of winterisationrules and an explanation of some of the key features fitted to existingwinterised LNG Carriers, whilst outlining many of the physical and cognitiverisks to seafarers in conditions of extreme cold, including their personalsafety and their ability to control the vessel and its systems. It introducessome of the systems redundancy features to mitigate the risks due to remotenessand methods for managing the resulting risks. These, include proceduraladaptations to manage exposure times and the operability of the ship, anddesign adaptations to reduce or remove hazards to the people on board and theways in which they can work.
Winterisation; Low temperatures; Icing; Classification Rules; LNG Carriers,Human Performance; Cold Climate Operations.
The extreme conditions and harsh environment for which FPSO's andhydrocarbon gathering facilities are being considered introduces distinctchallenges to effective and efficient project management and execution. The presentation is based on the experiences gathered during the design phasesof two contemporary harsh environment FPSO's and the associated subsea,flowline, pipeline and riser systems (Chevron Rosebank and GAZPROMShtokman). This presentation will focus on the adjustments that must beconsidered to "standard" project execution and management in order toincorporate the elemental distinctions without sacrificing efficiency, logicalsequencing, safety or project schedule. Specifically, the presentationwill focus on the following:
The paper is intended to inform the audience as to the distinctivecharacteristics of harsh environment design management contrasted with the morefamiliar benign environment design projects.
Reel-laying is a fast and cost-effective method to install offshore pipelines. During reel-laying, repeated plastic strain is introduced into the pipeline which may, in combination with ageing, affect strength and ductility of the pipe material. The effect of reel-laying on the pipe material is achieved by small- or full-scale reeling simulations followed by mechanical testing according to corresponding standards. In this report an appropriate test setup for full-scale reeling simulation is presented. The fitness-for-use of the test rig is demonstrated by finite element calculations as well as by full-scale reeling simulations on different pipes of various grades. Plus, small-scale reeling simulations with subsequent ageing and mechanical testing are performed on the same pipe material. A comparison of results from mechanical tests after small- and full-scale reeling simulations is given. Additionally results from collapse tests on pipes after full-scale reeling simulations are presented, and the influence of repeated bending of the pipe on its collapse behavior is discussed.
Two main concepts are normally used for laying offshore subsea pipelines. In the S- and J-lay method a pipeline is fabricated on the deck of a lay barge by welding individual lengths of pipe as the pipe is paid out from the barge. The pay-out operation must be interrupted periodically to permit new lengths of pipe to be welded to the string. The S- and J-lay method requires skilled welders and their relatively bulky equipment to accompany the pipe-laying barge crew during the entire laying operation; welding must be carried out on board and often under adverse weather conditions. Further, the S- and J-lay method is relatively slow, with even experienced crews laying only few miles of pipe a day. This can subject the entire operation to weather which can cause substantial delays and make working conditions quite harsh.
Capitalizing on the UAE's wide experience in the field of land reclamation and artificial island technology, the Abu Dhabi oil and gas industry, represented by ADNOC group of companies, is currently deploying an array of islands across Abu Dhabi's Exclusive Economic Zone in the Arabian Gulf for applications such as new field development and the upgrade or expansion of storage and offloading facilities. With favorable water depths and environmental conditions, land reclamation is often a more economical option for the accommodation of offshore facilities than the construction of fixed steel jacket platforms. ADMA-OPCO is currently engaged in applying the technology to projects such as the Satah Al-Raaz Boot (SARB) field development, a 105,000-bpd development comprising 86 wells on two artificial islands. Simultaneously, ZADCO is making progress on expanding drilling from the Upper Zakum field by constructing four artificial islands (UZAI) to increase field production to 750,000 bpd by 2015. While cost and schedule optimization will be realized with the selection of the artificial island option for these mega projects, designers and contractors are facing the challenge of securing or fabricating building materials in huge amounts for the construction of both the land masses and shore protection structures. Creative solutions to procuring these materials are tabled and investigated. Innovative engineering designs are tried and tested both numerically and using physical model tests. The presence of a soft soil layer within the foundation strata of one of the Upper Zakum islands required special treatment to satisfy island performance criteria. Schedule constraints of construction and fulfilling ADNOC's strategic production objectives continue to be the driving forces behind the resolution of all challenges.
Mapping karsts and other collapse disturbances in overburden is a challenge in a heterogeneous carbonate environment, as they are often poorly expressed features on 3D seismic amplitude data due to their inherent complex shapes, lateral variability and contrasting fill material density. Seismic attribute analysis combined with 3D seismic volume rendering and extraction techniques provide a significant amount of detailed information about karst and other collapse dissolution features in a Giant Carbonate Field Offshore Abu Dhabi, UAE. Traditional horizon-based attribute analysis, tedious and time consuming in these scenarios, can also reveal inadequate information about connectivity and volumetric extent of karsts or other collapse features.
Understanding the distribution of these features and connectivity in a 3D sense is crucial for velocity models, structural modeling of surfaces beneath such bodies and operationally as features to avoid whilst drilling to ensure drill-well integrity. A structural framework incorporating the impact of such features can be achieved by volumetric attribute generation followed by delineation and extraction of such features that are connected in a 3D sense.
This paper describes a workflow to carve out karst features dominant within the shallower Paleocene-Late Cretaceous section of the seismic data. It involves multi-trace volumetric seismic attribute-conditioned amplitude data that facilitates improved recognition of these features, providing detailed outlines of their geomorphology and infill. Advanced 3D volume rendering and applying a ‘geobody' technique helps to discriminate the complex shapes and variability of features from their surrounding rock mass and were used to pick key examples of these features. Using the opacity control, connectivity of the body's outline and connectedness of smaller associated satellite ‘karsts' can be displayed and extracted. Karst infill material, having slower velocity, causes the reflectors to sag in some places. In such instances a velocity seismic cube was used in this case.
A narrative on injection of CO2 for enhanced oil recovery considering the advantages of the integrally geared compressor over the single shaft compressor, and using the Siemens hermetically sealed canned motor-compressor in the process of separating export gas and CO2 for reinjection.
When injecting CO2 for EOR we have investigated the most important market requirements to identify the best solution from the existing portfolio of turbo machinery, when comparing a standard single shaft inline compressor to an integrally geared compressor, and have concluded, based on economics, efficiency, and power consumption, that integrally geared turbo compressors incorporate the optimum design concept for economic CO2 compression.
When re-injecting the produced gas after oil and gas separation there is a mix of saturated CO2 and hydrocarbons and other contaminants possibly containing hydrates, mercury and H2S. Gases and components which are preferably contained in the process equipment without possible leakages to the atmosphere due to seal leakages or malfunction of the compressor units dry gas seals. With the above in mind we developed a sealless (no dry gas seals) compressor which could add strategic benefits and eliminate the need for continuous flaring and venting of the seal gas and barrier gas to the atmosphere. And in conjunction with a fully categorized material selection provide the best solution with high availability and reliability.
Combined with the increased robustness of the overall system with less instrumentation and auxiliary systems and thus less spurious trips and downtime it is obvious that the integrally geared turbo compressor, STC-GV, in combination with the hermetically sealed compressor, STC-ECO, has the potential to considerably contribute to minimizing the environmental foot print, higher reliability and lower OPEX in the Oil & Gas operations especially in the process of mixed flow dirty gas separation found in the CO2 reinjection application.
For more than 60 years, internal plastic coatings have been used for corrosion protection on tubing, casing, line pipe and drill pipe. One of the historic concerns with the use of internal plastic coating is the threat of mechanical damage and subsequent corrosion cell generation. Through the earlier years of usage of internal plastic coatings, applicators relied solely on enhanced surface preparation and adhesion to ensure minimal exposure of the steel substrate if damage were to occur. Even with this minimization, the potential for corrosion was still a concern for some. Due to this, a focus on developing internal coatings that offered higher degrees of abrasion resistance was initiated. At this time, several materials have been developed that offer abrasion resistances up to twenty times greater than what had previously been seen. These abrasion resistant materials allow internal coatings to be used in applications that were previously filled with alloys and GRE liners. These applications include: production/injection wells that rely on frequent mechanical intervention, rod pumping wells, completion string systems and environments containing high amounts of entrained solids. This paper outlines the development of these products including the different chemistries used and their abrasion resistance, impact, laboratory evaluation of their abrasion resistance and initial case histories of applications where internal coatings have historically been excluded.
To satisfy the growing global gas demand more reservoirs with sour contaminants (up to 40% of H2S and significant CO2) will be developed. Worldwide more than 1600 TCF of Sour Gas is anticipated. Shell has more than 60 years of experience in sour gas processing, ranging from the first facilities installed in Jumping Pound, Canada, to recent projects under development in Kazakhstan and Oman. This paper will describe a number of challenges and opportunities associated with development of "sour?? projects.
The fact that H2S is lethal at low concentrations and highly corrosive in the presence of CO2 and/or (salty) water indicates that safety is a main driver in these projects. It is of crucial importance that the H2S is contained and that plant integrity is assured through tightly controlled maintenance programs.
Product specifications for produced gas and hydrocarbon liquids are ever tightening and legislation on emissions are becoming more stringent. Deep removal of H2S and other sulphur components like mercaptans and carbonyl sulphide is required. This increases the complexity and therefore cost of the sour gas processing facilities, which must compete with production from sweet gas in the region/country or alternatives such as LNG import. Technology innovation as well as smart integration of technologies are essential for the cost effective development of sour gas assets ensuring all specifications and emission requirements are met. Several examples of these technology innovations will be presented in this paper.