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De La Fuente J.G.,Repsol | Capelle J.-Y.,Total S.A. | Lemmers S.,Vopak | Bauer H.,Linde Group | And 20 more authors.
International Gas Union World Gas Conference Papers | Year: 2015

With natural gas advancing its position in the world energy mix, exploration activity, which has been historically focused on oil, now embraces gas with the same enthusiasm. Today it is the gas discoveries, which are dominating the headlines. Driven by demand, technological advances and viable economics, LNG is allowing the development of gas discoveries in more and more remote and hostile regions of the globe. As exploration moves into these new frontiers, gas liquefaction projects will similarly be located in increasingly distant and hostile areas. Perhaps considered the most hostile region of all, the Arctic Circle provides some of the most challenging projects for LNG today and looks to be one of the biggest growth areas in the coming 20-30 years of exploration. The purpose of this IGU report is to review the new and challenging remote and hostile regions where LNG projects are being planned and could be located in the future, and discuss the particular challenges that are faced in the whole chain from site selection through design and construction to the operation and LNG export from these plants. Whilst Floating LNG (FLNG) can be considered as another remote concept, it was decided to exclude FLNG from this discussion due to the very specific nature of the concept and extensive discussion in other publications or working groups. The term "remote"generally implies a significant distance from a particular place, and it is fair to say that, by definition, the majority of LNG production projects are in geographically isolated areas, as the driving force behind liquefaction projects has always been the need to monetize and transport isolated gas reserves in an economic way to markets, which can be anywhere in the world. However, this report proposes to include other factors into the term "remote" to give a more complete indication of the challenges that are faced by complex projects in complicated areas of the world. Therefore a Remoteness Index has been developed and presented in this report. The Remoteness Index, quantifies just how remote and hostile a particular project is and, based upon past projects experiences, looks at correlations, which may be useful in predicting outcomes and success rates of future projects. Several case studies are discussed of projects that are in operation or are under the planning/construction phase, and specific lessons learned are highlighted. The Remoteness Index does not just measure geographical distance. There are other factors that cause severe challenges in any or all of the planning, design, construction, operations, and export phases, and therefore these are incorporated into the concept of the remoteness of a project. The criteria identifying REMOTE are as follows: - Geographical Remoteness - This refers to the site being a significant distance from any infrastructure, any urban centre and any notable logistical availability. - Extreme climatic conditions - This refers to either constant extreme temperature, significant seasonal temperature swings, or other adverse constant or varying extreme conditions. - Manpower Problems - Severe operational challenges caused by lack of skilled affordable manpower, applicable mainly to the construction phase but also relevant to the operational phase. - Operational Challenges / infrastructure - Access to the site, local content problems through lack of local suppliers. This affects both the construction phase as well as the operational phase. - Technical hurdles - The need for a technical solution drives the development of the technical solution. This criterion rates the projects in relation to the technological challenges faced in the design, construction, and operational phases. - Environmental Sensitivity - By default most remote areas of the world are untouched and considered environmentally sensitive. New projects have an effect on the environment and there is an increasing public resistance to such intrusions. The earliest liquefaction plants were ground-breaking in terms of technology application and provided great leaps forward regarding know-how, and, whilst at the time they were constructed in what were considered out-of-the-way places, today many of the plants are now considered as standard. So, which plants are more remote than others, what makes them more remote and what does the future hold? In order to address this, and be able to have a quantification of remoteness, the previously mentioned factors can be defined and weighted to provide a numerical indication of remoteness. And when statistically analysing LNG Plants it was concluded that the distribution of the Remoteness Index was quite narrow in a band between 3 and 4, which nicely fitted a Gaussian distribution. However, new projects, especially in the United States do not follow the former trend. This is explained by the fact that these new liquefaction plants use a new production scheme (i.e. conversion of existing LNG receiving terminal into a liquefaction plants), are located close to the source of gas (not stranded gas) and are in an area where infrastructure is fully developed. United States shale gas has triggered a series of new projects with surprisingly low Remoteness Indices. The Remoteness Index can be used as an analytical tool to identify historical and future trends, and allows explanation of the historical trends and potential prediction of future trends. This will also be an indication for the complexity of certain remote projects. Major conclusions presented in the extended IGU report for the criteria defining the Remoteness Index are: Geographical and climatic conditions The Arctic Circle offers perhaps the most prolific potential regarding exploration, but at the same time it presents some of the biggest challenges regarding development and export of gas to market. Cold and harsh conditions present a unique set of technical challenges in all phases of the project, including LNG export in carriers with ice-breaking capability. Other locations in Asia-Pacific and in East Africa are likely hard to reach due to geographical isolation and lack of well-developed infrastructure. Severe climatic conditions affect the design of the project and can significantly influence construction activities. All planning cycles should be carefully matched with adequate contingencies for the weather cycles. While infrastructure will develop over the years, adverse climatic conditions cannot be changed by mankind. Thus, this aspect will remain a significant indicator for a competitive sufficient profit generating LNG liquefaction project. Social and environmental issues The majority of remote projects, even though initially located in areas of little or no urbanisation, do affect the socio-political landscape, often leading to development of urbanisation and bringing significant social change. In addition, the social implications of large scale investment projects are increasingly an obligation in the design and planning stage. They carry a large social responsibility towards indigenous habitants. Social responsibility programs need to be part of project execution and operation. Environmental aspect constraints need to be taken into account to minimise impact on marine and wildlife environment, which has not seen industrial development. While people may assimilate to changes in their social and cultural life within decades, the environment needs much longer periods to recover from imprudent disturbances. Short sighted run for profit may cause tremendous expenses to re-establish fair living conditions. Thus, a high rating in the category Environmental Concern needs to be considered seriously, when new projects approach FID. Technical and operational challenges All countries, especially the new LNG players are demanding significant Local Content in projects. Whilst most LNG project shareholders fully support the notion of Local Content, the reality is often a big obstacle in the sanctioning and development of remote projects. Development of these project requirements has a special focus on operation, maintenance, safety, and occupational health. From a design point of view remote projects have special requirements due to soil conditions, ambient conditions like snow and ice or storms, humidity, floods and sun radiation. This results in selecting optimal liquefaction technology, redundancy of equipment to ensure reliability and sometimes extensive winterisation of structures and equipment. Proper planning is critical since construction windows may be limited. Standardisation and modularisation to minimise construction work on site is one of the key success factors of constructing remote projects. However, technology is keeping pace with hostile environment project requirements. No project as yet has been shelved due to purely the lack of technological solutions, but due to the lack of economical sense of the required technological solutions. Cost impact of Remoteness Index From an aprioristic approach it could be expected, that the costs for an LNG project directly correlate to the remoteness (and therefore the Remoteness Index). However by evaluating past projects it is not possible to infer such a relationship exists. While certain remoteness criteria clearly do have an impact on a projects overall costs, other factors also have a very large impact on a particular projects costs (such as: raw materials costs, contractors' workload panorama, projects confluence, and many others). A clear view on the correlation between remoteness and cost looks as likely to be as absent for future projects as has been the case up until now. Usage of Remoteness Index Nevertheless, the Remoteness Index can be taken as an indication about how challenging a new LNG project can be due to its location; in this sense developers of new remote projects, can find it useful to check their new projects Remoteness Index estimate against other past projects with similarities. All of those projects, which have been classified as highly remote (Remoteness Index ≥4.0) and have started up already, are located in hot areas of the Asia-Pacific. Future projects including Yamal LNG and Alaska LNG will go further North and will be more in line with the general perception of remote.

GET SAMPLE REPORT @ Monthly Oil & Gas Industry Contracts Review - Midstream Sector Prevail Contracts Activity in the EMEA Region GlobalData's “Monthly Oil & Gas Industry Contracts Review - Midstream Sector Prevail Contracts Activity in the EMEA Region” report is an essential source of data on the contracts and open tenders in the oil and gas industry, The report portrays detailed comparative data on the number of contracts and their value in the month, subdivided by region, sector and geographies in Sep 2016, Additionally, the report provides information on the top contractors and issuers based on the worth of contracts executed in the oil and gas industry during the month by geographies and over the year. Data presented in this report is derived from GlobalData’s IPAR database and primary and secondary research. - Analyze oil and gas contracts in the global arena - Review of contracts in the upstream sector - exploration and production, midstream sector - pipeline, transportation, storage and processing, and in the downstream sector - refining and marketing - Information on the top awarded contracts by sector that took place in the oil and gas industry - Geographies covered include - North America, Europe, Asia Pacific, South & Central America, and Middle East & Africa - Summary of top contractors in the oil and gas industry over the past 12 months subdivided by the sector, this include key contractors such as Hyundai Engineering & Construction, SK Engineering & Construction, KBR, Transocean, and KOGAS - Summary of top issuers in the oil and gas industry over the past 12 months subdivided by the sector, this include key issuers such as Gazprom, Statoil, Liquefied Natural Gas Limited, Royal Dutch Shell, and Chevron - Enhance your decision making capability in a more rapid and time sensitive manner - Find out the major contracts/ open tenders focused sectors for investments in your industry - Understand the contracts and open tenders activity in the oil and gas industry - Evaluate the type of services offered by key contractors during the month - Identify growth sectors and regions wherein contracts opportunities are more lucrative - Look for key contractors/issuers if you are looking to award a contract or interested in open tender activity within the oil and gas industry FOR ANY QUERY, REACH US @ Monthly Oil & Gas Industry Contracts Review - Midstream Sector Prevail Contracts Activity in the EMEA Region

This study investigates characteristics of transient flow and the possibility of freezing in a pressure regulator and the rear connecting pipe of the pressure regulator during the closing process of the pressure control valve (PCV), which is an essential element in the operation of a natural gas pipeline network. For this purpose, the study develops a numerical model for the PCV and its rear connecting pipe by applying computational fluid dynamics method. The analysis is conducted in each of two cases: (1) a steady-state analysis in the case of normal operation and (2) an unsteady-state analysis in the case of emergency closure in problematic situations. First, we closely examine characteristics of internal flow in the pressure regulator and the rear connecting pipe when the PCV operates regularly with a 50% opening ratio in a steady state. Afterwards, unsteady-state analysis examines characteristics of transient flow, such as lowered pressure and temperature, velocity change, etc., of rear flow in the pressure regulator when the PCV is closed because of trouble in the pressure control system. © 2013 The Korean Society of Mechanical Engineers and Springer-Verlag Berlin Heidelberg.

Kim W.,KOGAS | Baek J.,KOGAS | Kim Y.,Korea University
International Gas Research Conference Proceedings | Year: 2011

Assessment methodology of structural integrity of gas pipeline is very important. For assessment of gas pipeline, many tests under various conditions have to be done. But test of real gas pipe is very dangerous and expensive. The objectives of this study are to develop micro-mechanical model for assessment of structural integrity of natural gas pipeline and develop damage model for assessment of defects in pipeline. We developed phenomenological damage simulation method for assessment of failure of natural gas pipeline, and developed user-subroutines in ABAQUS for implementation. This paper proposes a new method to simulate ductile failure using finite element analysis based on the stress-modified fracture strain model. A procedure is given to determine the stress-modified fracture strain as a function of the stress triaxiality from smooth and notched bar tensile tests with FE analyses. For validation, simulated results using the proposed method are compared with experimental data for cracked bar (tensile and bend) tests, extracted from API X65 pipes, and for full-scale burst test of gouged pipes, showing overall good agreements. Advantages in the use of the proposed method for practical structural integrity assessment of natural gas pipeline are discussed.

McCullagh C.L.,Colorado School of Mines | Tutuncu A.N.,Colorado School of Mines | Song T.H.,KOGAS
48th US Rock Mechanics / Geomechanics Symposium 2014 | Year: 2014

In this paper, the use of microseismic data for calibration and modification of wellbore temperature models will be introduced. Moreover, fracturing fluid distribution obtained using the modified temperature numerical model is coupled with the microseismic field data for several Eagle Ford shale wells to improve hydraulic fracture stimulation characterization. By measuring the temperature change along the wellbore, distributed temperature sensing (DTS) data may provide relative fluid distribution. This information may be used to assess the simple geometry of the hydraulic fractures, the fracture initiation points along the wellbore, wellbore integrity issues, and the effectiveness of isolation tools. With recently published wellbore temperature models, quantitative information about which zones receive the stimulation fluid can be numerically solved. However, DTS measurements and fluid distributions calculated using DTS data are restricted to the wellbore and near wellbore environment. For far field diagnostics of hydraulic fracturing stimulation other measurements are needed, specifically microseismic. By combining these two measurements, a new workflow is created which incorporates both the far field and wellbore measurements to characterize hydraulic fractures, both real-time and after the stimulation job. This workflow is especially useful in reservoirs that are naturally fractured or in wellbores were stress shadowing effects are significant, such as multistage fracturing multiple wells that are in close proximity to each other. In these scenarios the path that the fluid travels may be complex, even in the near wellbore environment. Due to this complexity, fluid distributed calculations based on DTS data may provide misleading results. Using information gained from microseismic, the wellbore temperature models may be modified to increase the reliability of the numerically calculated fluid distributions. The purpose of this paper is to propose how microseismic data may be used to modify the wellbore temperature models, and how stimulation fluid placement determined from the modified models may then be coupled with the microseismic to improve hvdraulic fracture stimulation characterization. Copyright (2014) ARMA, American Rock Mechanics Association

Baek J.-H.,KOGAS | Kim Y.-P.,KOGAS | Kim C.-M.,KOGAS | Kim W.-S.,KOGAS | And 2 more authors.
Proceedings of the Biennial International Pipeline Conference, IPC | Year: 2010

The objective of this study was to investigate the effect of the dent magnitude on the collapse behavior of dented pipe subjected to a combined internal pressure and in-plane bending. The plastic collapse behavior and bending moment of the dented pipe with several of dent dimensions were evaluated by using elastic-plastic finite element (FE) analyses. The indenters used to manufacture the dents on the API 5L X65 pipe were hemispherical rod type with diameter of 40, 80, 160 and 320 mm. Dent depths of 19, 38, 76, 114 and 152 mm were introduced on the pipe having a diameter of 762 mm and a wall thickness of 17.5 mm in analyses. A closing or opening inplane bending moment was applied on the dented pipes pressurized under internal pressure of the atmospheric pressure, 4, 8 and 16 MPa. The FE analyses results showed that the plastic collapse behavior of dented pipes was considerably governed by the bending mode and the dent geometry. Momentbending angle curves for dented pipe were obtained from computer simulation and evaluated with a variety of factors in FE analyses. Load carrying capacity of dented pipes under combined load was evaluated by TES (Twice Elastic Slope) moments. Load carrying capacity of pipe having up to 5% dent depth of outer diameter was not reduced compared with that of plain pipe. Opening bending mode had a higher load carrying capacity than closing bending mode under combined load regardless of dent depth. TES moment was decreased with increasing the dent depth and internal pressure regardless of bending modes. Copyright © 2010 by ASME.

Lee H.S.,Pukyong National University | Oh S.T.,Pukyong National University | Yoon J.I.,Pukyong National University | Lee S.G.,KOGAS | Choi K.H.,KOGAS
Defect and Diffusion Forum | Year: 2010

This paper presents the comparison of performance characteristics for the several natural gas liquefaction cycles. The liquefaction cycle with the staged compression was designed and simulated for improving the cycle efficiency using HYSYS software. This includes a cascade cycle with a two-stage intercooler which is consisted of a Propane, Ethylene and Methane cycle. In addition, these cycles are compared with a modified staged compression process. The key parameters of the above cascade cycles were compared and analyzed. The COP (Coefficient of Performance) of the cascade cycle with a two-stage intercooler and a modified staged compression process is 13.7% and 29.7% higher than that of basic cycle. Also, the yield efficiency of LNG (Liquefied Natural Gas) improved compared with the basic cycle by 28.5%. © (2010) Trans Tech Publications.

Kim K.-H.,Hanyang University | Sung W.-M.,Hanyang University | Han J.-M.,KOGAS | Lee T.-H.,Hanyang University
Geosystem Engineering | Year: 2012

To estimate methane recovery from an enhanced coal bed at the field scale, it is important to understand CO2 movement. Since coal beds are generally connected with aquifers, CO2 movement is affected by aquifer position and strength. Under conditions of no aquifer, CO2 initially has a tendency to move to the top layer of the coal seam due to the buoyancy effect. However, the permeability of the upper layer is decreased due to the swelling effect. The viscosity flow effectively improves CO2 movement due to high permeability in the bottom layer. Because of the offsetting effects of viscosity and gravitational flow, the vertical sweep efficiency of injected CO2 is very effective. Thus, methane recovery is highly calculated. Under conditions of an upper aquifer, CO2 flow in the bottom layer decreased as the injected CO2 leaked to the aquifer. As the hydraulic connection between the overlying aquifer and the coal seam is strong, the vertical sweep efficiency is weakened due to the high gas leakage rate. Therefore, methane recovery decreases. However, under conditions in which an aquifer is at the bottom, methane recovery should be high because the gas-leakage rate is almost negligible. Under conditions with an aquifer edge, injected CO2 in the coal bed has an asymmetric flow because pressure is only supported in the flow direction of the aquifer. As the pressure is greater at the aquifer, the asymmetric flow is gradually strengthened by changes in the equilibrium caused by viscosity and gravity. Consequently, enhanced coalbed methane recovery has irregular efficiency, in part due to the CO2 movement. However, by suitably adjusting the CO2 injection site and production well perforation, total methane recovery can be made more efficient, despite producing an asymmetric flow of injected CO2. These findings clearly indicate that production or injection plans for enhanced coalbed methane must be designed to consider CO2 movement. © 2012 Taylor & Francis.

Jang S.-H.,KOGAS
International Gas Research Conference Proceedings | Year: 2014

A presentation covers the balancing role of LNG in global gas market; effect of unconventional gas technology; US LNG exports; and globalization of LNG market. This is an abstract of a paper presented at the International Gas Union Research Conference (IGRC 2014) (Copenhagen, Denmark 9/17-19/2014).

Lee T.H.,Hanyang University | Lee Y.S.,KOGAS | Jang Y.H.,Hanyang University | Lee K.S.,Hanyang University | And 2 more authors.
Energy Sources, Part A: Recovery, Utilization and Environmental Effects | Year: 2012

According to the Nelson's classification scheme, naturally fractured basement reservoirs are Type 1 systems in which the fractures provide porosity and permeability. Hydrocarbon production from basement reservoirs only occurs through the connected fracture network. Thus, characterization and prediction of flow behavior in basement reservoirs is extremely difficult due to the heterogeneity of the fractures. In this study, a generalized multiphase discrete fracture network simulator was developed. The model implements 2D flow within a rectangular fracture, which is important in thick fractured reservoirs like basement rocks. The discrete fracture network model developed in this study was validated for two synthetic fracture systems using a commercial model, ECLIPSE. Comparison showed excellent agreement between the results for both models. To examine the changing production behavior in fractured basement reservoirs, an attempt was made to analyze the effect of a bottom-water aquifer on production behavior. It was confirmed that the discrete fracture network model is a useful tool in predicting water breakthrough and remaining oil phenomena. © 2012 Copyright Taylor and Francis Group, LLC.

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