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Abstract The expanding demand for primary energy has pushed exploration and production activities towards more challenging environments, such as the north slope of Alaska, Siberia and deeper oceans. In many cases associated gas could be a limiting factor in the field developments. While stabilised oil could be transported by pipelines and/or tankers, the options for gas and associated gas is rather limited and/or not economical. There are strict limitations on flaring due to environmental/economical concerns, and most of the available options for gas utilisation (e.g. gas to liquid, gas to wire, compressed natural gasโฆ) require considerable CAPEX. Recently, we have proposed HYDRAFLOW, which is a Cold Flow solution for avoiding gas hydrate problems. This could provide a solution for gas transportation. The concept of HYDRAFLOW is based on allowing/encouraging gas hydrate formation, but preventing their agglomeration and pipeline blockage by using chemicals and/or mechanical means. The aim is to eliminate/minimise the gas phase by converting it into hydrates and dispersing hydrates in oil and/or aqueous phase. Water could be added to maximise gas conversion into hydrates and/or adjusting the slurry viscosity. Furthermore, a loop concept has been developed where part of the liquid phase could be recycled, minimising chemical discharge to the environment. As HYDRAFLOW basically converts gas into hydrates and transport it as slurry in a liquid phase, it could provide a solution for gas utilisation for fields where the ambient temperature and pipeline pressure are inside the hydrate stability zone. In this communication, after introducing the HYDRAFLOW concept, the latest results of laboratory tests at subzero conditions are presented as well as an economical evaluation and a pipeline transportation simulation on one of the West Siberian oil fields. These simulations demonstrate that the concept is viable, and suggest that HYDRAFLOW technology could offer significant benefits over existing flow assurance strategies, providing a novel low CAPEX/OPEX solution for gas utilisation. Introduction The rising trend in global energy demand and high price of the oil has led to production from reserves previously considered uneconomic and/or less practical. There are many challenges in production from these reserves due to various reasons such as:โThe field is remote and/or located in deepwater (e.g. stranded gas). โThe gas field is too small to justify a gas pipeline for long-term production (marginal) โAmbient temperatures are very low such as the north slope of Alaska, Siberia and deeper oceans. โThere are restrictions on flaring associated gas. In many cases associated gas could be the limiting factor in the field developments. While stabilised oil could be transferred by pipeline and/or tankers, the options for gas and associated gas are rather limited and/or uneconomic. Worldwide, governments are restricting/limiting flaring associated gas. In many cases these restrictions could limit oil production rates. According to statistics [1], approximately 113 billion m3 (4 trillion cubic feet) of natural gas is being flared annually and close to 142 trillion m3 (5,000 trillion cubic feet) of natural gas (either associated with crude oil, or non-associated) is stranded worldwide. However, there is a high demand for natural gas in global market and considerable effort is being made throughout the industry to reduce the costs for natural gas transportation. There are a number of methods of exporting gas energy from an isolated field for use elsewhere such as pipelines, liquefied natural gas (LNG), gas to liquid (GtL), Gas to commodity (GtC), gas to wire (GtW), compressed natural gas (CNG) and gas to solids (GtS), i.e. hydrate (NGH).
- Europe (1.00)
- North America > United States > Alaska (0.45)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
- Facilities Design, Construction and Operation > Natural Gas Conversion and Storage > Liquified natural gas (LNG) (1.00)
- Facilities Design, Construction and Operation > Natural Gas Conversion and Storage > Compressed natural gas (CNG) (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Hydrates (1.00)
Abstract Natural gas has come to the forefront of the international energy debate. The reasons include increasing demand in the United States, China and India and a changing worldwide preference in power generation because of environmental concerns. As a result, the transport of natural gas becomes important. Currently, 70 percent of gas is transported to market by pipeline and 30 percent as liquefied natural gas (LNG). Pipelines are attractive but, offshore, their feasibility is greatly hindered by distance limits and terrain restrictions. On the other hand LNG facilities are expensive to construct and the process is complicated, costly and energy wasteful. It is applicable primarily for long distances and large volumes of gas. Sea-going compressed natural gas (CNG) is an alternative that has been proposed in recent years but has not made substantial headway for two reasons:the emphasis for investments by producers and large consumers has been primarily on LNG; CNG boat designs and projects have been envisioned to eke a bite out of the LNG pie which is not necessarily a good approach. CNG must make a niche in smaller markets and shorter distances. Here we present definitive economics by performing a specific case study for Sakhalin Island, Russia. Results delineate the landscape where this mode of transport is attractive and how it can be deployed with specific requirements of distance, market size and size distribution. Our studies show that for shorter distances (e.g., 500 km, about 300 miles) and even relatively large volumes, LNG cannot compete with CNG and at longer distances (e.g., 2,000 km, about 1,250 miles) CNG is far more attractive at small volumes, assuming that offshore pipelines are not feasible. For volumes such as 1 to 2 billion cubic meters per year (about 35 to 70 billion cubic feet per year), CNG is the only feasible solution to bring this energy source to many markets. These findings suggest that many parts of the world (such as the entire Mediterranean basin, the Scandinavian peninsula, Sakhalin Island, South-East Asia and the Caribbean) would be better served by CNG even if LNG projects have already been approved and under construction. We also performed a sensitivity study on gas price (both at the source and at the market) impacts on the value of both CNG and LNG projects and determine the breakeven points under a given gas demand of e.g., 1.5 Bcm/yr (about 50 Bcf/yr) and a distance of 1,500 km (about 900 miles). For example if the source price is $6/MMBtu then the breakeven price for CNG is $10.05 whereas for LNG it will have to be $14.24, a 40% increase. Introduction Arguably, natural gas is becoming a more and more important resource of energy, with its share in global consumption expected to increase dramatically over the next two decades. According to the most recent data available (Energy Information Administration, EIA, 2008), world consumption of natural gas is more than 105 Tcf (Trillion cubic feet), about 3,000 Bcm, an increase of 28% in a decade (compared with, approximately, 16% increase for oil and a 5% for coal). In the late 1990s analysts began to predict radical increases in the world natural gas energy share. Particularly aggressive was the forecast provided by Economides and Oligney (Economides et al,2001), who predicted that by 2020 natural gas will make up 45 to 50% of the world energy mix, starting from a 22% share in 2000. Such increases in demand will be excruciating and will be the result of massive restructuring of the transportation sector to use natural gas either as CNG directly or, indirectly, by electrifying vehicles. Besides the U.S, Europe, Japan and Korea, historically the leaders in natural gas consumption and whose demand will increase significantly, fast evolving large Asian economies such as China and India will definitely become new players in this rapidly expanding market. The dominant exporter of natural gas is and will be by far Russia, with its leading position in proved reserves (1,680 Tcf, about 50,000 Bcm) and production (over 23 Tcf, about 650 Bcm, produced in 2006) (EIA, 2008).
- North America > United States (1.00)
- Asia > Russia > Far Eastern Federal District > Sakhalin Island > Sea of Okhotsk (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Midstream (1.00)
- Asia > Russia > Far Eastern Federal District > Sakhalin Island > Sea of Okhotsk > North Sakhalin Basin > Piltun-Astokhskoye Field (0.99)
- Asia > Russia > Far Eastern Federal District > Sakhalin Island > Sea of Okhotsk > East Sakhalin - Central Sea of Okhotsk Basin > North Sakhalin Basin > Odoptu Field (0.99)
- Asia > Russia > Far Eastern Federal District > Sakhalin Island > Sea of Okhotsk > East Sakhalin - Central Sea of Okhotsk Basin > North Sakhalin Basin > Chayvo Field (0.99)
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