Temperature dependent characterization of optical fibres for distributed temperature sensing in hot geothermal wells

This study was performed in order to select a proper fibre for the application of a distributed temperature sensing system within a hot geothermal well in Iceland. Commercially available high temperature graded index fibres have been tested under in-situ temperature conditions. Experiments have been performed with four different polyimide coated fibres, a fibre with an aluminum coating and a fibre with a gold coating. To select a fibre, the relationship between attenuation, temperature, and time has been analyzed together with SEM micrographs. On the basis of these experiments, polyimide fibres have been chosen for utilisation. Further tests in ambient and inert atmosphere have been conducted with two polyimide coated fibres to set an operating temperature limit for these fibres. SEM micrographs, together with coating colour changes have been used to characterize the high temperature performance of the fibres. A novel cable design has been developed, a deployment strategy has been worked out and a suitable well for deployment has been selected.Comment: PACS: 42.81.Pa, 93.85.Fg, 47.80.Fg, 91.35.Dc, 07.20.Dt, 07.60.V

Recent advances in well-based monitoring of CO2 sequestration

Recent CO{sub 2} sequestration pilot projects have implemented novel approaches to well-based subsurface monitoring aimed at increasing the amount and quality of information available from boreholes. Some of the drivers for the establishment of new well-based technologies and methodologies arise from: (1) the need for data to assess physical and geochemical subsurface processes associated with CO{sub 2} emplacement; (2) the high cost of deep boreholes and need to maximize data yield from each; (3) need for increased temporal resolution to observe plume evolution; (4) a lack of established processes and technologies for integrated permanent sensors in the oil and gas industry; and (5) a lack of regulatory guidance concerning the amount, type, and duration of monitoring required for long-term performance confirmation of a CO{sub 2} storage site. In this paper we will examine some of the latest innovations in well-based monitoring and present examples of integrated monitoring programs

Simultaneous determination of thermal conductivity, thermal diffusivity and specific heat in sI methane hydrate

This paper is not subject to U.S. copyright. The definitive version was published in Geophysical Journal International 169 (2007), 767–774, doi:10.1111/j.1365-246X.2007.03382.x.Thermal conductivity, thermal diffusivity and specific heat of sI methane hydrate were measured as functions of temperature and pressure using a needle probe technique. The temperature dependence was measured between −20°C and 17°C at 31.5 MPa. The pressure dependence was measured between 31.5 and 102 MPa at 14.4°C. Only weak temperature and pressure dependencies were observed. Methane hydrate thermal conductivity differs from that of water by less than 10 per cent, too little to provide a sensitive measure of hydrate content in water-saturated systems. Thermal diffusivity of methane hydrate is more than twice that of water, however, and its specific heat is about half that of water. Thus, when drilling into or through hydrate-rich sediment, heat from the borehole can raise the formation temperature more than 20 per cent faster than if the formation's pore space contains only water. Thermal properties of methane hydrate should be considered in safety and economic assessments of hydrate-bearing sediment.Gas Hydrate Project of the U.S. Geological Survey’s Coastal and Marine Geology Program, in addition to Department of Energy contract DE-AI21–92MC2921

Distributed temperature sensing as a down-hole tool in hydrogeology

Distributed Temperature Sensing (DTS) technology enables down-hole temperature monitoring to study hydrogeological processes at unprecedentedly high frequency and spatial resolution. DTS has been widely applied in passive mode in site investigations of groundwater flow, in-well flow, and subsurface thermal property estimation. However, recent years have seen the further development of the use of DTS in an active mode (A-DTS) for which heat sources are deployed. A suite of recent studies using A-DTS down-hole in hydrogeological investigations illustrate the wide range of different approaches and creativity in designing methodologies. The purpose of this review is to outline and discuss the various applications and limitations of DTS in down-hole investigations for hydrogeological conditions and aquifer geological properties. To this end, we first review examples where passive DTS has been used to study hydrogeology via down-hole applications. Secondly, we discuss and categorize current A-DTS borehole methods into three types. These are thermal advection tests, hybrid cable flow logging, and heat pulse tests. We explore the various options with regards to cable installation, heating approach, duration, and spatial extent in order to improve their applicability in a range of settings. These determine the extent to which each method is sensitive to thermal properties, vertical in well flow, or natural gradient flow. Our review confirms that the application of DTS has significant advantages over discrete point temperature measurements, particularly in deep wells, and highlights the potential for further method developments in conjunction with other emerging fiber optic based sensors such as Distributed Acoustic Sensing. This article is protected by copyright. All rights reserved

Monitoring and volumetric estimation of injected CO 2 using 4D seismic, petrophysical data, core measurements and well logging: A case study at Ketzin, Germany

More than 50 000 tons of CO 2 have been injected at Ketzin into the Stuttgart Formation, a saline aquifer, at approximately 620 m depth, as of summer 2011. We present here results from the 1 st repeat 3D seismic survey that was performed at the site in autumn 2009, after about 22 000 tons of CO 2 had been injected. We show here that rather complex time-lapse signatures of this CO 2 can be clearly observed within a radius of about 300 m from the injection well. The highly irregular amplitude response within this radius is attributed to the heterogeneity of the injection reservoir. Time delays to a reflection below the injection level are also observed. Petrophysical measurements on core samples and geophysical logging of CO 2 saturation levels allow an estimate of the total amount of CO 2 visible in the seismic data to be made. These estimates are somewhat lower than the actual amount of CO 2 injected at the time of the survey and they are dependent upon the choice of a number of parameters. In spite of some uncertainty, the close agreement between the amount injected and the amount observed is encouraging for quantitative monitoring of a CO 2 storage site using seismic methods. © 2012 European Association of Geoscientists & Engineers