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Airborne imaging spectroscopy has evolved dramatically since the 1980s as a robust remote-sensing technique used to generate 2D maps of surface properties over large areas. Two recent applications are particularly relevant to the needs of the oil and gas sector and government: quantification of surficial hydrocarbon thickness in aquatic environments and mapping atmospheric greenhouse-gas components. These techniques provide valuable capabilities for monitoring petroleum seepage and for detection and quantification of fugitive emissions. The Jet Propulsion Laboratory (JPL), a National Aeronautics and Space Administration (NASA) federally funded research-and-development center operated by the California Institute of Technology, has been a pioneer in optical remote sensing since the 1980s. JPL capabilities include expertise across all project phases, including sensor design and construction, airborne experiment execution, and data generation driven by science and customer needs.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.59)
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 25984, “Crosscutting Airborne Remote-Sensing Technologies for Oil and Gas and Earth Science Applications,” by A.D. Aubrey, C. Frankenberg, R.O. Green, M.L. Eastwood, and D.R. Thompson, National Aeronautics and Space Administration Jet Propulsion Laboratory, California Institute of Technology, and A.K. Thorpe, University of California, Santa Barbara, prepared for the 2015 Offshore Technology Conference, Houston, 4–7 May. The paper has not been peer reviewed. Airborne imaging spectroscopy has evolved dramatically since the 1980s as a robust remote-sensing technique used to generate 2D maps of surface properties over large areas. Two recent applications are particularly relevant to the needs of the oil and gas sector and government: quantification of surficial hydrocarbon thickness in aquatic environments and mapping atmospheric greenhouse-gas components. These techniques provide valuable capabilities for monitoring petroleum seepage and for detection and quantification of fugitive emissions. Introduction The Jet Propulsion Laboratory (JPL), a National Aeronautics and Space Administration (NASA) federally funded research-and-development center operated by the California Institute of Technology, has been a pioneer in optical remote sensing since the 1980s. JPL capabilities include expertise across all project phases, including sensor design and construction, airborne experiment execution, and data generation driven by science and customer needs. JPL has particular expertise in imaging spectroscopy, a passive method to interrogate objects or surfaces without physical contact. Such remote sensing has traditionally been applied to investigation of surface composition in terrestrial environments. These surface compositions are characterized by use of a spectral library that includes the surface-reflectance or emissivity fingerprints of constituent materials. Airborne imaging spectrometers provide a powerful method to survey wide spatial extents with high-performance surface characterization because of the wide contiguous spectral range at moderate spectral resolution. Novel quantitative methods have emerged recently for both atmospheric gases and surficial oil on water.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.77)
Abstract The classical CDP imaging method approximates a zero source-receiver offset view under each surface symmetry position for the sources and receivers used. Marine seismic surveys are inherently two-dimensional in nature. Nevertheless, there is bone fide diffractive information content. Imaging between different traverses relies solely on this diffractive component. Many migration methods treat such contributions in approximation.. A final CDP-based image can deliver good to excellent data quality. We investigate here the effect of parameters such as the number of data planes, separation of the planes, and other such factors on the resulting imaging character. One particular imaging method is called the Highest Possible Resolution Seismic Image. In order to most effectively use the resulting extended spatial and reflection time resolution, a trace inversion is used to display seismic datat. Color presentations which significantly extend the visual dynamic range are also used. This allows better access to the full information content of the images. Examples will show these results and further enlighten geoscientists about basic seismic imaging considerations, with emphasis on resolution which have particular relevance to important applications such as 4D surveys. Introduction Classical CDP imaging approximates a zero source-receiver offset view under each surface symmetry position for the paired sources and receivers used. Marine seismic surveys however, are inherently two-dimensional in nature even when multiple streamers and sources are deployed. This character results from combining data acquired using parallel passes of the vessel. There is bone fide diffractive information in marine data which is derived laterally, but away from the basic survey plane of each traverse. When we image subsurface locations between different traverses, we rely primarily on this diffractive content. If we formulate a travel-time relationship as a function of lateral offset, we can see how the image relates to those parameters about which we have some information - source position, receiver location, velocity, etc. In fact, most current migration methods do approximately correct for such contributions. CDP Imaging methods can be effective despite using only reflective returns plus very limited diffractive components. The marine 3D final image can deliver good to excellent data that approaches the quality of full 3D imaging as on land for example, which has more diffractive contributions as well having a greater diversity of azimuths. We investigate here the effect of parameters such as the number of planes, separation of the planes, and other factors on the resulting imaging information content.
- North America > United States > Illinois > Madison County (0.45)
- North America > United States > Texas > Harris County > Houston (0.29)
Dynamic 3D Imaging of Fluid Mobility in Natural Fractures Using High-resolution Positron Emission Tomography
Maucec, Marko (Halliburton) | Dusterhoft, Ron (Halliburton) | Rickman, Richard (formerly of Halliburton) | Gibson, Ron (Halliburton) | Buffler, Andy (University of Cape Town) | Stankiewicz, Maciek (University of Cape Town) | van Heerden, Michael (iThemba LABS)
Abstract Positron emission tomography (PET) continues to have wide-ranging medical application and is based on the detection of gamma radiation emitted from the decay of certain types of radionuclides. Modern PET scanners produce three-dimensional (3D) images of the radiation source, in discrete time steps, using tomography analysis. This paper presents an application of PET for studying fluid mobility in pressurized low-permeability rocks in the presence of natural fractures. This technique uses a high-resolution PET scanner and image reconstruction based on filtered back-projection. Traditional techniques have been limited to pressure measurement of fracture conductivity and effective permeability, but little is understood about the dynamic flow and velocity profiles within the fracture. The objective of this work was to investigate if it is possible to measure the dynamic (e.g., time-lapse and continuous) distribution of the fluid flow as a function of the overburden stress. PET imaging was applied to the flow of a brine solution, which was tagged with F-fluorodeoxyglucose (FDG) positron emitting radionuclide, through nonfractured sandstone and naturally fractured shale cores. A special composite container was manufactured to sustain high-pressure conditions and minimize the absorption of emitted gamma rays. The experimental apparatus is described, and it is demonstrated that the 3D images obtained with a grid resolution of 2 ´ 2 ´ 2 mm allow clear determination of the fluid flow rate through the core as a function of overburden pressure and time. PET images are direct observations of the radiation source and allow an unambiguous determination of the fluid distribution in the core. The results of this research can be used to validate the numerical modeling of fluid flow through fractured rock matrices, to enable more accurate estimates on the directionality of fractures from the fluid distribution as a function of time, and to obtain more quantitatively sound estimates of fracture connectivity. Introduction One of the key issues the oil and gas industry is facing today is that fracturing (King 2012) to achieve economic production from unconventional plays (e.g., shale) is significantly different from the fracturing practiced during the previous 60 years (Soliman 1986; Soliman et al. 1990). Traditionally, fracturing treatments were designed to achieve long, effective fracture half-lengths and conductivity in millidarcy (md) and microdarcy (md) rocks. However, ultralow-matrix permeability is now being considered in formations such as shale that geologists used to consider seals. Under these conditions, the ultimate challenge is to design treatments to expose the maximum possible surface area to provide a path for the fluids to propagate back to the wellbore. Conventional bi-wing fractures in vertical wells cannot achieve and maintain economic production under these conditions, and multiple transverse fractures in horizontal wells are used to create complex fracture networks. While, in the past, the goal was to maximize the fracture length and width, the objectives now are to maximize the stimulated reservoir volume (SRV), optimize the fracture complexity within the SRV, identify the associated uncertainties, and help minimize the risk for economical application (King 2012; Edwards et al. 2007). The complexity of the problem requires a better understanding of fracture conductivity and its influence in low-permeability rocks, such as shale. Moreover, what really must be understood is how these unsupported and partly supported fractures will behave under production conditions.
- North America > United States > Texas (0.68)
- Asia (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
R&D Grand Challenges - This is the fifth in a series of articles on the great challenges facing the oil and gas industry as outlined by the SPE Research and Development (R&D) Committee. The R&D challenges comprise broad upstream business needs: increasing recovery factors, in-situ molecular manipulation, carbon capture and sequestration, produced water management, higher resolution subsurface imaging of hydrocarbons, and the environment. The articles in this series examine each of these challenges in depth. The R&D Grand Challenges Series, comprising articles published in JPT during 2011 and 2012, is available as a collection on OnePetro (SPE-163061-JPT). Introduction It is hard to read road signs if you have poor eyesight, which is why driver’s licenses are issued with restrictions requiring that corrective lenses must be worn. Likewise, it is hard to find and exploit subsurface resources if you can’t clearly see your targets or monitor the movement of fluids in the reservoir. Engineers now have powerful tools to precisely model subsurface reservoir production behavior, but a precise answer is still wrong if it is derived from an inaccurate subsurface description. Geoscientists make maps and rock property models of the subsurface by interpreting images that are produced from remote sensing data. Analogs from modern depositional environments and outcrop exposures guide subsurface data interpretation to predict ahead of the bit, then postdrill geostatistics are used to fill in stratigraphic details between wellbore control points. Selection of the right depositional model, facies distribution, and geostatistical analog depends on having the sharpest, most detailed and accurate image of the subsurface possible—the Grand Challenge of Higher Resolution Subsurface Imaging. Over the past century, the industry has relentlessly sought ways to improve subsurface imaging of hydrocarbons. Canadian inventor Reginald Fessenden first patented the use of the seismic method to infer geology in 1917. A decade later, Schlumberger lowered an electric tool down a borehole in France to record the first well log. Today, advances in seismic and gravity data acquisition, electromagnetics, signal processing and modeling powered by high-performance computing, and the nanotechnology revolution are at the forefront of improved reservoir imaging. In this paper, we will examine the challenges of getting higher resolution subsurface images of hydrocarbons and touch on emerging research trends and technologies aimed at delivering a more accurate reservoir picture.
- Geology > Sedimentary Geology (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.88)
- Geology > Geological Subdiscipline > Stratigraphy (0.88)
- Geology > Rock Type > Sedimentary Rock (0.67)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.68)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition > Land Seismic Acquisition (0.47)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying > Vertical Seismic Profile (VSP) (0.46)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Marlim Field > Macae Formation (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Marlim Field > Lago Feia Formation (0.99)