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Image Databases: Search and Retrieval of Digital Imagery Edited by Vittorio Castelli, Lawrence D. Bergman Copyright  2002 John Wiley & Sons, Inc. ISBNs: 0-471-32116-8 (Hardback); 0-471-22463-4 (Electronic) 5 Images in the Exploration for Oil and Gas PETER TILKE Schlumberger–Doll Research Center, Ridgefield, Connecticut 5.1 INTRODUCTION Images are central to the task of exploring for and producing oil and gas (hydro- carbons) from the Earth’s subsurface. To understand their utility, one must look at both how hydrocarbons are formed and how we explore for them. Oil and gas (hydrocarbons) are generally found in the pores of sedimentary rocks, such as sandstone or limestone. These rocks are formed by the burial of sediment over millions of years and its subsequent chemical alteration (diagen- esis). In addition to the sediment, organic material is also buried and subjected to the same high pressures and temperatures that turn the sediment into rock. This organic material eventually becomes oil and gas. Over time, the oil and gas migrates upward through porous and permeable rock or fractures because it is less dense than the surrounding groundwater. Most of these hydrocarbons reach the surface and either evaporate or dissipate. However, a small fraction of these migrating hydrocarbons become trapped in the subsurface. A hydrocarbon trap forms when an impermeable rock, such as shale, lies above a porous rock, such as sandstone or limestone. Traps are often associated with faults or folds in the rock layers. The exploration for hydrocarbons generally begins with the search for these traps. Oil exploration may begin with the acquisition of two-dimensional (2D) seismic data in an area of interest. These data may be thought of as two- dimensional images vertically slicing through the Earth, each slice being tens of kilometers long and several kilometers deep. If a candidate area is located on these images, then a three-dimensional (3D) seismic survey may be acquired over the region. This survey yields a 3D image of the subsurface. 107 108 IMAGES IN THE EXPLORATION FOR OIL AND GAS The 3D seismic images are then carefully analyzed and interpreted. If a trap is identified, and enough supporting evidence suggests that economical deposits of hydrocarbons are present, then the decision to drill a well might be made. After the well is drilled, wireline logs are acquired to image the rock strata penetrated by the well. If these wireline images and other supporting data suggest that hydrocarbons are present in the trap, then a core might be acquired over the small interval of interest for detailed analysis of the rock. The depicted scenario is just one possible use of imagery in the hunt for hydrocarbons. There are, however, many other steps involved in exploration and production, some of which are discussed later in this chapter. To interpret and manage these data, the petroleum industry relies on large software systems and databases. Through the 1980s, oil companies developed much of this software in-house for interpreting and managing oil fields. Most oil companies have traditionally had a heterogeneous mix of software tools that include vendor-supplied products and homegrown applications. Communication between these products typically involved exporting the data as ASCII text files and importing the data into another application. Just as they have long outsourced the acquisition of data, during the 1990s the oil companies increasingly outsourced the development of software. Numerous vendors now produce specialized applications that manage specific aspects of oil field development. To address the resulting interoperability nightmare, the major oil companies invested substantial effort to standardize data storage and exchange formats. In particular, the Petrotechnical Open Software Corporation (POSC) was created as a nonprofit organization whose purpose is to produce open specifications (called Energy eStandards) for leveraging and integrating information technologies. The late 1990s also saw the explosion of the Internet and the associated evolution of tools and standards for business-to-business e-commerce. POSC and the rest of the oil industry are embracing these new opportunities to build even more open data exchange standards. This chapter introduces some of the types of image data acquired during the hydrocarbon exploration and production task. This is followed first by a discussion of how these data are processed and integrated with each other and an analysis of data management issues. Finally, an overview of some of the most well-known interpretation and analysis systems is presented. 5.2 DATA CHARACTERISTICS A wide variety of image data is acquired from the subsurface during the hydro- carbon exploration task. Some of the principal technologies involved in image acquisition are discussed in this section. 5.2.1 Wireline Logs Wireline logging is the most common means for analyzing the rocks intersected by a well (Section 5.2.2). A well is “logged” after an interval has been drilled DATA CHARACTERISTICS 109 (for e.g., 3,000 feet). In logging the well, several different types of equipment are involved: • The “tool” assembly, which contains the instruments that measure the rock and fluid properties in the well. • The data acquisition system, located at the surface, which stores and analyzes the data. • The cable or “wireline,” which serves as the mechanical and data commu- nication link between the downhole tool and the surface data acquisition system. • The hoisting equipment used to raise and lower the tool in the well. The drill and drill pipe are first removed from the well, leaving the newly drilled well full of a high-density fluid (the drilling mud). The tool assembly is then lowered to the bottom of the well and slowly pulled to the surface, making various measurements (electrical, acoustic, and nuclear) of the surrounding rock and fluids as it passes up through the different geologic strata. These measurements generate a continuous stream of data up the “wireline” to the data acquisition system on the surface. These data are displayed on a “log” that presents the measurements about the rocks and fluids as a function of depth. The data are also recorded digitally for further processing and analysis. The tool assembly is composed of numerous instruments, each of which measures a different physical property of the rock and the fluid contained in the pore spaces. Depending on the complexity of the rock and fluid being analyzed, and the clients’ budget, 10 or more types of measurements may be required to obtain the desired information. Some measurements examine the natural nuclear radiation emitted by the rocks; others measure the formation’s response to bombardment by gamma rays or neutrons. There are yet other measurements that observe how induced vibra- tional (acoustic) waves are transmitted through the rock. Electrical measurements observe the conductivity of the surrounding rocks and fluids: salt water is conduc- tive, whereas oil and gas are nonconductive. The typical wireline logging tool resembles a long thin pipe. The Schlumberger combined magnetic resonance (CMR) tool is typical. The tool is 14 ft long with a diameter of 5.3 in. It can operate in holes with a diameter as small as 5.875 in. On the CMR tool, the sensor is a 6-in-long pad, which presses against the rock wall. The remaining 13.5 ft of the tool contain the power supply, computer hardware, and telemetry equipment needed to support the sensor. As hostile environmental conditions exist in the well, all components of the logging tool are engineered to operate under extreme conditions. Temperatures can exceed 400 ◦ F and pressures can exceed 20,000 psi. Pulling the tools through the well can subject them to high shock and vibration. Chemicals in the well are often extremely corrosive. The FMS (Formation MicroScanner) and FMI (Formation MicroImager) tools are used to image the circumference of the borehole. Both these tools have 110 IMAGES IN THE EXPLORATION FOR OIL AND GAS very closely spaced electrodes. As such, they produce and measure electrical current that flows near the well bore surface, rather than deep in the rock strata. Therefore, they measure localized electrical properties of the rock formations and yield high-resolution images. Figure 5.1 illustrates an FMS tool. The FMS consists of four orthogonal imaging pads, each containing 16 microelectrodes or buttons (Fig. 5.2), which Figure 5.1. Formation MicroScanner (FMS) sonde (http://www.ldeo.columbia.edu/BRG/ ODP/LOGGING/MANUAL/MENU/contents.html, ODP Logging Manual). Figure 5.2. Detailed view of the 16 electrodes on one of the four FMS pads (http://www.ldeo.columbia.edu/BRG/ODP/LOGGING/MANUAL/MENU/contents.html, ODP Logging Manual). DATA CHARACTERISTICS 111 are in direct contact with the borehole wall during the recording. After a portion of the well has been drilled, the FMS sonde is lowered into the deepest part of the interval of interest. The sonde is then slowly pulled up the well with the button current intensity being sampled every 2.5 mm. The tool works by emitting a focused current from the four pads into the formation. The current intensity variations are measured by the array of buttons on each of the pads. The FMI tool is very similar to the FMS tool. It has eight pads instead of four, and produces a more continuous image around the circumference of the borehole. An example of an FMI image is illustrated in Figure 5.3. Despite the power of 2D imaging tools such as FMI and FMS, the majority of logging tools are single channel, that is, for a given depth only one measurement is made for a particular physical property. Thus, as the tool is being pulled up the hole, it is taking “snapshots” of the surrounding rock at regular intervals. The XX92 XX93 XX94 Depth, ft Fractures Stylolite Figure 5.3. Sub-horizontal stylolites(wide dark bands) and inclined fractures (narrow dark lines) in a Middle East carbonate formation [Akbar et al., Classic interpretation problems: evaluating carbonates, Oilfield Rev., Winter, 38–57 (1995)]. A color version of this figure can be downloaded from ftp://wiley.com/public/sci tech med/image databases. 112 IMAGES IN THE EXPLORATION FOR OIL AND GAS typical depth-interval spacing for the single-channel logging tools is 6 inches. The measurements taken at a specific depth are termed frames. Other tools, such as the CMR, acquire multiple measurements at each frame. For example, the CMR tool measures the magnetic resonance relaxation time at each frame, which has varying signal intensity as a function of time. A relatively standard presentation for wireline logging data has evolved over the years. In this presentation, the vertical axis of the cartesian plot is the indepen- dent (depth) variable, whereas the horizontal axis is the dependent (measurement) variable. Some measurements are scaled linearly, while others are scaled logarith- mically, resulting in parallel plots. Imagery from FMI and FMS tools is typically displayed in an unwrapped format in which the vertical axis is depth and the horizontal axis is the azimuth around the borehole. This format presents the entire circumference of the borehole, although certain visual distortions result (Fig. 5.3). 5.2.2 Logging While Drilling The vast majority of vertical or deviated oil and gas wells are “logged” with wireline technology. “Horizontal wells” that are steered to follow the geologic strata at depth instead use a specialized technology called logging while drilling or LWD. LWD is the measurement of the petrophysical properties of the rock penetrated by a well during the drilling of the hole. LWD is very similar to wireline logging in that physical measurements are made on the rock but differs greatly in that the measurements are made during the drilling of wells rather than after. With LWD, the logging tools are integrated into the bottom hole assembly (BHA) of the drill string. Although expensive, and sometimes risky, LWD has the advantage of measuring properties of the rock before the drilling fluids invade deeply. Further, many well bores prove to be difficult or even impossible to measure with conventional wireline logging tools, especially highly deviated wells. In these situations, the LWD measurement ensures that some measurement of the subsurface is captured in the event that wireline operations are not possible. The BHA is located at the end of a continuous section of coiled tubing. Drilling mud is pumped down the center of the coiled tubing so that the hydraulic force of the mud drives the mud motor, which in turn drives the drill bit at the end of the BHA. The logging tools are located within the BHA but behind the drill bit. The resistivity at the bit (RAB) tool makes resistivity measurements around the circumference of the borehole. The RAB tool also contains a gamma ray detector, which supplies a total gamma ray measurement. An azimuthal positioning system allows the gamma ray measurement and certain resistivity measurements to be acquired around the borehole, thereby generating a borehole image. The RAB tool may be connected directly behind the bit or further back in the BHA. In LWD, the acquired logging data is delivered to the surface through mud pulse telemetry: positive and negative pressure waves are sent up through the mud column. The bandwidth of this telemetry system (less than 10 bits per second) is DATA CHARACTERISTICS 113 To p To p To p To pBottomBottom LWD image Wireline image Depth 4ft Figure 5.4. Comparison of LWD (RAB) image with an FMI image in a deviated well. Note the characteristic sinusoidal pattern caused by the intersection of the rock strata with the cylindrical borehole (http://www.ldeo.columbia.edu/BRG/ODP/LOGGING/MANUAL/ MENU/contents.html, ODP Logging Manual). A color version of this figure can be downloaded from ftp://wiley.com/public/sci tech med/image databases. much lower than that supported by the conventional wireline telemetry. Because drilling speeds are typically very low (less than 100 feet per hour), a lot of data can be delivered to the surface even with the low bandwidth. Thus, many of the same measurements that can be made with wireline logging can be made with LWD Figure 5.4 illustrates a comparison of LWD RAB tool and wireline electrical imaging FMI tool measurements of dense fracturing in consolidated sediments. Both images of the interior of the borehole wall are oriented to the top and bottom of the deviated (nonvertical) well. Note that the RAB tool has inferior bed resolution (by a factor of 30) than the FMI, although it provides complete circumferential coverage. As noted earlier, LWD is generally used in highly deviated or horizontal wells where it is not possible to lower a wireline tool into the hole. Highly deviated and horizontal wells are generally geosteered, that is, the driller can control in real time the direction of the drill. Geosteering requires an understanding of where the drill bit is relative to the surrounding rock. LWD is well suited to this purpose. Because the well is being “logged” as it is passing through the rock formations, the driller knows when the drill has entered or left the zone of interest, thereby allowing the geosteering activity to be controlled in near real time. 5.2.3 Core Images A core is a cylindrical sample of rock collected from a well. Conventionally, when a well is drilled, the diamond drill bit pulverizes the rock. To retrieve a 114 IMAGES IN THE EXPLORATION FOR OIL AND GAS consolidated section of core, a coring tool is required. A coring tool is essentially a hollow pipe that cuts out a cylinder of the rock without pulverizing it. The rock is then preserved inside the pipe and brought to the surface. The first coring tool appeared in 1908 in Holland. The first one used in the United States appeared some years later (1915) and was a piece of modified drill pipe with a saw-toothed edge for cutting — much like a milling shoe [3]. AOGC WILLIAMS #3 STANTON.K.S TOP 5661 Figure 5.5. Slabbed core in boxes. Note the holes in the core where rock samples have been removed for further analysis (http://crude2.kgs.ukans.edu/DPA/BigBow/CoreDesc, Kansa Geological Survey, Big Bow Field). A color version of this figure can be down- loaded from ftp://wiley.com/public/sci tech med/image databases. DATA CHARACTERISTICS 115 Once collected, the cores are placed in core boxes. The boxes are labeled with the well identification information and marked with the measured depths of each piece. In many cases the core is sliced down the axis of the cylinder (“slabbed”) so that a flat surface of the rock is exposed for visual inspection (Fig. 5.5). The core is then typically stored in large core “warehouses.” Traditionally, geologists and technicians would then visually inspect the core and have samples extracted for further analysis. Increasingly, these “slabbed” (and “unslabbed”) cores are digitally photographed. After the core has been boxed and possibly slabbed, small samples are taken for higher-resolution analysis (Figs 5.5 and 5.6). The data obtained from the core include photographic images, measurements of physical properties, such as porosity and permeability, and microphotographs of thin sections. Quite often, even higher-resolution imaging is required to fully understand the properties of the rock. In these cases, scanning electron microscopy (SEM) may be necessary. There are no standards for core photographs. Only recently have laboratories begun capturing the images digitally. Those cores that were photographed are now being “scanned” at varying resolutions. Figure 5.6. Slabbed core from a single well, illustrating variability in rock color, layering, and texture. Note the holes in the core where rock samples have been removed for further analysis (http://crude2.kgs.ukans.edu/DPA/BigBow/CoreDesc, Kansa Geological Survey, Big Bow Field). A color version of this figure can be downloaded from ftp://wiley.com/public/sci tech med/image databases. 116 IMAGES IN THE EXPLORATION FOR OIL AND GAS A common technique when photographing core is to take two photographs: one in white light, the other in ultraviolet light. Ultraviolet light is useful because oil becomes luminescent, and the oil-saturated rock then becomes easily distin- guishable from the oil-free rock. 5.2.4 Seismic Data Seismic imaging is the process through which acoustic waves reflected from rock layers and structures are observed and integrated to form one-, two-, and three-dimensional images (1D, 2D, and 3D) of the Earth’s subsurface. The resulting images allow us to interpret the geometric and material properties of the subsurface. 100 msec Two-way time 1 240 Level number a b Figure 5.7. VSP data in a horizontal well (red trace). The data show three important features; two faults marked A and B, which appear as anticipated in the reflected image, together with evidence of dipping. The apparent formation dips seem to be parallel to the borehole until very near total depth. This turned out to be entirely consistent with the Formation MicroScanner (FMS) –computed dips [Christie et al., Borehole seismic data sharpen the reservoir image, Oilfield Rev., Winter, 18–31 (1995)]. A color version of this figure can be downloaded from ftp://wiley.com/public/sci tech med/image databases.