US20140338897A1

US20140338897A1 - Methods for determining organic matter in shale

Info

Publication number: US20140338897A1
Application number: US14/168,962
Authority: US
Inventors: Andrew E. Pomerantz
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2013-05-16
Filing date: 2014-01-30
Publication date: 2014-11-20

Abstract

A method for analyzing a subterranean formation including measuring an electromagnetic spectrum of a rock sample of the subterranean formation using optical spectroscopy, identifying a first kerogen pixel of a plurality of pixels of the electromagnetic spectrum, and analyzing the first kerogen pixel and estimating a property of the first kerogen pixel.

Description

CROSS REFERENCE TO RELATED APPLICATION

This application claims priority to and the benefit of U.S. Provisional Patent Application Ser. No. 61/824,138, filed May 16, 2013, which is incorporated by reference herein.

BACKGROUND

Measuring properties of kerogen is one approach for estimating reservoir quality and completion quality in a given subterranean formation. In hydrocarbon exploration, reservoir quality typically refers to the factors or parameters that affect the amount and deliverability, or flow, of fluids in a potential hydrocarbon reservoir. Common reservoir quality factors include porosity, the volume of a rock that is capable of storing fluids, and permeability, the ability of a rock to transmit fluids. Completion quality typically refers to the extractability of fluids in a potential hydrocarbon reservoir. For example, with respect to hydraulic fracturing, completion quality relates to how well a particular formation can be hydraulically fractured. As reservoir quality and completion quality are often considered when determining whether a given reservoir is a potential hydrocarbon reserve, accurately measuring properties of kerogen can be a valuable resource in hydrocarbon exploration and production.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
In general, in one aspect, one or more embodiments of the present disclosure relates to a method for analyzing a subterranean formation including measuring an electromagnetic spectrum of a rock sample of the subterranean formation using optical spectroscopy, identifying a first kerogen pixel of a plurality of pixels of the electromagnetic spectrum, and analyzing the first kerogen pixel and estimating a property of the first kerogen pixel.
In another aspect, one or more embodiments of the present disclosure relates to a method for analyzing a subterranean formation including measuring a first and a second electromagnetic spectrum of at least one rock sample of the subterranean formation using optical spectroscopy, analyzing a first pixel of the first electromagnetic spectrum and a second pixel of the second electromagnetic, and comparing a spectral intensity of the first pixel to the spectral intensity of the second pixel to determine a kerogen pixel.
In yet another aspect, one or more embodiments of the present disclosure relates to a method for hydraulic fracturing of a subterranean formation including measuring a electromagnetic spectrum of a first rock sample of the subterranean formation using optical spectroscopy, identifying a plurality of kerogen pixels in the electromagnetic spectrum, analyzing the plurality of kerogen pixels and estimating properties of the plurality of kerogen pixels, estimating a property of the subterranean formation based on the properties of the plurality of kerogen pixels, and performing a drilling operation based on the property of the subterranean formation.
Other aspects and advantages of the invention will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

The subject disclosure is further described in the detailed description which follows, in reference to the noted plurality of drawings by way of non-limiting examples of the subject disclosure, in which like reference numerals represent similar parts throughout the several views of the drawings, and wherein:

FIG. 1 illustrates a rock sample in accordance with one or more embodiments of the present disclosure.

FIGS. 2-4 illustrate methods in accordance with one or more embodiments of the present disclosure.

FIG. 5 shows a well operation in accordance with one or more embodiments of the present disclosure.

FIG. 6 shows a computer system in accordance with one or more embodiments of the present disclosure.

DETAILED DESCRIPTION

Embodiments are shown in the above-identified drawings and described below. In describing the embodiments, like or identical reference numerals are used to identify common or similar elements. The drawings are not necessarily to scale and certain features may be shown exaggerated in scale or in schematic in the interest of clarity and conciseness.
While most of the terms used herein will be recognizable to those of skill in the art, it should be understood, however, that when not explicitly defined, terms should be interpreted as adopting a meaning presently accepted by those skilled in the art.
Kerogens are often used to describe the organic matter that naturally occurs in source rock. Different types of kerogen are capable of transforming into hydrocarbons when exposed to heat and pressure. Referring to FIG. 1, an image of a rock sample acquired using a scanning electron microscope technique is shown on a micron scale. In this example, the rock sample 101 includes organic matter 103, which may be, for example, kerogens. In addition, a number of pores 105, easily identified by their dark color (or absence of color), may exist within the organic matter 103, as shown. The concentration or amount of pores within a particular region of kerogen is often referred to kerogen porosity and determining the kerogen porosity of a particular rock may be useful during hydrocarbon exploration.
Measuring properties of kerogen may be beneficial for estimating reservoir quality and completion quality in shales. Traditionally, parameters such as kerogen type and maturity have been believed to vary on the length scale of kilometers or more. However, it is now known from images that porosity of kerogen can vary between grains. For example, as kerogen porosity often increases with maturity, the variability in kerogen porosity between grains only a few microns apart indicate that properties such as maturity may vary on much smaller length scales than previously assumed.
Accordingly, the present disclosure relates to imaging organic matter at the micron length scale using optical spectroscopy. The particulars shown herein are by way of example and for purposes of illustrative discussion of the examples of the subject disclosure only and are presented in the cause of providing what is believed to be the most useful and readily understood description of the principles and conceptual aspects of the subject disclosure. In this regard, no attempt is made to show structural details in more detail than is necessary, the description taken with the drawings making apparent to those skilled in the art how the several forms of the subject disclosure may be embodied in practice. Furthermore, like reference numbers and designations in the various drawings indicate like elements.
Kerogens are typically classified based on the type of organic matter that produced them. Four common classifications are referred to as Type I, Type II, Type III and Type IV. Type I Kerogens are produced mostly from lacustrine-based organic matter (e.g., algae) and are very likely to transform into oil, and Type II Kerogens are produced mostly from a mixture of land-based (e.g., wood) and marine-based organic matter and are likely to transform into oil but may also produce gas or a mixture of both. Type III Kerogens are produced mostly from land-based organic matter and are likely to transform into gas, while Type IV Kerogens are produced mainly from decomposed organic matter and are not likely to generate hydrocarbons.
Over time, kerogens are exposed to environmental and geologic conditions that affect the transformation of kerogen into hydrocarbons. Conditions including geothermal temperatures and pressures as well as the amount of time the kerogen has been exposed to such conditions are often used to determine the maturity of a kerogen. The maturity of kerogen may then be used to determine the ability of a source rock (e.g., shale) to generate hydrocarbons and estimate the potential of future hydrocarbon generation of the source rock.
There are numerous methods that may be used to measure the properties of kerogen. One example is measuring the chemical (e.g., elemental) composition of kerogen, performed on samples of kerogen isolated from shale. These methods are informative, but are time consuming (kerogen isolation may take days or weeks) and do not provide information regarding the spatial distribution of kerogen. Another example is Rock-Eval, which involves a pyrolysis test and provides an extensive array of data without requiring demineralization, but again provides no information on the spatial distribution. A third example is vitrinite reflectance, which can provide spatial resolution as well as kerogen properties, but vitrinite reflectance is manual, time-consuming, and requires a skilled operator.
In general, the methods disclosed herein involve imaging source rock (e.g., shale) with an optical microscope and measuring the electromagnetic spectrum (e.g., ultraviolet spectrum, visible spectrum, and/or near-infrared spectrum) of individual pixels in high resolution (on a scale of approximately one micron). The methods may be performed at a well site or at a remote site in a lab. In addition, the methods may even be performed and/or automated from a remote location (e.g., using a network).
Referring to FIG. 2, a method in accordance with one or more embodiments of the present invention is shown. In one or more embodiments, one or more of the elements shown in FIG. 2 may be omitted, repeated and/or substituted. Accordingly, embodiments of the present disclosure should not be considered limited to the arrangement of elements shown in FIG. 2.
As shown in FIG. 2, a rock sample is obtained at 201. The rock sample may include a drill core, a mined sample, drill cuttings or fragments, an outcrop, or may be downhole. Additionally, the rock sample may be obtained from the field at a well site and may be obtained from a well before, during or after drilling. The rock sample may be in the form of cuttings or fragments obtained from drilling a borehole or the rock sample may be a solid core obtained from coring the formation. In addition, in one or more embodiments, the rock sample may be located downhole (e.g., walls of a borehole drilled through a formation may be used as a core sample), such as when the method is performed downhole. Further, the rock sample may be obtained from a potential hydrocarbon reservoir in a subterranean formation or may be obtained from a hydrocarbon reservoir already in production. The rock sample may be from a source rock (e.g., shale) and may contain organic matter.
During analysis (described below), it may be advantageous to compare results of a number of different rock samples from different locations throughout the subterranean formation. In addition, should a rock sample be unsuitable for use in any embodiment disclosed herein (e.g., due to its size), a second rock sample may then be analyzed. Accordingly, in one or more embodiments, a number of rock samples may be obtained.
At 203, optical spectroscopy is performed on the rock sample obtained at 201. Prior to performing optical spectroscopy, the rock sample may be cleaned to remove any debris, such as, for example, drilling fluid, loose core fragments, and hydrocarbons, among many others. During optical spectroscopy, an electromagnetic spectrum is measured and may be done so using a spectrometer or spectral analyzers, for example. Additionally, in one or more embodiments, optical spectroscopy may be performed using an optical microscope, a transmitted light microscope or any other device known in the art. Further, optically spectroscopy on a micron scale, as discussed herein, may be referred to as optical microscopy. Those having ordinary skill in the art would appreciate that spectroscopy and the methods disclosed herein, may be performed at any scale.
The electromagnetic spectrum may include at least one of an ultraviolet spectrum, a visible spectrum, and a near-infrared spectrum, or any combination thereof. Those having ordinary skill in the art would appreciate that the electromagnetic spectrum may involve any form of electromagnetic radiation known in the art and may include a plurality of wavelengths.
The electromagnetic spectrum measured at 203 may often include a measurement of electromagnetic intensity (or radiation intensity) as a function of wavelength of radiation. Accordingly, in one or more embodiments, when performing optical spectroscopy, a number of wavelengths may be generated by a radiation source. The radiation may then be absorbed, scattered, reflected, and/or refracted by a rock sample. The radiation may then be measured and the intensity measured may vary based on the radiation source as well as the characteristics of the rock sample.
Once an electromagnetic spectrum is obtained, one or more pixels of the electromagnetic spectrum are identified or selected. The one or more pixels may be identified or selected based on spectral properties of the one or more pixels and/or the characteristics of the rock sample. Further, the one or more pixels may be used to identify kerogens or other matter (both organic and non-organic matter) that are included in the rock sample. In addition, or in the alternative, the one or more pixels may be identified based on their position or location. For example, two pixels may be identified for being adjacent each another or for being adjacent to a pixel showing possible kerogen characteristics.
In one or more embodiments, at 207, the pixel identified at 205 may undergo analysis and/or comparison. In one or more embodiments, the pixel may illustrate potential kerogen characteristics and may be referred to as a kerogen pixel. The kerogen pixel may then be identified or selected for later analysis. Additionally, one having ordinary skill would know and appreciate that a plurality of pixels be identified and may undergo analysis and/or comparison.
In some cases, kerogens may absorb radiation and thus, kerogen pixels may exhibit/produce an electromagnetic spectrum having a generally greater absorption (or less reflection) across a wavelength range. In addition, in other cases, kerogen and other organic matter may absorb more radiation at lower wavelengths. Thus, kerogen and other organic pixels may exhibit an electromagnetic spectrum showing a decrease in absorption as wavelength increases.
It is noted that these general trends are not always accurate and therefore the methods described herein should not be limited to the above noted circumstances. Those having ordinary skill in the art will appreciate that the analysis and comparison of one or more pixels should not be limited to the aforementioned examples and trends.
Still referring to 207, two or more pixels may be compared to each other. For example, and similar to the above, kerogens typically absorb radiation for example, and thus, kerogen pixels may exhibit/produce an electromagnetic spectrum having a generally lower intensity across a wavelength range when compared to other pixels.
At 209, a property of the pixel may be estimated from the analysis performed at 207. In one or more embodiments, the electromagnetic spectrum of a kerogen pixel may be analyzed. Once the electromagnetic spectrum of a kerogen pixel is analyzed, properties such as kerogen type and kerogen maturity may be estimated. The kerogen pixel may be analyzed by any means known in the art. For example, maturity of a kerogen may impact whether producible hydrocarbons are likely to be found and/or likely to produce oil or gas. Additionally, maturity of kerogen may correlate to whether the kerogen grains will be porous and/or permeable. Further, kerogen composition may be used to determined mechanical properties (such as ductility and brittleness) of the kerogen. Mechanical properties may then be used to determine completion quality.
In one or more embodiments, estimation of a property of two or more pixels may be performed. In particular, a first and a second pixel may be identified and analyzed and one or more properties of each pixel may be estimated. At 211, one or more properties of the first and second pixels may be compared each other to determine a variation in the properties between each pixel. Variation in the properties of the first and second pixel may be used to analyze other pixels.
In addition, variation in the properties of the first and the second pixel may also be used to analyze other properties of the first and the second pixel. For example, in one or more embodiments, kerogen type may be estimated for a first and a second pixel. The kerogen type of each pixel may be compared to another property of the pixels, such as maturity, for example. Analysis of comparing the kerogen types of the first and the second pixels may then be used to determine the maturity of each pixel. In another embodiment, analysis of comparing the kerogen types of the first and the second pixels may then be used to determine the kerogen type of other pixels. For example, comparing two or more kerogen pixels to each other may provide information relating to whether the kerogen contained in the sample is a single kerogen type or a mixture of two or more types of kerogen. Knowing whether or not there is one or more types of kerogen may be advantageous as the information can then be used to interpret and/or simplify other measurements.
In one or more embodiments, a kerogen pixel and a pixel adjacent the kerogen pixel may be analyzed. The pixel adjacent the kerogen pixel may exhibit organic or non-organic characteristics and the properties of the adjacent pixel may be estimated. The estimated properties of the adjacent pixel may then be used to determine the effect of organic and/or non-organic matter on the adjacent kerogen. For example, the estimated properties of the adjacent pixel may be used to determine the effect of organic and/or non-organic matter on properties of the kerogen. The analysis may also be used and applied to other pixels having similar kerogen properties adjacent organic and/or non-organic matter.
At 213, the reservoir quality may be estimated. As discussed above, reservoir quality typically refers to the factors or parameters that affect the amount and deliverability, or flow, of fluids in a potential hydrocarbon reservoir. Common reservoir quality factors include porosity, the volume of a rock that is capable of storing fluids, and permeability, the ability of a rock to transmit fluids. Estimating the reservoir quality may be performed using the estimated property of one or more pixels. In addition, reservoir quality may be estimated using the variation in pixels, for example, as determined at 211. Reservoir quality may then be considered to determine whether the subterranean formation from which the core sample was obtained is a potential hydrocarbon reserve.
Similarly, at 215, the completion quality may be estimated. As discussed above, completion quality typically refers to the extractability of fluids in a potential hydrocarbon reservoir. Estimating the completion quality may be performed using the estimated property of one or more pixels. In addition, completion quality may be estimated using the variation in pixels, for example, as determined at 211. Completion quality may then be considered to determine whether the subterranean formation from which the core sample was obtained is a potential hydrocarbon reserve.
Referring now to FIG. 3, a method in accordance with one or more embodiments of the present invention is shown. In one or more embodiments, one or more of the elements shown in FIG. 3 may be omitted, repeated and/or substituted. Accordingly, embodiments of the present disclosure should not be considered limited to the arrangement of elements shown in FIG. 3.
As shown in FIG. 3, a rock sample is obtained at 301. Similar to the above, the rock sample may include a drill core, a mined sample, drill cuttings or fragments, an outcrop, or may be downhole. Additionally, the rock sample may be obtained from the field at a well site and may be obtained from a well before, during or after drilling. The rock sample may be in the form of cuttings or fragments obtained from drilling a borehole or the rock sample may be a solid core obtained from coring the formation. In addition, in one or more embodiments, the rock sample may be located downhole (e.g., walls of a borehole drilled through a formation may be used as a core sample), such as when the method is performed downhole. Further, the rock sample may be obtained from a potential hydrocarbon reservoir in a subterranean formation or may be obtained from a hydrocarbon reservoir already in production. The rock sample may be from a source rock (e.g., shale) and may contain organic matter.
As discussed above, it may be advantageous to compare results of a number of different rock samples obtained from different locations throughout the subterranean formation. In addition, should a rock sample be unsuitable for use in any of the elements disclosed herein (e.g., due to its size), a second rock sample may then be analyzed. Accordingly, in one or more embodiments, a number of rock samples may be obtained.
At 303, optical spectroscopy is performed on the rock sample obtained at 301. Prior to performing optical spectroscopy, the rock sample may be cleaned to remove any debris, such as, for example, drilling fluid, loose core fragments, and hydrocarbons, among many others. For this example, multiple spectra are obtained at 303. For illustrative purposes only and for simplicity, a first and a second spectrum will be used when describing FIG. 3.
In one or more embodiments, a first and a second electromagnetic spectrum may be measured using one of the above mentioned techniques or by using any other technique in the art. Here, the first electromagnetic spectrum measured may be one of an ultraviolet spectrum, a visible spectrum, and a near-infrared spectrum, while the second electromagnetic spectrum measured may be the other of an ultraviolet spectrum, a visible spectrum, and a near-infrared spectrum. Those having ordinary skill in the art would appreciate that the electromagnetic spectrum may involve any form of electromagnetic radiation known in the art and may include a plurality of wavelengths.
Once the first and second electromagnetic spectrums area obtained, at 305, a first pixel from the first electromagnetic spectrum and a second pixel from the second electromagnetic spectrum are identified and analyzed, the second pixel corresponding to the first pixel. The first and second pixels may be used to identify kerogens or other matter (both organic and non-organic matter) that make up the rock sample.
In one or more embodiments, at 307, the intensities of the first pixel measured during optical spectroscopy may be compared to the intensities of the second pixel. The first and second pixels are compared to determine if the pixel exhibits characteristics of a kerogen. For example, kerogen and other organic matter may absorb more radiation at lower wavelengths. Thus, kerogen and other organic pixels may exhibit an electromagnetic spectrum showing a decrease in intensity as the wavelength decreases. As the first and second spectra were measured based on different wavelengths of light, by comparing the spectra of the first and the second pixel, a kerogen pixel may be determined.
Once a kerogen pixel is determined, the kerogen pixel may be analyzed and a property of the kerogen may be estimated at 309 using any technique known in the art. Once the electromagnetic spectrum of a kerogen pixel is analyzed, properties such as kerogen type and kerogen maturity may be estimated. For example, maturity of a kerogen may impact whether producible hydrocarbons are likely to be found and/or likely to produce oil or gas. Additionally, maturity of kerogen may correlate to whether the kerogen grains will be porous and/or permeable. Further, kerogen composition may be used to determined mechanical properties (such as ductility and brittleness) of the kerogen. Mechanical properties may then be used to determine completion quality.
At 311, the reservoir and/or completion quality may be estimated. As discussed above, reservoir quality typically refers to the factors or parameters that affect the amount and deliverability, or flow, of fluids in a potential hydrocarbon reservoir. Common reservoir quality factors include porosity, the volume of a rock that is capable of storing fluids, and permeability, the ability of a rock to transmit fluids. Similarly, completion quality typically refers to the extractability of fluids in a potential hydrocarbon reservoir. Reservoir and/or completion quality may then be considered to determine whether the subterranean formation from which the core sample was obtained is a potential hydrocarbon reserve.
Referring now to FIG. 4, a method in accordance with one or more embodiments of the present invention is shown. In one or more embodiments, one or more of the elements shown in FIG. 4 may be omitted, repeated and/or substituted. Accordingly, embodiments of the present disclosure should not be considered limited to the arrangement of elements shown in FIG. 4.
As shown in FIG. 4, a rock sample is obtained at 401. Similar to the above, the rock sample may include a drill core, a mined sample, drill cuttings or fragments, an outcrop, or may be downhole. Additionally, the rock sample may be obtained from the field at a well site and may be obtained from a well before, during or after drilling. The rock sample may be in the form of cuttings or fragments obtained from drilling a borehole or the rock sample may be a solid core obtained from coring the formation. In addition, in one or more embodiments, the rock sample may be located downhole (e.g., walls of a borehole drilled through a formation may be used as a core sample), such as when the method is performed downhole. Further, the rock sample may be obtained from a potential hydrocarbon reservoir in a subterranean formation or may be obtained from a hydrocarbon reservoir already in production. The rock sample may be from a source rock (e.g., shale) and may contain organic matter.
In addition, optical spectroscopy is performed on the rock sample. Prior to performing optical spectroscopy, the rock sample may be cleaned to remove any debris, such as, for example, drilling fluid, loose core fragments, and hydrocarbons, among many others. In one or more embodiments, a first electromagnetic spectrum may be measured using one of the above mentioned techniques or by using any other technique in the art. Here, the first electromagnetic spectrum measured may be any one of an ultraviolet spectrum, a visible spectrum, and a near-infrared spectrum, or any combination thereof. Those having ordinary skill in the art would appreciate that the electromagnetic spectrum may involve any form of electromagnetic radiation known in the art and may include a plurality of wavelengths.
Once the first electromagnetic spectrum is obtained, at 403, a plurality of pixels is identified and one or more of their corresponding properties estimated. Similar to the above, the intensities of the plurality of pixels may be measured during optical spectroscopy and the pixels may be analyzed to estimate properties of the plurality of pixels.
At 405, a property of the formation may be estimated based on the properties estimated of the plurality of pixels. In some embodiments the property of the formation may be one of reservoir quality and completion quality. As discussed above, reservoir quality typically refers to the factors or parameters that affect the amount and deliverability, or flow, of fluids in a potential hydrocarbon reservoir. Common reservoir quality factors include porosity, the volume of a rock that is capable of storing fluids, and permeability, the ability of a rock to transmit fluids. Similarly, completion quality typically refers to the extractability of fluids in a potential hydrocarbon reservoir. Based on the formation property, an oilfield operation may be performed. Oilfield operation may include drilling and fracturing. Those having ordinary skill in the art would appreciate that many other oilfield operation may be considered without departing from the scope of the present disclosure.
At 407, a second rock sample is obtained similar to the above first rock sample. Here, however, it may be advantageous to obtain the second rock sample at a location in the subterranean formation that is different from the first rock sample. For example, the second rock sample may be obtained a depth different from the first rock sample. As discussed above at 401, optical spectroscopy is then performed on the rock sample.
Similar to 403, at 409 a plurality of pixels is identified and one or more of their corresponding properties estimated. Similar to the above, the intensities of the plurality of pixels may be measured during optical spectroscopy and the pixels may be analyzed to estimate properties of the plurality of pixels.
At 411, a property of the formation may be estimated based on the properties estimated of the plurality of pixels at 409. In some embodiments the property of the formation may be one of reservoir quality and completion quality. Based on the formation property, an operating parameter may be modified. During a hydraulic fracturing operation, for example, operating parameters may include injection rate, injection pressure, fluid viscosity, fluid composition and fluid density. Those having ordinary skill in the art would appreciate that many other downhole operation parameters may be considered without departing from the scope of the present disclosure. Using the modified operating parameter obtained at 411, a downhole operation may be performed at 413. The downhole operation at 413 may be different than the operation performed at 405 in order to correspond with the modified operating parameter based on the property of the formation obtained from the second core sample.
Referring now to FIG. 5, a schematic view, partially in cross section, of a field 500 in which one or more embodiments of the present disclosure may be implemented is shown. In one or more embodiments, one or more of the modules and elements shown in FIG. 5 may be omitted, repeated and/or substituted. Accordingly, embodiments of the logging and analysis disclosed herein should not be considered limited to the specific arrangements of modules shown in FIG. 5.
As shown in FIG. 5, the subterranean formation 506 includes several geological structures. As shown, the formation has a sandstone layer 506A, a limestone layer 506B, a shale layer 506C, and a sand layer 506D. In one or more embodiments, various survey tools and/or data acquisition tools may be adapted to perform a portion or the entirety of one or more of the methods disclosed herein.
As shown in FIG. 5, the wellsite 505 includes a rig 501, a borehole 503 and a surface unit 504. In one or more embodiments, surface unit 504 may be located at the wellsite 505 and/or remote locations. The surface unit 504 may be provided with computer facilities for receiving, storing, processing and/or analyzing data from data acquisition tools disposed in the borehole 503, or other part of the field 500.
In one or more embodiments, a measuring equipment 502 may be installed on a bottom hole assembly (BHA) or a wireline in the borehole 503. The surface unit 504 may be configured to communicate with measuring equipment 502 and may receive data therefrom. In one or more embodiments, measuring equipment 502 may measure an electromagnetic spectrum of the formation 506, any layer of the formation (506A-506D), and/or a sample of the formation surrounding the borehole 503 by performing optical spectroscopy. In one or more embodiments, the electromagnetic spectrum may be measured using one of the above mentioned techniques or by using any other technique in the art. The electromagnetic spectrum measured may be any one of an ultraviolet spectrum, a visible spectrum, and a near-infrared spectrum, or any combination thereof. Those having ordinary skill in the art would appreciate that the electromagnetic spectrum may involve any form of electromagnetic radiation known in the art and may include a plurality of wavelengths.
Once the electromagnetic spectrum is measured, one or more pixels are identified and one or more of their corresponding properties estimated. Similar to the above, the intensities of the one or more pixels may be measured during optical spectroscopy and the one or more pixels may be analyzed to estimate properties of the one or more pixels.
Additionally, a property of the formation may be estimated based on the properties estimated of the one or more pixels. In some embodiments the property of the formation may be one of reservoir quality and completion quality. As discussed above, reservoir quality typically refers to the factors or parameters that affect the amount and deliverability, or flow, of fluids in a potential hydrocarbon reservoir. Common reservoir quality factors include porosity, the volume of a rock that is capable of storing fluids, and permeability, the ability of a rock to transmit fluids. Similarly, completion quality typically refers to the extractability of fluids in a potential hydrocarbon reservoir. Based on the formation property, an oilfield operation may be performed. Oilfield operation may include drilling and fracturing. Those having ordinary skill in the art would appreciate that many other oilfield operation may be considered without departing from the scope of the present disclosure.
In some cases, the measuring unit 502 may perform optical spectroscopy and analysis in accordance with one or more embodiments of the present disclosure at a location within the formation 506 continuously and/or at multiple depths or intervals along the borehole 503. Thus, formation properties may also be estimated continuously or at multiple depths. Based on the formation property, an operating parameter may be modified. During a hydraulic fracturing operation, for example, operating parameters may include injection rate, injection pressure, fluid viscosity, fluid composition and fluid density. Those having ordinary skill in the art would appreciate that many other downhole operation parameters may be considered without departing from the scope of the present disclosure. The modified operating parameter may then be transmitted from the measuring equipment 502 to the surface unit 504 and a downhole operation may be performed based on the estimated property of the formation.
Furthermore, although the estimation of a formation property was described herein as being performed by the measuring unit 502, in one or more embodiments, estimation may be performed by the surface unit 504. For example, in some cases, the measuring unit 502 may transmit information or data acquired while downhole to the surface unit 504. The surface unit 504 may then perform any portion of any one or more methods disclosed herein in order to determine one or more formation parameters. Further, the surface unit 504 may then transmit one or more operating parameters downhole based on the estimated formation parameter.
Embodiments of formation estimation may be implemented on virtually any type of computer regardless of the platform being used. For instance, as shown in FIG. 6, a computer system (600) includes one or more processor(s) (602) such as a central processing unit (CPU) or other hardware processor, associated memory (605) (e.g., random access memory (RAM), cache memory, flash memory, etc.), a storage device (606) (e.g., a hard disk, an optical drive such as a compact disk drive or digital video disk (DVD) drive, a flash memory stick, etc.), and numerous other elements and functionalities typical of today's computers (not shown). The computer (600) may also include input means, such as a keyboard (608), a mouse (610) or a microphone (not shown). Further, the computer (600) may include output means, such as a monitor (612) (e.g., a liquid crystal display LCD, a plasma display or cathode ray tube (CRT) monitor). The computer system (600) may be connected to a network (615) (e.g., a local area network (LAN), a wide area network (WAN) such as the Internet, or any other similar type of network) via a network interface connection (not shown). Those skilled in the art will appreciate that many different types of computer systems exist (e.g., workstation, desktop computer, a laptop computer, a personal media device, a mobile device, such as a cell phone or personal digital assistant, or any other computing system capable of executing computer readable instructions), and the aforementioned input and output means may take other forms, now known or later developed. Generally speaking, the computer system (600) includes at least the minimal processing, input and/or output means necessary to practice one or more embodiments.
Further, those skilled in the art will appreciate that one or more elements of the aforementioned computer system (600) may be located at a remote location and connected to the other elements over a network. Further, one or more embodiments may be implemented on a distributed system having a plurality of nodes, where each portion of the implementation may be located on a different node within the distributed system. In one or more embodiments, the node corresponds to a computer system. Alternatively, the node may correspond to a processor with associated physical memory. The node may alternatively correspond to a processor with shared memory and/or resources. Further, software instructions to perform one or more embodiments may be stored on a computer readable medium such as a compact disc (CD), a diskette, a tape or any other computer readable storage device.
Using one or more methods disclosed herein, properties of kerogen may be measured with a spatial resolution of approximately one micron. The methods disclosed herein are more efficient than traditional methods and do not typically require a skilled operator. Additionally, the methods may be automated and may be done so quickly.
While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims. Moreover, embodiments described herein may be practiced in the absence of any element that is not specifically disclosed herein.
In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Claims

What is claimed:

1. A method for analyzing a subterranean formation comprising:

measuring an electromagnetic spectrum of a rock sample of the subterranean formation using optical spectroscopy;

identifying a first kerogen pixel of a plurality of pixels of the electromagnetic spectrum; and

analyzing the first kerogen pixel and estimating a property of the first kerogen pixel.

2. The method of claim 1, wherein the rock sample is at least one selected from the group consisting of a core, a cutting, an outcrop, a mined sample, and downhole.

3. The method of claim 1, wherein identifying further comprises:

measuring a spectral intensity of a first pixel and a second pixel of the plurality of pixels of the electromagnetic spectrum; and

comparing the spectral intensity of the first pixel and the second pixel to determine the first kerogen pixel.

4. The method of claim 1, wherein the electromagnetic spectrum comprises at least one selected from the group consisting of an ultraviolet electromagnetic spectrum, a visible electromagnetic spectrum, and a near-infrared electromagnetic spectrum.

5. The method of claim 1, wherein the electromagnetic spectrum comprises a plurality of wavelengths.

6. The method of claim 1, wherein the property of the first kerogen pixel is at least one selected from the group consisting of kerogen type and kerogen maturity.

7. The method of claim 1 further comprising:

estimating at least one selected from the group consisting of reservoir quality and completion quality of the subterranean formation based on the property of the first kerogen pixel.

8. The method of claim 1 further comprising:

identifying a second kerogen pixel;

analyzing the second kerogen pixel and estimating a property of the second kerogen pixel; and

comparing the first kerogen pixel to the second kerogen pixel to determine a property variation between the first and second kerogen pixels.

9. The method of claim 8, wherein comparing further comprises:

identifying an adjacent pixel that is adjacent the first kerogen pixel and having a composition different than the first kerogen pixel; and

comparing the second kerogen pixel to the first kerogen pixel to determine an effect of the adjacent pixel on the property variation between the first kerogen pixel and the second kerogen pixel.

10. The method of claim 8, wherein comparing further comprises:

determining a first kerogen type of the first kerogen pixel and a second kerogen type of the second kerogen pixel; and

comparing the first kerogen type to the second kerogen type to determine an effect of kerogen type on the property variation between the first kerogen pixel and the second kerogen pixel.

11. The method of claim 8, wherein the property variation is at least one selected from the group consisting of maturity variation and type variation.

12. A method for analyzing a subterranean formation comprising:

measuring a first and a second electromagnetic spectrum of at least one rock sample of the subterranean formation using optical spectroscopy;

analyzing a first pixel of the first electromagnetic spectrum and a second pixel of the second electromagnetic; and

comparing a spectral intensity of the first pixel to the spectral intensity of the second pixel to determine a kerogen pixel.

13. The method of claim 12, wherein the first electromagnetic spectrum is at least one selected from the group consisting of an ultraviolet electromagnetic spectrum, a visible electromagnetic spectrum, and a near-infrared electromagnetic spectrum and the second electromagnetic spectrum is the other of the ultraviolet electromagnetic spectrum, the visible electromagnetic spectrum, and the near-infrared electromagnetic spectrum.

14. The method of claim 12, wherein the kerogen pixel is determined by identifying an increase in absorption of either the first or the second pixel when wavelength decreases.

15. The method of claim 12 further comprising:

analyzing the kerogen pixel and estimating a property of the kerogen, wherein the property of the kerogen is at least one selected from the group consisting of kerogen type and kerogen maturity.

16. The method of claim 12 further comprising:

estimating at least one selected from the group consisting of reservoir quality and completion quality of the subterranean formation based on the property of the kerogen.

17. A method for hydraulic fracturing of a subterranean formation comprising:

measuring a electromagnetic spectrum of a first rock sample of the subterranean formation using optical spectroscopy;

identifying a plurality of kerogen pixels in the electromagnetic spectrum;

analyzing the plurality of kerogen pixels and estimating properties of the plurality of kerogen pixels;

estimating a property of the subterranean formation based on the properties of the plurality of kerogen pixels; and

performing a drilling operation based on the property of the subterranean formation.

18. The method of claim 17, wherein the property of the subterranean formation is at least one selected from the group consisting of reservoir quality and completion quality.

19. The method of claim 17, wherein the properties of the plurality of kerogen pixels is at least one selected from the group consisting kerogen type and kerogen maturity.

20. The method of claim 17 further comprising:

measuring a second electromagnetic spectrum of a second rock sample of the subterranean formation using optical spectroscopy;

identifying a second plurality of kerogen pixels in the second electromagnetic spectrum;

analyzing the second plurality of kerogen pixels and estimating properties of the second plurality of kerogen pixels;

estimating a second property of the subterranean formation based on the properties of the second plurality of kerogen pixels;

modifying an operating parameter based on a comparison the second property to the first property of the subterranean formation; and

performing a downhole operation based on the modified operating parameter.

21. The method of claim 20, wherein the second rock sample occurs at a depth different that the first rock sample.

22. The method of claim 20, wherein the operating parameter is at least one selected from the group consisting of injection rate, injection pressure, fluid viscosity, fluid composition, and fluid density.