US20130056201A1

US20130056201A1 - Method for evaluating hydrocarbon-containing subterrean formations penetrated by a directional wellbore

Info

Publication number: US20130056201A1
Application number: US13/224,566
Authority: US
Inventors: William David Chandler, JR.
Original assignee: LATERAL EXPLORATION LABS
Current assignee: LATERAL EXPLORATION LABS
Priority date: 2011-09-02
Filing date: 2011-09-02
Publication date: 2013-03-07

Abstract

A method of evaluating a hydrocarbon-containing subterranean formation to identify potentially productive zones within the formation. The method may be particularly useful for evaluating formations penetrated by at least one directionally drilled wellbore. The method can include releasing, capturing, and measuring at least one property related to the hydrocarbon materials entrapped in rock samples obtained from the formation, and the results of the analysis can be used to perform at least one wellbore-related activity, such as drilling, stimulating, and/or producing a new or existing wellbore.

Description

BACKGROUND

1. Field
This invention relates to systems and methods for evaluating potentially productive zones within a hydrocarbon-containing subterranean formation.
2. Related Art
The use of directional, or non-vertical, wells to produce hydrocarbon from subterranean formations has gained prominence over the last several years. Directional drilling minimizes surface disruptions and opens access to untapped reserves in previously inaccessible underground formations, such as, for example, formations located under bodies of water, formations located proximate heavily populated or developed areas, and formations located in environmentally-sensitive regions. Directionally drilled wells provide a more targeted approach to accessing productive areas of a formation by maximizing the length of wellbore penetration through hydrocarbon-rich areas to thereby enhance production of hydrocarbon from the well.
Despite the benefits, much work remains to be done to improve and optimize methods for evaluating, stimulating, and producing directional wells. For example, in contrast to conventional wells, which can be vertically drilled via gravity-driven tools, directionally-drilled wells typically require the use of highly specialized, self-driven equipment capable of drilling through underground formations in a non-vertical direction. As a result, directional drilling tends to be a slower and more expensive process than conventional vertical drilling. For similar reasons, the tools and methods used to evaluate vertically-drilled wells (e.g., electric, acoustic, and nuclear wirelines and associated logs) have not yet been successfully implemented on a wide scale to evaluate formations penetrated by directionally-drilled wells. Thus, in the absence of reliable data indicating potentially productive zones within a formation of interest, drillers and producers of directional wells typically opt to stimulate the entire formation along the length of a wellbore—including both productive and non-productive zones—at a higher cost and greater degree of inefficiency.
Accordingly, there is a need for improved methods for evaluating hydrocarbon-containing formations, particularly those penetrated by one or more directionally-drilled wellbores, in order to identify potentially productive zones within a subterranean formation.

SUMMARY

One embodiment of the present invention concerns a method for identifying a productive zone within a hydrocarbon-containing subterranean formation. The method includes the following steps: (a) receiving a plurality of rock samples removed from a wellbore penetrating the hydrocarbon-containing subterranean formation, wherein at least a portion of the rock samples comprise entrapped hydrocarbon materials; (b) reducing the average particle size of at least a portion of the rock samples to thereby release at least a portion of the entrapped hydrocarbon materials; (c) capturing at least a portion of the entrapped hydrocarbon materials released in step (b); (d) measuring at least one property of the entrapped hydrocarbon materials captured in step (c) to thereby obtain a set of results; and (e) organizing the set of results obtained via the measuring of step (d). The organized set of data may then be used to carry out at least one wellbore-related activity.
Another embodiment of the present invention concerns a method for producing hydrocarbon from a hydrocarbon-containing subterranean formation. The method comprises the following steps: (a) drilling a directional wellbore into the hydrocarbon-containing subterranean formation; (b) obtaining a plurality of rock samples via the wellbore, wherein at least a portion of the rock samples comprise entrapped hydrocarbon materials; (c) analyzing at least a portion of the rock samples obtained in step (b), wherein the analyzing includes obtaining a set of results related to the entrapped hydrocarbon materials; and (d) based, at least in part, on the set of results obtained via the analyzing of step (c), performing at least one wellbore-related activity. The well-bore related activity may be selected from the group consisting of group consisting of continuing to drill the wellbore, drilling one or more new wellbores into the subterranean formation, drilling one or more new wellbores into a different subterranean formation, stimulating production of hydrocarbon from the formation, initiating or changing production of hydrocarbon from the wellbore or from one or more other wellbores, and combinations thereof.
Yet another embodiment of the present invention concerns a method for identifying a productive zone within in a hydrocarbon-containing subterranean formation. The method comprises the following steps: (a) receiving a plurality of rock samples removed from a wellbore penetrating the hydrocarbon-containing formation, wherein at least a portion of the rock samples comprise entrapped hydrocarbon materials and have a particle size distribution such that less than 20 weight percent of the rock samples have an average particle size less than 350 microns; (b) grinding at least a portion of the rock samples to provide crushed rock samples, wherein the crushed rock samples have a particle size distribution such that at least 25 weight percent of the crushed rock samples have an average particle size of less than 350 microns; (c) capturing at least a portion of the entrapped hydrocarbon materials released in step (b); (d) measuring at least one property of the entrapped hydrocarbon materials captured in step (c), wherein the analyzing includes using a gas detection or gas analysis device to obtain a set of data, wherein the set of data includes one or more values for a property related to the entrapped hydrocarbon materials, wherein the property relates at least one of the presence, the amount, and the composition of the entrapped hydrocarbon materials; and (e) organizing the set of data obtained via the analyzing of step (d). The organized set of data may then be used to carry out at least one wellbore-related activity.
This summary is provided to introduce a selection of concepts in a simplified form that are further described below in the detailed description. This summary is not intended to identify key features or essential features of the claimed subject matter, nor is it intended to be used to limit the scope of the claimed subject matter. Other aspects and advantages of the present invention will be apparent from the following detailed description of the preferred embodiments and the accompanying drawing figures.

BRIEF DESCRIPTION OF THE DRAWINGS

Various embodiments of the present invention are described in detail below with reference to the attached drawing figures, wherein:

FIG. 1 is a schematic depiction of a drilling system that includes a directional wellbore penetrating a hydrocarbon-containing subterranean formation according to one embodiment of the present invention;

FIG. 2 a is a flowchart representing the major steps involved in a method for evaluating a hydrocarbon-containing formation as generally depicted in FIG. 1 in accordance with one embodiment of the present invention; and

FIG. 2 b is a flowchart representing the major sub-steps involved in the analyzing step of the method for evaluating a hydrocarbon-containing formation depicted in the flowchart of FIG. 2 a in accordance with one embodiment of the present invention.

The drawing figures do not limit the present invention to the specific embodiments disclosed and described herein. The drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating the principles of the invention.

DETAILED DESCRIPTION

The following detailed description of the invention references the accompanying drawings that illustrate specific embodiments or particular aspects of the present invention. The embodiments are intended to describe aspects of the invention in sufficient detail to enable those skilled in the art to practice the invention. Other embodiments can be utilized and changes can be made without departing from the scope of the present invention. The following detailed description is, therefore, not to be taken in a limiting sense. The scope of the present invention is defined only by the appended claims, along with the full scope of equivalents to which such claims are entitled.
In this description, references to “one embodiment,” “an embodiment,” or “embodiments” mean that the feature or features being referred to are included in at least one embodiment of the technology. Separate references to “one embodiment,” “an embodiment”, or “embodiments” in this description do not necessarily refer to the same embodiment and are also not mutually exclusive unless so stated and/or except as will be readily apparent to those skilled in the art from the description. For example, a feature, structure, act, etc., described in one embodiment may also be included in other embodiments, but is not necessarily included. Thus, the present technology can include a variety of combinations and/or integrations of the embodiments described herein.

Evaluation of a Subterranean Formation Surrounding a Wellbore

According to one embodiment of the present invention, a method for evaluating a hydrocarbon-containing subterranean formation is provided. In some embodiments, the present invention can be utilized to identify one or more zones within a formation that have a high likelihood of producing hydrocarbon materials (i.e., productive zones). Rock samples obtained from one or more wellbores penetrating the formation can be analyzed, and the results of the analysis can subsequently be used to perform a wellbore-related activity, such as drilling and/or stimulating production of hydrocarbon from one or more wells. In some embodiments, the methods described herein may be particularly useful in evaluating subterranean formations penetrated by at least one directional (i.e., non-vertical) wellbore. Additional embodiments and details will now be discussed in detail, with reference to the Figures.
Turning now to FIG. 1, a schematic view of a drilling system 110 that includes at least one wellbore 130 penetrating a layered subterranean formation 120 is provided. In one embodiment depicted in FIG. 1, layered subterranean formation 120 can be positioned under a land surface 122, such that drilling system 110 is an “onshore” drilling system. In another embodiment, the subterranean formation may be positioned under an oceanic body of water (not shown in FIG. 1), such that the drilling system can be an “offshore” drilling system. Although generally described herein with reference to drilling system 110 as depicted in FIG. 1, it should be understood that the methods of the present invention have wide application to multiple aspects of the exploration, evaluation, stimulation, and production of various types of hydrocarbon-containing formations, as will be described in detail shortly.
The layers of formation 120 can comprise any suitable type of rock, including, for example, one or more types of sedimentary rock. Formation 120 can be a reservoir rock formation, a source rock formation, or can include multiple layers of both reservoir and source rock. As used herein, the term “source rock” refers to subterranean rock from which one or more hydrocarbon materials originated. Examples of specific types of source rock can include, but are not limited to, shales and claystones, as well as tar or oil sands. As used herein, the term “reservoir rock” refers to subterranean rock to which one or more hydrocarbon materials has migrated and in which hydrocarbon material is stored. Examples of specific types of reservoir rock can include, but are not limited to, limestones, sandstones, carbonates, dolomites, anhydrides, granite-washed rocks, and various types of sand.
In some embodiments, the individual layers of formation 120 can have a substantially similar porosity and/or permeability, while, in other embodiments, the values of one or both of these parameters can vary substantially amongst the various layers of formation 120. In one embodiment, the average porosity of formation 120, measured in at least one layer proximate wellbore 130, can be at least about 5 percent, at least about 10 percent, or at least about 15 percent and/or not more than about 60 percent, not more than about 50 percent, or not more than about 40 percent. In the same or other embodiments, formation 120 can have an average permeability of at least about 1 millidarcy, at least about 5 millidarcys, at least about 20 millidarcys, or at least about 30 millidarcys and/or not more than about 3000 millidarcys, not more than about 2500 millidarcys, not more than 2000 millidarcys, or not more than 1500 millidarcys. The values for porosity and/or permeability above can refer to the average value for a specific layer of formation 120 or to a composite value for two or more layers, as measured according to standard methods.
Formation 120 can comprise one or more areas or regions comprising at least one type of hydrocarbon material, such as natural gas, natural gas liquids (or condensate), crude oil, and combinations thereof. As used herein, the term “natural gas” refers to a mixture of hydrocarbon compounds wherein at least about 75 volume percent of the hydrocarbon molecules present comprise between 1 and 4 carbon atoms per molecule. As used herein, the term “natural gas liquids” or “condensate” refers to a mixture of hydrocarbon compounds wherein at least about 75 volume percent of the hydrocarbon molecules present comprise between 5 and 8 carbon atoms per molecule. As used herein, the term “crude oil” refers a mixture of hydrocarbon compounds wherein at least about 75 volume percent of the hydrocarbon molecules present comprise at least 9 carbon atoms per molecule. Formation 120 can include a single type of hydrocarbon or can include two or more different hydrocarbon materials. For example, in some embodiments wherein formation 120 includes mixtures of natural gas, condensate, and/or crude oil, the mixture can comprise at least about 50 volume percent, at least about 60 volume percent, at least about 75 volume percent, or at least 90 volume percent natural gas, with the remainder of the hydrocarbon material (if any) comprising condensate and/or crude oil. The hydrocarbon materials within the formation can also include one or more other compounds, such as water, carbon dioxide, various sulfur-containing compounds, and the like, which may be removed from the hydrocarbon material subsequent to its production from the formation but prior to its final use.
As shown in FIG. 1, drilling system 110 can comprise at least one wellbore 130 that penetrates at least one layer of formation 120. Wellbore 130 can be any type of wellbore. In some embodiments, wellbore can be a directional wellbore, as generally illustrated in FIG. 1. As used herein, the terms “directionally-drilled wellbore” and “directional wellbore” refer to a wellbore that penetrates one or more layers of a subterranean formation at a substantially non-vertical angle. In some embodiments, wellbore 130 can have an angle of inclination (measured from the vertical) of at least about 40°, at least about 50°, at least about 65°, or at least about 75°. In other embodiments (not shown in FIG. 1), the directional wellbore can be a horizontal wellbore having an angle of inclination in the range of from 80° to 100° or from 85° to 95° and/or a lateral wellbore that extends at an angle of inclination in the range of from 75° to 105° or 85° to 95° from a vertically-oriented primary or mother borehole.
As discussed above, embodiments of the present invention provide methods for evaluating a hydrocarbon-containing subterranean formation to identify, and subsequently produce hydrocarbon from, one or more productive zones within the formation. Turning now to FIG. 2 a, a flowchart representing the major steps of a method 200 for evaluating a hydrocarbon-containing formation according to one embodiment of the present invention is provided. In some alternative embodiments, the steps noted in the various blocks may occur out of the order specifically depicted in FIG. 2 a. For example, two blocks shown in succession in FIG. 2 a may sometimes be executed in the reverse order depending upon the functionality involved.
As shown in FIG. 2 a, method 200 may comprise the step of drilling a wellbore into a hydrocarbon-containing formation, as depicted by block 210. This step can be accomplished by utilizing one or more known drilling techniques and may be carried out using any suitable type of equipment. According to one embodiment, drilling step 210 can comprise drilling a directional wellbore, as discussed in detail above, and may be carried out for exploratory and/or production purposes. Drilling step 210 can be accomplished with any suitable drilling system, including the exemplary drilling system 110 depicted in FIG. 1. According to the embodiment depicted in FIG. 1, drilling system 110 can include a circulation system 150 for removing at least a portion of the drill cuttings from wellbore 130 with a drilling fluid. Suitable types of drilling fluids can include water-based and oil-based drilling fluids comprising various types of natural and/or synthetic components. Selection of a particular drilling fluid may depend, at least in part, on the type of rock within formation 120.
As illustrated in FIG. 1, circulation system 150 may comprise a fluid removal conduit 152 for transporting the cuttings-laden drilling fluid from wellbore 130 to a separation device 154. Separation device 154 can be any device operable to separate the fragmented rock cuttings from the drilling fluid. In one embodiment, separation device 154 can comprise a shale shaker operable to discharge the drill cuttings into a retention or reserve pond 156 and operable to recycle the drilling fluid back to the drill string (not shown in FIG. 1) lowered into wellbore 130 via a fluid return conduit (also not shown in FIG. 1). Drilling step 210 may also include a variety of other related activities, such as, for example, installing and/or removing various types of casing and other related steps. The type and number of these additional steps may depend, at least in part, on the specific type of rock penetrated by the wellbore and/or ultimate purpose (e.g., exploration or production) of the completed wellbore.
Turning back to FIG. 2 a, the method 200 can also comprise the step of obtaining a plurality of rock samples from the wellbore, as depicted by block 220. Obtaining step 220 can include removing a core sample from an exploratory or production well or collecting at least a portion of the drill cuttings removed from the drilling fluid, as described previously with respect to circulation system 150 shown in FIG. 1. In one embodiment of the present invention, drilling step 210 and obtaining step 220 can be carried out at substantially the same time, such that, for example, the samples can be obtained during drilling step 210.
Obtaining step 220 can further comprise the step of screening or otherwise separating the samples to obtain rock samples having a suitable average particle size and/or particle size distribution. For example, in one embodiment, the rock samples may be screened to have an average particle size of at least about 0.05 inches, at least about 0.10 inches, or at least 0.25 inches and/or not more than about 1 inch, not more than about 0.75 inches, or not more than about 0.5 inches. Alternatively, or in addition, the rock samples can be screened to have a particle size distribution such that less than about 20 percent, less than about 15 percent, or less than about 10 percent of the total volume of each sample has a particle size less than 350 microns. According to one embodiment, the total size of each sample gathered during obtaining step 220 can be at least about 6 US ounces (oz), at least about 8 US oz, or at least about 12 US oz and/or not more than about 24 US oz, not more than about 20 US oz, or not more than 18 US oz. Other samples sizes are contemplated according to embodiments of the present invention, but may, in some situations, require additional processing and/or separation prior to analysis.
During obtaining step 220, a plurality of samples can be removed from wellbore 130 at various intervals and/or locations within formation 120. For example, samples can be obtained that correspond to one or more specific areas of interest within formation 120 or samples can be taken along the entire length of wellbore 130, if desired. In one embodiment, samples may be obtained at regular intervals of at least 30 feet, at least 60 feet, at least 90 feet, or at least 110 feet and/or not more than about 1500 feet, not more than about 1000 feet, not more than 500 feet, or not more than 300 feet of drilled depth of wellbore 130. In other embodiments, samples may be collected at regular time intervals, depending on the magnitude and consistency of the drilling speed and other related drilling parameters.
In one embodiment, obtaining step 220 can further comprise the step of correlating at least a portion of the rock samples withdrawn from wellbore 130 with a physical location within wellbore 130 and/or formation 120, such that the samples are at least approximately matched to a specific region within wellbore 130 and/or formation 120. By correlating the obtained rock samples with a physical location within wellbore 130 and/or formation 120, more accurate predictions of the location of potentially productive zones within formation 120 may be formulated, as described in detail shortly. The rock samples may be correlated to specific regions of wellbore 130 and/or formation 120 by using total vertical depth (TVD) or total drilled (or measured) depth. The specific type of depth parameter may be chosen based, at least in part, on the type and location of the wellbore. For example, it may be desirable to correlate samples with total drilled, rather than total vertical, depth when wellbore 130 is a directional wellbore, as illustrated in FIG. 1.
As shown in FIG. 2 a, method 200 can also comprise the step of analyzing at least a portion of the rock samples obtained from the wellbore, as depicted by block 230. Conventional methods for detecting and evaluating hydrocarbon material associated with a formation are commonly carried out at the drill site and include analysis of the hydrocarbon materials evolved from the wellbore. In contrast, methods carried out according to embodiments of the present invention include a step of analyzing at least a portion of the hydrocarbon materials held, entrapped, or otherwise contained within the structural matrix of the rock samples to thereby facilitate the identification of one or more productive zones within formation 120. Additional details regarding various embodiments of analyzing step 230 will now be described in further detail with reference to FIG. 2 b.
Turning now to FIG. 2 b, a flowchart illustrating the major sub-steps in a step 230 for analyzing rock samples obtained from a wellbore is provided. In one embodiment, the sub-steps outlined in the flowchart of FIG. 2 b can be used to obtain results that can be used to evaluate a hydrocarbon-containing formation in accordance with one or more embodiments of the present invention. Similarly to the flowchart shown in FIG. 2 a, in some alternative embodiments, the sub-steps noted in the various blocks of FIG. 2 b may occur out of the order specifically depicted in FIG. 2 b. For example, two blocks shown in succession in FIG. 2 b may sometimes be executed in the reverse order depending upon the functionality involved. Furthermore, one or more blocks shown in FIG. 2 b may be carried out simultaneously with and/or in reverse order of one or more blocks depicted in FIG. 2 a, depending again on the functionality involved.
The major sub-steps of analyzing step 230 illustrated in FIG. 2 b include receiving the rock samples obtained from the wellbore (as depicted by block 231), releasing a portion of the entrapped hydrocarbon from the rock samples (as depicted by block 232), capturing at least a portion of the released hydrocarbon (as depicted by block 234), measuring at least one property of the captured hydrocarbon (as depicted by block 236), organizing the results (as depicted by block 238), and transmitting the organized results to another party (as depicted by block 239). According to one embodiment, each of the sub-steps 231, 232, 234, 236, 238, and 239 can be carried out at the same physical location of each of the other sub-steps and, in another embodiment, one or more of sub-steps 231, 232, 234, 236, 238, and/or 239 can be carried out at a separate physical location than one or more of the other sub-steps. Additional details regarding specific embodiments of sub-steps 231, 232, 234, 236, 238, and 239 of analyzing step 230 will now be discussed below, with general reference to FIGS. 1 and 2 b.
As shown in FIG. 2 b, analyzing step 230 can comprise the sub-step of receiving the rock samples obtained from the wellbore, as depicted by block 231. The rock samples can be received from an onsite or an offsite location. As used herein, the term “onsite” refers to a location within a distance of no more than about 15 miles, no more than about 10 miles, no more than about 5 miles, no more than about 1 mile, or no more than about 2000 feet from the location of the wellhead of wellbore from which the samples were withdrawn. The term “offsite” refers to a location within a distance of at least about 15 miles, at least about 50 miles, or at least about 150 miles from the wellhead of wellbore from which the samples were withdrawn. Thus, in one embodiment, at least one of sub-steps 232, 234, 236, 238, and/or 239 can be carried out at substantially the same physical location as wellbore 130, while, in other embodiments, at least a portion of the sub-steps of analyzing step 230 may be carried out at a different physical location than wellbore 130.
As shown in FIG. 2 b, analyzing step 230 can also comprise the step of releasing at least a portion of the entrapped hydrocarbon material contained within the rock samples, as depicted by block 232. In one embodiment, the entrapped hydrocarbon can be released by exposing the rock samples to substantial changes in pressure in a controlled system. For example, in accordance with one embodiment, the rock samples may be placed in a pressurized chamber and exposed to alternating cycles of relatively high and relatively low or even sub-atmospheric pressures. The high pressures can be at least about 1500 torr, at least about 2000 torr, or at least about 4000 torr and/or not more than about 7500 torr, not more than about 6000 torr, or not more than about 4500 torr, while the low pressures can be less than about 700 torr, less than about 500 torr, or less than about 350 torr. In some embodiments, this type of pressure cycle may release entrapped hydrocarbon material from the pores of the rock samples.
In another embodiment, the entrapped hydrocarbon can be released from the rock samples by breaking down at least a portion of the rock sample matrix via a chemical and/or mechanical means. For example, in one embodiment, the entrapped hydrocarbon can be chemically released by adding a strong acid having a pH (measured at standard conditions) of not more than 3, not more than 2, or not more than 1 to the rock samples. Examples of suitable strong acids can include, but are not limited to, hydrochloric acid, sulfuric acid, phosphoric acid, and combinations thereof. In some embodiments, the selection of a specific acid, or the use of a chemical release mechanism may depend, at least in part, on the chemical compatibility of the acid with the rock samples and/or with the entrapped hydrocarbon materials. In some embodiments, heat and/or mechanical energy (e.g., agitation) may be added to the acid-rock mixture to enhance the rate of hydrocarbon release.
In another embodiment, releasing sub-step 232 can include mechanically releasing at least a portion of the entrapped hydrocarbon materials by reducing the particle size of the samples. The particle size of the rock samples can be reduced by grinding, pulverizing, and/or crushing the rock in order to obtain crushed rock samples having a generally powder-like consistency. In one embodiment, the resulting crushed or powered rock samples can have an average particle size of at least about 20 microns, at least about 40 microns, or at least about 50 microns and/or not more than about 300 microns, not more than about 225 microns, or not more than about 150 microns, which can represent a final average particle size that is at least about 30 percent, at least about 50 percent, or at least about 65 percent less than the original average particle size of the sample prior to reducing sub-step 232. Any suitable grinding device can be utilized to crush or pulverize the rock, including, for example, a commercial-strength dual-blade grinding device or even a mortar and pestle. Optionally, one or more fluid diluents, such as water, may be added to the grinding device to facilitate the mechanical particle size reduction in accordance with one embodiment of releasing sub-step 232.
Releasing sub-step 232 can be carried out for any sufficient amount of time. For example, in one embodiment, releasing sub-step 232 can be carried out for a fixed time interval, including, for example, at least about 1 minute, at least about 2 minutes, at least about 5 minutes and/or not more than about 60 minutes, not more than about 45 minutes, or not more than about 30 minutes. In another embodiment, releasing sub-step 232 can be carried out for a length of time sufficient to achieve a particle size distribution such that at least about 25 percent, at least about 50 percent, or at least about 75 percent of the total weight of the sample has an average particle size no more than about 350 microns. When using particle size distribution to determine the endpoint of releasing sub-step 232, the particle size distribution can be visually inspected, via microscope, or can be determined using one or more other devices, including a particle size analyzer (such as those commercially available from Microtrac, Inc. in Montgomery, Pa.) or via a standardized set of sieves. In some embodiments, achieving similar particle size distribution amongst various samples obtained from different locations within the same wellbore may be desirable in order to produce consistent and comparable results from the analysis, as discussed in detail shortly.
Turning back to FIG. 2 b, analyzing step 230 may also comprise the sub-step of capturing at least a portion of the released hydrocarbon, as depicted by block 234. According to one embodiment, releasing sub-step 232 and capturing sub-step 234 can be carried out at substantially the same time such that a large portion, or substantially all, of the entrapped hydrocarbon materials released from the rock samples are captured nearly simultaneously. In some embodiments, the simultaneous steps of releasing and capturing entrapped hydrocarbon can be carried out in a single device, such as, for example, in an air-tight or otherwise enclosed grinding device. Once captured, the entrapped hydrocarbon materials can then be routed to a device capable of measuring at least one property of the captured hydrocarbon materials, as depicted by block 236 in FIG. 2 b. In some embodiments, measuring sub-step 236 can also be carried out simultaneously or nearly simultaneously with at least a portion of releasing sub-step 232 and/or capturing sub-step 234.
During measuring sub-step 236, one or more key properties relating to the presence, amount, and/or composition of the captured hydrocarbon material released from the rock samples can be determined. The measured property can be a qualitative property (e.g., verification of the presence or absence of a hydrocarbon material) or a quantitative property (e.g., the amount or composition of the hydrocarbon material). In some embodiments, the measured property can be indicative of an intrinsic quality of the sample being measured, such as, for example, whether or not entrapped hydrocarbon was present in the sample analyzed. In other embodiments, however, the measured property may be a relative property that may not directly correspond to a property of the formation itself. For example, when the measured property relates to the amount or specific composition of the entrapped hydrocarbon, it may not directly correspond to the precise amount or composition of the specific hydrocarbon material contained within the corresponding region of the subterranean formation. However, these types of relative measured properties can facilitate comparison of values amongst several samples obtained from other areas of the formation in order to provide useful information for predicting the location of potentially productive zones within the formation. When measuring step 236 includes determining one or more of these relative properties, it may be useful to ensure nearly identical conditions during the analysis of each of the samples to ensure comparability amongst the results.
Depending on the specific property being measured, any suitable device can be used to carry out measuring step 236. In one embodiment, the measurement device can be a hydrocarbon detection device, operable to determine the presence or absence of hydrocarbon, or a hydrocarbon analysis device, operable to determine the amount and/or composition of the hydrocarbon being analyzed. Examples of suitable measurement devices can include, but are not limited to, hot wire detectors, mass spectrometers, infrared (IR) analyzers, thermal conductivity analyzers, gas chromatographs, and the like. Hot wire detectors can include catalytic filament detectors, which catalytically combust hydrocarbon materials and measure the resulting change in resistance of the heated platinum filament; hydrogen flame ionization detectors, which ionize hydrocarbon molecules in the presence of a hydrogen flame and measure the resulting current; and/or semiconductor-type detectors, which utilize changes in electrical conductivity of indicator materials. Hot wire detectors generally predict the presence and/or relative amount of hydrocarbon materials and, consequently, should be calibrated to obtain nearly identical test conditions, especially during the analysis and comparison of two or more samples obtained from different regions of the same wellbore.
Once the desired property or properties of the hydrocarbon materials released from the rock samples have been measured, the resulting values for each of the measured properties can be organized, as depicted by block 238 in FIG. 2 b. In one embodiment, organizing step 238 can include correlating each of the values obtained during measuring step 236 with a physical location within the wellbore and/or surrounding formation. For example, in one embodiment, organizing step 238 can include matching the values of the measured properties for each sample analyzed with the respective total vertical depth and/or drilled depth from which the sample was removed from the formation. In some embodiments, this can further include expressing the values for the measured properties as a function of either drilled or total vertical depth and, optionally, organizing the correlated results in a visual representation. Examples of suitable visual representations can include, but are not limited to, graphs or customized mudlogs, tables, maps, and/or models. Visual representations may also include descriptive text, a written table, or a list or summary of recommendations.
Once the set of results from measuring step 236 have been organized into an suitable format, the organized results can be transmitted to an end user, as depicted by block 239 of FIG. 2 b. The end user receiving the organized results can include one or more parties responsible for the exploration, drilling, development, stimulation, and/or production of one or more wellbores penetrating the formation of interest. In one embodiment, the end user can comprise a driller and/or a producer. The specific mechanism for transmission of the results can depend, at least in part, on whether the analysis was conducted onsite or offsite, as well as the values measured and the desired purpose of the organized results of analyzing step 230.
Turning back to FIG. 2 a, once the organized results of analyzing step 230 have been transmitted, the results can be used to perform one or more wellbore-related activities, as depicted by block 240. As used herein, the term “wellbore-related activity” refers to any activity or activity associated with one or more wellbores penetrating a subterranean formation. Examples of wellbore-related activities can include, but are not limited to, those selected from the group consisting of continuing to drill the same wellbore from which the rock samples were originally removed; drilling one or more new wellbores into the same formation; drilling one or more new wellbores into a different formation; stimulating production of hydrocarbon from the wellbore from which the samples were removed; stimulating production of hydrocarbon from another wellbore penetrating the same formation; selectively initiating the production of hydrocarbon from the same or another wellbore penetrating the same (or another) formation; changing or optimizing the production of hydrocarbon from the same (or one or more other) new or existing wellbores penetrating the same hydrocarbon formation; and combinations thereof.
In one embodiment, performing step 240 can further comprise evaluating the organized results of analyzing step 230 to determine which wellbore-related activity or activities should be carried out, as well as data regarding the specific execution of the selected activities. Evaluation of the organized results can often include comparing the results of analyzing step 230 obtained for various regions of the wellbore and/or surrounding formation. Based on the comparison, one or more potentially productive regions surrounding the wellbore may be identified and, subsequently, one or more of those areas can be selectively drilled, stimulated, and/or produced, as desired. This may also prevent attempted stimulation or production from non-hydrocarbon-containing regions of the formation thereby enhancing overall efficiency and minimizing production cost.
Methods of the present invention according to embodiments described herein can be utilized in a variety of ways to improve and enhance exploration, drilling, development, stimulation, and/or production of hydrocarbon-containing subterranean formations, especially those surrounding directionally-drilled wellbores. In one embodiment, the rock samples can be withdrawn from a source rock formation drilled with a non-hydrocarbon based drilling fluid and the results of the analysis can be used to determine the location of one or more new wellbores in the same formation and/or initiate or optimize production from one or more existing wellbores in the same formation. In another embodiment, the rock samples can comprise reservoir rock samples withdrawn from a wellbore in the process of being drilled and, according to this embodiment, the results of the analysis can be used to determine the optimal drilling path through the formation. In yet another embodiment, results from the analyses described herein can be utilized to optimize the spacing of laterally- or otherwise directionally-drilled wellbores to thereby prevent depletion by one or more existing wellbores. Various other embodiments and combinations have been contemplated to fall within the scope of the invention as defined by the appended claims.

Claims

1. A method for identifying a productive zone within a hydrocarbon-containing subterranean formation, said method comprising:

(a) receiving a plurality of rock samples removed from a wellbore penetrating said hydrocarbon-containing subterranean formation, wherein at least a portion of said rock samples comprise entrapped hydrocarbon materials;

(b) reducing the average particle size of at least a portion of said rock samples to thereby release at least a portion of said entrapped hydrocarbon materials;

(c) capturing at least a portion of said entrapped hydrocarbon materials released in step (b);

(d) measuring at least one property of said entrapped hydrocarbon materials captured in step (c) to thereby obtain a set of results; and

(e) organizing said set of results obtained via said measuring of step (d), wherein the organized set of data is used to carry out at least one wellbore-related activity.

2. The method of claim 1, wherein said step (b) includes grinding at least a portion of said rock samples to thereby provide crushed rock samples, wherein said crushed rock samples have a particle size distribution such that at least 25 percent of said crushed rock samples have an average particle size of less than 350 microns.

3. The method of claim 1, wherein said step (b) and said capturing of step (c) are carried out simultaneously.

4. The method of claim 1, wherein said step (d) includes using a hydrocarbon detection or hydrocarbon analysis device to obtain said set of results, wherein said at least one property measured in step (d) relates at least one of the presence, the amount, and the composition of said entrapped hydrocarbon material.

5. The method of claim 1, wherein said step (e) includes creating a visual representation using said set of results, wherein said visual representation is selected from the group consisting of a graph, a table, a log, a map, and a model.

6. The method of claim 1, wherein said at least one wellbore-related activity is selected from the group consisting of continuing to drill said wellbore, drilling one or more new wellbores said subterranean formation, drilling one or more new wellbores into a different subterranean formation, stimulating production of hydrocarbon from said formation, initiating or changing production of hydrocarbon from said wellbore or from one or more other wellbores, and combinations thereof.

7. The method of claim 6, wherein said at least one wellbore-related activity is selectively stimulating production from said wellbore and said wellbore is a directional wellbore having an angle of inclination of at least 40°.

8. The method of claim 1, wherein said plurality of rock samples removed from said wellbore comprise a plurality of drill cuttings obtained during the drilling of said wellbore into said hydrocarbon-containing subterranean formation.

9. The method of claim 8, wherein said subterranean formation is a reservoir rock formation.

10. The method of claim 1, further comprising producing hydrocarbon from said wellbore, wherein at least 75 volume percent of said hydrocarbon produced from said wellbore comprises natural gas and/or natural gas liquids.

11. A method for producing hydrocarbon from a hydrocarbon-containing subterranean formation, said method comprising:

(a) drilling a directional wellbore into said hydrocarbon-containing subterranean formation;

(b) obtaining a plurality of rock samples via said wellbore, wherein at least a portion of said rock samples comprise entrapped hydrocarbon materials;

(c) analyzing at least a portion of said rock samples obtained in step (b), wherein said analyzing includes obtaining a set of results related to said entrapped hydrocarbon materials; and

(d) based, at least in part, on said set of results obtained via said analyzing of step (c), performing at least one wellbore-related activity,

wherein said well-bore related activity is selected from the group consisting of continuing to drill said wellbore, drilling one or more new wellbores into said subterranean formation, drilling one or more new wellbores into a different subterranean formation, stimulating production of hydrocarbon from said formation, initiating or changing production of hydrocarbon from said wellbore or from one or more other wellbores, and combinations thereof.

12. The method of claim 11, wherein said directional wellbore has an angle of inclination of at least 50°.

13. The method of claim 12, wherein said step (a) includes utilizing a non-hydrocarbon based drilling fluid and said wellbore-related activity comprises initiating or changing production of hydrocarbon from said wellbore or from one or more other wellbores.

14. The method of claim 12, wherein said subterranean formation comprises a reservoir rock formation and said wellbore-related activity comprises selectively stimulating production of hydrocarbon from said formation.

15. The method of claim 11, wherein said step (c) includes releasing at least a portion of said entrapped hydrocarbon materials from said rock samples, capturing at least a portion of the released hydrocarbon materials, and analyzing at least a portion of the captured hydrocarbon materials with a hydrocarbon detection or hydrocarbon analysis device to thereby provide said set of results.

16. The method of claim 15, wherein said releasing includes grinding at least a portion of said rock samples such that the average size particle size of said rock samples is less than 350 microns, wherein said releasing and said capturing of said entrapped hydrocarbon materials are carried out simultaneously.

17. The method of claim 11, further comprising correlating each of said rock samples obtained in step (b) with a specific physical location within said wellbore or said formation, wherein said physical location is at least partially expressed by total drilled depth.

18. The method of claim 11, wherein said step (c) is carried out at a first location and said steps (a), (b), and (d) are carried out at a second location, wherein said first and said second locations are within about 10 miles of one another.

19. A method for identifying a productive zone within in a hydrocarbon-containing subterranean formation, said method comprising:

(a) receiving a plurality of rock samples removed from a wellbore penetrating said hydrocarbon-containing formation, wherein at least a portion of said rock samples comprise entrapped hydrocarbon materials and have a particle size distribution such that less than 20 weight percent of said rock samples have an average particle size less than 350 microns;

(b) grinding at least a portion of said rock samples to provide crushed rock samples, wherein said crushed rock samples have a particle size distribution such that at least 25 weight percent of said crushed rock samples have an average particle size of less than 350 microns;

(d) measuring at least one property of said entrapped hydrocarbon materials captured in step (c), wherein said analyzing includes using a gas detection or gas analysis device to obtain a set of data, wherein said set of data includes one or more values for a property related to said entrapped hydrocarbon materials, wherein said property relates at least one of the presence, the amount, and the composition of said entrapped hydrocarbon materials; and

(e) organizing said set of data obtained via said analyzing of step (d), wherein the organized set of data is used to carry out at least one wellbore-related activity.

20. The process of claim 19, wherein said wellbore is a directional wellbore having an angle of inclination of at least 50° and said well-bore related activity is selected from the group consisting of continuing to drill said wellbore, drilling one or more new wellbores said subterranean formation, drilling one or more new wellbores into a different subterranean formation, stimulating production of hydrocarbon from said formation, initiating or changing production of hydrocarbon from said wellbore or from one or more other wellbores, and combinations thereof.

21. The process of claim 19, wherein each of steps (a) through (e) are carried out at a physical location that is located at least 15 miles from a wellhead of said wellbore.