US20140374091A1

US20140374091A1 - Electromagnetic Imaging Of Proppant In Induced Fractures

Info

Publication number: US20140374091A1
Application number: US13/923,311
Authority: US
Inventors: Michael Wilt; Pabrita Sen
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2013-06-20
Filing date: 2013-06-20
Publication date: 2014-12-25

Abstract

A method may include forming a borehole in a subterranean formation, lining at least part of the borehole with an electrically conductive casing, and injecting a fracturing fluid, a proppant, and a sensing additive into the borehole to form a propped fracture pattern. The method may further include driving the electrically conductive casing so that the sensing additive generates an electromagnetic (EM) field, sensing the EM field, and mapping the propped fracture pattern based upon the sensed EM field.

Description

BACKGROUND

Hydraulic fracturing, which is also known as “fracking”, is a technique used to release a hydrocarbon resource such as oil or natural gas from a subterranean rock formation. During the fracking process, a wellbore is drilled through the top surface layers down to the rock formation where the hydrocarbon resource is located. A hydraulic fluid is then introduced into the wellbore and pressurize to create cracks or fractures through the rock formation, through which the hydrocarbon resource may be extracted through the wellbore.
To maintain a desired fracture width and help keep the fractures open (or slow their rate of closing), a proppant may be injected into fractures. More particularly, materials such as grains of sand, ceramics, or other particulates are used as proppants to help prevent the fractures from closing when the injection is stopped and the pressure of the fluid is reduced. Different types of proppants may be selected for different depths, since at deeper depths the pressure and stresses on fractures are higher. The propped fractures are sufficiently permeable to allow the flow of the hydrocarbon resource to the wellbore, as well as other fluids that may be introduced into the wellbore during the drilling or fracturing process.

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.
A method is provided herein which may include forming a borehole in a subterranean formation, lining at least part of the borehole with an electrically conductive casing, and injecting a fracturing fluid, a proppant, and a sensing additive into the borehole to form a propped fracture pattern. The method may further include driving the electrically conductive casing so that the sensing additive generates an electromagnetic (EM) field, sensing the EM field, and mapping the propped fracture pattern based upon the sensed EM field.
A related method is for mapping a propped fracture pattern adjacent a borehole in a subterranean formation, where an electrically conductive casing lines at least part of the borehole, and the propped fracture pattern includes a sensing additive. The method may include driving the electrically conductive casing so that the sensing additive generates an EM field, sensing the EM field, and mapping the propped fracture pattern based upon the sensed EM field.
A related apparatus may include an electrically conductive casing within a borehole of a subterranean formation having a proppant and a sensing additive within a propped fracture pattern adjacent the borehole. The apparatus may further include a signal source to drive the electrically conductive casing so that the sensing additive generates an EM field (e.g., a secondary EM field), at least one sensor to sense the EM field, and a mapping device coupled to the at least one sensor to map the propped fracture pattern based upon the sensed EM field.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic block diagram of an example embodiment of an apparatus for mapping induced fracture patterns in a subterranean formation.

FIG. 2 is a schematic block diagram of another example embodiment of an apparatus for mapping induced fracture patterns in a subterranean formation.

FIG. 3 is a schematic block diagram of still another example embodiment of an apparatus for mapping induced fracture patterns in a subterranean formation.

FIG. 4 is an enlarged view of an example imaging additive for use with the systems of FIGS. 1-3.

FIG. 5 is a flow diagram illustrating various fracture pattern mapping method aspects.

DETAILED DESCRIPTION

The present description is made with reference to the accompanying drawings, in which example embodiments are shown. However, many different embodiments may be used, and thus the description should not be construed as limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete. Like numbers refer to like elements throughout, and prime and multiple prime notation are used to indicate similar elements in different embodiments.
Referring initially to FIGS. 1 and 5, an apparatus 30 for imaging an induced fracture pattern in a subterranean formation 31 and related method aspects are first described. A wellbore 35 extends into the subterranean formation 31, which illustratively includes one or more upper layers 32 (e.g., topsoil, aquifer layer, etc.) and a reservoir layer(s) 33 (e.g., a rock or limestone layer, etc.) where a hydrocarbon resource is located.
By way of background, induced fractures 34 are being used for developing oil and gas fields in the US and abroad. These fractures 34 provide pathways for fluids (e.g., oil, natural gas, etc.) to flow from the reservoir layers 33 into a wellbore 35 that is drilled into the subterranean formation 31. The fractures 34 enhance fluid flow in tight, low permeability formations. However, the geometry and characteristics of induced fractures 34 are not always well understood. Of interest to field operators is the determination of what part of the fractured volume has been forced to remain open by an injected proppant 36 within the fractures 34. A “propped” fracture 34 is considered to represent the portion of the fractured volume that is connecting the reservoir and the wellbore 35.
Generally speaking, the apparatus 30 and related method aspects described herein allow for improving the detectability of a propped segment of induced fractures 34 using co-injected contrast or imaging agents or additives, and electromagnetic (EM) methods to image these fractures. The approach involves injecting conductive, dielectric and/or magnetic contrast agents (also referred to as a sensing additive herein) along with proppants such as sand and/or ceramic materials. These contrast agents may be introduced as a mixture with regular proppants, the proppants may be modified to incorporate contrast agents, or a mixture of both may be used. The sensing additive may have similar sizes as the proppant particles so that there is relatively little loss of the proppant/contrast material into the formation. Subsequently, the location and distribution of the sensing additive may be illuminated and interrogated by single well or multi-well EM approaches, as will be discussed further below.
More particularly, with reference to the flow diagram 50 of FIG. 5, beginning at Block 51 the borehole 35 is formed (e.g., drilled) in the subterranean formation 31, at Block 52, and at least part of the borehole is lined with an electrically conductive casing 37, at Block 53. The conductive casing 37 may serve several purposes, such as support during drilling, allowing flowback returns during drilling and cementing of the surface casing, and to help prevent collapse of loose soil near the surface, for example. Typical sizes for a conductive casing may be from about 18 to 30 inches, although other sizes may be used as well. By way of example, the conductive casing 37 may comprise steel, etc.
After a fracturing fluid is injected into the borehole 35 to induce the fractures 34, a proppant is injected into the borehole to form a propped fracture pattern, at Block 54. The fracturing fluid and proppant may be injected through holes in the casing 37, for example. More particularly, the casing 37 allows the interval in the borehole 35 to be pressure-isolated, and perforations in the casing in the interval of interest allow the fracking fluid and proppant to be introduced at that location. As noted above, the proppant (and/or the fracturing fluid) includes a sensing additive. As a result, the electrically conductive casing 37 may be driven by a signal source 38 so that the sensing additive generates an electromagnetic (EM) field, at Block 55. That is, the casing 37 essentially provides an antenna to illuminate the sensing additive within the fractures 34. The EM field generated by the sensing additive may be considered as a total EM field resulting from the primary field from the signal source 38 as well as the secondary field from the target (i.e., sensing additive).
In the illustrated example, the signal source 38 is coupled to the casing 37 within the wellbore 35 adjacent to the area where the fractures 34 are located. The signal source 38 is also coupled to an electrode 39, which is positioned in the subterranean formation 31 and spaced apart from the borehole 35. However, other suitable electrode configurations or placements may be used when driving the casing 37.
In the example illustrated in FIG. 1, one or more EM sensors 40 are positioned in the borehole 35 adjacent the fractures 34 to be imaged. The EM sensor 40 is configured to sense an EM field from the sensing additive when driven by the signal source 38 via the casing 37, at Block 56. Example measuring units which may be configured to provide EM sensing through the casing 37 are described in U.S. Pat. No. 4,796,186 to Kaufman and U.S. Pat. No. 4,820,989 to Vail, III, which are hereby incorporated herein in their entireties by reference.
The system 30 further illustratively includes a mapping device 41 coupled to the EM sensor 40, which collects the EM field data from the EM sensor and maps the propped fracture pattern based upon the sensed EM field, at Block 57, which concludes the method illustrated in FIG. 5 (Block 58). By way of example, the mapping device 41 may be implemented using hardware (e.g., processor, memory, etc.) and associated computer-executable instructions. It should be noted that some or all of the mapping device components may be located remotely from the well site. That is, the data may be collected at the well site for mapping using a mapping device 41 located offsite.
In other example embodiments, EM sensors may be located remote from the borehole 35. In another example embodiment illustrated in FIG. 2, one or more EM sensor devices 40′ may be positioned at the surface of the subterranean formation 31′, instead of (or in addition to) within the borehole 35′. In still another example embodiment shown in FIG. 3, the EM sensor(s) 40″ may be positioned in one or more separate boreholes 45″ spaced apart from the primary borehole 35″, although an EM sensor may also be positioned within the primary borehole as well. The separate borehole(s) 45″ need not necessarily be lined with a casing.
With respect to the sensing additive, a relatively small volume fraction of a highly conductive material in the fracture fluid and/or proppant 36 can make the effective conductivity of the fractured regions 34 filled by this proppant relatively high. Generally speaking, the electrical properties of the proppant mixtures are determined by the concentration, shape and distribution of constituents. There is a percolation type behavior when highly conducting material is distributed in a relatively poorly conducting host. That is, the overall conductivity remains low until the highly conducting phase forms a well-connected “percolating” path for conduction.
In the case of a subterranean formation 31, the “host” may be the fracture fluid and inert portion part of the proppant, and the highly conducting part may be metallic particles such as aluminum or graphite beads, a conducting polymer, or a conductive material coating on sand/ceramic that can be mixed with the sand. The percolation threshold (f_c) volume fraction depends on the aspect ratio. For spherical grains, theoretical models give f_cto be about 0.28, that is, a relatively large volume fraction of conducting phase is needed. However, this percolating volume fraction may be reduced by using different geometries, such as an elongate or needle-like conductive phase particles 50, as shown in FIG. 4. That is, a relatively small volume fraction of needle-shaped conductive particles 50 may form a spanning or a percolating path through the propped fractures 34. By way of example, such non-spherical sensing co-agents may be included in the proppant mix to enhance the proppant conductivity or polarization at modest concentration levels of less than 15% by volume, and more particularly about 10-15%. Stated alternatively, a proppant to sensing additive volume ration may be greater than about 7 to 1. Example sensing agents may include aluminum, pyrite, magnetite, or graphite, and may be chosen based upon compatibility with chemistry of the fracture fluids. As noted above, inert proppants (e.g., sand, ceramic, etc.) may be coated with conductive or magnetic agents using doped polymers or resins.
By way of example, proppant sensing additives may be illuminated by various electromagnetic mechanisms. First, if the sensing additive changes the magnetic susceptibility of the propped zone, it can be illuminated with a low frequency magnetic signal (e.g., 20 Hz or less) that couples into the proppant through an enhancement of the magnetic field. Another approach is that electrically conductive sensing additives may be illuminated using a relatively low frequency electrical signal (e.g., 100 Hz or less), or a higher frequency electrical or magnetic source (e.g., 1000 Hz or less). At low frequency, the electrical signals are directly affected, via Ohm-s law, due to the change in electrical conductivity of the propped fracture 34. At higher frequencies, the electrical or magnetic signals couple electromagnetically into the proppant 36, causing secondary currents to flow and these currents, in turn, produce secondary EM fields. This affect is analogous to a transformer coupling.
Another approach is that conductive sensing additives may also be detected from their polarization effect. More particularly, if the conductors in the proppant are disseminated, the low frequency EM field will polarize the isolated conductive regions. When the external field is removed, the polarized regions will generate their own relaxation field as they return to equilibrium.
Contrast sensing additives which may be used to enhance the magnetic field include magnetite, illmenite or particles of iron. Conductivity enhancements may be affected by various metallic conductors including pyrite, aluminum, graphite, or a stainless steel coating, etc. Polarizability may be enhanced by discontinuous metallic conductors.
Generally speaking, imaging of the collected data may be accomplished by fitting the measurements to calculations from a numerical model, typical by an inverse procedure. Here, one may assume a physical property distribution corresponding to the background and fracture properties, and then adjust the model until the measured and calculated data fits within a tolerance. The final model depends on the assumptions made, as well as the data and misfit achieved.
One imaging model that may be used is a 3D pixelized model. With this model, the formation is divided into pixels within which the physical properties (electrical conductivity or magnetic permeability) are constant. It may be assumed that an initial property distribution is consistent with an extension of the borehole logs, and/or other available data, and adjust the properties of the pixels until a data fit is achieved.
It should be noted that a rectangular pixelized model may provide a relatively poor representation of a fractured medium, but an “effective medium theory” may be used to give an average physical property distribution within a pixel equivalent to the fracture properties. Within each pixel, the effective medium theory will provide the property values and anisotropy to provide an equivalent response to a fractured medium. The final model does not necessarily correspond to a fracture distribution, but it will provide equivalent EM responses to the fracture model. More particularly, the results of this process will provide property distribution, property anisotropy and overall dimensions of the anomalous propped region from a pixelized inversion.
Numerical codes which may be used in this approach may be found in Zaslaysky et al., “Hybrid finite-difference integral equation solver for 3D frequency domain anisotropic electromagnetic problems,” Geophysics 76, 123-137 (2011); and Li et al., “A compressed implicit Jacobian scheme for 3D electromagnetic data inversion,” Geophysics 76, 173-183 (2011), for example, which are hereby incorporated herein in their entireties by reference. Effective medium theory calculations are provided in Choy, “Effective Medium Theory: Principles and Applications,” International Series of Monographs on Physics, 1999, for example, which is also incorporated herein in its entirety by reference.
Another imaging model that may be used is a sheet model. In this approach, it may be assumed that the fractured volume may be approximated by a collection of conductive or magnetized sheets. The orientation, dimensions and number and properties of sheets are determined through an inverse or statistical method. Further details on this approach may be found in Weidelt, “The harmonic and transient electromagnetic response of a thin dipping dike,” Geophysics 48, 934-952 (1983), which is hereby incorporated herein in its entirety by reference.
Many modifications and other embodiments will come to the mind of one skilled in the art having the benefit of the teachings presented in the foregoing descriptions and the associated drawings. Therefore, it is understood that various modifications and embodiments are intended to be included within the scope of the appended claims.

Claims

That which is claimed is:

1. A method comprising:

forming a borehole in a subterranean formation;

lining at least part of the borehole with an electrically conductive casing;

injecting a fracturing fluid, a proppant, and a sensing additive into the borehole to form a propped fracture pattern;

driving the electrically conductive casing so that the sensing additive generates an electromagnetic (EM) field;

sensing the EM field; and

mapping the propped fracture pattern based upon the sensed EM field.

2. The method of claim 1 wherein driving comprises driving the electrically conductive casing with an alternating current (AC).

3. The method of claim 2 wherein the AC current has a frequency of less than 100 Hz.

4. The method of claim 2 wherein the AC current has a frequency of less than 1000 Hz.

5. The method of claim 1 wherein sensing comprises sensing from within the borehole.

6. The method of claim 1 wherein sensing comprises sensing remote from the borehole.

7. The method of claim 1 wherein sensing comprises magnetic field sensing.

8. The method of claim 1 wherein sensing comprises electric field sensing.

9. The method of claim 1 wherein the sensing additive comprises at least one of electrically conductive particles, magnetic particles, and polarizable particles.

10. The method of claim 1 wherein the sensing additive comprises particles have an elongate shape.

11. The method of claim 1 wherein a proppant to sensing additive volume ratio is greater than 7 to 1.

12. A method for mapping a propped fracture pattern adjacent a borehole in a subterranean formation, an electrically conductive casing lining at least part of the borehole, and the propped fracture pattern comprising a sensing additive, the method comprising:

sensing the EM field; and

mapping the propped fracture pattern based upon the sensed EM field.

13. The method of claim 12 wherein driving comprises driving the electrically conductive casing with an alternating current (AC).

14. The method of claim 12 wherein sensing comprises sensing from within the borehole.

15. The method of claim 12 wherein sensing comprises sensing remote from the borehole.

16. An apparatus comprising:

an electrically conductive casing within a borehole of a subterranean formation having a proppant and a sensing additive within a propped fracture pattern adjacent the borehole;

a signal source to drive the electrically conductive casing so that the sensing additive generates an electromagnetic (EM) field;

at least one sensor to sense the EM field; and

a mapping device coupled to said at least one sensor to map the propped fracture pattern based upon the sensed EM field.

17. The apparatus of claim 16 wherein said signal source comprises an alternating current (AC) source.

18. The apparatus of claim 16 wherein said at least one sensor is to sense the EM field from within the borehole.

19. The apparatus of claim 16 wherein said at least one sensor is to sense the EM field remotely from the borehole.

20. The apparatus of claim 16 wherein said at least one sensor comprises at least one of a magnetic field sensor and an electric field sensor.