System and method for joint flow potential and controlled source electromagnetic modeling

Abstract

Techniques are disclosed for improved modeling of subterranean formations that employ a combination of flow potential and controlled source electromagnetic techniques to achieve a better understanding of subterranean conditions.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims priority to U.S. Provisional Patent Application No. 1283-0046PUS US 63 / 374,930, filed on September 8, 2022, entitled “SYSTEM AND METHOD FOR JOINT STREAMING POTENTIAL AND CONTROLLED SOURCE ELECTROMAGNETIC MODELING”. The disclosure of the prior application is considered a part of this patent application and is incorporated by reference into this patent application. Technical Field

[0003] The present invention relates to the field of geophysics and, in particular, to techniques for improved modeling of subsurface formations. Background Art

[0004] The streaming potential SP technique is a passive geophysical tool that measures the naturally occurring electric field or voltage generated by the flow of fluids through geological formations. Widely recognized applications of the SP technique range from monitoring dam leakage, estimating hydraulic conductivity in hydrogeology, monitoring volcanic and geothermal activity, to well logging in the oil and gas industry. One of the advantages of the SP technique is the simplicity of data acquisition, without the need for an active artificial excitation source.

[0005] According to electrokinetic theory, two sources can generate SP signals: fluid flow rate and pressure changes over time. In the energy industry, for example, during hydraulic fracturing, borehole pressure varies at a fairly low frequency, close to direct current DC. This is consistent with the general understanding that the mechanism of SP is related to the relative motion of ions due to the zeta potential in the double layer region separating two phases of matter (such as between a solid and a liquid).

[0006] In contrast, controlled source electromagnetic (CSEM) is a generally active source technique that injects different current waveforms into the ground or into a coil and then measures the total electric and / or magnetic fields resulting from the interaction between the source and the subsurface formations. This means that both the signal strength and frequency content can be controlled, depending on the depth of the target of interest and the background formations. Summary of the invention

[0007] In a first aspect, a method for monitoring carbon capture, utilization and storage (CCUS) comprises: positioning a controlled source electromagnetic (CSEM) transmitter on the surface of the earth relative to a CCUS borehole casing; positioning a plurality of CSEM receivers relative to the CCUS borehole casing and synchronized with the CSEM transmitter; transmitting a signal from the CSEM transmitter to underground formations around the CCUS borehole casing; receiving a secondary electromagnetic (EM) field corresponding to the signal transmitted from the CSEM transmitter by a plurality of CSEM receivers, the secondary EM field being coupled with a flow potential at a location where a fluid is injected into the underground formation; measuring the secondary EM field; and calculating the pressure field by inverting an objective function based on the secondary EM field and a forward modeling function that converts a pressure or gradient of the pressure field into the secondary EM field.

[0008] In a second aspect, a method for imaging the saturation or permeability of a formation comprises: positioning a controlled source electromagnetic (CSEM) transmitter on the surface of the earth relative to a borehole; positioning a plurality of CSEM receivers relative to the borehole and synchronized with the CSEM transmitter; transmitting a signal from the CSEM transmitter to underground formations surrounding the borehole; receiving a secondary electromagnetic (EM) field corresponding to the signal transmitted from the CSEM transmitter by the plurality of CSEM receivers, the secondary EM field being coupled to a flow potential at a location where fluid is injected into the underground formation; measuring the secondary EM field; and calculating the saturation or permeability of the formation by inverting a target function based on the secondary EM field and a function that converts the saturation or permeability to the secondary EM field.

[0009] In a third aspect, a method for determining the injection or return rate into or from a subsurface formation comprises: positioning a controlled source electromagnetic (CSEM) transmitter on the surface of the earth relative to a borehole; positioning a plurality of CSEM receivers relative to the borehole and synchronized with the CSEM transmitter; transmitting a signal from the CSEM transmitter to the subsurface formation around the borehole; receiving a secondary electromagnetic (EM) field corresponding to the signal transmitted from the CSEM transmitter by a plurality of CSEM receivers, the secondary EM field being coupled with a flow potential at a location where fluid is injected into the subsurface formation; measuring the secondary EM field; and performing a reservoir simulation based on the injection rate or return rate by inverting a target function based on the secondary EM field and a function that converts a pressure or gradient of a pressure field into a secondary EM field.

[0010] In a fourth aspect, a method for calculating electric and magnetic fields in underground formations comprises: positioning a controlled source electromagnetic CSEM transmitter on the surface of the earth relative to a borehole; positioning a plurality of CSEM receivers relative to the borehole and synchronized with the CSEM transmitter; transmitting a signal from the CSEM transmitter to the underground formations around the borehole; receiving a secondary electromagnetic EM field corresponding to the signal transmitted from the CSEM transmitter by a plurality of CSEM receivers, the secondary EM field being coupled with a flow potential at a location where fluid is injected into the underground formation; measuring the secondary EM field; and calculating a flow potential current based on a cross-coupling coefficient and a pressure field between the fluid flow and the current flow; and calculating the electric and magnetic fields based on the excitation current and the flow potential current. BRIEF DESCRIPTION OF THE DRAWINGS

[0011] The accompanying drawings are incorporated into and constitute a part of this specification, illustrate embodiments of devices and methods consistent with the present invention, and together with the detailed description, are used to explain the advantages and principles consistent with the present invention. In the drawings:

[0012] 1 is a pair of graphs illustrating a comparison of an example spectral analysis and example borehole pressure data.

[0013] FIG. 2 is a pair of diagrams illustrating a CSEM project.

[0014] 3 is a pair of graphs from a fracturing operation further illustrating the relationship between pressure, injected fluid, proppant, and scattered-field CSEM response.

[0015] Figure 4 is a graph illustrating the results of performing a non-linear regression on all the data in the CSEM scattered field response of the data from FIG. 3 . DETAILED DESCRIPTION

[0016] In the following description, for ease of explanation, numerous specific details are set forth to provide a thorough understanding of the present invention. However, it will be understood by those skilled in the art that the present invention may be implemented without these specific details. In other examples, structures and devices are shown in block diagram form to avoid obscuring the present invention. References to numbers without subscripts should be understood as references to all subscripted instances corresponding to the referenced numbers. Moreover, the language used in this disclosure is selected primarily for readability and instructional purposes, and may not be selected to delimit or limit the creative subject matter, and appeal to the claims is necessary to determine such creative subject matter. References to "one embodiment" or "embodiment" in the specification mean that the specific features, structures or characteristics described in conjunction with the embodiment are included in at least one embodiment of the present invention, and multiple references to "one embodiment" or "embodiment" should not be understood as necessarily referring to the same embodiment.

[0017] Although some of the following descriptions are written in terms related to software or firmware, embodiments can implement the features and functions described herein in software, firmware or hardware as needed, including any combination of software, firmware and hardware. References to daemons, drivers, engines, modules or routines should not be considered as implying limitations of the present embodiment to any type of implementation. Actual dedicated control hardware code or software code for implementing these systems or methods is not a limitation of the implementation. Therefore, this article describes the operation and behavior of the system and method without mentioning specific software code, and it is understood that software and hardware can be used to implement these systems and methods based on the description herein.

[0018] As used herein, satisfying a threshold may depend on the context and refer to a value being greater than a threshold, greater than or equal to a threshold, less than a threshold, less than or equal to a threshold, equal to a threshold, etc., depending on the context.

[0019] Although particular combinations of features are recited in the claims and disclosed in the specification, these combinations are not intended to limit the disclosure of the various embodiments. Features may be combined in ways not specifically recited in the claims or disclosed in the specification.

[0020] Although each dependent claim listed below may only be directly dependent on one claim, the disclosure of the various embodiments includes each dependent claim in combination with every other claim in the claim set. No element, act, or instruction used herein should be construed as critical or essential unless explicitly described as such.

[0021] What is described in this paper demonstrates the advantages of combining SP signals and CSEM signals and provides new results.

[0022] Figure 1 is a pair of graphs illustrating a comparison of an example spectral analysis (110) and example borehole pressure data (100). The frequency content in the pressure data drops below 0.1 Hz, approaching DC.

[0023] The electric scattered field is defined as the difference in the total electric field between during and after the pumping event and before the start of the pumping event (background). Typically, the measured total field is normalized by the transmitter current.

[0024] An array of multiple surface CSEM receivers is deployed to record the response generated by powering the ground through a CSEM transmitter. Each member of the array of surface CSEM receivers thus receives a signal corresponding to the signal generated by the CSEM transmitter reflected from the subsurface. Each recording instrument in the CSEM transmitter and CSEM receiver array is precisely synchronized, preferably with a difference of less than 100 nanoseconds between all devices and extremely low drift. In addition, each recording instrument has as high a sampling rate as possible, preferably at least 50,000 samples per second.

[0025] In some embodiments, the CSEM transmitter and the CSEM receiver can be implemented as described in U.S. Patent No. 9,810,804, entitled “Acquisition and Transmission of Controlled Source Electromagnetic Signals,” issued on November 7, 2017, and U.S. Patent No. 11,221,429, entitled “Coherent Transmit and Receive Bi-Static Electromagnetic Geophysical Tomography,” issued on January 11, 2022, the entire contents of both patents are incorporated herein by reference for all purposes.

[0026] In applications involving carbon capture, utilization and storage CCUS monitoring, the CSEM receiver array is preferably deployed in a series of concentric circles around the CCUS borehole casing. In other applications, the CSEM receiver array is preferably deployed above the area where fluids are injected into the subsurface formation. In applications such as fracturing, the CSEM receiver array is preferably deployed above the stage where fracturing is taking place.

[0027] Generally speaking, a CSEM receiver array receives a secondary field, ie, a secondary EM field, corresponding to a signal transmitted from a CSEM transmitter, which is coupled to the flow potential at the location where fluid is injected into a subsurface formation and can then be measured.

[0028] FIG2 is a pair of graphs illustrating a CSEM project. As shown in FIG2, in this CSEM project, the electric scattered field (represented in a time-frequency format) of graph 210 measured at a sensor located at the surface near the injection well shows a strong correlation with the injection well borehole pressure and pump flow rate of graph 200, indicating the dominance of the SP signal in the measured CSEM data. In FIG2, the frequency of the EM data is 100 Hz, and the pressure and flow rate are in the time domain.

[0029] However, one of the unexplained issues in this observation is the frequency content in the measured electromagnetic (EM) data. The EM trace along time in Figure 2 is the scattering response at 100 Hz, whereas it is generally believed that the SP signal should be close to DC.

[0030] There is a discrepancy between the observed CSEM scattered field data and the SP signal with respect to frequency content.

[0031] Furthermore, the signal intensity of the CSEM scattered field as predicted by conventional 3D EM modeling at low frequencies is about 1 to 2 orders of magnitude smaller than what is observed. This is a further inconsistency between the observed and expected data.

[0032] The following diagram shows another real-world example of this relationship.

[0033] FIG3 is a pair of graphs illustrating another example of the relationship between pressure, injected fluid, proppant, and scattered field CSEM response in a fracturing operation. In FIG3, the measured CSEM scattered field signals (represented in a time-frequency format) at six sensor locations (300) are illustrated and compared to the borehole pressure and pump rate data (310). Note that the frequency of the EM data is 10 Hz, while the pressure and flow rate are in the time domain. The EM scattered field response in regions 320 and 330 is an order of magnitude larger than predicted by traditional modeling and indicates a pressure response from the streaming potential.

[0034] Figure 4 is a graph 400 illustrating the results of a nonlinear regression performed on all the data in the CSEM scattered field response from the data shown in FIG3 above. There is a clear peak for the sensors closest to the frac between 3 Hz and 10 Hz. Although the R^2 value is low, there is a priori data related to the location of the sensors, the location and time of the frac that increases the significance of the results; this correlation only exists in the pump flow data and pressure data.

[0035] A new geophysical method

[0036] A new mechanism for the streaming potential SP signal in CSEM measurements can be extended from the conventional Zeta potential theory: in the CSEM case, the relative displacement of ions is not due to fluid flow but is driven by an external excitation electromagnetic field that penetrates into the fluid flow region.

[0037] Given the proposed mechanism, the correlation between CSEM data and pressure and pumping rate can be well explained from a frequency perspective; therefore, a new geophysical method is proposed that combines the streaming potential and the CSEM scattered field, forming the spCSEM technique.

[0038] The new spCSEM technology will improve and expand the current stand-alone SP and CSEM methods in more applications in the energy industry, such as in hydraulic fracturing, geothermal, exploration, tailings dam monitoring and block cave mining, and CCUS monitoring.

[0039] A new spCSEM modeling algorithm

[0040] Based on the understanding of the mechanism of SP under external EM excitation source, a new spCSEM modeling algorithm is disclosed. e , streaming potential current J sp Can be considered as an additional source of electromagnetic signal for generating spCSEM. Streaming potential current J sp It can be obtained by formula (1):

[0041]

[0042] Where L is the cross-coupling coefficient between fluid flow and current flow in coupled flow theory, and p is the pressure field, which can be solved in reservoir simulation or geomechanics platforms. Therefore, the modified frequency-domain EM formulation for spCSEM may be as follows:

[0043]

[0044] By solving these equations, the electric and magnetic fields can then be calculated. This constitutes the spCSEM frequency domain forward modeling engine, which can be used for the following inverse problem as outlined in equations (5), (6) and (7) below. Through spCSEM inversion, the conductivity or conductivity change of the injected fluid can be inferred, and even the saturation and permeability can be inferred.

[0045] Pressure field to be obtained from reservoir simulation

[0046] The current density J in formula (1) sp It is obtained by solving the pressure field p over the entire domain. There are several ways to derive the pressure field, including: (1) by running a reservoir simulation based on fluid flow, or (2) by solving a combination of poroelastic fluid flow and mechanics equations.

[0047] Here we focus on solving the pressure field by using reservoir simulation because our main intended applications are hydraulic fracturing monitoring or CO2 monitoring in CCUS.

[0048] Typically, reservoir simulation software packages can be described using the following composition control equations.

[0049]

[0050] in

[0051] i=1,2,…,Nc, where Nc is the number of constituent units;

[0052] K represents the absolute permeability tensor;

[0053] k = o, w, g, representing oil phase, water phase and gas phase respectively;

[0054] xik is the fractional factor of phase k in unit I;

[0055] ρ k , K rk , and μ k represent phase density, relative permeability and viscosity, respectively;

[0056] γ k It is phase gravity;

[0057] Z is the vertical depth;

[0058] Q i is the source term for the injection or return of fluid;

[0059] φ is the porosity; and

[0060] S k Indicates phase saturation.

[0061] Together with related auxiliary formulas for saturation, relative permeability, capillary pressure, PVT properties, and rock properties, the pressure field p can be solved simultaneously using various numerical algorithms known in the art. k and S k .

[0062] It is evident from the above that the pressure field is a function of the injection rate and rock physical parameters such as porosity, saturation and permeability. Therefore, theoretically, the injection rate and any rock physical parameter can be retrieved or inferred from the pressure field in the sense of formulating it as an inverse problem. This opens the door for the use of spCSEM technology in new areas, which will be explained in the following sections.

[0063] Potential applications of spCSEM technology

[0064] Through streaming current density, conventional EM measurements are not only related to conductivity, but also to petrophysical parameters of the subsurface formation, as well as dynamic injection and return flow and pressure field changes. Therefore, spCSEM technology can be used in conjunction with conventional EM technology in oil and gas exploration and production. The advantages of combining streaming potential technology and CSEM technology have not been recognized before.

[0065] Application 1: Monitoring via conductivity / resistivity

[0066] The application is similar to conventional CSEM techniques. The difference here is that the flowing current is treated as an external excitation source that enhances the excitation field around the injection target of interest. As a result, the resulting EM signal can be greatly enhanced. This means that the spCSEM technique can be used in scenarios where conventional CSEM methods cannot detect or monitor the injection plume by conductivity and resistivity. This is particularly true when a steel cased well provides the conduit for the current to flow back and forth from the earth's surface, where the CSEM transmitter source and receiver are deployed, to the injection zone below the borehole.

[0067] Application 2: Imaging pressure fields

[0068] It is well known that bottom hole pressure data is essential for understanding reservoir performance and predicting future production behavior. Practical applications of pressure data may include reservoir volume calculation, understanding reservoir dynamics (e.g. permeability), fluid properties (e.g. density, phase behavior), drainage volumes (e.g. compartmentalization and flow barriers), etc.

[0069] Typically, pressure sensors are installed along production wells to directly measure reservoir dynamic pressure data.

[0070] In the spCSEM technique, as shown in equations (1) to (3), the pressure p or its gradient Related to the measurement of both electric and magnetic fields, this can be described abstractly by the general function:

[0071] d i =F i [m], i = 1, 2, ... N d

[0072] d i =F i [m], i = 1, 2, ... N d (5)

[0073] Among them, d i represents the measurement value at the i-th receiver, with a total number of receivers N d ;

[0074] F i is the function that converts the pressure or gradient of the pressure field into the EM field;

[0075] m is the unknown pressure p or its gradient at each grid or unit A vector that discretizes the underground volume into N g An unknown number.

[0076] Following the standard inversion procedure, in order to recover the unknown m, one can define the data matching objective function in the least squares sense as

[0077]

[0078] Therefore, the optimization of the inverse problem can be expressed as:

[0079]

[0080] Subject to the constraints on m.

[0081] If we assume that the effect of conductivity is minimal under certain circumstances, then any changes in the electric or magnetic field (E or H) can be attributed to changes in pressure or its gradient.

[0082] The inversion process can be performed at each time step individually, or by putting all the time lapse data together into the inversion system at once, and the dynamic unknown m can be obtained.

[0083] Therefore, the spCSEM technique can be used as an alternative tool for imaging dynamic pressure data in reservoir models, which can be very valuable in evaluating the performance of reservoir management.

[0084] Application 3: Imaging Saturation or Permeability

[0085] The saturation and permeability of a formation refer to the amount of fluid present in the formation and how easily or difficultly the fluid can flow through the matrix. These are key parameters in determining the production potential of oil and gas. In the oil and gas industry, the determination of these parameters involves various methods such as well logging, core analysis, pressure transient testing, and production testing.

[0086] For this purpose, we propose here a different technique.

[0087] In line with the ideas discussed in Application 2, we can further relate the E and H measurements from spCSEM to petrophysical parameters such as reservoir saturation or permeability. In other words, using the same approach as in Eqs. (5) to (7), saturation or permeability can be recovered from the EM signal. The only change required is to replace the forward modeling function F in Eq. (5) with i Replace with a similar function This function converts saturation or permeability into an EM field for the 3D model being studied.

[0088] Of course, in order to focus on one specific parameter, be it saturation or permeability, one has to make some assumptions about the rest. This may only be valid in certain special cases. However, in theory, this is indeed a potential application of spCSEM.

[0089] Indeed, one must remember that of all practical methods of predicting permeability, imaging permeability using spCSEM data will be unique to the site or formation for which it is being developed.

[0090] Application 4: Determining the source term - injection rate or return rate

[0091] Looking at formula (4), the source term Q i represents the injection rate or the reflow rate. Obviously, the observed pressure field, and therefore the EM measurement in the spCSEM, will be directly affected by this source term. Therefore, by analyzing the EM signal observed during the injection period or the reflow period, it is possible to determine the injection rate or the reflow rate.

[0092] In summary, the spCSEM technique provides a remote sensing geophysical tool for monitoring pressure fields and injected water or CO2 plumes in terms of conductivity, saturation or permeability in hydraulic fracturing, CCUS and geothermal management.

[0093] While certain example embodiments have been described in detail and shown in the drawings, it is to be understood that these embodiments are illustrative only and are not to be contemplated without departing from the basic scope thereof, which is determined by the following claims.

Claims

1. A method for monitoring carbon capture, utilization and storage (CCUS), comprising: positioning a controlled source electromagnetic (CSEM) transmitter on the surface of the earth relative to the CCUS borehole casing; positioning a plurality of CSEM receivers relative to the CCUS borehole casing, in synchronization with the CSEM transmitters; transmitting a signal from the CSEM transmitter to the subsurface formation surrounding the CCUS borehole casing; receiving, by the plurality of CSEM receivers, secondary electromagnetic (EM) fields corresponding to the signals transmitted from the CSEM transmitters, the secondary EM fields being coupled to a flow potential at a location where fluid is injected into the subsurface formation; measuring the secondary EM field; as well as The pressure field is calculated by inverting an objective function based on the secondary EM field and a forward modeling function that converts the pressure or gradient of the pressure field into the secondary EM field.

2. The method according to claim 1, wherein: Positioning the plurality of CSEM receivers includes positioning the plurality of CSEM receivers in a series of concentric circles around the CCUS borehole casing.

3. The method according to claim 1, wherein: Computing the pressure field by performing an inversion comprises performing an inversion separately at each time step.

4. The method according to claim 1, wherein: Calculating the pressure field by performing an inversion includes performing an inversion on a combination of all time lapse data.

5. A method for imaging the saturation or permeability of a formation, comprising: positioning a controlled source electromagnetic CSEM transmitter on the surface of the earth relative to the borehole; positioning a plurality of CSEM receivers relative to the borehole, synchronized with the CSEM transmitter; transmitting a signal from the CSEM transmitter to a subsurface formation surrounding the borehole; receiving, by the plurality of CSEM receivers, secondary electromagnetic (EM) fields corresponding to the signals transmitted from the CSEM transmitters, the secondary EM fields being coupled to a flow potential at a location where fluid is injected into the subsurface formation; measuring the secondary EM field; as well as The saturation or permeability of the formation is calculated by inverting an objective function based on the secondary EM field and a function that converts the saturation or permeability to the secondary EM field.

6. The method according to claim 5, wherein: Positioning the plurality of CSEM receivers includes positioning the plurality of CSEM receivers above a stage where fracturing is ongoing.

7. The method according to claim 5, further comprising: A 3D model of the saturation or permeability of the formation is created.

8. A method of determining an injection rate into a subsurface formation or a return flow rate from a subsurface formation, comprising: positioning a controlled source electromagnetic CSEM transmitter on the surface of the earth relative to the borehole; positioning a plurality of CSEM receivers relative to the borehole, synchronized with the CSEM transmitter; transmitting a signal from the CSEM transmitter to a subsurface formation surrounding the borehole; receiving, by the plurality of CSEM receivers, a secondary electromagnetic (EM) field corresponding to the signal transmitted from the CSEM transmitter, the secondary EM field being coupled to a streaming potential at a location where fluid is injected into the subsurface formation; measuring the secondary EM field; as well as Reservoir simulation is performed based on the injection rate or the backflow rate by inverting an objective function based on the secondary EM field and a function converting a pressure or a gradient of a pressure field into the secondary EM field.

9. The method according to claim 8, wherein: Positioning the plurality of CSEM receivers includes positioning the plurality of CSEM receivers above an area where fluid is injected into the subsurface formation.

10. A method for calculating electric and magnetic fields in a subsurface formation, comprising: positioning a controlled source electromagnetic CSEM transmitter on the surface of the earth relative to the borehole; positioning a plurality of CSEM receivers relative to the borehole, synchronized with the CSEM transmitter; transmitting a signal from the CSEM transmitter to a subsurface formation surrounding the borehole; receiving, by the plurality of CSEM receivers, a secondary electromagnetic (EM) field corresponding to the signal transmitted from the CSEM transmitter, the secondary EM field being coupled to a streaming potential at a location where fluid is injected into the subsurface formation; measuring the secondary EM field; as well as Calculate streaming potential current based on the cross-coupling coefficient between fluid flow and current flow and the pressure field; Calculates electric and magnetic fields based on the excitation current and streaming potential current.

11. The method according to claim 10, further comprising: Based on the secondary EM field and a function that converts the pressure or the gradient of the pressure field into the secondary EM field, an objective function is inverted.

12. The method according to claim 10, wherein: The pressure field is derived by running a reservoir simulation based on fluid flow.

13. The method according to claim 10, wherein: The pressure field is derived by solving a combination of poroelastic fluid flow and mechanics equations.

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