Patent Application
20160161630
Nuclear Magnetic Resonance (NMR) tools used for well-logging and downhole fluid characterization measure the response of nuclear spins in formation fluids to applied magnetic fields. Downhole NMR tools typically have a permanent magnet that produces a static magnetic field at a desired test location (e.g., where the fluid is located). The static magnetic field produces a magnetization in the fluid. The magnetization is aligned along the direction of the static field. The magnitude of the induced magnetization is proportional to the magnitude of the static field. A transmitter antenna produces a time-dependent radio frequency magnetic field that has a component perpendicular to the direction of the static field. The NMR resonance condition is satisfied when the radio frequency is equal to the Larmor frequency, which is proportional to the magnitude of the static magnetic field and the gyromagnetic ratio of the particular nuclear spin. The radio frequency magnetic field produces a torque on the magnetization vector that causes it to rotate about the axis of the applied radio frequency field. The rotation results in the magnetization vector developing a component perpendicular to the direction of the static and time varying magnetic fields. The magnetization vector then precesses around the static field at the Larmor frequency. At resonance between the Larmor and transmitter frequencies, the magnetization is tipped to the transverse plane (i.e., a plane normal to the static magnetic field vector). A series of radio frequency pulses are applied to generate spin echoes that are measured with the antenna.
NMR measurements can be used to estimate, among other things, formation porosity. For example, the area under the curve of a T2 distribution for a NMR measurement can be equated to or at least provides an estimate of the NMR-based porosity. The T2 distribution may also resemble the pore size distribution in water-saturated rocks. The raw reported porosity is provided by the ratio of the initial amplitude of the raw decay and the tool response in a water tank. This porosity is independent of the lithology of the rock matrix.
Another formation parameter is permeability. The typical laboratory technique for direct permeability measurement is to flow a fluid through a formation sample, thereby inducing a pressure gradient ΔP across the sample and measuring the fluid flux q. For a fluid of unit viscosity, these quantities are related to the sample permeability, k, through Darcy's law:
Thus, the permeability of the sample can be determined if the pressure gradient and the fluid flux are known. If the fluid is other than water, then the right hand side of Eq. (1) is multiplied by the fluid viscosity.
Enhanced oil recovery, employed after the primary recovery phase for a reservoir is essentially exhausted, may include injecting external fluid such as water or gas into the reservoir through injection wells located in rock that has fluid communication with one or more production wells. The purpose of such enhanced recovery is to maintain reservoir pressure and to displace hydrocarbons toward a production wellbore. The most common enhanced oil recovery techniques are gas injection and water flooding.
A NMR logging tool is provided and disposed at some desired depth in a wellbore penetrating a subsurface formation. A first set of NMR measurements is made over a desired depth range and depth of investigation, wherein the first set of NMR measurements includes a first NMR signal intensity. Supercritical carbon dioxide is injected into the formation and a second set of NMR measurements is made over the desired depth range and depth of investigation, wherein the second set of NMR measurements includes a second NMR signal intensity. The first NMR signal intensity is compared to the second NMR signal intensity and one or more properties of the formation are inferred using the compared NMR measurements. A magnetic field gradient that varies a static magnetic field along a desired spatial dimension of a region of investigation may be provided to map a rate of fluid movement.
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.
The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion. Embodiments are described with reference to the following figures. The same numbers are generally used throughout the figures to reference like features and components.
It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.
Some embodiments will now be described with reference to the figures. Like elements in the various figures may be referenced with like numbers for consistency. In the following description, numerous details are set forth to provide an understanding of various embodiments and/or features. However, it will be understood by those skilled in the art that some embodiments may be practiced without many of these details and that numerous variations or modifications from the described embodiments are possible. As used here, the terms “above” and “below”, “up” and “down”, “upper” and “lower”, “upwardly” and “downwardly”, and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe certain embodiments. However, when applied to equipment and methods for use in wells that are deviated or horizontal, such terms may refer to a left to right, right to left, or diagonal relationship, as appropriate. It will also be understood that, although the terms first, second, etc. may be used herein to describe various elements, these elements should not be limited by these terms. These terms are only used to distinguish one element from another.
The terminology used in the description herein is for the purpose of describing particular embodiments only and is not intended to be limiting. As used in the description and the appended claims, the singular forms “a”, “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will also be understood that the term “and/or” as used herein refers to and encompasses any and all possible combinations of one or more of the associated listed items. It will be further understood that the terms “includes,” “including,” “comprises,” and/or “comprising,” when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof.
As used herein, the term “if” may be construed to mean “when” or “upon” or “in response to determining” or “in response to detecting,” depending on the context. Similarly, the phrase “if it is determined” or “if [a stated condition or event] is detected” may be construed to mean “upon determining” or “in response to determining” or “upon detecting [the stated condition or event]” or “in response to detecting [the stated condition or event],” depending on the context.
The magnetic resonance logging device 30 may include a permanent magnet or permanent magnet array 22, which may, for example, comprise samarium-cobalt magnetic material, and one or more RF antennas 24. The region of investigation, or sensitivity zone, represented generally at 27, is a region in the formation in which the static magnetic field is generally uniform, except for local gradients, although this is not necessarily required for operation in accordance with this disclosure. It is understood that other suitable tool configurations can be used.
A system and method to use Nuclear Magnetic Resonance (NMR) logging in injection, observation, and production wells to monitor carbon dioxide (CO2) concentrations during CO2 flooding operations is disclosed. Since common NMR logging tools are only equipped to measure proton NMR, they are not directly sensitive to the presence or concentration of CO2. However, when CO2 is mixed with water or oil, it causes those materials to be diluted, thereby lowering their NMR signal intensities. This is equivalent to a negative NMR signal that can be used favorably to monitor de-saturation changes and adjust CO2 flooding operations, if needed. The carbon/oxygen ratio can also be measured and integrated with the NMR measurements to derive information on carbonic acid saturation and dissolved CO2 volumes in various fluid phases. (Generally the CO2 is both dissolved and disassociated. As used herein, the term “dissolved” includes both dissolution and disassociation.)
CO2 flooding is one common method used for enhanced oil recovery. The technique is considered a “tertiary” recovery technique, meaning it is normally used to extract more oil after a “secondary” recovery technique (e.g., water flooding) has been exhausted and no longer effectively produces oil. In one embodiment, CO2 at high pressure and high temperature is injected into an injection well. The pressure and temperature are chosen to ensure the CO2 is in a supercritical state; that is, it is in fluid phase. The fluid CO2 partly dissolves in the water phase (of the formation fluid) and forms carbonic acid, which in turn causes some dissolution of the carbonate matrix (if in a carbonate formation), but this is not considered the main mechanism of enhanced production from CO2 flooding. Rather, the majority of the CO2, which is a non-polar molecule, mixes with the oil phase residing in the pore space of the rock and causes a viscosity and density reduction of the oil, thereby allowing the oil to move through the rock pore space and be produced. To optimize the flooding operation, the CO2 concentration may be monitored as a function of time and space around the injection well.
Various factors can affect the success of a CO2 flooding operation. These include, but are not limited to, (1) the relative permeability of the CO2 fluid in the particular rock comprising the formation; (2) the relative permeability of the oil/CO2 mixture as a function of a ratio of those two materials; (3) the partition of fluid CO2 between formation water and formation oil; and (4) the rate of oil recovery as a function of CO2. Measurement of those parameters is not a trivial task because very few measurement techniques are sensitive to CO2 . For example, the most common logging measurement, resistivity, cannot distinguish between CO2 and oil since both are electrically non-conductive.
NMR may be used to study some of the above parameters at high pressure and temperature. As stated above, the proton-sensitive NMR tool that is commonly used in the field of oil well logging is not able to directly detect CO2 because there are no hydrogen atoms in the CO2 molecule. As a result, no attempts have been made to study CO2 with this technique.
However, added CO2 can dilute the oil and/or water phases of the formation fluid, for example, and cause the NMR signal intensity (from the oil and/or water phases) to decrease. In essence, the CO2 adds a negative intensity to the normal signal and causes a reduced NMR signal that, when compared with the signal before CO2 injection, provides information about the concentration and flow rate of the injected CO2.
In one embodiment, a laboratory NMR instrument having a high pressure/high temperature (HPHT) sample holder is set up as shown in
These measurements can be repeated using a rock core plug that is saturated with oil and/or with water. NMR measurements on the fully saturated core provide a background or control value. Then SCC is injected into the core plug and the NMR signal is measured again. The NMR signal will decrease and the quantified extent of this decrease may be applied to cases in which measurements are performed on the formation, such as the in the example below.
An NMR logging tool making measurements in an injection well may be used to quantify the CO2 in situ. As shown in
In the field of NMR measurement it is common to separate the measured NMR intensity into the fraction originating from oil and that from water. This is commonly done by measuring diffusion and T2 relaxation of the fluid mixture and generating a two dimensional D-T2 distribution.
Some low frequency laboratory and downhole NMR instruments are equipped to produce “one-dimensional” NMR images. In this case, an external magnetic field gradient is provided that varies the static (DC) magnetic field along the axial length of the core sample (i.e., for a lab sample or region of investigation in a wellbore, produces a non-homogeneous static field over the axial length of the sample). The gradient may arise naturally from an inherent reduction in field strength with distance from the magnetic source, or it may be expressly generated using additional magnetic sources such as one or more electric coils (“gradient coils”). Thus, each point (i.e., NMR signal source) in a plane perpendicular to the sample axis resonates at a different Larmor frequency than points (e.g., hydrogen protons) in other such planes. Therefore, when a particular frequency is sampled, one knows the resulting NMR signal is from a corresponding axial location on the sample. As a result, the NMR signal as a function of location along the length of the core sample may be obtained and imaged along one axis (i.e., 1-D imaging).
By “imaging”, we mean a collection of measurements made at different depths of investigations (DOIs). Certain NMR tools, such as those having no explicit gradient-generating device (i.e., no coils, but instead rely on natural fall-off of field strength with distance), may be programmed to produce a set number (e.g., four) of depths of investigation. However, other NMR tools, particularly those with explicit gradient-generating devices, can have a higher radial resolution (i.e., greater number of DOIs).
The image can have an axial resolution of 1 mm or less. Thus, a standard 50 mm long rock sample can be imaged into at least 50 slices with known NMR signal intensities (or T2 distributions) before injection of any SCC, as shown in
The above-determined relative permeability can be used to calculate the expected time it takes for a known volume of SCC to travel from an injection well to one or more observation or production wells. This is shown in
Some of the methods and processes described above, including processes, as listed above, can be performed by a processor. The term “processor” should not be construed to limit the embodiments disclosed herein to any particular device type or system. The processor may include a computer system. The computer system may also include a computer processor (e.g., a microprocessor, microcontroller, digital signal processor, or general purpose computer) for executing any of the methods and processes described above.
The computer system may further include a memory such as a semiconductor memory device (e.g., a RAM, ROM, PROM, EEPROM, or Flash-Programmable RAM), a magnetic memory device (e.g., a diskette or fixed disk), an optical memory device (e.g., a CD-ROM), a PC card (e.g., PCMCIA card), or other memory device.
Some of the methods and processes described above, as listed above, can be implemented as computer program logic for use with the computer processor. The computer program logic may be embodied in various forms, including a source code form or a computer executable form. Source code may include a series of computer program instructions in a variety of programming languages (e.g., an object code, an assembly language, or a high-level language such as C, C++, or JAVA). Such computer instructions can be stored in a non-transitory computer readable medium (e.g., memory) and executed by the computer processor. The computer instructions may be distributed in any form as a removable storage medium with accompanying printed or electronic documentation (e.g., shrink wrapped software), preloaded with a computer system (e.g., on system ROM or fixed disk), or distributed from a server or electronic bulletin board over a communication system (e.g., the Internet or World Wide Web).
Alternatively or additionally, the processor may include discrete electronic components coupled to a printed circuit board, integrated circuitry (e.g., Application Specific Integrated Circuits (ASIC)), and/or programmable logic devices (e.g., a Field Programmable Gate Arrays (FPGA)). Any of the methods and processes described above can be implemented using such logic devices.
While the embodiments described above particularly pertain to the oil and gas industry, this disclosure also contemplates and includes potential applications such as underground environmental spill monitoring and clean-up where either air, N2, CO2, or some other non-protonic agent is used. (That is, an agent that does not produce a NMR signal and thereby affects the NMR response similar to the manner in which CO2 does.) As used herein, the phrase “supercritical carbon dioxide” may include all such non-protonic agents.
The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the present disclosure. Those skilled in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. Those skilled in the art should also realize that such equivalent constructions do not depart from the scope of the present disclosure, and that they may make various changes, substitutions, and alterations herein without departing from the scope of the present disclosure.
The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. §1.72(b) to allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.
While only certain embodiments have been set forth, alternatives and modifications will be apparent from the above description to those skilled in the art. These and other alternatives are considered equivalents and within the scope of this disclosure and the appended claims. Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.
This application claims, under 35 U.S.C. §119(e), priority to and the benefit of U.S. Provisional Application No. 62/087,993, filed Dec. 5, 2014. This application is a continuation application of and, under 35 U.S.C. §120, claims priority to and the benefit of U.S. Nonprovisional application Ser. No. 14/886,187, filed Oct. 19, 2015, which also claims priority to and the benefit of U.S. Provisional Application No. 62/087,993, filed Dec. 5, 2014.
| Number | Date | Country | |
|---|---|---|---|
| 62087993 | Dec 2014 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 14886187 | Oct 2015 | US |
| Child | 14886593 | US |
