ANISOTROPY MEASUREMENTS BY FORMATION TESTER TRACER MEASUREMENTS

Abstract

Aspects of the subject technology relate to systems, methods, and computer readable media for determining a parameter of a formation based on withdrawal of an injected tracer solution. A changing concentration profile of a volume of tracer solution that is withdrawn from a formation is measured. A varying simulated concentration profile associated with the tracer solution in a simulated formation is generated by modifying simulated formation parameters of the simulated formation. The varying simulated concentration profile is compared to the changing concentration profile of the volume of tracer solution that is withdrawn from the formation. A parameter of the formation is identified based on a comparison of the varying simulated concentration profile to the changing concentration profile of the volume of tracer solution withdrawn from the formation.

Description

TECHNICAL FIELD

The present technology pertains to determining anisotropy measurements of a formation through flow path tracing, and more particularly, to determining anisotropy measurements of a formation through an inversion technique and based on withdrawal of an injected tracer solution.

BACKGROUND

During the drilling and completion of oil and gas wells, it may be necessary to engage in ancillary operations, such as monitoring the operability of equipment used during the drilling process or evaluating the production capabilities of formations intersected by the wellbore. For example, after a well or well interval has been drilled, zones of interest are often tested to determine various formation properties such as permeability, fluid type, fluid quality, formation temperature, formation pressure, and formation pressure gradient. These tests are performed in order to determine whether commercial exploitation of the intersected formations is viable and how to optimize production. Various tools and measurement techniques have been developed for evaluating formations through wellbores. For example, formation testers have been developed that probe the formation to identify formation properties.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to describe the manner in which the features and advantages of this disclosure can be obtained, a more particular description is provided with reference to specific embodiments thereof which are illustrated in the appended drawings. Understanding that these drawings depict only exemplary embodiments of the disclosure and are not therefore to be considered to be limiting of its scope, the principles herein are described and explained with additional specificity and detail through the use of the accompanying drawings in which:

FIG. 1 illustrates a schematic diagram of a system for drilling operations;

FIG. 2 illustrates the formation testing tool in greater detail;

FIG. 3 illustrates a flowchart for an example method of determining a permeability anisotropy of a formation by injecting and withdrawing a tracer solution;

FIG. 4 illustrates a schematic diagram of a downhole environment with a formation tester disposed in a wellbore with a first probe and a second probe set into a surrounding formation;

FIG. 5A is a simulated representation of a formation before tracer solution is injected into the formation;

FIG. 5B is a simulated representation of the formation after the tracer solution is injected into the formation;

FIG. 6A illustrates a graph of a fraction of tracer solution that is pumped out of a first probe and a second probe versus time for a formation with an anisotropic permeability of 0.5;

FIG. 6B illustrates a graph of a fraction of a tracer solution that is pumped out of a first probe and a second probe versus time for a formation with a smaller anisotropy in comparison to the formation represented by the responses in FIG. 6A;

FIG. 7 illustrates a flowchart for an example method of identifying formation parameters based on a comparison of varying simulated concentration profiles and a changing concentration profile of withdrawn tracer solution

FIG. 8 illustrates an example computing device architecture which can be employed to perform various steps, methods, and techniques disclosed herein.

DETAILED DESCRIPTION

Various embodiments of the disclosure are discussed in detail below. While specific implementations are discussed, it should be understood that this is done for illustration purposes only. A person skilled in the relevant art will recognize that other components and configurations may be used without parting from the spirit and scope of the disclosure.

Additional features and advantages of the disclosure will be set forth in the description which follows, and in part will be obvious from the description, or can be learned by practice of the principles disclosed herein. The features and advantages of the disclosure can be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims. These and other features of the disclosure will become more fully apparent from the following description and appended claims or can be learned by the practice of the principles set forth herein.

It will be appreciated that for simplicity and clarity of illustration, where appropriate, reference numerals have been repeated among the different figures to indicate corresponding or analogous elements. In addition, numerous specific details are set forth in order to provide a thorough understanding of the embodiments described herein. However, it will be understood by those of ordinary skill in the art that the embodiments described herein can be practiced without these specific details. In other instances, methods, procedures, and components have not been described in detail so as not to obscure the related relevant feature being described. The drawings are not necessarily to scale and the proportions of certain parts may be exaggerated to better illustrate details and features. The description is not to be considered as limiting the scope of the embodiments described herein.

Understanding the anisotropy of a reservoir is crucial for effective oil and gas operations. Anisotropy, the property by which the measure of a material's physical property changes with direction, can significantly impact the flow of hydrocarbons in a reservoir. It affects the reservoir's production, and thus, the ease with which oil and gas can be extracted. Accurate measurement of anisotropy can lead to more precise reservoir models, better production forecasts, and more efficient extraction strategies, ultimately optimizing the economic return from a reservoir.

Currently, formation testers are commonly used to measure anisotropy. These tools typically involve two probes: a drawdown probe and a monitor probe. The drawdown probe creates a pressure differential in the formation, and the monitor probe measures the pressure at a distance from the drawdown probe. By comparing the observed pressure at the monitor probe with the expected pressure based on an isotropic model, the anisotropy of the formation can be inferred.

However, this pressure-based approach has several challenges. Firstly, making hydraulic contact with the formation can be difficult, particularly in low-permeability or highly fractured formations. Secondly, the pressure differential created by the drawdown probe can be very small at a sufficiently large distance from the probe, making it difficult to obtain a representative measurement of anisotropy. Lastly, this method assumes a homogeneous medium, an assumption that often does not hold in complex geological formations.

The disclosed technology addresses the foregoing by determining anisotropy measurements of a formation through flow path tracing using a tracer solution injected into the formation. Specifically, anisotropy measurements of a formation can be determined through an inversion technique and based on withdrawal of an injected tracer solution. More specifically, tracer monitoring through an injected tracer solution presents a promising alternative to overcome the foregoing for various reasons. In a tracer test, a detectable substance can be injected into the formation, and its movement can be monitored over time. This approach can provide direct information about the flow paths in the reservoir, which can be particularly useful in complex or fractured reservoirs. Moreover, tracer tests can provide information about a larger volume of the reservoir compared to pressure measurements, providing a more representative measurement of the reservoir's properties.

Darcy's law is a fundamental principle in fluid dynamics that describes the flow of fluid through a porous medium. In its simplest form, it states that the flow rate of a fluid through a porous medium is proportional to the pressure gradient across the medium and inversely proportional to the fluid's viscosity. However, in anisotropic media, where the permeability varies with direction, Darcy's law becomes more complex. In such cases, the permeability becomes a tensor rather than a scalar, and the flow rate is calculated separately for each direction. The flow rates in the x, y, and z directions, denoted as Qx, Qy, and Qz, are given by −(kx/μ)*(dp/dx), −(ky/μ)*(dp/dy), and −(kz/μ)*(dp/dz), respectively, where kx, ky, and kz are the permeabilities in the respective directions, is the viscosity of the fluid, and dp/dx, dp/dy, and dp/dz are the pressure gradients in the respective directions. This extension of Darcy's law allows for a more accurate description of fluid flow in anisotropic reservoirs, which is crucial for effective reservoir management.

In the context of reservoir management, it's often assumed that the horizontal permeability (in the X and Y directions) is equal and greater than the vertical permeability (in the Z direction). This assumption is largely based on the depositional environment and the presence of bedding planes in sedimentary rocks, which are the most common reservoir rocks. During sediment deposition, layers or beds are formed, with the spaces between the grains within a layer providing pathways for fluid flow. These pathways are typically more interconnected in the horizontal direction, along the bedding planes, leading to higher horizontal permeability. Conversely, the vertical permeability is often lower due to the reduced connectivity of the pore spaces across the bedding planes. The ratio of horizontal to vertical permeability, often denoted as kv/kh, is a common measure of anisotropy in the oil and gas industry. This ratio provides a quantifiable measure of the degree to which the reservoir's permeability varies with direction, which is crucial for accurate reservoir modeling and efficient resource extraction. Darcy's law with the simplifying assumptions in a reservoir environment may be used to derive a flow model, as will be discussed in greater detail later, for interpreting a set of tracer injections with respect to anisotropy.

FIG. 1 illustrates a schematic diagram of a system 100 for drilling operations. It should be noted that the system 100 can also include a system for pumping operations, or other operations. The system 100 includes a drilling rig 102 located at a surface 104 of a well. The drilling rig 102 provides support for a down hole apparatus, including a drill string 108. The drill string 108 penetrates a rotary table 110 for drilling a borehole 112 through subsurface formations 114. The drill string 108 includes a Kelly 116 (in the upper portion), a drill pipe 118 and a bottom hole assembly 120 (located at the lower portion of the drill pipe 118). The bottom hole assembly 120 may include drill collars 122, a downhole tool 124 and a drill bit 126. The downhole tool 124 may be any of a number of different types of tools including measurement-while-drilling (MWD) tools, logging-while-drilling (LWD) tools, etc.

During drilling operations, the drill string 108 (including the Kelly 116, the drill pipe 118 and the bottom hole assembly 120) may be rotated by the rotary table 110. In addition or alternative to such rotation, the bottom hole assembly 120 may also be rotated by a motor that is downhole. The drill collars 122 may be used to add weight to the drill bit 126. The drill collars 122 also optionally stiffen the bottom hole assembly 120 allowing the bottom hole assembly 120 to transfer the weight to the drill bit 126. The weight provided by the drill collars 122 also assists the drill bit 126 in the penetration of the surface 104 and the subsurface formations 114.

During drilling operations, a mud pump 132 optionally pumps drilling fluid, for example, drilling mud, from a mud pit 134 through a hose 136 into the drill pipe 118 down to the drill bit 126. The drilling fluid can flow out from the drill bit 126 and return back to the surface through an annular area 140 between the drill pipe 118 and the sides of the borehole 112. The drilling fluid may then be returned to the mud pit 134, for example via pipe 137, and the fluid is filtered.

The downhole tool 124 may include one to a number of different sensors 145, which monitor different downhole parameters and generate data that is stored within one or more different storage mediums within the downhole tool 124 and communicated to the surface. The type of downhole tool 124 and the type of sensors 145 thereon may be dependent on the type of downhole parameters being measured. Such parameters may include the downhole temperature and pressure, the various characteristics of the subsurface formations (such as resistivity, radiation, density, porosity, etc.), the characteristics of the borehole (e.g., size, shape, etc.), etc. Further, and as will be discuss in greater detail later, the downhole tool 124 can include one or more fluid identification sensors for measuring a changing concentration of a tracer solution that is injected into the formation.

The downhole tool 124 further includes a power source 149, such as a battery or generator. A generator could be powered either hydraulically or by the rotary power of the drill string. The downhole tool 124 includes a formation testing tool 150, which can be powered by power source 149. In an embodiment, the formation testing tool 150 is mounted on a drill collar 122. The formation testing tool 150 includes a probe that engages the wall of the borehole 112 and extracts a sample of the fluid in the adjacent formation via a flow line. The probe can include one or more inner channels and one or more outer channels, where the one or more outer channels captures more contaminated fluid than the one or more inner channels. As will be described later in greater detail, the probe samples the formation and, in an option, inserts a fluid sample in a container 155. In an option, the tool 150 injects the carrier 155 into the return mud stream that is flowing intermediate the borehole wall 112 and the drill string 108, shown as drill collars 122 in FIG. 1. The container(s) 155 flow in the return mud stream to the surface and to mud pit or reservoir 134. A carrier extraction unit 160 is provided in the reservoir 134, in an embodiment. The carrier extraction unit 160 removes the carrier(s) 155 from the drilling mud.

FIG. 1 further illustrates an embodiment of a wireline system 170 that includes a downhole tool body 171 coupled to a base 176 by a logging cable 174. The logging cable 174 may include, but is not limited to, a wireline (multiple power and communication lines), a mono-cable (a single conductor), and a slick-line (no conductors for power or communications). The base 176 is positioned above ground and optionally includes support devices, communication devices, and computing devices. The tool body 171 houses a formation testing tool 150 that acquires samples from the formation. In an embodiment, the power source 149 is positioned in the tool body 171 to provide power to the formation testing tool 150. The tool body 171 may further include additional testing equipment 172. In operation, a wireline system 170 is typically sent downhole after the completion of a portion of the drilling. More specifically, the drill string 108 creates a borehole 112. The drill string is removed and the wireline system 170 is inserted into the borehole 112.

FIG. 2 illustrates the formation testing tool 150 in greater detail. As mentioned above, the formation testing tool 150 can be included on the wireline system 170 or a drilling system, for example. It should be noted the formation testing tool 150 can be included on other tools, including, but not limited to tools that lower themselves into the borehole. In FIG. 2, an example of the wireline system is shown with formation testing tool 150.

A portion of a borehole 201 is shown in a subterranean formation 207. The borehole wall is covered by a mud cake 205. The formation tester body 171 is connected to a wireline system 170 leading from a rig at the surface. The formation tester body 171 is provided with a mechanism, denoted by 210, to clamp the tester body at a fixed position in the borehole. In an option, the clamping mechanism 210 is at the same depth as a probe. Other mechanisms for engaging the probe with the borehole include, but are not limited to inflatable packers.

In an exam pie, a clamping mechanism 210 and a fluid sampling pad 213 are extended and mechanically pressed against the borehole wall. The fluid sampling pad 213 includes a probe that has one or more outer channels 156, and one or more inner channels 154. The inner channel(s) 154 is disposed within at least a portion of the outer channel(s) 156. In an option, the inner channel(s) 154 is extended from the center of the pad, through the mud cake 205, and pressed into contact with the formation. For instance, the inner channel(s) 156 is connected by a hydraulic flow line 223a to an inner channel sample chamber 227a. In another option, the fluid sample pad 213 is extended via extendable members 211, and the inner and outer channels 154, 156 can contact the formation. In an option, flow lines 223a, 223b for the inner and/or outer channels 154, 156 extend through the extendable members 211, and to their respective channels. In a further option, the probe is an articulating probe, where the probe can hinge at one or more locations 184 to contact the surface of a formation and borehole more readily.

The outer channel(s) 156 has one or more openings 158 there along, the openings being hydraulic connected with the formation thru the channel. Optionally the outer channel(s) can be directly contacting the formation. All of the openings can be connected to one or more hydraulic lines within the body of the tool. In an option, the outer channel(s) 154 is connected by its own hydraulic flow line, 223b, to an outer channel sample chamber, 227b. Because the flow line 223a of the inner channel(s) 154 and the flow line 223b of the outer channel(s) 156 are separate, the fluid flowing into the outer channel(s) 156 does not mix with the fluid flowing into the inner channel(s) 154. The outer channel(s) can 156 isolate the flow into the inner channel(s) 154 from the borehole beyond the pad 213. In a further example, the inner channel flow line 223a and/or the outer channel flow line 223b extend through extendable members 204 (FIGS. 6 and 7).

The hydraulic flow lines 223a and 223b are optionally provided with pressure transducers 211a and 211b. In an option, the pressure maintained in the outer channel flowline 223b is the same as, or slightly less than, the pressure in the inner channel flowline 223a. In another option, the pressure ratio maintained in the inner channel flow line 223a to the outer channel flow line 223b is about 2:1 to 1:2. In another option, the flow rates of the inner channel(s) 154 and the outer channel(s) 156 are regulated. For example, the flow rate ration of the inner channel(s) 154 to the outer channel(s) 156 is about 2:1 to 1:2. With the configuration of the pad 213 and the outer channel(s) 156, contaminated borehole fluid that flows around the edges of the pad 213 is drawn into the outer channel(s) 156, and diverted from entry into the inner channel(s) 154.

The flow lines 223a and 223b are optionally provided with pumps 221a and 221b, or other devices for flowing fluid within the flow lines. The pumps 221a and 221b are operated long enough to substantially deplete the invaded zone in the vicinity of the pad 213 and to establish an equilibrium condition in which the fluid flowing into the inner channel(s) 154 is substantially free of contaminating borehole filtrate.

The flow lines 223a and 223b are also provided with fluid identification sensors, 219a and 219b. This makes it possible to compare the composition of the fluid in the inner channel flowline 223a with the fluid in the outer channel flowline. As sampling proceeds, if the borehole fluid continues to flow from the borehole towards the inner channel(s) 154, the contaminated fluid is drawn into the outer channel(s) 156. Pumps 221a and 221b discharge the sampled fluid into the borehole. At some time, an equilibrium condition is reached in which contaminated fluid is drawn into the outer channel(s) 156 and uncontaminated fluid is drawn into the inner channel(s) 154. The fluid identification sensors 219a and 219b are used to determine when this equilibrium condition has been reached. At this point, the fluid in the inner channel flowline is free or nearly free of contamination by borehole fluids. Valve 225a is opened, allowing the fluid in the inner channel flowline 223a to be collected in the inner channel sample chamber 227a. Similarly, by opening valve 225b, the fluid in the outer channel flowline 223b is collected in the outer channel sample chamber 227b. Alternatively, the fluid gathered in the outer channel(s) can be pumped to the borehole while the fluid in the inner channel flow line 223a is directed to the inner channel sample chamber 227a. Sensors that identify the composition of fluid in a flowline can also be provided, in an option.

The previous discussion of a formation tester with multiple channels to sample fluid from a formation is merely an example tester, and the technology described herein can be implemented through a formation tester that utilizes a single channel to sample fluid through one or more probes.

The disclosure now continues with a discussion of systems and techniques for identifying formation parameters through a tracer solution. Specifically, FIG. 3 illustrates a flowchart for an example method of determining a permeability anisotropy of a formation by injecting and withdrawing a tracer solution. The method shown in FIG. 3 is provided by way of example, as there are a variety of ways to carry out the method. Additionally, while the example method is illustrated with a particular order of steps, those of ordinary skill in the art will appreciate that FIG. 3 and the modules shown therein can be executed in any order and can include fewer or more modules than illustrated. Each module shown in FIG. 3 represents one or more steps, processes, methods or routines in the method.

At step 300, a formation tester is disposed to a location within a wellbore. The formation tester can be disposed to the location through an applicable system. Specifically, the formation tester can be disposed to the location through a wireline system. Further, the formation tester can be disposed to the location as part of an applicable MWD tool or a LWD tool. As will be discussed in greater detail later, the formation tester can include applicable components for injecting a tracer solution into a formation accessible through the wellbore. For example, the formation tester can include probes and a tracer solution injection system, e.g. a pump and reservoir, for containing and pumping a volume of tracer solution into a formation through one of the probes. Further and as will be discussed in greater detail later, the formation tester can include applicable components for withdrawing fluid from a formation accessible through the wellbore. For example, the formation tester can include probes and a fluid withdrawal system, e.g. a pump, for withdrawing fluid including the tracer solution from a formation through one or more of the probes. Additionally and as will be discussed in greater detail later, the formation tester can include applicable components for identifying an amount of tracer solution that is withdrawn from a formation accessible through the wellbore. For example, the formation tester can include one or more fluid identification sensors that are configured to determine a changing concentration of tracer solution as the solution is withdrawn from a formation though one or more probes.

Once the formation tester is disposed to the location within the wellbore, at step 302, a plurality of probes of the formation tester are set into a formation at the location within the wellbore. Specifically, FIG. 4 illustrates a schematic diagram of a downhole environment with a formation tester 402 disposed in a wellbore 400 with a first probe 404 and a second probe 406 set into a surrounding formation 408. In the example downhole environment, the formation tester 402 is only shown as having two probes that are set into the formation 408, however, the technology described herein can be implemented through a formation tester that has more than two probes that can be set into a formation to inject tracer solution and withdraw fluid. As part of setting the probes into the formation, the probes can engage the formation such that fluid communication is established between the formation and the formation tester through the probes. For example, the probes can be pushed into the formation such that tracer solution can be injected into the formation through the probes and fluid can be withdrawn from the formation the probes.

Probes of the formation tester can be disposed at specific positions with respect to each other. Specifically, the first probe 404 and the second probe 406 can be positioned at a set distance from each other. For example, the first probe 404 and the second probe 406 can be spaced 7.25 inches from each other. As will be discussed in greater detail later, the permeability anisotropy of the formation can be identified based on the set positions at which the probes of the formation tester are disposed with respect to each other. More specifically, the permeability anisotropy of the formation can be determined based on the distance between the first and second probes 404 and 406 and a concentration at which tracer solution is withdrawn by either or both of the first and second probes 404 and 406.

Returning back to the flowchart shown in FIG. 3, at step 304, a tracer solution is injected into the formation through one of the plurality of probes. A tracer solution can include an applicable solution with a distinguishing feature from a formation fluid of a formation. Specifically, a distinguishing feature of a tracer solution can be detected to distinguish the tracer solution from formation fluid of a formation into which the tracer solution is injected. More specifically, an amount of distinguishing feature of a tracer solution in a volume of fluid that is withdrawn from a formation can be used to determine a volume of the tracer solution in the volume of fluid. An example of a distinguishing feature is a dye material of a tracer solution that is optically distinguishable from a formation fluid. In turn, an amount of the dye material of the tracer solution in the formation fluid that is withdrawn from the formation can be used in identifying a varying concentration of the tracer solution in the formation fluid as it is withdrawn from the formation. Distinguishing features of the tracer solution include applicable features that can be detected by an applicable technique such as an optical measurement technique, a resistivity measurement technique, a density measurement technique, a viscosity measurement technique, an acoustic measurement technique, a nuclear measurement technique, a nuclear magnetic resonance measurement technique, or a combination thereof.

After injecting the tracer solution into the formation, the tracer solution will be distributed into the formation and the fluid's spatial distribution will depend on the permeability anisotropy of the formation. For example, in an isotropic formation, the tracer solution can distribute spherically, forming an invasion profile represented by a spheroid. If the anisotropy is low (kv<kh), then the tracer solution will invade deep horizontally and less vertically, forming an invasion profile represented by an oblate spheroid. If the anisotropy is high (kv>kh), then the tracer solution will invade faster vertically than horizontally, forming an invasion profile represented by a prolate spheroid.

FIGS. 5A and 5B represent a distribution of a tracer solution in a formation. Specifically, FIG. 5A is a simulated representation of a formation before tracer solution is injected into the formation. FIG. 5B is a simulated representation of the formation after the tracer solution is injected into the formation. Specifically and as shown in FIG. 5B the tracer solution is injected through the first probe P1 for a period of ten minutes. Further and as shown in FIG. 5B, the tracer solution spreads to a region of the formation in which the second probe P2 is in fluid communication with the formation. The formation represented in FIGS. 5A and 5B is an isotropic formation.

The tracer solution can be injected into the formation until a specific volume of the tracer solution has been injected into the formation. The specific volume of the tracer solution to inject into the formation can be selected based on specific factors related to determining characteristics of the formation based on the injected tracer solution. For example, the specific volume of the tracer solution to inject into the formation can be selected based on known characteristics of the formation in relation to determining permeability anisotropy of the formation. Further, the tracer solution can be injected into the formation after a specific amount of time has passed since beginning injection of the tracer solution into the formation. The specific amount of time to inject the tracer solution into the formation can be selected based on specific factors related to determining characteristics of the formation based on the injected tracer solution. For example, the specific amount of time for injecting the tracer solution into the formation can be selected based on known characteristics of the formation in relation to determining permeability anisotropy of the formation.

After the tracer solution is injected into the formation, a fluid can be continuously withdrawn from the formation over a specific time interval. The fluid that is withdrawn from the formation can include either or both tracer solution and formation fluid. Specifically, the fluid that is withdrawn from the formation can comprise no tracer solution, almost pure tracer solution, or a changing concentration of tracer solution within formation fluid as the fluid is withdrawn from the formation over time, e.g. a time interval. For example, and with respect to the distribution profile shown in FIG. 5B, the first and second probes can be used to withdraw fluid from the formation. As shown in the distribution profile, a volume of the tracer solution is in fluid communication with the first and second probes. Therefore, initially fluid that is withdrawn through the probes will have a high concentration of tracer solution. The concentration of tracer solution will begin to decrease as more and more fluid is withdrawn from the formation. The changing concentration of the tracer solution as fluid is withdrawn from the formation can be referred to as a concentration profile or concentration decay profile of the tracer solution.

Fluid can be withdrawn from the formation through an applicable number of probes of the formation tester that are set into the formation. For example and with respect to the environment shown in FIG. 4, fluid can be withdrawn from the formation 408 through both the first probe 404 and the second probe 406. In using multiple probes to withdraw fluid from the formation, the fluid can be withdrawn either sequentially or synchronously over different portions of a time interval during which the fluid is withdrawn. For example, fluid can first be withdrawn from the formation 408 through the first probe 404 and then the second probe 406 in a sequential manner. In another example, fluid can simultaneously be withdrawn from the formation 408 through both the first probe 404 and the second probe 406 in a synchronous manner.

At step 308, a changing concentration of the tracer solution that is withdrawn from the formation can be measured over the time interval. Specifically, the changing concentration of the tracer solution can be measured from the withdrawn fluid based on the volume of the tracer solution that is withdrawn from the formation over the time interval. More specifically, the changing concentration of the tracer solution can be measured and represented as a concentration decay profile of the tracer solution.

The changing concentration of the tracer solution in the fluid that is withdrawn from the formation can depend on the distribution profile of the tracer solution in the formation after it is injected into the formation. The distribution profile of the tracer solution in the formation can depend on characteristics of the formation, e.g. permeability anisotropy of the formation. Accordingly, the changing concentration of the tracer solution in the fluid that is withdrawn from the formation can be indicative of the characteristics of the formation, e.g. the permeability anisotropy of the formation.

The concentration of the tracer solution that is withdrawn from the formation can be measured through one or more fluid identification sensors. Specifically, the fluid identification sensors can measure the changing concentration of the tracer solution in the fluid that is withdrawn from the formation. The one or more fluid identification sensors can measure the concentration through an applicable technique, such as an optical measurement technique, a resistivity measurement technique, a density measurement technique, a viscosity measurement technique, an acoustic measurement technique, a nuclear measurement technique, a nuclear magnetic resonance measurement technique, or a combination thereof. For example, the fluid identification sensors can include nuclear magnetic resonance sensors that use nuclear magnetic resonance-based techniques to identify concentrations of the tracer solution in the fluid that is withdrawn from the formation.

At step 310, a permeability anisotropy of the formation is determined based on the changing concentration of the tracer solution that is withdrawn from the formation over the time interval. Specifically, the concentration decay profiles of the tracer solution for the formation can be analyzed to determine the permeability anisotropy of the formation. More specifically, the concentration decay profiles of the tracer solution can be analyzed across probes that are used to withdraw the fluid from the formation to determine the permeability anisotropy of the formation. For example the concentration decay curve that is measured at the first probe 404 can be compared to the concentration decay curve that is measured at the second probe 406 to generate a decay ratio curve between the two probes. In turn, one or more analytical formulas can be applied to the decay ratio curve to identify permeability anisotropy.

In determining permeability anisotropy based on a changing concentration of the tracer solution that is withdrawn from the formation, the permeability anisotropy can be determined based on known positions of the probes relative to each other. Specifically, a model can be applied based on a known distance between probes to identify a permeability anisotropy. More specifically, the model can be applied to concentration decay curves of the corresponding probes and based on the known distance between the probes to identify a permeability anisotropy of a formation.

A model can be applied to corresponding tracer solution concentration profiles gathered by one or more probes to identify the permeability anisotropy of the formation. The model can represent varying permeability anisotropies as a function of varying tracer solution profiles, e.g. tracer solution decay profiles. The model can be trained using applicable sources of data and built through an applicable machine learning architecture. Specifically, concentration profile changes for various cases of formation and anisotropy properties can be simulated. As follows machine learning or statistical learning, e.g. Kriging, can be used to derive a model that relates the concentration profile and formation permeability anisotropy. Further, machine learning models can be trained based on known permeability data and observed concentration profile changes of tracer solution across varying formations.

Permeability anisotropy can also be determined based on measured pressure changes at the probes that are set in the formation. Specifically, permeability anisotropy can be determined based on both measured pressure changes at the probes and corresponding concentration profiles of the tracer solution that are measured at the probes. More specifically, corresponding pressure changes and tracer solution concentration decay curves can be observed and correlated, e.g. temporally, to accurately identify permeability anisotropy, e.g. in comparison to using just pressure changes to measure permeability.

The disclosure now continues with a discussion of the effect of anisotropy on permeability in formations, as observed through tracer solution concentration simulation. Specifically, FIG. 6A illustrates a graph of a fraction of tracer solution that is pumped out of a first probe and a second probe versus time for a formation with an anisotropic permeability of 0.5. FIG. 6B illustrates a graph of a fraction of a tracer solution that is pumped out of a first probe and a second probe versus time for a formation with a smaller anisotropy in comparison to the formation represented by the responses in FIG. 6A. As shown in both FIGS. 6A and 6B the withdrawal of tracer solution from the formation, e.g. during a pumpout phase, occurs at ten minutes. When comparing the responses of the first probes across the formations, represented by curves 602 and 604, a similar response is seen between the two formations. When comparing the responses of the second probes across the formations, represented by curves 606 and 608, differences in the responses are noticed. Specifically, the tracer solution concentration profile in the formation with the higher anisotropy, represented in FIG. 6B, decays slower than the formation with the smaller anisotropy, represented in FIG. 6B. This shows the effect of anisotropy on permeability in formations, as observed through tracer solution concentration simulation.

The disclosure now turns to a discussion of implementing an inversion technique to identify formation parameters based on a changing concentration profile of withdrawn tracer solution. Specifically, FIG. 7 illustrates a flowchart for an example method of identifying formation parameters based on a comparison of varying simulated concentration profiles and a changing concentration profile of withdrawn tracer solution. The method shown in FIG. 7 is provided by way of example, as there are a variety of ways to carry out the method. Additionally, while the example method is illustrated with a particular order of steps, those of ordinary skill in the art will appreciate that FIG. 7 and the modules shown therein can be executed in any order and can include fewer or more modules than illustrated. Each module shown in FIG. 7 represents one or more steps, processes, methods or routines in the method.

At step 700, a changing concentration profile of a volume of tracer solution that is withdrawn from a formation over a time interval is measured. The volume of tracer solution can be withdrawn through an applicable device, such as the formation testers described herein. Further, the volume of tracer solution can be withdrawn after being injected into a formation through an applicable device, such as the formation testers described herein.

The volume of tracer solution is withdrawn as part of a tracer test for identifying properties of the formation. A tracer test includes the process of injecting a tracer solution into a formation and withdrawing a volume of fluid from the formation that includes both formation fluid and the tracer solution that is injected into the formation. Tracer tests are advantageous, e.g. when compared to formation pressure tests, for numerous reasons. For example, tracer tests can provide information about a larger volume of the reservoir in comparison to pressure measurements, which are typically localized around the wellbore. This can provide a more representative measurement of the reservoir's properties. Further, tracer tests can provide direct information about the flow paths in the reservoir, which can be particularly useful in complex or fractured reservoirs where the flow paths may not be obvious. In some cases tracer measurements may be useful to map fracture networks. Additionally, tracer tests can be less sensitive to wellbore effects compared to pressure measurements. In comparison, pressure measurements can be affected by factors such as wellbore damage or skin effect, which can make it difficult to obtain accurate measurements of the reservoir's properties.

The tracer solution can be injected into the formation by a formation tester that contains the tracer solution downhole. Specifically, the tracer solution can be contained within the formation tester as the formation tester is disposed from the surface to a location in the wellbore. In turn, once the formation tester is at the location in the wellbore, then the contained tracer solution can be injected into the formation through one or more probes of the formation tester. The tracer solution can be injected into the formation at a varied rate over a time interval. As will be discussed in greater detail later, the rate at which the tracer solution is injected into the formation can influence its movement through the formation. As follows, insights into how the formation responds to different flow conditions can be gained by varying the injection rate. Further, the concentrations of one or more tracers in the tracer solution can be varied over a time interval. As will be discussed in greater detail later, the varying concentration level of injected tracers can facilitate greater insight into formation properties.

The injected tracer solution can include one or more tracer substances, otherwise referred to as tracers. A tracer is an applicable substance that can be detected after being injected into a formation and/or after being withdrawn from the formation. In various embodiments, a tracer can be easily detectable through an applicable detection mechanism, non-reactive with the reservoir fluids and rocks, not be naturally present in the reservoir, or a combination thereof. Furthermore, the tracer can fail to significantly alter the properties of formation fluids or flow behavior in the reservoir/formation.

Tracers used in reservoir studies can be broadly categorized into two types: conservative and reactive. Conservative tracers can include substances that do react with the reservoir rock or fluids and are used to study the physical flow of fluids in the reservoir. Examples of conservative tracers include salts and gases. Reactive tracers, on the other hand, can interact with the reservoir rock or fluids and can provide information about the chemical reactions occurring in the reservoir. Tracers can also be classified as passive or active. Passive tracers naturally exist in the reservoir and their concentrations are monitored over time. Active tracers are substances that can be artificially introduced into the reservoir.

The detection of tracers can be accomplished through various techniques, including chemical analysis of fluid samples, radioactive decay measurements for radioactive tracers, in-situ sensors that can detect the tracer directly in the reservoir, or a combination thereof. Specifically, a tracer can be a dye or another substance that is optically detectable in a volume of solution that is withdrawn from the formation after the tracer solution is injected into the formation. Specifically, optical tracers can be detected at very low concentrations using optical sensors, making them ideal for applications where the tracer should not significantly alter the properties of the formation fluids. Further, optical sensors can be integrated on formation testers to allow for real-time or pseudo real-time, in-situ monitoring of the tracer. This can provide more timely and accurate data compared to methods that require fluid samples to be collected and analyzed at the surface. Furthermore, the sensitivity of optical sensors allows for the detection of optical tracers at low concentrations, reducing the amount of tracer that needs to be injected into the reservoir and minimizing any potential impact on the reservoir's properties, e.g. in comparison to when more tracer needs to be injected into the formation.

In another example, a tracer can be detected through mass spectrometry. Specifically, mass spectrometry can be used to detect tracers such as salt or specialized organic compounds. Further, the volume of tracer solution that is withdrawn from the formation can be captured for analysis at the surface. Specifically, samples of the reservoir fluid and an injected tracer solution may be captured for laboratory analysis thereby expanding the types of tracers that may be used to more than those that can only be detected downhole. In other embodiments, a combination of downhole tracer detection and subsequently laboratory detection can be used in conjunction with one or more tracers in order to identify anisotropy and other applicable formation properties.

The tracer solution can include a plurality of different tracers that are injected into the formation. The plurality of different tracers can include applicable tracers that are distinguishable from each other through one or more detection mechanisms. For example, the plurality of different tracers can include optical dyes that are visible under different wavelengths of electromagnetic radiation. Further, the plurality of different tracers can be injected into the formation through two or more probes of a plurality of probes that are set into the formation. Specifically, different tracers can be injected through different proves that are set into the formation. For example, a first tracer can be injected through a first probe, while a second tracer can be injected through a second probe.

In an example operational scenario, a formation tester can be equipped with three probes that are positioned at applicable positions along the wellbore. The middle probe can serve as the drawdown probe for production, otherwise withdrawing fluid from the formation, and the upper and lower probes can be used for injection of fluid, e.g. tracer solution, into the formation. In other embodiments different probes can serve as the production probe(s) and the injection probe(s). The probes can be spaced asymmetrically along the wellbore, for instance with a smaller distance between the middle and lower probes (for example, 10 feet) and a larger distance between the middle and upper probes (for example, 15 feet). This asymmetric configuration can allow for the investigation of anisotropy over different distances and directions.

During operation, fluid can be withdrawn from the formation through the middle drawdown or production probe. The withdrawn fluid can then be split into two streams, each of which is mixed with a different dye, dye A or dye B, before being injected back into the formation through the upper and lower probes. The mixing of the dye with the formation fluid can be controlled by a series of sampling bottles. Each sampling bottle can be equipped with a nitrogen spring and capillary tubing of a specific diameter. This design allows for precise control over the rate of dye injection and the concentration of the dye in the formation fluid. Both dyes A and B can be located at both injection probes in each of three different bottles for a total of 6 bottles at the top probe and 6 bottles at the bottom probe. Each of the three bottles can be equipped with capillary tubing of a different size. This allows for ease of injection of the dyes at different rates. However other mechanisms to control the rate of injection are possible such as different nitrogen backing pressures. The total production injection rate can also be changed as well as the dye concentrations. By including both dyes at both probes the dye injection may be reversed (still injection from the exterior probes and production from the middle) so that effects of the dye's interaction with the formation can be analyzed. Also the injection production sequence can be reversed to check the experiment for hysteresis. In fact any combination of probes may be used for injection and production. Although it is desirable to use three probes asymmetrically spaced, tracer interaction with the formation can be negated, then two probes can be sufficient for anisotropy measurements.

Optical sensors can be located at each of the three probes to monitor the concentration of each dye in real-time or pseudo real-time. By comparing the observed concentrations of the two dyes at the middle probe, information about the anisotropy, permeability, and porosity of the formation can be inferred. This three-probe design allows for a comprehensive investigation of the formation's properties under a range of conditions. By varying the injection rate, dye concentration, and flow direction, data can be collected to provide a detailed understanding of the formation's anisotropy.

This three-probe design can account for many of the challenges associated with tracer studies in formations. Firstly, by injecting and monitoring tracers directly in the formation using in-situ probes, the need for fluid sample collection and surface analysis can be eliminated, thereby reducing operational complexity and potential for error. Secondly, the use of optical tracers, which can be detected at very low concentrations, minimizes the impact on the reservoir's properties and can ensure that the tracer does not significantly alter the flow behavior in the reservoir. Thirdly, the ability to control the injection rate and concentration of the tracers, as well as the direction of flow, can provide a high degree of experimental flexibility. This allows for a more comprehensive investigation of the formation's properties under a range of conditions. Additionally, the asymmetric placement of the probes can allow for the investigation of anisotropy over different distances and directions, providing a more representative measurement of the reservoir's properties.

Applicable operational parameters associated with injecting and withdrawing a tracer solution into a formation can be varied in identifying parameters of the formation. Specifically and as discussed previously, the rate at which the tracer is injected can be varied to influence the movement of the tracer through the reservoir. This can allow for insights into how the reservoir responds to different flow conditions can be gained. Further and as discussed previously, the initial concentration of the tracer can be varied. This can provide information about the dispersion and dilution of the tracer in the reservoir. Additionally, tracer properties can be varied. Specifically, tracers with different physical or chemical properties can be varied. This can provide information about the interaction of the tracer with the reservoir rock and fluids. For example, tracers might be used with different sizes or charges, or tracers that are reactive or non-reactive with the reservoir fluids. Further, the time period over which the tracer is injected into the formation can be varied. This can provide information about the temporal variability of the reservoir's properties, which can be important in reservoirs where properties change over time due to factors like depletion or water influx. Additionally, temperature and pressure conditions during the tracer test can be varied to affect tracer movement and determine various reservoir/formation properties.

At step 702, a varying simulated concentration profile associated with the tracer solution in a simulated formation is generated by modifying simulated formation parameters. Specifically, flows of different tracer solutions with varying operational parameters associated with an injection and withdrawal operation can be simulated in formations. More specifically, the flows can be simulated in formations having varied simulated formation parameters. For example, an operation can be simulated at varying types and characteristics of tracers, different initial concentrations, different injection rates, different time periods, different temperature and pressure conditions, and other applicable operational parameters. Formation parameters include applicable properties that define a formation, e.g. variable parameters across different types of formations that define the formation. For example, formation parameters can include properties of the formation that affect fluid movement through the formation. For example, the formation properties can include formation geometries, boundary conditions, porosity, permeability, anisotropy, and other applicable parameters.

The flows of tracer solutions in formations can be modeled through simulation using one or more applicable techniques. Specifically, by solving Darcy's laws for fluid flow in porous media, numerical models can simulate the movement of tracers in the reservoir under various conditions. These models can take into account the reservoir's geometry, initial and boundary conditions, and the properties of the fluid and the tracer.

The simulated concentration profile that is generated at step 702 can be for the same operational parameters that are applied in actually measuring the changing concentration profile as part of the tracer test. Specifically, the simulated concentration profile can be generated for the same tracer solution that is injected and withdrawn from the formation to generate the measured concentration profile at step 700. Further, the simulated concentration profile can be generated based on the same initial tracer concentration, the same tracer injection rates, the same time period, and the same temperature and pressure conditions as the actual tracer test during which the changing concentration profile is measured.

Further, the simulated concentration profile that is generated at step 702 can be for different operational parameters than those that are applied in actually measuring the changing concentration profile as part of the tracer test. Specifically, the simulated concentration profile can be generated for a related but different tracer solution to the one that is injected and withdrawn from the formation to generate the measured concentration profile at step 700. Further, the simulated concentration profile can be generated based on a different initial tracer concentration, different tracer injection rates, a different time period, and different temperature and pressure conditions as the actual tracer test during which the changing concentration profile is measured.

At step 704, the varying simulated concentration profile is compared to the changing concentration profile. Specifically, the results of the simulation are compared to the changing concentration profile and parameters of the formation can be inferred based on the comparison. More specifically, at step 706, a parameter of the formation is identified based on a comparison of the simulated concentration profile to the changing concentration profile of the volume of the tracer solution that is withdrawn from the formation. In comparing the results of the simulation with the changing concentration profile, the simulation and the changing concentration profile can be matched based on similarity between the simulated and observed responses, e.g. the simulated and observed concentration profiles over time. Then at times or instances when the simulation and the observed responses are matched, it can be inferred that the formation properties that were selected in generating the simulated concentration profile are the same as or otherwise correspond to the actual formation properties of the formation in which the tracer test is performed.

This process of generating a varying simulated concentration profile, comparing the simulated results and measured results, and inferring formation properties based on the comparison can be repeated an applicable number of times, e.g. as part of a feedback loop. This process, often referred to as inversion, can involve adjusting the parameters of the model (such as permeability, porosity, and anisotropy) until the simulated tracer behavior matches the observed data. The resulting model parameters can provide an estimate of the reservoir's properties/formation parameters. The formation parameters can include flow parameters of the formation. Flow parameters of a formation include applicable parameters that affect flow of a substance through a formation, such as anisotropy. The formation parameters can also include parameters of the formation that are related to an affinity parameter of the tracer solution within the formation. An affinity parameter can include an applicable parameter that describes or is characteristic of interactions between a tracer and a formation. The affinity parameter can be indicative of minerology information of the formation.

FIG. 8 illustrates an example computing device architecture 800 which can be employed to perform various steps, methods, and techniques disclosed herein. Specifically, the computing device architecture can be integrated with the electromagnetic imaging tools described herein. Further, the computing device can be configured to implement the techniques of controlling borehole image blending through machine learning described herein.

As noted above, FIG. 8 illustrates an example computing device architecture 800 of a computing device which can implement the various technologies and techniques described herein. The components of the computing device architecture 800 are shown in electrical communication with each other using a connection 805, such as a bus. The example computing device architecture 800 includes a processing unit (CPU or processor) 810 and a computing device connection 805 that couples various computing device components including the computing device memory 815, such as read only memory (ROM) 820 and random access memory (RAM) 825, to the processor 810.

The computing device architecture 800 can include a cache of high-speed memory connected directly with, in close proximity to, or integrated as part of the processor 810. The computing device architecture 800 can copy data from the memory 815 and/or the storage device 830 to the cache 813 for quick access by the processor 810. In this way, the cache can provide a performance boost that avoids processor 810 delays while waiting for data. These and other modules can control or be configured to control the processor 810 to perform various actions. Other computing device memory 815 may be available for use as well. The memory 815 can include multiple different types of memory with different performance characteristics. The processor 810 can include any general purpose processor and a hardware or software service, such as service 1 832, service 2 834, and service 3 836 stored in storage device 830, configured to control the processor 810 as well as a special-purpose processor where software instructions are incorporated into the processor design. The processor 810 may be a self-contained system, containing multiple cores or processors, a bus, memory controller, cache, etc. A multi-core processor may be symmetric or asymmetric.

To enable user interaction with the computing device architecture 800, an input device 845 can represent any number of input mechanisms, such as a microphone for speech, a touch-sensitive screen for gesture or graphical input, keyboard, mouse, motion input, speech and so forth. An output device 835 can also be one or more of a number of output mechanisms known to those of skill in the art, such as a display, projector, television, speaker device, etc. In some instances, multimodal computing devices can enable a user to provide multiple types of input to communicate with the computing device architecture 800. The communications interface 840 can generally govern and manage the user input and computing device output. There is no restriction on operating on any particular hardware arrangement and therefore the basic features here may easily be substituted for improved hardware or firmware arrangements as they are developed.

Storage device 830 is a non-volatile memory and can be a hard disk types of computer readable media which can store data that are accessible by a computer, such as magnetic cassettes, flash memory cards, solid state memory devices, digital versatile disks, cartridges, random access memories (RAMs) 825, read only memory (ROM) 820, and hybrids thereof. The storage device 830 can include services 832, 834, 836 for controlling the processor 810. Other hardware or software modules are contemplated. The storage device 830 can be connected to the computing device connection 805. In one aspect, a hardware module that performs a particular function can include the software component stored in a computer-readable medium in connection with the necessary hardware components, such as the processor 810, connection 805, output device 835, and so forth, to carry out the function.

For clarity of explanation, in some instances the present technology may be presented as including individual functional blocks including functional blocks comprising devices, device components, steps or routines in a method embodied in software, or combinations of hardware and software.

In some embodiments the computer-readable storage devices, mediums, and memories can include a cable or wireless signal containing a bit stream and the like. However, when mentioned, non-transitory computer-readable storage media expressly exclude media such as energy, carrier signals, electromagnetic waves, and signals per se.

Methods according to the above-described examples can be implemented using computer-executable instructions that are stored or otherwise available from computer readable media. Such instructions can include, for example, instructions and data which cause or otherwise configure a general purpose computer, special purpose computer, or a processing device to perform a certain function or group of functions. Portions of computer resources used can be accessible over a network. The computer executable instructions may be, for example, binaries, intermediate format instructions such as assembly language, firmware, source code, etc. Examples of computer-readable media that may be used to store instructions, information used, and/or information created during methods according to described examples include magnetic or optical disks, flash memory, USB devices provided with non-volatile memory, networked storage devices, and so on.

Devices implementing methods according to these disclosures can include hardware, firmware and/or software, and can take any of a variety of form factors. Typical examples of such form factors include laptops, smart phones, small form factor personal computers, personal digital assistants, rackmount devices, standalone devices, and so on. Functionality described herein also can be embodied in peripherals or add-in cards. Such functionality can also be implemented on a circuit board among different chips or different processes executing in a single device, by way of further example.

The instructions, media for conveying such instructions, computing resources for executing them, and other structures for supporting such computing resources are example means for providing the functions described in the disclosure.

In the foregoing description, aspects of the application are described with reference to specific embodiments thereof, but those skilled in the art will recognize that the application is not limited thereto. Thus, while illustrative embodiments of the application have been described in detail herein, it is to be understood that the disclosed concepts may be otherwise variously embodied and employed, and that the appended claims are intended to be construed to include such variations, except as limited by the prior art. Various features and aspects of the above-described subject matter may be used individually or jointly. Further, embodiments can be utilized in any number of environments and applications beyond those described herein without departing from the broader spirit and scope of the specification. The specification and drawings are, accordingly, to be regarded as illustrative rather than restrictive. For the purposes of illustration, methods were described in a particular order. It should be appreciated that in alternate embodiments, the methods may be performed in a different order than that described.

Where components are described as being “configured to” perform certain operations, such configuration can be accomplished, for example, by designing electronic circuits or other hardware to perform the operation, by programming programmable electronic circuits (e.g., microprocessors, or other suitable electronic circuits) to perform the operation, or any combination thereof.

The various illustrative logical blocks, modules, circuits, and algorithm steps described in connection with the examples disclosed herein may be implemented as electronic hardware, computer software, firmware, or combinations thereof. To clearly illustrate this interchangeability of hardware and software, various illustrative components, blocks, modules, circuits, and steps have been described above generally in terms of their functionality. Whether such functionality is implemented as hardware or software depends upon the particular application and design constraints imposed on the overall system. Skilled artisans may implement the described functionality in varying ways for each particular application, but such implementation decisions should not be interpreted as causing a departure from the scope of the present application.

The techniques described herein may also be implemented in electronic hardware, computer software, firmware, or any combination thereof. Such techniques may be implemented in any of a variety of devices such as general purposes computers, wireless communication device handsets, or integrated circuit devices having multiple uses including application in wireless communication device handsets and other devices. Any features described as modules or components may be implemented together in an integrated logic device or separately as discrete but interoperable logic devices. If implemented in software, the techniques may be realized at least in part by a computer-readable data storage medium comprising program code including instructions that, when executed, performs one or more of the method, algorithms, and/or operations described above. The computer-readable data storage medium may form part of a computer program product, which may include packaging materials.

The computer-readable medium may include memory or data storage media, such as random access memory (RAM) such as synchronous dynamic random access memory (SDRAM), read-only memory (ROM), non-volatile random access memory (NVRAM), electrically erasable programmable read-only memory (EEPROM), FLASH memory, magnetic or optical data storage media, and the like. The techniques additionally, or alternatively, may be realized at least in part by a computer-readable communication medium that carries or communicates program code in the form of instructions or data structures and that can be accessed, read, and/or executed by a computer, such as propagated signals or waves.

Other embodiments of the disclosure may be practiced in network computing environments with many types of computer system configurations, including personal computers, hand-held devices, multi-processor systems, microprocessor-based or programmable consumer electronics, network PCs, minicomputers, mainframe computers, and the like. Embodiments may also be practiced in distributed computing environments where tasks are performed by local and remote processing devices that are linked (either by hardwired links, wireless links, or by a combination thereof) through a communications network. In a distributed computing environment, program modules may be located in both local and remote memory storage devices.

In the above description, terms such as “upper,” “upward,” “lower,” “downward,” “above,” “below,” “downhole,” “uphole,” “longitudinal,” “lateral,” and the like, as used herein, shall mean in relation to the bottom or furthest extent of the surrounding wellbore even though the wellbore or portions of it may be deviated or horizontal. Correspondingly, the transverse, axial, lateral, longitudinal, radial, etc., orientations shall mean orientations relative to the orientation of the wellbore or tool. Additionally, the illustrate embodiments are illustrated such that the orientation is such that the right-hand side is downhole compared to the left-hand side.

The term “coupled” is defined as connected, whether directly or indirectly through intervening components, and is not necessarily limited to physical connections. The connection can be such that the objects are permanently connected or releasably connected. The term “outside” refers to a region that is beyond the outermost confines of a physical object. The term “inside” indicates that at least a portion of a region is partially contained within a boundary formed by the object. The term “substantially” is defined to be essentially conforming to the particular dimension, shape or another word that substantially modifies, such that the component need not be exact. For example, substantially cylindrical means that the object resembles a cylinder, but can have one or more deviations from a true cylinder.

The term “radially” means substantially in a direction along a radius of the object, or having a directional component in a direction along a radius of the object, even if the object is not exactly circular or cylindrical. The term “axially” means substantially along a direction of the axis of the object. If not specified, the term axially is such that it refers to the longer axis of the object.

Although a variety of information was used to explain aspects within the scope of the appended claims, no limitation of the claims should be implied based on particular features or arrangements, as one of ordinary skill would be able to derive a wide variety of implementations. Further and although some subject matter may have been described in language specific to structural features and/or method steps, it is to be understood that the subject matter defined in the appended claims is not necessarily limited to these described features or acts. Such functionality can be distributed differently or performed in components other than those identified herein. The described features and steps are disclosed as possible components of systems and methods within the scope of the appended claims.

Moreover, claim language reciting “at least one of” a set indicates that one member of the set or multiple members of the set satisfy the claim. For example, claim language reciting “at least one of A and B” means A, B, or A and B.

Statements of the Disclosure Include:

Statement 1. A method comprising: measuring a changing concentration profile of a volume of tracer solution that is withdrawn from a formation over a time interval, wherein the tracer solution is injected into the formation through one or more probes of a plurality of probes that are set into the formation at a location within a wellbore; generating a varying simulated concentration profile associated with the tracer solution in a simulated formation by modifying simulated formation parameters of the simulated formation; comparing the varying simulated concentration profile to the changing concentration profile of the volume of tracer solution that is withdrawn from the formation; and identifying a parameter of the formation based on a comparison of the varying simulated concentration profile to the changing concentration profile of the volume of tracer solution that is withdrawn from the formation.

Statement 2. The method of statement 1, wherein the parameter of the formation is a flow parameter of the formation.

Statement 3. The method of statement 2, wherein the flow parameter is anisotropy.

Statement 4. The method of any of statements 1 through 3, wherein the parameter of the formation is related to an affinity parameter of the tracer solution within the formation.

Statement 5. The method of statement 4, wherein the affinity parameter is indicative of minerology information of the formation.

Statement 6. The method of any of statements 1 through 5, wherein the tracer solution includes a dye that is optically detectable in a volume of solution that is withdrawn from the formation after the tracer solution is injected into the formation.

Statement 7. The method of any of statements 1 through 6, wherein the tracer solution includes a tracer that is detectable through mass spectrometry in a volume of solution that is withdrawn from the formation after the tracer solution is injected into the formation.

Statement 8. The method of any of statements 1 through 7, wherein the volume of tracer solution is captured for analysis at surface.

Statement 9. The method of any of statements 1 through 8, wherein the tracer solution is contained within a formation tester disposed at the location within the wellbore and the formation tester is configured to inject the tracer solution through the one or more probes into the formation.

Statement 10. The method of any of statements 1 through 9, wherein a rate at which the tracer solution is injected into the formation is varied.

Statement 11. The method of any of statements 1 through 10, wherein the tracer solution includes a plurality of different tracers.

Statement 12. The method of statement 11, wherein the plurality of different tracers are injected into the formation through two or more probes of the plurality of probes that are set into the formation.

Statement 13. The method of any of statements 11 and 12, further comprising: normalizing changing concentration profiles of each of the plurality of different tracers based on a concentration profile of a reference tracer; and comparing normalized concentration profiles of the plurality of different tracers to the simulation concentration profile as part of comparing the simulated concentration profile to the changing concentration profile of the volume of tracer solution that is withdrawn from the formation.

Statement 14. The method of any of statements 1 through 13, wherein the plurality of probes are asymmetrically spaced apart from each other.

Statement 15. The method of any of statements 1 through 14, wherein a rate at which the tracer solution is injected into the formation is varied separately from a rate at which tracer of the tracer solution is injected into the formation.

Statement 16. The method of any of statements 1 through 15, wherein the plurality of probes include an injection probe for injecting the tracer solution in the formation and a production probe for withdrawing the volume of tracer solution from the formation and operations of the injection probe and the production probe are varied with respect to each other.

Statement 17. The method of any of statements 1 through 16, further comprising: numerically inverting the changing concentration profile of the volume of tracer solution that is withdrawn from the formation; and comparing the numerically inverted changing concentration profile of the volume of tracer solution to the simulated concentration profile as part of comparing the simulated concentration profile to the changing concentration profile of the volume of tracer solution that is withdrawn from the formation.

Statement 18. The method of any of statements 1 through 17, wherein the tracer solution is mixed with formation fluid that is withdrawn from the formation over the time interval.

Statement 19. A system comprising: one or more processors; and at least one computer-readable storage medium having stored therein instructions which, when executed by the one or more processors, cause the one or more processors to: measure a changing concentration profile of a volume of tracer solution that is withdrawn from a formation over a time interval, wherein the tracer solution is injected into the formation through one or more probes of a plurality of probes that are set into the formation at a location within a wellbore; generate a varying simulated concentration profile of the tracer solution in a simulated formation by modifying simulated formation parameters of the simulated formation; compare the simulated concentration profile to the changing concentration profile of the volume of tracer solution that is withdrawn from the formation; and identify a parameter of the formation based on a comparison of the simulated concentration profile to the changing concentration profile of the volume of tracer solution that is withdrawn from the formation.

Statement 20. A non-transitory computer-readable storage medium storing instructions for causing one or more processors to: measure a changing concentration profile of a volume of tracer solution that is withdrawn from a formation over a time interval, wherein the tracer solution is injected into the formation through one or more probes of a plurality of probes that are set into the formation at a location within a wellbore; generate a varying simulated concentration profile of the tracer solution in a simulated formation by modifying simulated formation parameters of the simulated formation; compare the simulated concentration profile to the changing concentration profile of the volume of tracer solution that is withdrawn from the formation; and identify a parameter of the formation based on a comparison of the simulated concentration profile to the changing concentration profile of the volume of tracer solution that is withdrawn from the formation.

Statement 21. A system comprising means for performing a method according to any of statements 1 through 18.

Claims

1. A method comprising:

measuring a changing concentration profile of a volume of tracer solution that is withdrawn from a formation over a time interval, wherein the tracer solution is injected into the formation through one or more probes of a plurality of probes that are set into the formation at a location within a wellbore;

generating a varying simulated concentration profile associated with the tracer solution in a simulated formation by modifying simulated formation parameters of the simulated formation;

comparing the varying simulated concentration profile to the changing concentration profile of the volume of tracer solution that is withdrawn from the formation; and

identifying a parameter of the formation based on a comparison of the varying simulated concentration profile to the changing concentration profile of the volume of tracer solution that is withdrawn from the formation.

2. The method of claim 1, wherein the parameter of the formation is a flow parameter of the formation.

3. The method of claim 2, wherein the flow parameter is anisotropy.

4. The method of claim 1, wherein the parameter of the formation is related to an affinity parameter of the tracer solution within the formation.

5. The method of claim 4, wherein the affinity parameter is indicative of minerology information of the formation.

6. The method of claim 1, wherein the tracer solution includes a dye that is optically detectable in a volume of solution that is withdrawn from the formation after the tracer solution is injected into the formation.

7. The method of claim 1, wherein the tracer solution includes a tracer that is detectable through mass spectrometry in a volume of solution that is withdrawn from the formation after the tracer solution is injected into the formation.

8. The method of claim 1, wherein the volume of tracer solution is captured for analysis at surface.

9. The method of claim 1, wherein the tracer solution is contained within a formation tester disposed at the location within the wellbore and the formation tester is configured to inject the tracer solution through the one or more probes into the formation.

10. The method of claim 1, wherein a rate at which the tracer solution is injected into the formation is varied.

11. The method of claim 1, wherein the tracer solution includes a plurality of different tracers.

12. The method of claim 11, wherein the plurality of different tracers are injected into the formation through two or more probes of the plurality of probes that are set into the formation.

13. The method of claim 11, further comprising:

normalizing changing concentration profiles of each of the plurality of different tracers based on a concentration profile of a reference tracer; and

comparing normalized concentration profiles of the plurality of different tracers to the simulation concentration profile as part of comparing the simulated concentration profile to the changing concentration profile of the volume of tracer solution that is withdrawn from the formation.

14. The method of claim 1, wherein the plurality of probes are asymmetrically spaced apart from each other.

15. The method of claim 1, wherein a rate at which the tracer solution is injected into the formation is varied separately from a rate at which tracer of the tracer solution is injected into the formation.

16. The method of claim 1, wherein the plurality of probes include an injection probe for injecting the tracer solution in the formation and a production probe for withdrawing the volume of tracer solution from the formation and operations of the injection probe and the production probe are varied with respect to each other.

17. The method of claim 1, further comprising:

numerically inverting the changing concentration profile of the volume of tracer solution that is withdrawn from the formation; and

comparing the numerically inverted changing concentration profile of the volume of tracer solution to the simulated concentration profile as part of comparing the simulated concentration profile to the changing concentration profile of the volume of tracer solution that is withdrawn from the formation.

18. The method of claim 1, wherein the tracer solution is mixed with formation fluid that is withdrawn from the formation over the time interval.

19. A system comprising:

one or more processors; and

at least one computer-readable storage medium having stored therein instructions which, when executed by the one or more processors, cause the one or more processors to: measure a changing concentration profile of a volume of tracer solution that is withdrawn from a formation over a time interval, wherein the tracer solution is injected into the formation through one or more probes of a plurality of probes that are set into the formation at a location within a wellbore; generate a varying simulated concentration profile associated with the tracer solution in a simulated formation by modifying simulated formation parameters of the simulated formation; compare the varying simulated concentration profile to the changing concentration profile of the volume of tracer solution that is withdrawn from the formation; and identify a parameter of the formation based on a comparison of the varying simulated concentration profile to the changing concentration profile of the volume of tracer solution that is withdrawn from the formation.

20. A non-transitory computer-readable storage medium storing instructions for causing one or more processors to:

measure a changing concentration profile of a volume of tracer solution that is withdrawn from a formation over a time interval, wherein the tracer solution is injected into the formation through one or more probes of a plurality of probes that are set into the formation at a location within a wellbore;

generate a varying simulated concentration profile associated with the tracer solution in a simulated formation by modifying simulated formation parameters of the simulated formation;

compare the varying simulated concentration profile to the changing concentration profile of the volume of tracer solution that is withdrawn from the formation; and

identify a parameter of the formation based on a comparison of the varying simulated concentration profile to the changing concentration profile of the volume of tracer solution that is withdrawn from the formation.