Monitoring carbon sequestration in source rock reservoirs using stable isotopic fractionation to quantify its retention efficiency

Abstract

A process for monitoring and quantifying anthropogenic carbon retained within a reservoir includes, measuring δ13C and δ18O of in situ reservoir CO2 and calculating endpoint values of the in situ CO2 using δ13C and δ18O, measuring δ13C, and δ18O of anthropogenic CO2 and calculating endpoint value of the anthropogenic CO2 using δ13C and δ18O, injecting anthropogenic CO2 into the reservoir, obtaining volume or mass of anthropogenic CO2, collecting a produced sample from the reservoir after a period of time, measuring δ13C, and δ18O of a mixed in situ and anthropogenic CO2, and calculating the anthropogenic CO2 sequestered in the reservoir by using the endpoint values. A anthropogenic CO2 monitoring and quantifying system includes, injection wells, production wells, measurement devices for measuring an amount of CO2 injected and produced, and a measurement collection and analysis system for receiving gas samples and for measuring an amount of CO2 sequestered within the reservoir.

Description

BACKGROUND

[0001] Increased emissions of greenhouse gases are a major concern because greenhouse gases cause global warming and other undesired changes in the weather. These changes have had a significant impact on the ecosystem and have been linked to the melting of the ice caps, droughts, and increased severity of storms. The role of carbon dioxide (CO2) in global warming is of particular interest because CO2 is classified as a major greenhouse gas and CO2 is continuously emitted into the atmosphere because of the use of fossil fuels.

[0002] Emission of CO2 caused by human activity is known as anthropogenic CO2. The sources of anthropogenic CO2 include power generation, transportation, industrial sources, chemical production, petroleum production, and agricultural practices. Many of these sources burn fossil fuels (coal, oil, and natural gas), with CO2 emissions as a byproduct. Efforts to control and decrease anthropogenic CO2 emissions have led to developments in capturing anthropogenic CO2 and injecting it into oil and gas formations or reservoirs. Ultimately, anthropogenic CO2 derived substances may be stored indefinitely by carbon sequestration. An important aspect of storing carbon is measuring and quantifying the anthropogenic carbon that is retained or sequestered in a reservoir. However, the CO2 produced from a reservoir may arise from other sources. For example, the CO2 in a reservoir may be created in situ from kerogen. This in situ CO2 may interfere with accurately quantifying the anthropogenic CO2 introduced into the reservoir. Accordingly, there exists a need for methods that measure, monitor and quantify the injected anthropogenic carbon sequestered in a reservoir.SUMMARY

[0003] 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.

[0004] In one aspect, embodiments disclosed herein relate to, among other things, a process for monitoring and quantifying anthropogenic carbon retained within a reservoir. The process may include, measuring δ13C and δ18O of in situ CO2 from a reservoir and calculating endpoint values of the in situ CO2 using δ13C and δ18O of the situ CO2. The process also may include measuring δ13C, and δ18O of anthropogenic CO2 and calculating endpoint values of the anthropogenic CO2 using δ13C and δ18O of the anthropogenic CO2.

[0005] Subsequently, the anthropogenic CO2 may be injected into the reservoir and the volume or mass of the anthropogenic CO2 may be measured and obtained. In the reservoir, the injected anthropogenic CO2 may mix with the in situ CO2. The reservoir may be shut in for a period of time. After a period of time, a produced sample may be collected from the reservoir. After the sample is obtained, the process may include measuring the δ13C, and δ18O of a mixed in situ and anthropogenic CO2 and calculating the anthropogenic CO2 sequestered in the reservoir by using the endpoint values.

[0006] Further, the process may also include measuring δ13C and 82H of in situ CH4 from the reservoir and calculating endpoint values of the in situ CH4 using the δ13C and δ2H of the in situ CH4. The process may also include using an isotope mixing equation to calculate the fraction of the anthropogenic CO2 sequestered in the reservoir, and the isotope mixing equation may be modified by a compensation factor.

[0007] In another aspect, embodiments disclosed herein relating to a system for anthropogenic CO2 monitoring and quantifying include, among other things, injection wells, production wells, measurement devices for measuring an amount of CO2 injected and produced, and a measurement collection and analysis system for receiving gas samples to measure an amount of CO2 sequestered within the reservoir. Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.BRIEF DESCRIPTION OF DRAWINGS

[0008] FIG. 1 is a method for monitoring, measuring and quantifying CO2 sequestration according to one or more embodiments.

[0009] FIG. 2 is a system for monitoring, measuring and quantifying CO2 sequestration according to one or more embodiments.

[0010] FIG. 3 is a graph according to one or more embodiments.

[0011] FIG. 4 is a graph from a pilot project according to one or more embodiments.

[0012] FIG. 5 is a graph from a pilot project according to one or more embodiments.

[0013] FIG. 6 is a graph from a pilot project according to one or more embodiments.

[0014] While the subject matter disclosed herein is susceptible to various modifications and alternative forms, specific embodiments thereof have been shown by way of example in the drawings and are herein described in detail. It should be understood, however, that the description herein of specific embodiments is not intended to limit the disclosed subject matter to the particular forms disclosed, but on the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the disclosed subject matter as defined by the appended claims.

[0015] Typically, down is toward or at the bottom and up is toward or at the top of the figure. “Up” and “down” are oriented relative to a local vertical direction. However, in the oil and gas industry, one or more activity may take place in deviated or horizontal wells. Therefore, one or more figures may represent an activity in vertical, approximately vertical, deviated, approximately horizontal, or horizontal wellbore configuration.DETAILED DESCRIPTION

[0016] Carbon dioxide (CO2) may be used at numerous points in the lifetime of a reservoir. CO2 may be introduced in various drilling fluids during initial drilling of a well. CO2 may be injected during secondary or tertiary oil and gas recovery efforts, such as during enhanced oil recovery (EOR) operations. For example, CO2 may be injected as a gas, liquid, or supercritical fluid, and may be used alone or in a CO2 mixture or as a foaming agent to provide the desired effects during the secondary or tertiary oil and gas recovery operations. CO2 may also accompany the produced oil and gas during the secondary and tertiary recovery efforts, as well as migrate through the formation and be emitted through the surface layers into the atmosphere. CO2 may also be introduced into depleted (abandoned or non-producing) wells for the express purpose of carbon capture and storage.

[0017] During each of these stages of a lifetime of a reservoir (drilling, primary production, secondary and tertiary recovery, and shut-in), CO2 may be trapped, stored, or sequestered by various mechanisms within a formation. Some mechanisms for CO2 trapping may include static trapping, structural trapping, stratigraphic trapping, hydrodynamic trapping, and capillary trapping. CO2 may react with various rocks or minerals, may be adsorbed onto or within pores of various rocks and minerals, or may be effectively trapped below a non-porous layer of rock, among other numerous possibilities known to one skilled in the art.

[0018] The kerogen found in the rocks or minerals of a source rock reservoir may have undergone thermogenic transformation to produce hydrocarbons and non-hydrocarbon gases. As kerogen is converted into hydrocarbons, hydrogen is lost relative to carbon to produce methane, ethane, and propane. Also, oxygen is lost relative to carbon in kerogen, resulting in the generation of in situ CO2 gas. Thus, there may be two sources of CO2 in a reservoir where anthropogenic CO2 is introduced; anthropogenic CO2 and in situ CO2 originating from thermogenic sources. Accordingly, there exists a need for methods that measure, monitor, and quantify the injected anthropogenic carbon that is retained in a reservoir.

[0019] Embodiments herein are directed toward methods for accurately determining the amount of anthropogenic CO2 that has been retained or sequestered within a reservoir after a well starts producing using isotope fractionation. FIG. 1 offers an example of this computation, given the δ13C values mentioned as inputs. Some embodiments provide for measuring, monitoring or quantifying anthropogenic CO2, in situ CO2, and mixed CO2. Mixed CO2 may contain both anthropogenic CO2 and in situ CO2. The process may include measuring the δ13C, δ18O, and δ2H of CO2 and other gases (such as CH4) to determine the amount of anthropogenic CO2 sequestered in a reservoir.

[0020] FIG. 1 provides a schematic of the workflow 100 illustrating general steps of one or more embodiments of the method. The steps may include: Measuring δ13C, and δ18O of anthropogenic CO2 101; Calculating endpoint value of anthropogenic CO2 using δ13C, and δ18O 103; Measuring δ13C, δ18O, and δ2H of in situ CO2 and in situ CH4 from a reservoir 105; Calculating endpoint value of in situ CO2 and in situ CH4 using δ13C, δ18O, and δ2H 107; Injecting anthropogenic CO2 into reservoir via an injection well 109; Measuring volume or mass the anthropogenic CO2 injected into reservoir 111; Collecting produced sample from reservoir via a production well after a period of time 113; Conducting isotopic analysis of produced sample 115; and Calculating fraction of anthropogenic CO2 retained in reservoir by using endpoint values 117.

[0021] Isotope fractionation (fractionation) of carbon, oxygen, and hydrogen may be used to measure, monitor, and quantify chemical changes in solids, liquids, and gases. These changes may be caused by changes in temperature, pressure, or microbial activity. Fractionation of carbon and hydrogen in methane, ethane, and propane may be used to monitor a degree of thermogenic transformation of organic matter into hydrocarbons in source rocks in reservoirs. Further, these isotopic entities may be useful for measuring biogenic transformation of organic matter or gases caused by microbial activity in reservoirs. As a result, they provide a quantitative benchmark to monitor and quantify the changes taking place. Isotopic fractionation of gases is useful to monitor the source of gases in mixture of gases, provided that endpoint values of gas isotopes are measured before mixing occurs.

[0022] For CO2 produced from a reservoir (produced CO2), differences in isotopic fractionation between 13C / 12C and 18O / 16O may be measured to determine whether the CO2 originates from thermogenic or biogenic processes. The isotopic fractionation measurement for in situ CO2 for a particular formation is unique to the formation. Similarly, anthropogenic CO2 may have gone through changes in isotope fractionation as well and may have a characteristic isotopic fractionation value depending on the source of the CO2. Thus, if the isotopic fractionation measurement of each gas is known before an anthropogenic source is introduced, the values from both in situ and anthropogenic gases may be used as endpoints (also known as end-members) to monitor and quantify the presence of the different gases in a mixture. This is useful for determining the anthropogenic gas retention efficiency. Isotopic fractionation in gases is especially useful to monitor the difference in mixtures of gases provided that point values of the isotopes for each gas are known before mixing occurs.

[0023] The isotope value for an element may be defined as ratio (R):R⁢=lrlaEquation⁢ (l)where R is a proportion of the rare isotope (Ir) versus the most abundant isotope (Ia). Examples of rare and abundant isotopes include hydrogen isotopes (2H / 1H), carbon isotopes (13C / 12C), and oxygen isotopes (18O / 16O).The fractionation between two isotopes may occur in concentration or temperature gradients because of mass differences between the two isotopes. The lighter isotope may be more susceptible to bond breaking in a molecule because its bonds are weaker as compared to with the heavier isotope in a similar molecule. Thus, under sudden changes in conditions, such as an increase in temperature, the concentration of the heavier isotope may be depleted in the reaction products compared to the lighter isotope in the reaction products. In turn, the fractionated portion (the reactants) may be enriched in the concentration of the heavier isotope.

[0025] Thus, a change in the concentration of an isotope of lower abundance in reaction products may indicate diagnostic processes. The isotope fractionation occurring from these processes may be represented by:α=RARB=(ιrιa)A(ιrιa)BEquation⁢ (2)where α is the fractionation factor, RA is ratio of isotope in phase A, and RB is ratio of isotope in phase B. The fractionation factor, α may be simplified as follows:αA-B=(lr)A(lr)BEquation⁢ (3)Phase A and Phase B may be the fractionation between organic matter and thermogenic generation of its products. In an example embodiment, the two phases may be the fractionation between the thermogenic breakdown of methanal (CH2O), and the generation of products methane (CH4) and CO2. Thus, Phase A is CH2O and Phase B is CO2 and CH4. In situ sources of CO2 and CH4 may be generated in a reservoir by this reaction. A simplified pathway of the reaction is as follows:where the reaction produces the following isotopic values according to the fractionation factor:α⁡(C⁢H2⁢O-CO2)=(13C12C⁢(C⁢H2⁢O))(13C12C⁢(CO2))Equation⁢ (5)α⁡(C⁢H2⁢O-CH4)=(13C12C⁢(C⁢H2⁢O))(13C12C⁢(CH4))Equation⁢ (6)The value produced for phase A and phase B is related to the ratio of the concentration between the heavier isotope and the lighter isotope. In this example, the heavier isotope (13C) and lighter isotope (12C) of Carbon are measured.The fractionation is unique to the system from a thermodynamic standpoint. Thus, to obtain accurate and precise measurements, the measurements are adjusted by using stable isotopes of 13C and 12C. This adjustment factors out errors introduced from metabolic and respiratory pathway in the sample by using a standard reference. For example, the δ13C value of a compound, whether CO2 or CH4, may be derived relative to a 13C / 12C standard from CO2 gas generated from selected carbonates digested with pure (100%) phosphoric acid as such:δ1⁢3⁢C=[((13C12C)sp⁢1-(13C12C)s⁢t⁢d)(13C12C)s⁢t⁢d]×1⁢03⁢0 / 00Equation⁢ (7)where δ13C is the stable isotopic fractionation for Carbon, “spl” is the fractionation factor of the sample, and “std” is the fractionation factor of the standard. The CO2 gas isotopic standard of known 13C / 12C may be used to compute the δ13C value of carbon gases per mil (‰) as the per mil difference (+ / −%) relative to that standard. The value of δ13C may be negative or positive. A negative of δ13C value indicates that the sample is depleted in 13C relative to the standard, and a positive of δ13C value indicates that the sample is enriched in 13C relative to the value of the standard. Similarly, the relationship indicated by Equation (7) is applicable for isotopic fractionation of oxygen or hydrogen. For 18O and 2H enrichment or depletion may be determined for a sample relative to another standard called the standard mean ocean water. Those having skill in the art would appreciate the various standards that may be useful to determine a stable isotopic fractionation for a particular isotope.Various illustrative embodiments of the disclosed subject matter are described below. In the interest of clarity, not all features of an actual implementation are described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another.The present subject matter will now be described with reference to the attached figures. Various structures, systems and devices are schematically depicted in the drawings for purposes of explanation only and so as to not obscure the present disclosure with details that are well known to those skilled in the art. Nevertheless, the attached drawings are included to describe and explain illustrative examples of the present disclosure. The words and phrases used herein should be understood and interpreted to have a meaning consistent with the understanding of those words and phrases by those skilled in the relevant art. No special definition of a term or phrase, i.e., a definition that is different from the ordinary and customary meaning as understood by those skilled in the art, is intended to be implied by consistent usage of the term or phrase herein. To the extent that a term or phrase is intended to have a special meaning, i.e., a meaning other than that understood by skilled artisans, such a special definition will be expressly set forth in the specification in a definitional manner that directly and unequivocally provides the special definition for the term or phrase. With reference to the attached figures, various illustrative embodiments of the systems, devices and methods disclosed herein will now be described in more detail.FIG. 2 is a diagram that illustrates a carbon monitoring and quantifying system in accordance with one or more embodiments. The carbon monitoring and quantifying system 200 includes a well environment 201 that includes a reservoir 205. Above the reservoir 205 is a fluid-impenetrable overburden 210, which is part of subsurface 215. Below the reservoir 205 is the underburden 220, which is also part of the subsurface 215. The reservoir 205 may comprise matrix materials including, but not limited to, limestone, sandstone, and shale. Other matrix materials may be unconventional, including, but not limited to, marble, granite, or basalt or kerogen. The well environment 201 also includes a surface 225 representing the surface of the Earth, and a subsurface 215 below the surface 225. Traversing through subsurface 215 environment is a portion of the well injection system 500, which is part of the well environment 201.The carbon monitoring and quantifying system includes an isotope analysis facility 321 in accordance with one or more embodiments. The analysis facility may be part of a measurement, collection and analysis system 202. The isotope analysis facility 321 may be equipped with various tools and apparatus allowing additional sample processing, data collection and analysis of the samples, including those apparatus required to carry out the steps described in the workflow 100 of FIG. 1 including the measurements of δ13C, δ18O, and δ2H of anthropogenic, in situ and mixed gases in a particular reservoir 205. Some of the apparatus housed in the isotope analysis facility 321 may include equipment 325 such as isotopic analysis instruments 323 like mass spectrometers configured to obtain isotopic data, and processors 327 configured to obtain and analyze the results. Those having skill in the art would appreciate that additional tools, apparatus, equipment, and chemical solutions may be required to complete the steps in workflow 100 of FIG. 1.The well injection system 500 includes a CO2 injection well 510. A bottomhole 512 of the CO2 injection well 510 is positioned proximate to the underburden 220 but within the reservoir 205. In one or more embodiments, the underburden 220 is porous and permits CO2 migration. The CO2 injection well 510 may transverse into the underburden 220 and the bottomhole 512 of the CO2 injection well 510 may be positioned in the underburden 220. In one or more embodiments of the carbon measurement and quantification system 200, the well environment 201 includes two or more CO2 injection wells 510.CO2 may be stored on the surface 225 in a CO2 storage plant 520. CO2 in the CO2 storage plant 520 may pass through a CO2 flowline 522 and introduced into the reservoir 205 from a CO2 injection well 510. The stored CO2 may be in the state of a gas, a liquid, or a supercritical fluid. However, CO2 has very low density in a gaseous state compared to the density of formation fluids, such as brine and hydrocarbons. The very low density increases the upward mobility of the CO2. In contrast, both liquid and supercritical CO2 have higher densities than CO2 gas. The densities of liquid and supercritical CO2 are much closer to the densities of formation fluids in the reservoir. The similar density of the liquid and supercritical CO2 with respect to the formation fluids reduces the upward mobility of CO2. Even though this method can use CO2 in all states, the denser phases of CO2, whether liquid or supercritical, are preferred because of the desired reduction in upward mobility.

[0034] A sample 303 of anthropogenic CO2 may be obtained from the CO2 storage plant 520. According to one or more embodiments, the sample 303 is collected from the CO2 storage plant 520 and relocated to an Isotope analysis facility 321 for isotope analysis where the δ13C, δ18O of the anthropogenic CO2 are measured by the isotopic analysis instruments 323. The measurements are used to calculate endpoint value of anthropogenic CO2.

[0035] The amount of CO2 introduced into the reservoir may be measured uphole at the CO2 storage plant 520 by a device 621 measuring the flow rate of CO2 entering the CO2 flowline 522. In one or more embodiments, an orifice meter may be used to measure the CO2 entering the CO2 flowline 522 from the CO2 storage plant 520. The amount of CO2 introduced into the reservoir may also be measured downhole in the subsurface 215. A device 623 measuring the flow rate of the CO2 may be located downhole near the bottomhole 512 of the CO2 injection well 510. In one or more embodiments, Coriolis meters or ultrasonic meters may be used to measure the CO2 entering the reservoir near the bottomhole 512 of the CO2 injection well 510. The amount of CO2 entering the reservoir from the CO2 injection well 510 may be controlled by a choke valve 653 that may limit CO2 introduced into the reservoir. In one or more embodiments, the well environment 201 includes a mud-gas separator. The mud-gas separator is configured to separate gas from the fluids.

[0036] The well environment 201 includes a recovery or production well 536. According to one or more embodiments, a production well 536 is used to recover oil and gas from a hydrocarbon containing reservoir as part of enhanced oil recovery (EOR). In one or more embodiments a reservoir may be a depleted reservoir and may already have had productive hydrocarbons extracted. In depleted reservoirs, the carbon monitoring and quantifying system 200 may be utilized for sequestration of CO2 and not hydrocarbon exploitation. A bottomhole 538 of the production well 536 is positioned downhole proximate to the overburden 210 but within the reservoir 205. The production well 536 is fluidly connected by a flowline 542 to a processing plant 540. In one or more embodiments, the processing plant 540 includes a mud-gas separator 571 where a produced sample, i.e. sample 301 containing in situ gas 247 with CO2, O2, CH4 among other constituents, may be obtained. In one or more embodiments of the carbon monitoring and quantifying system 200, the well environment 201 includes two or more production wells 536.

[0037] The amount of in situ CO2 and other gases, including in situ CH4, produced from the reservoir may be measured uphole at the processing plant 540 by a device 641 measuring the flow rate of CO2 and other gases entering the CO2 flowline 542. In one or more embodiments, an orifice meter may be used to measure the CO2 entering the processing plant 540 from the CO2 flowline 542. The amount of CO2 produced from the reservoir may also be measured downhole in the subsurface 215. A device 643 measuring the flow rate of the CO2 may be located downhole near the bottomhole 538 of the CO2 production well 536. In one or more embodiments, Coriolis meters or ultrasonic meters may be used to measure the CO2 entering from the reservoir near the bottomhole 538 of the production well 536. The amount of produced fluids from the production well 536 in the reservoir may be controlled by a choke valve 657. The CO2 separated from the produced formation fluids may be recovered and re-injected into the reservoir.

[0038] A sample 301 is obtained from a subsurface 215 and analysis is performed at the surface 225. A sample 301 is removed from the reservoir 205 via the production well 536 and may be collected at the surface 305 from the mud-gas separator 571. In one or more embodiments, the sample 301 may be collected in isotubes for gas analysis. Once the sample is collected at the surface 225, the sample 301 may be relocated to an isotope analysis facility 321. The isotope analysis facility 321 contains various equipment and instruments configured to obtain and analyze isotopic data of the sample 301. For example, a mass spectrometer is utilized to obtain the mud gas signature.

[0039] The δ13C, δ18O, and δ2H of in situ CO2 and in situ CH4 produced from a gas 247 arising from the reservoir is measured at the isotope analysis facility 321 by isotopic analysis instruments 323. The measurements are used to calculate endpoint value of in situ CO2 and in situ CH4 using δ13C, δ18O, and δ2H. The measurements may be performed before the anthropogenic CO2 has mixed with the in situ CO2 and in situ CH4. The in situ gases 247 such as in situ CO2 and in situ NH4 arise from the kerogen 231 located in the reservoir.

[0040] According to one or more embodiments, other compounds may be added to the anthropogenic CO2 before or during introduction into a reservoir. For example, the CO2 may be injected with hydraulic fracturing fluid. Further, the CO2 may also be injected with any other substances like water or surfactants to aid sequestration.

[0041] As provided in the FIG. 1 workflow 100, in one or more embodiments the anthropogenic CO2 is introduced into an oil and gas reservoir as part of enhanced oil and gas recovery (EOR). In one or more embodiments, the anthropogenic CO2 is introduced into an oil and gas reservoir as part of drilling operations. In one or more embodiments, the anthropogenic CO2 is introduced into an oil and gas reservoir as part of hydraulic fracturing operations. The introduction of the CO2 is not so limited to be introduced into merely hydrocarbon-bearing formations, such as oil and gas reservoirs. The anthropogenic CO2 may also be introduced into depleted oil and gas reservoirs, saline aquifers, or basaltic formations, and unconventional reservoirs, such as coal beds and fractured or tight formations.

[0042] The introduced anthropogenic CO2 traverses into a reservoir 205 from the CO2 injection well bottomhole 512 (see arrow 251), as shown in FIG. 1. A portion of the introduced CO2 traversing in the reservoir 205 may be sequestered 233 in the reservoir 205 shortly after introduction; however, another portion of the CO2 is not sequestered or may require an additional time period for sequestration. A ratio of the portions or amount of CO2 sequestered and CO2 that is not sequestered is referred to as the “efficiency” of CO2 sequestration.

[0043] Several factors affect the efficiency of CO2 sequestration. The CO2 sequestration efficiency is mainly due to the density of CO2 compared to other fluids found in a reservoir, such as brine and residual hydrocarbons. The low specific gravity of CO2 may cause upward migration of CO2 (see arrow 255) and pooling at to the top of the reservoir 205, also known as “gravity override”. The anthropogenic CO2 (see arrow 255) may also mix within situ gas (see arrow 249) to form a mixed gas containing in situ gas and anthropogenic CO2 (see arrow 255). At the boundary of the interface between the reservoir and the overburden 210, the CO2 may collect as a layer of a separated yet continuous fluid phase within the reservoir. This near-homogenous layer of CO2 fluid makes it difficult for CO2 to dissolve into other fluids in the formation or to react with the formation material and chemically convert into an inert substance.

[0044] During introduction of CO2, the efficiency of the CO2 trapped within the reservoir is also reduced by an effect known as viscous fingering. Viscous fingering occurs because the viscosity of the formation fluids in a reservoir are greater than the viscosity of the introduced CO2. The difference in the viscosities of the CO2 and the formation fluids causes a condition where the interface of two liquids bypasses sections of the reservoir as well as fluids contained therein as the introduced CO2 moves inward, creating an uneven, or fingered, profile. Viscous fingering may cause CO2 to bypass much of the pore space of the reservoir, thereby reducing the total volume utilized for sequestration.

[0045] As provided in the FIG. 1 workflow 100, in one or more embodiments a production well 536 is configured to recover produced fluid containing a mixed gas (see arrow 257) from the reservoir 205. A produced sample 301 containing mixed gas 257 with anthropogenic CO2, in situ CO2, in situ O2, in situ CH4, among other constituents, may be obtained. A sample 301 of the mixed gas (see arrow 257) is obtained from a subsurface 215 and analysis is performed at the surface 225. A sample 301 is removed from the reservoir 205 via the production well 536 and may be collected at the surface 305 from the mud-gas separator 571. In one or more embodiments, the sample 301 may be collected in isotubes for gas analysis.

[0046] A time period between injecting anthropogenic CO2 into the reservoir and collecting a first sample obtained from the production well may depend on several factors including the hydraulic fracturing operation where CO2 is injected. Current hydraulic fracturing methods in source rocks involves multistage fracturing in extended reach horizontal wells. Typically, several stages are fractured per day and a well may be completed in a time period ranging from days to weeks. Further, an injection well may be shut in for a period of time ranging from weeks or months before production commences. After a first sample is collected, additional samples may be collected over a period of time. According to one or more embodiments, additional samples may be collected in approximately two-week intervals.

[0047] Once the sample is collected at the surface 205, the sample 301 may be relocated to an Isotope analysis facility 321. The δ13C, δ18O, and δ2H of in the mixed CO2 and other gases arising from the reservoir are measured at the isotope analysis facility 321 by isotopic analysis instruments 323. The measurements are used to calculate endpoint values of the mixed CO2 and the other gases using δ13C, δ18O, and δ2H. The measurements are performed after the anthropogenic CO2 has mixed with the in situ CO2 and in situ CH4. The in situ gases 247 such as in situ CO2 and in situ CH4 arise from the kerogen 231 located in the reservoir while the anthropogenic CO2 was injected into the reservoir 205.

[0048] The isotopic fractionation of carbon may be analyzed according to CO2 gas using mass spectrometers. The mass spectrometer separates ions by their mass to charge ratio (m / z). Differentiating between δ13C for CH4 versus δ13C for CO2 is useful because their values may be used as a chemical fingerprint of the well to monitor changes in CO2 retention or sequestration during production as a function of time. This is also useful for determining the fraction of anthropogenic CO2 versus in situ CO2. An Isotope Mixing Equation may be used to determine the contributions of each source of CO2:α=(δ1⁢3⁢CM-δ1⁢3⁢CX)(δ1⁢3⁢CY-δ1⁢3⁢CX)Equation⁢ (8)

[0049] where α is the fractionation factor, δ13CY is the δ13C value from in situ thermogenic sources of CO2 generated from the reservoir, δ13CX is the δ13C value from anthropogenic sources introduced into the reservoir, and δ13CM is the δ13C value from a mixture of CO2 produced from the reservoir. δ13CX and δ13CY may be used as endpoint values to measure their relative percentages or fraction of anthropogenic CO2 and in situ CO2 in a mixed CO2 sample, and to determine the retention efficiency or fraction of anthropogenic CO2 sequestered in the reservoir.

[0050] FIG. 3 is an example displaying inputs and results using Equation 8. In FIG. 3, computations for various δ13C value inputs are shown. Based on these values, 50% of the produced mixed CO2 gas is from in situ sources (meaning the CO2 is from the formations of the reservoir), and 50% is the produced mixed CO2 gas from anthropogenic sources (meaning the CO2 that was injected in to the reservoir). This is based on a mass balance equation since the contribution of sources as fractions must sum to 1.0. Thus, the CO2 retention efficiency would be 50% according to the following relationship where sum of fX and fY equals one (fX+fY=1):δ1⁢3⁢CM=δ1⁢3⁢CX⁢fX+δ1⁢3⁢CY⁢fYEquation⁢ (9)

[0051] This relationship holds so long as fractionation does not occur when the gas is produced from the reservoir or during the contact of the anthropogenic gas with the formation. However, such fractionation may occur because CO2 is soluble in water and oil. Aqueous solubility may change the fractionation of CO2 with the formation and disassociation of carbonate as follows:

[0052] where α1 is the fractionation factor of gaseous CO2 dissolving in water to form aqueous CO2, α2 is the fractionation factor of aqueous CO2 reacting to form bicarbonate (HCO3−), α3 is the fractionation factor of bicarbonate reacting to form carbonate (CO32−), α4 is the fractionation factor of carbonate reacting to form calcium carbonate (CaCO3), and Σα is the net change of gaseous CO2 fractionation caused by reactions α1, α2, α3, and α4 occurring within the formation. With respect to the carbonate matrix of many source rocks, this may alter the initial CO2 isotopic values of the introduced anthropogenic source. A standard deviation may occur in δ13C value that may be corrected by using a compensation factor and modifying the fractionation factor in equation (8):α=(δ1⁢3⁢CM-δ1⁢3⁢CX+Δ1⁢3⁢CX)(δ1⁢3⁢CY-δ1⁢3⁢CX+Δ1⁢3⁢CX)Equation⁢ (11)where Δ13CX is the difference in the δ13C value before introduction of anthropogenic CO2 and after interaction of the anthropogenic CO2 with aqueous fluids of the reservoir. These values are measured experimentally.Further, the δ13C of another gas that is not affected by aqueous solubility may be measured and analyzed to monitor changes in δ13C of CO2. Accordingly, monitoring and analyzing δ13C of CH4 may be useful.

[0054] Returning to Equation 9, if the volumes of the anthropogenic versus in situ sources are known along with their isotopic values, then δ13CM of the created mixture may be computed to compare with those analyzed from the time series. The values then may be plotted against CH4 values to establish a baseline. This relationship may be useful in monitoring the change in CO2 and CH4 isotopic values because δ13C value of the CH4 gas may change in less time than CO2 depending on the interval being produced from a reservoir. This highlights the usefulness of analyzing the isotopic mud-gas chemistry of produced samples.

[0055] FIG. 4 illustrates a graph displaying δ13C values over the depth of production wells for a particular formation. The δ13C values (dotted line) are reported in parts per thousand (‰) for C1. In this graph, C1 represents δ13C values of CH4. The y-axis of the graph displays the true vertical depth (TVD) of Well-D and Well-E in feet (ft). The various δ13C values were measured for C1-C5 gases obtained from mud-gas samples of drill cuttings that were collected in isotubes. The dissolved concentrations of C1-C5 gases (solid line) are reported as parts per million (ppm).

[0056] The graph shows that CH4 values may vary across the same TVD with respect to Well-D and Well-E. For Well-E, the lowest δ13C value for CH4 is from the formation section labeled 483 and illustrated with diagonal lines having a negative slope. The lowest δ13C value for CH4 from the formation section labeled 483 is measured to be −57‰. The highest δ13C value for CH4 is from the formation section labeled 485 and illustrated with narrow diagonal lines having a positive slope. The highest δ13C value for CH4 from the part of the formation section labeled 485 is measured to be −51‰. These values may be used as endpoints for Well-E. The endpoint measurements provide boundary values that are used to detect the change in amount of anthropogenic CO2 versus the in situ CO2.

[0057] FIG. 5 illustrates a graph displaying δ13C values of CO2 and CH4 from the formation section labeled 483 and the formation section labelled 485. The diagonal lines on the graph of FIG. 5 define the potential fractionation that may occur if CO2 is reduced to CH4. This is usually not an issue in hydrocarbon reservoirs because microbial activity facilitating these reactions is limited due to high pressure and temperature; however, it is useful to ensure that the reactions are not occurring as it may alter the fractionation between the initial CO2 and CH4 in the reservoir. In FIG. 5, δ13CM of CO2 values are plotted versus the δ13C values of CH4. The values are obtained from the data displayed in FIG. 4. As shown, the average δ13C of in situ CO2 endpoint is 4.14‰ and the average δ13C of anthropogenic CO2 is −0.4‰.

[0058] Using the measurements displayed in FIG. 4 and FIG. 5, the well received 30% of CO2 from an anthropogenic source with δ13C of 0.4‰ and mixed with 70% of in situ CO2 with δ13C of 4.14‰. Using Equation 9, the δ13C value for the mixed CO2 gas was calculated to be +2.778.

[0059] FIG. 6 illustrates a graph of δ13C values of CO2 and CH4 from FIG. 5 using a different scale to view a time series analysis. Changing the scale of the data of the graph in FIG. 5 is useful for reviewing the spatial resolution between the endpoints of the boundary conditions. In FIG. 6, δ13CM value of CO2 values are plotted versus the δ13C values of CH4. Also, as the well is produced, the graph allows for a method for plotting the δ13C from both CH4 and CO2 to monitor for significant changes over time. According to one or more embodiments, a first sample (T1) is collected and analyzed for δ13C and a second sample (T2) is also collected and analyzed for δ13C. The data shows that production is originating from both the from the formation section labeled 483 and the formation section labelled 485 (see FIG. 4) based on δ13C of the CH4 and the δ13C of the CO2. This is because the values are similar to the initially computed values.

[0060] Using the Isotope Mixing Equation, a change, in the retention of anthropogenic CO2 may be measured, monitored, and quantified over a period of time represented by the difference between the collection times (i.e. time difference between T2 and T1). The time period between T2 and T1 may vary. For example, the time period between T2 and T1 could be 1 week or 1 month or other time periods depending on the well conditions.

[0061] 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.

Claims

1. A process for monitoring and quantifying anthropogenic carbon retained within a reservoir, the process comprising:measuring δ13C and δ18O of in situ CO2 from a reservoir;calculating endpoint values of the in situ CO2 using the δ13C and the δ18O;measuring δ13C, and δ18O of anthropogenic CO2;calculating endpoint values of the anthropogenic CO2 using the δ13C, and the δ18O;injecting the anthropogenic CO2 into the reservoir via an injection well;obtaining a volume or mass the anthropogenic CO2 injected into the reservoir;collecting a produced sample from the reservoir via a production well after a period of time;measuring δ13C, and δ18O of a mixed in situ and anthropogenic CO2; andcalculating fraction of the anthropogenic CO2 sequestered in the reservoir by using the endpoint values.

2. The process of claim 1, further comprising measuring δ13C and δ2H of in situ CH4 from the reservoir.

3. The process of claim 2, further comprising calculating endpoint values of the in situ CH4 using the δ13C and δ2H.

4. The process of claim 1, wherein measuring of in situ CO2 comprises measuring an amount of CO2 recovered from a mud gas-separator.

5. The process of claim 1, wherein collecting comprises collecting multiple produced samples over a time interval.

6. The process of claim 5, wherein the time interval is two or more weeks.

7. The process of claim 1, wherein collecting comprises collecting produced sample in an isotube.

8. The process of claim 1, wherein measuring δ13C, and δ18O of a mixed CO2 comprises measuring CO2 recovered from a mud gas separator.

9. The process of claim 1, wherein the reservoir is shut in for a period of time after injecting the anthropogenic CO2 into the reservoir via an injection well.

10. The process of claim 9, wherein the reservoir is shut in for at least a one month period before production commences.

11. The process of claim 1, wherein calculating the fraction is accomplished by using an isotope mixing equation.

12. The process of claim 11, wherein the isotope mixing equation is modified by a compensation factor.

13. The process of claim 1, wherein collecting produced sample from the reservoir via a production well is during enhanced oil recovery or during drilling operations.

14. An anthropogenic CO2 monitoring and quantifying system comprising:one or more injection wells;one or more production wells;one or more measurement devices associated with the one or more injection wells for measuring an amount of CO2 injected into a reservoir via the one or more injection wells; anda measurement collection and analysis system configured for receiving gas samples and for measuring an amount of CO2 sequestered within the reservoir.

15. The system of claim 14, wherein CO2 monitoring and quantifying system further comprises a mud gas separator.

16. The system of claim 14, wherein CO2 monitoring and quantifying system further comprises a CO2 storage plant.

17. The system of claim 14, wherein CO2 monitoring and quantifying system further comprises a processing plant.

18. The system of claim 14, wherein the reservoir is a depleted reservoir.

19. The system of claim 14, wherein the reservoir is undergoing enhanced oil recovery or drilling operations.

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