Monitoring Carbon Sequestration in Source Rock Reservoirs Using Stable Isotopic Fractionation to Quantify Its Retention Efficiency

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.offers an example of this computation, given the δC 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 δC, δO, and δH of CO2 and other gases (such as CH4) to determine the amount of anthropogenic CO2 sequestered in a reservoir.

provides a schematic of the workflowillustrating general steps of one or more embodiments of the method. The steps may include: Measuring δC, and δO of anthropogenic CO2; Calculating endpoint value of anthropogenic CO2 using δC, and δO; Measuring δC, δO, and δH of in situ CO2 and in situ CH4 from a reservoir; Calculating endpoint value of in situ CO2 and in situ CH4 using δC, δO, and δH; Injecting anthropogenic CO2 into reservoir via an injection well; Measuring volume or mass the anthropogenic CO2 injected into reservoir; Collecting produced sample from reservoir via a production well after a period of time; Conducting isotopic analysis of produced sample; and Calculating fraction of anthropogenic CO2 retained in reservoir by using endpoint values.

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.

For CO2 produced from a reservoir (produced CO2), differences in isotopic fractionation betweenC/C andO/O 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.

The isotope value for an element may be defined as ratio (R):

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 (H/H), carbon isotopes (C/C), and oxygen isotopes (O/O).

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.

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:

where α is the fractionation factor, Ris ratio of isotope in phase A, and Ris ratio of isotope in phase B. The fractionation factor, α may be simplified as follows:

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:

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 (C) and lighter isotope (C) 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 ofC andC. This adjustment factors out errors introduced from metabolic and respiratory pathway in the sample by using a standard reference. For example, the δC value of a compound, whether CO2 or CH4, may be derived relative to aC/C standard from CO2 gas generated from selected carbonates digested with pure (100%) phosphoric acid as such:

where δC 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 knownC/C may be used to compute the δC value of carbon gases per mil (‰) as the per mil difference (+/−%) relative to that standard. The value of δC may be negative or positive. A negative of δC value indicates that the sample is depleted inC relative to the standard, and a positive of δC value indicates that the sample is enriched inC relative to the value of the standard. Similarly, the relationship indicated by Equation (7) is applicable for isotopic fractionation of oxygen or hydrogen. ForO andH 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.

is a diagram that illustrates a carbon monitoring and quantifying system in accordance with one or more embodiments. The carbon monitoring and quantifying systemincludes a well environmentthat includes a reservoir. Above the reservoiris a fluid-impenetrable overburden, which is part of subsurface. Below the reservoiris the underburden, which is also part of the subsurface. The reservoirmay 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 environmentalso includes a surfacerepresenting the surface of the Earth, and a subsurfacebelow the surface. Traversing through subsurfaceenvironment is a portion of the well injection system, which is part of the well environment.

The carbon monitoring and quantifying system includes an isotope analysis facilityin accordance with one or more embodiments. The analysis facility may be part of a measurement, collection and analysis system. The isotope analysis facilitymay 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 workflowofincluding the measurements of δC, δ1O, and δH of anthropogenic, in situ and mixed gases in a particular reservoir. Some of the apparatus housed in the isotope analysis facilitymay include equipmentsuch as isotopic analysis instrumentslike mass spectrometers configured to obtain isotopic data, and processorsconfigured 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 workflowof.

The well injection systemincludes a CO2 injection well. A bottomholeof the CO2 injection wellis positioned proximate to the underburdenbut within the reservoir. In one or more embodiments, the underburdenis porous and permits CO2 migration. The CO2 injection wellmay transverse into the underburdenand the bottomholeof the CO2 injection wellmay be positioned in the underburden. In one or more embodiments of the carbon measurement and quantification system, the well environmentincludes two or more CO2 injection wells.

CO2 may be stored on the surfacein a CO2 storage plant. CO2 in the CO2 storage plantmay pass through a CO2 flowlineand introduced into the reservoirfrom a CO2 injection well. 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.

A sampleof anthropogenic CO2 may be obtained from the CO2 storage plant. According to one or more embodiments, the sampleis collected from the CO2 storage plantand relocated to an Isotope analysis facilityfor isotope analysis where the δC, δ1O of the anthropogenic CO2 are measured by the isotopic analysis instruments. The measurements are used to calculate endpoint value of anthropogenic CO2.

The amount of CO2 introduced into the reservoir may be measured uphole at the CO2 storage plantby a devicemeasuring the flow rate of CO2 entering the CO2 flowline. In one or more embodiments, an orifice meter may be used to measure the CO2 entering the CO2 flowlinefrom the CO2 storage plant. The amount of CO2 introduced into the reservoir may also be measured downhole in the subsurface. A devicemeasuring the flow rate of the CO2 may be located downhole near the bottomholeof the CO2 injection well. In one or more embodiments, Coriolis meters or ultrasonic meters may be used to measure the CO2 entering the reservoir near the bottomholeof the CO2 injection well. The amount of CO2 entering the reservoir from the CO2 injection wellmay be controlled by a choke valvethat may limit CO2 introduced into the reservoir. In one or more embodiments, the well environmentincludes a mud-gas separator. The mud-gas separator is configured to separate gas from the fluids.

The well environmentincludes a recovery or production well. According to one or more embodiments, a production wellis 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 systemmay be utilized for sequestration of CO2 and not hydrocarbon exploitation. A bottomholeof the production wellis positioned downhole proximate to the overburdenbut within the reservoir. The production wellis fluidly connected by a flowlineto a processing plant. In one or more embodiments, the processing plantincludes a mud-gas separatorwhere a produced sample, i.e. samplecontaining in situ gaswith CO2, O2, CH4 among other constituents, may be obtained. In one or more embodiments of the carbon monitoring and quantifying system, the well environmentincludes two or more production wells.

The amount of in situ CO2 and other gases, including in situ CH4, produced from the reservoir may be measured uphole at the processing plantby a devicemeasuring the flow rate of CO2 and other gases entering the CO2 flowline. In one or more embodiments, an orifice meter may be used to measure the CO2 entering the processing plantfrom the CO2 flowline. The amount of CO2 produced from the reservoir may also be measured downhole in the subsurface. A devicemeasuring the flow rate of the CO2 may be located downhole near the bottomholeof the CO2 production well. In one or more embodiments, Coriolis meters or ultrasonic meters may be used to measure the CO2 entering from the reservoir near the bottomholeof the production well. The amount of produced fluids from the production wellin the reservoir may be controlled by a choke valve. The CO2 separated from the produced formation fluids may be recovered and re-injected into the reservoir.

A sampleis obtained from a subsurfaceand analysis is performed at the surface. A sampleis removed from the reservoirvia the production welland may be collected at the surfacefrom the mud-gas separator. In one or more embodiments, the samplemay be collected in isotubes for gas analysis. Once the sample is collected at the surface, the samplemay be relocated to an isotope analysis facility. The isotope analysis facilitycontains various equipment and instruments configured to obtain and analyze isotopic data of the sample. For example, a mass spectrometer is utilized to obtain the mud gas signature.

The δC, δ1O, and δH of in situ CO2 and in situ CH4 produced from a gasarising from the reservoir is measured at the isotope analysis facilityby isotopic analysis instruments. 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 gasessuch as in situ CO2 and in situ NH4 arise from the kerogenlocated in the reservoir.

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.

As provided in theworkflow, 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.

The introduced anthropogenic CO2 traverses into a reservoirfrom the CO2 injection well bottomhole(see arrow), as shown in. A portion of the introduced CO2 traversing in the reservoirmay be sequesteredin the reservoirshortly 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.

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) and pooling at to the top of the reservoir, also known as “gravity override”. The anthropogenic CO2 (see arrow) may also mix within situ gas (see arrow) to form a mixed gas containing in situ gas and anthropogenic CO2 (see arrow). At the boundary of the interface between the reservoir and the overburden, 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.

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.

As provided in theworkflow, in one or more embodiments a production wellis configured to recover produced fluid containing a mixed gas (see arrow) from the reservoir. A produced samplecontaining mixed gaswith anthropogenic CO2, in situ CO2, in situ O2, in situ CH4, among other constituents, may be obtained. A sampleof the mixed gas (see arrow) is obtained from a subsurfaceand analysis is performed at the surface. A sampleis removed from the reservoirvia the production welland may be collected at the surfacefrom the mud-gas separator. In one or more embodiments, the samplemay be collected in isotubes for gas analysis.