method for producing hydrocarbons

专利摘要:
METHOD FOR PRODUCING HYDROCARBONS A method for producing hydrocarbons using reservoir surveillance is disclosed. The method includes interpreting a sample to determine noble gas signatures and aggregated isotope signatures for the region of interest. Then, using the fingerprint region of interest to perform reservoir surveillance on fluids produced from subsurface regions
公开号:BR112014007819B1
申请号:R112014007819-0
申请日:2012-11-09
公开日:2021-03-02
发明作者:Robert J. Pottorf；Michael Lawson；Steven R. May；Sebastien L. Dreyfus；Sumathy Raman；Amelia C. Robinson
申请人:Exxonmobil Upstream Research Company；
IPC主号:

专利说明:

CROSS REFERENCE TO RELATED ORDER
[0001] This application claims priority benefit from the National Stage of International Patent Application No. PCT / US2012 / 52542, filed on August 27, 2012, which claims priority benefit from Provisional Patent Application US 61 / 668,822 filed in November 11, 2011 entitled “METHOD FOR DETERMINING THE PRESENCE AND LOCATION OF A SUBSURFACE HYDROCARBON ACCUMULATION AND THE ORIGIN OF THE ASSOCIATED HYDROCARBONS”, all of which is incorporated by reference here. FIELD OF DISSEMINATION
[0002] Modalities of the present discovery generally relate to the field of geochemistry. More particularly, the present disclosure relates to systems and methods for managing hydrocarbon production by performing reservoir surveillance through the use of aggregate isotope data, noble gas data, or the combination of aggregate isotope and noble gas data. These aggregate isotope and / or noble gas data are combined with geochemical and physical data to develop understandable geochemical fingerprints required to perform reservoir surveillance for one or more areas of interest. FUNDAMENTALS
[0003] This section is intended to introduce various aspects of the technique, which can be associated with exemplary modalities of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the methodologies and techniques disclosed. Consequently, it should be understood that this section should be read in this light, and not necessarily as admissions to the prior art.
[0004] To produce hydrocarbons from accumulations or subsurface formations, a development plan is typically used. The development plan may include a reservoir depletion scheme and a reservoir surveillance strategy. Such a reservoir surveillance strategy may include monitoring production fluids to detect and predict static reservoir compartmentalization and to determine the mixing ratios of different reservoir intervals in a mixed hydrocarbon phase for long-term delivery of hydrocarbons (e.g. production allocation). An additional consideration in reservoir development is to predict how reservoir performance can change over up to 10 years. The prediction of dynamic changes in hydrocarbon production for individual compartments, intervals and individual reservoirs typically relies on measurements of fluid properties in situ, such as PVT studies, and can be influenced by chemical or physical processes, such as liquid discharge, by example.
[0005] An effective technique to mitigate the effects of chemical and physical processes that can negatively impact reservoir performance is by monitoring geochemical and physical parameters (such as pressure). That is, a change in conditions can be identified and then adjustments to hydrocarbon production are made. In fact, petroleum geochemistry has been applied to various aspects of reservoir surveillance based on the variability of fluid compositions within the same compartments, intervals or reservoirs. See for example, Larter and Aplin, (1995). See, e.g., Larter, S.R., and Aplin, A.C. Reservoir geochemistry: methods, applications and opportunities. Geological Society of London Special Publication, 86, 5-32, 1995. For example, isotopic and molecular compositional analysis of hydrocarbons and / or water provides different signatures for reservoir and water hydrocarbon products when it differs from the existing signature between intervals or compartments. However, these compositional and isotopic signatures have limited application in static reservoir surveillance applications when the geochemical signatures of hydrocarbons derived from different reservoirs or compartments in the area of interest are indistinguishable. Additionally, in dynamic reservoir surveillance applications, traditional techniques are reactive to deviation from such processes and do not provide advanced indications of imminent changes in reservoir fluid properties. This is exacerbated by the fact that three is a shortage of tracers available to conduct reservoir surveillance in predominantly natural gas reservoir systems. In fact, currently typically only systems of stable isotope and / or organic and inorganic geochemistry of carbon and hydrogen mass are used in such investigations or monitoring practices. In addition, mass composition and stable isotopes can provide information on source, maturation and the extent of alteration processes such as biodegradation. These techniques do not provide introspection in physical processes, such as phase transformations, liquid spillage or degassing of formation water, nor do they allow estimates of HC volume changes that occur during production from a compartment, interval or reservoir ( region of interest).
[0006] As a result, intensifications to geochemical traces are necessary for reservoir surveillance. These indicators can provide greater variability than current traits and exhibit sensitivity to chemical and / or physical processes to provide more effective dynamic and static reservoir surveillance monitoring techniques. In this way, depletion strategies can be adjusted to improve hydrocarbon production and advance our understanding of long-term assessment and management practices. SUMMARY
[0007] In one embodiment, a method for producing hydrocarbons is described. The method may include: taking a sample from one or more subsurface regions; interpret the sample to determine one or more noble gas signatures and an aggregated isotope signature for the samples obtained; generate a region of digital fingerprint of interest having one or more noble gas signatures and an aggregated isotope signature for the samples obtained; producing fluids from one or more subsurface regions, where the fluids produced comprise hydrocarbons; and perform reservoir surveillance on fluids produced from one or more subsurface regions.
[0008] In one or more modalities, the method may include certain characteristics. For example, carrying out reservoir surveillance on the fluids produced still comprises: obtaining a first sample of the fluids produced; determining a first fingerprint of the sample for the first sample obtained, wherein the first fingerprint of the sample comprises one or more noble gas signatures and an aggregated isotope signature; compare the first sample fingerprint to the fingerprint of the region of interest; and determine whether the first sample fingerprint has changed based on comparing the region of the first sample fingerprint with the fingerprint of the region of interest. In another example, performing reservoir surveillance on produced fluids also comprises: obtaining a second sample of the produced fluids, in which the second sample is obtained a period of time after obtaining the first sample; determining a second sample fingerprint for the second sample, wherein the second sample fingerprint comprises one or more noble gas signatures and an aggregated isotope signature; comparing the second sample fingerprint to the fingerprint region of interest; and determining whether the second sample fingerprint has changed based on comparing the second sample fingerprint with the region of fingerprint of interest. Additionally, the comparison is between the first sample fingerprint and a static fingerprint for the regions of interest to determine interregional changes and / or the comparison is between the first sample fingerprint and a dynamic fingerprint for the regions of interest in determining intra-regional changes. The method may also include developing a depletion strategy based on the region of the fingerprint of interest to produce hydrocarbons of a specific quality and composition.
[0009] These and other features and advantages of the present disclosure will be readily apparent upon consideration of the following description in conjunction with the accompanying drawings. BRIEF DESCRIPTION OF THE DRAWINGS
[0010] Advantages of current techniques may become apparent under review and following detailed description and accompanying drawings.
[0011] Figure 1 is a flowchart for producing hydrocarbons according to an exemplary modality of current techniques.
[0012] Figure 2 is a flow chart for using different reservoir surveillance techniques according to an exemplary modality of current techniques.
[0013] Figure 3 is a flowchart for using static fingerprints for multiple regions of interest to conduct reservoir surveillance according to an exemplary modality of current techniques.
[0014] Figure 4 is an alternative flowchart for using a dynamic change in the fingerprint of an individual or unique region of interest to conduct reservoir surveillance according to an exemplary modality of current techniques.
[0015] Figure 5 is a block diagram of a computer system according to methodologies and techniques disclosed. DETAILED DESCRIPTION
[0016] Various terms as used here are defined below. In addition, if a term used in a claim is not defined below, a personal definition should be given in the relevant technique given that term in the context in which it should be used.
[0017] As used here, "one" or "one" entity refers to one or more of the entities. As such, the terms "one" (or "one"), "one or more", and "at least one" can be used interchangeably here unless a limit is specifically quoted.
[0018] As used here, the terms "comprising", "understands", "understood", "containing", "contains", "having", "has", "including", "includes" are open transition terms used for the transition of a subject recited before the term to one or more elements recited after the term, where the element or elements listed after the transition term are not necessarily the only elements that form the subject.
[0019] As used here, "exemplary" means exclusively "serving as an example, instance, or illustration". Any modality described here as an example is not intended to be built as preferred or advantageous under the other modalities.
[0020] As used here, "hydrocarbons" are generally defined as molecules formed primarily of carbon and hydrogen atoms such as oil and natural gas. Hydrocarbons can also include other elements or compounds, such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and sulfur. Non-hydrocarbon gases, such as hydrogen sulfide (H2S), nitrogen gas (N2) and carbon dioxide (CO2), can be produced with or in addition to hydrocarbons. Hydrocarbon and non-hydrocarbon gases can be produced from hydrocarbon reservoirs through wells by penetrating a hydrocarbon-containing formation. Hydrocarbons derived from a hydrocarbon reservoir may include, but are not limited to, petroleum, kerogen, bitumen, pyrobetum, asphaltenes, breus, oils, natural gas, or combinations thereof. Hydrocarbon and non-hydrocarbon gases can be located inside or adjacent to the mineral matrices inside the earth, cited reservoirs. Matrices may include, but are not limited to, sedimentary rocks, sands, silicates, carbonates, diatomites, and other porous media.
[0021] As used here, "hydrocarbon production" or "producing hydrocarbons" refers to any activity associated with hydrocarbon extraction from a well or other opening. Hydrocarbon production typically refers to any activity conducted in or in the well after the well is completed. Consequently, hydrocarbon production or extraction includes not only primary hydrocarbon extraction, but also secondary and tertiary production techniques, such as gas or liquid injection to increase drive pressure, hydrocarbon mobilization or treatment by, for example, chemical or hydraulic borehole billing to promote increased flow, well service, well registration, and other well and well bore treatments.
[0022] As used here the term "noble gases" refers to a series of chemically inert elements that exhibit similar properties. The six naturally occurring noble gases are helium (He), neon (Ne), Argon (Ar), Krypton (Kr), Xenon (Xe), and radon (Rn). The noble gases considered in this disclosure are He, Ne, Ar, Kr and Xe.
[0023] As used here the term "isotope" refers to one or two or more atoms with the same atomic number but with different neutron numbers. For example, helium can be present in one or two stable isotopes: 3He, which has 2 protons and 1 neutron (shown here as 3He); and 4He, which has 2 protons and 2 neutrons.
[0024] As used here the term "signatures" refers to the abundances, concentrations and / or relative ratios of various elements and isotopes of a given species.
[0025] As used here the term "formation water" refers to any water that resides within the subsurface that may be present in a reservoir rock, however water on the subsurface may also occur in aquifers, sediments, or not associated with an occurrence of hydrocarbon. For the purposes indicated here, the primary focus is water occurring in a porous medium within the accumulation or immediately below, but in contact with the hydrocarbon accumulation (eg the water leg). This can derive from a) meteoric origin, b) recharge of surface water such as rainwater or seawater and that migrates through the permeable rock within the subsurface, and / or c) water trapped in the sediment during burial and remains in the place.
[0026] As used here the term "residence time" refers to the period of time that formation water is present within the subsurface, and the age of the formation water can be considered.
[0027] As used here the term "radiogenic" refers to the generation or creation of a substance through the radioactive decay of another substance. Gases 4 21 40 82 86 129 130 136 noble radiogenics include He, Ne, Ar, Kr, Kr, Xe, Xe and Xe.
[0028] As used here the term "region of interest" refers to an interval, compartment, or reservoir where hydrocarbons, non-hydrocarbon gases and / or water may reside. “Regions of interest” refer to multiple intervals, compartments, or reservoirs where hydrocarbons, non-hydrocarbon gases and / or water may reside.
[0029] As used herein the term "interregional" or "inter-compartment" refers to comparisons of multiple geochemical fingerprints derived from multiple regions of interest including, but not limited to, compartments, intervals or reservoirs. Deviations in “interregional” fingerprints can be derived from different proportions of individual regions of interest contributing to a combined flow stream during production, multiple compartments that are connected on the subsurface that produces a consistent fingerprint with multiple inputs, and the like. "Intra-regional" or "intra-compartment" refers to comparisons of multiple geochemical fingerprints derived from a region of interest including, but not limited to, compartments, ranges or reservoirs. Derivations in “intra-regional” fingerprints are derived from changes in the properties of a region of interest such as produced fluids or processes occurring within the region of interest.
[0030] As used here the term "fingerprint" or "geochemical fingerprint" refers to a collection of geochemical signatures that are associated with a particular region of interest.
[0031] As used herein the term "signatures" refers to chemical or geochemical compositions, components, concentrations or ratios of one or more elements, isotopes, compounds, or the like. These signatures can be derived from one or more of the following, hydrocarbons, non-hydrocarbon gases, water, noble gases, and aggregated isotopes.
[0032] As used here the term "thermogenic" refers to the hydrocarbons generated from kerogen which is currently / has been in the past subject to high temperature and pressure.
[0033] As used here, the term “dis-risk” refers to an assessment of the possibility that undesirable species such as H2S, CO2 are present in concentrations that make hydrocarbon production or refining more difficult or reduces the value of the hydrocarbons produced.
[0034] As used here, the term "computer component" refers to a computer-related entity, either hardware, firmware, software, a combination thereof, or running software. For example, a computer component can be, but is not limited to, a process running on a processor, processor, object, executable, threat of execution, a program, and / or a computer. One or more computer components can reside within a process and / or threat of execution and a computer component can be located on a computer and / or distributed between two or more computers.
[0035] As used here, the terms "computer-readable media" or "machine-readable media tangible" refer to any tangible storage that participates by providing instructions to a processor for execution. Such a media can take many forms, including, but not limited to, non-volatile media, and volatile media. Non-volatile media includes, for example, NVRAM, or magnetic or optical disks. Volatile media include dynamic memory, such as main memory. Computer-readable media can include, for example, a floppy disk, a floppy disk, hard disk, magnetic tape, or any other magnetic medium, optical-magneto medium, a CD-ROM, any other optical medium, a RAM, a PROM , and EPROM, a FLASH-EPROM, a solid state medium such as holographic memory, a memory card, or any other type of memory chip or cartridge, or any other physical medium on which a computer can read. When computer-readable media is configured according to the database, it is to be understood that the database can be of any type of database, such as relational, hierarchical, object-oriented, and / or the like. Consequently, exemplary modalities of the present techniques can be considered to include a tangible storage medium or tangible distribution medium and before equivalents recognized by successor technique and media, in which the software implementations that modalize the present techniques are stored.
[0036] Some portions of the detailed description in which it follows are presented in terms of procedures, steps, logic blocks, processing and other symbolic representations of operations on data bits within a computer memory. These descriptions and representations are the means used by those skilled in data processing techniques to more effectively bring the substance of their work to others skilled in the art. In the present application, a procedure, step, logic block, process, or the like, is designed to be a self-consistent sequence of steps or instructions leading to a desired result. The steps are those requiring physical manipulation of the physical quantities. Usually, although not necessarily, these quantities take the form of electrical or magnetic signals capable of being stored, transferred, combined, compared, and otherwise manipulated in a computer system.
[0037] It should be kept in mind, however, that all of these similar terms are to be associated with the appropriate physical quantities and are merely convenient labels applied to those quantities. Unless otherwise recited as apparent from the following discussions, it is appreciated that through this application, discussions, using terms such as "model", "modify", "measure", "compare", "determine", "analyze" "," Issue "," display "," estimate "," integrate ", or similar, refers to the action and processes of a computer system, or similar electronic computing device, that transforms data represented as physical (electronic) quantities within of computer system records and memories in other data similarly represented as physical quantities within computer system memories or records or others such as information storage, transmission or display devices. Example methods can be better appreciated with reference to flowcharts.
[0038] While for the sake of simplicity of explanation, the illustrated methodologies are shown and described as a series of blocks, it is to be appreciated that the methodologies are not limited in the order of the blocks, as some blocks may occur in different orders and / or concurrently with other blocks from those shown and described. Furthermore, less than all the illustrated blocks may be required to implement an example methodology. Blocks can be combined or separated into multiple components. In addition, additional and / or alternative methodologies may employ additional, non-illustrated blocks. While the figures illustrate various actions that occur serially, it is to be appreciated that several actions can occur concurrently, substantially in parallel, and / or at substantially different points in time.
[0039] In the following section, specific modalities of the disclosed methodologies and techniques are described in connection with disclosed aspects and techniques. However, to the extent that the following description is specific to a particular aspect, technique or particular use, this is intended to be for exemplary purposes only and not limited to the disclosed aspects and techniques described below, but instead includes all alternatives, modifications, and equivalents falling within the scope of the appended claims.
[0040] This present disclosure involves a system and method for producing hydrocarbons more effectively through the use of reservoir surveillance. In particular, the present techniques provide a new group of conservative geochemical tracers that have greater variability than current techniques and that exhibit sensitivity to chemical and / or physical processes to provide a more effective dynamic and static reservoir surveillance monitoring technology. In particular, some applications of the method provide a means for predicting and / or identifying the earlier deviation of physical processes that occur within the reservoirs in advance of the impact being observed in the production well. This forecast can be used to improve depletion strategies by responding to changes in production before changes become a significant concern. That is, the depletion strategy can be adjusted for reduced periods of well closure and last intensified hydrocarbon production. Consequently, the integration of geochemical traits and physical properties provides an inexpensive, predicted value forecasting method that provides a comprehensive group of reservoir surveillance technologies.
[0041] In one or more modalities, the present techniques may include combining aggregated isotopic signatures of hydrocarbon gases and non-hydrocarbon gases (eg, CO2, H2S, N2, H2) with elementary noble gases and isotopic signatures obtained from gas, oil, water and fluid inclusion samples. The use of these two geochemical technologies, which are aggregated isotopic geochemistry and noble gas geochemistry, can intensify the reservoir surveillance process. When combined and integrated with traditional geochemical techniques, such as molecular geochemistry (eg methane, ethane, carbon dioxide, nitrogen), mass (eg gas mixtures) or stable isotope (eg carbon , hydrogen, nitrogen, sulfur) of hydrocarbon and non-hydrocarbon gases and physical measurements (eg pressure, volume and temperature (PVT), these techniques provide intensifications for sampling reservoir surveillance to identify individual regions of interest ( (eg reservoirs, intervals or compartments) and subsequent monitoring of produced hydrocarbons, that is, new geochemical tracers can be used to perform reservoir surveillance techniques, such as allocating production when traditional techniques do not have the sensitivity to distinguish between flows of different regions of interest. Also for the first time it provides a tool that can predict or identify the chemical and / or physical processes such as spillage of liquid that can have detrimental effects on reservoir performance. This technology provides a mechanism for other production strategies to prevent or mitigate the impact of such processes on hydrocarbon production.
[0042] Noble gases (He, Ne, Ar, Kr, and Xe) are a group of chemically inert, or conservative gases that have a low natural abundance in crustal systems. Various physical processes have resulted in different areas of noble gases (the mantle, atmospheric areas and crust) becoming distinct in their isotopic composition and relatively elementary abundances. The low abundance and distinct isotopic character of noble gases within the different areas means that contributions from these different sources to an accumulated crust fluid, such as a hydrocarbon accumulation, can generally be resolved and quantified (Ballentine and Burnard, 2002). See, e.g., Ballentine, C. J., and Burnard, P. G. Production, release and transport of noble gases in the continental crust. Reviews in Mineralogy and Geochemistry, 47, 481-538, 2002. The composition of the noble gas reservoir is controlled by the amount of atmospheric noble gases (eg 20Ne, 36Ar) introduced from the formation water and the expansion of noble radiogenic gases (eg 4He, 40Ar) produced by radioactive decay of uranium, thorium or potassium having minerals inside the reservoir. This last component is controlled lately by the concentration of these minerals and the time scale on which the expansion took place. The conservative nature of noble gases means that they are not involved in chemical or biological processes that may impact other geochemical traits. However, they are sensitive to physical processes, such as phase separation, gas removal and degassing.
[0043] The concentrations of noble gases in oil, gas, and water are based on the combined influence of their solubilities, which are a function of pressure, temperature, and fluid composition (PTX) that prevailed during dissolution or ex-solution, interaction and mixes with other fluids, and the expansion of noble gases from radioactive decay of minerals in the crust. If the PTX conditions of the water in contact with a subsurface HC accumulation can be estimated or measured, the size of the hydrocarbon accumulation can be estimated or calculated based on the partitioning of the noble gas solubility between water and hydrocarbons.
[0044] As an example, a modality may include a method for determining the volume and ratio gas / oil, condensate / gas or gas / water or oil / water from an accumulation of subsurface hydrocarbon from a sample related thereto. An initial concentration of noble atmospheric gases present in the formation water in contact with the subsurface hydrocarbon accumulation is measured or modeled. The modeled initial concentration is modified taking into account the expansion of noble radiogenic gases over time in the formation water. A sample related to the subsurface hydrocarbon accumulation is obtained. Concentrations and isotopic ratios of the noble gases present in the sample are measured. The measured concentrations and isotopic ratios of the atmospheric noble gases and the radiogenic noble gases present in the sample are compared to the modified measured / modeled concentrations of the formation water for a plurality of exchange processes. A source of hydrocarbons present in the sample is determined. A signature of atmospheric noble gas measured in the hydrocarbon phase is compared with the modified measured / modeled concentration of atmospheric noble gases in the formation water for the plurality of exchange processes. A type and ratio of hydrocarbon / water volume in the subsurface accumulation, and / or gas / oil, condensate / gas or and a subsurface accumulation volume is determined.
[0045] In another aspect, a method is disclosed to determine a type and volume of a subsurface hydrocarbon accumulation based on analysis of a sample related to it. The sample is analyzed to determine a sample's geochemical signature. An initial concentration of noble atmospheric gases present in the formation water in contact with the subsurface hydrocarbon accumulation is determined. Expansion of radiogenic noble gases is modeled to modify the initial concentration for given formation water residence times. A residence time of the formation water is determined. An extent of interaction with a hydrocarbon phase is determined. The origin of the sample is determined. A hydrocarbon / water volume ratio when the sample origin is a hydrocarbon accumulation is determined. From the hydrocarbon / water volume ratio, the volume of the hydrocarbon accumulation is determined.
[0046] In another aspect, a method is disclosed to determine a type and volume of a subsurface hydrocarbon buildup from a hydrocarbon sample thereof. An initial concentration of the noble atmospheric gases present throughout a hydrocarbon species is determined. A range of expected concentrations of noble atmospheric and radiogenic gases present in the sample is modeled for a range of residence times and for various extensions of interaction between formation water and a hydrocarbon phase. Concentrations and isotopic ratios of noble gases present in the sample are measured. The measured noble gas concentrations are compared with the modeled range of expected concentrations of atmospheric and radiogenic noble gases. Using the comparison, it is determined whether the hydrocarbons present in the sample escaped from subsurface accumulation. From the measured noble gas concentrations and the modeled range of expected concentrations of atmospheric and radiogenic noble gases, the hydrocarbon volume / water ratio forming the subsurface hydrocarbon accumulation is estimated. The ratio of hydrocarbon volume / water forming the subsurface accumulation is integrated with seismic reflection restrictions in a volume of the hydrocarbon accumulation and a volume of water present in the hydrocarbon accumulation, thus determining the volume of hydrocarbons present in the subsurface accumulation. .
[0047] The computer system includes a processor and a machine-readable, tangible storage medium that stores machine-readable instructions for execution by the processor. Machine-readable instructions include: code to determine an expected concentration of isotopes of a hydrocarbon species; code to model, using high-level ab initio calculation, an expected temperature dependence of isotopes present in the sample; code to measure an aggregated isotope signature of the isotopes present in the sample; code to compare the aggregated isotopic signature with the expected concentration of isotopes; and code to determine, using said comparison, whether hydrocarbons present in the sample originate directly from a source rock or whether the hydrocarbons present in the sample escaped from a subsurface accumulation.
[0048] The geochemistry of aggregated isotopes is based on the variation in the distribution of isotopes within a molecule that gives rise to molecules that are identical in their elementary composition, but which may differ in the isotopic composition of individual atoms within that molecule. These species are called isotopes. For example, they are three nitrogen isotopes (14N2, 15N14N, and 15N2). An isotope in which two or more isotopes are present in proximity (eg isotopic "aggregates") is called a multiply substituted isotope or aggregated isotope (eg, 15N2). The hydrocarbon isotope involves hydrocarbon compounds (eg, carbon and hydrogen atoms) that have natural isotopes of 12C, 13C, 1H, or 2H (deuterium or D). 12C forms 98.93% carbon on Earth, while 13C forms the remainder 1.07%. Similarly, the isotopic abundance of 1H on Earth is 99.985% while 2H has an abundance of 0.015%. The signature of an aggregated isotope of any molecule is a function of (i) randomly populated processes independent of temperature (stochastic distribution) and (ii) isotopic exchange of thermal equilibrium. The latter process can be controlled or dependent on the surrounding temperature. The stochastic distribution of any isotope can be determined from the mass isotope signatures of the species from which it is derived. For example, determining the stochastic distribution of methane isotopes requires knowledge of the methane 13C and D signatures.
[0049] As an example, a modality may include a method for determining a location of a subsurface hydrocarbon accumulation or region of interest in a naturally occurring substance sample. According to the method, an expected concentration of isotopes of a hydrocarbon species is determined. A dependence on the expected temperature of the isotopes present in the sample is modeled using high-level ab initio calculations. An aggregated isotope signature of the isotopes present in the sample is measured. The aggregated isotopic signature is compared with the expected isotope concentration. The current equilibrium storage temperature of the hydrocarbon species in the region of interest is determined. A location in the region of interest is determined. Various aspects of the techniques present are further described in Figures 1 to 5.
[0050] Figure 1 is a flow chart 100 for producing hydrocarbons according to a modality of the present techniques. Flowchart 100 includes the acquisition of fluid samples (eg, water, gas and / or oil) and material samples (eg, cuts or core samples) from isolated regions of interest (eg ., compartments, intervals or reservoirs). Flowchart 100 includes a drilling stage, which includes blocks 102 to 106, an analysis stage, which includes blocks 108 to 118, and followed by a hydrocarbon production stage, which includes blocks 120 and 124.
[0051] To start, the method includes drilling stage, which includes blocks 102 to 106. In block 102, a location for a well to access hydrocarbons is determined. The determination of the location of the perforation can be based on different data and models associated with the subsurface region. Drilling the well can be performed using commonly used techniques. Then, samples can be obtained, as shown in block 106. The samples, which can include fluid samples (eg, water, gas and / or oil) and material samples (eg, cuts or samples of core) of isolated regions of interest, can be obtained concurrently with the drilling of the well or subsequent to the drilling of the well. Fluid samples can be collected by techniques, such as drill stem tests (DTS's), separator samples, modular dynamic open-hole test (MDT) or similar, while core material samples or cutting samples are typically collected when drilling the pit. Obtaining the sample may also depend on the type of sample and the objective to be determined (eg, fluid inclusions vs. gas samples). For example, samples for noble gas analysis, as noted below in block 110, can be collected on sampling devices that prevent atmospheric contamination intrusion into gases.
[0052] After the samples are obtained, an analysis stage, which includes blocks 108 to 118, is performed. With the samples obtained, one or more blocks 108, 110 and 112 can be performed on the samples. Different analysis techniques may include measuring molecular and isotopic geochemistry in the sample, as noted in block 108, measuring the noble gas compositions in the sample, as noted in block 110 and / or measuring the compositions of the aggregated isotope in the sample, as noted in block 112. Measurements of molecular geochemistry, mass and isotope of gas, water, and oil samples are conducted to characterize the organic signature of fluids including water and hydrocarbons extracted from the sample. This can include mass chromatography spectrometry (GC / MS), GC / GC / MS, liquid chromatography. Inorganic analysis of samples can also be performed. This may include but is not restricted to inductively coupled plasma mass spectrometry (ICP-MS) and ICP-optical emission spectroscopy. Chemical gas analysis can also be performed and may include isotope - mass spectrometry and GC ratio. Measurement of the abundance of each aggregated isotope or isotope can be conducted using multiple techniques, such as mass spectroscopy and / or laser-based spectroscopy.
[0053] Then, in block 114, the noble gas and / or aggregated isotope compositions can be interpreted. Interpretation may include characterizing noble gas elements and isotope signatures, and aggregate isotope signatures, which can be created on a sample fingerprint. The compositions obtained by analysis of noble gas and / or aggregated isotope can be interpreted in the context of the region of individual interest, such as a reservoir or a compartment. Noble gas signatures in the different regions of interest vary due to differences in the reservoir mineralogy (which controls concentrations of radiogenic noble gas), fluid history (eg, loss of noble gases due to degassing of oils, dissolution to formation of waters that subsequently migrate, etc.) and interactions between fluid phases within the reservoir. Similarly, aggregate isotope signatures may differ between reservoirs because of their sensitivity to the reservoir temperature and stable isotope signatures. Stable isotope signatures may not differ between regions of interest, such as compartments or reservoirs, however the aggregate isotope signature varies between regions of interest at different temperature regimes, but may not differ between compartments in the same reservoir.
[0054] In block 116, the geochemical signatures of aggregated isotope and noble gas can be integrated with data from other geochemical techniques. These geochemical techniques may include isotopic and traditional molecular techniques, which include, but are not restricted to, biomarker signatures, stable carbon and hydrogen isotopes, and non-hydrocarbon gas compositions (eg, H2S, N2, CO2) . These interpretations can also be further refined by integrating with other traditional geochemical data as listed above to identify common differences associated with additional parameters, such as source faces, thermal maturity, and thermogenic versus biogenic gas, origin of non-hydrocarbon gases, etc. Then, in block 118, a fingerprint region of interest can be determined by having multiple geochemical signatures. The fingerprint region of interest may include the combination of one or more analyzed data, which can be used as different plotters. The fingerprint is unique to individual regions of interest (eg, compartments, intervals or reservoirs of interest). Once the region of the fingerprints of interest is obtained, they can be used in a wide range of reservoir surveillance operations and to intensify depletion strategies.
[0055] After the region of fingerprints of interest has been determined, a hydrocarbon production stage, which includes blocks 120 to 124, is carried out. In block 120, hydrocarbons can be produced based on the digital printing region of interest. Hydrocarbons can be produced from a hydrocarbon reservoir or accumulation based on the depletion strategy. Production may include installing a production facility that is set up to monitor and produce hydrocarbons from production intervals that provide access to the reservoir located in the subsurface formation. The production facility may include one or more units to process and manage the flow of production fluids, such as hydrocarbons and / or water, from the formation. To access production intervals, the production facility can be connected to a tree and several control valves via umbilical control, production piping to pass fluids from the tree to the production facility, control piping for hydraulic devices or electrical, and a control cable for communication with other devices inside the well bore.
[0056] In block 122, reservoir surveillance can be performed on hydrocarbons based on the region of fingerprint of interest. That is, the fluids produced can be analyzed to determine geochemical signatures. These geochemical signatures can be determined in a manner similar to the techniques used in any of blocks 108 to 116. An example of reservoir surveillance is further described in Figure 2.
[0057] In block 124, the adjustments for production can be made based at least partially on the region of digital printing of interest. These adjustments may include performing one or more operational tasks to enhance hydrocarbon recovery. As an example, operational tasks may include reducing or stopping flow from one or more reservoirs.
[0058] Beneficially, the monitoring of noble gas and / or aggregated isotope signatures as part of the reservoir surveillance can provide an additional mechanism to proactively respond to changes with the production of the drilling well.
[0059] Reservoir surveillance can be performed in a variety of different techniques. As an example, Figure 2 is a flow chart 200 for using different reservoir surveillance techniques according to an exemplary embodiment of the present techniques. In this flowchart 200, the unique natural geochemical fingerprint or induced by hydrocarbon production for multiple regions of interest can be used to intensify reservoir surveillance operations. In particular, the fingerprint region of interest, which can be determined as noted above in block 118 of Fig. 1, can be used as part of reservoir surveillance operations. Using the fingerprint region of interest established in the reservoir profile, reservoir surveillance can predict potential challenges with fingerprint based well hole production for different regions of interest, which may include one or more compartments, intervals , or reservoirs of interest. In addition, reservoir surveillance can also be used to intensify production allocations.
[0060] In this flowchart 200, reservoir surveillance is performed using the fingerprint region of interest in block 202. Reservoir surveillance can be performed on the fluids produced (eg, oil, gas and water), which are analyzed to determine the geochemical signatures, which is noted above in relation to block 122 of Fig. 1. The performance of reservoir surveillance may include performing certain analyzes based on the aspect being monitored. That is, certain features (eg, geochemical signatures) can relate to the natural / geological derived compositional variability (eg, “interregional” aspects), which are discussed in blocks 204 to 208, while tracers can relate the compositional variability induced by hydrocarbon production (eg, “intra-regional” aspects), which are described in blocks 210 to 214.
[0061] One aspect of reservoir surveillance lies in the variability in geochemical fingerprints of different regions of interest (eg, compartments, intervals, reservoirs of interest), which can be referred to as interregional variability, which arises as a result of natural or geological processes, as noted in block 204. These components of the fingerprint may be static (eg, static reservoir of the fingerprint of interest) and may not change in the production timescale. Examples of reservoir surveillance that fall on these natural or static fingerprints include, but are not limited to, production allocation, as noted in block 206, and reservoir connectivity analysis, as noted in block 208.
[0062] Another aspect of reservoir surveillance relates to the dynamic variability of geochemical fingerprints (eg, dynamic region of the fingerprint of interest) within individual regions of interest (eg, compartment, range, or reservoir of interest), which can be referred to as intra-regional variability, which arises during hydrocarbon production, as described in block 210. The components of the fingerprint are sensitive to chemical and / or physical processes, such as phase separation and degassing that it occurs due to changes in physical conditions, such as pressure and temperature. Examples of reservoir surveillance that fall on these hydrocarbon production, dynamic fingerprints include, but are not limited to, predicting water through, as described in block 212, and earlier identification of the phase separation in the reservoir, as described in block 214.
[0063] As noted above, reservoir surveillance can use variability in geochemical fingerprints from different regions of interest, such as compartments, gaps, or reservoirs of interest, to intensify various interregional aspects, such as production allocation, reservoir connectivity and similar aspects and / or intraregional aspects, such as predicting water coming out and the earlier identification of phase separation in the reservoir. Changes in the region (s) of fingerprint of interest are used to carry out surveillance of interregional and intraregional reservoirs. This monitoring can measure changes in co-mixed fluids due to changes in the proportion of liquids, gases or water obtained from multiple compartments, intervals or reservoirs, which is purchased with previously obtained samples or determined geochemical fingerprints. Specifically, these fingerprints can take into account physical properties and geochemical signatures associated with each individual region. Physical characteristics and properties may include, but are not limited to, temperature and reservoir pressure. These measurements can be obtained from samples of pressure volume temperature (PVT) or similar.
[0064] As an example, Figure 3 is a flow chart 300 for applying the geochemical fingerprint for reservoir surveillance according to an exemplary modality of the present techniques. In this flowchart 300, changes in the geochemical fingerprint are used to perform interregional reservoir surveillance. This method can include a development stage, which includes blocks 302 and 304, and a monitoring stage, which includes blocks 306 to 314.
[0065] The development stage, which includes blocks 302 and 304, can be used to develop the region of digital printing of interest and depletion strategy that counts for multiple geochemical signatures. In block 302, physical properties and geochemical signatures can be combined to develop a unique geochemical fingerprint for the region of interest (eg, an individual compartment, range, or reservoir of interest). The individual fingerprint can be created for each of the different regions of interest (eg, compartment, range or reservoir). Then, in block 304, a desired composition and quality of fluids produced (eg, gas, oil and / or water) is determined. The desired composition and quality of the fluids produced can be formulated and used as part of the depletion strategy. The depletion strategy is developed to provide a desired composition that takes into account the desired hydrocarbon production (eg, quantity and quality), limited production of less desired components (eg, H2S), as well as infrastructure and facility tolerances. This depletion strategy can be accompanied by the identification of the proportions of the different compartments, intervals, and / or reservoirs that contribute to the co-mixed produced fluid. Also, production of the individual compartments, intervals or reservoirs may be necessary to be adjusted to fall within the desired compositional ranges during the production time interval. The desired composition and quality may include oil production with a target API gravity, H2S concentration, asphaltene and wax contents, acidity, gas-oil ratio, water-gas ratio, and the like.
[0066] After the development stage, a monitoring stage is performed, which includes blocks 306 to 314. In block 306, a production allocation and depletion strategy to produce the desired composition, flow rate, and physical properties. The composition, flow rate and physical properties can include condensate-gas ratio, dryness of the gas, production pressures, and water fields. In block 307, physical properties including temperature and pressure can be monitored using hole sensors below or on the surface during production. Also in block 307, the geochemistry of the fluid produced (oil, gas and / or water) is obtained from one or more subsurface regions (eg, one or more compartments, intervals, and / or reservoirs) and can be monitored . The fluids produced can be obtained either inside the well bore (eg Dynamic Modular Test (MDT), or on the surface (eg in one or more separators that produce water, oil or gas). , these samples can be obtained inside the well bore and associated with the individual compartment and / or reservoir, while other modalities may include monitoring mixtures of fluids produced from different subsurface regions. can be performed at various times over the production time interval to provide data on how the subsurface regions of interest are producing in relation to the expected contributions. So, in block 308, a determination is made whether the geochemical fingerprint or physical properties The determination may include comparing the geochemical fingerprint of the fluids produced with the original geochemical fingerprint l for the fluids produced, which are part of the region of interest. The comparison may include calculating a change in one or more of the geochemical signatures in the fluid produced associated with one or more different individual compartments, range and / or reservoir. If no change in signatures has occurred, the process can continue to monitor physical properties and geochemical fingerprints of the fluids produced, as described in block 307.
[0067] If changes in composition have occurred, the source of the change can be identified, as noted in block 310. For example, when multiple regions of interest contribute to a fluid produced (co-mixed fluid), monitoring of the geochemical fingerprint of the produced fluid may allow the identification of an increase in the concentration of noble radiogenic gases that result from an increased contribution of a region of interest to the produced fluid. Then, in block 312, changes in geochemical signatures and fluid properties due to changes in the proportions contributed from each subsurface region can be modeled. Modeling may include incorporation of one or more models of certain geochemical signatures or fluid properties (eg, changes in noble gas signature pressure and Condensed Gas Ratio (CGR)). For example, an understanding of the signature of the noble static gas from different regions of interest can be used to quantify the relative contributions of different regions when deviations from the anticipated signature are identified in block 308. This information can be integrated with knowledge of the pressure regime of these different regions of interest. Sampling these fluids produced at various intervals over the production time interval can then be used with the model to provide some additional information and data as well as the subsurface regions they are producing in relation to the expected contributions. A model can then be used to determine the expected fingerprint of a gas produced when changes are needed. In block 314, depletion strategies can be adjusted to maintain desired composition, quality, and flow rates. This adjustment for the depletion strategy can be based on the determination of the models developed in block 312. That is, production from individual compartments, intervals, or reservoirs can be adjusted to stay within the desired geochemical fingerprint or physical property ranges. of the depletion strategy.
[0068] Beneficially, while traditional reservoir surveillance techniques may not be able to distinguish different subsurface regions, the present techniques provide additional improvements to reservoir surveillance techniques that provide improvements to subsurface regions. That is, other reservoir surveillance techniques may fall in a few strokes (eg, biomarkers or gas geochemistry), as well as the stable isotope (13C, D) and organic hydrocarbon signatures associated with maturity, source faces, and reservoir change processes may not be unique to different regions within an area of interest. As a result, these techniques are not always able to distinguish components derived from the same source and which are of similar maturity and quality. In contrast, the isotopic signature of noble gases and the aggregate isotope signature of hydrocarbons are particularly sensitive to small changes in temperature and composition of the reservoir rocks, and provide unique geochemical traits (eg, components within the reservoir profile or geochemical fingerprint). The techniques present here provide distinguishable tracers to distinguish between different subsurface regions. In addition, noble gases and light hydrocarbon aggregate isotope species are similar to undergo rapid equilibrium within a single region and then have a homogeneous signature across the region. For example, inside stacked and compartmentalized hydrocarbon reservoirs, where each compartment has a different average temperature, the aggregated isotope signature of the hydrocarbons is enriched in relation to a random distribution. This enrichment is simply sensitive to the average temperature of the reservoir, and as such reflects the storage temperature of the given reservoir.
[0069] In contrast, the signature of the noble gas of any given region of interest within a reservoir rock only reflects the grain size, porosity and permeability, composition (eg, concentration of U, Th and K), and contact with formation water. This inherited signature can then be influenced by the transport processes (eg dispersed versus diffuse) that operate in the noble gases that reflect the compartment's ability to retain its hydrocarbons. Given the different ages and heterogeneous nature of sediments within the reservoir rocks, the signatures of noble gas and aggregated isotope of hydrocarbons must be unique for individual compartments. Characterization of unique signatures provides a mechanism to identify contributions from different reservoirs to a fluid produced to be quantified in a co-mixed well.
[0070] The geochemical fingerprints described in the present techniques provide additional tools to resolve differences between the subsurface regions that are not possible given these traditional methods. That is, the understandable set of new tracers available is developed through the integration of traditional geochemical methods such as stable isotope geochemistry and biomarkers with aggregated isotope and noble gas signatures in the context of physical properties. This understandable geochemical fingerprint of a region of interest, coupled with statistical methods or modeling approaches, provides more opportunities to identify sudden changes in the co-mixed produced fluids, associated with differential contributions from specific compartments, intervals, or reservoirs, before changes in the production chain. Consequently, depletion and reservoir management strategies can then be adjusted to maintain desired compositions, quality and flow rates.
[0071] As another example, Figure 4 is an alternative flowchart 400 for applying the geochemical fingerprint to conduct reservoir surveillance according to an exemplary embodiment of the present techniques. In this flowchart 400, the introduction of noble gases and aggregated isotopes, as described above, provides additional tracers to conduct analysis of dynamic reservoir connectivity through the temporal monitoring of the produced geochemical fingerprints. These changes in the geochemical fingerprint are used to carry out intra-regional reservoir surveillance. That is, the workflow provides a mechanism for proactive intra-regional reservoir surveillance. This reservoir surveillance monitors changes in the geochemical fingerprint of individual regions of interest to identify responses in the geochemical fingerprint that arise from the earlier deviation of the chemical or physical processes within the reservoir. The method can include a development stage, which includes blocks 402 and 404, and a monitoring stage, which includes blocks 406 to 414.
[0072] The development stage, which includes blocks 402 and 404, can be used to develop the region of digital printing of interest and depletion strategy that takes into account the geochemical digital printing. In block 402, physical properties and geochemical signatures can be combined to develop a unique geochemical fingerprint for an individual region of interest (eg, compartment, range, or reservoir). The individual fingerprint can be created for each of the different regions of interest. The geochemical fingerprint of the individual region (eg, compartment, range, or reservoir) is combined or integrated with physical observations that include, but are not limited to, reservoir temperature and pressure. These measurements can be obtained from PVT samples or the like. Then, in block 404, qualitative guidelines are developed to relate changes in the geochemical signatures of produced fluids (eg gas) to identify likely physical or chemical processes. Qualitative guidelines can provide one or more guidelines for different event scenarios. This aspect may include the development of a series of qualitative guidelines that link chemical or physical processes, such as water withdrawal, phase separation, or acid-rock interaction for changes in the fingerprint of the fluid produced. As an example, reservoir surveillance can monitor the borehole for changes in noble gas subscriptions. The elemental fractionation patterns in the noble gas signatures of the produced gases can be monitored and used to indicate certain identified processes, such as water withdrawal or phase separation. For example, the noble gas signature of the hydrocarbons produced preserves a signature that can be used to identify interaction of the hydrocarbon phase with formation waters that are rich in atmospheric noble gases. As a starting point, the concentration of noble gases in a natural gas is a function of three variables: (i) the initial concentration and isotopic signature of the noble gases in the aqueous phase, (ii) solubility of the noble gases in water and oil (solubility of noble gases in oil is controlled by oil quality), and (iii) the ratio of oil / water, gas / water or gas / oil / water volumes. Given the relationship between the three variables, any change in the oil / water, gas / water or gas / oil / water ratio triggers a change in the signature of the noble gas in the gas phase.
[0073] As another example, phase separation can occur during production. The production of a gaseous phase may arise during a pressure drop in an oily phase or loss of liquid may occur during a pressure decrease within a gaseous phase. Noble gases fractionate between the gas and liquid phases based on their relative solubilities. Light noble gases are less soluble than heavy noble gases, which results in light noble gases becoming dominant in the gas phase (eg, He and Ne) and heavy noble gases (eg, Kr and Xe) dominating the phase of liquid hydrocarbon (oil or condensate). This results in a fractionation in the elementary patterns of a noble gas signature of the liquid hydrocarbon and the gas phase.
[0074] After the development stage, a monitoring stage is carried out, which includes blocks 406 to 414. In block 406, physical properties and geochemical fingerprints of fluids produced (eg, oil, gas or water) obtained from from the region (eg compartment, range or reservoir) can be monitored. The fluids produced can be obtained either inside the well bore (eg Dynamic Modular Test (MDT), or on the surface (eg in one or more separators that produce water, oil or gas). , these samples can be obtained inside the well bore and associated with the individual compartment, gap and / or reservoir, while other modalities may include monitoring mixtures of fluids produced from different subsurface regions, so in block 408, a determination whether a Deviations have occurred.Deviations in one or more physical properties or geochemical signatures of the original geochemical fingerprint can be identified by comparing the monitored data with the geochemical fingerprint developed for the static fingerprint region of interest. one or more of the components (eg noble gases, aggregated isotopes, stable isotopes) in the fluid produced associated with one or more compartments different individual, interval and / or reservoir. For example, the signature of noble gas in the geochemical fingerprint may indicate an increase in the contribution of atmospheric noble gases, derived from water within the region of interest. This increase in atmospheric noble gases derived from water can result in the degassing of an aqueous phase due to an increase in the volume of water as concentrations of noble gas are dependent on the ratio of the volume of hydrocarbons to water. This indicates the potential for water withdrawal from the wellhead. If no deviation occurs, the process can continue to monitor physical properties and fingerprints of produced fluids, as described in block 406.
[0075] If deviations occur, the chemical and physical processes associated with changes in chemical fingerprint or physical properties can be identified, as noted in block 410. As an example, the qualitative guideline developed in block 404 can be used to identify which physical or chemical processes may be responsible for the identified change. Then, in block 402, one or more quantitative models relating changes in geochemical fingerprint to physical processes can be developed. Quantitative models can include models of certain signatures (eg, noble gas signatures, stable isotopes, mass composition). The understandable quantitative model can be developed to model the dynamic interactions that link changes in geochemistry and physics and chemical processes (eg pressure changes condensate / gas impact ratios). For example, when comparing the deviation from the fingerprint region of interest identified in block 408 with the qualitative model developed in block 404 identifies a particular process occurring within the reservoir, a model can be developed to quantitatively assess the impact (for example, example, in terms of increasing / decreasing the volume of a particular phase) within the reservoir. In block 414, the management of physical properties can be adjusted to mitigate the impact of the identified processes. This adjustment can be based on quantitative models and / or the chemical or physical processes identified.
[0076] As an example, noble gases in the aqueous phase are dominated by atmospheric noble gases. When pressure is taken down in a production reservoir, the volume of water inside the reservoir can increase to maintain pressure when, for example, there is an active water drive. The speed or transport of gas within the reservoir exceeds the speed that water can migrate within the reservoir. With this, produced gases can be removed from sections far from the reservoir that were initially in contact with water at a rate that exceeds the rate at which formation waters can migrate within the subsurface. A progressively increasing signature of noble atmospheric derived gases and isotope signatures of a "water-like" mass suggest an increased volume of water within the reservoir.
[0077] In this modality, a formation water scenario is identified according to the process responsible for deviations from the region of fingerprint of interest through monitoring in block 406 and comparison with the qualitative models developed in block 404. A model is then developed to quantify the increase in the volume of water inside the reservoir that has already been drilled in the well bore. This drilling of water in the well bore can impact the production of hydrocarbons. A quantitative model is developed in block 412 that calculates the volume of water present in the reservoir from the concentration of atmospheric noble gases in the gaseous or aqueous phase measured in block 406. This model can also provide a range of volumes for a range of concentrations of atmospheric noble gas in order to tend that an increase or decrease in the volume of water can be identified. This signature can be used to predict a pending increase in the formation water cut to produce fluids in advance of the aqueous phase migrating to the well. This information could be used to take preventive action by changing flow conditions (eg, repressing production pressure) to prevent or limit the volume of water being produced from the formation. Consequently, the observation of an increased contribution of water derived from noble gases in a produced gas provides early warning of drilling water hanging in front of the aqueous phase reaching the well, which can be identified by water-soluble tracers.
[0078] As another example, if liquid spillage is identified as the physical process producing changes in the geochemical fingerprint on block 410, this method can provide early detection of small volumes of condensate produced within the reservoir. A quantitative model developed in block 412 can provide the volume of condensate produced in the reservoir to be determined by measuring the noble gas concentrations of the gas produced. The flow rate of the well can then be reduced to maintain pressure inside the reservoir and prevent additional liquid from escaping from inside the reservoir. The composition of the gas produced can then continue to be monitored to identify any further changes in the geochemical fingerprint.
[0079] As yet another example, when a deviation in the fingerprint is identified in block 408 from that of the geochemical fingerprint of the region of interest developed in block 402, a process such as a phase transformation is identified in block 410 by comparison with the qualitative model in block 404. This change can be recorded by a change in the signature of the noble gas of the hydrocarbon produced. When this phase transformation is related to the formation of a gas cap within a region of interest that can be triggered by a decrease in pressure within an oil reservoir, a model is developed in block 412 that quantifies the volume of the gas formed . The noble gas signature of the oil produced may display a fractional signature. In particular, the noble gas signature in the oil phase can be depleted in the light noble gases and relatively enriched in the heavier noble gases as a result of the solubility differences between the different noble gases. The model in block 412 uses the noble gas signature fractionation extension to determine the volume of gas produced. The model also provides forecasts to be made of volume increase or decrease with time during production considering potential changes in the noble gas signature of the produced hydrocarbons. This reservoir surveillance method can identify the formation of a gas cap before the production of gas in the well and provides a method for predicting changes in the gas / oil ratio that can be produced in the region of interest.
[0080] As yet another application, this reservoir surveillance method can be used to quantify hydrocarbons remaining in place at different stages of production in a region of interest. When a deviation in the fingerprint is identified in block 408 in which the geochemical fingerprint of the region of interest developed in block 402, a process such as a decrease in a volume of hydrocarbon within a region of interest (gas, oil or gas and oil) is identified in block 410 by comparison with the qualitative model in block 404. This change can be recorded by a change in the noble gas signature of the fluids produced. When this phase transformation is related to a decrease in volume in one or more of oil and gas and / or a change in the volume of water within a region of interest resulting from production, a model is developed in block 412 that quantifies these changes volumetric. The noble gas signature of the oil produced and / or gas and / or water may display a fractional signature. In particular, when the volume of oil or gas is decreased in an oil-water or gas-water system, or both gas and oil are exhausted at the same rate (eg maintaining the gas-oil ratio), the concentration of noble gases atmospheric increases in each of the hydrocarbon phases as a result of the decrease in the hydrocarbon / water volume ratio. When the oil-gas ratio changes during production in a gas-oil-water system, the noble gas signature for each hydrocarbon phase exhibits a fractionated noble gas signature consistent with the time-modified volume ratio. For example, as gas is exhausted within a region of interest, and the gas / oil ratio decreases, the fractionation pattern in the gas phase may address the oil phase as a result of differences in solubility between different noble gases. The model in block 412 uses the noble gas signature fractionation extension to determine the remaining volume of gas and oil within the region of interest. The model may also allow forecasts to be made of decreasing the volume of hydrocarbons with time during production considering the potential changes in the noble gas signature of the produced hydrocarbons. This can also be reflected in the noble gas signature of the water as discussed in the drilling water example. This reservoir surveillance method however allows for a quantitative estimate of the remaining hydrocarbon phase to be made and optimized depletion strategies for these volumetric changes during production in the region of interest.
[0081] As yet another application, this reservoir surveillance method can be used to evaluate and quantify the efficiency of the injection of surface or produced water while maintaining reservoir pressure and the production of hydrocarbons from within the region of interest. The geochemical fingerprint for the region of interest developed in block 402 is established before the injection of large volumes of fluids. The primary production of the reservoir can result in a decrease in the reservoir pressure and then the hydrocarbon rate in the region of interest. In such cases, produced water or surface water can be injected into the region of interest to develop and maintain sufficient pressure for the continued production of hydrocarbons in that region. The injected fluids have a different signature than that of typical subsurface waters. In particular, this injected fluid can be depleted in noble radiogenic gases compared to subsurface waters. When injected this fluid can mix with subsurface fluids and contact hydrocarbons. This contact results in additional partitioning of the water's noble gases to hydrocarbon phases. As the volume of fluid injected increases on the subsurface, the concentration of noble radiogenic gas in the water mixed in the region of interest decreases. This results in a subsequent decrease in the noble radiogenic gases in the hydrocarbon phase in contact with this fluid. A decrease in the signature of noble radiogenic gas monitored in block 406 can be identified in block 408. By comparing the fingerprint produced with qualitative in block 404, water injection is identified as the process responsible for the change in block 410. A model developed in block 412 can quantify the volume of injected water that has contributed to this change. Comparison of the quantified volume with the total volume of the injected fluid allows an efficiency of the water injection to be determined. The continuous injection of water to maintain pressure results in a decrease in the gas-water and / or oil-water ratios, resulting in hydrocarbon phases that most closely meet the noble gas signatures of the injected water (increased atmospheric contribution) with a decrease in noble radiogenic gas because of subsequent dilution by the injected water.
[0082] In one or more modalities, the method for performing integrated geochemistry and physical techniques for reservoir surveillance may include geochemical variability, such as interregional or intra-regional, identified through the integration of aggregate and isotope geochemistry characterization. / or noble gas geochemistry with other geochemical and physical properties. The method may include obtaining sensor data by monitoring the fluids produced (eg, time) and monitoring physical changes within subsurface regions. Reservoir surveillance can be used for intraregional applications, which may include, but are not limited to, identification of drilling water prior to the production of water above a limit in the well and / or phase transformation (e.g. spill of liquid). Reservoir surveillance can be used for interregional applications by applying unique geological (natural) / static compositions of individual reservoir / compartments to identify deviations from desired mixing ratios over time, which may include, but are not limited to, production allocation and reservoir connectivity.
[0083] Additionally, in one or more modalities, the techniques of interregional and intraregional variability can be combined in a larger composite workflow to identify both the variability in the mixing ratios of the static compositions and changes in the systems of mixed reservoir and intra-reservoir production induced changes to optimize long-term productivity and field productivity. That is, a depletion strategy can be developed based on the unique geological / natural geochemical fingerprints of the regions of interest to produce hydrocarbons of a specific quality (eg, dry gas) and composition (eg, compensated gas). Then, reservoir surveillance can be conducted to monitor composition and / or quality and verify operation of the depletion strategy and adjust production allocation to provide consistent compositions to facilitate during time lapse or four-dimensional reservoir surveillance.
[0084] In one or more modalities, the samples (eg, produced fluids) can be analyzed for noble gas signatures and / or aggregated isotope signatures. This measurement may include the analysis of noble gas signatures (He, Ne, Ar, Kr and Xe) and the isotope or aggregate isotope signature of both non-hydrocarbon and hydrocarbon molecules (in gases, water, or oils). The sample of interest may comprise water, oil, natural gas, sediment or other types of rock, or fluids present in sediment, rocks, water or air. Abundance measurements of each noble gas isotope can be performed following standard extraction techniques using mass spectrometry. Measurement of the abundance of each aggregated isotope or isotope can be conducted using multiple techniques, such as mass spectrometry and / or laser-based spectrometry. Molecular and isotopic signatures of non-hydrocarbon gases (eg, H2S, CO2, N2) and hydrocarbons are typically measured in the fluids produced. Standard molecular analyzes are conducted to characterize the organic signature of hydrocarbons extracted from the sample. This can include gas chromatography - mass spectrometry (GC / MS), GC / GC / MS, liquid chromatography. Inorganic analysis of the samples can also be performed. This may include but is not restricted to inductively coupled plasma mass spectrometry (ICP-MS) and ICP-optical emission spectroscopy. Chemical gas analysis can also be conducted and may include isotope - mass spectrometry and GC ratios.
[0085] The interpretation of advanced and isotopic molecular signatures, including noble gas signatures and isotope signatures of hydrocarbon and non-hydrocarbon molecules, can also be performed and incorporated into a geochemical fingerprint region of interest. With one example, noble gases can be used to determine hydrocarbon type and volume as described in U.S. Patent No. 61/616813. As natural gases and oils are initially devoid of noble gases, the addition of these through interaction with water formation provides information about the samples. The impact of this interaction on isotopic ratios and absolute concentrations of noble gases present in the hydrocarbon phase is a function of three variables, the solubility of noble gases, the initial concentration in the aqueous phase, and the volume ratio of the hydrocarbon to water. The initial concentration of noble gases in the aqueous phase before interaction with any hydrocarbon can be precisely measured or estimated. Noble gases dissolve in water during recharge of meteoric waters or at the air / water limit for sea water. This initial signature is however dominated by noble atmospheric gases, namely 20Ne, 36Ar, 84Kr and 132Xe. The amount of noble gases that dissolve in the aqueous phase obeys Henry's Law, which says that the amount of noble gases dissolved in water is proportional to the partial pressure of noble gases in the atmosphere (which varies as a function of altitude for recharging meteoric water ). Henry's constant is directly related to the salinity of the aqueous phase and to the ambient temperature during the transfer of the noble gases to the water. Formation waters recharged from meteoric waters at the air / soil interface may have an additional component of noble atmospheric derived gases than is expected purely from equilibrium, "excess air". These influences can be subject to adjustments (eg, correction schemes, such as those noted in Aeschbach-Hertig et al., 2000, for example). See, e.g., Aeschbach-Hertig, W., Peeters, F., Beyerle, U., Kipfer, R. Palaeotemperature reconstruction from noble gases in ground water taking into account equilibrium with entrapped air. Nature, 405, 1040-1044, 2000. The resulting noble gas signature is then positioned between saturated air-water (ASW), saturated air-sea water (ASSW) and saturated air-brine (ABS) for any given temperature. Noble radiogenic gases are then introduced following recharge through radioactive decay of minerals within the subsurface. The concentration of noble radiogenic gases typically increases with an increase in the residence time of formation water (or age). This signature of noble gas evolving in the aqueous phase is modified as a result of mixing and interacting with other fluids.
[0086] The solubilities of noble gases in water have been determined for a different temperature range, as is known in the art (eg, Crovetto et al., 1982; Smith, 1985). See, e.g., Smith, S.P. Noble gas solubilities in water at high temperature. EOS Transactions of the American Geophysical Union, 66, 397, 1985 and Crovetto, R., Fernandez-Prini, R., Japas, ML Solubilities of inert gases and methane in H2O and D2O in the temperature range of 300 to 600K, Journal of Chemical Physics 76 (2), 1077-1086, 1982. Similarly, the measured solubility of noble gases in oil increases with decreasing oil density (Kharaka and Specht, 1988). See, e.g., Kharaka, Y.K. and Specht, D.K. The solubility of noble gases in crude oil at 25-100oC. Applied Geochemistry, 3, 137-144, 1988. The exchange of noble atmospheric gases between water formation and both oily and / or gaseous hydrocarbon phases can occur through several processes, and the extent of fractionation induced by each of these processes gives different signatures at different stages. These processes can be modeled and can comprise equilibrium solubility, Rayleigh-style fractionation and gas removal. The exchange of noble gases between oil and water can result in the oily phase developing an enrichment in heavy noble gases (Kr and Xe), and an associated depletion in light noble gases (He and Ne) in relation to the aqueous phase. This is because of the greater solubility of noble gases heavier in oil than in water. In contrast, the interaction of a gaseous phase with water can result in the gaseous phase becoming relatively enriched in the lighter noble gases and depleted in the heavy noble gases in relation to an aqueous phase. The magnitude of this fractionation can change depending on the exchange process involved and the density of the oil phase.
[0087] The noble gases provide a conservative plotter of the type of hydrocarbon present within the subsurface (oil vs gas). Finally, given the two of the three variables that control the exchange of noble gases between water and hydrocarbons are known or can be modeled, the hydrocarbon / water volume ratio within a subsurface hydrocarbon accumulation can be determined. From this it is possible to quantitatively predict the volume of hydrocarbon present within a subsurface accumulation and the volume of water, which can be compared with other data in the model.
[0088] In addition to the use of noble gases to determine hydrocarbon accumulation volume, and hydrocarbon type, the aggregated isotope geochemistry can be used to determine the depth of a production region of interest. As an example, U.S. Patent No. 61/558; 822 describes a process for determining the aggregated isotope signature of any molecule. The signature of the aggregated isotope of any molecule is a function of (i) temperature - randomly populated processes randomly independent of temperature (eg, stochastic distribution) and (ii) isotopic exchange of thermal equilibrium. The latter process is controlled or dependent on the surrounding temperature. The stochastic distribution of any isotope can be determined from the mass isotope signatures of the species in which it is derived. For example, determining the stochastic distribution of isotopes pro methane requires knowledge of methane 13C and D signatures.
[0089] The expected increased abundance, or enrichment, of any given isotope or aggregated isotope can be modeled or empirically determined for any given temperature. By measuring the signatures of aggregate and isotope of a given molecule, and through knowledge of the stochastic distribution, the enrichment of the measured concentrations in relation to the stochastic distribution can be used to determine the temperature on the subsurface in which this molecule is derived.
[0090] Hydrocarbons that derive from a region of interest can retain an aggregated isotope signature that most reflects the temperature at which the hydrocarbons were stored on the subsurface. This non-kinetic control in isotopic exchange reactions in hydrocarbon isotopes that originate from a subsurface accumulation arises as a result of the inherently long residence times of hydrocarbons in the subsurface. Figure 5 is a block diagram of a computer system 500 that can be used to perform any of the methods disclosed here. A central processing unit (CPU) 502 is coupled to the system bus 504. The CPU (502 can be any general purpose CPU, although other types of CPU architecture 502 (or other exemplary system components 500) can be used while CPU 502 (and other system components 300) support operations created as described here. CPU 502 can execute the various logical instructions according to disclosed aspects and methodologies. For example, CPU 502 can execute machine-level instructions for perform processing according to aspects and methodologies disclosed here.
[0091] Computer system 500 may also include computer components such as random access memory (RAM) 506, which may be SRAM, DRAM, SDRAM, or the like. Computer system 500 may also include read-only memory (ROM) 508, which may be PROM, EPROM, EEPROM, or the like. RAM 506 and ROM 508 maintain user and system data and programs, as is known in the art. The computer system 500 may also include an input / output (I / O) adapter 510, a communication adapter 522, a user interface adapter 524, and a display adapter 518. The I / O adapter 510, the user interface adapter 524, and / or communication adapter 522 may, in certain aspects and techniques, enable a user to interact with computer system 500 to input information.
[0092] The I / O adapter 510 preferably connects a storage device (s) 512, such as one or more hard drives, compact disk drive (CD), flexible disk drive, tape drive, etc. for computer system 500. The storage device (s) can be used when RAM 506 is insufficient for the memory requirements associated with storage data for operations of modalities of the current techniques. The data storage of the computer system 500 can be used to store information and / or other data used or generated as disclosed herein. Communication adapter 522 can couple computer system 500 to a network (not shown), which can allow information to be input to and / or output from system 300 over a network (for example, a wide area network, a network local area, a wireless network, any combination of the aforementioned). User interface adapter 524 couples user input devices, such as the keyboard 528, a pointing device 526, and the like, to the computer system 500. The display adapter 518 is powered by CPU 502 to control, via a drive display 516, the display on a display device 520. Information and / or representations of one or more two-dimensional (2D) screens and one or more three-dimensional (3D) windows can be displayed, in accordance with disclosed aspects and methodologies.
[0093] The architecture of the 500 system can be varied as desired. For example, any suitable processor-based device can be used, including without limitation personal computers, portable computers, computer workstations, and multiprocessor servers. In addition, modalities can be implemented in application-specific integrated circuits (ASICs) or very large-scale integrated circuits (VLSI). In fact, people of ordinary skill in the art can use any number of suitable structures capable of performing logical operations according to the modalities.
[0094] In one or more modalities, the method of any of Figures 1 to 4 can be implemented in machine-readable logic, set of instructions or code that, when executed, perform a method to manage hydrocarbon production to perform oil surveillance. reservoir through the use of quantitative models comprised of aggregate isotope, noble gas data, or combination of aggregate isotope and noble gas data. This executable code may also include quantitative models comprised of traditional geochemical signatures and physical properties observed within the region of interest. The quantitative models developed in block 412 are developed and the code can be used or executed with a computer system, such as computer system 500.
[0095] As an example, current techniques may include a computer system having a process or and memory, where a set of instructions is stored in memory and accessible by the process. The instruction set is configured to use integrated geochemical and physical techniques for reservoir surveillance.
[0096] In one or more modalities, the method may include storing and using intra-regional geochemical variability (eg, identified through integration of aggregate isotope geochemistry characterization, noble gas geochemistry with conventional geochemistry and physical properties) arising from physical changes induced by (temporal) / dynamic production within the region of interest, which can be used to identify drilling water prior to the production of water in the well, and phase transformation (eg liquid spillage).
[0097] Interregional geochemical variability (identified through geochemical integration of aggregated isotopes, geochemical characterization of noble gas with geochemical and physical properties) applying unique static / geological (natural) compositions of individual regions to identify deviations from the intended mixing ratios over time, which may include allocation of production and reservoir connectivity. In addition, intraregional variability techniques can be combined into a larger composite workflow to identify both variability in mixing ratios from static compositions and changes in the mixed reservoir system from changes induced by intra-reservoir production to ensure productivity and optimized long-term field productivity.
[0098] Illustrative, non-exclusive examples of the methods and products according to the present disclosure are presented in the following un enumerated paragraphs. It is within the scope of this disclosure that an individual step in a method recited here, including in the following paragraphs listed, may additionally or alternatively be referred to as a "step to" perform the recited action. 1. A method for producing hydrocarbons, comprising: obtaining a sample from one or more subsurface regions in an accumulation of subsurface hydrocarbon; interpret the sample to determine one or more noble gas signatures and aggregated isotope signatures for the samples obtained; generate a fingerprint region of interest having one or more noble gas signatures and an added isotope signatures for the samples obtained; producing fluids from one or more subsurface regions, where the fluids produced comprise hydrocarbons; and to carry out reservoir surveillance in the fluids produced from one or more subsurface regions. 2. The method of paragraph 1, in which reservoir monitoring of produced fluids still comprises: obtaining a first sample from the produced fluids; determining a first fingerprint of the sample for the first sample obtained, wherein the first fingerprint of the sample comprises one or more noble gas signatures and an aggregated isotope signature; compare the first sample fingerprint for the region of interest; and determining whether the first sample fingerprint has changed based on comparing the region of the first fingerprint with the region of the fingerprint of interest. 3. The Method of paragraph 1, in which reservoir monitoring of produced fluids still comprises: obtaining a second sample of the produced fluids, in which the second sample is obtained a period of time after obtaining the first sample; determining a second fingerprint of the sample for the second sample obtained, wherein the second fingerprint of the sample comprises one or more noble gas signatures and an aggregated isotope signature; comparing the second sample fingerprint to the fingerprint region of interest; and determining whether a second sample fingerprint has changed based on comparing the second sample fingerprint with the region of fingerprint of interest. 4. The method in paragraph 2, where the comparison is between the first sample fingerprint and a static fingerprint for the regions of interest to determine inter-region changes. 5. The method in paragraph 2, where the comparison is between the first sample fingerprint and a dynamic fingerprint for the regions of interest to determine intra-regional changes. 6. The method of paragraph 1, in which it still comprises developing a depletion strategy based on the region of digital printing of interest to produce hydrocarbons of a specific quality and composition. 7. The method of any of paragraphs 1 to 6, in which determining the aggregate isotope signature comprises: measuring or modeling an initial concentration of noble atmospheric gases present in the formation water in contact with the subsurface hydrocarbon accumulation; modify the initial measured / modeled concentration taking into account the expansion of noble radiogenic gases during the residence time of the formation water; measure concentrations and isotopic ratios of atmospheric noble gases and noble radiogenic gases present in the sample; compare the measured concentrations and isotopic ratios of atmospheric noble gases and noble radiogenic gases present in the sample with the measured / modeled concentrations of formation water for a plurality of exchange processes; determine a source of hydrocarbons present in the sample; compare a signature of atmospheric noble gas measured in the hydrocarbon phase with the modified measured / modeled concentration of atmospheric noble gases in the formation water for the plurality of exchange processes; and determine at least one of a presence of a subsurface hydrocarbon build-up, a type of hydrocarbons in the subsurface build-up and a hydrocarbon / water volume ratio in the subsurface build-up before escaping to the surface, and a build-up volume of subsurface. 8. The method of paragraph 7, in which the plurality of exchange processes include at least one of equilibrium solubility laws calibrated for the conditions reflected in subsurface accumulation, Rayleigh-style fractionation to represent degassing of an oil phase, and withdrawal of gas to represent enrichment in a gas phase. 8. The method of paragraph 8, where conditions include at least one of reservoir temperature, pressure, formation water salinity and oil density. 9. The method of paragraph 7, in which the noble gases include at least one of helium (He), Neonium (Ne), Argon (Ar), Krypton (Kr), and Xenon (Xe). 10. The method of paragraph 7, where isotopic ratios include a Kr to Ar ratio, which can include Kr to Ar ratio as an 84Kr / 36Ar ratio. 11. The method of paragraph 7, in which the isotopic ratios include an Xe to Ar ratio, which may include the Xe to Ar ratio as a 132Xe / 36Ar ratio. 12. The method of paragraph 7, in which the isotopic ratios include a ratio of Ne to Ar, which may include the ratio of krypton to argon is a ratio of 20Ne / 36Ar. 13. The method of paragraph 7, further comprising producing hydrocarbons based on at least one of the determined types, ratio in volume of hydrocarbon / water, and the volume of subsurface accumulation. 14. The method of paragraph 7, in which the initial concentration is modeled to reflect fluid salinity and exchange temperature during recharge / exchange with atmosphere. 15. The method of paragraph 7, in which the sample comprises one of water, oil, natural gas, sediments, rock, fluids present in the sediments, fluids from rock pores, and fluids trapped in the fluid inclusions. 16. The method of paragraph 7, further comprising characterizing the risk of non-hydrocarbon gas associated with the accumulation of subsurface hydrocarbon. 17. The method of any of paragraphs 1 to 6, in which determining the signature of the noble gas comprises analyzing the sample to determine a geochemical signature of the sample; determine an initial concentration of noble atmospheric gases present in the formation water in contact with the subsurface hydrocarbon accumulation; model expansion of noble radiogenic gases to modify the initial concentration for a given residence time of formation water; determine a residence time of the formation water; determine an extent of interaction with a hydrocarbon phase; determine the origin of the sample; determine at least one of a kind, and ratio in volume of hydrocarbon / water when the sample origin is a hydrocarbon accumulation; and the hydrocarbon / water volume ratio, determine the volume of the hydrocarbon accumulation. 18. The method of any one of paragraphs 1 to 6, in which determining the noble gas signature comprises: determining an initial concentration of atmospheric noble gases present throughout a hydrocarbon species; model a range of expected concentrations of noble radiogenic and atmospheric gases present in the sample for a range of residence times and for various extensions of interaction between formation water and a hydrocarbon phase; measure concentrations and isotopic ratios of noble gases present in the sample; compare the measured noble gas concentrations with the modeled range of expected concentrations of atmospheric and radiogenic noble gases; determine, using the comparison, if the hydrocarbons present in the sample escaped the subsurface accumulation; to estimate, from the measured noble gas concentrations and the modeled range of expected concentrations of atmospheric and radiogenic noble gases, type and quality of hydrocarbons in the subsurface accumulation and the hydrocarbon / water volume ratio of formation of the subsurface accumulation; and integrate the estimated type of hydrocarbons in the subsurface accumulation and the hydrocarbon / water volume ratio of the subsurface accumulation with seismic reflection restrictions in a volume of the hydrocarbon accumulation and a volume of water present in the hydrocarbon accumulation, as well determining the volume of hydrocarbons present in the subsurface accumulation. 19. The method of any one of paragraphs 1 to 6, in which determining the signature of the noble gas comprises: using a processor and a machine-readable, tangible storage medium that stores machine-readable instructions for execution by the processor, in which the machine-readable instructions include code to determine expected concentrations of noble gases present in formation waters, code to model one or more exchanges and fractionation processes at expected concentrations of noble gases present in the sample, code to measure concentrations of noble gases present in the sample , code to compare the measured concentrations of noble gases with the modeled concentrations of noble gases in the formation waters, code to determine, using said comparison, the type of hydrocarbons present in the subsurface. 20. The method of any one of paragraphs 1 to 6, in which determining the noble gas signature comprises: using a computer program product having computer executable logic recorded on a machine-readable, tangible medium, the product of a program. computer comprising: code to determine expected concentrations of noble gases present in formation waters, code to measure concentrations of noble gases present in the hydrocarbon sample, code to compare measured concentrations of noble gases with modeled concentrations of noble gases in formation waters , code to determine, using said comparison, a type of hydrocarbons present in the hydrocarbon sample. 21. The method of any of paragraphs 1 to 20, in which determining the aggregated isotope signature of the sample comprises: determining an expected concentration of isotopes of a hydrocarbon species; model, using high-level initio ab calculation, a dependence on the expected temperature of the isotopes present in the sample; measure an aggregated isotope signature of isotopes present in the sample; compare the aggregated isotopic signature with the expected concentration of isotopes; determine, using this comparison, the current equilibrium storage temperature of the hydrocarbon species in the subsurface region of interest. 22. The method of paragraph 21, in which determining an expected concentration of isotopes includes determining a stochastic distribution of isotopes of hydrocarbon species for a given mass isotopic signature for the species. 23. The method of paragraph 22, further comprising: where the given mass isotopic signature of the hydrocarbon species has been altered from the secondary isotope exchange processes or mixture, applying a correction scheme to arrive at an initial primary isotopic signature representative of what was produced from the source rock. 24. The method of paragraph 21, where the location comprises a depth. 25. The method of paragraph 24, in which determining a location includes applying a thermal gradient to an equilibrium storage temperature of subsurface accumulation. 26. The method of any one of paragraphs 1 to 20, in which determining the aggregated isotope signature of the sample comprises: obtaining a hydrocarbon sample; analyzing the hydrocarbon sample to determine its geochemical signature, said analysis including measuring an isotope distribution for a hydrocarbon species present in the hydrocarbon sample; determine a stochastic distribution of isotopes for the hydrocarbon species; determine a deviation from the measured distribution of isotopes from the stochastic distribution of isotopes for the hydrocarbon species; determine a source of the hydrocarbon sample; determining a storage temperature for the hydrocarbon species when the source of the hydrocarbon sample is an accumulation of hydrocarbon; and storage temperature. 27. The method of paragraph 1, in which reservoir surveillance of fluids produced in one of one or more subsurface regions involves identifying processes responsible for the deviation of fingerprints to the region of interest. 28. The method of paragraph 27, further comprises developing a mitigation strategy to lessen the impact of the identified processes. 29. The method of paragraph 1, in which reservoir surveillance of fluids produced from one or more subsurface regions comprises using fingerprint deviations for reservoir connectivity applications.
[0099] It should be understood that the foregoing is merely a detailed description of the specific modalities of the invention and that numerous changes, modifications, and alternatives to the disclosed modalities can be made in accordance with the disclosure here without departing from the scope of the invention. The foregoing description, then, is not significant in limiting the scope of the invention. Instead, the scope of the invention is to be determined only by the appended or equivalent claims. It is also contemplated that structures and features embodied in the present examples can be altered, rearranged, replaced, deleted, duplicated, combined, or added to each other. The articles "o", "a", "one" and "one" are not necessarily limited to mean only one, but are instead inclusive and open to include, optionally, multiple such elements.

权利要求:
Claims (17)
[0001]
1. Method for producing hydrocarbons, characterized by the fact that it comprises: obtaining one or more samples from one or more subsurface regions of interest; analyze the sample to determine a noble gas signature and an aggregated hydrocarbon isotope signature for each of the samples obtained; generate a region of digital fingerprint of interest comprising the signature of noble gas and the signature of the aggregated isotope of the hydrocarbon for the samples obtained; producing fluids from one or more subsurface regions of interest, in which the fluids produced comprising hydrocarbons; and carry out reservoir surveillance in the fluids produced from one or more subsurface regions of interest; where carrying out surveillance of the reservoir in the produced fluids also comprises: obtaining a first sample from the produced fluids; analyzing a first sample to determine a first fingerprint of the sample, wherein the first fingerprint of the sample comprises a prime gas signature and an aggregated isotope signature of the hydrocarbon of the first sample; and compare the first sample fingerprint for the region of the first fingerprint of interest.
[0002]
2. Method, according to claim 1, characterized by the fact that carrying out reservoir surveillance in the produced fluids also comprises: obtaining a second sample of the produced fluids, in which the second sample is obtained a period of time after obtaining the first sample ; analyzing the second sample to determine a second fingerprint of the sample, wherein the second fingerprint of the sample comprises a noble gas signature and an aggregated isotope signature of the hydrocarbon of the second sample; and comparing the second sample fingerprint to the fingerprint region of interest.
[0003]
3. Method, according to claim 1, characterized by the fact that comparing the first sample fingerprint to the fingerprint region of interest comprises comparing the first sample fingerprint and a static fingerprint to the region of interest to determine interregional changes.
[0004]
4. Method according to claim 1, characterized by the fact that comparing the first sample fingerprint to the region of fingerprint of interest comprises comparing the first sample fingerprint and a dynamic fingerprint to the region of interest to determine intra-regional changes.
[0005]
5. Method, according to claim 1, characterized by the fact that it still comprises developing a depletion strategy based on the region of digital printing of interest to produce hydrocarbons of a specific quality and composition.
[0006]
6. Method, according to claim 1, characterized by the fact that determining the aggregated isotope signature of the hydrocarbon comprises: determining an expected concentration of isotopologists of a hydrocarbon species in the sample; model, using high-level initio ab calculations, an expected temperature dependence of isotopes present in the sample; measure an aggregated isotopic signature of the hydrocarbon of the isotopes present in the sample; compare the aggregated isotopic signature of the hydrocarbon with the expected concentration of isotopes; and determining a current equilibrium storage temperature for the hydrocarbon species in the sample.
[0007]
7. Method according to claim 6, characterized in that determining an expected concentration of isotopes includes determining a stochastic distribution of isotopes of hydrocarbon species for a given center isotopic signature for hydrocarbon species.
[0008]
8. Method according to claim 6, characterized by the fact that it further comprises using the hydrocarbon aggregate isotope signature to determine a depth from which the hydrocarbons in the sample originated.
[0009]
9. Method according to claim 8, characterized by the fact that determining the depth comprises applying a thermal gradient to the equilibrium storage temperature of the subsurface accumulation.
[0010]
10. Method according to claim 8, characterized by the fact that determining the depth comprises using a geophysical imaging technique.
[0011]
11. Method according to claim 1, characterized by the fact that determining the noble gas signature comprises: measuring or modeling an initial concentration of atmospheric noble gas present in the formation water in contact with an infiltrate associated with the hydrocarbon accumulation subsurface in the region of interest; modify the initial measured / modeled concentration by counting the expansion of the noble radiogenic gases during the residence time of the formation water; measure concentrations and isotopic ratios of atmospheric noble gases and noble radiogenic gases present in the sample; compare the measured concentrations and isotopic ratios of atmospheric noble gases and radiogenic noble gases present in the sample to the modified measured / modeled concentrations of the formation water for a plurality of exchange processes; and to compare a signature of atmospheric noble gas measured in a sample hydrocarbon phase with the modified measured / modeled concentration of atmospheric noble gases in the formation water for the plurality of exchange processes.
[0012]
12. Method according to claim 11, characterized by the fact that the plurality of exchange processes includes at least one of the equilibrium solubility laws calibrated to reflect conditions in subsurface hydrocarbon accumulations, Rayleigh-style fractionation to represent degassing of an oily phase, and gas separation to represent enrichment in a gaseous phase.
[0013]
13. Method according to claim 12, characterized by the fact that conditions in subsurface hydrocarbon accumulations include at least one of the reservoir temperature, pressure, formation water salinity and oil density.
[0014]
14. Method according to claim 11, characterized by the fact that the noble gas includes at least one of helium (He), Neon (Ne), Argon (Ar), krypton (Kr), and Xenon (Xe).
[0015]
15. Method, according to claim 1, characterized by the fact that the one or more samples of the region of interest comprise one of water, oil, natural gas, sediments, rocks, fluids present in the sediments, fluids from the pores of the rocks, and fluids trapped in fluid inclusions.
[0016]
16. Method, according to claim 1, characterized by the fact that carrying out reservoir surveillance in the fluids produced from one or more subsurface regions comprises identifying responsible processes for the change in the first fingerprint of the fingerprint sample in the region of interest.
[0017]
17. Method, according to claim 15, characterized by the fact that it also includes developing a mitigation strategy to reduce the impact of the identified processes.

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法律状态:
2018-12-04| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|

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2019-12-03| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|

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2020-12-15| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|

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2021-03-02| B16A| Patent or certificate of addition of invention granted [chapter 16.1 patent gazette]|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 09/11/2012, OBSERVADAS AS CONDICOES LEGAIS. |

优先权:

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申请号 | 申请日 | 专利标题

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US201161558822P| true| 2011-11-11|2011-11-11|

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US61/558,822|2011-11-11|

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US201261616813P| true| 2012-03-28|2012-03-28|

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US61/616,813|2012-03-28|

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USPCT/US2012/052542|2012-08-27|

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PCT/US2012/064552|WO2013071189A1|2011-11-11|2012-11-09|Method and system for reservoir surveillance utilizing a clumped isotope and/or noble gas data|

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