[go: up one dir, main page]

WO2016016335A1 - Système d'identification de fluide - Google Patents

Système d'identification de fluide Download PDF

Info

Publication number
WO2016016335A1
WO2016016335A1 PCT/EP2015/067432 EP2015067432W WO2016016335A1 WO 2016016335 A1 WO2016016335 A1 WO 2016016335A1 EP 2015067432 W EP2015067432 W EP 2015067432W WO 2016016335 A1 WO2016016335 A1 WO 2016016335A1
Authority
WO
WIPO (PCT)
Prior art keywords
tracer
oil
fluid
injected
iii
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Ceased
Application number
PCT/EP2015/067432
Other languages
English (en)
Inventor
Dominic Patrick MCCANN
Kevin John FORBES
Ian COOPER
Robert Seth HARTSHORNE
Gary John TUSTIN
Gary ODDIE
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Tracesa Ltd
Schlumberger Holdings Ltd
Original Assignee
Tracesa Ltd
Schlumberger Holdings Ltd
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Tracesa Ltd, Schlumberger Holdings Ltd filed Critical Tracesa Ltd
Publication of WO2016016335A1 publication Critical patent/WO2016016335A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/10—Locating fluid leaks, intrusions or movements
    • E21B47/11—Locating fluid leaks, intrusions or movements using tracers; using radioactivity
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/80—Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open
    • C09K8/805—Coated proppants
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/02—Well-drilling compositions
    • C09K8/03—Specific additives for general use in well-drilling compositions
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
    • C09K2208/10—Nanoparticle-containing well treatment fluids
    • C—CHEMISTRY; METALLURGY
    • C12—BIOCHEMISTRY; BEER; SPIRITS; WINE; VINEGAR; MICROBIOLOGY; ENZYMOLOGY; MUTATION OR GENETIC ENGINEERING
    • C12Q—MEASURING OR TESTING PROCESSES INVOLVING ENZYMES, NUCLEIC ACIDS OR MICROORGANISMS; COMPOSITIONS OR TEST PAPERS THEREFOR; PROCESSES OF PREPARING SUCH COMPOSITIONS; CONDITION-RESPONSIVE CONTROL IN MICROBIOLOGICAL OR ENZYMOLOGICAL PROCESSES
    • C12Q2563/00—Nucleic acid detection characterized by the use of physical, structural and functional properties
    • C12Q2563/185—Nucleic acid dedicated to use as a hidden marker/bar code, e.g. inclusion of nucleic acids to mark art objects or animals

Definitions

  • the present invention relates to a particle capture and sampling system, a method of particle capture and sampling system.
  • this invention relates to a tracer technology and the applications thereof within the oil and gas exploration, production and transportation industries.
  • fluids are introduced, produced or moved during the oil and gas operations of exploration, production and transportation. These fluids range from those manufactured to perform specific functions to those collected from different formations in a well. Some of the fluids collected are fluids originally injected into the well or reservoir rocks, returning to the surface during operations such as drilling mud or fracturing fluids. Other fluids that are used occur naturally in the formation rocks, for example, oil, gas condensate and water. Of course, in many cases fluids collected can be a mixture of naturally occurring fluids and fluids introduced in to reservoir rocks.
  • the information gleaned from this understanding can tell the operator (for example, the oil company managing the field) a lot about the efficiency of production of oil and gas, how well certain specialised fluids are working, e.g., stimulation fluids, whether fluids are moving from one production zone to another (for example, through the reservoir rock or behinds seals in a well that are meant to isolate these zones) and also if some of the fluids injected are finding a route into shallower aquifers which could lead to environmental issues.
  • certain specialised fluids e.g., stimulation fluids, whether fluids are moving from one production zone to another (for example, through the reservoir rock or behinds seals in a well that are meant to isolate these zones) and also if some of the fluids injected are finding a route into shallower aquifers which could lead to environmental issues.
  • EOR enhanced oil recovery
  • a common practice that is used today to try and understand fluid flow is to use what is called a tracer.
  • the tracer is added to a fluid at one point in the process and is detected at another point later in the process. For example, it is common to add a tracer to the drilling mud and to detect it in the mud that returns to the surface. If the time the tracer is added and the time it is first detected in the returns are compared then the fluid circulation time can be easily calculated as the difference between the two. This circulation time can help establish if the well is being cleaned properly or if the hole drilled is in gauge, washed out or has other potential flow paths.
  • a chemical or isotopic marker that is uniformly distributed in the continuous phase of a drilling, coring or completion fluid and used to later identify the filtrate in cores or in fluids sampled from the reservoir.
  • the tracer must become part of the filtrate, remaining in solution and moving with the filtrate into permeable zones. It should not be absorbed on clays or degrade. It needs to be measureable in trace amounts and safe to handle. Examples include: Weakly emitting radioisotopes which can be safe and effective, Bromide or iodide compounds are practical because they do not occur naturally in most muds or reservoirs and Nitrate anion added as sodium, potassium or calcium nitrate is one of the earliest tracers but it is difficult to analyse and degradation can be significant.
  • Radioactive 'paints' applied to a specific part of the borehole so that a particular zone can be precisely identified upon re-entry into the borehole.
  • the tracer injection profile that is, concentrations as a function of time
  • more information about the tracer transit through the system e.g., the well(s) and/or formation
  • the time between the peaks of the injection and detection profiles will give the transit time and the change in the width of the injection profile compared to the width of the detection profile will provide information about the particle dispersion within the system.
  • GB2489714 and WO2012136734 disclose a system and method that uses encapsulated DNA in nanoparticles for unique fluid identification. These patents also disclose methods for introducing and capturing the nanoparticles as they are returned entrained in the flow of fluids from the well or are captured by taking samples from the well or reservoir. The method of pumping the particles entrained in the fluids to be traced is disclosed. While these approaches will work in many situations, they are not optimal in others.
  • This invention addresses the limitations of the technology presently used and disclosed in the prior art.
  • the present inventors have worked to establish technical solutions to the above restrictions associated with technology presently used in the industry or disclosed in the prior art.
  • the present invention accordingly provides apparatus and methods for the controlled introduction of DNA nano or micro particles in to the flow system and their capture as the leave the flow system.
  • the flow system as an oil and gas well or a series of wells or a reservoir or any sub-surface rock formation or a pipeline network used to transport oil and gas or any combination of the above.
  • Preferred aspects of the invention relate to the introduction, detection, collection and separation of nanoparticles in the continuous phase of fluids that are used within the oil and gas industry.
  • the application of controlled introduction and capture of these nanoparticles for the better understanding of reservoir and sub-surface fluid flow and also the movement of fluids within a well, for example, from one formation to another or from one well section to another or from fractures generated in the formation and the well or between wells (e.g. during injection operations) are some of the embodiments described in this invention.
  • the present invention provides a tracer particle for use in the exploration, production, transportation and/or storage of oil and/or gas, the tracer particle comprising a proppant material, a coating layer at least partially surrounding the proppant material and a tracer material within the coating layer, the tracer material having an identifiable DNA.
  • the proppant material comprises sand particles, gravel particles, synthetic ceramic materials, or any mixture thereof.
  • the tracer material comprises a plurality of nanoparticles having identifiable DNA dispersed within the coating layer.
  • an outer surface of at least some of the nanoparticles is functionalised for capture by a physical or chemical mechanism.
  • the outer surface of at least some of the nanoparticles is chemically functionalised for capture by a chemical mechanism.
  • the outer surface of at least some of the nanoparticles may comprise at least one protein, at least one antibody, and/or at least one hydroxyl moiety, located in at least an outer surface of the coating layer.
  • the at least one protein may comprise streptavidin, biotin, protein A or any mixture thereof, the at least one antibody may comprise an immunoglobulin G antibody, and/or the at least one hydroxyl moiety
  • s may be present in at least one of a diol or cis-diol moiety and an alpha-hydroxy acid moiety or a mixture thereof.
  • the identifiable DNA is complexed with a complexing agent, for example as a complexing polymer.
  • the identifiable DNA may be at least partly encapsulated by an encapsulating polymer, for example the encapsulating polymer comprising at least one acrylate-, methacrylate- or styrene-based polymer.
  • the encapsulating polymer may be a cross-linked polymer including a cross-linker, optionally the cross- linker being adapted to be chemically reduced by a reducing agent thereby to degrade the encapsulating polymer to release the DNA for analysis, further optionally a disulfide cross-linker.
  • the coating layer comprises an oil-soluble or water-soluble material.
  • the oil-soluble material may be selected from a hydrocarbon wax, a resin, a polymer or any mixture of two or more thereof.
  • the water-soluble material may be at least one polymer, typically the at least one polymer comprising polylactic acid, partially hydrolysed polyacrylamide, polyethylene oxide or any mixture of two or more thereof.
  • a tracer sample comprising a plurality of tracer particles according to the invention, the tracer particles comprising a mixture of a plurality of first tracer particles and a plurality of second tracer particles, the first tracer particles comprising a first tracer material and the second tracer particles comprising a second tracer material, wherein the first and second tracer materials have different identifiable DNA, and the coating layers of the first and second tracer particles comprise respective first and second oil-soluble and/or water-soluble material which have respective different solubility in oil and/or water.
  • the coating layer of the first tracer particles may comprise an oil-soluble material and the coating layer of the second tracer particles may comprise a water-soluble material.
  • the coating layer is an inner coating layer with a first tracer material therein, and the tracer particle further comprises an outer coating layer at least partially surrounding the inner coating layer and a second tracer material within the outer coating layer, wherein the first and second tracer materials have different identifiable DNA and the inner and outer coating layers comprise respective first and second oil-soluble and/or water-soluble material which have respective different solubility in oil and/or water.
  • the outer coating layer may comprise an oil-soluble material and the inner coating layer comprises a water-soluble material.
  • the oil-soluble material may be selected from a hydrocarbon wax, a resin, a polymer or any mixture of two or more thereof.
  • the water-soluble material may be at least one polymer, for example the at least one polymer comprising polylactic acid, partially hydrolysed polyacrylamide, polyethylene oxide or any mixture of two or more thereof.
  • the present invention provides a tracer particle in the form of a capsule comprising an outer shell encapsulating tracer material which comprises a plurality of nanoparticles having identifiable DNA.
  • an outer surface of at least some of the nanoparticles is functionalised for capture by a physical or chemical mechanism.
  • the outer surface of at least some of the nanoparticles is chemically functionalised for capture by a chemical mechanism.
  • the outer surface of at least some of the nanoparticles may comprise at least one protein, at least one antibody, and/or at least one hydroxyl moiety, located in at least an outer surface of the coating layer.
  • the at least one protein may comprise streptavidin, biotin, protein A or any mixture thereof, the at least one antibody may comprise an immunoglobulin G antibody, and/or the at least one hydroxyl moiety may be present in at least one of a diol or c/ ' s-diol moiety and an alpha-hydroxy acid moiety or a mixture thereof.
  • the identifiable DNA is complexed with a complexing agent.
  • the complexing agent may be a complexing polymer.
  • the identifiable DNA may be at least partly encapsulated by an encapsulating polymer.
  • the encapsulating polymer may comprise at least one acrylate-, methacrylate- or styrene-based polymer.
  • the encapsulating polymer is a cross-linked polymer including a cross- linker, optionally wherein the cross-linker is adapted to be chemically reduced by a reducing agent thereby to degrade the encapsulating polymer to release the DNA for analysis, further optionally a disulfide cross-linker.
  • the outer shell comprises at least one cellulose material, further optionally hydrocellulose.
  • the invention also provides a plurality of tracer particles according to the invention or a tracer sample according to the invention, wherein the tracer particles are present in a carrier fluid which comprises a detectable indicator, optionally comprising at least one dye, in addition to the tracer material.
  • the present invention provides a method of tracing fluid during the exploration, production and/or storage of oil and/or gas, the method comprising the steps of:
  • a tracer particle comprising (a) a proppant material, a coating layer at least partially surrounding the proppant material and a tracer material within the coating layer, the tracer material having an identifiable DNA or (b) a capsule comprising an outer shell encapsulating tracer material which comprises a plurality of nanoparticles having identifiable DNA;
  • step (iii) the fluid is injected, either as a pulse or continuously, into a flow of a second fluid which may or may not contain a proppant.
  • step (iii) the fluid is injected as a sequence of intermittent pulses.
  • a plurality of the oil or gas wells is provided, and in step (iii) a respective sample of the fluid is injected as a respective pulse into a respective well or at least two of the respective wells, and optionally in preceding or subsequent injection operations a pulse of a further tracer material comprising a plurality of nanoparticles having an identifiable DNA and in the absence of proppant material is injected into the respective well or at least two of the respective wells.
  • step (iii) the fluid is injected sequentially into the at least two of the respective wells.
  • an injection time that the fluid is injected is recorded and in step (iv) a recovery time that the tracer material is recovered is recorded.
  • a residence time between the injection and recovery times is determined.
  • the residence time may be input as a parameter into a computer model of a production system including one or more oil or gas reservoirs or wells or any combination thereof.
  • the parameter may be adapted to function as a calibration parameter for the computer model.
  • step (iii) an injection time period during which the fluid is injected is recorded and in step (iv) a recovery time period during which the tracer material is recovered is recorded.
  • a time period relationship between the injection time period and the recovery time period is determined.
  • a variation of the time period relationship with time may be determined.
  • at least one of the time period relationship or the variation of the time period relationship with time is input as a parameter, optionally as a calibration parameter, into a computer model of a production system including one or more oil or gas reservoirs or wells or any combination thereof.
  • step (iii) in a first injection operation a first tracer material is injected and subsequently in a second injection operation a second tracer material, optionally in the presence or absence of proppant material, is injected, the first and second tracer materials having different identifiable DNA.
  • the injected fluid comprises a known initial concentration of the tracer material and in step (iv) a final concentration of the recovered tracer material is recorded.
  • the known initial concentration of the tracer material varies with time and in step (iv) a final concentration, varying with time, of the recovered tracer material is recorded.
  • a concentration relationship between the initial and final concentrations may be determined.
  • a variation of the concentration relationship with time may be determined.
  • at least one of the concentration relationship or the variation of the concentration relationship with time is input as a parameter into a computer model of a production system including one or more oil or gas reservoirs or wells or any combination thereof.
  • the fluid comprises a detectable indicator in addition to the tracer material.
  • the detectable indicator may comprise at least one dye.
  • the fluid is injected into an oil or gas well in a hydraulic fracturing operation. During the hydraulic fracturing operation the coating layer may be degraded, such as by dissolution and/or breaking, within the well to release the tracer material into the well.
  • the method may optionally further comprise the step of injecting into the respective well or at least two of the respective wells a pulse of a further tracer material comprising a plurality of nanoparticles having an identifiable DNA and in the absence of proppant material in an enhanced oil recover (EOR) operation.
  • a plurality of the oil or gas wells is provided defining a central area therebetween, and in step (iii) a respective sample of the fluid is injected into a respective well or at least two of the respective wells, each sample having a respective tracer material therein.
  • step (ii) the tracer particle is introduced into the fluid after the fluid has been pressurized to an injection pressure.
  • the injection pressure may be controlled or varied to control or vary the injection rate in step (iii).
  • step (ii) a plurality of the tracer particles are introduced into the fluid at a known concentration and/or at a known dosage rate and/or over a known time period.
  • the supply of oil or gas is monitored to detect the fluid, any nanoparticles having an identifiable DNA therein or any identifiable DNA therein, and step (iv) is initiated after detection of the fluid or any nanoparticles having the identifiable DNA or any identifiable DNA in the supply of oil or gas.
  • the monitoring of the supply of oil or gas may include measuring a physical property of the fluid or any tracer material therein, the physical property being selected from absorption and/or reflection and/or scattering of electromagnetic radiation, dielectric constant, colour in the visible region of the spectrum, and fluorescence, or any combination thereof.
  • the tracer material is captured on a surface of a recovery element, the surface being adapted to bind chemically or physically to a surface of the tracer material.
  • the tracer material comprises a plurality of nanoparticles having identifiable DNA.
  • the surface of the recovery element includes a first chemical moiety adapted to bind chemically to a complementary second chemical moiety on the surface of the tracer nanoparticle.
  • the first or second chemical moiety may comprise at least one of a boroe acid or a derivative thereof, for example phenylboronic acid or benzoboroxole or a mixture thereof.
  • the first or second chemical moiety may comprise at least one hydroxyl moiety, for example the at least one hydroxyl moiety being present in at least one of a diol or c/s-diol moiety and an alpha-hydroxy acid moiety or a mixture thereof.
  • the first or second chemical moiety may comprise at least one protein, for example streptavidin, biotin, protein A or any mixture thereof.
  • the first or second chemical moiety may comprise at least one antibody, for example an immunoglobulin G antibody.
  • the surface of the recovery element is monitored to indicate, directly or indirectly, capture of the nanoparticle on the surface of the recovery element.
  • the electrical properties or visual appearance of the surface of the recovery element is monitored.
  • the surface of the recovery element is monitored to indicate, directly or indirectly, an amount o the nanoparticle captured on the surface of the recovery element.
  • the indicated amount of the nanoparticle captured on the surface of the recovery element reaches a predetermined threshold, the analysis step (v) is initiated for the nanoparticle captured on the surface of the recovery element.
  • a predetermined volume of the fluid having a predetermined concentration of the identifiable DNA, is injected.
  • the predetermined volume of the fluid may be injected from a cartridge containing the predetermined volume, may be injected by a plunger mechanism or may be injected from a tank through a flowmeter.
  • the proppant material comprises sand particles, gravel particles, synthetic ceramic materials or any mixture thereof.
  • the tracer material comprises a plurality of nanoparticies having identifiable DNA dispersed within the coating layer.
  • an outer surface of at least some of the nanoparticies is functionalised for capture by a physical or chemical mechanism.
  • the outer surface of at least some of the nanoparticies is chemically functionalised for capture by a chemical mechanism.
  • the outer surface of at least some of the nanoparticies may comprise at least one protein, at least one antibody, and/or at least one hydroxyl moiety, located in at least an outer surface of the nanoparticle.
  • the at least one protein comprises streptavidin, biotin, protein A or any mixture thereof
  • the at least one antibody comprises an immunoglobulin G antibody
  • the at least one hydroxyl moiety is present in at least one of a diol or c .v-diol moiety and an alpha-hydroxy acid moiety or a mixture thereof.
  • the coating layer comprises an oil-soluble or water-soluble material.
  • the oil-soluble material may be selected from a hydrocarbon wax, a resin, a polymer or any mixture of two or more thereof.
  • the oil-soluble material may at least partly dissolve in at least one hydrocarbon present in the oil or gas well.
  • the water-soluble material may be at least one polymer, for example the at least one polymer comprising polylactic acid, partially hydrolysed polyacrylamide, polyethylene oxide or any mixture of two or more thereof.
  • the water-soluble material may at least partly dissolve in at least one aqueous liquid present in the oil or gas well.
  • a plurality of tracer particles is injected, the tracer particles comprising a mixture of a plurality of first tracer particles and a plurality of second tracer particles, the first tracer particles comprising a first tracer material and the second tracer particles comprising a second tracer material, wherein the first and second tracer materials have different identifiable D A, and the coating layers of the first and second tracer particles comprise respective first and second oil-soluble and/or water-soluble material which have respective different solubility in oil and/or water.
  • the coating layer of the first tracer particles comprises an oil-soluble material and the coating layer of the second tracer particles comprises a water-soluble material.
  • the coating layer is an inner coating layer with a first tracer material therein, and the tracer particle further comprises an outer coating layer at least partially surrounding the inner coating layer and a second tracer material within the outer coating layer, wherein the first and second tracer materials have different identifiable DNA and the inner and outer coating layers comprise respective first and second oil-soluble and/or water-soluble material which have respective different solubility in oil and/or water.
  • the outer coating layer may comprise an oil-soluble material and the inner coating layer may comprise a water-soluble material.
  • the oil- soluble material may be selected from a hydrocarbon wax, a resin, a polymer or any mixture of two or more thereof.
  • the water-soluble material may be at least one polymer, for example the at least one polymer comprising polyiactic acid, partially hydrolysed polyacrylamide, polyethylene oxide or any mixture of two or more thereof.
  • the outer shell comprises a cellulose material, further optionally hydrocellulose.
  • the outer shell fractures under compression within an oil or gas well to release the nanoparticles encapsulated therein into the oil or gas well.
  • the present invention provides an apparatus for tracing fluid during the exploration, production, transportation and/or storage of oil and/or gas, the apparatus comprising an injector unit for injecting a pulse of fluid, containing at least one tracer particle, including tracer material having identifiable DNA, therein, into a supply of oil or gas; a monitoring unit for monitoring the supply of oil or gas to detect the fluid or any tracer material therein; a recovery unit for subsequently recovering at least some of the tracer material which was in the injected fluid, the recovery unit includes a recovery element having a surface adapted to bind chemically or physically to a surface of the tracer material to capture the tracer material on the recovery element; an analysis unit for analyzing any identifiable DNA in the tracer material, and a controller for controlling the operation of at least one of the injector unit, the monitoring unit, the recovery unit and the analysis unit or any combination thereof.
  • the injector unit is adapted to inject the fluid as a sequence of intermittent pulses.
  • the controller is adapted to record an injection time that the fluid is injected by the injector unit and a recovery time that the tracer material is recovered by the recovery unit.
  • the controller may be adapted to determine a residence time between the injection and recovery times.
  • the controller may be adapted to input the residence time as a parameter, optionally a calibration parameter into a computer model of a production system including one or more oil or gas reservoirs or wells or any combination thereof.
  • the controller is adapted to record an injection time period during which the fluid is injected by the injector unit and a recovery time period during which the tracer material is recovered by the recovery unit.
  • the controller may be adapted to determine a time period relationship between the injection time period and the recovery time period.
  • the controller may be adapted to determine a variation of the time period relationship with time.
  • the controller may be adapted to input at least one of the time period relationship or the variation of the time period relationship with time as a parameter, optionally a calibration parameter, into a computer model of a production system including one or more oil or gas reservoirs or wells or any combination thereof.
  • the controller is adapted to record a concentration of the tracer material injected by the injector unit and/or recovered by the recovery unit.
  • the controller may be adapted to determine a concentration relationship between the concentration of the tracer material injected by the injector unit and the concentration of the tracer material recovered by the recovery unit.
  • the controller may be adapted to determine a variation of the concentration relationship with time.
  • the controller may be adapted to input at least one of the concentration relationship or the variation of the concentration relationship with time as a parameter, optionally a calibration parameter, into a computer model of a production system including one or more oil or gas reservoirs or wells or any combination thereof.
  • the monitoring unit includes a measuring device for measuring a physical property of the fluid or any tracer material therein, the physical property being selected from absorption and/or reflection and/or scattering of electromagnetic radiation, dielectric constant, colour in the visible region of the spectrum, and fluorescence, or any combination thereof.
  • the surface of the recovery element includes a first chemical moiety adapted to bind chemically to a complementary second chemical moiety on the surface of the tracer material.
  • the first chemical moiety may comprise at least one of a boron acid or a derivative thereof, for example phenylboronic acid or benzoboroxole or a mixture thereof.
  • the first chemical moiety may comprise at least one protein, for example streptavidin, biotin, protein A or any mixture thereof.
  • the first chemical moiety may comprise at least one antibody, for example an immunoglobulin G antibody.
  • the monitoring unit is adapted to monitor the surface of the recovery element to indicate, directly or indirectly, capture of the tracer material on the surface of the recovery element.
  • the monitoring unit may be adapted to monitor electrical properties or visual appearance of the surface of the recovery element.
  • the monitoring unit may be adapted to monitor the surface of the recovery element to indicate, directly or indirectly, an amount of the tracer material captured on the surface of the recovery element.
  • the controller may be adapted to initiate the analysis unit to analyse the tracer material captured on the surface of the recovery element after an indicated amount of the tracer material captured on the surface of the recovery element reaches a predetermined threshold.
  • the injector unit is adapted to inject a predetermined volume of the fluid is injected.
  • the injector unit may be adapted to inject the predetermined volume of the fluid from a cartridge containing the predetermined volume.
  • the injector unit may be adapted to inject the predetermined volume of the fluid by a plunger mechanism.
  • the injector unit may be adapted to inject the predetermined volume of the fluid from a tank through a flowmeter.
  • the present invention provides a tracer nanoparticle for use in the exploration, production, transportation and/or storage of oil and/or gas, the tracer nanoparticle comprising a tracer material having an identifiable DNA, and at least one chemical moiety located in at least an outer surface of the tracer nanoparticle, the at least one chemical moiety comprising at least one protein, at least one antibody, and/or at least one hydroxyl moiety.
  • the at least one protein may comprise streptavidin, biotin, protein A or any mixture thereof.
  • the at least one antibody may comprise an immunoglobulin G antibody.
  • the at least one hydroxyl moiety may be present in at least one of a diol or c j-diol moiety and an alpha-hydroxy acid moiety or a mixture thereof.
  • the identifiable DNA is complexed with a complexing agent, optionally wherein the complexing agent is a complexing polymer.
  • the identifiable DNA is at least partly encapsulated by an encapsulating polymer, optionally wherein the encapsulating polymer comprises at least one acrylate-, methacrylate- or styrene- based polymer, further optionally wherein the encapsulating polymer is a cross-linked polymer including a cross-linker, yet further optionally wherein the cross-linker is adapted to be chemically reduced by a reducing agent thereby to degrade the encapsulating polymer to release the DNA for analysis, optionally a disulfide cross- linker.
  • a tracer particle having an outer surface which is provided by a coating layer of an oil-soluble or water-soluble material which encapsulates a plurality of the nanoparticles according to the fifth aspect of the present invention.
  • the tracer particle further comprises a proppant material at least partly surrounded by the coating layer, optionally wherein the proppant material comprises a sand particle, a gravel particle, a synthetic ceramic material, or any mixture thereof.
  • a tracer sample comprising a plurality of tracer particles according to claim 144 or claim 145, the tracer particles comprising a mixture of a plurality of first tracer particles and a plurality of second tracer particles, the first tracer particles comprising a first tracer material and the second tracer particles comprising a second tracer material, wherein the first and second tracer materials have different identifiable DNA, and the coating layers of the first and second tracer particles comprise respective first and second oil-soluble and/or water-soluble material which have respective different solubility in oil and/or water.
  • the coating layer of the first tracer particles comprises an oil-soluble material and the coating layer of the second tracer particles comprises a water-soluble material.
  • the coating layer is an inner coating layer with a first tracer material therein, and the tracer particle further comprises an outer coating layer at least partially surrounding the inner coating layer and a second tracer material within the outer coating layer, wherein the first and second tracer materials have different identifiable DNA and the inner and outer coating layers comprise respective first and second oil-soluble and/or water-soluble material which have respective different solubility in oil and/or water.
  • the outer coating layer comprises an oil- soluble material and the inner coating layer comprises a water-soluble material.
  • the oil-soluble material is selected from a hydrocarbon wax, a resin, a polymer or any mixture of two or more thereof.
  • the water-soluble material is at least one polymer.
  • the at least one polymer comprises polylactic acid, partially hydrolysed polyacrylamide, polyethylene oxide or any mixture of two or more thereof.
  • the present invention provides a method of tracing fluid during the exploration, production, transportation and/or storage of oil and/or gas, the method comprising the steps of:
  • tracer nanoparticles comprising a tracer material having an identifiable DNA. and at least one chemical moiety located in at least an outer surface of the tracer nanoparticles;
  • step (iv) subsequently recovering at least some of the tracer material which was in the injected fluid, wherein in step (iv) the tracer material is captured on a surface of a recovery element, the surface being adapted to bind chemically or physically to the at least one chemical moiety;
  • the surface of the recovery element includes a first chemical moiety adapted to bind chemically to a complementary second chemical moiety located in at least the outer surface of the tracer nanoparticle.
  • the first or second chemical moiety may comprise at least one of a boron acid or a derivative thereof, for example phenylboronic acid or benzoboroxole or a mixture thereof.
  • the first or second chemical moiety may comprise at least one hydroxyl moiety, for example the at least one hydroxyl moiety is present in at least one of a diol or cis-diol moiety and an alpha-hydroxy acid moiety or a mixture thereof.
  • the first or second chemical moiety may comprise at least one protein, for example streptavidin, biotin, protein A or any mixture thereof.
  • the first or second chemical moiety may comprise at least one antibody, for example an immunoglobulin G antibody.
  • the surface of the recovery element is monitored to indicate, directly or indirectly, capture of the tracer nanoparticle on the surface of the recovery element.
  • the electrical properties or visual appearance of the surface of the recovery element may be monitored.
  • the surface of the recovery element is monitored to indicate, directly or indirectly, an amount of the tracer nanoparticies captured on the surface of the recovery element.
  • the analysis step (v) may be initiated for the tracer nanoparticies captured on the surface of the recovery element.
  • the present invention provides a method of tracing fluid during the exploration or production of oil arid/or gas, the method comprising the steps of:
  • step (vi) before, simultaneously with, or after step (v), comparing the injection and recovery parameters to determine a property of the oil or gas reservoir and/or well and/or a property of the behaviour of the tracer particle or tracer material within the oil or gas reservoir and/or well.
  • step (iii) the injection parameter has a first variable and in step (iv) the recovery parameter has a second variable, and in step (vi) the first and second variables are compared.
  • step (iii) the fluid is injected as a pulse.
  • step (iii) the fluid is injected as a sequence of intermittent pulses.
  • a plurality of the oil or gas wells is provided, and in step (iii) a respective sample of the fluid is injected as a respective pulse into a respective well of at least two of the respective wells.
  • the fluid may be injected sequentially into the at least two of the respective wells.
  • an injection time that the fluid is injected is recorded and in step (iv) a recovery time that the tracer material is recovered is recorded.
  • a residence time between the injection and recovery times may be determined. The residence time may be input as a parameter, optionally a calibration parameter, into a computer model of a production system including one or more oil or gas reservoirs or wells or any combination thereof.
  • step (iii) an injection time period during which the fluid is injected is recorded and in step (iv) a recovery time period during which the tracer material is recovered is recorded.
  • a time period relationship between the injection time period and the recovery time period may be determined.
  • a variation of the time period relationship with time may be determined.
  • At least one of the time period relationship or the variation of the time period relationship with time may be input as a parameter into a computer model of a production system including one or more oil or gas reservoirs or wells or any combination thereof.
  • step (iii) in a first injection operation a first tracer material is injected and subsequently in a second injection operation a second tracer material is injected, the first and second tracer materials having different identifiable DNA.
  • the injected fluid comprises a known initial concentration of the tracer material and in step (iv) a final concentration of the recovered tracer material is recorded.
  • the known initial concentration of the tracer material may vary with time and in step (iv) a final concentration, varying with time, of the recovered tracer material may be recorded.
  • a concentration relationship between the initial and final concentrations may be determined.
  • a variation of the concentration relationship with time may be determined.
  • At least one of the concentration relationship or the variation of the concentration relationship with time may be input as a parameter, optionally a calibration parameter, into a computer model of a production system including one or more oil or gas reservoirs or wells or any combination thereof.
  • the present invention provides a method of tracing fluid during the exploration and/or production, of oil and/or gas, the method comprising the steps of: (i) providing a tracer particle encapsulating a tracer material, the tracer material having an identifiable DMA;
  • step (vii) before, simultaneously with, or after step (v), determining the fracture closure time by analysis of the period between the injection time in step (iii) and the recovery time in step (v).
  • step (iii) the fluid is injected as a pulse.
  • step (iii) the fluid is injected as a sequence of intermittent pulses.
  • a plurality of the oil or gas wells is provided, and in step (iii) a respective sample of the fluid is injected as a respective pulse into a respective well of at least two of the respective wells.
  • the fluid may be injected sequentially into the at least two of the respective wells.
  • step (iii) an injection time that the fluid is injected is recorded and in step (iv) a recovery time that the tracer material is recovered is recorded.
  • a residence time between the injection and recovery times may be determined.
  • the residence time may be input as a parameter, optionally a calibration parameter, into a computer model of a production system including one or more oil or gas reservoirs or wells or any combination thereof.
  • step (iii) an injection time period during which the fluid is injected is recorded and in step (iv) a recovery time period during which the tracer material is recovered is recorded.
  • a time period relationship between the injection time period and the recovery time period may be determined.
  • a variation of the time period relationship with time may be determined.
  • At least one of the time period relationship or the variation of the time period relationship with time may be input as a parameter, optionally a calibration parameter, into a computer model of a production system including one or more oil or gas reservoirs or wells or any combination thereof.
  • step (iii) in a first injection operation a first tracer material is injected and subsequently in a second injection operation a second tracer material is injected, the first and second tracer materials having different identifiable DNA,
  • the injected fluid comprises a known initial concentration of the tracer material and in step (iv) a final concentration of the recovered tracer material is recorded.
  • the known initial concentration of the tracer material varies with time and in step (iv) a final concentration, varying with time, of the recovered tracer material is recorded.
  • a concentration relationship between the initial and final concentrations may be determined.
  • a variation of the concentration relationship with time may be determined.
  • at least one of the concentration relationship or the variation of the concentration relationship with time is input as a parameter, optionally a calibration parameter, into a computer model of a production system including one or more oil or gas reservoirs or wells or any combination thereof.
  • the fluid comprises a detectable indicator in addition to the tracer material.
  • the detectable indicator may comprise at least one dye.
  • the tracer material is encapsulated within a coating layer of the tracer particle and during the hydraulic fracturing operation the coating layer is degraded within the well to release the tracer material into the well.
  • the tracer material is encapsulated as a plurality of nanoparticles within the coating layer and during the hydraulic fracturing operation the coating layer is degraded within the well to release the nanoparticles into the well.
  • step (iii) the fluid is injected into an oil or gas well in an enhanced oil recovery (EOR) operation.
  • EOR enhanced oil recovery
  • a plurality of the oil or gas wells is provided defining a central area therebetween, and in step (iii) a respective sample of the fluid is injected into a respective well of at least two of the respective wells, each sample having a respective tracer material therein.
  • the identifiable DNA is complexed with a complexing agent, for example a complexing polymer.
  • the identifiable DNA may be at least partly encapsulated by an encapsulating polymer in a nanoparticle, for example the encapsulating polymer comprising at least one acrylate-, methacrylate- or styrene-based polymer.
  • the encapsulating polymer may be a cross-linked polymer including a cross-linker, optionally the cross-linker is adapted to be chemically reduced by a reducing agent thereby to degrade the encapsulating polymer to release the DNA for analysis, optionally a disulfide cross-linker.
  • a means to introduce a known volume of fluid containing nanoparticles of a predefined concentration into fluids that are being pumped into a well can be introduced into the fluid flow on either the high pressure or preferably on the low pressure side of the pump.
  • the particles can be introduced into the fluid flow on either the high pressure or preferably the low pressure side of the pump.
  • the particle injection rate is controlled as a function of the pump rate of the fluid being injected into a well.
  • the particle injection rate is controlled as a function of the pump rate of the fluid being injected into a well.
  • the particle injection rate is controlled as a function of the pump rate of the fluid being injected into a well.
  • the nanoparticles are suspended and introduced in a carrier fluid that is readily detected when it returns from the well.
  • the carrier fluid can be a dye or a fluid with a known fluorescence characteristic, for example, fluorescence under examination with UV light.
  • a control unit is provided that monitors the pump rate and/or particle fluid injection rate and controls valves arid particle introduction volume rates in a prescribed fashion in order to satisfy certain particle injection criteria, for example, particle concentration per unit volume of injected fluids.
  • a means to coat materials that are pumped into a well during certain operations for example, fracturing proppant or gravel during gravel packing or cement, with nanoparticles (or otherwise bind to or incorporate within such materials).
  • the coating or binding material is designed to dissolve or breakdown to release the nanoparticles from the surface of the proppant material, for example, when the said coating comes into contact with water flowing from the formation and the nanoparticles flow to surface entrained in the water flow.
  • the coating material is designed to dissolve or breakdown to release the nanoparticles from the surface of the proppant material, for example, when the said coating comes into contact with hydrocarbon flowing from the formation and the nanoparticles flow to surface entrained in the hydrocarbon flow.
  • the coating material is designed to dissolve or breakdown to release the nanoparticles from the surface of the proppant material, for example, when the said coating comes into contact with a fluid with a particular chemical characteristic, for example, of a particular pH or with a pH within a particular range or above or below a particular value.
  • a particular chemical characteristic for example, of a particular pH or with a pH within a particular range or above or below a particular value.
  • nanoparticles can be encapsulated/embedded in larger capsules whose crash strength is such that they readily break when compressed between the proppant on closure of the fracture (for example the hydrocellulosic materials used to encapsulate gel fluid breakers in fracturing operations). These capsules are placed within the fracture along with the proppant and as the fracture closes, the compressive stresses created cause these materials to rupture and the encapsulated nanoparticles are released at the inception of the cleanup/flow back process.
  • the positive detection can trigger the capture of a sample or trigger the capture of a sequence of samples.
  • the nanoparticles are detected by a characteristic signature of the absorption or reflection spectra when the returning fluid is interrogated with a particular source, for example, electromagnetic waves of particular wavelengths or X-rays or any other form of radiation, and the nanoparticles within the fluid give rise to a characteristic absorption or reflective response that is measured by an appropriate detection device, thus providing an indication of their presences or not.
  • a characteristic signature of the absorption or reflection spectra when the returning fluid is interrogated with a particular source, for example, electromagnetic waves of particular wavelengths or X-rays or any other form of radiation
  • the nanoparticles within the fluid give rise to a characteristic absorption or reflective response that is measured by an appropriate detection device, thus providing an indication of their presences or not.
  • inline mass spectrometry can also be used for this purpose or some of scattering characteristics of EM of different wavelength (e.g., light or X-rays) by the nanoparticles or monitoring the dielectric constant or any other physical property of the fluid changed by the presence
  • this carrier fluid could be a dye that ca be detected visually (by the human eye) or preferably automatically through the detection of its colour when interrogated with, e.g., white light. Or it could be a fluid that fluorescences when interrogated at a particular wavelength, for example, pic-green.
  • this carrier fluid could be a dye that ca be detected visually (by the human eye) or preferably automatically through the detection of its colour when interrogated with, e.g., white light.
  • it could be a fluid that fluorescences when interrogated at a particular wavelength, for example, pic-green.
  • a means to produce a nanoparticle comprising specific surface functionalities
  • the surface functionalities are chemical groups that enable the nanoparticles to be concentrated when coming into contact with a chemically-complementary 'tab' (designed to enable chemical or physical binding or absorption of the nanoparticles to the tab) placed in the flow coming from the well.
  • a chemically-complementary 'tab' designed to enable chemical or physical binding or absorption of the nanoparticles to the tab placed in the flow coming from the well.
  • the tab must be functionalised with a moiety that specifically binds to the nanoparticle surface functional groups.
  • nanoparticle that comprises c/j'-diol or alpha-hydroxy acid groups protruding from the outer surface and a 'tab' that is coated with a boron acid moiety (e.g. phenylboronic acid, benzoboroxole etc).
  • a boron acid moiety e.g. phenylboronic acid, benzoboroxole etc.
  • other groups could provide the same technical effect (such as provision of a donor/receptor lock and key docking mechanism) and these are encompassed in this invention.
  • a means to continually interrogate the tab in order to determine changes in its physical or electrical properties, for example, its resistance, that will change as the number of nanoparticles that are stuck on the tab increases. This measurement can thus be used to determine when the tab is fully loaded with captured nanoparticles and should be removed and replaced with a new tab. Other changes in the physical properties of the tab could equally be used to determine the particle loading on the tab, for example, its colour change as the number of captured particles increases.
  • detection of changes in tab properties is used to trigger the capture of a sample or a sequence of samples of the fluid flowing out of the well.
  • a controller that monitors nanoparticle detection measurements and/or nanoparticle capture tabs and/or fluid flow rates, and uses this information to control valves and sample capture devices such that single or multiple samples are automatically taken and placed into sample bottles.
  • the volume of each sample can be controlled.
  • the rate at which the sample is taken can also be controlled in accordance with the returning fluid flow rate and/or the nanoparticle injection rate or injection profile so that representative samples are obtained.
  • the time, volume, sample rate etc. can be recorded for analysis with the injection parameters, in order to provide information about the nanoparticle transit through the flow system (well, reservoir etc).
  • a magnetic component eg an iron oxide
  • This can be used (a) to detect the presence of nanoparticles in the return flow from the well by sensing changes in the magnetic characteristics (field) of the fluid and (b) to capture, separate and concentrate the nanoparticles for further analysis by passing the return fluid over a suitable magnet or through a magnetic separator.
  • Figure 1 schematically illustrates several systems for the injection of fluids containing nanoparticles into a fracturing fluid pumped into a well.
  • Figures 2a, 2b arid 2c schematically illustrate proppant particles coated with degradable material in which nanoparticles are embedded and are thus pumped into a well.
  • Figure 3 schematically shows a system for the detection of nanoparticles in the flow returning from a well and the collection of samples from such a flow.
  • Figure 4 schematically illustrates a tab that can be used to capture nanoparticles in the fluid returning from a well.
  • Figure 5 schematically illustrates nanoparticles with a functionalised surface coating and a particle collection tab that is 'chemically sticky' to the nanoparticles.
  • Figure 6 is an illustration of EOR as an example application.
  • fracturing fluid is pumped into the well at high pressure in order to induce fractures in the formation, 102.
  • the fracturing fluid is pumped by pump 101 from a tank 104, along a surface flowline 103.
  • a flow meter 1 16 that measures the rate at which the fracturing fluid is pumped into the well 100.
  • the fluid pumped from tank, 104 often contains proppant, which can be sand particles of a particular size. This proppant then flows in the fracture fluid and enters the fractures, 102.
  • the proppant will help maintain fractures open once the pump pressure is removed and when fluids, for example, oil, are produced from the reservoir or fractures. It should be noted that the proppant may move as oil (or another fluid) flows through the fractures.
  • a controller, 105 which can take measurements from sensors (1 16 and 115) and/or control valves (108 and 1 13) and/or actuator (109) and/or pumps (101 and 1 18) in a prescribed fashion.
  • the applications of this controller will be apparent as various embodiments of this invention are described. It should be noted that the controller can be manually operated but preferably it is automatic. It should also be noted that this same control is preferably used to control the sampling process that will be described later.
  • a sample tank 106 is shown that will contain the fluid which has the nanoparticles suspended within it. The volume and concentration of the nanoparticles per unit volume are predefined depending on the application.
  • a one-way or nonreturn valve 107 is provided to allow flow from the sample tank into the flowline 103 but prevents flow back into the tank 106. In some situation it may be necessary to also provide a pump 1 18 to control the flow of the fluid from the sample tank 106 into the flowline 103. Valve 108 is actuated to open/close by the controller 105. In addition, optionally a flow meter 115 is provided to measure the rate at which the nanoparticle containing fluid enters into the flowline 103. This rate can be controlled to provide a desired nanoparticle concentration per unit volume in the fracturing fluid that is then pumped into the well using pump 101.
  • one sample injection embodiment encompasses the components 106, 107, 108 and optionally 1 15.
  • a cylinder, 1 1 1 with a plunger, 1 10, is used to inject the nanoparticle fluid instead of the tank, 106 and pump 1 18.
  • the plunger is moved by the actuator
  • the plunger is at the top of the cylinder and the fluid containing the nanoparticle is placed in the cylinder, 1 1 1 , below it.
  • the cylinder can be prefilled with nanoparticle laden fluid of a predefined volume and concentration. These samples can be in cartridges (not shown) that are loaded in the cylinder, in a similar manner that caulking is loaded into a caulking gun.
  • the actuator, 109 is connected to the controller 105.
  • a valve 1 13 is also connected to the controller and a non-return valve 1 12 is provided to prevent fluid returning into the cylinder 1 1 1.
  • the controller can control the actuator so as to move the plunger,
  • the controller can use the measured fracturing flowrate from flow meter 1 16 or from the measured stroke rate of the pump 101 (assuming some efficiency coefficient) to determine the nanoparticle injection rate in order to achieve a certain nanoparticle concentration per unit volume of fracturing fluid. It will be appreciated by those skilled in the art, that certain tracer applications are very long time scale events, for example, months or years in the case of EOR, and nanoparticle injection will need to occur continuously or in slow periodic bursts whose timing is controlled and known.
  • nanoparticles are injected in bursts that can occur over shorter periods.
  • tracing for fracturing fluids during a fracturing job are over much shorter periods and as a result nanoparticles are injected in bursts that can occur over shorter periods.
  • nanoparticles that have different and unique DNA signatures into each fracture stage. This can be achieved by loading different cartridges or nanoparticle fluids into cylinder, 1 1 1 , after each stage is fractured and before the next one is started. Different DNA signature nanoparticles fluids could equally be placed in sample tank, 106, between fracturing stages.
  • each fracture stage can be traced with unique DNA signature particles and the controlled capture and analysis of these particles once the well starts to flow will allow the quantification of the efficiency of each fracture stage.
  • figure 1 it is shown that the two different nanoparticle injection systems; one using the sample tank 106 and the other using the injection cylinder, 1 1 1 , are repeated as illustrated in the dashed box 1 17, on the high pressure side of the pump 101. This is to illustrate that these components could be placed downstream of the pump in which case the nanoparticles would not need to pass through the pump.
  • the preferred embodiment is as described above where the injection occurs on the low pressure side of the pump 101. In this case, the injection system is exposed to much lower pressures and can be more easily manufactured.
  • the fracturing fluid is loaded with proppant.
  • proppant is used to deliver the nanoparticles into the well and into the fractures.
  • other materials that are pumped into a well for example, gravel used in a gravel pack operation or any other material that is moveable and will be pumped into the well or fractures, can equally be used to deliver nanoparticles into the flow system.
  • the particle, 200 is coated with a material, 201, that dissolves or degrades in a predefined fashion when it comes into contact with a predefined fluid.
  • the coating, 201 can be manufactured from oil-soluble resins or waxes with tuned melting temperatures or other classes of chemicals that will dissolve in hydrocarbon.
  • oil-soluble resins for example is beneficial because they will not break down under the harsh temperature and pressure environment found in oil wells but will only dissolve/disintegrate when they come into contact with hydrocarbons such as oil.
  • Nanoparticles, 202 are embedded in the coating material, 201 during the manufacturing processes so that the proppant particle 200 is thus coated with a nanoparticle laden material 201.
  • the nanoparticles will in turn encapsulate or have embedded in them DNA of a known and unique signature as disclosed in GB2489714 and PCT/EP2012/056230.
  • FIG 2a when the fluid, 203, in which the coating, 201 , dissolves flows past the proppant particle, the nanoparticles 202 are released and will flow to surface where they are captured and analysed.
  • the proppant particle remains in the well or formation or it may move as a result of the flow 203.
  • the nanoparticles, 202, released are captured at surface as described in other embodiments of this invention, !n figure 2b, there is shown schematically proppant particles 200 that are coated in different materials 201 or 203. These coatings have nanoparticles 202 and 204 respectively, embedded within them. In addition, these nanoparticles have different unique DNA signatures.
  • the coatings 201 and 203 will dissolve or degrade in different fluids, for example, 203 could consist of for example, hydrocarbon waxes chosen such that their glass transition temperature is well below the maximum temperature that will be encountered during the process/operation and will dissolve in hydrocarbon and 201 can be made of, for example, polylactic acid or other water soluble polymers such as partially hydrolysed polyacrylamides or polyethylene oxide and will dissolve or degrade in water.
  • a first fluid, 205 for example, hydrocarbon flows over the proppant particles and releases the nanoparticles 204 that will flow to surface entrained in the hydrocarbon. At this time the coating 201 remains intact.
  • a different fluid, 206 for example, formation or injected water flows through the proppant particles and dissolves the coating 201 to release nanoparticles 202 which will flow to surface in the water (or likely oil/water mixture) where they can be captured.
  • coatings 201 or 203 each with its own unique DNA particles can be utilised.
  • different fractures can have particles coated with 201 and/or 203 but with unique DNA nanoparticles that distinguish them from other fractures in the same well.
  • the nanoparticles released and captured at surface will provide the information to establish exactly what fluid is flowing and from which fracture.
  • nanoparticles can be encapsulated embedded in larger capsules whose crash strength is such that they readily break when compressed between the proppant on closure of the fracture (for example the hydrocellulosic materials used to encapsulate gel fluid breakers in fracturing operations).
  • FIG. 2c Another embodiment is schematically illustrated in figure 2c.
  • a proppant particle, 200 is first coated with a material 201 that has nanoparticles 202 embedded within it. It is then coated with a second material, 203, that has different and unique other nanoparticles, 204, embedded within it. The nanoparticles 202 and 204 will have different DNA signatures embedded with them making them unique.
  • a first fluid 205 flows through the proppant, for example, hydrocarbon, which dissolves or degrades the outer coating 203 and thus releases nanoparticles 204.
  • the capture and analysis of nanoparticles 204 at surface is a unique indication that fluid 205 has flowed past the proppant, 200, wherever it may be initially placed within the well or fracture sequences.
  • the coating 201 that does not react with fluid 205 remains intact.
  • a different fluid 206 for example, formation or injected water, flows through the proppant and dissolves or degrades the coating 201 and so releases the nanoparticles 202 into the water (or oil/water) flow. These particles are returned to surface in this flow where they can be captured and analysed.
  • fracturing fluids can be water based and without this double layer system the water soluble coating may be dissolved during the proppant pumping operation, that is, long before the well starts to produce water.
  • Another aspect of this invention is the controlled capture o nanoparticles as they return to surface in the flow from the well.
  • Related embodiments are now described with reference to figures 3, 4 and 5.
  • Figure 3 shows return flow from fractures 102 generated in the formation as a result of a fracturing operation.
  • the flow returns to surface fiowline 303 via the well 100.
  • a flowmeter 314 is provided that gives a measure of the rate at which fluid is returning from the well 100.
  • a fracturing operation is used to illustrate the various embodiments of this invention but other operations such as EOR are well known to those skilled in the art and are equally encompassed in this invention.
  • EOR the returning flow will be oil and gas swept to the producing well, 100, by water injected in an offset well or wells, not shown.
  • nanoparticle detection unit 301 is an inline spectrometer that uses spectral absorption or reflection to identify characteristic signatures that represent the presences of nanoparticles of a particular size within the flow.
  • the nanoparticles are injected in a carrier fluid, for example, a dye or a fluid that fluoresces at a particular wavelength, as explained in other embodiments of this invention, and the detection unit 301 detects the dye or fluorescence by interrogating the fluid as it flows through the unit, for example, by use of electromagnetic waves at a particular wavelength or selection of wavelengths.
  • a carrier fluid for example, a dye or a fluid that fluoresces at a particular wavelength
  • 301 contains a tab as schematically illustrated in figure 5.
  • the returning flow from the well, 501 contains nanoparticles 502.
  • the nanoparticles, 502 have surface properties to comprise cw-diol or alpha-hydroxy acid groups protruding from the outer surface.
  • the collection tab in 301, 503, has a mesh, which is coated with boron acid moiety (for example, phenylboronic acid, benzoboroxole etc).
  • boron acid moiety for example, phenylboronic acid, benzoboroxole etc.
  • the surface of the collection tab 301 , 503, forming a recovery element includes a first chemical moiety adapted to bind chemically to a complementary second chemical moiety located in at least the outer surface of the tracer nanoparticle.
  • the first or second chemical moiety may comprise at least one of a boron acid or a derivative thereof, for example phenylboronic acid or benzoboroxole or a mixture thereof.
  • the first or second chemical moiety may comprise at least one hydroxyl moiety, for example the at least one hydroxyl moiety is present in at least one of a diol or ew-diol moiety and an alpha-hydroxy acid moiety or a mixture thereof.
  • the first or second chemical moiety may comprise at least one protein, for example streptavidin, biotin, protein A or any mixture thereof.
  • the first or second chemical moiety may comprise at least one antibody, for example an immunoglobulin G antibody.
  • an electric property of the tab is modified as the number of captured nanoparticles is increases. For example, if the tab is initially of low conductance its resistance decreases as the captured nanoparticles provide an increasing current path. Or if the tab comprise multiple layers, the capacitance across these layers changes as the number of nanoparticles captured increases. The change of electric property is measured by means of an appropriated electronic circuit, 505, that is not detailed but is readily appreciated by someone skilled in the art.
  • the tab can be interrogated by, for example, electromagnetic waves of a given wavelength as illustrated by 506 in figure 5.
  • the resulting reflected or transmitted waves 507 can be used to determine, for example, the degree of fluorescence or colour change of the tab which in turn is an indication of the number of (or change in the number of) nanoparticles stuck to or the loading of nanoparticles on the tab.
  • the measured change in property or nanoparticle loading is provided to the controller 305 as shown in figures 3 and 4, and the controller can be configured to trigger the action as will be described later with reference to figure 3 or alternatively it could simply inform the operator that nanoparticles have been detected or the tab is now loaded with nanoparticles so it should be removed and replaced as illustrated in figure 4.
  • the tab can be treated as disclosed in GB2489714 and PCT/FJP2012/056230, to release and break the nanoparticles to release the enclosed DNA for analysis by means known to those skilled in the art, for example, qPCR.
  • the DNA characterisation and signature matching is achieved using a handheld technology as provided by Bio-Nems. see www.bio-nems.com. Further, providing a means for such a handheld device to take the tab directly, release the nanoparticles, break the nanoparticles to release the DNA and carryout the DNA analysis is preferred.
  • the chemical tab described above can be replaced by a magnet, magnetic tab or magnetic separator to capture and detect magnetically-tagged nanoparticles.
  • This approach uses a physical property rather than a chemical characteristic of the particle to aid detection and measurement and those skilled in the art will appreciate that tags exploiting other physical properties can also be used for this purpose.
  • FIG 3 the detection of nanoparticles by 301, is used to trigger the collection of a sample or samples.
  • the controller 305 is provided to use such measurements and carryout the required actions.
  • a sampling cylinder 306 is provided to act as a syringe to draw a sample from flowline 303.
  • the controller will open valve 309 and instructing the actuator 308 that is attached to the plunger 307, to draw a sample from the flowline 303 into the cylindrical chamber 306.
  • a non-retum valve 310 is provided to prevent flow from returning back into flowline 303.
  • the plunger controller 308 can be actuated on order to take a certain sample volume and at a certain rate.
  • This rate and volume can be controlled using a measure of the flow rate from the well, 314, so as to achieve a certain volume rate per unit volume of flow from the well. Or it could be controlled by the nanoparticle concentration rate as provided by 301 and 314 combined.
  • the controller 305 can instruct to open a valve 312, in order to allow flow into a sample bottle 313.
  • the cylindrical chamber 306 contains a cartridge that is filled and is removed and replaced with an empty cartridge manually.
  • the plunger controller 308 is instructed to push the plunger 307 downwards and thus push the sample out of the chamber 306, through the non-return valve 311 and into the selected bottle 313. It will be understood by those skilled in the art that different arrangements of valves and flow networks can be used to achieve that same technical effect and all are encompassed in this invention.
  • a particle collection tab (chemical or physical/magnetic), as described earlier and schematically shown in figure 5, can be placed inline with a sample bottle as illustrated by 315 in figure 3.
  • a sample bottle as illustrated by 315 in figure 3.
  • controller 305 can be the same controller 105, described in other embodiments of this invention as schematically illustrated in figures 1 or the controllers 105 and 305 could be linked in order to share information.
  • both the nanoparticle injection profiles and the nanoparticle collection profiles can be controlled so that both are by design and in accordance with one another.
  • we consider an EOR operation where water is continually injected into a reservoir in order to sweep oil towards a production well. This water can be injected through a network of wells that surround the production well. This is schematically illustrated in figure 6a where a plan view of a single production well, 600, is shown surrounded by hexagonal array of injection wells 601.
  • Each injection well may be operated independently and water may be continually pumped into it at some predefined rate. As water is injected into all six wells, oil is pushed towards the production well 600 in the centre. Those skilled in the art will be familiar this method of EOR and will also appreciate that the number and location of injection and production wells will vary depending on specific reservoir conditions.
  • nanoparticle injection profiles 603 and 606 are shown that may be applied in two different injection wells.
  • the other injection wells may also have nanoparticle injection profiles but these are not shown.
  • the profile 603 represents nanoparticles injected into this injected water as described in other embodiments of this invention.
  • the nanoparticle injection profile is controlled by the controller 105, and a pulse of nanoparticles with a concentration and duration represented by the height and width of 604, respectively, is injected into the injected water.
  • the nanoparticle pulses are repeated at a regular interval of 605. As an example, a pulse of 6 hours duration could be repeated every 10 days.
  • each pulse of nanoparticles 604 will contain DNA signatures that are unique and different thus uniquely identifying each and every pulse.
  • a second nanoparticle injection profile, 606 is shown to illustrate that profiles of different concentration, duration and/or interval may be applied to a different injection well, 602, and the other injection wells may have other different profiles that are not shown.
  • each nanoparticle injection pulse can comprise a 'carrier' fluid that is readily detected as described in other embodiments.
  • the same carrier fluid e.g., a particular dye
  • the carrier simply provides an indication to the sampling system that a sample (or samples) should be taken as describe in other embodiments.
  • a nanoparticle capture tab could also be used to the same effect.
  • FIG. 6c shows a schematic illustration of a nanoparticle pulse profile, 607, captured in the flow from the production well 600.
  • the DNA signature within the nanoparticles can be used to identify from which injection well the nanoparticles came and indeed can indicate the exact nanoparticle injection pulse. Therefore, the injection profile, for example, 603, can be compared to the capture profile 607.
  • important information relating to the flow of fluid through the reservoir between wells 601 and 600 can be determined.
  • the time between the pulses 604 and 608 will provide the transit time for the fluid through the reservoir.
  • the width of pulse 608 as compared to 604 can be related to the dispersion within the reservoir.
  • Such comparisons contain important information about a number of reservoir characteristics such as permeability, relative permeability, absorption behaviour, distribution of fluid flow paths etc.
  • the change in pulse interval 605 to 609 can provide information related to the change in transit time as the flow changes from mostly oil to mostly water. This is because ahead of pulse 608 it is oil that is primarily flowing but between 608 and 610 the amount of water is increasing.
  • Samples taken during pulse 608, 610 and future pulses can be analysed to determine changes in the oil/water ratio and this change can be determined with time and provide important information about relative permeability characteristics.
  • the injection controller 105 can be instructed to change, for example, the nanoparticle pulse interval period into well 601 as a result of information obtained from the capture profile 607.
  • water injection rates into the wells 601 may be adjusted to improve the overall oil sweep efficiency.
  • This information can also be used to trigger or define the sampling characteristics, for example, the sampling frequency or duration.
  • This granularity of reservoir calibrations is not possible with the technology available today but is possible through the embodiments described herein because of the flexibility of control of both the nanoparticle tracer injection and capture systems.

Landscapes

  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Physics & Mathematics (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Chemical & Material Sciences (AREA)
  • Geophysics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Materials Engineering (AREA)
  • Organic Chemistry (AREA)
  • Measuring Or Testing Involving Enzymes Or Micro-Organisms (AREA)
  • Investigating, Analyzing Materials By Fluorescence Or Luminescence (AREA)

Abstract

La présente invention concerne une particule de marquage destinée à être utilisée dans l'exploration, la production, le transport et/ou le stockage de pétrole et/ou de gaz, ladite particule de marquage comprenant un agent de soutènement, une couche de revêtement entourant au moins en partie l'agent de soutènement et une substance de marquage à l'intérieur de ladite couche de revêtement, ladite substance de marquage ayant un ADN identifiable. L'invention concerne également une nanoparticule de marquage destinée à être utilisée dans l'exploration, la production, le transport et/ou le stockage de pétrole et/ou de gaz, ladite nanoparticule de marquage comprenant une substance de marquage ayant un ADN identifiable, et au moins une fraction chimique située dans au moins une surface externe de ladite nanoparticule de marquage, ladite fraction chimique comprenant au moins une protéine, au moins un anticorps, et/ou au moins une fraction hydroxyle. L'invention concerne en outre des procédés et un appareil de marquage de fluide au cours de l'exploration, de la production, du transport et/ou du stockage de pétrole et/ou de gaz.
PCT/EP2015/067432 2014-07-30 2015-07-29 Système d'identification de fluide Ceased WO2016016335A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
GB1413478.7A GB2528716B (en) 2014-07-30 2014-07-30 Fluid identification system
GB1413478.7 2014-07-30

Publications (1)

Publication Number Publication Date
WO2016016335A1 true WO2016016335A1 (fr) 2016-02-04

Family

ID=51587450

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/EP2015/067432 Ceased WO2016016335A1 (fr) 2014-07-30 2015-07-29 Système d'identification de fluide

Country Status (2)

Country Link
GB (1) GB2528716B (fr)
WO (1) WO2016016335A1 (fr)

Cited By (12)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2018148853A1 (fr) * 2017-02-15 2018-08-23 BLANCO GRANDI , Sergio Mario Dispositif de prélèvement non intrusif d'échantillons génétiques
EP3434786A1 (fr) * 2017-07-28 2019-01-30 FRAUNHOFER-GESELLSCHAFT zur Förderung der angewandten Forschung e.V. Procédé de fabrication et d'authentification infalsifiable d'un produit médical à l'aide d'un acide nucléique à séquence partielle connue
CN111139053A (zh) * 2018-11-06 2020-05-12 中国石油化工股份有限公司 一种纳米二氧化硅有机硼交联剂及其制备方法
CN111139052A (zh) * 2018-11-06 2020-05-12 中国石油化工股份有限公司 一种低浓度的羟丙基胍胶压裂液及制备方法
WO2020185344A1 (fr) * 2019-03-08 2020-09-17 Multi-Chem Group, Llc Suivi de la production par application de traceurs solubles sur une particule solide
US11237295B1 (en) 2020-10-13 2022-02-01 Saudi Arabian Oil Company Method for intelligent automatic rock fragments depth determination while drilling
US20220065101A1 (en) * 2020-09-03 2022-03-03 Saudi Arabian Oil Company Injecting multiple tracer tag fluids into a wellbore
CN115306376A (zh) * 2021-05-08 2022-11-08 中国石油天然气股份有限公司 油气井压裂监测试剂、方法及其应用
CN115961940A (zh) * 2022-08-04 2023-04-14 成都理工大学 一种DNA@SiO2示踪剂的应用方法及模拟样品柱
US11719092B2 (en) 2020-10-13 2023-08-08 Saudi Arabian Oil Company Systems and methods for drilling a wellbore using taggant analysis
US11760925B1 (en) 2022-03-07 2023-09-19 Core Laboratories Lp Oligonucleotide-containing tracer particles for subterranean applications
WO2024064139A1 (fr) * 2022-09-21 2024-03-28 Saudi Arabian Oil Company Structures organiques covalentes utilisées en tant que traceurs pour l'imagerie par fluorescence en amont

Families Citing this family (12)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US10106727B2 (en) * 2014-09-17 2018-10-23 National Technology & Engineering Solutions Of Sandia, Llc Proppant compositions and methods of use
US10871066B1 (en) 2014-09-17 2020-12-22 National Technology & Engineering Solutions Of Sandia, Llc Molecular tracers and modified proppants for monitoring underground fluid flows
WO2016169904A1 (fr) * 2015-04-20 2016-10-27 Eth Zurich Éléments de détection distribués particulaires
CN107795310B (zh) * 2016-09-07 2020-05-15 中国石油化工股份有限公司 水平井分段压裂效果长期实时跟踪方法
CN107385043A (zh) * 2017-07-31 2017-11-24 天津大学 包含有环状dna的水土环境污染物示踪剂及制备方法
CN107385045A (zh) * 2017-07-31 2017-11-24 天津大学 包含有链状dna的水土环境污染物示踪剂及制备方法
CN112300767B (zh) * 2020-09-22 2022-04-05 山东大学 一种绿色靶向微胶囊及制备体系、制备方法和应用
CN112480902B (zh) * 2020-11-26 2023-03-28 四川省帕提科斯能源科技有限公司 一种智能包封酸及使用方法
US12000278B2 (en) * 2021-12-16 2024-06-04 Saudi Arabian Oil Company Determining oil and water production rates in multiple production zones from a single production well
CN116413475B (zh) * 2021-12-30 2025-08-12 中国石油天然气股份有限公司 一种天然气管道内流场示踪粒子加注装置及加注方法
US12331632B2 (en) 2023-05-15 2025-06-17 Saudi Arabian Oil Company Analyzing hydrocarbon flow into multi-lateral wells by releasing tracers from the surface
US12305504B2 (en) 2023-10-19 2025-05-20 Saudi Arabian Oil Company Quantifying zonal flow in multi-lateral wells via taggants of fluids

Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5665538A (en) * 1990-05-04 1997-09-09 Slater; James Howard Ultrasensitive microtrace procedure for monitoring the origin of a material
WO2007132137A1 (fr) * 2006-05-17 2007-11-22 Schlumberger Technology B.V. Procédés et systèmes pour l'évaluation de réservoirs d'hydrocarbures et fluides associés utilisant des marqueurs biologiques et une pcr en temps réel
US20100258743A1 (en) * 2009-04-13 2010-10-14 Src, Inc. Location Analysis Using Nucleic Acid-Labeled Tags
GB2489714A (en) * 2011-04-05 2012-10-10 Tracesa Ltd Fluid identification system comprising encapsulated DNA
WO2014144464A2 (fr) * 2013-03-15 2014-09-18 Carbo Ceramics Inc. Composition et procédé de fracturation hydraulique et évaluation et diagnostics de fractures hydrauliques à l'aide d'un agent de soutènement céramique poreux infusé

Family Cites Families (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9290689B2 (en) * 2009-06-03 2016-03-22 Schlumberger Technology Corporation Use of encapsulated tracers

Patent Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5665538A (en) * 1990-05-04 1997-09-09 Slater; James Howard Ultrasensitive microtrace procedure for monitoring the origin of a material
WO2007132137A1 (fr) * 2006-05-17 2007-11-22 Schlumberger Technology B.V. Procédés et systèmes pour l'évaluation de réservoirs d'hydrocarbures et fluides associés utilisant des marqueurs biologiques et une pcr en temps réel
US20100258743A1 (en) * 2009-04-13 2010-10-14 Src, Inc. Location Analysis Using Nucleic Acid-Labeled Tags
GB2489714A (en) * 2011-04-05 2012-10-10 Tracesa Ltd Fluid identification system comprising encapsulated DNA
WO2012136734A1 (fr) * 2011-04-05 2012-10-11 Tracesa Ltd. Système d'identification d'un fluide, sa fabrication et son utilisation
WO2014144464A2 (fr) * 2013-03-15 2014-09-18 Carbo Ceramics Inc. Composition et procédé de fracturation hydraulique et évaluation et diagnostics de fractures hydrauliques à l'aide d'un agent de soutènement céramique poreux infusé

Cited By (17)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2018148853A1 (fr) * 2017-02-15 2018-08-23 BLANCO GRANDI , Sergio Mario Dispositif de prélèvement non intrusif d'échantillons génétiques
EP3434786A1 (fr) * 2017-07-28 2019-01-30 FRAUNHOFER-GESELLSCHAFT zur Förderung der angewandten Forschung e.V. Procédé de fabrication et d'authentification infalsifiable d'un produit médical à l'aide d'un acide nucléique à séquence partielle connue
CN111139053B (zh) * 2018-11-06 2022-05-13 中国石油化工股份有限公司 一种纳米二氧化硅有机硼交联剂及其制备方法
CN111139053A (zh) * 2018-11-06 2020-05-12 中国石油化工股份有限公司 一种纳米二氧化硅有机硼交联剂及其制备方法
CN111139052A (zh) * 2018-11-06 2020-05-12 中国石油化工股份有限公司 一种低浓度的羟丙基胍胶压裂液及制备方法
CN111139052B (zh) * 2018-11-06 2022-06-10 中国石油化工股份有限公司 一种低浓度的羟丙基胍胶压裂液及制备方法
WO2020185344A1 (fr) * 2019-03-08 2020-09-17 Multi-Chem Group, Llc Suivi de la production par application de traceurs solubles sur une particule solide
US10961445B2 (en) 2019-03-08 2021-03-30 Multi-Chem Group, Llc Tracking production of oil, gas, and water from subterranean formation by adding soluble tracers coated onto solid particulate
US20220065101A1 (en) * 2020-09-03 2022-03-03 Saudi Arabian Oil Company Injecting multiple tracer tag fluids into a wellbore
US11773715B2 (en) * 2020-09-03 2023-10-03 Saudi Arabian Oil Company Injecting multiple tracer tag fluids into a wellbore
US12203362B2 (en) 2020-09-03 2025-01-21 Saudi Arabian Oil Company Injecting multiple tracer tag fluids into a wellbore
US11237295B1 (en) 2020-10-13 2022-02-01 Saudi Arabian Oil Company Method for intelligent automatic rock fragments depth determination while drilling
US11719092B2 (en) 2020-10-13 2023-08-08 Saudi Arabian Oil Company Systems and methods for drilling a wellbore using taggant analysis
CN115306376A (zh) * 2021-05-08 2022-11-08 中国石油天然气股份有限公司 油气井压裂监测试剂、方法及其应用
US11760925B1 (en) 2022-03-07 2023-09-19 Core Laboratories Lp Oligonucleotide-containing tracer particles for subterranean applications
CN115961940A (zh) * 2022-08-04 2023-04-14 成都理工大学 一种DNA@SiO2示踪剂的应用方法及模拟样品柱
WO2024064139A1 (fr) * 2022-09-21 2024-03-28 Saudi Arabian Oil Company Structures organiques covalentes utilisées en tant que traceurs pour l'imagerie par fluorescence en amont

Also Published As

Publication number Publication date
GB2528716A (en) 2016-02-03
GB2528716B (en) 2017-07-19
GB201413478D0 (en) 2014-09-10

Similar Documents

Publication Publication Date Title
WO2016016335A1 (fr) Système d'identification de fluide
CN110805432A (zh) 一种采用量子点示踪剂测试水平井产液剖面的方法
US5441110A (en) System and method for monitoring fracture growth during hydraulic fracture treatment
GB2489714A (en) Fluid identification system comprising encapsulated DNA
US9464512B2 (en) Methods for fluid monitoring in a subterranean formation using one or more integrated computational elements
US20090087912A1 (en) Tagged particles for downhole application
US20130032338A1 (en) Methods for Fluid Monitoring in a Subterranean Formation Using One or More Integrated Computational Elements
US20090151939A1 (en) Surface tagging system with wired tubulars
US10400584B2 (en) Methods and systems for monitoring a subterranean formation and wellbore production
CN104018822A (zh) 一种油井分段压裂效果监测方法
RU2482272C2 (ru) Способ контроля за разработкой месторождения углеводородов
US8674290B2 (en) Method for monitoring or tracing operations in well boreholes
WO2013165780A1 (fr) Outils à capture de neutrons pulsés utilisés pour localiser un agent de soutènement au voisinage d'un trou de forage
WO2014104914A1 (fr) Procédé de commande de développement de champ d'hydrocarbures
US20140251600A1 (en) Encapsulated microsensors for reservoir interrogation
RU2544923C1 (ru) Способ мониторинга добывающих или нагнетательных горизонтальных или наклонно направленных скважин
Ghergut et al. Tracer-based quantification of individual frac discharge in single-well multiple-frac backflow: sensitivity study
RU2685601C1 (ru) Способ определения дебитов воды, нефти, газа
US20230279770A1 (en) Method of using an ultrahigh resolution nanoparticle tracer additive in a wellbore, hydraulic fractures and subsurface reservoir
US12025001B2 (en) Method of using a dissolvable deployment device for the transfer of ultrahigh resolution nanoparticle tracer additives into a wellbore
CA3223366A1 (fr) Appareil et methodes pour utiliser des particules colloidales pour caracteriser des traitements de fracturation
WO2015040042A1 (fr) Détection d'une zone asséchée dans une complétion segmentée
US20250075617A1 (en) Method of using non-magnetic solid tracers
US12460541B2 (en) Method of using a perforator device for the transfer of nanoparticle tracer additives into a formation and cluster level flow mapping
US20240410274A1 (en) Methods and materials for monitoring stimulation effectiveness

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 15744211

Country of ref document: EP

Kind code of ref document: A1

NENP Non-entry into the national phase

Ref country code: DE

122 Ep: pct application non-entry in european phase

Ref document number: 15744211

Country of ref document: EP

Kind code of ref document: A1