Method and system for characterising fractures

Abstract

The invention provides a method of interpretating nanoparticle tracer data to characterise at least one stage fracture in a well. The method may comprise forming at least one stage fracture in the well and injecting at least one nanoparticle tracer into the at least one stage fracture. The method may comprise collecting samples of produced fluid and analysing tracer concentrations and estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the tracer concentrations.

Description

[0001] METHOD AND SYSTEM FOR CHARACTERISING FRACTURES

[0002] The present invention relates to the monitoring and characterisation of subterranean fractures. In particular, the present invention relates to characterisation of fracturing performed during the formation of hydrocarbon production wells, geothermal wells or enhanced geothermal systems. Aspects of the invention relate to methods of interpreting fluid flow characteristics.

[0003] Background to the invention

[0004] The efficient recovery of hydrocarbons from a reservoir is a difficult and complex process which requires an understanding of the flow conditions of the hydrocarbons in the reservoir, formation and connected wells. Similarly, the efficient extraction of heat from geothermal wells or enhanced geothermal systems (EGS) where hydraulic fractures connect injection and production wells requires understanding of the flow conditions of injected fluids.

[0005] Well stimulation techniques use mechanical or chemical methods to artificially create channels such as fractures in the formation which may facilitate the flow of fluids in order to extract economically viable quantities of hydrocarbon from formations with low flow characteristics. Well stimulation techniques include fracturing, acidizing and fracture acidizing methods.

[0006] Fracturing is a method which involves pumping a large volume of fracturing liquid, typically water, from a well into a formation, causing cracks in the formation enabling the flow of fluids through the cracks to extract the hydrocarbon or pass fluids through the formation. The cracks are filled with a supporting material called proppant to prevent the cracks from closing.

[0007] In order to maximise energy output of a geothermal system or maximise contact between a hydrocarbon reservoir and a production well it is important to understand the geometry and fluid connections of the fractures from the well.Summary of the invention

[0008] It is amongst the aims and objects of the invention to provide a system and method which obviates or mitigates one or more drawbacks or disadvantages of the prior art subterranean fractures characterisation methods.

[0009] It is object of an aspect of the invention to provide a method and system for characterising fractures in and / or from a well.

[0010] It is another object of the present invention to provide a method of assessing or characterising changes in flow profiles of fractures.

[0011] Further aims and objects of the invention will become apparent from reading the following description.

[0012] According to a first aspect of the invention, there is provided a method of characterising at least one stage fracture in a well; the method comprising

[0013] forming at least one stage fracture in the well;

[0014] injecting at least one nanoparticle tracer into the at least one stage fracture;

[0015] collecting samples of produced fluid and analysing tracer concentrations;

[0016] estimating or calculating at least one condition and / or characteristic of the at least one fracture from the analysis of the tracer concentrations.

[0017] The method may comprise characterising at least one stage fracture in a well combination. The well combination may comprise at least one injector well and at least one production well. The method may comprise forming at least one stage fracture from a first well of the well combination to a second well. The method may comprise characterising at least one stage fracture in a well combination comprising at least one production well. The method may comprise forming at least one stage fracture from a first well into a formation and / or a reservoir. The method may comprise forming at least one stage fracture in a production well and producing fluid from the first well. The method may comprise forming at least one stage fracture in a first well and producing fluid from the first well. The method may comprise characterising two or more stages fractures. The method may comprise characterising two or more stages fractures by injecting at least one distinct nanoparticle tracer into each stage fracture. The method may comprise forming two or more stage fractures. The method may comprise injecting at least one nanoparticle tracer into at least one stage fracture. Themethod may comprise injecting at least one distinct nanoparticle tracer into each of the two or more stage fractures. The method may comprise injecting two or more distinct nanoparticle tracers into each of the two or more stage fractures. The method may comprise characterising multiple stages fractures in or from a well. The method may comprise forming multiple stage fractures in or from a well. The method may comprise injecting at least one nanoparticle tracer into at least one stage fracture. The method may comprise injecting at least one distinct nanoparticle tracer into each of the multiple stage fractures. The method may comprise injecting two or more distinct nanoparticle tracers into each of the multiple stage fractures.

[0018] The well combination may be a geothermal well. The well combination may be an enhanced geothermal system. The well combination may be a hydrocarbon well. The well combination may be an unconventional well. The method may comprise analysing tracer concentrations with respect to sampling time. The method may comprise introducing the at least one nanoparticle tracer into the at least one stage fracture with a well treatment. The method may comprise introducing the at least one nanoparticle tracer into the at least one stage fracture with a well treatment. The method may comprise injecting at least one distinct nanoparticle tracer into each stage fracture. The method may comprise injecting at least one distinct nanoparticle tracer into each stage fracture. The method may comprise introducing at least one distinct nanoparticle tracer into a well before and / or with the well treatment. The method may comprise introducing at least one distinct nanoparticle tracer into a well at an early portion of the well treatment. The method may comprise introducing two or more distinct nanoparticle tracers into a stage fracture. The method may comprise introducing two or more distinct nanoparticle tracers with a well treatment to create a stage fracture. The method may comprise introducing at least one distinct nanoparticle tracer into a well at a later stage fracture or later well treatment to create a later stage fracture. The method may comprise introducing at least one distinct nanoparticle tracer into a well before and / or with a first well treatment to create or develop a first stage fracture. The method may comprise introducing at least one distinct nanoparticle tracer into a well before and / or with a second well treatment to create or develop a second stage fracture. The method may comprise a multistage well treatment operation. The method may comprise introducing at least two distinct nanoparticle tracers per treatment stage in a multistage operation. The method may comprise introducing each of the distinct nanoparticle tracers into the well by injecting the tracer into the well from surface and / or from a downhole device. The at least one distinct nanoparticle tracer may be installed, arranged or positioned in the well. The method may comprise introducing the at least one distinct nanoparticle tracer into the well by releasingthe nanoparticle tracer from at least one installed, arranged or positioned tracer source in the well. The at least one nanoparticle tracer may be a solid tracer. Each of the at least one nanoparticle tracer may be distinct or different to one another. Each of the two or more nanoparticle tracers may be distinct or different to one another. The at least one nanoparticle tracer may have a diameter size in the range of 0.01 pm to 100 pm (microns). The at least one nanoparticle tracer may have a diameter size in the range of 0.1 pm to 10 pm (microns). The at least one nanoparticle tracer may be detected and / or measured using techniques selected from the group comprising optical detection, optical fibers, spectrophotometric methods, spectrometric methods, fluorescence, radioactivity analysis, x-ray diffraction (XRD), neutron scattering, chromatography and / or electrophoresis.

[0019] The at least one nanoparticle tracer may be pumped or injected into the at least one stage fracture with a treatment such as proppant particles or fluid loss particles. The method may comprise introducing at least one nanoparticle tracer into the well or fracture with a slurry. The at least nanoparticle tracer may be a component or mixed with a pre-acid slurry and / or composition. The method may comprise introducing the at least one nanoparticle tracer into the well and / or at least one fracture with a treatment fluid. The method may comprise introducing at least one nanoparticle tracer into the well and / or at least one fracture with an acid fluid. The method may comprise introducing at least one nanoparticle tracer into the well and / or at least one fracture with a pad fluid. The method may comprise introducing at least one nanoparticle tracer into the well and / or fracture with a fracturing fluid. The method may comprise introducing at least one nanoparticle tracer into the well and / or fracture with a flush fluid or a post fracturing fluid.

[0020] The method may comprise comparing the presence and / or concentration of the at least one distinct nanoparticle tracer produced from the individual stage fractures. The method may comprise assessing flow quality and / or flow characteristics through or from the at least one fracture based on a comparison of the presence and / or concentration of the at least one distinct nanoparticle tracer and / or at least one distinct chemical tracer produced from each individual stage fracture. The method may comprise estimating fracture characteristics based on a comparison of the presence and / or concentration of the at least one distinct nanoparticle tracer and / or at least one distinct chemical tracer produced from each individual stage fracture. The method may comprise quantifying or estimating flow contributions from each stage based on a comparison of the presence and / or concentration of the at least one distinct nanoparticle tracer and / or at least one distinct chemical tracer associated with each individual stage in the collected samples. The flow contributions from each fracture stagemay be based on a nanoparticle tracer response interpretation. The flow contributions from each fracture stage may be based on a nanoparticle tracer response interpretation and / or a chemical tracer response interpretation.

[0021] The method may comprise calculating or estimating a representative velocity (apparent velocity) for each stage of a multistage fracture. The representative velocity (apparent velocity) may be based on the respective average of the velocity allocation per fracture stage. The method may comprise calculating or estimating a relative velocity based on a ratio of measured concentration of each distinct nanoparticle tracer produced from each fracture being proportional to the ratio of velocities in the fractures contributing to the produced flow. The relative velocity may be based on a nanoparticle tracer response data interpretation. The average relative velocity may be a mean average per fracture stage. The method may comprise calculating or estimating a relative velocity for each stage of a multistage fracture. The relative velocity may be based on a ratio of the respective calculated representative velocity and the average representative velocity. The method may comprise interpreting an apparent velocity of each fracture stage based an appropriate governing equation such as Stokes’ Law for the flow regime if dependent on Reynolds number. The method may comprise calculating or estimating a relative cross-sectional area to flow for the at least one fracture. The method may comprise calculating or estimating a relative cross-sectional area based on the relative aperture, width and porosity. The method may comprise calculating or estimating a relative cross-sectional area may be calculated based on a ratio of flow rate and velocity, based on nanoparticle tracer response interpretation and / or a chemical tracer response interpretation. The method may comprise estimating or calculating a relative aperture of each fracture stage based on a respective calculated flow rate allocation and relative velocity of each fracture. The method may comprise estimating or calculating a relative aperture of each fracture stage based on a relative cross-sectional area to flow. The method may comprise estimating or calculating a relative aperture of each fracture stage based on a relative cross-sectional area to flow and microseismic data and / or mass balance data.

[0022] The method may may comprise estimating or calculating at least one condition and / or characteristic of the fracture selected from the group comprising plugging, convective jamming, deep-bed filtration, stagnation points, tortious flow paths, fracture aperture, dynamic changes in fracture aperture, flow velocity, relative cross-sectional area, variations in flow velocity, relative velocity, apparent velocity, relative aperture and apparent aperture.The method may comprise adjusting or modifying at least one parameter and observing how the at least one nanoparticle tracer responds to the adjusted or modified at least one parameter. The method may comprise performing at least one interrogation step to adjust or modify at least one parameter. The at least one parameter may be selected from the group comprising nanoparticle tracer size, particle tracer density, nanoparticle tracer type, fluid viscosity, fluid density, injection rate, production rate and / or bottom hole pressure. The method may comprise injecting at least one fluid with a different viscosity and / or a different density into the at least one fracture. The method may comprise injecting two or more fluids each with a different viscosity and / or a different density into the at least one fracture. The method may comprise injecting at least one fluid with a different viscosity and / or a different density into each fracture. The method may comprise injecting two or more fluids each with a different viscosity and / or a different density into each fracture. The method may comprise calculating or estimating a fracture characteristic based on a nanoparticle tracer response to different fluid viscosities and / or a different fluid densities injected into each fracture.

[0023] The method may comprise calculating or estimating an apparent velocity based on a nanoparticle tracer response to different fluid viscosities and / or a different fluid densities injected into each fracture. The method may comprise estimating or calculating relative velocity and / or apparent velocity of each fracture stage based on nanoparticle tracer response data interpretation using fluids with a different viscosity and / or a different density. The method may comprise estimating or calculating relative aperture and / or apparent aperture of each fracture stage based on nanoparticle tracer response data interpretation using fluids with a different viscosity and / or a different density. The method may comprise adjusting or modifying a production flow rate. The method may comprise adjusting or modifying the production flow rate from a first production flow rate to at least a second production flow rate. The at least a second production flow rate may be higher or lower than the first production flow rate. The method may comprise adjusting or modifying a production flow rate to multiple different flow rates. The method may comprise calculating or estimating a relative velocity and / or apparent velocity based on a nanoparticle tracer response to different production flow rates. The method may comprise calculating or estimating a fracture characteristic based on a nanoparticle tracer response when the nanoparticle tracer size and / or density is varied. The method may comprise calculating or estimating an apparent velocity based on a nanoparticle tracer response using two or more nanoparticle tracers having different size and / or density injected into each fracture. The method may comprise estimating or calculating relative velocity and / or apparent velocity of each fracture stage based on nanoparticle tracer response data interpretation using two or more nanoparticletracers having different size and / or density injected into each fracture. The method may comprise estimating or calculating relative aperture and / or apparent aperture of each fracture stage based on nanoparticle tracer response data interpretation using two or more nanoparticle tracers having different size and / or density injected into each fracture.

[0024] The method may comprise measuring, estimating and / or calculating a flow rate of the at least one stage fracture. The method may comprise measuring, estimating and / or calculating a flow rate of each stage fracture. The method may comprise measuring, estimating and / or calculating a flow rate of the at least one stage fracture using production logging. The method may comprise measuring, estimating and / or calculating a flow rate of the at least one stage fracture using fibre optic measurement. The method may comprise measuring, estimating and / or calculating a flow rate of the at least one stage fracture using chemical production logging. The method may comprise measuring, estimating and / or calculating a flow rate of the at least one stage fracture using at least one chemical tracer. The flow rate allocation may be based on an interpretation of the chemical tracer data.

[0025] The method may comprise estimating or calculating at least one fracture geometry parameter based on the measured nanoparticle tracer data. The at least one fracture geometry parameter may be selected from the group comprising fracture aperture, representative aperture, apparent aperture, fracture velocity, representative velocity, apparent velocity, relative cross-sectional area, proppant stability and / or proppant pack porosity volume. Alternatively, or additionally, the at least one fracture geometry parameter may comprise a parameter estimated, calculated or simulated from fracture geometry information, for example using a hydraulic fracture simulator, microseismic data and / or mass balance data. The at least one fracture geometry parameter may comprise one or more of: hydraulic fracture surface area and / or propped fracture surface area.

[0026] The method may comprise injecting the at least one nanoparticle tracer into a fracture during forming of the fracture. The method may comprise injecting the at least one nanoparticle tracer into a fracture after the at least one fracture has been formed. The method may comprise injecting or releasing the at least one nanoparticle tracer into an injection fluid.

[0027] The at least one stage fracture may comprise at least one chemical tracer. The method may comprise injecting at least one distinct chemical tracer into the at least one stage fracture. The method may comprise introducing at least one chemical tracer into the at least one stage fracture with a well treatment. The method may comprise introducing at least onechemical tracer into the at least one stage fracture with a well treatment. The method may comprise injecting at least one distinct chemical tracer into each stage fracture. The method may comprise injecting at least one distinct chemical tracer into each stage fracture. The method may comprise introducing at least one distinct chemical tracer into a well before and / or with the well treatment. The method may comprise introducing at least one distinct chemical tracer into a well at an early portion of the well treatment. The method may comprise introducing two or more distinct chemical tracers into a stage fracture. The method may comprise introducing two or more distinct chemical tracers into each stage fracture. The method may comprise introducing two or more distinct chemical tracers with a well treatment to create a stage fracture. The method may comprise introducing at least one distinct chemical tracer into a well at a later stage fracture or later well treatment to create a later stage fracture. The method may comprise introducing at least one distinct chemical tracer into a well before and / or with a first well treatment to create or develop a first stage fracture. The method may comprise introducing at least one distinct chemical tracer into a well before and / or with a second well treatment to create or develop a second stage fracture. The method may comprise a multistage well treatment operation. The method may comprise characterising two or more stages fractures by injecting at least one distinct chemical tracer into each stage fracture. The method may comprise characterising multiple stages fractures in or from a well. The method may comprise forming multiple stage fractures in or from a well. The method may comprise injecting at least one chemical tracer into at least one stage fracture. The method may comprise injecting at least one distinct chemical tracer into each of the multiple stage fractures. The method may comprise injecting two or more distinct chemical tracers into each of the multiple stage fractures. The method may comprise introducing at least two distinct chemical tracers per treatment stage in a multistage operation. The method may comprise introducing each of the distinct chemical tracers into the well by injecting the tracer into the well from surface and / or from a downhole device. Each of the distinct chemical tracers may be installed, arranged or positioned in the well. The method may comprise introducing the at least one distinct chemical tracer into the well by releasing the chemical tracer from at least one installed, arranged or positioned tracer source in the well. Each of the distinct chemical tracer may be a liquid, solid or gas tracer.

[0028] The well combination may comprise at least one injector well and at least one production well. The well combination may comprise at least one stage fracture from a first well of the well combination to at least a second well. The method may comprise circulating fluid from a first well to the second well of the well combination via the at least one stage fracture. The method may comprise circulating fluid from a first well to the second well of the wellcombination via each stage fracture. The method may comprise back producing fluid in a first well and collecting samples of produced fluid and analysing tracer concentrations. The method may comprise back producing fluid from an injection well and collecting samples of produced fluid and analysing tracer concentrations.

[0029] The at least one chemical tracer may be infused or encapsulated in a polymer matrix. The at least one chemical tracer may be a powder or particulate made of chemical tracer infused or encapsulated in a polymer matrix. The at least one chemical tracer may be associated with, infused with proppant particles or fluid loss particles. The at least one chemical tracer may encapsulate proppant particles or fluid loss particles. The at least one chemical tracer or be encapsulated with proppant particles or fluid loss particles. The at least one chemical tracer may be configured to slowly release from particulates pumped with the treatment such as proppant particles or fluid loss particles. The at least one chemical tracer may be premixed with a well treatment fluid. The at least one chemical tracer may be added to the well treatment fluid. The at least one chemical tracer may be co-injected with a well treatment fluid. The at least one chemical tracer may be co-released with the well treatment fluid. The at least one chemical tracer may be an inflow tracer. The at least one chemical tracer may be an interwell tracer. The at least one chemical tracer may be in particulate form. Each of the two or more chemical tracers may be distinct or different to one another. Each of the two or more chemical tracers may be non-radioactive chemical tracer. The method may comprise introducing at least one chemical tracer into the well with a slurry. Thet least one chemical tracer may be a component or mixed with a pre-acid slurry or composition. The method may comprise introducing at least one chemical tracer into the well with a treatment fluid. The method may comprise introducing at least one chemical tracer into the well with an acid fluid. The method may comprise introducing at least one chemical tracer into the well with a fracturing fluid. The method may comprise comparing the presence and / or concentration of the at least one distinct nanoparticle tracer produced from the individual stage fractures with the presence and / or concentration of the at least one chemical tracer in fluid produced from the individual stage fractures. The method may comprise calculating or estimating a flow rate and / or flow volume of a stage fracture based on a measured concentration of the at least chemical tracer produced from a stage fracture. The method may comprise calculating or estimating a flow contribution rate and / or flow contribution volume of a stage fracture based on a measured concentration of the at least chemical tracer in fluid produced from a stage fracture. The method may comprise calculating or estimating a flow rate and / or flow volume of each individual stage fracture based on measured concentrations of a distinct chemical tracer in fluid produced from each individualstage fracture. The method may comprise calculating or estimating a flow contribution rate and / or flow contribution volume of each individual stage fracture based on measured concentrations of a distinct chemical tracer in fluid produced from each individual stage fracture. The method may comprise quantifying or estimating flow contributions from each stage based on a comparison of the presence and / or concentration of the at least one chemical tracer associated with each individual stage in the collected samples. The method may comprise determining fracture geometry and / or dominant flow paths based on the nanoparticle tracer response. The at least one chemical tracer may be selected from the group comprising water tracers, oil tracers, gas tracers, or tracers deployed as solids such as in a polymer matrix, impregnated proppant, or fluid loss material. The at least one tracer may be a non-radioactive tracer. The at least one tracer may be injected with or comprise a proppant. The at least one tracer may be configured to release at a known rate from proppant or proppant particles. The at least one chemical tracer may be water soluble. The at least one chemical tracer may be immobilized within and / or to a tracer release apparatus. The at least one chemical tracer release apparatus may comprise tracer molecules and a carrier. The carrier may be a matrix material. The matrix material may be a polymeric material. The tracer material may be chemically immobilized in a way that it releases tracer molecules or particles in the presence of a chemical trigger. The at least one chemical tracer may be selected from the group comprising chemical, fluorescent, phosphorescent, metallic complex, poly functionalized PEG and PPGs, DNA, antibodies, non-radioactive compounds and / or radioactive compounds. The at least one chemical tracer may be selected from the group comprising perfluorinated hydrocarbons or perfluoroethers. The perfluorinated hydrocarbons may be selected from the group of perfluoro buthane (PB), perfluoro methyl cyclopentane (PMCP), perfluoro methyl cyclohexane (PMCH). The method may comprise introducing at least one distinctive chemical tracer into a well before and / or with a further well treatment and introducing a different tracer into the well at a later stage or later portion of the well treatment or after at least well treatment stage has been completed or approaching completion. The method may comprise estimating or calculating an influx profile based on a response in the at least one chemical tracer concentration in the samples as a function of the sampling times. The at least one chemical tracer may be stable at a temperature in the range of 30°C to 500°C. By 'stable' is meant the at least one tracer or a tracer carrier is thermally stable and still functional as tracers or as a tracer carrier. The method may comprise identifying at least one chemical tracer in the samples.

[0030] The method may comprise obtaining fluid from the well. The method may comprise obtaining fluid samples from the well. The method may comprise obtaining fluid from at least oneinjection well. The method may comprise obtaining fluid from at least one production well. The method may comprise collecting samples of the fluid. The sampling may be conducted at one or more sampling times. The sampling may be conducted downhole in a well. The sampling may be conducted downhole in an injection well. The sampling may be conducted downhole in a production well. The sampling may be conducted at surface. The sampling may be conducted at a location in a direction towards the surface of the well. Samples may be collected for later analysis. The collected samples may be analysed onsite or offsite. The method may comprise in-line sampling. The method may comprise detecting the presence and / or concentration of at least one nanoparticle tracer in the sampled fluid. The method may comprise detecting the presence and / or concentration of at least one chemical tracer in the sampled fluid. The method may comprise detecting the presence and / or concentration of at least one nanoparticle tracer in the sampled fluid in real time. The method may comprise detecting the presence and / or concentration of at least one chemical tracer in the sampled fluid in real time.

[0031] The method may comprise detecting the presence and / or concentration of at least one nanoparticle tracer in the sampled fluid using an online analyser. The method may comprise detecting the presence and / or concentration of at least one chemical tracer in the sampled fluid using an online analyser. The method may comprise measuring a concentration of at least one nanoparticle tracer in the sampled fluid. The method may comprise measuring a concentration of at least one chemical tracer in the sampled fluid. The method may comprise measuring a concentration of at least one nanoparticle tracer in the sampled fluid in real time. The method may comprise measuring a concentration of at least one chemical tracer in the sampled fluid in real time. The method may comprise measuring a concentration of at least one nanoparticle tracer in the sampled fluid using an online analyser. The method may comprise measuring a concentration of at least one chemical tracer in the sampled fluid using an online analyser. The sample collection may be an automated process. The method may comprise storing collected samples in a storage device. The method may comprise storing collected samples in a storage device for export to a laboratory and / or later analysis. The samples may be stored by adsorbing them to a chemical adsorption tube (CAT). The method may comprise collecting the at least one sample in at least one sample container or sampling tube. The method may comprise collecting the at least one sample in a sample container such as PVT sample canisters or isotubes. The method may comprise collecting the at least one sample in at least one sampling tube comprising a sorbent material. The sorbent material may be configured to adsorb the at least one chemical tracer. The sorbent material may be configured to adsorbthe at least one nanoparticle tracer. The sorbent material may be configured to adsorb the two or more chemical tracers. The sorbent material may be configured to adsorb the two or more nanoparticle tracers. The at least one chemical tracer may be an interwell tracer. The at least one chemical tracer may be an inflow tracer. The at least one nanoparticle tracer may be an interwell tracer. The at least one nanoparticle tracer may be an inflow tracer. The method may comprise storing and / or transporting the sorbent material. The method may comprise storing and / or transporting the sorbent material for later analysis. The method may comprise determining the type of nanoparticle tracer or nanoparticle tracers in the sample. The method may comprise measuring and / or monitoring a concentration of the at least one nanoparticle tracer. The method may comprise the measuring and / or monitoring the transport time of the at least one nanoparticle tracer. The method may comprise the measuring and / or monitoring the transport time of the at least one nanoparticle tracer from injection to detection in the produced fluid. The method may comprise determining the type of chemical tracer or chemical tracers in the sample. The method may comprise measuring and / or monitoring the concentration of the at least one chemical tracer. The method may comprise the measuring and / or monitoring the transport time of the at least one chemical tracer. The method may comprise the measuring and / or monitoring the transport time of the at least one chemical tracer from injection to detection in the produced fluid. The at least one chemical tracer may be detected and / or measured using techniques selected from the group comprising optical detection, optical fibers, spectrophotometric methods, spectrometric methods, fluorescence, chromatographic methods, HPLC (high performance liquid chromatography), MS (mass spectrometry) inductively coupled plasma mass spectrometry (ICP-MS), mass spectroscopy (MS) or multidimensional MS and / or radioactivity analysis.

[0032] The method may comprise injecting and / or releasing at least one nanoparticle tracer in two or more injection wells. The method may comprise injecting or releasing at least one nanoparticle tracer in two or more injection wells. The method may comprise injecting and / or releasing at least one chemical tracer in two or more injection wells. The method may comprise injecting or releasing at least one chemical tracer in two or more injection wells. The method may comprise analysing the arrival of tracer concentration of each nanoparticle tracer in the well. The method may comprise analysing the arrival of tracer concentration of each nanoparticle tracer in a production well. The method may comprise analysing the arrival of tracer concentration of each nanoparticle tracer back produced in an injection or a production well. The method may comprise analysing the rate of decline of the nanoparticle tracer concentration in the well to determine fracture flow characteristics, flow rates and / or flow paths. The method may comprise analysing the rate of decline of the nanoparticle tracerconcentration in the production well to determine fracture flow characteristics, flow rates and / or flow paths. The method may comprise analysing the arrival of tracer concentration of each chemical tracer in the well. The method may comprise analysing the arrival of tracer concentration of each chemical tracer in a production well. The method may comprise analysing the arrival of tracer concentration of each chemical tracer back produced in an injection or a production well. The method may comprise analysing the rate of decline of the chemical tracer concentration in the well to determine fracture flow characteristics, flow rates and / or flow paths. The method may comprise analysing the rate of decline of the chemical tracer concentration in the production well to determine fracture flow characteristics, flow rates and / or flow paths. The method may include calculating a flow characteristic by quantifying a proportion of flow from each stage by performing a dilution calculation. The method may comprise calculating a mathematical derivative of a nanoparticle tracer response curve. The method may comprise calculating a mathematical derivative of a chemical tracer response curve. The calculated derivative can be characterized by means of Residence Time Distribution (RTD) analysis. The RTD analysis may include assisted history matching to calculate the flow characteristics.

[0033] The method may comprise injecting a first nanoparticle tracer into a first stage hydraulic fracture. The method may comprise injecting a second nanoparticle tracer into a second stage hydraulic fracture. The first and second tracers may be distinct nanoparticle tracers, and therefore the first and second stage hydraulic fractures, may comprise distinct nanoparticle tracers. The method comprises injecting at least one tracer into at least one of the first or second stage hydraulic fracture, and comprises back producing fluid in the well. The method comprises injecting at least one tracer into at least one of the first or second stage hydraulic fracture, and comprises circulating fluid from the first well to the second well. The method may comprise multistage fracture treatments comprising three or more hydraulic fracture stages from the well. The method may comprise multistage fracture treatments comprising three or more hydraulic fracture stages from the first well of the well combination. The method may comprise injecting at least one distinct tracer into each stage hydraulic fracture. The method may comprise circulating from a first well to a second well through the at least one fracture stage.

[0034] The method may comprise designing an enhanced geothermal system, geothermal reservoir system, hydrocarbon reservoir system or an unconventional well system. The invention may facilitate fracture data based on the nanoparticle tracer response data to be applied to subsequent steps in the formation of an enhanced geothermal system, geothermal reservoirsystem, hydrocarbon reservoir system or unconventional well system. An enhanced geothermal system or geothermal system may be designed with an improved, and optionally optimized, fracture surface area, fracture aperture and / or fracture flow velocity for utilization of efficient heat transfer. A hydrocarbon system may be designed with an improved, and optionally optimized, fracture surface area, fracture aperture and / or fracture flow velocity for utilization of efficient reservoir contact and hydrocarbon recovery. The at least one design parameter may relate to aspects of well stimulation. The at least one design parameter may include, but is not limited to, one or more of: the number of perforation clusters per stage; fracture geometry; fracture fluid viscosity; proppant type and / or mass; fracture fluid volume; post-fracture treatments such as fracture plugging, milling and / or fracture hydraulic conductivity. The at least one design parameter may relate to an operational parameter of the enhanced geothermal system, geothermal reservoir system or hydrocarbon reservoir system. The at least one design parameter may include, but is not limited to, one or more of: an injection rate, a production rate; a rate of circulation of fluid in the system; fluid density, fluid viscosity, circulation fluid type and / or bottomhole pressure. The flow characteristic used for calculating a fracture circulation efficiency may comprise a flow rate allocation for at least one of the first and second stage fractures. Optionally, the flow characteristic used for calculating a fracture circulation efficiency comprises a flow rate allocation for each stage of a multistage fracture. The flow rate allocation may be based on a fracture nanoparticle tracer response interpretation. The flow rate allocation may be based on a fracture chemical tracer response interpretation. The method may comprise forecasting heating efficiency or production and reservoir performance based on identified stimulation patterns, flow patterns and / or fracture characteristics and / or fracture conditions. The method may comprise adjusting flow conditions, injection rates, production rates, bottom hole pressures, production simulations and / or reservoir simulations to improve or assist forecasting of production and reservoir performance. The method may comprise modifying or adjusting reservoir flow patterns based on the measured tracer data. The method may comprise injecting polymers to modify fluid sweep profiles. The method may comprise analysing the measured tracer data to identify a flow path type through a formation.

[0035] The method may comprise creating a model of the at least one fracture, reservoir and / or well. The method may comprise creating a model of the well stimulation treatment. The method may comprise constructing a model of the at least one fracture, reservoir and / or well from measured physical data. The method may comprise constructing the model from historical measured tracer data. The method may comprise characterizing the at least one fracture based on the model. The method may comprise creating a nanoparticle tracer curvefrom the modelled tracer concentration as a function of time. The method may comprise comparing the modelled nanoparticle tracer curve data set with the measured nanoparticle tracer curve data set. The method may comprise controlling and / or adjusting flow into and out from the at least one fractures based on the model. The method may comprise controlling and / or adjusting parameters of well stimulation treatments based on the model. The adjustable parameters may be selected from the group comprising treatment type, treatment fluid type, reactivity, injection volume, injection rate and / or injection pressure, production rate, bottomhole pressure, velocity, apparent velocity, relative velocity, relative cross-sectional area, aperture, relative aperture, apparent aperture, proppant type and / or proppant stability. The method may comprise characterizing the at least one fracture based on the measured tracer data set and / or model. The method may comprise determining parameters of the at least one fracture based on the measured tracer data set and / or model. The method may comprise determining fracture velocity and / or fracture aperture based on the measured tracer data set and / or model. The method comprise analysing a tracer data set using artificial intelligence or machine learning to calculate or estimate at least one fracture characteristic. The method comprise analysing a tracer response data set of nanoparticles tracers of various size and density using artificial intelligence or machine learning to calculate or estimate fracture characteristics such as velocity and aperture. The method comprise analysing a nanoparticle tracer response to different flow conditions such as different flow rate, different fluid densities and / or different fluid viscosities using artificial intelligence or machine learning to calculate or estimate fracture characteristics such as velocity and aperture.

[0036] According to a second aspect of the invention, there is provided a method of characterising at least one stage fracture in a well combination comprising at least one injector well and at least one production well; the method comprising;

[0037] forming at least one stage fracture from a first well of the well combination to a second well; circulating fluid from the first well to the second well of the well combination via the at least one stage fracture,

[0038] wherein the at least one stage fracture comprises at least one nanoparticle tracer; collecting samples of fluid from the second well and analysing tracer concentrations; estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the tracer concentrations.The well combination may be a geothermal well. The well combination may be an enhanced geothermal system. The well combination may be a hydrocarbon well. The well combination may be an unconventional well.

[0039] Embodiments of the second aspect of the invention may include one or more features of the first aspect of the invention or its embodiments, or vice versa.

[0040] According to a third aspect of the invention, there is provided a method of characterising at least one stage fracture in a well; the method comprising

[0041] forming at least one stage fracture in a well;

[0042] injecting at least one distinct nanoparticle tracer in the at least one stage fracture; producing fluid in the well;

[0043] collecting samples of produced fluid and analysing tracer concentrations;

[0044] estimating or calculating at least one condition and / or characteristic of the at least one fracture from the analysis of the tracer concentrations.

[0045] The method may be a push and pull tracer test. The method may comprise back producing fluid from the well. The well may be an injection well. The well may be a production well. The at least one fracture may be formed and produce fluid into the same well.

[0046] Embodiments of the third aspect of the invention may include one or more features of the first or second aspects of the invention or their embodiments, or vice versa.

[0047] According to a fourth aspect of the invention there is provided an interpretation method for characterising at least one fracture in a well system, the method comprising:

[0048] providing tracer data, the tracer data previously obtained by analysis of samples of fluid collected from a well having at least one stage fracture wherein the at least one stage fracture comprises at least one distinct nanoparticle tracer and fluid was produced from the well via the at least one fracture;

[0049] estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the tracer data.

[0050] The well may be an injector well. The well may be a production well. The at least one fracture may comprise at least one distinct chemical tracer. The well system may comprise two or more fractures. The well system may comprise two or more fractures in communication with the injector well and at least one production well. Each of the two ofmore fractures may comprise at least one distinct nanoparticle tracer. Each of the two of more fractures may comprise two or more distinct nanoparticle tracers. Each of the two of more fractures may comprise at least one distinct chemical tracer. Each of the two of more fractures may comprise two or more distinct chemical tracers. The method may comprise estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the nanoparticle tracer data and / or the chemical tracer data. The well may be an injection well and / or a production well of an enhanced geothermal system. The well may be an injection well and / or a production well of a geothermal reservoir system. The well may be an injection well and / or a production well of a hydrocarbon well system. The method may comprise adjusting or modifying at least one parameter and observing how the nanoparticle tracer responds to the adjusted or modified at least one parameter. The method may comprise adjusting or modifying at least one parameter and observing how the concentration of nanoparticle tracer in the samples is affected by the adjusted or modified at least one parameter. The method may comprise performing at least one interrogation step to adjust or modify at least one well parameter. The at least one well parameter may be selected from the group comprising nanoparticle tracer size, nanoparticle tracer density, nanoparticle tracer type, fluid viscosity, fluid density, injection rate, production rate and / or bottom hole pressure. The method may comprise injecting at least one fluid with a different viscosity and / or a different density into the at least one fracture. The method may comprise injecting two or more fluids each with a different viscosity and / or a different density into the at least one fracture. The method may comprise injecting at least one fluid with a different viscosity and / or a different density into each fracture. The method may comprise injecting two or more fluids each with a different viscosity and / or a different density into each fracture. The method may comprise calculating or estimating a fracture characteristic based on a nanoparticle tracer response to different fluid viscosities and / or a different fluid densities injected into each fracture. The method may comprise calculating or estimating a fracture characteristic based on a nanoparticle tracer concentration response in the samples to different fluid viscosities and / or a different fluid density injected into each fracture. The method may comprise calculating or estimating a fracture characteristic based on a nanoparticle tracer response when the nanoparticle tracer size and / or density is varied. The method may comprise calculating or estimating a fracture characteristic based on a nanoparticle tracer concentration response in the samples when the nanoparticle tracer size and / or density is varied. The method may comprise calculating or estimating an apparent velocity based on a nanoparticle tracer response to different fluid viscosities and / or a different fluid density injected into each fracture. The method may comprise estimating or calculating relative velocity and / or apparent velocity of each fracture stage based on nanoparticle tracerresponse data interpretation using fluids with a different viscosity and / or a different density. The method may comprise estimating or calculating relative aperture and / or apparent aperture of each fracture stage based on nanoparticle tracer response data interpretation using fluids with a different viscosity and / or a different density. The method may comprise adjusting or modifying a production flow rate. The method may comprise adjusting or modifying the production flow rate from a first production flow rate to at least a second production flow rate. The at least a second production flow rate may be higher or lower than the first production flow rate. The method may comprise adjusting or modifying a production flow rate to multiple different flow rates. The method may comprise calculating or estimating a relative velocity and / or apparent velocity based on a nanoparticle tracer response to different production flow rates.

[0051] Embodiments of the fourth aspect of the invention may include one or more features of any of the first to third aspects of the invention or their embodiments, or vice versa.

[0052] According to a fifth aspect of the invention there is provided an interpretation method for characterising at least one fracture in a well system, wherein the well system comprises a well combination comprising at least one fracture in communication with an injector well and at least one production well; wherein at least one distinct nanoparticle tracer was injected into the at least one stage fracture;

[0053] the method comprising:

[0054] providing tracer data, the tracer data previously obtained by analysis of samples of fluid collected from fluid produced from the production well via the at least one fracture; estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the nanoparticle tracer data.

[0055] The at least one fracture may comprise at least one distinct chemical tracer. The well system may comprise two or more fractures. The well system may comprise two or more fractures in communication with the injector well and at least one production well. Each of the two of more fractures may comprise at least one distinct nanoparticle tracer. Each of the two of more fractures may comprise two or more distinct nanoparticle tracers. Each of the two of more fractures may comprise at least one distinct chemical tracer. Each of the two of more fractures may comprise two or more distinct chemical tracers. The method may comprise estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the nanoparticle tracer data and / or the chemical tracer data.Embodiments of the fifth aspect of the invention may include one or more features of any of the first to fourth aspects of the invention or their embodiments, or vice versa.

[0056] According to a sixth aspect of the invention there is provided a method of characterising at least one fracture in a well system, the method comprising:

[0057] analysing collected samples, the collected samples previously collected from a well having at least one stage fracture wherein the at least one stage fracture comprises at least one distinct nanoparticle tracer and fluid was produced from the well via the at least one fracture; estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the tracer data.

[0058] The well may be an injector well. The well may be a production well. The at least one fracture may comprise at least one distinct chemical tracer. The well system comprises two or more fractures in communication with the injector well and at least one production well. Each of the two of more fractures may comprise at least one distinct nanoparticle tracer. Each of the two of more fractures may comprise two or more distinct nanoparticle tracers. Each of the two of more fractures may comprise at least one distinct chemical tracer. Each of the two of more fractures may comprise two or more distinct chemical tracers. The method may comprise estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the nanoparticle tracer data and the chemical tracer data.

[0059] Embodiments of the sixth aspect of the invention may include one or more features of any of the first to fifth aspects of the invention or their embodiments, or vice versa.

[0060] According to a seventh aspect of the invention there is provided an interpretation method of characterising at least one fracture in a well system, the method comprising:

[0061] providing tracer data, the tracer data previously obtained by analysis of samples of fluid collected from a production well in a well combination comprising at least one injector well and at least one production well, and having at two or more stage fractures wherein each of the two or more fractures comprises at least one distinct nanoparticle tracer; wherein fluid has been circulated fluid from the at least one injector well to the at least one production well via the two more stage fractures;

[0062] estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the tracer data.The at least one fracture may comprise at least one distinct chemical tracer. Each of the two of more fractures may comprise at least one distinct nanoparticle tracer. Each of the two of more fractures may comprise two or more distinct nanoparticle tracers. Each of the two of more fractures may comprise at least one distinct chemical tracer. Each of the two of more fractures may comprise two or more distinct chemical tracers. The method may comprise estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the nanoparticle tracer data and the chemical tracer data.

[0063] Embodiments of the seventh aspect of the invention may include one or more features of any of the first to sixth aspects of the invention or their embodiments, or vice versa.

[0064] According to an eighth aspect of the invention there is provided an interpretation method of characterising at least one fracture in a well system, the method comprising:

[0065] providing tracer data, the tracer data previously obtained by analysis of samples of fluid collected from a production well in a well combination comprising at least one injector well and at least one production well, and having at two or more stage fractures; wherein each of the two or more fractures comprising at least one distinct nanoparticle tracer and at least one distinct chemical tracer; wherein fluid has been circulated fluid from the at least one injector well to the at least one production well via the two more stage fractures;

[0066] estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the nanoparticle tracer data and the chemical tracer data.

[0067] Each of the two of more fractures may comprise two or more distinct nanoparticle tracers. Each of the two of more fractures may comprise two or more distinct chemical tracers.

[0068] The method may comprise estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the nanoparticle tracer data and the chemical tracer data. The at least one fracture may comprise at least one distinct chemical tracer. Each of the two of more fractures may comprise at least one distinct nanoparticle tracer. Each of the two of more fractures may comprise two or more distinct nanoparticle tracers. Each of the two of more fractures may comprise at least one distinct chemical tracer. Each of the two of more fractures may comprise two or more distinct chemical tracers. The method may comprise estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the nanoparticle tracer data and the chemical tracer data.

[0069] Embodiments of the eighth aspect of the invention may include one or more features of any of the first to seventh aspects of the invention or their embodiments, or vice versa.According to a ninth aspect of the invention there is provided an interpretation method of characterising at least one fracture in a well system, the method comprising:

[0070] providing tracer data, the tracer data previously obtained by analysis of samples of fluid collected from a production well in a well combination comprising at least one injector well and at least one production well, and having at two or more stage fractures wherein each of the two or more fractures comprising at least two or more distinct nanoparticle tracers; wherein at least one fluid has been circulated fluid from the at least one injector well to the at least one production well via the two more stage fractures;

[0071] estimating or calculating at least one condition and / or characteristic of the two or more fractures from the analysis of the tracer data.

[0072] At least one fracture may comprise at least one distinct chemical tracer. Each of the two of more fractures may comprise at least one distinct chemical tracer. Each of the two of more fractures may comprise two or more distinct chemical tracers. The method may comprise estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the nanoparticle tracer data and the chemical tracer data. Each of the two or more distinct nanoparticle tracers may have a different size, shape and / or density.

[0073] The at least one fluid may have a known viscosity and / or density. The method may comprise analysing tracer data previously obtained by analysis of samples of different fluids collected by circulating two or more fluids from the at least one injector well to the at least one production well via the two more stage fractures. The two of more fluids may comprise different viscosities and / or densities. The method may comprise estimating or calculating at least one condition and / or characteristic of the two or more fractures from the analysis of the tracer data in response to changes in fluid viscosity and / or density. The method may comprise analysing tracer data previously obtained by analysis of samples of fluid collected by circulating fluids at two or more injection flow rate from the at least one injector well to two more stage fractures. . The method may comprise estimating or calculating at least one condition and / or characteristic of the two or more fractures from the analysis of the tracer data in response to changes in injection flow rate. The method may comprise analysing tracer data previously obtained by analysis of samples of fluid collected by circulating fluids at two or more production flow rates. The method may comprise estimating or calculating at least one condition and / or characteristic of the two or more fractures from the analysis of the tracer data in response to changes in production flow rate. The two of more fluids may comprise different viscosities and / or densities. The method may comprise estimating or calculating at least one condition and / or characteristic of the two or more fractures from the analysis of the tracer data in response to changes in fluid viscosity and / or density.Embodiments of the ninth aspect of the invention may include one or more features of any of the first to eighth aspects of the invention or their embodiments, or vice versa.

[0074] According to a tenth aspect of the invention there is provided an interpretation method for characterising at least one fracture in a well system, the method comprising:

[0075] providing tracer data, the tracer data previously obtained by analysis of samples of fluid collected from a well having at least one stage fracture; wherein the at least one stage fracture comprises at least one distinct nanoparticle tracer and fluid was produced from the well via the at least one fracture at different times before and after adjusting or modifying at least one well parameter;

[0076] estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the tracer data.

[0077] The well may be an injector well. The well may be a production well. The at least one fracture may comprise at least one distinct chemical tracer. The well system comprises two or more fractures in communication with the injector well and at least one production well. Each of the two of more fractures may comprise at least one distinct nanoparticle tracer. Each of the two of more fractures may comprise two or more distinct nanoparticle tracers. Each of the two of more fractures may comprise at least one distinct chemical tracer. Each of the two of more fractures may comprise two or more distinct chemical tracers.

[0078] The method may comprise estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the nanoparticle tracer data and the chemical tracer data. The well may be an injection well and / or a production well of an enhanced geothermal system. The well may be an injection well and / or a production well of a geothermal reservoir system. The well may be an injection well and / or a production well of a hydrocarbon well system. The method may comprise performing at least one interrogation step to adjust or modify at least one parameter. The at least one well parameter may be selected from the group comprising nanoparticle tracer size, nanoparticle tracer density, nanoparticle tracer type, fluid viscosity, fluid density, injection rate, production rate and / or bottomhole pressure. The method may comprise analysing tracer data previously obtained by analysis of samples of different fluids collected by circulating two or more fluids from the at least one injector well to the at least one production well via the at least one stage fracture. The two of more fluids may comprise different viscosities and / or densities. The two of more fluids may be circulated at different times. The method may comprise estimating or calculating at least one condition and / or characteristic of the at least one fracture from the analysis of the tracer data in response to changes in fluid viscosity and / or density.The method may comprise analysing tracer data previously obtained by analysis of samples of fluid collected by circulating fluids at two or more injection flow rate from the at least one injector well to the at least one stage fracture. The method may comprise estimating or calculating at least one condition and / or characteristic of the at least one fracture from the analysis of the tracer data in response to changes in injection flow rate. The method may comprise analysing tracer data previously obtained by analysis of samples of fluid collected by circulating fluids at two or more production flow rates. The method may comprise estimating or calculating at least one condition and / or characteristic of the at least one fracture from the analysis of the tracer data in response to changes in production flow rate. The two of more fluids may comprise different viscosities and / or densities. The method may comprise estimating or calculating at least one condition and / or characteristic of the at least one fracture from the analysis of the tracer data in response to changes in fluid viscosity and / or density.

[0079] Embodiments of the tenth aspect of the invention may include one or more features of the first to ninth aspects of the invention or their embodiments, or vice versa.

[0080] According to an eleventh aspect of the invention there is provided a system for characterising a fracture in a well system comprising:

[0081] a well combination comprising at least one injector well and at least one production well, at least one stage fracture from a first well of the well combination;

[0082] at least one nanoparticle tracer configured to be injected into the at least one stage fracture; and a collection device configured to collect samples of fluid produced in the well.

[0083] The at least one stage fracture from a first well of the well combination may be formed according to a fracture treatment. The collecting samples may be configured to collect samples at known sampling times. The system may comprise two or more nanoparticle tracers with distinct tracer materials. The system may comprise at least one chemical tracer configured to be injected into the at least one stage fracture. The system may comprise two or more chemical tracers with distinct tracer materials. The system may comprise a nanoparticle tracer release device configured to release the at least one nanoparticle tracer into the injection well. The system may comprise a nanoparticle tracer release device configured to release the at least one nanoparticle tracer into the at least one fracture. The system may comprise at least one nanoparticle tracer analyser device configured to detect and / or measure the concentration of the at least one nanoparticle tracer in fluid produced from the well system. The system may comprise at least one nanoparticle tracer analyserdevice configured to detect and / or measure the concentration of the two or more nanoparticle tracer materials in fluid produced in a production well. The system may comprise at least one nanoparticle tracer analyser device configured to detect and / or measure the concentration of the two or more nanoparticle tracer materials in fluid back produced in a production well or an injection well. The system may comprise a chemical tracer release device configured to release the at least one chemical tracer into the injection well. The system may comprise a chemical tracer release device configured to release the at least one chemical tracer into the at least one fracture. The system may comprise at least one chemical tracer analyser device configured to detect and / or measure the concentration of the at least one nanoparticle tracer in fluid produced from the well system. The system may comprise at least one chemical tracer analyser device configured to detect and / or measure the concentration of the two or more chemical tracer materials in fluid produced in a production well. The system may comprise at least one chemical tracer analyser device configured to detect and / or measure the concentration of the two or more chemical tracer materials in fluid back produced in a production well or an injection well.

[0084] The system may comprise at least one processor. The at least one processor may be a computer processor. The process may be a computer-implemented processor. The processor may be configured to calculate and / or monitor a characteristic of the at least one fracture based on the presence and / or concentration of tracer in the samples. The at least one processor may be configured to analyse and / or compare tracer data sets of the two or more tracers in collected samples. The at least one processor may be configured to calculate, estimate and / or determine at least one spatial or temporal moment for each tracer. The at least one processor may be configured to analyse at least one spatial or temporal tracer moment of the tracers to estimate at least one characteristic and / or condition of the at least one fracture. The at least one processor may be configured to analyse the tracer data to compare the at least one spatial or temporal tracer moment of the tracers to estimate at least one characteristic and / or condition of the at least one fracture. The at least one processor may be configured to analyse the tracer data to compare the at least one spatial or temporal tracer moment of the at least one nanoparticle tracer and / or the at least one chemical tracer to estimate at least one characteristic and / or condition of the at least one fracture.

[0085] The processor may be configured to analyse the tracer data using a tracer response model to calculate or estimate at least one fracture characteristic and / or condition. The processor may be configured to artificial intelligence or machine learning to a tracer data set tocalculate or estimate at least one fracture characteristic. The processor may be configured to apply artificial intelligence or machine learning to a tracer response data set of nanoparticles tracers of various size and density to calculate or estimate fracture characteristics such as velocity and aperture. The processor may be configured to apply artificial intelligence or machine learning to a nanoparticle tracer response to different flow conditions such as different flow rate, different fluid densities and / or different fluid viscosities to calculate or estimate fracture characteristics such as velocity and aperture.

[0086] Embodiments of the eleventh aspect of the invention may include one or more features of the first to tenth aspects of the invention or their embodiments, or vice versa.

[0087] According to a twelfth aspect of the invention, there is provided a method of collecting samples for analysis in a method of characterising at least one fracture in a well system, wherein the well system comprises a well combination comprising at least one fracture in communication with an injector well and at least one production well; wherein the at least one fracture comprises at least one distinct nanoparticle tracer;

[0088] the method comprising circulating fluid from the injector well to the production well of the well combination via the at least one fracture; and

[0089] collecting samples from the production well.

[0090] The samples may be collected at known sampling times. The at least one fracture may comprise at least one distinct chemical tracer. The well system comprises two or more fractures in communication with the injector well and at least one production well. Each of the two of more fractures may comprise at least one distinct nanoparticle tracer. Each of the two of more fractures may comprise two or more distinct nanoparticle tracers. Each of the two of more fractures may comprise at least one distinct chemical tracer. Each of the two of more fractures may comprise two or more distinct chemical tracers. The well system maybe an enhanced geothermal system, a geothermal reservoir system, an unconventional reservoir or a hydrocarbon well system.

[0091] Embodiments of the twelfth aspect of the invention may include one or more features of the first to eleventh aspects of the invention or their embodiments, or vice versa.

[0092] According to a thirteenth aspect of the invention, there is provided a method of collecting samples for analysis in a method of characterising at least one fracture in a well system,wherein the well system comprises a well combination comprising at least one fracture; wherein the at least one fracture comprises at least one distinct nanoparticle tracer;

[0093] the method comprising producing fluid from the well via the at least one fracture; and collecting samples from the well.

[0094] The samples may be collected at known sampling times. The well may be an injector well. The well may be a production well. The at least one fracture may comprise at least one distinct chemical tracer. The well system comprises two or more fractures in communication with the injector well and at least one production well. Each of the two of more fractures may comprise at least one distinct nanoparticle tracer. Each of the two of more fractures may comprise two or more distinct nanoparticle tracers. Each of the two of more fractures may comprise at least one distinct chemical tracer. Each of the two of more fractures may comprise two or more distinct chemical tracers. The well may be an injection well and / or a production well of an enhanced geothermal system. The well may be an injection well and / or a production well of a geothermal reservoir system. The well may be an injection well and / or a production well of a hydrocarbon well system.

[0095] Embodiments of the thirteenth aspect of the invention may include one or more features of the first to twelfth aspects of the invention or their embodiments, or vice versa.

[0096] According to a fourteenth aspect of the invention, there is provided an interpretation method for characterising at least one fracture in a well combination, the method comprising: providing tracer data, the tracer data previously obtained by analysis of samples of fluid collected from a well having at least one stage fracture wherein the at least one stage fracture comprises at least one distinct nanoparticle tracer and fluid was produced from the well via the at least one fracture;

[0097] estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the tracer data.

[0098] The well combination may comprise at least one injector well and at least one production well. The well combination may comprise at least one stage fracture from a first well of the well combination to at least a second well. The method may comprise circulating fluid from a first well to the second well of the well combination via the at least one stage fracture. The method may comprise circulating fluid from a first well to the second well of the well combination via each stage fracture. The method may comprise back producing fluid in a first well and collecting samples of produced fluid and analysing tracer concentrations. Themethod may comprise back producing fluid from an injection well and collecting samples of produced fluid and analysing tracer concentrations. The well combination may comprise two or more fractures in communication with an injector well and at least one production well. Each of the two of more fractures may comprise at least one distinct nanoparticle tracer. At least one fracture may comprise at least one distinct chemical tracer. Each of the two of more fractures may comprise at least one chemical tracer. The method may comprise estimating or calculating at least one condition and / or characteristic of the fracture selected from the group comprising plugging, convective jamming, deep-bed filtration, stagnation points, tortious flow paths, fracture aperture, dynamic changes in fracture aperture, flow velocity, relative cross-sectional area, variations in flow velocity, relative velocity, apparent velocity, relative aperture and / or apparent aperture. The method may comprise adjusting or modifying at least one parameter and observing how the nanoparticle tracer responds to the adjusted or modified at least one parameter. The at least one parameter may be selected from the group comprising nanoparticle tracer size, particle tracer density, nanoparticle tracer type, fluid viscosity, fluid density, injection rate, production rate and / or bottom hole pressure. The method may comprise analysing tracer data previously obtained by analysis of samples of different fluids collected by circulating two or more fluids from the at least one injector well to the at least one production well via the two more stage fractures. The method may comprise estimating or calculating at least one condition and / or characteristic of the two or more fractures from the analysis of the tracer data in response to changes in fluid viscosity, density and / or injection flow rate, or flow rate. The method may be a computer-implemented method. The method may comprise storing the measured tracer data to a database. The method may comprise storing model data to a database. The method may comprise interrogating or comparing modelled tracer data, library of tracer data and / or tracer data database with at least one measured tracer data set. The method may comprise processing the tracer data to determine a temporal and / or spatial distribution of the at least one nanoparticle tracer and / or the at least one chemical tracer in the produced fluid. The method may comprise processing the tracer data using a processor. The method may comprise determining, based on the processed tracer data, at least one physical condition or characteristic of the fracture selected from group comprising plugging, convective jamming, deep-bed filtration, stagnation points, tortious flow paths, fracture aperture, dynamic changes in fracture aperture, flow velocity, relative cross-sectional area, variations in flow velocity, relative velocity, apparent velocity, relative aperture and / or apparent aperture fracture connectivity, fracture contribution to fluid production, fracture conductivity, fracture volume and / or fracture flow behaviour.Embodiments of the fourteenth aspect of the invention may include one or more features of the first to thirteenth aspects of the invention or their embodiments, or vice versa.

[0099] According to a fifteenth aspect of the invention, there is provided a system for characterising a fracture in a well combination comprising:

[0100] at least one nanoparticle tracer configured to be injected into at least one stage fracture in a well ; and

[0101] a collection device configured to collect samples of fluid produced from a well.

[0102] The system may comprise at least one chemical tracer configured to be injected into the at least one stage fracture. The system may comprise two or more nanoparticle tracers with distinct tracer materials. The system may comprise two or more chemical tracers with distinct tracer materials. The system may comprise at least one nanoparticle tracer release device configured to release the at least one nanoparticle tracer into an injection well and / or at least one fracture. The system may comprise at least one chemical tracer release device configured to release the at least one chemical tracer into an injection well and / or at least one fracture. The system may comprise at least one collection device configured to collect samples of fluid produced from a well. The system may comprise at least one collection device configured to collect samples of fluid produced from an injector well and / or a production well. The system may comprise at least one nanoparticle tracer analyser device configured to detect and / or measure the concentration of the at least one nanoparticle tracer in fluid produced from the well. The system may comprise at least one chemical tracer analyser device configured to detect and / or measure the concentration of the at least one chemical tracer in fluid produced from the well.

[0103] Embodiments of the fifteenth aspect of the invention may include one or more features of the first to fourteenth aspects of the invention or their embodiments, or vice versa.

[0104] According to a sixteenth aspect of the invention, there is provided a method of characterising at least one stage fracture in a well combination; the method comprising:

[0105] injecting at least one nanoparticle tracer into the at least one stage fracture;

[0106] collecting samples of produced fluid and analysing tracer concentrations;

[0107] estimating or calculating at least one condition and / or characteristic of the at least one fracture based on the tracer concentration.The method may comprise forming at least one stage fracture in the well. The method may comprise forming two or more stage fractures in the well. The method may comprise forming at least one stage fracture from a first well of the well combination to a second well. The method may comprise characterising at least one stage fracture in a well combination comprising at least one production well. The method may comprise forming at least one stage fracture from a first well into a formation and / or a reservoir. The method may comprise forming at least one stage fracture in a production well and producing fluid from the first well. The method may comprise forming at least one stage fracture in a first well and producing fluid from the first well. The method may comprise characterising two or more stages fractures.

[0108] Embodiments of the sixteenth aspect of the invention may include one or more of any of features of the first to fifteenth aspects of the invention or their embodiments, or vice versa.

[0109] According to a further aspect of the invention, there may be provided a method of characterising at least one fracture of an enhanced geothermal system according to an interpretation method from a previous aspect of the invention.

[0110] According to a further aspect of the invention, there may be provided a method of characterising at least one fracture of a geothermal reservoir system according to an interpretation method from a previous aspect of the invention.

[0111] According to a further aspect of the invention, there may be provided a method of characterising at least one fracture of a hydrocarbon well system according to an interpretation method from a previous aspect of the invention.

[0112] According to a further aspect of the invention, there may be provided a method of modelling a parameter of a fracture in a well system, the method comprising:

[0113] Calculating or estimating at least one fracture characteristic using a method according to any of the first to third aspects of the invention; and

[0114] - Adjusting a parameter of the fracture treatment, at least one nanoparticle tracer, fluid conditions, fluid viscosity, fluid density, flow conditions and / or bottom hole pressure.

[0115] Embodiments of the further aspects of the invention may include one or more features of any previous aspect of the invention or their embodiments, or vice versa.Brief description of the drawings

[0116] There will now be described, by way of example only, various embodiments of the invention with reference to the following drawings (like reference numerals referring to like features) in which:

[0117] Figure 1A is a schematic of an enhanced geothermal system in accordance with an embodiment of the invention;

[0118] Figure 1B is a schematic end view of the system of Figure 1A depicting parameters calculated according to embodiments of the invention;

[0119] Figure 1C is a schematic an injection well and a production well of an enhanced geothermal system showing three fractures stages in accordance with an embodiment of the invention; Figure 2 is a schematic diagram showing forces acting on a nanoparticle tracer in the well.

[0120] Figure 3A is a graph showing flow back testing with percentage flow contribution data for eight fracture stages 3R to 10 based on chemical tracer concentrations;

[0121] Figure 3B is a graph showing flow back test with percentage flow contribution data for eight fracture stages 3R to 10 based on nanoparticle tracer concentrations;

[0122] Figure 4 is graph showing bottom hole pressure vs surface flow rate and how they can affect the stability of the proppant a fracture;

[0123] Figure 5A is a graph showing circulation testing with percentage flow contribution data for eight fracture stages 3R to 10 based on chemical tracer concentrations;

[0124] Figure 5B is a graph showing circulation testing with percentage flow contribution data for eight fracture stages 3R to 10 based on nanoparticle tracer concentrations;

[0125] Figure 6 is graph showing the relative velocity estimation or each stage fracture in an Enhanced Geothermal System (EGS) based on circulation test; and

[0126] Figure 7 is graph showing the relative aperture estimation for each stage fracture in an Enhanced Geothermal System (EGS) based on circulation tests.Detailed description of preferred embodiments

[0127] Figures 1A, 1B and 1C are a simplified representations of an enhanced geothermal system (EGS) shown generally as 10. The geothermal system has an injection well 12 and a production well 14. A series of hydraulic fracture treatments are carried out in the injection well with the aim of establishing a fluid connection between the injection well and the production well through the dry hot rock formation 16. Typically, hydraulic fracturing is carried out at different fracture initiation sites of the injection well 12 in a multistage hydraulic fracture process. In the example shown in Figure 1C three stages are shown, however it will be appreciated that the number of stages may be more than three or less than three. During a first stage, fracturing fluid is pumped from the surface through the wellbore and through perforations at injection site 20. The pumped fluid causes stresses in the rock formation 16, and as the fluid pressure and pumping rate exceed the critical stresses, fractures 30 form and propagate through the surrounding rocks. Further pumping leads to deeper fracture propagation. In this example the fracturing fluid may comprise proppant material which fill the developing fractures preventing fractures closure and improve the conductivity through the fracture. During the second stage, injection site 20 is isolated from injection site 22, for example by a wellbore plug or packer, and fracturing fluid is pumped from the surface through the wellbore and through perforations at injection site 22 to form fractures 40. The process is repeated for injection site 34 to form fractures 50, and the fracture site isolation tools are removed. In this example, the resulting fractures 30,40, 50 have different profiles, which may be due to the natural rock formation, differing fracture treatments or perforation design, or a combination.

[0128] The system as best shown in Figure 1C is a simple, functional, enhanced geothermal system comprising a single injection well and a single production well, it is also representative of a well system that may be the first injection and production well combination of a larger, more sophisticated enhanced geothermal system comprising multiple injection wells and / or multiple production wells arranged throughout the geothermal system. Referring now to Figure 1B, there is shown schematically an end view of the enhanced geothermal system 10. Fractures (not shown) are formed between the injection well 12 and the production well 14. Figure 1B shows a cross-sectional area 60 representing the hydraulic fracture geometry associated with the well combination and fracture network. This may be for example hydraulic fracture surface area, which is calculated or simulated from fracture geometry information using a hydraulic fracture simulator. An area 62 represents propped fracture area, which may also be calculated or simulated from fracturegeometry information using a hydraulic fracture simulator. Area 64 represents the fracture circulation area calculated from the analysis of a tracer response, and it is considerably less than any of the hydraulic fracture geometry and propped fracture area.

[0129] A hydraulic fracture simulator is a computer program that is also referred to as a fracture model, fracture simulator, or fracture placement model is commonly used by those skilled in the art to design fracturing treatments and predict fracturing treatment results. Commercial fracture simulators are readily available. Fracture simulators may use inputs regarding treatment conditions such as pump rate, fluid viscosity, fluid volume, and proppant mass, combined with reservoir parameters such as stress profile, matrix permeability, and natural fracture profiles. The simulator output is often an optimized fracturing treatment pumping schedule and the predicted fracture properties including the created fracture geometry (height, half-length, propped fracture half-length, propped fracture width) and proppant pack hydraulic conductivity. In accordance with the invention, tracers (not shown) introduced into the fractures may provide information on the characteristic and condition of the fractures as circulated fluid moves to the producer well. Samples collected from the production well (in this example) can be analysed for tracer concentrations to provide one or more flow characteristics associated with the fracture. In other examples the injection well may be back produced and samples may be collected from the injection well. In a preferred embodiment of the invention, distinct nanoparticle tracers (not shown) are injected into each respective fracture 30, 40, 50. Injection of the tracers may occur during pumping of the fracturing fluid or proppant, or as a subsequent injection step after the fracture has been formed. Subsequent circulation of fluid between the injector well 12 and the producer well 14 such as during a circulation test may cause the nanoparticle tracers to flow with the circulated fluid to the production well. Samples collected from the production well can be analysed for tracer concentrations to calculate a flow rate allocation associated with each fracture nanoparticle tracer, as will be described in more detail below.

[0130] A distinct chemical tracer may also be injected into each respective fracture 30, 40, 50. In this example three distinct water soluble perfluorocarbon tracers encapsulated in a polymer matrix where each injected into a respective fracture 30, 40, 50. The chemical tracer polymer matrix was designed to remain in the fracture and release the soluble tracer from the polymer matrix into the fluid flow (water). As the chemical tracer is gradually released from the polymer it dissolves into the fluid and moves with the fluid. In contrast the nanoparticle tracers is not dissolved in the fluid but is dispersed and carried with the fluid flow.The nanoparticle tracers are not dissolved in the fluid, but remain discrete particles carried by the flow. The movement of the nanoparticles is governed forces acting on nanoparticles where a critical velocity threshold is required before they begin to move.

[0131] Figure 2 is a diagram showing some of the forces acting on the discrete nanoparticles. As the nanoparticles 120 move through the fluid and proppants 122 they experience forces including gravity, fluid drag, viscous shear and lift. Their movement is governed by Stokes' Law. Stokes Law describes the motion of small particles in fluid by quantifying the drag force acting on the particles. It applies to low Reynolds number (laminar flow) conditions, where inertial forces are negligible compared to viscous forces. The mathematical expression of Stokes; Law is the drag force (Fd) experienced by a particle moving through a fluid is given by:

[0132] Fd= 6TTI )V (Eqn 1)

[0133] Where:

[0134] = Dynamic viscosity of the fluid (Pa s)

[0135] r = Radius of the particle (m)

[0136] v= Velocity of the particle relative to the fluid (m / s)

[0137] TT = Mathematical constant (pi)

[0138] When a particle is denser than the surrounding fluid, it experiences gravitational force and moves downward out of the flow and can settle. The net force acting on the particle is the balance of gravitational force, buoyant force, and viscous drag. At terminal velocity (vt), these forces reach equilibrium where:

[0139]

[0140] Where:

[0141] pp = Density of the particle

[0142] pf = Density of the fluid

[0143] g = Acceleration due to gravity

[0144] If the upward flow velocity is greater than the terminal velocity, particles remain suspended or move upward, the particles are in suspension and transported with the fluid flow. If the flow velocity is lower than the terminal velocity the particles settle.During fracturing, proppants (such as sand or ceramic beads) and nanoparticle tracers are suspended in the fracturing fluid and transported into the fractures. Stokes' Law may be used to predict how nanoparticle tracers move with the flow or settle based on their size, density, and the fluid viscosity. In low flow or stagnant zones, nanoparticle tracers might settle or become trapped, particularly in narrow fracture spaces or within the pore throats of the proppant 122. Given the size difference between nanoparticle tracers and chemical tracers, if nanoparticle tracers settle, block narrow pore throats or get trapped within restricted pathways this may lead to erratic or absent detection in sampling tracer data. Settling velocity (ws) occurs at the point where the submerged weight of the particle equals the drag force. The submerged (immersed) weight = Weight of particle - buoyancy force. Buoyancy force equals the weight of the displaced fluid. The volume of displaced fluid is the volume of the particle. Thus, the settling velocity ws for Reynolds (Re) <1 is

[0145] ws= 1 / 18. (y D2 / p) (Eqn 3)

[0146] The Reynolds number represents the ratio of inertial forces to viscous forces and is a convenient parameter for predicting if a flow condition will be laminar or turbulent. It is defined as:

[0147] ReReynOids = Pco.VD / p (Eqn 4)

[0148] Where V is the mean flow velocity, D is a characteristic linear dimension, p fluid density and p dynamic viscosity. Stokes Law applies to particles at low Reynolds numbers such that laminar flow persists during settling. In Figure 2, the flow on the left side of the image represents laminar flow with a Reynolds number of less than 500-2000. In contrast the flow on the right-hand side of the image represents turbulent flow with a Reynolds number greater than 500-2000. In turbulent flow there is flow stream mixing and flow separation.

[0149] Nanoparticle tracers move predictably along laminar flow (Low Reynolds Number) streamlines. However, if flow velocity is below their critical movement threshold, they may settle or accumulate in low-permeability zones. In turbulent flow (High Reynolds Number) streamlines nanoparticle tracers may experience mixing and mobility, potentially increasing their dispersion. This may lead to higher variability in their detection and the sampling tracer data. In contrast chemical tracers, which are fully dissolved in the fluid and can move freely with the flow. Chemical tracers do not experience the same effects during residence in the fracture and typically continue to flow into the production well unhindered. Analysis of thenanoparticle tracer response may be used to determined characteristics and / or conditions of the fracture including variations in aperture, velocity, turbulence and / or formation plugging.

[0150] Figures 3A and 3B show chemical tracer data and nanoparticle tracer data respectively for flow back testing with percentage flow contribution data for eight fracture stages 3R to 10. In this example the percentage flow contribution data is based on chemical tracer concentrations. The graph show data from flow through plugs in the fracture (full lines) and after the plugs were milled (faint lines). In this example eight fracture stages were created between an injector well and a production well. Fracture stages 7, 8, 9 and 10 were located at the heel of the well and Fracture stages 3R, 4, 5 and 6 at the toe of the well. Into each fracture stage a distinct chemical tracer was injected and in fracture stages 3R, 4, 5, 8, 9 and 10 distinct nanoparticle tracers were injected. A flow back test was performed in the injection well where fluid was produced from the injection well. Samples of the fluid produced from the well were taken and the concentration of the chemical tracer and the nanoparticle tracer as associated with each were measured as a function for time. Initial flow back was with flow-through plugs still in the well. After about 75,000 barrels (bbls) of flowback the plugs were milled for flow back through the casing and further samples were collected after the plugs were milled. Figure 3A shows that the chemical tracers from each of the eight stages 3R to 10 were detected in flow through plugs in the fractures (full lines) and after the plugs were milled (faint lines). In contrast Figure 3B shows that there was no nanoparticle tracer detected in stages 3R to 5 in the toe of the well while flowing through plugs in the fracture (faint lines). However, after the plugs were milled (full lines) nanoparticle tracer from stages 3R to 5 was detected. The results from Figure 3B show that the nanoparticles were not flowing effectively from the toe fractures when the plugs were in position. Possible reasons for the lack of nanoparticle tracer response from the toe section fractures while the plugs are in place include the velocity, viscosity and / or density differences between the fluid and the nanoparticle tracers in these fractures. One possible scenario is that the nanoparticle tracers are trapped or are stagnant in these fractures. Based on Stokes law this could be due to plugging, convective jamming or deep bed filtration inside a proppant pack. Movement of the nanoparticle tracer in the fracture may have a torturous flow path that has stagnation points and very irregular flow profile. The tortuous flow paths can be impacted by rough surface disparities. This may cause differences in stress and channels around the proppant. The flow in the fracture may be heterogeneous resulting in a heterogeneity of velocity. Any perturbation in that system may change the velocity and impact on the flow nanoparticle through the fracture.Referring to Figure 4 which is a cross plot 200 showing bottomhole pressure versus flow rate and defines conditions where a proppant pack in a fracture is stable or unstable. In areas with a cross hatch 210 the proppant 122 is stable. In the dotted area 220 there is proppant migration where there is not sufficient force acting on the proppant it is moves and acts as a fluidised bed. The area 230 with diagonal lines is where the proppant is crushed and damaged. As the flow rate and the pressures changes, the width of the fracture may change overtime. By moving back and forth between various flow rate and pressure positions on the plot the fracture in the near wellbore opens and closes. The graph in Figure 4 demonstrates the balance of the effective stresses on the fracture and the proppant. The geomechanics and the pressure in the fracture may cause it to open and close to cause proppant and nanoparticle tracer to move around or become stagnant.

[0151] Referring to Figure 3B, the pressure difference between the presence and removal of the plugs may have changed the bottomhole pressure and affected characteristics and / or condition of the fracture such as the flow path around proppant, fracture aperture and / or fracture width.

[0152] Figures 5A and 5B show circulation testing with percentage flow contribution data for eight fracture stages 3R to 10 based on chemical tracer concentrations. The graph show data from flow through plugs in the fracture (full lines) and after the plugs were milled (faint lines) In this example eight fracture stages were created between an injector well and a producer well. Into each fracture stage a distinct chemical tracer was injected and in fracture stages 3R, 4, 5, 8, 9 and 10 distinct nanoparticle tracers were injected. Flow was circulated between the injector well through each fracture stage to the production well. Samples of the fluid flow from the production well were collected and tested for the concentration of the distinct chemical tracers and a distinct nanoparticle tracers associated with each fracture stage.

[0153] Figure 5A shows that the chemical tracers from each of the eight stages 3R to 10 were detected in produced flow. Figure 5B shows that nanoparticle tracers were detected in each of the stages fracture 3R, 4, 5, 8, 9 and 10. The results also showed the chemical tracer response for each stage were consistent (relatively small variation in height over time). In contrast the nanoparticle tracer responses for each stage were erratic over time with variations of 5% to -80% flow contribution. The erratic response of the nanoparticle tracer depends on a number of parameters including plugging, convective jamming, deep-bed filtration, stagnation points, tortuous flow paths and / or dynamic changes in the fractureaperture. In this example, data indicates that the effective porosity is about 80% in the flow path, so deep-bed filtration should not be playing a significant role in the proppant pack, while there could be a significant tortuous path around asperities and arches. Since a single particle size and fluid viscosity is used in this example, the variability is due to local velocity differences. On the basis that this variability is due to velocity variability, then the low responses represent low apparent velocity per stage while the high responses represent relatively high velocities per stage. From Figure 5B it can be seen when one stage has a high velocity, other stages have low velocity, and that the velocities are dynamically changing over time. On this basis, the y-axis is taken as a representative of the relative velocity.

[0154] Using the assumption that all nanoparticle tracers in this example have the same properties. In other example if there are any differences in nanoparticle properties which are known, then they may be taken into account based on governing equations such as Stokes Law. Using only the nanoparticle tracer data per fracture stage, we assume that the average of the variability per stage is representative of the relative velocity per stage. The ratio of nanoparticle tracer response is proportional to the ratio of velocities in the various stage fractures. Hence, we calculate the relative velocities (Vi / Vaverage) across the various stages. Based on the data from Figure 5B the representative velocity (apparent velocity) for each stage is shown in Table 1.

[0155]

[0156] Table 1 representative velocities of based on nanoparticle response data.

[0157] Figure 6 is a graph of the relative velocity per stage. The relative velocity per stage is calculated as the representative velocity (apparent velocity) / average representative velocity (e.g. for stage 10 is its 7.5% / 12.5% = 0.6). Based on the data from Figure 6 the relative velocity for each stage is shown in Table 2.

[0158]

[0159] Table 2 Relative Velocities of based on nanoparticle response data.Using the nanoparticle tracer data from each fracture stage other characteristics of the fracture may be determined including relative aperture of the fracture. By integrating the Relative Velocity (above) with percentage flow contribution data the relative aperture (bi / baverage) may be calculated per stage. In this example the percentage flow contribution data is calculated from chemical tracers where the volumetric flow rate per stage (Qi) as

[0160] Qi = Qsurface x %flow contribution (from chemical tracer concentrations). (Eqn.5)

[0161] It will be appreciated that additionally or alternatively other forms of quantitative production logging may be used such as fiber optic measurement instead of chemical tracer concentrations. The relative aperture (bi / baverage) may be calculated per stage using the equation:

[0162] Qi / Qaverage=(Vi / Vaverage) X (bi / baverage) X (Wi / Waverage) X (Pi / P average) (Eqn. 6)

[0163] Where: (Vi / Vaverage) is relative velocity, bi / baverage is relative aperture, (Wi / Waverage) is relative width and Pi / Paverage is relative porosity.

[0164] In this example a relative cross-sectional area to flow ( Ai = bi * Wi * porosity i ) is calculated from a ratio of chemical tracer derived flow rate and nano particle tracer derived velocity using equation 6. The relative aperture may be calculated from relative cross-sectional area to flow by further integrating data including microseismic and mass balance information.

[0165] The Qi / Qaverage is known from chemical tracer data (or alternative production logging data in other examples). We assume the width ratio (Wi / Waverage) is 1 or we can estimate width by integrating other data such as microseismic or fracture modelling. The flow rate per cluster Qi is calculated as % Flow Contribution * Q total (8 .1 bpm at surface) I number of clusters connected per stage (based on number of clusters and estimated fracture corridors from fiber optic strain). For Wi / Waverage =1 , we get the relative aperture as shown Figure 7. For example, the relative aperture for stage 3R is about 0.5, or about 50% of the average aperture for the overall system.

[0166] Based on the data from Figure 7 the relative aperture for each stage is shown in Table 3.

[0167]

[0168] Table 3 Relative Aperture of each fracture stage.

[0169] In another example, using nanoparticle tracer data where one distinct nanoparticle tracer is injected into each stage fracture, based on Stokes’ law, parameters of the injection rate, injection volume, production rate, production volume, nanoparticle tracer, and / or fluid may be adjusted to change the flow conditions. Based on the nanoparticle tracer response to different conditions an apparent velocity (Vi) per stage fracture may be estimated. For example, injecting a sweep of fluids with different fluid viscosities and / or different fluid densities may allow an estimate of apparent velocity (Vi) per stage fracture based on the nanoparticle tracer response to the different fluid viscosities and / or different fluid densities. Additionally, or alternatively, the injection rates could be adjusted and changes in nanoparticle tracer response observed to estimate of apparent velocity (Vi) per stage fracture. By combining the estimated apparent velocity (Vi) per stage fracture with the Qi measured from chemical tracer data (or production logging data), then an aperture per stage may be estimated from Qi = Vi * (bi) * W (where W can be assumed or calculated by integrating other data such as microseismic or fracture modelling.

[0170] In the above example only one distinct nanoparticle tracer is injected into each stage fracture. In other examples two or more distinct nanoparticle tracer may be injected into each stage fracture. In an example the two or more distinct nanoparticle tracers injected into each stage fracture may have different sizes and / or densities and therefore respond differently to the velocity field. By analysing the nanoparticle tracer response to each of the different sized and / or different density nanoparticle tracers an apparent velocity (Vi) per fracture stage may be estimated. By combining the estimated apparent velocity (Vi) per stage fracture with the Qi measured from chemical tracer data (or production logging data), then an aperture per stage may be estimated from Qi = Vi * (bi) x W (where W can be assumed or calculated by integrating other data such as microseismic or fracture modelling).In the above examples tracer data is used characterize fractures in an enhanced geothermal system. It will be appreciated that the method may also be used for other well types including but not limited to hydrocarbon wells, geothermal reservoirs and / or unconventional reservoirs.

[0171] In the above examples chemical tracer data is used to determine percentage flow contribution for each of the fractures. It will be appreciated that the use of chemical tracers is optional in the above methods and alternative methods of calculating or estimating percentage flow contribution may be used such as production logging equipment including fiber optic systems. However, the use of chemical tracers is a preferred method of determining percentage flow contribution for each of the fracture as the chemical tracer is measuring the same flow path through the fracture at the nanoparticle tracer.

[0172] The invention may provide a method of interpretating nanoparticle tracer data to characterise at least one stage fracture in a well. The method may comprise forming at least one stage fracture in the well and injecting at least one nanoparticle tracer into the at least one stage fracture. The method may comprise collecting samples of produced fluid and analysing tracer concentrations and estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the tracer concentrations.

[0173] By analysing and interpretating tracer response data from nanoparticle tracers injected into fractures may allow characteristics and / or conditions of the fractures to be determined. This may allow geometries of the fractures to be estimated. In the application of enhanced geothermal systems and geothermal reservoirs this may allow an improved understanding of the heat transfer surface areas and therefore maximize energy output. In the application of hydrocarbon production systems, it may provide an improved understanding of the surface area of exposed reservoir rock to the wellbore and therefore maximize hydrocarbon flow efficiency.

[0174] The steps of nanoparticle tracer installation, placement or release in a well; chemical tracer installation, placement or release in a well; nanoparticle tracer injection into at least one fracture or at least one injection well; chemical tracer injection into at least one fracture or at least one injection well; collecting samples; analysis of samples; interpretation of tracer data in sample and / or modelling of tracer data may be all be considered as separate discrete methods from one another and performed at different times or jurisdictions.Throughout the specification, unless the context demands otherwise, the terms 'comprise' or 'include', or variations such as 'comprises' or 'comprising', 'includes' or 'including' will be understood to imply the inclusion of a stated integer or group of integers, but not the exclusion of any other integer or group of integers. Furthermore, relative terms such as “up”, “down”, “top”, “bottom”, “upper”, “lower”, “upward”, “downward”, “horizontal”, “vertical” and the like are used herein to indicate directions and locations as they apply to the appended drawings and will not be construed as limiting the invention and features thereof to particular arrangements or orientations.

[0175] The foregoing description of the invention has been presented for the purposes of illustration and description and is not intended to be exhaustive or to limit the invention to the precise form disclosed. The described embodiments were chosen and described in order to best explain the principles of the invention and its practical application to thereby enable others skilled in the art to best utilise the invention in various embodiments and with various modifications as are suited to the particular use contemplated. Therefore, further modifications or improvements may be incorporated without departing from the scope of the invention as defined by the appended claims.

Claims

Claims:

1. A method of characterising at least one stage fracture in a well combination; the method comprisinginjecting at least one nanoparticle tracer into the at least one stage fracture; collecting samples of produced fluid and analysing tracer concentrations; estimating or calculating at least one condition and / or characteristic of the at least one fracture from the analysis of the tracer concentrations.

2. The method according to claim 1 wherein the well combination comprises at least one injector well and at least one production well and forming at least one stage fracture from a first well of the well combination to a second well.

3. The method according to claim 1 or 2 comprising characterising two or more stages fractures by injecting at least one distinct nanoparticle tracer into each stage fracture.

4. The method according to any preceding claim comprising injecting the at least one nanoparticle tracer into a well before and / or with a well treatment.

5. The method according to any preceding claim comprising injecting at least one distinct chemical tracer into the at least one stage fracture.

6. The method according to claim 5 comprising characterising two or more stages fractures by injecting at least one distinct chemical tracer into each stage fracture.

7. The method according to any preceding claim comprising analysing tracer concentrations with respect to sampling time.

8. The method according to any preceding claim comprising circulating fluid from a first well to the second well of the well combination via the at least one stage fracture and collecting samples of produced fluid.

9. The method according to any preceding claim comprising back producing fluid in a well and collecting samples of produced fluid and analysing tracer concentrations.

10. The method according to any preceding claim wherein the at least one nanoparticle tracer has a diameter size in the range of 0.01 pm to 100 pm.

11. The method according to any preceding claim comprising wherein the at least one nanoparticle tracer is pumped or injected into the at least one stage fracture with a treatment such as proppant particles or fluid loss particles.

12. The method according to any preceding claim comprising introducing the at least one nanoparticle tracer into the well and / or at least one fracture with a treatment fluid, acid fluid, pad fluid, a flush fluid or a post fracturing fluid.

13. The method according to any of claims 5 to 12 comprising quantifying or estimating flow contributions from each stage based on a comparison of the presence and / or concentration of the at least one distinct nanoparticle tracer and / or at least one distinct chemical tracer associated with each stage in the collected samples.

14. The method according to any preceding claim comprising estimating or calculating at least one condition and / or characteristic of the fracture selected from the group comprising plugging, convective jamming, deep-bed filtration, stagnation points, tortious flow paths, fracture aperture, dynamic changes in fracture aperture, flow velocity, relative cross-sectional area, variations in flow velocity, relative velocity, apparent velocity, relative aperture and / or apparent aperture.

15. The method according to any preceding claim comprising adjusting or modifying at least one parameter and observing how the at least one nanoparticle tracer responds to the adjusted or modified at least one parameter, wherein the at least one parameter is selected from the group comprising nanoparticle tracer size, particle tracer density, nanoparticle tracer type, fluid viscosity, fluid density, injection rate, production rate and / or bottom hole pressure.

16. The method according to any preceding claim comprising injecting two or more fluids each with a different viscosity and / or a different density into the at least one fracture and calculating or estimating a fracture characteristic based on a nanoparticle tracer response to different fluid viscosity and / or a different fluid density injected into the at least one fracture.

17. The method according to any preceding claim comprising adjusting or modifying a production flow rate, and calculating or estimating a fracture characteristic based on a nanoparticle tracer response to different flow rates.

18. The method according to any preceding claim comprising estimating or calculating at least one fracture geometry parameter based on the measured nanoparticle tracer data, wherein the at least one fracture geometry parameter is selected from the group comprising fracture aperture, representative aperture, apparent aperture, fracture velocity, representative velocity, apparent velocity, relative cross-sectional area, proppant stability, hydraulic fracture surface area, propped fracture surface area and / or proppant pack porosity volume.

19. The method according to any preceding claim wherein the well combination is selected from a geothermal well, an enhanced geothermal system, a hydrocarbon well and / or an unconventional well.

20. An interpretation method for characterising at least one fracture in a well combination, the method comprising:providing tracer data, the tracer data previously obtained by analysis of samples of fluid collected from a well having at least one stage fracture wherein the at least one stage fracture comprises at least one distinct nanoparticle tracer and fluid was produced from the well via the at least one fracture;estimating or calculating at least one condition and / or characteristic of the fracture from the analysis of the tracer data.

21. The method according to claim 20 wherein the well combination comprises two or more fractures in communication with an injector well and at least one production well.

22. The method according to claim 21 wherein each of the two of more fractures comprises at least one distinct nanoparticle tracer.

23. The method according to any of claims 20 to 22 wherein at least one fracture comprises at least one distinct chemical tracer.

24. The method according to any of claims 20 to 23 comprising estimating or calculating at least one condition and / or characteristic of the fracture selected from the group comprising plugging, convective jamming, deep-bed filtration, stagnation points, tortious flow paths, fracture aperture, dynamic changes in fracture aperture, flow velocity, relative cross-sectional area, variations in flow velocity, relative velocity, apparent velocity, relative aperture and / or apparent aperture.

25. A system for characterising a fracture in a well combination comprising: at least one nanoparticle tracer configured to be injected into at least one stage fracture in a well;and a collection device configured to collect samples of fluid produced from a well.

26. The system according to claim 25 comprising at least one chemical tracer configured to be injected into the at least one stage fracture.

27. The system according to claim 25 or 26 comprising at least one nanoparticle tracer release device configured to release the at least one nanoparticle tracer into an injection well and / or into at least one fracture.

28. The system according to any of claims 25 to 27 comprising a collection device configured to collect samples of fluid produced from a producing well.

29. The system according to any of claims 25 to 28 comprising at least one nanoparticle tracer analyser device configured to detect and / or measure a concentration of the at least one nanoparticle tracer in fluid produced from a well.

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