Method and system for monitoring well flow characteristics

Abstract

Methods of characterising one or more fractures in a well system are disclosed. One or more fractures 19 are formed from a first well to a second well, a first tracer 32 is injected into the fracture(

Description

The present invention relates to the field of well treatment and more specifically well treatments including fracturing, acidizing, acidizing fracturing and / or enhanced oil recovery treatment. Aspects of the invention include a method of assessing and characterising flow characteristics of wells. Background to the invention 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. Well stimulation techniques may be used to create fractures along the wellbore to generate large contact areas with the reservoir and increase reservoir permeability to the flow of hydrocarbons. An enhanced geothermal system (EGS) generates geothermal electricity without natural convective hydrothermal resources. In many areas, subterranean rock is hot but there is not enough natural permeability or fluids present to allow the generation of electricity. An enhanced geothermal system may be used by creating a human-made reservoir to extract heat for electricity production. In an enhanced geothermal system, a first well (injection well) is drilled and hydraulic, thermal, or chemical stimulation is conducted deep underground under carefully controlled conditions to create fluid connectivity in initially low-permeability rocks by creating fractures or reopening pre-existing fractures between the first well and a second well. Fluid is pumped in the first well through the fractures in the hot rock heating the fluid which is circulated back to surface via the second well where it is used to generate electricity. Well stimulation techniques use mechanical or chemical methods to artificially create channels in the formation which may facilitate the flow of fluids. In the case of hydrocarbon wells to extract economically viable quantities of hydrocarbon from formations with low flow characteristics. In the case of EGS to improve fluid connectivity and permeability in high temperature formations. Well stimulation techniques include fracturing, acidizing and fracture acidizing methods. 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 in the formation. The cracks are filled with a supporting material called proppant to prevent the cracks from closing during hydrocarbon production. Acidizing is a method of exposing minerals and rock in the formation to an acid. The minerals and rock are dissolved by the acid creating channels into the rock through which fluids can flow. Fracture acidizing is a well-stimulation operation in which an acid is injected into a formation typical a carbonate formation at a pressure above the formation-fracturing pressure. Flowing acid may etch the fracture faces in a nonuniform pattern, forming conductive channels which remain open without a propping agent after the fracture closes. In order to maximise hydrocarbon production in the case of hydrocarbon wells or energy output in the case of EGS wells it is important to understand the fluid connections between the first well and the second well and characteristics of the fractures between the wells. Summary of the invention It is amongst the aims and objects of the invention to provide a method and system for characterising flow and / or flow paths between wells. It is another object of the invention to provide a method and system for characterising flow and / or flow paths between wells flow profiles following or during well treatments. It is a further object of an aspect of the invention to provide a method and system for assessing at least one flow path and / or characterising of at least one flow path between wells. It is another object of the present invention to provide a method of assessing tracer residence time distribution (RTD) response to assess the flow through fractures created in a reservoir or well as a result of well treatments. It is further object of the invention to characterise at least one fracture between wells in a hydrocarbon well system, an enhanced geothermal system or mineral extraction system. Further aims and objects of the invention will become apparent from reading the following description. According to a first aspect of the invention there is provided a method of characterising at least one fracture in a well system comprising a first well and at least a second well, the method comprising: forming at least one fracture from the first well to at least a second well; injecting at least a first tracer into the at least one fracture; locating at least a second tracer in or at the at least one fracture; producing fluid from the at least a second well, collecting samples of produced fluid; analysing the samples for the presence and / or concentration of tracers; calculating at least one flow characteristic for the at least one fracture based on the presence and / or concentration of tracers in the samples. The method may comprise locating or positioning the second tracer at the start of the fracture in the first well. The method may comprise locating or positioning the second tracer at a location in the at least one fracture near the well bore of the first well. The method may comprise locating or positioning the second tracer at a known location in or at the at least one fracture. The method may comprise localising the second tracer at a location at the start of the at least one fracture. The method may comprise injecting the second tracer into the at least one fracture. The purpose of the second tracer may be to trace the start of the at least one fracture in the first well so that the length and / or volume of the at least one fracture may be determined. The first tracer may be configured to occupy at least part or all of the fluid volume of the at least one fracture. The second tracer may be configured to be localised to a location or position at the start of the at least one fracture when placed in the at least one fracture. The first tracer may be a fracture tracer. The first tracer may be a mass balance tracer. The second tracer may be a pulse tracer. The method may comprise producing fluid from or in the at least a second well to draw, pull and / or direct tracer and fluid in the at least one fracture into the second well. The method may comprise circulating at least one circulation tracer from the first well to the second well with a circulated fluid. The at least one circulation tracer may be configured to pass through at least one fracture from the first well to the at least a second well. The at least one circulation tracer may be configured to pass through two or more fractures from the first well to the at least one second well. The at least one circulation tracer may be configured to pass through multiple fractures from the first well to the at least one second well. The at least one circulation tracer may be configured to pass through all of the fractures from the at least one first well to the at least one second well. The method may comprise repeating the circulation test for different injection rates into the injector well. The method may comprise repeating the circulation test for different production rates from the production well. The method may comprise circulating fluid from the first well to a second well at different flow rates. The method may comprise circulating fluid from the first well to a second well two or more flow rates. The method may comprise circulating fluid from the first well to a second well at multiple flow rates. At least one distinct circulating tracer may be used for each different flow rate. The method may comprise collecting samples of fluid from the second well during a period of stable flow. The method may comprise producing fluid from the at least one second well to draw, pull and / or direct flow from the at least one fracture into the at least one second well. The method may comprise producing fluid from the at least one second well to draw, pull and / or direct the first tracer and / or second tracer located in the at least one fracture into the at least one second well. The method may comprise producing fluid from the at least one second well to draw, pull and / or direct tracer and fluid in or through the at least one fracture into at least the second well. The method may comprise producing fluid from the at least one second well to draw, pull and / or direct at least one tracer located in two or more fractures into the at least one second well. The method may comprise producing fluid from the at least one second well to draw, pull and / or direct at least one tracer located in two or more fracture into the at least one second well. The method may comprise producing fluid from the at least one second well to draw, pull and / or direct tracer located in each fracture into the at least one second well. The method may comprise producing fluid at different flow rates. The method may comprise drawing, pulling and / or directing flow from the at least one fracture into the at least one second well at different flow rates. The method may comprise producing fluid at different flow rates. The method may comprise drawing, pulling and / or directing flow from the at least one fracture into the at least one second well at two or more flow rates. The method may comprise producing fluid at different flow rates. The method may comprise drawing, pulling and / or directing flow from the at least one fracture into the second well at multiple flow rates. The method may comprise collecting samples of fluid from the second well during a period of stable flow. The method may comprise collecting samples of fluid from at least the second well during a period of stable flow. The method may comprise measuring surface flow rate. The method may comprise measuring surface pressure. The method may comprise measuring downhole pressure. The method may comprise measuring downhole flow rate. The method may comprise measuring pressure at a fracture. The method may comprise measuring pressure at each fracture. The method may comprise calculating the bottom-hole pressure. The method may comprise calculating a bottom-hole pressure from measured surface pressure. The method may comprise measuring surface flow rate, measuring surface pressure, measuring downhole pressure, measuring pressure at a stage hydraulic fracture, calculating downhole pressure for each stage fracture and / or measuring pressure at each stage hydraulic fracture while producing from one or more wells and using these data as input for permeability and conductivity calculations. The method may comprise determining an effect of a frac hit on production in a production well. The well system or well combination may comprise a third or further well. The well system or well combination may comprise at least one treatment well. The well system or well combination may comprise at least one production well. The well system or well combination may comprise at least one treatment well and at least one production well. The at least one first well may be at least one treatment well. The at least one second well may be at least one production well. The third or further well may be at least one production well. The at least one treatment well may be an injector well. The at least one treatment well may be an infill well. The at least one treatment well may be a child well. The at least one production may be a parent well. The well system or well combination may comprise two or more treatment wells. The well system or well combination may comprise two or more production wells. The well system or well combination may comprise two or more production wells. The at least one fracture may be formed or created by a well treatment. The well treatment may be stimulation treatment. The well treatment may be selected from the group comprising well stimulation treatment, acidizing treatment, matrix acidizing treatment, fracturing treatment, hydraulic fracturing treatment, fracture acidizing treatment, enhanced oil recovery treatment, and / or water control treatment. The at least one fracture may connect the first well and the at least one second well. The at least one fracture may connect the first well to two or more wells. The at least one fracture may connect the first well to a third or further well. The second, third and / or further well may be offset from the first well. The at least one fracture may connect the first well to multiple wells. The method may comprise forming at least two fractures. The method may comprise forming at least two fracture stages. The method may comprise forming at least two fractures or at least two fracture stages from the first well to the second well. The method may comprise forming at least two fractures or two fracture stages to connect the first well and the at least one second well. The method may comprise forming at least two fractures or two fracture stages to connect the first well to a third or further well. The method may comprise forming multiple fractures or multiple fracturing stages from the first well to the second well. The method may comprise forming multiple fractures or multiple fracture stages to connect the first well and the at least one second well. The method may comprise forming at least two fractures or two fracture stages to connect the first well to two or more wells. The method may comprise forming at least two fractures or two fracture stages to connect the first well and to multiple wells. The method may comprise forming at least two fractures or at least two fracture stages to connect the first well to the second well and at least one other well. The method may comprise forming at least one fracture to connect the first well to the second well and at least one fracture to connect the first well to at least a third or further well. The method may comprise forming two or more fractures. The method may comprise forming multiple fractures. The method may comprise forming two or more fractures or two or more fracture stages to connect the first well to the second well and at least one fracture to connect the first well to at least a third or further well. The method may comprise forming two or more fractures; injecting at least one distinct first tracer into each fracture and locating at least one distinct second tracer at a known position or location in or at each fracture. The method may comprise forming two or more fractures; injecting at least one distinct first tracer into each fracture and locating at least one distinct second tracer at each fracture near the well bore of the first well or at the start of the at least one fracture. The method may comprise forming two or more fractures or two or more fracture stages to connect the first well to the second well and two or more fractures or two or more fracture stages to connect the first well to at least a third or further well. The method may comprise locating the second tracer in, at, upstream or downstream of the at least one fracture. The method may comprise locating the second tracer at a known position or location in or at the at least one fracture. The method may comprise locating a different distinct second tracer at a known position or location in or at each fracture. The method may comprise injecting a distinct first tracer into each fracture or fracture stage. The method may comprise locating a distinct second tracer in each fracture or fracture stage in the second stage. The method may comprise injecting a first distinct first tracer into a first fracture or first fracture stage. The method may comprise injecting a second distinct first tracer into a second fracture or second fracture stage. The method may comprise injecting a third or further distinct first tracer into a third or further fracture or third or further fracture stage. The method may comprise locating a distinct second tracer in each fracture or fracture stage in the second stage. The method may comprise injecting a first distinct second tracer into a first fracture or first fracture stage. The method may comprise injecting a second distinct second tracer into a second fracture or second fracture stage. The method may comprise injecting a third or further distinct second tracer into a third or further fracture or third or further fracture stage. The method may comprise producing fluid from at least the second well to draw, pull and / or direct at least one tracer located in two or more fractures into at least the second well. The method may comprise drawing, pulling and / or directing flow from or through the at least one fracture into at least the second well at different flow rates. The well combination may comprise a first well, a second well and a third or further well. The at least one fracture may extend from the first well to the second well and / or third or further wells. The method may comprise producing fluid from the second, third or further well to draw, pull and / or direct at least one tracer located in at least one fracture into the second, third or further well. Two or more fractures may extend from the first well to the second well and / or third or further wells. The method may comprise producing fluid from the second, third or further well to draw, pull and / or direct at least one tracer located in each fracture into the second, third or further well. The method may comprise producing fluid from the second, third or further well to draw, pull and / or direct at least the first tracer and / or second tracer located in each fracture into the second, third or further well. The method may comprise characterising at least one fracture flow path. The method may comprise characterising at least one fracture flow path volume. The method may comprise characterising flow from, through and / or in each fracture in the well. The method may comprise characterising a fracture flow path volume of each fracture in the well system. The method of characterising a hydraulic connection between the first well and at least a second well. The method of characterising permeability between the first well and at least a second well. The method of characterising a hydraulic connection between the first well and at least a third or further well. The method of characterising permeability between the first well and at least a third or further well. The method may include calculating at least one flow characteristic and / or at least one fracture characteristic selected from the group comprising perforation clusters per stage; fracture geometry; fracture fluid volume; fracture width; hydraulic width; fracture aperture; hydraulic cross-sectional area; cross-sectional area of flow; percentage flow distribution; percentage flow distribution per stage; proppant transport capacity; fracture circulation volume; fracture circulation volume per stage; permeability; permeability per stage; conductivity; conductivity per stage and / or fracture hydraulic conductivity. The at least one well system may be a hydrocarbon well system. The at least one well system may be a hydrocarbon reservoir system. The at least one well system may be a geothermal well system. The at least one well system may be an enhanced geothermal system. The at least one well system may be a mineral extraction well system. The method may comprise injecting the first tracer into the at least one fracture during the formation of the at least one fracture. The method may comprise injecting the first tracer in the fracture fluid. The method may comprise injecting the first tracer into a fracture after the at least one fracture has been formed. The distinct first tracer may be injected as mass balance tracer. Each first tracer may be injected as mass balance tracer at a constant concentration throughout each fracture stage. The method may comprise injecting a different first tracer into each fracture. The method may comprise locating a different second tracer in each fracture. The first tracer may be a primary tracer. The second tracer may be a secondary tracer. The method may comprise injecting a first primary tracer into a first fracture stage. The method may comprise injecting a different primary tracer into a second fracture stage. The method may comprise injecting a second primary tracer into a second fracture stage. The method may comprise injecting a different primary tracer into a third or further fracture. The method may comprise injecting a third or further primary tracer into a third or further fracture stage. The first, second, third and / or further primary tracers may be distinct from one another. The second tracer may be a secondary tracer. The method may comprise locating a first secondary tracer in a first fracture stage. The method may comprise locating a different secondary tracer into a second fracture stage. The method may comprise locating a second secondary tracer into a second fracture stage. The method may comprise locating a different secondary tracer into a third or further fracture. The method may comprise locating a third or further secondary tracer into a third or further fracture stage. The first, second, third and / or further secondary tracers may be distinct from one another. Each primary tracer may be associated with a respective fracture stage. Each secondary tracer may be associated with a respective fracture stage. The method may comprise associated each fracture stage with a distinct first and / or second tracer. The method may comprise filling or occupying a volume of the at least one fracture with a distinct primary tracer. The distinct primary tracers may be injected as mass balance tracer. The at least one primary tracer may be injected as mass balance tracers at a constant concentration throughout each fracture stage. The method may comprise locating at least one secondary tracer in the at least one fracture at the near wellbore. The first tracer and second tracer may be distinct from one another. The primary tracer and secondary tracer may be distinct from one another. Each primary tracer may be distinct from the other primary tracers and the secondary tracers. The secondary tracers may be distinct from the other secondary tracers and the primary tracers. Each tracer may be a distinct tracer. Each tracer in each of a first, second, third or further fracture may be distinct tracers. Each fracture stages may comprise distinct tracers. The first and second stage hydraulic fractures may comprise distinct tracers. Each tracer may be distinguishable from other tracers by differences in chemical and / or physical appearances. Each tracer may be distinguishable from other tracers in amount or concentration. Each tracer may be distinguishable from other tracers in tracer combinations of distinguishable differences. The first tracer and second tracer may be the same type of tracer but present at a different concentration. The difference in concentration level between the first and second tracer may provide a distinguishable tracer response. Preferably the first tracer is a fracture tracer. The first tracer may be a first fracture stage tracer. The method may comprise injecting a first fracture stage tracer into a first fracture stage. The method may comprise injecting the first fracture tracer into a first stage hydraulic fracture. The method may comprise injecting a different tracer into a second fracture stage. The method may comprise injecting a second fracture stage tracer into a second fracture stage. The method may comprise injecting a second fracture stage tracer into a second stage hydraulic fracture. The method may comprise injecting a different tracer into a third or further fracture. The method may comprise injecting a third or further fracture tracer into a third or further fracture stage. The method may comprise injecting a third or further fracture tracer into a third or further stage hydraulic fracture. The first, second, third and / or further fracture tracers may be distinct from one another. Preferably the second tracer is a pulse tracer. The second tracer may be a first fracture stage pulse tracer. The method may comprise locating a first pulse tracer into a first fracture stage. The method may comprise locating the first pulse tracer into a first stage hydraulic fracture. The method may comprise locating a different pulse tracer into a second fracture stage. The method may comprise locating a second pulse tracer into a second fracture stage. The method may comprise locating a second pulse tracer into a second stage hydraulic fracture. The method may comprise locating a different pulse tracer into a third or further fracture. The method may comprise locating a third or further pulse tracer into a third or further fracture stage. The method may comprise locating a third or further pulse tracer into a third or further stage hydraulic fracture. The first, second, third and / or further pulse tracers may be distinct from one another. Each fracture stage tracer may be associated with a respective fracture stage. The method may comprise associated each fracture stage with a distinct fracture tracer. The method may comprise filling or occupying a volume of the at least one fracture with a distinct fracture stage tracer. The distinct fracture tracers may be injected as mass balance tracers. The at least one fracture tracer may be injected as mass balance tracers at a constant concentration throughout each fracture stage. Each pulse tracer may be associated with a respective fracture stage. The method may comprise locating at least one pulse tracer in the at least one fracture at the near wellbore. The method may comprise introducing at least a first tracer into a well before and / or with the well treatment. The method may comprise introducing the at least one first tracer into a well at an early stage or portion of the well treatment. The method may comprise introducing the at least one first tracer into a well before and / or with a first well treatment. The method may comprise introducing the at least one second tracer into a well at a known time after introducing the at least one first tracer into the well. The method may comprise introducing the at least one second tracer into a well at a later stage or later portion of the well treatment or after at least one well treatment stage has been completed or approaching completion. The method may comprise introducing the first tracer into a well before and / or with the well treatment and introducing at least the at least one second tracer into a well at a later stage or later portion of the well treatment or after at least one well treatment stage has been completed or approaching completion. The method may comprise introducing a plurality of tracers into the well. The method may comprise introducing at least two tracers into each fracture. The method may comprise locating a distinct second tracer into each of the first or second stage hydraulic fractures. The method may comprise injecting a distinct second tracer into each of the first or second stage hydraulic fractures. The second tracer may be introduced, placed and / or deployed in the last proppant stage. The second tracer may be introduced, placed and / or deployed in the flush stage of the last fracturing stage. The second tracer may be introduced, placed and / or deployed during post-fracturing injections such as during plug milling. The method may comprise a multistage fracture treatment comprising two or more fracture stages from the first well. The method may comprise multistage fracture treatments comprising two or more hydraulic fracture stages from the first well. The method may comprise multistage fracture treatments comprising three or more fracture stages from the first well. The method may comprise multistage fracture treatments comprising three or more hydraulic fracture stages from the first well. The method may comprise injecting at least one distinct first tracer into each stage hydraulic fracture. The method may comprise locating at least one distinct second tracer into each stage hydraulic fracture. The method may comprise forming and / or characterising two or more fractures. The method may comprise forming and / or characterising a plurality of fractures. The method may comprise injecting the at least one first and / or second tracer into a fracture during forming of the at least one fracture. The method may comprise injecting the at least one first and / or second tracer into at least one fracture from surface. The method may comprise injecting the at least one first and / or second tracer into at least one fracture from a downhole device. The method may comprise injecting the at least one first and / or second tracer into at least one fracture from a tracer source installed, arranged or positioned in the first well. The at least one tracer source may be installed, arranged or positioned in the first well. The method may comprise introducing the at least one first and / or second tracer into the well by releasing the tracer from an installed, arranged or positioned tracer source in the well. Each of the at least one first and / or second tracers may be installed, arranged or positioned as a tracer source in the well in the vicinity of a well stimulation treatment zone. The method may comprise releasing the at least one first and / or second from the tracer source into the first well. The at least one first and / or second tracer may be released or injected into the first well via a tracer injection device. The tracer injection device may be permanently installed in a well or injection site. The method may comprise pumping the released at least first and / or second tracer into the first and / or second fracture stage. At least one first tracer may be premixed with a well stimulation treatment fluid and / or injection fluid. The at least one first tracer may be co-injected with a well stimulation treatment fluid and / or injection fluid. The at least one first tracer may be added to the well stimulation treatment fluid and / or injection fluid. The at least one first tracer and the well stimulation treatment fluid and / or injection fluid may be introduced and / or released into the injection well. The at least one first tracer may be co-released with the well stimulation treatment fluid and / or injection fluid. The at least one first and / or second tracer may be a chemical tracer. The at least one first and / or second tracer may be a non-radioactive tracer. The at least one first and / or second tracer may be injected with or comprise a proppant. The at least one first and / or second tracer may be configured to release at a known rate from proppant or proppant particles. The at least one first and / or second tracer may be selected from the group comprising chemical, fluorescent, phosphorescent and radioactive compounds isotope, isotope signature, stable isotope, radioactive isotope of elements constituting a part of a tracer molecule. The at least one first and / or second tracer may comprise stable or radioactive isotopes of elements constituting a part of a tracer molecule, quantum dot, nanoparticles, or a combination thereof. Multiple tracer types for the first and / or second tracers may be used. Multiple tracer combinations may be used. The at least one first and / or second tracer may be a water tracer. The at least one first and / or second tracer may be a solid, liquid or gas. The at least one first and / or second tracer may be applied in solution. The at least one first and / or second tracer may be in a semi-crystalline or crystalline form. The at least one first and / or second tracer may be attached to or comprise a proppant. The at least one first and / or second tracer may be configured to be soluble and / or dissolve in water. The at least one first and / or second tracer may be a perfluorinated compounds. The at least one first and / or second tracer may be an organofluorine compound with hydrogen replaced by fluorine. The at least one first and / or second tracer may be a perfluorocarbon. The at least one first and / or second tracer may comprise chemical tracers 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 tracer material may comprise polyfunctionalized polyethylene or polypropylene glycols. The tracer material may be an inflow tracer. The at least one first and / or second tracer may be a nanoparticle. The at least one first and / or second tracer may be a quantum dot. The at least one first and / or second tracer may be a naphthalene sulphonic acid. The at least one first and / or second tracer may be a water tracer. The at least one first and / or second tracer may be an oil tracer. The at least one first and / or second tracer may be a gas tracer. The tracer material may be designed to release tracer molecules when exposed to a target fluid i.e. oil, gas or water. The tracer material and / or tracer source may comprise a tracer and a carrier. The carrier may be a matrix material. The matrix material may be a polymeric material. The tracer may be chemically immobilized within and / or to the carrier. The tracer material may be chemically immobilized and configured to release tracer molecules or particles in the presence of a chemical trigger or specific fluid. The carrier may be a polymer. The tracer may be physically dispersed and / or physically encapsulated in the carrier. The tracer material may release tracer molecules into fluid by dissolution, diffusion and / or degradation of the carrier and / or the tracer into the produced fluid. The carrier may be selected to controllable degrade on contact with the produced fluid into the production well. The carrier may be selected to degrade by hydrolysis of the carrier. The tracer and / or the carrier may be fluid specific such that the tracer molecules will be released from the tracer material as a response to a contact with a target liquid such as the injection fluid or produced fluid. The tracers and / or the carrier may be chemically intelligent such that tracer molecules will be released from the tracer material as a response the exposure of the tracer material to a target fluid. Each of the tracer release device may be configured to release one distinct tracer. Each of the tracer release device may be configured to release two or more distinct tracers. The at least one tracer may be a liquid, solid or gas. The at least one tracer may be a powdered solid. The method may comprise identifying at least one first tracer in the samples. The method may comprise identifying at least one second tracer in the samples. The method may comprise obtaining fluid samples from the second well. The method may comprise obtaining produced fluid from the second well. The method may comprise obtaining fluid samples from a third or further well. The method may comprise obtaining produced fluid from a third of further 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 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 second 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 tracer in the sampled fluid. The method may comprise detecting the presence and / or concentration of tracer in the sampled fluid in real time. The method may comprise detecting the presence and / or concentration of tracer in the sampled fluid using an online analyser. The method may comprise measuring a concentration of at least one first and / or second tracer in the sampled fluid. The method may comprise measuring a concentration of at least one first and / or second tracer in the sampled fluid in real time. The method may comprise measuring a concentration of at least one tracer in the sampled fluid using an online analyser. The sample collection may be an automated process. The method may comprise determining the type of tracer or tracers in the sample. The method may comprise measuring and / or monitoring the concentration of tracer in the at least one sample. The method may comprise measuring and / or monitoring the transport time of the at least one tracer. The method may comprise calculating at least one flow characteristics for the at least one fracture based on the arrival time of the first tracer and / or the second tracer. The method may comprise calculating at least one flow characteristic for the at least one fracture based on the arrival time of tracer in the samples. The method may comprise measuring and / or monitoring the arrival time of the at least one tracer from injection to detection in the produced fluid. The method may comprise measuring and / or monitoring the arrival time of the at least one first tracer in the produced fluid. The method may comprise measuring and / or monitoring the arrival time of the at least one second tracer in the produced fluid. The first, second, third and / or further tracer may correspond to a first, second, third and / or further fracture stage in the treatment well respectively. The method may comprise measuring and / or monitoring the arrival time of a first fracture tracer in the produced fluid. The method may comprise measuring and / or monitoring the arrival time of a first fracture pulse tracer in the produced fluid. The method may comprise measuring and / or monitoring the arrival time of a second fracture tracer in the produced fluid. The method may comprise measuring and / or monitoring the arrival time of a second fracture pulse tracer in the produced fluid. The method may comprise measuring and / or monitoring the arrival time of the third or further fracture tracer in the produced fluid. The method may comprise measuring and / or monitoring the arrival time of the third or further fracture pulse tracer in the produced fluid. The method may comprise shutting in the first well. The method may comprise controlling and / or modifying production of fluid in the first well. The method may comprise controlling and / or modifying the production flow rate of fluid in the first well to a production rate less than or equal to a production rate of at least a second well. The method may comprise controlling and / or modifying the production flow rate of fluid in the first well to a production rate less than or equal to the production rate of a third or further well. The method may comprise controlling and / or modifying the production flow rate of fluid in the first well to a production rate less than or equal to the production well. The method may comprise starting clean-up and / or production in the second well. The tracers 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. The method may comprise analysing the arrival of tracer concentration of each tracer in the second well. The method may comprise analysing the arrival of tracer concentration of each tracer in the samples. The method may comprise analysing the arrival of tracer concentration of each tracer in a third or further well. The method may comprise analysing tracer data for each tracer for each fracture stage. The method may include calculating a flow characteristic by quantifying a proportion of flow from each stage in the offset producer(s) by performing a dilution calculation. The method may include calculating a flow characteristic by quantifying a proportion of flow from each fracture stage in the offset producer(s) by performing a dilution calculation. The method may include calculating a flow characteristic by quantifying a proportion of flow from each fracture stage in the at least second well by performing a dilution calculation. The method may include calculating a flow characteristic by quantifying a proportion of flow from each fracture stage by performing a dilution calculation. The method may comprise calculating a mathematical derivative of a tracer response curve. The calculated derivative may be characterized by means of Residence Time Distribution (RTD) analysis. The RTD analysis may include assisted history matching to calculate the flow characteristics. The method may comprise assessing fractures between hydrocarbon wells. The method may comprise assessing fractures between geothermal wells. The method may comprise assessing at least one fracture between at least one injector well and at least one production well in a geothermal well system. By fracture it is meant one or more physical cracks, voids or an increase in permeability between the first well and at least the second well. In the case of a third or further well, one or more physical cracks, voids or an increase in permeability between the first well and the third or further well. It is not necessary for a crack or void extending from the first well to physically intersect with the second well, third well and / or further well. However, the fracture from the first well may form a hydraulic or fluid connection with at least the second well, third well and / or further well. This may be through induced cracks or voids alone or a combination of induced cracks or voids interacting with existing permeability in the well system. The at least one fracture may improve the permeability though the matrix between the first well and at least the second well, third well and / or further well. The at least one fracture may intersect at least one producer well. The well system may be an unconventional well system. The method may comprise at least one fracture which may intersect at least one producer well creating at least one frac hit. The method may comprise characterising the at least one fracture and / or the at least one frac hit. The method may comprise determining the effect of a frac hit on production in the production well. The method may comprise carrying out one or more fracture treatments with the aim of establishing a fluid connection between the first well and at least one second well. The at least one second well may be offset from the first well. The at least one third or further well may be offset from the first well. The first well may have been previously fractured. The at least on second well may have been previously fractured. The method may comprise carrying out one or more fracture treatments with the aim of establishing a fluid connection between the first well and a third or further well. The third or further well may have been previously fractured. The method may comprise determining and / or calculating the fracture flow path volume of each fracture. The method may comprise calculating a fracture flow path volume of the at least one fracture. The method may comprise calculating a fracture flow path volume based on the detection of the at least one first tracer and the at least one second tracer in the samples. The method may comprise calculating residence time (time of travel) from a frac hit location in the production well to the sampling location. The method may comprise detecting the second tracer in samples collected from the produced fluid to provide the residence time (time of travel) from the start of the fracture to the sample point. The method may comprise calculating a residence time of the fracture by subtracting the arrival time of first tracer in the samples from the residence time of second tracer. The method may comprise calculating the time of travel through the fracture based on the difference in arrival times for the first tracer and the second tracer for each fracture stage. The method may comprise calculating a production rate of each fracture based on the dilution of the concentration of the first tracer (associated with each fracture stage). The method may comprise calculating or determine a percentage of the flow in well is allocated from a fracture based on a percentage dilution of the at least one first tracer (associated with each fracture stage). The method may comprise calculating a production rate of each fracture based on the dilution of the concentration of the first tracer (associated with each fracture stage) multiplied by the total flow rate of production well during cleanup and / or production. The method may comprise interpreting at least one flow characteristics of the at least one fracture. The method may comprise assessing tracer type curve. The at least one flow characteristics may be selected from the group comprising duning, channelling, open fractures, cluster runaway, and micro-annulus impact the effectiveness of hydrocarbon production. The method may comprise calculating a fracture flow path volume of the at least one fracture based on the production rate of fracture multiplied by the time of travel of second tracer (tracer pulse). The method may comprise calculating a fracture flow path efficiency. The method may comprise interpreting characteristics of the flow path such as flow through open fractures. The method may comprise calculating the percentage of propped fracture surface area (e.g., based on fracture simulations for fracture geometry, stimulated reservoir volume from microseismic data, and / or similar fracture geometry information). The method may comprise calculating the flow path percentage of the fracture treatment volume. The method may comprise obtaining treatment data such as injected fluid type, injection rate, proppant mass and / or treatment volumes. The method may comprise optimising the well treatment by adjusting one or more parameters selected from the group comprising stimulation fluid type, fluid viscosity, fluid reactivity, acid concentration, additive concentration, injection volume, injection rates, pulsing, proppant concentrations, fluid loss additive concentration and / or diverting agents. The method may comprise optimising a well treatment by adjusting additional treatment and / or changing the treatment design in subsequent stages or subsequent wells. The method may comprise constructing a model of the well system stimulation treatment(s). The method may comprise constructing a model of the well system stimulation treatment(s) to estimate the geometry of the created fractures and propped fracture geometry. The method may comprise constructing a model of the reservoir from measured physical data. The method may comprise constructing the model from historical measured data. The method may comprise constructing the model from historical physical data. The method may comprise analysing a measured tracer data set for each of the two or more tracers (first and / or second tracer) from each fracture stage. The measured tracer data set may be a tracer concentration as a function of time. The method may comprise calculating at least one flow characteristic for the at least one fracture based on the concentration of tracer(s) as a function of time. The measured tracer data set may be a tracer concentration time series. The measured tracer data set may be a residence time distribution. Each of the two or more tracers from each fracture may be a water tracer, an oil tracer and / or a gas tracer. The measured tracer data set may be a tracer concentration as a function of space. The measured tracer data set may be a tracer concentration measured at distinct positions in space. The measured tracer data set may be a spatial distribution of tracer. The method may comprise calculating a residence time distribution data set for each of the two or more tracers from each fracture stage. The method may comprise calculating a residence time distribution data set for each tracer from each fracture. The method may comprise measuring injection rates, production rates, surface pressures and / or bottom hole pressures in the production wells and / or the treatment well. The bottom hole pressure may be measured by downhole pressure gauges or calculated based on surface well pressures. The tracer data may provide a direct measure of flow rate per flow path. The method may comprise calculating a permeability of the fracture flow paths per stage. The method may comprise calculating a permeability of the fracture flow paths based on the fracture circulation volume calculated from tracer data. The method may comprise determining a downhole pressure difference between the first well and the at least one second well. The method may comprise determining a pressure drop across the at least one fracture connecting the wells. The method may comprise determining a downhole pressure difference based on the measured or calculated downhole pressures. The method may comprise calculating a percent flow profile per fracturing stage based on tracer response measured in samples taken from the produced fluid from the production well. The production profile may represent a flow profile through the fracturing stages connecting the treatment well and / or production wells. The method may comprise calculating flow rate per fracture based on the percent flow contribution multiplied by the total production well flowrate measured at surface and divided by the number of stimulated perforation clusters per stage. According to a second aspect of the invention there is provided a method of characterising at least one fracture in a well system comprising at least one treatment well and at least one production well, the method comprising: forming at least one fracture from the at least one treatment well to the at least one production well; injecting a first tracer into the at least one fracture; locating a second tracer in or at the at least one fracture; producing fluid from the at least one production well, collecting samples of produced fluid; analysing the samples for the presence and / or concentration of tracers; calculating at least one flow characteristic for the at least one fracture based on the presence and / or concentration of tracers in the samples. The first tracer may be a first fracture stage tracer. The first tracer may be a first fracture tracer. The second tracer may be present and / or located in at least part of the fracture. The second tracer may be a pulse tracer. The second tracer may be a pulse tracer located near the start of the at least one fracture. The method may comprise injecting the first fracture tracer into the fluid volume of the at least one fracture. The method may comprise localising the pulse tracer at a location at the start of the at least one fracture. The method may comprise localising the pulse tracer at a location in the fracture near the wellbore of the at least one treatment well. 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. According to a third aspect of the invention there is provided a method of characterising at least one fracture in a well system comprising at least one injection well and at least one production well, the method comprising: forming at least one fracture from the at least injection well to the at least one production well; injecting a first tracer into the at least one fracture; producing fluid from the at least one production well, collecting samples of produced fluid; calculating at least one fracture characteristic based on the presence and / or concentration of tracer in the samples. The method may comprise injection or locating a second tracer in, at, upstream or downstream of the at least one fracture. The method may comprise analysing the samples for the presence and / or concentration of tracers. The method may comprise circulating at least one circulation tracer from the injection well to the production well with a circulated fluid. The at least one circulation tracer may be configured to pass through at least one fracture from the injection well to the at least a production well. The at least one circulation tracer may be configured to pass through two or more fractures from the injection well to the at least one production well. The at least one circulation tracer may be configured to pass through multiple fractures from the injection well to the at least one production well. The at least one circulation tracer may be configured to pass through all of the fractures from the at least one injection well to the at least one production well. The method may comprise repeating the circulation test for different injection rates into the injector well. The method may comprise repeating the circulation test for different production rates from the production well. The method may comprise circulating fluid from the injection well to a production well at different flow rates. The method may comprise circulating fluid from the injection well to a production well two or more flow rates. The method may comprise circulating fluid from the injection well to a production well at multiple flow rates. At least one distinct circulating tracer may be used for each different flow rate. The method may comprise collecting samples of fluid from the production well during a period of stable flow. The method may comprise producing fluid from the production well to draw, pull and / or direct flow from the injection well into the production well. The method may comprise producing fluid from the production well to draw, pull and / or direct flow from the at least one fracture into the production well. The method may comprise producing fluid from the production well to draw, pull and / or direct the first tracer and / or second tracer located in the at least one fracture into the production well. The method may comprise producing fluid from the production well to draw, pull and / or direct at least one tracer located in two or more fractures into the production well. The method may comprise producing fluid from the production well to draw, pull and / or direct at least one tracer located in two or more fracture into the production well. The method may comprise producing fluid from the production well to draw, pull and / or direct tracer located in each fracture into the production well. The first tracer may be a first fracture stage tracer. The first tracer may be a first fracture tracer. The second tracer may be present and / or located in at least part of the fracture. The second tracer may be a pulse tracer. The second tracer may be a pulse tracer located near the start of the at least one fracture. The method may comprise injecting the first fracture tracer into the fluid volume of the at least one fracture. The method may comprise localising the pulse tracer at a location at the start of the at least one fracture. The method may comprise localising the pulse tracer at a location in the fracture near the wellbore of the at least one treatment well. The method may include calculating at least one flow characteristic and / or at least one fracture characteristic selected from the group comprising perforation clusters per stage; fracture geometry; fracture fluid volume; fracture width; fracture aperture; cross-sectional area of flow; percentage flow distribution; percentage flow distribution per stage; proppant transport capacity; fracture circulation volume; fracture circulation volume per stage; permeability; permeability per stage; conductivity; conductivity per stage and / or fracture hydraulic conductivity. Embodiments of the third aspect of the invention may include one or more features of the first or second aspects of the invention or its embodiments, or vice versa. According to a fourth aspect of the invention there is provided a method of characterising at least one fracture in a well system comprising at least one first well and at least one second well, the method comprising: injecting at least a first stage fluid to form at least one fracture from the at least one first well to the at least one second well; injecting at least a first tracer into the at least one fracture; locating at least a second tracer in or at the at least one fracture located near to the wellbore of the at least one first well; producing fluid from the at least one production well, collecting samples of produced fluid; analysing the samples for the presence and / or concentration of tracers; calculating at least one flow characteristic for the at least one fracture and / or at least one fracture characteristic based on the presence and / or concentration of tracers in the samples. The at least one first well may be a treatment well. The at least one second well may be a production well. The first tracer may be a fracture tracer. The second tracer may be a pulse tracer. The method may comprise injecting the at least one first tracer into the fracture fluid. The at least one first tracer may be premixed with a well stimulation treatment fluid, fracture fluid and / or injection fluid. The at least one first tracer may be co-injected with a well stimulation treatment fluid, fracture fluid and / or injection fluid. The at least one first tracer may be added to the well stimulation treatment fluid, fracture fluid and / or injection fluid. The at least one first tracer and the well stimulation treatment fluid, fracture fluid and / or injection fluid may be introduced or released into the injection well. The at least one first tracer may be co-released with the well stimulation treatment fluid and / or injection fluid. The method may comprise localising the at least second tracer at a location at the start of the at least one fracture. The purpose of the at least second tracer may be to trace the start of the fracture in the treatment well so that the length and / or volume of the fracture may be determined. The at least one first tracer may be configured to occupy at least some of the fluid volume of the at least one fracture. The at least one second tracer may be configured to be localised to a location or position at the start of the at least one fracture when placed in the at least one fracture. The method may include calculating at least one flow characteristic and / or at least one fracture characteristic selected from the group comprising perforation clusters per stage; fracture geometry; fracture fluid volume; fracture width; fracture aperture; cross-sectional area of flow; percentage flow distribution; percentage flow distribution per stage; proppant transport capacity; fracture circulation volume; fracture circulation volume per stage; permeability; permeability per stage; conductivity; conductivity per stage and / or fracture hydraulic conductivity. 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. According to a fifth aspect of the invention there is provided a method of characterising at least one fracture in a well system comprising at least one treatment well and at least one production well, the method comprising: injecting at least a first fracture stage fluid to form first fracture from the at least one treatment well to the at least one production well; injecting a first tracer into the first fracture fluid; locating a second tracer in or at the first fracture located near to the wellbore; producing fluid from the at least one production well, collecting samples of produced fluid; analysing the samples for the presence and / or concentration of tracers; calculating at least one flow characteristic for the at least one fracture and / or at least one fracture characteristic based on the presence and / or concentration of tracers in the samples. The first tracer may be a fracture tracer. The method may comprise injecting a first fracture tracer into the first fracture fluid. The first tracer may be a first fracture tracer. The second tracer may be a pulse tracer. The method may comprise locating a pulse tracer in the at least one fracture located near to the wellbore. The second tracer may be a first pulse tracer. The method may comprise injecting a second fracture stage fluid to form a second fracture from the at least one treatment well. The method may comprise injecting a distinct first tracer into the second fracture fluid and locating a distinct second tracer in the second fracture located near to the wellbore. The method may comprise injecting a second fracture tracer into the second fracture fluid. The method may comprise locating a second pulse tracer in the second fracture located near to the wellbore. The method may comprise producing fluid from the at least one production well. The method may comprise calculating at least one flow characteristics for the first fracture and / or the second fracture based on the presence and / or concentration of tracers in the samples. The first fracture may connect the at least one treatment well with a first production well. The second fracture may connect the at least one treatment well to the first production well. The second fracture may connect the at least one treatment well to a second or different production well. 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. According to a sixth aspect of the invention there is provided a method of characterising flow between wells in a well system comprising at least one first well and at least one second well, the method comprising: forming a first fracture stage from the at least one first well of the well system to the at least one second well; injecting a first fracture tracer into the first fracture stage; locating a first pulse tracer into the first fracture stage; forming a second fracture stage from the first well; injecting a second fracture tracer into the second fracture stage; locating a second pulse tracer into the second fracture stage; producing fluid in the second well to draw or pull flow through the first fracture stage and / or second fracture stage into the second well; collecting samples of fluid from the second well and analysing tracer concentrations with respect to sampling time. The method may comprise calculating a flow characteristic for the first stage and / or second fracture stages from the analysis of the tracer concentrations. The method may comprise calculating a flow characteristic for each of the first stage and / or second fracture stages from the analysis of the tracer concentrations. The second fracture stage may be configured to connect the first well with the second well. The second fracture stage may be configured to connect the first well with a third or further well. The method may comprise forming a third or further fracture stage from the first well to the at least one second well. The method may comprise injecting a third or further fracture tracer into the third or further fracture stage. The method may comprise locating a third or further pulse tracer into the third or further fracture stage. The method may comprise calculating a flow characteristic for the third or further fracture stages from the analysis of the tracer concentrations. The method may comprise calculating a flow characteristic for each of the fracture stages from the analysis of the tracer concentrations. The third or further fracture stage may be configured to connect the first well to the second well. The third or further fracture stage may be configured to connect the first well to a third or further well. The method may comprise forming a first fracture stage from the at least one treatment well of the well system to the at least one production well. The method may comprise forming a first fracture stage from a first treatment well of the well system to a first production well. The method may comprise forming a second fracture stage from the first treatment well of the well system to a second production well. The first and second production wells may be different wells. The method may comprise forming a first fracture stage from a first treatment well of the well system a first production well. The method may comprise forming a second fracture stage from a second treatment well of the well system to the first production well. The first and second treatment wells may be different wells. The method may comprise injecting and / or releasing a second fracture tracer into the second fracture stage. The method may comprise locating a second pulse tracer in the second fracture stage located near to the wellbore. The method may comprise injecting the second fracture tracer in the second fracture stage fluid. The method may comprise injecting the second fracture tracer in the second fracture stage fluid during the second fracture stage operation. The method may comprise injecting and / or releasing a third or further fracture tracer into a third or further fracture stage. The method may comprise locating a third or further pulse tracer in the third or further fracture stage located near to the wellbore. The method may comprise injecting the third or further fracture tracer in the third or further fracture stage fluid. The method may comprise injecting the third or further fracture tracer in the third or further fracture stage fluid during the third or further fracture stage operation. The method may comprise introducing each of the fracture tracers at known different times and / or stages of the well treatment. The method may comprise introducing the first fracture tracer into a well before and / or with the first stage well treatment. The method may comprise introducing the first fracture tracer into a well before and / or with the first stage treatment fluid. The method may comprise introducing the first fracture tracer into the well at an early stage or portion of the first stage well treatment. The method may comprise introducing the second fracture tracer into a well before and / or with the second stage well treatment. The method may comprise introducing the second fracture tracer into a well before and / or with the second stage treatment fluid. The method may comprise introducing the second fracture tracer into the well at an early stage or portion of the second stage well treatment. The method may comprise introducing the third or further fracture tracer into a well before and / or with the third or further stage well treatment. The method may comprise introducing the third or further fracture tracer into a well before and / or with the third or further stage treatment fluid. The method may comprise introducing the third or further fracture tracer into the well at an early stage or portion of the third or further stage well treatment. The method may comprise introducing a first pulse tracer into the well at a known time after introducing the first fracture tracer into the well. The method may comprise introducing the first pulse tracer into a well at a later stage or later portion of the well treatment or after the at least one well treatment stage has been completed or approaching completion. The method may comprise locating the first pulse tracer in the first fracture near the well bore of the treatment well. The method may comprise introducing a second pulse tracer into a well at a known time after introducing the second fracture tracer into the well. The method may comprise introducing the second pulse tracer into a well at a later stage or later portion of the well treatment or after the at least one well treatment stage has been completed or approaching completion. The method may comprise locating the second pulse tracer in the second fracture near the well bore of the treatment well. The method may comprise introducing a third or further pulse tracer into a well at a known time after introducing the third or further fracture tracer into the well. The method may comprise introducing the third or further pulse tracer into a well at a later stage or later portion of the well treatment or after the at least one well treatment stage has been completed or approaching completion. The method may comprise locating the third or further pulse tracer in a third or further fracture near the well bore of the treatment well. 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. According to a seventh aspect of the invention there is provided a method of characterising flow between wells in a well system comprising at least one treatment well and at least one production well, the method comprising: injecting at least a first fracture stage fluid to form a first fracture stage from the at least one treatment well to the at least one production well; injecting a first tracer into the first fracture stage fluid; locating a second tracer in or at the at least one fracture located near to the wellbore; producing fluid from the at least one production well, collecting samples of produced fluid; analysing the samples for the presence and / or concentration of tracers; calculating at least one flow characteristic of the at least one fracture based on the presence and / or concentration of tracers in the samples. The first stage tracer may be a first fracture tracer. The second stage tracer may be a second fracture tracer The method may comprise injecting a distinct stage tracer into each of the first or second stage hydraulic fractures. The method may comprise injecting a distinct fracture tracer into each of the first or second stage hydraulic fractures. The method may comprise locating a distinct pulse tracer into each of the first hydraulic fracture stage or second hydraulic fracture stage. The method may comprise injecting a distinct pulse tracer into each of the first or second hydraulic fracture stages. Preferably the first stage tracer and the second stage tracer are distinct. The method may comprise injecting at least a second fracture stage fluid to form a second fracture stage from the at least one treatment well to the same or a different production well. The method may comprise injecting a distinct first tracer into the second fracture stage fluid. The method may comprise locating a distinct second tracer in the second fracture located near to the wellbore. The method may comprise multistage stage treatments comprising two or more fracture stages from the treatment well. The method may comprise multistage fracture treatments comprising two or more hydraulic fracture stages from the treatment well. The method may comprise multistage fracture treatments comprising three or more fracture stages from the treatment well. The method may comprise multistage fracture treatments comprising three or more hydraulic fracture stages from the treatment well. The method may comprise injecting at least one distinct tracer into each stage hydraulic fracture. The method may comprise locating at least one distinct second tracer into each stage hydraulic fracture. The method may comprise locating at least one distinct pulse tracer into each stage hydraulic fracture. The method may comprise injecting the at least one tracer into a fracture during forming of the at least one fracture. The method may comprise injecting the at least one tracer into a fracture after the at least one fracture has been formed. 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. According to an eighth aspect of the invention, there is provided a method of characterising at least one fracture in an enhanced geothermal system comprising at least one well system of a first well and at least one second well, the method comprising: forming a first fracture stage from the at least one first well to connect with the at least one second well; injecting a first tracer into the first fracture stage; locating a second tracer into the first fracture stage; producing fluid in the at least one second well; collecting samples of fluid from the at least one second well and analysing tracer concentrations with respect to sampling time; calculating at least one flow characteristic and / or at least one fracture characteristic for the first fracture stage from the analysis of the tracer concentrations. The method may comprise forming a second fracture stage from the at least a first well. The method may comprise forming a second fracture stage from the at least a first well to the at least a second well. The method may comprise forming a second fracture stage from the at least a first well to a third or further well. The first tracer may be a fracture tracer. The second tracer may be a pulse tracer. The method may comprise injecting a second fracture tracer into the second fracture stage. The method may comprise locating a second pulse tracer into the second fracture stage. The method may comprise calculating at least one flow characteristic for the second fracture stage from the analysis of the tracer concentrations. The method may comprise calculating at least one flow characteristic for each of the first fracture stage and the second fracture stage from the analysis of the tracer concentrations. The method may comprise producing fluid in the second, third and / or further well to draw and / or pull flow through the first fracture stage and / or second fracture into the second, third and / or further well. The method may comprise producing fluid in the second, third and / or further well to draw and / or pull the first stage tracer and / or second pulse through the first fracture stage into the second, third and / or further well. The method may comprise producing fluid in the second, third and / or further well to draw and / or pull the second stage tracer and / or second tracer through the second fracture stage into the second, third and / or further well. The method may comprise forming a third or further fracture stage from the at least a first well. The method may comprise forming a connection between the first well and a second, third or further well. The method may comprise injecting a third or further fracture tracer into the third or further fracture stage. The method may comprise locating a third or further pulse tracer into the third or further fracture stage. The method may comprise calculating at least one flow characteristic for the third or further fracture stage from the analysis of the tracer concentrations. The method may comprise calculating at least one flow characteristic for each of the fracture stage. The method may comprise producing fluid in the third or further well to draw and / or pull flow through the third or further fracture stage into the third or further well. The fracture tracers in each fracture stage may be different. The pulse tracers in each fracture stage may be different The at least one first well may be an injector well. The at least one second well may be a production well. The third of further wells may be production wells. 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 a method of characterising at least one fracture in an enhanced geothermal system comprising at least one well system of at least one first well and at least one second well, the method comprising: forming a first fracture stage from the at least one first well; injecting a first fracture tracer into the first fracture stage; locating a first pulse tracer into the first fracture stage; producing fluid in the second well; collecting samples of fluid from the second well and analysing tracer concentrations with respect to sampling time; calculating at least one flow characteristic for the first fracture stage from the analysis of the tracer concentrations. 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. According to a tenth aspect of the invention, there is provided a method of collecting samples for analysis in characterising at least one fracture in a well system, wherein the system comprises a well combination comprising a first well and at least one second well and at least one fracture between the first well and at least one second well; the method comprising producing fluid in the at least one second well to draw or pull flow into the at least one second well from the at least one fracture, wherein the flow from the at least one fracture carries at least one first tracer to the at least one second well; collecting samples from the production well. The at least one fracture may comprise at least one second tracer. The at least one first tracer may be a fracture tracer. The at least one fracture may comprise at least two tracers. Each fracture may comprise at least two distinct tracers. The second tracer may be a pulse tracer. Each fracture may comprise at least one fracture tracer and least one pulse tracer. There may be two or more fractures between the first well and at least one second well. Each fracture may comprise a distinct first tracer and a distinct second tracer. The well system may comprise a third or further well. There may be at least one fracture between the first well and the third or further well. Embodiments of the tenth aspect of the invention may include one or more features of any of the first to ninth aspects of the invention or their embodiments, or vice versa. According to an eleventh aspect of the invention, there is provided a method of collecting samples for analysis in characterising at least one fracture in a well system, wherein the system comprises a well combination comprising a first well and at least one second well and at least one fracture between the first well and at least one second well; the method comprising flowing fluid from the at least one fracture to the at least one second well to carry at least one first tracer to the at least one second well; collecting samples from the second well. The at least one fracture may comprise at least a first tracer injected into the at least one fracture. The at least one fracture may comprise at least a second tracer located in or at the at least one fracture. The at least one fracture may comprise at least a second tracer located at a known position in or at the at least one fracture. The method may comprise flowing fluid from the at least one fracture to the at least one second well to carry at least one second tracer to the at least one second well. The method may comprise circulating at least one circulation tracer from the first well to the second well with a circulated fluid. The at least one circulation tracer may be configured to pass through at least one fracture from the first well to the at least a second well. The at least one circulation tracer may be configured to pass through two or more fractures from the first well to the at least one second well. The at least one circulation tracer may be configured to pass through multiple fractures from the first well to the at least one second well. The at least one circulation tracer may be configured to pass through all of the fractures from the at least one first well to the at least one second well. The method may comprise repeating the circulation test at different injection rates into the injector well. The method may comprise repeating the circulation test at different production rates from the production well. The method may comprise circulating fluid from the first well to a second well at different flow rates. The method may comprise circulating fluid from the first well to a second well at two or more flow rates. The method may comprise circulating fluid from the first well to a second well at multiple flow rates. At least one distinct circulating tracer may be used for each different flow rate. The method may comprise collecting samples of fluid from the second well during a period of stable flow. The method may comprise producing fluid from the second well to draw, pull and / or direct flow from the at least one fracture into the second well. The method may comprise producing fluid from the second well to draw, pull and / or direct the first tracer and / or second tracer located in the at least one fracture into at least the second well. The method may comprise producing fluid from the second well to draw, pull and / or direct at least one tracer located in two or more fractures into the second well. The method may comprise producing fluid from the second well to draw, pull and / or direct at least one tracer located in two or more fracture into the second well. The method may comprise producing fluid from the second well to draw, pull and / or direct tracer located in each fracture into the second well. The method may comprise producing fluid at different flow rates. The method may comprise drawing, pulling and / or directing flow from the at least one fracture into the second well at different flow rates. The method may comprise producing fluid at different flow rates. The method may comprise drawing, pulling and / or directing flow from the at least one fracture into the second well at two or more flow rates. The method may comprise producing fluid at different flow rates. The method may comprise drawing, pulling and / or directing flow from the at least one fracture into the second well at multiple flow rates. The method may comprise collecting samples of fluid from the second well during a period of stable flow. The well combination may comprise multiple wells. The well combination may comprise a first well, a second well and a third or further well. The at least one fracture may extend from the first well to the second well and / or third or further wells. The method may comprise producing fluid from the second, third or further well to draw, pull and / or direct at least one tracer located in at least one fracture into the second, third or further well. Two or more fractures may extend from the first well to the second well and / or third or further wells. Multiple fractures may extend from the first well to the second well and / or third or further wells The method may comprise producing fluid from the second, third or further well to draw, pull and / or direct at least one tracer located in each fracture into the second, third or further well. Embodiments of the eleventh aspect of the invention may include one or more features of any of the first to tenth aspects of the invention or their embodiments, or vice versa. According to a twelfth aspect of the invention there is provided an interpretation method for characterising at least one fracture in well system, the method comprising: providing tracer data, the tracer data previously obtained by analysis of samples of fluid collected from a production well in a well system comprising at least one treatment well and at least one production well, and having at least a first fracture stage from the at least one treatment well; wherein fluid is drawn from the at least one fracture into the production well of the well and wherein the fluid carries at least one first stage tracer to the production well; calculating at least one flow characteristic from tracer data. The at least one fracture may comprise at least one fracture stage tracer. The at least one fracture may comprise at least two tracers. Each fracture may comprise at least two tracers. The at least one fracture may comprise at least one fracture tracer. The at least one fracture may comprise at least one pulse tracer. Each fracture may comprise at least one fracture stage tracer and least one pulse tracer. There may be at least a first fracture stage from the at least one treatment well to the at least one production well. There may be a second fracture stage from the at least one treatment well to the at least one production well. The second fracture stage may be from the at least one treatment well to a different production well. The second fracture stage may comprise a second stage tracer. There may be a third or further fracture stage from the at least one treatment well to the at least one production well. The third or further fracture stage may be from the at least one treatment well to a different production well. There may be multiple fracture stages from the at least one treatment well to the at least one production well. Each stage may comprise at least one distinct fracture tracer and at least one distinct pulse tracer. Production may be induced or controlled in the at least one production well to draw, pull and / or direct flow from or through the at least one fracture into the at least one production well. Production may be induced or controlled in two or more production wells to draw, pull and / or direct flow from or through the at least one fracture into two or more production wells. The flow from the first fracture may carry a first fracture tracer and / or a first pulse tracer into the at least one production well. The flow from the second fracture may carry a second fracture tracer and / or a second pulse tracer into the at least one production well. The flow from the third or further fracture may carry a third or further fracture tracer and / or a third or further pulse tracer into the at least one production well. The at least one well system may be a hydrocarbon well system. The at least one well system may be a hydrocarbon reservoir system. The at least one well system may be a geothermal well system. The at least one well system may be an enhanced geothermal system. The at least one well system may be a mineral extraction well system. Embodiments of the twelfth aspect of the invention may include one or more features of any of the first to eleventh aspects of the invention or their embodiments, or vice versa. According to a thirteenth aspect of the invention there is provided a system for characterising at least one fracture in a well system comprising at least a first well and a second well: a fracture fluid configured to be injected in the first well to form a first fracture stage; at least one first fracture stage tracer configured to be injected into the first fracture stage; and a collection device configured to collect samples of fluid produced in the second well. The system may comprise a second tracer configured to be located in the first fracture stage. The second tracer may be configured to be located at the start of the first fracture stage. The second tracer may be configured to be located in first fracture stage close to the wellbore of the first well. The second tracer may be configured to be located at a known position of the first fracture stage. The second tracer may be a first pulse tracer. The system may comprise at least one circulation tracer. The system may comprise a second fracture fluid configured to be injected in the first well to from a second fracture stage. The system may comprise a second fracture stage tracer configured to be injected into the second fracture stage. The system may comprise a distinct pulse tracer configured to be located in the second fracture stage. The pulse tracer may be configured to be located at the start of the second fracture stage. The pulse tracer may be configured to be located at a known position of the second fracture stage The pulse tracer may be configured to be located in second fracture stage close to the wellbore of the first well. The well system may comprise a third or further well. The system may comprise a third fracture fluid configured to be injected in the first well to from a third fracture stage. The system may comprise a third fracture stage tracer configured to be injected into the third fracture stage. The system may comprise a distinct pulse tracer configured to be located in the third fracture stage. The pulse tracer may be configured to be located at the start of the third fracture stage. The collection device may be configured to collect samples at known sampling times. The tracers in a fracture stage comprise distinct tracer materials. The tracers in a fracture stage may be inflow tracers. The tracers in a fracture stage may be interwell tracers. The system may comprise a tracer release device configured to release the at least one tracer into the injection well. The system may comprise a tracer release device configured to release the at least one tracer into the at least one fracture. The system may comprise at least one tracer analyser device configured to detect and / or measure the concentration of the at least one tracer in fluid produced from the production well. The system may comprise at least one tracer analyser device configured to detect and / or measure the concentration of the tracer in fluid produced in the production well. The system may comprise at least one tracer analyser device configured to detect and / or measure the concentration of the at least one fracture tracer in fluid produced in the production well. The system may comprise at least one tracer analyser device configured to detect and / or measure the concentration of the at least one pulse tracer in fluid produced in the production well. The system may comprise at least one tracer analyser device configured to detect and / or measure the concentration of the tracers in the fluids in the production well. The system may comprise at least one probe. The at least one probe may be configured to detect the concentration of the at least one tracer in fluid produced from in the production well. The at least one probe may be a sample collection probe, a detector probe and / or a real time detector probe. The system may comprise a tracer analyser for analysing presence, type and / or concentration of the at least one tracer. The system may comprise a processor. The process may be a computer-implemented processor. The processor may be configured to compare a tracer type and / or concentration of measured in the production well with a tracer type and / or concentration of at least one injected interwell tracer in the injection well. The processor may be configured to compare a tracer type and / or concentration of measured in the production well with at least one inflow tracer arranged in the production well. 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. Embodiments of the thirteenth aspect of the invention may include one or more features of any of the first to twelfth aspects of the invention or their embodiments, or vice versa. According to a fourteenth aspect of the invention there is provided a method of characterising at least one fracture in a well system comprising a first well and at least one other well, the method comprising: forming at least two fracture stages from the first well wherein at least one fracture stage connects with the at least one other well; injecting a first fracture tracer into a first fracture stage and injecting a second fracture tracer in the second fracture stage; locating at least a first pulse tracer in the first fracture stage and a second pulse tracer in the second fracture stage; producing fluid from the at least at least one other well, collecting samples of produced fluid; analysing the samples for the presence and / or concentration of tracers; calculating at least one flow characteristics for the at least one fracture based on the presence and / or concentration of tracers in the samples. Embodiments of the fourteenth aspect of the invention may include one or more features of any of the first to thirteenth aspects of the invention or their embodiments, or vice versa. According to a fifteenth aspect of the invention there is provided a method of collecting samples for analysis in characterising at least one fracture in a well system, wherein the system comprises a well combination comprising a first well and at least one second well and at least one fracture between the first well and the at least one second well; wherein the at least one fracture comprises at least one first tracer injected into the at least one fracture and at least one second tracer located in or at the at least one fracture; the method comprising flowing fluid from the at least one fracture to the at least one second well to carry tracer to the at least one second well; collecting samples from at least the second well. The method may comprise producing fluid from or in the at least a second well to draw, pull and / or direct tracer and fluid in or through the at least one fracture into the at least second well. The well combination may comprise multiple wells. The well combination may comprise a first well, a second well and a third or further well. The at least one fracture may extend from the first well to the second well and / or third or further wells. The method may comprise producing fluid from the second, third or further well to draw, pull and / or direct at least one tracer located in at least one fracture into the second, third or further well. Two or more fractures may extend from the first well to the second well and / or third or further wells. Multiple fractures may extend from the first well to the second well and / or third or further wells The method may comprise producing fluid from the second, third or further well to draw, pull and / or direct at least one tracer located in each fracture into the second, third or further well. Embodiments of the fifteenth aspect of the invention may include one or more features of any of the first to fourteenth aspects of the invention or their embodiments, or vice versa. According to a sixteenth aspect of the invention there is provided an interpretation method for characterising at least one fracture in well system, the method comprising: providing tracer data, the tracer data previously obtained by analysis of samples of fluid collected from a production well in a well system comprising a first well and at least a second well, and having at least a first fracture stage from the first well; wherein fluid is transferred from the at least one fracture to the at least one production well to carry tracer to the at least one production well; calculating at least one flow characteristic from the tracer data. The method may comprise drawing and / or pulling fluid from or through the at least one fracture into the production well. The well combination may comprise multiple wells. The well combination may comprise a first well, a second well and a third or further well. The at least one fracture may extend from the first well to the second well and / or third or further wells. The method may comprise producing fluid from the second, third or further well to draw, pull and / or direct at least one tracer located in at least one fracture into the second, third or further well. Two or more fractures may extend from the first well to the second well and / or third or further wells. Multiple fractures may extend from the first well to the second well and / or third or further wells The method may comprise producing fluid from the second, third or further well to draw, pull and / or direct at least one tracer located in each fracture into the second, third or further well. The first tracer may be a fracture tracer. The first tracer may be a mass balance tracer. The first tracer may be a mass balance fracture tracer. A different distinct first tracer was previously injected into each stage hydraulic fracture. The second tracer may be a pulse tracer. A different distinct second tracer was previously located at or in each stage hydraulic fracture. A distinct second tracer was previously located at a known position at or in each stage hydraulic fracture. Embodiments of the sixteenth aspect of the invention may include one or more features of any of the first to fifteenth aspects of the invention or their embodiments, or vice versa. Brief description of the drawings 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: Figure 1 is a simplified representation of a tracer pull system showing one treatment well and two offset productions wells wherein the treatment well is shut in after placement of the tracers in the fractures, according to an embodiment of the invention; Figure 2 is a simplified representation of a tracer pull system showing one treatment well and two offset productions wells wherein fluid is produced from the treatment well after placement of the tracers in the fractures according to an embodiment of the invention; Figure 3 is a simplified representation of an enhanced geothermal system showing one treatment well (injection well) and two offset productions wells, according to an embodiment of the invention; and Figure 4 is a simplified representation of an enhanced geothermal system showing one injection well and one production well, according to an embodiment of the invention. Detailed description of preferred embodiments Figure 1 is a simplified representation of a tracer pull system shown generally as 10. In this example the tracer pull system is used to assess fractures between hydrocarbon wells. However, the system may be used in other systems such as geothermal wells, enhanced geothermal systems (EGS) or mineral extraction well systems. Figure 1 shows a treatment well 12 and two offset wells 14, 16. In unconventional wells with multistage hydraulic fracturing, it is common for fractures 18 created from the treatment well 12 to intersect with offset wells 14, 16 as shown in Figure 1. The fracture connections are commonly referred to a Fracture Driven Interactions (FDIs) or frac hit 15a, 15b, 15c. By understanding characteristics of the fracture and the frac hit may provide information on how the frac hit affects production or flow in the offset well. It will be appreciated that fracture treatments are carried out in the treatment well with the aim of establishing a fluid connection between at least one offset well. Although two offset wells are shown the number of wells may be one, or more than two. Figure 1 shows that offset wells 14, 16 were previously hydraulically fractured creating fractures 19, 19a. However, in other examples the offset wells may not have been previously fractured. Optimising the productivity of hydraulic fractures may be improved by having knowledge of the flow path volume within the fracture connections. Fracture flow path volume can be interpreted to provide flow characteristics such as duning, channelling, open fractures, cluster runaway, and micro-annulus impact the effectiveness of hydrocarbon production. A series of hydraulic fracture treatments are carried out in treatment well 12 with the aim of establishing a fluid connection between the treatment well 12 and the offset wells 14, 16. In this example hydraulic fracturing is carried out at three fracture sites 20, 22 and 24 in the treatment well in a multistage hydraulic fracture process. During a first stage, fracturing fluid 30a is pumped from the surface through the wellbore and through perforations at site 20. The pumped fluid causes stresses in the rock formation, and as the fluid pressure and pumping rate exceed the critical stresses, fractures 18a form and propagate through the surrounding rocks. Further pumping leads to deeper fracture propagation. The fracturing fluid may comprise proppant material which fill the developing fractures preventing fractures closure and improve the conductivity through the fracture. In this example distinct (first) tracers are injected as mass balance tracers (fracture tracers) at a known constant concentration throughout each fracture stage. The fracturing fluid comprises a first tracer 32 (fracture tracer). This results in the mass balance tracer 32 present in the volume of the fracture 18a. At the end or towards the end of the hydraulic fracture treatment a second tracer 42 (pulse tracer) is injected as a tracer pulse into the fracture 18a. In this example a high concentration of tracer 42 is injected into the hydraulic fracture treatment and pushed or displaced into fracture 18a to locate it at point “A” shown in Figure 1 the near wellbore of the treatment well 12. The second tracer (pulse tracer) 42 is injected prior to a subsequent fracturing stage. It will be appreciated that additionally or alternatively the second tracer (pulse tracer) 42 may be released from a tracer source located in the wellbore. The tracer source may be exposed to the treatment fluid and / or shut in to accumulate tracer in the treatment fluid. During a second fracture stage, fracture site 20 is isolated, for example by a wellbore plug or packer at position 21. Once isolated, fracturing fluid 30b is pumped from the surface through the wellbore and through perforations at site 22 to form fractures 18b. The fracturing fluid 30b comprises a first tracer 34 (fracture tracer). Similar, but distinct to tracer 32, the first tracer 34 is injected at a known constant concentration into the fracturing fluid during the second stage hydraulic fracturing treatment. This results in a distinct mass balance tracer 34 present in the volume of the fracture 18b. At the end or towards the end of the hydraulic fracture treatment a second tracer 44 (pulse tracer) is injected as a tracer pulse into the fracture 18b. In this example a high concentration of second tracer 44 is injected into the hydraulic fracture treatment and pushed or displaced into fracture 18b to locate it at point “B” shown in Figure 1 near the wellbore of the treatment well. The second tracer (pulse tracer) 44 is injected prior to a subsequent fracturing stage. The process is repeated for a third fracture stage to form fracture 18c. In this example, fracture sites 20 and 22 are isolated from fracture sites 24 for example by a wellbore plug or packer at position 23. Once isolated, fracturing fluid 30c comprising a first tracer 36 is pumped from the surface through the wellbore and through perforations at site 24 to form fractures 18c. Similar, but distinct to first tracers 32, 34, first tracer 36 is injected at a known constant concentration into the fracturing fluid during the third stage hydraulic fracturing treatment. This results in a distinct mass balance tracer 36 present in the volume of the fracture 18c. At the end or towards the end of the hydraulic fracture treatment a second tracer (pulse tracer) 46 is injected as a tracer pulse into the fracture 18c. In this example a high concentration of tracer 46 is injected into the hydraulic fracture treatment and pushed or displaced into fracture 18c to locate it at point “C” shown in Figure 1 near the wellbore of the treatment well. As shown in Figure 1, each distinct tracer 32,34,36 are each associated with a different fracture stage and fill or partially fill the volume of fractures 18a, 18b, 18c respectively. Distinct pulse tracers 42, 44, 46 are located at the near wellbore of fractures 18a, 18b, 18c respectively. In this example the treatment well is shut-in and clean-up and / or production is started in offset wells 14, 16. In this example as there are two offset wells clean-up and / or production is started in offset wells 14, 16 sequentially or simultaneously. Desirably before the treatment well is shut in isolation tools between fracture initiation sites have been removed or de-actuated. During production in the well 14, flow draws and carries the fluid volume and tracers 36, 46 through and / or from fracture 15c into well 14 shown by arrow 50 in Figure 1. During production in the well 14, flow draws and carries the fluid volume and tracers 32, 42 through and / or from fracture 15a into well 14 shown by arrow 52 in Figure 1. Similarly, production in well 16 draws and carries the fluid volume and tracers 34, 44 through and / or from fracture 15b into the well 16 shown by arrow 54 in Figure 1. Offset wells 14, 16 are unconventional wells and producing hydrocarbons, it is not possible to perform a circulating tracer test were fluid and tracer is injected into the treatment well and produced at the producer wells 14, 16. The pull test described above is provided to characterize the flow paths connecting the treatment and offset wells. In this pull test fluid and tracers present in the fracture volumes are drawn into the producer wells 14, 16 by production flow in producer wells 14, 16. Samples are collected from fluid produced at each of the offset well(s). Optionally samples may be collected from the treatment well during cleanup / flowback and early production. The collected samples may be analysed on-site or analysed at a later period of time and / or at a different location. The samples are analysed to measure tracer concentrations over time. The fracture flow path volumes of fractures 18a, 18b and 18c may be calculated between the treatment well and wells 14, 16 based on the detection of the mass balance tracers (first tracers) 32, 34, 36 and pulse tracers (second tracers) 42, 44, 46 in the samples. Taking fracture 18c as an example, the detection of the first tracer 36 in samples collected from the produced fluid provides the residence time (time of travel) from the frac hit location 15c to the sampling location. The detection of second tracer 46 in samples collected from the produced fluid provides the residence time (time of travel) from point “C” to the sample point. By subtracting the residence time of first tracer 36 from the residence time of second tracer 46 the residence time of the fracture 18c may be calculated. The time of travel of tracer pulse is calculated based on the difference in arrival times for the first tracer (mass balance tracer) and second tracer (pulse tracer) per stage. The production rate of fracture 18c may be calculated based on the dilution of the known concentration of the first tracer (mass balance tracer) 36. Based on the dilution of the first tracer (mass balance tracer) 36 may provide an understanding of the ratio in the flow system. A percentage dilution may be used for each of the first tracers 32, 34, 36 (mass balance tracers) to determine the percentage of the flow in well 14 which is allocated from fracture 18c. The production rate of fracture 18c may be calculated based on the dilution of the known concentration of the first tracer (mass balance tracer)36 multiplied by the total flow rate of well 14 during cleanup and / or production. Fracture flow path volume of fracture 18c is calculated as production rate of fracture 18c multiplied by the time of travel of second tracer (pulse tracer) 46. Similarly, the detection of the first tracer 34 and second tracer 44 from fracture 18b in samples collected from well 16 allow for the residence time of the fracture 18b to be calculated. The detection of the first tracer 32 and second tracer 42 from fracture 18a in samples collected from well 14 allow for the residence time of the fracture 18a to be calculated. Similarly, the fracture flow path volumes of fractures 18a and / or 18b may be calculated using the above method described to calculate the fracture 18c above. This arrangement provides control over the placement of a first known concentration of a distinct tracer in the volume of each of the fractures 18a, 18b, 18c. This arrangement provides control over the placement of a distinct tracer in a near wellbore location in each of the fractures 18a, 18b, 18c. This arrangement is not possible in a conventional reservoir. This method also provides control over the flow back conditions to determine characteristics of the fractures 18a, 18b and 18c. This arrangement may facilitate interpretation of fracture characteristics based on tracer response data from tracers in the fracture drawn from or through the fracture volume to the production well. Optionally the fracture flow path efficiency may be calculated. Optionally the percentage of propped fracture surface area may be calculated (e.g., based on fracture simulations for fracture geometry, stimulated reservoir volume from microseismic data, and / or similar fracture geometry information). Optionally the flow path percentage of the fracture treatment volume may be calculated. Optionally the injection rates, production rates, surface pressures, and bottom hole pressures may be measured in the production wells 14, 16 and / or the treatment during the tracer test (pull test). The bottom hole pressure may be measured by downhole pressure gauges or calculated based on surface well pressures. The tracer data may provide a direct measure of flow rate per flow path. The method may comprise calculating a permeability of the fracture flow paths per stage. The method may comprise calculating a permeability of the fracture flow paths based on the fracture circulation volume calculated from tracer data. The method may comprise determining a downhole pressure difference between the treatment well 12 and production wells 14, 16. The method may comprise determining a pressure drop across the fracture(s) connecting the wells. The method may comprise determining a downhole pressure difference based on the measured or calculated downhole pressures. The method may comprise calculating the percent flow profile per fracturing stage based on tracer response measured in samples taken from the produced fluid from the production well. This production profile represents the flow profile through the fracturing stages, connecting the treatment well and production wells. The flow rate per fracture is calculated as the percent flow contribution multiplied by the total production well flowrate measured at surface and divided by the number of stimulated perforation clusters per stage. The permeability of the flow path is calculated from Darcy’s Law: k =     =                                      (Equation 1) A AP VfAP ' ' where: k is the permeability of the fracture flow path (likely a proppant pack) Q is the volumetric flow rate in the fracture A is the cross-sectional area of the flow Vf is the volume of the fracture flow path between the wells as measured from the tracer interpretation < / > is the porosity Delta P is the pressure drop across the proppant pack (between the wells) p. is the dynamic viscosity of the fluid L is the distance between injection and production wells The permeability values may be compared to that expected for the proppant pack. If the calculated permeabilities are larger than that of the expected proppant pack permeability then the results may indicate flow through some type of open fracture such as a channel or duning. The above method of calculating the permeability of the fracture flow paths per stage may be repeated for each of the traced fracturing stages 18a, 18b and18c. The permeability calculation is based on the tracer data collected from the production well which provides a flow profile for each flow path through a fracture. The calculation of permeability is possible because the flow rate per flow path is known; the fracture circulated volume is known from tracer data; a flow path distance between wells is known and the total flow rate and downhole pressures for the wells are known. Optionally a design of the well system may be optimised for subsequent wells based on parameters such as the number of perforation clusters per stage, fracture geometry, fracture hydraulic conductivity, injection and production well spacing, wine rack pattern, well spot pattern, and cemented / cased vs open hole completion. For example, based on the fracture flow path efficiency metric the design may be changed to improve the fracture flow path efficiency such as increasing the proppant pack conductivity, increasing the fluid viscosity, increasing the fluid viscosity to improve proppant transport, increasing the fluid viscosity to reduce settling, adding fiber to reduce proppant settling, and / or a combination of these changes or alternative changes. Figure 2 shows an alternative arrangement of a tracer pull system 100 according to the invention. The system 100 is similar to the system 10 described in Figure 1 and will be understood from the description of Figure 1. However, the treatment well is not shut-in during production in well 114 and / or well 116. The placement of distinct mass balance tracers (first tracers) 132, 134, 136 are each associated with a different fracture stage and fill the volume of fractures 118a, 118b, 118c respectively. Distinct pulse tracers (second tracers) 142, 144 and 146 are located at the near wellbore of fractures 118a, 118b, 118c at positions “A”, “B” and “C” respectively the same as described in Figure 1 above. In this example the operator may produce fluid from the treatment well 112 as well as the offset wells 114, 116. In this example the production flow in well 114 is designated Q2, production flow in well 116 is designated Q1 and flow in treatment well 112 is designated Q3. The flow in treatment well is choked or controlled such that Q3 is less than Q1 or Q2 to facilitate flow from the treatment well to the offset wells through the fractures. Optionally, the ratio of Q3 to Q1 and / or Q2 may be controlled and / or optimised. The ratio of Q3 to Q1 and / or Q2 may be controlled to optimise production in treatment well 112 and / or offset wells 114, 116 whilst facilitating flow in the fracture(s) from the treatment well to one or more offset well. Characteristics of the fractures 118a, 118b and 118c may be determined based on the tracer data based on the method described above in relation to Figure 1. Figure 3 shows an alternative arrangement of a tracer pull system 200 in an enhanced geothermal system. The system 200 is similar to the system 10 described in Figure 1 and system 100 described in Figure 2 will be understood from the description of Figures 1 and 2. However, the treatment well is an injection well and is not shut-in during production in well 214 and / or well 216. In this example the treatment well (injection well) 212 is hydraulically fractured with at least three fracture stages 218a, 218b and 218c. The hydraulic fractures intersect offset production wells 214, 216. The production wells may or may not also be hydraulically fractured, in this example they are not hydraulically fractured. In some embodiments the treatment well 212 may be shut in while the production well produce fluid and the “Pull Test” is performed by producing the offset production well to draw the flow from and / or through the fractures into the production wells. In this example the well 212 wellhead is open and maintained with a constant liquid head with water, as illustrated in Figure 3. As will be understood from Figure 2, fluid is produced in wells 216 and 214 at rates Q1 and Q2 respectively while the well 212 wellhead is open while maintaining a water column in the well 212. The first tracer (fracture 218c first tracer) 236 and second tracer (fracture 218c pulse tracer) 246 are drawn into the wells 216 and 214 following arrows 250a, 250b and detected in produced fluids in the production wells 216 and 214. Similarly, the first tracer (fracture 218b first tracer) 234 and second tracer (fracture 218b pulse tracer) 244 are drawn into the wells 216 and 214 following arrows 254a, 254b. Similarly, first tracer (fracture 218a first tracer) 232 and second tracer (fracture 218a pulse tracer) 242 are drawn into the wells 216 and 214 following arrows 252a, 252b and detected in produced fluids in the production wells 216 and 214. Characteristics of the fractures 218a, 218b and 218c may be determined based on the tracer data based on the method described above in relation to Figure 1. The method may comprise designing and interpretating tracer testing to characterize fracture volumes. The analysis and interpretation of the tracer concentrations from the sampling of fluid may include quantifying a proportion of flow from each stage in the offset producer(s) by performing a dilution calculation. A mathematical derivative of the response curve may be taken to find a pulse equivalent, and that derivative may be characterized by means of Residence Time Distribution (RTD) analysis. The RTD analysis may include assisted history matching to calculate the flow characteristics of the fractures. RTD is the distribution of times used by a population of tracer particles to travel through a medium. The tracers represent elements of fluid that travel through different paths, and that therefore use different amounts of time to pass through a medium. The distribution, E(t), of these times is called the residence time distribution, of the fluid in the system. E(t) is defined from produced tracer concentrations, C(t), production rate, Qp(t), and injected tracer amount, M: E(t) = C(t) ■                                 (Equation 2) The unit of E is the inverse of the time unit. Important information about the geometry and flow in a system can be obtained from the moments of the residence time distribution. They are defined as mn = I E(t) • tn(t) dt (Equation 3) oo For concrete physical interpretation exemplification, the zero moment represents the relative amount of tracer produced in production well and the first moment can provide the average residence time, {T) = m1 / m0, for the tracers between the injection well and a producer. Higher order moments, such as the second order moment, the third order moment etc. carry additional information on the space where flow occurs. The second order moment is of particular interest as it carries information on the spreading of the fluid, i.e. the dispersion resulting from heterogeneity in the flow space. The temporal moments defined in Equation 3 are closely related to the moments of the spatial distribution of tracer and dispersion assessment based on the tracer curve as function of time at an outlet thus gives information about the heterogeneity of the flow space. In addition to individual moments (mn) combinations of moments are also useful to characterize the fracture space. One particularly interesting combination is the zero vs first order moments. One application of RTD of particular interest is the quantification of the flowing volume, i.e. measuring the volume through which a fluid is flowing. Specifically, this volume is given from the product of the average residence time and the rate of the fluid moving in the flowing volume. For example, if the injection rate (QJ at an inlet to an open system is known and the RTD at an outlet is established from an injected tracer, the sweep volume can be calculated as = m0 ■ &■ {T). Here {T) is the average residence time and m0 is the proportion of fluid produced at the specific outlet. The quantity m0 in the expression for swept volume represents an assessment of the proportion of injected fluid that move towards the outlet of interest vs. the injected fluid. An alternative to using the moments of the RTD to find this proportion is to use a dilution analysis approach. This approach is based on the fundamental principle of mass conservation - i.e. that mass of an ideal tracer is conserved during transport in a system. In practice, a dilution analysis can be used to identify the proportion of fluid from a specific source if that fluid is mixed with fluid from other sources, if the concentration of a tracer is known in the specific source and in the mixture. Referring to Figures 1 to 3 above, a dilution analysis may be used to determine the proportion of fluid in any offset well originating from a specific stage of the treatment well by use of the mass balance tracers (first tracers) in each fracture stage. This proportion can then be combined with the moments of the residence time distributions, calculated from the distinct pulse tracers (second tracers) in each fracture stage. Residence time distributions are commonly based on the movement of tracer of a narrow pulse. However, residence time distributions may be applied to the movement of tracer as pulses that have a significant duration compared to the travel time, or indeed a continuously injected tracer, i.e. tracers that are introduced as a step change (i.e. a Heavyside function instead of a Dirac function). Heavyside function may be interpreted as a step, some value changes to a new value suddenly and stays at that value. The Dirac function is interpreted as an impulse, some value changing suddenly and then returning to the old value. In such injection scenarios, the tracer response signal of a Dirac pulse would correspond to the differential of the response to the step change (Heavyside function). A potential benefit of using a step change (Heavyside function) input tracer signals is that the ordinate would give the dilution factor, whereas the time differential of the pulse could be used as basis for an RTD to quantify volume. A combination of long and short pulses may be possible and would create output signals which carry information of the flow volume through which the traced fluid has been transported. The method may comprise improving models using tracer data. In standard workflows used to assimilate tracer information for assisted history matching, it is common to compare time series of measured data to time series of simulated data. The work-flows calculate a misfit (squared difference between measured and simulated time series) and reduces this misfit by systematically performing simulations where reservoir parameters are guessed and re-guessed. Formally we can define the misfit in standard approaches as: AT e = «) -yd2 i=0 (Equation 4) where f (t, a) is our model function of time defined by model parameters a, and yt are our measured response at times ti. Note that this misfit definition can be generalized to multiple spatial dimensions as well as time and f(t) can be a multidimensional function of space and time. The values off at specific points in space and time depend on the set of parameters a and history matching is the process of finding the values of a that gives the best possible representation of the measured data. In practice, this is done by minimizing the misfit with respect to the model parameters, i.e. by solving the equation: — = 0 (Equation 5) da One application of an RTD is to replace the misfit that compares measured and simulated concentration time series by a misfit that compare the RTD moments of the simulated and measured tracer curve instead of the curves themselves. In practice this can be achieved by calculating the moments m0,m1,m2.. from the model using Eq.2 and compare to the moments calculated the measured data. Similarly, the difference in magnitude of the dilution tracer between the model and measurement would be well suited as measurement of the misfit between model and reality and could be used to extract information on parameters of interest. While the system of Figures 1 and 3 are simple, functional, well system comprising one treatment well and two production wells, it is will be understood that in other examples the well system may comprise one production well or more than two production wells. In the above examples three fracture stages are shown. It will be appreciated that there may be at least one fracture stage. The method may be used to determine characteristics of the at least one fracture. It will be appreciated that there may be two or more fracture stages. The method may be used to determine characteristics of each of the two or more fracture stages. The systems of Figures 1 and 3 are representatives of a treatment well and production well(s) of a possible larger, more sophisticated well system comprising multiple treatment wells and / or multiple production wells arranged throughout a reservoir system. In the present invention, such a well combination is used in a process for designing subsequent steps of the well system, for example by determining the position of further wells and / or fracture treatment processes according to design objectives. The methodology of the invention may use the one or more flow characteristics calculated from the tracer responses to determine or calculate a fracture circulation efficiency metric. Figure 4 is a simplified representation of an enhanced geothermal system shown generally as 300. In this example the enhanced geothermal has an injection well 312 and a production well 314. In this example the injection well has eight injection zones, however it will be appreciated that the number of injections zone may be more than eight or less than eight. Distinct tracers are located at known locations and configured to release or inject the distinct tracer into a corresponding injection zone. The distinct tracers 315a-315h introduced into the injection zones may provide information on characteristics and conditions of the fractures as circulated fluid moves to the production well. Samples collected from the production well 314 can be analysed for tracer concentrations to provide one or more flow characteristics associated with the fractures of each injection zone. The injection well and production well have a known distance “L”. Subsequent circulation of fluid between the injector well 312 and the producer well 314 during a circulation test may cause the distinct chemical tracers to flow with the circulated fluid to the production well. Optionally based on the concentration of chemical tracers detected in collected samples in the production well a percentage flow distribution from each fracture may be determined. Based on the tracer response data flow rate data per injection zone is calculated where: Flow rate per zone = % flow distribution x Q (flow rate at surface). (Equation 6) The tracer data allows flow through each zone fracture to be simultaneously measured and the flow is undisturbed. Optionally, in addition to injecting distinct fracture tracers per zone at least one circulation tracer may be injected into an injection fluid during a circulation test. The circulation tracer may travel through each of the zone fractures during circulation of flow from the injection well to the production well to provide information on flow characteristics of the fractures. In this example a distinct circulation tracer is added to the injection fluid which is injected into all of the fractures. The circulation tracer may be injected as a pulse or in a continuous manner at a constant concentration during circulation. The circulation test between the injection well and production well is conducted at a first injection and / or production rate. Samples of the produced fluid are collected from the production well. The samples are collected when there is a stable flow in the production flow. Optionally the circulation test may be repeated with a different circulation tracer. Optionally the circulation test may be repeated at a different or a range of different flow rates. A distinct circulation tracer may be used for each of the different flow rates. Samples of the produced fluid are analysed for fracture zone tracer and circulation tracer concentrations to calculate a flow rate allocation associated with each fracture / zone. The circulation test between the injection well and production well may be conducted at a multiple injection and / or production rates. A distinct circulation tracer may be injected for each of the different injection and / or production rates. In one example the circulation test is conducted at four different injection and / or production rates. The duration of time of each injection and / or production rates is sufficient to allow stable flow in the production flow and samples to be collected during a period of stable production flow. For each injection and / or production rate the surface flow rate, pressure and / or bottom hole pressure is measured and / or calculated. A graph of average flow rate per cluster based on the tracer data against calculated bottom hole pressure may be created. The percentage flow contribution data may be based on chemical tracer concentrations for each stage. The bottom hole pressure may be measured directly using equipment downhole. Alternatively, the bottom hole pressure may be calculated based on measured surface pressure. In a further example, a proppant transport capacity may be optionally calculated for each fracture zone where: Proppant transport capacity= (Ci) x (Wi)                            (Equation 7) Ci= conductivity; Wi= fracture width. As the tracer data may be measured for a range of production rates and therefore different pressures the slope of the graph is a measure of conductivity x flow width per viscosity and distance between the two wells according to Darcy's law. As the viscosity and distance between the two wells are known the slope provides information on the proppant transport capacity. The proppant transport capacity may be a measure of how effective the various treatments were in placing proppant in the fracture system. In the above example tracer data taken for multiple pressures / flow rate are used to calculate proppant transport capacity. It will be appreciated that alternatively discrete data points at one or more pressures / flow rate may be used to calculate proppant transport capacity. The response functions from monitoring circulation tracer in the collected samples may be used to characterize the total flow volume between the injection well and producer well using Residence Time Distribution (RTD) as described above. The tracer data represents elements of fluid that travel through different paths, and that therefore use different amounts of time to pass through a fracture. The distribution, E(t), of these times is called the residence time distribution of the fluid in the system. E(t) is defined from produced tracer concentrations, C(t), production rate, QP(E), and injected tracer amount, M based on Equation 2 above. The total flow volume between each injection well and production well pair can be quantified. Using a combination of RTD and the distinct zone tracers, the flow characteristics can be delineated per zone and provide fracture information such as volume between injection well and production well per stage level. Optionally Fracture Circulation Volume (VFC) and Fracture Circulation Volume per zone (VFCi) may be determined based on the circulating tracer data from a circulation test, where: VFCi = VFC x % flow distribution per zone (Equation 8) From the RTD analysis, a distribution of arrival times may be obtained. So, a distribution of permeabilities per zone may be created. Dividing the volume between the injection well and production well by the distance between the wells provides the hydraulic cross-sectional flow area. Optionally, using the tracer data from each fracture stage other characteristics of the fracture may be determined including the hydraulic cross-sectional area to flow, which equals the relative aperture x relative hydraulic width of the fracture. The hydraulic cross-sectional area (Ac) may be calculated per stage using the equation: Ac= Bi x Wi = Vfc / L                                              (Equation 9) Bi= Aperture; Wi=hydraulic width; Vfc= fracture circulation volume; L = distance between wells. In this example a hydraulic cross-sectional area of flow of each fracture is based on the circulation tracer data, the RTD analysis and a known distance between the injection and production wells. Optionally the permeability (ki) per zone may be calculated where: Permeability (ki) = (Ci) x (Wi) / (Aperture (bi) x Width (Wi))            (Equation. 10) The permeability (ki) may optionally be determined as a distribution of ki for each fracture zone. Optionally the aperture of the fracture may be determined based on the hydraulic cross-sectional area data. A sensitivity range of aperture (b) and hydraulic width of flow channel (W) may be determined based on known, measure or calculated limits. Optionally the stage tracer conductivity Ci per stage is calculated based on the equation: Ci = ki / bi.                                                              (Equation 11) Based on the RTD analysis a distribution of conductivities per zonal fracture may be calculated. The above fracture analysis described above in relation to the enhanced geothermal system of Figure 4 may be applied to other well systems such as hydrocarbon systems, enhanced oil recovery systems and / or unconventional well system. The distributions of permeability and / or distributions of conductivity may be used to optimise an, EGS, EOR or unconventional well operation. Using the tracer data, characteristics of each fracture stage may be determined, which may be used to assess the economic life per treatment stage. By determining characteristics of the fracture such as volume per fracture, aperture, surface area per fracture and / or aperture the economic life, surface area for heat transfer and / or thermal decline of the EGS may be determined. It will be appreciated that the steps described above are examples of some of the characteristics of the fractures between the wells that may be determined and that one or more steps may be omitted, replaced, added and / or that the sequence of the steps may be different. For example, a similar workflow may be applied to determining characteristics of fractures in an enhanced oil recovery system. In this example distinct tracers may be located at each zone of interest. In another example a similar workflow may be applied to determining characteristics of fractures in an unconventional well system. In this example with the circulation test may be replaced with the pull test described above in relation to Figures 1 to 3. Optionally a similar workflow may be applied to determining characteristics of fractures in an unconventional well system during flowback into the injection well. In this further example the distance between wells may be unknown and may be estimated from frac modelling or microseismic data. Optionally nanoparticle tracer studies may be performed to determine characteristics of fractures between wells. For example, at least one distinct nanoparticle tracers and at least one distinct chemical tracer may be injected into each in fracture. Flow may be circulated between the injector well through each fracture to the production well (in a circulation test) or flow back into the injection well (flow back test). Samples of the fluid flow may be collected and tested for the concentration of the distinct chemical tracers and a distinct nanoparticle tracers associated with each fracture. Using only the nanoparticle tracer data per fracture we assume that the average of the variability per stage is representative of the relative velocity per stage / zone. The ratio of nanoparticle tracer response is proportional to the ratio of velocities in the various stage / zone fractures. Hence, we calculate the relative velocities (Vi / Vaverage) across the various stages / zones. 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 / zone. In this example the percentage flow contribution data is calculated from chemical tracers where the volumetric flow rate per stage (Qi) as: Qi = Qsurface x %flow contribution. (Equation. 12) The relative aperture (bi / baverage) may be calculated per stage using the equation: Qi / Qaverage = (Vi / Vaverage) X (bi / baverage) X (Wi / Waverage) X (Pi / Paverage) (Equation. 13) Where: (Vi / Vaverage) is relative velocity, bi / baverage is relative aperture, (Wi / Waverage) is relative width and Pi / Paverage is relative porosity. A relative cross-sectional area to flow (Ai = bi * Wi * porosity i) may be calculated from a ratio of chemical tracer derived flow rate and nano particle tracer derived velocity using equation 13. The relative aperture may be calculated from relative cross-sectional area to flow by further integrating data including microseismic and mass balance information. Nanoparticle tracer studies may be performed to determine the hydraulic cross-sectional area which may involve injecting distinct nanoparticle tracer into each stage / zone 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 hydraulic cross-sectional area (b*W) per stage may be estimated from Qi = Vi * (bi) * W. The aperture can then be calculated by integrating W from other data such as microseismic or fracture modelling. Optionally more than one distinct nanoparticle tracer may be injected into each stage fracture. In an example two or more distinct nanoparticle tracers may be 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). The invention may provide a method and system of characterising at least one fracture in a well system comprising at least a first well and a second well. The method may comprise forming at least one fracture from the first well to the second well injecting a first fracture tracer into the at least one fracture. The method may comprise locating a pulse tracer in the at least one fracture and producing fluid from the at least a second well. The method comprising collecting samples of produced fluid and analysing the samples for the presence and / or concentration of tracers. At least one flow characteristics for the at least one fracture is calculated based on the presence and / or concentration of tracers in the samples. Embodiments of the invention may provide control over the placement of a first distinct tracer in the fluid volume of a fracture and the placement of a second distinct tracer in a near wellbore location, at the start of the fracture. This arrangement may facilitate tracer response data to be collected from the tracers drawn or pulled from and / or through the fracture to a production well. This may also be repeated with distinct tracers for each fracture or fracture stage. This may facilitate control over the flow back conditions to determine characteristics of the fractures. Embodiments of the invention may facilitate the calculation of permeability of a fracture flow paths per stage based on the fracture circulation volume calculated from tracer data. 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”, “inlet”, “outlet” 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. 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

1. A method of characterising at least one fracture in a well system comprising a first well and at least a second well, the method comprising: forming at least one fracture from the first well to at least the second well; injecting at least a first tracer into the at least one fracture;locating at least a second tracer in or at the at least one fracture;producing fluid from the at least a second well, collecting samples of produced fluid;analysing the samples for the presence and / or concentration of tracer; calculating at least one flow characteristic for the at least one fracture based on the presence and / or concentration of tracer in the samples.

2. The method according to claim 1 comprising locating the second tracer at a location in the at least one fracture near the well bore of the first well or at the start of the at least one fracture.

3. The method according to claim 1 or 2 wherein the first tracer is a fracture tracer and the second tracer is a pulse tracer.

4. The method according to any preceding claim wherein the first tracer and / or second tracer is selected from the group comprising chemical, fluorescent, phosphorescent, radioactive compounds, isotope, quantum dot, nanoparticles, or a combination thereof.

5. The method according to any preceding claim comprising producing fluid from at least the second well to draw, pull and / or direct tracer and fluid in or through the at least one fracture into at least the second well.

6. The method according to any preceding claim comprising forming two or more fractures; injecting at least one distinct first tracer into each fracture and locating at least one distinct second tracer at each fracture near the well bore of the first well or at the start of the at least one fracture.

7. The method according to claim 6 comprising producing fluid from at least the second well to draw, pull and / or direct at least one tracer located in two or more fractures into at least the second well.

8. The method according to any preceding claim comprising drawing, pulling and / or directing flow from or through the at least one fracture into at least the second well at different flow rates.

9. The method according to any preceding claim comprising controlling and / or modifying the production flow rate of fluid in the first well to a production rate less than or equal to a production rate of the at least a second well.

10. The method according to any preceding claim comprising collecting samples of fluid from the at least a second well during a period of stable flow.

11. The method according to any preceding claim wherein the well system or well combination comprises at least one treatment well and at least one production well.

12. The method according to any preceding claim wherein the at least one fracture is formed or created by a well treatment selected from the group comprising well stimulation treatment, acidizing treatment, matrix acidizing treatment, fracturing treatment, hydraulic fracturing treatment, fracture acidizing treatment, enhanced oil recovery treatment, and / or water control treatment.

13. The method according to any preceding claim comprising characterising at least one fracture flow path; characterising at least one fracture flow path volume; characterising flow from, through and / or in each fracture in the well; characterising a fracture flow path volume of each fracture in the well system; characterising a hydraulic connection between the first well and at least a second well; characterising fracture flow path efficiency; characterising permeability between the first well and at least a second well; characterising porosity between the first well and at least a second well; characterising a hydraulic connection between the first well and at least a third or further well; and / or characterising permeability between the first well and at least a third or further well.

14. The method according to any preceding claim comprising calculating at least one flow characteristic and / or at least one fracture characteristic selected from the group comprising fracture geometry; fracture width; hydraulic width; fracture aperture; hydraulic cross-sectional area; cross-sectional area of flow; percentageflow distribution; percentage flow distribution per stage; proppant transport capacity; fracture circulation volume; fracture circulation volume per stage; permeability; permeability per stage; porosity; porosity per stage; conductivity; conductivity per stage and / or fracture hydraulic conductivity.

15. The method according to any preceding claim comprising injecting the first tracer into the at least one fracture during the formation of the at least one fracture.

16. The method according to any preceding claim comprising collecting samples of the fluid at one or more sampling times.

17. The method according to any preceding claim comprising measuring and / or monitoring the concentration of tracer in the samples.

18. The method according to any preceding claim comprising calculating at least one flow characteristic for the at least one fracture based on the arrival time of tracer in the samples.

19. The method according to any preceding claim comprising calculating at least one flow characteristic by quantifying a proportion of flow from each fracture stage by performing a dilution calculation.

20. The method according to any preceding claim comprising measuring surface flow rate, measuring surface pressure, measuring downhole pressure, measuring pressure at a stage hydraulic fracture, calculating downhole pressure for each stage fracture and / or measuring pressure at each stage hydraulic fracture while producing from one or more wells and using these data as input for permeability and conductivity calculations.

21. The method according to any preceding claim comprising determining an effect of a frac hit on production in a production well.

22. The method according to any preceding claim analysing tracer data set for each tracer for each fracture stage.

23. The method according to any preceding claim comprising calculating a residence time distribution data set for each tracer from each fracture.

24. A method of collecting samples for analysis in characterising at least one fracture in a well system, wherein the system comprises a well combination comprising a first well and at least one second well and at least one fracture between the first well and the at least one second well; wherein the at least one fracture comprises a first tracer injected into the at least one fracture and a second tracer is located in or at the at least one fracture;the method comprising flowing fluid from the at least one fracture to the at least one second well to carry tracer to the at least one second well;collecting samples from at least the second well.

25. The method according to claim 24 comprising producing fluid from or in the at least a second well to draw, pull and / or direct tracer and fluid in or through the at least one fracture into the at least second well.

26. An interpretation method for characterising at least one fracture in well system, the method comprising:providing tracer data, the tracer data previously obtained by analysis of samples of fluid collected from a production well in a well system comprising a first well and at least a second well, and having at least a first fracture stage from the first well; wherein the at least first fracture comprises at least a first tracer injected into the fracture and at least a second tracer located in or at the fracture;wherein fluid is transferred from the at least one fracture to the at least one production well to carry tracer to the at least one production well;calculating at least one flow characteristic from the tracer data.

27. The method according to claim 26 wherein fluid is drawn and / or pulled from or through the at least one fracture into the production well.A

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