Method and system for monitoring a well treatment

Abstract

Methods of characterising, optimising and interpreting a well treatment using spatial or temporal tracer moment data. The well treatment may be well stimulation, acidizing, matrix acidizing, fracturin

Description

The present invention relates to the field of well treatment and more specifically well treatments including fracturing, acidizing, acidizing fracturing, enhanced oil recovery treatment and / or water control treatments. Aspects of the invention include a method of assessing and characterising a well treatment. Another aspect relates to the optimisation of well treatments and / or well placement. A further aspect relates to characterisation well treatments to improve production forecasting. Background to the invention The efficient recovery of hydrocarbons from a reservoir is a difficult and complex process which reguires an understanding of the flow conditions of the hydrocarbons in the reservoir, formation and connected wells. Similarly, the efficient extraction of heat from enhanced geothermal systems (EGS) where hydraulic fractures connect injection and production wells requires understanding of the flow conditions of injected fluids. Well stimulation techniques use mechanical or chemical methods to artificially create channels in the formation which may facilitate the flow of fluids in order to extract economically viable quantities of hydrocarbon from formations with low flow characteristics. Well stimulation techniques include fracturing, acidizing and fracture acidizing methods. Fracturing is a method which involves pumping a large volume of fracturing liquid, typically water, from a well into a formation, causing cracks in the formation enabling the flow of fluids through the cracks to extract the hydrocarbon or pass fluids through the formation. The cracks are filled with a supporting material called proppant to prevent the cracks from closing. During hydraulic fracturing, planar, branched, or complex fracture networks may form. Knowing the fracture complexity can allow for better forecasting of production and improved treatment design optimization. Acidizing is a method of exposing minerals and rock in the formation to an acid or other reactive fluid. The minerals and rock are dissolved by the acid creating channels into the rock through which fluids can flow. During acidizing of formations typically a carbonate formation, complex flow patterns called wormholes form as a result of acid transport and reaction in the porous formation media. The wormhole structure may vary significantly. Knowing the wormhole structure created in the reservoir would allow for better forecasting of production and for optimization of the treatments. Fracture acidizing is a well-stimulation operation in which an acid is injected into a formation typically 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. Differential etch patterns form on the fracture faces which enhance productivity. The length and pattern of the etched fracture depends on acid leak-off and acid spending. The development of wormholes in the fracture face can increase the reactive surface area and cause excessive leak-off and rapid spending of the acid. Knowing the etch length and pattern created in the reservoir would allow for better forecasting of production and for optimization of the treatments. Summary of the invention It is amongst the aims and objects of the invention to provide a method and system for characterising changes in flow profiles following well treatments. It is another object of an aspect of the invention to provide a method and system for assessing at least one flow path and / or characteristics of at least one flow path after a well treatment using tracer data. It is a further object of an aspect of the invention to characterise a stimulation treatment using tracer type curves. It is another object of the present invention to provide a method of assessing or characterising changes in flow profiles during and / or after a well treatment operation. It is further object of the present invention to provide a method of assessing curves from tracer residence time distribution (RTD) response to assess the type of flow pattern that are created in the reservoir as a result of well treatments such as matrix acidizing, fracture acidizing, hydraulic fracturing stimulation treatments water control treatment and / or enhanced oil recovery treatment. 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 a a well treatment, the method comprising: introducing two or more tracers into a well at known times, steps and / or stages of the well treatment; producing fluid in the well from a reservoir, collecting samples of produced fluid; analysing the samples for the presence and / or concentration of the two or more tracers; based on the presence and / or concentration of tracers in the samples estimating at least one characteristic of the well 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 well may be a hydrocarbon well, a treatment well, an injection well, a hydrocarbon reservoir system, a geothermal well, geothermal well system or an enhanced geothermal system. The method may comprise introducing the two or more tracers at known different times, steps and / or stages of the well treatment. The method may comprise introducing at least one tracer into a well before and / or with the well treatment. The method may comprise introducing at least one tracer into a well at an early stage or portion of the well treatment. The method may comprise introducing a first tracer into a well before and / or with the well treatment. The may comprise introducing a second or further tracer into a well at a known time after introducing the first tracer into the well. The method may comprise introducing at least one 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 first tracer into a well before and / or with the well treatment and introducing at least a 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 two or more tracers into a well at different times in a stage of a well treatment. The method may comprise introducing two or more tracers into a well at different times during a stage of a well treatment. The method may comprise introducing two or more tracers into a well at different times in each stage of a well treatment. The method may comprise introducing two or more tracers into a well at different times during a first treatment stage. The method may comprise introducing two or more tracers into a well at different times during a second treatment stage. The method may comprise a multistage well treatment operation. The method may comprise introducing at least two tracers per treatment stage in a multistage operation. The method may comprise introducing a plurality of tracers into the well. The method may comprise obtaining tracer test data of the reservoir and / or well before the well treatment from historical tracer injection and / or production associated with production from the reservoir. The method may comprise obtaining tracer test data from historical tests previously conducted before the well treatment. The historical tracer data may be stored in a database. The method may comprise introducing at least one tracer into the well by injecting the tracer into the well from surface and / or from a downhole device. The method may comprise introducing each of the two or more tracers into the well by injecting the tracer into the well from surface and / or from a downhole device. Each of the two or more tracers may be installed, arranged or positioned in the well. The method may comprise introducing the at least one tracer into the well by releasing the tracer from at least one installed, arranged or positioned tracer source in the well. Each of the two or more tracers may be a liquid, solid or gas tracer. The two or more tracers may be a solid tracer configured to slowly release from particulates pumped with the treatment such as proppant particles or fluid loss particles. The method may comprise injecting at least one partitioning tracer with at least one passive tracer into the reservoir. The method may comprise injecting at least one reactive partitioning tracer with at least one passive tracer into the reservoir. The method may comprise injecting at least one partitioning tracer with at least one passive tracer concurrently. At least one tracer may be premixed with a well treatment fluid. At least one tracer may be added to the well treatment fluid. At least one tracer may be co-injected with a well treatment fluid. At least one tracer may be co-released with the well treatment fluid. At least one tracer may be in an inflow tracer. At least one tracer may be in particulate form. At least one tracer may comprise a fluid loss additive. At least one tracer may be a proppant. Each of the two or more tracers may be distinct or different to one another. Each of the two or more tracers may be a chemical tracer. Each of the two or more tracers may be non-radioactive tracer. The method may comprise introducing at least one tracer into the well with a slurry. At least one tracer may be a component or mixed with a pre-acid slurry or composition. The method may comprise introducing at least one tracer into the well with a treatment fluid. The method may comprise introducing at least one tracer into the well with an acid fluid. The method may comprise introducing at least one tracer into the well with a fracturing fluid. The first tracer may be a component or mixed with a pre-acid slurry, treatment fluid, acid fluid, pad fluid and / or fracturing fluid. The method may comprise adding at least one circulation tracer to all fluid injected. The method may comprise adding at least one circulation tracer to fluid in each stage. The method may comprise adding at least one circulation tracer to fluid in all stages. The at least one circulation tracer may be a distinct tracers. The at least one circulation tracer may be injected as mass balance tracers at a constant concentration throughout each fracture stage. The at least one circulation tracer may be a mass balance tracer. The method may comprise circulating at least one circulation tracer from the well to and / or through each fracture stage. At least one of the tracers may be a circulation tracer. The method may comprise multistage fracture treatments comprising two or more fracture stages. The method may comprise injecting at least one distinct tracer into each stage hydraulic fracture, and may comprise circulating at least one distinct circulation tracer through each fracture. The method may comprise injecting at least one distinct tracer into each stage hydraulic fracture, and may comprise circulating at least one circulation tracer through all fracture stages. The method may comprise injecting the at least one tracer into at least one fracture or circulating the at least one circulation tracer from surface. The method may comprise injecting the at least one tracer into at least one fracture or circulating the at least one circulation tracer from a downhole device. The method may comprise injecting the at least one tracer into at least one fracture or circulating the at least one circulation tracer from a tracer source installed, arranged or positioned in the well. The method may comprise comparing the presence and / or concentration of the at least one circulation tracer with the presence and / or concentration of the at least one tracer introduced to individual stages. The method may comprise assessing quality control based on a comparison of the presence and / or concentration of the at least one circulation tracer with the presence and / or concentration of the at least one tracer introduced to individual stages a may be determined. The method may comprise quantifying a total proportion of injected fluid vs other fluids based on a comparison of the presence and / or concentration of the at least one circulation tracer with the presence and / or concentration of the at least one tracer introduced to individual stages. The method may comprise calculating, estimating and / or determining at least one spatial or temporal moment for each of the two or more tracers from a measured tracer data set. The method may comprise comparing the at least one spatial or temporal moment of each of the two or more tracers. The at least one spatial or temporal moment may be at least one spatial or temporal tracer distribution moment. The method may comprise comparing at least one spatial or temporal moment for the first tracer with at least one spatial or temporal moment for the second tracer. The method may comprise measuring, calculating or determining a difference or change between the least one spatial or temporal moment for the two or more tracers. The method may comprise measuring, calculating or determining a difference or change between the least one spatial or temporal moment of the first tracer and the at least second tracer. The method may comprise associating a difference or change between the at least one spatial or temporal moment for the two of more tracers with a characteristic of the well treatment. The method may comprise measuring, calculating or determining a ratio between the least one spatial or temporal moment of each of the two or more tracers. The method may comprise associating a ratio between the at least one spatial or temporal tracer distribution moment for the two of more tracers with a characteristic of the well treatment. The method may comprise measuring, calculating or determining a ratio between the least one spatial or temporal moment of the first tracer and the at least second tracer. The method may comprise associating a difference or change or ratio between the at least one spatial or temporal moment for the first tracer and the at least second tracer with a characteristic of the well treatment. The method may comprise analysing a measured tracer data set for each of the two or more tracers. The measured tracer data set may be a tracer concentration 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 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 storing the measured tracer data sets in a database. The at least one moment may be selected from a zero order moment, a first order moment, a second order moment and / or a third order moment. The at least one order moment may be more than two orders. The method may comprise calculating a residence time distribution data set for each of the two or more tracers. The method may comprise calculating a residence time distribution data set for the first tracer. The method may comprise calculating a residence time distribution data set for the second or a further tracer. The method may comprise obtaining or calculating a residence time distribution by monitoring the tracer concentration produced from the reservoir as a function of time and / or space. The method may comprise creating a tracer curve from the measured tracer concentration as a function of time. The method may comprise calculating an area under the tracer curve to calculate the at least one moment of measured tracer data set. The method may comprise comparing the at least one moment of the measurement data set of the first tracer and the at least one moment of the measurement data set of the at least the second tracer to characterise and / or assess the well treatment. The method may comprise calculating a swept volume for each of the two or more tracers. The method may comprise calculating a swept volume of the first tracer in the reservoir from the first order moment of the first tracer data set. The method may comprise calculating a swept volume of the at least the second tracer in the reservoir from the first order moment of the at least the second tracer data set. The method may comprise comparing the sweep volumes from before and after the treatment. The method may comprise comparing tracer response data following a well treatment or well treatment stage with a tracer response data conducted separately prior to the well treatment or well treatment stage. The method may comprise calculating at least one tracer arrival time characteristic. The method may comprise calculating at least one tracer arrival time characteristic for each of the two or more tracers. The method may comprise calculating tracer arrival time characteristic for the first tracer. The method may comprise calculating tracer arrival time characteristic for the second tracer. The arrival time characteristic may comprise first arrival times and / or average arrival times. The method may comprise comparing the arrival time characteristic for the two or more tracers to assess the well treatment and / or to assess a magnitude of change associated with the well treatment. The method may comprise comparing the arrival time characteristic for the first and second tracer to assess the well treatment and / or to assess a magnitude of change associated with the well treatment. The method may comprise comparing the tracer response curves of the two or more tracers to assess the well treatment. The method may comprise comparing the at least one moment for the two or more tracers to assess the well treatment and / or to assess a magnitude of change associated with the well treatment. The method may comprise comparing the at least one moment for the first and / or second tracer to assess the well treatment and / or to assess a magnitude of change associated with the well treatment. The method may comprise calculating a first temporal moment, a second temporal moment and / or a third temporal moment for at least one tracer. The method may comprise calculating a first temporal moment, a second temporal moment and / or a third temporal moment for each of the two or more tracers. The method may comprise calculating a ratio of the first temporal moment, a second temporal moment and / or a third temporal moment for each of the two or more tracers. The method may comprise calculating a mean arrival time for at least one tracer. The method may comprise calculating a mean arrival time for each of the two or more tracers. The method may comprise comparing the mean arrival time of each of the two or more tracers. The method may comprise calculating a ratio of the mean arrival time for each of the two or more tracers. The method may comprise calculating a ratio of the third temporal moment and a ratio of the mean arrival time for each of the two or more tracers. The method may comprise analysing the measured tracer data to characterize a reservoir flow pattern. The method may comprise analysing the measured tracer data to identify a reservoir flow pattern and / or identify a reservoir flow pattern type created by the well treatment. The method may comprise identifying at least one characteristic including a type of stimulation pattern, flow pattern, fracture type, and / or at least one flow path associated with channels, proppant duning, cluster runaway, or micro-annulus. The method may comprise identifying at least one characteristic including loss in complexity, loss in conductivity, and / or loss of connectivity over time. The method may comprise identifying a type of stimulation pattern, flow pattern, fracture types, and / or flow path associated with channels, proppant duning, cluster runaway, or micro-annulus. The method may comprise characterising a fracture. The method may comprise characterising a fracture complexity. The method may comprise identifying a type of stimulation pattern, flow pattern, fracture types, and / or flow path associated with channels, proppant duning, cluster runaway, or micro-annulus by comparing a measured tracer response curve with a library of tracer response curves associated with various stimulation pattern, flow pattern, fracture types, and / or flow paths associated with channels, proppant duning, cluster runaway, or micro-annulus. The method may comprise identifying a type of stimulation pattern, flow pattern and / or fracture type by comparing a measured tracer residence time distribution pattern with a library of residence time distribution patterns associated with various stimulation pattern, flow pattern, fracture types, and / or flow paths associated with channels, proppant duning, cluster runaway, or micro-annulus. The method may comprise identifying and / or characterising flow patterns by comparing a measured difference, change, and or ratio between tracer response curves with a library of difference, change, and / or ratio between tracer response curves associated with various stimulation pattern, flow pattern, fracture types, and / or flow paths associated with channels, proppant duning, cluster runaway, or micro-annulus. The method may comprise identifying or characterising a degree of complexity and / or shape of a fracture or flow path pattern. The method may comprise identifying a type of stimulation pattern, flow pattern and / or fracture type by comparing a measured arrival time data set with a library of arrival time data sets associated with various stimulation pattern, flow pattern, fracture types, and / or flow paths associated with channels, proppant duning, cluster runaway, or micro-annulus. The method may comprise quantifying a reservoir volume. The method may comprise quantifying an effective reservoir volume. The method may comprise quantifying an effective stimulated reservoir volume. The method may comprise characterising and / or classifying the tracer response curve type. The method may comprise identifying a stimulation treatment status, well treatment status or pattern based on the characterised and / or classified tracer response curve type. The library of tracer response curves, residence time distribution pattern, arrival time data sets, differences, change, and / or ratio associated with various stimulation patterns, flow patterns and / or fracture types may be determined from model simulations, laboratory core flow experiments, laboratory fracture conductivity experiments, calibration of typical treatment results in the field and / or historical tracer injection and / or production data. The method may comprise repeating the analysis for multiple treatment stages in a single well. For each treatment stage at least one tracer may be introduced before and / or with the well treatment. For each treatment stage at least one tracer may be introduced 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 optimising the well treatment to achieve the optimum stimulation pattern, flow pattern and / or fracture type. The method may comprise optimising the well treatment to achieve the optimum stimulation pattern, flow pattern and / or fracture type in future well treatments stages. 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 the well treatment by adjusting additional treatment and / or changing the treatment design in subsequent stages or subsequent wells. The method may comprise optimising the well treatment by adjusting one or more parameters selected from the group comprising well landing point, well trajectory, perforation locations, perforation cluster spacing, stage length, number of perforation clusters per stage, and / or limited entry perforating. The method may comprise forecasting production and reservoir performance based on identified stimulation patterns, flow patterns and / or fracture types. The method may comprise adjusting production simulations and / or reservoir simulations with identified stimulation patterns, flow patterns and / or fracture types to improve or assist forecasting of production and reservoir performance. The method may comprise characterising changes in reservoir flow patterns. The method may comprise controlling or adjusting reservoir flow patterns based on the measured tracer data. The method may comprise injecting surfactants to change wettability. The method may comprise injecting diverting agents to block zones from further injection. The method may comprise injecting polymers to modify sweep profiles during enhanced oil recovery (EOR). The method may comprise injecting plugging agents for water control. The method may comprise analysing the measured tracer data to identify a flow path type through a formation. The method may comprise analysing the measured tracer data to identify and / or characterise a flow path type created as a result of a well treatment such as matrix acidizing, fracture acidizing and / or hydraulic fracturing. The flow path type may be selected from the group comprising a face dissolution, conical wormhole, dominant wormhole, ramified wormhole, uniform dissolution, an etch pattern, a near-wellbore dissolution, heterogeneous etch channel, channels, planar fractures, branched fractures, complex fractures and / or cracks, flow around proppant dunes and / or proppant pillars (e.g., such as in channel fracturing), flow through micro-annulus, and / or flow patterns associated with cluster runaway. The method may comprise obtaining well treatment data. The well treatment data may be selected from the group comprising treatment type, treatment fluid type, fluid reactivity, injection rate, injection volume, and / or treatment pressure. The well stimulation treatment may be selected from the group comprising acidizing, matrix acidizing, fracturing, hydraulic fracturing, and / or fracture acidizing. The method may be used to characterize the type of fracture driven interaction, commonly referred to as frac hit. The method may be used to characterize the change in flow profile created by enhanced oil recovery operations. The method may comprise creating a model of the reservoir and / or well. The method may comprise creating a model of the well treatment. The method may comprise creating a model of the well stimulation treatment. The method may comprise constructing a model of the reservoir, well and / or well treatment from measured physical data. The method may comprise constructing the model from historical measured tracer data. The method may comprise characterizing the well treatments based on the model. The method may comprise controlling and / or adjusting well treatments based on the model. The method may comprise controlling and / or adjusting parameters of well treatments based on the model. The adjustable parameters may be selected from the group comprising treatment type, treatment fluid type, reactivity, injection volume, injection rate, pulsing and / or injection pressure. The method may comprise modelling data from each of the tracers. The model tracer data set may be a tracer concentration as a function of time. The model tracer data set may be a tracer concentration time series. The model tracer data set may be a modelled residence time distribution. The model tracer data set may be a residence time distribution. The model tracer data set may be a tracer concentration as a function of space. The model tracer data set may be a tracer concentration measured at distinct positions in space. The model tracer data set may be a modelled spatial distribution of tracer. The model tracer data set may be a spatial distribution of tracer. The method may comprise creating a tracer curve from the modelled tracer concentration as a function of time. The method may comprise calculating an area under the tracer curve to calculate the at least one moment of modelled tracer data set The method may comprise analysing the tracer data from the two or more tracers. The method may comprise modelling data from the two or more tracers. The method may comprise iteratively varying at least one a value of at least one parameter in the model until an optimal well treatment is determined. The method may comprise comparing measured tracer data with a library of modelled and / or historical tracer data sets or response curves associated with various stimulation patterns, flow patterns and / or fracture types. The method may be a computer-implemented method. The method may comprise storing the measured tracer data to a database. The method may comprise storing the model data to a database. The method may comprise interrogating or comparing the modelled tracer data, library of tracer data and / or tracer data database with at least one measured tracer data set. The method may comprise characterizing the well treatment based on the measured tracer data set and / or model. The method may comprise modifying the well treatment based on the measured tracer data set and / or model. The method may comprise modifying a future stage of the well treatment based on the measured tracer data set and / or model. The method may comprise modifying a future well treatment based on the measured tracer data set and / or model. The method may comprise modifying injection and / or injection rates into the well and / or reservoir based on the measured tracer data set and / or model. The method may comprise modifying production and / or production rates from the reservoir based on the measured tracer data set and / or model. The reservoir and / or well may be a hydrocarbon reservoir well, an unconventional reservoir, a reservoir undergoing enhanced oil recovery (EOR) operations, or a geothermal reservoir / well. The method may comprise optimising an injection configuration of the injection fluid and / or a production configuration of the produced fluid based on the tracer data. The injection configuration may be an injection rate, injection concentration, injection location, number of injection locations, injection time, injection well location, injection location in the injection well, injection frequency and / or injection volume. The production configuration may be a production rate, production location, production time, sampling time, sampling location, production frequency and / or production volume. The method may comprise controlling and / or optimising the rate of injection and / or rate of producing fluid from the subterranean formation. The method may comprise controlling and / or optimising the rate of injection and / or rate of producing fluid from the subterranean formation based on the tracer data. The method may comprise controlling energy output by adjusting the injection rate of the injection fluid and / or adjusting a production rate of the produced fluid. The method may comprise evaluating a well injection and / or well production configuration based on at least one fracture characteristic, fracture type and / or fracture complexity. The method may comprise modelling the formation or reservoir, tracer concentration, transport time, injection flow rate and / or production rates. The formation or reservoir model profile, tracer concentration, transport time, injection flow rate and / or production rate may be adjusted until calculated concentrations of model tracers compare with the measured concentrations of identified tracers to estimate formation or reservoir characteristics. The model may comprise parameters selected from the group comprising: the number of injection wells, temperature, number of production wells, transport time, transport time of tracer-containing fluid from injection to production for one or more injection wells, transport time of tracer-containing fluid from injection to production for one or more production wells, transport time of tracer-containing fluid through the reservoir, tracer type, tracer combination, concentration of tracer, concentration of tracer as a function of time, fluid flow path from one or more injection well to one or more production wells in communication to the reservoir, residence time, injection rate, production rate, rock mechanics, pressure, gravity, density, viscosity; reservoir permeability, reservoir heterogeneities, solubility, fluid chemistry, porosity, fluid saturation, injection amount, injection volumes and / or migration path of the at least one tracer in and / or through the formation. In the case of a geothermal system the model may additionally or alternatively comprise parameters selected from the group comprising mixing capacity of cold injected fluid with hot fluid in the reservoir, heat equilibrium rate of the reservoir, temperature of fluid injected, the temperature of fluid at each injection well, temperature of fluid produced, enthalpy, enthalpy output and / or heat equilibrium rate of the reservoir. According to a second aspect of the invention there is provided a method of characterising or assessing a well treatment, the method comprising: calculating, obtaining and / or measuring a tracer data set for at least one tracer in the well before the well treatment; calculating, obtaining and / or measuring a tracer data set for at least one tracer introduced into the well at a later stage or later portion of the well treatment or after at least well treatment stage has been completed or approaching completion; comparing the tracer data set of the tracers to estimate at least one characteristic of the well treatment. The method may comprise calculating, obtaining and / or measuring a tracer data set for at least one tracer present in the well before and / or at an early stage or portion of the well treatment. The method may comprise producing fluid in the well from the reservoir after the well treatment. The method may comprise collecting samples of produced fluid. The method may comprise analysing the samples for the presence and / or concentration of the two or more tracers. The method may comprise assessing the well stimulation treatment based on the presence and / or concentration of the tracers in the samples assessing the well treatment. The method may comprise introducing the two or more tracers at known different times and / or stages of the well treatment. The method may comprise introducing at least one tracer into a well before and / or with the well treatment. The method may comprise introducing at least one tracer into a well at an early stage of the well treatment. The method may comprise introducing a first tracer into a well before and / or with the well treatment. The may comprise introducing a second or further tracer into a well at a known time after introducing the first tracer into the well. The method may comprise introducing at least one 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 first tracer into a well before and / or with the well treatment and introducing at least a 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 calculating, estimating and / or determining at least one spatial or temporal moment for each of the two or more tracers from a measured tracer data set. The method may comprise comparing the at least one spatial or temporal moment of each of the two or more tracers. The method may comprise measuring, calculating or determining a difference or change between the least one spatial or temporal moment for the two or more tracers. The method may comprise associating a difference or change between the at least one spatial or temporal moment for the two of more tracers with a characteristic of the well stimulation treatment. The method may comprise analysing a measured tracer data set for each of the two or more tracers. The measured tracer data set may be a tracer concentration as a function of time. The measured tracer data set may be a tracer concentration time series. The method may comprise calculating a residence time distribution data set for each of the two or more tracers. The method may comprise creating a tracer curve from the measured tracer concentration as a function of time. The method may comprise calculating an area under the tracer curve to calculate the at least one moment of measured tracer data set. The method may comprise comparing the at least one moment of the measurement data set of the first tracer and the at least one moment of the measurement data set of the at least the second tracer to characterise and / or assess the well treatment. The method may comprise calculating a swept volume for each of the two or more tracers. The method may comprise calculating at least one tracer arrival time characteristic. The method may comprise calculating at least one tracer arrival time characteristic for each of the two or more tracers. The method may comprise comparing the arrival time characteristic for the two or more tracers to assess the well treatment. The method may comprise analysing the measured tracer data to characterize a reservoir flow pattern. The method may comprise analysing the measured tracer data to identify a reservoir flow pattern. The method may comprise analysing the measured tracer data to identify a reservoir flow pattern type created by the well treatment. The method may comprise identifying a type of stimulation pattern, flow pattern and / or fracture type by comparing a measured tracer response curve with a library of tracer response curves associated with various stimulation patterns, flow patterns and / or fracture types. The method may comprise identifying a type of stimulation pattern, flow pattern and / or fracture type by comparing a measured tracer residence time distribution pattern with a library of residence time distribution patterns associated with various stimulation patterns, flow patterns and / or fracture types. The method may comprise identifying a type of stimulation pattern, flow patterns and / or fracture type by comparing a measured arrival time data set with a library of arrival time data sets associated with various stimulation patterns, flow patterns and / or fracture types. The method may comprise characterising and / or classifying the tracer response curve type. The method may comprise identifying a stimulation treatment status, well treatment status or pattern based on the characterised and / or classified tracer response curve type. The library of tracer response curves, residence time distribution pattern and / or arrival time data sets associated with various stimulation patterns, flow patterns and / or fracture types may be determined from model simulations, laboratory core flow experiments, laboratory fracture conductivity experiments, calibration of typical treatment results in the field and / or historical tracer injection and / or production data. 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 optimising a a well treatment, the method comprising: introducing two or more tracers into a well at known times and / or stages of the well treatment; producing fluid in the well from the reservoir, collecting samples of produced fluid; analysing the samples for the presence and / or concentration of the two or more tracers; based on the presence and / or concentration of the tracers in the samples estimating at least one characteristic of the well treatment; and adjusting at least one parameter of the well stimulation treatment. The method may comprise optimising the well treatment to achieve an optimum stimulation pattern, flow pattern and / or fracture type. The method may comprise optimising the well treatment to achieve the optimum stimulation pattern, flow patterns and / or fracture type in future well treatments stages. The method may comprise optimising the well treatment by adjusting one or more parameters selected from the group comprising well treatment type, stimulation type, stimulation fluid type, fluid reactivity, injection volume, injection rates, proppant concentrations and / or diverting agents. The method may comprise optimising the well treatment by adjusting additional treatment and / or changing the treatment design in subsequent stages or subsequent wells. The method may comprise forecasting production and reservoir performance based on identified stimulation patterns, flow pattern and / or fracture types. The method may comprise adjusting production simulations and / or reservoir simulations with identified stimulation patterns, flow pattern and / or fracture types to improve or assist forecasting of production and reservoir performance. 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 method may comprise characterising changes in reservoir flow patterns. The method may comprise controlling or adjusting reservoir flow patterns based on the measured tracer data. The method may comprise injecting surfactants to change wettability. The method may comprise injecting diverting agents to block zones from further injection. The method may comprise injecting polymers to modify sweep profiles during enhanced oil recovery (EOR). The method may comprise injecting plugging agents for water control. The method may comprise analysing the measured tracer data to identify a flow path type through a formation. The method may comprise analysing the measured tracer data to identify a flow path type created as a result of a stimulation treatment such as matrix acidizing, fracture acidizing and / or hydraulic fracturing. The flow path type may be selected from the group comprising a face dissolution, conical wormhole, dominant wormhole, ramified wormhole, uniform dissolution, an etch pattern, a near-wellbore dissolution, heterogeneous etch channel, channels, planar fractures, complex fractures and / or cracks. The method may comprise obtaining well stimulation treatment data. The well stimulation treatment data may be selected from the group comprising treatment fluid type, fluid reactivity, injection rate, injection volume, and / or treating pressure. The well stimulation treatment may be selected from the group comprising acidizing, matrix acidizing, fracturing, hydraulic fracturing, and / or fracture acidizing. The method may comprise creating a model of the reservoir and / or well. The method may comprise controlling and / or adjusting well stimulation treatments based on the model. The method may comprise controlling and / or adjusting parameters of well stimulation treatments based on the model. The adjustable parameters may be selected from the group comprising treatment type, treatment fluid type, reactivity, injection volume, injection rate and / or injection pressure. The method may comprise controlling the stimulation treatment based on the measured tracer data set and / or model. The method may comprise controlling a future stage of stimulation treatment based on the measured tracer data set and / or model. The method may comprise controlling a future stimulation treatment based on the measured tracer data set and / or model. The method may comprise controlling injection and / or injection rates into the well and / or reservoir based on the measured tracer data set and / or model. The method may comprise controlling production and / or production rates from the reservoir based on the measured tracer data set and / or model. Embodiments of the third aspect of the invention may include one or more features of the first or second aspects of the invention or their embodiments, or vice versa. According to a fourth aspect of the invention there is provided a method of characterising a a hydraulic fracturing treatment, the method comprising: introducing two or more tracers into a well at known times or stages of the well stimulation treatment; producing fluid in the well from a reservoir, collecting samples of produced fluid; analysing the samples for the presence and / or concentration of the two or more tracers; based on the presence and / or concentration of the tracers in the samples estimating at least one characteristic of the hydraulic fracturing treatment. The method may comprise analysing the measured tracer data to identify a flow path type through a formation. The method may comprise analysing the measured tracer data to identify a flow path type created as a result of a hydraulic fracturing treatment. The method may comprise identifying a flow path type selected from the group comprising channels, planar fractures, complex fractures and / or cracks. The method may comprise characterizing a loss in conductivity from a hydraulic fracture over time. At least one tracer may be a solid tracer. At least one tracer may be a slow release tracer. At least one tracer may be located or positioned into the near-wellbore region. At least one tracer may be an inflow tracer placed in the completion or a particulate tracer in the near wellbore. At least one tracer may be located or positioned into a fracture network. The method may comprise exposing the two or more tracers to the same flow rate from the same fracture. The method may comprise assessing a difference in tracer response from the two or more tracers to characterize a loss in conductivity over time. 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 a well stimulation acidizing treatment, the method comprising: introducing at least one tracer into a well at known times and / or stages of the acidizing treatment; producing fluid in the well from the reservoir, collecting samples of produced fluid; analysing the samples for the presence and / or concentration of tracer; based on the presence and / or concentration of tracer in the samples estimating at least one characteristic of the acidizing treatment. The method may comprise introducing at least one tracer into a well before and / or with the well stimulation treatment. The method may comprise introducing the two or more tracers at known different times and / or stages of the well stimulation treatment. The method may comprise introducing at least one tracer into a well at an early stage of the well stimulation treatment. The method may comprise introducing a first tracer into a well before and / or with the well stimulation treatment. The method may comprise introducing a second or further tracer into a well at a known time after introducing the first tracer into the well. The method may comprise introducing at least one tracer into a well at a later stage or later portion of the well stimulation treatment or after at least one well stimulation treatment stage has been completed or approaching completion. The method may comprise introducing a first tracer into a well before and / or with the well stimulation treatment and introducing at least a second tracer into a well at a later stage or later portion of the well stimulation treatment or after at least one well stimulation treatment stage has been completed or approaching completion. The method may comprise introducing a plurality of tracers into the well. The method may comprise analysing the measured tracer data to identify a flow path type through a formation. The method may comprise analysing the measured tracer data to identify a flow path type created as a result of the acidizing treatment. The method may comprise identifying a flow path type selected from the group comprising face dissolution, conical wormhole, dominant wormhole, ramified wormhole, uniform dissolution, an etch pattern, a near-wellbore dissolution and / or heterogeneous etch channel, depth of perforation, channel size and type, planar fractures, complex fractures and / or cracks. 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 a an acidizing fracturing treatment, the method comprising: introducing at least one tracer into a well at known times and / or stages of the acidizing fracturing treatment; producing fluid in the well from the reservoir, collecting samples of produced fluid; analysing the samples for the presence and / or concentration of the at least one tracer; based on the presence and / or concentration of the tracers in the samples estimating at least one characteristic of the acidizing fracturing treatment. The method may comprise introducing at least one tracer into a well before and / or with the well stimulation treatment. The method may comprise introducing the two or more tracers at known different times and / or stages of the well stimulation treatment. The method may comprise introducing at least one tracer into a well at an early stage of the well stimulation treatment. The method may comprise introducing a first tracer into a well before and / or with the well stimulation treatment. The method may comprise introducing a second or further tracer into a well at a known time after introducing the first tracer into the well. The method may comprise introducing at least one tracer into a well at a later stage or later portion of the well stimulation treatment or after at least one well stimulation treatment stage has been completed or approaching completion. The method may comprise introducing a first tracer into a well before and / or with the well stimulation treatment and introducing at least a second tracer into a well at a later stage or later portion of the well stimulation treatment or after at least one well stimulation treatment stage has been completed or approaching completion. The method may comprise introducing a plurality of tracers into the well. The method may comprise analysing the measured tracer data to identify a flow path type through a formation. The method may comprise analysing the measured tracer data to identify a flow path type created as a result of the acidizing fracturing treatment. The method may comprise identifying a flow path type selected from the group comprising face dissolution, conical wormhole, dominant wormhole, ramified wormhole, uniform dissolution, an etch pattern, a near-wellbore dissolution and / or heterogeneous etch channel, depth of perforation, channel size and type, planar fractures, complex fractures and / or cracks. 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 a well stimulation treatment, the method comprising: analysing samples for the presence and / or concentration of tracers in the samples, the samples previously collected from the production flow after introducing two or more tracers into a well at known times and / or stages of the well stimulation treatment; based on the presence and / or concentration tracers in the samples estimating at least one characteristic of the well stimulation treatment. The samples previously collected may be collected from the production flow after introducing a first tracer into the well into the well before and / or with a well stimulation treatment; and introducing at least a second tracer at a later stage of the well stimulation treatment or after the well stimulation treatment has been completed. 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 optimising a well stimulation treatment, the method comprising: analysing samples for the presence and / or concentration of tracers in the samples, the samples previously collected from the production flow after introducing two or more tracers into a well at known times and / or stages of the well stimulation treatment; based on the presence and / or concentration tracers in the samples estimating at least one characteristic of the acidizing fracturing treatment; and adjusting at least one parameter of the well stimulation treatment. The samples may be previously collected from the production flow after introducing a first tracer into the well into the well before and / or with a well stimulation treatment; and introducing at least a second tracer at a later stage of the well stimulation treatment or after the well stimulation treatment has been completed. The method may comprise optimising the well stimulation treatment to achieve the optimum stimulation pattern and / or fracture type. The method may comprise optimising the well stimulation treatment to achieve an optimum stimulation pattern and / or fracture type in future well stimulation treatments stages. The method may comprise optimising the well stimulation 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 the well stimulation treatment by adjusting additional treatment and / or changing the treatment design in subsequent stages or subsequent wells. The method may comprise forecasting production and reservoir performance based on identified stimulation patterns, flow patterns and / or fracture types. The method may comprise adjusting production simulations and / or reservoir simulations with identified stimulation patterns and / or fracture types to improve or assist forecasting of production and reservoir performance. The method may comprise characterising changes in reservoir flow patterns. The method may comprise modifying or adjusting reservoir flow patterns based on the measured tracer data. The method may comprise injecting surfactants to change wettability. The method may comprise injecting diverting agents to block zones from further injection. The method may comprise injecting polymers to modify sweep profiles during enhanced oil recovery (EOR). The method may comprise injecting plugging agents for water control. The method may comprise analysing the measured tracer data to identify a flow path type through a formation. The method may comprise analysing the measured tracer data to identify a flow path type created as a result of a stimulation treatment such as matrix acidizing, fracture acidizing and / or hydraulic fracturing. The flow path type may be selected from the group comprising a face dissolution, conical wormhole, dominant wormhole, ramified wormhole, uniform dissolution, an etch pattern, a nearwellbore dissolution, heterogeneous etch channel, channels, planar fractures, complex fractures and / or cracks. The method may comprise obtaining well stimulation treatment data. The well stimulation treatment data may be selected from the group comprising treatment fluid type, fluid reactivity, injection rate, injection volume, and / or treating pressure. The well stimulation treatment may be selected from the group comprising acidizing, matrix acidizing, fracturing, hydraulic fracturing, frac hit, enhanced oil recovery and / or fracture acidizing. The method may comprise creating a model of the reservoir and / or well. The method may comprise creating a model of the well stimulation treatment. The method may comprise constructing a model of the reservoir, well and / or well stimulation treatment from measured physical data. The method may comprise constructing the model from historical measured tracer data. The method may comprise characterizing the well stimulation treatments based on the model. The method may comprise creating a tracer curve from the modelled tracer concentration as a function of time. The method may comprise calculating an area under the tracer curve to calculate the at least one moment of modelled tracer data set. The method may comprise controlling and / or adjusting well stimulation treatments based on the model. The method may comprise controlling and / or adjusting parameters of well stimulation treatments based on the model. The adjustable parameters may be selected from the group comprising treatment type, treatment fluid type, reactivity, injection volume, injection rate and / or injection pressure. The method may comprise characterizing the stimulation treatment based on the measured tracer data set and / or model. The method may comprise controlling the stimulation treatment based on the measured tracer data set and / or model. The method may comprise controlling a future stage of stimulation treatment based on the measured tracer data set and / or model. The method may comprise controlling a future stimulation treatment based on the measured tracer data set and / or model. The method may comprise controlling injection and / or injection rates into the well and / or reservoir based on the measured tracer data set and / or model. The method may comprise controlling production and / or production rates from the reservoir based on the measured tracer data set and / or model. The reservoir and / or well may be a hydrocarbon reservoir well, an unconventional reservoir; a geothermal reservoir / well and / or an enhanced geothermal system. Embodiments of the eighth aspect of the invention may include one or more features of any of the first to seventh aspects of the invention or their embodiments, or vice versa. According to a ninth aspect of the invention there is provided an interpretation method for a treatment of a well comprising; providing tracer data from a producing well after a treatment; wherein the tracer data comprises tracer concentration over time of two or more tracers in the production flow; wherein the two or more tracers were introduced into the well at known times of the well treatment; analysing the tracer data to estimate at least one characteristic of the well treatment. The known times of the well treatment may be before, during and / or after the well treatment. The method may comprise analysing the tracer data to estimate at least one characteristic of the well after the treatment based on the presence and / or concentration of tracers in the samples. The method may comprise introducing at least one tracer before or at an early stage or portion of the well 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. At least one first tracer was introduced into the well before the well treatment and / or in an early portion of the well treatment. At least one second tracer was introduced into the well at a later portion of the well treatment or after a well treatment stage has been completed or approaching completion. The method may comprise analysing the tracer data to compare the at least one spatial or temporal tracer moment of the at least one first tracer and the at least one second tracer to estimate at least one characteristic of the well treatment. The method may comprise analysing the tracer data to estimate at least one characteristic of the well treatment based on the presence and / or concentration of tracers in the samples. By “early portion" it is meant an early point, time period, or step in a well treatment stage. By “later portion" it is meant a later point, time period, or step in a well treatment stage. 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 computer-readable medium, comprising statements, instructions and / or code configured to direct at least one processor to compare at least a first tracer data set and a second tracer data set; wherein the first tracer data set is obtained from a first tracer introduced into the well before a well treatment, with a well treatment and / or at an early stage or portion of the well treatment and measured first tracer concentrations as a function of time in produced fluids; wherein the second tracer data set is obtained from at least a second tracer introduced into the well at a later stage or after a stimulation treatment and measured second or further tracer concentrations as a function of time in produced fluids. The at least one processor may be configured to calculate and / or analyse an arrival time of the first tracer data set. The at least one processor may be configured to calculate and / or analyse an arrival time of the second or further tracer data set. The at least one processor may be configured to calculate and / or analyse a residence time distribution of the first tracer data set. The at least one processor may be configured to calculate and / or analyse a residence time distribution of the second or further tracer data set. The at least one processor may be configured to calculate at least one moment of the first tracer data set. The at least one processor may be configured to calculate at least one moment of the second tracer data set. The at least one processor may be configured to determine a comparison value of the at least one moment of the first tracer data set compared to the at least one moment of the second tracer data set. The method may comprise calculating at least one moment of the residence time distribution data from the first tracer data set. The method may comprise calculating at least one moment of the residence time distribution data from the second tracer data set. The at least one processor may be configured to compare the tracer response curves of the two or more tracers to assess the well stimulation treatment. The at least one processor may be configured to compare measured tracer response curves with a library of tracer response curves associated with various stimulation pattern and / or fracture types. The at least one processor may be configured identifying a type of stimulation patterns and / or fracture types by comparing a measured tracer residence time distribution pattern with a library of residence time distribution patterns associated with various stimulation pattern and / or fracture types. Embodiments of the tenth aspect of the invention may include one or more of any of features 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 system for characterising and / or optimising a well stimulation treatment, the systems comprises: two or more tracer sources each with a distinct tracer material; at least one tracer release mechanism; at least one well stimulation fluid; at least one pump apparatus to pump or inject the at least one well stimulation fluid; and at least one sampling device configured to collect at least one sample of well fluid at a known sampling location. The at least one tracer release mechanism may be configured to be located in the well. The at least one tracer release mechanism may be configured to be located downhole. The at least one tracer release mechanism may be configured to be located at surface. The at least one tracer release mechanism may be configured to release tracer into the well. The released tracer may be carried with a well stimulation fluid or displacement fluid into the formation and / or reservoir. The at least one tracer release mechanism may be configured to pump or inject tracer into the well. The system may comprise two or more tracer release mechanism. The system may comprise a tracer release mechanism for each tracer. The at least one tracer release mechanism may be configured to release, pump or inject tracer on command and / or a pre-programmed timer or sequence. The at least one tracer release mechanism may be configured introduce the two or more tracer into a well at known times and / or stages of the well stimulation treatment. The at least one tracer release mechanism may be configured to release at least one first tracer into the well before the well treatment and / or in an early portion of the well treatment. The at least one tracer release mechanism may be configured to release at least one second tracer into the well at a later portion of the well treatment or after a well treatment stage has been completed or approaching completion. The at least one sampling device may be configured to collect or take samples of the production flow. The at least one sampling device may be configured to collect or take samples at one or more sampling times. The at least one sampling device may be configured to collect or take samples of well fluid at the surface or downhole. The at least one sampling device may be configured to collect or take samples for further analysis onsite or offsite. The at least one sampling device may be configured to detect the presence of one or more tracers. The at least one sampling device may be configured to detect the presence of tracer one or more tracers in real time. The sampling device may be configured to measure the concentration of one or more tracers in the well fluid. The sampling device may be configured to measure the concentration of one or more tracers in the well fluid in real time. The system may comprise a tracer analyser. The system may comprise at least one processor. The at least one processor may be a computer processor. The at least one processor may be configured to analyse and / or compare tracer data sets of the two or more tracers in collected samples. The at least one processor may be configured to calculate, estimate and / or determine at least one spatial or temporal moment for each tracer. The at least one processor may be configured to analyse at least one spatial or temporal tracer moment of the tracers to estimate at least one characteristic of the well treatment. The at least one processor may be configured to analyse the tracer data to compare the at least one spatial or temporal tracer moment of the tracers to estimate at least one characteristic of the well treatment. The at least one processor may be configured to analyse the tracer data to compare the at least one spatial or temporal tracer moment of the at least one first tracer and the at least one second tracer to estimate at least one characteristic of the well treatment. Embodiments of the eleventh aspect of the invention may include one or more of any of features 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 a method of characterising a well treatment, the method comprising: calculating, estimating and / or determining at least one spatial or temporal tracer moment for at least one tracer in the well before the well treatment and / or in an early portion of the well treatment; calculating, estimating and / or determining at least one spatial or temporal tracer moment for at least one tracer introduced into the well at a later stage or later portion of the well treatment or after at least well treatment stage has been completed or approaching completion; comparing the at least one spatial or temporal tracer moment of the two or more tracers to estimate at least one characteristic of the well treatment. The method may comprise calculating, estimating and / or determining at least one spatial or temporal tracer moment for at least one first tracer in the well before a well treatment and / or in an early portion of a well treatment. The method may comprise calculating, estimating and / or determining at least one spatial or temporal tracer moment for at least one second tracer introduced into the well at a later portion of the well treatment or after a well treatment stage has been completed or approaching completion. The method may comprise comparing the at least one spatial or temporal tracer moment of the at least one first tracer and the at least one second tracer to estimate at least one characteristic of the well treatment. The method may comprise calculating, estimating and / or determining at least one spatial or temporal tracer distribution moment for each tracer. 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 tracer in the well before the well treatment and / or in an early portion of the well treatment is preferably distinct from the at least one tracer introduced into the well at a later stage or later portion of the well treatment or after at least well treatment stage has been completed or approaching completion. The method may comprise calculating, estimating and / or determining at least one spatial or temporal tracer distribution moment for each distinct tracer introduced or present in the well before, during and / or after each stage or portion of a well treatment. The method may comprise introducing at least one tracer into a well before and / or with the well treatment. The method may comprise introducing at least one first tracer into a well before and / or with the well treatment. The method may comprise calculating, estimating and / or determining at least one spatial or temporal tracer distribution moment for at least one tracer in the well before the well treatment from historical tracer injection and / or production associated with production from the reservoir. The at least one tracer may be at least one first tracer. The method may comprise introducing each of the two or more tracers into the well by injecting the two or more tracers into the well from surface or from a downhole device. The method may comprise introducing or injecting each of the two or more tracers into the well at different times before and / or during the same treatment stage. The method may comprise introducing or injecting each of the at least one first tracer and the at least one second tracer at different times before and / or during the same treatment stage. The method may comprise introducing each of the at least one first tracer and the at least one second tracer into the well by injecting the tracers into the well from surface or from a downhole device. The method may comprise introducing at least one tracer into the well by releasing tracer from tracer sources installed, arranged or positioned in the well. The method may comprise introducing each of the at least one first tracer and the at least one second tracer into the well by releasing tracer from tracer sources installed, arranged or positioned in the well. The method may comprise introducing two or more tracer into the same injector well or different injector wells. The method may comprise introducing each of the at least one first tracer and the at least one second tracer into the same injector well or different injector wells. The method may comprise introducing two or more tracers into an injector well, a production well or a combination of at least one injector well and production well. The method may comprise introducing the at least one first tracer and / or the at least one second tracer into an injector well, a production well or a combination of at least one injector well and production well. The method may comprise associating a difference or change between the at least one spatial or temporal tracer distribution moment for the two of more tracers with a characteristic of the well treatment. The method may comprise associating a difference or change between the at least one spatial or temporal tracer moment for the at least one first tracer and the at least one second tracer with a characteristic of the well treatment. The method may comprise associating a ratio between the at least one spatial or temporal tracer moment for the at least one first tracer and the at least one second tracer with a characteristic of the well treatment. The at least one moment may be selected from a zero order moment, a first order moment, a second order moment, a third order moment and / or a higher order moment. The method may comprise introducing at least two tracers per treatment stage in a multistage operation. The method may comprise introducing at least one first tracer and at least one second per treatment stage. The at least one first tracer may be distinctive for each different treatment stage. The at least one second tracer may be distinctive for each different treatment stage. The at least one first tracer and at least one second tracer may be distinctive from one another. The method may comprise analysing a measured tracer concentration data set for each of the two or more tracers. The method may comprise analysing a measured tracer concentration data set for each of the at least one first tracer and the at least one second tracer. The measured tracer concentration data set is tracer concentration as a function of time, tracer concentration as a function of space and / or a residence time distribution. The method may comprise creating a tracer curve from the measured tracer concentration as a function of time and comparing the tracer curves of the two or more tracers to assess the well treatment. The method may comprise calculating an area under the tracer curve to calculate the at least one moment of measured tracer data set and comparing the area under the tracer curve for each of the two or more tracers. The method may comprise calculating an area under the tracer curve to calculate the at least one moment of measured tracer data set and comparing the area under the tracer curve for each of the at least one first tracer and the at least one second tracer. The method may comprise calculating a swept volume for each of the two or more tracers and comparing the swept volume of each of the two or more tracers. The method may comprise calculating a swept volume for each of the at least one first tracer and the at least one second tracer and comparing the swept volume of each of the tracers. The method may comprise calculating an arrival time characteristic for each of the two or more tracers and comparing the arrival time characteristic for the two or more tracers to assess a magnitude of change associated with the well stimulation treatment. The method may comprise calculating an arrival time characteristic for each of the of the at least one first tracer and the at least one second tracer and comparing the arrival time characteristic for the tracers to assess a magnitude of change associated with the well stimulation treatment. The method may comprise analysing the measured tracer concentration data to characterise and / or identify a flow type pattern selected from the group comprising a face dissolution, conical wormhole, dominant wormhole, ramified wormhole, uniform dissolution, an etch pattern, a near-wellbore dissolution, heterogeneous etch channel, channels, planar fractures, complex fractures and / or cracks. The method may comprise identifying and / or characterising flow patterns by comparing a measured tracer response curve with a library of tracer response curves associated with various flow type patterns. The method may comprise improving production forecasting based on characterising flow patterns after the well treatment. The tracers may be selected from the group comprising water tracers, oil tracers, gas tracers, or tracers deployed as solids such as in a polymer matrix, impregnated proppant, or fluid loss material. The tracers may be water soluble. The tracer may be immobilized within and / or to a tracer release apparatus. The tracer release apparatus may comprise tracer molecules and a carrier. The carrier may be a matrix material. The matrix material may be a polymeric material. The tracer material may be chemically immobilized in a way that it releases tracer molecules or particles in the presence of a chemical trigger. The tracer may be selected from the group comprising chemical, fluorescent, phosphorescent, metallic complex, particles, nano particles, quantum dots, magnetic, poly functionalized PEG and PPGs, DNA, antibodies and / or radioactive compounds. The 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 method may comprise introducing at least one distinctive tracer into a well before and / or with a further well treatment and introducing a different tracer into the well at a later stage or later portion of the well treatment or after at least well treatment stage has been completed or approaching completion and comparing the at least one spatial or temporal moment of the tracers to estimate at least one characteristic of the further well treatment. Embodiments of the twelfth aspect of the invention may include one or more of any of features 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 method of optimising a well treatment, the method comprising: calculating, estimating and / or determining at least one spatial or temporal moment for at least one tracer in the well before the well treatment and / or in an early portion of the well treatment; calculating, estimating and / or determining at least one spatial or temporal moment for the at least one tracer introduced into the well at a later stage or later portion of the well treatment or after a well treatment stage has been completed or approaching completion; comparing the at least one spatial or temporal moment of the tracers to estimate at least one characteristic of the well treatment. The method may comprise calculating, estimating and / or determining at least one spatial or temporal moment for at least one first tracer in the well before the well treatment and / or in an early portion of the well treatment. The method may comprise calculating, estimating and / or determining at least one spatial or temporal moment for at least one second tracer introduced into the well at a later portion of the well treatment or after a treatment stage has been completed or approaching completion. The method may comprise comparing the at least one spatial or temporal moment of the at least one first tracer and the at least one second tracer to estimate at least one characteristic of the well treatment. The method may comprise adjusting one or more parameters to optimise the well treatment. The well treatment may be a well profile modification treatment. 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 characterising changes in reservoir flow patterns and optimising the well treatment by adjusting additional treatment and / or changing the treatment design in subsequent stages or subsequent wells. Embodiments of the thirteenth aspect of the invention may include one or more of any of features 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 an interpretation method for characterising a fracture in a well comprising; providing tracer data from a producing well after a well treatment; wherein the tracer data comprises tracer concentration over time of at least one tracer in the production flow; wherein the at least one tracers is introduced into the well at known different times of the well treatment; analysing the tracer data to estimate at least one characteristic of the fracture based on the presence and / or concentration of tracers in the samples. The tracer data may comprise tracer concentration over time of two or more tracers in the production flow; wherein the two or more tracers are introduced into the well at known different times of the well treatment. Embodiments of the fourteenth aspect of the invention may include one or more of any of features 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 an interpretation method for a well treatment of a well comprising; providing tracer data from a producing well; wherein the tracer data comprises tracer concentration over time of one or more tracers in the production flow; wherein the one or more tracers were introduced into the injection well at known times; analysing the tracer data to estimate at least one characteristic of the well stimulation treatment based on the presence and / or concentration of tracers in the samples. The known times including before, during and / or after the well stimulation treatment. Embodiments of the fifteenth aspect of the invention may include one or more of any of features 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 a well treatment of a well comprising; providing tracer data from a producing well at known times after a stimulation treatment; wherein at least two tracers were previously injected in at least one injection well, wherein the tracer data comprises tracer concentration over time of two or more tracers in the production flow; wherein the at least two tracers were introduced into the at least one injection well at known times including before and / or after the well stimulation treatment; analysing the tracer data to estimate at least one characteristic of the well stimulation treatment based on the presence and / or concentration of tracers in the samples. The characteristics of the stimulation may include loss in complexity and / or loss in conductivity overtime. The two or more tracers may be injected in the same injector well. The two or more tracers may be injected in the different injector wells. The tracers may arrive at the production well at two or more times after the stimulation treatment. Embodiments of the sixteenth aspect of the invention may include one or more of any of features of the first to fifteenth aspects of the invention or their embodiments, or vice versa. According to a seventeenth aspect of the invention there is provided a method of characterising at least one fracture in a well, the method comprising: introducing two or more tracers into a well at known times and / or stages of a well treatment; producing fluid in the well, collecting samples of produced fluid; analysing the samples for the presence and / or concentration of the two or more tracers; based on the presence and / or concentration of tracers in the samples estimating at least one characteristic of the at least one fracture. Embodiments of the seventeenth aspect of the invention may include one or more of any of features of the first to sixteenth 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: Figures 1A to 1E are neutron radiographs and castings from laboratory core flow test demonstrating the five main types of dissolution structures formed during matrix acidizing in carbonate porous media; Figure 2A to 2E are simplified sectional diagrams illustrating a comparison of perforation depth for dissolution structures or patterns formed during matrix acidizing in carbonate porous media; Figure 3 is a simplified sectional diagram of a well illustrating a method of assessing a stimulation treatment according to an embodiment of the invention; Figures 4A to 4E are simplified diagrams of a method of assessing different stimulation treatments according to an embodiment of the invention; Figures 5A to 5E are tracer concentration curves over time for different stimulation treatments according to an embodiment of the invention; Figure 6 is a graph showing the difference is skewness of the tracer response vs difference in area under the tracer response curves; Figure 7A to 7C are simplified sectional diagrams illustrating differences in etch patterns formed during fracture acidizing treatments; Figure 8A to 8C are simplified sectional diagrams illustrating different fracture types during fracturing treatments; Figure 9A to 9C are simplified sectional diagrams of a well illustrating a method of assessing a planar fracture, branched fracture and complex fracture network respectively according to an embodiment of the invention; Figure 10A to 10C are example tracer response curves for the planar fracture of Figure 9A, branched fracture of Figure 9B and complex fracture network of Figure 9C respectively according to an embodiment of the invention; Figure 11 is a graph showing the difference is skewness of the tracer response vs difference in variance for hydraulic fracturing; Figure 12 is a flow chart showing steps to characterise a stimulation treatment based on the tracer data according to an embodiment of the invention; Figure 13A to 13C are simplified sectional diagrams of a well illustrating a method of assessing near wellbore dissolution, heterogeneous etch channels and uniform dissolution fracture acidizing types respectively according to an embodiment of the invention; Figure 14A to 14C are example tracer response curves for the near wellbore dissolution of Figure 13A, heterogeneous etch channels of Figure 13B and uniform dissolution of Figure 13C respectively according to an embodiment of the invention; Figure 15 is a graph showing the difference is skewness of the tracer response vs ratio of variance (tracer 2 / tracer 1); Figure 16A is an example tracer response curves for four tracers each injected at a different time during a well treatment stage according to an embodiment of the invention; and; Figure 16B is a graph showing the tracer flowback data compared to flow patter type library data according to an embodiment of the invention. Detailed description of preferred embodiments Well stimulation techniques use mechanical or chemical methods to artificially create channels or flow paths through the formation matrix which may facilitate the flow of fluids from a reservoir to a well. Well stimulation techniques include fracturing, acidizing and fracture acidizing methods. During matrix acidizing of a carbonate formation complex flow patterns called wormholes, form as a result of transport and reaction in the porous media. The wormhole structure depends on parameters such as the acid type, injection rate, and temperature and include face dissolution, conical wormholes, dominant wormholes, ramified wormhole, and uniform dissolution. Figures 1A to 1E shows neutron radiographs and castings 10 from laboratory core flow test demonstrating the five main types of dissolution structures or patterns formed during matrix acidizing in carbonate porous media. Figure 1A is an example of face dissolution where the matrix 12 near the inlet end 14 is dissolved completely and a face dissolution pattern 16 is formed. There is little penetration of the acid into the matrix 12. Figure 1B is an example of conical wormhole 18 where increased acidizing efficiency through the matrix 12 has occurred when compared to face dissolution 16 in Figure 1A, this can be due to increased acid injection rate. Figure 1C is an example of dominant wormhole 20, where the matrix 12 is penetrated in the form of a wormhole which consumes less acid solution volume with high acidizing efficiency. The dominant wormhole structure provides the most efficient depth of penetration into a reservoir. Figure 1D is an example of ramified wormhole 22 where the flow channels in the matrix 12 are more highly branched or ramified when compared to the dominant wormhole 20 in Figure 1C as fluid is forced into smaller pores in the matrix 12. Figure 1E is an example of uniform dissolution 22 where the acid injection rate is high and the porosity of the matrix 12 is dissolved more uniformly where the acid penetrates the pores in the matrix uniformly. The transition in dissolution structures from Figure 1A to Figure 1E is commonly observed as the injection rate is increased and / or the fluid reactivity is decreased (e.g., by decreasing the effective diffusion rate). Figure 2A to 2E are cross-sectional representations showing the depth of penetration for each of the flow channel types / wormhole types (all illustrations for the same volume of acid injected). As can be seen in Figure 2C a dominant wormhole is the optimal acidizing structure as the wormhole provides significant permeability through the formation and requires a minimum pore volume of fluid to break through the matrix. Figure 3 is a cross-sectional representation showing steps of a stimulation treatment stage. Shown at 100 is a wellbore 102 and matrix formation 104 prior to the stimulation treatment with no channels or wormholes in the matrix formation 104. In a first step shown at 110 a first tracer 112 is injected or released into the wellbore injected into the well bore 102. The first tracer 112 enters the near-wellbore matrix 106. The first tracer 112 is in the pore space of the matrix. As shown at 120 a stimulation fluid 114 is introduced into the wellbore 102 after the first tracer 112 and starts to create highly conductive channels 122 in the matrix. The channels extend into the matrix beyond the first tracer plume in the pore space. In this example the stimulation fluid is an acid fluid and the stimulation treatment is an acidizing treatment. In this example the channels created in the matrix 104 are wormhole structures 122. However, it will be appreciated that the stimulation treatment may additionally or alternatively be a fracturing treatment or an acidizing fracturing treatment. It will also be appreciated that the first tracer 112 may alternatively be injected or released at the same time as the stimulation fluid or after the stimulation fluid is injected but before the stimulation fluid has created the channels created in the matrix 104. As shown at 130, a second tracer 116 is introduced as the stimulation treatment stage continues. The injected second tracer 116 enters and travels along the channels 122 in the matrix 104. The channels influence the flow of reservoir fluids because their conductivity is several orders of magnitude higher than the porous matrix 104. The structure and type of the channel can vary significantly with flow conditions, stimulation type, stimulation fluid, matrix properties, injection volume and / or injection rate. The method may comprise calculating, estimating and / or determining at least one spatial or temporal tracer moment for the first tracer in the well before a well treatment and / or in an early portion of a well treatment. The method may comprise calculating, estimating and / or determining at least one spatial or temporal tracer moment for the second tracer introduced into the well at a later time, later step, later stage or later portion of the well treatment or after at least well treatment stage has been completed or approaching completion. By understanding the difference of flow characteristics of the second tracer compared to the first tracer the effectiveness of the stimulation treatment can be assessed and characteristics of the channel type be determined. The tracer concentration flowback profile of the first tracer and second tracer is dependent on the characteristics of the channels 122. Figures 4A to 4E are cross-sectional representations showing five different possible acid stimulation operations and how the tracers migrate through the formation matrix. Figures 5A to 5E are corresponding tracer response curves for the first and second tracers for each of the acid stimulation operations shown in Figures 4A to 4E. In each of the examples shown in Figures 4A to 4E a first tracer (Tracer 1) 212 is injected just prior to the start of acid injection treatment and a second tracer (Tracer 2) 216 is injected near the end of the acid injection treatment. Figures 4A to 4E illustrate how the tracers may distribute within the matrix in the various cases and Figures 5A to 5E represent example tracer response curves (concentration versus time) associated during flowback and production in the well. Analysis may also provide information on the inflow profile in the producer well. Residence Time Distribution (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. Interpretation of tracer data by use of residence time distribution (RTD) analysis may also be used to quantify sweep volume and the magnitude of connections in oil and gas reservoirs. The zero-order temporal moment of the residence time distributions (m0 = f E(t)dt) give the fraction of fluid produced from the well. The first order moment m1 = ft- E(t)dt is closely related to average residence time «t) = In Figure 4A the first tracer 212 is injected under pressure into the wellbore. A high differential pressure between the wellbore 202 and the matrix 204 in order for the fluids to inject into the pore space. The first tracer 212 migrates through the matrix from left to right direction shown as arrow “A”. An acid is injected into the wellbore which reacts with the matrix. The structure formed through the matrix depends on parameters such as the injection rate of the acid, matrix composition, and the reaction kinetics etc. In the example shown in Figure 4A the acid interacts with the matrix to create a face dissolution 213 where the matrix near the inlet end is dissolved completely. A second tracer 216 is injected towards the end of the acidizing operation. A displacement fluid is then injected into the wellbore which pushes the second tracer through the matrix towards the reservoir in the direction of arrow “A”. During flowback of fluid from the reservoir into the wellbore the first tracer 212 and second tracer 216 are carried into the wellbore and measured at a sampling point. The second tracer 216 arrives first as shown in Figure 5A as it is closer to the wellbore. The first tracer has a similar curve shape as the second tracer but is slower to arrive as it was further away from the wellbore. In Figure 4B the first tracer 212 is injected into the wellbore followed by the acid. In the example shown in Figure 4B the acid interacts with the matrix to create a conical wormhole 215. A second tracer 216 is injected towards the end of the acidizing operation. A displacement fluid is then injected into the wellbore 202 which pushes the second tracer 216 through the conical wormhole resulting in a flow bias with a high concentration of the second tracer passing through the conical wormhole structure. The passage of the second tracer through the wormhole displaces and skews the progression pathway of the first tracer through the matrix resulting in the first tracer being pushed aside of the wormhole and forming a substantially conical shape 211 with a vertex 211a pointing toward the reservoir. As shown in Figure 5B, during flowback of produced fluid from the reservoir into the wellbore the first tracer 212 and second tracer 216 are carried into the wellbore and measured at a sampling point. In this example the second tracer 216 arrives first as the flow bias through the conical wormhole transports the second tracer into the wellbore. In contrast the first tracer 212 has diffused over a wider area and the resulting flow back response curve is smaller and slower. In Figure 4C the first tracer 212 is injected into the wellbore followed by the acid. In the example shown in Figure 4C the acid interacts with the matrix 204 to create a dominant wormhole 217. A second tracer is injected towards the end of the acidizing operation. A displacement fluid is then injected into the wellbore which pushes the second tracer 216 through the dominant wormhole resulting in a high concentration of the second tracer passing through the wormhole and is shown positioned along the wormhole structure in Figure 4C. The passage of the second tracer through the wormhole displaces the progression pathway of the first tracer 212 through the matrix 204. The majority of the first tracer 212 is pushed aside of the wormhole and remains at the near borehole wall. Due to the formation of the wormhole through the matrix, the pressure in the wellbore is approximately the same as the pressure at the tip of the wormhole which means there is little pressure acting on the first tracer 212 trapped in the matrix at the near bore wall to progress through the matrix. As shown in Figure 5C, during flowback of produced fluid from the reservoir into the wellbore the first tracer 212 and second tracer 216 are carried into the wellbore and measured at a sampling point. In this example the second tracer 216 arrives first with an initial high concentration as flow passes through the highly conductive dominant wormhole in a direction “B” transporting the second tracer into the wellbore. The response curve for the first tracer is smaller and slower as most of the flow travels through the wormhole bypassing the trapped tracer located at the near wellbore side. In Figure 4D the first tracer 212 is injected into the wellbore followed by the acid. In the example shown in Figure 4D the acid interacts with the matrix to create a ramified wormhole 219. Small pockets of the first tracer 212 become trapped in the network of the ramified wormhole as it forms. A second tracer 216 is injected towards the end of the acidizing operation. A displacement fluid is then injected into the wellbore which pushes the second tracer through the ramified wormhole resulting in some of second tracer trapped in the network of the ramified wormhole. As shown in Figure 5D, during flowback of produced fluid from the reservoir into the wellbore the first tracer 212 and second tracer 216 are carried into the wellbore and measured at a sampling point. In this example the second tracer 216 arrives first with an initial high concentration as flow passes through the ramified wormhole in a direction “B” transporting the second tracer into the wellbore. The response curve for the first tracer has a similar height as the first tracer uses the ramified wormhole to enter the wellbore but is slower as the second tracer was initially closer to the wellbore. As shown in Figure 4E, the first tracer 212 is injected into the wellbore where the tracer migrates through the matrix 204 from left to right direction shown as arrow “A” in Figure 4E. An acid is injected to the wellbore which reacts with the matrix to create a uniform dissolution 221. The acid uniformly enters the pore space all along the wellbore section. A second tracer 216 is injected towards the end of the acidizing operation. A displacement fluid is then injected into the wellbore 202 which pushes the second tracer uniformly through the matrix. During flowback of fluid from the reservoir into the wellbore the first tracer 212 and second tracer 216 are carried into the wellbore and measured at a sampling point. As shown in Figure 5E the second tracer arrives first as it was original closer to the wellbore. The first tracer 212 has a similar curve shape as the second tracer but is slower to arrive as it was further away from the wellbore. By analysing tracer response curves from two or more tracers where a first tracer is injected or released at the start of the stimulation treatment before the flow profiles has been significantly changed by the treatment and a second or further tracer injected or released at a later time, step or stage of stimulation where the treatment has changed the flow profiles, the flow profile and stimulation treatment may be characterized. By characterising the flow profile information, the stimulation may be optimized to improve depth of penetration and conductivity. In an example shown in Figure 6, the tracer response curves of the first tracer (Tracer 1) and second tracer (Tracer 2) are compared and analysed and characteristics of the stimulation operation are determined. As an example from the measured tracer data calculations of the difference in skewness between the tracer 2 and tracer 1 response curves may be plotted versus the difference in area under the curve between the tracer 2 and tracer 1 responses. Figure 6 shows a graph 300 of skewness difference between the second tracer and the first tracer response curves (tracer 2- tracer 1) plotted against the difference of the area under the curve of the second tracer and the first tracer response curves (tracer 2- tracer 1). Figure 6 shows that the optimum stimulation structure, dominant wormhole 320 which has the most efficient depth of penetration and highest conductivity through the matrix is located at the top right quadrant with a high skewness value between the tracer responses and a high tracer curve area difference. In contrast, both the conical wormhole structure 322 and the face dissolution structure 324 have a high skewness value but a low tracer curve area difference. This indicates that a higher injection rate and / or a lower reactive acid composition is required to improve depth of penetration and conductivity. The ramified wormhole structure 326 and uniform dissolution structure 328 both have a negative skewness value and a low tracer curve area difference. This indicates that a reduction in the injection rate and / or an increase in the reactivity of the acid composition is required to improve depth of penetration and conductivity. Additionally, or alternatively a similar approach can be used to characterize other changes in reservoir flow patterns such as those that occur due to injection of surfactants to change wettability, injection of diverting agents to block zones from further injection, injection of polymers to modify sweep profiles during enhanced oil recovery (EOR) or plugging agents for water control. The injection or release of different tracers before and after the induced reservoir change and analysis of the tracer response data would be applied to provide flow profile change type curves. Additionally or alternatively tracer arrival time data may be used, such as the difference in first arrival times for tracer 2 and / or tracer 1 responses to assess and / or optimise a stimulation operation. Figures 7A to 7C show illustrations of etch patterns formed during fracture acidizing in carbonate formations. The type of acid etched pattern affects conductivity of flow. The etch pattern may be influenced by temperature, mineralogy, acid type, and injection rate. During fracture acidizing in carbonate formations, dissolution of the fracture face results in heterogeneous etch patterns that depend on the local variability in flow velocity (e.g., due to local heterogeneity in fracture width that may be caused by local changes in rock mechanical properties, stress, and / or reactivity associated with variability in minerology. The etch pattern can be optimized by controlling and changing the treatment design. The etch pattern can be further impacted by viscous fingering associated with alternating treatment steps or stages of different treatment fluids with different viscosities. The etch patterns on the fracture face 340 can be characterized as near-wellbore dissolution as shown in Figure 7A, this can occur with rapid reactant consumption with no etched channel / pillar structure and results in poor conductivity. Heterogeneous etch pattern as shown in Figure 7B, this can be created by variations in local velocity under mass-transfer limited dissolution. It results in differential etching 350 enhanced by variations in mineralogy and viscous fingering. Large areas of undissolved rock for effective support of closure stresses. Uniform dissolution as illustrated in Figure 7C can occur with slow reactant consumption with no etched channel / pillar structure and results in poor conductivity. The heterogeneous etch channels is the optimum pattern for increasing fracture conductivity and productivity. By injecting a first tracer before, or at an early step or stage of the treatment, and a second tracer towards the end or after the treatment and analysing the tracer flow back data the etch channel type may be identified and characterised. Figures 13A, 13B and 13C are map view representations showing three possible carbonate fracture acidizing operations, near-wellbore dissolution (Figure 13A), Heterogeneous Etch Channels (Figure 13B) and Uniform Dissolution (Figure 13C) and illustrations of how the tracers migrate through the fractures in the formation. Figures 14A, 14B and 14C are corresponding tracer response curves for the first and second tracers for each of the fracture acidizing operations shown in Figures 13A, 13B and 13C respectively. In each of the examples shown in Figures 13A, 13B and 13C, a first tracer (Tracer 1) 812 is injected in the horizontal wellbore at an early pad stage at the start of the fracture acidizing treatment and a second tracer (Tracer 2) 816 is injected near the end of the fracture acidizing treatment. Figures 13A, 13B and 13C illustrate how the tracers may distribute within the fractures in the various cases and Figures 14A.14B and 14C represent example tracer response curves (concentration versus time) associated during flowback and production in the well. From the measured tracer data calculations a graph showing a ratio of skewness between the Tracer 2 and Tracer 1 responses may be plotted versus the ratio of variance between the Tracer 2 and Tracer 1 responses as shown in Figure 15. Figure 15 shows that in this example the optimum treatment type is the etched channel 922 which has the highest conductivity for the etched fracture face. In contrast, near-wellbore dissolution type appears to have an injection rate which is too low and / or reactivity which is too high. The uniform dissolution type appears to have an injection rate which is too high and / or reactivity too low. In hydraulic fracturing with fracturing fluids such as slickwater or polymer the channels which form may be planar fractures 410 having primary fractures 412 shown as Figure 8A, branched fractures 430 having primary fractures 432 and secondary fractures 434 as shown in Figure 8B or complex fracture networks 450 having primary fractures 452, secondary fractures 454 and tertiary fractures 456 as shown in Figure 8C. The type of fracture depends on parameters such as the rock fabric, stress environment, and completion design. Complex fractures generally form in unconventional reservoirs and it is generally believed that more complexity leads to better production performance. However, it is important to note that the optimum pattern depends on the reservoir characteristics. For example, a complex fracture pattern can lead to lower production in some reservoirs, such as when the complex hydraulic fracture propagates through natural fractures that are damaged from scale deposition in the reservoir and thereby do not benefit production. Hence, it is valuable to characterize the fracture complexity in a given reservoir to determine what pattern type is beneficial and enable treatment optimisation. Figures 9A, 9B and 9C are map view representations showing three possible fracturing stimulation operations, planar fractures 610, branched fractures 630 and complex fracture networks 650 and illustrations of how the tracers migrate through the fractures in the formation. Figures 10A, 10B and 10C are corresponding tracer response curves for the first and second tracers for each of the fracturing stimulation operations shown in Figures 9A, 9B and 9C respectively. In each of the examples shown in Figures 9A,9B and 9C, a first tracer (Tracer 1) 612 is injected in the horizontal wellbore 613 at an early pad stage at the start of fracturing treatment and a second tracer (Tracer 2) 616 is injected near the end of the fracturing treatment. Figures 9A, 9B and 9C illustrate how the tracers may distribute within the fractures in the various cases and Figures 10A,10B and 10C represent example tracer response curves (concentration versus time) associated during flowback and production in the well. In Figure 9A the first tracer 612 is injected under pressure into the well. The first tracer 212 migrates a first distance into the formation as shown in Figure 9A. A fracturing fluid is injected to the wellbore under high pressure creating a planar fracture having primary fractures 622 shown in Figure 9A. A second tracer 616 is injected towards the end of the fracturing operation. During flowback of fluid from the reservoir into the wellbore the first tracer 612 and second tracer 616 are carried into the wellbore and measured at a sampling point. As shown in Figure 10A a low concentration of first tracer 612 arrives first as the tracer is closer to the wellbore and slowly migrates into the wellbore. A high concentration of second tracer 616 arrives as shown in Figure 10A as the tracer flows along the primary fracture into the wellbore. In Figure 9B the first tracer 612 is injected under pressure into the well. The first tracer 612 migrates a first distance into the formation as shown in Figure 9B. A fracturing fluid is injected to the wellbore under high pressure creating a branched fracture having primary fractures 632 and secondary fractures 634 shown in Figure 9B. A second tracer 616 is injected towards the end of the fracturing operation. Pockets of second tracer are positioned in primary fractures 632 and secondary fractures 634. During flowback of fluid from the reservoir into the wellbore the first tracer 612 and second tracer 616 are carried into the wellbore and measured at a sampling point. As shown in Figure 10B a low concentration of first tracer 612 arrives first as the tracer is closer to the wellbore and slowly migrates into the wellbore. A high concentration of second tracer 616 arrives as shown in Figure 10B as the tracer flows along the primary fractures 632 and secondary fractures 634 of the branched fracture into the wellbore. The second tracer curve gradually decreases as tracer from branches is released into the wellbore. In Figure 9C the first tracer 612 is injected under pressure into the well. The first tracer 612 migrates a first distance into the formation as shown in Figure 9C. A fracturing fluid is injected to the wellbore under high pressure creating a complex fracture network having primary fractures 652, secondary fractures 654 and tertiary fractures 656. A second tracer 616 is injected towards the end of the fracturing operation. Pockets of second tracer are distributed in network of the complex fracture. During flowback of fluid from the reservoir into the wellbore the first tracer 612 and second tracer 616 are carried into the wellbore and measured at a sampling point. As shown in Figure 10C a low concentration of first tracer 612 arrives first as the tracer is closer to the wellbore and slowly migrates into the wellbore. A high concentration of second tracer 616 arrives as shown in Figure 10C as the tracer flows along the complex fracture into the wellbore. The second tracer curve gradually decreases in step-like curve as tracer from complex network is gradually released into the wellbore. From the measured tracer data calculations a graph 700 showing a ratio of skewness between the Tracer 2 and Tracer 1 responses may be plotted versus the difference in variance between the Tracer 2 and Tracer 1 responses as shown in Figure 11. In this example the plot separates and identifies the fracture characteristics. The planar fracture 710 has a high skewness value and high difference in variance. The branched fracture 712 has a medium difference in variance and low skewness value. The complex fracture 714 has a low difference in variance and low skewness value. As shown by arrow “C” in Figure 11 the fracture network complexity increases towards the bottom-left corner (low difference in variance and low skewness value). Figure 12 shows a flow chart 500 for characterising and optionally optimising a stimulation treatment based on tracer data. In a first step 510 a known amount of a first tracer type is injected into the wellbore at a known period of time. In this example the tracer is injected before the stimulation treatment, it will be appreciated that the first tracer may be injected at the same time or after the stimulation treatment but before the stimulation treatment affects the flow path in the matrix. A stimulation treatment is actuated in step 512, in this example the stimulation treatment is fracturing and a fracturing liquid is pumped into the wellbore. It will be appreciated that other stimulation treatments such as acidizing or acidizing fracturing may be used. In step 514, a second tracer, different to the first tracer is injected into the wellbore at a known period of time after the start of the stimulation treatment. In this example the second tracer is injected towards the end of the fracturing operation. It will be appreciated the second tracer may be injected in the last proppant step of the fracturing operation. Optionally further stimulation stages 516 may be performed as shown in dotted box 518. During or after each further stimulation stages a different first tracer and second tracer may be injected to allow comparisons and assessment of each stimulation stages. Once the stimulation operation (or stage) is completed, production is induced and samples of the produced fluid are collected at step 522 at known times at a known sampling location. At step 524 the samples are analysed. In this example the analysis step includes measuring the type and tracer concentration in the samples. The analysis step may include a tracer residence time distribution analysis, measuring the arrival time of each tracer and the sampling time, calculating an average travel time to the sample location and / or swept volume of the tracer. The analysis may comprise comparing the tracer response for the first tracer with the second and optionally subsequent tracers. The first tracer response may be considered a baseline response before the stimulation treatment affects or changes the flow pattern though the matrix. The first and second tracer response are compared to identify flow path pattern and characterise the stimulation treatment for each of the stages at step 526. The characterised stimulation treatment may be used to optimise future stimulation treatments at step 528. Optionally as shown in dotted box 570, a library of tracer response signatures for each stimulation treatment and the possible range of flow patterns and / or flow channels may be created as shown in step 530. The library may comprise tracer response signatures corresponding to a range of flow path types created as a result of various stimulation treatments such as matrix acidizing, fracture acidizing and / or hydraulic fracturing. The flow path type may include face dissolution, conical wormhole, dominant wormhole, ramified wormhole, uniform dissolution, an etch pattern, a near-wellbore dissolution, heterogeneous etch channel, channels, planar fractures, complex fractures and / or cracks. At step 532 the measured tracer data may be compared with the library of simulation treatment responses to identify and / or characterise the stimulation treatment and flow path pattern. If the measured tracer data does not match a signature in the library, the library may be tuned or iteratively adjusted at step 540 until the modelled tracer data substantially matches the measured tracer data to within a desired target range. At step 536 based on the characterised stimulation treatment and / or flow path pattern the parameters of subsequent stimulation treatment stages or stimulation treatments may be optimised to achieve an optimum stimulation pattern and / or fracture type to improve depth penetration or conductivity. The method may comprise optimising the well stimulation treatment by adjusting one or more parameters selected from the group comprising stimulation fluid type, fluid viscosity, reactivity, acid concentration, additive concentration, injection volume, injection rates, pulsing, proppant concentrations, fluid loss additive concentration and / or diverting agents. Optionally a model of the well and reservoir may be created or updated at step 550 with the stimulation treatment data to facilitate improved knowledge and / or control of production and reservoir performance. The model may be based on data selected from the group comprising: seismic data, geological data, reservoir geometry, core data, log data, rock mechanics, temperature, pressure, gravity, density, viscosity; reservoir permeability, reservoir heterogeneities, solubility, fluid chemistry; porosity, fluid saturation. The model may be updated with reservoir and / or pathways of injected tracer, modelled migration pathways, modelled tracer injection tracer amounts, volumes and injection rates, injection locations, sampling locations, tracer arrival time, residence time distribution, physical behaviour of tracer, stimulation type, stimulation fluid; channel type, wormhole type and / or fracture type. The analysis of tracers in the collected samples may be a separate method to the collection of samples. Samples may be analysed at a time or jurisdiction which is separate and distinct from the sampling location and the collection of the samples. The analysis of measured tracer data may be a separate method to the collection or analysis of the samples. The tracer data may be analysed at a time or jurisdiction which is separate and distinct from the sampling location, collection of the samples and or measurement of tracer concentrations. In the above example the first tracer and the second tracer are injected, it will be appreciated that in other examples the tracers may be released into the wellbore via alternative mechanisms such as a tracer release apparatus. The above examples describe well stimulation treatments including acidizing and fracturing treatments. It will be appreciated that the methods may be used to characterise and optimise other types of well treatment including enhanced oil recovery treatment, and / or water control treatment. Figure 16A is an example tracer response curve for four tracers each injected at a different time during a well treatment stage according to an embodiment of the invention. In the above examples a first tracer and a second tracer are injected at different times before and / or during a treatment stage. However, it will be appreciated that more than two tracers may be injected at each time or at different times before and / or during a treatment stage. It will be appreciated that different tracers may be injected at more than two different times before and / or during a treatment stage. It will also be appreciated that there may be more than one treatment stage and distinct tracers (e.g.at least one first tracer and at least one second tracer) may be injected at different times in each different treatment stage. Figure 16A shows tracer response curves for four distinct tracer pulses injected in one hydraulic fracturing treatment stage pumped in an injection well for enhance geothermal systems (EGS) application. In this example four distinct tracer pulses were injected at different times during a well treatment stage operation. A first tracer (tracer 1 shown as (triangular points in Figure 16A) was injected during the pad injection. The pad injection is fluid that does not contain any propping agent which it injected to create fractures. A second tracer (tracer 2 shown as circular points in Figure 16A) was injected with a proppant concentration (ppa) of 0.5ppa. A third tracer (tracer 3 shown as cross points in Figure 16A) was injected with a proppant concentration (ppa) of 1,25ppa. A fourth tracer (tracer 4 shown as square points in Figure 16A) was injected with a proppant concentration (ppa) of 1.5ppa. The first tracer was pushed the deepest into fractures in the formation. The fourth tracer was pushed the least distance into fractures and located closest to the wellbore. During flowback of fluid from the reservoir into the wellbore the concentration of the four tracers 1 to 4 were measured at a sampling point. Figure 16A shows the tracer response curve for each tracer. Temporal moments and parameters such as mean arrival time (MAT) and third central moments are calculated for each of the four tracer responses. Figure 16B shows the ratio of third central moment for tracer 1 / tracer n versus the ratio of the MAT for tracer n / tracer 1, where n = 2 (tracer 2) shown as black dot 1054, n = 3 (tracer 3) shown as black dot 1052 and n = 4 (tracer 4) shown as black dot 1050. Figure 16B also shows possible flow pattern scenarios based on a theoretical library of flow types for an EGS application which are illustrated by the black squares. These include planar fracture (propped) shown as square 1060, planar with duning shown as square 1062, complex fracture network with duning shown as square 1064 and cluster runaway show as square 1066. Based on the comparison, the tracer interpretation for this treatment stage are consistent with flow through a relatively planar fracture with proppant duning. It will be appreciated that the above example describes one stage of a well treatment. It will be appreciated that a multistage well treatment may be conducted at different locations along the well. An embodiment of the invention may comprise pumping a well treatment such as a well stimulation treatment in a production well with no tracers in the treatment and analysis can be made based on tracers injected from an injection well and monitored in a production well. The first tracer (tracer 1) analysis may be based on residence time distribution measured from tracer response prior to the stimulation treatment and a second tracer (tracer 2) analysis would be based on residence time distribution measured from tracer response after the stimulation treatment, with both based on measurement from the production well that is stimulated. An embodiment of the invention may be used to characterize loss in conductivity that may occur during production from a hydraulic fracture over time. The method may comprise slow release tracer as tracer n (where n is 2 or higher) that is placed out into the fracture network and tracer 1 would be a slow release tracer placed in the near-wellbore region (such as an inflow tracer placed in the completion or a particulate tracer in the near wellbore). The method may comprise exposing both tracers to the same flow rate from the same fracture, the difference in tracer response for tracer n and tracer 1 characterizes the loss in conductivity that occurs over time. The invention may provide methods of characterising and / or optimising a well stimulation treatment. The method may comprise introducing two or more tracers into a well at known times, steps and / or stages of the well stimulation treatment. The method comprises producing fluid in the well from a reservoir, collecting samples of produced fluid and analysing the samples for the presence and / or concentration of the two or more tracers. Based on the presence and / or concentration of tracers in the samples estimating characteristics of the well stimulation treatment. Embodiments of the invention may use tracer data including tracer curves from tracer residence time distribution flow back responses to facilitate the assessment and characterization of the type of flow pattern created in the reservoir as a result of well treatment including matrix acidizing, fracture acidizing, hydraulic fracturing, water control treatment and / or enhanced oil recovery treatments. By injecting two or more tracers in a treatment with at least a first tracer being injected before or at the start of a treatment before the flow profile has been significantly changed by the treatment and a second tracer injected at a later step or stage after the treatment has changed the flow profile, the change in the flow profile can be characterized. Embodiments of the invention may be used to characterize other changes in reservoir flow patterns such as those that occur due to injection of surfactants to change wettability, injection of diverting agents to block zones from further injection, injection of polymers to modify sweep profiles during enhanced oil recovery (EOR), or plugging agents for water control. By injecting different tracers before and after the induced reservoir change and analysing the produced tracer data, changes in a flow profile may be characterized. Throughout the specification, unless the context demands otherwise, the terms 'comprise' or 'include', or variations such as 'comprises' or 'comprising', 'includes' or 'including' will be understood to imply the inclusion of a stated integer or group of integers, but not the exclusion of any other integer or group of integers. Furthermore, relative terms such as “up”, “down”, “top”, “bottom”, “upper”, “lower”, “upward”, “downward”, “horizontal”, “vertical”, “and the like are used herein to indicate directions and locations as they apply to the appended drawings and will not be construed as limiting the invention and features thereof to particular arrangements or orientations. 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 a well treatment, the method comprising:calculating, estimating and / or determining at least one spatial or temporal tracer moment for at least one first tracer in the well before a well treatment and / or in an early portion of a well treatment;calculating, estimating and / or determining at least one spatial or temporal tracer moment for at least one second tracer introduced into the well at a later portion of the well treatment or after a well treatment stage has been completed or approaching completion;comparing the at least one spatial or temporal tracer moment of the at least one first tracer and the at least one second tracer to estimate at least one characteristic of the well treatment.

2. The method according to claim 1 wherein the well treatment is 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.

3. The method according to claim 1 or claim 2 comprising introducing the at least one first tracer into a well before and / or with the well treatment.

4. The method according to any preceding claim comprising introducing at least two tracers at each stage in a multistage operation.

5. The method according to any preceding claim comprising calculating, estimating and / or determining at least one spatial or temporal tracer distribution moment for the at least one first tracer in the well before the well treatment from historical tracer injection and / or production associated with production from the reservoir.

6. The method according to any preceding claim comprising introducing each of the at least one first tracer and the at least one second tracer into the well by injecting the tracers into the well from surface or from a downhole device.

7. The method according to any preceding claim comprising introducing each of the at least one first tracer and the at least one second tracer into the well by releasing tracer from tracer sources installed, arranged or positioned in the well.

8. The method according to any preceding claim comprising introducing each of the at least one first tracer and the at least one second tracer into one injector well or different injector wells.

9. The method according to any preceding claim comprising introducing each of the at least one first tracer and the at least one second tracer into an injector well, a production well or a combination of at least one injector well and production well.

10. The method according to any preceding claim comprising associating a difference or change between the at least one spatial or temporal tracer moment for the at least one first tracer and the at least one second tracer with a characteristic of the well treatment.

11. The method according to any preceding claim comprising associating a ratio between the at least one spatial or temporal tracer moment for the at least one first tracer and the at least one second tracer with a characteristic of the well treatment.

12. The method according to any preceding claim wherein the at least one moment is selected from a zero order moment, a first order moment, a second order moment, and / or a higher order moment.

13. The method according to any preceding claim comprising analysing a measured tracer concentration data set for each of the at least one first tracer and the at least one second tracer wherein the measured tracer concentration data set is tracer concentration as a function of time, tracer concentration as a function of space and / or a residence time distribution.

14. The method according to any preceding claim comprising creating a tracer curve from the measured tracer concentration as a function of time and comparing the tracer curves of the at least one first tracer and the at least one second tracer to assess the well stimulation treatment.

15. The method according to claim 14 comprising calculating an area under the tracer curve to calculate the at least one moment of measured tracer data set and comparing the area under the tracer curve for each of the at least one first tracer and the at least one second tracer.

16. The method according to any preceding claim comprising calculating a swept volume for each of the at least one first tracer and the at least one second tracer and comparing the swept volume of each of the tracers.

17. The method according to any preceding claim comprising calculating a mean arrival time for each of the at least one first tracer and the at least one second tracer and comparing the mean arrival time of each of the tracers.

18. The method according to any preceding claim comprising calculating an arrival time characteristic for each of the at least one first tracer and the at least one second tracer and comparing the arrival time characteristic for the tracers to assess a magnitude of change associated with the well stimulation treatment.

19. The method according to any preceding claim comprising analysing the measured tracer concentration data to characterise and / or identify a flow type pattern selected from the group comprising a face dissolution, conical wormhole, dominant wormhole, ramified wormhole, uniform dissolution, an etch pattern, a near-wellbore dissolution, heterogeneous etch channel, channels, planar fractures, branched fractures, complex fractures and / or cracks, flow around proppant dunes and / or proppant pillars, flow through micro-annulus, and / or flow patterns associated with cluster runaway.

20. The method according to any preceding claim comprising identifying and / or characterising flow patterns by comparing a measured tracer response curve with a library of tracer response curves associated with various flow type patterns.

21. The method according to any preceding claim comprising identifying and / or characterising flow patterns by comparing a measured difference, change, and or ratio between tracer response curves with a library of difference, change, and or ratio between tracer response curves associated with various flow type patterns.

22. The method according to any preceding claim comprising improving production forecasting based on characterising flow patterns after the well treatment.

23. The method according to any preceding claim wherein the tracers are selected from the group comprising water tracers, oil tracers, gas tracers, or tracers deployed as solids such as in a polymer matrix, impregnated proppant, or fluid loss material.

24. The method according to any preceding claim introducing at least one distinctive tracer into a well before and / or with a further well treatment and introducing a different tracer into the well at a later stage or later portion of the well treatment or after at least well treatment stage has been completed or approaching completion and comparing the at least one spatial or temporal moment of the tracers to estimate at least one characteristic of the further well treatment.

25. A method of optimising a well treatment, the method comprising: calculating, estimating and / or determining at least one spatial or temporal moment for at least one first tracer in the well before the well treatment and / or in an early portion of the well treatment;calculating, estimating and / or determining at least one spatial or temporal moment for at least one second tracer introduced into the well at a later portion of the well treatment or after a treatment stage has been completed or approaching completion; comparing the at least one spatial or temporal moment of the at least one first tracer and the at least one second tracer to estimate at least one characteristic of the well treatment;adjusting one or more parameters to optimise the well treatment.

26. The method according to claim 25 comprising 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.

27. The method according to claim 25 or claim 26 comprising optimising the well treatment by adjusting one or more parameters selected from the group comprising well landing point, well trajectory, perforation locations, perforation cluster spacing, stage length, number of perforation clusters per stage, and / or limited entry perforating.

28. The method according to any of claims 25 to 27 comprising characterising changes in reservoir flow patterns and optimising the well treatment by adjusting additionaltreatment and / or changing the treatment design in subsequent stages or subsequent wells.

29. An interpretation method for a well treatment of a well comprising; providing tracer data from a producing well after a well treatment; wherein the tracer data comprises tracer concentration over time of two or more tracers in the production flow;wherein at least one first tracer was introduced into the well before the well treatment and / or in an early portion of the well treatment;wherein at least one second tracer was introduced into the well at a later portion of the well treatment or after a well treatment stage has been completed or approaching completion;analysing the tracer data to compare the at least one spatial or temporal tracer moment of the at least one first tracer and the at least one second tracer to estimate at least one characteristic of the well treatment.

30. A system for characterising and / or optimising a well treatment, the system comprises: two or more tracer sources each with a distinct tracer material;at least one tracer release mechanism configured to release at least one first tracer into the well before the well treatment and / or in an early portion of the well treatment and release at least one second tracer into the well at a later portion of the well treatment or after a well treatment stage has been completed or approaching completion;at least one well stimulation fluid;at least one pump apparatus to pump or inject the at least one well stimulation fluid; and at least one sampling device configured to collect at least one sample of well fluid at a known sampling location.

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