ENHANCED GEOTHERMAL SYSTEMS AND METHODS

Description

This application claims priority to U.S. Provisional Patent Application No. 63/668,746, filed Jul. 8, 2024 and U.S. Provisional Patent Application No. 63/785,922, filed Apr. 9, 2025, the contents of both of which are incorporated herein by reference.

The present invention relates to enhanced geothermal systems and in particular the application of tracers to improve enhanced geothermal systems. Aspects of the invention relate to methods of designing and optimizing enhanced geothermal system.

BACKGROUND TO THE INVENTION

A geothermal reservoir is a naturally occurring area of hydrothermal resources providing heat, water, and rock permeability sufficient to allow energy extraction. These reservoirs are deep underground and are largely undetectable above ground. A geothermal production well is drilled into a known geothermal reservoir and hot geothermal fluids flow through the production well to a power plant for use in generating electricity. An injection well is drilled into the known geothermal reservoir to return used geothermal fluids to the geothermal reservoir. A geothermal reservoir may be in communication with multiple injector and/or production wells.

An enhanced geothermal system (EGS) generates geothermal electricity without natural convective hydrothermal resources. In many areas, subterranean rock is hot but there is not enough natural permeability or fluids present to allow the generation of electricity. An enhanced geothermal system may be used create a human-made reservoir to extract heat for electricity production.

In an enhanced geothermal system, a first well (injection well) is drilled and hydraulic, thermal, or chemical stimulation is conducted deep underground under carefully controlled conditions to create fluid connectivity in initially low-permeability rocks by creating fractures or reopening pre-existing fractures between the first well and a second well. Fluid is pumped in the first well through the fractures in the hot rock heating the fluid which is circulated back to surface via the second well where it is used to generate electricity.

In order to maximise energy output of the enhanced geothermal system it is important to understand the fluid connections between the first well and the second well and the geometry of the fractures.

SUMMARY OF THE INVENTION

It is amongst the aims and objects of the invention to provide a system and method which obviates or mitigates one or more drawbacks or disadvantages of the prior art enhanced geothermal systems.

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 designing an enhanced geothermal system, the method comprising:

• • in a well combination comprising at least one injector well and at least one production well, forming a first stage hydraulic fracture from a first well of the well combination according to a first fracture treatment;
  • forming a second stage hydraulic fracture from the first well according to a second fracture treatment;
  • circulating fluid from the first well to a second well of the well combination via the first and second stage fractures, wherein the circulated fluid carries at least one tracer to the second well;
  • collecting samples of fluid from the second well and analysing tracer concentrations with respect to sampling time;
  • calculating a flow characteristic from the analysis of the tracer concentrations;
  • calculating a fracture circulation efficiency metric from the calculated flow characteristic and at least one fracture geometry parameter;
  • based on the fracture circulation efficiency metric, determining at least one design parameter for the enhanced geothermal system.

The method may comprise injecting a first tracer into the first stage hydraulic fracture. The method may comprise injecting the first tracer into the first stage hydraulic fracture during the formation of the first stage hydraulic fracture. The method may comprise injecting the first tracer into the first stage hydraulic fracture during pumping of the fracturing fluid and/or pumping of the proppant. The method may comprise injecting the first tracer into the first stage hydraulic fracture during the formation of the first stage hydraulic fracture during an injection step after the fracture has been formed. The method may comprise injecting a second tracer into the second stage hydraulic fracture. The method may comprise injecting the second tracer into the second stage hydraulic fracture during the formation of the second stage hydraulic fracture. The method may comprise injecting the second tracer into the second stage hydraulic fracture during pumping of the fracturing fluid and/or pumping of the proppant. The method may comprise injecting the second tracer into the second stage hydraulic fracture during the formation of the second stage hydraulic fracture during an injection step after the fracture has been formed. The method may comprise forming a third or further stage hydraulic fracture from the first well according to a third or further fracture treatment. The method may comprise injecting a third or further tracer into the third or further stage hydraulic fracture. The method May comprise injecting the third or further tracer into the third or further stage hydraulic fracture during the formation of the third or further stage hydraulic fracture. The method May comprise injecting the third or further tracer into the third or further stage hydraulic fracture during pumping of the fracturing fluid and/or pumping of the proppant. The method May comprise injecting the third or further tracer into the second stage hydraulic fracture during the formation of the third or further stage hydraulic fracture during an injection step after the fracture has been formed. The method may comprise forming an nth stage hydraulic fracture from the first well according to a nth fracture treatment. The method may comprise injecting an nth tracer into the nth stage hydraulic fracture. The method may comprise injecting the nth tracer into the nth stage hydraulic fracture during the formation of the nth stage hydraulic fracture. The method may comprise injecting the nth tracer into the nth stage hydraulic fracture during pumping of the fracturing fluid and/or pumping of the proppant. The method may comprise injecting the nth tracer into the nth stage hydraulic fracture during the formation of the nth stage hydraulic fracture during an injection step after the fracture has been formed. The number of stages (n) may be any value such as more than two, more than 5, more than 10, more than twenty, more than fifty or more than 80.

The method may comprise forming one or more fractures from at least one well according to a fracture treatment. The method may comprise forming one or more fractures from more than one well according to a fracture treatment. The method may comprise forming one or more fractures from a first well to a second well. The method may comprise forming one or more fractures from a first well to a second, third and/or further well. The method may comprise forming one or more fractures from more than one injector well. The method may comprise forming one or more fractures from and/or to more than one production well. The method may comprise injecting tracers in fracturing treatments in more than one well. The first and second tracers may be distinct tracers, and therefore the first and second stage hydraulic fractures, may comprise distinct tracers. The at least one tracer may comprise a fracture tracer, which may be associated with a respective one of the first or second stage hydraulic fractures. The tracer injected into a stage hydraulic fracture may be a stage tracer. The method may comprise forming multiple stage hydraulic fractures from a first well of the well combination. The method may comprise injecting a distinct tracer into each stage hydraulic fracture. The method may comprise tracing more than one fracture stage with the same tracer. The method may comprise injecting two or more tracers across two or more fracture stages in the well. The method may comprise injecting two or more tracers into each fracture stage. The method may comprise injecting a distinct tracer combination or tracer ratio into each fracture. The method may comprise circulating at least one circulation tracer from a first well to a second well with the circulated fluid. The method may comprise circulating at least one circulation tracer from at least one injector well to at least one production well with the circulated fluid. The at least one tracer may comprise a circulation tracer. The at least one circulation tracer may be configured to pass through at least one stage hydraulic fracture from the at least one injector well to the at least one production well. The at least one circulation tracer may be configured to pass through two or more stage hydraulic fracture from the at least one injector well to the at least one production well. The at least one circulation tracer may be configured to pass through nth stage hydraulic fracture from the at least one injector well to the at least one production well. The at least one circulation tracer may be configured to pass through multiple stage hydraulic fractures from the at least one injector well to the at least one production well. The at least one circulation tracer may be configured to pass through all of the stage hydraulic fractures from the at least one injector well to the at least one production well.

Preferably, the method comprises injecting at least one tracer into at least one of the first or second stage hydraulic fracture, and comprises circulating a circulation tracer from the first well to the second well with the circulated fluid. Preferably, the method comprises injecting a distinct tracer into each of the first and/or second stage hydraulic fractures, and comprises circulating a distinct circulation tracer from the first well to the second well with the circulated fluid.

The method may comprise multistage fracture treatments comprising three or more hydraulic fracture stages from the first well of the well combination. The method May comprise injecting at least one tracer into each of the multiple stage hydraulic fractures, and may comprise circulating a circulation tracer from at least one injection well to the at least one production well with the circulated fluid. Optionally, the method comprises injecting at least one distinct tracer into each stage hydraulic fracture, and may comprise circulating at least one distinct circulation tracer from the first well to the second well with the circulated fluid.

The method may comprise repeating the circulation test at different flow rates. The method may comprise repeating the circulation test between two wells at different flow rates. The method may comprise repeating the circulation test at different injection rates into the injector well. The method may comprise repeating the circulation test at different production rates from the production well. The method may comprise circulating fluid from the first well to a second well at different flow rates. The method may comprise circulating fluid from the first well to a second well at two or more flow rates. The method May comprise circulating fluid from the first well to a second well at multiple flow rates. At least one distinct circulating tracer may be used for each different flow rate. The method May comprise collecting samples of fluid from the second well during a period of stable flow. The method may comprise measuring surface flow rate. The method may comprise measuring surface pressure. The method may comprise measuring downhole pressure. The method may comprise measuring downhole flow rate. The method may comprise measuring pressure at a stage hydraulic fracture. The method may comprise measuring pressure at each stage hydraulic fracture. The method may comprise calculating the bottom-hole pressure. The method may comprise calculating the bottom-hole pressure from measured surface pressure. The method may comprise calculating the pressure for at least one stage. The method may comprise calculating the pressure for each stage. The method may comprise calculating the pressure at each stage.

By determining at least one design parameter for the enhanced geothermal system from a fracture circulation efficiency metric, the invention may allow learnings from the well combination to be applied to subsequent steps in the formation of the enhanced geothermal system. The enhanced geothermal system may be designed with an improved, and optionally optimized, fracture surface area utilization for heat transfer. It should be appreciated that optimization in the context of this aspect of the invention May be in the context of certain design requirements being fixed or inflexible, such as the total number of fracture stages, the total number of wells, or other design constraints. The at least one design parameter may relate to aspects of well placement or position. The at least one design parameter may include, but is not limited to, one or more of: the number of and placement of further injection and/or production wells; proximity of further injection and/or production wells from existing wells; and/or pattern or distribution of further wells in the geothermal reservoir. For example, if the fracture circulation efficiency is low, then determining the at least one design parameter may include making changes relative to the features of the first and second wells in the well combination, for example increasing the well spacing, increasing the vertical offset, and/or changing a “wine rack” pattern or well spot pattern. The at least one design parameter may relate to aspects of well completion. The at least one design parameter may include, but is not limited to, one or more of: selection of cased hole completion; selection of open-hole completion; and/or selection of well geometry. The at least one design parameter may relate to aspects of well stimulation. The at least one design parameter may include, but is not limited to, one or more of: the number of perforation clusters per stage; fracture geometry; fracture fluid viscosity; proppant type and/or mass; fracture fluid volume; fracture width; hydraulic width; fracture aperture; cross-sectional area of flow; hydraulic cross-sectional area; percentage flow distribution; percentage flow distribution per stage; proppant transport capacity; fracture circulation volume; fracture circulation volume per stage; permeability; permeability per stage; conductivity; conductivity per stage; post-fracture treatments such as fracture plugging and/or acidization; and/or fracture hydraulic conductivity. For example, if the fracture circulation efficiency is low, then determining the at least one design parameter may include making changes relative to the features of the first and second stage hydraulic fractures in the well combination, for example reducing the fracture conductivity. The at least one design parameter may relate to an operational parameter of the enhanced geothermal system. The at least one design parameter may include, but is not limited to, one or more of: the rate of circulation of a circulated heat transfer fluid; circulation fluid type; and/or the viscosity of a circulated heat transfer fluid. Determining the at least one design parameter may include aspects of well placement or position, well completion, well stimulation, and/or operation of the enhanced geothermal system in combination, optionally with other aspects of enhanced geothermal system design. The method may determine at least one design parameter for the enhanced geothermal system that improves at least one fracture circulation efficiency metric. Alternatively, or in addition, the method may comprise optimizing at least one fracture circulation efficiency metric. Alternatively, or in addition, the method may comprise maximizing a fracture surface area efficiency using the fewest number of wells within the hydraulic fracture geometry. Other objective may include maximizing power generation per reservoir unit (e.g., form more wells to effectively circulate the fracture surface area), or maximizing power generation per total well cost (e.g., reduce hydraulic fracture geometry and cost to effectively cover just the area that can be circulated with the desired well plan). The flow characteristic used for calculating a fracture circulation efficiency metric may comprise a flow rate allocation for at least one of the first and second stage fractures. Optionally, the flow characteristic used for calculating a fracture circulation efficiency metric comprises a flow rate allocation for each stage of a multistage fracture. The flow rate allocation may be based on a fracture tracer response interpretation. The flow characteristic used for calculating a fracture circulation efficiency metric may comprise an average fracture circulation volume between the first and second wells. The average fracture circulation volume may be based on a circulation tracer response interpretation. The average fracture circulation volume may be a mean average per fracture stage. The flow characteristic used for calculating a fracture circulation efficiency metric may comprise a fracture circulation volume for at least one of the first and second stage fractures. Optionally, the flow characteristic used for calculating a fracture circulation efficiency metric comprises a fracture circulation volume for each stage of a multistage fracture. The fracture circulation volume may be based on a respective calculated flow rate allocation and average fracture circulation volume. The at least one fracture geometry parameter used for calculating a fracture circulation efficiency metric may comprise a parameter derived from measured data. The at least one fracture geometry parameter may comprise one or more of: stimulated reservoir volume (SRV); fracturing fluid treatment volume; and/or proppant pack porosity volume. The stimulated reservoir volume (SRV) may be determined from microseismic data.

Alternatively, or in addition, the at least one fracture geometry parameter may comprise a parameter estimated, calculated or simulated from fracture geometry information, for example using a hydraulic fracture simulator. The at least one fracture geometry parameter may comprise one or more of: hydraulic fracture surface area and/or propped fracture surface area. The fracture circulation efficiency metric may be calculated for each of the first and second stage hydraulic fractures, or for each stage or a multistage hydraulic fracture treatment. Alternatively, or in addition, the fracture circulation efficiency metric may be calculated on the basis of the total fracture network comprising the first and second (or all) of the multistage fracture treatment. The method may comprise injecting the at least one tracer into a fracture during forming of the one fracture. The method May comprise injecting the at least one tracer into a fracture after the at least one fracture has been formed.

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 first well. The at least one tracer source may be installed, arranged or positioned in the first well. The at least one tracer source may be installed, arranged or positioned in the first and/or second well. The method may comprise introducing the at least one tracer into the well by releasing the tracer from an installed, arranged or positioned tracer source in the well. Each of the at least one tracer may be installed, arranged or positioned as a tracer source in the well in the vicinity of a well stimulation treatment zone. The method may comprise releasing the at least one tracer from the tracer source into the first well. The method may comprise releasing the at least one tracer from the tracer source into the second well. The at least one tracer may be released or injected into the first well via a tracer injection device. The at least one tracer may be released or injected into the second well via a tracer injection device. The tracer injection device may be permanently installed in a well or injection site. The method may comprise pumping the released at least one tracer into the first and/or second stage fracture. At least one fracture tracer may be premixed with a well stimulation treatment fluid and/or injection fluid. The at least one fracture tracer may be co-injected with a well stimulation treatment fluid and/or injection fluid. The at least one fracture tracer may be added to the well stimulation treatment fluid and/or injection fluid. The at least one fracture tracer and the well stimulation treatment fluid and/or injection fluid may be introduced or released into the injection well. The at least one fracture tracer may be co-released with the well stimulation treatment fluid and/or injection fluid.

The method may comprise arranging at least one tracer source with distinct tracer materials in known levels of the at least one injector well. The method may comprise arranging two or more tracer sources with distinct tracer materials in known levels of the at least one injector well. The at least one tracer source may be an interwell tracer. The method may comprise arranging at least one tracer source with distinct tracer materials in known levels of the at least one production well. The method may comprise arranging two or more tracer sources with distinct tracer materials in known levels of the at least one production well. The at least one tracer source may be an inflow tracer.

The at least one tracer may be a chemical tracer. The at least one tracer may be a non-radioactive tracer. The at least one tracer may be injected with or comprise a proppant. The at least one tracer may be configured to release at a known rate from proppant or proppant particles. The at least one tracer may be selected from the group comprising chemical, fluorescent, phosphorescent and radioactive compounds isotope, isotope signature, stable isotope and/or radioactive isotope of elements constituting a part of a tracer molecule. The at least one tracer may comprise stable or radioactive isotopes of elements constituting a part of a tracer molecule. The at least one tracer may be a water tracer. The at least one tracer may be a solid, liquid or gas. The at least one tracer may be applied in solution. The at least one tracer may be in a semi-crystalline or crystalline form. The at least one circulation tracer may be configured to be soluble and/or dissolve in water. The at least one circulation tracer may be a perfluorinated compounds. The at least one tracer may be an organofluorine compound with hydrogen replaced by fluorine. The at least one tracer may be a perfluorocarbon. The at least one tracer may comprise chemical tracers selected from the group comprising perfluorinated hydrocarbons or perfluoroethers. The perfluorinated hydrocarbons may be selected from the group of perfluoro buthane (PB), perfluoro methyl cyclopentane (PMCP), perfluoro methyl cyclohexane (PMCH). The tracer material may comprise polyfunctionalized polyethylene or polypropylene glycols. The tracer material may be an inflow tracer. The at least one tracer may be a nanoparticle. The at least one tracer may be a quantum dot. The at least one tracer may be a naphthalene sulphonic acid. The at least one tracer may comprise at least one cation. The at least one tracer may comprise at least one organic cation and/or at least one inorganic cation. The at least one tracer may comprise two or more cations. The at least one cation may be selected from the group comprising Cs, Rb, K, Li and/or Na. The at least one cation may be an alkaline earth metal cation. The at least one cation may be a cation of Mg, Ca, Sr, Ba and/or mixtures thereof. The at least one cation an alkali metal cation. The at least one cation may be a cation of Li, Na and/or K. The at least one cation may be a cation of ammonium, alkylammonium, pyridine and/or substituted pyridine cations. The at least one cation may be a cation of Pb, Zn and/or Ag. The at least one tracer May comprise at least one anion. The at least one anion may be selected from the group comprising Cl, B, F and/or I. The at least one tracer may comprise at least one organic anion and/or at least one inorganic anion. The at least one tracer may comprise an inorganic anionic metal complex. The metal of said inorganic anionic complex is a metal selected from the groups comprising 4, 5, 6, 7, 9 or 16 of the periodic table. The metal May be selected from the group comprising of Se, Ti, Zr, Hf, V, Nb, Ta, Cr, Mo, W, Mn, Tc, Re, Co, Rh and Ir. The metal may be a group VI or a group VII metal, such as Mo, W or Re. The inorganic anionic metal complex may be a complex of a metal with at least one anionic ligand selected from oxide, hydroxide, halide (e.g. fluoride, chloride, bromide or iodide), thiocyanate, and/or cyanide. The complex may comprise one or more ligands of the same sort, or two or more different ligands. The ligands in the anionic metal complex may be inorganic. The at least one tracer may be a water tracer. The tracer material May be designed to release tracer molecules when exposed to a target fluid i.e. water. The at least one tracer may be stable at a temperature in the range of 100° C. to 500° C. By ‘stable’ is meant the tracer or a tracer carrier is thermally stable and still functional as tracers or as a tracer carrier.

The tracer material and/or tracer source may comprise a tracer and a carrier. The carrier may be a matrix material. The matrix material may be a polymeric material. The tracer may be chemically immobilized within and/or to the carrier. The tracer material may be chemically immobilized and configured to release tracer molecules or particles in the presence of a chemical trigger or specific fluid. The carrier may be a polymer. The tracer may be physically dispersed and/or physically encapsulated in the carrier. The tracer material may release tracer molecules into fluid by dissolution, diffusion and/or degradation of the carrier and/or the tracer into the produced fluid. The carrier may be selected to controllable degrade on contact with the produced fluid into the production well. The carrier may be selected to degrade by hydrolysis of the carrier. The tracer and/or the carrier may be fluid specific such that the tracer molecules will be released from the tracer material as a response to a contact with a target liquid such as the injection fluid or produced fluid. The tracers and/or the carrier may be chemically intelligent such that tracer molecules will be released from the tracer material as a response the exposure of the tracer material to a target fluid. Each of the tracer release device may be configured to release one distinct tracer. Each of the tracer release device may be configured to release two or more distinct tracers. The at least one tracer may be a liquid, solid or gas. The at least one tracer may be a powdered solid.

The method may comprise identifying at least one fracture tracer in the samples. The method may comprise identifying at least one circulation tracer in the samples. The method may comprise obtaining fluid from the second well. The method may comprise collecting samples of the fluid. The sampling may be conducted at one or more sampling times. The sampling may be conducted downhole in a production well. The sampling may be conducted at surface. The sampling may be conducted at a location in a direction towards the surface of the second well. Samples may be collected for later analysis. The collected samples may be analysed onsite or offsite. The method may comprise in-line sampling. The method may comprise detecting the presence and/or concentration of tracer in the sampled fluid. The method may comprise detecting the presence and/or concentration of tracer in the sampled fluid in real time. The method may comprise detecting the presence and/or concentration of tracer in the sampled fluid using an online analyser. The method may comprise measuring a concentration of at least one tracer in the sampled fluid. The method may comprise measuring a concentration of at least one tracer in the sampled fluid in real time. The method may comprise measuring a concentration of at least one tracer in the sampled fluid using an online analyser. The sample collection may be an automated process.

The method may comprise storing collected samples in a storage device. The method May comprise storing collected samples in a storage device for export to a laboratory and/or later analysis. The samples may be stored by adsorbing them to a chemical adsorption tube (CAT). The method may comprise collecting the at least one sample in at least one sample container or sampling tube. The method may comprise collecting the at least one sample in a sample container such as PVT sample canisters or isotubes. The method May comprise collecting the at least one sample in at least one sampling tube comprising a sorbent material. The sorbent material may be configured to adsorb the at least one tracer. The sorbent material may be configured to adsorb tracer from the two or more tracer sources. The sorbent material may be configured to adsorb at least one interwell tracer. The sorbent material may be configured to adsorb at least one inflow tracer. The method may comprise extracting the at least one tracer from the sample to the sorbent material.

The method may comprise storing and/or transporting the sorbent material. The method may comprise storing and/or transporting the sorbent material for later analysis.

The method may comprise determining the type of tracer or tracers in the sample. The method may comprise measuring and/or monitoring the concentration of tracer. The method may comprise the measuring and/or monitoring the transport time of the at least one tracer. The method may comprise the measuring and/or monitoring the transport time of the at least one tracer from injection to detection in the produced fluid. The at least one tracer may be detected and/or measured using techniques selected from the group comprising optical detection, optical fibers, spectrophotometric methods, spectrometric methods, fluorescence, chromatographic methods, HPLC (high performance liquid chromatography), MS (mass spectrometry) inductively coupled plasma mass spectrometry (ICP-MS), mass spectroscopy (MS) or multidimensional MS and/or radioactivity analysis.

The method may comprise injecting and/or releasing at least one tracer in two or more injection wells. The method may comprise injecting or releasing at least one tracer in two or more injection wells. The method may comprise analysing the arrival of tracer concentration of each tracer in the second well. The method may comprise analysing the rate of decline of the tracer concentration in the second well to determine fracture flow characteristics, flow rates and/or flow paths. The method may include calculating at least one flow characteristic and/or at least one fracture characteristic by quantifying a proportion of flow from each stage in the offset producer(s). The method may include calculating at least one flow characteristic and/or at least one fracture characteristic by quantifying a proportion of flow from each stage in the offset producer(s) by performing a dilution calculation. The method may comprise calculating a mathematical derivative of a tracer response curve. The calculated derivative can be characterized by means of Residence Time Distribution (RTD) analysis. The RTD analysis may include assisted history matching to calculate the flow characteristics and/or fracture characteristics. The method may include calculating at least one flow characteristic and/or at least one fracture characteristic selected from the group comprising perforation clusters per stage; fracture geometry; fracture fluid volume; fracture width; hydraulic width; fracture aperture; cross-sectional area of flow; hydraulic cross-sectional area; percentage flow distribution; percentage flow distribution per stage; proppant transport capacity; fracture circulation volume; fracture circulation volume per stage; permeability; permeability per stage; conductivity; conductivity per stage and/or fracture hydraulic conductivity.

According to a second aspect of the invention, there is provided a method of characterising at least one fracture in an enhanced geothermal system comprising at least one well combination of an injector well and a production well, the method comprising:

• • forming a first stage hydraulic fracture from a first well of the well combination according to a first fracture treatment design;
  • injecting a first tracer into the first stage hydraulic fracture;
  • forming a second stage hydraulic fracture from the first well according to a second fracture treatment design;
  • injecting a second tracer into the second stage hydraulic fracture;
  • circulating fluid from the first well to a second well of well combination via the first and second stage fractures;
  • collecting samples of fluid from the second well and analysing tracer concentrations with respect to sampling time;
  • calculating a flow characteristic for each of the first stage and second stage fractures from the analysis of the tracer concentrations.

The method may comprise, for each of the first stage and second stage fractures, calculating a respective fracture circulation efficiency from the calculated flow characteristic and at least one fracture geometry parameter. The method may comprise associating the first and/or second fracture treatment design with a respective calculated fracture circulation efficiency. The method may comprise circulating at least one distinct circulation tracer from the first well to the second well with the circulated fluid. The method may comprise circulating fluid from the first well to a second well at different flow rates. The method may comprise circulating fluid from the first well to a second well at two or more flow rates. The method may comprise circulating fluid from the first well to a second well at multiple flow rates. At least one distinct circulating tracer may be used for each different flow rate. The method may comprise collecting samples of fluid from the second well during a period of stable flow. The method may comprise measuring surface flow rate. The method may comprise measuring surface pressure. The method may comprise measuring downhole pressure. The method may comprise measuring surface pressure. The method may comprise measuring pressure at a stage hydraulic fracture. The method may comprise measuring pressure at each stage hydraulic fracture. The method may include calculating at least one fracture characteristic selected from the group comprising hydraulic width; fracture aperture; hydraulic cross-sectional area; cross-sectional area of flow; percentage flow distribution; percentage flow distribution per stage; proppant transport capacity; fracture circulation volume; fracture circulation volume per stage; permeability; permeability per stage; conductivity; conductivity per stage and/or fracture hydraulic conductivity.

The method may comprise forming a third or further stage hydraulic fracture from the first well according to a third or further fracture treatment. The method may comprise injecting a third or further tracer into the third or further stage hydraulic fracture. The method may comprise injecting the third or further tracer into the third or further stage hydraulic fracture during the formation of the third or further stage hydraulic fracture. The method May comprise injecting the third or further tracer into the third or further stage hydraulic fracture during pumping of the fracturing fluid and/or pumping of the proppant. The method May comprise injecting the third or further tracer into the second stage hydraulic fracture during the formation of the third or further stage hydraulic fracture during an injection step after the fracture has been formed. The method may comprise forming one or more fractures from at least one well according to a fracture treatment. The method may comprise forming one or more fractures from more than one well according to a fracture treatment. The method may comprise forming one or more fractures from more than one injector well. The method may comprise forming one or more fractures from more than one production well. The method may comprise injecting tracers in fracturing treatments in more than one well.

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

According to a third aspect of the invention, there is provided a method of characterising a fracture in an enhanced geothermal system comprising at least one well combination of an injector well and a production well, the method comprising:

• • forming a first stage hydraulic fracture from a first well of the well combination according to a first fracture treatment design;
  • injecting at least one first tracer into the first stage hydraulic fracture;
  • forming a second stage hydraulic fracture from the first well according to a second fracture treatment design;
  • injecting at least one second tracer into the second stage hydraulic fracture;
  • circulating fluid from the first well to a second well of well combination via the first and second stage fractures;
  • collecting samples of fluid from the second well and analysing tracer concentrations with respect to sampling time;
  • calculating at least one fracture characteristic from the analysis of the tracer concentrations.

The method may comprise forming a third or further stage hydraulic fracture from the first well according to a third or further fracture treatment. The method may comprise injecting a third or further tracer into the third or further stage hydraulic fracture. The method may comprise injecting the third or further tracer into the third or further stage hydraulic fracture during the formation of the third or further stage hydraulic fracture. The method May comprise injecting the third or further tracer into the third or further stage hydraulic fracture during pumping of the fracturing fluid and/or pumping of the proppant. The method May comprise injecting the third or further tracer into the second stage hydraulic fracture during the formation of the third or further stage hydraulic fracture during an injection step after the fracture has been formed. The method may comprise forming one or more fractures from at least one well according to a fracture treatment. The method may comprise forming one or more fractures from more than one well according to a fracture treatment. The method may comprise forming one or more fractures from more than one injector well. The method may comprise forming one or more fractures from more than one production well. The method may comprise injecting tracers in fracturing treatments in more than one well.

The method may comprise, for each stage, calculating a respective fracture circulation efficiency from the calculated flow characteristic and at least one fracture geometry parameter. The method may comprise associating a fracture treatment design with a respective calculated fracture circulation efficiency. The method may comprise circulating at least one distinct circulation tracer from the at least first well to the at least second well with the circulated fluid. The first well may comprise two or more injector wells. The second well may comprise two or more production wells. The method may comprise circulating fluid from the at least first well to the at least second well at different flow rates. The method may comprise circulating fluid from the at least first well to the at least second well at two or more flow rates. The method may comprise circulating fluid from the at least first well to the at least second well at multiple flow rates. At least one distinct circulating tracer may be used for each different flow rate. The method may comprise collecting samples of fluid from the second well during a period of stable flow. The method may comprise measuring surface flow rate. The method may comprise measuring surface pressure. The method may comprise measuring downhole pressure. The method may comprise measuring surface pressure. The method may comprise measuring pressure at a stage hydraulic fracture. The method may comprise measuring pressure at each stage hydraulic fracture. The method may comprise calculating bottom-hole pressure from measured surface pressure. The method may comprise calculating pressure for each stage. The at least one fracture characteristic may be selected from the group comprising perforation clusters per stage; fracture geometry; fracture fluid volume; fracture width; hydraulic width; fracture aperture; cross-sectional area of flow; hydraulic cross-sectional area; percentage flow distribution; percentage flow distribution per stage; proppant transport capacity; fracture circulation volume; fracture circulation volume per stage; permeability; permeability per stage; conductivity; conductivity per stage and/or fracture hydraulic conductivity.

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

According to a fourth aspect of the invention, there is provided a method of collecting samples for analysis in a method of designing an enhanced geothermal system, wherein the system comprises a well combination comprising at least one injector well and at least one production well;

• • the method comprising circulating fluid from the at least one injector well to the at least one production well of the well combination via first and second stage fractures, wherein the circulated fluid carries at least one tracer to the at least one production well;
  • collecting samples from the at least one production well.

Preferably the samples are collected at known sampling times.

Embodiments of the fourth aspect of the invention may include one or more features 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 collecting samples for analysis in a method of characterising a fracture in an enhanced geothermal system, wherein the system comprises a well combination comprising at least one injector well and at least one production well;

• • the method comprising circulating fluid from the at least one injector well to the at least one production well of the well combination via first and second stage fractures, wherein the circulated fluid carries at least one tracer to the at least one production well;
  • collecting samples from the at least one production well.

Preferably the samples are collected at known sampling times.

Embodiments of the fifth aspect of the invention may include one or more features 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 an interpretation method for designing an enhanced geothermal system, the method comprising:

• • providing tracer data, the tracer data previously obtained by analysis of samples of fluid collected from a production well in a well combination comprising at least one injector well and at least one production well, and having a first stage hydraulic fracture from a first well of the well combination according to a first fracture treatment; and a second stage hydraulic fracture from the first well according to a second fracture treatment, wherein fluid has been circulated fluid from the injection well to the production well of the well combination via the first and second stage fractures, and wherein the circulated fluid carries at least one tracer to the second well;
  • calculating a flow characteristic from tracer data;
  • calculating a fracture circulation efficiency metric from the calculated flow characteristic and at least one fracture geometry parameter;
  • based on the fracture circulation efficiency metric, determining at least one design parameter for the enhanced geothermal system.

Embodiments of the sixth aspect of the invention may include one or more features 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 an interpretation method of characterising at least one fracture in an enhanced geothermal system, the method comprising: providing tracer data, the tracer data previously obtained by analysis of samples of fluid collected from a production well in a well combination comprising at least one injector well and at least one production well, and having a first stage hydraulic fracture from a first well of the well combination according to a first fracture treatment; and a second stage hydraulic fracture from the first well according to a second fracture treatment, wherein fluid has been circulated fluid from the injection well to the production well of the well combination via the first and second stage fractures, and wherein the circulated fluid carries at least one tracer to the second well;

• • calculating a flow characteristic from tracer data.

The well may comprise a third or further hydraulic fracture from a first well of the well combination according to a third or further fracture treatment, wherein fluid has been circulated fluid from the injection well to the at least one production well of the well combination via the first, second and third or further stage fractures, and wherein the circulated fluid carries at least one tracer to the at least one production well. The well combination may comprise one or more fractures from at least injector well to at least one production well. The well combination may comprise one or more fractures from more than one injector well. The well combination may comprise two or more fractures from more than one injector well. The well combination may comprise one or more fractures from and/or to more than one production well.

Embodiments of the seventh aspect of the invention may include one or more features 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 an interpretation method of characterising at least one fracture in an enhanced geothermal system, the method comprising: providing tracer data, the tracer data previously obtained by analysis of samples of fluid collected from a production well in a well combination comprising at least one injector well and at least one production well, and having a first stage hydraulic fracture from a first well of the well combination according to a first fracture treatment; and a second stage hydraulic fracture from the first well according to a second fracture treatment, wherein fluid has been circulated fluid from the injection well to the production well of the well combination via the first and second stage fractures, and wherein the circulated fluid carries at least one tracer to the second well;

• • calculating at least one characteristic from tracer data.

The at least one fracture characteristic may be selected from the group comprising perforation cluster per stage; fracture geometry; fracture fluid volume; fracture width; hydraulic width; fracture aperture; hydraulic cross-sectional area; cross-sectional area of flow; percentage flow distribution; percentage flow distribution per stage; proppant transport capacity; fracture circulation volume; fracture circulation volume per stage; permeability; permeability per stage; conductivity; conductivity per stage and/or fracture hydraulic conductivity. The well combination may comprise three or more stage hydraulic fractures. The well combination may comprise multiple stage hydraulic fractures.

Embodiments of the eighth aspect of the invention may include one or more features of the first to seventh aspects of the invention or their embodiments, or vice versa.

According to a ninth aspect of the invention there is provided a system for designing an enhanced geothermal system comprising:

• • a well combination comprising at least one injector well and at least one production well,
  • a first stage hydraulic fracture from a first well of the well combination formed according to a first fracture treatment;
  • a second stage hydraulic fracture from the first well formed according to a second fracture treatment;
  • at least one tracer configured to be carried by a circulated fluid to the second well;
  • and a collection device configure to collect samples of fluid produced in the production well.

The collection device may be configured to collect samples at known sampling times. The two or more tracer sources with distinct tracer materials may be inflow tracers. The injected at least one tracer may be an interwell tracer. The system may comprise a tracer release device configured to release the at least one tracer into the injection well. The system may comprise a tracer release device configured to release the at least one tracer into the at least one fracture. The system may comprise at least one tracer analyser device configured to detect and/or measure the concentration of the at least one tracer in fluid produced from the geothermal system. The system may comprise at least one tracer analyser device configured to detect and/or measure the concentration of the two or more tracer materials in fluid produced in the production well. The system may comprise at least one tracer analyser device configured to detect and/or measure the concentration of the two or more inflow tracers in the fluids in the production well. The system may comprise at least one probe. The at least one probe may be configured to detect the concentration of the at least one tracer in fluid produced from the geothermal system. The at least one probe may be a sample collection probe, a detector probe and/or a real time detector probe. The system may comprise a tracer analyser for analysing presence, type and/or concentration of the at least one tracer. The system may comprise a processor. The process may be a computer-implemented processor. The processor may be configured to compare a tracer type and/or concentration of measured in the production well with a tracer type and/or concentration of at least one injected interwell tracer in the injection well. The processor may be configured to compare a tracer type and/or concentration of measured in the production well with at least one inflow tracer arranged in the production well. The processor may be configured to calculate and/or monitor a characteristic of the at least one fracture based on the presence and/or concentration of tracer in the samples.

Embodiments of the ninth aspect of the invention may include one or more features 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 system for characterising at least one fracture in an enhanced geothermal system comprising:

• • a well combination comprising at least one injector well and at least one production well, a first stage hydraulic fracture from a first well of the well combination formed according to a first fracture treatment;
  • a second stage hydraulic fracture from the first well formed according to a second fracture treatment;
  • at least one tracer configured to be carried by a circulated fluid to the second well;
  • and a collection device configured to collect samples of fluid produced in the production well.

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

According to an eleventh aspect of the invention, there is provided a method of forming an enhanced geothermal system according to a design parameter determined from a previous aspect of the invention.

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

According to a twelfth aspect of the invention, there is provided a method of operating an enhanced geothermal system according to a design parameter determined from a previous aspect of the invention.

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

According to a thirteenth aspect of the invention, there is provided a method of modelling a parameter of a hydraulic fracture treatment in an enhanced geothermal system, the method comprising:

• • calculating a fracture flow characteristic using a method according to the second or third aspects of the invention;
  • calculating a fracture geometry parameter for the hydraulic fracture treatment from the calculated flow characteristic.

The method may comprise calculating a fracture geometry parameter for the hydraulic fracture treatment from the calculated flow characteristic and a fracture circulation efficiency associated with the hydraulic fracture treatment.

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

According to a fourteenth aspect of the invention, there is provided a method of characterising at least one fracture in an enhanced geothermal system comprising at least one well combination of at least one injector well and at least one production well, the method comprising:

• • forming at least one stage fracture from at least one well of the well combination according to a fracture treatment design;
  • injecting at least one tracer into the at least one stage fracture;
  • circulating fluid from at least a first well to at least a second well of well combination via the at least one stage fracture; wherein the circulated fluid carries at least one circulation tracer;
  • collecting samples of fluid from at least one well and analysing tracer concentrations with respect to sampling time;
  • calculating at least one fracture characteristic from the analysis of the tracer concentrations.

The method may comprise forming two or more stage fractures from at least one well of the well combination; injecting at least one distinct tracer into each stage fracture and circulating fluid through each stage fracture. The method may comprise forming multiple stage fractures from at least one well of the well combination; injecting at least one distinct tracer into each stage fracture and circulating fluid through each stage fracture. The method may comprise forming at least one fracture from at least one injector well. The method may comprise forming at least one fracture from at least one production well. The method may comprise injecting the at least one tracer into a stage fracture during the formation of the fracture. The method may comprise forming at least one stage fracture from two or more wells of the well combination. The method may comprise forming at least one stage fracture between two or more wells of the well combination. The method may comprise injecting a first fracture tracer into a first stage hydraulic fracture, injecting a second fracture tracer into a second stage hydraulic fracture, and injecting a third or further fracture tracer into a third or further stage hydraulic fracture. The method May comprise, for each fracture, calculating a respective fracture circulation efficiency from a calculated flow characteristic and at least one fracture geometry parameter. The method may comprise injecting at least one stage tracer in fracturing treatments in more than one well. The method may comprise circulating fluid from at least the first well to at least the second well at two or more flow rates. The method may comprise collecting samples of fluid from the at least first and/or second well during a period of stable flow. The at least one tracer comprises two or more tracers in a distinct combination or ratio. The method may comprise measuring surface flow rate, measuring surface pressure, measuring downhole pressure, measuring pressure at a stage hydraulic fracture, calculating downhole pressure for each stage fracture and/or measuring pressure at each stage hydraulic fracture. The at least one fracture characteristic may be selected from the group comprising fracture geometry; fracture width; hydraulic width; fracture aperture; cross-sectional area of flow; hydraulic cross-sectional area; percentage flow distribution; percentage flow distribution per stage; proppant transport capacity; fracture circulation volume; fracture circulation volume per stage; permeability; permeability per stage; hydraulic fracture conductivity; and/or hydraulic fracture conductivity per stage. The method may comprise designing an enhanced geothermal system comprising calculating a fracture circulation efficiency metric from a calculated flow characteristic and at least one fracture geometry parameter;

• • based on the fracture circulation efficiency metric, determining at least one design parameter for the enhanced geothermal system. The at least one design parameter may be selected from the group comprising the number of and placement of further injection and/or production wells; proximity of further injection and/or production wells from existing wells; pattern or distribution of further wells in the geothermal reservoir, selection of cased hole completion; selection of open-hole completion; selection of well geometry; perforation clusters per stage; fracture geometry; fracture fluid viscosity; proppant type and/or mass; fracture fluid volume; fracture width; hydraulic width; fracture aperture; cross-sectional area of flow; hydraulic cross-sectional area; percentage flow distribution; percentage flow distribution per stage; proppant transport capacity; fracture circulation volume; fracture circulation volume per stage; permeability; permeability per stage; conductivity; conductivity per stage; post-fracture treatments such as fracture plugging and/or acidization; fracture hydraulic conductivity, the rate of circulation of a circulated heat transfer fluid; circulation fluid type and/or the viscosity of a circulated heat transfer fluid. The flow characteristic used for calculating a fracture circulation efficiency metric may be selected from the group comprising a flow rate allocation for at least one of the stage fractures, a flow rate allocation for each stage of a multistage fracture, an average fracture circulation volume between the first and second wells, a fracture circulation volume for at least one of the stage fractures and/or a fracture circulation volume for each stage of a multistage fracture. The at least one fracture geometry parameter may be selected from the group comprising a parameter derived from measured data, stimulated reservoir volume (SRV); fracturing fluid treatment volume; and/or proppant pack porosity volume; hydraulic fracture surface area and/or propped fracture surface area. The method May comprise injecting the at least one fracture tracer into at least one fracture and/or circulating the at least one circulation tracer from a tracer source installed, arranged or positioned in the first well. The method may comprise analysing the arrival of tracer concentration in the second well. The method may comprise measuring and/or monitoring arrival time of each tracer in the second well. The method may comprise calculating a mathematical derivative of a tracer response curve. The calculated derivative may be characterized by means of Residence Time Distribution (RTD) analysis. The RTD analysis may include assisted history matching to calculate at least one fracture characteristic. The well combination may comprise multiple stage hydraulic fractures and at least one distinct fracture tracer may be associated with each stage hydraulic fracture.

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

According to a fifteenth aspect of the invention, there is provided an interpretation method of characterising at least one fracture in an enhanced geothermal system, the method comprising:

• • providing tracer data, the tracer data previously obtained by analysis of samples of fluid collected from at least one well in a well combination comprising at least one injector well and at least one production well, at least one hydraulic fracture from least one well in the well combination according to a fracture treatment, wherein each fracture has at least one distinct tracer in the fracture;
  • wherein fluid has been circulated fluid from at least one well to at least a second well of the well combination via the at least one fracture, and wherein the circulated fluid carries at least one circulation tracer to at least the second well;
  • calculating at least one characteristic from the tracer data.

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

According to a sixteenth aspect of the invention, there is provided a method of designing an enhanced geothermal system, the method comprising:

• • in a well combination comprising at least one injector well and at least one production well, forming at least one stage fracture from at least one well of the well combination according to a fracture treatment design;
  • injecting at least one tracer into the at least one stage fracture;
  • circulating fluid from the at least one well to at least a second well of well combination via the at least one fracture; wherein the circulated fluid carries at least one circulation tracer;
  • collecting samples of fluid from the at least one well and analysing tracer concentrations with respect to sampling time;
  • calculating a flow characteristic from the analysis of the tracer concentrations;
  • calculating a fracture circulation efficiency metric from the calculated flow characteristic and at least one fracture geometry parameter;
  • based on the fracture circulation efficiency metric, determining at least one design parameter for the enhanced geothermal system.

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

BRIEF DESCRIPTION OF THE DRAWINGS

There will now be described, by way of example only, various embodiments of the invention with reference to the drawings, of which:

FIG. 1 is a schematic map view of an enhanced geothermal system in accordance with an embodiment of the invention;

FIG. 2 is a schematic end view of the system of FIG. 1 depicting parameters calculated according to embodiments of the invention;

FIG. 3 is a schematic end view of an enhanced geothermal system designed according to embodiments of the invention;

FIG. 4 is a flow chart showing steps for designing an enhanced geothermal system in accordance with an embodiment of the invention;

FIG. 5 is a schematic map view of an enhanced geothermal system in accordance with an alternative embodiment of the invention;

FIG. 6 is a plot of tracer produced concentration versus volume swept, for the system represented in FIG. 5;

FIGS. 7a to 7d are an illustration of the sequence used to obtain fluid samples with tracer concentrations that provide inflow contribution from individually monitored fracture zones;

FIG. 8a is an illustration of injection of tracers in two injection wells and a production well in an enhanced geothermal system;

FIG. 8b illustrates typical tracer response from one of the circulation tracers;

FIG. 9 is a visualization of the zero and first order moments of a Residence Time Distribution;

FIG. 10 is a schematic map view of an enhanced geothermal system with eight fracture stages in accordance with an embodiment of the invention;

FIG. 11 is a graph showing percentage flow contribution data for eight fracture stages based on chemical tracer concentrations;

FIG. 12 is a graph showing example tracer data for distinct tracers in each of fracture stages 3R to 10 and a circulation tracer;

FIG. 13 is graph showing average flow rate per cluster vs calculated bottom hole pressure drop between wells for each of the eight fracture stages;

FIG. 14 is a graph showing the relative proppant transport capacity (normalized by value for fracture stage 4) measured based on FIG. 13 for different fracturing fluids in different fracture stages;

FIG. 15A is a graph showing fracture circulation volume per stage or cluster;

FIG. 15B is a graph showing Residence Time Distribution curve for two different circulation tracers taken from two different times during circulation tests;

FIG. 16 is graph showing the calculated hydraulic cross-sectional area of flow (biWi) for each of the fracture stages based on RTD analysis; the graph also provides a comparison calculated hydraulic cross-sectional area of flow (biWi) obtained from a combination of chemical and nano particles tracer data;

FIG. 17 is graph showing Permeability (ki) for each of the eight fracture stages;

FIG. 18 shows a graph of sensitivity range for fracture aperture for each fracture stage;

FIG. 19 shows a graph of sensitivity range for fracture conductivity for each fracture stage for three different aperture sizes; and

FIG. 20 shows a graph of calculated economic lifetime for each fracture stage.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

FIG. 1 is a simplified representation of an enhanced geothermal system (EGS) shown generally as 1. The geothermal system has an injection well 20 and a production well 30. A series of hydraulic fracture treatments are carried out in the injection well with the aim of establishing a fluid connection between the injection well and the production well through the geothermal reservoir 10. In this example hydraulic fracturing is carried out at three fracture initiation sites of the injection well 101, 102, 103 in a multistage hydraulic fracture process. During the first stage, fracturing fluid is pumped from the surface through the wellbore and through perforations at site 101. The pumped fluid causes stresses in the rock formation, and as the fluid pressure and pumping rate exceed the critical stresses, fractures 111 form and propagate through the surrounding rocks. Further pumping leads to deeper fracture propagation. The fracturing fluid may comprise proppant material which fill the developing fractures preventing fractures closure and improve the conductivity through the fracture. During the second stage, site 102 is isolated from position 101, for example by a wellbore plug or packer, and fracturing fluid is pumped from the surface through the wellbore and through perforations at site 102 to form fractures 112. The process is repeated for site 103 to form fractures 113, and the fracture site isolation tools are removed. In this example, the resulting fractures 111, 112, 113 have different profiles, which may be due to the natural rock formation, differing fracture treatments or perforation design, or a combination.

While the system of FIG. 1 is a simple, functional, enhanced geothermal system comprising a single injection well and a single production well, it is also representative of a that may be the first injection and production well combination of a larger, more sophisticated enhanced geothermal system comprising multiple injection wells and/or multiple production wells arranged throughout the geothermal reservoir. In the present invention, such a well combination is used in a process for designing subsequent steps of the enhanced geothermal system, for example by determining the position of further wells and/or fracture treatment processes according to design objectives. In accordance with the invention, tracers (not shown) introduced into the system, and subsequent circulation of a fluid between the injector well 20 and the producer well 30 will cause the tracers to flow with the circulated fluid to the producer well. Samples collected from the producer well can be analysed for tracer concentrations to provide one or more flow characteristics associated with the fracture.

In a preferred embodiment of the invention, distinct tracers (not shown) are injected into each respective fracture 111, 112, 113. Injection of the tracers may occur during pumping of the fracturing fluid or proppant, or as a subsequent injection step after the fracture has been formed (desirably before the respective isolation tools between fracture initiation sites have been removed). In this embodiment, distinct tracers are injected as mass balance tracers at a constant concentration throughout each fracture stage. Subsequent circulation of fluid between the injector well 20 and the producer well 30 during a circulation test will cause the fracture tracers to flow with the circulated fluid to the 11 producer well. Samples collected from the producer well can be analysed for tracer concentrations to calculate a flow rate allocation associated with each fracture 111, 112, 113, as will be described in more detail below. A distinct circulation tracer is also injected with the circulation fluid during at least an early part of the circulation test. Typically, the circulation tracer is injected at constant rate during the first approximately 3000 bbls (about 477,000 litres) of circulation fluid. The circulation tracer will flow with the circulated fluid to the producer well. Samples collected from the producer well can be analysed for tracer concentrations to calculate the total circulated volume, and the average fracture circulated volume, as will be described in more detail below. The fracture circulated volume for each fracture stage can optionally be calculated from the flow rate allocation and the average fracture circulated volume. In other examples fluid may be circulated and/or injected at two or more different rates. A distinct circulation tracer may be injected at each different rate. Samples may be collected during a period of stable flow. In another example, a combination of chemical tracers, nano particle tracers, and a known flow distance (such as the distance between wells) may optionally be calculated for each stage. The methodology of the invention uses the one or more flow characteristics calculated from the tracer responses to calculate at least one fracture characteristic and/or fracture circulation efficiency metric.

Referring now to FIG. 2, there is shown schematically an end view of the enhanced geothermal system 1. The injection well 20 and the production well 30 are formed in the reservoir 10, and the fractures (not shown) are formed between the wells. Also shown in FIG. 2 are cross sectional areas representing fracture geometry parameters associated with the well combination and fracture network. Area 40 represents stimulated reservoir volume (SRV) determined from microseismic data. Area 50 represents hydraulic fracture geometry, which may be for example hydraulic fracture surface area, which is calculated or simulated from fracture geometry information using a hydraulic fracture simulator. Area 60 represents propped fracture area, which is also calculated or simulated from fracture geometry information using a hydraulic fracture simulator. A hydraulic fracture simulator is a computer program that is also referred to as a fracture model, fracture simulator, or fracture placement model is commonly used by those skilled in the art to design fracturing treatments and predict fracturing treatment results. Commercial fracture simulators are readily available. One such fracture simulator is ResFrac (https://www.resfrac.com/), which is a fully coupled fracture and reservoir simulator. Fracture simulators use inputs regarding treatment conditions such as pump rate, fluid viscosity, fluid volume, and proppant mass, combined with reservoir parameters such as stress profile, matrix 12 permeability, and natural fracture profiles. The simulator output is often an optimized fracturing treatment pumping schedule and the predicted fracture properties including the created fracture geometry (height, half-length, propped fracture half-length, propped fracture width) and proppant pack hydraulic conductivity. More details on hydraulic fracture simulators can be found in Chapter 10 of “Hydraulic Fracturing: Fundamentals and Advancements”, SPE Monograph Series, 2019 edited by Jennifer L. Miskimins, Stephen A. Holditch, and Ralph W. Veatch, Jr.

Area 70 represents the fracture circulation area calculated from the analysis of the tracer response, and it is notable that it is considerably less than any of the fracture geometry parameters displayed in FIG. 2. The method of the invention calculates a fracture circulation efficiency metric from the calculated flow characteristic and one or more fracture geometry parameters. Using an example from FIG. 2, a fracture circulation efficiency metric E_FC is calculated according to:

EFC = AFC / APF ( Equation ⁢ 1 )

• • where A_FC is the fracture circulation area calculated from the analysis of the tracer response; and
  • where A_PF is propped fracture area, calculated or simulated from fracture geometry information using a hydraulic fracture simulator and/or determined from microseismic cloud of events.

Based on the fracture efficiency calculation metric, at least one design parameter can be determined for the enhanced geothermal system. By relating the efficiency metric to, for example, the fracture treatment used, well spacing, and other parameters used to form the existing well combination and fractures of the system 1, design parameters can be determined for subsequent wells and/or well stimulation treatments for the system which sustain, improve, or optimize performance. Alternatively, or in addition, design parameters relating to the operation of the enhanced geothermal system, for example the properties of a heat transfer circulation fluid, and circulation flow rate, can be determined. In other embodiments, the determined design parameters may be applied to a new enhanced geothermal system. Examples of design parameters which may be determined include: the number of perforation clusters per stage, fracture geometry, fracture hydraulic conductivity, injection and production well spacing, ‘wine rack’ pattern, well spot pattern, and cemented/cased vs open hole completion. For example, if the fracture circulation efficiency is low, then the design change may include increasing the well spacing, increasing the vertical offset, reducing the fracture conductivity, and/or a combination of these changes or alternative changes.

FIG. 3 is a schematic end view of an enhanced geothermal system 1′ designed in accordance with the methodology of the invention. The system, generally shown at 1′, comprises a single injection well 20′ and four production wells 30′ with fractures (not shown) formed between the wells. Also shown in FIG. 3 are cross sectional areas representing fracture geometry parameters associated with the well combination and fracture network. Area 40′ represents stimulated reservoir volume (SRV) determined from microseismic data. Area 50′ represents hydraulic fracture geometry, which may be for example hydraulic fracture surface area, which is calculated or simulated from fracture geometry information using a hydraulic fracture simulator. Area 60′ represents propped fracture area, which is also calculated or simulated from fracture geometry information using a hydraulic fracture simulator.

The system 1′ has a 5-spot horizontal well placement and large well spacing. This well spot pattern can be continued to the left and right of this well combination. The well spacing, wine rack pattern and well spot pattern have been determined to provide a high fracture circulation efficiency, relative to a simple system design. This is visually depicted by the relatively high proportion of the propped fracture area A_PF 60′ occupied by the fracture circulation area A_FC 70′.

Although the fracture circulation efficiency metric of the examples above is calculated from the fracture circulation area and propped fracture area, other metrics may be used in alternative embodiments of the invention. Examples include:

Direct Volume Metrics:

• • fracture circulation volume/SRV (stimulated reservoir volume from microseismic);
  • fracture circulation volume/fracturing fluid treatment volume;
  • fracture circulation volume/proppant pack porosity volume.
    Calculated Area Metrics Based on an Understanding of Fracture Geometry (e.g. From a Hydraulic Fracture Simulator):
  • fracture circulation area/hydraulic fracture surface area;
  • fracture circulation area/propped fracture surface area.

These metrics can be calculated as an average for all hydraulic fractures or for each hydraulic fracture stage.

The determined design parameters may be applied to subsequent injection and production well combinations. For example, they can be applied to a second, third, and further production wells in proximity to the first injection well, and/or to additional injection wells. The design parameters may be applied to individual fracture treatment stages and/or fracture modification treatments, well completion designs, and/or operational parameters of the enhanced geothermal system. Alternatively, or in addition, the design parameters may be applied to new enhanced geothermal systems, which may be in different locations. For each new well combination formed, the steps of introducing tracers, sampling and analysing for tracer response, calculating flow characteristics and fracture circulation efficiency can be repeated. Thus, the subsequent well combinations can be used for determination of further design parameters for further wells or systems.

FIG. 4 is a flow chart showing steps for designing an enhanced geothermal system in accordance with an embodiment of the invention. The method, generally shown at 400 comprises performing 401 a multistage fracture, consisting of N fracture stages, in a well combination. In a circulation test 402, a tracer is brought by the circulation fluid to a producer well, and fluid samples are collected 403. The circulation fluid may include distinct tracers 402a associated with each fracture stage N, and/or a circulation tracer 402b injected with the circulation fluid. The samples are analyzed 404 for tracer concentrations with respect to sampling times, and from the tracer response at least one characteristic associated with a fracture stage is calculated 405. A flow characteristic is optionally a flow rate allocation 406 based for each fracture stage, based on a fracture tracer response, or an average flow circulation volume 407, or both. Where an average flow circulation volume 407 is calculated, a fracture circulation volume can be calculated 408 for each fracture stage. The flow characteristics are combined with a fracture geometry parameter 409 to calculate a fracture circulation efficiency metric 410, from which design parameters for an enhanced geothermal system can be determined 411. The determined design parameters can be used 412 in the development of an EGS comprising the well combination, or in forming a new EGS. The developed or new EGS can be used to repeat 413 steps 401 to 411 to derive further design parameters.

The method may be extended to construct a model of the reservoir stimulation treatment(s), which may be used to estimate the fracture geometry parameters of the created hydraulic fracture(s), based on one or flow characteristics calculated from tracer data, and a fracture circulation efficiency metric. For example, the model may be used to estimate the geometry of a created hydraulic fracture(s) and/or its propped fracture geometry. The model may be constructed from one or more of measured physical data, historical physical data, historical measured tracer data.

The multistage fracturing 401, circulation test 402, sampling 403, and analysis and interpretation steps 405 to 411 may all be considered as separate methods from one another and performed at different times or in different jurisdictions. In particular, the analysis and/or the interpretation of the tracer response and may be performed at different times from the collection of samples, or in different jurisdictions from the EGS.

FIG. 5 is a schematic map view of an enhanced geothermal system in accordance with an alternative embodiment of the invention. The system, generally depicted at 501, comprises a single injection well 520 and a pair of production wells 530a, 530b. Three stages of fracture treatments have been performed to form fractures 511, 512, 513, and each fracture has been injected with a distinct fracture tracer T1, T2, T3. Blocks 541, 542, 543 are representative of a snap shot the volume of fluid circulated in the respective fractures at a point in time during a circulation test. The Figure shows that each fracture has asymmetric flow characteristics towards the different producers 530a, 530b, and the circulation in each fracture is different from one another.

FIG. 6 is a plot of tracer produced concentration versus circulation fluid volume swept for the system represented in FIG. 5, with the lines T1, T2, T3 corresponding to the respective fracture tracers. The snapshot in FIG. 5 is around the value 50 on the X-axis. The T1 tracer has arrived in the producer 530a and is showing in the tracer response; the tracer T2 is close to arriving in the producer 530a but is not yet showing in the response; and tracer T3 is some way from arriving in the producer well 530b. In a similar plot from for the producer well 530b (not shown), tracer T3 would be showing in the tracer response at the value 50.

FIGS. 5 and 6 are a simple representation of how the tracer response may be used to derive information about the respective fracture profiles.

In embodiments of the invention, the analysis and interpretation of the tracer concentrations from the sampling of fluid may include quantifying a proportion of flow from each stage in the offset producer(s) by performing a dilution calculation. A mathematical derivative of the response curve may be taken to find a pulse equivalent, and that derivative can be characterized by means of Residence Time Distribution (RTD) analysis. The RTD analysis may include assisted history matching to calculate the flow characteristics of the fractures. Details of preferred and optional approaches of tracer testing and interpretation for the characterization of flow characteristic such as fracture stimulation volume in EGS applications will now be described.

Characterizing the Flowing Fractured Space.

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. The distribution, E(t), of these times is called the residence time distribution of the fluid in the system. E(t) is defined from produced tracer concentrations, C(t), production rate, Q_p(t), and injected tracer amount, M, as (cf. Huseby et al. 2014):

E ⁡ ( t ) = C ⁡ ( t ) · Q p ( t ) / M ( Equation ⁢ 2 )

The unit of E is the inverse of the time unit. Important information about the geometry and flow in a system can be obtained from the moments of the residence time distribution.

They are defined as:

m n = ∫ - ∞ ∞ E ⁡ ( t ) · t n ( t ) ⁢ d ⁢ t ( Equation ⁢ 3 )

For concrete physical interpretation exemplification, the zero moment represents the relative amount of tracer produced in production well and the first moment represents the average residence time for the tracers between the injection well and a producer.

Higher order moments, such as the second order moment, the third order moment etc. carry additional information on the space where flow occurs. The second order moment is of particular interest as it carries information on the spreading of the fluid, i.e. the dispersion resulting from heterogeneity in the flow space (Huseby et al., 2001). The temporal moments defined in Equation 3 are closely related to the moments of the spatial distribution of tracer (cf. Gonzalez-Garcia Ref: 1) and dispersion assessment based on the tracer curve as function of time at an outlet thus gives information about the heterogeneity of the flow space.

In addition to individual moments (m_n) combinations of moments are also useful to characterize the fracture space. One particularly interesting combination is the zero vs first order moments, as discussed e.g. in US 2015/0226061 A1. Various forms of this combination exist, and they are frequently denoted the Lorentz coefficient, the Dykstra-Parson coefficient or the Koval factor.

Quantification of the Flow Portion in Subsets of Space

The residence time distribution, or its counterpart the spatial tracer distribution, can be established from individual tracers and used to investigate flow in a defined flow space. It is easily realized that multiple tracers placed in sub-domains of the flow space can provide information of flow in that sub domain.

In an enhanced geothermal setting, individual parts of an injection well can be targeted by individual tracers. The placement of individual tracers into subdomains of the flow space is illustrated in FIGS. 7a to 7d, which are an illustration of the sequence used to obtain fluid samples with tracer concentrations that provide inflow contribution from individually monitored fracture zones. FIGS. 7a to 7c illustrate how individual fracked and completed zones/stages are opened for injection of fluid volumes V₁=V₂= . . . =VN individually into each stage. Injection of the tracers are devised in such that a constant concentration (C_i=C₁, C₂, . . . , C_N) is establish for tracers in the individual stages. FIG. 7c also displays a production well (Producer B) that connects with injector A. FIG. 7d illustrates the production stage, where the production well B is open, and fluid circulates through the enhanced geothermal system.

In a fracturing operation a typical scenario is that the well is drilled and isolated from the surrounding rock, before fracturing is induced stagewise by injection of fluid (FIGS. 7a to 7c). Each stage is typically isolated using e.g. packers and the amount of fluid used per stage is known. It is therefore possible to establish known, tracer concentrations (C₁, C₂, . . . , C_N) in each sub space. These concentrations can be made constant e.g. by injecting tracer continuously for each stage injection. Furthermore, it also possible to inject a tracer (C_mb) in all stages as a mass balance tracer (not illustrated in the figure). Once the enhanced geothermal system is put into production, fluid is injected into the injector A and produced at the outlet in producer B. During this process another tracer “A” can be injected in injector A either at a constant concentration (CA) or in the form of a short pulse. The calculation of rate fractions from each stage of an injection well can now be calculated, from the fundamental principle of mass-conservation, that applies for each tracer in the individual tracer systems. If we define a small control volume V=Q·Δt, corresponding to a sample at surface, and if we assume that no tracer mass leaves or enters this control volume during transport from the entry point to the sampling point, then the mass in this control volume is conserved.

Referring to notation given in FIGS. 7A to 7D, the mass of a tracer i=1, 2, . . . , N, placed into the fracturing volumes at a concentration C_i, enters at a rate Q_i,B and must equal the mass topside where the rate Q_B and concentration C′_i is measured. We thus have

m i = Q i , B · C i · Δ ⁢ t = Q B · C i ′ · Δ ⁢ t ( Equation ⁢ 4 )

Eliminating the time interval and re-arranging we can write

Q i ′ ⁢ Q ′ = C i ′ / C i ( Equation ⁢ 5 )

Since all the concentrations C_i are known, the proportion of rate from a particular stage (ƒ_i=Q_i/Q′) are given directly from the concentration fractions. Moreover, if the only source of fluid in the producer B is from the from fracking of injector A, the sum

∑ i N ⁢ f i = 1 .

This latter fact can be used to identify other sources of fluid in producer B. A value of Σƒ_i smaller than 1 implies that there are other sources of fluid and the proportion of this additional fluid is simply be given as 1−Σƒ_i.

One obvious source of fluid not from fracking of injector A is water injected into injector A during the circulation of water in the production phase of the system. This water can be identified using a separate circulation tracer, injected at a known concentration CA.

FIG. 8a is an illustration of injector of tracers in two injectors and a producer in an enhanced geothermal system. In addition to injecting unique fracture tracers per stage during fracking, tracers “A” and “B” are circulation tracers injected during circulation. FIG. 8b illustrates typical tracer response from one of the circulation tracers, injected as a pulse (dotted line) or in a continuous manner at a constant concentration during circulation.

After the initial fracking, where the fracture network and flow patterns are established in the system, fluid is circulated from the injectors to producers. In this circulation unique tracers per injector can be added to the injection fluid (cf. FIG. 8a). These tracers can be injected continuously or as pulses, creating distinct differently responses, illustrated in FIG. 8B. It should be noted that even if different in nature, the response from a step function injection (full line in FIG. 8b) can be transformed to that of a pulse (dotted line in FIG. 8b) by differentiation of the response.

The response functions from injection during circulation can be used to characterize the total flow volume between specific injectors and producer pairs in the system, using the RTD approach, as explained above. As an example, the total flow volume between each injector-producer pair can be quantified. Using a combination of the RTD and the stage tracers, the flow characteristics can be delineated per stage and answer important questions, such as what the volume is between injectors and producers on a per stage level.

Improving Simulation Models Using Circulation and Per Stage Tracer Data

The moments of the RTD are possibly the best representation of the reservoir information contained in the tracer curves. In standard workflows used to assimilate information for assisted history matching, it is common to compare time series of measured data to time series of simulated data. The workflows calculate a misfit (squared difference between measured and simulated time series) and reduces this misfit by systematically performing simulations where reservoir parameters are guessed and re-guessed. Formally we can define the misfit in standard approaches as:

ϵ = ∑ i = 0 N ( f ⁡ ( t i , α ) - y i ) 2 ( Equation ⁢ 6 )

where ƒ(t, α) is our model function of time defined by model parameters α, and y_i are our measured response at times t_i.

Note that this misfit definition can be generalized to multiple spatial dimensions as well as time and ƒ(t) can be a multidimensional function of space and time. The values of ƒ at specific points in space and time depend on the set of parameters α and history matching is the process of finding the values of α that gives the best possible representation of the measured data. In practice, this is done by minimizing the misfit with respect to the model parameters, i.e. by solving the equation

∂ ϵ ∂ α = 0 ( Equation ⁢ 7 )

One application of an RTD is to replace the misfit that compares measured and simulated concentration time series by a misfit that compare the RTD moments of the simulated and measured tracer curve instead of the curves themselves. In practice this can be achieved by calculating the moments m₀, m₁, m₂ . . . from the model using Equation 3 and compare to the moments calculated the measured data.

In a similar manner, the first order moment from a model can be compared to the first order moment from tracer data. These first order moments can be used to find swept volume from injector to producer from data and model, that in turn can be illustrated as a volume or area of a given size. One example can be to plot an ellipse from the injector to the producer, as shown in FIG. 9. FIG. 9 is a visualization of the zero and first order moments as the width of an arrow from an injector to a producer and an elliptical area. The width of the arrow represents the magnitude of the zero-order moment, and the size of the elliptical area represents the value of the swept area from the first order moment. By comparing visual representations of these moments from a model (left) to those obtained from measured data (right) a visual illustration of the misfit between model and data is immediately available. In the example a significant misfit is obvious.

FIG. 10 is a simplified representation of an enhanced geothermal system (EGS) shown generally as 600. The geothermal system has an injection well 612 and a production well 614. A series of hydraulic fracture treatments are carried out in the injection well with the aim of establishing a fluid connection between the injection well and the production well through the dry hot rock formation 616. Typically, hydraulic fracturing is carried out at different fracture initiation sites of the injection well 612 in a multistage hydraulic fracture process. In this example eight stages are shown, however it will be appreciated that the number of stages may be more than eight or less than eight. During a first stage, fracturing fluid is pumped from the surface through the wellbore and through perforations at injection site 620. The pumped fluid causes stresses in the rock formation 616, and as the fluid pressure and pumping rate exceed the critical stresses, fractures 630 form and propagate through the surrounding rocks. Further pumping leads to deeper fracture propagation. In this example a distinct tracer 615a is injected into the fracturing fluid and introduced into the fracture 630. The fracturing fluid may comprise proppant material which fill the developing fractures preventing fractures closure and improve the conductivity through the fracture. During the second stage, injection site 620 is isolated from injection site 622, for example by a wellbore plug or frac plug, and fracturing fluid is pumped from the surface through the wellbore and through perforations at injection site 622 to form fractures 635. A distinct tracer 615b is injected into the fracturing fluid and introduced into the fracture 635. This process is repeated for all eight stages with a distinct tracer introduced into the each of the respective fractures. In this example, the resulting fractures 630, 635, 640, 645, 650, 655, 660, 665 have different profiles, which may be due to the natural rock formation, differing fracture treatments or perforation design, or a combination. The distinct tracers 615a-615h introduced into the fractures may provide information on the characteristic and condition of the fractures as circulated fluid moves to the production well. Samples collected from the production well 614 can be analysed for tracer concentrations to provide one or more flow characteristics associated with the fracture.

In the above example the tracer is injected into each respective fracture during pumping of the fracturing fluid. It will be appreciated that the distinct tracers may be introduced into the fractures during pumping of the proppant, or as a subsequent injection step after the fracture has been formed. Alternatively, the tracers could be introduced via inflow tracers located at each stage in the injection well. The injection well and production well have a known distance “L”. Subsequent circulation of fluid between the injector well 612 and the producer well 614 during a circulation test may cause the distinct chemical tracers to flow with the circulated fluid to the production well. Optionally based on the concentration of chemical tracers detected in collected samples in the production well a percentage flow distribution from each fracture may be determined.

FIG. 11 shows a quantitative production log for a well having eight fracture stages (3R, 4 to 10) where distinct tracers are injected into each of the eight stages (3R, 4 to 10). In FIG. 11 the y-axis shows the percentage flow contributions per fracture stage on the x-axis. Each individual bar represents tracer data from a single sample collected at known sampling times. Based on the tracer response data flow rate data per stage is calculated where:

F ⁢ low ⁢ rate ⁢ per ⁢ stage = % ⁢ flow ⁢ distribution × Q ⁢ ( flow ⁢ rate ⁢ at ⁢ surface ) . ( Equation ⁢ 8 )

The use of tracers allows flow through each fracture to be simultaneously measured, and the flow is undisturbed. Optionally, in addition to injecting distinct fracture tracers per stage during fracturing, at least one circulation tracer may be injected into an injection fluid during a circulation test. The circulation tracer may travel through each of the fractures during circulation of flow from the injection well to the production well to provide information on flow characteristics of the fractures.

In this example a distinct circulation tracer is added to the injection fluid which is injected into all of the fractures. The circulation tracer may be injected as a pulse or in a continuous manner at a constant concentration during circulation. The circulation test between the injection well and production well is conducted at a first injection and/or production rate. Samples of the produced fluid are collected from the production well. The samples are collected when there is a stable flow in the production flow. Optionally the circulation test may be repeated with a different circulation tracer. Optionally the circulation test may be repeated at a different or a range of different flow rates. A distinct circulation tracer may be used for each of the different flow rates.

FIG. 12 shows a tracer response graph showing the volume of produced fluid in the x-axis and the tracer concentration for each of the eight stage tracers and a circulation tracer. Samples of the produced fluid are analysed for stage tracer and circulation tracer concentrations to calculate a flow rate allocation associated with each fracture. The circulation test between the injection well and production well may be conducted at a multiple injection and/or production rates. A distinct circulation tracer may be injected for each of the different injection and/or production rates.

In this further example the circulation test is conducted at four different injection and/or production rates. The duration of time of each injection and/or production rates is sufficient to allow stable flow in the production flow and samples to be collected during a period of stable production flow. For each injection and/or production rate the surface flow rate, pressure and/or bottom hole pressure is measured and/or calculated.

FIG. 13 shows a graph of average flow rate per cluster based on the tracer data against calculated bottom hole pressure. In this example the percentage flow contribution data are based on chemical tracer concentrations for each stage. The graph shows rate versus delta pressure for each of the eight fracture stages. The bottom hole pressure may be measured directly using equipment downhole. Alternatively, the bottom hole pressure May be calculated based on measured surface pressure. In this example the pressure was calculated at the perforations entering the fractures in order to determine the corresponding pressure drop between wells.

In a further example, a proppant transport capacity may be optionally calculated for each stage where:

Proppant ⁢ transport ⁢ capacity = ( Ci ) × ( Wi ) . ( Equation ⁢ 9 )

Ci=conductivity, Wi=fracture width.

As the tracer data in FIG. 13 was measured for a range of production rates and therefore different pressures the slope of the graph in FIG. 13 is a measure of conductivity×flow width per viscosity and distance between the two wells according to Darcy's law. As the viscosity and distance between the two wells are known the slope provides information on the proppant transport capacity. The proppant transport capacity is a measure of how effective the various treatments were in placing proppant in the fracture system. In the above example tracer data taken for multiple pressures/flow rate are used to calculate proppant transport capacity. It will be appreciated that alternatively discrete data points at one or more pressures/flow rate may be used to calculate proppant transport capacity.

FIG. 14 is a graph showing the effects of fracturing fluids on the relative proppant transport capacity (normalized by the transport capacity for stage 4). Carboxymethyl Hydroxypropyl Guar (CMHPG) and Slickwater are two different types of fracturing fluids which may impact proppant transport capacity in hydraulic fracturing. The properties of the fracturing fluid may affect fluid velocity, viscosity, and proppant suspension, which in turn may influence the likelihood of proppant transport. CMHPG is a viscous, gel-based fracturing fluid derived from guar gum. It is used to improve proppant transport. Slickwater is a low-viscosity, water-based fracturing fluid with small amounts of friction reducers to allow for high-rate pumping. In this example CMHPG was used as a fracturing fluid in stage 5 and 8, Slickwater was used as a fracturing fluid in stage 3R and 4. FIG. 14 shows that the estimated proppant transport coefficient is 18% higher when CMHPG is used as fracturing fluid versus slick water.

The response functions from monitoring circulation tracer in the collected samples may be used to characterize the total flow volume between the injection well and producer well using Residence Time Distribution (RTD) as described above. The tracer data represents elements of fluid that travel through different paths and therefore use different amounts of time to pass through a fracture. The distribution, E(t), of these times is called the residence time distribution of the fluid in the system. E(t) is defined from produced tracer concentrations, C(t), production rate, Q_p(t), and injected tracer amount, M based on Equation 2 above. The total flow volume between each injection well and production well pair can be quantified. Using a combination of RTD and the stage tracers, the flow characteristics can be delineated per stage and provide fracture information such as volume between injection well and production well per stage level.

Optionally Fracture Circulation Volume (VFC) and Fracture Circulation Volume per stage (VFCi) may be determined based on the circulating tracer data from a circulation test, where:

VFCi = VFC × Percentage ⁢ flow ⁢ distribution ⁢ per ⁢ stage . ( Equation ⁢ 10 )

FIG. 15A is a graph showing fracture circulation volume per stage/cluster for each of the eight stages. FIG. 15A shows the calculated fracture circulation volume per stage (dark shade bars) for each of the eight stages in this example. FIG. 15A also provides details on the calculated fracture circulation volume per cluster (light shade bars). In this example stage 3R has 2 clusters plus an open hole section, stage 4 has 1 cluster, stage 5 has 1 cluster, stage 6 has 2 clusters, stage 7 has 3 clusters, stage 8 has 8 clusters, stage 9 has 8 clusters and stage 10 has 1 clusters. The assumption made is that the number of fractures is proportional to the number of clusters and open hole sections.

FIG. 15B is a distribution curve for circulating tracer vs time. The solid grey line shows the distribution curve for circulating tracer. The distribution curve is an average of two different circulation tests using two different circulating tracers. The pulses are each at 10 bpm. The distribution curve shows an apex measuring a swept volume of 4680 bbls for the flow paths between the injection well and the production well. The dotted black line shows a distribution curve for tracer in fast flow path. The grey dotted line shows a distribution curve for tracer in slow flow path. Three vertical lines “A” (first arrival), “B” (apex) and “C” (mean) are shown in this example which correspond to three different points in the RTD analysis. This may be used to determine or confirm permeability data. It will be appreciated that further data points (vertical lines analysis) may be taken in other examples to provide a distribution of permeabilities.

From the RTD analysis, a distribution of arrival times may be obtained. So, a distribution of permeabilities per stage may be created. In the example FIG. 15B shows a volume of 4680 bbl for flow paths between the injection well and production well. By dividing this volume by the distance between the wells provides the hydraulic cross-sectional flow area.

Optionally, using the tracer data from each fracture stage other characteristics of the fracture may be determined including the hydraulic cross-sectional area to flow, which equals the relative aperture×relative hydraulic width of the fracture.

The hydraulic cross-sectional area (Ac) may be calculated per stage using the equation:

Ac = Bi × Wi = Vfc ) / L ( Equation ⁢ 11 )

Bi=Aperture; Wi=hydraulic Width; Vfc=fracture circulation volume; L=distance between wells.

FIG. 16 shows the calculated hydraulic cross-sectional area for each of the eight stages in this further example. This is calculated based on the volume in each of the fractures as shown in FIGS. 15A and 15B from RTD analysis and divided by the distance between the injection and production wells.

In this example a hydraulic cross-sectional area of flow of each fracture is based on the circulation tracer data, the RTD analysis and a known distance between the injection and production wells. The dark grey data bars shown in FIG. 16 are based on the RTD analysis from the circulating tracer as described above and the circulation volume of the fracture divided by the distance between the wells. FIG. 16 also provides a comparison data set (light grey bars) for the hydraulic cross-sectional area of flow is obtained by an alternative optional method of determining a cross-sectional area of each fracture based on the use of nanoparticles to determine velocity combined with chemical tracer data to determine inflow distribution as described below.

In a nanoparticle tracer study at least one distinct nanoparticle tracers and at least one distinct chemical tracer were injected into each in fracture stage. Flow was circulated between the injector well through each fracture stage to the production well. Samples of the fluid flow from the production well were collected and tested for the concentration of the distinct chemical tracers and a distinct nanoparticle tracers associated with each fracture stage. Using only the nanoparticle tracer data per fracture stage, we assume that the average of the variability per stage is representative of the relative velocity per stage. The ratio of nanoparticle tracer response is proportional to the ratio of velocities in the various stage fractures. Hence, we calculate the relative velocities (Vi/Vaverage) across the various stages. The relative velocity per stage is calculated as the representative velocity (apparent velocity)/average representative velocity.

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

Qi = Q surface × % ⁢ flow ⁢ contribution ( Equation . 12 )

The relative aperture (bi/b_average) may be calculated per stage using the equation:

Qi / Q a ⁢ v ⁢ e ⁢ r ⁢ a ⁢ g ⁢ e = ( Vi / V a ⁢ v ⁢ e ⁢ r ⁢ a ⁢ g ⁢ e ) × ( bi / b a ⁢ v ⁢ e ⁢ r ⁢ a ⁢ g ⁢ e ) × ( Wi / W a ⁢ v ⁢ e ⁢ r ⁢ a ⁢ g ⁢ e ) × ( Pi / P a ⁢ v ⁢ e ⁢ r ⁢ a ⁢ g ⁢ e ) ( Equation . 13 )

Where: (Vi/V_average) is relative velocity, bi/b_average is relative aperture, (Wi/W_average) is relative width and Pi/P_average is relative porosity. In this example a relative cross-sectional area to flow (Ai=bi*Wi*porosity i) is calculated from a ratio of chemical tracer derived flow rate and nano particle tracer derived velocity using equation 13. The relative aperture may be calculated from relative cross-sectional area to flow by further integrating data including microseismic and mass balance information. A comparison of the data bars in FIG. 16 show that both methods provide a very similar hydraulic cross-sectional area of flow through the fractures for each of stages 3R, 4, 5, 8 to 10. Nanoparticle tracer data was not available for stages 6 and 7.

Optionally the permeability (ki) per stage may be calculated where:

Permeability ⁢ ( ki ) = ( Ci ) × ( Wi ) / ( Aperture ⁢ ( bi ) × Width ⁢ ( Wi ) ) ( Equation . 14 )

FIG. 17 shows the Permeability (ki) for each of the eight stages in this example (grey bar for apex RTD analysis). The number of fractures is proportional to the number of clusters. In this example the data is based on the assumption of 1 fracture per cluster and open hole section. The permeability (ki) may optionally be determined as a distribution of ki for each fracture stage. FIG. 17 shows a graph of permeability (ki) for a first arrival path (dotted bar), apex path (grey bar) and mean/average path (diagonal stripes) for each of the eight stages in this example. Optionally the aperture of the fracture may be determined based on the hydraulic cross-sectional area data. A sensitivity range of aperture (b) and hydraulic width of flow channel (W) may be determined based on known, measured or calculated limits.

FIG. 18 shows a sensitivity range of aperture for each stage. Frac simulations shown as (dotted bar) provide a maximum aperture size of 0.12 inches at the time of pumping which is the widest size of the aperture which reduces after pumping. Microseismic SRV data shown as (diagonal hassed bar) provides a maximum width which combined with a known biW (Aperture×Width) product allows a minimum aperture size of about 0.02 inches to be calculated. An average between this maximum aperture and minimum aperture is shown as grey bar. Other Aperture ranges (horizontal dashed bars) were calculated based on nano particle tracer studies described below.

Nanoparticle tracer studies to determine the hydraulic cross-sectional area may involve injecting distinct nanoparticle tracer into each stage fracture, based on Stokes' law, parameters of the injection rate, injection volume, production rate, production volume, nanoparticle tracer, and/or fluid may be adjusted to change the flow conditions. Based on the nanoparticle tracer response to different conditions an apparent velocity (Vi) per stage fracture may be estimated. For example, injecting a sweep of fluids with different fluid viscosities and/or different fluid densities may allow an estimate of apparent velocity (Vi) per stage fracture based on the nanoparticle tracer response to the different fluid viscosities and/or different fluid densities. Additionally or alternatively, the injection rates could be adjusted and changes in nanoparticle tracer response observed to estimate of apparent velocity (Vi) per stage fracture. By combining the estimated apparent velocity (Vi) per stage fracture with the Qi measured from chemical tracer data (or production logging data), then hydraulic cross-sectional area (b*W) per stage may be estimated from Qi=Vi*(bi)*W. The aperture can then be calculated by integrating W from other data such as microseismic or fracture modelling.

In the above example only one distinct nanoparticle tracer is injected into each stage fracture. In other examples two or more distinct nanoparticle tracer may be injected into each stage fracture. In an example the two or more distinct nanoparticle tracers injected into each stage fracture may have different sizes and/or densities and therefore respond differently to the velocity field. By analysing the nanoparticle tracer response to each of the different sized and/or different density nanoparticle tracers an apparent velocity (Vi) per fracture stage may be estimated. By combining the estimated apparent velocity (Vi) per stage fracture with the Qi measured from chemical tracer data (or production logging data), then an aperture per stage may be estimated from Qi=Vi*(bi)×W (where W can be assumed or calculated by integrating other data such as microseismic or fracture modelling).

Optionally the stage tracer conductivity Ci per stage is calculated based on the equation:

Ci = ki / bi . ( Equation ⁢ 15 )

FIG. 19 shows a graph of sensitivity range for fracture conductivity for each fracture stage (3R, 4 to 10) based on three different aperture sizes and the RTD analysis for the apex. The maximum aperture size 0.1 inches (shown dotted bar), minimum aperture size 0.04 inches (shown as cross hatched bar) and an average aperture size 0.07 inches (shown as grey) from the average bi from FIG. 18. FIG. 19 is a graph showing sensitivity range for stage tracer conductivity Ci per stage for an average aperture size. 0.04 and 0.1 inches were selected as a narrower range of the aperture sensitivity taken from FIG. 18. Based on the RTD analysis a distribution of conductivities per fracture may be calculated. The distributions of permeability and/or distributions of conductivity may be used to optimise the EGS.

Using the tracer data, characteristics of each fracture stage may be determined, which may be used to assess the economic life per treatment stage. By determining characteristics of the fracture such as volume per fracture, aperture, surface area per fracture and/or aperture the economic life, surface area for heat transfer and/or thermal decline of the EGS may be determined. FIG. 20 shows a graph of the expected economic lifetime in years of each of the fracture stages based on the thermal decline curves reported by Gringarten et al (1975). The error bars correspond to range of bimin vs bimax.

It will be appreciated that the steps described above are examples of some of the characteristics of the fractures between the wells that may be determined and that one or more steps may be omitted, replaced, added and/or that the sequence of the steps may be different.

The invention may provide a method of characterising at least one fracture in an enhanced geothermal system and/or designing an enhanced geothermal system. The method comprises forming a first stage hydraulic fracture from a first well of the well combination according to a first fracture treatment in a well combination comprising at least one injector well and at least one production well. A second stage hydraulic fracture is formed from the first well according to a second fracture treatment. Fluid is circulated from the first well to a second well of the well combination via the first and second stage fractures. The circulated fluid carries at least one tracer to the second well. Samples of fluid are collected from the second well and analysing tracer concentrations with respect to sampling time, and a flow characteristic is calculated from the analysis of the tracer concentrations. A fracture circulation efficiency metric is calculated from the calculated flow characteristic and at least one fracture geometry parameter. Based on the fracture circulation efficiency metric, the method comprises determining at least one design parameter for the enhanced geothermal system.

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”, “extend”, “retract” 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.

REFERENCE

• 1) Gonzalez-Garcia R. Huseby O., Thovert J.-F., Ledesert B. and Adler P. M.: “Three-dimensional characterization of a fractured granite and transport properties”. J. Geophys. Research, Vol 105, no. B9 pp 21387-21401, 2000.
• 2) Gringarten et al. “Theory of heat extraction from fractured hot dry rock”. J. Geophys. Res., 80 (8)), pp. 1120-1124, 1975.