WO2010017557A1 - Procédé pour faire un essai d’un système géothermique industriel en utilisant un puits stimulé - Google Patents

Procédé pour faire un essai d’un système géothermique industriel en utilisant un puits stimulé Download PDF

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Publication number
WO2010017557A1
WO2010017557A1 PCT/US2009/053304 US2009053304W WO2010017557A1 WO 2010017557 A1 WO2010017557 A1 WO 2010017557A1 US 2009053304 W US2009053304 W US 2009053304W WO 2010017557 A1 WO2010017557 A1 WO 2010017557A1
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Prior art keywords
subterranean
fluid
recited
tracer
well
Prior art date
Application number
PCT/US2009/053304
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English (en)
Inventor
Susan Petty
Peter Rose
Laura Nofziger
Original Assignee
Altarock Energy, Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Altarock Energy, Inc. filed Critical Altarock Energy, Inc.
Priority to AU2009279407A priority Critical patent/AU2009279407A1/en
Priority to EP09791340A priority patent/EP2334904A1/fr
Publication of WO2010017557A1 publication Critical patent/WO2010017557A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E21B49/008—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells by injection test; by analysing pressure variations in an injection or production test, e.g. for estimating the skin factor
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F24—HEATING; RANGES; VENTILATING
    • F24T—GEOTHERMAL COLLECTORS; GEOTHERMAL SYSTEMS
    • F24T10/00—Geothermal collectors
    • F24T10/30—Geothermal collectors using underground reservoirs for accumulating working fluids or intermediate fluids
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F24—HEATING; RANGES; VENTILATING
    • F24T—GEOTHERMAL COLLECTORS; GEOTHERMAL SYSTEMS
    • F24T10/00—Geothermal collectors
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F24—HEATING; RANGES; VENTILATING
    • F24T—GEOTHERMAL COLLECTORS; GEOTHERMAL SYSTEMS
    • F24T2201/00—Prediction; Simulation
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E10/00—Energy generation through renewable energy sources
    • Y02E10/10—Geothermal energy

Definitions

  • the present application is directed to systems and methods for testing subterranean formations. More particularly, the present application is directed to systems and methods for testing engineered geothermal systems.
  • radioactive tracers are utilized to identify flow paths.
  • concentration of radioactive tracers is measured in the same well or neighboring wells using gamma spectroscopy integrated in a logging tool with a radioactive source.
  • the use of radioactive tracers and radioactive logging tools is expensive and gives rise to health, safety and security concerns.
  • spectral gamma tools are not capable of operation in high temperature environments encountered in geothermal wells.
  • a method includes stimulating a substantially non-permeable medium within a subterranean formation to create a fractured reservoir. At least one stimulation parameter is measured during stimulation. A well drilled in the subterranean formation is shut-in. A fluid is produced from the subterranean well and at least one production parameter is measured during production. The stimulation and production parameters are used in a numerical reservoir fluid flow model to identify parameters of the fractured reservoir.
  • FIG. IA illustrates an exemplary system for testing a subterranean formation according to one embodiment
  • FIG. 1 B illustrates an exemplary system for testing a subterranean formation according to another embodiment
  • FIG. 2 illustrates a flow chart of an exemplary process for testing a subterranean formation.
  • FIG. IA illustrates an exemplary system for testing a subterranean formation 100 according to one embodiment.
  • a subterranean well 102 is drilled in a subterranean formation 100.
  • the subterranean formation 100 includes a substantially non-porous medium having a number of subterranean intervals 104, 106, 108.
  • Treatment fluid is injected into fracture networks 110, 111, 112 within the subterranean intervals 104, 106, 108 to stimulate the fracture networks 110, 1 11, 112 and create a fractured reservoir 114.
  • FIG. IB illustrates an exemplary system for testing a subterranean formation 100 according to another embodiment.
  • the fractured reservoir 114 may be created by isolating subterranean intervals 104, 106, 108 consecutively or simultaneously before stimulating fracture networks 110, 111, 112 therein.
  • the fractured reservoir 114 may be created by blocking fractures 110 in a selected subterranean interval 104 with a blocking agent 120 such as a high viscosity fluid or temporary fracture sealant before stimulating fracture networks 111, 112 in isolated subterranean intervals 106, 108.
  • Selected subterranean intervals 104, 106, 108 may also be isolated with zonal isolation systems such as downhole packers, scab liners or other isolation systems know in the art before stimulating fracture networks 110, 111, 112 therein.
  • the fractured reservoir 114 may be created by injecting any one or a combination of treatment fluids capable of stimulating fractures including, but not limited to water, brine, carbon dioxide, nitrogen, hydrocarbons or any other fluid known in the art that is capable of stimulating fractures in a subterranean formation.
  • a micro-seismic monitoring system is used to measure parameters within the fractured reservoir 114 as the reservoir is formed.
  • the micro-seismic monitoring system may be any system known in the art for detecting, measuring and processing the seismicity within subterranean formations.
  • the micro-seismic monitoring system may include a seismic data acquisition unit, seismic sensor units and a seismic data line. Seismic sensor units include signal transmitting channels and seismic sensors typically providing two components of horizontal seismic event-sensing and one component of vertical seismic event-sensing during fracture stimulation.
  • the seismic sensor units may be positioned at the surface or in a neighboring wellbore.
  • Seismic event signals generated by small rock movements along failure planes in the formation 100 are detected by seismic sensors and transmitted to the seismic data acquisition unit via the seismic data line or via a wireless communication network.
  • P and S waves generated by the small rock movements along failure planes are received at seismic sensors at different arrival times. The arrival times of P and S waves are used to determine the location of seismic events and map the propagation of fractures in the fractured reservoir 114 during fracture stimulation.
  • the streaming potential or electromagnetic field generated by the treatment fluid during injection is also detected, measured and processed to determine the flow path and flow characteristics of treatment fluid within the fractured reservoir 114.
  • the polarization of shear seismic waves reflected from stimulated fracture networks 110, 111, 112 may also be detected, measured and processed to determine the portion of the fractured volume within the fractured reservoir 114 that is filled with fluid.
  • Data obtained from the micro-seismic monitoring system is used to generate a micro-seismic event map of seismic events occurring within at least a portion of the subterranean formation 100 including the fractured reservoir 114.
  • a fiber optic logging tool 130 is used to measure the temperature along the full length of the subterranean well 102 or wellbore and pressure proximate the bottom of the subterranean well 102.
  • the fiber optic logging tool 130 may be any fiber optic logging tool known in the art for measuring temperature and pressure in a downhole environment including, but not limited to those described in U.S. Patent 7,284,903 incorporated herein by reference.
  • the fiber optic logging tool 130 may include an optical source, a fiber optic cable 132, an optical pressure sensor 134 and a fiber optic data acquisition unit 136.
  • the optical source transmits optical signals through the fiber optic cable 132 and the fiber optic data acquisition unit 136 processes and converts signals into temperature and pressure data.
  • the fiber optic cable 132 may be encased in a protective housing or lowered into the subterranean well 102 within a tubing string to protect the fiber optic cable 132 from heat and corrosive fluids within the subterranean well 102.
  • the pressure as a function of time proximate the bottom of subterranean well 102 may be monitored through the optical pressure sensor 134 to control well pressure and prevent tensile fractures from forming in the fractured reservoir 114 during fracture stimulation.
  • the pressure during stimulation is also compared to tests prior to stimulation to determine the improvement in well injectivity obtained from the stimulation.
  • the temperature as a function of time along the vertical and/or horizontal length of the subterranean well 102 is measured to determine the flow path and flow rate of treatment fluid injected into the fractured reservoir 114.
  • fracture networks 110, 111, 112 are stimulated or opened to form fluid flow paths within the fractured reservoir 114.
  • the temperature increases adjacent to the subterranean intervals 104, 106, 108 having stimulated fracture networks 110, 111 , 112, because the treatment fluid flows into the stimulated fracture networks 110, 111, 112 and does not circulate within the wellbore to cool the well 102 adjacent to the stimulated intervals 104, 106, 108.
  • the temperature of the subterranean well 102 adjacent to the subterranean intervals 104, 106, 108 is an indication of the location and size of available fluid flow paths and stimulated fracture networks 110, 111 , 112 within the subterranean intervals 104, 106, 108.
  • a blocking agent 120 may be injected into a subterranean interval 104 to block or plug a stimulated fracture network 110.
  • the blocking agent 120 prevents treatment fluid from entering the stimulated fracture network 110.
  • the circulation of treatment fluid within the wellbore cools the well 102 adjacent to the blocked subterranean interval 104 to a temperature close to the initial temperature of the injected treatment fluid.
  • Treatment fluid injected into the subterranean formation 102 bypasses the blocked subterranean interval 104 and begins stimulating or opening fracture networks 111 , 112 within subterranean intervals 106, 108 having higher fracture initiation pressures.
  • the temperature of the subterranean well 102 adjacent to the subterranean intervals 104, 106, 108 is an indication of the location and size of available fluid flow paths and stimulated fracture networks 110, 111, 112 within the subterranean intervals 104, 106, 108.
  • a first unique tracer composition may be injected into a first formed fracture network 110 within a selected subterranean interval 104 as part of the treatment fluid during fracture stimulation.
  • the temperature increases adjacent to the subterranean interval 104 wherein new fluid flow paths and a stimulated fracture network 110 are created.
  • the stimulated fracture network 110 within the stimulated subterranean interval 104 may be blocked with a blocking agent 120.
  • a second unique tracer composition may be injected into the subterranean well 102 as part of the treatment fluid to stimulate another fracture network 111 within a subterranean interval 106 having a higher fracture initiation pressure.
  • the temperature increases adjacent to the subterranean interval 106 wherein new fluid flow paths and a stimulated fracture network 111 are created.
  • the stimulated fracture network 111 within the stimulated subterranean interval 106 may be blocked with a blocking agent 120.
  • a third unique tracer composition may be injected into the subterranean well 102 as part of the treatment fluid to stimulate another fracture network 112 within a subterranean interval 108 having a higher fracture initiation pressure.
  • the temperature increases adjacent to the subterranean interval 108 wherein new fluid flow paths and a stimulated fracture network 112 are created.
  • a unique tracer composition may be injected into each fracture network 110, 111, 112 in the fractured reservoir 114 by first isolating each subterranean interval 104, 106, 108 consecutively or simultaneously before injecting the unique tracer composition within the selected subterranean interval 104, 106, 108.
  • Any number of unique tracer compositions may also be injected into each fracture network 110, 111, 112 within a selected subterranean interval 104, 106, 108 as part of a test fluid after simulating fracture networks 110, 111, 112 with the treatment fluid.
  • the test fluid is an aqueous solution including water and a unique tracer composition.
  • a unique tracer composition for each subterranean interval 104, 106, 108 may be injected into each fracture network 110, 111, 112 as part of the test fluid after isolating each subterranean interval 104, 106, 108 consecutively or simultaneously and after stimulating fracture networks 110, 111, 112 with treatment fluid.
  • the tracer composition is a mixture of reactive tracers and nonreactive tracers having a measurable difference in known thermal or chemical decay kinetics.
  • the reactive tracers may be thermally reactive or chemically reactive.
  • the tracer composition may include one or more reactive tracers and one or more nonreactive tracers.
  • the tracer composition may be injected at a constant ratio of reactive tracers to nonreactive tracers. Nonreactive tracers may also be injected as pulses.
  • the tracer composition may also be injected at equal or unequal ratios of reactive tracers to nonreactive tracers. Tracers may be chemically distinct powders or liquids dissolved in aqueous solution. Reactive and nonreactive tracers may also be injected as part of the treatment fluid or test fluid as entrained vapor or liquid solute.
  • Thermally reactive tracers react with minerals or other species in the formation 100 and are lost to fluid within the formation 100 during injection, shut-in or flow back.
  • Thermally reactive tracers are thermally unstable and a substantial and measurable portion of thermally reactive tracers is lost due to thermal degradation as the tracer travels through the heated formation 100 during injection, shut-in or flow back.
  • Thermally reactive tracers may have different reaction rates and temperature limitations that affect their rate of degradation and thus their useful life.
  • the tracer composition may include low reactive tracers, moderately reactive tracers, highly reactive tracers or combinations thereof.
  • Reactive tracers may include, but are not limited to esters, amines, aryl halides, eosin Y, Oregon Green, rhodamine, sodium fluorescein (uranine), halogenated fluoresceins, and combinations thereof.
  • Sodium fluorescein (uranine) for instance begins to thermally degrade above about 250 0 C.
  • the thermal decay kinetics (e.g. degradation as a function of time) and chemical decay kinetics (e.g. rate of reaction within the formation) of each injected thermally or chemically reactive tracer is determined before it is injected into the subterranean formation.
  • Nonreactive tracers are substantially inert and do not thermally degrade and/or do not react with other species in the subterranean formation 100 during injection, shut-in or flow back.
  • Nonreactive tracers may include, but are not limited to alcohols, alkali metals, alkaline- earth metals, halides, sulfonic acid, bromides, rhodamine WT, naphthalene sulfonates, naphthalene disulfonates and sodium fluorescein (uranine).
  • a number of naphthalene sulfonates and naphthalene di-sulfonates are thermally stable at subterranean temperatures below about 340 0 C.
  • the micro-seismic monitoring system is used to measure parameters within the fractured reservoir 114 to generate a micro-seismic event map indicating the extent of the created fractures which may form fluid flow paths within the fractured reservoir 114.
  • the streaming potential of the treatment fluid or the test fluid is detected, measured and processed during injection to determine the movement of fluid, the fluid flow paths and fluid flow characteristics within fracture networks 110, 111, 112.
  • 110, 111, 112 may also be detected, measured and processed to determine the volume of fluid filled stimulated fracture networks 110, 111, 112 and the direction of fracture networks 110,
  • the fiber optic logging tool 130 is used to measure parameters such as the temperature of subterranean intervals 104, 106, 108 and the pressure proximate the bottom of the subterranean well 102.
  • the temperature as a function of time along the vertical and/or horizontal length of the subterranean well 102 is measured to determine fluid exit points from the wellbore and fluid flow rates within the fractured reservoir 114.
  • the pressure as a function of time proximate the bottom of subterranean well 102 is monitored to control well pressure and prevent tensile fractures from forming in the fractured reservoir 114 during injection.
  • the flow rate and pressure of treatment fluid or test fluid injected into the subterranean well 102 may also be measured at the surface.
  • Wellbore image logs obtained prior to the stimulation and/or injection and test data obtained during stimulation and/or injection including the micro-seismic event map, the pressure within the subterranean well 102 and the temperature along the vertical and/or horizontal length of the subterranean well 102 is used in a stochastic fracture model to generate an equivalent porous medium representing at least a portion of the subterranean formation 100 making up the fractured reservoir 114.
  • the equivalent porous medium is incorporated into a numerical reservoir fluid flow model to simulate the characteristics and expected behavior of at least a portion of the subterranean formation 100 including the fractured reservoir 114.
  • the subterranean well 102 is shut-in for a period of time (e.g. hours, days, weeks, months). During shut-in, the tracer composition is permitted to remain in contact with fracture networks 110, 111, 112 in the fractured reservoir 114. During shut-in, the subterranean formation 100 including the fractured reservoir 114 increases in temperature towards the geostatic temperature of the subterranean formation 100. Reactive tracers injected into the fracture networks 110, 111, 112 begin to thermally degrade or chemically react as temperature and time increases. The pressure of the subterranean well 102 may be monitored during shut-in.
  • a period of time e.g. hours, days, weeks, months.
  • the subterranean well 102 is flowed-back to produce the treatment fluid or test fluid having the tracer composition.
  • the fiber optic logging tool 130 is lowered back into the subterranean well 102.
  • Temperature along the length of the subterranean well 102 is monitored while pressure is measured downhole.
  • the flow rate of fluid produced from the subterranean well 102 is controlled at a first constant flow rate for a period of time.
  • the draw down or change in pressure and the temperature along the length of the subterranean well 102 is measured at the first constant flow rate.
  • the flow rate of fluid produced from the subterranean well 102 is adjusted to a second constant flow rate for a period of time.
  • the draw down or change in pressure and the temperature along the length of the subterranean well 102 is measured at the second constant flow rate.
  • the flow rate of fluid produced from the subterranean well 102 is adjusted to a third constant flow rate for a period of time.
  • the draw down or change in pressure and the temperature along the length of the subterranean well 102 is measured at the third constant flow rate.
  • the flow rate of fluid produced from the subterranean well 102 may be controlled to produce any number of step flow rate changes in fluid produced from the well 102.
  • the temperature along the length of the subterranean well 102 is measured at each flow rate and the fluid properties at each flow rate are modified according to the temperature and flow rate.
  • the productivity of the subterranean well 102 can be calculated from a plurality of step rate changes in fluid flow rate produced from the well 102.
  • the micro-seismic monitoring system may be used to detect seismicity in the form of the fluid flow noise such as repeated periodic high frequency noise or repeated similar wave form seismic events caused by large pressure drops at fracture nodes.
  • the seismicity can be used to map the propagation of fracture networks 110, 111, 112 within the fractured reservoir 114 during flow-back.
  • the streaming potential or electromagnetic field generated by the treatment fluid during flow-back may also be detected, measured and processed to determine the flow paths and flow characteristics within the fractured reservoir 1 14.
  • the treatment fluid and/or the test fluid produced from the subterranean well 102 are separated into the liquid phase and the gas phase either in an atmospheric separator or a closed pressure separator.
  • the flow rate of the liquid phase and gas phase of treatment fluid and/or test fluid produced from the subterranean well 102 is measured to determine the fluid enthalpy.
  • Fluorescent spectroscopy is used to measure the concentration of reactive tracers and nonreactive tracers within each unique tracer composition produced from each subterranean interval 104, 106, 108 within the fractured reservoir 114.
  • the concentration of reactive tracers and nonreactive tracers may be measured continuously by running a side stream of the treatment fluid and/or test fluid through a pipeline including an inline spectrometer and/or samples may be taken at regular intervals within the subterranean well 102 or at the surface.
  • the concentration of reactive tracers and nonreactive tracers within each unique tracer composition produced from each subterranean interval 104, 106, 108 indicates the flow contribution and the heat exchange area of each fracture network 110, 111, 112 and each subterranean interval 104, 106, 108 within the fractured reservoir 114.
  • the area (A) of a planar fracture is determined with the use of Equation 1 and by inputting the concentration of reactive tracers and nonreactive tracers, the temperature (T out ) at any time (t) within a planar fracture, the average fluid flow rate (q), the fluid heat capacity (C p ), the fluid density (p), the fluid heat transfer coefficient ( ⁇ ), and the fluid thermal density ( ⁇ ) into the numerical reservoir fluid flow model.
  • each fracture network 110, 111, 112 Because a unique tracer composition is injected into each fracture network 110, 111, 112, the relative concentrations of each unique reactive tracer and nonreactive tracers in the total fluid flow rate produced from the subterranean well 102 can be used to determine the flow contribution of each fracture network 110, 111, 112 in the fractured reservoir 114. Therefore, by inputting the parameters described above into the numerical reservoir fluid flow model, the heat exchange area (A) of a plurality of fracture networks 110, 111, 112 and the total heat exchange area of the fractured reservoir 114 may be determined.
  • test data obtained from testing the subterranean formation 100 during stimulation, injection and flow-back including but not limited to, the seismicity within the fractured reservoir 114, the pressure proximate the bottom of the subterranean well 102, the temperature adjacent to the subterranean intervals 104, 106, 108, the flow contribution of the fracture networks 104, 106, 108, the flow rate of fluids produced from the well 102, the concentration of reactive and nonreactive tracers produced from the well 102, and the enthalpy of fluids produced from the well 102 is iteratively compared to theoretical data generated by the numerical reservoir fluid flow model to improve the accuracy of the numerical reservoir fluid flow model.
  • the numerical reservoir fluid flow model simulates the expected behavior of at least a portion of the subterranean formation 100 making up the fractured reservoir 114 by predicting the reservoir heat exchange area, reservoir boundary, reservoir circulating volume, reservoir fluid saturation, reservoir permeability, reservoir porosity (storage phi), reservoir skin effect (near wellbore pressure drop), reactive tracer concentration, nonreactive tracer concentration, combined reservoir compressibility and reservoir thickness.
  • the numerical reservoir fluid flow model may be incorporated in a processor module or a microprocessor run program residing on a computer-readable medium.
  • the numerical reservoir fluid flow model includes an equivalent porous medium representing at least a portion of the subterranean formation 100 including the fractured reservoir 114.
  • the processor module simulates the expected behavior and characteristics of at least a portion of the subterranean formation 100 including the fractured reservoir 114.
  • the test data is iteratively compared to the theoretical data generated by the processor module to improve the accuracy of the numerical reservoir fluid flow model.
  • the processor module comprising the numerical reservoir fluid flow model simulates the expected behavior of at least a portion of the subterranean formation 100 including the fractured reservoir 114 by predicting and outputting theoretical data including the reservoir heat exchange area, reservoir boundary, reservoir circulating volume, reservoir fluid saturation, reservoir permeability, reservoir porosity (storage phi), reservoir skin effect (near wellbore pressure drop), reactive tracer concentration, nonreactive tracer concentration, combined reservoir compressibility and reservoir thickness.
  • the processor module comprising the numerical reservoir fluid flow model may also output the theoretical data in terms of the contribution of each subterranean interval within the fractured reservoir. [0034] FIG.
  • FIG. 2 illustrates a flow chart of an exemplary process for testing a subterranean formation.
  • a subterranean well is drilled in a subterranean formation.
  • treatment fluid is injected into the subterranean formation to stimulate a substantially non-permeable medium within at least a portion of the subterranean formation and to create a fractured reservoir.
  • a tracer composition may be injected into the fractured reservoir as part of the treatment fluid during stimulation at step 201.
  • a micro-seismic event map is generated with the use of a micro-seismic monitoring system by measuring parameters including, but not limited to the seismicity within the fractured reservoir, the polarization of shear seismic waves within the fractured reservoir and/or the streaming potential of treatment fluid injected into the fractured reservoir.
  • the temperature as a function of time along the vertical and/or horizontal length of the subterranean well and the pressure as a function of time proximate the bottom of the subterranean well is measured with a fiber-optic logging tool during stimulation.
  • the tracer composition is injected into the fractured reservoir as part of the treatment fluid during stimulation, the micro-seismic event map of seismic events occurring within the fractured reservoir during stimulation is used to develop an equivalent porous medium representing the fractured reservoir which is incorporated into a numerical reservoir fluid flow model at step 207. If the tracer composition is not injected in the subterranean well as part of the treatment fluid during stimulation, the tracer composition is injected as part of a test fluid at step 204.
  • a micro-seismic event map is generated with the use of a micro- seismic monitoring system by measuring parameters including, but not limited to the seismicity within the fractured reservoir, the polarization of shear seismic waves within the fractured reservoir and/or the streaming potential of test fluid injected into the fractured reservoir.
  • the temperature as a function of time along the vertical and/or horizontal length of the subterranean well and the pressure as a function of time proximate the bottom of the subterranean well is measured with a fiber-optic logging tool during injection of the test fluid.
  • the micro-seismic event map of seismic events occurring within the fractured reservoir during stimulation and/or injection of the test fluid is used to develop an equivalent porous medium representing the fractured reservoir which is incorporated into the numerical reservoir fluid flow model.
  • the subterranean well is shut-in.
  • the pressure of the subterranean well may be monitored during shut-in.
  • the subterranean well is flowed-back and fluids within the fractured reservoir are produced at step 209.
  • the fiber-optic logging tool is lowered into the subterranean well at step 210 to measure the temperature as a function of time along the vertical and/or horizontal length of the well and the pressure as a function of time proximate the bottom of the well.
  • the flow rate of fluid produced from the subterranean well is measured and the concentration of reactive tracers and nonreactive tracers is measured with a fluorescent spectrometer.
  • test data obtained from testing the subterranean formation during stimulation, injection and flow- back including but not limited to, the seismicity within the fractured reservoir, the pressure proximate the bottom of the subterranean well, the temperature along the vertical and/or horizontal length of the well, the flow contribution of a plurality of fracture networks within the fractured reservoir, the flow rate of fluids produced from the well, the concentration of reactive and nonreactive tracers produced from the well, and the enthalpy of fluids produced from the well is iteratively compared to theoretical data generated as output from the numerical reservoir fluid flow model.
  • Example embodiments have been described hereinabove regarding improved systems and methods for testing a subterranean formation. Various modifications to and departures from the disclosed example embodiments will occur to those having ordinary skill in the art. The subject matter that is intended to be within the spirit of this disclosure is set forth in the following claims.

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Abstract

L'invention concerne des systèmes et des procédés pour faire un essai d’une formation souterraine. Selon un mode de réalisation, un procédé comprend la stimulation d'un milieu sensiblement imperméable à l'intérieur d'une formation souterraine pour créer un réservoir fracturé. Au moins un paramètre de stimulation est mesuré pendant une stimulation. Un puits foré dans la formation souterraine est obturé. Un fluide est produit à partir du puits de formation souterraine, et au moins un paramètre de production est mesuré pendant la production. Les paramètres de stimulation et de production sont utilisés dans un modèle d'écoulement de fluide de réservoir numérique, afin d'identifier des paramètres du réservoir fracturé.
PCT/US2009/053304 2008-08-08 2009-08-10 Procédé pour faire un essai d’un système géothermique industriel en utilisant un puits stimulé WO2010017557A1 (fr)

Priority Applications (2)

Application Number Priority Date Filing Date Title
AU2009279407A AU2009279407A1 (en) 2008-08-08 2009-08-10 Method for testing an engineered geothermal system using one stimulated well
EP09791340A EP2334904A1 (fr) 2008-08-08 2009-08-10 Procédé pour faire un essai d un système géothermique industriel en utilisant un puits stimulé

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Application Number Priority Date Filing Date Title
US8735108P 2008-08-08 2008-08-08
US61/087,351 2008-08-08

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WO2010017557A1 true WO2010017557A1 (fr) 2010-02-11

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US (1) US20100032156A1 (fr)
EP (1) EP2334904A1 (fr)
AU (1) AU2009279407A1 (fr)
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WO2017173329A1 (fr) * 2016-04-01 2017-10-05 Board Of Regents Of The Nevada System Of Higher Education, On Behalf Of The University Of Nevada, Reno Systèmes et procédés pour améliorer l'extraction d'énergie de puits géothermiques
CN107829722A (zh) * 2017-10-30 2018-03-23 中国石油大学(华东) 一种深层地热气水两相井底测量装置及数据处理方法

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