EP2639401B1 - Surveillance en temps réel de puits de forage et analyse de contribution de fracture - Google Patents

Surveillance en temps réel de puits de forage et analyse de contribution de fracture Download PDF

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Publication number
EP2639401B1
EP2639401B1 EP13159586.0A EP13159586A EP2639401B1 EP 2639401 B1 EP2639401 B1 EP 2639401B1 EP 13159586 A EP13159586 A EP 13159586A EP 2639401 B1 EP2639401 B1 EP 2639401B1
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Prior art keywords
fractures
fractured intervals
production
time
determining
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German (de)
English (en)
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EP2639401A1 (fr
Inventor
Luis E Gonzalez
Rajan N Chokshi
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Weatherford Technology Holdings LLC
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Weatherford Technology Holdings LLC
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    • 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
    • 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
    • E21B47/00—Survey of boreholes or wells
    • E21B47/10—Locating fluid leaks, intrusions or movements
    • E21B47/103—Locating fluid leaks, intrusions or movements using thermal measurements
    • 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

Definitions

  • Embodiments of the present invention generally relate to hydrocarbon production and, more particularly, to determining the individual contribution of fractured intervals (or fractures) in time.
  • a system for determining production of hydrocarbons comprising:
  • Embodiments of the invention generally relate to allocating production of each of a plurality of fractured intervals (or fractures). This allocation may be performed by combining temperature distribution (and pressure) measurements, a real-time surface multiphase flow measurement, and an inflow model for each fractured interval (or fracture).
  • One embodiment of the invention is a method for determining production of hydrocarbons.
  • the method generally includes determining a temperature distribution associated with a plurality of fractured intervals or fractures disposed along a well; measuring a total flow rate for the well; modeling an inflow rate for each of the plurality of fractured intervals or fractures; and allocating production of each of the plurality of fractured intervals or fractures based on the temperature distribution, the total flow rate, and the inflow rates.
  • the system generally includes a temperature sensing device configured to determine a temperature distribution associated with a plurality of fractured intervals or fractures disposed along a well, a flowmeter configured to measure a total flow rate for the well, and a processing unit.
  • the processing unit is typically configured to model an inflow rate for each of the plurality of fractured intervals or fractures and to allocate production of each of the plurality of fractured intervals or fractures based on the temperature distribution, the total flow rate, and the inflow rates.
  • Yet another embodiment of the invention provides a system for determining production hydrocarbons.
  • the system generally includes means for determining a temperature distribution associated with a plurality of fractured intervals or fractures disposed along a well; means for measuring a total flow rate for the well; means for modeling an inflow rate for each of the plurality of fractured intervals or fractures; and means for allocating production of each of the plurality of fractured intervals or fractures based on the temperature distribution, the total flow rate, and the inflow rates.
  • Embodiments of the invention provide techniques and apparatus for calculating production of each of a plurality of fractured intervals (or fractures) and monitoring changes in the fracture contribution with time. Such real-time monitoring and analysis may be based on a combination of different measurements in the wellbore, on the surface, and from a mathematical model, as described below. In this manner, the industry may be able to understand the behavior of fractures and, in turn, optimize the number of stages ( i.e ., fractured intervals), the number of fractures, and the spacing between fractures and stages.
  • a hydrocarbon production system 100 containing one or more production pipes 102 (also known as production tubing) that may extend downward through a casing 104 to one or more hydrocarbon sources 106 (e.g., reservoirs).
  • An annulus 108 may exist between the pipe 102 and the casing 104.
  • Each production pipe 102 may include one or more lateral sections ( e.g ., created by horizontal drilling) that branch off to access different hydrocarbon sources 106 or different areas of the same hydrocarbon source 106.
  • the fluid mixture may flow from sources 106 to the well completion through the production pipes 102, as indicated by fluid flow 130.
  • the production pipe 102 may include one or more tools 122 for performing various tasks (e.g ., sensing parameters such as pressure or temperature) in, on, or adjacent a pipe or other conduit as the fluid mixtures flow through the production pipes 102.
  • the tools 122 may be any type of downhole device, such as a flow control device (e.g ., a valve), a sensor (e.g ., a pressure, temperature or fluid flow sensor) or other instrument, an actuator ( e.g ., a solenoid), a data storage device ( e.g., a programmable memory), a communication device (e.g., a transmitter or a receiver), etc.
  • a flow control device e.g ., a valve
  • a sensor e.g ., a pressure, temperature or fluid flow sensor
  • an actuator e.g ., a solenoid
  • a data storage device e.g., a programmable memory
  • a communication device e.g.
  • Each tool 122 may be incorporated into an existing section of production pipe 102 or may be incorporated into a specific pipe section that is inserted in line with the production pipe 102.
  • the distributed scheme of tools 122 shown in FIG. 1 may permit an operator of the system 100 to determine, for example, the level of depletion of the hydrocarbon reservoir. This information may permit the operator to monitor and intelligently control production of the hydrocarbon reservoir.
  • microseismic and production logs have helped in the fracture evaluation to determine the drainage volume and fracture inflow.
  • Microseismic can provide useful information on the development of fracture symmetry, half-length, azimuth, width and height, and their dependence on the treatment parameters and reservoir characteristics. Additionally, these fracture geometries in conjunction with other measured or calculated parameters (e.g ., rates, inflow models, etc.) can be used to better understand fracture modeling and production characteristics.
  • Embodiments of the invention provide methods and apparatus to optimize, or at least increase, the production of horizontal fractured wells in shale reservoirs, for example.
  • methods described herein enable the optimization of the number of fractures, the spacing of fractures, and the length of the horizontal section by determining the contribution of the fracture stages (or the fractures) over time.
  • each fracture stage may be calculated in an analogous way to that performed in a traditional field, where the total production rates are allocated to each production well using well testing measurements, done periodically with daily measurement information like wellhead pressure.
  • an acceptable production allocation can be made as a function of time. Because the system is transient, such allocation may be performed on a real-time basis.
  • the idealized system 200 shown in FIG. 2 may be used to model the reservoir.
  • multiple fractures 204, 206 are represented as spaced along and transverse to the horizontal well trajectory 202. Assuming fracturing conditions were the same, the length and width of each fracture in the fracture stage may be considered equal.
  • These parallel fractures are formed in an area ( e . g ., a shale reservoir) with essentially zero permeability (as illustrated in the region 212 unshaded in FIG. 2 ), thereby forming a region 214 of modified permeability (shaded in FIG. 2 ), essentially creating a reservoir where none existed before.
  • N frac any number of fractures
  • five fractures are illustrated in the fracture stage of FIG. 2 (two external fractures 204 and three internal fractures 206) with equal fracture spacing.
  • the fracture stage is defined by confining external boundaries 210.
  • FIG. 2 shows that external fractures 204 are confined by virtual no-flow boundaries 208, which force the external fractures to have the same behavior as the internal fractures 206, and pure linear flow initially occurs. In shale gas reservoirs of nanodarcy permeability, pure linear flow opposite the fracture faces occurs for very long times.
  • SRV Stimulated Reservoir Volume
  • DTS distributed temperature sensing
  • ATS multi-point or array temperature sensing
  • FIG. 3 illustrates a multi-well system 300 in an oil/gas production field, in which hydrocarbon production may be allocated to each of the wells.
  • periodical (e.g., 15 days to weeks or months) production well tests are performed on each individual well, and daily (or in some cases, every few hours) pressure (P) and/or temperature (T) measurements at or near the wellhead 302 of each well are registered.
  • the produced fluids from each well may be collected at a manifold and then separated by a separator 310 into oil, gas, and water.
  • Daily (or in some cases, every few hours or minutes) total flow rates of oil (Qo), gas (Qg), and water (Qw) may be measured.
  • the well performance (P vs. Q relation) for each well at the wellhead 302 is calculated. The use of this wellhead performance with frequent wellhead pressure measurements allows the flow rates of each individual well to be determined.
  • an allocation factor (K) is found using the relationship between the total flow rate (Qt) measured and the sum of the individual well flow rates ( ⁇ Qi) and may be subsequently used.
  • FIG. 4 illustrates a system 400 for allocating hydrocarbon produced from a horizontal well with multiple fractured intervals 402 along a horizontal well, in accordance with an embodiment of the invention. Although seven fractured intervals 402, each with five fractures 404, are shown in FIG. 4 , any number of fractured intervals and any number of fractures per interval may be used.
  • the system 400 also includes a multiphase real-time flowmeter 406 and a DTS cable 408 disposed downhole.
  • the system may also include one or more sensors 410 for measuring pressure (P) and/or temperature (T), which may be disposed anywhere in the wellbore, such as in the vertical section as shown.
  • P pressure
  • T temperature
  • the multiphase flowmeter 406 may be installed at or adjacent the wellhead or within the well bore and, for some embodiments, may be an optical flowmeter ( e . g ., an optical downhole flowmeter).
  • the DTS cable 408 may be installed adjacent the casing 104, as shown in FIG. 4 .
  • each stage (i . e ., fractured interval 402) in FIG. 4 is akin to a producing well.
  • the variation of temperature and a transient inflow model it is possible to calculate the production of each stage at any time. In fact, if the temperature variation is high enough to distinguish between fractures 404, it may also be possible to allocate the production of each particular fracture.
  • each stage or fracture may be considered as an individual contributor to production
  • the main characteristics of the fractures e.g., length and width
  • the inflow rate of each fracture will be computed by an analytical transient model and combined with the change in temperature (as determined by the DTS cable 408, for example) at each stage referenced to an initial condition prior to fracturing.
  • Qt total flow rate measured by the multiphase flowmeter 406
  • FIG. 5 is a flow diagram of example operations 500 for determining the contribution to hydrocarbon production of each fractured interval (or each fracture).
  • the operations 500 may begin, at 502, by determining a temperature distribution associated with a plurality of fractured intervals or fractures disposed along a well.
  • the temperature distribution may be determined by performing at least one of distributed temperature sensing (DTS) or array temperature sensing (ATS).
  • DTS distributed temperature sensing
  • ATS array temperature sensing
  • the plurality of fractured intervals or fractures may be located in a shale reservoir, for example.
  • a total flow rate of a fluid (or any combination of fluids) produced by the well is measured.
  • the total flow rate may be a total gas flow rate or a total oil flow rate, for example.
  • the total flow rate may be measured using a flowmeter disposed at the surface.
  • the flowmeter may be disposed at or adjacent a wellhead of the well.
  • An inflow rate is modeled at 506 for each of the plurality of fractured intervals or fractures.
  • the inflow rate may be an inflow gas rate or an inflow oil rate, for example.
  • allocating the production at 508 may include: (1) determining a first temperature value T 0 at a first time t 0 ( e . g ., before production starts) for each of the plurality of fractured intervals or fractures; (2) determining a second temperature value T n at a second time t n ( e .
  • the operations 500 may also include repeating the determining at 502, the measuring at 504, and the modeling at 506 within a period short enough to observe transient behavior of the plurality of fractured intervals or fractures.
  • the determining, measuring, and/or modeling described above may be performed and repeated with any desired frequency (at any desired rate or periodicity).
  • the determining, measuring, and/or modeling may be performed continuously, hourly, daily, weekly, or with other frequencies.
  • the operations 500 may also include determining one or more pressure measurements for the well.
  • allocation of the production at 508 may also be based on the pressure measurements.
  • the pressure measurements may be made by one or more pressure sensors located downhole, along the horizontal or vertical portion of the wellbore.
  • the pressure sensors may be optical-based pressure sensors having one or more fiber Bragg gratings (FBGs) located therein.
  • FBGs fiber Bragg gratings
  • FIG. 6 illustrates a workflow 600 for identifying and calculating the contribution of each fractured interval (or fracture), in accordance with an embodiment of the invention.
  • the workflow 600 can be easily expanded to production allocation for each fracture, as long as the temperature variation is high enough to distinguish between fractures.
  • the DTS (or ATS) data 602 is related to the geothermal gradient value for each stage 402.
  • the cable 408 may be sampled with some periodicity to generate the data 602, leading to temperature measurements at certain sampling times (t n ).
  • the delta temperature ( ⁇ T) between the temperature at the sampling time and at time t 0 is calculated for each stage 402.
  • the ⁇ T values for each stage are divided by Tg to normalize the data.
  • pressure measurements e . g ., taken by the sensors 410) may be used to ensure accuracy of the ⁇ T values for each stage ( e . g ., by correlation with the temperature measurements).
  • a ratio (( ⁇ T/Tg)/( ⁇ T/Tg)max) for the sampling time (t n ) is calculated for each stage 402.
  • the ratio for each stage is calculated by dividing the Tg-normalized ⁇ T value for this particular stage by the maximum Tg-normalized ⁇ T value over all previous times for this stage.
  • the ⁇ T value at time to is initially assumed to be the maximum Tg-normalized ⁇ T value, so the ratio in this case will be 1.
  • the maximum ⁇ T value is stored for later validation of this assumption.
  • inflow transient models are run to generate inflow rates for each stage 402 (indexed by "i").
  • the workflow 600 of FIG. 6 generates inflow gas rates for each stage (Qgfi), but inflow oil rates or both may also be used.
  • the inflow transient models either produce the inflow rates at the sampling time (t n ) as shown at 610, or interpolation or other techniques are used to determine inflow rates at the sampling time based on inflow rates produced for other times.
  • the ratio at the sampling time (t n ) for each stage calculated at 606 is multiplied with the modeled inflow rate for each stage from 610 corresponding to the sampling time.
  • surface multiphase measurements may be made at 614, for example, by the flowmeter 406, to generate one or more total flow rates (Qg, Qo, and/or Qw) for the well.
  • the total flow rates may either be generated at the sampling time (t n ) as shown at 616, or interpolation or other techniques may be used to determine the total flow rates at sampling time based on measurements taken at other times.
  • results of the multiplications at 612 for each of the stages 402 at the sampling time (t n ) may be summed ( ⁇ Q'gfi). At 618, this sum may be compared to the total gas flow rate (Qg) corresponding to the sampling time (t n ).
  • the ratio for each stage 402 calculated at 606 is multiplied by the Qgfi at t 0 for each stage at 612, and the sum of all Qgfi values is compared to the Qg corresponding to to at 618.
  • the value of ⁇ T 1 will be compared to the value of ⁇ T 0 . If ⁇ T 1 is bigger, then a new maximum value is obtained.
  • This new maximum value replaces the previous value, and in this case the contribution of this particular stage will be 100% during this period of time, and the assumption on the previous time step was wrong. A new calculation for to will be performed to correct the first assumption and similarly at any time that a new maximum value is found.
  • the workflow 600 operating on a "real-time" basis, will increase well productivity, helping to determine what is the optimal choke size to flow back the well and to have all fractures contributing (or to find out which fractures do not contribute at all).
  • a normalized graph of production versus a number of contributing stages and/or fractures can be obtained and, based on these results, an optimal number of stages and/or fractures may be determined.
  • a good relationship is expected of production versus number of contributing fractures, more consistent than the plot 700 of gas production versus number of contributing fractures shown in FIG. 7 (from Modeland N.
  • DTS distributed temperature sensing
  • ATS multi-point or array temperature sensing

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  • General Life Sciences & Earth Sciences (AREA)
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Claims (13)

  1. Procédé (500) permettant de déterminer une production d'hydrocarbure, comprenant les étapes consistant à :
    déterminer (502) une distribution de température associée à une pluralité d'intervalles fracturés ou de fractures agencées le long d'un puits ;
    mesurer (504) un débit total pour ledit puits ;
    modéliser (506) un débit entrant pour chacun parmi la pluralité d'intervalles fracturés ou de fractures ; et
    affecter (508) une production de chacun parmi la pluralité d'intervalles fracturés ou de fractures en se basant sur la distribution de température, le débit total, et les débits entrants.
  2. Procédé selon la revendication 1, comprenant en outre une étape consistant à répéter (510) les étapes de détermination, de mesure, et de modélisation au sein d'une période suffisamment courte pour observer un comportement transitoire de la pluralité d'intervalles fracturés ou de fractures.
  3. Procédé selon la revendication 1 ou 2, dans lequel l'étape de mesure comprend une étape consistant à mesurer le débit total en utilisant un débitmètre multiphase (406).
  4. Procédé selon la revendication 1, 2 ou 3, dans lequel au moins une étape parmi les étapes de détermination, de mesure, ou de modélisation est mise en oeuvre quotidiennement.
  5. Procédé selon la revendication 1, 2, 3 ou 4, dans lequel au moins une étape parmi les étapes de détermination, de mesure, ou de modélisation est mise en oeuvre de manière continue.
  6. Système (400) permettant de déterminer une production d'hydrocarbures, comprenant :
    un dispositif de détection de température (410) configuré pour déterminer une distribution de température associée à une pluralité d'intervalles fracturés (402) ou de fractures agencés le long d'un puits ;
    un débitmètre (406) configuré pour mesurer un débit total pour ledit puits ; et
    une unité de traitement configurée pour :
    modéliser un débit entrant pour chacun parmi la pluralité d'intervalles fracturés ou de fractures ; et
    affecter une production de chacun parmi une pluralité d'intervalles fracturés ou de fractures en se basant sur la distribution de température, le débit total, et les débits entrants.
  7. Procédé selon l'une quelconque des revendications 1 à 5, ou système selon la revendication 6, dans lequel la pluralité d'intervalles fracturés ou de fractures est située dans un réservoir de schiste.
  8. Procédé selon l'une quelconque des revendications 1 à 5, ou selon la revendication 7, comprenant en outre une étape consistant à déterminer une ou plusieurs mesure(s) de pression pour ledit puits, dans lequel l'étape d'affectation de la production est en outre basée sur les mesures de pression, ou système selon la revendication 6 ou 7, comprenant en outre un capteur de pression configuré pour déterminer une ou plusieurs mesure(s) de pression pour ledit puits, dans lequel l'unité de traitement est configurée pour affecter la production en se basant en outre sur les mesures de pression.
  9. Procédé selon l'une quelconque des revendications 1 à 5, ou selon la revendication 7 ou 8, dans lequel l'étape d'affectation de la production comprend les étapes consistant à, ou système selon la revendication 6, 7 ou 8, dans lequel l'unité de traitement est configurée pour affecter la production grâce aux étapes consistant à :
    déterminer une première valeur de température à un premier instant pour chacun parmi la pluralité d'intervalles fracturés ou de fractures ;
    déterminer une deuxième valeur de température à un deuxième instant pour chacun parmi la pluralité d'intervalles fracturés ou de fractures ;
    calculer une valeur delta de température pour le deuxième instant pour chacun parmi la pluralité d'intervalles fracturés ou de fractures grâce à une étape consistant à déterminer une différence entre les première et deuxième valeurs de température pour chacun parmi la pluralité d'intervalles fracturés ou de fractures ;
    calculer un premier rapport constitué de la valeur delta de température pour le deuxième instant pour chacun parmi la pluralité d'intervalles fracturés ou de fractures sur une température géothermique ;
    comparer le premier rapport pour le deuxième instant à une valeur maximale du premier rapport sur tous les instants précédents pour chacun parmi la pluralité d'intervalles fracturés ou de fractures ;
    pour chacun parmi la pluralité d'intervalles fracturés ou de fractures, designer le premier rapport pour le deuxième instant en tant que valeur maximale du premier rapport sur tous les instants précédents si le premier rapport pour le deuxième instant est supérieur à une valeur maximale précédemment désignée ;
    pour chacun parmi la pluralité d'intervalles fracturés ou de fractures, calculer un deuxième rapport constitué du premier rapport pour le deuxième instant sur une valeur maximale, actuellement désignée, du premier rapport sur tous les instants précédents ;
    multiplier le deuxième rapport pour le deuxième instant par le débit entrant modélisé correspondant au deuxième instant pour chacun parmi la pluralité d'intervalles fracturés ou de fractures ;
    additionner des résultats de la multiplication pour chacun parmi la pluralité d'intervalles fracturés ou de fractures ; et
    déterminer un facteur d'affectation grâce à l'étape consistant à diviser le débit total mesuré correspondant au deuxième instant par ladite somme.
  10. Procédé selon la revendication 9, dans lequel le premier instant survient avant que les hydrocarbures soient produits.
  11. Procédé selon la revendication 9 ou 10, comprenant en outre une étape consistant à appliquer le facteur d'affectation au débit entrant modélisé pour chacun parmi la pluralité d'intervalles fracturés ou de fractures, ou système selon la revendication 9, dans lequel l'unité de traitement est en outre configurée pour appliquer le facteur d'affectation au débit entrant modélisé pour chacun parmi la pluralité d'intervalles fracturés ou de fractures.
  12. Procédé selon l'une quelconque des revendications 1 à 5, ou 7 à 11, dans lequel l'étape de détermination de la distribution de température comprend une étape consistant à mettre en oeuvre au moins une parmi une détection de température distribuée (DTS) ou une détection de température en réseau (ATS), ou système selon l'une quelconque des revendications 6 à 9, ou 11, dans lequel le dispositif de détection de température comprend un dispositif de détection de température distribuée (DTS) ou un dispositif de détection de température en réseau (ATS).
  13. Procédé selon l'une quelconque des revendications 1 à 5, ou 7 à 12, ou système selon l'une quelconque des revendications 6 à 9, ou 11 ou 12, dans lequel le débit total comprend un débit de gaz total et dans lequel les débits entrants comprennent des débits de gaz entrants.
EP13159586.0A 2012-03-16 2013-03-15 Surveillance en temps réel de puits de forage et analyse de contribution de fracture Active EP2639401B1 (fr)

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CA2808858A1 (fr) 2013-09-16
EP2639401A1 (fr) 2013-09-18
BR102013006266A2 (pt) 2015-07-07
AU2013201757A1 (en) 2013-10-03
BR102013006266A8 (pt) 2017-07-11
AU2013201757B2 (en) 2015-10-22
CA2808858C (fr) 2016-01-26
CN103306664A (zh) 2013-09-18
BR102013006266B1 (pt) 2021-02-17
AR090353A1 (es) 2014-11-05
US20130245953A1 (en) 2013-09-19

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