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WO2008152599A2 - Interprétation en boucle fermée en temps réel de systèmes et de procédés de traitement de tuyauterie - Google Patents

Interprétation en boucle fermée en temps réel de systèmes et de procédés de traitement de tuyauterie Download PDF

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Publication number
WO2008152599A2
WO2008152599A2 PCT/IB2008/052318 IB2008052318W WO2008152599A2 WO 2008152599 A2 WO2008152599 A2 WO 2008152599A2 IB 2008052318 W IB2008052318 W IB 2008052318W WO 2008152599 A2 WO2008152599 A2 WO 2008152599A2
Authority
WO
WIPO (PCT)
Prior art keywords
downhole
recited
real time
fluid
control system
Prior art date
Legal status (The legal status 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 status listed.)
Ceased
Application number
PCT/IB2008/052318
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English (en)
Other versions
WO2008152599A3 (fr
Inventor
Hubertus V. Thomeer
Rex Burgos
Xiaowei Weng
Moussa Kane
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Schlumberger Canada Ltd
Services Petroliers Schlumberger SA
Schlumberger Technology BV
Schlumberger Holdings Ltd
Prad Research and Development Ltd
Original Assignee
Schlumberger Canada Ltd
Services Petroliers Schlumberger SA
Schlumberger Technology BV
Schlumberger Holdings Ltd
Prad Research and Development Ltd
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 Schlumberger Canada Ltd, Services Petroliers Schlumberger SA, Schlumberger Technology BV, Schlumberger Holdings Ltd, Prad Research and Development Ltd filed Critical Schlumberger Canada Ltd
Priority to EP08763308A priority Critical patent/EP2153025A2/fr
Priority to EA201070005A priority patent/EA022992B1/ru
Priority to CA2687892A priority patent/CA2687892C/fr
Priority to MX2009013108A priority patent/MX2009013108A/es
Publication of WO2008152599A2 publication Critical patent/WO2008152599A2/fr
Publication of WO2008152599A3 publication Critical patent/WO2008152599A3/fr
Priority to EG2009111716A priority patent/EG27115A/xx
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

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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
    • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
    • 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
    • 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
    • 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

Definitions

  • a variety of systems and methods are used for making downhole measurements related to well treatment operations. Downhole measurements are made and the data is conveyed upwardly via fluid pulse signals, electromagnetic wireless signals, or hardwired electric signals. The measurements can be used to determine an event or downhole property/measurement, but existing systems and methods are limited in their ability to provide an operator with a comprehensive understanding of the downhole event/environment. Additionally, the measurements generally are typically performed for a single event. [0003] Furthermore, existing systems and methods fail to enable sufficient control of downhole conditions and/or events. Surface measurements must be correlated with downhole measurements before an action can be taken. No continuous feedback loop is provided to enable real time decisions, and substantial dependence on operator input is required to achieve a desired output and/or event downhole. The existing systems are not well-suited for use at the surface in a manner that enables synchronization and rapid adjustment in response to events happening in the well. These limitations reduce downhole efficiency and/or reservoir optimization.
  • the present invention provides a system and method for treating a subterranean formation.
  • the system and method utilize a fluid delivery apparatus that comprises a continuous feedback system utilizing a real time closed loop interpretation technique to instantaneously synchronize and adjust actions at a well site surface relative to measured downhole events.
  • Sensors are used to monitor at least one downhole property/measurement, in real time. Based on the real time data from surface and downhole, adjustments can be made to manage and to influence a downhole event or environment.
  • Figure 1 is a schematic front elevation view of a well treatment system positioned to deploy a fluid to a well formation, according to an embodiment of the present invention
  • Figure 2 is a graphical representation of real time data output from a subterranean location in a form that can be displayed via a graphical user interface, according to an embodiment of the present invention
  • Figure 3 is a schematic front elevation view of another example of a well treatment system positioned to obtain data in multiple well zones, according to an embodiment of the present invention
  • Figure 4 is another example of a displayed output based on data obtained from a downhole location, according to an embodiment of the present invention.
  • Figure 5 is another example of a graphical user interface for providing information and enabling operator input, according to an embodiment of the present invention.
  • Figure 6 is another example of a graphical user interface for providing information and enabling operator input, according to an embodiment of the present invention.
  • Figure 7 is another example of a graphical user interface for providing information based on downhole data, according to an embodiment of the present invention.
  • Figure 8 is another example of a graphical user interface for providing information and enabling operator input, according to an embodiment of the present invention.
  • Figure 9 is a graph illustrating pressure versus true vertical depth during a run-in-hole, according to an alternate embodiment of the present invention.
  • Figure 10 is an illustration similar to that of Figure 9;
  • Figure 11 is a schematic front elevation view of a well treatment system being run-in-hole and the resultant change in fluid level, according to an embodiment of the present invention
  • Figure 12 is a graph illustrating true vertical depth, pressure and gradient versus time, according to an embodiment of the present invention.
  • Figure 13 is another example of a graphical user interface for providing information and enabling operator input, according to an embodiment of the present invention.
  • Figure 14 illustrates a matrix that can be utilized to determine the level of risk associated with a given well treatment operation, according to an embodiment of the present invention
  • Figure 15 illustrates another matrix that can be utilized to determine the level of risk associated with a given well treatment operation, according to an embodiment of the present invention
  • Figure 16 illustrates another matrix that can be utilized to determine the level of risk associated with a given well treatment operation, according to an embodiment of the present invention
  • Figure 17 illustrates another matrix that can be utilized to determine the level of risk associated with a given well treatment operation, according to an embodiment of the present invention.
  • Figure 18 is another example of a graphical user interface for providing information and enabling operator input, according to an embodiment of the present invention.
  • the present invention generally relates to a system and method for closed loop interpretation during fluid treatment of a subterranean reservoir using a fluid delivery apparatus including a tubing string that may be formed of coiled tubing.
  • the system and method relate to a real time closed loop interpretation method for coiled tubing services to synchronize and adjust actions at the surface with events happening downhole to improve downhole efficiency and/or reservoir optimization.
  • the improvements in downhole efficiency and reservoir optimization can result from improved pressure management, load management, downhole tool management, reservoir management, and/or management of other aspects of the fluid treatment operation.
  • the system and methodology provide solutions to a need for control over the operation by enabling synchronization and adjustment of actions at the surface relative to prior, current, or future downhole events through real time closed loop interpretation of subterranean treatments.
  • the real time control technique can be used in relationship to one or more downhole events.
  • detection and adjustment in real time of downhole events related to pressure management may include making adjustments related to stuck potential, diversion indicators, stimulation indicators, staying on target (over and under a set downhole pressure), and treatment fluid nozzle efficiency.
  • Adjustment of the downhole event also may relate to load management and include downhole events related to weight on downhole tools and real time extended reach control.
  • Detection and control also can be related to downhole tool management and include control of downhole devices that are sensitive to pressure differentials, spikes, changes in slope (increasing, flat or decreasing), and compressive, tensile or torsional forces.
  • the detection and control also can be related to reservoir management and include downhole events characterized as injectivity profiles, placement of treatment fluids, location and volume characterization of deposited scale in the tubulars and reservoir, testing reservoir properties (e.g. capacity, deliverability), and characterization, predicting and identifying injection profiles.
  • downhole events characterized as injectivity profiles, placement of treatment fluids, location and volume characterization of deposited scale in the tubulars and reservoir, testing reservoir properties (e.g. capacity, deliverability), and characterization, predicting and identifying injection profiles.
  • novel systems and methodology utilize real time closed loop interpretation for subterranean treatment services that provide distinct advantages and benefits.
  • the advantages and benefits arise come at least in part, from the ability to predict the dynamic behaviors and/or events both at the surface and downhole, to provide feedback related to the downhole events or control of those events, and to control or adjust the downhole events.
  • the control system enables monitoring of one or more properties that can be used in exercising control over multiple downhole events.
  • the detection and control of the specific downhole events are enabled based on monitoring and evaluation of properties, such as pressure, load, velocity, and other indicative properties, with data available both downhole and at a surface location.
  • real time closed loop interpretation is used with coiled tubing systems and methods to predict a desired output for a desired a downhole event.
  • Downhole properties are measured, and the measurements are sent to the surface as feedback.
  • the feedback is used by a control system that can change the properties downhole and affect the downhole event. Values can be input into the control system to affect control over the downhole event as desired by a well operator.
  • downhole properties may be measured, and the measurement data can be evaluated with a suitable control device located within the wellbore.
  • the control device can be used to monitor feedback and to influence or control the downhole event based on the feedback information.
  • the monitoring and evaluation can be accomplished by a combined surface control system and downhole control system.
  • the techniques for monitoring downhole properties and controlling downhole events in treatment operations are amenable for use with coiled tubing services and systems, but they also can be used with other suitable formation treatment techniques and equipment.
  • the system and methodology is useful for real time closed loop interpretation of coiled tubing services that involve characterizing an event, determining the trajectory, estimating the likelihood and potential severity of an occurrence of a specific downhole event, and displaying the information to an operator.
  • the technique also can be used to optimize a service plan by first selecting an initial plan, determining the likelihood and severity of a downhole event, adjusting a parameter of the initial plan, reevaluating the likelihood and severity of the downhole event, and then repeating the process of adjusting and reevaluating as desired.
  • the technique also can be used to provide a real time closed loop interpretation of coiled tubing services involving predicting in real time the tendency toward an event by acquiring both surface and downhole data. The data is used to determine and predict the ensuing operations and treatment outcome tendencies with closed loop calculations.
  • the system and methodology can be used to provide a real time closed loop interpretation of coiled tubing services involving a system for warning of coiled tubing/pipe sticking by monitoring downhole and surface data. Ongoing data can be obtained and compared for differences. If sufficient differences arise, an alarm can be raised to indicate the onset of a downhole event due to changing parameters. The alarm enables intervention by an operator or automatic intervention by a control system able to take remedial action.
  • the technique also can be used to provide real time closed loop interpretation of coiled tubing services involving a method for determining one or more properties of a well treatment related event or plan by estimating the properties at one position in the wellbore and then at a second position. After estimating the properties, the well is flowed, and the measurements are repeated at the first and second positions. This process can be repeated as necessary to enable the verification of baselines and to make the necessary changes as baselines change. In some embodiments, the data from repeated measurements at the first and second positions is transmitted to the surface and recorded for determination of flow properties.
  • a well treatment system 20 is illustrated as deployed for use in a real time closed loop interpretation of tubing services, e.g. coiled tubing services.
  • the system provides the ability to predict the dynamic behaviors/events both at the surface and downhole and to exercise control over downhole events based on feedback.
  • the feedback can be gained by measuring and evaluating downhole properties, such as pressure, load, velocity, and other suitable properties. These properties can be measured both downhole and at the surface.
  • well treatment system 20 may comprise or be in the form of a fluid delivery system or apparatus comprising a continuous feedback system 22 that utilizes a real time closed loop interpretation technique to instantaneously synchronize and adjust actions at the surface relative to measured downhole events.
  • the continuous feedback system 22 comprises a well treatment tubing string 24 deployed in a wellbore 26, a sensor system 28, and a control system 30 that may comprise a data acquisition, analysis and control system.
  • Well treatment tubing string 24 comprises a treatment tool 32 deployed downhole to a desired location in wellbore 26 proximate a surrounding subterranean formation 34 that is to be treated.
  • Treatment tool 32 is conveyed through wellbore 26 via a tubing 36, such as coiled tubing, that is conveyed downhole from suitable surface equipment 38 positioned at a surface location 40.
  • Surface equipment 38 may comprise a coiled tubing rig designed to selectively deliver coiled tubing downhole and withdraw the coiled tubing and treatment tool 32.
  • a treatment fluid is pumped downhole by suitable pumping equipment 42 that also may be positioned at surface location 40.
  • Control system 30 also may be coupled to pumping equipment 42 to control delivery of treatment fluid based on monitored properties, and thereby influence/control downhole events.
  • the treatment fluid is flowed down through tubing 36 and out through treatment tool 32, as represented by arrows 44. From treatment tool 32, the treatment fluid is forced outwardly into formation 34 through, for example, perforations 46 formed in a well casing 48.
  • the treatment fluid and the configuration of treatment tool 32 can vary depending on the specific treatment operation and the environment in which the operation is conducted.
  • Sensor system 28 can be used to detect, in real time, at least one downhole property or measurement that can be used as an indicator for at least one downhole item, e.g. an event or an environment.
  • sensor system 28 may have a plurality of sensors 50 comprising, for example, one or more pressure sensors, temperature sensors, load sensors, casing collar locator sensors, fluid characteristic sensors, e.g. fluid velocity sensors, acoustic sensors, infrared sensors, optical sensors, flow sensors, and other types of sensors designed to detect and monitor one or more properties that can be used as an indicator of a downhole event.
  • changes in the property/measurement can be an indication of the future occurrence, the current occurrence or the past occurrence of a downhole item of interest, such as an event or an environment.
  • Sensors 50 also can be positioned at other locations, such as surface locations to provide, for example, comparison data that can be used for comparing, calibrating, or verifying downhole data.
  • Control system 30 may have a variety of forms and may be located in whole or in part at the well site/surface location 40 or at remote locations. Additionally, control system 30 may be a processor based control system, such as a computer control system in which data from sensor system 28 is processed on one or more computers. Control system 30 also can be automated to automatically provide predetermined control signals based on the real time detection of the at least one downhole property/measurement. For example, changes in the downhole property/measurement may cause control system 30 to take an automated control action to change the downhole property/measurement and to thereby influence and/or control a downhole event or environment.
  • sensor system 28 communicates with control system 30 via one or more control lines 52.
  • the control line 52 may comprise a wired control line, a wireless control line, or combinations of wired and wireless segments for conveying signals from sensors 50 to control system 30 in real time.
  • the control system 30 may comprise a plurality of input/output units 54, and at least one or more of the units 54 may comprise computers 56 for processing and analyzing data received from sensor system 28 in real time.
  • a variety of software programs can be loaded on the computer or computers 56 depending on the downhole property/measurement being monitored. Additionally, a plurality of the computers 56 can be used in cooperation by processing certain data on one computer and other data on another computer.
  • each unit 54 may comprise a display 58, to display information to an operator, and an input device 60, such as a keypad or touchscreen, to enable the operator to input information.
  • the displays 58 can be used to provide a graphical user interface 62 for displaying information and for prompting the operator to input detection, analysis, and control related information.
  • a variety of other components can be used to convey and evaluate data.
  • a router or other suitable equipment 64 can be used to disseminate information to a plurality of units 54.
  • a variety of transmitters and receivers 66 can be used to receive and transmit from, for example, a remotely located computer.
  • the continuous feedback system 22 can be used in a variety of applications for sensing many types of properties that facilitate the control of many types of potential downhole events.
  • the measured downhole property/measurement may comprise pressure, load, fluid velocity, fluid direction, temperature, fluid pH, fluid solids content, fluid density, and other properties.
  • Individual properties or combinations of properties can be detected and used as an indicator of specific downhole events and/or environments. Examples of such downhole events include stuck potential, diversion, stimulation, over/under balance, nozzle efficiency, downhole tool load, real time extended reach, pressure differential, pressure spikes, changes in measurement over time slope (increasing, flat or decreasing), injectivity profile, fluid placement, volume characterization of deposited scale, and a variety of reservoir properties.
  • pressure management can be achieved by obtaining data from one or more of the downhole sensors 50.
  • the control system 30 serves as an acquisition and analysis system and also displays various information and indicators to an operator via one or more displays 58.
  • the control system can be used to provide a real time indicator based on changes in a downhole pressure measurement and/or changes in other measurements, such as temperature or casing collar locator measurements.
  • Information can be displayed via displays 58 in a variety of formats, including a horizontal time log 68, as illustrated in Figure 2.
  • control system 30 creates a time based horizontal log and can perform a variety of operations on the time log, including annotations, printing, scale changes, add/delete tracks, or multiple time log windows.
  • specific channels can be selected for display on horizontal time log 68 from a predetermined list of channels available or downloaded on the control system 30.
  • the list also can include calculated channels, such as foam quality, calculated bottom hole pressure, and derivative temperature.
  • graph lines 70 illustrate display channels representative of foam quality measurements or of a variety of other downhole property measurements.
  • the time based log can be used to display selected threshold values, as referenced by graph lines 72. The selected threshold values can be entered by an operator via graphical user interface 62 or via another suitable input device.
  • foam quality suitable threshold values are selected, e.g. foam quality limits at 60% to 70%, and those values are displayed via graph lines 72.
  • the foam quality is determined by control system 30 based on pressure and temperature measurements relayed from downhole sensors 50 in real time.
  • the foam quality values are calculated by control system 30 and displayed.
  • control system 30 can be used to provide an API Logs template on which the calculated values are displayed as API logs.
  • An operator can enter the boundary values (see graph lines 72) to provide an indication of the suitable range for calculated foam quality values. Movement of the foam quality values outside of the boundaries is an indicator of a downhole event requiring changes to the treatment operation.
  • Control system 30 can be used to influence or control the foam quality by changing aspects of the well treatment operation.
  • An additional example of a downhole property that can be used as an indicator of a specific downhole event is estimated bottom hole pressure at formation depth while acquisition is running.
  • the calculation is based on the following parameters: bottom hole pressure measurement obtained from the downhole sensors 50; true vertical depth (TVD) where bottom hole pressure (iBHP) is based on the coiled tubing depth and the trajectory information entered as borehole surveys; TVD of the location where bottom hole pressure is calculated, based on the measured depth entered by user and trajectory information; and density of the fluid below the tool.
  • TVD true vertical depth
  • iBHP bottom hole pressure
  • cBHP iCTBHP + w * ⁇ cDepth d - ctDepth d )
  • Calculated bottom hole pressure can be monitored versus formation pressure and fracturing pressure, which can be entered into control system 30 by an operator.
  • the calculated bottom hole pressure, formation pressure, and fracturing pressure also can be displayed on horizontal time log 68.
  • the calculated bottom hole pressure can be determined for a plurality of well zones 74 in which each zone has its own depth, fracturing pressure and formation pressure. Again, the appropriate values for each of these well zones 74 can be entered into control system 30.
  • Downhole properties/measurements also can provide an under balance/overbalance indicator in real time.
  • the measured downhole property may comprise pressure which is monitored by a suitable downhole sensor 50 and transmitted to the surface data acquisition, analysis and control system 30.
  • the measurement can be used to predict bottom hole pressure (cBHP) at formation depth in different zones. Differences in the bottom hole calculation can arise from differences in fluid density. Accordingly, an operator can select different fluids, and thus different fluid densities, for each well zone 74 to enable independent pressure calculations in each well zone 74. Fluid types can be entered by the operator via graphical user interface 62 or another suitable input device. The calculated bottom hole pressure is used, along with formation properties, to provide indicators to the operator regarding the pressure condition at defined well zones. In this example, pore pressure can be entered as well as the fracturing pressure for each zone. Control system 30 is then able to create different pressure intervals that are indicative of specific downhole events relative to the under balance/over balance condition of the well.
  • cBHP bottom hole pressure
  • FIG. 4 provides minimum and maximum pressure conditions for a plurality of listed downhole events 76.
  • pressure balance ranges can be provided for under balanced, balanced, overbalanced, fracture warning, and fracture conditions.
  • the interface 62 provides an indicator 78 that points to selected downhole conditions, e.g. under balance/over balance conditions, as represented by pressure segments 80.
  • the pressure segments 80 may correspond with ranges for predicting downhole events 76.
  • a bar graph section 82 is used to illustrate a history of the wellbore condition according to colored indicators that match the color of pressure segments 80.
  • the graphical user interface 62 provides an input 84 for starting and/or stopping the monitoring of specific well zones.
  • a fluid selection window 86 also enables the selection of fluid for use in making bottom hole pressure calculations at each well zone, as described above.
  • a zone property input 88 can be used to select or change a variety of values used to characterize a specific reservoir or interval.
  • a display area 90 also can be used to display a variety of additional information, such as the depth of specific well zones.
  • Similar interfaces can be displayed simultaneously on one or more of the graphical user interfaces 62.
  • interfaces are displayed for four different well zones, although the number of interfaces displayed can be greater or lesser depending on the treatment application and the number of well zones.
  • each interface provides an under balanced/over balanced indicator for each zone, however multiple interfaces can be provided to indicate the occurrence of other or additional downhole events.
  • Pressure and/or other downhole properties can be monitored and analyzed as an indicator of the level of differential pressure between the inside and outside of coiled tubing 36.
  • Sensors 50 comprise pressure sensors that are capable of measuring the pressure inside and outside of the coiled tubing 36 which can serve as predictive indicators of downhole events related to use of the coiled tubing.
  • control system 30 uses the ratings to create a plurality of intervals/downhole events 92, as illustrated in Figure 7.
  • the intervals 92 are displayed with associated color coding.
  • the plurality of intervals 92 are established for differential pressure states related to the coiled tubing 36 and may include collapse, near collapse, low pressure, operating pressure, high pressure, and burst states as well as additional states.
  • a variety of graphical user interfaces 62 also can be used.
  • One example of a suitable graphical user interface 62 is illustrated in Figure 8 and includes a scale 94 having a plurality of color-coded markers 96 indicating the differential pressure levels for the various differential pressure states.
  • the graphical user interface 62 comprises a variety of inputs 98 that can be used to enter values for pressure ratings and pressure intervals.
  • a variety of additional displays, inputs, and screens can be incorporated into the illustrated interface.
  • FIG. 30 Another example of a downhole event that can be detected in real time based on monitoring of one or more downhole properties involves static bottom hole pressure.
  • wellbore fluid density and pore pressure formation pressure
  • Control system 30 can provide a facility and procedure to estimate these values to prevent false user entries. If the well condition prior to the well treatment is such that a steady fluid column has been established, e.g. after a period of shut-in, the formation pressure is equal to the static bottom hole pressure, which can be determined by the fluid level and the wellbore fluid density.
  • Wellbore fluid density can be estimated at the start of the job as the coiled tubing is run-in-hole by using the bottom hole pressure measurement from an appropriate sensor 50 on treatment tool 32.
  • an operator can enter the liquid level (TVDo) into control system 30, and then enter/select whether or not the well is to be topped off with liquid.
  • the control system 30 is designed to compute and plot the gradient (Gr) while running- in-hole when there is no pumping or minimal pumping of treatment fluid downhole.
  • Gr the gradient
  • Dtubmg represents the overall diameter of the tubing
  • D CT represents the diameter of the coiled tubing
  • h represents liquid level rise.
  • the liquid height above the coiled tubing end is determined by:
  • the gradient Gr may then be computed as follows while TVD ⁇ TVDlimit (TVDlimit is the coiled tubing depth when the fluid level reaches the top):
  • WHP equals wellhead pressure
  • a graph is provided illustrating the gradient Gr plotted against time by graph line 100. Additionally, the graph illustrates a pressure graph line 102 and a TVD graph line 104 plotted against time.
  • the graph can be computed and displayed via control system 30.
  • the calculated gradient Gr is monitored to determine when a stable gradient baseline Gro is achieved.
  • the Gro value can be entered in a designated field by an operator, or control system 30 can be used to automatically record the value.
  • the control system 30 uses this value in computing wellbore fluid density, RHOo, via, for example, the following expression:
  • Reservoir pressure estimates can be computed at selected reservoir depths, such as TVDresl and TVDres2 as follows:
  • FIG. 13 One example of a display format/graphical user interface 62 is illustrated in Figure 13 and provides a representation of a gradient baseline 106. Additional plots of pressure 108 and TVD 110 also can be displayed.
  • a user/operator is able to select a gradient baseline by selecting and moving a displayed drag bar 112.
  • a related display window 114 can be used to display corresponding parameters, such as density and gradient values as drag bar 112 is moved or changed.
  • One or more additional displays 116 also can be used to display a variety of other parameters, such as calculated pore pressure, at different zones.
  • an input area 118 can be provided to enable an operator to enter the liquid level for a given wellbore.
  • Some applications of the present system and methodology provide diversion and stimulation indicators based on measurements from downhole tools, such as treatment tool 32, via sensors 50.
  • the rate of bottom hole pressure change can be used to determine if the diversion or stimulation occurring is based on the fluid pumped during the treatment procedure.
  • the following matrix can be used to determine the state of diversion or stimulation downhole:
  • the bottom hole pressure (BHP) value can be calculated via control system 30 for specific well zones as defined or selected by an operator via a suitable graphical user interface.
  • the selection of bottom hole pressure values helps ensure that BHP is calculated for a fixed point and is not affected by coiled tubing movement.
  • the BHP measurement can have substantial noise, but a variety of algorithms can be used to smooth the data.
  • a smoothing algorithm can be based on averaging over a sliding window.
  • a default sliding window size for the averaging/smoothing of data can be selected, e.g. 30 seconds, and the rate can be calculated by comparing the current average value with the value calculated at the previous interval, e.g. 30 second interval.
  • the threshold values used in the matrix provided above are the default values and can be changed by an operator.
  • the control system 30 enables the operator to save modified values for use in other well treatment jobs or for later analysis.
  • the graphical user interface displays a diversion indicator that becomes "live” only when a diverter is exiting the coiled tubing end. Similarly, a stimulation indicator becomes “live” only when an acid is exiting the coiled tubing end.
  • Other applications of the present system and methodology provide a warning to an operator if downhole measurements via, for example, sensors 50 indicate the possibility of a stuck or embedded coiled tubing 36 or treatment tool 32.
  • the determination may be made based on a variety of input variables, such as carrier fluid type; carrier fluid density; fill type and density; reservoir pressure; reservoir depth (interval); completion - casing and tubing size and depth; coiled tubing outer diameter; clean out speed; sweep speed; and other related parameters.
  • the carrier treatment fluid may be water, brine, gelled fluid, foam, slick water, energized fluid, nitrogen, carbon dioxide, and other suitable carrier fluids.
  • the following list provides fill types and corresponding densities:
  • Determination of the potential for being stuck during an operation is evaluated based on matrices that establish a defined set of parameters indicative of the risk for being stuck.
  • the parameters can include, for example, angular velocity, concentration of solid in suspension (volume), bottom hole pressure gradient rate of change, coiled tubing weight variations, over/under balance, run-in-hole/pull-out-of-hole speed, and other parameters.
  • a water/brine risk matrix is provided in Figure 14
  • Figure 15 one example of a gelled fluid matrix is provided.
  • Figure 16 provides one example of a foam risk matrix.
  • Figure 17 provides one example of a nitrogen matrix.
  • PPA refers to the pounds of solids added per gallon of carrier fluid
  • CS is the clean out speed in feet per minute (value can be input by operator)
  • SS refers to the sweep speed in feet per minute (value can be input by operator)
  • Y is the density corresponding to a low risk PPA limit
  • Z is the density corresponding to a high risk PPA limit.
  • the Y and Z PPG calculations can be made using the following formula:
  • Realtime PPG can be determined by:
  • FIG. 18 another example of a graphical user interface 62 is illustrated.
  • the graphical user interface displays the stuck/embedding potential via a risk bar 120.
  • a plurality of input windows 122 are provided to enable an operator to enter the various parameters used in calculating the risk as discussed above with respect to Figures 14 through 17.
  • well treatment system 20 can be constructed in a variety of configurations for use in many environments and applications.
  • control system 30 can be constructed with a central controller or a plurality of cooperating controllers located proximate the well site or remote from the well site.
  • a variety of sensors 50, treatment tools 32, and tubing 36 also can be used depending on the treatment operation and the properties monitored in real time.
  • the data obtained and provided by sensors 50 also can be used in a variety of formulas, algorithms, and models to aid in the detection of one or more downhole events based on the monitoring of one or more downhole properties.
  • the control system 30 and a sensors 50 cooperate to provide a continuous feedback system utilizing a real time closed loop interpretation technique that enables control system 30 to instantaneously synchronize and adjust well treatment actions at a surface location, e.g. adjust pumping equipment 42, to affect a downhole event.
  • the data can be used to detect the actual occurrence or the potential for specific events.
  • Control system 30 can be programmed to automatically react in specific ways to the detected or calculated properties for exercising control over the treatment operation in a manner that influences or controls the downhole event.

Landscapes

  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Geophysics (AREA)
  • Measuring Fluid Pressure (AREA)
  • Paper (AREA)
  • Pipeline Systems (AREA)
  • Testing Or Calibration Of Command Recording Devices (AREA)
  • Control Of Heat Treatment Processes (AREA)

Abstract

L'invention concerne une technique qui facilite le traitement d'une formation souterraine. La technique met en jeu l'utilisation d'un système de distribution de fluide qui comprend un système de rétroaction continue. Le système de rétroaction continue utilise une technique d'interprétation en boucle fermée en temps réel pour synchroniser et ajuster instantanément des actions au niveau d'une surface de site de puits par rapport à des événements de fond de trou de forage mesurés. Des détecteurs sont utilisés pour surveiller au moins une propriété de fond de trou en temps réel. Sur la base des données en temps réel, le système de rétroaction continue permet de faire des ajustements par rapport à une ou à plusieurs propriété de façon désignée pour influencer un événement de fond de trou.
PCT/IB2008/052318 2007-06-12 2008-06-11 Interprétation en boucle fermée en temps réel de systèmes et de procédés de traitement de tuyauterie Ceased WO2008152599A2 (fr)

Priority Applications (5)

Application Number Priority Date Filing Date Title
EP08763308A EP2153025A2 (fr) 2007-06-12 2008-06-11 Interprétation en boucle fermée en temps réel de systèmes et de procédés de traitement de tuyauterie
EA201070005A EA022992B1 (ru) 2007-06-12 2008-06-11 Системы и способы обработки подземного пласта с интерпретацией данных замкнутого цикла в режиме реального времени
CA2687892A CA2687892C (fr) 2007-06-12 2008-06-11 Interpretation en boucle fermee en temps reel de systemes et de procedes de traitement de tuyauterie
MX2009013108A MX2009013108A (es) 2007-06-12 2008-06-11 Interpretacion de circuito cerrado en tiempo real de sistemas y metodos de tratamiento de tuberias.
EG2009111716A EG27115A (en) 2007-06-12 2009-11-23 Real time closed loop interpretation of tubing treatment systems and methods

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
US93425807P 2007-06-12 2007-06-12
US60/934,258 2007-06-12
US12/135,453 US20080308272A1 (en) 2007-06-12 2008-06-09 Real Time Closed Loop Interpretation of Tubing Treatment Systems and Methods
US12/135,453 2008-06-09

Publications (2)

Publication Number Publication Date
WO2008152599A2 true WO2008152599A2 (fr) 2008-12-18
WO2008152599A3 WO2008152599A3 (fr) 2009-11-12

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PCT/IB2008/052318 Ceased WO2008152599A2 (fr) 2007-06-12 2008-06-11 Interprétation en boucle fermée en temps réel de systèmes et de procédés de traitement de tuyauterie

Country Status (7)

Country Link
US (1) US20080308272A1 (fr)
EP (1) EP2153025A2 (fr)
CA (1) CA2687892C (fr)
EA (1) EA022992B1 (fr)
EG (1) EG27115A (fr)
MX (1) MX2009013108A (fr)
WO (1) WO2008152599A2 (fr)

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Also Published As

Publication number Publication date
CA2687892A1 (fr) 2008-12-18
EA201070005A1 (ru) 2010-06-30
CA2687892C (fr) 2016-05-24
EP2153025A2 (fr) 2010-02-17
US20080308272A1 (en) 2008-12-18
MX2009013108A (es) 2010-01-15
EG27115A (en) 2015-06-23
WO2008152599A3 (fr) 2009-11-12
EA022992B1 (ru) 2016-04-29

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