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US20080230221A1 - Methods and systems for monitoring near-wellbore and far-field reservoir properties using formation-embedded pressure sensors - Google Patents

Methods and systems for monitoring near-wellbore and far-field reservoir properties using formation-embedded pressure sensors Download PDF

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Publication number
US20080230221A1
US20080230221A1 US11/688,934 US68893407A US2008230221A1 US 20080230221 A1 US20080230221 A1 US 20080230221A1 US 68893407 A US68893407 A US 68893407A US 2008230221 A1 US2008230221 A1 US 2008230221A1
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United States
Prior art keywords
wellbore
formation
pressure sensor
pressures
pressure
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Abandoned
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US11/688,934
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English (en)
Inventor
Mohammad Zafari
Younes Jalali
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Schlumberger Technology Corp
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Schlumberger Technology Corp
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Priority to US11/688,934 priority Critical patent/US20080230221A1/en
Priority to NO20081416A priority patent/NO20081416L/no
Publication of US20080230221A1 publication Critical patent/US20080230221A1/en
Abandoned legal-status Critical Current

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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
    • 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
    • E21B47/00—Survey of boreholes or wells
    • E21B47/06—Measuring temperature or pressure
    • 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
    • E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
    • E21B49/087—Well testing, e.g. testing for reservoir productivity or formation parameters

Definitions

  • the invention relates generally to methods and systems for monitoring formation properties. More particularly, the invention relates to measuring or monitoring formation properties using sensors disposed in a wellbore and in formations.
  • Wells for the production of hydrocarbons such as oil and natural gas should be carefully monitored to prevent catastrophic mishaps that may be dangerous and have severe environmental impacts.
  • the production of a well should be monitored and controlled to maximize the production over time.
  • Well production levels and efficiencies depend on reservoir formation characteristics (such as pressure, porosity, permeability, temperature and physical layout of the reservoir) and the nature of the hydrocarbon (or other material) extracted from the formation.
  • Producing hydrocarbons too quickly from a well may result in stranding hydrocarbons in the formation.
  • improper production may separate an oil pool into multiple portions.
  • additional wells may need to be drilled to produce the oil from the separated pools.
  • legal restrictions or economic considerations may not allow another well to be drilled, thereby stranding the pools of oils and wasting their potentials for revenues.
  • Real-time monitoring of formation properties may be used to determine the production status and for decision making. For example, in a laminated reservoir having different zones or layers, mapping the formation properties of these zones can help an operator decide whether to run more perforations in selected zones to increase productivity.
  • sensors may also be deployed in the formations (typically near wellbore) to monitor the pressure responses.
  • U.S. Pat. No. 7,140,434, issued to Chouzenoux et al. discloses sensors and methods that may be deployed in formation layers to monitor the production of a well.
  • FIG. 1 to monitor pressure development in layered formations, such as layered sands, several pressure-measurement sensors 11 may be placed in a producer well 122 that has been previously drilled and cased. In this example, the sensors are deployed along the wellbore in reservoir section 10 . Some sensors are deployed in the perforated zone 124 , while others are deployed above and below the perforated zone 124 .
  • the non-perforated sections above and below the perforated sections are expected to have a low contribution to the production because the flow is mostly radial and the vertical cross-flow is limited.
  • the operator can monitor and/or probe the production characteristics of the zones or the well. For example, by varying the well flow (production) rate Q, the operator may monitor the changes in the pressures as detected by the different sensors in different layers. If the pressure is constant within a layer while the well flow is varied, the particular layer has a low contribution to the overall well production.
  • the pressure transient recording would look like “Pressure Response 1 ” (inset in FIG. 1 ).
  • the pressure response will vary as the well flow is modified.
  • the response will took like “Pressure Response 2 ”. Therefore, by monitoring the pressure in each layer as a function of the overall production flow, it is possible to characterize the productivity of the particular layer. An operator can then use this information to decide whether to run complementary perforations in order to better produce the whole reservoir section
  • the prior art methods typically focus on monitoring a well in the axial direction along the wellbore (i.e., in a vertical direction for a typical vertical well).
  • knowing the reservoir boundaries or formation permeabilities along the fluid path to the wellbore within a production zone may help the operator decide how to produce the well to obtain the maximum economic benefits.
  • mapping the formation properties in the radial directions is critical when injecting fluid (such as water and steam) into a formation through an injection well to drive oil or gas to a production well.
  • fluid such as water and steam
  • decisions can be made to stop or reduce production before the injection fluid reaches the production well.
  • the present invention relates to methods for measuring formation property.
  • a method in accordance with one embodiment of the invention includes obtaining a set of measurements indicative of wellbore pressures for a selected duration after a pressure perturbation is created in a wellbore; obtaining at least one additional set of measurements indicative of formation pressures for the selected duration after the pressure perturbation; and deriving the formation property based on the set of measurements indicative of the wellbore pressures and the at least one additional set of measurements indicative of formation pressures.
  • a system in accordance with one embodiment of the invention includes a first pressure sensor disposed proximate a wellbore for measuring pressures in the wellbore; a second pressure sensor disposed in a formation at a predetermined distance from the wellbore; and a flow rate measuring device.
  • FIG. 1 shows a conventional system for pressure monitoring in a laminated reservoir.
  • FIG. 2 shows a system for monitoring formation properties in accordance with one embodiment of the invention.
  • FIG. 3 shows results from formation property study using a system shown in FIG. 2 ; the graph shows a near wellbore production index derived from the results.
  • FIG. 4 shows a system for monitoring formation properties in accordance with another embodiment of the invention.
  • FIG. 5 shows a system for monitoring formation properties disposed in a formation having two boundaries in accordance with one embodiment of the invention.
  • FIG. 6 shows Homer and Bourdet curves based on pressure data obtained using the system of FIG. 5 .
  • FIG. 7 shows a flow chart of a method for formation property monitoring in accordance with one embodiment of the invention.
  • Embodiments of the invention relate to methods and systems for measuring or monitoring formation properties at different radial distances from the wellbore. For example, near-wellbore and far-field reservoir properties may be determined or monitored using sensors, e.g., pressure sensors, disposed in the wellbore and/or in the formation. In accordance with embodiments of the invention, such measuring or monitoring typically are performed within the same sedimentation layers or zones.
  • sensors e.g., pressure sensors
  • FIG. 2 illustrates a formation property monitoring system in accordance with one embodiment of the invention.
  • a wellbore 20 is drilled in the formations 10 .
  • the wellbore 20 penetrates a production zone 10 a .
  • a sensor 21 is deployed in the wellbore 20 and another sensor 22 is disposed in the formation (e.g., in the production zone 10 a ).
  • the sensor 21 is shown to be disposed in the wellbore, it may also be disposed in a casing, a production tubing, or the wellbore wall for measuring pressures in the wellbore.
  • a flow rate measuring device 23 is shown to be disposed in the wellbore 20 . Note that the flow rate measurements may also be performed on the surface, i.e., the flow rate measuring device 23 may be deployed on the surface in accordance with some embodiments of the invention.
  • the flow rates in the wellbore 20 may be varied (e.g., by changing the pump rates), and the flow rate changes may be measured by using the device 23 .
  • the pressure changes in response to such flow rate changes may be recorded or detected in the wellbore using the sensor 21 and in the formation using sensor 22 .
  • the production rate may be increased to create a transiently lower pressure in the wellbore 20 , similar to performing a drawdown.
  • the fluid flow from the formation will increase until a new steady state is reached.
  • the pump may be shut off after the pressure perturbation to create a shut-in.
  • the pressure will gradually buildup in the wellbore when the fluids from the formation flow into the wellbore.
  • the pressure changes in the wellbore (sensor 21 ) and the formation (sensor 22 ) may be monitored during the drawdown and buildup periods for later analysis.
  • the flow rate (or pressure) changes may also be achieved with other methods, e.g., by a flow or pressure pulse.
  • the pressure measurements recorded by each sensor may be analyzed separately as in a conventional approach. Such analysis typically involves the use of a plot in a form of pressures versus the log of shut-in time. Such a curve is conventionally referred to as a Homer Curve.
  • a Homer curve may be analyzed as a derivative with respect to time, which produces a Bourdet Curve. In a radially extending reservoir without boundaries, the Homer curve exhibits a gradual increase of the pressure until the pressure reaches that of the formation pressure. In the Bourdet curve, the rates of pressure changes will gradually decrease to approach zero when the buildup is complete.
  • the measurements recorded by the sensor in the wellbore (sensor 21 ) and in the formation (sensor 22 ) may be analyzed together.
  • the pressures (or the rate of pressure changes) detected by these two sensors may be compared, either as ratios or as differences.
  • FIG. 3 shows one example, in which the pressures (or pressure changes) measured by the sensor in the wellbore (sensor 21 ) and in the formation (sensor 22 ) are analyzed as differences.
  • the baseline 31 a steady state value as the pressures in the system eventually reach an equilibrium, illustrated as the baseline 31 .
  • the spikes up and down 32 are from transient changes in the flow, e.g., due to pump stoppage or gassing out in the fluids.
  • the steady-state value represented by the baseline 31 in FIG. 3 , relates to the hydraulic resistance in the near wellbore region. Accordingly, this values may be used as a near wellbore production index (NWPI).
  • NWPI is a good indicator of how well the near wellbore region perform under the production conditions because the far-field effects are removed in the difference.
  • the near wellbore production index (NWPI) is different from the conventional production index because the conventional production index measures how the well performs as a unit, i.e., there is no distinction between the near wellbore, matrix, and far-field effects.
  • Conventional production index is typically expressed as the volume delivered per psi of drawdown at the surface (bbl/psi).
  • NWPI is useful because it can inform the operator that slow production may be due to problems in the near wellbore region. In that case, remedial measures may be taken to improve the well performance.
  • FIG. 3 shows difference in the measurements made with the sensors in the wellbore and in the formation
  • ratios may also reflect near wellbore effects because the far-field effects (which is minimally perturbed by the flow rate changes in the wellbore) is factored out in the ratios.
  • NWPI near wellbore production index
  • the system shown in FIG. 3 uses two sensors. This may be referred to as a two-node system.
  • Embodiments of the invention may use two or more nodes (sensors). With more nodes, more sophisticated analysis becomes possible.
  • FIG. 4 shows a three-node system in accordance with one embodiment of the invention.
  • sensor 41 is disposed in the wellbore 40
  • sensors 42 and 43 are disposed in the formation (e.g., production zone 10 a ) such that they are in different radial directions from the wellbore, i.e., sensors 42 and 43 are disposed at different azimuthal angles (locations).
  • sensors 42 and 43 are separated by about 180° in azimuthal angles.
  • these sensors may be separated with azimuthal angles other than 180°.
  • more sensors may be used and are disposed at various azimuthal angles and/or different radial distances.
  • the sensors in the formation e.g., sensors 42 and 43
  • the sensors in the formation may be disposed at the same or different radial distances from the wellbore. With such a set up, it is possible to assess separate near-wellbore effects at different locations (i.e., different azimuthal angles), by analyzing measurements in pairs (e.g., sensors 42 and 41 as a pair, or sensors 43 and 41 as a pair) as described above with reference to FIG. 3 .
  • measurements obtained with such a multi-node system may be analyzed to derive the far-field effects, e.g., reservoir boundaries.
  • multiple nodes may be used to detect orientation and relative distance of reservoir boundaries to the wellbore.
  • FIG. 5 and FIG. 6 One exemplary approach is illustrated in FIG. 5 and FIG. 6 .
  • FIG. 5 shows an illustrative set up with a three-node system, similar to that shown in FIG. 4 .
  • a near reservoir boundary 58 about 1,500 ft or 500 m from the well
  • a far reservoir boundary 59 about 3,000 ft or 1,000 m from the well
  • sensor 51 is disposed in the wellbore at about 0.2 ft (6 cm) from the center of the well
  • sensors 52 and 53 are disposed about 12 ft (4 m) into the formation from the well.
  • Sensor 52 is closer to the near reservoir boundary 58
  • sensor 53 is closer to the far reservoir boundary 59 .
  • the illustration in FIG. 5 is not to the scale.
  • the particular dimensions and configuration are for illustration only and are not intended to limit the scope of the invention.
  • the three sets of measurements obtained by the three sensors 51 , 52 , 53 may be analyzed separately, as shown in FIG. 6 .
  • the curves shown in FIG. 6 are Homer curves ( 61 H, 62 H, 63 H) and Bourdet curves (the derivatives of Homer curves) ( 61 B, 62 B, 63 B) for the three sensors 51 , 52 , 53 , respectively.
  • the Homer curves 61 H, 62 H, 63 H show the typical gradual increase in the pressures. It is relatively difficult to discern any pressure changes, besides the typical buildup, from these Homer curves.
  • the Bourdet curves can reveal more details about the pressure changes that may result from far-field effects, e.g., reservoir boundaries.
  • embodiments of the invention may include more then three nodes. Such systems may be used to further pinpoint the orientations and distances of the boundaries.
  • the data may also be analyzed for quantitative information.
  • the relative arrival times (to the sensors) is a function of the distances from the boundaries to the sensors. Because the pressure waves disperse out in “spheres,” it takes four times longer for the waves to travel twice the distance, i.e., the distance correlates with square root of time (d correlates with t 1/2 ). Thus, if it takes four times longer for the far boundary to reach the sensors than does the near boundary, then it can be concluded that the far boundary is about twice farther, as compared with the near boundary, from the sensors.
  • these data may also be analyzed as differences (as illustrated above in reference to FIG. 3 ) or ratios.
  • the measurement data from sensors 52 and 53 may be used to derive the differences and/or ratios, which may then be used to determine the orientations and relative distances of the boundaries.
  • ratios may provide a more sensitive indicators as to the relative orientations of the boundaries.
  • Embodiments of the invention may use any suitable pressure sensors known in the art.
  • U.S. Pat. No. 7,140,434 issued to Chouzenoux et al., discloses sensors for installation in an underground well having a casing or tubing installed therein.
  • a sensor as disclosed in this patent, comprises a sensor body, sensor elements, and communication elements.
  • the sensor body can be installed in a hole formed in the casing or tubing so as to extend between the inside and outside of the casing or tubing, while the sensor elements are located within the body and capable of sensing properties of an underground formation surrounding the well.
  • the communication elements are also located within the body and capable of communicating information between the sensor elements and a communication device in the well.
  • U.S. Pat. Nos. 6,028,534 and 6,943,697 issued to Ciglenec et al. disclose methods for installing sensors in the formation.
  • remote sensing units may be set during open-hole operations.
  • the remote sensing units may be deployed from a drill string tool that forms part of the collars of the drill string, similar to that disclosed in the Edwards et al. described above.
  • the remote sensing units may be deployed from an open-hole logging tool.
  • the sensors or sensing units can be positioned within the formation of interest by any suitable means, as disclosed in U.S. Pat. No. 6,028,534 issued to Ciglenec et al.
  • a hydraulically energized ram can propel the sensor from the drill collar into the formation with sufficient hydraulic force for the sensor to penetrate the formation by a sufficient depth for sensing formation data.
  • apparatus in the drill collar can be extended to drill outwardly or laterally into the formation, with the sensor then being positioned within the lateral bore by a sensor actuator.
  • a propellant energized system onboard the drill collar can be activated to fire the sensor with sufficient force to penetrate into the formation laterally beyond the wellbore.
  • the sensor is appropriately encapsulated to withstand damage during its lateral installation into the formation, whatever the formation positioning method may be.
  • FIG. 7 illustrates a method 70 in accordance with one embodiment of the invention.
  • a pressure perturbation is created in a wellbore (step 72 ).
  • such pressure perturbations may be created by varying the pump rates.
  • the pressures or pressure changes in the wellbore and in the formations are recorded (step 74 ).
  • the measurement data, both from the wellbore and from the formation, are then analyzed, as described above, to provide a formation property (e.g., near wellbore production index, reservoir boundaries, etc) (step 76 ).
  • a formation property e.g., near wellbore production index, reservoir boundaries, etc
  • Embodiments of the invention provide methods that can be used to probe formation properties with respect to the near wellbore effects and far field effects.
  • the methods of the invention may also be used to detect the reservoir boundaries in terms of the relative distance and orientations. These methods may be practiced with any suitable sensors and techniques known in the art.

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US11/688,934 2007-03-21 2007-03-21 Methods and systems for monitoring near-wellbore and far-field reservoir properties using formation-embedded pressure sensors Abandoned US20080230221A1 (en)

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US20150009039A1 (en) * 2012-02-21 2015-01-08 Tendeka B.V. Wireless communication
US20190250090A1 (en) * 2016-06-20 2019-08-15 Fugro N.V. A method, a system, and a computer program product for determining soil properties
US11021948B2 (en) * 2017-01-11 2021-06-01 Tgt Oilfield Services Limited Method for the hydrodynamic characterization of multi-reservoir wells
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