CN104453869A - Method of conducting diagnostics on a subterranean formation - Google Patents

Abstract

The present invention relates to methods of diagnosing subterranean formations. A method includes placing sensors in an injection well and an observation well; increasing pressure in the injection well until a fracture extends from a location of initiation through a portion of the subterranean formation to a location where the observation well intersects, wherein increasing the pressure in the injection well includes introducing fluid into the injection well ; obtain a measurement indicative of fracture initiation from a first sensor; determine the height of the fracture at the injection well; obtain a measurement indicative of fracture intersection from a second sensor; determine the volume of fluid introduced between fracture initiation and fracture intersection; The distance between the initiation location and the intersection location; determining the time delay between fracture initiation and fracture intersection; and using the determined values, hydraulic fracture properties are calculated.

Description

Methods for Diagnosing Subsurface Formations

Related cases

This application claims the benefit of US Provisional Application 61/882,139, filed September 25, 2013, which is hereby incorporated by reference.

technical field

The invention relates to a method for diagnosing underground formations.

Background technique

Hydraulic fracturing of reservoir formations is a technique that optimizes the value of subsurface hydrocarbon-bearing formations, particularly unconventional gas-rich liquid shale deposits. Due to the tight nature of formations containing such deposits, standard techniques for reservoir characterization and hydraulic fracture design are often not applicable, or interpretation challenges arise. Understanding the leak process is a key component of characterization and design. Standard practice for leak estimation involves performing minimal frac or leak testing. This test generally provides poor results due to the very low permeability of unconventional gas-rich liquid shale formations. Another way to estimate leaks is to use analytical methods that require knowledge of certain parameters of the formation, such as permeability and porosity. However, these parameters can be difficult to estimate in tight formations.

Contents of the invention

According to one aspect of the present disclosure, a method includes positioning a first sensor in an injection well penetrating a subterranean formation. The method also includes positioning a second sensor in the observation well penetrated into the subterranean formation. The method further includes increasing pressure in the injection well until the fracture extends from an initiation location of the injection well through a portion of the subterranean formation to an intersection location of the observation well, wherein increasing the pressure in the injection well includes introducing fluid into the injection well. The method includes obtaining measurements indicative of fracture initiation from a first sensor. Additionally, the method includes determining the height of the fracture at the injection well. The method also includes obtaining measurements indicative of fracture convergence from the second sensor. The method includes determining a volume of fluid introduced between fracture initiation and fracture convergence. Additionally, the method includes determining the distance between the initiation location and the intersection location. The method also includes determining a time lapse between fracture initiation and fracture convergence. Additionally, the method includes using the determined values to calculate hydraulic fracture properties.

Description of drawings

FIG. 1 shows a schematic diagram of an injection well and an observation well (with a fracture extending between the injection well and the observation well) according to one aspect of the present disclosure.

Detailed ways

The present disclosure provides methods for field testing and deriving hydraulic fracturing parameters. Typically, a combination of distributed temperature and acoustic sensors are installed in vertical and deviated wells, respectively, to measure fracture height, time required for the fracture to grow to a certain length, and fluid leakage rate. The estimated parameters can also be used in history fitting to reduce uncertainties in characterizing the stress field, fracture toughness and other relevant properties of the formation.

Referring now to FIG. 1 , injection wells 10 and observation wells 12 may be provided. The injection well 10 may be a hydraulically fractured well. One or both of the injection well 10 and observation well 12 may penetrate a subterranean formation 14 of interest. For example, the subterranean formation 14 may contain hydrocarbons or other natural resources. The injection well 10 and observation well 12 may start at a single pad (not shown) at the surface 15 . Then, as shown, the injection well 10 starts at the surface 15 at an injection site 16 and the observation well 12 starts at the surface 15 at an observation site 18 . The method of evaluating a formation may include placing or otherwise disposing a sensor 20 in the injection well 10 at a location where the sensor 20 may sense a parameter indicative of fracture initiation in the injection well 10 from an initiation location 24 . As shown, the initiation site 24 is a perforation in the shell isolated by two packers 23 . The sensor 20 may be a distributed temperature sensor (DTS), a manometer, multiple manometers, or the like. For example a fiber optic DTS may be attached to the wellbore casing and provide measurements of the temperature drop (or rise) in response to the injection of cold (hot) fluids. In some embodiments, including the one shown, the sensor 20 may be placed in a substantially vertical portion 25 of the injection well 10 . In these embodiments, the initiation location 24 may be in a substantially vertical portion 25 of the injection well 10 .

The method may also include placing or otherwise positioning another sensor 26 at a location in the observation well 12 where the sensor 26 may sense a parameter indicative of fracture intersection at the intersection location 30 in the observation well 12 . The sensor 26 may be a distributed acoustic sensor (DAS), a DTS, a DAS/DTS combination, or any other instrument in the observation well 12 . A fiber optic DAS can be attached to the wellbore casing and measure the deformation caused by the fracture. DAS and DTS can be used in one wellbore at the same time. Alternatively, piezometers may be present in the observation well or in both injection and observation wells. In some embodiments, including the one shown, the sensor 26 may be placed in a sloped portion 31 of the observation well 12 . In these embodiments, the junction location 30 may be in a sloped portion 31 of the observation well 12 .

The inclined portion 31 of the injection well 10 and the observation well 12 may be positioned along the direction of maximum horizontal stress σ _H . Once the sensor 20 has been positioned within the injection well 10 and the sensor 26 has been positioned within the observation well 12 , fluid may be introduced into the injection well 10 at the surface 15 . The pressure within the injection well may be gradually increased by pressurizing the fluid until fractures 34 begin to form. The fracture 34 may extend through a portion of the subterranean formation 14 from an initiation location 24 in the injection well 10 to a junction location 30 in the observation well 12 . While it is possible for the fracture 34 to continue beyond the junction location 30, the present disclosure considers the junction location 30 to be of particular concern.

The initiation of crack 34 may provide a signal detectable by sensor 20 . For example, fracturing of subterranean formation 14 may be registered by a change in pressure, a change in heat, or some other change that may be measured by sensor 20 . Therefore, it may be possible to obtain measurements from the sensor 20 indicative of crack initiation. The measurements may include an indication of the value sensed (e.g., a temperature measurement, a pressure measurement, a deformation measurement, etc.) and an indication of the time at which the value was sensed ("time to crack initiation" or t ₀ = 0). Such one or more measurements may be retained for later reference and use. In order to sense changes in the measurements of sensor 20 , a baseline measurement may be obtained from sensor 20 prior to obtaining any measurements associated with the formation of crack 34 . Accordingly, determination of time to initiation may involve comparing a baseline measurement with one or more subsequent measurements until a sufficiently variable characteristic of fracture initiation is detected. Therefore, determining when a change is detected provides a determination of the time of crack initiation. Depending on whether the sensor is configured to detect a change in temperature (when the baseline and subsequent measurement is a temperature measurement), a change in pressure (when the baseline and subsequent measurement is a pressure measurement), or some other type of change, the variation can be up to threshold temperature, pressure or other value. The interpreted fracture initiation time can be further compared with and supported by the fracture initiation interpreted from the processed pressure records.

The height 36 of the fracture 34 may be determined at the injection well 10 . Specifically, the height 36 of the fracture 34 may be determined at the initiation location 24 by radiotracers, temperature logging, or any other device in the injection well 10 . In some embodiments, determining height 36 of fracture 34 may include obtaining additional measurements from sensor 20 . For example, if sensor 20 is configured to provide temperature measurements, changes in temperature along the length of sensor 20 may provide information regarding the height of fracture 34 . Thus, determining the height 36 of the crack may involve a comparison of the temperature measurements of the sensor 20 over time.

As injection continues at closely monitored and recorded injection rates, fracture 34 propagates through subterranean formation 14 until fracture 34 intersects the observation well at intersection location 30 . The intersection of fracture 34 with observation well 12 may provide a signal that may be detected by sensor 24 . For example, arrival of fracture 34 to observation well 12 may be marked by an acoustic change or some other change measurable by sensor 26 . Such measurements may include an indication of the sensed value (eg, an acoustic measurement, a temperature measurement, or a combination of both) and an indication of the time at which the value was sensed ("junction time" or t). Such one or more measurements may be retained for later reference and use. In order to sense changes in the measurements of the sensors 26 , baseline measurements may be obtained from the sensors 26 prior to any measurements associated with the intersection of the fracture 34 and the observation well 12 . Thus, determining the time of convergence may involve comparing a baseline measurement with one or more subsequent measurements until a sufficient change is detected. Therefore, determining the time when a change is detected provides a determination of the junction time. Depending on whether the sensor 26 is configured to detect an acoustic change (when the baseline and subsequent measurements are acoustic measurements) or some other type of change, the change may reach an acoustic threshold or other value.

The same process can optionally be repeated for additional observation wells (not shown) using additional sensors (not shown). In such instances, such additional measurement(s) may also be retained for later reference and use in a manner similar to that described with respect to the illustrated observation well 12 .

The initiation time and convergence time can be used to determine the volume of fluid introduced between fracture initiation and fracture convergence. For example, the initiation time can be subtracted from the junction time, and the volumetric flow rate can be multiplied by the elapsed time. Alternatively, the initiation time can be set to 0, and the timer starts measuring time at the initiation time and stops measuring at the junction time. Again, this time delay can be multiplied by the steady volumetric flow rate. Alternatively, the volume of fluid introduced between fracture initiation and fracture convergence may be determined by other methods including measurement, monitoring, recording, and the like.

In addition to knowing the volume of fluid introduced and the height 36 of the fracture, it may also be useful to determine the fracture length 38 or the distance between the initiation location 24 and the junction location 30 . Slit length 38 may actually be approximately half the length of slit 34 . Thus, length 38 may not include portions of fracture 34 extending from injection well 10 in a direction away from observation well 12 . Likewise, length 38 may exclude portions of fracture 34 that extend beyond observation well 12 . Determining fracture length 38 may be as simple as obtaining and comparing position measurements from sensor 20 and sensor 26 . Alternatively, fracture length can be estimated using microseismic monitoring. However, these measurements may be inherently less accurate or more uncertain.

In another embodiment (not shown), the injection well 10 may have a sloped portion, and the initiation location 24 may be located in the sloped portion of the injection well 10 . In such an embodiment, the sensors 20 , 26 may mark the initiation time and the junction time, and the sensors 20 , 26 and/or additional sensors may further use microseismic data or other techniques that allow the height 36 of the fracture 34 to be estimated.

The same process can optionally be repeated for additional observation wells (not shown) using additional sensors (not shown). In such instances, such additional measurement(s) may be obtained in a similar manner and used to estimate interfracture fluid distribution from DAS or other data.

Once the length 38, height 36, and volume of fluid introduced are known, hydraulic fracture properties can be calculated. For example, leak volume, leak coefficient, and/or permeability can be calculated. Some of these calculations may involve additional determinations, such as fluid pressure in the fracture, reservoir pressure, fluid viscosity, and fluid compressibility. Other properties such as Young's modulus, Poisson's ratio, complete elliptic integral of the second kind, and net fracture pressure can be determined and used in the methods described here.

Based on elastic relations. The leakage volume V _loff (L>>h) of a long rectangular fracture is:

${\mathrm{<span\; class="notranslate">\; V</span>}}_{\mathrm{<span\; class="notranslate">\; loff</span>}}<span\; class="notranslate">\; =</span>{\mathrm{<span\; class="notranslate">\; V</span>}}_{\mathrm{<span\; class="notranslate">\; inj</span>}}<span\; class="notranslate">\; -</span>{\mathrm{<span\; class="notranslate">\; V</span>}}_{\mathrm{<span\; class="notranslate">\; f</span>}}<span\; class="notranslate">\; =</span>{<span\; class="notranslate">\; \&Integral;</span>}_{\mathrm{<span\; class="notranslate">\; 0</span>}}^{\mathrm{<span\; class="notranslate">\; t</span>}}\mathrm{<span\; class="notranslate">\; Qdt</span>}<span\; class="notranslate">\; -</span>\frac{{\mathrm{<span\; class="notranslate">\; \&pi;</span>}}^{\mathrm{<span\; class="notranslate">\; 2</span>}}}{\mathrm{<span\; class="notranslate">\; 4</span>}}<span\; class="notranslate">\; \&Center\; Dot;</span>\frac{\mathrm{<span\; class="notranslate">\; 1</span>}<span\; class="notranslate">\; -</span>\mathrm{<span\; class="notranslate">\; v</span>}}{\mathrm{<span\; class="notranslate">\; E.</span>}}<span\; class="notranslate">\; \&Center\; Dot;</span>\frac{\mathrm{<span\; class="notranslate">\; L</span>}{\mathrm{<span\; class="notranslate">\; h</span>}}^{\mathrm{<span\; class="notranslate">\; 2</span>}}}{\mathrm{<span\; class="notranslate">\; I</span>}<span\; class="notranslate">\; (</span>\mathrm{<span\; class="notranslate">\; m</span>}<span\; class="notranslate">\; )</span>}\mathrm{<span\; class="notranslate">\; \&Delta;p</span>}$

where V _inj is the injected fluid volume, V _f is the fracture volume at time t, Q is the volumetric injection rate, t is the time when the sensor 26 marked fracture 34 meets the observation well 12, and h is the fracture height 36 (determined by measured by sensor 30 in well 10), L is half the length 38 of the fracture (same as the distance between wells), E is Young's modulus, ν is Poisson's ratio, I(m) is the complete elliptic integral of the second kind, Δp is the net fracture pressure, and

The leakage factor is calculated as follows

${\mathrm{<span\; class="notranslate">\; C</span>}}_{\mathrm{<span\; class="notranslate">\; L</span>}}<span\; class="notranslate">\; =</span>\frac{\mathrm{<span\; class="notranslate">\; 3</span>}}{\mathrm{<span\; class="notranslate">\; 4</span>}}\frac{{\mathrm{<span\; class="notranslate">\; V</span>}}_{\mathrm{<span\; class="notranslate">\; L</span>}}}{\mathrm{<span\; class="notranslate">\; L</span>}\sqrt{\mathrm{<span\; class="notranslate">\; t</span>}}}$

To illustrate the link between the leakage and flow properties of the subterranean formation 14, the following constants can also be estimated

$\mathrm{<span\; class="notranslate">\; k\&phi;</span>}<span\; class="notranslate">\; =</span>\frac{{\mathrm{<span\; class="notranslate">\; C</span>}}_{\mathrm{<span\; class="notranslate">\; L</span>}}^{\mathrm{<span\; class="notranslate">\; 2</span>}}}{{<span\; class="notranslate">\; (</span>{\mathrm{<span\; class="notranslate">\; p</span>}}_{\mathrm{<span\; class="notranslate">\; f</span>}}<span\; class="notranslate">\; -</span>{\mathrm{<span\; class="notranslate">\; p</span>}}_{\mathrm{<span\; class="notranslate">\; i</span>}}<span\; class="notranslate">\; )</span>}^{\mathrm{<span\; class="notranslate">\; 2</span>}}}<span\; class="notranslate">\; \&Center\; Dot;</span>\frac{\mathrm{<span\; class="notranslate">\; \&pi;\&mu;</span>}}{{\mathrm{<span\; class="notranslate">\; c</span>}}_{\mathrm{<span\; class="notranslate">\; t</span>}}}$

where k is the formation permeability, φ is the formation porosity, p _f is the fluid pressure in the fracture, p _i is the reservoir pressure, μ is the viscosity of the fracturing fluid and c _t is the fluid compressibility.

Accordingly, the methods described above may be useful for examining and/or diagnosing subterranean formations 14 and otherwise aiding in simulation design and reservoir development and for estimating reservoir and fracture properties. The method may be particularly useful for tight formations or other formations with low hydraulic conductivity and/or low permeability.

The various estimated properties provided here can be used in a hydraulic fracture simulator to history fit other parameters of interest (eg, stress state and in situ fracture toughness). For example, the described method may allow estimation of fracture height and correspondingly height of HF confinement zone (if any), leakage volume V _L and velocity u _L , leakage coefficient C _L and other formation flow related properties.

Those skilled in the art will appreciate that various modifications and changes may exist in the disclosed embodiments, configurations, materials and methods without departing from their scope. Accordingly, the scope of the claims and their functional equivalents should not be limited to the particular embodiments described and illustrated, since these embodiments are merely exemplary in nature and separately described elements may be optionally combination.

Claims (15)

1. A method comprising a. placing a first sensor in an injection well penetrating a subterranean formation; b. placing a second sensor in an observation well penetrating the subterranean formation; c. increasing the pressure in the injection well until the fracture extends from an initiation location in the injection well through a portion of the subterranean formation to an intersection location in the observation well, wherein increasing the pressure in the injection well comprises introducing fluid into the into the injection well; d. Obtaining measurements indicative of fracture initiation from the first sensor; e. determining the height of said fracture at said injection well; f. Obtaining measurements indicative of fracture convergence from the second sensor; g. determining the volume of fluid introduced between said fracture initiation and said fracture convergence; h. Determine the distance between the crack initiation location and the intersection location; i. determining a time delay between said fracture initiation and said fracture convergence; and j. Using the determined values, calculate hydraulic fracture properties. 2. The method of claim 1, wherein the first sensor comprises a distributed temperature sensor. 3. The method of claim 1, wherein the second sensor comprises a distributed acoustic sensor. 4. The method of claim 1, wherein step (a) comprises placing the first sensor in a substantially vertical portion of the injection well; wherein a fracture initiation location is in the substantially vertical portion of the injection well middle. 5. The method of claim 1, wherein step (b) comprises placing the second sensor in a sloped portion of the observation well; wherein the intersection location is in the sloped portion of the observation well . 6. The method of claim 1, wherein the measurements of step (d) include temperature measurements, the method further comprising: - obtaining at least one reference temperature measurement from said first sensor prior to obtaining the temperature measurement of step (d); and - comparing the reference temperature measurement with the temperature measurement of step (d) to determine the crack initiation time. 7. The method of claim 1, wherein the measurements of step (d) include pressure measurements, the method further comprising: - obtaining at least one reference pressure measurement from said first sensor prior to obtaining the pressure measurement of step (d); and - comparing the reference pressure measurement with the pressure measurement of step (d) to determine the initiation time. 8. The method of claim 1, wherein the measurements of step (f) include acoustic measurements, the method further comprising: - obtaining at least one reference acoustic measurement from said second sensor prior to obtaining the acoustic measurement of step (f); and - comparing the baseline acoustic measurements with the acoustic measurements of step (f) to determine the rendezvous time. 9. The method of claim 1, further comprising, obtaining a position measurement from the first sensor and obtaining a position measurement from the second sensor, wherein determining the distance of step (h) comprises comparing the position measurement results. 10. The method of claim 1, wherein determining the height of the fracture comprises obtaining at least one additional measurement from a first sensor. 11. The method of claim 10, wherein the measurements of step (d) include temperature measurements, wherein the additional measurements from the first sensor include temperature measurements, and wherein determining the height of the fracture includes comparing the temperature measurement results. 12. The method of claim 1, further comprising determining Young's modulus and Poisson's ratio, complete elliptic integral of the second kind, and net fracture pressure of the portion of the subterranean formation through which the fracture extends; wherein step (i) The calculations for further include using the determined Young's modulus, Poisson's ratio, complete elliptic integral of the second kind, and net fracture pressure. 13. The method of claim 1, wherein the hydraulic fracture characteristic comprises leakage volume. 14. The method of claim 1, wherein the hydraulic fracture characteristic comprises a leak coefficient. 15. The method of claim 1, wherein the hydraulic fracturing properties include permeability, the method further comprising determining fluid pressure in the fracture, reservoir pressure, fluid viscosity, and fluid compressibility, wherein step The calculation of (i) further includes using the determined fluid pressure in the fracture, reservoir pressure, fluid viscosity and fluid compressibility.