METHOD OF CONDUCTING DIAGNOSTICS ON A SUBTERRANEAN FORMATION

Abstract

A method including providing sensors in injection and observation wells; increasing pressure within the injection well until a fracture extends from an initiation location through a portion of a subterranean formation to an intersection location in the observation well, wherein increasing pressure within the injection well comprises introducing fluid into the injection well; obtaining a measurement indicative of fracture initiation from the first sensor; determining a height of the fracture at the injection well; obtaining a measurement indicative of fracture intersection from the second sensor; determining a volume of fluid introduced between the fracture initiation and the fracture intersection; determining a distance between the initiation location and the intersection location; determining a time lapse between the fracture initiation and the fracture intersection; and using the determined values, calculating a hydraulic fracturing characteristic.

Description

RELATED CASES

This application claims the benefit of U.S. Provisional Application No. 61/882,139, filed on Sep. 25, 2013, which is incorporated herein by reference.

FIELD OF THE INVENTION

The invention relates to a method of conducting diagnostics on a subterranean formation.

BACKGROUND

Hydraulic fracturing of reservoirs is a technology optimizing the value of subterranean hydrocarbon-bearing formations and, in particular, of unconventional gas and liquid rich shale deposits. Due to the tight nature of formations containing such deposits, standard techniques for reservoir characterization and hydraulic fracture design are often inapplicable or present interpretation challenges. Understanding leak-off process is a key component of characterization and design. A standard practice of leak-off estimation involves conducting a minifrac or leak-off test. Due to very low permeability of the unconventional gas and liquid rich shale formations this test generally provides poor results. Another way to estimate the leak-off is to use analytical approach which requires knowledge of some parameters of the formation such as permeability and porosity. However, these parameters can be very hard to estimate in tight formations.

SUMMARY OF THE INVENTION

In accordance with one aspect of the present disclosure, a method includes providing a first sensor in an injection well penetrating a subterranean formation. The method also includes providing a second sensor in an observation well penetrating the subterranean formation. The method further includes increasing pressure within the injection well until a 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 pressure within the injection well comprises introducing fluid into the injection well. The method includes obtaining a measurement indicative of fracture initiation from the first sensor. Additionally, the method includes determining a height of the fracture at the injection well. The method also includes obtaining a measurement indicative of fracture intersection from the second sensor. The method includes determining a volume of fluid introduced between the fracture initiation and the fracture intersection. Additionally, the method includes determining a distance between the initiation location and the intersection location. The method also includes determining a time lapse between the fracture initiation and the fracture intersection. Additionally, the method includes using the determined values, calculating a hydraulic fracturing characteristic.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 illustrates a schematic of an injection well and an observation well with a fracture extending therebetween in accordance with one aspect of the present disclosure.

DETAILED DESCRIPTION

The present disclosure provides methods for field testing and deriving hydraulic fracturing parameters. Generally, a combination of distributed temperature and acoustic sensors are installed in a vertical and deviated well respectively to measure fracture height, time required for the fracture to grow to a length, and fluid leak-off rate. The estimated parameters may also be employed in history matching to decrease the uncertainty in characterizing the stress field, fracture toughness of the formation, and other related properties.

Referring now to FIG. 1, an injection well 10 and an observation well 12 may be provided. The injection well 10 may be a hydraulically fractured well. One or both of the injection well 10 and the observation well 12 may penetrate a subterranean formation 14 of interest. For example, the subterranean formation 14 may contain hydrocarbon or other natural resources. The injection well 10 and the observation well 12 may originate at a surface 15 at a single pad (not shown). However, as illustrated, the injection well 10 originates at the surface 15 at an injection pad 16 and the observation well 12 originates at the surface 15 at an observation pad 18. A method of evaluating a formation may include placing or otherwise providing a sensor 20 in the injection well 10 at a location where the sensor 20 can sense a parameter indicative of fracture initiation from an initiation location 24 in the injection well 10. As illustrated, the initiation location 24 is a perforation in casing, isolated by two packers 23. The sensor 20 may be a distributed temperature sensor (DTS), a pressure gauge, multiple pressure gauges, etc. For example a fiber optic DTS may be attached to the wellbore casing and provide measurements of temperature decrease (or increase) in response to the injection of cool (hot) fluid. In some embodiments, including the embodiment illustrated, the sensor 20 may be placed in a substantially vertical portion 25 of the injection well 10. In such embodiments, the initiation location 24 may be in the substantially vertical portion 25 of the injection well 10.

The method may also include placing or otherwise providing another sensor 26 in the observation well 12 at a location where the sensor 26 can sense a parameter indicative of fracture intersection at an 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 instrumentation in the observation well 12. A fiber optic DAS may be attached to the wellbore casing and measure the deformation induced by fracturing. A DAS and DTS may be simultaneously used in one wellbore. Alternatively, pressure gauges may be present in the observation well or in both injection and observation wells. In some embodiments, including the embodiment illustrated, the sensor 26 may be placed in a deviated portion 31 of the observation well 12. In such embodiments, the intersection location 30 may be in the deviated portion 31 of the observation well 12.

The injection well 10 and the deviated portion 31 of the observation well 12 may be positioned along the direction of maximum horizontal stress σ_H. Once the sensor 20 has been provided in the injection well 10 and the sensor 26 has been provided in 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 a fracture 34 begins to form. The fracture 34 may extend from the initiation location 24 in the injection well 10, through a portion of the subterranean formation 14, to the intersection location 30 in the observation well 12. While it is likely that the fracture 34 would continue beyond the intersection location 30, the present disclosure notes that the intersection location 30 is of particular interest.

The initiation of the fracture 34 may provide a signal that can be detected by the sensor 20. For example, breaking of the subterranean formation 14 may be registered by a pressure change, a thermal change, or some other change measurable by the sensor 20. Thus, it may be possible to obtain a measurement indicative of fracture initiation from the sensor 20. Such measurement may include an indication of the sensed value (e.g., a temperature measurement, a pressure measurement, deformation measurement, etc.) and indication of a time (“initiation time” or t₀=0) at which the value was sensed. Such measurement(s) may be saved for later reference and use. In order to sense a change in the measurement of the sensor 20, a baseline measurement may be obtained from the sensor 20 prior to any measurement associated with formation of the fracture 34. Thus, determination of the time of initiation may involve comparing the baseline measurement with one or more subsequent measurements until a sufficient change characteristic of fracture initiation is detected. Thus, determining the time at which that change is detected provides a determination of the time of initiation. That change may reach a threshold temperature, pressure, or other value, depending on whether the sensor 20 is configured to detect a temperature change (when the baseline and subsequent measurements are temperature measurements), a pressure change (when the baseline and subsequent measurements are pressure measurements), or some other type of change The interpreted fracture initiation time can be further compared with and supported by the fracture initiation interpreted from the treating pressure record.

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 via radioactive tracers, temperature logs, or any other instrumentation in the injection well 10. In some embodiments, determining the height 36 of the fracture 34 may include obtaining an additional measurement from the sensor 20. For example, if the sensor 20 is configured to provide temperature measurements, changes in temperature along the length of the sensor 20 may provide information about the height of the fracture 34. Thus, determining the height 36 of the fracture may involve comparison of temperature measurements of the sensor 20 over time.

As injection proceeds with closely monitored and recorded injection volumes, the fracture 34 propagates through the subterranean formation 14, until the fracture 34 intersects the observation well 12 at the intersection location 30. The intersection of the fracture 34 with the observation well 12 may provide a signal that can be detected by the sensor 24. For example, arrival of the fracture 34 at the observation well 12 may be registered by an acoustic change or some other change measurable by the sensor 26. Such measurement may include an indication of the sensed value (e.g., an acoustic measurement, a temperature measurement, or a combination thereof) and an indication of a time (“intersection time” or t) at which the value was sensed. Such measurement(s) may be saved for later reference and use. In order to sense a change in the measurement of the sensor 26, a baseline measurement may be obtained from the sensor 26 prior to any measurement associated with intersection of the fracture 34 with the observation well 12. Thus, determination of the time of intersection may involve comparing the baseline measurement with one or more subsequent measurements until a sufficient change is detected. Thus, determining the time at which that change is detected provides a determination of the time of intersection. That change may reach a threshold acoustic or other value, 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 same process may optionally be repeated for additional observation wells (not shown) with use of additional sensors (not shown). In such instance, such additional measurement(s) may also be saved for later reference and use in a similar manner as that described with respect to the illustrated observation well 12.

The initiation time and the intersection time may be used to determine a volume of fluid introduced between the fracture initiation and the fracture intersection. For example, the initiation time may be subtracted from the intersection time and a volumetric flow rate may be multiplied by the time lapsed. Alternatively, the initiation time might be set to zero, with a timer starting to measure time at the initiation time and stop measuring at the intersection time. Again, the time lapse may be multiplied by a steady volumetric flow rate. Alternatively, the volume of fluid introduced between the fracture initiation and the fracture intersection may be determined by other methods, including measuring, monitoring, recording, etc.

In addition to knowing the volume of fluid introduced and the height 36 of the fracture, it may be useful to determine a fracture length 38 or distance between the initiation location 24 and the intersection location 30. The fracture length 38 may actually approximate a half-length of the fracture 34. Thus, the length 38 may not include portions of the fracture 34 extending from the injection well 10 in a direction away from the observation well 12. Likewise, the length 38 may exclude portions of the fracture 34 extending beyond the observation well 12. Determining the fracture length 38 may be as straightforward as obtaining and comparing location measurements from the sensor 20 and the sensor 26. Alternatively, fracture length can be estimated using microseismic monitoring. However, these measurements would likely be substantially less accurate and more uncertain.

In another embodiment (not shown), the injection well 10 may have a deviated portion and the initiation location 24 may be in the deviated portion of the injection well 10. In such embodiments, the sensors 20, 26 may register the initiation time and intersection time and the sensors 20, 26 and/or additional sensors may further use microseismic data or other techniques allowing for an estimation of the height 36 of the fracture 34. The same process may optionally be repeated for additional observation wells (not shown) with use of additional sensors (not shown). In such instance, such additional measurement(s) may be obtained in a similar manner and used to estimate fluid distribution between the fractures from DAS or other data.

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

Based on relations of elasticity, leak off volume V_loff for a long rectangular fracture (L>>h) is

$V_{\mathrm{loff}}=V_{\mathrm{inj}}-V_f={\int }_0^tQt-\frac{{\pi }^2}{4}·\frac{1-v}{E}·\frac{{\mathrm{Lh}}^2}{I\left(m\right)}\Delta p$

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 of sensor 26 registering intersection of the fracture 34 with the observation well 12, h is the fracture height 36 (measured by sensor 30 in the injection well 10), L is the fracture half-length 38 (equal to the distance between the wells), E is the Young's modulus ν is the Poisson Ratio, I(m) is the complete elliptical integral of the second kind, Δp is the fracture net pressure, and

$m={\left(\frac{h}{2L}\right)}^2.$

Leak-off coefficient is calculated as

$C_L=\frac{3}{4}\frac{V_L}{L\sqrt{t}}$

Accounting for the connection between the leak-off and flow properties of the subterranean formation 14 the following constant can be estimated as well

$k\phi =\frac{C_L^2}{{\left(p_f-p_i\right)}^2}·\frac{\mathrm{\pi \mu }}{c_t}$

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.

Thus, the method described above may be useful for testing and/or conducting diagnostics on the subterranean formation 14 and otherwise aiding in stimulation design and reservoir development and for estimating reservoir and fracturing characteristics. The method may be particularly useful for tight formations or other formations having low hydraulic conductivity and/or low permeability.

Various estimated characteristics provided herein may be used in hydraulic fracturing simulators to history match other parameters of interest (e.g., stress state and in-situ fracture toughness). For example, the methodology described may allow for estimating fracture height and correspondingly the height of the HF confining zone (if any), the leak-off volume V_L and velocity μ_L, the leak-off coefficient C_L, and other formation flow-related properties.

Those of skill in the art will appreciate that many modifications and variations are possible in terms of 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 by the particular embodiments described and illustrated, as these are merely exemplary in nature and elements described separately may be optionally combined.

Claims

1. A method comprising:

a. providing a first sensor in an injection well penetrating a subterranean formation;

b. providing a second sensor in an observation well penetrating the subterranean formation;

c. increasing pressure within the injection well until a 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 pressure within the injection well comprises introducing fluid into the injection well;

d. obtaining a measurement indicative of fracture initiation from the first sensor;

e. determining a height of the fracture at the injection well;

f. obtaining a measurement indicative of fracture intersection from the second sensor;

g. determining a volume of fluid introduced between the fracture initiation and the fracture intersection;

h. determining a distance between the initiation location and the intersection location;

i. determining a time lapse between the fracture initiation and the fracture intersection; and

j. using the determined values, calculating a hydraulic fracturing characteristic.

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 initiation location is in the substantially vertical portion of the injection well.

5. The method of claim 1, wherein step (b) comprises placing the second sensor in a deviated portion of the observation well; wherein the intersection location is in the deviated portion of the observation well.

6. The method of claim 1, wherein the measurement of step (d) comprises a temperature measurement, the method further comprising:

obtaining at least one baseline temperature measurement from the first sensor prior to obtaining the temperature measurement of step (d); and

comparing the baseline temperature measurement with the temperature measurement of step (d) to determine a time of initiation.

7. The method of claim 1, wherein the measurement of step (d) comprises a pressure measurement, the method further comprising:

obtaining at least one baseline pressure measurement from the first sensor prior to obtaining the pressure measurement of step (d); and

comparing the baseline pressure measurement with the pressure measurement of step (d) to determine a time of initiation.

8. The method of claim 1, wherein the measurement of step (f) comprises an acoustic measurement, the method further comprising:

obtaining at least one baseline acoustic measurement from the second sensor prior to obtaining the acoustic measurement of step (f); and

comparing the baseline acoustic measurement with the acoustic measurement of step (f) to determine a time of intersection.

9. The method of claim 1, further comprising, obtaining a location measurement from the first sensor and obtaining a location measurement from the second sensor, wherein determining the distance of step (h) comprises comparing the location measurements.

10. The method of claim 1, wherein determining the height of the fracture comprises obtaining at least one additional measurement from the first sensor.

11. The method of claim 10, wherein the measurement of step (d) comprises a temperature measurement, wherein the additional measurement from the first sensor comprises a temperature measurement, and wherein determining the height of the fracture comprises comparing the temperature measurements.

12. The method of claim 1, further comprising determining a Young's modulus and Poisson ratio of the portion of the subterranean formation through which the fracture extends, complete elliptical integral of the second kind, and fracture net pressure; wherein the calculating of step (i) further comprises using the determined Young's modulus, Poisson ratio, complete elliptical integral of the second kind, and fracture net pressure.

13. The method of claim 1, wherein the hydraulic fracturing characteristic comprises a leak-off volume.

14. The method of claim 1, wherein the hydraulic fracturing characteristic comprises a leak-off coefficient.

15. The method of claim 1, wherein the hydraulic fracturing characteristic comprises permeability, the method further comprising determining fluid pressure in the fracture, reservoir pressure, viscosity of the fluid, and fluid compressibility, wherein the calculating of step (i) further comprises using the determined fluid pressure in the fracture, reservoir pressure, viscosity of the fluid, and fluid compressibility.