EA040992B1 - MONITORING THE EFFICIENCY OF REPEATED HYDRAULIC FRACTURING USING VISCOUS PACK TECHNOLOGY AND HIGH-FREQUENCY PRESSURE MONITORING - Google Patents

Description

Technical field

Hydrocarbons (oil, natural gas, etc.) are produced from a subterranean geological formation (ie, reservoir) by drilling a well that passes through the reservoir. As a result, a partial path of hydrocarbon movement to the surface is created. For the extraction of hydrocarbons, i.e. to move from the reservoir to the wellbore (and eventually to the surface), hydrocarbons must be provided with a substantially unobstructed path from the reservoir to the wellbore.

Fractures in the earth's crust are of great importance for the extraction of underground fluid resources such as hydrocarbons. In low permeability, low porosity formations, the potential production from a wellbore drilled into the formation is directly related to the number of fractures opened. For secondary recovery of hydrocarbons after production has been depleted at initial fluid pressure in the reservoir, fluid injection is often used to increase hydrocarbon production, and knowledge of reservoir fractures is truly invaluable in predicting overall recovery.

Hydraulic fracturing (hereinafter, hydraulic fracturing) is a method of well stimulation by creating fractures within an oil and gas reservoir, in which fractures are created by pumping a fluid and a proppant into the well at high pressure. The main purpose of hydraulic fracturing is to increase the productivity of the well, and fracturing and acidizing operations to increase the permeability of the formation can be designed based on reservoir data, proppant, acid volume injected, target well productivity factor, and the like. However, the difficulty in determining the effectiveness of a hydraulic fracturing treatment on a formation can provide some degree of uncertainty about the total amount of hydrocarbons recovered from a given reservoir.

Brief description of the entity

This entity summary contains a selection of concepts that are detailed below. This description is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid to limiting the scope of the claimed subject matter.

In one aspect, the embodiments described herein relate to a method for treating a subterranean formation through which a wellbore passes, wherein the well has a plurality of previously stimulated intervals, which method comprises: properties) with registration of the pressure curve by a pressure sensor at the wellhead; b) determining the depth (L) of the treatment fluid injection point and the depth uncertainties (ΔL); c) providing a water hammer at the wellhead that induces tube waves; d) determining the depth (L) of the treatment fluid injection point and the depth uncertainties (ΔL) by treating the water hammer by high frequency pressure monitoring; e) determining the tube wave velocity from the combination of data from (b)-(d); f) providing hydraulic fracturing; and g) providing a water hammer at the wellhead at the end of fracturing operation (f) with an improved treatment fluid injection point depth and less uncertainty.

Other aspects of the claimed subject matter will be presented in the description and the appended claims.

Brief description of graphic materials

In FIG. 1 shows pressure versus time in accordance with embodiments of the present disclosure.

In FIG. 2 is a cepstrogram according to embodiments of the present disclosure.

In FIG. 3 is a flowchart for processing in accordance with embodiments of the present disclosure.

In FIG. 4 shows pressure versus time for pumping a viscous pack according to embodiments of the present disclosure.

In FIG. 5 and 6 are graphical representations illustrating refracturing monitoring processes in accordance with embodiments of the present disclosure.

Detailed description

The embodiments described herein generally relate to methods for monitoring the effectiveness of refracturing previously stimulated subterranean formations to improve well performance and hydrocarbon recovery. More specifically, the embodiments described herein relate to methods for monitoring, controlling, evaluating, and improving the efficiency of refracturing a well with multiple previously stimulated stages. In some embodiments, the methods may also include performing one or more recovery actions to make

- 1 040992 changes to the real-time processing project. The authors of the present description have found that the use of viscous pack technology in combination with high frequency pressure measurements (HFPM - High Frequency Pressure Measurement) with water hammer provides real-time information about the effectiveness of re-fracturing a subterranean formation with higher accuracy and reliability at a lower cost and in a shorter period of time than with either of these technologies. The higher accuracy of refracturing performance data that is achieved as described herein allows more stages to be restimulated (than in the case of, for example, viscous pack technology) with minimal risk of understimulating some stages and overstimulating others. .

As defined herein, understimulation can be considered hydraulic or acid fracturing. In addition, as defined herein, the term stage or interval defines an element of a wellbore completion that allows a hydraulic fracturing operation (treatment) to be performed at that location. In addition, multi-stage treatment (multi-stage fracturing) is defined as successive (staged) hydraulic fracturing operations. These definitions can be found in the Schlumberger Oilfield Glossary.

The methods of the present disclosure can be used to monitor the effectiveness of refracturing a well having multiple previously stimulated stages. Such methods can be used to monitor the effectiveness of a secondary or tertiary stimulation treatment to provide real-time information on the effectiveness of the re-fracturing in each stage of stimulation. With such information, the operator can decide, for example, whether a given stage of production is already effectively stimulated or whether other stages should be isolated and then re-fractured at that stage.

According to embodiments of the present disclosure, a method for monitoring the effectiveness of re-fracturing combines viscous pack (VP/VP) technology, i.e. injection of marker viscous fluid (with high viscosity that decomposes over time), and high frequency pressure measurements (HFPM) with water hammering at the end of the treatment stage and their further processing.

In practice, the viscous pack technology makes it possible to identify the position of a fracture obtained during formation stimulation by hydraulic fracturing. Such a method is based on a local change in the viscosity and/or density of the fluid injected into the wellbore and includes pumping the fracturing fluid into the wellbore at a pressure that is higher than the formation fracture pressure to create at least one fracture. After that, a marker pulse is pumped into the well, then the fracturing fluid is pumped back into the well. When the marker pulse enters at least one of the fractures of the hydraulic fracturing, a pressure-based response is observed, and the position of the fracture is determined by the volume of the hydraulic fracturing fluid injected after the marker pulse. A marker pulse is a portion of a fluid whose viscosity and/or density is different from the fracturing fluids injected before and after the marker pulse. Examples of viscous pack technology are discussed in more detail in WO 2018004370.

As stated above, viscous pack technology can be combined with high frequency pressure measurements (HFPM) to provide water hammer. In one or more embodiments, high frequency pressure measurements (HFPM) may use cepstral analysis (eng). For example, WO 2018004369 discusses in more detail a method for monitoring well operations based on cepstral analysis of downhole pressure data recorded at the wellhead. This method determines the position of the downhole object reflecting the hydraulic signal. In accordance with such a method, the well is filled with a fluid that allows the transmission of a hydraulic signal. A hydraulic signal source is provided that is in fluid communication with the well and configured to provide a hydraulic signal. The pressure sensor is configured to detect a hydraulic signal and is in communication with the wellbore via a fluid medium and at least one hydraulic signal source. Using a pressure sensor, a hydraulic signal is recorded and a pressure cepstrogram is created with an intense signal highlighted on the pressure cepstrogram. After that, an object is detected that reflects the hydraulic signal.

In accordance with one or more embodiments, a method for treating a subterranean formation through which a wellbore passes, such as a method for monitoring re-fracturing, comprises the use of sequential injection of a viscous pack (and depth determination), high-frequency monitoring of the pressure of hydraulic shocks (at the end of a viscous pack, also to determine the depth) and a diverter (fluid diverter) to block the stages with the highest fluid intake with additional high-frequency pressure monitoring at the end of injection of the specified diverter.

- 2 040992

Combining these methods makes it possible, for example, to reliably determine whether the diverter is working well or whether additional diverter needs to be injected. In addition, the amount of viscous pack that is injected can be reduced due to additional data obtained during high-frequency pressure monitoring. As a result, processing can be performed faster and at lower cost. The higher accuracy of treatment fluid deflection efficiency data achieved by using these two technologies also allows for more stages to be re-stimulated (than viscous burst technology) with a reduced (or even minimal) risk of under-stimulating some stages and over-stimulating others. .

According to embodiments of the present disclosure, a re-fracturing operation is performed on a well that has previously been stimulated (fracturing) and that has multiple previously stimulated intervals, but in which hydrocarbon production has declined, thus new stimulation (or re-stimulation, or re-fracturing) is considered appropriate. In one or more embodiments, the re-fracturing operation is performed in a specific sequence of steps as described below. In such embodiments, the first stage of a well stimulation treatment is to determine which of the previously stimulated stages of the well can receive fluids, followed by alternating stages of stimulation treatment (e.g., fracturing) to form new fracture(s) and isolating such(their) crack(s) using downhole whipstocks. The sequence of stages is repeated until all the stages planned for this stimulation are subjected (or earlier, if the work schedule is revised). Data may be collected and processed to evaluate the effectiveness of the stimulation treatment and determine future stimulation treatments.

In accordance with embodiments of the present disclosure, any type of fluid used as a stimulation fluid can be used. It is assumed that in some embodiments, the implementation of the properties of the liquid remain unchanged throughout the processing process. In addition, it is envisaged that in some embodiments, the implementation of the properties may vary from one stimulation to another; in such embodiments, the difference can be accounted for using tube wave velocity correction factors based on knowledge of the properties of the fluid. In one or more embodiments, the properties of the fluid may be unknown or poorly defined. In such embodiments, a more viscous pack may be pumped.

In accordance with one or more embodiments of the present disclosure, a re-fracturing operation in a multi-stage well may comprise the following sequence of operations.

1. Fluid injection in accordance with the stimulation plan (HF) to create the first hydraulic fracture. A fracture can appear in any of the 1.. .N stages available in the well.

2. Isolation of the created crack by applying a chemical (soluble) diverter, i.e. fluid with specially designed particles that can block an open crack.

3. Injection of fluid in accordance with the stimulation plan (HF) to create a second hydraulic fracture. The second fracture may appear in any of the 1.N stages available in the well. If a fracture forms in a new stage of production, the stimulation is considered successful. If a new fracture is not formed, and the fluid is pumped into the first fracture, then the new stage is not stimulated, and stimulation is considered a failure. Timely detection of a failed stimulation attempt can be used to update the stimulation plan, for example, to repeat the isolation stage of already stimulated stages, then change the concentration of additives in the diverter pack, followed by adjustment of the pack volume, then make changes to the fracturing plan, such as adjusting the volume of fluid injected to increase the fracture, or adjust the proppant/fibre concentration.

4. Isolate both existing cracks.

5. Carrying out a new stimulation treatment (HF).

As noted above, the sequence of stages is repeated until all stages planned for this stimulation are subjected to stimulation (or earlier, if the work schedule is revised due to new data). The prediction is whether the stimulation of any stage will be successful or if the fluid is pumped into already existing fractures. With the development of modeling capabilities, software and hardware, the ability to optimize designs before processing and in real time has become more feasible. Currently, there are several ways to determine the fluid entry point during re-fracturing, such as distributed temperature sensing (DTS), distributed vibration sensing (DVS), radioactive and chemical tracers, microseismic technologies. However, such approaches have numerous limitations and therefore the information obtained has a high measurement uncertainty, which can limit the reliability of the forecasts.

- 3 040992

The DTS method involves injection of a large volume of cold fluid and long-term measurements of temperature distribution along the wellbore. The DVS method is very sensitive to small volumes of gases because gas bubbles can cause false vibrations. The microseismic method works well in mechanically hard formations and depends on monitoring the location of the well relative to the treated well. In addition, microseismic technology is not downhole and is sensitive to events that occur several hundred feet from the wellbore. Thus, the vertical depth in the wellbore is not exactly known. The presence of chemical or radioactive tracers is indicative of zones of sufficiently high permeability in the reservoir, which may or may not be related to the fracture. Conversely, the absence (or concentration below background) of chemical or radioactive tracers in the wellbore zone may indicate that the particles were injected deep into the formation. Finally, these methods are unpopular for health, safety and environmental reasons.

Another method that is widely used due to its simplicity and low cost is surface pressure monitoring. In this case, the liquid entry point is not measured; instead, deflection performance is monitored by changing the instantaneous shutdown pressure (ISP): the deflection is considered successful if the post-stimulation ISV exceeds the previous stimulation MDV. Unfortunately, this method does not guarantee the accuracy of the results. In addition, the calculation of the MWR may take some time, and it can still be determined with some degree of uncertainty. Thus, the difference between the current and previous MHD values must exceed a minimum threshold, which is subjective. In addition, a negative difference between the MDOS values does not mean a bad deviation, and friction pressure losses must also be evaluated: if they increased compared to the previous stimulation, then the deviation is also successful, despite the difference in MDOS values (friction pressure may be higher for formations with lower value of MDOS due to friction losses in the damaged near-wellbore zone).

Another way to determine the liquid entry point is the viscous pack technology. When a viscous pack is pumped into the well, a pressure increase can be observed as the pack enters the fracture. The depth of the fluid entry point can be predicted from well completion data, injection rate, and the point in time when the fluid reaches the fracture. However, in many cases this depth can be predicted with an accuracy comparable to the distance between stimulated stages, and therefore it is impossible to obtain accurate results. In addition, pumping a viscous pack at the end of each stage may not be cost effective and may require more additional time. For these reasons, viscous pack technology is not very widely used on its own.

Without being bound by any theory, the authors of the present disclosure have found that the disadvantage of using viscous pack technology can be overcome by combining such technology with high frequency wellhead pressure measurements. This combination allows monitoring of treatment efficiency using re-fracturing. In one or more embodiments, the methods may use viscous pack technology, i. e. injection of a viscous fluid (1000 or more cP at 100 s ^-1 for at least 20 minutes with a rapid decrease in viscosity to 100 cP or less), and high-frequency pressure measurements with water hammer at the end of the operation, followed by data processing.

As described herein, high frequency pressure measurements are based on the analysis of water hammer (or tube wave) signals propagating in the wellbore. Tube waves are boundary waves that occur in cased wells when a Rayleigh wave collides with the wellbore and disturbs the fluid in the wellbore. The tube wave travels down the wellbore along the interface between the fluid in the wellbore and the wellbore wall. Because the tube wave is associated with the formation through which it passes, it can perturb the formation through open fractures crossing the wellbore, providing a compression effect that provides secondary tube waves that bounce up and down from the fracture location. The intercepted secondary tube waves may contain signatures to identify open fractures, as well as an amplitude qualitatively related to length and width, such as the volume of fluid-filled fracture space, in addition to other characteristics such as fracture closure pressure, fracture initiation pressure, etc. P. Tube waves can also be used to detect other objects such as obstacles, pipe sections of various diameters, perforations and open cracks.

In practice, the secondary tube waves can be reconstructed from the convolution of the primary tube waves by determining the time and magnitude of the peak value of the envelope of the reconstructed signal from the convolution. This time and magnitude change in a predictable way, and this change can be analyzed with depth. You can also use advanced tools to extract tube wave data to locate multiple fractures from the wellbore.

- 4 040992 algorithms for processing tube waves (for example, the cepstral analysis described above), as well as mechanisms for controlling pressure sources, including pump noise, active pulse sources, etc.

As used herein, high frequency pressure measurements can provide a computational period for water hammers (or tube waves) that are provided at the end of each stage (or even between stages when the injection rate is changing very rapidly). These periods refer to the time that the tube waves travel from the wellhead to the fracture and are reflected back from the fracture. Periods (or reflection times) can be converted to depth values if the tube wave velocity is known, which is not the usual case. Some other calibration information can be used to predict this speed. One way is to use the fluid entry point predicted by the viscous pack technology. In this case, the combination of time and depth values allows a fairly accurate estimate of the speed (at least in the given stage in which stimulation is performed). A reasonable assumption that the rate does not change too much between the nearest stages, as well as the use of other methods described below, can provide information about whether stimulation of all stages has occurred or not. This information is available at the end of each stage and can be used by the operator to adjust the stimulation plan for subsequent stages.

In accordance with one or more embodiments, a method for treating a subterranean formation through which a wellbore passes may comprise: a) pumping a viscous pack into the well while recording a pressure curve with a wellhead pressure sensor; b) determining the depth (L) of the treatment fluid entry point and depth uncertainties (ΔL); c) providing a water hammer at the wellhead that induces tube waves; d) Determining the depth (L) of the treatment fluid entry point and the depth uncertainties (ΔL) by treating the water hammer by high frequency pressure monitoring; e) determining the tube wave velocity from the combination of data from (b)-(d); f) providing hydraulic fracturing; and g) providing water hammer at the wellhead at the end of the fracturing operation with an improved depth of the treatment fluid entry point and less uncertainty. In such embodiments, the well has a plurality of previously stimulated intervals. In one or more embodiments, a plurality of stimulation treatments may be performed in the well.

In accordance with one or more embodiments, prior to injecting the viscous pack into the well, a data-frac treatment (ie, low-volume fracturing to obtain formation data) may be performed (https://petrowiki.org/Glossary). In such embodiments, the implementation of the viscous pack may be part of the fluid, the viscosity of which is at least 100 times the viscosity of the well fluid. In one or more embodiments in which multiple stimulation treatments are performed, a viscous pack is pumped prior to each fracturing treatment. In such embodiments, the implementation of water hammer can be achieved by turning off the pumps at the surface. In one or more embodiments, the high frequency pressure monitoring method includes processing the pressure signal, for example, including pre-filtering the signal and post-processing using cepstral analysis. In addition, it is envisaged that after step (g) a diverter can be additionally pumped into the wellbore. In such embodiments, the diverter may be part of a particle suspension capable of isolating at least one of the previously stimulated intervals. In one or more embodiments, the diverter may be selected from the group of chemical (soluble) and mechanical diverters.

In one or more embodiments, the method for treating a subterranean formation may further comprise performing a completion operation. In such embodiments, the completion operation is selected from the group of completions with the installation of a bridge plug in the perforation zone or completions using sliding sleeves.

In addition, it is contemplated that the method of treating a subterranean formation through which the wellbore passes may comprise: 1) pumping a first viscous pack into a well located in the subterranean formation, the well having a plurality of previously stimulated stages, 2) determining the depth (L) of the point fluid entry for treatment and depth uncertainty (AL) for those previously stimulated stages that can accept fluid, 3) providing water hammer at the wellhead to stimulate tube waves, 4) treating the water hammer by high frequency pressure monitoring to determine the depth (L) of the point treatment fluid entry and depth uncertainty (AL), 5) determining tube wave velocity by combining 2)-4), 6) performing a first stimulation treatment (such as fracturing) in at least one previously stimulated stage that receives fluid , to form the first new crack in at least one previously stimulated th stage, 7) providing water hammer at the wellhead at the end of treatment 6) with hydraulic fracturing with a refined depth of the entry point of the fluid for treatment and with less uncertainty, 8) isolating the first new fracture by pumping a portion of the diverter, 9) calculating at least reflection time

- 5 040992 water hammer and reflection time uncertainties using high-frequency pressure monitoring with water hammer, which provide, at least at the end of one stage of treatment, 10) prediction of the tube wave velocity for at least one previously stimulated (subjected to hydraulic fracturing) stage using less than the depth (L) of the fluid entry point and the shock reversal time, and 11) evaluating the effectiveness of the first stimulation treatment to determine future stimulation treatments, if any. In one or more embodiments, determining the depth (L) of the fluid entry point and the depth uncertainty (AL) of at least one previously stimulated stage is performed using viscous burst technology, high frequency pressure monitoring, or a combination thereof. In such embodiments, the depth determination (L) may have a resolution of at least 100 feet (30.48 m). In one or more embodiments, the maximum measured depth of at least one hydraulic fracture may be up to 40,000 feet (12,192 m). In addition, it is contemplated that a plurality of viscous packs and high-frequency hydraulic shocks can be used for stimulation in the first stage of the treatment.

In addition, it is envisaged that after isolation of the first new fracture (when the diverter is injected), a second viscous pack can be injected into the well. The next step is to check if there has been a shift in the previously stimulated stages that can receive fluid compared to the original value. If there is an indication that the first stimulation treatment was effective without any additional amount of diverter, a second stimulation treatment can be performed in the second stage.

In such an embodiment, a second stimulation treatment is performed at at least the second previously stimulated stage, which can receive fluid, to form a second fracture, after which the second new fracture is isolated by whipping, at least the water hammer reflection time is calculated (more precisely, the time required for the tube waves to travel from the wellhead to the fracture and back) and the uncertainty of reflection time using high-frequency pressure monitoring with hydraulic shocks, which provide, at least at the end of one stage of processing, predict the speed of the tube wave for, according to at least a second previously stimulated stage using at least the depth of the fluid entry point and the water hammer reversal time, and evaluate the effectiveness of the second stimulation treatment to determine future stimulation treatments, if any.

It is further contemplated that if the first stimulation treatment is ineffective, additional diverter may be injected. In such embodiments, the amount of diverter can be adjusted (up or down) based on the effectiveness of the re-fracturing. As described herein, the diverter can be selected from the group of chemical (soluble) and mechanical diverters. In such embodiments, a second isolation treatment may be performed in at least one previously stimulated step.

As noted above, the sequence of these processing stages is repeated until all the stages planned for this stimulation are subjected (or earlier, if the work schedule is revised). After stimulation, the next stage of treatment is the completion operation. In such embodiments, the completion operation can be selected from a group of completions with a bridge plug in the perforation zone or completions using sliding sleeves.

Further, it is contemplated that the method for treating a subterranean formation is a method for stimulating a subterranean formation through which a wellbore passes. In such illustrative embodiments, the method includes pumping a first viscous pack into a well located in a subterranean formation, the well having a plurality of previously stimulated stages, administering a first stimulation treatment to form a first new fracture in at least one previously stimulated stage that can receive fluid. , providing hydraulic shock at the end of the fracturing with an improved depth of the treatment fluid entry point and with less uncertainty, and adjusting the future stimulation treatment(s) in accordance with the processed input data collected at various stages of the treatment.

As noted above, the depth determination may have a resolution of at least 100 feet (30.48 m). In one or more embodiments, the maximum measured depth of at least one hydraulic fracture may be up to 40,000 feet (12,192 m).

According to one or more embodiments, a plurality of viscous packs and high frequency hydraulic shocks may be used for stimulation in the first stage of the treatment.

In addition, it is provided that after isolation of the first new fracture by pumping the diverter into the well, a second viscous pack can be pumped. The next step is to check if there has been a shift in the previously stimulated stages that can receive fluid compared to the original value. If there is an indication that the first stimulation treatment was

- 6 040992 effective and without any additional amount of diverter, it is possible to carry out a second treatment for stimulation in the second stage.

In such an embodiment, a second stimulation treatment is performed in at least a second previously stimulated stage that can accept fluid to form a second new fracture, provide a hydraulic shock at the end of the fracturing with an improved depth of the treatment fluid entry point and less uncertainty. and adjusting the future treatment(s) for stimulation according to the processed input data collected at the various stages of processing.

It is further contemplated that if the first stimulation treatment is ineffective, additional diverter may be injected. As described herein, the diverter can be selected from the group of chemical (soluble) and mechanical diverters. In such embodiments, a second isolation treatment may be performed in at least one previously stimulated stage.

As noted above, the sequence of these processing stages is repeated until all the stages planned for this stimulation are subjected (or earlier, if the work schedule is revised). After stimulation, the next stage of treatment is the completion operation. In such embodiments, the completion operation can be selected from a group of completions with a bridge plug in the perforation zone or completions using sliding sleeves.

High Frequency Pressure Measurement (HFPM)

The use of high frequency (at least 20 or 30 Hz) pressure measurement technology provides much more information than standard pressure measurement. Rapid rate changes from peak to zero at the end of injection can cause water hammer (or tube waves) to travel from the wellhead down to the fracture and back. The reflection time of these waves (typically 3 to 10 s) can indicate the depth of an open fracture and can generally be used to determine the fluid entry point. These vibrations may include parameters other than the vibration components, such as damping, frictional pressure loss, fluid leakage into the formation, noise, or reflections from other elements in the wellbore. Thus, determining the reflection time can be difficult. However, various methods have been developed to determine such parameters. For example, cepstral analysis can be used to measure reflection time, as shown in FIG. 2.

As shown in FIG. 1 and 2, in Fig. 1 shows a typical high frequency pressure curve during water hammer. Its cepstrogram is shown in Fig. 2. In particular, in FIG. 1 shows pressure fluctuations at the end of injection, and FIG. 2 shows a cepstrogram, i.e. amplitudes of waves with different reflection times as a function of time. In FIG. 2200 represents the strongest amplitude, i.e. reflection of the main pressure wave from the fracture, while 210 is represented as a line, shows the reflection time. Width 210 defines the uncertainty.

In most cases, the speed of the tube wave is unknown, and the reflection time itself is useless. However, a special algorithm can be used to determine the speed. In one or more embodiments, this can be described based on the example of a plug-in-perforation completion, but it can be extended to other cases. It is assumed that there are N available stages where cracks can potentially form.

L|^LN are the depths of these stages, and σL ₁ ... σL _N is the depth uncertainty. In the case where the stage has a width ΔL _i , the uncertainty σ Li can be calculated as the uncertainty for a uniform distribution and using formula 1:

σίί ^{= (1)}

The first fracture may be in the first stage (the depth and depth uncertainty of which are known) since there are no other perforations. This allows the calculation of the speed in the first stage and the corresponding determination of the uncertainty. This data can be used as an initial guess to calculate the second stage velocity, which, combined with the reflection time of events (such as water hammers) after the second stage treatment, can predict the possible depth of the second stage fracture. This predicted depth is then compared to the second stage perforation depth (if the mechanical isolation is successful) and the first stage perforation depth (if the mechanical isolation fails/leaks). The difference between the predicted depth and the available stage depth cannot exceed two to three sigma values, where σ is the standard deviation (or uncertainty) of the difference, which can also be calculated. This makes it possible to predict whether the second stimulation was successful, and it gives the probability of successful stimulation if both scenarios are carried out.

In addition, for each of these scenarios, the rate can be determined with higher accuracy if information from more than one stage is available, such as data on injection operations in the first and second stages. The same principle can be used for subsequent events.

- 7 040992 (stimulations). Using some advanced statistical methods (including Bayesian methods), it is possible to predict the position of the fracture for each treatment by considering each available scenario more accurately as more measurements are taken, the velocity value is adjusted, and it slowly changes along the lateral.

More than one scenario can be observed at any stage, but they all have their own probability p, which is based on the maximum likelihood method, description in formula 2:

uA'1 1? ( Фг”^) ² \ Φη“ £ίη) ² \ p(il,i2,..m) exp(^ _{2(σΡΪ+σ£?ι)} ) exp(^ -exp( ₂ ( _σ ο^ _η ) ) ⁽²⁾

Finally, the number of possible scenarios can be very large if the data for each event is very inaccurate (high values of στ _i and oLi - reflection time and depth uncertainty) and/or only a few events are observed. Conversely, this number can be small (only a few or even one) if the reflection times are precisely defined, the stage width is small compared to the distance between them, and the total number of stimulations is large enough.

Viscous pack technology and high frequency pressure measurements

In accordance with embodiments of the present disclosure, viscous pack technology and high frequency measurements can be used together. This combination allows refracturing to be monitored faster, with a high level of confidence, in a short time and with a minimum of resources involved. In such embodiments, monitoring is carried out as follows.

1. A viscous pack is pumped and the fluid entry point is determined with uncertainty. The given fluid entry point is tied to one of several stages with their own probability. The number of possible scenarios where a fracture will be created is less than or equal to the total number of stages.

2. Carry out the first treatment for stimulation. The use of hydraulic shocks at the end of the processing stage makes it possible to determine the reflection time and uncertainty. Using the values of the depth of the possible stages and the resulting reflection time, it is possible to predict the speed for each of the stages, as defined above in paragraph 1.

3. Pump in diverter. At the end of the diverter injection, hydraulic shocks are used to obtain a new reflection time, which, together with the velocity for each of the possible scenarios, allows the new depth to be predicted. This depth can then be compared with all possible stage depths where the second fracture can pass.

4. Create a new set of scenarios with their probabilities that are proportional to the product of the probabilities from pp.1 and 3 above. After normalization, scenarios with probabilities less than a given threshold value (for example, 0.5% or 0.005 of the most likely scenario) can be removed from consideration.

5. If the number of scenarios is greater than one, a new diverter may or may not be uploaded depending on their relative probabilities, time, and resource constraints.

6. Conduct the second stimulation. With the help of water hammer at the end of the processing stage, the reflection time and uncertainty can be determined. Using the data of all existing scenarios, the predicted depth of the second fracture is compared, as shown in formula 3:

(3) with all possible stages to estimate its location (in this case, the speed and time of reflection are used, the coefficient ½ arises from the path of the wave: the mouth - the bottom of the well and vice versa). If the location of the fracture is different from the location of the previous fracture, the stimulation can be considered successful and the rate can be updated using all available data, which should be similar, and for example, the actual rate at each stage can be calculated according to formula 4:

(4) where ^t l is the reflection time of the i-th event,

Di are the estimated fracture depths corresponding to a given event, the weights wi are the event weights (the longer the event reflection time and the depth uncertainty, the lower its weight).

The new probability for all scenarios is calculated as the normalized product of the probabilities defined in 1, 3, 5, 6. However, the situation in which one scenario remains at this stage, even if the stimulation was evaluated as successful, is not a common case. In fact, several scenarios are possible, if in each of them the first stage differs from the second stage. If in some scenarios stimulation ended in failure, the probability of failure should be estimated according to formula 5:

- ΣίίιΡΐ * (1 in case of successful rejection) (5)

- 8 040992

If the probability of failure is high enough, additional actions can be performed, such as creating a new event (starting and stopping a pump, opening or closing a valve, etc.). For example, in such a case, its water hammer can be analyzed and used in all revaluation scenarios. If the probability of failure is still high, additional actions can be taken, such as pumping a new viscous pack, assessing depth, reevaluating scenarios, etc. If failure is still likely, an additional diverter can be pumped.

7. Pump in a new diverter. Reevaluate all scenarios.

8. Carry out the third treatment for stimulation. The use of water hammer at the end of the processing stage allows the reflection time and uncertainty to be determined. Using the data, all scenarios are re-evaluated to decide on the effectiveness of the stimulation of all three stimulation operations.

9. Continue processing for stimulation.

This decision sequence diagram is shown in FIG. 3. This flowchart allows a well with multiple stages to be stimulated to be re-fractured much faster than currently used methods, with fewer resources, and providing more reliable information on the effectiveness of stimulation to treat each stages.

Examples

The following examples are provided as further illustration of the method for monitoring re-fracturing in accordance with the present disclosure and should not be interpreted as limiting the scope of the disclosure unless expressly stated otherwise in the appended claims.

For comparison, the classic viscous pack technology was used. The classic viscous pack technology (without high frequency pressure monitoring) includes the following sequence of steps:

1. Mix the pack using a linear gel and a crosslinking agent.

2. Approximately 3-4 m ³ of a viscous pack (which has a viscosity of at least 100 times the viscosity of the well fluid) is pumped at low flow rates. The first viscous pack is pumped into the well after the injection test. Such a pack is used to determine the stage that best accepts the liquid. The determination is carried out by monitoring and analyzing the pressure. The surface pressure slope should increase as the viscous pack enters the fracture.

3. Carry out the first stage of stimulation.

4. A diverter (isolating agent) is pumped into the wellbore.

5. A second viscous pack is pumped in to check if there has been a shift in the point at which the liquid is received, compared to the original value (the position of the diverter isolation). Depending on the result (if the diverter does not fulfill its purpose), additional chemical (soluble) diverter can be pumped or other actions agreed with the client.

6. After deflection is achieved, a second stimulation (fracturing) is performed and the treatment is continued in the same manner from one stimulation stage to the next.

The method for determining the liquid entry point may involve finding the optimal intersection point of two (almost) linear sections of the pressure-time curve with its statistical processing. From this intersection point, in combination with well completion data and injection rate, the depth value of the fluid entry point is derived. The liquid-receiving stage is predicted by comparison with the depths of the various stages.

A typical pressure curve with analysis to determine the fluid entry point is shown in FIG. 4. In FIG. 4 shows an identification or marker pack as described in WO 2018004370. As can be seen from FIG. 4, the change in slope from a small angle to a large one determines the time of entry of a viscous pack into an open fracture (since the start of injection). The result is 17.7±0.3 min. For a typical pack velocity of ~2 m/s, this results in a depth estimation error of about 36 m, which is comparable to the typical distance between stages. Thus, positioning a viscous pack with such accuracy does not guarantee a reliable response for all processing steps.

A two-stage re-fracturing was performed in the well. The well itself contains 4 stages (perforations separated by packers). The first stimulation was datafrack type to obtain data on the general properties of the formation (pressure declining curve analysis) and to determine which stage can best accept fluid (using high frequency pressure monitoring). A data fracturing operation (or fracturing preparatory work) is defined as pumping a moderate amount of clean fracturing fluid at a pressure that is higher than the reservoir fracturing pressure to collect information about the mechanical properties of the rock, this evaluation is necessary for more accurate prediction

- 9 040992 subsequent full-scale operation of hydraulic fracturing (hereinafter referred to as stimulation). Since there was no information about the tube wave velocities (except for physical limitations for the well fluid from 1300 to 1700 m/s), this measurement was not decisive, and then a viscous pack was used. Three sets of data were then available: data-frac data (processed with HFPM), viscous pack depth determined from pressure surge (standard viscous pack technology), and water hammer data at the end of viscous pack injection (processed with HFPM technology). ). The results are presented in table. 1.

It is noted that the use of a viscous pack allows to predict stages with probabilities of 28 and 72% for stages 3 and 4. If injection of a viscous pack is the only technology used, the operator cannot rely on this data. In this case, HFPM technology was also used, and it made it possible to predict 30 and 70% for the same stages in the wellbore. Thus, their combination (combination of probabilities from different types of measurements) is more reliable. The main processing stage presents another piece of information (water hammer at the end of injection, which is processed using HFPM technology); the results of three injection operations are given in table. 2. It should be noted that the water hammer data, even in combination with all previous data, is not exhaustive in identifying the dominant stage capable of receiving liquid: stage 4 is most likely to be able to accept liquid (with a lower probability for stage 3). This may mean that both stages receive liquid at the same time with different flow rates.

When pumping a chemical (soluble) diverter (insulating agent), the obtained data on hydraulic shocks are analyzed, which show that the previous stages (3 and 4) are isolated (Table 3). This information is already sufficient for the second stimulation, and as a result, the injection of a viscous pack is not carried out at this stage. However, the quality of water hammer after whipping is low. This is because when diverter is injected, the best receiving stages are isolated (blocked) and tubular wave reflections can occur from minor sources (i.e., near-closed fractures that cannot receive liquid).

Table 1—Results of refracturing monitoring with HFPM and viscous pack technology. Perform two injections of liquid (data-coat and viscous pack)

OPERATION Stages subjected to stimulation (HF) 1 2 3 4 Datafrak1 (HFPM processing) 0% eleven% 59% thirty% Viscous pack 1 (HFPM treatment) 0% 0% thirty% 70% Viscous pack 1 (VP) 0% 0% 28% 72%

Table 2. Results of refracturing monitoring with HFPM and ______ viscous pack technology. Added main operation (hydraulic fracturing)___________

OPERATION Stages subjected to stimulation (HF) 1 2 3 4 Datafrak1 (HFPM processing) 0% eleven% 59% thirty% Datafrak1 (HFPM processing) 0% 0% thirty% 70% Viscous pack 1 (HFPM treatment) 0% 0% 28% 72% Main fracturing operation 1 (HFPM treatment) 0% 0% 42% 58%

Table 3. Monitoring results of re-fracturing after injection of a chemical (soluble) diverter

OPERATION Stages subjected to stimulation (HF) 1 2 3 4 Datafrak1 (HFPM processing) 0% eleven% 59% thirty% Datafrak1 (HFPM processing) 0% 0% thirty% 70% Viscous pack 1 (VP) 0% 0% 28% 72%

- 10 040992

Main fracturing operation 1 (HFPM treatment) 0% 0% 42% 58% Whipstock Injection (HFPM Treatment) 71% 24% 4% 0%

The second main processing stage can then be injected. The results are presented below in table. 4. At this stage, a viscous pack is pumped. In table. 5 shows the results of this injection. However, injection of a viscous pack may not be performed due to the use of viscous pack and HFPM technologies in the stimulation of the previous stage. The results presented in table. 5 are identical to the results obtained without pumping the second viscous pack. This allows you to save time and resources and start oil production at a particular well faster. In this case, two main processing steps were analyzed. If more than two consecutive stimulation treatments were performed, the results of resource and time evaluations can be taken into account.

These results can be presented as shown in Fig. 5 and 6. In FIG. Figures 5 and 6 show the depth and fluid entry point for all events. Cloud size determines depth uncertainty, more than one cloud per event indicates the likelihood of different stages being stimulated. As can be seen from the example in Fig. 5, the clouds are located at the calculated depths, their sizes indicate depth uncertainties (this figure shows the final results). It is clearly seen how the stimulation depth changes throughout the treatment: data-frac fracturing, injection of the first viscous pack and the main stage of treatment (operation 1) show stimulation at stages 3 and 4. The diverter analysis showed that, most likely, stages 3 and 4 are blocked and a reflection from stage 1 is observed; additional measurements fully confirm this.

Table 4. Results of monitoring of repeated hydraulic fracturing without the second viscous pack

OPERATION Stages subjected to stimulation (HF) 1 2 3 4 Datafrak1 (HFPM processing) 0% eleven% 59% thirty% Viscous pack 1 (HFPM treatment) 0% 0% thirty% 70% Viscous pack 1 (VP) 0% 0% 28% 72% Main fracturing operation 1 (HFPM treatment) 0% 0% 42% 58% Whipstock Injection (HFPM Treatment) 71% 24% 4% 0% Main fracturing operation 2 (HFPM treatment) 100% 0% 0% 0%

Table 5. Results of monitoring of repeated hydraulic fracturing with the second viscous pack

OPERATION Studi 1 and I will submit 2 tee stimulating 3 1 and (frac) 4 Datafrak1 (HFPM processing) 0% eleven% 59% thirty% Viscous pack 1 (HFPM treatment) 0% 0% thirty% 70% Viscous pack 1 (VP) 0% 0% 28% 72% Main fracturing operation 1 (HFPM treatment) 0% 0% 42% 58% Whipstock Injection (HFPM Treatment) 71% 24% 4% 0% Viscous bundle 2 (HFPM treatment) 100% 0% 0% 0% Viscous bundle 2 (VP) 100% 0% 0% 0% Main fracturing operation 2 (HFPM treatment) 100% 0% 0% 0%

Embodiments of the present disclosure provide methods for monitoring re-fracturing that determine the effectiveness of re-fracturing a subterranean formation. In particular, it has been found that such methods allow determination of the depth of the receiving fluid stage by responding to pressure changes in a viscous pack in combination with high frequency pressure monitoring. The method provides functionality such as calibrating the pressure wave velocity, finding the fluid entry point, measuring the depths of stimulated stages, and preventing overstimulation of already stimulated stages. The method as described in this document can be applied to cracks of any

- 11 040992 sizes, as well as for any distance between cracks. In addition, the method for monitoring the effectiveness of re-fracturing as described herein can provide calibration of the pressure wave velocity during the treatment.

Although several exemplary embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications to the exemplary embodiments are possible without substantially departing from the present disclosure. Accordingly, all such modifications are intended to be included within the scope of the present disclosure as defined in the following claims. In the claims, the means plus function clauses represent structures that are presented herein as performing the described function, and not only as structural equivalents, but also as equivalent structures. Therefore, although a nail and a screw cannot be structural equivalents, since a nail uses a cylindrical surface to hold wood together while a screw uses a helical surface, in a wood fixing environment, a nail and a screw can be equivalent structures.

Claims (11)

1. A method for treating a subterranean formation through which a wellbore passes, wherein the well has a plurality of previously stimulated intervals, the method comprising: a) injection of a viscous pack into the well with the registration of the pressure curve by the pressure sensor at the wellhead; b) determining the depth (L) of the treatment fluid entry point and depth uncertainties (ΔL); c) providing a water hammer at the wellhead that induces tube waves; d) determining the depth (L) of the treatment fluid entry point and the depth uncertainties (ΔL) by processing the water hammer by high frequency pressure monitoring; e) determining the tube wave velocity from the combination of data (b)-(d); f) performing hydraulic fracturing; and g) generation of water hammer at the wellhead at the end of operation (f) with an updated depth of the entry point of the treatment fluid and with less uncertainty. 2. The method of claim 1, wherein a plurality of stimulation operations are performed. 3. The method of claim 1, wherein the data fracturing is performed prior to pumping the viscous pack. 4. The method of claim 1, wherein the viscous pack is included in a fluid whose viscosity is at least 100 times that of the well fluid. 5. The method of claim 1 wherein the water hammer is provided by stopping the pumps at the surface. 6. The method of claim 1, wherein the high frequency pressure monitoring method comprises pressure signal processing. 7. The method of claim 6, wherein the processing of the pressure signal comprises pre-filtering the signal. 8. The method of claim 6, wherein the pressure signal processing further comprises cepstral analysis processing. 9. The method of claim 1, wherein the diverter is further pumped into the wellbore after (g). 10. The method of claim 1, wherein the depth determination (L) has a resolution of at least 30.48 m (100 ft). 11. The method of claim 1, further comprising a completion operation, wherein the completion operation is selected from the group of completions with the installation of a bridge plug in the perforation zone or completions using sliding sleeves.