OFFSET PRESSURE RESPONSE

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a non-provisional application which claims benefit under 35 USC § 119 (e) to U.S. Provisional Application Ser. No. 63/654,660 filed May 31, 2024, entitled “OFFSET PRESSURE RESPONSE,” which is incorporated herein in its entirety.

FEDERALLY SPONSORED RESEARCH AND DEVELOPMENT

None.

BACKGROUND OF THE INVENTION

Hydraulic fracturing is an economically important stimulation technique applied to reservoirs to increase oil and gas production. During hydraulic fracturing stimulation process, highly pressurized fluids are injected into a reservoir rock. Fractures are created when the pressurized fluids overcome the breaking strength of the rock (i.e., fluid pressure exceeds in-situ stress). These induced fractures and fracture systems (network of fractures) can act as pathways through which oil and natural gas migrate en route to a borehole and eventually brought up to surface. Efficiently and accurately characterizing created fracture systems is important to more fully realize the economic benefits of hydraulic fracturing. Determination and evaluation of hydraulic fracture geometry can influence field development practices in a number of important ways such as, but not limited to, well spacing/placement design, infill well drilling and timing, and completion design.

More recently, fracturing of shale from horizontal wells to produce hydrocarbons has become increasingly important. Horizontal wellbore may be formed to reach desired regions of a formation not readily accessible. When hydraulically fracturing horizontal wells, multiple stages (in some cases dozens of stages) of fracturing can occur in a single well. These fracture stages are implemented in a single well bore to increase production levels and provide effective drainage. In many cases, there can also be multiple wells per location.

What is needed is an effective and efficient way to monitor well treatments and collect formation pressure data including a variety of pressure responses.

SUMMARY OF THE INVENTION

The invention more particularly includes utilizing a downhole check valve to allow a variety of pressure diagnostics to be easily captured and compared within a single monitor well. Pressure responses from below the check valve are open to the formation and provide detailed stress shadowing, poroelastic pressure response, and other sensitive pressure measurements from the open toe, allowing ingress from the wellbore while additional responses can be obtained above the check valve provided the pressure events below do not overcome the pressure above or the spring setting of the valve. This allows for an increase in available data points from the monitor well and a direct comparison of geomechanical and mechanical responses.

In one embodiment, a swab cup/sealing dart has been deployed allowing high direct & poroelastic fracture connections from below the dart to be observed while also allowing mechanical pressure responses to be observed as fractures intersect the casing further uphole. This case study utilizes surface pressure with downhole DAS fiberoptic to distinguish between pressure response types.

In another embodiment, a temporary wellbore seal the temporary wellbore seal comprising one or more pressure sensors selected from a distal pressure sensor, a proximal pressure sensor, or a both a distal pressure sensor and a proximal pressure sensor.

Additionally, methods to measure a sealed wellbore pressure include identifying a monitor wellbore to be sealed the monitor wellbore adjacent a treatment wellbore; pumping a temporary seal into the monitor wellbore until a sufficient length of wellbore is sealed; installing a pressure sensor at the surface of the monitor wellbore; treating the treatment wellbore while measuring pressure at the pressure sensor; recording the sealed wellbore pressure from the monitor wellbore; repeating steps d & e until the treatment wellbore has been completely treated; and removing the temporary seal.

In another embodiment, a sealed wellbore pressure and a poroelastic response are measured by identifying a monitor wellbore to be sealed the monitor wellbore adjacent a treatment wellbore; pumping a temporary seal into the monitor wellbore until a sufficient length of wellbore is sealed the temporary seal having a distal pressure monitor; installing a pressure sensor at the surface of the monitor wellbore; treating the treatment wellbore while measuring pressure at the pressure sensor; recording a sealed wellbore pressure and a poroelastic response from the monitor wellbore; repeating steps d & e until the treatment wellbore has been completely treated; and removing the temporary seal.

A method to measure a sealed wellbore pressure and a poroelastic response may include identifying a monitor wellbore to be sealed the monitor wellbore adjacent a treatment wellbore; pumping a temporary seal into the monitor wellbore until a sufficient length of wellbore is sealed the temporary seal having a distal pressure monitor and a proximal pressure monitor; installing a pressure sensor at the surface of the monitor wellbore; treating the treatment wellbore while measuring pressure at the pressure sensors; recording a sealed wellbore pressure and a poroelastic response from the monitor wellbore; repeating steps d & e until the treatment wellbore has been completely treated; and removing the temporary seal.

A temporary seal may be created from a cup, ball, dart, pig, FDI valve, or disposable bottom hole assembly. The temporary seal may have one or more accessories selected from a pressure sensor, thermometer, flow meter, accelerometer, camera, data storage, battery, transmitter, check valve, burst disk, control valve, pressure sensing valve, safety valve, wireline distributor, fiberoptic distributor, or combinations thereof. The temporary seal transmits data through a wireline or fiber optic cable.

A treatment for the treatment well may be fracturing, refracturing, acid fracturing, washing, water jetting, cementing, completion, pressure testing, chemical treatment, scale removal, H2S treatment, nitrogen treatment, high pressure breakdown, gas storage, liquid storage, or other well pumping operation.

As used herein, pressure response includes stress shadowing, poroelastic response measurement (PRM), sealed wellbore pressure monitoring (SWPM), and other wellbore pressure measurements.

As used herein, temporary seal may include a ball or dart, a wash cup, a pig, or a bottom hole assembly (BHA), a temporary disc or other wellbore occlusion that seals the entirety of the wellbore across the entire circumference of the wellbore. In some embodiments the temporary seal may include a valve, checkvalve, pressure release valve, or other apparatus to temporarily prevent flow through the seal or to limit flow based on pressure.

In another embodiment, the temporary seal may include one or more sensors including pressure, temperature, flow meter, and the like.

In another embodiment the temporary seal is dissolvable. In another embodiment the temporary seal is retrievable. In another embodiment the temporary seal may communicate through a wireline, fiberoptic or other means to transmit data to the surface. In another embodiment the temporary seal may store data until retrieved.

As used herein, distal refers to the toe of the well or the end of the well farthest from the wellhead and proximal refers to the wellhead or the end closest to the wellhead. An open toe refers to the end of the well being open to the formation and receiving pressure readings directly from changes in the reservoir.

As used herein, fracturing well refers to the well being fractured and monitor well refers to one or more adjacent wells within the formation.

BRIEF DESCRIPTION OF DRAWINGS

The patent or application file contains at least one drawing executed in color. Copies of this patent or patent application publication with color drawing(s) will be provided by the Office upon request and payment of the necessary fee. A more complete understanding of the present invention and benefits thereof may be acquired by referring to the follow description taken in conjunction with the accompanying drawings.

FIG. 1 is a wireline or fiberoptic wire dispenser comprising a cup, shaft, and dispenser along with several alternative temporary plug designs.

FIG. 2 is an FDI valve installed providing unidirectional flow through the toe of the wellbore.

FIG. 3 is a wellbore diagram showing multiple wellbores in a reservoir.

FIG. 4: FIG. 4A shows the Pressure in a monitor well and FIG. 4B shows the pump rate in frac well.

FIG. 5: VFR Comparison from both Data Types.

FIG. 6: Data Match from a Fracturing Stage; FIG. 6A shows a Distributed Acoustic Fiber optic data set; FIG. 6B shows the pressure in the monitor well; FIG. 6C shows the pressure and pump rate in the fracturing well.

FIG. 7: Data Match from a Fracturing Stage; FIG. 7A shows a Distributed Acoustic Fiber optic data set; FIG. 7B shows the pressure in the monitor well; FIG. 7C shows the pressure and pump rate in the fracturing well.

FIG. 8: Data Match from an outlier Fracturing Stage; FIG. 8A shows a Distributed Acoustic Fiber optic data set; FIG. 8B shows the pressure in the monitor well; FIG. 8C shows the pressure and pump rate in the fracturing well.

FIG. 9: Data Match from an outlier Fracturing Stage; FIG. 9A shows a Distributed Acoustic Fiber optic data set; FIG. 9B shows the pressure in the monitor well; FIG. 9C shows the pressure and pump rate in the fracturing well.

FIG. 10: Data Match from an outlier Fracturing Stage; FIG. 10A shows a Distributed Acoustic Fiber optic data set; FIG. 10B shows the pressure in the monitor well; FIG. 10C shows the pressure and pump rate in the fracturing well.

FIG. 11: Data Match from an outlier Fracturing Stage; FIG. 11A shows a Distributed Acoustic Fiber optic data set; FIG. 11B shows the pressure in the monitor well; FIG. 11C shows the pressure and pump rate in the fracturing well.

DETAILED DESCRIPTION OF THE INVENTION

Turning now to the detailed description of the preferred arrangement or arrangements of the present invention, it should be understood that the inventive features and concepts may be manifested in other arrangements and that the scope of the invention is not limited to the embodiments described or illustrated. The scope of the invention is intended only to be limited by the scope of the claims that follow.

As shown in FIG. 1, Wireline or fiberoptic dispenser comprising a cup, shaft, and dispenser and alternative temporary designs. Alternative designs include a cup, ball, pig, dart, or disposable BHA. A cup is inexpensive and directional, meaning the cup can be dropped and pumped in until it seats, with the distal end pointing out the toe of the well and the proximal end pointing toward the well head. A ball may be completely spherical or may have a seat or trailing end to help maintain directionality. In it's simplest form the ball is spherical and may have two diametrically opposed sensors, thus when the ball seats, it may have one sensor on the toe side of the seat and one sensor on the wellbore side of the seat. A pig is typically made of a polymeric material that occupies the entire drift of the wellbore for several inches or feet. Typically the pig, used for cleaning wellbores has a nose on one end and flexible rings around the diameter of the pig. The flexible rings may be one diameter or may be different diameters depending on the pig design. A large number and variety of pigs are available commercially and a person of ordinary skill in the art would be able to select an appropriate pig from a variety of vendors. In one embodiment the pig has one or more sensors in the nose, has a solid body in a polymeric exterior. The pig may also have one or more sensors on the tail. The nose is distal and faces the toe of the well and the tail is proximal and faces the interior of the wellbore. Finally, a bottom hole assembly or BHA may be designed to meet a number of requirements. Shown in FIG. 1 is a disposable BHA comprising a cup, wireline storage, and a wireline dispenser. The BHA may comprise many different types of equipment and sensors, the BHA may be wired or wireless. The BHA may also have batteries, processors, sensors, data recorders, a clock, depth meter, pressure meter, thermometer, flow meter, accelerometers, and/or other sensors to measure a variety of wellbore properties.

As shown in FIG. 2, a simple unidirectional check valve may have a ball or plate that allows fluid to flow in one direction but prevents flow in the opposite direction. Check valves may be a simple ball design as shown or may have a spring, door, or other obstruction that limits flow or the rate of flow in a given direction or below a selected pressure in the case of a pressure sensing valve.

The following examples of certain embodiments of the invention are given. Each example is provided by way of explanation of the invention, one of many embodiments of the invention, and the following examples should not be read to limit, or define, the scope of the invention.

Example 1: Converting Nearby Well(s) to Monitor Wells

In one embodiment an inexpensive cup, ball, dart, or wiper may be used to convert a nearby well quickly and easily into a monitor well. By running temporary seal into a well bore and monitoring pressure at the wellhead, a nearby well may be converted into a monitor well. For example a temporary ball may dropped into a monitor well near a treatment well undergoing fracturing. The ball is pumped in with minimal pressure until the ball seats at the toe of the well. Once seated, the pressure within the wellbore can be monitored continuously from the wellhead and fracturing treatments in nearby wells can be monitored. Due to the ease of well plugging, multiple monitor wells may be monitored during treatment to assess signal distance, strength and direction. In one embodiment two or more wells are temporarily sealed to create multiple monitor wells during fracturing and pressure is monitored from the well heads. It is noted that the monitor well may be a horizontal or vertical well dependent solely on proximity to the treatment well.

Example 2: Converting Nearby Well(s) to Monitor Wells and Retrieving Toe Pressure

In another embodiment, the inexpensive seal includes a toe pressure monitor to monitor toe pressure during fracturing treatments. A cup, ball, pig, or dart with a pressure sensor on the distal end of the seal is seated in the toe of the well. The pressure is monitored during one or more fracturing treatments in addition to monitoring wellhead pressure. The data for wellhead pressure and toe pressure can then be compared directly in the same well. In one embodiment the temporary seal may be connected to a wireline or fiberoptic cable allowing information to be transmitted in real time. In another embodiment, the temporary seal may be retrieved to acquire the data after treatment.

Example 3: Converting Nearby Well(s) to Monitor Wells and Retrieving Toc & Wellbore Pressure

In another embodiment, the inexpensive seal includes a toe pressure monitor and a wellbore pressure monitor to monitor toe pressure and wellbore pressure simultaneously during fracturing treatments. A temporary seal with two pressure sensors one on the distal end and one on the proximal end of the seal is seated in the toe of the well. The pressure is monitored on the toe and wellbore side of the seal during one or more fracturing treatments in addition wellhead pressure may also be monitored. The data for wellhead pressure, toe pressure, and wellbore pressure can then be compared directly in the same well. In one embodiment the temporary seal may be connected to a wireline or fiberoptic cable allowing information to be transmitted in real time. In another embodiment, the temporary seal may be retrieved to acquire the data after treatment.

The methodology of using a downhole check allows for an increase in available data points from the monitor well and a direct comparison of geomechanical and mechanical responses. The type of pressure responses relative to the location of the downhole check provides additional insight into fracture geometry. Fracture geometry data obtained from PRM can be used to augment statistical frequency of the mechanical pressure responses observed above the check valve. Use of a downhole pressure gauge, or multiple downhole pressure gauges could also be useful in distinguishing between pressure response types, fracture geometry, and connectivity of the stimulated rock volume (SRV) between wells. The application of this methodology could use tools deployed on the production casing, tubing, coiled tubing, or via wireline deployment. The check valve could be permanent, temporary/degradable, or retrievable. Potential tools currently available include ball drop/caged ball frac plugs and tubing conveyed check valves with or without a packer.

Utilizing a downhole check valve allows different types of pressure response diagnostics to be easily obtained and compared within a single monitor well. Pressure responses from below the check valve are PRM type, allowing ingress from the wellbore while additional responses can be obtained above the check valve provided the pressure events below do not overcome the pressure above the sensitivity of the pressure valve. This allows for an increase in available data points from the monitor well and a direct comparison of geomechanical and mechanical responses. Location of the downhole check valve can be easily manipulated depending on the desired diagnostic and potentially moved multiple times. Intervention is minimal and only requires one monitor wellbore. Surface, downhole, or both surface and downhole pressure can be used.

Example 4: Fiber Optic and Pressure Monitoring During Refracturing

In order to observe pseudo-sealed wellbore and distributed acoustic signals simultaneously, a disposable DAS fiber optic filament was pumped down monitor wells D1 and C1 prior to fracturing treatment well A1 which required refracturing. Second frequency surface pressure gauges were also deployed on the monitor wells D1 and C1. Both D1 and C1 were open toe wells and could be used to monitor fracturing. The open toe was required to pump fluids into the well carrying the fiber to the bottom of the well. No issues pumping fiber into the monitor well or subsequently fracturing of the wells after initial fracturing was completed. In other words, the monitor wells were sufficient to monitor fracturing of nearby wells and could subsequently be fractured when required.

The disposable fiber pump down bottom hole assembly (BHA) shown in FIG. 1 utilized a 4.5″ OD polymeric dart to pull the disposable BHA to the toe of the well. The disposable fiber was pumped down an monitor well prior to fracturing an adjacent well that required refracturing. Second frequency surface pressure gauges were also deployed on the monitor wells. The monitor well had an open toe on allowing the disposable BHA to pumped to the toe of the monitor well. There were no issues subsequently fracturing the monitor well after the initial fracturing was completed on the initial treatment well.

As shown in FIG. 3, the monitor wellbore C1 overlapped the wellbore being fractured A1 allowing observation of subtle pressure changes even with no toe overlap. In FIG. 5, the pressure observed in the monitor well C1 is shown above the pump rate and pressure in the treatment well A1. A compressive response with <10 psi magnitude could be observed in the monitor well while the treatment well was being fractured. As shown in FIG. 5, the correlation of VFR Comparison from both Data Types, examples of outliers (red) reveal delayed FDI picks from fiber due to coupling issues. Pressure is likely more reliable for the FDI arrival/VFR calibration but DAS provides an accurate depth measurement.

Example 5: Fiber Optic and Pressure Monitoring During Fracturing with Toe Sensors

In order to observe sealed wellbore and distributed acoustic signals simultaneously, a disposable DAS fiber optic filament may be pumped down one or more monitor wells prior to fracturing a treatment well. In one embodiment a disposable BHA includes a pressure sensor at the nose of the wash cup, the disposable BHA may include one or more wash cups of varying width and flexibility, possibly including a larger soft flexible cup behind a smaller more rigid flexible cup. The larger cup exceeding the wellbore drift and sealing the entirety of the wellbore. The BHA contains a transmitter for transmitting BHA sensor information through the fiberoptic cable. The BHA sensor information being transmitted between DAS interrogations on the fiberoptic cable.

FIGS. 6-11 show a comparison of changes in LF-DAS during treatment compared to increasing pressure and the treatment during a similar time. FIGS. 6 & 7 show a good correlation between LF-DAS and pressure measurements providing an excellent match, FIGS. 8-11 show the identification of errors in treatment, pressure measurement, sealing, LF-DAS, and the like.

FIG. 8 demonstrates an outlier caused by possible fiber mis-interpretation due to lack of coupling with the casing.

FIG. 9 demonstrates an outlier caused by possible fiber mis-interpretation due to lack of coupling with the casing. Note 2 strain events are seen on fiber and 2 matching pressure events are present.

FIG. 10 demonstrates an outlier caused by possible fiber mis-interpretation due to lack of coupling with the casing.

FIG. 11 demonstrates an outlier caused by missing fiber data at the start of the stage.

Benefits of the current system include, being able to collocate the sealed region with the area of fracturing. Given that wellbores may be thousands of feet in length and changes in pressure due to fracturing may be regionally located, the ability to easily move the sealed section of the monitor well adjacent to the area being fractured will increase sensitivity and allow subtle changes in pressure to be observed. In one embodiment, the upper and lower ends of a pig or dart may be sealed, and the pressure measured between to two ends of the tool meaning that the area where the pressure is measured can be isolated to a meter or less. Additionally if the tool is connected via wireline or fiberoptic, data may be retrieved and analyzed during the fracturing treatment allowing the operator to identify when the fracturing signal is detected, the magnitude of the fracturing signal, and the changes as pressure is decreased.

Although the systems and processes described herein have been described in detail, it should be understood that various changes, substitutions, and alterations can be made without departing from the spirit and scope of the invention as defined by the following claims. Those skilled in the art may be able to study the preferred embodiments and identify other ways to practice the invention that are not exactly as described herein. It is the intent of the inventors that variations and equivalents of the invention are within the scope of the claims while the description, abstract and drawings are not to be used to limit the scope of the invention. The invention is specifically intended to be as broad as the claims below and their equivalents.

Turning now to the detailed description of the preferred arrangement or arrangements of the present invention, it should be understood that the inventive features and concepts may be manifested in other arrangements and that the scope of the invention is not limited to the embodiments described or illustrated. The scope of the invention is intended only to be limited by the scope of the claims that follow. At the same time, each and every claim below is hereby incorporated into this detailed description or specification as an additional embodiments of the present invention.

REFERENCES

In closing, it should be noted that the discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. Each of the references below is incorporated in their entirety for all purposes.

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