WO2016200808A1

WO2016200808A1 - Controlled placement of proppant while fracturing

Info

Publication number: WO2016200808A1
Application number: PCT/US2016/036211
Authority: WO
Inventors: David Lindsay Alexander LANGILLE; Menno Mathieu Molenaar
Original assignee: Shell Oil Company; Shell Internationale Research Maatschappij B.V.
Priority date: 2015-06-09
Filing date: 2016-06-07
Publication date: 2016-12-15

Abstract

The present invention includes a method for providing fractures (105) from a wellbore in a formation (122), the method including the steps of: providing a wellbore into the formation; providing at least one controllable sleeve valve (104) incorporated into a casing (102) within the wellbore; providing a sensor (114) to determine a flow rate of fluids passing through the controllable sleeve valve; injecting into the wellbore a fluid at a pressure sufficient to initiate and propagate a fracture in the formation juxtaposed to the sleeve valve; including a proppant material in the fluid; determining, in real time, the amount of proppant that has entered the fracture juxtaposed to the sleeve valve; and closing the sleeve valve when a predetermined amount of proppant has entered the fracture.

Description

CONTROLLED PLACEMENT OF PROPPANT WHILE FRACTURING

Background

Hydraulic fracturing is conducted to increase the surface area of a formation that is in communication with a wellbore in order to increase, or stimulate, production of hydrocarbons from the formation. To conduct a hydraulic fracturing operation from a cased portion of a wellbore, perforations are created in the casing by, for example, explosive charges that create holes in the casing and into the formation. Perforations are most often grouped into small intervals referred to as perforation clusters (or just "clusters"). In the case of a horizontal well, the perforation clusters are generally spaced evenly down the length of the lateral section.

Fluids are then pumped into the wellbore that is in communication with the formation through the perforations at pressures which exceed the pressure necessary to cause a fracture to form in the formation extending from the perforations. Fractures are typically initiated with low viscosity fracturing fluids. After the fracture is initiated, proppants are added to the fracturing fluids. Proppants are generally finely sized sands which are forced into the factures, and hold the fractures at least partially open after fluid pressures are removed. The finely sized sands permit flow of formation fluids back into the wellbore from a large portion of the surface of the fracture.

To accommodate many fractures from each wellbore, the wellbores are often drilled horizontally in a direction of the least in-situ stress of the formation, so that fractures would tend to extend perpendicular to the wellbore. To cost-effectively provide these fractures, typically multiple fractures are created at one time. Providing multiple fractures at the same time significantly reduces the time and expense required to provide the fractures, but a disadvantage of providing multiple fractures at the same time is that the fractures tend to be different sizes.

A fracturing operation typically starts by providing a number of perforations at the end of a lateral portion of the wellbore, and then fractures are created at those clusters of perforations. A plug is then set to isolate the portion of the wellbore containing the fractured perforations from the remaining wellbore, and another set of clusters of perforations are provided and fractures are then created at those perforations. Another plug is then provided to isolate the newly created fractures from the remaining wellbore. This process is repeated until the fracturing is completed. Thirty or more fractures could be provided in a horizontal well extending over a distance of two miles or more.

Fracturing of one cluster of perforations at a time, or single-point entry stimulation ensures all perforation clusters are effectively fractured, but because of the time required, but this single point entry stimulation takes considerably more rig time, and generally is not economic. With tens to more than a hundred perforation clusters to stimulate, fracturing of all of the clusters of perforations at one time, or a single bullhead injection, will probably result in most of the fracturing fluid and proppant entering the first few initiated fractures leaving the remaining zones unstimulated. For this reason multi-stage hydraulic fracturing is performed using a limited entry fracture design. A limited entry fracture design provides and fractures two to six clusters of perforations. A limited entry fracture design results in all (or at least most) of the perforation clusters are stimulated. A limited entry fracture design results in fractures that differ in size, but represents a compromise which between the cost of providing the fractures and the effectiveness of the fractures.

There is accepted evidence that limited entry hydraulic fracturing of horizontal wells in unconventional reservoirs results in production variations from perforation cluster to perforation cluster. The results in production differ significantly from ideal. Approximately, between 30% and 40% of the clusters do not significantly contribute to the total well production, while the majority of the production comes from only 20% to 30% of the clusters (Miller, C. K., Waters, G. A., & Rylander, E. I. (2011). Evaluation of Production Log Data from Horizontal Wells Drilled in Organic Shales, Society of Petroleum Engineers).

This poor performance has been attributed to the variability in of the formation along the wellbore in terms of reservoir quality, mechanical rock properties and (minimum) in-situ stress as discussed in, for example: Horizontal Wells in Tight Gas Sands-A Method for Risk Management To Maximize Success (Jason D. Baihly (Schlumberger) I Dee Grant

(Schlumberger) I Li Fan (Schlumberger) I Suhas V. Bodwadkar (Schlumberger) - SPE

Production & Operations Volume 24 Issue02 Publication Date May 2009). Also field observations from digital acustic sensing and distributed temperature sensing diagnostics during stimulation (Molenaar, M.M, Fidan, E., and Hill, D.J., (2012). Real-Time Downhole Monitoring Of Hydraulic Fracturing Treatments Using Fibre Optic Distributed Temperature And Acoustic Sensing. Paper SPE 152981 presented at the SPE/EAGE European

Unconventional Resources Conference and Exhibition, Vienna, Austria, 20-22 March) clearly show uneven distribution of fluid and proppant between the clusters within a stage, which could be a critical problem that needs to be solved to improve the production efficiency of multi-stage fracturing

Generally, the desirable size of a fracture is limited by the distance proppant can be placed into the fracture. Portions of the fracture that extend beyond the distance which proppant is carried are in general considered not productive because after fluid pressure from within the fracture is reduced, that portion of the fracture will close. The portion of the fracture that does not contain proppant is considerably less productive then the portion of the fracture which contains proppant.

When multiple fractures are provided at the same time, the pressure for each fracture to initiate and propagate will be higher than the previous fracture because of increased formation stress caused by the earlier fractures. This is referred to as stress shadowing.

Because formations have very little compressibility, the opening of the fracture, although only by a few millimeters, causes a stress shadow that extends many hundreds of feet away from the fracture. Thus when fractures are provided from multiple clusters of perforations, the fractures will tend to initiate at perforations most removed from the previously provided fractures. Subsequent fractures will tend to be smaller than this first fracture because of the increased formation stress. There are also occasionally perforations which are never successfully fractured. Thus the number of clusters of perforations which can be optimally fractured at the same time is limited to, for example, three of four fractures.

One technique utilized to provide more equally sized fractures is to provide a slug of diverter material in the fracturing fluid after a predetermined amount of proppant has been injected. The diverter material is generally provided with a wide range of particle sizes so that it will easily bridge and plug either the perforation itself, or the proppants within the fracture. The diverter material will essentially plug the existing fracture, and permit the pressure in the wellbore to increase and initiate another fracture. Diverter material is generally made of material which decomposes at wellbore conditions so that the plug of the fracture is temporary, and not an impediment to production. By using a number of slugs of diverter material which is one less than the number of clusters of perforations, more equally sized fractures can generally be provided. This technique helps provide more equally sized fractures, but it would be beneficial to have a method which provides better control over how much proppant is placed in each fracture. US patent application publication US20150114664 suggests sleeves to cover openings in a casing which may be opened, and when opened, also closes a flapper valve to block flow below the open sleeve. The formation is then fracked at the open sleeve. The sleeves are opened and the formation fractured sequentially from the distal end of the wellbore toward the wellhead.

US patent 7516793 suggests a method and system for providing fractures from a wellbore that includes obtaining real time data from a fracturing operation and utilizing this real time data to provide feed-back to control the fracturing operation to provide more optimum fractures.

US patent 7451812 suggests a method and system for using data from sensors to provide control of proppant injection to provide for effective heterogeneous proppant placement.

US patent 8245780 teaches a method utilizing a fiber optic cable placed on the outside of a casing to measure flow rates within a wellbore. The system is said to be useful to identify, during a fracturing operation, when sand arrives at perforations, and to monitor the flow into each set of perforations.

Summary of the Invention

The present invention comprises a method for providing fractures from a wellbore in a formation, the method comprising the steps of: providing a wellbore into the formation;

providing at least one controllable sleeve valve incorporated into a casing within the wellbore; providing a sensor to determine a flow rate of fluids passing through the controllable sleeve valve; injecting into the wellbore a fluid at a pressure sufficient to initiate and propagate a fracture in the formation juxtaposed to the sleeve valve; including a proppant material in the fluid; determining, in real time, the amount of proppant that has entered the fracture juxtaposed to the sleeve valve; and closing the sleeve valve when a predetermined amount of proppant has entered the fracture.

The present invention also includes a system for performance of this method. In one embodiment of the present invention, the sensor to determine a flow rate of fluids passing through the controllable sleeve valve is a fiber optic sensor, and the fiber optic system also transmits signals from the surface to control opening and closing of the controllable sleeve valves. By control of proppant containing fracturing fluids into individual fractures, either by throttling the flows during real time, by shutting the controllable sleeve valves after a target amount of proppant has entered into each fracture, or by discontinuing injection of fracturing fluid and resetting positions of at least one of the controllable sleeve valves, essentially an equal amount of proppant could be injected into each of the fractures. Benefits may include being able to fracture more, if not all, of the fractues in one operation rather than having to provide a limited amount of fractures at a time.

Brief Description of the Figures

Figure 1 is a schematic of the system of the present invention.

Detailed Description of the Invention

Figure 1 shows a wellbore 101, extending from a wellhead 120, through an overburden 121, into a formation in which fractures are to be created. The wellhead may be configured to accept a flow of fracturing fluid 123 which may be measured by meter 124, which generates a signal representing the flow rate of fracturing fluid 125. A casing 102 may be secured in the wellbore by cement 103. Three controllable sleeve valves 104 are shown with perforations and fractures 105 shown extending into the formation from the wellbores. The controllable sleeve valves, when in the open position, provide continuation between the inside of the casing 106 and the fractures 105. The number of controllable sleeve valves and fractures that might be provided could be from one to fifty or more. There could also be perforations and fractures places where there is no controllable sleeve valves. For example, at the location farthest from the wellhead, the fracture might tend to be hardest to develop, and therefore, not need a controllable sleeve valve in order to obtain essentially equally sized fractures.

The wellbore is shown as a deviated or nearly horizontal wellbore, but the present invention could be applied to multiple fractures in a vertical wellbore. Three fractures are shown, but in practice the number of fractures is limited only by the distance between fractures and the length of the wellbore that could be provided. Typically, horizontal wellbores could be provided at least two miles long, or about 4000 meters. Optimum distance between fractures is determined by formation properties, properties of formation fluids, and costs of providing fractures. Typical distances between fractures may be from 30 meters to 200 meters.

Controllable sleeve valves may be, for example, similar to the valves disclosed in US patent application publication US20150014664, but there is no need, with the present invention to provide the flapper to additionally block flow to the wellbore below the sliding sleeve valve. The controllable sliding sleeve valve may have a sliding closure cylinder which is held open by a control pin, but biased to close by a spring, compressed fluid, or other source of stored energy so upon release of the control pin, the sliding closure cylinder moves to a closed position. Upon completion of the fracturing operation, the sliding closure needs to be removed to enable production from the fracture 105 into the inside of the casing 106. The sliding closure could be made from a material that decomposes after a predetermined time at wellbore conditions, such as the materials disclosed in US patent 7625846 to Claude Cooke, the disclosure of which is incorporated herein by reference. Alternatively, the controllable sleeve valve could comprise a second bias mechanism which overpowers the mechanism holding the valve closed, and when triggered, forces the sliding closure cylinder back to an open position. In this embodiment, the sliding closure could have more than two positions. For example, one position could have no obstructions, a second position could be fully closed, and the final third position could include a screen which keeps fracture sand from flowing into the wellbore from the fracture. The biasing force to move the sliding closure to the second position could be the same biasing force that moves the sliding closure cylinder to the third position, with the stop of the sliding sleeve in the second position being controlled by a second control pin. The sliding sleeve could also be retained in the second position by a stop that degrades after a predetermined amount of time at wellbore conditions to then permit the biasing force to move the sliding sleeve to a final position.

A fiber optic cable 108 is shown on the exterior of the casing 102 to enable sensing of flows within the casing according, for example, to the invention of US patent 8,245,780, the disclosure of which is incorporated herein by reference. Flow rates could be estimated above the first controllable sleeve valve, 109, above the second controllable sleeve valve 110, and above the third controllable sleeve valve 111. The differences between the sensed flows would be the flow of fluids into the formation through the controllable sleeve valves. Other ways to determine the flow of fluids on each side of the controllable sleeve valves could be utilized.

The fiber optic cable may be connected to a light source and detector for the reflected signals 112. The light source and detector could be part of a controller 113 that receives the raw signals and provides control signals to the controllable sleeve valves via the fiber optic cable 108. Signals useful for the controller may be a signal representing the total flow rate of fracturing fluids 125, a signal indicating the presence of proppant in the fracturing fluid or the concentration of proppants in the fracturing fluid, and flows of fluids in the wellbores at a plurality of locations within the wellbore. In some embodiments, the flow of fluids within the wellbore may be a flow upstream of each controllable sleeve valve, or upstream of each set of perforations from which fractures are to be provided. The fiber optic cable could be connected to detectors 114 located at each of the controllable sleeve valves. The controller 113 could send an optic signal that could be sensed at the controllers located at the controllable sleeve valves to trigger changes in positions of each controllable sleeve valve.

Alternatively, each controllable sleeve valve could be provided with data from the sensors directly and movement of the sliding valves controlled down-hole.

After the casing with the controllable sleeve valves and the sensors are installed, the wellbore may be cemented in place to provide zonal isolation between the casing and the formation. The controllable sleeve valves may be in the closed position for the cementing operation, or the openings could be covered with a sacrificial material that is weak enough to be fractured in the fracturing operation, or blocked by a material that degrades under wellbore conditions after a time period which permits completion of the cementing operation. If, after the system is installed and cemented in the wellbore, fractures are provided in groups of controllable sleeve valves at one time, then the controllable sleeve valves may be in closed position when other groups are being fractured.

In one embodiment of the present invention, all of the fractures could be provided in one operation, with the controllable sleeve valves closing as the sensors have detected the predetermined amount of flow having passed through the controllable sleeve valve. This embodiment of the present invention eliminates the need to set and move packers or plugs completely. In one embodiment of the present invention, the controllable sleeve valve could be moved during the fracturing operation so that flow through the valve is throttled or controlled so that the flows into at least some fractures could be limited in real time during the fracturing operation. Movement of the controllable sleeve valve during the actual fracturing operation may be challenging so an alternative would be to occasionally stop injection and reset the position of the controllable sleeve valves so that flow into the different fractures could be better balanced. Because proppants being injected in fracturing fluid could take a certain amount of time to reach, for example, the first fracture of controllable sleeve valve, and additional time to reach each subsequent controllable sleeve valve, the controller could take into account this time delay in determining the amount of proppant injected into each fracture.

In another embodiment of the invention, the controllable sleeve valves could be selectively opened to provide fractures in a predetermined sequence. For example, alternating controllable sleeve valves could be opened and fractured initially, and then after one to twenty days, the remaining fractures provided from the remaining controllable sleeve valves.

Providing fractures in a sequence like this could result in more equally created fractures because the stress shadows from the first set of fractures have significantly less effect on each other, and after sufficient time has passed, the stresses in the formation tend to be relieved, for example, but partial closure of the factures as the formation presses back on proppant in the initial fractures.

Alternatively, all the controllable sleeve valves in the well could comprise a mechanism which is triggered after the well has been producing for a while and puts all the valves in back to a closed position. This could be triggered a mechanism that degrades after a predetermined amount of time at wellbore conditions, a timer, or this closing could be triggered by a wellbore intervention such as circulation of a magnetic ball through the wellbore. In this embodiment of the present invention, all of the fractures could be re- stimulated. There is industry evidence that in many cases, re-stimulations increase production. Having the initial fractures through controllable sleeve valves, and closing the sleeve valves for a subsequent refracturing process could eliminate a need to seal off the first fractures prior to the refracturing operation. In another embodiment of the present invention, the controllable sleeve valves could then be reopened after the refracturing process to permit continued production through the initial fractures along with production through the fractures provided in the refracturing process.

Claims

C L A I M S

A method for providing fractures from a wellbore in a formation, the method comprising the steps of:

providing a wellbore into the formation;

providing at least one controllable sleeve valve incorporated into a casing within the wellbore;

providing a sensor to determine a flow rate of fluids passing through the controllable sleeve valve;

injecting into the wellbore a fluid at a pressure sufficient to initiate and propagate a fracture in the formation juxtaposed to the sleeve valve;

including a proppant material in the fluid;

determining, in real time, the amount of proppant that has entered the fracture juxtaposed to the sleeve valve; and

closing the sleeve valve when a predetermined amount of proppant has entered the fracture.

The method of claim 1 wherein the flow sensor is a fiber optic cable.

The method of claim 1 wherein a plurality of controllable sleeve valves are provided in the wellbore.

The method of claim 1 wherein the sleeve valves are made of a material which decomposes at wellbore conditions after a predetermined time period.

The method of claim 1 wherein the sleeve valves are made of a material which may be decomposed by a material injected into the wellbore after the fractures are provided. The method of claim 3 wherein the plurality of fractures are provided without moving a packer between provision of fractures.

7. A system for controlling placement of proppants in formation fractures, the system comprising:

a cased wellbore within the formation:

a plurality of controllable sleeve valves in the casing, the controllable sleeve valves providing communication between a volume inside of the cased wellbore and a fracture in the formation outside of the cased wellbore:

a sensor for determining an amount of proppant passing through at least one of the controllable sleeve valves: and

a programmable controller configured to receive the signal, and to operate at least one of the controllable sleeves to close the controllable sleeve valve after a predetermined amount of proppant has entered the fracture.

8. The system of claim 7 wherein the controllable sleeve valve comprises a sleeve made from a material which decomposes at wellbore conditions after a predetermined time period.

9. The system of claim 7 wherein the sensor comprises a fiber optic cable capable of determining a flow rate in the wellbore above and below at least one controllable sleeve valve.

10. The system of claim 7 further comprising a pump capable of pumping proppant

containing fracturing fluids into the wellbore at pressures that exceed a fracture initiation pressure for the formation.

11. The system of claim 7 wherein the controller also receives a signal related to the flow rate of proppants into the wellbore.

12. The system of claim 11 wherein a sensor determines the flow of proppant through each of the plurality of controllable sleeve valves.

13. The system of claim 12 wherein the controller utilizes the signal related to the total flow rate of proppants into the wellbore to adjust the flow of proppant through each of the plurality of controllable sleeve valves.

14. A method for providing fractures from a wellbore in a formation, the method comprising the steps of:

providing a wellbore into the formation;

including a proppant material in the fluid;

controlling a position of the controllable sleeve valves based on the determined amount of propant that has entered the fracture juxtaposed to the sleeve valve.

15. The method of claim 14 wherein a plurality of controllable sleeve valves are provided.

16. The method of claim 15 wherein the position of the controllable sleeve valve is

controlled to equalize the amount of proppant in each fracture.