# US 4,393,933 A · Determination of maximum fracture pressure

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- Number: US 4,393,933 A
- Document ID: US4393933A
- Status: Granted
- Kind: A
- Application number: 06/251,666
- Filed: 1981-04-06
- Granted: 1983-07-19
- Earliest claimed: 1980-06-20
- Assignees: Standard Oil Company (Indiana)
- Inventors: Kenneth G. Nolte; Michael B. Smith
- Web page: https://patentgrep.com/patent/US4393933A

## CPC

- E21B 49/006: {Measuring wall stresses in the borehole}
- E21B 43/26: by forming crevices or fractures
- E21B 49/008: {by injection test; by analysing pressure variations in an injection or production test, e.g. for estimating the skin factor (measuring pressure E21B47/06)}
- E21B: EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS

## Abstract

During injection of fracture fluid into a subterranean formation, the bottomhole treating pressure at which the change in pressure is essentially zero is determined. This pressure is the maximum which should be attained for that formation during fracture and is useful for designing subsequent fracture treatments within the same subterranean formation.

## Claims

### Claim 1

A method of determining the maximum bottomhole treating pressure which should be attained during the fracturing of a subterranean formation at a first wellbore extending into the formation, which comprises
extending a fracture into the formation from a second wellbore extending into the formation by injecting fluid into the fracture at a rate sufficient for extending said fracture into the formation until the change in the bottomhole treating pressure is substantially zero during the injection of the fluid,
measuring at the second wellbore the bottomhole treating pressure,
determining the bottomhole treating pressure at which the change in bottomhole treating pressure during the formation of the fracture extending from the second wellbore is substantially zero, and
taking the sum of said determined bottomhole treating pressure less the in situ closure stress of the formation at the second wellbore plus the in situ closure stress of the formation at a said first wellbore extending into the formation as the maximum bottomhole treating pressure which should be attained during the fracturing of the formation at said first wellbore.

### Claim 2

A method of determining the maximum bottomhole treating pressure which should be attained during the fracturing of a subterranean formation at a first wellbore extending into said formation, which comprises:
injecting a fluid into a second wellbore extending into said formation at a rate sufficient to extend a fracture into said formation from said second wellbore until the change in the difference between bottomhole treating pressure of said second wellbore and closure pressure of said formation at said second wellbore is substantially zero during said fluid injection,
measuring the difference between bottomhole treating pressure of said second wellbore and closure pressure of said formation at said second wellbore, determining the difference between bottomhole treating pressure of said second wellbore and closure pressure of said formation at said second wellbore at which the change in the difference between bottomhole treating pressure of said second wellbore and closure pressure of said formation at said second wellbore during said fluid injection into said second wellbore is substantially zero, and
taking the sum of said determine difference between bottom hole treating pressure at said second wellbore and closure pressure of said formation at said second wellbore and the in situ closure pressure of said formation at said first wellbore as the maximum bottomhole treating pressure which should be attained during said fracturing of said formation at said first wellbore.

### Claim 3 (depends on 4, 5, 6, 7)

The method of claim 4, 5, 6 or 7 wherein said fluid injection is continued until said pressure difference increases significantly.

### Claim 4 (depends on 1, 2)

The method of claim 1 or 2 wherein said fluid injection is continued until said pressure difference decreases.

### Claim 5 (depends on 1, 2)

The method of claim 1 or 2 wherein said injection of fracturing fluid into said formation is at a constant rate.

### Claim 6

A method for hydraulic fracturing of an underground formation through a first wellbore extending into said formation comprising:
(a) determining at a second wellbore extending into said formation a maximum pressure to extend a fracture into the formation without undesirable fracturing effects, such as screen out of proppants, undesirable fracture height growth, excessive fluid loss and the like;
(b) treating said first well with a hydraulic fracture treatment so that the bottomhole pressure during the fracture treatment does not exceed the maximum pressure determined in the second wellbore.

### Claim 7 (depends on 6)

A method of claim 6 wherein step (a) is performed by a method comprising:
(a) extending a fracture into the formation from a second wellbore extending into the formation by injecting fluid into the fracture at a rate sufficient for extending said fracture into the formation until the change in the bottomhole treating pressure is substantially zero during the injection of the fluid;
(b) measuring at the second wellbore the bottomhole treating pressure;
(c) determining the bottomhole treating pressure at which the change in bottomhole treating pressure during the formation of the fracture extending from the second wellbore is substantially zero; and
(d) taking the sum of said determined bottomhole treating pressure less the in situ closure stress of the formation at the second wellbore plus the in situ closure stress of the formation at said first wellbore extending into the formation as the maximum bottomhole treating pressure which should be obtained during the fracturing of the formation of said first wellbore.

### Claim 8 (depends on 6)

A method of claim 6 wherein step (a) is performed by a method comprising:
(a) injecting a fluid into a second wellbore extending into said formation at a rate sufficient to extend a fracture into said formation from said second wellbore until the change in the difference between bottomhole treating pressure of said second wellbore and closure pressure of said formation at said second wellbore is substantially zero during said fluid injection;
(b) measuring the difference between the bottomhole treating pressure of said second wellbore and closure pressure of said formation at said second wellbore;
(c) determining the difference between the bottomhole treating pressure of said second wellbore and closure pressure of said formation at said second wellbore at which the change in the difference between bottomhole treating pressure of said second wellbore and closure pressure of said formation at said second wellbore during said fluid injection into said second wellbore is substantially zero; and
(d) taking the sum of said determined difference between bottomhole treating pressure at said second wellbore and closure pressure of said formation at said second wellbore and the in situ closure pressure of said formation at said first wellbore as the maximum bottomhole treating pressure which should be obtained during said fracturing of said formation at said first wellbore.