# US 2014/0151043 A1 · Stabilized fluids in well treatment

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- Number: US 2014/0151043 A1
- Document ID: US20140151043A1
- Status: Published application
- Kind: A1
- Application number: 13/803,352
- Filed: 2013-03-14
- Published: 2014-06-05
- Earliest claimed: 2012-12-03
- Assignees: Schlumberger Technology Corporation
- Inventors: Matthew J. Miller; John R. Whitsitt; James Ernest Brown
- Web page: https://patentgrep.com/patent/US20140151043A1

## CPC

- E21B 43/267: reinforcing fractures by propping
- E21B 34/14: operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools {(E21B34/066 takes precedence)}
- E21B 43/26: by forming crevices or fractures
- E21B 47/13: by electromagnetic energy, e.g. radio frequency
- E21B: EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS

## Abstract

Using stabilized fluids in multistage well treatment is disclosed. Also disclosed are methods, fluids, equipment and/or systems for treating a subterranean formation penetrated by a wellbore, relating to a stabilized treatment slurry.

## Claims

### Claim 1

A method, comprising:
placing a downhole completion staging system tool in a wellbore adjacent a subterranean formation;
operating the downhole completion staging system tool to establish one or more passages for fluid communication between the wellbore and the subterranean formation in a plurality of wellbore stages spaced along the wellbore;
isolating one of the wellbore stages for treatment;
injecting a stabilized slurry treatment fluid through the wellbore and the one or more passages of the isolated wellbore stage into the subterranean formation to place proppant in a fracture in the subterranean formation; and
repeating the isolation and proppant placement for one or more additional stages.

### Claim 2 (depends on 1)

The method of claim 1, wherein the placement of the downhole completion staging system tool is tethered to a string.

### Claim 3 (depends on 1)

The method of claim 1, wherein the downhole completion staging system tool is translated within the wellbore using the stabilized slurry treatment fluid as a transport medium.

### Claim 4 (depends on 1)

The method of claim 1, wherein the downhole completion staging system tool comprises a wireline tool string comprising a blanking plug and perforating guns, and further comprising setting the blanking plug in the wellbore, placing one or more perforation clusters above the blanking plug, and recovering the wireline tool string to the surface, wherein the stabilized slurry treatment fluid is circulated through the wellbore into the formation to create the fracture, place the proppant or a combination thereof.

### Claim 5 (depends on 1)

The method of claim 1, wherein the downhole completion staging system tool comprises a pipe or coiled tubing string comprising a jetting assembly, and further comprising placing the jetting assembly in the wellbore, closing an annulus around the string, circulating abrasive materials down the string through the jetting assembly to perforate a wellbore casing, wherein the stabilized slurry treatment fluid is circulated through the annulus, perforations and into the formation to create the fracture, place the proppant or a combination thereof.

### Claim 6 (depends on 1)

The method of claim 1, further comprising placing a production liner in the wellbore wherein the production liner is fitted with a plurality of sliding sleeves in the closed position, and inserting a sleeve-shifting device into a capture feature on the downhole completion staging system tool to open a fracturing port, wherein the stabilized slurry treatment fluid is circulated through the fracturing port and into the formation to create the fracture, place the proppant or a combination thereof.

### Claim 7 (depends on 1)

The method of claim 1, further comprising forming a plug between at least two stages.

### Claim 8 (depends on 7)

The method of claim 7, wherein the plug is formed from a slurry treatment fluid and further comprising re-slurrying the plug following completion of the proppant placement for one stage to access another one of the one or more additional stages for a subsequent isolation and proppant placement for the additional one of the one or more stages.

### Claim 9 (depends on 1)

The method of claim 1, wherein stabilized slurry treatment fluid from one stage is circulated in the wellbore to another stage to create the fracture, place the proppant or a combination thereof.

### Claim 10 (depends on 1)

The method of claim 1, further comprising circulating another stabilized slurry treatment fluid through the wellbore between stages to flush debris from the wellbore following completion of one stage and prior to initiation of a serial stage, wherein the flushing slurry treatment fluid may be the same or different treatment fluid with respect to the proppant placement treatment fluid of either or both of the immediately preceding or immediately subsequent stages.

### Claim 11 (depends on 1)

The method of claim 1, wherein the stabilized slurry treatment fluid comprises a viscosity less than 300 mPa-s (170 s−1, 25° C.), a solids phase having a packed volume fraction (PVF) greater than 0.72, a slurry solids volume fraction (SVF) less than the PVF and a ratio of SVF/PVF greater than about 1-2.1*(PVF-0.72).

### Claim 12 (depends on 1)

The method of claim 1, wherein the stabilized slurry treatment fluid comprises 0.36 L or more of proppant volume per liter of proppant-containing treatment fluid, a viscosity less than 300 mPa-s (170 s−1, 25° C.), solids having a packed volume fraction (PVF) greater than 0.6 and a slurry solids volume fraction (SVF) greater than the PVF.

### Claim 13 (depends on 1)

The method of claim 1, further comprising:
stopping circulation of the stabilized slurry treatment fluid to thereby strand the treatment fluid in the wellbore without solids settling; and
thereafter resuming circulation of the treatment fluid.

### Claim 14 (depends on 1)

The method of claim 1, further comprising stabilizing a treatment fluid to form the stabilized treatment slurry fluid meeting at least one of the following conditions:
(1) the slurry has a low-shear viscosity equal to or greater than 1 Pa-s (5.11 s−1, 25° C.);
(2) the slurry has a Herschel-Buckley (including Bingham plastic) yield stress (as determined in the manner described herein) equal to or greater than 1 Pa; or
(3) the largest particle mode in the slurry has a static settling rate less than 0.01 mm/hr; or
(4) the depth of any free fluid at the end of a 72-hour static settling test condition or an 8 h@15 Hz/10 d-static dynamic settling test condition (4 hours vibration followed by 20 hours static followed by 4 hours vibration followed finally by 10 days of static conditions) is no more than 2% of total depth; or
(5) the apparent dynamic viscosity (25° C., 170 s−1) across column strata after the 72-hour static settling test condition or the 8 h@15 Hz/10 d-static dynamic settling test condition is no more than +/−20% of the initial dynamic viscosity; or
(6) the slurry solids volume fraction (SVF) across the column strata below any free water layer after the 72-hour static settling test condition or the 8 h@15 Hz/10 d-static dynamic settling test condition is no more than 5% greater than the initial SVF; or
(7) the density across the column strata below any free water layer after the 72-hour static settling test condition or the 8 h@15 Hz/10 d-static dynamic settling test condition is no more than 1% of the initial density.

### Claim 15 (depends on 14)

The method of claim 14, wherein: the depth of any free fluid at the end of the 8 h@15 Hz/10 d-static dynamic settling test condition is no more than 2% of total depth, the apparent dynamic viscosity (25° C., 170 s−1) across column strata after the 8 h@15 Hz/10 d-static dynamic settling test condition is no more than +/−20% of the initial dynamic viscosity, the slurry solids volume fraction (SVF) across the column strata below any free water layer after the 8 h@15 Hz/10 d-static dynamic settling test condition is no more than 5% greater than the initial SVF, and the density across the column strata below any free water layer after the 8 h@15 Hz/10 d-static dynamic settling test condition is no more than 1% of the initial density.

### Claim 16 (depends on 14)

The method of claim 14, wherein the stabilized treatment slurry is formed by at least one of: (1) introducing sufficient particles into the slurry or treatment fluid to increase the SVF of the treatment fluid to at least 0.4; (2) increasing a low-shear viscosity of the slurry or treatment fluid to at least 1 Pa-s (5.11 s−1, 25° C.); (3) increasing a yield stress of the slurry or treatment fluid to at least 1 Pa; (4) increasing apparent viscosity of the slurry or treatment fluid to at least 50 mPa-s (170 s−1, 25° C.); (5) introducing a multimodal solids phase into the slurry or treatment fluid; (6) introducing a solids phase having a PVF greater than 0.7 into the slurry or treatment fluid; (7) introducing into the slurry or treatment fluid a viscosifier selected from viscoelastic surfactants, e.g., in an amount ranging from 0.01 up to 7.2 g/L (60 ppt), and hydratable gelling agents, e.g., in an amount ranging from 0.01 up to 4.8 g/L (40 ppt) based on the volume of fluid phase; (8) introducing colloidal particles into the slurry or treatment fluid; (9) reducing a particle-fluid density delta to less than 1.6 g/mL (e.g., introducing particles having a specific gravity less than 2.65 g/mL, carrier fluid having a density greater than 1.05 g/mL or a combination thereof); (10) introducing particles into the slurry or treatment fluid having an aspect ratio of at least 6; (11) introducing ciliated or coated proppant into slurry or treatment fluid; and (12) combinations thereof.

### Claim 17

A method, comprising:
placing a downhole completion staging tool in a wellbore adjacent a subterranean formation;
operating the downhole completion staging tool to establish one or more passages for fluid communication between the wellbore and the subterranean formation in a plurality of wellbore stages spaced along the wellbore; isolating one or more of the wellbore stages for treatment;
isolating one or more of the wellbore stages for treatment;
injecting a treatment fluid through the wellbore and the one or more passages of the isolated wellbore stage into the subterranean formation to place proppant in a fracture in the subterranean formation;
circulating a stabilized slurry treatment fluid through the isolated wellbore stage to facilitate removal of proppant from the wellbore stage; and
repeating the isolation, proppant placement and slurry treatment fluid circulation for one or more additional stages.

### Claim 18 (depends on 17)

The method of claim 17, further comprising
stabilizing a treatment fluid to form the stabilized treatment slurry fluid meeting at least one of the following conditions:
(1) the slurry has a low-shear viscosity equal to or greater than 1 Pa-s (5.11 s−1, 25° C.);
(2) the slurry has a Herschel-Buckley (including Bingham plastic) yield stress (as determined in the manner described herein) equal to or greater than 1 Pa; or
(3) the largest particle mode in the slurry has a static settling rate less than 0.01 mm/hr; or
(4) the depth of any free fluid at the end of a 72-hour static settling test condition or an 8 h@15 Hz/10 d-static dynamic settling test condition (4 hours vibration followed by 20 hours static followed by 4 hours vibration followed finally by 10 days of static conditions) is no more than 2% of total depth; or
(5) the apparent dynamic viscosity (25° C., 170 s−1) across column strata after the 72-hour static settling test condition or the 8 h@15 Hz/10 d-static dynamic settling test condition is no more than +/−20% of the initial dynamic viscosity; or
(6) the slurry solids volume fraction (SVF) across the column strata below any free water layer after the 72-hour static settling test condition or the 8 h@15 Hz/10 d-static dynamic settling test condition is no more than 5% greater than the initial SVF; or
(7) the density across the column strata below any free water layer after the 72-hour static settling test condition or the 8 h@15 Hz/10 d-static dynamic settling test condition is no more than 1% of the initial density.

### Claim 19 (depends on 17)

The method of claim 17, wherein the stabilized treatment slurry is formed by at least one of: (1) introducing sufficient particles into the slurry or treatment fluid to increase the SVF of the treatment fluid to at least 0.4; (2) increasing a low-shear viscosity of the slurry or treatment fluid to at least 1 Pa-s (5.11 s−1, 25° C.); (3) increasing a yield stress of the slurry or treatment fluid to at least 1 Pa; (4) increasing apparent viscosity of the slurry or treatment fluid to at least 50 mPa-s (170 s−1, 25° C.); (5) introducing a multimodal solids phase into the slurry or treatment fluid; (6) introducing a solids phase having a PVF greater than 0.7 into the slurry or treatment fluid; (7) introducing into the slurry or treatment fluid a viscosifier selected from viscoelastic surfactants, e.g., in an amount ranging from 0.01 up to 7.2 g/L (60 ppt), and hydratable gelling agents, e.g., in an amount ranging from 0.01 up to 4.8 g/L (40 ppt) based on the volume of fluid phase; (8) introducing colloidal particles into the slurry or treatment fluid; (9) reducing a particle-fluid density delta to less than 1.6 g/mL (e.g., introducing particles having a specific gravity less than 2.65 g/mL, carrier fluid having a density greater than 1.05 g/mL or a combination thereof); (10) introducing particles into the slurry or treatment fluid having an aspect ratio of at least 6; (11) introducing ciliated or coated proppant into slurry or treatment fluid; and (12) combinations thereof.

### Claim 20

A method, comprising:
placing a downhole completion staging tool in a wellbore adjacent a subterranean formation;
operating the downhole completion staging tool to establish one or more passages for fluid communication between the wellbore and the subterranean formation in a plurality of wellbore stages spaced along the wellbore;
injecting a treatment fluid through the wellbore and the one or more passages into the subterranean formation to place proppant in a fracture in the subterranean formation;
moving the downhole completion staging tool away from the one or more passages either before, during or after the injection without removing the downhole completion staging tool from the wellbore;
deploying a diversion agent to block further flow through the one or more passages;
circulating a stabilized slurry treatment fluid through the wellbore as the injected treatment fluid or as a flush to facilitate removal of proppant from the wellbore; and
repeating the downhole completion staging tool placement and operation, proppant placement, downhole completion staging tool movement and stabilized slurry treatment circulation for one or more additional stages.