# US 10,119,392 B2 · Determining depth of loss zones in subterranean formations

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- Number: US 10,119,392 B2
- Document ID: US10119392B2
- Status: Granted
- Kind: B2
- Application number: 14/769,628
- Filed: 2014-11-26
- Published: 2016-11-24
- Granted: 2018-11-06
- Earliest claimed: 2014-11-26
- Assignees: Halliburton Energy Services, Inc.
- Applicants: Halliburton Energy Services, Inc.
- Inventors: Krishna Babu Yerubandi; Mark Ryan Savery
- Web page: https://patentgrep.com/patent/US10119392B2

## CPC

- E21B 47/10: Locating fluid leaks, intrusions or movements
- E21B 33/03: Well heads; Setting-up thereof
- E21B 33/13: Methods or devices for cementing, for plugging holes, crevices or the like
- E21B 47/04: Measuring depth or liquid level
- E21B 47/06: Measuring temperature or pressure
- C09K 8/50: Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls (compositions for consolidating loose sand or the like around wells C09K8/56)
- E21B: EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- C09K: MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE

## Abstract

Methods of locating a loss zone in a wellbore in a subterranean formation including determining a calculated wellhead pressure, calculating a wellhead pressure differential, calculating a flow rate loss, estimating a loss zone depth, determining a modified calculated wellhead pressure, and calculating a modified wellhead pressure differential until the modified wellhead pressure differential corresponds to a loss zone location in the wellbore.

## Claims

### Claim 1

A method of locating a loss zone in a subterranean formation comprising:
(a) providing a wellbore in the subterranean formation having a tubular therein, wherein an annulus is formed between the tubular and a face of the wellbore;
(b) introducing a treatment fluid into the wellbore through the tubular and displacing the treatment fluid up through the annulus;
(c) logging real-time measurements during introducing and displacing the treatment fluid, the real-time measurements selected from the group consisting of actual wellhead pressure (AWP), treatment fluid inlet density (ρi), inlet flow rate ({dot over (Q)}i), outlet flow rate ({dot over (Q)}o), treatment fluid inlet viscosity (μi), and any combination thereof;
(d) determining a calculated wellhead pressure (CWP) based on the real-time measurements of step (c);
(e) calculating a wellhead pressure differential (ΔWP) based on Formula 1: ΔWP=|CWP−AWP|;
(f) calculating a flow rate loss ({dot over (Q)}loss) based on Formula 2: {dot over (Q)}loss={dot over (Q)}i−{dot over (Q)}o;
(g) estimating a loss zone depth (dest) at a depth along the wellbore,
wherein estimating the loss zone depth comprises receiving a user input indicating a predetermined loss zone depth value;
(h) determining a modified calculated wellhead pressure (CWPmod) based on hydraulic calculations, wherein the flow rate loss ({dot over (Q)}loss) and the estimated loss zone depth (dlz) are used as inputs, wherein determining the modified calculated wellhead pressure comprises modifying the calculated wellhead pressure using the predetermined loss zone depth value from the received user input;
(i) calculating a modified wellhead pressure differential (ΔWPmod); and
(j) repeating steps (g) through (i) until the modified wellhead pressure differential (ΔWPmod) is in the range of 0 to a user defined maximum, whereby the estimated loss zone depth (dest) substantially corresponds to a loss zone location (dlz) in the wellbore.

### Claim 2 (depends on 1)

The method of claim 1, wherein the treatment fluid is selected from the group consisting of a non-aqueous fluid, an aqueous fluid, an aqueous-miscible fluid, a water-in-oil emulsion, an oil-in-water emulsion, and any combination thereof.

### Claim 3 (depends on 1)

The method of claim 1, wherein the tubular is selected from the group consisting of a casing string, a flexible tubing, an inflexible tubing, a drill string, and any combination thereof.

### Claim 4 (depends on 1)

The method of claim 1, wherein the hydraulic calculations of step (h) are performed using hydraulic simulation software.

### Claim 5 (depends on 1)

The method of claim 1, wherein the user defined maximum is less than about 50,000.

### Claim 6 (depends on 1)

The method of claim 1, further comprising a wellhead with the tubular extending therefrom and into the wellbore, and a pump fluidly coupled to the tubular.

### Claim 7 (depends on 1)

The method of claim 1, wherein:
adjusting the modified wellhead pressure differential until the modified wellhead pressure differential is in the range of 0 to the user defined maximum, wherein the modified wellhead pressure differential is adjusted based on a change in the estimated loss zone depth.

### Claim 8 (depends on 1)

The method of claim 1, further comprising:
extrapolating the estimated loss zone depth of the wellbore to establish a second loss zone location in a different wellbore in the subterranean formation.

### Claim 9

A method of locating a loss zone in a subterranean formation comprising:
(a) providing a wellbore in the subterranean formation having a tubular therein, wherein an annulus is formed between the tubular and a face of the wellbore;
(b) introducing a treatment fluid into the wellbore through the tubular and displacing the treatment fluid up through the annulus;
(c) logging real-time measurements during introducing and displacing the treatment fluid, the real-time measurements selected from the group consisting of actual wellhead pressure (AWP), treatment fluid inlet density (ρi), inlet flow rate ({dot over (Q)}i), outlet flow rate ({dot over (Q)}o), treatment fluid inlet viscosity (μi), and any combination thereof;
(d) determining a calculated wellhead pressure (CWP) based on the real-time measurements of step (c);
(e) calculating a wellhead pressure differential (ΔWP) based on Formula 1: ΔWP=|CWP−AWP|;
(f) calculating a flow rate loss ({dot over (Q)}loss) based on Formula 2: {dot over (Q)}loss={dot over (Q)}i−{dot over (Q)}o;
(g) estimating a loss zone depth (dest) at a depth along the wellbore,
wherein estimating the loss zone depth comprises receiving a user input indicating a predetermined loss zone depth value;
(h) determining a modified calculated wellhead pressure (CWPmod) based on hydraulic calculations, wherein the flow rate loss ({dot over (Q)}loss) and the estimated loss zone depth (dlz) are used as inputs, wherein determining the modified calculated wellhead pressure comprises modifying the calculated wellhead pressure using the predetermined loss zone depth value from the received user input;
(i) calculating a modified wellhead pressure differential (ΔWPmod); and
(j) repeating steps (g) through (i) until the modified wellhead pressure differential (ΔWPmod) is in the range of 0 to a user defined maximum, whereby the estimated loss zone depth (dest) substantially corresponds to a loss zone location (dlz) in the wellbore, wherein the modified wellhead pressure differential is adjusted based on a change in the estimated loss zone depth; and
(k) performing a remedial operation to at least partially seal the loss zone location (dlz) in the wellbore.

### Claim 10 (depends on 9)

The method of claim 9, wherein the remedial operation is selected from the group consisting of ceasing operations, removing the treatment fluid from the wellbore, reformulating the treatment fluid, introducing a loss circulation pill into the wellbore, reducing the inlet flow rate ({dot over (Q)}i), increasing the inlet flow rate ({dot over (Q)}i), and any combination thereof.

### Claim 11 (depends on 9)

The method of claim 9, wherein the treatment fluid is selected from the group consisting of a non-aqueous fluid, an aqueous fluid, an aqueous-miscible fluid, a water-in-oil emulsion, an oil-in-water emulsion, and any combination thereof.

### Claim 12 (depends on 9)

The method of claim 9, wherein the tubular is selected from the group consisting of a casing string, a flexible tubing, an inflexible tubing, a drill string, and any combination thereof.

### Claim 13 (depends on 9)

The method of claim 9, wherein the hydraulic calculations of step (h) are performed using hydraulic simulation software.

### Claim 14 (depends on 9)

The method of claim 9, wherein the user defined maximum is less than about 50,000.

### Claim 15 (depends on 9)

The method of claim 9, further comprising a wellhead with the tubular extending therefrom and into the wellbore, and a pump fluidly coupled to the tubular.

### Claim 16

A method of locating a loss zone in a subterranean formation comprising:
(a) providing a first wellbore in the subterranean formation having a tubular therein, wherein an annulus is formed between the tubular and a face of the wellbore,
wherein subterranean formation comprises an oilfield;
(b) introducing a first treatment fluid into the first wellbore through the tubular and displacing the first treatment fluid up through the annulus;
(c) logging real-time measurements during introducing and displacing the treatment fluid, the real-time measurements selected from the group consisting of actual wellhead pressure (AWP), first treatment fluid inlet density (ρi), inlet flow rate ({dot over (Q)}i), outlet flow rate ({dot over (Q)}o), treatment fluid inlet viscosity (μi), and any combination thereof;
(d) determining a calculated wellhead pressure (CWP) based on the real-time measurements of step (c);
(e) calculating a wellhead pressure differential (ΔWP) based on Formula 1: ΔWP=|CWP−AWP|;
(f) calculating a flow rate loss ({dot over (Q)}loss) based on Formula 2: {dot over (Q)}loss={dot over (Q)}i−{dot over (Q)}o;
(g) estimating a loss zone depth (dest) at a depth along the wellbore,
wherein estimating the loss zone depth comprises receiving a user input indicating a predetermined loss zone depth value;
(h) determining a modified calculated wellhead pressure (CWPmod) based on hydraulic calculations, wherein the flow rate loss ({dot over (Q)}loss) and the estimated loss zone depth (dlz) are used as inputs, wherein determining the modified calculated wellhead pressure comprises modifying the calculated wellhead pressure using the predetermined loss zone depth value from the received user input;
(i) calculating a modified wellhead pressure differential (ΔWPmod); and
(j) repeating steps (g) through (i) until the modified wellhead pressure differential (ΔWPmod) is in the range of 0 to a user defined maximum, whereby the estimated loss zone depth (dest) substantially corresponds to a loss zone location (dlz) in the first wellbore;
(k) establishing an oilfield loss zone location (dfield lz) for the oilfield that is equivalent to the location of the loss zone in the wellbore;
(l) providing a second wellbore in the subterranean formation having the oilfield loss zone location (dfield lz) therein;
(m) performing a preventative operation to at least partially seal the oilfield loss zone location (dfield lz) in the second wellbore.

### Claim 17 (depends on 16)

The method of claim 16, wherein the preventative operation in the second wellbore is selected from the group consisting of introducing a loss circulation material into the second wellbore, reducing the inlet flow rate ({dot over (Q)}i), increasing the inlet flow rate ({dot over (Q)}i), adjusting the wellbore geometry, adjusting the location of the second wellbore, and any combination thereof.

### Claim 18 (depends on 16)

The method of claim 16, wherein the treatment fluid is selected from the group consisting of a non-aqueous fluid, an aqueous fluid, an aqueous-miscible fluid, a water-in-oil emulsion, an oil-in-water emulsion, and any combination thereof.

### Claim 19 (depends on 16)

The method of claim 16, wherein the tubular is selected from the group consisting of a casing string, a flexible tubing, an inflexible tubing, a drill string, and any combination thereof.

### Claim 20 (depends on 16)

The method of claim 16, wherein the hydraulic calculations of step (h) are performed using hydraulic simulation software.

### Claim 21 (depends on 16)

The method of claim 16, wherein the user defined maximum is less than about 50,000.

### Claim 22 (depends on 16)

The method of claim 16, further comprising a wellhead with the tubular extending therefrom and into the wellbore, and a pump fluidly coupled to the tubular.