Lesson 5 Gas Kick Behavior

Confidential to DGD JIPConfidential to DGD JIP Slide 1 of 486. Gas Kick Behavior

by Hans C. Juvkam-Wold

Lesson 6

Gas Kick Behavior

Dual Gradient DrillingBasic Technology


• Gas Kicks in Shallow Wells

• The “PV = constant” Assumption - Is it valid?

• The Perfect Gas Law: “PV = nRT ”

• The Real Gas Law: “PV = ZnRT. “ Z-Factor

• Gas Kicks in Deepwater Wells

• Effect of Temp. and Pressure on Real Gases

• Gas Kick Volume and Density forrReal Gases

• Pumping Gas with the MLP

• Solubility of Gas in Oil or Synthetic Based Mud

Contents


Gas Kicks in Shallow Wells

What is the volume of a gas kick as it is being circulated out of the hole under the following assumptions:

• Initial Kick Size = 10 bbl

• Stabilized BHP = 6,000 psia (absolute)

• Well Depth = 10,000 ft

• Maximum Choke Pressure = 1,000 psia

(when the kick arrives at the surface choke)


Gas Kick Behavior - cont’dGas Kicks in Shallow Wells

What is the volume of a gas kick as it is being circulated out of the hole under the above assumptions?

SOLUTION METHOD 1:

• Assume PV = constant

• (i.e., assume perfect gas and ignore any changes in temperature)



SOLUTION METHOD 1:

PV = constant

At the bottom, P = 6,000 psia,

V = 10 bbl

At the surface, P = 1,000 psia,

V = ?



SOLUTION METHOD 1:

ASSUME “PV = constant”

i.e.,

so, VSURFACE = 60 bbl

Kick expands from 10 bbls to 60 bbls.

BOTTOMHOLESURFACE PVPV

BOTTOMHOLESURFACE 10*000,6V000,1


Gas Kick Behavior - cont’dGas Kicks in Shallow WellsSOLUTION METHOD 1: PV = constant.

0

2,000

4,000

6,000

8,000

10,000

12,000

0 20 40 60 80

Kick Volume, bbl

De

pth

, f

t

Maximum Choke

Pressure= 1,000 psia


Gas Kick Behavior - cont’dShallow Kick - Ideal Gas

What is the volume of a kick as it is being circulated out of the hole under the above assumptions?

SOLUTION METHOD 2:

• Assume PV = nRT

• (i.e., assume perfect gas. Note that the temperature must be expressed in oR)



SOLUTION METHOD 2:

PV = nRT also, oF + 460 = oR

Let us assume that the surface temperature is 80 oF. 80 + 460 = 540 oR

so, surface temperature = 540 oR

Let us consider three different temperature gradients: 0.00, 0.01 and 0.02 oF / ft

0.00 oF / ft is the same as assuming PV = const.



SOLUTION METHOD 2A: PV = nRT

When temperature gradient = 0.01 deg F/ft

then surface temperature = 540 oR

and bottomhole temp. = 540 + 0.01 * 10,000 = 640 oR

At the bottom of the hole,

P = 6,000 psia, T = 640 oR, and V = 10 bbl

At the surface,

P = 1,000 psia, T = 540 oR, and V = ?



ALTERNATE SOLUTION METHOD 2A:

PV = nRT

0.01 deg F/ft

VSURFACE = 50.63 bbl

BOTTOMHOLESURFACE nRT

PV

nRT

PV

BOTTOMHOLESURFACE 640

10*000,6

540

V000,1

BOTTOMHOLESURFACE T

PV

T

PV



SOLUTION METHOD 2B:

When temperature gradient = 0.02 deg F/ft

Surface temperature = 540 oR

and bottomhole temp. = 540 + 0.02 * 10,000 = 740 oR

Bottom: P = 6,000 psia, T = 740 oR, and V = 10 bbl

Surface: P = 1,000 psia, T = 540 oR, and V = ?



ALTERNATE SOLUTION METHOD 2B:

PV = nRT

0.02 deg F/ft

VSURFACE = 43.78 bbl

BOTTOMHOLESURFACE nRT

PV

nRT

PV

BOTTOMHOLESURFACE 740

10*000,6

540

V000,1

BOTTOMHOLESURFACE T

PV

T

PV



SOLUTION METHOD 2: Summary

Temperature Kick Volume

Gradient at Surface0.00 deg F/ft 60.00 bbls

0.01 deg F/ft 50.63 bbls

0.02 deg F/ft 43.78 bbls

Assuming a zero temperature gradient, when the actual temperature gradient was 0.02 deg F/ft resulted in overestimating the kick volume at the surface by 37%.


Gas Kick Behavior - cont’dShallow Kick - Ideal GasEffect of Temperature Gradient

0

2,000

4,000

6,000

8,000

10,000

12,000

0 10 20 30 40 50 60 70

Kick Volume, bbls

De

pth

, ft

0.00 deg F/ft

0.02 deg F/ft

0.01 deg F/ft


Gas Kick Behavior - cont’dShallow Kick - Real Gas

SOLUTION METHOD 3: PV = ZnR T

When the temperature gradient = 0.02 deg F/ft

Surface conditions: 540 oR and 1,000 psia

Bottomhole conditions: 740 oR and 6,000 psia

Under these conditions, assuming a gas of S.G. = 0.65):

the Z-factor at the surface = 0.852 (density = 0.510 ppg)

the Z-factor at the bottom = 1.100 (density = 1.731 ppg)

These Z-factor values may be obtained by calculation, or, approximately, from the graph on the next page.


Gas Kick Behavior - cont’dZ-Factor - In Shallow Wells

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000

Pressure, psig

Ga

s C

om

pre

ss

ibili

ty F

ac

tor

(Z-F

ac

tor)

30 F

60 F

100 F

150 F

200 F

300 F

400 F


Gas Kick Behavior - cont’dShallow Kick - Real Gas

SOLUTION METHOD 3: PV = ZnR T

BOTTOMHOLESURFACE ZnRT

PV

ZnRT

PV

BOTTOMHOLESURFACE740*100.1

10*000,6

540*852.0

V000,1

bbl91.33VSURFACE

So, the 60 bbl estimate is within a factor of 2 of the above value


Gas Kick Behavior - cont’dShallow Gas Kick - Summary

Effect of Temperature and Z-Factor

0

2,000

4,000

6,000

8,000

10,000

12,000

0 10 20 30 40 50 60 70

Kick Volume, bbls

De

pth

, ft

Real Gas Ideal Gas PV = constant

0.02 deg F/ft


Gas Kick Behavior

In the previous slides we have studied the behaviour of gas kicks in relatively shallow wells.

We saw, in one case, when a temperature gradient of 0.02 deg F/ft was assumed, the predicted kick volume at the surface dropped from 60 bbs to 44 bbls. The initial kick volume was 10 bbls at a depth of 10,000 ft.

When a correction for variation in Z-Factor was added, the more accurate prediction was 34 bbls at the surface.

The predicted gas volumes varied by a factor of TWO or less in every case investigated.


Gas Kicks in Deep DGD Wells

The main reason why the predicted results varied by no more than a factor of two in the cases studied is that the Z-factor was always close to 1 ( ± 20% ).

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000

Pressure, psig

Ga

s C

om

pre

ss

ibili

ty F

ac

tor

(Z-F

ac

tor)

30 F

60 F

100 F

150 F

200 F

300 F

400 F

In deep-water, very deep, high-pressure wells the Z-factor may vary from 0.7 to 2.5 or even more! This may yield unexpected results.

0.5

1.0

1.5

2.0

2.5

3.0

0 5,000 10,000 15,000 20,000 25,000

Pressure, psig

Co

mp

ress

ibili

ty (

Z-F

acto

r)

3060

100150200300

400

Temperature, oF


Gas Density and Z-Factor

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

0 5,000 10,000 15,000 20,000 25,000 30,000

Pressure, psia

Gas D

en

sit

y,

lb

/gal


Gas Density, lb/gal

Z-Factor

0.65 S.G. and 400 0F



Assumed Pressure Profilein Annulus and Return Line

0

5,000

10,000

15,000

20,000

25,000

30,000

0 5,000 10,000 15,000 20,000 25,000

Kick Pressure, psig

Ver

tica

l D

epth

, f

t

Mud Line



Kick Volume vs. Depth0

5,000

10,000

15,000

20,000

25,000

30,000

0 5 10 15 20 25 30

Kick Volume, bbl

De

pth

, f

t

As expected, most of the expansion occurs

in the top 3,000 ft or so



5,000

10,000

15,000

20,000

25,000

30,000

0 5 10 15 20 25 30 35 40 45 50

Kick Volume, bbl

De

pth

, f

tGas Kicks in Deep DGD Wells

PV = constant

PV = ZnRT



Gas Density vs. Depth0

5,000

10,000

15,000

20,000

25,000

30,000

0.0 1.0 2.0 3.0 4.0

Gas Density, lb/gal

De

pth

, f

t

Mud Line



Z-Factor vs. Depth0

5,000

10,000

15,000

20,000

25,000

30,000

0.0 0.5 1.0 1.5 2.0 2.5

Gas Compressibility Factor (Z-Factor)

Dep

th,

ft


Gas Kick Behavior - Z-Factor

0.5

1.0

1.5

2.0

2.5

3.0

0 5,000 10,000 15,000 20,000 25,000

Pressure, psig

Co

mp

ressib

ility

(Z

-Facto

r)

3060

100150200300

400

Temperature, oF



In the last few slides we have seen the behavior of gas kicks in deepwater, deep DGD wells.

We saw that a 10-bbl gas kick at 30,000 ft was predicted, under the “PV = constant” assumption, to expand to 46 bbls by the time it reached the inlet to the MLP at the seafloor.

When corrections for variations in Z-Factor and temperature were added, the more accurate prediction was 13 bbls at the MLP.

The predicted gas expansion decreased from 360% to a mere 30% in the more accurate analysis!


Kicks Migration in Deep DGD Wells

The predicted gas expansion decreased from 360% to a mere 30% in the more accurate analysis.

Why is this significant?

Well, it helps to know what to expect. For example, suppose this 10-bbl kick were to migrate up the hole under conditions where circulation was not possible. We would expect to bleed to allow for kick expansion to avoid excessive pressures in the wellbore.

In this case we might expect to have to bleed 36 bbls when only 3 bbls are called for. Excessive bleeding could invite additional kicks. Maybe NO bleeding is really necessary in this case…(?)


Pumping of Gas with MLP

In DGD gas kicks that are circulated out must pass through the MLP. Can this pump handle gas?

How severe is the problem? What can we expect?

Under the “PV = const.” assumption the 10-bbl gas kick would have to be compressed from 46 bbl to approximately 24 bbl. That can be done...


5,000

10,000

15,000

20,000

25,000

30,000

0 5 10 15 20 25 30 35 40 45 50

Kick Volume, bblD

ep

th,

ft

The more accurate analysis says that the gas only needs to be compressed from 13 to 11 bbl! That is much less challenging!



What happens to pump efficiency as we try to pump gas? Should we expect “gas lockup”?

In our example DGD well the pressure increase across the MLP is from 4,520 to 8,460 psi.

If the pump is 100% efficient then there is no problem; when pumping gas the efficiency is still 100%.

Let us consider a more modest pump efficiency of 90%.By that we mean that the “piston” sweeps 90% of the volume inside the pump. 10% remains in the pump.



Let us first consider the “PV = constant” case.

In this case we ended up compressing the gas from 46 bbl to 24 bbl. During the first part of the stroke the gas is being compressed and nothing comes out. At the end of the stroke 10% of the pump volume still contains gas.

At the beginning of the next stroke this 10% expands to 10 * 46/25) = 18.4% of the pump volume. 100 - 18.4 = 81.6

The resulting pump efficiency is therefore reduced from 90% to 81.6%. That would seem acceptable!



Let us now consider the “Real Gas” case. (PV = ZnRT)

In this case we ended up compressing the gas from 13 bbl to 11 bbl. As before, at first gas is being compressed and nothing comes out. At the end of the stroke 10% of the pump volume still contains gas.

At the beginning of the next stroke this 10% expands to 10 * 13/11) = 11.8% of the pump volume. 100 - 11.8 = 88.2

The resulting pump efficiency is therefore reduced from 90% to 88.2%. Hardly even noticable!



Two factors may further reduce this potential problem:

1. The actual MLP we’ll be using will probably have a volumetric efficiency in excess of 95%.

In this case the remaining 5% expands to 5 * 13/11) = 5.9% of the pump volume. 100 - 5.9 = 94.1

The resulting pump efficiency is therefore reduced from 95% to 94.1%. LESS THAN 1% LOSS!!

2. The above calculations assumed that 100% pure gas would arrive at the pump. Dilution with mud will usually reduce this %age by a significant factor, further increasing efficiency...



Note that because of the high pump efficiency there is no significant reduction in the fluid circulation rate in the annulus!

In extreme cases it may be necessary to speed up the pump very slightly in order to follow the drill pipe pressure decline schedule.

There is a slight reduction in volumetric rate in the return line because of gas compression. There is no reduction in the average mass circulation rate in the return line! It remains the same as in the annulus.



So, what ever happened to “gas lockup”?

In DGD it is unlikely that we shall see a volumetric compression requirement much greater than a factor of two. Usually it will be much less.

However, let us imagine a situation where the volumetric compression requirement is a factor of 10, and the pump volumetric efficiency is 90%:

In this case the 10% that remains in the pump will expand to 10% * 10 =100%. In other words, the left-over gas will completely fill the pump at the next stroke. No gas is pumped. We would have achieved gas lockup!


Gas Gradients

What is the pressure gradient in a gas at very high pressure? How does it affect wellbore pressures?

At very high pressure the density may very well be as high as 3 lb/gal. This would correspond to a gradient of:

GGAS = 0.052 * 3 = 0.156 psi/ft

Consider a large gas kick that occupies 1,000 ft of the annulus, when drilling with 15 lb/gal mud. After pressures have stabilized, what is the increase in pressure at inlet to the MLP?

P = 0.052 * (15 - 3) * 1,000 = 624 psi


BOP

Static Pressures - DGD

PRESSURE

DE

PT

H

Seawater Hydrostatic

DGD MudHydrostatic

wo/kick

624 psi

Annulus MudHydrostatic

w/kick

Kick


Solubility of Gas Kick in Oil or Synthetic Based Drilling Fluids

• We know from experience that, at relatively low

pressures a gas kick may seem to disappear by

dissolving into the mud?

• As the kick gets close to the surface some or even most of the gas may come out of solution and present some unpleasant surprises.

• If we are drilling in a deep DGD well with an oil or synthetic based drilling fluid, what should we expect?



• Will a gas kick disappear by dissolving into the

mud in a deep DGD well?

• If we take a 10-bbl gas kick while drilling with a water-based drilling fluid we would expect to see a 10-bbl pit gain

• If we take a 10-bbl gas kick while drilling with an oil or synthetic based drilling fluid, would the pit gain be close to 10 bbl or closer to 1 bbl?



• If the kick takes place at high pressure in a

deep DGD well the pit gain would probably be

closer to 9 bbl!

• A 3 lb/gal gas kick behaves more like a liquid than a gas, and this fluid would mix with the drilling mud without substantial loss of volume

• The final mixture would have a density close to the weighted average of the two fluids


• The “PV = constant” assumption appears to be more or less acceptable in evaluating shallow gas kicks. It could be off by a factor of two

• The Perfect Gas Law: “PV = nRT ” improves on our predictions by including the effect of temperature

• The Real Gas Law: “PV = ZnRT ” is required if we want to predict accurately the behavior of real gases in deep DGD wells

Summary


• The “ Z-Factor ” is a factor that distinguishes between real gases and ideal gases

• The Z-factor has a value near 1.0 under atmospheric conditions. It can vary from 0.7 to 2.5 or more

• Below 7,000 psi an increase in temperature increases the Z-factor

• Above 8,000 psi an increase in temperature decreases the Z-factor

Summary - cont’d


• Gas expansion in deep DGD wells is only a small fraction of what we might expect from shallow-well experience with gas kicks

• The density of a gas at 20,000 psi may be as high as 3 lb/gal or even higher! This gas behaves more like a liquid than a gas.

• At high pressures a Gas kick mixes with Oil or Synthetic Based Mud with little change in volume

Summary - cont’d


by Hans C. Juvkam-WoldNovember 2000

The End6. Gas Kick Behavior

Dual Gradient DrillingBasic Technology

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Lesson 5 Gas Kick Behavior