Gas Condensate Reservoirs:Sampling, Characterization and

Optimization

SPE Distinguished Lecture Series

2003 - 2004

F. Brent Thomas

Presentation Outline

1.Fundamentals of Phase Behavior

2.Pitfalls to Avoid in Sampling Condensate wells

3.Characterization of Gas Condensate Fluids

4.Production Considerations

5.Performance Optimization

Sample set for this Presentation:

Good and Bad

35% of GIP produced before dew point pressure

85% of total GIP recovered

Only 10% GIP ultimately recovered

Abandon the reservoir

at the dew point.

What makes one retrograde reservoir so good and another so bad?

Presentation Outline

1.Fundamentals of Phase Behavior

2. Pitfalls to Avoid in Sampling Condensate wells

3. Characterization of Gas Condensate Fluids

4. Production Considerations

5. Performance Optimization

Basic Phase Behavior

TEMPERATURETEMPERATURE

PRESSURE

Gas-Oil Ratio - m3/m30 100 500 2000 10000

356 18BBL/MMscf

Rules of thumb

Volatile Oil – Condensate Transition : <12.5 mole% C7+

Presentation Outline

1. Fundamentals of Phase Behavior

2.Pitfalls to Avoid in Sampling Condensate wells

3. Characterization of Gas Condensate Fluids

4. Production Considerations

5. Performance Optimization

Standard Technique:

Stable flow rate and GOR are necessary conditions for sampling.

1. Allow the well to clean up.

2. Flow at a low rate (lowest drawdown where stability is maintained). Capture liquid and gas samples.

3. Flow at a higher rate – capture liquid and gas samples.

4. Beneficial to obtain samples for at least three rates.

As a general expectation -Apparent GOR vs Flowrate

0

500

1000

1500

2000

2500

0 1 2 3 4 5 6 7

Flowrate (MMscfD)

Ap

pare

nt

GO

R (

m3/m

3)

Formation issuesWellbor

e issues

Flowrate

GOR vs Gas Rate - 28 103m3/d

300000

350000

400000

450000

500000

550000

10 11 12 13 14 15 16 17 18

Cumulative Time (Hours)

GO

R (

m3 /m

3)

0.989 MMscfD

As a general expectation -

Apparent GOR vs Flowrate

0

500

1000

1500

2000

2500

0 1 2 3 4 5 6 7

Flowrate (MMscfD)

Ap

pare

nt

GO

R (

m3/m

3)

Formation issuesWellbor

e issues

Flowrate

4.24 MMscfD

GOR vs Gas Rate - 120 103m3/d

150001600017000180001900020000210002200023000

13 14 15 16 17 18 19 20 21

Cumulative Time (Hours)

GO

R (

m3 /m

3)

4.24 MMscfD

What about Bottom-Hole Samples?

Mole Fraction Methane vs Well

0

0.2

0.4

0.6

0.8

1

1 2 3

Well Number

Me

tha

ne

Mo

le F

ract

ion

Sample 1 Sample 2

What about Bottom-Hole Samples?

Mole Fraction Methane vs Well

0

0.2

0.4

0.6

0.8

1

1 2 3

Well Number

Me

tha

ne

Mo

le F

ract

ion

Sample 1 Sample 2

Bubble Point

Mole Fraction vs MW

0

0.05

0.1

0.15

0.2

0.25

0.3

0 100 200 300 400 500 600 700 800 900 1000

Molecular Mass

Mo

le F

ract

ion

Wax Resin Asphaltene

For example:Comparison of C15+ Mole Fraction Distribution

Gas Condensate Samples

0.0000

0.0100

0.0200

0.0300

0.0400

0.0500

0.0600

0.0700

0.0800

0.0900

5 10 15 20 25 30

Component Number

Mole

Fra

ctio

n

BHS- 1 BHS- 2 Separator Oil

MW 216

MW 206

Multi-Rate Sampling :

resolves Liquid – Vapor Ambiguities

Bottom-Hole Sampling:

resolves Liquid – Solid Concerns

Therefore:

Presentation Outline

1. Fundamentals of Phase Behavior

2. Pitfalls to Avoid in Sampling Condensate wells

3.Characterization of Gas Condensate Fluids

4. Production Considerations

5. Performance Optimization

1-D thinking

100 C & 2000 Psi

50 C & 500 Psi

20 C & 200 Psi

Reservoir Fluid

100 C & 3000 Psi

100 C & 2000 Psi

50 C & 500 Psi

20 C & 200 Psi

Reservoir Fluid

100 C & 3000 Psi

4

1

1

2

Near Well-boreStill in the reservoir

Up the well-bore

Surface Separator

We do it all the time in characterizing condensates

70

60

40

1

2

3

MMscfD

bbl/MMscf)

BUT -

Time

Conclusion of the evaluation engineers -

-liquid yield was only 22.7 bbl/MMscf

-fluid in situ is a wet gas

-no concerns are foreseen.

Problem: Rates were too high.

Change the rate and you change the yield.

Constant Volume Depletion - % Liquid Accumulation

y = -9.8895E-09P2 + 1.6338E-04P + 2.2456E+00

R2 = 9.9916E-01

-0.5

0

0.5

1

1.5

2

2.5

3

3.5

0 5000 10000 15000 20000 25000 30000

Pressure (kPa)

Liq

uid

(%

)

0.000

0.002

0.004

0.006

0.008

0.010

0.012

0.014

0.016

0.018

0.020

C12 C13 C14 C15 C16 C17 C18 C19 C20 C21 C22 C23

Compositon

Mo

le F

ract

ion

Feb. 19/2002

May 25/2002

Jun 24/2002

0.000

0.002

0.004

0.006

0.008

0.010

0.012

0.014

0.016

0.018

0.020

C12 C13 C14 C15 C16 C17 C18 C19 C20 C21 C22 C23

Compositon

Mo

le F

ract

ion

Feb. 19/2002

May 25/2002

Jun 24/2002

In addition to liquid volume, look at heavier ends -

EarlyMiddleLateThe heavier

ends are already gone!

Impact on composition is significant.

-Liquids condense from the gas

-liquids accumulate in the formation.

-surface liquid is apparently lighter (less heavy ends).

The result – lower apparent dew point pressure and lower apparent liquid yield.

1. Perform multi-rate sampling2. If any appearance of solids obtain BHS for reference on C12+.3. Sample early in the life of the well/reservoir.

We recommend -

Presentation Outline

1. Fundamentals of Phase Behavior

2. Pitfalls to Avoid in Sampling Condensate wells

3. Characterization of Gas Condensate Fluids

4.Production Considerations5. Performance Optimization

It should be producing at three times the rate! Get a bigger pump!!!

My consideration? Increase Revenue!

1. Interfacial Tension Effects

ΔP α IFT/D

- IFT increases as Pressure decreases

- greater P will be required to produce similar flow rates.

PCAP

D

Pressure

IFT

4520 psi

6000 psi

IFT may increase very rapidly with decreasing Pressure.

0.0125

0.50Increase of 40X

Regain Permeability vs DP

0

50

100

20 80 200 800 Lean Gas

Delta P (psi/ft)

Reg

ain

(%)

Regain Gas Perm vs DP

0

50

100

200 800 2000 Lean Gas

Delta P (psi/ft)

Re

ga

in (

%)

20684 kPa

(3000 Psia)

13789 kPa

2000 Psia

Bigger pump may be counter-effective!

Relative Permeability vs IFT

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.2 0.4 0.6 0.8 1

Liquid Saturation

Rel

ativ

e P

erm

0.20 D/cm

2.0 D/cm

Impact of IFT on KREL

2. Porous Feature Size Effects

Permeability Reduction with Rock Quality

0

10

20

30

40

2 8 20

Rock Air Permeability (mD)

Per

mea

bilit

y R

educ

tion

Beware!

Example:

Core 1 had a permeability of 256 mD, =17.4%.

Core 2 had a permeability of 39 mD, =18.5 %.

Core 1 had 10X reduction in KG due to liquid

Core 2 had a 25% reduction in KG due to liquid

0

0.2

0.4

0.6

0.8

1

Auto

corr

ela

tion F

unction

0 50 100 150 200 250 300 350 400 Lag (microns)

Integrated Cuttings Analysisln(K)=9.33+5.75 ln(por) +0.737 ln(IS)

Integral = 32.5

Optical Porosity & Perm = 10.9% & 0.41 mD

Presentation Outline

1. Fundamentals of Phase Behavior

2. Pitfalls to Avoid in Sampling Condensate wells

3. Characterization of Gas Condensate Fluids

4. Production Considerations

5.Performance Optimization

Cal Canal field, California:

“ There were three simultaneous effects: a) the gas transmissibility drastically declined as a result of retrograde fallout around the wellboreb) the skin changed from negative to positive as a result of liquid blockage . . . and c) the production rate increased sharply, but rapidly declined to a much lower rate.”

SPE 13650, 1985, Roy Engineer.

Mass of hydrocarbon left behind?

What are the options:

Blow it down. Implement pressure

maintenance via different forms of gas cycling.

What is legal and what is moral?

Our observation – only if it affects gas production.

Easiest Pressure maintenance-start above dew point pressure

Phase Loop Shrinkage with Cycling

1000

6000

11000

16000

21000

26000

0 100 200 300 400 500

Temperature (K)

Pre

ss

ure

(kP

a)

Original After cycling

Tres

Shrinkage with Cycling at 4000 Psia & 197 F

0.5

0.6

0.7

0.8

0.9

1

1.1

1 2 3 4

Cycle Number

Liq

uid

Fra

cti

on

Experimental EOS

More common approach:

Shrinkage w/ Cycling at Pres and Tres

27579 kPa (4000 psi)

13789 kPa (2000 psi)

Another factor is productivity

Relative Permeability vs Gas Saturation

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0.000 0.100 0.200 0.300 0.400 0.500 0.600 0.700 0.800

Gas Saturation

Re

lati

ve

Pe

rme

ab

iity

Gas Condensate

Regain Permeability vs DP

0

50

100

20 80 200 800 Lean Gas

Delta P (psi/ft)

Rega

in (%

)

Ultimately for cycling optimization:

1. How much of the liquid will be lost w/o cycling.

2. What will be the effect on gas rates?

3. What can you recover with cycling?

4. What are your objectives - short term/ long term?

Total Revenues - Costs

0.00

1000.00

2000.00

3000.00

4000.00

5000.00

6000.00

0 500 1000 1500 2000 2500 3000 3500 4000 4500

Pressure

Do

lla

rs

1.50 $ 2.50 $ 3.50 $ 4.50 $

4.50 $/ Mscf

1.50 $/ Mscf

Assuming that liquid dropout does not significantly affect gas rate:

Optimization for recovery of liquid drop out

If gas rates decrease rapidly with liquid saturation, then gas cycling/ stimulation may be required regardless.

Relative Permeability vs Gas Saturation

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0.000 0.100 0.200 0.300 0.400 0.500 0.600 0.700 0.800

Gas Saturation

Re

lati

ve P

erm

eab

iity

Gas Condensate

In summary of optimization:

• how much hydrocarbon will be left behind

• how much can be re-vaporized/ kept from condensing

• need cheap gas – 6 Mscf/BOE

• When gas price is high, liquid recovery may be insufficient incentive to implement gas cycling

• if gas rates are severely impaired then cycling/ stimulation is only option

Presentation Outline

1. Fundamentals of Phase Behavior

2. Pitfalls to Avoid in Sampling Condensate wells

3. Characterization of Gas Condensate Fluids

4. Production Considerations

5. Performance Optimization