Transcript Document

Gas Condensate Blockage
A worked example using a simplified
simulation model to demonstrate
 Impact of condensate blockage in a
lean gas condensate reservoir.
 Sensitivity to near-well relative
permeabilities.
 How to estimate near-well relative
permeabilities, taking account of
velocity-dependent effects.
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
1
Gas Condensate
Blockage
Problem Description
• In a gas condensate well, FBHP
dropping below the dewpoint
causes a significant condensate
saturation buildup near the
wellbore, resulting in lowered
gas relative permeability.
• This reduced gas permeability
is called ‘condensate blockage’.
It can lower a well’s reservoir
PI by 50 to 200% (equivalent to
a skin of 5 to 20).
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
2
Gas Condensate
Blockage
Problem Description (continued)
• Condensate blockage adds
pressure drop which can be
important to low- and
moderate-permeability (kh)
wells.
– High permeability (kh) wells show
little effect because most of the
well’s pressure drop is in the
tubing.
- Low and moderate-permeability
reservoirs ( kh < about 10,000
md.ft ) may be affected by
condensate blockage.
- Blockage can still be important
for fractured and horizontal wells
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
3
Gas Condensate
Blockage
Problem Description (continued)
• Fine grid simulation studies using
measured ‘rock’ rel perm curves
often predict a significant loss in gas
deliverability due to condensate
blockage.
• Recently, numerous authors have
shown from field data that the use
of rock curves in radial simulations
overstates the condensate blockage
effect – a different modeling
approach is needed.
• Lab experiments show that rel perms
in gas condensate systems increase
at high velocity. The rel perms in
simulation models need to take
account of this effect.
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
4
Gas Condensate
Blockage
Recommended approach
• The following data will be
used:
- PVT data for the reservoir
fluid – black oil or EoS.
- Relative permeability curves
from full-field simulation model
(rock curves); use another
field’s curves or Corey
functions if no measured data.
- Radial single-well model
carefully constructed to
represent an average well in
the full-field model.
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
5
Gas Condensate
Blockage
Recommended approach
• Build a single-well radial model
- Scale model to represent an
average well’s drainage area,
OGIP, kh, etc.
- Pick gas rate as a well’s share
of the total field’s plateau
rate.
- Use r-z radial grid with 20-30
cells in r direction, with <1 ft
first block radius and
logarithmic radial spacing. Run
implicit.
- Use well tubing tables and THP
control
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
6
Gas Condensate
Blockage
Recommended approach
• The first single-well radial
model run should use rock
curves.
• The gas & oil curves should
cross at about 0.1 (0.05 0.12 usually); use Corey
exponents 2-3 if core data
are not available.
• Rock curves are considered
the worst case for
condensate blockage.
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
7
Gas Condensate
Blockage
Recommended approach
• The second single-well
radial model run should use
straight line (‘miscible’)
curves.
• The straight-line miscible
curves are considered the
best case for condensate
blockage.
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
8
Relative permeability
Rock and straight line rel
perms used to estimate
possible impact of
condensate blockage.
1
krg - rock
0.9
krg - rock
0.8
krg - misc
kro - misc
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
Gas saturation
Rock rel perms
have crossover
‘value’ of ~ 0.08
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
9
Gas Condensate
Blockage
Recommended approach
• Check - The plateau period
for the single-well radial
run using straight line
relative permeability
curves should be about that
seen for the full-field
model; little blockage.
• Compare - The plateau
period of gas production of
the two single-well radial
runs using rock and
straight-line relative
permeability curves.
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
10
Gas Condensate
Blockage
Recommended approach
• If the difference in
plateau period is not
significant, you’re done.
Don’t worry about
condensate blockage!
• If the difference in
plateau period is significant
and the correct period is
important to the economics
of the project, ‘engineer’
the condensate blockage
problem.
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
11
Gas production rate (MMscf/d)
High permeability reservoir
- similar results with rock
and straight line rel perms –
condensate blockage is not a
problem
45
40
35
30
25
20
100 md, st line rel perms
15
10
100 md, rock curves
5
0
0
2
4
6
8
10
Time (years)
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
12
Gas production rate (MMscf/d)
Low permeability reservoir different results with rock and
straight line rel perms –
condensate blockage impacts well
deliverability
45
40
35
10md, st line rel perms
30
25
10md, rock curves
20
15
10
5
0
0
2
4
6
8
10
Time (years)
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
13
Gas Condensate
Blockage
Recommended approach
In the low permeability reservoir
• The length of the plateau is
reduced by >50% between the
‘best’ and ‘worst’ case scenarios
for condensate blockage.
• In the worst case scenario, we
would need more wells, more
compression, etc.
• In practice, we will end up
somewhere between the two
extremes because of the
increase in relative
permeabilities at high capillary
number.
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
14
How can we calculate the
change in relative
permeabilities at high
velocity?
Experimental data suggest that
the changes can be correlated
as a function of the Capillary
Number.
The Capillary Number (Nc) is a
dimensionless number which
measures the ratio between
viscous and capillary forces.
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
15
Definition of Capillary
Number
Nc = velocity * viscosity / IFT
( Nc = DP(viscous)/Pc )
‘velocity’ is the superficial pore gas
velocity –
Darcy velocity / porosity / (1-Swc)
Data must be in consistent units –
simplest is to use SI units velocity in m/s, viscosity in Pa.s,
IFT in N/m.
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
16
Change in Rel Perms with Capillary
Number - Eclipse 300 model
Needs at least 7 empirical
parameters – suitable values not
published in open literature!
1
0.9
relative permeability
0.8
0.7
0.6
0.5Increasing
Increasing
Nc
0.4Nc
0.3
0.2
0.1
0
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
Gas saturation
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
17
Change in Rel Perms with Capillary
Number - Fevang-Whitson Model
Needs only 2 empirical parameters –
suitable values published in open
literature.
Based on krg as a function of krg/kro –
this is the fundamental rel perm
relationship which controls condensate
blockage.
1.0
0.9
relative permeability
0.8
0.7
Increasing
Nc
0.6
0.5
0.4
0.3
0.2
0.1
0.0
0.01
0.10
1.00
10.00
100.00
krg/kro
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
18
Change in Rel Perms with Capillary
Number - Fevang-Whitson Model
Interpolates between rock and miscible
(straight line) rel perms at fixed values
of krg/kro
krg  fkrg ,rock  (1  f )krg ,misc
Nc 
n
1
  3000 5000
Interpolation parameter from Fevang-Whitson
correlation for variation of rel perm with capillary
number
f=1 - rock
rel perms 1
0.9
interpolat ion parameter, f
f 
1
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
n  0 .7
July 21, 2015
f=0 - st line 0
rel perms 1E-07
1E-05
1E-03
1E-01
1E+01
Capillary number, Nc
e-notes (c) Curtis H. Whitson, Robert E. Mott
19
How can we run a single-well
simulation with the ‘correct’
relative permeabilities for
the near-well region?
EITHER
Use a compositional simulator
(e.g. Eclipse 300) with a model
for velocity dependent rel
perms.
•
Need to know the parameters for
the E300 correlation
OR
Estimate capillary number and
rel perms manually.
•
•
July 21, 2015
Described in the next 2 slides
This will give a first approximation
of the importance of the Nc
effect
e-notes (c) Curtis H. Whitson, Robert E. Mott
20
Estimating capillary number
and choosing near-well rel
perms
1.
2.
3.
4.
5.
July 21, 2015
Choose a time step near or just
after the end of plateau.
Calculate the Capillary Number
Nc and the interpolation
parameter f (Nc) at each grid
cell.
Take an ‘average’ value of f – e.g.
weighted according to pressure
drop across the cell.
Find the krg vs krg/kro curve for
this average value of f.
Choose new kr vs Sg curves which
honor the krg vs krg/kro
relationship for this average value
of f.
e-notes (c) Curtis H. Whitson, Robert E. Mott
21
Choosing near-well rel perms
Straight line
rel perms
Gas relative permeability
1
From ‘new’
kr vs Sg
curves
krg - rock
0.9
0.8
krg - misc
0.7
krg-interpolated
0.6
krg from new 'nearwell' curves
0.5
0.4
0.3
Interpolated
krg at
‘average’ Nc
0.2
0.1
0
0.001
0.01
0.1
1
10
100
1000
krg/kro
Rock
curves
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
22
Gas production rate (MMscf/d)
Repeat simulation using ‘near
well’ rel perm curves
45
10md, st line rel perms
40
10md, rock curves
35
30
10md, new 'near well'
curves
25
20
15
10
5
0
0
2
4
6
8
10
Time (years)
For this example, the use of velocitydependent rel perms has a significant
impact, and more detailed study is
justified.
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
23
Condensate blockage skin
Condensate blockage skin
from single well model
25
rock curves
Rock curves
– skin ~ 20
20
new 'near well' curves
15
10
With ‘nearwell’
curves, skin
~ 7
5
0
0
1000
2000
3000
4000
5000
6000
7000
reservoir pressure (psi)
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
24
Full field simulation where
condensate blockage is an
important issue (1)
Three levels of modeling (in
increasing order of complexity)
1. Coarse grid model with
condensate blockage skin from
single well models.
2. Coarse grid model with
generalized pseudopressure
(GPP) model for well inflow.
•
GPP model accounts for
condensate blockage in the well
inflow equations
3. Use local grid refinement around
the wells.
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
25
Full field simulation where
condensate blockage is an
important issue (2)
Coarse grid with generalized
pseudopressure (GPP) model is the
recommended approach in almost all
cases.
• GPP model only requires a small
overhead
• GPP model can include velocitydependent rel perms
Including LGRs increases run time
and affects numerical stability.
LGR only recommended for very lean
gas condensates in models with very
large grid cells.
• In this case LGR does not treat
blockage per se, but provides accurate
flowing GORs to the GPP model.
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
26
Simulation exercise
1. (optional) Run 1D Sensor model
for these cases. (Or just use
these output files.)
A. 10 md, rock rel perms
B. 10 md, straight line rel perms
C. 100 md, rock rel perms
D. 100 md, straight line rel perms
2. Look at development of the
condensate bank with time –
radius of bank and gas rel perms
in the bank.
3. Plot gas production rates and look
at impact of condensate banking.
Is it important for the 100 md
reservoir? For the 10 md
reservoir?
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
27
Simulation exercise
(continued)
For the 10md, rock rel perms case
4. Calculate condensate blockage skin, and
compare with results from simple
spreadsheet.
5. Calculate capillary number for each grid
cell near end of plateau.
6. Find a typical value of the parameter f
for interpolating between ‘rock’ and
straight line rel perms. Assume  =
4000, n = 0.7. Calculate the krg vs
krg/kro relationship for the condensate
bank.
7. Find rel perm curves which give similar
krg/kro behaviour for the range of
krg/kro values that occur in the
condensate.
8. Repeat simulations with these new
‘interpolated near-well’ rel perm curves,
and calculate condensate blockage skin.
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
28
Simulation exercise (results)
Gas production profiles show little
difference between st line and rock curve
results for 100 md reservoir, but a
significant difference for 10 md.
The calculations of capillary number and
relative permeability interpolation give an
average value of f of about 0.75.
A rel perm calculation shows that rel perm
curves with Corey exponents of 1.9 the
same krg vs krg/kro relationship the
interpolated curves with f = 0.75.
Gas production profiles shows a plateau of
about 3.5 years, compared with 1.5 years
using rock rel perms and 4.5 years using
straight line rel perms.
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
29
References
1.
Gas Condensate Relative Permeability for Well Calculations
2.
Measurement of Relative Permeability for calculating Gas
Condensate Well Deliverability
3.
Calculating Well Deliverability in Gas condensate Reservoirs
Notes
July 21, 2015
e-notes (c) Curtis H. Whitson, Robert E. Mott
30