Modeling the PVT Behavior of Kerogen Thermal Conversion Products and its Effect on Carbon Steel Corrosion at
High Temperatures
OLI Simulation Conference October 21-22, 2014
Brent Sherar, Rudolf Hausler, and Ravi Krishnamurthy
Blade Energy Partners Houston, TX
Background
Downhole:
325 °C and
42 psia
Wellhead:
140 °C and 20 psia
The wellbore fluids (hydrocarbon + H2O), under extreme environmental
conditions might pose a material integrity threat.
Injectors
contain
heaters
(500 to
600 °C)
Kerogen
(formation)
250 m
Objective
1) Reconcile the pyrolytic water sample analysis;
2) Recombine the water sample analysis with the hydrocarbon phase under reservoir conditions – generate a “produced wellbore fluid”;
3) Model the dew point temperature behavior of the produced wellbore fluid over time;
4) Estimate the carbon steel (casing) corrosion rate
Evaluate whether the produced pyrolytic fluid, under extreme well conditions, causes an integrity threat for an
exploratory pilot well during 500+ days of operation.
Approach using OLI with AQE framework
Task 1: Reconcile the mixed pyrolytic-pore water sample analysis
Mixed Pore-Pyrolysis Water Compositions
During production, it was expected in-situ pyrolysis would yield a mixed weighted average composition:
88 % pore – 12 % pyrolysis water
Kerogen core samples were collected from the field.
In the lab, samples were heated to initiate pyrolysis. The pyrolysis water composition was analyzed.
pH between 8 to 9.
Water sample is more basic than typical “oilfield” produced water. Has a significant nitrogen content.
Reported Pore-Pyrolysis Water Sample
6
Parameter Unit
Lab
Mixed pore-
pyrolysis water
pH \ 8.8
Total Kjehldahl
Nitrogen (TKN) mg/L 1,717.0
NH4+ mg/L 1,633.0
NO3– mg/L 121.0
NO2– mg/L 0.1
Cl– mg/L 744.0
• When attempting to charge
balance water sample in OLI,
the sample was severely
anionic deficient.
• The “as reported” analytical
[NH4+] (determined via the
Kjehldahl method) reflects
both the contribution of NH4+
(87 %) and NH3 (13 %).
The 88 % pore – 12 % pyrolysis mixed water
composition is now charged balanced and pH reconciled.
Task 2: Recombine the water sample analyses with the hydrocarbon phase
under reservoir conditions
Geothermal Modeled Production Data
Table includes the total water production rates, but the data does not include all the water-soluble species (e.g., NH3 and HCl) that pose a
corrosive threat.
Combined Pyrolysis (gas and water) Composition: Total Wellbore Fluid
Phase I II III IV
(kg/day)
H2O 820.3 881.6 279.6 647.1
H2S 2.6 18 29.9 3.4
CO2 1.95 14.3 27.5 5.35
HCl 0.21 0.28 0.5
NH3 0.025 0.6 0.44 1.01
NaCl 8.5 1.6
Using OLI, both acid and volatile inoroganic gases are
included at the appropriate rate
The speciation reflects those which have the greatest influence
on tubing integrity.
Wellbore fluid composition changes per phase
9
Having recombined the produced hydrocarbon, acid and volatile gases, and
water compositions, the integrity of the casing can be evaluated.
Task 3: Model the dew point temperature behavior of the produced wellbore fluid
over time
Modeling the Dew Point Temperature in the Wellbore
Downhole:
325 °C and 42 psia
Entire fluid is in the gas
phase entering casing
annulus
Kerogen
(formation)
Wellhead:
140 °C and 20 psia
Fluid is liquid + gas
Dew point temperature of water:
1) (pH < 3 and very high Cl− content)
2) Location changes with time
Dew Point Temperature Calculations
At the dew point temperature, OLI predicts the over-saturation of NH4Cl:
NH3 + HCl → NH4Cl
NH4Cl deposition has been linked to refinery corrosion
Used the Combined Pyrolysis (gas and water) Composition
Phase Period (d)
Dew Point
Temperature in
Casing (°C) at 42
psia
pH at Dew
Point
[Cl–] 10 °C
below the dew
point (mg/L)
Daily NH4Cl
deposition
(kg/day)
II 175-212 167 2.80 341,000 0.26
II 213-237 167 3.06 341,000 0.78
III 238-425 154 3.23 314,000 0.28
IV 426-527 168 3.06 311,000 0.58
The presence of NH3 and HCl raise the dew point
temperature compared to pure water.
Acidic and highly chlorinated
environment
The producer pressure was set to 42 psia for all calculations
Experimental Corrosion Rates: Carbon Steel vs. Corrosion
Resistant Alloys (CRA)
Effect of materials on corrosion rate in 40 %wt NH4Cl solution at 149°C.
The marginal cost of using CRA vs. carbon steel is prohibitive.
Sun and Fan, NACE, paper no. 10359, 2010
800 mpy is too high for 6
month pilot well.
13
Task 4: Estimate the carbon steel (casing) corrosion rate
Corrosion Modeling Premise
As production ramps up, the internal well temperature increases. Consequently, the dew point location will move up the casing with
time. Corrosion only occurs in the presence of liquid water.
General corrosion
Dew point, or
localized,
corrosion
Time
Tem
per
ature
hotter
cooler
Vapor phase: no
liquid water
Total wall loss = Dew point corrosion + General corrosion
Dew Point Depth in the Casing with Time
0
50
100
150
200
250
150 200 250 300 350 400 450 500 550
Ca
sin
g d
epth
(m
)
Time (day)
Having established the dew point casing depth with time, the wall
loss at each node can be estimated.
Sources of Corrosion with depth and Time
0
50
100
150
200
250
150 200 250 300 350 400 450 500 550
Ca
sin
g d
epth
(m
)
Time (day)
General corrosion
No corrosion
Below the dew point
temperature, general
corrosion can occur.
Above the dew point
temperature of water no
corrosion as no liquid
water exists
At the dew point
temperature,
localized (pitting)
corrosion.
Total wall loss = Dew point corrosion + General corrosion
Corrosion Wall Loss Estimate
Objective: Define a cumulative corrosion wall loss for the casing as a function of both wellbore depth and time. Sources of corrosion: 1) General corrosion (below the dew point temperature; ~ 25 mpy
calculated by OLI) 2) Localized corrosion (at the dew point; 1,000 mpy, literature based). A corrosion wall loss value was calculated for a specific duration the dew point temperature of water remains at a particular depth.
Total wall loss = Dew point corrosion + ∑General corrosion (Phases I – IV)
Casing depth versus type of corrosion 50
70
90
110
130
150
170
190
210
230
250
0 50 100 150 200 250
Casi
ng d
epth
(m
)
Wall loss (milli-inch)
Total wall loss
Localized corrosion
General corrosion
The variability in the localized corrosion rate is dependent on the length of time the
dew point remains at a particular location.
Extra wall
thickness
designed for
corrosion
wall loss
Summary
Task Outcome
Reconcile the water sample analyses
Source of NH3 and HCl – impacts dew point calculations and localized corrosion
Recombine the water sample analyses with the hydrocarbon phase under
reservoir conditions
Generated a produced wellbore fluid – model phase behavior within casing annulus
Calculate the dew point temperature of the
produced fluid over time
NH4Cl precipitation at the dew point temperature - source of localized corrosion
Estimate the carbon steel (casing) corrosion rate
General (OLI) and Localized/pitting (literature) corrosion rates
