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Removal of CO2 from natural gas (or other streams)
using a solid poly-amine adduct (SPAA), With stripping at elevated pressures
to reduce or eliminate CO2 compression
Canada Chemical Corporation24, 4807-32 Street S.E.Calgary, Alberta, Canada T2B [email protected](403) 560-7483, Conrad Ayasse, Ph.D., FCIC, President
US 8,597,411 Sorbents for the recovery and stripping of acid gases
CO2 and H2S are recovered with a low- energy solid- state process utilizing an amine composite. Stripping is achieved at elevated pressures (over 400 psi), saving compression energy for CO2 transportation or disposal. Traditional energy-intensive liquid amine processes strip CO2 with high temperature steam at atmospheric pressure: the CO2 must then be compressed from atmospheric pressure to over 750 psi.
The Business Opportunity:
High-CO2 Natural Gas
Location Horn River, BC, Llaird FormationNGL-rich Gas resource 48-trillion scfCO2 Concentration 13 %Llaird Pressure 7650- 13,800 psi
Will require deep well CO2 disposal with high compression costs
Canadian Field with High CO2
Horn River Shale
The Horn River Basin shale play is located in northeast British Columbia and is a relatively
new natural gas discovery. It is the largest known shale gas field in Canada. A large
number of mostly Canadian and American companies have been busy obtaining leases
in the Horn River area, and a 36-inch pipeline is being built to transport natural gas from
this remote area to a tie-in point on TransCanada’s existing Alberta System.
Experts estimate there is about 250 trillion cubic feet (tcf) of natural gas in the field, of which 10% to 20% is recoverable. Another
emerging shale play in British Columbia, just south of the Horn River shale, is the Montney shale, which is estimated to hold up to 50 tcf
of gas reserves and extends east into Alberta.
APACHE: Liard basinIn northern British Columbia, Canada, Apache has validated an outstanding new shale play in the Liard Basin with net estimated sales gas of 48 trillion cubic feet (Tcf) of natural gas (8 billion Boe) across 430,000 acres held with a 100-percent working interest. The resource estimate at Liard is based on recent drilling, test results and earlier well control points.
Companies involved in the extraction of natural gas from the Horn River Shale include EnCana, Apache, EOG, Stone Mountain Resources, Exxon, Quicksilver Resources, Nexen and Devon Energy.
Liard Basin•Best gas-shale reservoir evaluated in North America•Main reservoir is Lower Besa River First Black Shale•Excellent vertical and lateral reservoir continuity•D-34-K well: IP30 = 21.3MMcfd; EUR 18 BCFHorn River Basin•Among North America’s leading shale gas basins•Two main reservoirs (Muskwa/Otterpark and Evie)•Proven viability with 100+ wells producing wells•Established Infrastructure and connectivity to key liquidity hubs
RESERVOIR UNITS LIARD HORN RIVER NE-PA
MARCELLUSHAYNESVILLE
Depth (f) 9,500 - 15,000 500 - 9,800 7,000 - 11,000 10,000 - 13,000
Thickness (f) 400 - 1,000 330 - 660 150 - 400 100 - 300
Porosity (%) 3 - 8 2 - 8 6 - 12 4 - 7
Water Saturation (%) 15 - 20 10 - 40 15 - 45 20 - 40
OGIP / Sec (Bcf) 170 - 500 100 - 200 30 - 200 50 - 100
Thermal Maturity (VRo) > 1.5 > 2.0 > 1.6 > 1.7
Pressure (Psi/ft) 0.85 - 0.92 0.57 - 0.70 0.5 - 0.65 ~ 0.85
GOR Dry gas Dry gas Dry gas Dry gas
Quartz+Carb (Vol %) > 90 85 - 90 65 - 90 60 - 70
TOC (Wt. %) 3 - 6
Reservoir pressure, Psi range 7650-13,800 285-6860 3500-7170 8500-11,050
Horn River Field Data
Best in N.A.
OUR TECHNOLOGY:
SEPARATION OF CO2WHILE MAINTAINING RAW
GAS PRESSURETO
ELIMINATE CO2 COMPRESSION COSTS
Figure 1. Traditional amine CO2 recovery: present state-of-the-art.
Regardless of Raw Gas pressure, acid gas recovery pressure is 35-40 psia
Traditional liquid amine absorbers strip CO2 at 110-130 ºC and 35-40 psia using
steam. We strip a solid poly-amine adduct with hot CO2 at Raw Gas pressure or
higher.
How do you recover CO2 as a liquid without
a compression step?
Answer: If the Raw Gas pressure is above 1070
psia,absorb the CO2 with our SPAA
absorbent that is sensitive to stripping temperature.
Solid Poly-Amine Adduct: No amine vapour losses, high CO2 absorption capacity.
0 100 200 300 400 500 6000
0.5
1
1.5
2
2.5
3
3.5
4
f(x) = 0.0066403331700147 x + 0.286849485546301R² = 0.999156232187072
CO2 absorption capacity increases linearly up to at least 500 psia for our SPAA
Absorption pressure
Abso
rptio
n ca
pacit
y, m
Mol
CO
2/g
abso
rben
t
Figure 2. CO2 absorption capacity versus Raw Gas pressure for SPAA
CO2
H2S
Absorption cycle conducted at 100 psia for all cases
CO2: Full stripping up to 300 psia, 80% at 400 psiaH2S: Full stripping up to 400 psia
Figure 3. Complete acid gas recovery at pressures above absorption pressure
Full recovery
Figure 4. The SPAA absorbent capacity is unchanged over 30 days:
The Absorbent is stable.
The Absorber is a bed packed with porous alumina or silica particles.
A poly-amine adduct is synthesized inside the pores
Porous particle
The pore space contains polyethyleneimine, an amine polymer that is reacted with a polyvinyl alcohol and bonded to the alumina or silica surface (US Patent 8,597,411).
Figure 5. The “solid state” SPAA absorbent
ParticleProperties
Pore volume 1-ml/gSurface area 270 m2/g
Figure 6. The reaction of polyethyleneimine with polyvinylalcohol in the presence of acetic acid
PEI, MW 1300 AMU PVA, MW 85,000-124,000 AMU
Reactive secondary or tertiary amines react with CO2
Bonds to support surface
Solid polyamine
SPAA
Figure 7. CO2 Phase Diagram
Critical Point:73.77 bar (31 ºC.)7377 kPa (1070 psia)
Examples:
CO2 absorbed from Raw Gas at 100 psi can be stripped at over 300 psi, saving 2-stages of compression.
CO2 absorbed from Raw Gas at 1100 psi can be stripped at >1100 psi and then it cools as a liquid without compression.
Plant operation
By supplying CO2 at an elevated pressure, our Process reduces the energy and number of compression stages that are required for CO2 liquefaction. For the case where Raw Gas Pressure is above 1070 psia, a CO2 compressor is not needed.
Cooler
LiquidCO2 (<31 ºC.)
Back-PressureRegulator
(>1070 psia)
Absorber 1
Absorber 2
Raw Gas
Heater
CleanGas
Cool CO2 (<31 ºC.)
Hot CO2 (130 ºC.)
This is the starting configuration (Connections from Absorber 2 to CO2 vessels are not shown).Absorber 1 is saturated with CO2 and Absorber 2 has begun treating Raw Gas.
Figure 8. SPAA Plant starting conditions
Compressor
Cooler
LiquidCO2
Back-Pressureregulator
Absorber 1
Absorber 2
Raw Gas
Heater
CleanGas
Cool CO2
Hot CO2
Raw Gas is swept from the free space of Absorber 1 with pure cool CO2 and sent to Absorber 2 so that hydrocarbons do not contaminate the stored CO2
Figure 9. Removing Raw Gas
Compressor
Cooler
LiquidCO2
Back-Pressureregulator
Absorber 1
Absorber 2
Raw Gas
Heater
CleanGas
Cool CO2
Hot CO2
Some stored CO2 is heated to the stripping temperature, 130 ºC, so that absorbed CO2 will be released from the bed particles and recovered . This continues until the bed is low in absorbed CO2.
Figure 10. Stripping CO2
Compressor
Cooler
Back-PressureRegulator
Absorber 1
Absorber 2
Raw Gas
Heater
CleanGas
Cool CO2
Hot CO2
The hot CO2 in the free space between the particles is pushed into the cooler with Raw Gas in preparation for starting the absorption cycle on Absorber 1.
Figure 11. Flushing hot stripping gas
Compressor.
LiquidCO2
Cooler
LiquidCO2
Back-Pressureregulator
Absorber 2
Absorber 1
Raw Gas
Heater
CleanGas
Cool CO2
Hot CO2
The Raw Gas stream is re-directed to Absorber 1, and the CO2 stripping cycle is begun on Absorber 2.
Figure 12. Switching Absorbers
Compressor
Sour Natural Gas: H2S also recoveredCO2-rich natural gas that also contains H2S (sour natural gas) can also be cleaned with our economical process. The H2S will end up mixed with the CO2 at high-pressure for deep-well disposal.
If the mixture contains less than 50% CO2 it could be sent directly to a Claus plant. For higher CO2 concentrations, a second water-based amine absorber/scrubber pair are required and the low-pressure CO2 is vented. This adds considerable expense and produces CO2 at near atmospheric pressure that is emitted to the atmosphere.
Our process (no liquid amine plant and no Claus plant) is already cheaper than the existing traditional Amine/ Claus process: As CO2 emission penalties are imposed by Governments, our process will become imperative for capturing and disposing of the CO2