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 2X3canchem@telusplanet.net(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