Removal of CO 2 from natural gas (or other streams) using a solid poly-amine adduct (SPAA), With stripping at elevated pressures to reduce or eliminate CO 2 compression Canada Chemical Corporation 24, Street S.E. Calgary, Alberta, Canada T2B 2X3 (403) , Conrad Ayasse, Ph.D., FCIC, President

US 8,597,411 Sorbents for the recovery and stripping of acid gases CO 2 and H 2 S 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 CO 2 transportation or disposal. Traditional energy-intensive liquid amine processes strip CO 2 with high temperature steam at atmospheric pressure: the CO 2 must then be compressed from atmospheric pressure to over 750 psi.

The Business Opportunity: High-CO 2 Natural Gas

Location Horn River, BC, Llaird Formation NGL-rich Gas resource48-trillion scf CO 2 Concentration13 % Llaird Pressure ,800 psi Will require deep well CO 2 disposal with high compression costs Canadian Field with High CO 2

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 basin In 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.EnCanaApache EOGExxonQuicksilver ResourcesNexenDevon 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 BCF Horn 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

RESERVOIRUNITSLIARD HORN RIVER NE-PA MARCELLUS HAYNESVILLE Depth(f)9, , ,800 7, ,00010, ,000 Thickness(f) , Porosity(%) Water Saturation(%) OGIP / Sec(Bcf) Thermal Maturity(VRo)> 1.5 > 2.0 > 1.6> 1.7 Pressure(Psi/ft) ~ 0.85 GOR Dry gas Quartz+Carb(Vol %)> TOC(Wt. %)3 - 6 Reservoir pressure, Psi range , ,050 Horn River Field Data Best in N.A.

OUR TECHNOLOGY: SEPARATION OF CO2 WHILE MAINTAINING RAW GAS PRESSURE TO ELIMINATE CO2 COMPRESSION COSTS

Figure 1. Traditional amine CO 2 recovery: present state-of-the-art. Regardless of Raw Gas pressure, acid gas recovery pressure is psia

Traditional liquid amine absorbers strip CO 2 at ºC and psia using steam. We strip a solid poly-amine adduct with hot CO 2 at Raw Gas pressure or higher.

How do you recover CO 2 as a liquid without a compression step?

Answer: If the Raw Gas pressure is above 1070 psia, absorb the CO 2 with our SPAA absorbent that is sensitive to stripping temperature. Solid Poly-Amine Adduct: No amine vapour losses, high CO 2 absorption capacity.

Figure 2. CO 2 absorption capacity versus Raw Gas pressure for SPAA

CO 2 H2SH2S Absorption cycle conducted at 100 psia for all cases CO 2 : Full stripping up to 300 psia, 80% at 400 psia H 2 S: 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 Particle Properties Pore volume 1-ml/g Surface area 270 m 2 /g

Figure 6. The reaction of polyethyleneimine with polyvinylalcohol in the presence of acetic acid PEI, MW 1300 AMU PVA, MW 85, ,000 AMU Reactive secondary or tertiary amines react with CO 2 Bonds to support surface Solid polyamine SPAA

Figure 7. CO 2 Phase Diagram Critical Point: bar (31 ºC.) 7377 kPa (1070 psia)

Examples: CO 2 absorbed from Raw Gas at 100 psi can be stripped at over 300 psi, saving 2-stages of compression. CO 2 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 CO 2 at an elevated pressure, our Process reduces the energy and number of compression stages that are required for CO 2 liquefaction. For the case where Raw Gas Pressure is above 1070 psia, a CO 2 compressor is not needed.

Cooler Liquid CO 2 (<31 ºC.) Back- Pressure Regulator (>1070 psia) Absorber 1 Absorber 2 Raw Gas Heater Clean Gas Cool CO 2 (<31 ºC.) Hot CO 2 (130 ºC.) This is the starting configuration (Connections from Absorber 2 to CO 2 vessels are not shown). Absorber 1 is saturated with CO 2 and Absorber 2 has begun treating Raw Gas. Figure 8. SPAA Plant starting conditions Compressor

Cooler Liquid CO 2 Back- Pressure regulator Absorber 1 Absorber 2 Raw Gas Heater Clean Gas Cool CO 2 Hot CO 2 Raw Gas is swept from the free space of Absorber 1 with pure cool CO 2 and sent to Absorber 2 so that hydrocarbons do not contaminate the stored CO 2 Figure 9. Removing Raw Gas Compressor

Cooler Liquid CO 2 Back- Pressure regulator Absorber 1 Absorber 2 Raw Gas Heater Clean Gas Cool CO 2 Hot CO 2 Some stored CO 2 is heated to the stripping temperature, 130 ºC, so that absorbed CO 2 will be released from the bed particles and recovered. This continues until the bed is low in absorbed CO 2. Figure 10. Stripping CO 2 Compressor

Cooler Back- Pressure Regulator Absorber 1 Absorber 2 Raw Gas Heater Clean Gas Cool CO 2 Hot CO 2 The hot CO 2 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. Liquid CO 2

Cooler Liquid CO 2 Back- Pressure regulator Absorber 2 Absorber 1 Raw Gas Heater Clean Gas Cool CO 2 Hot CO 2 The Raw Gas stream is re- directed to Absorber 1, and the CO 2 stripping cycle is begun on Absorber 2. Figure 12. Switching Absorbers Compressor

Sour Natural Gas: H 2 S also recovered CO 2 -rich natural gas that also contains H 2 S (sour natural gas) can also be cleaned with our economical process. The H 2 S will end up mixed with the CO 2 at high-pressure for deep-well disposal. If the mixture contains less than 50% CO 2 it could be sent directly to a Claus plant. For higher CO 2 concentrations, a second water-based amine absorber/scrubber pair are required and the low-pressure CO 2 is vented. This adds considerable expense and produces CO 2 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 CO 2 emission penalties are imposed by Governments, our process will become imperative for capturing and disposing of the CO 2