The document outlines a proposed gas treatment plant with the following key points: - The plant would process raw shale gas from the Bakken formation to produce compressed natural gas, liquefied natural gas (LNG), and natural gas liquids (NGL) for various uses. - Major processes would include sour gas treatment to remove hydrogen sulfide, dehydration, demethanization, NGL stabilization, and nitrogen rejection via cryogenic distillation. - Economics analysis shows total annual revenues of $317 million against operating costs of $395 million, with a total installed capital cost of $144 million. - Key recommendations are for the plant to move forward given its importance in supplying gas to other

1. Gas Treatment Plant
Team Alpha
Kyle Soumar
Stephanie Sampra
Chris Drouganis
Mariam Buari
Mentor: Jerry Palmer

2. Outline
1. Purpose
2. Objective
3. Design Basis
o Composition
o Simple One Block Flow Diagram
o Product Specifications
4. Overall Block Flow Diagram
5. Individual Processes
6. Economics
o Capital Cost/Total Installation cost
o Revenues
o Expenses
7. Constraints
o Safety Risks Mitigation
o Environmental Risk Mitigation
8. Recommendations
9. Outlook
10. Q & A

3. Purpose: What is Shale Gas?
● Energy independence
● Cleaner than coal or oil.
● Lower greenhouse gas
emissions.
It is natural gas trapped within shale formations.
Importance

4. Objective
● Process raw shale gas.
● Produce compressed natural gas.
● Supply methane for Ammonia Plant, Air Separations
and Syngas Plant, the Direct Iron Reduction Plant, and
Combined Heat/Power plant.
● Produce liquefied natural gas (LNG)
● Separate natural gas liquids (NGL) for market.

5. Block Flow Diagram

6. Design Basis: Raw Gas
Composition
Bakken-Rich Gas Composition
Component Mol%
H2O(Water) 0.02
N2 (Nitrogen) 5.21
CO2 (Carbon Dioxide) 0.57
H2S (Hydrogen Sulfide) 0.01 (100ppm)
C1 (Methane) 57.67
C2 (Ethane) 19.94
C3 (Propane) 11.33
I-C4 (Isobutane) 0.97
N-C4 (N-butane) 2.83
C5+ (Pentanes) 0.91
Feed Specifications
Flow Rate 310 MMSCFD
Temperature 200 F
Pressure 800 PSIg

7. Design Basis: Product
Specifications
Treated Natural Gas
Component Mol%
H2O 0.00
N2 4.00
CO2 0.02
H2S (Hydrogen Sulfide) (6.05 PPB)
C1 (Methane) 94.5
C2 (Ethane) 0.77
C3 (Propane) 0.00
C4 (butanes) 0.00
C5+ (Pentanes) 0.00
Production Rates
Ammonia Plant 19.13 MMSCFD
Syngas Plant 42.16 MMSCFD
Midrex Plant 19.58 MMSCFD
CHP facility 50.00 MMSCFD
Pipeline 2.70 MMSCFD
NGL 57233.4 BBL/D
LNG 16335.44 BBL/D
Sulfur Cake 60 LB/HR

8. Overall Block Flow Diagram

9. Gas Receiving
Major equipment: 3 horizontal knock out tanks.
Purpose:
●To protect against liquid surges from well
head.
●To remove liquids that will condense at high
temperature and low pressure.
●Ensures gas pressure nominal for process.

10. Sour Gas Treatment
Two-Step Process for Complete SOur Gas Treatment
MDEA Treatment
-Selectional removal of H2S and CO2
-Achieves H2S content to 1 ppm in sweetened gas stream
-Most economically viable option for design basis of gas feed flow rate
LO-CAT II Sulfur Production
-Cost effective solution for Hydrogen Sulfide
-Reduces H2S to a 60 wt% cake of elemental sulfur
-Revenues of approximately $25,000/year
-Low operating costs compared to other processes
-Effective way to handle H2S
-LO-CAT catalyst solution is corrosion resistant and recycled

11. Dehydration
Lean Gas Absorption
-TEG dehydration
-Glycol is cost effective
- Achieves water content down to 10 ppmv
-Glycol can be replaced continuously
-Does not remove CO2
Adsorption
-Mole sieve dehydration
-Adsorbent like molecular sieves are expensive
-Achieves water content to as low as 0.1ppmv
-Multiple adsorption beds are required for continuous use
-Removes C02
Membrane
-Yields water content between 20-100 ppmv
-Removes CO2

12. Demethanization
Mechanical Refrigeration Plant:
- limited to -24 to -40 F
- only 60% propane
Lean oil absorption:
- 40% ethane
- 90% propane
- 100% heavier hydrocarbons
- Heating and cooling required
- High operating cost
Turboexpander:
- 60-90% ethane
- 90-98% propane
-100% of heavier hydrocarbons
● Since high percent ethane recovery is required, this is the most
economical method

13. Heavy Hydrocarbon
Stabilization
Natural gas liquids have to be stabilized to a
point that it can be stored and transported
in low-pressurized vessels.
Enhances the safety in handling, and
improving the liquid's marketability.
Stabilizing the liquid reduces the volatility.

14. Nitrogen Rejection
Cryogenic Distillation
Requires flow rates <50 MMSCFD
Best recovery rate
Highest purity product
Most benefits from economy of scale
Pressure Swing Adsorption
Second Most Commonly used NRU
Not scalable economically above 50 MMscfd
High Compression Costs at high flow rates
Sorbent must be replaced every 3-years
Membrane Separation
Applicable up to 100 MMSCFD
Most widely applied below 10 MMscfd
Because of limitations of membrane size
scalability becomes difficult at very high flow
rates
Compression costs become very high above 100
MMscfd
Lower recovery rate can affect plant economics
Must replace membranes every 3-years
At this stage of analysis cryogenic distillation has been selected for its
● high recovery and high purity of product (Nitrogen stream contains 3 wt% methane)
o Literature suggests nitrogen stream can contain as low as 0.5 wt% methane.
● Ability to liquefy natural gas for LNG production.
● Scalable to high flow rates
● Chiller supplies additional cooling to demethanizer feed
Its recommend that further analysis go into other processes constraints on nitrogen content and then re-
examine the need for such a high amount of gas upgrading.

15. LNG Production
Major equipment:
Joule-Thomson valve and flash drum.
Purpose:
●To simply and efficiently produce liquefied
natural gas for sale.

16. Plant Layout

17. Economics
Revenues
Pipeline Gas $4,400,000
NGL $224,533,762
LNG $88,300,000
Sulfur Cake $23,547
Total $317,257,309
Operating Costs
Salaries and fringes $10,500,000
Maintenance (3% of TIC) $4,332,002
Wellhead Gas $379,000,000
sorbents $525,714
MDEA $500,000
Total $394,857,716
Total Installation Cost
Total Equipment Cost $41,257,159
Total Installed Cost $144,400,056

18. Constraints
• Issues include highly pressurized vessels, high temperatures,cryogenic
temperatures, poisonous by-products.
• Pressure relief valves would be installed on all pressure vessels to
direct excess gases to the flare.
• Safety training for operators working around high or low temperature
equipment, as well as proper insulation of equipment.
• Hydrogen sulfide, which is very toxic, is immediately converted to an
inert sulfur cake.
•Hydrogen sulfide has a LD50 of 600 PPM / 30 minutes

19. Recommendations
It's recommend that this plant go forward
1.It is an essential for supplying large
quantities of gas for other processes within
the complex.
2.Offers some flexibility in products being
produced.

20. Future Outlook: NGL Stabilization Economics
Gate 2 possibility:
Separation of individual Hydrocarbons for
revenue.
Assuming 17 year life
No inflation accounted for
Additional
Capital Cost
Additional
Revenue
Additional
Operating
Cost
NPV
Fractionation $33,000,000 $195,000,000 $4,941,000 $814,000,000

21. Q & A