Acid Gas Removal Options for
Minimizing Methane Emissions
Lessons Learned from Natural Gas STAR

Occidental Petroleum Corporation andCalifornia Independent Petroleum AssociationProducers Technology Transfer Workshop
Long Beach, California
August 21, 2007

epa.gov/gasstar

Acid Gas Removal: Agenda
Methane Losses
Methane Recovery
Is Recovery Profitable?
Industry Experience
Discussion1

Methane Losses from Acid Gas
RemovalThere are 287 acid gas removal (AGR) units in thenatural gas industry1
Emit 634 million cubic feet (MMcf) annually1
6 thousand cubic feet per day (Mcf/day) emitted by theaverage AGR unit1Most AGR units use an amine process or SelexolTM
process
Several new processes remove acid gas with lower
methane emissions and other associated benefits
1 – Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990 - 20052

What is the Problem?
1/3 of U.S. gas reserves contain carbon dioxide (CO2) and/or
nitrogen (N2)1
Wellhead natural gas may contain acid gases
Hydrogen sulfide (H2S), CO2 are corrosive to gathering/boosting andtransmission lines, compressors, pneumatic instruments, anddistribution equipment

Acid gas removal processes have traditionally used anaqueous amine solution to absorb acid gas
Amine regeneration strips acid gas (and absorbed methane)
CO2 (with methane) is typically vented to the atmosphere, flared, or
recovered for enhanced oil recovery (EOR)
H2S is typically flared in low concentrations or sent to sulfur recovery

1 – Daiminger and Lind, Engelhard Corporation. Adsorption Processes for Natural Gas Treatment

3

Typical Amine Process

CO2 / methane toatmosphere / flare /thermal oxidizer

Sweet
Gas
Lean AmineContactor(Absorber)

Stripper DiethanolAmine(DEA)

H2S tosulfur
plant orflareCondenser

Reflux PumpReboiler

Sour Gas
Fuel/Recycle
Rich Amine

Flash Tank

HeatingMedium
Exchanger
BoosterPump
Filter4Methane Recovery - New Acid Gas
Removal Technologies
GTI & Uhde Morphysorb® Process
Kvaerner Membrane Process
Guild / Engelhard Molecular Gate® Process
Primary driver is process economics, not methane
emissions savings
Reduce methane venting by 50 to 100%5Morphysorb® Process
Compression
Clean Gas
AbsorberAcid Gas
Compression

Flash 1
Feed Gas
Flash 2
Flash 3
Flash 4
Pump6

Morphysorb® Process
Morphysorb® absorbs acid gas but also absorbs
some methane
Methane absorbed is 66% to 75% lower than competing
solvents1

Flash vessels 1 & 2 recycled to absorber inlet tominimize methane losses
Flash vessels 3 & 4 at lower pressure to remove acidgas and regenerate Morphysorb®
1 – Oil and Gas Journal, July 12, 2004, p 57
7

Is Recovery Profitable?
Morphysorb® can process streams with high (>10%) acid gas
compositionMorphysorb® has a 30% to 40% operating cost advantage
over DEA or SelexolTM 2
66% to 75% less methane absorbed than DEA or SelexolTM
About 33% less total hydrocarbons (THC) absorbed2
Lower solvent circulation volumes

At least 25% capital cost advantage from smaller contactor
and recycles2
Flash recycles 1 & 2 recover about 80% of methane that isabsorbed1
1 – Oil and Gas Journal, July 12, 2004, p 57, Fig. 7
2 – GTI8

Industry Experience - Spectra Energy
Kwoen plant does not produce pipeline-spec gas
Separates acid gas and reinjects it in reservoir
Frees gathering and processing capacity further
downstream

Morphysorb® retrofitted to a process unit designed
for other solvent
Morphysorb® chosen for acid gas selectivity overmethaneLess recycle volumes; reduced gas compressor
horsepower
9Kvaerner Membrane ProcessMembrane separation of CO2 from feed gas
Cellulose acetate spiral wound membrane

High CO2 permeate (effluent or waste stream) exiting themembrane is vented or blended into fuel gas
Low CO2 product exiting the membrane exceeds pipeline spec
and is blended with feed gas
Fuel Gas Spec
Bypass for Fuel
Aerosol
Separators

High CO2 Permeate
MEMBRANE
UNIT

Feed Gas(trace lube,glycol, etc.
removal)Bypass for Blending

Pipeline Spec

Adapted from “TrimmingResidue CO2 with MembraneTechnology”, 2005
10Kvaerner Membrane Technology
CO2 (and some methane) diffuse
axially through the membrane
High-CO2 permeate exits fromcenter of tube; enriched productexits from outer annular section
One application for fuel gas
permeate
Methane/CO2 waste stream is added with
fuel gas in a ratio to keep compressor
emissions in compliance

Design requirements
Upstream separators remove
contaminants which may foul membraneLine heater may be necessary
DCP Midstream

11Industry Experience – DCP Midstream
Kvaerner process installed at Mewborn processing
plant in Colorado, 2003
Problem: sales gas CO2 content increasing above
the 3% pipeline spec
Evaluated options
Blend with better-than-spec gas
Not enough available

Use cryogenic natural gas liquids(NGL) recovery to reject CO2
Infrastructure/capital costs too highFinal choice: membrane or amineunit
DCP Midstream

12Industry Experience - Continued
Membrane chosen for other advantages; zero emissions is added benefit
65% less capital cost than amine unit
About 10% operating cost (compared to amine)
About 10% operator man hours (compared to amine)
1/3 footprint of amine unit

Less process upsetsLess noiseLess additional infrastructure
construction

Typical process conditionsFlow Into Membrane

Membrane
Residue (Product)

Membrane
Permeate

22.3 MMcf/day

211.3

70 to 110 degrees Fahrenheit

70 to 110

70 to 110

800 to 865 psia

835

55

3% CO22%

16%

84% C189%

77%

13% C2+

9%7%~0% H2O

~ 0%~0%~0% H2S~0%~0%

13

Is Recovery Profitable?
Costs
Conventional DEA AGR would cost $4.5 to $5 million capital, $0.5
million operation and maintenance (O&M) per year
Kvaerner Membrane process cost $1.5 to $1.7 million capital, $0.02 to$0.05 million O&M per year

Optimization of permeate stream
Permeate mixed with fuel gas, $5/Mcf fuel credit
Only installed enough membranes to take feed from >3% to >2% CO2,and have an economic supplemental fuel supply for compressors

In operation since 2005
Offshore Middle East using NATCO membrane process on
gas with 90% CO2, achieving pipeline spec quality

14

Methane Recovery - Molecular Gate®
CO2 Removal
Adsorbs acid gas (CO2 and H2S) in fixed bed
Molecular sieve application selectively adsorbs acidgas molecules of smaller diameter than methane
Bed regenerated by depressuring~10% of feed methane lost in “tail gas” depressuring
Route tail gas to fuelmethane

CO2C3+adsorbed
on binder15

Molecular Gate® Applicability
Lean gasGas wells, coal bed methane

Associated gas
Tidelands Oil Production
Company
1.4 MMcf/day
18% to 40% CO2
Water saturated, rich gas

Design options for C4+ in tail gas
streamHeavy hydrocarbon recovery before
Molecular Gate®
Recover heavies from tail gas inadsorber bed
Use as fuel for process equipment

Coal bed methane System in Illinois
www.moleculargate.com

16

Molecular Gate® CO2 Removal
10 psi pressure dropOptional

ProductEnriched C190 - 95% of C1
80 - 90% of C2
50% of C3Recycle

PressureSwing
Adsorption

HighPressureFeedC1C2C3
C4+CO2
H2SH2O

Tail Gas
VacuumCompressor

C4+ Recovery
Dehydration

5- 10% of C1
10 - 20% of C2
50% of C3
C4+CO2
H2S
H2O
17

Industry Experience - Tidelands
Molecular Gate® UnitFirst commercial unit started inMay 2002
Process up to 1.4 MMcf/day
No glycol system is required
Heavy hydrocarbons and water
removed with CO2
Tail gas used for fuel is a key
optimization: no process venting
18% to 40% CO2 removed topipeline specifications (2%)
Eliminated flaring18

Molecular Gate Performance at Tidelands
Flow, MMcf/day
Pressure, psig
Temperature, F

Design Feed

Actual Feed

Design Product

Actual Product

1.065
60-80

1.4
70
60-80

0.52
63
60-80

0.54
68
60-80

71.25
400 ppm
2.18
18.82
2.35
2.12
1.75
0.76
0.72
saturated

48.35
800 ppm
1.34
37.58
2.96
3.77
3.11
1.40
1.41
saturated

95.09
700 ppm
3.74
0.19
0.90
0.20
-94.171500 ppm
2.40
1.90
0.68
0.03
-Composition, Mol %C1O2
N2
CO2C2C3C4C5C6+H2OF = Fahrenheit
psig = pounds per square inch, gauge
ppm = parts per million

19

$140,000$120,000$100,000$80,000$60,000$40,000

Oct-07
Jul-07
Apr-07
Jan-07
Oct-06
Jul-06
Apr-06
Jan-06
Oct-05Jul-05
Apr-05Jan-05
Oct-04
Jul-04
Apr-04Jan-04
Oct-03
Jul-03
Apr-03Jan-03Oct-02
Jul-02
Apr-02

$0

6.81
7.44
7.26
6.51
7.37
7.10
5.65
6.70
7.13
4.29
6.75
6.18
5.64
5.37
6.48
6.30
6.87
7.49
9.51
8.77
11.09
10.42
8.56
6.49
6.79
6.07
7.06
6.86
5.80
6.02
6.09
6.22
7.34
5.07
4.95
5.72
6.02
6.44
5.70
4.87
4.94
5.22
5.56
4.59
4.38
4.36
4.94
4.52
5.10
5.45
4.82
4.57
6.50
4.72
4.52
3.55
3.96
3.02
2.87
2.92
3.08
2.59
3.17
3.45

$20,000

20

Gas Price ($/Million British Thermal Unit)
Gas Volume
Gas Revenue

560
520
480
440
400
360
320
280
240
200
160
120
80
40
0

throughput
Mcf/day

Tidelands Gas Revenue & Associated Volume

Is Recovery Profitable?
Molecular Gate® costs are 20% less than amine
process
9 to 35 ¢ / Mcf product depending on scale

Fixed-bed tail gas vent can be used as supplemental
fuel
Eliminates venting from acid gas removal

Other Benefits
Allows wells with high acid gas content to produce(alternative is shut-in)
Can dehydrate and remove acid gas to pipeline specs inone stepLess operator attention
21

Other Molecular Gate Applications
Nitrogen removal from natural gas
Dew point control by heavy hydrocarbon and water
removalRemoval of C2 (<6%), C3+ (<3%) and C6+ (<0.2%)
for California Air Resources Board compressed
natural gas
Removal of heavy hydrocarbons from CO2 in amine
plant vents to eliminate flaring

22Comparison of AGR Alternatives
Amine (orSelexolTM)
Process

MolecularGate® CO2Morphysorb®
Process

Kvaerner
Membrane

Absorbent or
Adsorbent

Water & Amine(SelexolTM)

Titanium
Silicate

Morpholine
Derivatives

Cellulose
AcetateMethaneSavings
Compared toAmine Process--Methane in tailgas combusted
for fuel

66 to 75% lessmethaneabsorption

Methane inpermeate gas
combusted
for fuel

ReducePressure &Heat

ReducePressure to
VacuumReduce Pressure

Replace
Membrane
about 5 years

Amine(SelexolTM) &SteamElectricity

Electricity

Nil

Capital Cost

100%

<100%75%

35%

Operating Cost

100%80%60% to 70%<10%Regeneration
Primary
Operating Costs

23

Discussion
Industry experience applying these technologies andpractices
Limitations on application of these technologies anpractices
Actual costs and benefits

24