# Presentation: 917246

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

**Processors Technology Transfer Workshop**
**Gas Processors Association,**
**Devon Energy, Enogex, **
**Dynegy Midstream Services and**
**EPA’s Natural Gas STAR Program**
**April 22, 2005**

## Acid Gas Removal: Agenda

- Methane Losses
- Methane Recovery
- Is Recovery Profitable?
- Industry Experience
- Discussion Questions

## Methane Losses from Acid Gas Removal

- There are 291 acid gas removal (AGR) units in gas processing plants1
**Emit 646 MMcf annually****1**
**6 Mcf/day emitted by average AGR unit****1**
**Most AGR units use diethanol amine (DEA) process or Selexol****TM**** process**
**Several new processes have recently been introduced to the gas processing industry**

- 1Inventory of U.S. Greenhouse Gas Emissions and  Sinks 1990 - 2002

## What is the Problem?

- 1/3 of U.S. gas reserves contain CO2 and/or N21
- Wellhead natural gas may contain acid gases
**H****2****S, CO****2,**** are corrosive to gathering/boosting and transmission lines, compressors, pneumatic instruments and distribution equipment**
- Acid gas removal processes have traditionally used DEA to absorb acid gas
- DEA regeneration strips acid gas (and absorbed methane)
**CO****2**** (with methane) is typically vented to the atmosphere**
**H****2****S is typically flared or sent to sulfur recovery**

- 1www.engelhard.com/documents/GPApaper2002.pdf

## Typical Amine Process

**Filter**

**Exchanger**

**Booster Pump**

**Flash Tank**

**Sour Gas**

**Sweet Gas**

**Contractor (Absorber)**

**Rich Amine**

**Lean Amine**

**Stripper (DEA)**

**Condenser**

**H****2****S to sulfur plant or flare**

**Reflux Pump**

**Reboiler**

**Heating Medium**

**CO****2**** to atmosphere**

**Notes:**
I think this process diagram is too much for our purposes...suggest removing pumps & exchangers.

## Methane Recovery - New Acid Gas Removal Technologies

- GTI & Uhde Morphysorb® Process
- Engelhard Molecular Gate® Process
- Kvaerner Membrane Process
- Primary driver is process economics, not methane emissions savings
- Reduce methane venting by 50 to 100%

## Morphysorb®  Process

**Absorber**

**Feed Gas**

**Flash 1**

**Flash 2**

**Clean Gas**

**Flash 3**

**Flash 4**

**Acid Gas**

**Compression**

**Compression**

**Pump**

## Morphysorb® Process

- Morphysorb® absorbs acid gas but also absorbs some methane
**Methane absorbed is 66% to 75% lower than competing solvents****1**
- Flash vessels 1 & 2 recycled to absorber inlet to minimize methane losses
- Flash vessels 3 & 4 at lower pressure to remove acid gas and regenerate Morphysorb®

- 1Oil and Gas Journal, July 12, 2004, p57

## Is Recovery Profitable?

- Morphysorb® can process streams with high (>10%) acid gas composition
- 30% to 40% Morphysorb® operating cost advantage over DEA or SelexolTM 2
**66% to 75% less methane absorbed than DEA or Selexol****TM**
**About 33% less THC absorbed****2**
**Lower solvent circulation volumes**
- At least 25% capital cost advantage from smaller contactor and recycles2
- Flash recycles 1 & 2 recover ~80% of methane that is absorbed1

- 1Oil and Gas Journal, July 12, 2004, p57, Fig. 7
- 2GTI

## Industry Experience - Duke Energy

- Kwoen plant does not produce pipeline-spec gas
**Separates acid gas and reinjects it in reservoir**
**Frees gathering and processing capacity further downstream**
- Morpysorb® used in process unit designed for other solvent
- Morphysorb® chosen for acid gas selectivity over methane
**Less recycle volumes; reduced compressor horsepower**

## Methane Recovery - Molecular Gate® CO2 Removal

**Methane Recovery - Molecular Gate****®**** CO****2 ****Removal**

- Adsorbs acid gas contaminants in fixed bed
- Molecular sieve application selectively adsorbs acid gas molecules of smaller diameter than methane
- Bed regenerated by depressuring
**5% to 10% of feed methane lost in “tail gas” depressuring**
**Route tail gas to fuel **

**CH****4**

**CO****2**

**C3+ adsorbed on binder**

## Molecular Gate® Applicability

- Lean gas
**Gas wells**
**Coal bed methane**
- Associated gas
**Tidelands Oil Production Co.**
**1 MMcf/d**
**18% to 40% CO****2**
**Water saturated**
**Design options for C****4****+ in tail gas stream**
**Heavy hydrocarbon recovery before Molecular Gate****®**
**Recover heavies from tail gas in absorber bed**
**Use as fuel for process equipment**

- www.engelhard.com

## Molecular Gate® CO2 Removal

**Molecular Gate****®**** CO****2**** ****Removal**

**10 psi pressure drop**

**Product**
**95% of C****1**
**90% of C****2**
**50% of C****3**

**5 psia**

**Tail Gas**
**5% of C****1**
**10% of C****2**
**50% of C****3**
**C****4****+**
**CO****2**
**H****2****S**
**H****2****O**

**Enriched C1**** **
**30 psia**

**High Pressure Feed**
**  ****C****1**
**  ****C****2**
**  ****C****3**
**  ****C****4****+**
**  ****CO****2**
**  ****H****2****S**
**  ****H****2****O**

**Pressure Swing Adsorption**

**Vacuum**
**Compressor**

**C4+ Recovery**

**Dehydration**

## Industry Experience - Tidelands Molecular Gate® Unit

- www.engelhard.com/documents/CO2%20Removal-1.pdf

- First commercial unit started on May 2002
- Process up to 10 MMcf/d
- Separate recycle compressor is required
- No glycol  system is required
- Heavy HC removed with CO2
- Tail gas used for fuel is a key optimization: No process venting
- 18% to 40% CO2 removed to pipeline specifications (2%)

## 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 in one step**
**Less operator attention**

## Kvaerner Membrane Process

- Adapted from “Trimming Residue CO2 with Membrane Technology,” 2005

**MEMBRANE**
**UNIT**

**Aerosol Separators**

**Bypass for Fuel**

**High CO****2  ****Permeate**

**Feed Gas**

**Bypass for Blending**

**Pipeline Spec**

**Fuel Gas Spec**

**(trace lube, glycol, etc. removal)**

- Membrane separation of CO2 from feed gas
**Cellulose acetate spiral wound membrane**
- High CO2 permeate (effluent or waste stream) exiting the membrane is vented or blended into fuel gas
- Low CO2 product exiting the membrane exceeds pipeline spec and is blended with feed gas

**Notes:**
ALL Kvaerner membrane data in this presentation for 2005 comes from a paper presented at a GPA conference “Trimming Residue CO2 with Membrane Technology,” Conrad H. Smith, et. Al. Conrad also emailed us pictures from his GPA conference presentation.

## Kvaerner Membrane Technology

- CO2 (and some methane) diffuse axially through the membrane
- High-CO2 permeate exits from center of tube; enriched product exits from outer annular section
- One application for fuel gas permeate
**Methane/CO****2**** 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 membrane**
**Line heater may be necessary**

- Duke Energy Field Services

**Notes:**
The 17% CO2 permeate stream cools the gas engine combustion chamber, but blending the permeate with feed gas reduces the fuel gas CO2 content. The result is that NOX and SOX emissions from compressors are still in compliance for Duke Energy’s implementation of this technology.

## Industry Experience – Duke Energy

- 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 NGL recovery to reject CO****2**
**Infrastructure/capital costs too high**
**Final choice: membrane or amine unit**

- Duke Energy Field Services

## Industry Experience

| Flow Into Membrane | Membrane Residue (Product) | Membrane Permeate |
| --- | --- | --- |
| 22.3 MMcf/d | 21 | 1.3 |
| 70 to 110 oF | 70 to 110 | 70 to 110 |
| 800 to 865 psia | 835 | 55 |
| 3% CO2 | 2% | 16% |
| 84% C1 | 89% | 77% |
| 13% C2+ | 9% | 7% |
| ~0% H2O | ~0% | ~0% |
| ~0% H2S | ~0% | ~0% |

- Membrane chosen for other advantages; zero emissions is added benefit
**65% less capital cost than amine unit**
**<10% less operating cost**
**<10% less operator man hours**
- Typical Process conditions

**1/3 footprint of amine unit**
**Less process upsets**
**Less noise**
**Less additional infrastructure construction**

**Notes:**
All the data in the table is supplied in the membrane paper, EXCEPT the permeate C1 of 77% which is from Don’s notes during the presentation. I did a mass balance to fill in the other outlet stream C1 and C2+ mol %s.

## Is Recovery Profitable?

- Costs
**Conventional DEA AGR would cost $4.5 to $5 million capital, $0.5 million O&M**
**Kvaerner Membrane process cost $1.5 to $1.7 million capital, $0.02 to $0.05 million O&M**
- Optimization of permeate stream
**Permeate mixed with fuel gas, $5/Mcf fuel credit**
**Only installed enough membranes to take feed from >3% to >2% CO****2****, and have an economic supplemental fuel supply for compressors**
- In operation for 1 year
- Offshore Middle East using NATCO membrane process on gas with 90% CO2, achieving pipeline spec quality

## Comparison of AGR Alternatives

|  | Amine (or SelexolTM) Process | Morphysorb®  Process | Molecular Gate® CO2 | Kvaerner Membrane |
| --- | --- | --- | --- | --- |
| Absorbent or
Adsorbent | Water & Amine
(SelexolTM) | Morpholine Derivatives | Titanium Silicate | Cellulose Acetate |
| Methane Savings | 100% | 66 to 75% | 0% | 0% or higher |
| 
Regeneration | Reduce Pressure & Heat | Reduce Pressure | Reduce Pressure to Vacuum | Replace Membrane   ~5 years |
| Primary Operating Costs | Amine (SelexolTM) & Steam | Electricity | Electricity | Nil |
| Capital Cost

Operating Cost | 100%

100% | 75%

60% to 70% | <100%

80% | 35%

<10% |

## Discussion Questions

- Have you studied any of these new technologies?
- How can our presentation be improved to help you find new opportunities to reduce methane emissions from AGR units?
- What are the barriers (technological, economic, lack of information, regulatory, focus, manpower, etc.) that are preventing you from** **implementing either of these technologies?