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Methane Vent Mitigation in Methane Vent Mitigation in Upstream Oil & Gas Upstream Oil & Gas
OperationsOperations
5151stst Canadian Chemical Engineering Conf. Canadian Chemical Engineering Conf. October, 2001October, 2001
by Bruce Peachey, P.Eng.,MCICby Bruce Peachey, P.Eng.,MCICPresident, New Paradigm Engineering Ltd.President, New Paradigm Engineering Ltd.
Edmonton, AlbertaEdmonton, Alberta
Methane from the Upstream Industry Over $400-$800M/yr of methane vented or emitted as
fugitives from upstream sites (@$3-$6/GJ)• Equivalent to over 20% of Upstream O&G Industry energy use
At the same time methane is being flared or burned as fuel.
GHG emissions from heavy oil wells • Almost 50% of oil & gas GHG emissions
• Over 8% of Canada’s GHG emissions
• Over 30% of Alberta’s emissions
GHG, Flaring and Odour Issues affecting ability to develop new leases
Methane emissions have doubled since 1990 as gas production has doubled to increase exports to the U.S.
Methane a Good GHG Target
It has an economic value ($3-$6/GJ) It can provide the energy to support it’s own use or
conversion It has a greater impact as a tonne of Methane = 18-21 tCO2e Lower cost to convert than to sequester CO2
• Estimates for sequestration of CO2 usually in the US$20/tonne range
• Many methane mitigation options make money; breakeven would be <$US1.50/tCO2e just to convert methane into CO2
Many opportunities to use existing technology to reduce emissions.
• Many emissions are based on designs that were done when gas was worth C$0.30/GJ and there was no environmental drive against emitting methane.
• So there are a lot of “low hanging fruit”
Gas Processing6%
Other1%
Conventional Oil Production
8%
Product Transmission
16%
Accidents and Equipment Failures
5%
Heavy Oil Production
29%
Gas Production35%
The Targets for Change
Upstream Oil & Gas Methane Emission Sources
Ref: CAPP Pub #1999-0009
Conventional Heavy Oil Status
Over $100-$200M/yr of methane vented from heavy oil sites ($3-$6/GJ)
• Equivalent to over 5% of O&G Industry energy use
Over $40-$80M/yr of energy purchased for heavy oil sites ($4-$8/GJ)
GHG emissions from heavy oil wells• 79% of methane from oil batteries is not conserved or
flared. Mostly sweet gas from heavy oil well vents• 30% of oil & gas industry methane emissions;
• 15% of oil & gas GHG emissions
• Over 2% of Canada’s GHG emissions
Heavy Oil Vents – Major Challenges
Highly variable vent flows (years, months and hours) Vent volumes of low value per lease
• Large total volume but widely distributed over 12,000+ wells• Wells may only produce 5-7 years and only vent part of that time
Highly variable development strategies used by producers
Operations in two provinces Highly variable commodity values Options range from very simple to very complex Must be simple and low cost
Typical Heavy Oil Single Well Lease
Case Study Assessments
Initial task for producers assessing their options. What gas is venting from where and How Much? What is the overall energy balance for the operating
area? Energy purchased or supplied vs. energy in vent gas What is the individual lease balance?
• Little or no gas vented• Some gas but not large surplus – Usual condition• Significant amounts of excess gas
What are the best options?
Case Study Assessment Process
Evaluate Current Site Balances in
an Area
A. Case Study Tool
Assess & Implement Energy
DisplacementOptions
B. Fuel/Energy Displacement Options Tool
Assess LocationFactors vs. Surplus
EnergyAvailable andPotential Uses
C. Managed Options Case
Study Tool
Assess Managed EquipmentOptions:
Power, EOR orCompression
D. Managed Options
Tool
Conversion &Odour Options
Vent & Purchased Gas(Excluding Well #11)
0
200
400
600
800
1000
1200
1400
1600
1 2 3 4 5 6 7 8 9 10 12 13 14 15
Well Number
Gas
Vol
ume
(m3/
d)
Casing Vent (m3/d)
Purchased Gas (m3/d)
Total Lease Fuel vs. Fluid Production
y = 11x + 69
0
200
400
600
800
1000
0 10 20 30 40 50 60
Fluid Production (m3/d)
Lea
se F
uel U
se (m
3/d)
Purchased Energy Displacement
Key Drivers: Supply/Demand Balance, Best where supply and demand for energy are high
Pro’s:• Economic prize is known from existing energy costs• Generally supply/demand is proportional to production• Generally lowest capital cost options• Quickest payout with no little or no third party involvement
Con’s:• Must be implemented at most producing sites• Solutions need to be simple and easy to retrofit• Short well life requires high portability
Case Study – Area Fuel Displacement Summary Case Study of a group of 15 venting wells: Potential fuel cost savings of over $200k/yr ($3/GJ)
• Cost of less than $5k per site to implement for year round operation.
Payouts Ranging from 1-18 months. Best Sites – High fuel demand; Propane make-up GHG Emissions Reduction potential was 23,000
tonnes/yr CO2(eq) by displacing fuel. Over $100k/yr ($3/GJ) worth of vent gas remaining
for managed options.
Case Study – Single Well
For methanol injection – Well Prod: Oil 44m3/d; Water 3.8 m3/d; Vent GOR = 22; Other assumptions.
Total Capital = $3,013 (pipe, insulation, MeOH pump) Op cost Increment = $3,059/yr (time and chemicals) Weighted Risked Cost = $5,624/yr (some downtime) Fuel Cost Savings = $37,910/yr (@$3/GJ) Value of GHG Credits (@$0.50/t) = $2,523/yr Payout = 1.1 months Year 1 Net Cash Flow = $28,737/yr Year 2+ Net Cash Flow = $31,750/yr
Options Covered
Stabilize vent gas flows Displace purchased gas or power Distributed power generation Vent gas collection and compression for sales Enhanced oil recovery or production enhancement Conversion of uneconomic vent gas to CO2 (GHG
credits) Odour mitigation methods Some Examples
Heavy Oil – Stabilization Options
Increase Backpressure on Wells Foamy Flow Options Trapped Gas Options Insulating Lines on the Lease Dewatering Lines Engine Fuel Treatment and Make-up Gas Electric Direct Drive Options Electric/Hydraulic Drive Options
Daily Casing Gas Flow Variability – Typical Circular Chart Traces
Normal GOR Flow Foamy Flow? “Trap” Flow?
Should be expected for most wells which
have constant oil rates
Theory: Indicates some
gasgoing to tank as
foam. Exits through tank vent
Theory: Indicates gas
building up behindcasing.
Periodicallyflows into well.
Foam Volume vs. Absolute Pressure
020406080
100120140160
5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90Pressure (psia)
Vol
ume
(m3/
m3
oil)
Foam VolumeGOR=50
Foam VolumeGOR=10
Atmospheric Pressure
At Some Foam Volume the Foam BecomesUnstable and Breaks Down into Gas and Oil
Foamy Flow Options
Suck vacuum to break down foam.• Foam breakdown enhanced by lower pressures. Likely why low
annulus pressure helps production.
Add heat to well by hot water recycle down annulus Add anti-foam chemicals Decrease pumping rate
• Allow more time for foam break down
Heavy Oil – Production Heating Options Fire Tube Heaters (Base Case) Enhanced Fire-tube Controls Thermosyphon systems Catalytic Line Heaters Catalytic Tank Heaters Fired Line Heater Co-generation Heating Use of Propane as Heater Make-up Fuel
Stabilize Fuel Demand
0
50
100
150
200
250
300
350
Gas Volume (m3/d)
Full Fire Pilot Full Fire Pilot
Effect of Heating Cycles (0.5 MMBTU/hr burner at 50% load)
Burner Demand
Casing Gas Available
Average Demand
Winterization and Gas Drying Options Manipulate Conditions Winterization Heaters Electric Tracing Engine Coolant Tracing Methanol Injection: Anderson 82 sites ($1.6M/yr
saving) Glycol Injection Calcium Chloride Dryers Pressure Swing Adsorption Dryers Glycol Dehydrators
Engine Coolant for Heat Tracing
Return Line to Water Pump
Outlet off Intake Manifold
Coolant Hoses Run Outside Shack to Heat Trace Tubing
Engine Coolant for Heat Tracing
Heat Trace Tubing
Production Flow Line
Tank Fuel Gas Line (not yet traced)
Gas Compression Options
Rotary Vane Compressors Beam Mounted Gas Compressors Liquid Eductors Multi-phase Pumps Screw Compressors Reciprocating Compressors
Reciprocating Compressors
Gas Collection, Sharing and Sales
Low Pressure< 50 psig
Freeze protect
To/from County
To/from HP Supply/Sales
Local Sales System 150-200 psig
No liquid water
High Pressure>1000 psig
<4# Water/mmscf
Net Demand Sites
Truck
Power Generation & Cogeneration
Thermoelectric Generation Microturbines Reciprocating Engine Gensets Gas Turbine Gensets Fuel Cells Cogeneration Options for all of the above
Power Generation
Low PressureGas Gathering
< 50 psigFreeze protect
To/from Local Grid
Local Sales System 25 kV powerlines
Net Demand Sites
Central Power Generation
Electrified Sites. Gensets toBack out energy
Approx 10 m3/kwh for most systems
Enhanced Oil Recovery Options
Methane Reinjection Hot/Warm Water Injection Conventional Steam Injection Flue Gas Steam Generator CO2/Nitrogen Injection Gas Pressure Cycling Combinations of Methods
Enhanced Oil Recovery – Hot Water
T=65-80C
Lease ProducedWater Storage
Surface PCP
Watered out Well
Line HeaterT= 150-200CP= 400-1400 kPa
1 mmbtu/hr = 1000 m3/d gas @ 70% effCan heat 100 m3/d of water by 100 deg CHow many m3 oil would this add to production?
Casing Vent Gas Avoids ProducedWater Trucking to Disposal $3+/m3
Example – “Why Not” (WOR = 0.24)
$(1,000,000)
$(500,000)
$-
$500,000
$1,000,000
$1,500,000
$2,000,000
$2,500,000
$3,000,000
$3,500,000
1 2 3 4 5 6 7
Years
Cum
ulat
ive
Cas
h F
low
Fuel DisplacementPower GenerationGas Compression & SalesEOR - ReinjectionEOR - SteamEOR - Hot Water
Example – “What If” (WOR = 2)
$(2,000,000)
$-
$2,000,000
$4,000,000
$6,000,000
$8,000,000
$10,000,000
$12,000,000
1 2 3 4 5 6 7
Years
Cum
ulat
ive
Cas
h F
low
Fuel DisplacementPower GenerationGas Compression & SalesEOR - ReinjectionEOR - SteamEOR - Hot Water
Methane Conversion
Increase Use of Surplus Gas Flare Stacks Enclosed Flare Stacks Catalytic Converters
Catalytic Methane Conversion
Production to Tank
Air
CO2 + HeatAdd or remove modules as required:
•Units start-up and shutdown based on the amount of vent gas available.•Mounted near wellhead but out of the way of well operations and workovers.•Patents pending
Vent Gas
Real Life Examples – Fuel displacement Husky using vent gas for engines and tanks at many
leases in the summer. Tried catalytic winterization heaters, payout in one season. Now using pump drive engine heat to trace above ground lines.
Anderson Exploration reported that they used basic water separators and methanol injection on 82 wells and saved $1.6 million/yr and over 145,000 t CO2(eq)/yr in GHG emissions. Cost $3000/well & $230/mo.
Others have used small compressors, CaCl dryers, electric tracing off drive engine to increase gas pressure and winterize sites.
Conventional Oil and Gas Vents – Production Major Challenges/Options Glycol regenerator vents mostly water, also contains BTEX
• Use alternate designs and separate gas from glycol before it is heated
Instrumentation and Pumps• Utilize low pressure power gas as fuel
Conventional oil vent streams are richer• Use energy in vent stream to recover C3+ from tank vents
Odours a bigger issue• Use vent gas as fuel to mitigate odours
Variable Operations• Over time – Volumes processed reduce but equipment stays the same
• Gas Processed – Sweet gas vs. sour gas
Incomplete Combustion
Glycol Dehydration
InstrumentationP umps
Fugitives
All Other
Methane Sources of a Conventional Oil & Gas Company
Wellhead Dehydrator Main GHG Streams
Glycol Regenerator
Fuel $$$
$$
Chemical Pumps
$
Instrument Vents
$
Glycol Regenerator Options
Glycol Regenerator
Fuel $ or <$
<$
1. Flash TankUpstream of Still
3. Water Condenser
4. CatalyticOxidation
2. UpgradeBurner Controls(Avoid on/off)
5. CatalyticConverter
Instrument Vent Options
Instrument Vents
$2. Replace High Bleed Controls
3. Add Instrument Air Compressors
1. Catalytic HeaterTo Supplement Burner
Chemical Pumps
Chemical Pumps
$
3. Catalytic HeaterTo Supplement Burner1. Change to Drip Pot
• Manual Fill• Solar Powered Day Pump• Vehicle Powered Day Pump
2. Change Pump Power• Electric – Solar, Thermoelectric, Line• Air compressor• Glycol Stream (Same as Glycol Pump)
Strategic Facilities Changes
GasplantCompressor
100 psi
Glycol System Replaced with:• Glycol Injection• CaCl Dryers • Methanol Injection
High Press
Retool as conditions change:• Original Design (1500+ psi) hydrates form at 25 deg C• Current condition (<200 psi) hydrates no longer a problem
Conventional Gas Fugitive Emissions – Major Challenges/Options Low Cost Monitoring for Fugitives
• Indicator tapes, sonic generators and monitors
Fugitives new problems dealing with air/methane mixtures
• Biological, catalytic or other methods to convert low concentrations of methane in air
Collection of fugitives• Use buildings to concentrate fugitive methane
Low cost conversion of fugitives and small sources• Including monitoring for GHG credits.
Summary for Methane Vent Mitigation Vent streams can be used to generate positive
economics Were there are no opportunities to use the energy, the
methane/hydrocarbons can be converted to CO2 New Paradigm is working to develop low cost systems
to convert methane from small and fugitive sources. More work is needed to address:
• Royalty and Regulatory Issues
• Improve experience with some systems
• Try other systems.
• Transfer the Technology to Practice
Acknowledgements
Current Participants for Conventional Heavy Oil – AEC, Anderson, Husky, CNRL, Nexen, Exxon-Mobil, EnerPlus Group, CAPP, AERI
Current Participants for Thermal Heavy Oil – Nexen, Husky, CAPP
Current Participants for Conventional Oil and Gas – BP Energy, Husky, CAPP
Sub-Consultants – EMF Technical Services; Holly Miller, P.Eng.; Jamieson Engineering Ltd.; SGS Services
Support from the Petroleum Technology Alliance Canada (www.ptac.org)
Contact Information
New Paradigm Engineering Ltd.
C/o Advanced Technology Centre
9650-20 Avenue
Edmonton, Alberta
Canada T6N 1G1
tel: 780.448.9195
fax: 780.462.7297
email: [email protected]
web: www.newparadigm.ab.ca