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Methane Vent Mitigation in Upstream Oil & Gas Operations 51 st Canadian Chemical Engineering Conf. October, 2001 by Bruce Peachey, P.Eng.,MCIC President, New Paradigm Engineering Ltd. Edmonton, Alberta. Methane from the Upstream Industry.

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Methane Vent Mitigation in Upstream Oil & Gas Operations51st Canadian Chemical Engineering Conf. October, 2001by Bruce Peachey, P.Eng.,MCICPresident, New Paradigm Engineering Ltd.Edmonton, Alberta

methane from the upstream industry
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
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”
the targets for change
The Targets for Change

Upstream Oil & Gas Methane Emission Sources

Ref: CAPP Pub #1999-0009

conventional heavy oil status
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
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
case study assessments
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
Case Study Assessment Process


Current Site

Balances in

an Area

Assess Location

Factors vs. Surplus


Available and

Potential Uses

Conversion &

Odour Options

A. Case Study


C. Managed

Options Case

Study Tool

Assess &

Implement Energy



Assess Managed



Power, EOR or


B. Fuel/Energy


Options Tool

D. Managed



purchased energy displacement
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 – 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
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
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
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


Indicates some gas

going to tank as

foam. Exits through tank vent


Indicates gas

building up behind

casing. Periodically

flows into well.

Daily Casing Gas Flow Variability – Typical Circular Chart Traces
foamy flow options
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
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
winterization and gas drying options
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

Coolant Hoses Run Outside Shack to Heat Trace Tubing

Outlet off Intake Manifold

engine coolant for heat tracing
Engine Coolant for Heat Tracing

Tank Fuel Gas Line (not yet traced)

Heat Trace Tubing

Production Flow Line

gas compression options
Gas Compression Options
  • Rotary Vane Compressors
  • Beam Mounted Gas Compressors
  • Liquid Eductors
  • Multi-phase Pumps
  • Screw Compressors
  • Reciprocating Compressors
gas collection sharing and sales
Gas Collection, Sharing and Sales

Net Demand Sites


To/from HP Supply/Sales

To/from County

Low Pressure

< 50 psig

Freeze protect

High Pressure

>1000 psig

<4# Water/mmscf

Local Sales System

150-200 psig

No liquid water

power generation cogeneration
Power Generation & Cogeneration
  • Thermoelectric Generation
  • Microturbines
  • Reciprocating Engine Gensets
  • Gas Turbine Gensets
  • Fuel Cells
  • Cogeneration Options for all of the above
power generation
Power Generation

Net Demand Sites

Central Power Generation

Approx 10 m3/kwh for most systems

To/from Local Grid

Low Pressure

Gas Gathering

< 50 psig

Freeze protect


Sites. Gensets to

Back out energy

Local Sales System

25 kV powerlines

enhanced oil recovery options
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
Enhanced Oil Recovery – Hot Water


1 mmbtu/hr = 1000 m3/d gas @ 70% eff

Can heat 100 m3/d of water by 100 deg C

How many m3 oil would this add to production?

T= 150-200C

P= 400-1400 kPa

Line Heater

Lease Produced

Water Storage

Surface PCP

Avoids Produced

Water Trucking to

Disposal $3+/m3

Watered out


Casing Vent Gas

methane conversion
Methane Conversion
  • Increase Use of Surplus Gas
  • Flare Stacks
  • Enclosed Flare Stacks
  • Catalytic Converters
catalytic methane conversion
Catalytic Methane Conversion
  • Add 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

CO2 + Heat

Vent Gas


Production to Tank

real life examples fuel displacement
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
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
wellhead dehydrator main ghg streams




Fuel $$$

Chemical Pumps

Instrument Vents

Glycol Regenerator

Wellhead Dehydrator Main GHG Streams
glycol regenerator options
Glycol Regenerator Options

5. Catalytic


4. Catalytic



3. Water Condenser

Fuel $ or <$

2. Upgrade

Burner Controls

(Avoid on/off)

  • Flash Tank
  • Upstream of Still

Glycol Regenerator

instrument vent options


Instrument Vents

Instrument Vent Options
  • Catalytic Heater
  • To Supplement Burner

2. Replace High Bleed


3. Add Instrument

Air Compressors

chemical pumps
Chemical Pumps

3. Catalytic Heater

To Supplement Burner

  • 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)

Chemical Pumps

strategic facilities changes
Strategic Facilities Changes
  • Retool as conditions change:
  • Original Design (1500+ psi) hydrates form at 25 deg C
  • Current condition (<200 psi) hydrates no longer a problem



100 psi



  • Glycol System Replaced with:
  • Glycol Injection
  • CaCl Dryers
  • Methanol Injection
conventional gas fugitive emissions major challenges options
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
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
  • 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 (
contact information
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