Methane Vent Mitigation in Upstream Oil & Gas Operations

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Canadian Chemical Engineering Conf. October, 2001 by Bruce Peachey, P.Eng.,MCIC President, New Paradigm Engineering Ltd.

Edmonton, 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”

The Targets for Change Upstream Oil & Gas Methane Emission Sources Other 1% Gas Processing 6% Heavy Oil Production 29% Conventional Oil Production 8% Product Transmission 16% Accidents and Equipment Failures 5%

Ref: CAPP Pub #1999-0009

Gas Production 35%

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 Displacement Options B. Fuel/Energy Displacement Options Tool Assess Location Factors vs. Surplus Energy Available and Potential Uses C. Managed Options Case Study Tool Conversion & Odour Options Assess Managed Equipment Options: Power, EOR or Compression D. Managed Options Tool

Vent & Purchased Gas (Excluding Well #11) 1600 1400 1200 1000 800 600 400 200 0 Casing Vent (m3/d) Purchased Gas (m3/d) 1 2 3 4 5 6 7 8 Well Number 9 10 12 13 14 15

Total Lease Fuel vs. Fluid Production 1000 800 600 400 200 0 0 y = 11x + 69 10 20 30 40 Fluid Production (m3/d) 50 60

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

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 gas going to tank as foam. Exits through tank vent Theory: Indicates gas building up behind casing. Periodically flows into well.

160 140 120 100 80 60 40 20 0 Foam Volume vs. Absolute Pressure Atmospheric Pressure At Some Foam Volume the Foam Becomes Unstable and Breaks Down into Gas and Oil Foam Volume GOR=50 Foam Volume GOR=10 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 Pressure (psia)

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

Effect of Heating Cycles (0.5 MMBTU/hr burner at 50% load) 350 300 250 Gas Volume 200 (m3/d) 150 100 50 0 Full Fire Pilot Full Fire Pilot 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 Coolant Hoses Run Outside Shack to Heat Trace Tubing Outlet off Intake Manifold

Engine Coolant for Heat Tracing

Tank Fuel Gas Line (not yet traced) Heat Trace Tubing Production Flow Line

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

Net Demand Sites Truck 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

Power Generation & Cogeneration

 Thermoelectric Generation  Microturbines  Reciprocating Engine Gensets  Gas Turbine Gensets  Fuel Cells  Cogeneration Options for all of the above

Power Generation

Net Demand Sites Central Power Generation Approx 10 m3/kwh for most systems Low Pressure Gas Gathering < 50 psig Freeze protect To/from Local Grid Local Sales System 25 kV powerlines Electrified Sites. Gensets to Back out energy

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

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=65-80C T= 150-200C P= 400-1400 kPa Line Heater Watered out Well Surface PCP Lease Produced Water Storage Casing Vent Gas Avoids Produced Water Trucking to Disposal $3+/m3

Example – “Why Not” (WOR = 0.24)

$3,500,000 $3,000,000 $2,500,000 $2,000,000 $1,500,000 $1,000,000 $500,000 $ $(500,000) $(1,000,000) 1 Fuel Displacement Power Generation Gas Compression & Sales EOR - Reinjection EOR - Steam EOR - Hot Water 2 3 4 Years 5 6 7

Example – “What If” (WOR = 2)

$12,000,000 $10,000,000 $8,000,000 $6,000,000 $4,000,000 $2,000,000 $ $(2,000,000) 1 Fuel Displacement Power Generation Gas Compression & Sales EOR - Reinjection EOR - Steam EOR - Hot Water 2 3 4 Years 5 6 7

Methane Conversion

 Increase Use of Surplus Gas  Flare Stacks  Enclosed Flare Stacks  Catalytic Converters

Catalytic Methane Conversion Vent Gas CO2 + Heat

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

Air

Production to Tank workovers.

•Patents pending

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

Methane Sources of a Conventional Oil & Gas Company

Fugitives A ll Other Inco mplete Co mbustio n Glyco l Dehydratio n P umps Instrumentatio n

Wellhead Dehydrator Main GHG Streams $$ $ $ Fuel $$$ Chemical Pumps Instrument Vents Glycol Regenerator

Glycol Regenerator Options 4. Catalytic Oxidation <$ 3. Water Condenser 5. Catalytic Converter Fuel $ or <$ 1. Flash Tank Upstream of Still 2. Upgrade Burner Controls (Avoid on/off)

Instrument Vent Options 1. Catalytic Heater To Supplement Burner $ 3. Add Instrument Air Compressors Instrument Vents 2. Replace High Bleed Controls

Chemical Pumps 1. Change to Drip Pot

•

Manual Fill

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Solar Powered Day Pump Vehicle Powered Day Pump 3. Catalytic Heater To Supplement Burner $ 2. Change Pump Power

•

Electric – Solar, Thermoelectric, Line

• •

Air compressor

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 Gasplant High Press 100 psi Compressor

• • •

Glycol System Replaced with: Glycol Injection CaCl Dryers Methanol Injection

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 Services – EMF Technical Services; Holly Miller, P.Eng.; Jamieson Engineering Ltd.; SGS  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