Methane from the Upstream Industry

1. 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

2. 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.

3. 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”

4. The Targets for Change Upstream Oil & Gas Methane Emission Sources Ref: CAPP Pub #1999-0009

5. 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

6. 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

7. Typical Heavy Oil Single Well Lease

8. 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?

9. Case Study Assessment Process Evaluate Current Site Balances in an Area Assess Location Factors vs. Surplus Energy Available and Potential Uses Conversion & Odour Options A. Case Study Tool C. Managed Options Case Study Tool Assess & Implement Energy Displacement Options Assess Managed Equipment Options: Power, EOR or Compression B. Fuel/Energy Displacement Options Tool D. Managed Options Tool

12. 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

13. 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.

14. 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

15. 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

16. 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

17. 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. Daily Casing Gas Flow Variability – Typical Circular Chart Traces

19. 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

20. 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

21. Stabilize Fuel Demand

22. 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

23. Engine Coolant for Heat Tracing Return Line to Water Pump Coolant Hoses Run Outside Shack to Heat Trace Tubing Outlet off Intake Manifold

24. Engine Coolant for Heat Tracing Tank Fuel Gas Line (not yet traced) Heat Trace Tubing Production Flow Line

25. Gas Compression Options • Rotary Vane Compressors • Beam Mounted Gas Compressors • Liquid Eductors • Multi-phase Pumps • Screw Compressors • Reciprocating Compressors

26. Reciprocating Compressors

27. Gas Collection, Sharing and Sales Net Demand Sites Truck 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

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

29. 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 Electrified Sites. Gensets to Back out energy Local Sales System 25 kV powerlines

30. 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

31. Enhanced Oil Recovery – Hot Water T=65-80C 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 Well Casing Vent Gas

32. Example – “Why Not” (WOR = 0.24)

33. Example – “What If” (WOR = 2)

34. Methane Conversion • Increase Use of Surplus Gas • Flare Stacks • Enclosed Flare Stacks • Catalytic Converters

35. 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 Air Production to Tank

36. 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.

37. 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

38. Methane Sources of a Conventional Oil & Gas Company

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

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

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

42. 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

43. 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 High Press 100 psi Compressor Gasplant • Glycol System Replaced with: • Glycol Injection • CaCl Dryers • Methanol Injection

44. 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.

45. 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

46. 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)

47. 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: bruce@newparadigm.ab.ca web: www.newparadigm.ab.ca