Methane Vent Mitigation in Upstream Oil & Gas Operations 51 st Canadian Chemical Engineering...

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: bruce@newparadigm.ab.ca

web: www.newparadigm.ab.ca