thermal heavy oil options - new paradigm engineering ltd

Thermal Heavy Oil – Phase 1b

B.R. PeacheyFebruary 15, 2002

Thermal Heavy Oil – Phase 1bPotential Vent/Efficiency Options

One Page Options List

13. Report Summary Booklet13.1. Index13.2. Option Assessments based on Operational Objectives13.3. High Level Operation and Emission Assessment Options

13.3.1. Overall Option Assessment Process13.3.2. Overall Energy Efficiency Indicators13.3.3. Defining Operational Objectives13.3.4. Moving from Overall Assessment to Options

13.4. Reservoir and Production Options13.4.1. Reservoir Energy Distribution Control

13.4.1.1. Use of Blocking Agents13.4.1.2. Gas Blanket13.4.1.3. Quenching13.4.1.4. Steam Soak13.4.1.5. Distribution Monitoring

13.4.2. Produced Water Use Options13.4.2.1. Hot Water Flood13.4.2.2. Zonal Preheat

13.4.3. Gas Reinjection13.4.3.1. Continuous Injection for Pressure Maintenance13.4.3.2. Pressure Cycling

13.4.4. Steam Injection Options13.4.4.1. Static Insulation of Tubulars13.4.4.2. Dynamic Insulation of Tubulars

13.4.5. Minimizing Vent Streams13.4.5.1. Control of Venting13.4.5.2. Multi-Phase Pumping

13.4.6. Vent Stream Reinjection13.4.6.1. Steam Eductors13.4.6.2. Compression13.4.6.3. Multi-Phase Pumping from Satellite13.4.6.4. CO2/N2 Reinjection

13.5. Facility Options13.5.1. Casing Vent Stream Treatment

13.5.1.1. Vent Gas Cooling13.5.1.2. Dehydration13.5.1.3. Sweetening

13.5.2. Steam Generator Design and Operation Options13.5.2.1. Use of Sour Gas as Fuel13.5.2.2. Use of Produced Heavy Oil as Fuel13.5.2.3. Enhanced Burner Controls13.5.2.4. Enriched Air Combustion13.5.2.5. Decrease Stack Losses



13.5.2.6. Downhole Steam Generation on Surface13.5.3. Produced Water Reuse for Steam Generation13.5.4. Power Generation Options

13.5.4.1. Reciprocating Engine Gensets13.5.4.2. Gas Turbines13.5.4.3. Co-Generation13.5.4.4. Waste Heat Power Generation

13.5.5. Heater Treater Design and Operation Options13.5.5.1. Use of Sour Vent Gas as Fuel13.5.5.2. Stack Losses & Enhanced Burner Controls13.5.5.3. Energy Recovery Heat Exchange13.5.5.4. Diluent Assisted Treating13.5.5.5. Electrostatic Treating

13.5.6. Product Transportation Options13.5.6.1. Trucking and Fuel Options13.5.6.2. Diluted or Emulsion Pipelines13.5.6.3. Heated Pipelines

13.5.7. Fuel Switching Options13.5.8. Flares, Fugitives and Odours

13.6. Area Options13.6.1. Use of Conventional Heavy Oil Vent Gas13.6.2. Use of Alternate Produced Water Sources13.6.3. Distributed Power Generation



Thermal Heavy Oil – Phase 1bPotential Vent/Efficiency Options

13.2 Option Assessments based on Operational Objectives

Purpose of the Tool:

The charts on the following pages are intended to help users short list and prioritize options to consider based on the current operationalobjectives for their Thermal Heavy Oil Operations. Each option in the one page option list has been assessed to roughly indicate (X) whichobjectives they have potential to significantly enhance, as well as which other objective areas might be also be affected: enhanced (+) ordegraded (-). Blanks indicate that there would likely be very little effect. These assessments are very subjective and it is recommended thatthe charts be reviewed and modified if they do not seem to fit.

The reason the charts were developed is to help adjust and select options for implementation based on current corporate or operational areaobjectives which change over time based on commodity prices, economic environment, rate of expansion of operations and overallprofitability.

The Four Operational Objectives (see Option Sheet 13.3.3):

Reduce Off-site Energy Required (Op Costs) – Reduce the off-site energy needs, which willreduce the risk of the operation becoming uneconomic if energy supply costs are high.

Increase Oil Rate (Cash Flow) – Oil rate is the indicator used by most operators to assesstheir performance, usually governs when heavy oil price is high and energy supply costs arelow.

Increase Oil Recovery (Return on Investment) – Increased oil recovery is a longer-termmeasure of operating performance and is the main indicator of the efficient depletion of the oil resource. Increases the return on the capitalinvested in: exploration, drilling and completion of wells, and for surface facilities and pipelines.

Health, Safety and Environment (Reduce Risk) – Providing sustainable benefits requires that the hydrocarbon resources be depletedefficiently with the minimum of waste, while protecting workers, local residents and other organisms from any emissions that might degradetheir health or well being. Corporately dominates during period of expansion and new project approvals.

Balancing Objectives

Return on Investment

ReduceRisk

CashFlow

Op Costs

Profit

ability



Option Sheet Description (Tier1) ReduceOp Costs

IncreaseCash Flow

IncreaseReturn onInvestment

ReduceHSE Risks

Impacts• 13.3.1 Overall Option Assessment Process X X X X• 13.3.2 Overall Energy Efficiency Indicators X X X X• 13.3.3 Defining Operational Objectives X X X X• 13.3.4 Moving from Overall Assessment to Options X X X X• 13.4.1.1 Use of Blocking Agents (Tier 1-2) (-) (+) X• 13.4.1.2 Gas Blanket (Tier 2) (-) X (+)• 13.4.1.3 Quenching (Tier 1) (-) X• 13.4.1.4 Steam Soak (Tier 1) (+) (-) X• 13.4.1.5 Distribution Monitoring (Tier 1) (-) X• 13.4.2.1 Hot Water Flood (Tier 2) (+) X• 13.4.2.2 Zonal Preheat (Tier 2) (+) X• 13.4.3.1 Continuous Injection for Pressure Maintenance (Tier 1) (-) (+) X• 13.4.3.2 Pressure Cycling (Tier 2) (-) X (+)• 13.4.4.1 Static Insulation of Tubulars (Tier 1) X (+) (+)• 13.4.4.2 Dynamic Insulation of Tubulars (Tier 2) (-) X (+) (+)• 13.4.5.1 Control of Venting (Tier 1) X (+) (+) (+)• 13.4.5.2 Multi-Phase Pumping (Tier 1) X (+)• 13.4.6.1 Steam Eductors (Tier 2) X (+)• 13.4.6.2 Compression (Tier 1) (-) X (-)• 13.4.6.3 Multi-Phase Pumping from Satellite (Tier 2) X (+)• 13.4.6.4 CO2/N2 Reinjection (Tier 2) (-) (+) X (+)

1 Note Options are designated “Tier” levels based on their state of commercialization. Tier 1 – Option is commercially available and has been shown to be economic inthermal heavy oil. Tier 2 – Option appears to be technically viable and has been tested, but may not be widely available or accepted as being economic. Tier 3 –Options showing promise but requiring further commercial development to establish technical and economic viability in Canadian Thermal Heavy Oil Operations.Assessments are subjective.



Option Sheet Description (Tier) ReduceOp Costs

IncreaseCash Flow

IncreaseReturn onInvestment

ReduceHSE Risks

Impacts• 13.5.1.1 Vent Gas Cooling (Tier 1) X (-) (+)• 13.5.1.2 Dehydration (Tier 1) X (+) (-) (-)• 13.5.1.3 Sweetening (Tier 1-3) (+) X• 13.5.2.1 Use of Sour Gas as Fuel (Steam Generation) (Tier 1-2) X• 13.5.2.2 Use of Produced Heavy Oil as Fuel (Tier 1-3) X X X• 13.5.2.3 Enhanced Burner Controls (Tier 1) X X• 13.5.2.4 Enriched Air Combustion (Tier 2) X• 13.5.2.5 Decrease Stack Losses (Tier 2) X X• 13.5.2.6 Downhole Steam Generation on Surface (Tier 3) X X X (+)• 13.5.3 Produced Water Reuse for Steam Generation (Tier 1) X (-) (+)• 13.5.4.1 Reciprocating Engine Gensets (Tier 1) X (-) (+)• 13.5.4.2 Gas Turbines (Tier 1) X (-) (+)• 13.5.4.3 Co-Generation (Tier 1) X (+) X• 13.5.4.4 Waste Heat Power Generation (Tier 2-3) X (-) (+)• 13.5.5.1 Use of Sour Vent Gas as Fuel (Treaters) (Tier 1) X• 13.5.5.2 Stack Losses & Enhanced Burner Controls (Tier 1) X (+)• 13.5.5.3 Energy Recovery Heat Exchange (Tier 1) X (-)• 13.5.5.4 Diluent Assisted Treating (Tier 1) X (-)• 13.5.5.5 Electrostatic Treating (Tier 1) X (+)• 13.5.6.1 Trucking and Fuel Options (Tier 1-2) (+) X (-)• 13.5.6.2 Diluted or Emulsion Pipelines (Tier 1-2) X (+) X• 13.5.6.3 Heated Pipelines (Tier 1-2) X (+) (-)• 13.5.7 Fuel Switching Options (Tier 1) X (+)• 13.5.8 Flares, Fugitives and Odours (Tier 1) (-) X• 13.6.1 Use of Conventional Heavy Oil Vent Gas (Tier 1) X X X• 13.6.2 Use of Alternate Produced Water Sources (Tier 2) (+) (+) X• 13.6.3 Distributed Power Generation (Tier 1) X X (-) (+)

Thermal Heavy Oil Vent Gas and Energy Options Sheet

Option Sheet 13.3.1: Overall Option Assessment Process

In thermal heavy oil operations the basic process is very simple. Water from some sourceis heated, delivered to the reservoir where it can transfer energy to the oil to reduce theviscosity and increase the relative mobility of the oil. In the reservoir heating causessome gas to evolve, either bycracking of the oil or distillation, sogas, oil and water are producedback. The water and gas must findan outlet and require managementwhile the produced oil eventuallyreaches a market somewhere, andarrives there at a temperature andpressure quite similar to what it wasoriginally at in the reservoir. Alongthe way the process requires aninput of a great deal of energy in theform of fuel and power and all thisenergy is dissipated or lost to theenvironment.

Since the process is very energy intensive and uses more energy from outside sourcesthan any other type of oil or gas production, the main criteria for economic and technicalsuccess in operations is based on efficient use of the energy inputs and in obtaining theenergy from the lowest cost sources.

The overall assessment process to be used in this study is based on identifying alllocations in the entire thermal injection and production process where high quality energyis input and where it is reduced to lower quality energy, or lost from the process as lowquality heat. Once these losses have been quantified options can be considered to:

• Maintain the stream at a higher energy level longer, to increase efficiency andallow for increased energy recovery

• Make use of any energy level reductions to provide some other benefit

• Provide a benefit from low quality energy sources that are being lost from theprocess.

• Identify ways of reducing the cost and improving the efficiency of using theenergy inputs.

Pro’s:

Generic Thermal Process

HeatWater Deliver

Water toReservoir

Transfer HeatTo Oil

Produce Oil,Water & Gas

Treat & ShipOil

Dispose ofWater & Gas

Energy Input

Energy Losses

• Improving the energy efficiency of thermal operations will have a majorimpact on improving their economics.

• Thermal operations are less affected by gas, diluent, power and GHG costs ifthey are more energy efficient.

• Current projects were built based on the availability of low cost gas and powersupplies, without change it will be uneconomic to produce a low quality productlike heavy oil.

Con’s:

• More work is required to address the energy use on a thermal site than in otheroil and gas operations that have internally generated and controlled sources ofenergy.

• Projects must be planned further into the future to ensure designs and energysupply sources are flexible enough to allow on-going operation relativelyindependent of the energy commodity prices.

• Thermal operations are the lowest net return so receive the least attention frommanagement, shareholders and support staff.


Option Sheet 13.3.2: Overall Energy Efficiency Indicators

There are a number of energyefficiency indicators that have beenused in thermal heavy oil operationsto allow benchmarking of the overallenergy efficiency of the recoveryprocess and/or the facility operations.

Oil/Steam Ratio (OSR) or theinverse Steam/Oil Ratio (SOR) –OSR or SOR are the indicatorscommonly used by reservoirengineers to compare various steamrecovery operations. The ratioscompare the volume of oil produced(m3) to the volume of steam injected,in m3 of Cold Water Equivalent(CWE). To be useful as an indicatorthis assumes that the steam isgenerated at consistent conditions ofpressure, temperature and particularlysteam quality (% of the CWE that isturned into water vapour). However,this indicator excludes the electricaland oil processing energy input to theprocess, and also does not reflect theefficiency of the rest of the process.For similar types of operation, withsimilar processes, this may give areasonable indication of relative efficiency but can’t be used to compare steam processesof various types, or thermal processes, which do not use steam.

Energy Input/Energy Output Ratio – This type of calculation will provide a moreconsistent and better indication of the overall energy efficiency of an operation. In thisanalysis, the potential energy value of all energy exports from a hydrocarbon deposit(might be power, gas or oil) is compared to all the energy inputs into the process toproduce the exports including fuel gas, oil combustion, electrical power, vehicle fuel onthe lease, etc. The energy balance can be developed for a given production operation, orcould be a full cycle assessment right from the virgin reservoir condition to the final end-

Energy Inputs - Example

P u rc h a s e d G a s

8 0 %

V e n t G a s

5 %

P o w e r

1 5 %

R e se rv o i r L o sse s

1 0%

W e l lb o re H e a t

L o ss

1 5%

P o w e r

1 5%

P ro d u c e d W a te r

5 %

V e n t G a s F la re

5 %

T re a te r S ta ck a n d

A e ria l C o o l in g

5 %

G e n e ra to r S ta ck

1 5%

P a yz o n e H e a tin g

3 0%

Energy Losses – Example

user of the produced energy streams. The extent of the analysis is determined by whattypes of operation are compared, as well as what options are assessed.

GHG Emissions per Unit of Production – As most of the energy used in the upstreamoil and gas industry in western Canada comes from combustion of hydrocarbons, theGHG emissions per unit of production will be relatively proportional to energy use.However, some GHG value must be assigned to the imported energy to a site to reflectGHG emissions at the energy source, and GHG associated with energy lost intransmission.

Oil/Fuel Gas Ratio – As most thermal heavy oil operations mainly use natural gas asfuel, the ratio of oil produced to natural gas used as fuel, can provide an overall indicatorof energy efficiency of the overall process.

Pro’s:

• Energy efficiency indicators help to show improvement in the operations

• Assist in comparing thermal operations to operations in other sectors andreservoirs.

• Gives an indication of the relative risk and economics of an operation as inputenergy costs increase.

Con’s:

• Takes some effort to set up the indicator calculations and educate operationsand management on their appropriate use.

• Only work over a timeframe of years, and not as a short-term indicator, as theimpacts of a change in energy use or conservation may not show up inproduction performance for many months.


Option Sheet 13.3.3: Defining Operational Objectives

To maximize the benefits of energy reductions in any operation, and to allow relativeassessment of energy reduction options, the overall operational objectives of the businessmust first be defined, and redefined as changes in direction occur in a producerorganization. Changes in objectives lead to selection of different alternatives buteventually all will lead to increased profitability of the operation.

Reduce Off-site Energy Required (Op Costs) – Unlike most energy productionoperations (coal power, gas, light oil or mined oil sands), thermal in-situ bitumen andheavy oil operations are unique inbeing heavily dependent on externalenergy and commodity sources.Many thermal heavy oil operationsare at risk unless they can supplylarge amounts of their energy needsfrom their own corporate sources ina given province. Maximizing theuse of local, corporate energyresources is one method of reducingthe risk from wide fluctuations inreturn from thermal operations.However, a better option may be toreduce the off-site energy needs,which will reduce the risk of theoperation having to be shutdown, and free up the other corporate energy sources forexternal sale.

Increase Oil Rate (Cash Flow) – Oil rate is the indicator used by most operators toassess their performance, however, higher rates are often achieved at a high cost forsmall, or short-term incremental gains in oil rate. Some operators have recognized thatunexpected peaks in rate can result in product being dumped into the market at a neteconomic loss. The incremental cost of a unit of production might be very high if itrequires a reduction in the energy efficiency of the operation to achieve it. Increasedproduction from all heavy oil sources also tends to depress prices if there is an oversupply, as demand is limited by upgrader capacity and seasonal outlets such as asphalt forroad paving. As with external energy supplies, producers with their own corporateupgrading capacity will be less affected by low oil prices, than those that have to competeto fill remaining capacity.

Balancing Objectives

Return on Investment

ReduceRisk

CashFlow

Op Costs

Profit

ability

Increase Oil Recovery (Return on Investment) – Increased oil recovery is a longer-term measure of operating performance and is the main indicator of the efficientdepletion of the oil resource. Maximizing recovery increases the return on the capitalinvested in: exploration, drilling and completion of wells, and for surface facilities andpipelines that have little, if any, salvage value once the target heavy oil deposit is nolonger economically viable to operate.

Health, Safety and Environment (Reduce Risk) – Ultimately everything producedfrom the reservoir will become an emission, as most hydrocarbons produced will turninto carbon dioxide within days or months of leaving the site. Providing sustainablebenefits to society would require that the hydrocarbon resources be depleted efficientlywith the minimum of waste, while protecting workers, local residents and otherorganisms from any emissions that might degrade their health or well being. Generally,this will mean balancing reservoir fluid injection with production; and convertingemissions to less noxious forms; while maximizing the benefit achieved from investmentin capital and energy. While this issue is usually of paramount importance at the projectapproval stage, meeting the targets at existing operations will smooth approval of futureprojects and avoid surprises.

Pro’s:

• Provides motivation to field and design personnel working to improveoperations.

• Ensures the immediate objectives of the corporation are being satisfied at anygiven time.

• Reduces frustration at changes in direction or lack of approval of projectswhich might have been expected to be approved at a different time when otherobjectives predominate.

Con’s:

• Requires clear and timely communication from upper management when theprimary objective for an operation changes.

• Objectives may be different for different operations within a corporation socommunications must clarify and explain the reasons for this.

• Makes corporate strategies more likely to become common knowledge.


Option Sheet 13.3.4: Moving from Overall Assessment to Options

Once the information in option sheets 13.3.1-3 have been assessed then work can beginon assessing which options should be considered for implementation and to determine theeconomics associated with the implementation. As indicated previously not all optionswill be attractive at the same time or with the various corporate objectives. So for anyoperation or proposed project the assessment, and conclusions concerning what should beundertaken when, may be different. However, to some degree provision or considerationshould be given as to how all appropriate options, for all objectives, might beimplemented. The key steps in moving from the overall assessment to determining whichoptions should be studied or advanced at a given time will include the following steps:

• Given the OperationalObjectives what primary result arewe trying to achieve at this timefor this operation? For example ina time of high energy cost and lowproduct value the objective willlikely be to reduce operating costswith minimal capital expenditure.

• Which Options can helpimprove the primary objective?Reducing costs might tend tofocus on finding lower cost energysupplies (fuel and/or power) usingsurplus, low cost or leasedequipment. So options considered will focus on fuel switching and power generation.

• What waste energy sources are available that can be used in each of those options?CHO casing vent gas from other operators in the area, thermal vent gas, low valueupgrader products or other energy streams might be locally available at low cost toprovide fuel and/or power from internal or lower cost external sources.

• What options for the primary objective will also improve the indicators or improve onother objectives? Using CHO casing or thermal vents also reduce GHG emissions.

• Work the economic cases for the options that fit best. A focused effort on negotiatingsupplies of casing vent gas from other heavy oil producers in the area might benegotiated, suggesting to a power utility that the site can be converted to internal powergeneration might allow discounted power costs for interruptible demand or a loweringof power rates might be negotiated.

Overall Assessment à Options

Operational Objectives

Options that MightAdvance Objective

Assessment of Energy Source vs.

Demand Options with Synergies

Work the EconomicCases

Pro’s:

• Should allow for flexible but focused assessment of options for an operationin an environment of change.

• Helps to prioritize focus on issues of greatest importance to the on-goingviability of a particular thermal operation.

• Encourages clear definition of objectives for the organization.

• Objectives for thermal heavy oil may tend to be the opposite of those forconventional oil and gas operations. E.g. thermal operations better when gasprices and heavy/light spreads are low; conventional operations are better whenthose factors are high.

Con’s:

• Frustration if the objectives change before options are implemented.

• Staff and skills required for each objective are different and will tend to be indemand at the same time for all parts of an organization responding to the sameobjective.


Option Sheet 13.4.1.1: Use of Blocking Agents (Tier 1-2)

Blocking agents such as foams and gels are used to control water or gas distribution inconventional oil or enhanced oil recovery projects. In thermal operations most of theseagents are not able to withstand the high temperatures of the injected steam and quicklybreakdown or lose their effectiveness. The high permeability of most heavy oil reservoirscan make it very easy for the steam to move around a static plug once it is placed, sodynamic blocking or periodic injection of blocking agents is likely to be more effective.Some options for thermal operations to help redirect the injected steam or block highpermeability channels between wells, which may hinder the steam injection process, are:

Fluid Injection Staging (Tier 1) – This is any process where fluids with a rangeof properties are injected in various ways and orders into one or more wells to try andalter the distribution pattern of the hot injected fluids to increase steam contact, andsweep efficiency, in the reservoir. Blocking by injection staging is a dynamic process asit is based on the relative permeability and mobility of the fluids used, rather thanstatically blocking pore throats. Predicting the impacts, since the properties of thereservoir change with temperature and time, wouldbe difficult and it may be just trial and error to findthe methods that are most likely to enhance oilproduction and recovery.

Sulphur (Tier 2) – Some attempts1 havebeen made to use molten sulphur injection to blockhigh permeability flow channels in the reservoir,usually as a single treatment. Injection of smallvolumes of molten sulphur (sulphur melting pointis 120 degrees C) with steam on a semi-continuousbasis may act as a dynamic and static blocker andfill in high permeability channels in bottom water,as it solidifies. The molten sulphur will alsocontribute energy to the formation and oncesolidified would be an excellent insulator to reduce conduction losses to underlyingzones. Currently sulphur markets in Western Canada are extremely depressed so sulphurcan be obtained from upgraders or sour gas plants at low cost and trucked to the injectionsite. Sulphur that has solidified would tend to melt and redistribute itself if steamreturned to the same area of the reservoir.

1 This method was tried by Imperial Oil in Cold Lake, however, we are not aware of any publisheddocumentation on this trial. Others have suggested sulphur blocking as an area for further study.

Inject LiquidSulphur with Steam(120 degrees C)

Sulphur Flows Down,Solidifies & Blocks Water

Inject LiquidSulphur with Steam(120 degrees C)

Sulphur Flows Down,Solidifies & Blocks Water

Gas AWACT (Tier 2) – The AWACT process was developed through theAlberta Research Council (ARC) and was intended as a means of preventing waterconing into heavy oil producing wells. The process requires injection of high-pressuregas into the water zone of a well, with the theory being that gas will tend to distributeitself at the oil/water interface and reduce water permeability from the bottom waterzones. Nitrogen would be a preferred gas and might have synergies with a combustionair enrichment process.

Pro’s:

• Help to redirect steam into new areas of the reservoir instead of followingestablished paths and heating depleted portions.

• Reduces heat and steam losses to bottom water zones and conduction out ofthe zone.

• Varying the volumes of blocking agents as injection and production proceedcan help to provide some control.

• Most of the blocking agents suggested are readily available at relatively lowcost in most heavy oil production areas. (i.e. water, nitrogen from the air,methane, or sulphur by truck).

• Use of blocking agents can be carried out with portable equipment so theremay be no capital costs involved.

Con’s:

• Blocking is very difficult to model in heterogeneous reservoirs, so trial anderror will be required, and patience to optimize for a given operation.

• Some blocking agents may carry through or return to producing wells andcause problems in production or dilute the production.

• Familiarity with handling the blocking agents, such as sulphur is needed.

More Information:

• Various technical papers on AWACT, sulphur and injection stagingstimulation techniques.

• ARC www.arc.com , SRC, CIM, SPE and International Centre for HeavyHydrocarbons www.oildrop.org


Option Sheet: 13.4.1.2: Gas Blanket (Tier 2)

The existence or generation of a gas blanket or gas cap at the top of the reservoir is oftenseen as a negative factor as it will allow steam to short circuit between wells. However,it should also help reduce heat losses to the overburden and would help provide widerdistribution of the steam to allow fora type of steam over-ride operation.The key would be to control steaminjection and producing welloperations so that the steam inputmatches the energy that can betransferred to the reservoir, ratherthan a fixed rate or volume of steam.

This assumes that the gas will tend tobe lighter than the steam and providean insulating effect at the top of thereservoir. Continuous gas injectionwould avoid steam sweeping the gasout of the reservoir and at the sametime can provide dynamic insulationof the injection well. On productionthe gas would be produced back andcan then be recycled.

Gas injection into oil sands reservoirs where formation fracturing is required is notattractive due to the high injection pressures (up to 15 MPa or 2000 psia). However,where steam injection is possible at lower pressures, as in the Lloydminster area, thecapital costs of providing compression for gas blanketing and recycle may be attractive.Also many sites may have access to casing gas from conventional heavy oil sites whichotherwise would be vented to atmosphere.

Pro’s:

• Uses methane as an insulator to reduce energy lost out of formation.

• Can also provide insulation in injector wellbore.

• Does not add a new component to production

• Should help steam migrate to a larger portion of the reservoir with the samevolume of steam injected by acting as a carrier gas. Gas injection should belower in energy cost than a similar volume of steam.

Gas Blanket

Inject Steam atLower Rates with Some Methane

Gas Blanket

Inject Steam atLower Rates with Some Methane

Con’s:

• Requires capital for gas compression and distribution to injection sites.

• Increases the volume of gas circulating and venting from production wells.

• It will be difficult to predict performance by modeling so patience andexperience must be gained to determine the effectiveness of this technique.

More Information:

• Various technical papers on co-current injection techniques.

• ARC www.arc.com, SRC, CIM, SPE and International Centre for HeavyHydrocarbons www.oildrop.org


Options Sheet 13.4.1.3: Quenching (Tier 1)

Heat losses from the reservoir occur by conduction, which is driven by temperaturedifferentials. As relatively small temperature increases can significantly decrease theviscosity of heavy oil there should be an optimum reservoir temperature that balancesheat losses and other negative impacts of high temperature (in-situ upgrading, generationof H2S, and thermal coking), versusenergy transferred to the oil to encourageit to flow which is the desired result.These losses would tend to increase asoperations continue over time, as thesteam will have to move further throughthe reservoir to contact new cold oil.

Quenching consists of injecting steamfollowed by a hot/warm water chaser topush the steam’s energy further into thereservoir, rather than leaving it near theinjector where it will add to theconductive heat losses but not contributeto heating new oil. This result in thesame net energy input to the reservoir butshould reduce the energy losses to theover and underburden by reducing theaverage temperature of the reservoir.

If the process is used in a cyclic operation the initial production will be warm/hot water,so provision must be made for managing this water by quickly injecting it into anotherwell. This will also delay hot oil flowing to the well, as the quench water must beproduced first. On a steam-flood operation injection could be rotated between injectorsand the water would also help lift the oil into any flow channels that are higher in theformation, so it can flow to the producers.

Pro’s:

• Should lower the average reservoir temperature and reduce conductive lossesand transfer more energy to the oil-bearing portions of the reservoir.

• Provides an outlet for produced water which can provide pressuremaintenance and voidage replacement in the reservoir.

• May help oil migrate to producers by displacement.

Inject Steam followedBy hot/warm waterInjection to carry heatfurther

Con’s:

• Can result in increased water production.

• Water injected to quench should be limited to the volume required for oilvoidage replacement to minimize water recirculation and increases in waterhandling costs.

More Information:

• Various technical papers on quenching studies and projects.



Options Sheet 13.4.1.4: Steam Soak (Tier 1)

Steam soaking has been suggested as a process to give more time for energy to betransferred from the steam to the oil before the well is turned back to production in cyclicoperations. Soaking is a trade-offbetween calendar day oil rate andenergy efficiency. More soaktime should result in more of theinjected steam thermal energybeing transferred to the oil togenerate more production, for thesame energy input, but takeslonger. To increase calendar dayrates short soak times use thepressure energy of the steam torapidly move mobile oil to thewell for production, so increasethe average oil rate from a givenwell but at the cost of being moreenergy intensive.

The optimum soak time is very difficult to assess, as it will be a function of manyvariables, including:• Cost for the fuel and energy at the time the steam is injected which is generally

higher in winter.• Value of the produced oil at the time it is produced which is often higher during the

summer.• Area of oil zone exposed to the injected fluids that limits the rate of heat transfer,

which should increase over time as the heavy oil is produced.• Distance the heated oil has to flow to the producing well as the steam affected zone

grows.• Change in pressure gradients as the steam changes from vapour to liquid.• Pay zone thickness and the size of the steam filled chamber.• Volume of non-condensable gas that is in the steam zone, which is a function of gas

evolution from the oil, gas already present and gas injected.

Pro’s:

• Steam soak should be more energy efficient to reduce the energy intensity ofthe oil production.

• May be more useful in early cycles when heat transfer area to the oil is smalland in later cycles when the oil is further away from the cyclic well.

• Can be used to allow steam to be injected when fuel costs are lower andproduce the oil when prices or spreads are better.

Con’s:

• Requires more wells for the same production, as daily rate per well will belower.

• May result in larger energy losses to over and under-burden as the averagereservoir temperature during the soak period will be higher, although some ofthe energy may be recovered later in the cycle.

• Requires development of dynamic reservoir management tools to optimizesteam injection and production timing.

More Information:

• Various technical papers on steam soak.



Options Sheet 13.4.1.5: Distribution Monitoring (Tier 1)

New technologies have now been demonstrated that can help to determine which parts ofthe reservoir have been affected by steam. This provides the key information required todevelop and monitor new injection strategies to improve performance and preferentiallydirect heat energy to untouched areas of the reservoir. Without this type of monitoring itwill be difficult to troubleshoot problems with reservoir performance and it will also beextremely difficult to predict potential impacts ofchanges in the operating strategies discussed in otheroption sheets.

The two main methods are:

Comparative Seismic – This method has beenutilized by Imperial Oil at Cold Lake, where the oilsands deposits are very large, and homogeneous, overlarge areas. The technique compares seismic resultsfrom steamed and un-steamed areas of the reservoir todetermine where steam has penetrated. This is mostuseful in these large deposits and for areas whereseismic of the virgin reservoir is not available.

4D Seismic – A series of seismic surveys takenwith consistent methods and along the same survey linescan be used to determine where steam has accessed thedeposit over time and, similar to comparative seismic,help direct future steam operations. This method is better for new projects so that abaseline survey can be conducted.

Other potential sources of data are from temperature observation wells and from coringinfill wells. The main information provided by these methods will be in assessing theimpacts of changes in geologic structure on the vertical steam distribution in thereservoir, but the value is more limited and generally these options are higher cost thanseismic.

Pro’s:

• Is one of the few methods of determining what is happening in the reservoir

• Relatively inexpensive if it is planned for in advance of operations.

Virgin Reservoir w Gas CapVirgin Reservoir w Gas Cap

After X Years of SteamingAfter X Years of Steaming

• Should allow for much greater control of the operation and allow somepotential to avoid problems such as steam breakthrough between wells.

• Should increase recovery by ensuring that most areas of the reservoir willreceive some heating from the steam and avoid premature abandonment ofsteaming.

Con’s:

• Requires pre-planning of seismic work.

• Requires that seismic be repeated on an area every few years to allow timelyadjustment of operational strategies.

• More complex analysis techniques than is required for most conventionaloperations.

More Information:

• Seismic services contractors

• Reference materials from CIM, SPE and others.


Option Sheet: 13.4.2.1: Hot Water Flood (Tier 2)

Produced water can often represent a significant loss of energy from thermal or otherheavy oil process. Water requires twice the energy to heat up than oil or bitumen does,and, if there are no convenient heat sinks for the energy, it is often disposed of to aninjection zone. This energy could be utilized to heat or pre-heat the reservoir by the useof a hot water flood rather than sending the water to a disposal zone where the energywill be lost, and has no chance of contributing to production.

Hot produced water from thermal operations in Lloydminster type formations could beused in adjacent field areas for hot water flooding. Non-producing areas, no longer usedfor thermal operations, or cold flow producing areas near the thermal operations couldbenefit from injection of hot produced water to generate incremental production. In coldflow areas surplus vent gas could be used to further heat the produced water. As theviscosity of heavy oil decreases logarithmically with increasing temperature, even a smalltemperature increase should enhance production. Traditionally, there would be a concernthat water would finger, which would reduce the ability of the water to push oil toproducing wells, however, cold heavy oil cannot be pushed until it is heated and fingeringwill improve heat transfer to the oil. A recent paper on a geothermal hot water flood inIndonesia1 shows the type of studyneeded to determine the impact ofwater temperature on theperformance of a flood withtemperature sensitive oil. As in thecase of a geothermal hot watersource, a hot water flood inconjunction with a thermal heavyoil operation takes advantage of theavailability of a low cost hot watersource, so no additional energyneeds to be input. If CHO casinggas is available additional waterheating might be desirable but is nota necessary component.

Equipment costs are minimal, as the water is already hot and being pumped into adisposal zone. All that is required is an insulated line to a waterflood injector orrecompletion of the disposal well into the producing formation or target zone for heating.

1 SPE 68724, “Geothermal Hot-Water Flood – Balam South Telisa Sand, Sumatra, Indonesia” by John M.Pederson, and Jayadi H. Sitorus of PT Caltex Pacific Indonesia.

Warm/Hot Water – Tier 2

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 Disposal

Potentially produced water could be also be used as a heat transfer fluid for recoveringenergy from the steam generation and treater stacks. To avoid the acidic conditions thatcause corrosion in the stack gases as they are condensed, the produced water might beused to dilute the acid by spraying it into the waste heat recovery units. The producedwater will pick up energy from the stack gases as it cools them, it should also absorbsome of the SO2, CO2 and NOx emissions which will go into solution. The heatedproduced water stream could then be injected into the reservoir as a hot water flood orused as a heat source for an Organic Rankin Cycle power generation system., beforegoing to injection or disposal.

Pro’s:

• Hot produced water likely contains 5-10% of the energy input by the steamgenerators and is wasted in a disposal zone.

• Increased oil production possible at very low cost.

• Water will also maintain reservoir pressure through voidage replacement

• Equipment to change where the water is injected should be minimal andlimited to insulated lines or recompletion work

• If CHO casing gas is available or waste heat from generators then water canbe pressurized and heated to 150-200 degrees C with no need for softening.

Con’s:

• More water will be circulating so WOR’s will likely increase.

• Water injection locations will likely have to be changed over time.

• Effects of relative mobility are more difficult to model.

More Information:

• Papers and reservoir engineering texts cover many aspects of water floodingwhich is a mature technology. Use of low cost waste energy sources and hotwater flooding in shallow, low temperature formations is newer.



Option Sheet: 13.4.2.2: Zonal Preheat (Tier 2)

Zonal preheating would also make some use of the energy that has already been investedin producing hot water. In this case the hot water would be used to try and reduce heatlosses from the steam injection. Itwould also tend to allow steam tobecome more evenly distributed inthe producing reservoir by makingit easier for the steam to penetratethe upper and lower parts of the oil-bearing formation across the entirereservoir.

Hot produced water could beinjected into bottom water zones orany water zone above or below theoil producing formation that arepreferably only separated by thinshale barriers, so that flow in thezones is segregated, but thermalenergy transfer is supported fromthe hot water to the cold oil bearingreservoir. The heating would reduce the temperature gradient out of the producingreservoir and provide some heating to all of the area where the two zones aresuperimposed. This provides some thermal benefit without the problem of the waterhaving to be produced again on surface and re-circulated.

Pro’s:

• Produced water is not re-circulated but more energy is input or stays in thetarget producing zone.

• Provides some potential to effectively utilize the 5-10% of the waste energy inthe produced water disposal stream.

• May just require re-completion of existing disposal wells.

• Distribution of the heat in the water bearing formation(s) will tend to beaerially more uniform than heat injected into an oil rich zone.

• May be very little change in operation.

Hot WaterInjection

Con’s:

• Greater risk of communication or creating communication channels betweenzones. Will need to work with regulators as this may or may not be a problem.

• Highly dependent on the location and local stratigraphy in the reservoir.

• Zones may not be entirely segregated or isolated from each other.

• Complicates thermal modeling as fluid properties in one zone might beaffected by heat flow in another zone.

More Information:

• Some studies have been done on thermal energy transfer between producingand non-producing zones.



Option Sheet: 13.4.3.1: Continuous Injection for Pressure Maintenance (Tier 1)

Gas injection for EOR is distinguished from vent gas injection in that the gas used maynot be from the vent stream, may be focused on a smaller number of injection wells andwould be a more controlled process rather than the opportunistic vent gas reinjection.Generally gas injection for EOR is not thought to be particularly effective in cold heavyoil or bitumen wells but may be useful in thermal operations.

This type of injection would be similar to standard practices in conventional light oilreservoirs. The gas would beinjected into a high feature in thereservoir structure, such as a gascap. The gas pressure would helpto force heated oil to the producingwells, would serve as a barrier toheat transfer out of the reservoir andhelp ensure that the injected steamdoes not just fill a large volumewhere there may be no potential forincremental oil recovery. Pressurerequired would likely be quite lowand would be a function of howproducing wells near the gasinjectors are operated.

Pro’s:

• Gas injection would only be into a limited number of injection wells ratherthan every producer.

• CHO casing vent gas may be readily available for injection and as fuel forcompressors.

• Lloydminster type operations generally do not require high injectionpressures.

Con’s:

• Heavy oil must be heated before it can be moved to any great extent by gaspressure.

• Once gas breaks through to a producer it will be difficult to retain the gas inthe reservoir as many producing wells are completed over the entire oil bearing

Methane Reinjection (Tier 1)

Watered out Well

T= 150-200 o CP= 1000 - 4000 kPaMethane

1000 m3/d gas à 900 m3/d gas injection Assume 10% of gas needed for fuel

Injection Compressors(Vent Gas for Fuel)

Vent Gas

Water Reduction

zone and isolating flow in the zone with well recompletions is not likely to besuccessful.

More Information:

• Compressor suppliers.



Option Sheet: 13.4.3.2: Pressure Cycling (Tier 2)

Some have proposed pressure cycling for non-thermal heavy oil to allow the oil to berecharged with gas to support continued cold flow production. This type of process mayalso help in thermal operations,although the benefit may be a resultof providing drive energy to move oilto the producing wells rather thaninducing gas back into solution. Itwould also be necessary to have arelatively isolated area or inject thegas with the steam (Option 13.4.1.2)into the reservoir. The pressureswould have to be able built up andcare must be taken that the injectedgas is not just being vented fromadjacent producing wells.

The mechanism may be more like apneumatic pumping system orblowcase to assist oil flow andincrease calendar day oil rates, ratherthan affecting the properties of theoil.

Pro’s:

• Gas could be cycled with only the amount used as fuel actually consumed.

• Process may increase calendar day oil rates at a lower input energy cost thaninjecting more steam and avoiding soak time to do the same thing.

• Gas used would not have to be treated any more than is necessary to allow itto be compressed and injected.

• Low cost if another waste energy source (letdown of high repressure steam oreductor systems) can be used to compress the gas for injection.

• Can provided dynamic insulation if it is injected with the steam.

Con’s:

• More gas will be cycled through the process.

• May be difficult to predict performance in this type of operation.

02468

10121416

Months

1 2 3 4

Cycle Number

Gas Injection Production

• Performance will likely be a strong function of the reservoir characteristicsand may be less effective in thick pay zones.

More Information:

• SRC has been investigating pressure cycling in conventional heavy oil wells.



Option Sheet 13.4.4.1: Static Insulation of Tubulars (Tier 1)

The use of insulated tubulars or an insulating medium in the annulus between the tubingand casing has potential to reduce heat losses on production and injection. Farouq Aliand Meldau, 19831 developed a comparison of heat losses on injection based on varioustypes of insulation in the annulus as follows:

Conditions: Depth 2000 ft (615 m), Pressure 1000 psig (7 MPa), Rate 500 bblssteam/day (14 m3/d), Time 30 days, Tubing – 2-7/8”, Casing 7”

Insulation Provided Heat Losses (%) Casing Temp (oC)

No Insulation 24% 290

Gas Pack 20% 230

Vented Annulus 17% 200

Crude Oil Gel 10% 140

Solid Insulation 6% 90

The above table is based on anisolated annular space so that theinjected steam is not allowed toenter the well annular spacebetween the tubing and casing.Without an isolated annulus theheat losses may not be reduced, assteam will tend to enter theannulus and condense on thecasing, resulting in little or nochange in casing temperature andtherefore conductive heat loss.

Pro’s:

• Work well in a steam flood with dedicated injector wells

• Provide higher insulation and less heat lost than other options.

• Insulation effect can be calculated.

1 As reported by Aurel Carcoana in “Applied Enhanced Oil Recovery”, Prentice Hall 1991, page 33.

Static Insulation of TubularsModel for Static Losses

Casing Temp Varies with Insulation

Actual with Open AnnulusCasing Temp = Steam Temp

Con’s:

• Requires a packer that allows for tubing expansion on heating and contractionon cooling.

• Insulated strings are more expensive.

• Insulation used must be able to withstand high temperatures (200-350 degreesC)

More Information:

• Insulated tubing suppliers.



Option Sheet 13.4.4.2: Dynamic Insulation of Tubulars (Tier 2)

One potential method of insulating the annulus during steaming and early productionstages would be to inject the steam down the well tubing and co-currently inject naturalgas down the well annulus. The gas injection rate could be quite low, enough to ensuresteam is kept out of the annulus,and the gas would be injectedwith the steam into the reservoirand should be recovered duringthe production cycle. Since thegas is flowing downward anyenergy it acquires from the tubingwill be transferred to the reservoirand the well casing can be cooledto reduce heat losses. On theproduction cycle gas injectioncould continue down the annulusif the well is able to flowback or“flump” (flowing but with thepump going to assist the flow) ofif a multi-phase pumping systemcan be used.

It is assumed that the effect of dynamic insulation would be similar to somethingintermediate to a gas pack or vented annulus calculations in option 14.4.4.1. This mightreduce heat losses by 15-20% compared to an open annulus without dynamic insulation.

Pro’s:

• No change in downhole equipment

• Can be easily used on cyclic steam stimulation wells in steaming and earlyproduction phases.

• Gas addition may also help reduce heat losses in the reservoir and provideother benefits. See options 13.4.1.2, 13.4.3.1 and 13.4.3.2.

Con’s:

• Requires surface compression and gas lines to all wells.

• Pressure required for insulating gas is set by steam injection pressure.

More Information:

Hot WaterMethane

SteamMethane

Hot WaterMethane

SteamMethane


Option Sheet: 13.4.5.1: Control of Venting (Tier 1)

Vent streams from thermal wells may contain a significant amount of energy in the formof low-pressure steam and vented hydrocarbons (mainly methane). In some reservoirtexts, describing thermal operations, the energy content of the steam in the vent is notconsidered as it is assumed that only gas, saturated with water is produced. However,many operators believe that hard venting of the annulus, even on hot, recently steamedwells will increase production. The vent stream in this case may be anywhere from 5 to99% steam depending on the well conditions and the temperature and pressure at thecasing vent. As a result much more energy may be lost than is recognized and any short-term increase in production rate will likely be negated by long term loss of energyefficiency. The options to minimize the vent stream focus on methods of controlling thevent stream to ensure that only the non-condensable gases entering the well are beingvented. The result will be that the energy, that might have been lost with the vent gas, isretained in the produced fluids going to the plant and directionally less heat energy willhave to be added in the heater treaters.

To avoid gas locking of pumps the free gas produced with the oil must be vented fromthe casing vent, however, venting steam only reduces the energy available in the oilproduction and causes boiling to occur at some point in the well.

Steam Saturation Curve

0200400600800

100012001400160018002000

100 110 120 130 140 150 160 170 180 190 200 210

Temperature (Deg C)

Pre

ssur

e (

kPa)

Only Water Saturated Gas Vented

On the Line Unknown Volumes of SteamAre Being Vented with the Gas

Vents can be controlled by a number of methods with a wide variation in the cost toimplement.

Manual Control - Well operators can use the well annulus pressure andtemperature readings, and a water saturation curve, (see on the previous page) to ensurethat the vent stream is always below the saturation curve and will therefore only be watersaturated gas.

Pressure Control Valve – The manual process can be made more operator-friendly by installing a backpressure control valve, on each vent, that the operators canadjust as the wellhead temperature drops. This option would be much more expensiveand difficult to maintain but may be easier for the well operators to use to control the wellvent. Again the backpressure would be set so that the vent stream is always under thewater saturation curve.

Smart Control Valve - “Smart” pressure control valves can be supplied that mayhave the capability to adjust the pressure based on the measured temperature so that thevent stream is always operating at conditions where only wet gas is being vented and notsteam.

Pro’s:

• Leaves more vent energy in the liquid stream which will reduce the fueldemand for treating.

• Reduces energy and water in the vent gas stream so less capital is required forvent coolers to condense the water to allow the gas to be compressed or used asfuel.

Con’s:

• Requires that the annulus vent conditions be controlled, either through moreoperator time to make adjustments or more capital for control valves.

More Information:

• Saturated gas at atmospheric pressure can contain up to 0.7 m3 of water per1000 m3 of gas. This can be used as a target for vent gas control if water ismeasured when it is condensed and separated from the vent stream.

• Imperial Oil’s Mahkeses Vent Gas Compression condensers are designed foran average of 1.6 m3/1000 m3 of gas.


Option Sheet: 13.4.5.2: Multi-Phase Pumping (Tier 1)

Vendors have developed multi-phase or high GOR pumps for downhole applications sothat gas venting from the annulus would not berequired.1 Most of these pumps will be based onpositive displacement designs and may be operatedwith either rotating or reciprocating rod pumps.Using multi-phase pumps keeps all the vent gas incontact with the produced oil and water so it willbe much dryer by the time it is separated at theproduction battery.

Multi-phase pumping is relatively new, and thepresence of gas will reduce pump efficiency, butoverall may be more economic than dealing with aseparate vent gas stream.

Pro’s:

• Leaves all the vent energy in the liquidstream which will to reduce the fueldemand for treating.

• Avoids capital costs for vent gas lines and coolers if all the gas goesthrough the pumps.

• Pumps also add pressure to the gas to facilitate downstream uses.

• Gas separated at the plant will contain less water and will require lesstreatment.

Con’s:

• Multi-phase pumps are new so less experience is available in their design anduse.

• Pump efficiency is lower.

• Higher cost for the pumps.

More Information:

• Can-K Process & Mining Equipment Ltd – www.can-k.com in Edmonton.All metal twin screw downhole pumps.

1 Photo of twin screw pump from www.can-k.com .Photo of compressor pump from www.quinnpumps.com

• Quinn Pumps – www.quinnpumps.com in Red Deer. Compressor pumps.


Option Sheet 13.4.6.1: Steam Eductors (Tier 2)

It may be beneficial to reinject the vent gas and/or steam, back into the reservoir to helpmove the steam further into the reservoir and to minimize energy losses from thereservoir through the vent. Ideally the reinjection systems would make use of the surplussteam pressure that is provided by the steam generators, and utilize it to provide theenergy to reinject the vent gas. This type of system was considered for high-pressurecyclic operations in bitumen producing areas, but is not feasible if high steam injectionpressures are required for fracturing the reservoir as there is no steam differentialpressure to take advantage of and it is expensive to provide more complex equipment thatis only used during steam injection.

Eductors would use the pressure energy providedby the high-pressure steam to educt smallervolumes of low-pressure vent gas and steam intothe injection stream. If the steam is generated at10-17MPa and injected at 6-8 MPa there should bea considerable amount of energy available thatwould otherwise be lost through energy dissipationin choke valves. Eductors have the advantage ofsimplicity and could be set up to draw gas out of acommon vent gas header in a satellite and into asteam header for injection, with the eductormounted in the steam header in the same fashion asa flow nozzle. High pressure isolation and checkvalves would be required to prevent the steamfrom flowing into the vent header which may alsorequire a relief device if it is designed for a lowermaximum pressure than the steam header is. Thevent stream would then be commingled with theinjection steam.

Pro’s:

• Gas and steam injection is accomplished with energy which would otherwisebe wasted.

• Equipment is relatively low cost with no moving parts and can be permanentlyinstalled in a satellite for use whenever a well in the satellite is on steaminjection.

Discharge

Suction

MotiveSteam

Gas and Vent Steam

Discharge

Suction

MotiveSteam

Gas and Vent Steam

• Eductors can be manufactured for high pressures and work better with higherdensity streams (high pressure steam) as the motive force.

• Recovers steam and gas without requiring coolers or other equipment.

• Gas and energy reinjected may add to oil production through insulation,pressure maintenance and other mechanisms.

Con’s:

• Need to ensure the combined vent/steam system is protected againstoverpressure.

• Vent gas is not reinjected if there is no well on steam, so a parallel system isneeded or steaming and venting must be scheduled to increase utilization of thevents.

• Eduction calculations need to be carried out to confirm sizing, capacity rangesand costs.

More Information:

• Schutte & Koerting, Pennsylvania (215) 639-0900 www.s-k.com• Fox Valve Development Corp., New Jersey (973)-328-1011

www.foxvalve.com.

Screw Compressor

Photo courtesy Eagle Pump & Compressor Ltd.


Option Sheet 13.4.6.2: Compression (Tier 1)

A second option is to use compression units to recover and reinject the vent gas. Ideallythe vent stream would only be treated enough to allow economic compression of the gas.The compressed gas could then be either injected down the tubing with the steam or maybe used as a dynamic insulator for the tubing as described in option 13.4.4.2 and injecteddown the annulus. As well as selecting a robust compressor there are some options fordriving the compressors.

Steam Driven Compression - The surplus energy in the injection steam could also beused to drive a compressor unit to compress the vent gas, especially if the vent streamwas mainly gas. A high-pressure steam separator might be needed so that only steamvapour would be used, however, some steam engines might be able to operate on highquality steam. The major issue in using injection steam in this type of equipment is thatmost steam drivers would likely not be designed for steam at these pressures andtemperatures. If steam drive compression is not feasible to make use of the steampressure losses then other more conventional drive systems could be used.

Electric Motor or Gas Engine DrivenCompressors – Many companies offer standardpackages with electric or engine drives. Generallymotors will be lower capital cost if power isavailable but demand power which is often moreexpensive than natural gas.

Compressors - A number of types of standardcompressor systems are available: reciprocating,rotary vane, screw, liquid ring, etc. Each havetheir own strengths for use with hot, wet vent streams so selection will be dependent onthe process constraints and requirements. A detailed comparison will not be providedhere.

Reciprocating Compressors are the workhorse ofthe upstream oil and gas industry and are familiar tomost producers and operators. However, they arenot often preferred for streams with high watercontent or potential for liquids.

Screw Compressors - Oil injected rotary screwcompressors are positive displacement devices thatconsist of two rotors intermeshing to compress the

Recipro cating Compressor

Photo courtesy Eagle Pump & Compressor Ltd.

gas. The gas entering at the suction flange is conveyed to the discharge port bycontinuously diminishing spaces between the convolutions of the two rotors. The resultis gas compressed to the final pressure before it is discharged. The oil acts as a lubricantseparating the two screws and provides cooling. Generally, screw compressors areapplicable to larger volumes (>200 mscfd) but can be applied to lower flow by slowingthe unit down and recycling discharge gas to the suction of the compressor at the expenseof efficiency. Both inlet and outlet pressures need to be controlled for stable operation.Screw compressors are attractive because they are very low maintenance and simple indesign relative to other types of compressors. Seal oil must be replaced periodically andis expensive.

Pro’s:

• Compressors are conventional technology that is in widespread use andfamiliar to operations.

• Most commonly used method of dealing with vent gas.

• Steam driver option would provide a low cost energy source.

Con’s:

• Condensers and/or compression equipment would be located at each satelliteor separate pipelines for vent gas and reinjection gas would have to be providedif compressors were centrally located.

• High capital costs for high pressures.

• High operating and maintenance costs.

More Information:

• Daval Industries, Nisku; Phone: (780) 955-7547.

• Eagle Pump and Compressor Ltd, Calgary; Phone: 1-888-831-2777

• Ironhorse Compression Ltd., Edmonton; Phone: (780)462-6840


Option Sheet 13.4.6.3 – Multi-Phase Pumping from the Satellite (Tier 2)

A more flexible, capital and energy efficient system for handling the vent gas may be toinstall multi-phase pumps at each satellite to move production and vent gas togetherthrough the production line to the central battery. Most of the vent stream thermal energyand water would be transferred to the produced fluids to reduce heating for oil treatment,only one collection line is required and the gas can be centrally dried and compressed forreinjection through a dry gas distribution system, and/or other uses. By reducing theproduction back-pressure on all the producing wells in a satellite the loads on all theartificial lift systems would be directionally reduced. Surface multi-phase pumps wouldbe more cost effective and efficient than similar downhole equipment.1

Pump Drives- As with compressor systems, the surplus energy in the injection steamcould also be used to drive a multi-phase pump. A high-pressure steam separator mightbe needed so that only steam vapour would be used, however, some steam engines mightbe able to operate on high quality steam. The major issue in using injection steam in thistype of equipment is that most steam drivers would likely not be designed for steam atthese pressures and temperatures. If steam drive compression is not feasible to make useof the steam pressure losses then other more conventional drive systems could be used.

Pro’s:

• Multi-phase pumps provide a single system for gas, steam and producedfluids.

• Thermal vent energy will be transferred to the produced fluids.

• Gas separated would be dryer and easier to utilize at the battery or plant.

1 Diagram from www.lopomnitech.com

• Reduces loads on artificial lift equipment and rods which should reduce liftingcosts.

• Much more flexible system that avoids pipelining vent gas or compressors ateach satellite.

• Pumps can be modular and moved or easily changed out as volumes producedchange at a satellite.

• Steam driver option would provide a low cost energy source.

Con’s:

• Multi-phase pumps are new so less experience is available in their design anduse.

• Requires an assessment of the full cycle energy balance includingcompression, artificial lift, and production heating cooling.

• The higher the percentage of vapour in the feed stream the higher the cost forthe pump and the lower the efficiency.

More Information:

• Can-K Process & Mining Equipment Ltd – www.can-k.com in Edmonton.All metal twin screw pumps.

• LOP Omnitech www.lopomnitech.com


Option Sheet 13.4.6.4 – CO2/N2 Reinjection (Tier 2)

If the vent gas is being used for pressure maintenance then the use of an engine andcompression system to increase the volume of gas injected may be an option. Theprocess shown in the diagram is taken from an article for a unit that provides low costN2/CO2 from propane for under-balanced drilling, however, it may be applicable forusing vent gas. Vent gas is more complex due to the water and H2S associated with it,however, the volume of gas forinjection is increased from 9-10times for the same volume of inputvent gas. The major problem, ifusing sweet vent gas, will bematerials and corrosion issues in thesystem and in the downstreaminjection wells. The processcorrosion can be reduced byensuring that the oxygen is allconverted and with corrosioninhibitors. Downstream thecorrosion will be less if the streamis kept dry or, possible if it iscombined with a large volume of wet steam that can buffer the CO2/SO2 in solution.

Increased production may result especially if the CO2 is absorbed by the heavy oil andreduces it’s viscosity.

Pro’s:

• Increases volume of gas for injection without outside energy inputs.

Con’s:

• Corrosion problems and sour service issues need to be addressed.

• High capital cost for equipment and operating costs for corrosion inhibition.

• May cause corrosion and gas problems in producing wells if N2 and CO2breakthrough to producers.

• N2 and CO2 will dilute the vent gas that is produced making the heating valuemore variable.

More Information:

• Under-balanced Drilling Limited

CO2/N2 Injection (Under-Balanced Drilling Systems Limited)

CH4 + 2 O2 + 8 N2 à CO2 + 2 H2O + 8 N2Approx 1000m3 CH4 à 9000 m3 hot, dry injection gas

From Nickle’s New Technology, Dec 1998

Natural GasEngine

CatalyticConverter

Exhaust Gas Out900 deg F

N2, CO2, H2OO2

1100 deg FN2, CO2, H2O

Cooler BodyGas Exits at Ambient +15 deg F

CorrosionInhibitor

CompressorService Gas

N2, CO2

Methane

Air

Thermal Heavy Oil Vent Gas and Energy Option Sheet

Option Sheet 13.5.1.1: Vent Gas Cooling (Tier 1)

It should be advantageous, as indicated in section 13.4.5, to control the vent stream at thewellhead and to try and utilize the vent stream to assist in reservoir recovery and processseparation. Other options such as 13.4.6.3 Multi-Phase pumping allow recovery of thevent energy as well as cooling the vent steam. However, timing of steam and productioncycles may not always allow use of the vent gas at a satellite and venting with high steamcontent may be necessary. The main priority will be to treat the vent gas stream so that itcan be used as fuel in fired equipment.

The main treatment for thermal vent gas is to cool the gas so that the water content can bereduced to increase heating value and decrease potential problems with liquids in thefired equipment. Direct cooling of wet vent gas is not recommended for winteroperations as it can lead to freezing.Most sites use an intermediateglycol heat exchanger and then coolthe glycol in an aerial cooler. Thiswaste heat might find other uses,however, if the amount of steam inthe vent gas is minimized theadditional energy from the gascooling will be minimal. The ventcooling system should be kept smallto limit the amount of steamventing.1

Pro’s:

• Most commonly usedcooling method in thermaloperations.

• Capacity is significantlyhigher, than design, in winter when ambient temperatures are low.

Con’s:

• Thermal energy in the vent stream is dissipated to atmosphere.

• High capital cost to dump the energy.

More Information:

• Cooling equipment vendors and engineering contractors.

1 Photos from www.propaksystems.com


Option Sheet 13.5.1.2: Dehydration (Tier 1)

Dehydration of produced gas should not be required unless the gas is to be compressed tohigh pressures for injection or transported through pipelines, which might freeze orhydrate off. While the dehydration of the vent gases will increase the gas heating valueand make it more consistent to improve combustion in any fired equipment, thedehydration systems themselves will add considerable cost, capital, operating and energy,so there may be no net gain.2 If the gas is to be reinjected at high pressure or transporteda considerable distance away from the production site then some dehydration will berequired.

Glycol Dehydrators (Tier 1) - For any reasonable volume of wet gas a glycol dehydratorsystem will likely be preferred. Options covered in New Paradigm’s conventional oil andgas vent options study should be considered to minimize emissions and reduce energycosts for running the dehydrators and other types of dehydration system.

FIELD GUIDESIZE GAS = MMSCF/DAY @ PSI WP

235# 500# 720# 1000#

1200# 1440#

12" 8 TRAY 1 1.5 1.9 2 2.5 2.7

16" 8 TRAY 1.3 2.0 2.4 3.5 4.3 5.0

20" 8 TRAY 3.1 4.6 5.2 6.8 7.5 7.7

24" 8 TRAY 4.5 7.5 9.0 10.1 12.0 12.5

30" 8 TRAY 8.0 12.5 15.0 17.5 20.0 22.5

Pressure Swing Absorption Dryers (Tier 1) – These units use solid desiccant and areregenerated by reducing pressure and passing gas through the columns to remove thewater as low pressure gas can hold more water than high pressure gas. However, theregeneration gas must be conserved in some way, as it may constitute 5-10% of the totalgas throughput.

Calcium Chloride Dryers (Tier 1) – Are used in some low pressure, low volumeapplications, however, these units are not likely to be suitable for the sour, wet and highvolume vent gas streams normally found in thermal heavy oil operations.

Pro’s:

• Allows gas to be transported without risk of freezing or hydrate formation.

• Relatively standard process with a large number of suppliers.

2 Sizing field guide and photo from www.argosales.com

• Technology well known

Con’s:

• Capital cost that may not be necessary to allow the use of the vent gas.

• Energy required for the glycol regenerator burner

• Provision must be made to limit emissions. Gas from the regenerator willlikely have to be flared or incinerated.

More Information:

• Gas processing engineering companies and product manufacturers andsuppliers.


Option Sheet 13.5.1.3: Sweetening (Tier 1-3)

For low levels of H2S in the produced gas sweetening may not be required if the gas isused for on-site fuel. The sour produced gas volumes tend to be low compared tocommercial gas brought into the site, and also generally has a relatively low H2Sconcentration. If sweetening is required for large volumes an amine system may bepreferred, however, other options for sweetening might be considered if the volumes ofgas and H2S are low.

Amine Systems (Tier 1) - Some operators, operating combined conventional and thermalheavy oil operations, have installed a gas sweetening plant to sweeten the vent gas for useand for sales, with the acid gas being flared.

Batch Systems (Tier 1) - The main challenge with batch absorption systems is their highoperating costs (anywhere from $5-$20 per kg of H2S removed) due to the need tocontinually supply and dispose of the absorption liquids or solid absorbants.

Membranes3 (Tier 2) - have beendeveloped that may be a lower costalternative to amine, however,membranes require higher pressuresfor their operation. Potentiallymembranes could be used toseparate a sweet gas from a sourvent gas stream, with theconcentrated H2S sent to flare.

Activated Carbon Catalysis Reactor (Tier 3) - technology is under active developmentby Dr. Ajay Dalai at the University of Saskatchewan in Saskatoon. It is specificallybeing developed as a low cost method of sweetening low H2S concentration streamsusing activated carbon as the catalyst. H2S reacts in the bed and is regenerated,producing a small stream of liquid sulphur, which could be collected as a solid anddisposed of at an upgrader or sour gas plant, or used as a steam blocking agent (Seeoption 13.4.1.1). The bench-scale reactor is quite simple, the catalyst is relativelyinexpensive and only having to transport solid sulphur would be much more costeffective than handling batch absorbants. This system may be ready forcommercialization over the next 1-3 years.

Pro’s:

• Gas sweetening makes it safer and more efficient to utilize the vent gas indownstream equipment.

3 Photo from www.mtrinc.com

• May produce a stream of sulphur for use in other options.

Con’s:

• Adds to capital and operating costs as well as energy consumption.

• Amine and membrane systems generate a more concentrated H2S streamwhich may add to corrosion and safety concerns.

• Not needed for on-site use of the gas.

More Information:

• Membranes – Membrane Technology Research Inc. – www.mtrinc.comKaaeid A. Lokhandwala; VaporSep Product Manager - Refining and NaturalGas; Tel: 650-328-2228 x 140; Email: [email protected]

• Activated Carbon Catalysis Reactor – Dr. Ajay Dalai; Ph: 306-966-4771;Email: [email protected] .

• Amine Plants – Oil and Gas engineering contractors and package unitvendors.


Option Sheet 13.5.2.1: Use of Sour Gas as Fuel (Tier 1-2)

Most oilfield steam generators used in thermal operations are once through horizontaldesigns with radiant and economizer sections. The units are designed for pressures up to17 Mpa, however, in shallow conventional heavy oil operations the steam is oftengenerated at a lower pressure. As most of the energy input goes to evaporating the waterthe energy input for heating is relatively independent of pressure, even though thedischarge steam temperature may be much higher at high pressures with the same steamquality. As operating pressure drops the velocity of steam in the tubes will increase sothere is a limit on how low the steam discharge pressure can be dropped. Usuallygenerators are designed based on cold, softened fresh water feed, and using sweetcommercial spec natural gas as fuel.

Most gas vented from thermal operations in western Canada will be sour even if mostinitial solution gas produced under cold flow conditions is sweet. The H2S is producedas a result of partial cracking and upgrading of the heavy sour crude when subjected tohigh temperatures and pressures, along with the presence of steam. Feedwater forgenerators may be fresh or reused produced water, but will usually be pre-heatedupstream of the generator

Allowable Stack/Economizer Temperature – To avoid acid condensation in thegenerator economizer and stack, the flue gas must be kept above the dew point of theacids in the flue gas, which may be near 150 degrees C if sweet gas is being burned or20-150 degrees higher (sulphur trioxide dew point) if sour fuel is being burned.Increasing concentrations of sulphur in the fuel, or increasing excess combustion air,increase the allowable stack temperature. Also if the fluid entering the economizer isbelow the allowable temperature there may still be problems with cold side condensationas the downstream side of the economizer tubes will be closer to the temperature of thewater in the tubes than the stack gas temperature, so acid may still condense on the tubesand cause corrosion or sulphur formation.

Preventing Damage from Sour Gas – Existing boilersmay be modified, with input from the steam generatorvendor, to allow use of sour fuels by:

a) Increase Inlet Temperature (Tier 1) -Raising the temperature of the inlet boiler feedwater;

b) Decrease Heat Transfer Area (Tier 1) -Reducing the surface area of tubes in the economizer,either by removing tubes if the generator will mainly beburning sour gas, or by installing a 3-way valve to

bypass some tubes if the generator may be switching from sweet to sour fuel (seediagram); or

c) Chemicals (Tier 2) - at least one chemical supplier is testing a fuel additive,which is intended to suppress solid formation in the economizer so that the allowablestack temperature can be lowered.

Sour Gas in the Steam Plant – If the steam generation facilities were designed for sweetgas there may not be sufficient allowance for the use of sour gas in the steam generatorbuilding. Points to check are: a) H2S monitors in case of fuel gas leaks; b) sour specpiping and fittings on the fuel system and burners; c) isolation between sweet and soursystems.

Sulphur Dioxide Emissions – If there is no sulphur recovery or reinjection equipment inthe facility then there will likely be no change in the net amount of sulphur emitted fromthe site. However, the location of the emission and elevation and velocity of the emissionwill be different from a flare stack so plant approvals might have to be reviewed andpermits adjusted to allow for sour gas use. This should be supported as the H2S andother components of the vent gas will be more completely consumed in a generator thanin an open flare stack, so there may be a net gain in reducing emissions of other chemicalspecies.

Fuel Heating Value – The introduction of sour vent gas will have some effect on theheating value of the fuel, which may require additional adjustment of burners and air/fuelratios to allow for its use.

Pro’s:

• Allows use of sour vent gas without gas sweetening facilities.

• Reduced demand for outside gas supplies.

• Reduces flaring and undesirable flare emissions.

• SO2 emissions unchanged.

Con’s:

• Requires changes to the generator if it was not designed for sour gas.

• Most methods to allow sour fuel use reduce generator efficiency by 1-3%because of higher stack temperatures.

• Use of chemicals to retain efficiency increases operating costs.

More Information:

• “Rules of thumb for Chemical Engineers” 2 nd edition by Carl Branan, Gulfpublishing. Nomograph page 330-331 source Okkes, A.G.

• Other combustion references in the literature. Combustion consultants andsteam generator vendors.


Option Sheet 13.5.2.2: Use of Produced Heavy Oil as Fuel (Tier 1-3)

Many of the original oilfield generators used in Canada, California and other areas weredesigned to use the produced heavy oil as fuel. These generators require fuel preheatersand atomizers to feed fuel into the generator, and also, taller stacks were required for thedischarge of flue gases, due to the high levels of sulphur dioxide produced. To mitigatesome of the problems encountered with use of heavy oil there are some proven andpotential technologies, which might be of use:

Orimulsion Fuel (Tier 2) – Orimulsion fuel wasdeveloped in Venezuela as a source of steam generatorfuel for thermal development of the Orinoco Basin,which is relatively isolated from large supplies ofnatural gas. Orimulsion is basically heavy oil orbitumen (70%) emulsified with water (30%) throughthe use of chemical additives through the patentedIMULSION process. Orimulsion is used in a numberof power generation facilities as a low cost alternate tooil, coal or natural gas. The emulsion has combustionand fuel properties that are more suitable for use in asteam generator and its use may avoid some of theproblems associated with using raw produced fluids.1

Fuel Upgrading (Tier 3) – A number of studies havelooked at small scale upgrading for the viscosityreduction of the bulk produced heavy oil streamhowever, this process changes the properties of theproduction, so the value of the sales oil is often reduced. A possible alternate applicationof some of these small-scale processes might be to use them to upgrade a portion of theproduction for use as fuel. This may also allow a fuel to be produced with a lowersulphur content than the bulk product stream.

Other Options – Other fuel options are covered in Section 13.5.7 under fuel switching.

Pro’s:

• Reduces dependence on purchased fuel.

• Lowers operating costs.

• Uses a lower quality fuel. 1 Photo from www.bitor-europe.co.uk website showing New Brunswick Power site using Orimulsion.

• May be needed in the future as natural gas demand increases and supplydecreases.

Con’s:

• Sour fuel will increase emissions so may require permit revisions.

• Cost of generator modifications, burner and stack, to allow for use of heavyoil derived fuel.

• Offset reduced sales of heavy oil vs. reduced energy purchases.

• Some options require licensing of technology.

More Information:

• Imulsion Process – www.pdv.com/intevep/ingles.iml.html ; Orimulsionwww.bitor-europe.co.uk . Use in Canada New Brunswick Powerwww.nbpower.com.

• Fuel Stream Upgrading – Dr. Ajay Dalai, University of Saskatchewan Email:[email protected] or National Centre for Upgrading Technology(NCUT) Bill Dawson [email protected]


Option Sheet 13.5.2.3: Enhanced Burner Controls (Tier 1)

Depending on the age and specifications for the steam generator the burner controls maybe quite simple. The purpose of enhanced burner controls is to improve the air/fuel ratioso that excess air is optimized to minimize stack losses and maintain proper combustionconditions through any variation or shift in fuel composition. Some options might be:

Multiple Burner Systems – Generator vendors can design burner systems where there isa separate burner for each type of fuel that might be used in a steam generator. As mostdry vent gas should be fairly similar in heating value to natural gas a separate burner maynot be required, even though the control of air/fuel ratios will be different with the twofuels.

Fuel Monitoring and Combustion Control – Tomaintain optimum operation, instrumentation thatcan monitor changes in heating value of feed gasesand adjust burner and generator operatingconditions is available. A Wobbe Index Analyzer2

measures the heating value of the fuel gas and canbe included in a control loop to adjust burneroperation as the heating values change.

Pro’s:

• Improves ability to modify combustioncontrol to match fuel available.

• Automatically respond to changes infuel quality.

Con’s:

• Higher cost and maintenance.

• Benefits increase with increasing variability in fuel gas composition.

More Information:

• Burner, steam generator and combustion control vendors and consultants.

2 Photo taken from www.cosa-instrument.com shows a fast response Wobbe Index Analyzer


Option Sheet 13.5.2.4: Enriched Air Combustion (Tier 2)

Recently more work has been done to look at oxygen enriched air for combustion toincrease the CO2 concentration in the flue gas tomake it easier to recover for EOR processes orsequestration, and also to improve fired heaterefficiency as less energy will be lost to heatingnitrogen that makes up 79% of the combustion airstream. In a small operation enriched air will likelynot be a viable solution unless there is a local andeasy to access source of oxygen.

Pro’s:

• Reduces energy lost to heating nitrogenin combustion air.

• Produces a flue gas with a higherconcentration of CO2 which might berecovered for EOR.

Con’s:

• Requires high cost air separationequipment.

• Requires changes in steam generator combustion control.

• Produces a hotter flame.

• Likely can only be applied to new installations that are designed specificallyfor enriched air.

More Information:

• Suppliers of industrial gas separation systems and combustion enhancementequipment.

NitrogenNitrogen


Option Sheet 13.5.2.5: Decrease Stack Losses (Tier 2)

As much as 15-20% of the energy released by fuel combustion will be lost in the flue gasas hot nitrogen, CO2 and water vapour. A major portion of the loss is the water vapourcomponent. For any significant recovery from the flue stream the water vapour wouldhave to be condensed which will result in a very acidic stream, especially wherecondensation initially takes place. Also there must be a stream that requires heating thatis below the water dewpoint. Since boiler feedwater is normally preheated with processwaste heat a cooler stream is not often readily available.

The process illustrated in the diagram might be investigated as a means of heatingproduced water for a hot water flood (Option 13.4.2.1); to increase the temperature of awater stream for an Organic RankinCycle Power generation system(Option 13.5.4.4); ProductionHeating (Option 13.5.5.4) orProduction Rankin Cycle Cooling(Option 13.5.5.7). The largevolumes of produced water wouldbe used to directly cool the stackgases below 100 degrees C whilediluting the acids that wouldcondense out if the stack gas wascooled in an exchanger. Studywould be required to determinetrade-offs on emissions as CO2 andSO2 emissions may be reduced butsome volatile components in the produced water may be emitted.

This opportunity is available due to the large amount of energy and large volumes ofproduced water that are already being generated at a common site, and the potential foreconomic use of the hot water for oil recovery or other purposes to reduce the cost ofpurchased energy.

Pro’s:

• A large portion of the 15% of the energy normally lost with the stack gaseswould be recovered.

• Energy could be used to increase oil recovery, decrease fuel use in other partsof the process or increase the cooling available.

Warm ProducedWater In

(60 degrees C)

Hot ProducedWater Out

(100 degrees C)

Spray Contactor

Cooled Flue Gas(<100 degrees C)

Warm ProducedWater In

(60 degrees C)

Hot ProducedWater Out

(100 degrees C)

Spray Contactor

Cooled Flue Gas(<100 degrees C)

• May result in a reduction in emissions.

Con’s:

• Process is untried and requires more development.

• Requires a use for 100 deg C water.

• May allow oxygen into the water system.

More Information:

• See other options referred to above.

• Engineering consultants and suppliers of spray contactors.


Option Sheet 13.5.2.6: Downhole Steam Generation on Surface (Tier 3)

In the 1970’s considerable work was done looking at devices to generate steam at thebottom of a well, with the intended result being to avoid wellbore heat losses in deepinjectors. Not much has happened with this technology as it was normally found to betoo expensive to run theequipment down a welland maintain it, and mostheavy oil deposits areshallow enough that theenergy savings due toreduced wellbore loss waseither not as great asanticipated or too difficultto measure.

A unique extension of theconcept has beenreportedly tried in Russia3

where a downholegenerator was operated onthe surface using diesel fuel and river water to generate a steam and flue gas stream forwell stimulation.

In a thermal operation, compressed air and a fuel, such as diesel, Orimulsion orcompressed gas could be used to generate a high-pressure stream, consisting of steam andhot flue gases, which could be injected instead of steam alone. Wellbore heat loss wouldstill occur but more of the energy produced would make it into the reservoir, as well asthe carbon dioxide, nitrogen and sulphur dioxide in the flue gas, which could serve toenhance oil production through a combination of dilution and pressure maintenance. Themain problem to be overcome for long term injection, would be corrosion in the tubularsof injectors and producers.

The attraction of this process would be if untreated produced water and heavy oil couldbe used to generate the steam/flue gas mixture and injected. This would maximize theheat to the reservoir with the same amount of fuel and would also significantly reduceGHG emissions at the producing site as much of the injected CO2, SO2 and NOxgenerated in combustion might be absorbed by the water and sequestered while at the

3 Source is a Russian engineer who was involved with stimulation testing in the Soviet Union and is nowworking in Edmonton.

Downhole Steam Generator on Surface

ReciprocatingBFW Pump

Well

“Downhole” Steam Generator

T= 190 -275+CP= 1000 – 6000+ kPaN2, CO2, Steam

1 mmbtu/hr = 1000 m3/d gas @ 70% effTurns 15 m3/d of water into 80% quality steam plus 9000 m3 of N2/CO2 for Injection?

Compressed Gasor Diesel Fuel

T=65 -80C

Avoids ProducedWater Disposal

Air

Air Compressors

Vent Gas(Fuel forAir Compression)

same time increasing oil production. I.e. there may be many benefits if it can be made towork.

Pro’s:

• Almost all the energy from combustion will be injected into the well.

• CO2 and other flue gas components can also enhance oil flow in the reservoir.

• Reduced GHG emissions if combustion gases sequestered with the producedwater.

• Small direct contact steam generators may allow produced water reusewithout expensive water treatment facilities.

• Should be better in lower pressure reservoirs where there is some primaryproduction.

Con’s:

• Much of the downhole generator technology and expertise would have to beredeveloped.

• Corrosion of tubulars in injection and production wells will have to beevaluated.

• Highest cost in the process is air compression equipment.

More Information:

• Papers and literature on downhole generation equipment from various sources.

• New Paradigm Engineering Ltd is interested in following up on this concept ifthere is interest from producers. Contact Bruce Peachey, P.Eng. 780-448-9195Email [email protected] .


Option Sheet 13.5.3: Produced Water Reuse for Steam Generation

Produced water often represents a significant loss of energy from a thermal or other heavyoil process. Water requires twice the energy to heat than an equivalent volume oil orbitumen does, and if there are no convenient heat sinks for the energy it is often disposed ofwith the water to an injection zone. This energy might be better utilized to heat or pre-heatthe reservoir by the use of a hot water flood (See section 13.4.2) rather than losing it to adisposal zone where it cannot contribute to production. If the water cannot be used forflooding then consideration can be given to using it for steam generation, as is done atImperial Oil’s Cold Lake operation and other in-situ oil sands locations.

Much of the produced water in thermal operations is simply the returning steam that hasgiven up most of it’s heat to the reservoir and is being produced back. Reusing this waterreduces demand for fresh water (still require some to replace the oil voidage), reducesenergy losses as all the energy in the produced water stream is retained, and also reducesdisposal facility requirements. The produced water does not have as high a mineral contentas the in-situ connate water would normally have, which makes it easier to reuse. Waterreuse options in use around the world in thermal operations are:

• Hot Lime Softening process, used in Cold Lake, where lime and otherchemicals are added in an up-flow contactor to soften the produced water. Waterto the generators still contains dissolved hydrocarbons, sodium chloride and otherminerals. The hardness ions (Ca and Mg) are taken off with the bottom of thelime softener with the lime sludge.

• Thermosludge systems are much simpler as the softening occurs in the steamgenerator with softening chemicals injected with the water at the generator inletand separated off at the outlet; or

• Demineralization (distillation of the feed water using various types ofdesalination process technology), which is more common in Europe.

Filtration Ion ExchangeFiltration

Thermosludge

Chemicals

Filtration Ion ExchangeFiltration

Thermosludge

Chemicals

Pro’s:

• Makes use of energy content of the produced water

• Reduces fresh water required for steam generation.

• Reduces water disposal system size and energy costs for disposal

• Reduces over-pressuring of water disposal zones.

• Greater public acceptance in times of fresh water shortages.

Con’s:

• More capital, operator and chemical intensive.

• Better for large-scale operations.

• Produces lime sludge or other high mineral content streams for disposal.

• Increased risk of plant upsets and generator downtime.

More Information:

• Engineering contractors who have designed water reuse or treatment facilities

• Applications for thermal oil sands projects which incorporate water reusetechnology.

• Literature and papers on water treatment for thermal heavy oil operations.


Option Sheet 13.5.4.1: Reciprocating Engine Gensets (Tier 1)

Power generation options should only be considered if the surplus of vent gas can utilizewaste heat sources, back out more expensive purchased power, or utilize surplus casingvent gas from conventional heavy oil operations in the area. For small operations thetotal power demand will be quite low so exports of surplus power may not be feasible.Even having the capability of producing power may be an advantage as it may allow theproducer to negotiate preferred rates from the utility as an interruptible load.

Reciprocating engine gensets have wide acceptance as a means of providing reliablepower. The sizes of the more commonly available reciprocating gas engine drivengensets range from 55 kW to 3 MW. Gas consumptions of these range from around 15MCF/D to 850 MCF/D at rated power output and assuming a gas heating value ofapproximately 1000BTU/SCF or 37.7 MJ/Sm3.

Efficiencies for energy conversion toelectrical energy are in the 30% to35% range. (Through cogenerationoptions, this overall energy utilizationcan be increased by two to three fold.)These units are readily available in arange of sizes and could beconsidered when there is a pricedifferential between natural gas andpurchased electrical power. Capitalcosts for these genset units rangefrom $400/kW to $600/kW,excluding infrastructure andinstallation costs.

The main operational impact is that moving into the power generation business is new tooperators and producer management. If power sales are contemplated, partnering withthird party power generation companies to manage the power generation facilities andoperations is likely advisable. A major advantage with recip gensets is that mostoperations personnel are familiar with them and surplus, used or rental units are widelyavailable at lower cost.

Pro’s:

• Can be used when power prices are high or if there is a supply of low cost orstranded natural gas available.

Reciprocating Engine Genset

• Relatively high efficiency and no specialized maintenance required.

• Standard equipment in the industry.

• May be third parties willing to invest in power generation for sale to the gridto allow sparing of equipment.

Con’s:

• Capital and operators required for equipment.

• May cause a decrease in reliability unless the ability to draw power from thegrid is retained or spare capacity is installed.

More Information:

• Suppliers/Manufacturers: Caterpillar; Cummins; Ingersoll-Rand Canada Inc.• Potential to Out Source: A number of independent power generators are active

in the business as a result of deregulation of the electric utility industry and areinvolved in providing services:

o Canadian Hydro Developers Inc. Tel: 403-269-9379o Encore Energy Solutions L.P, Tel: 403-297-0342o Mercury Electric Corporation Tel: 403-261-8611


Option Sheet 13.5.4.2: Gas Turbines (Tier 1)

For larger thermal operations with power demands in the 500 kW to multi-megawattrange, gas turbines might be considered for power generation, especially if a low cost gassource is available and if surplus power from spare capacity can be exported to the powergrid.

Gas turbine sizes can range fromaround half a megawatt to upwardsof thirty megawatts. Installedcapital costs can be as low as$1000/MW, or lower. Operatingcosts and maintenance costs, on aunitized basis, can also be lower,because of some economies ofscale. Additional costs to install theunit may include step uptransformers, if required, utilitydisconnects, bi-directional meteringfor power exports, and other relatedequipment.

Approximately 400 MCFD (approximately 11000 m3/d) of gas with a heating value of1000 BTU/ft3 will produce approximately 1.2 MW of electric power for export onto thegrid or for local consumption. For a gas turbine, efficiencies for energy conversion toelectrical energy are in the 25% to 30% range. Through cogeneration options, this overallenergy utilization efficiency can be increased by two to three fold. Combustionefficiency ranges in excess of 99.5%, and so virtually complete incineration of thehydrocarbon input stream is achieved, to produce essentially only water vapour andcarbon dioxide. Low emissions and Nitrogen oxide (NOx) levels of less than 25 ppm arereadily achievable. Some of the manufacturers have achieved NOx levels of less than 3ppm. For the gas turbine genset, maintenance costs are lower than that for comparablysized reciprocating gas engine gensets, and can be as low as one third that of areciprocating gas engine driven genset. Whereas a reciprocating gas engine driven gensetmay cost 1.5c/kWh in maintenance costs, the gas turbine can be as low as 0.5c/kWhmaintenance costs.

Pro’s:

• Lower new power costs if a low cost supply of natural gas is available.

• Potential to attract third parties to cover capital cost and sell power to the grid.

• Ideal for co-generation

• Lower maintenance costs than for reciprocating engine gensets.

• For high power loads in remote areas may increase power reliability.

• Should produce a net reduction in GHG emissions on a system basis as poweris generated from natural gas vs. coal, and there is no loss of energy intransmission lines.

Con’s:

• Higher capital investment, with third party utilities involved.

• To be economic spare capacity with the ability to export surplus power to thegrid is needed.

More Information:

• A number of independent power generators are active in the business as aresult of deregulation of the electric utility industry and are involved inproviding services;

o Canadian Hydro Developers Inc. Tel: 403-269-9379o EMF Corporation, Tel: 403-547-8259 / 403-208-2000o Encore Energy Solutions L.P Tel: 403-297-0342

• Power utilities.


Option Sheet 13.5.4.3: Co-Generation (Tier 1)

A potential application for power generation systems is to generate power with naturalgas and use the waste heat from the power generator to provide heating for productiontreating, boiler feedwater preheating or steam generation. The best situations for co-generation are when the electricalload and heating load occur at thesame time, which is the case at anythermal heavy oil operation. Theonly incremental cost, over powergeneration alone, is for the heattransfer equipment.

Cogeneration, or CHP (CombinedHeat and Power), is defined as thegeneration of electric energy andcommercial or industrial qualityheat or steam from a single facility.The incremental installed cost of aco-generator over straightgeneration is usually the cost of the heat recovery system, which can be a Heat RecoverySteam Generator (HRSG), an Air-to-Liquid heat exchanger or an Air-to-Air HeatExchanger, depending on the host facility process heating requirements. A number ofmanufacturers have recently made available heat recovery units to be used with thevarious power generation systems. Co-generation technology is not new but waspreviously limited by regulations which restricted independent power generation. Themove to deregulation has resulted in many industrial plants to install co-generationsystems, including large thermal heavy oil and oil sands operations.

For a gas turbine, the electrical efficiency is around 30 percent. The overall cogeneratorenergy efficiency can be over 75-80 percent at normal operating conditions, dependant onhost facility process heating requirements. The best sites for cogeneration will be wherethere is a significant heat load, preferably a year round, with a high load factor.

Pro’s:

• Thermal operations need large amounts of both electrical and heat energyalmost all the time.

• There are many heating loads such as treaters, building heating, boiler waterpre-heat and steam generation that could use the heat from a power generator.

• Overall lower external energy demands

Con’s:

• Capital costs

• Power and heating are integrated which adds some complexity.

More Information:

• Examples of Potential Suppliers:o Unifin International, London, Ontario Tel: 800-349-7820o Mariah Energy Corp., Tel: 403-264-2880

• Potential to Out Source - A number of independent power generators haveemerged as a result of deregulation of the electric utility industry and areinvolved in providing services including cogeneration. See power generationoptions.


Option Sheet 13.5.4.4: Waste Heat Power Generation (Tier 2-3)

A major opportunity in thermal operations is to try and increase the efficient use of theinput energy, and one of the main losses is through low quality waste heat from steamgenerator stacks and hot produced fluids. Power generation from low quality sources isgrowing as energy costs increase and as pressure mounts to increase energy efficiencyand reduce GHG emissions. The basic principles for achieving this have been developedfor geothermal power generation and other low quality sources but is now becomingmore economic.

Organic Rankine Cycle (ORC) Power Generation (Tier 2) - These units come fromthe geothermal power industry and are designed so they can generate power fromrelatively low quality heat sources (less than100 degrees C). The cycle is similar to aconventional steam power generationsystem, however, the power fluid is anorganic medium such as isobutane. Heatsources to generate power could be theproduced water stream prior to injection,vent streams that are water vapour rich; orthe primary target source, which is the steamgenerator flue gas. Since cooling the stackgas will cause condensation of water andgenerate acids the options for the flue gas toisobutane exchange equipment would be toeither construct the exchanger and stack ofmore expensive metals to avoid corrosionand/or spray in another fluid to neutralize thecondensing acid. This is where the producedwater stream (see Option 13.5.3) might beused. A stream of the produced water sprayedinto a special economizer section of thegenerator would mix with flue gas to recoverthe energy and buffer pH from acid gascondensation. The energy would be transferredto the isobutane stream and used for generatingpower.

Stirling Engines (Tier 3) - are another heat energy driven system that has been knownfor a considerable time. They work on temperature differentials, of even lower qualitythan the ORC systems. Engines have been built that are either reciprocating or rotary.

While these have promise the units currently available are likely too expensive to beconsidered economically viable at this time. Due to higher energy costs in Europe andJapan it is likely that stirling engines will be further developed and deployed in thoseareas before they migrate to North America.

Pro’s:

• Can be used to generate power from hot stack gases or increase power frompower generators.

• Can make use of the energy content of the produced water

• ORC technology has been technically proven in geothermal operations.

• May be an opportunity for government subsidies to introduce this technologyto thermal operations.

Con’s:

• More capital required.

• Dependent on being able to generate a large hot water stream and recoveringenergy from generator stack gases.

More Information:

• ORC systems – www.barber-nichols.com/turbines.htm

• Stirling Engines – Dr. Ian Potter, Alberta Research Council, has beenassessing the technology and commercial applications. [email protected]


Option Sheet 13.5.5.1: Use of Sour Vent Gas as Fuel (Tier 1)

Many treaters in heavy oil service use fire-tubes to heat production to enhance separationof the produced oil and water. Some additional heat may be required to bring productionto the optimum separation temperature, where the density difference between the heavyoil and produced water is greatest and viscous effects of the heavy oil are minimized.Some types of treaters (evaporative) are used for difficult to treat streams and demandmore energy as they evaporate the water from the emulsion, the units are normallyequipped with heat exchangecomponents to recover energy fromthe vapourized water to preheat theinlet stream, but use of these unitsshould be minimized.1

As in the steam generators (Optionsheet 13.5.2.1) sour vent gas could beused as fuel, with the same cautions ifthe facility is not designed for sourgas to be present. Normally oilseparation facilities would already beequipped for the presence of sour gas as some produced gas will enter with the producedfluids. Therefore, depending on the relative volumes of vent gas available and treaterenergy demand it may be more cost effective to use the sour vent gas in the treatersinstead of the steam generators, provided the fuel demand is relatively constant (seeOption 13.5.5.3). This may also be an advantage as the stack temperatures for treatersare normally much higher than for steam generators, so there will be less chance ofcorrosion of the stacks from acid condensation, and the consequences of condensation inthe stacks is reduced as there is no economizer.

Use of sour gas in treater fire tubes is also easier from a control point of view as thedemand must be made relatively constant but treaters are less sensitive to fuel qualitychanges than steam generators are.

Pro’s:

• Treater fire tubes more suited to sour fuel use than steam generators.

• Less chance or impact of stack corrosion from condensation of combustionproducts.

• No major changes in controls or burners are required.

1 Photo from www.natco.ab.ca a dual polarity treater with dual firetubes.

• Most treaters are already designed based on the potential of having sour orhighly variable fuel gas.

• Treater buildings and surrounding areas should already be set up for thepresence of sour gas.

Con’s:

• Piping may be required to direct sour gas to the treaters.

• Fire-tube operation needs to be adjusted to try and ensure continuousoperation to maximize vent gas use.

More Information:

• Heater treater vendors.


Option Sheet 13.5.5.2: Stack Losses and Enhanced Burner Control (Tier 1)

Stack Losses - As the heater treaters are not equipped with economizers the stacktemperatures under full fire conditions will likely be higher than those of the steamgenerators. Heat transfer to the production is limited by the area of the firetube, sooperating at a lower firing rate for a longer time or in continuous operation shouldincrease the net heat transferred while decreasing stack losses. This operating mode alsohelps in utilizing vent gas as the demand is continuous. Depending on the situation itmay be economic to recover heat from the treater stacks, although this will likely be moredifficult as the standard flamearrested burners have limitedability to pressurize the air stream.

Enhanced Burner Controls – Asheater treaters are often requiredto handle a wide range ofproduction flows andcompositions, they usually havefired heaters sized based on amaximum load. As flame arrestedburners usually cannot be turned down below a firing rate of about 30-40%, most treaterswill have multiple fire tubes so that heating duty can be turned down in increments bycontrolling how many burners are operating. The main purpose of any enhanced controlswould be to stabilize the firing rate and ensure that there is a continuous demand for thevent gas. Many treater burners are controlled with a simple temperature switch and gofrom pilot to high fire when the temperature drops below a set value. The key objectiveis to ensure the treater or fire-tube vendor is aware that the control system will beexpected to achieve steady firing and high thermal efficiency.

Potential enhancements to stabilize operation and improve the ability to efficiently utilizevent gas are:

• Continuous firing of one burner - If there is more than one fire tube haveone burner (or more depending on the volume of vent gas available) set up toburn vent gas. Adjust the burner fuel gas pressure so that it is in continuousfiring mode and set to come on first. The other burners can be set up to just turnon when needed using sweet gas.

• Staged firing – Have more than one temperature controller to graduallyincrease the rate of firing as the vessel temperature drops to provide finer controland allow for more continuous firing.

050

100

150200250

300

350

Gas Volume (m3/d)

Full Fire Pilot Full Fire Pilot

Cycle Number

Effect of Heating Cycles (0.5 MMBTU/hr burner with at 50% load)

Burner Demand

Casing Gas Available

Average Demand

• More advanced systems – Other control systems are available to improvetreater burner management and minimize use of purchased fuel. These may benecessary if there are wide variations in flows of vent gas or production throughthe treater.

Pro’s:

• Allows sour vent gas use in the treaters to be maximized.

• Reduces stack energy losses.

• May improve temperature and flow stability in the treater.

• Relatively low cost operational or control changes will get most of the benefit.

Con’s:

• Treaters may not be able to consume all of the vent gas.

• Requires more operational time and effort to set up and adjust.

More Information:

• Heater treater and firetube burner vendors and consultants.


Option Sheet 13.5.5.3: Energy Recovery Heat Exchange (Tier 1)

It is unlikely in any thermal operation that the produced oil and water streams will bealready at a temperature that provides optimum separation in a treater. As heavy oil isvery close to the density of water and it’s viscosity is highly temperature dependent itwill likely be necessary to either heat the production or cool it at some point in thetreating process. The main purpose of energy recovery heat exchange is to minimize theamount of external energy that must be added to the system through the treater fire-tubesor that must be removed from the system through a heat sink.

Upstream Heat Exchange – In mostoperations production needs to beheated to enhance separation of the oiland water. If the inlet stream is muchcolder than the optimum separationtemperature then it will beadvantageous to pre-heat the feed withthe hotter streams leaving the treatingsystem. This just requires inlet heat exchangers to allow cross-exchange of energybetween the two streams.

Downstream Cooling – In most thermal heavy oil operations boiler feedwater will be thepreferred stream to use for cooling produced fluids to recover energy and control thetemperature of the oil stream to storage tanks, to avoid foaming and vapour emissions. Inthermal operations where fresh water is the main source for steam generation, it willlikely be similar in volume to the produced fluid and should be able to recover asignificant portion of the energy in the oil and water streams. In some cases, especially insmall pilot operations, where much of the production is not thermally produced and incases where the produced water is being reused for steam generation, there will not beenough boiler feedwater to provide adequate cooling. In these cases supplementalcooling must be provided and the usual problem is to find a heat sink which can absorbthe energy and generate some useful benefit. Some options might be:

• Glycol Cooling – Glycol could be used as an intermediate cooling streamwith the heated glycol being used to provide building heat, or tracing for freezeprotection. When the demand for providing that heating type of heating is lowthen the energy could be dissipated through aerial coolers.

• ORC Power Generation – As covered in Option 13.5.4.4 low quality wasteheat sources can be used to generate power through an Organic Rankine Cyclegenerator.

• Diluent Cooling – Sites with diluted oil pipelines for their producttransportation will have cold diluent available that could be used for cooling oil

upstream of a storage tank and then blended with the oil as it is pumped into thepipeline. This may provide some marginal reduction in pipeline pressure lossand may require lower cost heat exchange equipment than other alternatives.

• Direct Aerial Cooling – The final option is to dump the energy to atmospherethrough aerial coolers. This provides no additional benefits as the energy is lostand can cause other problems as aerial cooler capacity is usually sized toprovide adequate cooling in hot summer conditions but is over-sized the rest ofthe year which may result in freezing or plugging problems.

Pro’s:

• Heat recovery systems can help utilize low quality waste heat streams tominimize energy inputs to the operation.

• Heating and cooling is a major part of the process and streams to be heatedand cooled are often of similar volume.

Con’s:

• Challenge to optimally match waste heat sources to heat sinks whileminimizing the cost of the heat exchange equipment.

• Generally the waste heat will be of low quality.

• The only sinks will be fresh boiler feedwater and any imported dilutant.

More Information:

• Heat exchange vendors and engineering contractors.


Option Sheet 13.5.5.4: Diluent Assisted Treating (Tier 1)

For larger heavy oil operations where product is shipped by pipeline there is usually areturn diluent line to bring lighter fluids to the plant to blend with production. Often 20-30% diluent must be added to the heavy oil to allow it to flow with reasonable pressuredrop at ground temperature. However, at higher temperatures even a small amount ofdiluent added to the oil will havea significant impact on oil waterseparation by increasing thedensity difference between the oiland water, decreasing the oilviscosity so that the waterdroplets can fall-out and reduceoil surface tension so that waterdroplets in the oil phase can moreeasily coalesce.

Two phase separation is governedby the rising velocity of the fluidin the treater vs. the velocity ofwater droplets trying to separate out.

Velocity of the rising oil (Vo) is proportional to:(flow rate)/(water droplet area perpendicular to the flow)

Velocity of the falling water droplet (Vd) is proportional to:((drop radius)2 x (density difference))/(oil viscosity)

If Vd < Vo the water droplet goes out with the oil.If Vd > Vo the water droplet separates.

Adding diluent tends to increase the drop radius and density difference, while at the sametime greatly reducing the viscosity.

A key to achieving good separation and to avoid diluent flashing in the treater is to ensurethe blended stream is well mixed before it enters the treater. To avoid diluent losses fromtankage an on-line boot can be used2 so that production from the treater can go directlyinto the pipeline.

2 An on-line boot system was proposed for Imperial’s Makeses project to avoid some loss of diluent fromtank vents.

Diluent Assisted Treating

FWKO Treater

Diluent for Treating (5%)

Diluent forPipelining (25%)

If no diluent pipeline is available the process may still be viable for small operations bytrucking diluent to the site on some of the trucks returning from delivering product to apipeline terminal for blending. Another option is to have an initial charge of diluent andrecycling it through the process by distilling the diluent out before the product goes tosales, however, the energy required to recover the diluent stream in many cases may begreater than the energy to just heat the production, and more capital equipment isrequired.

Pro’s:

• Allow improved treating at a lower temperature taking advantage of a diluentstream that is already available and is going to be added anyway.

• Should increase treater throughput.

• Reduces need for downstream cooling.

• Blending in stages makes it easier to control the final blend to the pipeline.

Con’s:

• Brings a more volatile liquid into the treater area, which increases the firehazard level.

• Some diluent can be lost to the produced gas and vented from tankage.

More Information:

• Review properties of diluted heavy oil at various dilutions with treatervendors to estimate potential impacts on treater separation efficiency.


Option Sheet 13.5.5.5: Electrostatic Treating (Tier 1)

Electrostatic treating is used extensively in refineries for removing water from productstreams (desalting) and has been used successfully at Cold Lake and other bitumenoperations. These treaters use electrical fields to encourage coalescing of the waterdroplets in an emulsion stream. The two main fields used are: a) AC where the rapidalternation in charge sign on a set of grids cause the water droplets to vibrate whichreduces surface tension and allows them to moreeasily coalesce when they touch; and b) DCfields where plates of opposite charge encouragewater droplets to move back and forth betweenthem increasing the number and frequency ofdroplet collisions to encourage coalescing.Treaters with DC fields are usually calledAC/DC or Dual Polarity Treaters and have a DCfield between the grid plates and an AC fieldbetween the grid and the oil/water interface.Electrical power is applied in both cases butcurrent draw is only high during process upsets.The use of electrostatic treaters may enhanceseparation at lower temperatures so that the needfor production heating is reduced.

Pro’s:

• Proven technology in heavy oil and refinery applications

• Can consistently produce pipeline quality product emulsions are not stabilizedby solids or other contaminants in the production or recycle streams.

• Allows direct production to a pipeline.

• Lower operating energy cost than for heater treaters.

• Can be combined into a unit with fire tubes.

Con’s:

• Higher capital cost.

• Have problems with some streams.

• Benefit is incremental so some heating is still required in most cases.

More Information:

• Treater vendors such as Natco www.natco.ab.ca


Option Sheet 13.5.6.1: Trucking and Fuel Options (Tier 1-2)

The transportation method selected for transporting the oil off the thermal production sitecan have an impact on the overall energy efficiency of the operation. Pipelines oftenrequire outside fuel or energy to operate but could potentially serve as methods of gainingbenefit from the waste heat of other waste energy sources at or near the thermal site. Thebase case methods are assumed to be either trucking or diluted pipeline systems but evenin those systems there are options which may reduce energy or other costs.

Trucking of heavy oil is common practice for small thermal operations where the cost ofa pipeline system is prohibitive. Trucks load at the production site and transport the oil topipeline or upgrader truck terminals, where the product can be further treated andtransferred to a pipeline or upgrader. Heavy oil must be kept warm to facilitate loadingand transporting as is normally done using trucks similar to those used for asphalthauling. As volumes increase truck safety and the impacts of traffic on back-roads andhighways is often a concern of the local residents. The main energy expenditures are forthe fuel required to move the truck and contents whatever distance is required, loaded andunloaded. The trucking service is normally contracted so the producer does not pay theenergy costs for fuel directly, but these doimpact the rates charged for transportingthe oil.

Trucking costs might be lowered withnatural gas or dual powered vehicles. Asthe trucks are contracted the conversionmight be done at the contractor’s cost,while the producer could arrange toprovide natural gas refueling facilities atthe production site. This would beparticularly attractive for areas that havesurplus natural gas from conventionalheavy oil operations and where the trucksare staying in the local area. Fleetconversions can sometimes be eligible forgovernment incentives and many commercial gaspipeline companies are building natural gas fuelingsites.

Duel fuel vehicles are those equipped to burn naturalgas and diesel.

Pro’s:

• Capital costs for fleet conversions and refueling points could be by others andmay be subsidized.

• May be a way to utilize surplus casing vent gas from conventional heavy oiloperations.

• Reduce truck fuel costs should reduce product transportation costs.

• Cleaner burning fuel might reduce concerns of residents.

Con’s:

• Requires a source of high pressure dry natural gas.

• Creates difficulty using converted vehicle in other areas.

• Dependent on relative cost of natural gas and compression facilities vs. thecost of diesel fuel for trucks.

• Third parties have to buy in and see value.

More Information:

• Industrial Gas suppliers.

• Sask Energy and NRCan conversion incentive program informationwww.saskenergy.com/appliances/naturalgasvehicles.htm .


Option Sheet 13.5.6.2: Diluent or Emulsion Pipelines (Tier 1-2)

Diluent Pipelines (Tier 1) - Where oil production volumes are sufficient to justify apipeline a diluted oil pipeline is often the best option. If the oil is going to a localrefinery or upgrader, the diluent can be recycled in a return pipeline at fairly low net costas there is only the cost of the initial charge of diluent and then an energy cost to separatethe diluent for recycle. If the product is going to be shipped a long distance to markets, inthe U.S. or elsewhere, then the diluent is lost and new diluent must always be purchased,as there is no return of diluent to Canada from external markets. If the diluent must bepurchased anyway then best use can be made of it if it is delivered right to the oilproduction site. The longer the length of pipeline needed to transport the oil the greaterthe advantages of a diluent pipeline.

Emulsion Pipelines (Tier 2) – Some work has been done on looking at emulsionpipelines where oil is mixed with water into a stable emulsion. Such emulsions have alower viscosity than heavy oil alone and some trials have been done by batching anemulsion through pipeline systems. However, the process is not favoured as theemulsion must be broken at the receiving end of the line, usually a refinery with fewfacilities for disposing of it, and also can contaminate other hydrocarbons being batchedthrough the large pipeline systems.1

Pro’s:

• Pipeline pressure losses are reduced.

• Both oil and diluent are valued at the other end.

• Lines can be shutdown and restarted

• Product is easily stored

Con’s:

• Cost for diluent or cost of water disposal.

• Diluent system requires a local supply of diluent or areturn pipeline.

• Water in emulsion can result in corrosion.

More Information:

• AEC Pipelines, Express Pipeline and other pipelinecompanies.

1 Photo from www.cepa.com


Option Sheet 13.5.6.3: Heated Pipelines (Tier 1-2)

Heated Insulated Pipeline (Tier 1) – For shorter pipelines (<200-300 km) to a pipelineterminal, refinery or upgrader, one option is a heated insulated pipeline like the Echo linefrom Elk Point to Hardisty. In this case energy in the hot oil at the producing end allowsthe oil to flow without diluent. If the flowrates are high enough the ground around thepipe will retain a considerable amount of energy, which can help maintain temperaturesthrough short flow stoppages, however, if flow is going to be down for any time the linemust be purged with diluent to ensure it can be restarted. This option makes use of theenergy that has already been invested at the oil treating stage and avoids the need for areturn diluent pipeline.

Hot Fluid Pipeline (Tier 2) - A variation on the heated/insulated pipeline is a designwhich has been used by Shell for molten sulphur pipelines. It is a pipe within a pipearrangement with the oil in the inner line and aheating or insulating medium in the annulus.Depending on the situation the fluid in theannulus could be hot produced water from theproduction site, which will provide the energy tokeep the line warm and then be disposed of at thedischarge end, a liquid hydrocarbon fuel streamfrom an upgrader, or natural gas, which canprovide an extra insulating effect. Othervariations on this may be to pipeline an emulsionto an Upgrader and use the annulus to return water for disposal.

Pro’s:

• Makes use of the hot oil generated at the producing site.

• Lower operating cost as diluent is not required.

Con’s:

• If the flow slows down or stops the line will cool so must be displaced withdiluent.

• Insulation adds to capital cost, and a dual pipe system will be even moreexpensive.

• If the heavy oil does cool off getting the flow moving again will take time andeffort.

More Information:

• Pipeline companies and contractors. www.gibsons.com


Option Sheet 13.5.7: Fuel Switching Options (Tier 1)

Recent history has shown that gas and power prices, that have traditionally been fairlystable in Western Canada, may now experience large price swings. While the spikesexperienced in 2000-2001 have now been reduced, by dropping demand and increases insupply, they are likely going to become more frequent in the future. Because heavy oil isoften undervalued because of over supply, the high fuel and energy costs can quicklymake thermal heavy oil operations uneconomic. During the high prices some operationswere shutdown and many were looking to find ways to easily convert to coal or someother lower cost fuel. Large integrated producers were less affected by these trendsbecause they can supply themselves with fuel gas. However, the spikes established theneed to be able to reduce the dependence of thermal heavy oil operations on any outsideenergy sources.

The chart below illustrates the impact of rising natural gas prices compared to the sameenergy input using either heavy oil or diluent. Normally gas has been at the $2-3/GJlevel while heavy oil might be $20/bbl and diluent in the $30/bbl range. A chart similarto this could be used at a site to determine which fuel source, available to that site, ismost economic to use at any given time. As the commodities often vary independent ofeach other, the more potential fuel sources that can be used in a facility the easier it willbe to switch fuels to minimize fuel costs.

Fuel Cost - 50 MMBTU/hr Generator

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

2 4 6 8 10 12 14 16 18 20 22 24 26 28 30

Unit Fuel Price - $/GJ(gas) or $/bbl

Fu

el C

ost

$M

M/y

r

Gas (35 MJ/m3)

Heavy Oil (5.8 GJ/bbl)

Diluent (6.4 GJ/bbl)

Heavy Oil – The use of heavy oil as fuel is covered in Option Sheet 13.5.2.2 as it wouldbe the lowest cost alternate fuel supply on an on-going basis. However, the use of rawheavy oil is a problem because of the high sulphur content, which would cause asignificant increase in SO2 emissions. Increased SO2 emissions would likely require the

addition of large stacks and revisions to environmental permits to allow its use, or someability to produce a sweet fuel from the heavy oil. The other options suggested belowavoid these capital and regulatory impacts by using liquid hydrocarbon fuels that mightbe relatively cheap and are already low in sulphur content.

Diluent - If the thermal operation is already utilizing diluent for pipelining it may beeconomic, depending on the cost per energy unit, to switch from natural gas to diluent asfuel. As diluent tends to be composed of lighter hydrocarbons that are usually in highdemand, the cost of the diluent will be higher than some other hydrocarbon liquid streamscovered below, and the main advantage might be the fact that the transportation system tobring the diluent to the site is already in place.

Sweet Crude, Upgraded or Refined Products - An alternative to use of diluent is to usesome other liquid stream, that has a low relative value compared to diluent, but has alower sulphur content than heavy oil. This stream may be an upgrader byproduct streamthat has been partially upgraded to reduce sulphur content and reduce viscosity but notyet hydrotreated. It could also be sweet crude oil, diesel, kerosene or some other productwith a lower market value. The composition of such a stream could vary over time, andwould require some adjustment of burners at the production site. If a diluent line is inplace the alternate fuel stream could be batched through the line as is done with batchingother petroleum products from refineries to end markets. Some extra tankage would berequired for batching and some cross-contamination of diluent and fuel streams mightoccur but would not greatly impact operations.

Pro’s:

• Ability to fuel switch will likely be desirable at some point when gas pricesare high.

• Fuel switching allows the use of the lowest cost hydrocarbon fuel at any time.

• Diluent lines can be used to transport most liquid fuels in batches.

Con’s:

• Requires more effort to monitor and plan for changes in fuel use ascommodity prices change.

• Facilities must be designed to facilitate switching to liquid fuels of varioustypes.

More Information:

• Websites tracking commodity prices including refined products.

• Refineries and upgraders.


Option Sheet 13.5.8: Flares, Fugitive and Odours (Tier 1)

Most thermal heavy oil operations no longer vent significant volumes of methane, whichalso means that most sources of odours have also been reduced. The largest remainingodour source in plant areas are likely tank vents (product, diluent and water tanks) andpotential methods for mitigating these types of emissions have been covered in theprevious Conventional Heavy Oil Vent Options Study (Phase 1a) and the ConventionalOil and Gas Production Facility Vent Options Study (Phase 2a). Options for dealing withfugitive emissions of sweet natural gas in process buildings are being covered in theNatural Gas Processing and Compression Vent Options Study (Phase 2b). Optionsdiscussed in other phases will not be covered here as there are no significant differencesand all materials will be in the public domain. A source of fugitives, fluid spills andodours that is somewhat unique to thermal heavy oil is the emissions due to wellheadstuffing box leaks covered below.

Wellhead stuffing boxes have long been a problem in thermal heavy oil operations withreciprocating beam pumps. The packing in the stuffing box, which provides the sealaround the reciprocating polished rod, must withstand high temperatures; wear from sandand scale, and hot hydrocarbon fluids and steam. The basic function of the stuffing boxis the same as in other conventional oil or heavy oil situations, however, in hot thermalwells the produced oil and water do not provide as much lubrication as light oil andcolder water do. Preventing and detecting leakage is the primary need as uncontrolledleaks lead to gas and fluid emissions and if not detected early enough can lead to majorspills. Options for reducing stuffing box leaks are:

• Improvements in stuffing box designs and seal elementshave been made by vendors to improve the seal life anddurability1. Many vendors can provide alternate stuffingbox designs and packing materials.

• A way to reduce packing wear is to provide a separatelubricator for the stuffing box. This can be a simplemechanical chemical pump powered by the pump jack thatwould provide a small amount (drop or two) of oil witheach pump stroke. The oil used for lubrication could beobtained from a local garage, which does not have anotherarrangement for recycling used engine oil.

• Some vendors offer stuffing box leak detectors which can monitor leakage andshutdown pumps if leaks are detected. With pad developments these devices may bemore economic if they can accept multiple signals. Serious leaks at pads can have a

1 Photo from www.nelgarservices.com showing Nelgar’s “Rod Knuckle”

greater economic impact than leaks on single well sites, as a leak in one well can impactproduction from other wells.

Pro’s:

• Prevention or early detection of packing leaks reduces gas emissions, odoursand liquid spills.

• Small changes in cost in the equipment and seal selection may have a largeimpact on maintenance and clean-up costs, and on emissions.

• Many products on the market, some specific to thermal heavy oil applications.

Con’s:

• Determining the best solution for any application is time-consuming as it isoften by trial and close monitoring of performance.

• Cost of leak detection is relatively high vs. increased monitoring by operationsstaff.

More Information:

• Stuffing box vendors.

• Stuffing box leak detection www.stellartechsys.com in Calgary.


Option Sheet 13.6.1: Use of Conventional Heavy Oil Vent Gas (Tier 1)

In many areas where thermal operations are in the same general area as conventionalheavy oil there is often a potential fuel supply available from casing vents in theconventional wells. This gas is often low pressure but it’s recovery and use as fuel in thethermal operation should always be preferred to purchasing treated commercial gas forfuel.

As most conventional heavy oilcasing gas that is being vented issweet, or has extremely low levelsof H2S, the gathering system shouldbe commingled with the sourthermal vent gas. This will reducethe cost of equipment to sweetenthe sour gas and/or allow the twostreams to be used in the mostefficient manner in fired equipmentin the plant. Incremental costs forseparate systems, whereconventional and thermal operationsare adjacent should be smallcompared to the cost of dealingwith a larger sour stream.

As the casing vent gas is low pressure it may need some compression to be able to supplysteam generators or treaters at a steam and production battery, however, compressionrequirements for using the gas as fuel are considerable less expensive than compressingthe vent gas into a sales system. Also, depending on the situation, drying of the gas to acommercial spec can be avoided which will significantly reduce capital costs forrecovering the casing vent gas.

Pro’s:

• Creates synergies between conventional and thermal operations to maximizeprofitability and reduce overall area emissions of GHG.

• Vent gas is economically diverted to generate more oil production and backout external energy sources.

• Casing vent gas can also be used for power generation at the thermal site.

Gas Collection and Sharing

Low Pressure< 50 psig

Freeze protect

Low PressureSour Vent Gas

Net Demand Sites

Central CollectionCompression Site

(If required)

Steam and ProductionBattery or Plant

Con’s:

• Requires interconnecting pipelines (HDPE lines preferred) and segregation ofsweet and sour vent gas systems.

• Fuel systems might have to be duplicated in the plant between high pressurepurchased fuel gas and lower pressure vent gas streams.

More Information:

• See New Paradigm’s Phase 1a report and toolkit on Conventional Heavy Oilvent gas mitigation options. Available on www.newparadigm.ab.ca


Option Sheet 13.6.2: Use of Alternate Hot Produced Water Sources (Tier 2)

Conventional heavy oil operations normally use tank heaters to heat production to 65 to85 degrees C to allow for tank separation. In the Conventional Heavy Oil Vent Optionsstudy it was suggested that the energy already invested in heating the produced watermight be used to advantage inincreasing oil production throughhot water flooding or stimulation.In some cases hot produced water isor could be trucked to nearbythermal operations for disposal.The energy in this stream might beused to generate power orsupplement the thermal recoveryprocess.

If possible trucking of water shouldbe avoided so insulated pipelinesmight be required to move hotproduced water from truck unloading facilities in the conventional heavy oil areas to thethermal operations. Low cost HDPE lines would be preferred for this. Concentric HDPElines with a water line inside a larger gas line to transport hot water and sweet lowpressure gas from a CHO operation to a thermal operation might be viable. (i.e. plow in a6” HDPE coil gas line then insert a 4” water line leaving the annulus for gas flow and toinsulate the water line).

Pro’s:

• Increases the quantity of hot/warm water available for reuse or use in variousoptions such as those described in section 13.4.2.

• Provides an alternate disposal outlet for conventional heavy oil producedwater. Injection of produced water into a producing zone would likely requireless energy than injecting it into a tighter deep disposal zone.

• May be synergies with gas transfer pipelines, see above.

Con’s:

• The hot water must be transported in a way that will minimize energy losses.

• Requires that the hot/warm water can be put to use at the thermal site.

More Information:

• HDPE pipe suppliers and installation contractors.


Option Sheet 13.6.3: Distributed Power Generation (Tier 1)

If the thermal operation is in a fairly isolated area some distance removed from a utilitypower plant or in an area with only one main power line into the area it may beadvantageous to generate power for more than just the thermal operations needs. Withderegulation in Alberta, and amarket gradually opening up forthird party power generation andsales to the crown utility inSaskatchewan, this might create anadditional revenue stream for theoperation. It would also provide aservice to the local community andother producer operations in thearea by increasing the reliability ofthe power supply and decreaseoverall power costs.

Gas supplied from CHO well casingvents could provide the fuel for thepower generators as well as the steam generators for the thermal operation.

Feeding power into a grid with other users and controlled by a utility is more complexthan using the power on a site to back out external power. Some issues are:

• The need for two directional metering so the operation only pays or receivespayment for it’s net power demand.

• Negotiating agreements with the local transmission company to feed the grid.• Safety issues for the transmissions company as each new potential source of

electricity to a grid complicates the network of switches and procedures requiredto de-energize portions of the grid for repairs and maintenance.

Pro’s:

• Centralize power generation at a single site in an area.

• Increase power reliability in remote areas.

• Utilize surplus casing gas from CHO operations in an area.

• Reduce producer power costs in an area and reduce power transmission linelosses.

• Third parties may be willing to invest capital and operate the power plants.

Distributed Power Generation

Low PressureGas Gathering

< 50 psigFreeze protect

To/from Local Grid

Local Sales System 25 kV powerlines

Net Demand Sites

Central Power Generation @ Thermal Plant Site

Electrified Thermal Sites

Con’s:

• Requires agreement of local power transmission utility.

• Requires ability to feed power into the grid or take power form the grid.

• Requires an economic benefit from investment in power generation facilities.

More Information:

• Various sources and studies. Main sources would be contacts in localelectrical utilities to investigate opportunities.

thermal heavy oil options - new paradigm engineering ltd

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