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PETROLEUM SOCIETYCANADIAN INSTITUTE OF MINING, METALLURGY & PETROLEUM

PAPER 2002-205

Pipeline Transportation of EmergingPartially Upgraded BitumenR.W. Luhning, A. Anand, T. Blackmore, D.S. Lawson

Enbridge Inc.

This paper is to be presented at the Petroleum Society’s Canadian International Petroleum Conference 2002, Calgary, Alberta,Canada, June 11 – 13, 2002. Discussion of this paper is invited and may be presented at the meeting if filed in writing with thetechnical program chairman prior to the conclusion of the meeting. This paper and any discussion filed will be considered forpublication in Petroleum Society journals. Publication rights are reserved. This is a pre-print and subject to correction.

ABSTRACT

The potential for bitumen and heavy oil production in

Canada over the coming decade is predicted to be

constrained by existing pipeline capacity, diluent

availability and refinery conversion capacity. Technology

for partial upgrading of bitumen to produce pipeline

specification oil, reduce diluent requirements and add

sales value is under aggressive development. The

partially upgraded bitumen will be attractive for

additional upgrading to end user products in a wider

range of refineries than raw bitumen. The transportation

of partially upgraded crude in existing pipelines to USA

and potentially in new pipelines to new overseas

customers will present new opportunities and challenges.

This paper provides an overview of emerging partial

upgrading technologies, the current pipeline

specifications and the procedures to transport partially

upgraded product, number of existing refineries to

potentially accept partially upgraded product and future

predictions.

INTRODUCTION

Canada, mainly in the province of Alberta, holds one

of the largest reserves of oil in the world. With current

technology the recoverable reserves are estimated to be

335 billion barrels1a. The vast majority of these reserves

are in the oil sands. In 2001 Canada was the largest

import supplier of crude oil to the USA1. Saudi Arabia2

was the second largest supplier as shown in Table 1.

As shown in Figure 1, oil sands production is predicted

to increase to 50% of Canada's oil by 2011. Over the

coming decade conventional oil production is predicted

to decline with the increased production being provided

by synthetic light oil and bitumen from Alberta oil sands.

The announced oil sands projects are listed in Table 2. If

all projects were to proceed, the oil sands production

alone would reach 3,445,000 bbl/d by 2011 as shown in

Figure 2. Besides the physical and financial hurdles, there

are three main challenges related to the transportation and

marketing of the new production.

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The first challenge is the physical capacity of the

existing pipelines to deliver the oil to market. With the

expansions underway, the capacity is projected to be

adequate until the middle of the coming decade then the

projected production will exceed the capacity as shown in

Figure 2.

The second challenge is the supply of low viscosity

diluent, usually natural gas condensate, to reduce the

bitumen viscosity and density to meet pipeline

specifications. The limit of bitumen that can be shipped

by pipeline with the anticipated diluent availability is less

than the projected bitumen production.

The third challenge is the projected refinery market

constraint to process the bitumen and synthetic light oil

into consumer fuel products. The market constraint is less

than the anticipated projected bitumen and synthetic light

oil production as shown in Figure 2. This is a particular

concern to producers of bitumen that are not integrated

oil companies.

There are a variety of ways to address the increasing

bitumen production challenge. These include: 1) refinery

modifications and increased Canadian access in PADD

(Petroleum Administration Defense District) II and IV, 2)

development of a regional upgrader in Alberta, 3)

production of synthetic diluent for blending with

bitumen, 4) developing new markets and 5) adding

additional pipeline capacity. The newest emerging

approach is partial upgrading (field upgrading) of the

bitumen at or near the bitumen production site. While the

ultimate solution will likely be a combination of methods,

the technology of partial upgrading appears to have good

potential to have a role in the future.

OBJECTIVES OF PARTIAL UPGRADING

The objective and role of a particular partial upgrading

technology in bitumen upgrading, transportation and

marketing will vary with the technology. The generic

objectives of partial upgrading are provided in Table 3

including improved economics and reduced greenhouse

gas missions.

Reduce or Eliminate Requirement for Diluent

A typical bitumen in situ production operation, such as

SAGD (Steam Assisted Gravity Drainage), produces

bitumen that has too high a viscosity and density to be

transported by pipeline over long distances. In order to

meet pipeline specifications, the bitumen is blended,

depending on the bitumen and diluent viscosity, with up

to 50% of a light diluent. The objective of a partial

upgrader located at a SAGD site is to reduce the bitumen

viscosity and density to meet pipeline specifications thus

reducing or eliminating the need to use diluent and the

associated cost of transporting the diluent to the site.

The elimination of diluent to transport the bitumen

effectively removes the "diluent availability" cap for

transporting bitumen. This could reduce dependence on

limited and increasingly expensive sources of diluent.

Provide Steam for SAGD Bitumen Recovery

SAGD and other thermal recovery methods use about

2.5+ barrels of steam (cold water equivalent) per barrel of

oil produced. Natural gas is normally burned to produce

the steam. Depending on process, partial upgrading at site

can produce up to 100% of the required steam thereby

reducing the dependence on purchased natural gas which

represents a large portion of the operating cost for

bitumen recovery. This also preserves the supply of

natural gas, a premium fuel, for other uses.

Extend the Capacity of Existing Pipelines

The elimination of the need to blend bitumen with up

to 50% of diluent means that only one barrel of pipeline

capacity will be required to transport a barrel of product

to a particular location. This will allow more pipeline

flexibility to transport the total volume of products.

Increase Refinery Export Market for Bitumen

While it is predicted that bitumen production in

Canada will increase dramatically over the coming

decade, the current production and export market for

bitumen is relatively small. About 170,000 bbl/d of

diluted bitumen3 are exported to the USA with the

majority going to refineries in PADD II. The small

market leads to price fragility especially with only 5 US

refineries, as shown in Table 4, taking about half of the

Canadian heavy oil plus bitumen4. The refining of

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bitumen to produce fuels generally requires that the

asphaltenes and coke be converted or removed from the

bitumen. For the production of liquid fuels, asphaltenes

and coke are low value materials5.

Partial upgrading of bitumen generally involves the

conversion and/or the removal of coke or asphaltenes.

This results in a partially upgraded oil that has less heavy

components (i.e. those boiling above 700 oC). Thus the

oil may potentially be processed in refineries without the

requirement for coke removal facilities.

PIPELINE SPECIFICATIONS AND ISSUES

The specifications for pipeline transportation of oil are

of critical importance for diluted bitumen transportation

to market. This is because the amount of diluent to be

blended with the bitumen is essentially determined by the

viscosity and density specifications.

The crude stream quality acceptance criteria are

provided in Table 5. The criterion6 have two purposes: 1)

to insure the crude meets the quality specifications in the

crude petroleum tariff document, mainly viscosity,

density, Reid vapour pressure, sediment & water, receipt

temperature and organic chloride content, 2) information

related to safety, operational, crude compatibility and

refinery concerns. Table 6 provides current tariff

specifications for crude transportation on the Enbridge

"mainline" system and the Athabasca pipeline. Crude that

does not meet the specifications is not accepted.

Pipeline Specifications and Diluent Price

The historic price of natural gas condensate that is

blended with bitumen to meet pipeline viscosity and

density specifications has increased in value steadily in

response to increased demand as diluent for bitumen and

heavy oil. As shown in Figure 3, the prices peaked at

about 125% of par value in 1997/98 and again in

2000/01. On January 1, 1999, the viscosity specification

for crude transport was increased from 250 cSt to 350

cSt. The higher viscosity means that less condensate is

required for blending and consequently there was

stabilization in the price with the lower demand. There is

seasonal change in condensate usage since the lower

temperature winter viscosity specification requires more

condensate in the blend than in summer.

Solution to Dilution: Synthetic Diluent or PartialUpgrading?

Depending on the future production rate of bitumen,

the current supply of natural gas condensate for bitumen

blending is predicted to be outstripped by demand3 by the

middle of the decade. Alternate potential sources of

natural and synthetic diluent are listed in Table 7

including condensate from Arctic gas. The availability of

synthetic diluent is expected to increase as the overall

average price paid for diluent goes up.

Partial upgrading of bitumen to pipeline specification

oil can eliminate the need for diluent. The solution for

dilution may well include partial upgrading depending on

the specific situation.

Cracked Product: Pipeline and Refinery

Many partial upgrading processes produce oil that

meets pipeline specifications for viscosity and density by

coking or thermally cracking the bitumen. When bitumen

is cracked organic compounds with double bonds, called

olefins and di-olefins (two pairs of double bonds) are

produced. The olefins are unstable (especially in contact

with heat or oxygen) and will form fouling sludge in

refinery equipment7, catalyst beds and pipelines unless

carefully handled. Thus, it is important that cracked

product not be delivered to a refinery that is not prepared

to receive such product.

Cracked product is pipelined with "buffers" of a

compatible crude (that the refinery must accept) ahead

and following the cracked product in the pipeline to

totally segregate the cracked product. This protects other

refineries from receiving the cracked product. Tanks must

be dedicated to cracked product service to ensure

containment of the cracked oil.

Olefin content is measured, Table 5, by the "bromine

number" in the distillation cut from initial boiling to 250oC. A bromine number under 10 is considered acceptable

for normal crude handling.

Refinery Potential for Partially Upgraded Oil

As outlined in Table 8, procedures and equipment are

in place on the Enbridge system that currently provides

for the transport of cracked product to Regina (line 3), to

Clearbrook/Superior (line 4) and continuing on to

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Chicago (line 6A). Seven refineries are located along

these pipelines. Three refineries receive cracked product

on a regular basis.

Refineries that have facilities to process cracked

product of the type produced by coking have the highest

potential to accept and process, with modifications,

partially upgraded oils. There are 15 refineries in the

USA with coking facilities that are accessible or

potentially accessible from Canada2,4,8 including the

Premcor refinery at Hartford Illinois that has announced9

plans to close due to high costs to convert to low sulphur

specifications for gasoline and diesel. Twenty-one US

refineries and nine Canadian refineries can access heavy

crude from Canada. Alberta bitumen is regularly

processed in 7 US refineries for fuels (Table 9).

EMERGING PARTIAL UPGRADING METHODS

The increasing production of bitumen, shortage of

diluent and potential to integrate field upgrading with

bitumen production has created a "landslide" (Table 10)

of innovation for partial upgrading methods. The

emerging technologies are at various stages.

OrCrudeTM Upgrading Process

The OrCrude upgrading process is a proprietary

carbon-rejection process10 developed by the Ormat Group

of Companies that can process bitumen to remove the

heaviest, lowest value components and thermally treat the

remainder by integration11 with other commercially

available technologies. A 500 bbl/d OrCrude pilot has

been constructed near Cold Lake, Alberta. OPTI Canada

Inc. and Nexen Inc. are developing the Long Lake project

near Fort McMurray, Alberta. The project is to begin

with a 3000 bbl/d SAGD pilot project12. SAGD will be

integrated with a 60,000 bbl/d upgrader based on the

OrCrude process with startup in 2006 for an "all

inclusive" cost of $1.5 billion, or $25,000 per daily

barrel39. Asphaltene gasification, hydrotreater and

sulphur removal facilities will be included to produce 37o

API synthetic crude12a that can be transported in existing

pipelines. The produced gas will be used as fuel in the

SAGD process. Hydrogen from the gasification unit will

be used for hydrotreating.

Rapid Thermal Processing (RTPTM)

Ensyn Group Inc. developed the RTP technology for

partial upgrading of bitumen at its research facility in

Greely, Ontario. The patented process converts bitumen

to lighter, lower viscosity pipeline-able product by rapid

addition of heat to the bitumen at low pressure for a short

period of time (seconds). By-product coke is consumed in

the process to generate heat for the process. Excess heat

from the RTP process and produced gas can be used to

generate steam for an integrated SAGD operation. The

RTP technology has been applied commercially for over

12 years for the production of food flavorings and fuels

from wood and biomass.

Ensyn is scheduled to install a RTP demonstration

pilot for upgrading up to 1000 bbl/d at the Enbridge

Pipelines Inc. Hardisty, Alberta pipeline terminal in

200213. ITS Engineering Systems, Inc of Katy, Texas and

Ensyn have established a joint venture for construction of

RTP plants14 for upgrading bitumen and heavy oil.

Construction of the RTP demonstration pilot has been

initiated by the joint venture. The technology is expected

to be economic at about 5,000 bbl/d with a capital cost of

about $4,000 per daily barrel23.

CPJ Process for Upgrading Heavy Oil

The CPJ process by Synergy Technologies Corp. is

based on instantaneous transfer of energy from

superheated steam to a fine mist of heavy oil15 that is

preheated to just below the temperature required for

thermal cracking. Synergy has patented specially

designed injectors for the process. The thermal shock in

conjunction with mechanical shear in the process breaks

the long chain molecules in the heavy oil resulting in

lighter and lower viscosity oil. Neither hydrogen nor

catalysts are used in the process. Tests performed16 in a

1/2 bbl/d laboratory pilot converted 13o API gravity

heavy oil to 30o API oil with 90% liquid yield and 50%

reduction in sulphur content. A polyaromatic pitch is co-

produced that can be used to fuel the process.

TaBoRR Process

TaBoRR (Tank Bottom Recovery and Remediation)

process is a patented process developed by the Western

Research Institute17 of Laramie Wyoming. The process

was initially developed to remediate oily wastes from

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refineries, production operations and used motor oil.

Process development began in 1992 and progressed to a

300 bbl/d transportable demonstration unit. Cold Lake

bitumen has been tested18 in a 1bbl/d bench top unit that

produced 20o API product. The TaBoRR process is a

carbon rejection process that consists of two main

elements: 1) Patented "horizontal" stripper (distillation)

to separate low boiling material and 2) Pyrolyzer unit to

crack and coke the heavy ends from the stripper.

The pyrolyzer is made up of pipes with interior rotary

screws that are heated in a fluidized bed of hot sand. The

heavy oil is cracked and coked in the pipes. The cracked

gaseous material exits and is condensed. The solid coke

deposited on the interior of the pipes is moved out of the

pipe by the screws in a continuous operation. The capital

cost for a 20,000 bbl/d commercial operation with Cold

Lake bitumen to produce 16,404 bbl/d of 26.5o API

product with 3.1% sulphur is estimated18 at $98.2 million

with operating cost of $2.66/bbl feed. Cold Lake bitumen

is 11.0 API with 4.6% sulphur.

Value Creation Upgrading Process

PanCanadian Petroleum Limited and Value Creation

Group, both of Calgary, Alberta has a joint agreement for

development of a novel upgrading process19 invented by

Value Creation. The process is aimed at converting

bitumen to lower viscosity, higher value oil that would

reduce or eliminate the need for diluent for pipeline

transportation. The technology is based on removing

"contaminants" such as asphaltenes23 to produce lower

viscosity oil. The "contaminants" are subsequently

converted to light crude components. If successful, the

process could be applied at the PanCanadian SAGD

Christina Lake project in the Athabasca oil sands.

Genoil Hydro-Processor Upgrading

The Genoil Inc. upgrading process20 combines

hydrocracking and hydrotreating in a non-catalytic mode

of operation with the objective to convert bitumen to

sweet crude that meets pipeline specifications. The

conversion of 6.8o API, 5% sulphur content bitumen to

28o API, 0.2% sulphur oil without producing coke has

been reported with operations at 745 oF and 1600 psig

pressure. A 10 bbl/d pilot plant22 has been located at

Conoco's (formerly Gulf) operation at Kerrobert,

Saskatchewan. The hydrogen for the pilot is provided by

an 1140 scf/hour electrolyser from Hydrogen Systems

Inc21. The upgrading process has potential for field

upgrading and regional scale graders processing heavy oil

or bitumen. The anticipated capital cost is reported23 as

about $10,000 per daily barrel. Synenco Energy Inc. of

Calgary is evaluating the results of the pilot.

Albian Muskeg River Oil Sands Mining

The Albian Sands Energy Inc. bitumen extraction

process specified for the Athabasca oil sands mining

operation at Muskeg River involves the use of paraffinic

solvents (i.e. pentane and hexane) that precipitate fine

solids and 4% of the bitumen comprised of resins and

asphaltenes24. With the removal of a portion of the

heaviest hydrocarbons during the extraction of bitumen at

the mining site, the Shell Scotford refinery in Edmonton

will use catalytic hydrogen conversion technology to

upgrade the remaining bitumen.

Vapex Process In Situ Upgrading

The Vapex (vapor extraction) process is a non-thermal

process that uses vaporized solvents that are injected into

heavy oil or bitumen reservoirs25. The solvent dissolves

in the oil reducing the oil viscosity so the oil will flow by

gravity at natural reservoir temperature to horizontal

production wells. The solvent (i.e. propane) also causes

asphaltenes to be precipitated from the bitumen in the

reservoir thus reducing the bitumen viscosity and density.

The partially upgraded Vapex bitumen requires less

diluent for pipeline transport and has less heavy

asphaltene content, which is a benefit for upgrading.

Devon Canada Corporation (Northstar) and Alberta

Energy Company are beginning Vapex field pilots in the

Athabasca oil sands at the Dover and Foster Creek sites

respectively26. Baytex Energy Ltd. has initiated a Vapex

field pilot in heavy oil at Soda Creek, Saskatchewan.

Nexen Inc. is planning a Vapex pilot in heavy oil at

Plover Lake, Saskatchewan.

Super Critical Partial Oxidation (SUPOX)

In the SUPOX process27, heavy oil is partly combusted

in a reactor in the presence of supercritical water (water

supercritical point is 3206.2 psia at 705.4 oF). Hydrogen

is formed by the reaction of water and carbon monoxide

that combines with thermally cracked oil to produce

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hydrogenated light oil. PanCanadian and Baker Hughes

formed a joint venture28 with University of Calgary

combustion group building a prototype scale reactor and

National Centre for Upgrading Technology (NCUT)

operating the reactor at their Devon, Alberta facility. The

development is aimed at small scale field upgrading. The

Saskatchewan Research Council also conducted

experiments using supercritical water-oil reactions29 to

provide viscosity reductions and density improvements.

Ionic Liquid Catalysts

The Saskatchewan Research Council and University of

Regina are conducting laboratory scale investigations into

the use of ionic liquid catalysts that will upgrade heavy

oil at room temperature29 for field upgrading applications.

Ionic liquids are essentially "molten" salts, some of

which are liquid at room temperature. When oil is

exposed to particular ionic liquids, the oil reacts to

produce upgraded oil. The most common use of ionic

salts is in the manufacture of aluminum.

Biocatalyst Upgrading

The upgrading of heavy oil by bioprocessing is under

investigation in a collaborative research project between

NCUT and the University of Alberta. The objective is to

isolate biocatalysts that will selectively "attack" large oil

molecules and break them into smaller molecules. The oil

viscosity will be reduced thus requiring less diluent for

pipeline transportation.

CAPRI In Situ Upgrading

The CAPRI (not an acronym) process aims at coupling

downhole catalysts with in situ combustion for oil

recovery to produce upgraded oil. The process30 has been

developed through laboratory physical model

experiments at the University of Bath, United Kingdom.

In a reservoir application, in situ combustion would be

conducted by air injection into a vertical well located

near the toe of a horizontal production well that has been

"gravel packed" with catalyst. The high temperature

combustion cracks the oil and the reaction of carbon

monoxide and water produces hydrogen. The oil is

further upgraded and hydrogenated as it passes through

the catalyst surrounding the horizontal production well.

AquaconversionTM Process

Intevep of Venezuela invented the Aquaconversion

process that is "marketed" via an alliance of Intevep,

Foster Wheel and Universial Oil Products (UOP).

Aquaconversion is an improvement31 on conventional

refinery visbreaking technology that exposes heavy oil to

heat to convert heavy fractions of the oil to lighter

product. The challenge with visbreaking is that the

production is not saturated with hydrogen and requires

additional processing. The Aquaconversion process uses

oil soluble, once-through catalysts (that can be

regenerated) to convert entrained water to hydrogen. The

free hydrogen reacts with the cracked oil to produce a

hydrogenated product.

The process has been demonstrated in a 36,000 bbl/d

visbreaking unit modified for the purpose. The ongoing

process development has as one of its objectives, the

application of the process directly at the wellhead.

ROSETM Process for Partial Upgrading

The Kellogg Brown & Root ROSE (Residuum Oil

Supercritical Extraction) process is a commercial refinery

process to extract asphalt from heavy oil32. The

deasphalted oil can be refined using a hydrogen addition

process. Excess amounts of produced asphalt are difficult

to market and may be burned to produce energy or

gasified to co-produce hydrogen for refinery operations

and power generation. The ROSE process and

gasification has been combined on a commercial basis at

the ISAB Energy "refinery" in Italy.

Chattanooga Process

The Chattanooga Corp. upgrading process35 is aimed

at processing mined oil sands to simultaneously upgrade

bitumen and separate it from the sand. A pilot test has

been conducted at NCUT to determine the reaction

kinetics of bitumen in dry oil sands in a fluid bed reactor

with high-pressure hydrogen. The objective is to directly

convert oil sands to sulphur free synthetic crude.

CANMET Emulsion Upgrading Process (CEU)

The CEU process was invented in the CANMET

Energy Research Laboratories of the Canadian

Government with Gulf in the 1980s. The process36

involves reaction heavy oil/water emulsions at elevated

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temperature and pressure in the presence of catalyst and

synthetic gas containing carbon monoxide. The water

reacts with the CO to product H2 and CO2. The produced

H2 reacts with the crude oil to produce upgraded oil of

lower viscosity and lower gravity. Bench scale

experiments upgraded Athabasca bitumen to 19.2o API

with 65% pitch conversion. Economic analysis indicated

that pipeline specification product could be produced at

67-73% of the cost of delayed coking.

UniPure Sulphur Removal and Upgrading

UniPure Corporation have developed38 a process to

remove sulphur from fuel products (gasoline and diesel)

without the use of hydrogen. The ASR-2 process uses an

oxidant catalyst to convert sulphur compounds in the fuel

(substituted dibenzothiophene) to sulfone which may be

mechanically separated from the liquid fuels. Unipure are

also working an upgrading technology based on coke

removal.

Geotreater Process

The Geotreater40 uses the natural heat of the earth via a

vertical tubular reactor/heat exchanger sunk in the ground

for mild thermal treatment of heavy oil to reduce

viscosity. A small amount of oxygen is injected into the

oil at the base of the well. A 50 bbl/d pilot was run by

Resource Technology Associates at Golden, Colorado

that modified the gravity/viscosity of Cold Lake bitumen

to reduce the pipeline diluent requirement by 50%.

DEVELOPING NEW MARKETS

As bitumen and synthetic oil production increases,

new markets for the production will need to be

developed. New products specifically designed for the

markets may also be required.

Pipeline Infrastructure

Enbridge Inc. is undertaking a comprehensive study to

evaluate Western Canadian supply and demand issues as

well as transportation options with respect to significant

new volumes of oil sands production forecast to come on

stream over the next six to eight years. Enbridge is

working closely with producers and refiners, to develop

several alternatives to move the increasing production of

bitumen and synthetic crude to market. Further expansion

of pipeline systems into the US Midwest may be required

including expansions to Enbridge's existing mainline

system. Other options (Table 11) include new

transportation corridors to access other US markets or

consideration of a new market pipeline33 west to the

British Columbia coast, for tidewater access to the

California and Asia markets.

Regional Upgrader or Mid-Stream Polisher

Regional upgraders to convert Alberta bitumen to

synthetic light oil have been studied37 for many years.

The regional upgrader concept is to service the needs of

producers that are not integrated with a refinery by

converting bitumen to synthetic light oil. The Husky bi-

provincial upgrader operating at Lloydminster,

Saskatchewan is an example of a regional approach that

was initialed with participation by government and

industry. A regional upgrader is essentially a stand-alone

refinery with comparable capital and operating costs.

The emergence of partial upgrading is opening the

possibility to conduct portions of the upgrading of

bitumen to fuels at different locations. Partial upgrading

at a SAGD field site has the advantage of providing by-

product energy for the SAGD operation. Depending on

the upgrading process, cracked product may be produced

that contain unstable olefins. The mid-stream polisher

would provide mild hydrotreating34 of the low boiling

fraction (i.e. up to 250 oC) to stabilize the oil for

transportation and refinery processing. The mid-stream

polisher would ideally be located in Alberta near to

mainline pipeline terminal/injection facilities and to oil

reservoirs amenable to CO2 flooding to make use of

concentrated CO2 produced when making hydrogen. An

appropriately stabilized product (i.e. bromine number

below 10) could be transported in a manner similar to

normal crude (Table 12).

ECONOMIC ADVANTAGE

Since partial upgrading technologies are emerging in a

competitive environment, there is not a large amount of

published information on the individual process

economics. In order to estimate the size of the potential

economic "prize" for partial upgrading, an economic

analysis was conducted for a generic carbon removal

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partial upgrading process based on a collage of

information from the available reference material. For the

analysis it was also assumed that a facility, such as the

mid-stream polisher, would be available to allow the

product to be transported as normal crude (without

buffering) via pipeline and potentially ocean tanker. The

polished product would also widen the market for the

product beyond those refineries with the ability to handle

cracked product.

The situation of using partial upgrading and mid-

stream polisher coupled with SAGD bitumen production

was examined. The economic benefit is a combination of

increased sales value for the product compared to

bitumen and reduced production and transportation costs.

These benefits are offset by the capital and operating

costs of partial upgrading and mid-stream polisher. The

main benefits include: 1) increased product sales value,

2) steam generation from the upgrader to reduce the

amount of natural gas required to produce steam, 3)

elimination of net cost of diluent, 4) elimination of

diluent transportation to SAGD site and 5) reduction in

transportation cost to market (due to smaller volume of

higher value product).

The analysis in Table 13 indicates a net benefit at the

SAGD wellhead of $3.00 - $5.00 per barrel of bitumen.

Obviously, the net benefit is highly dependent upon

bitumen recovery factors and light/heavy price

differentials, natural gas prices as well as other factors.

However, the analysis does suggest that significant value

can potentially be derived from the processes.

GREENHOUSE REDUCTION WELL TO WHEELS

In order to determine if partial upgrading could

potentially reduce "well to wheels" emissions, generic

SAGD operations with and without partial upgrading

were compared. The stand-alone SAGD operation was

located in the Athabasca oil sands with diluted bitumen

transported to a coking refinery located in the US to

produce transportation fuels. The comparison cases had

partial upgrading with by-product carbon removal either

stored or integrated as fuel in the field to make steam for

SAGD. The gas produced by the partial upgrading

process was used in both cases to reduce natural gas

required to make steam. The production was stabilized in

a mid-stream polisher and transported without diluent to a

US refinery that produced an equal amount of

transportation fuels for all cases.

As shown in Table 14, using the carbon removed by

partial upgrading as fuel for SAGD reduces the well to

wheels greenhouse gas emissions by 25%. Storing the

carbon removed by partial upgrading rather than using it

for fuel reduces the greenhouse gas emissions by 50%.

CONCLUSIONS

There is a large number of partial upgrading

technologies under development. As stated earlier, partial

upgrading may an element in a combination of

approaches for oil sands production. Current technology

is technically and economically attractive for oil sands

production as evidenced by the large number announced

projects listed in Table 2. The history of oil sands has

been continuous technical and economic improvement.

If the technology development is successful, partial

upgrading may provide the following advantages:

1) Reduce or eliminate the requirement for diluent to be

blended with bitumen for transportation to market.

2) Provide steam for SAGD bitumen production from

heat available via the partial upgrading process.

3) Stabilization of cracked product from partial

upgrading would be an advantage for pipeline

transportation and refinery operations.

4) More pipeline flexibility (effective capacity) may be

provided to transport products (i.e. partially

upgraded bitumen to one location and the diluent

elsewhere).

5) Partially upgraded bitumen may be attractive to more

refineries than raw bitumen.

6) Partial upgrading may reduce the total "well to

wheels" greenhouse gas emissions when making

transportation fuels from bitumen.

7) Field demonstration of partial upgrading

technologies is required to confirm the potential for

technical, economic and environmental advantages.

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Partial upgrading may have disadvantages as follows:

1) Partial upgrading will impact asphalt production and

quality.

2) The most desired fuels product slate that may be

produced in a refinery may be constrained by the

initial partial upgrading. (i.e upgrading by carbon

removal vs. by hydrogen addition).

3) Partial upgrading may not "scale up" to the size

needed to centrally service oil sands mining

operations as compared to de-centralized field

upgrading of the scale targeted for in situ bitumen

production.

ACKNOWLEDGEMENTS

The Authors thank Enbridge Inc. for permission to

publish this paper.

REFERENCES

1 . Amdal, W. "Oil Sands Update" Regional Issues,

Group, Fort McMurray, Alberta, March 19, 2002.

1a.. Alberta Energy & Utilities Board, "Alberta Reserves

2000" Statistical Series 2001-98.

2. Mawdsley, J.R. et al "Tar to Car: Matching Bitumen

Production Growth with Refinery Capacity",

Canadian Heavy Oil Association Conference,

Calgary, Nov. 2001.

3. National Energy Board "Canada's Oil Sands: Supply

& Market Outlook to 2015", October 2000.

4 . Feick, R. "Canadian Oil & Gas Heavy Oil

Differentials" National Bank Financials, Jan. 25,

2002.

5 . Heaton, P. et al "Heavy Crude Quality from a

Refiner's Perspective", NCUT Symposium on

Stability and Compatibility, Calgary, September 17,

2001.

6. Blackmore, T. "New Crude Acceptance Criteria for

Enbridge Pipelines Inc.", NCUT Symposium on

Stability & Compatibility, Calgary, Sept. 17, 2001.

7 . Wright, P.E. "Causes and Control of Hydrotreater

Fouling" NCUT Symposium on Stability and

Compatibility, Calgary, Sept. 17, 2001.

8 . International Petroleum Encyclopedia, Pennwell,

2000.

9. Platts Oilgram News " Premcor to Shut 70,000 bbl/d

Illinois Refinery, March 1, 2002.

10. Application to AEUB, "Long Lake Project" Opti

Canada Inc., Calgary, December 2000.

11. Arnold, J. "Upgrader Demonstration Project" Can.

Heavy Oil Assn. Conference, Calgary, Nov. 21,

2001.

12. News Release "Opti Canada Partner with Nexen on

Major Oil Sands Project", Opti Canada, Oct. 30,

2001

12a. Nexen Newsletter "Brave New (Bitumen) World"

March 2002.

13. News Release "Enbridge and Ensyn Establish

Alliance to Facilitate Heavy Oil Development",

Enbridge, January 8, 2002.

14. News Release "ITS and Ensyn Establish Joint

Venture to Build and Sell Ensyn RTP Equipment to

Oil Industry", Ensyn, February 4, 2002.

15. Synergy Technologies "Synergy's Heavy Oil

Upgrading Technology" Synergy Web Site, March

20, 2002.

16. Alexander's Gas & Oil Connections "Synergy

Achieved Excellent Results Testing CPJ Process"

Oct 18, 2000.

17. Western Research Institute "Tank Bottom Waste

Recovery and Remediation", Web Site, March 1,

2001.

18. Brecher L.E., "The Use of TaBoRR as a Heavy Oil

Upgrader" Pacific Coast Oil Show & Conference,

Bakersfield, California, November 14, 2001.

19. News Release "PanCanadian & Value Creation Sign

Agreement to Pursue Oil Sands Upgrading

Technology" PanCanadian, August 14, 2001.

10

20. News Release "Genoil Reports Successful Testing of

Tar Sands Bitumen at Kerrobert", Genoil, Oct. 16,

2001

21. News Release "Hydrogen Systems Inc Hydrogen

Generator Operating in Heavy Oil Field of Central

Sask." Hydrogen Systems, September 4, 2001.

22. Regina Leader Post "Genoil Tests Cheaper Heavy

Oil Technology" September 5, 2001.

23. Ross, E. "Search for the Holy Grail" New

Technology Magazine, Calgary, September 2001.

24. AEUB Application 970588 "Approval for Muskeg

river Mining Project", Shell Canada, Dec. 19, 1997.

25. Luhning, R. and Luhning, C. "The Vapex Process:

Non-Thermal Recovery of Bitumen and Heavy Oil"

Can. Heavy Oil Assn. Conf., Calgary, Nov. 24, 1999.

26. Edmunds, N. " SAGD- Present and Future" Can.

Heavy Oil Assn. Conf., Fort McMurray, Sept. 5,

2001.

27. Gupta, S. et al "Heavy Oil Upgrading with Water via

Super Critical Partial Oxidation" Petroleum

Technology Alliance of Canada, 1998 Newsletter.

28. Polczer, S. "Making the Upgrade" New Technology

Magazine, Calgary, 1998.

29. Regina Leader Post "Enhancing the Future for

Saskatchewan's Heavy Oil", October 18, 2001.

30. Ayasse, C."New Heavy Oil recovery Process", CMG

Advances Newsletter, Calgary, Vol. 12, Issue 1.

31. Marzin, R. "The Aquaconversion Process for

Residue Processing", NPRA Annual Meeting, San

Francisco, March 15-17, 1998.

32. Abdel-Halim, T. "Partial Upgrading of Heavy Oil

with Rose and Gasification or Combustion", NCUT

Symposium on Upgrading, Edmonton, Sept. 18,

2000.

33. Calgary Herald "Enbridge Proposes Oil Sands

Pipeline", March 7, 2002.

34. Rahimi, P. et al "Stability and Compatibility of

Refinery Streams" NCUT Symposium on Stability &

Compatibility, Calgary, September 17, 2001.

35. Doyle, J. "Chattanooga Process, Reactor System

Synthetic Oil Process" Chattanooga Corporation

Literature, Cordova, TN., USA, 1999.

36. Patmore, D.J. et al "Canmet Emulsion Upgrading

Process" Oil Sands - Our Petroleum Future

Conference, Edmonton, Alberta, April 4-7, 1993.

37. Alberta Chamber of Resources, "Bitumen Market

Expansion Study", Edmonton, Alberta, January

1998.

38. Levy, R.E. et al "UniPure's ASR-2 Desulphurization

Process Provides Cost-Effective Solution for Ultra-

Low-Sulfur Refined Products" World Refining, May

2001.

39. Oil Daily "Nexen to Build Crude Plant" Vol. 52 no.

70, April 12, 2007.

40. Oil & Gas Journal "New Technology Seeks to End

Pipelines Heavy Crude Diluent" May 30, 1988.

11

Table 1United States 2001 Crude Sources*

Country Crude Sources (% of USA Oil)Canada 9%Saudi Arabia 8.5%Venezuela 8%Mexico 7%Iraq 4%Nigeria 4%USA (domestic) 41%Others 18.5%

_______________* Source US Energy Information Administration

Table 2Announced Oil Sands Projects

Company Project Project Volume Year Ultimate (mbpd) Production

Suncor Firebag/Voyageur 215-550 2011Syncrude Aurora Mine/Upgrader 235-465 2007Shell/Chevron/Western

Lease 13/Upgrader/Jackpine 25-525 2010Conoco Surmont 100 2010Imperial Cold Lake 160-225 2010True North Fort Hills 85-190 2009Husky/Imperial Kearl Lake 250 2010Mobil Kearl Lake 100 2005Petro-Canada MacKay River 30 2002Petro-Canada Meadow Creek 80 2007Petro-Canada Lewis Creek 60 2006PanCanadian Christina Lake 70 2008JACOS Hangingstone 50 2006Blackrock Orion 30 2007Deer Creek Deer Creek 30 2004AEC Foster Creek 20-100 2007CNRL Horizon 25-300 2010SynEnCo Northern Lights 75-150 2006Nexen/Opti Long Lake 140 2010Total Ultimate 3,445

Table 3Objectives of Partial Upgrading

• Improve Economics of Bitumen Production• Reduce Greenhouse Gas Emissions• Increase Refinery Export Market for Bitumen• Provide Steam for SAGD Bitumen Recovery• Reduce or Eliminate Requirement for Diluent• Extend Capacity of Existing Pipelines

12

Table 4Heavy Refining Capacity Accessible to Canadian Crude

Refinery Percent of Total Heavy ProductionKoch: Pine Bend, MN 15%BP: Whiting, IN 11%BP: Toledo, OH 8%ExxonMobil: Joliet, IL 7%Husky: Lloydminster, ALTA 7%PDV: Lemont, IL 5%Other 24 Refineries 47%

Table 5Quality Information Required for New Crude Stream Approval

Quality Test Name ProcedureDensity (kg/m3 at 15 °C) ASTM D 1298 or D 5002Kinematic viscosity (cSt at 10°C, 20°C, 30°C) ASTM D 445Reid vapor pressure (kPa absolute at 37.8C) ASTM D 323Pour point (°C) ASTM D 97Sulphur content:

1) total sulphur (weight %)2) hydrogen sulfide (weight ppm)3) volatile mercaptan sulfur (weight ppm)

ASTM D 2622 or D 4294ASTM D 5623ASTM D 5623

Organic chlorides (weight ppm) ASTM D 4929Bromine number in distillation cut from IBP to 250°C ASTM D 1159Salt content (kg/1000 m3) ASTM D 3230Metals/elements in whole crude (weight ppm):

1) vanadium2) nickel3) manganese

Plasma AnalysisPlasma AnalysisPlasma Analysis

Neutralization number (mg KOH/gm) ASTM D 664True boiling point distribution ASTM D 86Benzene content (weight ppm) GC-FID

13

Table 6Enbridge Crude Transportation Tariff Specifications

Measurement Restriction Maximum Main Line Athabasca Line

Maximum Receipt Temperature, oC 38 42 Density, kg/m3 @ 15 oC 940 970 Reid Vapour Pressure, kPa @ 37.8 oC 103 103 Viscosity, cSt @ Reference Temperature* 350 350 Sediment & Water, % by volume 0.5 0.5 Organic Halides none none

_________________________* Main line reference temperature is set biweekly related to pipeline temperature in the earth. In2001 the reference temperature varied from 7.5 oC in January/March to 19.5 oC in August.

Table 7Diluent Sources For Heavy Oil Transportation

• Remaining and Undiscovered Gas Condensate• Condensate from Arctic Gas• Light Crude• Synthetic Crude• Synthetic Diluent

Table 8 Transporting Cracked Crude Product

• Olefins in Cracked Crude Form Sludge in Refineries• Bromine Number is Indicator of Olefin Content• Normal Crude has Bromine Number Below 10• Need to Securely Segregate Cracked Product• Crude "Buffers" in Pipeline and Dedicated Tanks• Enbridge Delivers Cracked Product (10+ Bromine #)

Line 3 to Regina Line 4 to Clearbrook/Superior, Line 6A to Chicago

Table 9Refinery Potential for Cracked Crude Product

• Canadian Heavy Oil Delivered to 30 Refineries• 21 USA and 9 Canadian Refineries• Refineries with Cokers Produce and Process Cracked Material• 15 USA Coking Refineries are Accessible from Canada• 14 Canada and US Refineries Process Bitumen for Asphalt and Fuels• Bitumen Regularly Coked for Fuels in 7 USA Refineries• Cracked Bitumen Regularly Pipelined to be Processed in 3 Refineries

14

Table 10Emerging Processes to Partially Upgrade Bitumen

Process Method Development Status

__________________________________________________________________________________________________________

Opti, OrCrudeTM Asphaltene gasification Operating 500 bbl/d pilot withhydrotreater, sulphur removal commercial application plan

____________________________________________________________________________________________________________

Ensyn, RTP Coke removal by rapid heating Building 1000 bbl/d pilot____________________________________________________________________________________________________________

Synergy, CPJ Cracking by steam thermal shock Operating laboratory pilot____________________________________________________________________________________________________________

WRI, TaBoRR Stripper/pyrolyzer makes solid coke Movable 300 bbl/d pilot____________________________________________________________________________________________________________

Value Creation Asphaltene removal & conversion "High Head" laboratory pilot____________________________________________________________________________________________________________

Genoil Inc. Hydrocracking & hydrotreating 10 bbl/d field pilot____________________________________________________________________________________________________________

Albian, Muskeg Asphaltene removal & disposal Commercial oil sands mine____________________________________________________________________________________________________________

Vapex Process In Situ asphalt deposition Four field pilots in startup____________________________________________________________________________________________________________

PanCanadian, SUPOX Combustion/supercritical water "High Head" laboratory pilot____________________________________________________________________________________________________________

SRC, Ionic Catalysts Liquid ionic salts catalysts Laboratory investigations____________________________________________________________________________________________________________

NCUT/U of Alberta Biocatalysts Laboratory investigations____________________________________________________________________________________________________________

Capri Process In situ combustion/producer well catalysts Lab. Work & reservoir design____________________________________________________________________________________________________________

Intevep, AquaconversionTM Visbreaker/hydrogenation catalysts Commercial demonstration____________________________________________________________________________________________________________

Kellogg, ROSETM Asphalt removal & gasification Commercial operation____________________________________________________________________________________________________________

Chattanooga Fluid bed hydrogenation of mined oil sands Laboratory pilot____________________________________________________________________________________________________________

CANMET, CEU Oil/water emulsion reaction with catalyst Bench scale pilot______________________________________________________________________________UniPure Coke removal process Laboratory/feasibility______________________________________________________________________________Geotreater Thermal visbreaking with oxygen addition 50/bbl/d pilot______________________________________________________________________________

Table 11Developing New Markets

• Pipeline to Canada's West CoastBitumen/Synthetic Oil to Washington & CaliforniaShip Bitumen/Synthetic Oil by Tanker to Asia

• Extend Canadian Accessibility in USA

15

Table 12Regional Upgrader or Mid-stream Polisher

• Non Integrated Companies Need Access to Refining• New Regional Upgrader(s)

Example: Husky Bi-Provincial UpgraderProduce Synthetic Light Oil

• Mid-Stream Polisher for Partially Upgraded BitumenMild Hydrotreating to Stabilize Olefins in Cracked ProductNormal Crude Pipeline ProcedureMore Attractive Product for Refinery MarketsCentral Location near Conventional Oil Reservoirs for CO2 Flood

• Use CO2 from Hydrogen Plant for EOR

Table 13Generic Partial Upgrading / Mid-Stream Polisher Economic Benefits

Alberta Bitumen to USA Refinery

Assumed Basis : SAGD VS. SAGD + Partial Upgrader & Mid-Stream Polisher

bitumen partially upgraded at SAGD site8 API 19 API (pipeline specification)1 bbl bitumen 0.85 bbl partially upgradedGas for steam 65% SAGD steam via upgrader

Value Increase & Cost Reduction• Incremental Sales Value X

(Higher Value Product to Refiner)• SAGD Natural Gas Cost Reduction X

(Gas @ $3.50/mscf @ 3.0 SOR)• Eliminate Diluent Transport to/from SAGD Site X

(Pipeline, Tankage & Operations)• Reduction in Diluent Premium Net Cost X

(WTI @ US$28/bbl @ 5% premium, 40% blend)• Reduction in Transport Volume Cost X

(0.85 bbl vs. 1 bbl) Total Additional Benefit $10.50Capital & Operations Costs• Partial Upgrader (Capex + Opex) (X)

Capex: $5,000/daily bbl bitumen)• Mid-Stream Processor (Capex + Opex) (X)

(Capex: $3,000/daily bbl partially upgraded feed)Total Additional Cost ($6.50)

Range of Benefit at Wellhead $3.00 - $5.00

16

Table 14Generic Partial Upgrading "Well to Wheels" Greenhouse Reduction

SAGD SAGD+Partial Upgrading (CO2e kg/m3 bitumen at wellhead)

Carbon &Gas Gas (store carbon)Bitumen Production (Steam/Oil Ratio = 3.0)

Natural Gas for Steam Boilers 500 170 420Partial Upgrading Produced Steam -----

- Energy from coke & produced gas 730- Energy from produced gas (store coke) 160

Pipeline Diluted Bitumen or Non Diluted Partially Upgraded to USAMid-Stream Polisher (CO2 from H2 production) ----- -------(30 to CO2 Flood)-------Transportation 40 30 30

Refinery Upgrading (Identical Products)Refinery Coke & Gas Disposed for Fuel 650 --- ---Transportation Fuel Products ---------equal transportation fuels---------

____ ____ ____CO2e kg/m3 Bitumen at Wellhead 1190 900 580

Reduction in Greenhouse Gas ----- 25% 50%

17

• Pipeline capacity is for transport of products from the oil sands to Edmonton with the plannednew "hot bitumen" pipeline in place.

• The "hot bitumen" pipeline will transport heated raw bitumen without the need for diluent toreduce viscosity. The temperature of the bitumen naturally reduces the viscosity.

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18

• Diluent premium compared to WTI par crude

• Diluent price stabilized in 1999 when the pipeline viscosity specification was increased from250 cSt to 350 cSt thus reducing the amount of diluent needed to be blended with heavy oiland bitumen

• Recently the Bowden refinery (10,000+ bbl/d) in Alberta that processed diluent in therefinery suspended operations and the price of diluent fell.