CCQTA Update for IMG

Thermal group

January 19, 2016

Randy Segato President CCQTA

Sr Crude Quality Specialist Suncor

CCQTA “The New Direction”

1. Have completed change from a volunteer board to a

governance model.

2. Increased membership fees ($5K) to permit more shared

CCQTA funded projects (open projects ; broadly shared

learnings).

3. Option to have outside sources (Gov’t, regulators, other

Associations, etc..) commission CCQTA work.

4. Members continue to have the option to

sponsor/promote member funded (closed) projects.

5. Some historical participant funded projects converted to

CCQTA funded projects

3

CCQTA PROJECTS LIST

Participant Funded 1. Condensate Quality

2. Organic Chlorides/Halides

3. Phosphorus (Legacy)

4. TAN (Phase 4)

5. Emulsion Characterization

6. Pipeline Corrosion

7. Sour Service

CCQTA Funded 1. Bitumen Dewatering

2. Bitumen Blend Viscosity

3. TVP/RVP

4. H2S PVT

5. Crude Oil Flammability

6. Compatibility Test Method

7. Single Phase Sampling

Program

8. VLE Method Development

9. Analysis of TIOM

10. Properties of Thermally

Processed Material

(Todays update focus)

1. Bitumen Dewatering and Volume Correction

• Project details provided at March 2016 COQA joint

San Antonio meeting.

• Project work led to the

– development of a standard dewatering and solids

removal procedure to prepare bitumen for analysis

– development of arithmetic correction factors to

API 12.3 for improved accuracy of blend volume

calculations for Alberta bitumen and diluent

• Work initially funded by 6 members. CCQTA

provided additional funding

• Report published on public side of CCQTA website

– Results made available to industry at large

1. Bitumen Dewatering and Volume Correction

http://www.ccqta.com/publications.php?files_id=30

CCQTA report notes • Outlines the work that was done by industry to validate the application of a shrinkage

model to all Alberta bitumen ranges noting that all past equations have never been

proven/validated for the full range of diluents and bitumens we see today.

• This should be published in Hydrocarbon publishing this spring and will be championed

through API as a formal modification thereafter.

• Note that many CCQTA derived methods are accepted by industry and used for many

rules and regs (Ex,. CCQTA method for TAN modification of ASTMD664, , method

used for % olefins in crude, , method for Volatile Phosphorus limit).

• We can go forward with this new CCQTA modification to API 12.3 now for new

standards and for past contract work as well.

• Note as well that the Royalty Bitumen Valuation Methodology has used the API12.3

method as recommended by CAPP and approved by the ADOE since 2008. It continues

to be the official government shrinkage model and I expect the new CCQTA model

parameters will be incorporated shortly after due process.

• Note that the existing “Novacor” equation has no scientific facts nor validity for our

current bitumens (which have gotten heavier) or condensates (which have gotten

lighter). It is simply a legacy process model applied to ongoing systems, with no

supporting technical due diligence.

6

…Sidebar on volume correction/shrinkage

density inlet

kg/m3 m3 kg

vol fraction

of feed

wt fraction

of feed and

wt fraction

in blend kg

outlet blend

volume

("apparent"

for

components,

real for

blend) m3

Shrinkage

volume outlet density

Measured> 1015.0 76.28 77424.6592 0.75624 0.82542 75.6240 0.6565

Measured> 666.0 24.59 16375.3408 0.24376 0.17458 24.3760 0.2116

929.93 100.87 93800 1.00000 1.00000 93800.0000 100.0000 0.8681 938.00 -8.07

^Theoretical density^ ̂only this net blend volume is measurable^ ^Actual Density^

The component volumes are an "apparent volume" simply by assuming

that they both "shrink in direct relationship to the input"

inlet outlet

density

change

Lets consider what we know and what we measure …

Note that Bitumen Density may not be directly

measurable at 15 deg C depending on method

…excellent accuracy if linear regression of 80, 60, 40

deg C actual density is extrapolated to 15 deg C (this

approach is used in Royalty calculations under BVM)

…Sidebar on volume correction/shrinkage

Lets consider the shrinkage equation API 12.3…

Diluent Addition/ Shrinkage Calculations Volumetric Shrinkage Due to Blending

AS PER API 12.3

MODEL INPUTS RESULTS

m3 Volume of Dry Crude = m3

kg/m3 % C5+ in Total Blend (Fc) = %

kg/m3 Diluent Required in Blend= m3

kg/m3 Shrinkage Volume = m3

Volume of Blend = m3

S.F. shrinkage factor

Calculation

Iteration 1 Iteration 2 Iteration 3 Iteration 4

1/d 1/d 1/d 1/d 1/d

Diluent Density kg/m3 666.0 0.001502 666.0 0.001502 666.0 0.001502 666.0 0.001502 666.0 0.001502

Raw Crude Density kg/m3 1015.0 0.000985 945.5 0.001058 938.8 0.001065 938.1 0.001066 938.0 0.001066

Target Density kg/m3 938.0 938.0 938.0 938.0 938.0

Raw Crude Volume m3 76.28045 97.09774 99.69470 99.96866 99.99699

Raw Crude Mass kg 77,424.7 91,806.3 93,590.4 93,778.5 93,798.0

Required Diluent Volume m3 21.59410 2.67886 0.28242 0.02920 0.00301

Diluent Mass kg 14,381.7 1,784.1 188.1 19.5 2.0

Total Blend Mass kg 91,806.3 93,590.4 93,778.5 93,798.0 93,800.0

Volume % Diluent in Blend % 22.06 2.68 0.28 0.03 0.00

Volumetric Shrinkage, API 12.3 0.79368 0.08208 0.00847 0.00087 0.00009

Total Calculated Blend Volume m3 97.87455 99.77660 99.97712 99.99786 100.00000

Shrinkage Volume m3 0.77681 0.08190 0.00847 0.00087 0.00009

Total Actual Blend Volume m3 97.09774 99.69470 99.96866 99.99699 99.99991

Actual Blend Density kg/m3 945.5043 938.7705 938.0795 938.0082 938.0008

English units 4.86 SI Units 26900

mod 5.73 mod 31715.432 31715

Iteration 5

Density of Dry Crude 1015.0 24.38

Density of Diluent 666.0 24.58760

Density of Target Blend 938.00 0.8681

99.9999

0.9914

76.2805Volume of Dry Crude 76.280452

…equation comparisons... Novacor vs API 12.3 modified

The difference between methods is not insignificant and can cause errors in volume

balances the long run.

For the same system, I compared the shrinkage for each equation. The system example I

chose was 1015 kg/m3 bitumen, 666 kg/m3 diluent, 938 kg/m3 blend and 100 m3 of

blended dilbit

The lost volume was…

1) 0.4202 m3 for Novacor

77.1351 m3 dry Bitumen + 23.2850 m3 diluent = 100.00 m3 blend

2) 0.7258 m3 for API 12.3

76.5520 m3 dry Bitumen + 24.1738 m3 diluent = 100.00 m3 blend

3) 0.8681 m3 for API 12.3 Modified by CCQTA..recommended!

76.2805 m3 dry Bitumen + 24.5876 m3 diluent = 100.00 m3 blend

9

AER related items • As mentioned the entire system shrinks , and one cannot say one component shrinks and the other

does not. Stating all losses are attributed to the diluent is not valid and will introduce economic

inbalances depending on which side you are on.

• Note that losses due to vapourization or tank venting is different than system blended shrinkage

and AER terminology of live crude oils is not what we are considering. We are considering here

just normal crude measurements of already stabilized streams.

Here is a quote which states this from the AER end and which gives industry the ability to ensure the most accurate method should

be used for their system

Https://Www.Aer.Ca/Documents/Directives/Directive017.Pdf

“12.1.4 Diluent/Condensate Receipts and Blending

Blending occurs when two oils of dissimilar properties are mixed. This mixing results in volumetric discrepancies from the ideal

combination, which would yield a volume that would be the sum of the two products. The discrepancy is usually shrinkage, which is

the result of smaller molecules of the lighter hydrocarbon filling in the voids or spaces between larger molecules of the heavier

hydrocarbon. The result is a combined liquid volume that is less than the sum of the two original volumes. This shrinkage must be

determined and properly applied to volumes making up the liquid to ensure proper allocation and reporting.

12.1.4.1 Hydrocarbon Blending and Flashing Shrinkage

Generally, heavy oil is not significantly affected by shrinkage caused by flashing of light ends. However, there is always potential

for shrinkage depending on the actual operating pressure at which the wells are producing. Operators should evaluate each

facility based on its operating characteristics. See section 14.3 for details.

Later, the AER clearly states “Calculation of shrinkage factors resulting from hydrocarbon blending without flashing must be performed

in accordance with API MPMS, chapter 12.3, or an equivalent procedure accepted by an appropriate industry technical standards

association.”

Clearly, our CCQTA work on API 12.3 modified application fits with this AER guideline. I would also say that the old Novacor

equation did not pass through the rigour across all bitumen systems when it was developed decades ago.

10

2. Bitumen Blend Viscosity

• Project work

– Development of an improved viscosity model for

blend predictions for bitumens and diluents

• Work initially funded by members of the Bitumen

Dewatering project. CCQTA has agreed to provide

additional funding

• Report to be published on private side of CCQTA

website (members only)

– Report to include an open source model based on all data

– Some members funding additional internal optimized fitting

of their own data

3. TVP/RVP (True/Total Vapor Pressure , Reid Vapor Pressure)

Progress to Date

– Dataset showing bias in vapor pressure test results based on

sampling methods.

Conventional bottle vs.

Evacuated cylinder vs.

Floating piston cylinder

– Dataset showing bias between Legacy D323 results and

D6377 results for volatile crude oils.

– Widespread adoption of D6377 for accurate vapor pressure

measurement. Diluent pending.

– ASTM D7975 published Jan 2015 (“Field” VP Tester)

– ASTM D8003 published June 2015 (HPLIS Method)

– ASTM D8009 published Dec 2015 (MPC Practice)

TVP/RVP

Work pending

– Development of D7975 operating FAQ

– AITF drafting paper on EOS vapor pressure

based on HPLIS (D8003) vs. D6377

measurements.

– Draft “Best Practice” white paper to

summarize findings and recommendations.

Useful for Equalization, New Contracts,

Referee methods/Arbitration, Technical

Studies

Estimated project completion Dec 2016

4. H2S PVT Hydrogen Sulfide Pressure Vapor Temperature (Relationship)

Progress to Date

– Originally set out to build a standardized predictive

tool to estimate H2S in the vapor phase based on

known accurate liquid phase measurements .

Predictive modeling based on liquid phase was not

feasible.

– Updated objectives to develop a field measurement

tester that can be used to assess H2S evolution risk.

• Developed prototype field tester. Initial prototype too large

and complex for field deployment.

(Single phase sampling protocol, sealed vapor expansion chamber)

• Initiated development of a miniaturized version of field

prototype.

H2S PVT

Field Tester Requirements

– Targeting a replacement for ASTM D5705 for use

specifically with crude oils/condensates.

– Direct Measure H2S in vapor space under different

conditions (V/L ratio, temperature).

– Must be portable and easy to use (12VDC-Tailgate).

– Must have a wide operating range.

• 1 to 20000 ppm (2%)

– Must be robust for field operability.

– Must be simplistic in design to minimize cost.

H2S PVT

Field Tester Uses

– Provide standardized method for transportation

regulators (TC), EH&S, etc...

• Ability to clearly define test conditions with fit for

purpose test.

– Evaluation of scavenger dosing requirements

• Direct scavenger injection and vapor testing

• Test, dose, retest…

– Generation of H2S evolution with V/L ratio

• Test H2S at multiple V/L ratios to develop evolution

curve with car/truck/tank outage conditions.

• Two version (field and lab)

Field Tester Development

Sample Expansion/Gas Evolution to be Fully Automated

• Sample introduction

• Fill/Purge cycles

• Heating/Agitation

• V/L ratios

H2S PVT

Proposed Analysis System

H2S Vapor Field Tester

Milestones

6 Months

(Mar 2016)

Evaluation of separation and detection

technologies and success potential.

Short list of two technologies.

12 Months

(Sept 2016)

Progress evaluation and decision on project

continuation.

18 Months

(Mar 2017)

Final decisions on technologies, functions and

layout.

24 Months

(Sept 2017)

Complete 5 prototype units for field evaluation.

Draft ASTM Method.

5. Crude Oil Flammability

Phase 1:

– Evaluate suitable test methods using a small subset of

samples ranging from light condensate to “railbit”

Phase 2:

– gain a better understanding of flammable behaviours of

diluted bitumen.

Part 1: Evaluate the ignition potential of various

diluent/bitumen blends to identify a potential threshold for

diluent blend volumes as it applies to the flammability of the

dilbit.

Part 2: Investigate immediate ignition (flash) versus

sustained combustion

Phase 2

Part 1: Flashpoint vs. Diluent Content

– 5 blends of each of 4 commonly used

diluents with raw undiluted bitumen

– Identify potential threshold for diluent blend

volumes as applied to flammability of dilbit

Part 2: Sustained Combustion

– Evaluate the self-extinguish and/or self

combustion properties of dilbit blends in a

static pool fire scenario.

– 2 diluents

– 3 blend concentrations at 4 temperatures

SLD(light diluent)/Bitumen

Blend Properties

Blend 0.5 Mass% 1 Mass% 3 Mass% 5 Mass% 10 Mass%

Mass %

Diluent 0.61 1.09 3.01 5.01 10.01

Density @

15°C (kg/m3) 1010 1008 998.8 990.0 967.5

Viscosity @

20°C (mm2/s

(cSt)

338930 321248 88553 28854 3651

IBP (°C) - GC

merge 95.5 37 23.5 22.5 0.5

Flashpoint

(°C) 106 62 39 27 2

CPM(heavy diluent)/Bitumen

Blend Properties

Blend 0.5 Mass% 1 Mass% 3 Mass% 5 Mass% 10 Mass%

Mass %

Diluent 0.56 0.99 3.00 5.04 10.01

Density @

15°C (kg/m3) 1011 1009 1003 997.2 982.4

Viscosity @

20°C (mm2/s

(cSt))

444989 324129 141478 66352 11309

IBP (°C) - GC

merge - - - - -

Flashpoint

(°C) >120 97 66 46 26

Flash Points

Threshold for classification as a flammable liquid: flash point ≤ 60°C

Mass % diluent required to cross threshold for a Class 3, PG III

flammable liquid…

0

20

40

60

80

100

120

0 2 4 6 8 10 12

Fla

sh

Po

int

(°C

)

Mass% Diluent

Flash Point vs. Mass % Diluent

SLD Blends

CPM Blends

Flammable Liquid

SLD: between 1-3 mass%

CPM: between 3-5 mass%

Burn Pan (at AITF)

SLD/Bitumen Blend Properties

Blend 10 Vol.% 20 Vol.% 30 Vol.%

Density @ 15°C (kg/m3) 981.5 949.4 916.1

Flashpoint (°C) 22 -11 <-37

Carbon (mass%) 83.00 82.58 81.37

Hydrogen (mass%) 11.92 12.19 12.29

C/H ratio 6.96 6.77 6.62

SLD/Bitumen Blend Flash Points Part 1&2

-60

-40

-20

0

20

40

60

80

100

120

0 5 10 15 20 25

Fla

sh

Po

int

(°C

)

Mass % Diluent

Part 1

Part 2

Flammable Liquid

10 Vol.% SLD/Bitumen Blend Video

30 Vol.% SLD Blend Video

Bases of Development of the New (industry shared)

Method Petroleum containing asphaltenes

:

• Deliberately precipitate asphaltenes by

having excess non-solvent oil in a mixture of

Aromatic + Paraffinic

• Adjusting the amount of solvent oil in the

mixture of Aromatic + Paraffinic solvents to

dissolve asphaltenes

6. Crude Oil Compatibility Method

WCS as received

1g WCS + (9mL H + 4.4mL T) 1g WCS + (9mL H + 4.3mL T)

1g WCS + (9mL H + 1mL T)

Crude Oil Compatibility Method (example observations)

Crude Oil Compatibility Method

Status

– Preliminary method has been developed and

is being testing/validated in at Maxxam

Analytics

– 42 members! participated in the project

meeting on Tuesday.

Target completion date – December 2016

• Firm up the procedures A and B (repeatability (WCS, LA 10 X)

• Firm up SOP for posting on CCQTA website

• Apply the methodology to crudes with asphaltenes:

– different crudes with different properties (10 crudes)

– Heavy oils/bitumen

– Waxy crudes

– Processed samples – Partially upgraded

• Initiate Round Robin (CanmetENERGY, AITF, U of A)

• Apply the method to crudes with no/little asphaltenes

– Crudes with asphaltenes < 1wt%

– Processed stream , Condensate/diluents

Crude Oil Compatibility Method

Path forward

7. Single Phase Sampling Program

“Manual Piston Cylinder”

Initiated from TVP/RVP project in 2014

• Initially recommended the VP Field tester as simply a

means to capture a single-phase sample and transport it to

the laboratory for D6377 or D8003.

• Found too many dead legs (gauges, lines, etc…) that could

trap previous sample material and contaminate the

composition of the next sample.

• Needed a simplified version that was functionally

equivalent to the D3700 Floating Piston Cylinder and

suitable for D6377 and D8003.

Manual Piston Cylinder

Road to a Published Standard – Drafted as an annex to D3700 in February 2015

– Balloted in ASTM SC D02.H in March 2015 (1 negative)

– Ballot withdrawn and the practice was revised as a standalone.

– Concurrently balloted SC D02.H and D02 Main (9 negatives

(jurisdiction issues between D02.H and D02.02)

– Ballot withdrawn and jurisdiction transferred to D02.02 which is

also joint with API COMQ.

– ASTM/API working group formed and revised the practice to

ensure it is technically sound.

– Passed concurrent SC D02.02 and D02 Main ballot in October

2015.

Published December 2015

8. VLE Gas Composition Screening Method

Synopsis – Utilizes the MPC as an expansion chamber to create a known

vapor-liquid-equilibrium condition.

– Equilibrium vapor is transferred isobarically to a standard

refinery gas analyzer and the composition determined.

– Provides hydrocarbon and fixed gas (CO, CO2, H2, H2S, N2, O2)

composition of the vapor phase.

– Intended for use in screening the bulk of gaseous components

present in the vapor that may contribute to vapor pressure, but not

identified by D8003.

– Gases may originate from production, or may be the result of pad

gas, or other gas addition during handling or transport.

Status

– ASTM Standard Practice has been drafted.

– Intended to submit to both D02.08 and D02.02

(API COMQ) for review and comment prior to

submitting for ballot.

– Potential for ballot in 2016/2017

VLE Gas Composition Screening Method

9. Analysis of TIOM (Toluene Insoluble Organic Material)

Synopsis – TIOM’s have been identified as an issue in the CCQTA since 2005.

– First detected in NGL Fractionator reboilers and subsequently

reported in condensate deposits and refinery exchangers.

– High molecular weight carbon based material, often mistaken for

asphaltenes.

– TIOM’s have little/no functional chemistry and are not toluene

soluble.

– Previous work on TIOM with 4 CCQTA projects led to the

development of a Deposit Analysis Protocol

– Recently acquired some TIOM materials from a gas plant which are

to be analyzed

• Sample believed to be closer to source!

10.Properties of Thermally Processed Material

Synopsis

– AI-EES and Canmet Energy have received funding for

studying quality issue associated with partially

upgraded bitumens.

– Step 1 is to review the role of olefins/di olefins on

refinery fouling

– Additional work will look at the impact of olefins on

product quality/plant operation.

– CCQTA’s role is to function as technical resource

(particularly a liason for refiners) for this work.

• CCQTA is not asked to provide any funding for this work.

CCQTA Contact Information

President

Randy Segato (Suncor) • Ph: 403.296.4561

• Email: president@ccqta.com

Technical Director

Andre Lemieux (Omnicon)

• Ph: 780.975.3026

• E-mail: technical.director@cctqa.com

Secretary

Dave Murray (Omnicon)

• Ph: 780.218.3759

• E-mail: secretary@ccqta.com

…End