This document summarizes a case study comparing the use of potassium formatebrine and water-based drilling fluids to the traditional oil-based mud for drilling performance. The study found that using potassium formatebrine drilling fluid improved rate of penetration by over 30%, reduced drilling time by 10 days, and lowered total well costs by 12% compared to oil-based mud. However, formatebrine fluids may have limitations due to increased drag and restricted well length. Overall, the case study demonstrates the benefits of formatebrine drilling fluids for improved drilling efficiency and cost savings.

1. Using formatebrine and water based fluids drilling fluids to improve drilling performance
A case study in Pipestone
Ryan Siemens and Elie MeyerDrilling EngineersCalgary | September 16 | 2014
Copyright © 2014 Encana Corporation. All Rights Reserved.No part of this document may be reproduced or transmitted in any form or by anymeans, electronic, mechanical, photocopying, recording, or otherwise, without prior written permission of Encana Corporation.

2. This presentation of Encana Corporation (“Encana”) on using formatebrine and water based fluids drilling fluids to improve drilling performance (this “Presentation”) is for general information purposes only.
The contents of this Presentation are not intended to be, and may not be relied upon by any person, company, trust, partnership or other entity (“Person”) for the purpose of making any investment decision, including without limitation, any decision to purchase, hold or sell any securities of Encana or any of its affiliates.
Encana expressly disclaims, and makes no representation or warranty, express or implied, with respect to any of the information made available in this Presentation where such information is used by any Person for the purposes of making any investment decision as prohibited by this disclaimer, and none of Encana and its affiliates, and their respective officers, directors, employees, agents, advisors and contractors shall have any liability to any Person in respect thereof.
Encana does not warrant the quality, accuracy or completeness of any information provided in this Presentation and such information is provided as is, without any warranty or condition of any kind. Neither Encana nor any other person associated with the creation of this Presentation or its contents shall be liable or responsible to any Person for any harm, loss or damage that may arise in connection with the use of the Presentation or any of its contents, including without limitation, any indirect, third party, or consequential damages.
Any Person relying on the information contained in this Presentation does so at its own risk and without any recourse against Encana or any of their respective officers, directors, employees, agents and advisors. Encana expressly disclaims any representations or warranties with respect to any information contained in this Presentation.
DISCLAIMER
2

3. Agenda
•
Pipestone well design
•
2013 Invert performance summary
•
Introduction to brine fluids
•
Why use potassium formatebrine
•
Special operational considerations
•
Design and results of field trial
•
Potassium formate1.0 performance
•
Potassium formate2.0 performance
•
Cost of utilization
•
Challenges and limitations

4. 
Sour service pipe design

Halfway 18 % -Doig11% -Montney 8%

Mud 90/10 invert (oil-based mud) for hole stability and lubricity

LWD resistivity utilized to geosteer
244.5mm J-55 Surface Casing
~600m
177.8mm L-80 Intermediate Casing
Set at ~70° (Surface to ~2550m)
TVD 2400-2700 m
222mm intermediate hole
Liner Hanger Packer Set at ~35°
2200m leg
~41 days Spud to RR
Pipestone well design
Horizontal open hole set packers

5. 2013 Invert performance summary

6. Introduction to brine fluids
•
Salt
–
Ionic compounds that result from the neutralization reaction of an acid and a base
•
Brine
–
Dissolved solution of salts, most commonly solvent is water
•
pH
–
The ratio of hydroxide ions to hydronium ions determines a solution pH
•
FormateBrine
–
Formatebrines are the aqueous solutions of the alkalimetalsalts of formic acid. These salts are readily soluble in water, yielding high-density brines
•
Sodium formate
•
Potassium formate
•
Cesium formate

7. What is the brine advantage?
Solids (%)
Yield Pt.
(Pa)
Plastic Vis. (mPa.s)
Thermal Cap.
(J/g.°C)
ThermalCond. (W/m.K)
Water/brine
0-1
0 -1
1 -2
0.6
4.2
Oil/invert
10-18
4 -8
10 -40
0.2
2

8. Why potassium formate brines? Corrosion & lubricity

9. Halide brine corrosion damageW. Canadian examples

10. Corrosion testing results

11. Formation compatibility testing
distilled water –potassium formate –calcium bromide –calcium chloride

12. Solids control setupBead recovery unit & davelintank
Fluid
Solids
Beads

13. Temperature limitation

14. Temperature limitationResults

15. Potassium formate trial pad

16. Potassium formate parametersRate of penetration, length of runs
13 m/hr. vs. 24 m/hr.
236 m vs. 850 m

17. Potassium formate parametersStandpipe pressure
~6000 kPa
25%

18. Potassium formate parametersRotary torque
Increase bead concentration

19. Potassium formate trial pad
8-11 days

20. Potassium formate trial padNormalized lateral meterage
4-7 days
~40%

21. Potassium formate 1.0 performance2014 Q2 time depth vs. 2013 invert

22. Potassium formate 1.0 performance2014 Q2 time depth vs. 2013 invert
10 days
~30%

23. Potassium formate 1.0 performance2014 Q2 time depth vs. 2013 invert –normalized lateral

24. Potassium formate 1.0 performance2014 Q2 time depth vs. 2013 invert –normalized lateral
10 days
~40%

25. Potassium formate 2.0 performanceFloc/formatevs. invert in intermediate section
2.5 days
~30%

26. But isn’t formate too expensive? Comparing fluid cost
125 %
250 %
320 %
360 %
100 %

27. Cost of serviceMud cost & total service cost
•
tank farm
•
bead unit
•
davlintank
•
agitator
•
Invert surcharge
17 %
27 %

28. Total drilling well costInvert vs. formate 2013 -2014
11 %
27 %

29. Total drilling well costLaterals greater than 2000 m invert vs. formate
27 %

30. Total drilling well costFormatein lateral vs. floc/formate in intermediate
12 %

31. Challenges & limitations
Lubricity
Increased drag
Limitation to well length
Switching to invert at toe
Using invert for liner install

32. Key Contributors & References
Encana drilling team
–
Nathan Gullacher
–
Don Poffenroth
–
James Highet
–
Ryan Siemens
–
Bill Mulloy
–
Elie Meyer
–
Lois McCorriston
External
–
Nick Legacy (DMK)
–
Chris Kostiuk(DMK)
–
Kelly Burake (DMK)
–
Wade Wondrasek (Paramount)
Formate Technical Manual (Cabot)
PertrofromTechnical Manual (ADDCON)
SPE 27143 –105733 –145562

33. BACKUP SLIDES

34. Questions?