1. Value Proposition of Polyketone Liners & Continuous Rod in Deviated Wells

2. Deviated Rod Pumped Failure Methods
Abrasive Wear
Rod on tubing wear
Deviation
Buckling
Enhanced by presence of solids
Corrosive Wear
Chemical reaction on surface of tubing
Corroded material worn away, allowing for corrosion to attack again
12/10/2018

3. Potential Benefits of Thermoplastic Liners
Prevents rod on tubing contact, eliminating steel on steel wear
Does not allow corrosive fluids to continuously erode tubing
Protects tubing from exposure to abrasive solids
Holiday-free to prevent localized corrosion attack
12/10/2018

4. Thermoplastic Liner Resin Options
General Specifications
Material Type
Max Temp.
Dimensions
H2S
CO2
Cost
HDPE
140° F
2 3/8" - 4 1/2" 2%
10% $
HDPE - Modified
210° F $$
POK - Modified
240° F 5%
20%
PPS - Modified
340° F
$$$$
PEEK
500° F
$$$$$
12/10/2018

5. Polyolefin Ketone Resin (POK)
Unique engineering plastic with a carbon-only backbone
Highly crystalline with a compact crystal structure
Stable at high temperatures
Has excellent abrasion/chemical/fuel resistance
Gas barrier properties
Physical and chemical properties make the resin well suited for downhole applications
12/10/2018

6. Resin Working Temperature vs. Cost
12/10/2018

7. Potential Benefits of Continuous Rod
Side Load Distributed over Entire String, Not on Coupling Alone
No Reduced Flow Area around Couplings
Reduce breakout of corrosive elements due to turbulent flow around couplings and rod guides
Potentially increase production with less flow restriction in the tubing
Eliminate Care & Handling Failures and Improper Makeup
Fast, Easy Installation
12/10/2018

8. Superior Toughness – Charpy Impact
Testing Performed at 20˚C
12/10/2018

9. Trial Wells: Continuous Rod in Permian Basin
Well #1, installed 1/30/2017 with taper design 1” and 7/8”
Well #2, installed 2/3/2017 with taper design 1” and 7/8”
Well #3, installed 2/7/2017 with taper design 1” and 7/8”
Well #4, installed 4/11/2017 with taper design 1” and 7/8”
Well #5, installed 4/13/2017 with taper design 1” and 7/8”
Well #6, installed 7/21/2017 with design 7/8”
12/10/2018

10. Trial Wells: Previous Failures and Run Times
Failures primarily due to wear:
Side Loading
Accelerated by corrosion issues
Tubing failures
Field-Wide MTBF before Continuous Rod:
180 Days
12/10/2018

11. Current Run Times
12/10/2018

12. Trial Well #1 – Cost Analysis—5400 ft Well
Base rod workover cost $15,000
Rod Cost per Foot (mix) $4.38
Oil Price per Barrel $60
Oil Production Rate (BPD) 30
Lifting Cost per Barrel $10
Annual Production Decline Rate 10%
Downtime per Failure (days) 21
Previous MTBF (months) 6
Failures Saved to Date 1.88
Delayed Production Revenue per Failure $30,500
Total Savings per Failure $45,500
Total Savings Less Investment to Date $86,000
ROI to Date 262
12/10/2018

13. Continuous Rod Installation
12/10/2018

14. Permian Basin Trial Parameters
Operator began experimenting with a mixture of continuous rod and thermoplastic liners on very high failure frequency wells Q4 2016
Initial pilot consisted of 6 wells, with various configurations
Longest running wells used conventional sucker rod with thermoplastic liners
More recent installations included both thermoplastic liners and continuous rod
Failure frequency on the six wells prior to trial was failures/well/year
12/10/2018

15. Trial Wells Six well pilot in South Delaware Basin Asset
Trial Well #1 installed 9/29/2016 with mixture of PPS and POK
Trial Well #2 installed 11/17/2016 with conventional stick rod
Trial Well #3 installed 12/8/2016
Trial Well #4 installed 2/14/2017
Trial Well #5 installed 3/23/2017
Trial Well #6 installed 7/13/2017
Failures primarily due to wear
Side loads near 200 lbs
Likely due to buckling in many instances
Accelerated by mild corrosion
12/10/2018

16. Case Study 1 – Trial Well #2
Delaware Basin, Reeves County, Texas
MTBF of ~60 days on tubing prior to installing thermoplastic liner
POK liner installed from 4000ft to 10,000ft
Bare tubing ran above 4000ft
Run in the hole with conventional rods
Currently operating 568 days without tubing failure (was down 32 days due to rod failure)
12/10/2018

17. Case Study 1 – Cost Analysis
Base tubing workover cost $60,000
Liner Cost per Foot $5.73
Oil Price per Barrel $60
Oil Production Rate (BPD) 30
Lifting Cost per Barrel $10
Annual Production Decline Rate 10%
Downtime per Failure (days) 21
Previous MTBF (months) 2
Failures Saved to Date 8.34
Delayed Production Revenue per Failure $30,400
Total Savings per Failure $90,400
Total Savings Less Investment to Date $754,000
ROI to Date 2092
12/10/2018

18. Case Study 1 – Cumulative Operating Profit
* Annual Decline Rate = 10%, Annual Discount Rate = 7%
12/10/2018

19. Case Study 2 – Trial Well #1
Delaware Basin, Reeves County, Texas
MTBF of 6 months on tubing prior to installing thermoplastic liner
POK liner installed from surface to 6,500ft
PPS liner installed from 6,500ft to 10,000ft
Run in the hole with continuous rods
Currently operating for 639 days (was down 10 days to replace 25 jts of tubing)
12/10/2018

20. Case Study 2 – Cost Analysis
Base tubing workover cost $60,000
Liner Cost per Foot (blended) $7.57
Initial Continuous Rod Investment $20,000
Oil Price per Barrel $60
Oil Production Rate (BPD) 30
Lifting Cost per Barrel $10
Annual Production Decline Rate 10%
Downtime per Failure (days) 21
Previous MTBF (months) 6
Failures Saved to Date 2.5
Delayed Production Revenue per Failure $30,200
Total Savings per Failure $90,200
Total Savings Less Investment to Date $212,000
ROI to Date 159
12/10/2018

21. Case Study 2 – Cumulative Operating Profit
* Annual Decline Rate = 10%, Annual Discount Rate = 7%
12/10/2018

22. Case Study 2 – ROI Sensitivity
All variables remain constant except run-time
ROI after 30 additional days = 177
ROI after 90 additional days = 212
ROI after 180 additional days = 264
ROI after 365 additional days = 371
All variables remain constant except oil price
ROI at $50/bbl = 144
ROI at $65/bbl = 166
ROI at $80/bbl = 189
12/10/2018

23. Trial Results to Date
Early results on initial 6 well pilot indicate a decrease in failures from failures/well/year to ~0.25 failures/well/year
At this point, it is too early to tell whether continuous rod with lined tubing will be more effective than lined tubing alone, but the cost of continuous rod is comparable with conventional rod so investment is minimal
Reducing failure rate by half would allow project to break even, which has already been accomplished in first 6 wells
Current average run time on 6 well pilot is 522 days, which would equate to .70 failures/well/year if all 6 wells failed today
Current savings of $293,000 per well and an average ROI of 487
12/10/2018

24. Current Field Performance
Over 30 wells with LF115 lined tubing installed in the Permian and Rockies
Longest runtimes have exceeded 500 days
Numerous wells have extended MTBF by two to three times
Over two years of run time on oldest LF170 installations
30+ continuous rod installations to date, with over 12 months run time on the oldest installation
Four wells with continuous rod and lined tubing with pumps in horizontal section of wellbore
12/10/2018

25. Lined Tubing Field Performance
Install Date
Location
Product
Previous MTBF
Current Run Time
8/29/2016
Midland County - Permian
LF115 & LF170
180 Days
650+ Days
9/29/2016
Reeves County - Permian
LF115
600+ Days
11/17/2016
Reeves County – Permian
90 Days
500+ Days
2/8/2017
Ward County - Permian
450+ Days
4/1/2017
Altamont, Utah
200 Days
400+ Days
One Permian operator has extended decreased failure rate from 2.95 failures/well/year to 0.25 failures/well/year
by using LF115 liners in combination with continuous rod.
12/10/2018

26. Sample ROI Calculation (5,000 ft well)
1 well wells
Failures Saved per Year
Days production saved per year days days
Production Avg. 20 bbl/d bbl 10,000 bbl
Workover costs $15,000 $1,500,000
Delayed Production Revenue $4,500 $450,000
Total Savings per Failure $19,500 $1,950,000
Total Savings per Year $29,791 $2,979,100
ROI to Date %
12/10/2018 26

27. Field-wide Cost of Failures
12/10/2018

28. Other Ongoing Trials
Continuous rod run in Reeves County, TX to a depth of 11,200 ft
Continuous rod and Polyketone Thermoplastic Liner ran in two wells where pump is landed at 90˚ and 7000’ MD in Irion County, TX
Polyketone liner being run in SWD wells in same basin with OXY
Around 40+ wells now using Polyketone Thermoplastic Liner with operators in Permian Basin, Delaware Basin, and Uintah Basin
30+ continuous rod installations with LPS continuous rod since January, 2017
12/10/2018

29. Considerations to Improve ROI
Investment cost for thermoplastic liner can be reduced by lining used tubulars
Lost production value is more impactful for wells with high production or long lead times for workovers
Continuous rod workover typically are quicker than conventional stick rod, which can reduce workover cost
Combination of Coiled Rod & Thermoplastic Liners have the greatest impact on ROI
For most applications, thermoplastic liner will break even before the first workover is avoided
Continuous rod can have a positive ROI by increasing MTBF by as little as 30 days
12/10/2018

30. Questions? Zach Stearman – Artificial Lift Applications Engineer
C: (405)
L.J. Guillotte - President
C: (281)
O: (281)
12/10/2018