SRP EVOLUTION FOR VACA MUERTA'S LOW GAS/OIL RATIO WELLS

© 2018 Chevron Corporation
Loma Campana Artificial Lift
Overview
November 2, 2022

2
• Chevron Argentina
unconventional portfolio
• Loma Campana
Production History
• AL Playbook
• Well Life Cycle
• Challenges, lessons
learned, and next steps
• Pumping Units
• Rod Lock
• Pump design
Loma Campana AL Overview
Discussion Topics
• Loma Campana AL selection depends mainly on GOR
– GOR<1700 scf/stb: Sucker Rod Pump
– 1700<GOR<5600: Gas Lift
– GOR>5600: Plunger Lift
• Longer lateral and aggressive draw down brought new AL
Challenges for SRP
– ESP non economic for short period of time.
– 192 inches pumpjack seemed too short for long length horizontal wells
– Hydraulic pumping units offer the most flexible choice for 6 wells PAD
• Challenges to AL Selection and Optimization
– High decline rates
– Frac interferences
– Flamping Wells
Key Messages

3
Chevron Argentina unconventional portfolio

4
Loma Campana – Current
development
Loma Campana East – main development area
Loma Campana development
highlights:
§ Discovery well - 2010 by YPF.
§ Initially developed thru vertical
wells. (+ poor results first hz).
§ CVX entered JV dec 2013.
§ Shift to hz wells started 2Q 2015
in the EAST (best performance).
4Q 2015 last verticals.
§ 1500 m (4900ft) lateral length
standard shifted to 2500 m
(8200ft) in 2018.

5
Loma Campana overview – Field
production activity
Total Field Production by well type [boepd]
Horizontal wells represent
22% of total well count but
contribute with 82% of total
field production Total Prod ~ 50.0MBOED
Oil ~ 41.0MBOPD
Gas ~ 54.0MMSCFD
Average lateral length per year [m]
Std lat length
2022 = 2500m
2023 = 3400m

6
Loma Campana Fluid Properties
Loma Campana Oil:
– API: 40 to 45
– GOR: 550 to 20000
scf/stb
– Viscosity: 0.3 to 0.8 cP
– Paraffin: 5% to 20%

7
Loma Campana Artificial Lift Overview
South West
GOR>5600
Centre
5600>GOR>1700
West
20000>GOR>5600
East
GOR<1700
Bombeo Mecánico
Plunger Lift
Surgente Casing
Surgente Tubing
q - Casing Flowing Wells: 71
q - Tubing Flowing Wells: 75
q - SRP: 213
q - Plunger Lift: 281
q - Gas Lift: 11
q - Horizontal Wells: 245
q - Vertical Wells: 408

8
Full Field Development
q 480 SRP
q 250 Gas Lift
q 110 Plunger Lift

9
Well Evolution
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
-
200
400
600
800
1,000
1,200
0 2 4 6 8 10 12 14 16 18 20 22 24
BHP
(psi)
qo
(bpd)
Months
Qo BHP (PSI)
Casing Flowing Tubing Flowing SRP

10
Plug set with
Slick Line
Well Evolution
Production engineers: Federico Fernández Biscay, Guadalupe Moll, Ignacio Cuneo
Casing Flowing
(1200 – 600 bpd
8 -12 months)
5” Casing
Arrow Set Packer
Shear Out
(Set with Wire Line)
Anchor
(9000ft)
Perforated
Niple
1 ¼” tbg for
gas
separation
Shear Out
open
Tubing Flowing
(600 – 250 bpd
4 – 6 months)
SRP
(250 – 3 bpd)
z

11
Opex. Failure Related Costs
Failure Rate:
2019: 0.54
2022: 0.29
Pulling (kusd/Job) 57
Materials (kusd/Job) 14
SubTotal (kusd/well/year) 38
Sucker Rod Pump Gas Lift
Slick Line kusd/yr 4.5
Maintenance kusd/yr 5
• Challenges to improve FR were:
• Avoid hot oil for gas locked pumps by the use of long stroke
untits, anti gas lock pumps and variable slippage or
perforated barrel pumps.
• Corrosion resistant rod design: UHS => API D => Alpha CS?
• 2 7/8” tbg instead of 2 3/8” to avoid the use of 7/8” Slim hole
couplings.
• Gas Lift pilot started March 2019
• Main Challenges include
• Higher WHP than expected due to production
pipe constraint
• Liquid after gas Lift pipe pigging
• Operations lack of experiance

12
Challenges, Lessons Learned, Next Steps
q Challenges
ØGas Lock
ØFlamping Wells (SRP problems as Gas Lock after natural flowing)
ØHigh Production Rate in 5” Casing with long stroke SRP or ESP
ØFlow Assurance without Heated Tracing
q Lessons Learned
ØDouble seat pump or sand packer for lower pulling costs
ØCorrosion resistant rod design
ØRod Lock for Frac Interferences
ØAntilock Pump Design
qNext Steps for SRP
ØImprove Run Life (Chemical treatment for Corrosion, paraffin, and Scale)
ØIncrease SRP Production Rate
ØNew surface equipment for unexpected frac interferences

13
Increase Production Rate
Until May 2020
1500 m (4900ft) lateral length wells, ALS for 35 cmpd (220 bpd):
Ø640-912 Units
ØAPID rods (4142)
Ø20-150-RWABC-24-5 pumps
Ø2 7/8”- 2 3/8” tbg
ØGas separator
From June 2020
2500 m (8200ft) lateral length wells, ALS for 70 cmpd (440 bpd):
Ø912 Pumpjacks, RF950 Rotaflex or 336 BHA
ØAlpha Rod HS or Norris 97
Ø25-175-RWABC-36-5 or 25-200-RWABC-24-5 pumps
Ø2 7/8” tbg
ØGas Separator, Anti gas lock travelling valve, Variable Slippage Pump

14
Need of Long Stroke Units
40
15
35
0
10
20
30
40
50
60
2019 Tbg flowing => SRP 2020 Tbg flowing => SRP
Lateral Length Change
1500 m (4900ft) lateral length wells
2500 m (8200ft) lateral length wells, ALS for 70 cmpd (440 bpd)

15
Frac Interference Early Design
Double Ram BOP For SRP 10 Kpsi - Rod Lock
Production Engineer: Fernando Villagra
10K ROD LOCK
3K Compac-T

16
Frac Interference Design
Double +Simple Ram BOP For SRP 10 Kpsi -
Rod Lock

17
Frac Interference Design
Rod Lock Evolution

18
Rotaflex 288
q Installed at 32 feet from a pumpjack and 64 feet from the other Rotaflex leaving
it retrieved before running ALS.

19
Hydraulic Pumping Units
Advantages:
q half a day for installation vs 2 days for Mark II Pumpjack
q pulling Jobs are possible in a well between two HPUs installed at 32 feet
Disadvantages:
qenergy consumption without counterbalance

20
Hydraulic Pumping Units
Models used:
qSerinpet 30-220 (stuffing box and winds needed)
qCamlift 40-192 (stuffing box needed, no winds)
qCamlift 30-144 (stuffing box needed, no winds)
qKudu 40-336 (no stuffing box, no winds)

21
Anti gas lock travelling valve
qNew design: corrosion and sand proof.
Advantages:
Ø No gas separator needed
Ø Above 750psi backpressure improving pump performance with low fluid level,
without AG was not possible because travelling valve would keep closed.
Disadvantage:
ØNot successful in some Wells because of longer space between valves.

22
Variable Slippage Pumps
Options
ØHarbison Fischer (Appergy): standard
section + gradual i.d. tapered section,
full brass, slotted plunger can be
used.
ØPecom: standard brass barrel +
conical Steel barrel, no slotted
plunger allowed.
ØWeatherford “triple barrel”: standard
barrel + 2 feet recirculation extension,
no slotted plunger allowed.

23
Perforated Barrel Pump
Production Engineers: Luciano Bossotto, Gregorio Raslawsky, Gonzalo Pérez Cometo. Production leader: Guillermo Vega. Vendor Specialist: Rubén Quintana
Advantages:
-Slotted plunger.
-Perforations can be made in different
distances for each well.
-Success clue after Steel Barrels corrosion
Disadvantages:
-Fluid circulation between tbg and pump.
Testing:
640-305-168 Mark II
Pumpjack
30-220 Hydraulic pumping
unit

24
640-305-168 Mark II Pumpjack

25
1,6 feet over-
displacement
1 foot from first
to sixth
perforation
Bottom
dead
center
9 feet
effective
displacement
vs
11,6 feet

26
Production Engineers: Matías Urio, Rosmary Duran
Carta de Fondo
20 40 60 80 100 120 140 160 180 200
0
-3000
-2000
-1000
0
1000
2000
-4000
3000

27
Production Engineers: Matías Urio, Rosmary Duran

28
Questions

SRP EVOLUTION FOR VACA MUERTA'S LOW GAS/OIL RATIO WELLS

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