Multipay Well Completion in Argentina: A Versatile Pinpoint Completion Technology Applied through Several Conventional, Tight, and Shale Reservoirs

SPE-185478-MS

Multipay Well Completion in Argentina: A

Versatile Pinpoint Completion Technology

Applied Through Several Conventional, Tight,

and Shale Reservoirs

Juan C. Bonapace, Halliburton; Federico Sorenson, Pan American Energy; Pablo Forni, Grupo Capsa; Fernando Barbalace, Pampa Energía; and Federico Kovalenko, Halliburton

2017 Halliburton. All Rights Reserved.

Agenda

� Introduction

� Completion techniques in Argentina

� Hydrajet perforating annular-path treatment placement + proppant plug

diversion (HPAP-PPD)

� Argentina historical evolution, reservoirs and formation applied, statistics

� Case histories

� Conventional oil (CO), conventional gas (CG), tight gas (TG), and shale oil

(SO)

� Discussions (looking forward)

� Conclusions

Slide 2

SPE-185478-MS • Multipay Well Completion in Argentina: A Versatile Pinpoint Completion Technology Applied

Through Several Conventional, Tight, and Shale Reservoirs • Juan Carlos Bonapace

Slide 3

Introduction

This paper documents the experiences, lessons learned, and results

achieved using a versatile pinpoint completion technique for several

types of reservoirs in Argentina.

Hydraulic Fracture in Argentina:

• Oil and gas reservoir since 1960

• Conventional, tight, and shale

• Depth: 300 to 4500 m• Bottomhole temperature: 100 to 350°F• Reservoir pressure: subnormal to overpressure

• Formation permeability: high, medium, low, and ultralow

permeability

• Complex formation type, various reservoir problems

• Multilayer reservoir and multitarget wells

• Oil- and water-based systems, alcohol-water mixtures, and foams



Slide 4

Completions Techniques in Argentina



McDaniel (2005): documents a scorecard to identify the best completion option based

on the reservoir (or well) characteristics and limitations (or benefits) of the completion

technique.

Argentina Reservoirs: present multilayer reservoirs (small lenticular lenses or

multitarget wells).

Completion Methodologies:

� Workover unit operations

� Tubing string with a set of packers and mechanical plugs

� Tubing string with a set of straddle packer systems

� Rigless operations (plug-and-perf)� Through casing, applying limited-entry perforating, isolating by bridge plugs

� Through casing, applying limited-entry perforating, isolating by sand plugs

Slide 5

Pinpoint Technique (HPAP-PPD)



HPAP-PPD

USA: Introduced in 2004 in vertical wells (Surjaatmadja et al. 2005) and soon

also applied in horizontal wells (McDaniel et al. 2006).

Argentina: Introduced in 2006 only in vertical wells (Folmer et al. 2008; Favoretti

and Ferrer 2008; Forni 2008; Bonapace et al. 2009; Kovalenko 2009; Barbalace

et al. 2012; Forni et al. 2014, 2015; Bonapace 2016).

Slide 6


Reservoirs



Basin GSJ GSJ Neuquén Neuquén Neuquén Neuquén Neuquén

Formation Comodoro Rivadavia

Mina del Carmen

Lotena Lajas Los Molles Vaca Muerta Punta

Rosada

Reservoir fluid Oil Oil Oil Gas Gas Oil and gas Gas

Reservoir type Conventional Conventional Conventional Conventional Conventional/

tight Shale Tight

Depth (m) 1000 to 2250 2250 to 3000 1400 to 2000 1600 to 2400 2350 to 3200 2400 to 3000 3200 to 3900

BHT (°F) 120 to 190 190 to 230 135 to 165 145 to 180 180 to 220 185 to 215 225 to 255

Porosity (%) 12 to 18 14 to 19 12 to 17 8 to 12 6 to 12 2 to 9 4 to 12

Permeability (md)

10 to 50 5 to 25 10 to 45 0.2 to 0.65 0.08 to 0.2 0.00001 to

0.0001 0.001 to 0.01

Reservoir pressure (psi/ft)

0.28 to 0.35 0.37 to 0.40 0.32 to 0.38 0.23 to 0.35 0.35 to 0.65 0.75 to 0.90 0.55 to 0.7

Young’s modulus (Mpsi)

1.3 to 2.2 1.5 to 2.6 1.1 to 2.3 1.8 to 3.0 2.8 to 5.5 3.5 to 6.0 3.8 to 6.3

Table 1—Summary of the main characteristics for each formation.

Basin GSJ GSJ Neuquén Neuquén Neuquén Neuquén Neuquén

Formation Comodoro Rivadavia

Mina del Carmen

Lotena Lajas Los Molles Vaca Muerta Punta

Rosada

Reservoir fluid Oil Oil Oil Gas Gas Oil and gas Gas

Reservoir type Conventional Conventional Conventional Conventional Conventional/

tight Shale Tight

Depth (m) 1000 to 2250 2250 to 3000 1400 to 2000 1600 to 2400 2350 to 3200 2400 to 3000 3200 to 3900

BHT (°F) 120 to 190 190 to 230 135 to 165 145 to 180 180 to 220 185 to 215 225 to 255

Porosity (%) 12 to 18 14 to 19 12 to 17 8 to 12 6 to 12 2 to 9 4 to 12

Permeability (md)

10 to 50 5 to 25 10 to 45 0.2 to 0.65 0.08 to 0.2 0.00001 to

0.0001 0.001 to 0.01

Reservoir pressure (psi/ft)

0.28 to 0.35 0.37 to 0.40 0.32 to 0.38 0.23 to 0.35 0.35 to 0.65 0.75 to 0.90 0.55 to 0.7

Young’s modulus (Mpsi)

1.3 to 2.2 1.5 to 2.6 1.1 to 2.3 1.8 to 3.0 2.8 to 5.5 3.5 to 6.0 3.8 to 6.3

Table 1—Summary of the main characteristics for each formation.

Slide 7




Conventional oil

Conventional gas

Tight gas

Shale oil

Evolution and Statistics

Slide 8

Case Histories—Conventional Oil (CO)



First Step: “Breaking Paradigms”

• Adapting technology

• Modified casing types, set initial and

intermediate bridge plug

• Develop learning curve

• Rigup and rigdown, water and proppant

logistics

• Validate technology

• Verify location and quality of the perforations

• Improve times

• Achieve the target time and improve

completion times (offset wells)

• Evaluate production

• Higher initial production and stabilized

production compared to offset wells

Hydrajet perforation Gun perforation

Slide 9

Case Histories—Conventional Oil (CO)



Data/Type Reservoir Conventional Oil

Avg. fracture stages 9

Well geometry (in.) 5 1/2

Max. pressure (psi) 10,000

CT unit (injector) 60K

CT outer diameter (OD) (in.) 1 3/4

Hydrajet tool Old tool

BHA - N° hole 3

Working time (hours) 12

Fracture depth (m) 1050 to 2500

BHST (°F) 120 to 205

Fracture gradient (psi/ft) 0.53 to 0.85

Pump rate (bbl/min) 16 to 19

Wellhead pressure (psi) 1,100 to 4,300

Fracture fluid (gal/1,000 gal) Guar-borate (25)

Total well fluid (m3) 500

Total well proppant (lbm) 230,000

Type of proppant Sand - RCP - ISP

Type of mesh proppant 12/20, 16/30, 20/40

Hydraulic horsepower (HHP) 550 to 2,000

Table 2—Summary of primary characteristics

Slide 10

Case Histories—Conventional Gas (CG)



Confirming the Technology: “The Right Place”

• Continue validating technology

• Understanding the new technique, evaluating erosive perforations for the

stimulation and production phase, checking proppant flowback with this technology.

• Environmental applications

• Used in sensitive areas (urban/rural), minimizing intervention well times.

• Improving profitability of project

• Completion time reduced, decreased operational costs, improved initial production.

• Tested a new model completion (multitarget well)

• Decided to use this technique to stimulate three formations in a single well

intervention (30 fracture stages).

Slide 11

Case Histories—Conventional Gas (CG)










BHA - N° hole 3



BHST (°F) 120 to 205











Conventional Gas

9

5 1/2

10,000

60K

1 3/4

Old tool

3

12

1400 to 2800

135 to 200

0.55 to 0.80

18 to 24

2,250 to 5,700

CMHPG-Zr (25)

1,510

585,000

Sand - ISP

16/30, 20/40

1,300 to 2,850

Slide 12

Case Histories—Tight Gas (TG)



Working in a Difficult Environment

• Reservoir condition

• Deeper wells (avg. 3500 m/11,500 ft), higher pore

pressure (0.65 to 0.7 psi/ft), high fracture gradient (0.85

to 0.9 psi/ft), and low permeability (0.01 to 0.001 md).

• Adjusting the technique

• Bottomhole assembly (BHA): only two holes (delta

pressure), older hydrajet tool had to be changed at least

once per well (erosion), new hydrajet tool did not need to

be changed.

• Improving time and logistics

• Change in working time (12 to 24 hours), proper water and

proppant logistics were necessary (850 to 1500 m3/day

water and 2,800 to 4,500 sks/day proppant).

Old hydrajet tool performing 10 abrasive perforationsNew hydrajet tool performing 21 abrasive perforations

Slide 13

Case Histories—Tight Gas (TG)










BHA - N° hole 3



BHST (°F) 120 to 205











Conventional Gas

9

5 1/2

10,000

60K

1 3/4

Old tool

3

12

1400 to 2800

135 to 200

0.55 to 0.80

18 to 24

2,250 to 5,700

CMHPG-Zr (25)

1,510

585,000

Sand - ISP

16/30, 20/40

1,300 to 2,850

Tight Gas

11

4 1/2

10,000

60 to 95K

1 3/4

Old tool / new tool

2

12 / 24

2900 to 3800

210 to 250

0.75 to 0.95

16 to 20

6,800 to 9,300

CMHPG-Zr (25)

2,475

970,000

ISP

30/60, 20/40

3,000 to 4,350

Slide 14

Case Histories—Shale Oil (SO)



Challenges Associated with Unconventionals (Vaca Muerta)

• Using existing well for unconventional project

• Reconditioning old well, additional workover operations.

• Technical and operational feasibility

• Multiple well geometry option, pinpoint parameter design for these alternatives.

• Applying experiences

• TG pinpoint experience, engineering solutions, logistics for unconventional

projects, new hydrajet tool.

• Project objectives

• Complete a multifracture well with more selective stimulations, cost projection

equal to or lower than previous wells.

Slide 15

Case Histories—Shale Oil (SO)










BHA - N° hole 3



BHST (°F) 120 to 205











Conventional Gas

9

5 1/2

10,000

60K

1 3/4

Old tool

3

12

1400 to 2800

135 to 200

0.55 to 0.80

18 to 24

2,250 to 5,700

CMHPG-Zr (25)

1,510

585,000

Sand - ISP

16/30, 20/40

1,300 to 2,850

Tight Gas

11

4 1/2

10,000

60 to 95K

1 3/4

Old tool / new tool

2

12 / 24

2900 to 3800

210 to 250

0.75 to 0.95

16 to 20

6,800 to 9,300

CMHPG-Zr (25)

2,475

970,000

ISP

30/60, 20/40

3,000 to 4,350

Shale Oil

12

7 + 4 1/2

10,000

95K

1 3/4

New tool

2

24

2350 to 2900

180 to 210

0.93 to 1.05

15 to 23

6,500 to 8,500

CMHPG-Zr (25)

4,800

1,045,000

ISP

30/60, 20/40

3,400 to 4,600

Discussions (Looking Forward)

This technique can be used in the following:

• Geographic areas without workover units.

• By operators with experience, availability, and rigless completion models.

• Projects to optimize completion time and costs.

• Reservoirs (fields) not needing evaluation (testing).

• Well or reservoir revitalization (preconditioning old wells to be applicable to this

technology).

• Nontraditional applications.• Wells with no nominal internal diameters (obstruction, restriction, or deformation).

• Vaca Muerta formation (evaluated to be completed using HPAP-PPD).

Slide 16



Discussions (Looking Forward)

Benefit obtained:

• Completion technique with lower costs, less risk, and faster operating times.

• No over-displacement of proppant.

• Higher conductivity in the near-wellbore region.

• More effective at treating multiple closely spaced entry points compared to limited-entry

techniques that are not working efficiently.

• Coiled tubing hydrajetting can be used for remedial applications. • When fracturing treatments using plug-and-perf or sliding sleeves cannot be performed

because of mechanical issues.

• New style hydrajetting tools help enhance this benefit.

Slide 17



Conclusions

• Adaptability: various types of reservoirs, coiled tubing units, well geometry, rock

types, and fracture designs

• Logistics and planning: continuous learning with different operators, coordination of

resources (water, proppant, materials, equipment) to help minimize negative impacts to

the projects

• Hydrajet tool:• Initial old style showed erosion in TG → additional time (change BHA)

• New design was applied for TG and SO → improving completion time

Slide 18



Conclusions

• Reduced completion time:• CO reduced up to 65%

• CG reduced 40 to 50%

• TG wells required only 5 hours to complete one stage

• SO required 8 hours for one stage

• Production increase: several authors document production increases and higher

initial production rates compared to offsets wells.

• Results obtained have been attributed toa) Elimination of the damaged region (stress cage) in the perforation tunnel

b) Creation of a high-conductivity cavity just at the perforation tunnel

c) Shorter residence time of the fluid in the formation

d) Focalized stimulation

e) High conductivity in the near-wellbore area

f) Strong connectivity well-formation (no overflush).

Slide 19



AcknowledgementsThe authors thank the following:

• Pan American Energy, Grupo Capsa, Pampa Energía, and Halliburton for permission to

publish this work.

• Staff of the Production Enhancement PSL, Production Solutions PSL, and Global Pinpoint

Stimulation Group.

• Halliburton personnel Mariano Garcia, Leonardo Canini, and Juan Martin Szklarz and

former Halliburton employees Diego Duran (Pluspetrol) and German Rimondi (CWS).

• Buddy McDaniel for his guidance during the last few years.

Slide 20

Slide 21

Thank you for your attention

Engineering

Multipay Well Completion in Argentina: A Versatile Pinpoint Completion Technology Applied through Several Conventional, Tight, and Shale Reservoirs