INTERNATIONAL PERFORATING SYMPOSIUM · PDF fileINTERNATIONAL PERFORATING SYMPOSIUM 2014 ......

WELL FLOW MANAGEMENTTM

Completion evolution:

The role of perforating in horizontal shale wells

Kerry Daly, Global BD Manager- DST TCP

INTERNATIONAL

PERFORATING

SYMPOSIUM

2014

IPS-14-38

Introduction

• The first horizontal well in unconventional shale was completed in 1981

• Completion techniques were not fully proven until 2002

• Since then, thousands of wells have been completed using two primary techniques:

1) Leaving the wellbore uncased across the formation and using open hole packers for

isolation and frac sleeves for zonal access (OHMS)

2) Cementing casing in place and then perforating distinct sections of the wellbore for

stimulation/ production purposes (CHPP)

The technique chosen depends on:

• Wellbore parameters

• Client preferences

• Equipment availability and limitations

Ultimate differentiators being:

• Cost reduction

• Productivity enhancement.

Production data comparing the techniques is now available.

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OHMS- Open Hole Multi-Stage system:

Steps:

1. Surface or intermediate casing is placed in vertical section and cemented in place.

2. Casing is not emplaced across the horizontal, instead the OHMS consisting of frac sleeves and

open hole packers is run and positioned with a liner hanger.

3. Pressuring up inflates packers and dropping balls isolates the sleeves, allowing stimulation into

the formation at staged intervals.

• Optional systems allow for cementing in place where regulation requires.

Benefits:

• No formation damage from cementing

• No interventions are required and fracking is continuous once started

� Thus saving time.

Disadvantages:

• No perforations in the formation beyond mud infiltration zone or to initiate fracture.

• System costs may be substantially higher, limiting number of formation access points.

� Drives the decision to use the alternate CHPP method.

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CHPP- Cased Hole Plug and Perf system: IPS-14-38

Steps:

1. Surface or intermediate casing is placed in vertical section and cemented in place.

2. Production casing is then run across the lateral and cemented, thus restricting flow into/

around casing.

3. Perforating with Tubing Conveyed (TCP) via tubing or coiled tubing (CT), or electric wireline

via pump down or tractor, establishes contact with formation for stimulation/ production.

Optional systems available:

• Toe Gun • Casing Toe Sleeve • CT TCP Plug and Perf (when screen-outs occur)

4. Fracking breaks down formation through perforations; stages isolated with composite plugs

5. Afterwards, production from all zones is established by milling up composite plugs.

Benefits:

• Systems cheaper but take longer to complete, thus offsetting costs

• May be easier to rework in case of problems or when production drops.

Disadvantages:

• Each intervention costs time, thus driving the decision to use the alternative OHMS.

CHPP IPS-14-38

TCP Toe Prep, via Coiled Tubing or standard Tubing:

• First operation after clean-out, no open perforations yet.

• Normally covers the first 500 ft. of wellbore > firing more clusters than previous

• Stages consist of 1 - 10 guns

� Gun lengths: 1 - 6 ft. long

� Gun OD: 2-3/4”, 2-7/8”, 3-1/8”, 3-3/8”

� depending on casing size (4-1/2”, 5” 5-1/2”)

� Gun Type: 6 SPF, 60 degree with DP or Super DP charges

� Guns typically not oriented, let pressure determine fracture path

Drivers

• Job Parameters:

� One or many pressure-activated firing

heads fired at same time

� May or may not have time delays

attached

� WL correlation not required, pipe tally

used

� Packer normally not run

� Gun assemblies spaced out with

tubing between, no length limitation

� Total trip time ~8 - 12 hours

• Cost:

� Rig ~$10,000/ day

� TCP ~ $15,000

� Estimated total ~$25,000

• Risk: If gun doesn’t fire, lost time +

additional trip on pipe required

• Job Parameters:

� One pressure-activated or ball-drop

differential firing fires first gun

� Time delays between guns allow CT to

move to next zone

� Number of guns and zones limited by

surface lubricator length and crane height

(~70 ft.)

� WL correlation not required, pipe tally

used

� Total trip time ~6 - 10 hours

• Cost:

� CT unit ~$25,000/ day

� TCP ~ $15,000


• Risk: If gun doesn’t fire, lost time + additional

trip on CT

TCP- If Conveyed by Workover Rig: If Conveyed by Coiled Tubing (CT):

To reduce cost, new technology has been developed which requires no rig or CT .

IPS-14-38CHPP- Toe Prep

• Attached to outside of casing and run as part of casing string

� Run just above float collar/ shoe and cemented in place

� Requires larger borehole, which drives drilling cost

� Requires high-temperature explosives, more expensive

� Guns are downhole longer, risk leak at o-rings

• After the cement cures, pressure up to rupture disk or shear pins to fire gun

� To limit cement sheath at tool, must always bump wiper plug and

follow with special fluid recipe.

• Removes Workover Rig/ CT costs and run time

• Creates limited perforations, usually maximum 10-ft. so entire toe is not

prepped.

� Requires pressure pumping

� Requires subsequent WL pump down perforating

• Risk: If gun doesn’t fire or unable to establish pump rate, must perform

traditional TCP toe prep.

CHPP- Alternative

- To eliminate the cost of CT Toe Prep

Casing Toe Gun

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CHPP- Alternative

- Becoming the System of Choice, Saves Two Coiled Tubing Runs.

Casing Toe Sleeve

• Run just above float collar/ shoe and cemented in place

• After the cement cures, pressure up to rupture disk or shear pins

� Pressure shifts a sleeve, which opens ports to expose formation to frac pressure

� Optional fluid metering allows casing test prior to opening

• Safer option as no explosives used

• Removes Workover Rig/ CT costs and run time

• Doesn’t create perforations, just access to formation

� Requires pressure pumping

� Requires subsequent WL pump down perforating

• Risk: If sleeve doesn’t open or unable to establish pump rate, must perform traditional Toe

Prep.

� To limit cement sheath at tool, must always bump wiper plug and follow with special

fluid recipe.

System

Comparison

Casing

OD

Tool

OD

Min.

Borehole

Toe Gun 4-1/2

in.

7.50

in.

8-1/4 in.

Toe Sleeve 4-1/2

in.

5.75

in.

6-1/4 in.

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- Regardless of how toe is perforated

Frac Between Perforating Runs- Parameters:

• Perforations have established flow path

• Components of fracture (after perforation)

� Formation breaks down at ~10,000 psi (Eagle Ford)

� Fractures propagate best at ~ 100 bbl/min

� Bull head through the casing

� Allows higher pump-in rates

IPS-14-38CHPP- Frac parameters between runs

• Wireline Plug & Perforation System

Parameters:

• Run time is only 2 -3 hours

• First set a Composite Frac Plug

• Then move up-hole to fire guns, 1-10 typically as Select-Fire with reverse polarity switches

• At end of run, circulate a ball into the Composite Frac Plug

� This seals the zone below and allows fracturing through newly created perforations

• Risks: High failure rate

� Simplest failure: electrical short resulting in 4-6 hours lost time at ~$2,000/ hour standby.

� Most complex failure: parted line with live guns lost in hole resulting in 50 hours lost time.

• Rewards: Short operating time, limiting frac standby costs

� Unlimited stages can be performed

� Benefits far outweigh the risks!

� WL Pump-down Plug and Perf is the preferred method- not going away!

IPS-14-38CHPP- Wireline (e-Line) Pump Down

• Other Risks:

� Formation fails to break down

� If can’t generate minimum 10 bbl/min, then cannot pump down WL guns

� If WL bridges out during pump down operations due to residual fill in casing

� Wellbore has not been reentered since frac event

� Necessary to run a TCP system to complete the stage

• Cost:

� WL Perforating~$10,000 per stage (additional cost of water not included)


• Operation:

� Set composite fracture plug, isolates previous stage

� Typically have residual pressure on wellbore: 1,000- 4,000 psi

� Pressure control equipment required

� Requires high volume pumping to position guns, 10 – 18 bbl/min

� Maximum running speed ~200 ft/min

CHPP- Wireline (e-Line) Pump Down MENAPS 13-17

IPS-14-38Comparison- OHMS vs CHPP

OHMS- Positives Negatives

• Multiple stages can be performed in a single trip • Can be problematic if completion fails to get to depth

• No perforating or plug runs are required • Inflexible- can skip a stage but can't add one

• No plugs must be drilled up • Less productive because fractures cannot be oriented with

maximum horizontal stress

• Takes much less time • Complicated- hardware is not foolproof, and failures are

difficult to resolve

• No guarantee that fracture will propagate opposite the open

sleeve port- could be hundreds of feet up or down the well.

• In case of screen-out, cannot get Coiled Tubing past

restrictions in ports- graduated drop ball systems

• Regulatory bodies are requiring cemented liners along with

casing test- OHMS cannot provide

• Completion type and frac port locations must be planned

well in advance

• Cost of equipment is high

CCNP-Positives Negatives

• Easier to get to bottom • Takes longer, but sometimes investment is worthwhile to get

higher productivity

• More flexible- optimize frac in real time • Future technology will allow 50+ stages of OHMS, leaving

CCPP at a disadvantage

• Inexpensive due to a widespread availability of

equipment and crews

• Higher frac costs due to standby in between stages

1

Time Cost Production Time Cost Production

OHMS 0.2 0.7 1 0.55 0.77 1

PNP 1 1 0.67 1 1 0.65

0

0.2

0.4

0.6

0.8

1

1.2

Ratio

Comparison

Montney

Comparison- Early Results IPS-14-38

Wells Completed before 2011 2

Early Industry Drivers:

• Lack of available

equipment

• Lack of trained personnel

• High frac costs

• High coiled tubing costs

• High standby rates

First shale completions:

• Used CCPP

• High costs/ high risk drove

development of OHMS

• Time savings made these

economical choice

Costs have come down, so

OHMS may not provide

benefits it once did.

Granite Wash

Comparison- New Techniques IPS-14-38

Wells Completed in 2013-Operator #1 3

← 300-N →

Older Style:

Sliding Sleeve Completion

Frac Design: 4

• Slick water (3 times more water)

• Increased Proppant (lb-ft)

Annulus Stages

Frac Ports

per Stage

Potential

Entry Points

Free Fluid

Between

Packers

30 1 30

Annulus Stages

Perforation

Clusters

per Stage

Potential

Entry Points

Cemented 40 3 120

New Style:

Cemented Liner Completion

← 250-N →

Comparison- Later Results IPS-14-38

Field Well Liner Style Completion 24-hr IP

(BOEPD)

Cost

1 1 Uncemented Sliding Sleeve 2,715 $8.23M

2 Cemented Plug & Perf 3,795 $8.23M

2 1 Uncemented Sliding Sleeve 884 $7.91M





2 Uncemented Sliding Sleeve 476 $8.24M


5 1 Uncemented Sliding Sleeve 1,888 $7.83M

2 Uncemented Sliding Sleeve 1,398 $7.76M


Uncemented Sliding Sleeve Avg. 1,201 $7.81M

Cemented Plug & Perf Avg. 1,966 $7.78M

Percentage Increase/ Decrease- PNP vs. OHMS 64% ↑ 0.1% ↓

Wells Completed in 2013- Operator #1 3

0

500

1000

1500

2000

2500

Uncemented

Sliding Sleeve Avg.

Cemented Plug &

Perf Avg.

24-hr IP

(BOEPD)

Production

0

2

4

6

8

10

Uncemented

Sliding Sleeve Avg.

Cemented Plug &

Perf Avg.

$

(Millions)

Cost

Comparison- Later Results IPS-14-38

Wells Completed in 2013- Operator #2 5

Historical Industry

Practice

Current Industry

Practice

Planned Company

Practice

Lateral • 2,000- 5,000 ft. • 6,000+ ft. • Longer than 7,200+ ft.

Lateral Placement • Varied, trial and error • Well defined • Well defined

Frac Type • Slick water • Hybrid • Hybrid *

Proppant • Less than 1,400 lb/ft • 1,400 lb/ft + • 1,400 lb/ft +

Cluster Spacing • 70-ft or greater • 66-ft or less • 50-ft

Results: Avg IP BOEPD

3 Wells 38% ↑ over OHMS 3,060

4 Wells 77% ↑ over OHMS 2,094

2 Wells 91% ↑ over OHMS 462 M Ultimate recovery

New Style: Cemented Liner Completion using Plug and Perf

Frac Design:

• Using Ceramic Proppant

• Increased Proppant per Lateral Ft.

• Increased Stage Density

• Employing Simultaneous or Zipper Fracs (Two adjacent wells frac’d at same time)

* Hybrid Frac:

• Slick water pad

• Gel during prop

CHPP Steps:

1. Clean-out Run> first run after running casing and cementing (becoming optional)

• Alternate: Combination CT Clean-out with Abrasive Jet Perforating (non-explosive)

2. TCP Toe Prep> required as no perforations yet (can’t pump into formation)

• Two primary methods- 1) Tubing conveyed on Workover Rig or 2) Coiled Tubing conveyed

� Alternate: Casing Toe Gun, run on casing but requires larger bore hole and high-temp

explosives

� Alternate: Casing Toe Sleeve, run on casing but requires over-displacement of cement

(becoming method of choice for toe prep)

3. Bullhead Frac down casing

4. Wireline Pump-down Plug and Perf> unlimited stages but risky (method of choice after flow into

formation established)

• Alternate: TCP Plug and Perf (annular pressure)

• Alternate: TCP Plug and Perf (tubing pressure)

� Each stage followed by Bullhead Frac down casing

5. Mill up Composite Plugs

• Frac flow back, Clean up, and put well on Production

Summary IPS-14-38

OHMS vs. CHPP:

� Openhole Multistage systems delivered good results early in Shale Development,

• Primarily because of equipment shortages, high rates for services and standby costs .

• Saves costs as multiple stages can be frac’d continuously

• Saves time as no perforating or plug runs are required and no plugs to drill up

• But, completion and frac port locations must be planned well in advance

• But, cost of equipment remains high (machining costs have not reduced proportionally)

• Still viable system but production rates reversing toward CHPP.

Summary IPS-14-38

OHMS vs. CHPP:

� Cased Hole Plug-N-Perf system is showing improving results due to new techniques

• Not stand-alone, one aspect of new completion technique which includes changes in frac.

• Costs have come down significantly for coiled tubing and frac standby, now similar in cost

• More points of contact with formation aid in formation breakdown and proppant placement.

• More flexible, can add stages quickly and easily and optimize the frac in real time

• Takes longer, but sometimes investment is worthwhile to get higher productivity

• Overall costs are similar but production rates are improving.

� Good news for the Perforating Industry- We’re Still in the Game!

� Thank you! Questions?

Summary IPS-14-38

References

1. Cheselin, R. , Quittitut Consulting (2011, August). Openhole Multistage vs. Plug-N-Perf Completions: Sleeves

vs. Shots- The Debase Continues.

2. Rivenbark, M., & Appleton, J. (2013, January 28). Cemented Versus Open Hole Completions: What is Best for

Your Well? Society of Petroleum Engineers. doi:10.2118/163946-MS

3. Whiting.com (2014, April). Current Corporate Presentation

4. Bakken.com (2013, December 26). Whiting Petroleum Exploits Cemented Liners For Major Production Gains

5. HalconResources. Com (2013, June 10). Halcón Resources Provides Operational Update: Company Reports

3,060 Boe/d IP Rate on Latest Fort Berthold Area Bakken Well

IPS-14-38

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