HPHT WELLS EUROPE 2012 CONFERENCE Haynesville Shale Seminar Perspectives of Encana Oil & Gas

John Dees

Completions Engineering Advisor MCBU, Dallas,Texas October 22-24, 2012

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Data Analysis – How to reach the optimum? (fast!) on HPHT wells what process do you use to travel up the hill to reach the pinnacle? This is a 3-D surface plot. X1 and X2 are the inputs while Y is the output of the process. The red star is the starting point while the green star is the optimum that we seek.

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Our challenge is to move performance from where the red star is located to where the green star is located. What are the options?

• Generally experiments can be grouped into the following categories: • Trial and Error • One-Factor-At-a-Time (OFAT) • Design of Experiment • EVOP or evolutionary operations

• While OFAT is simple, the experimental efficiency given up is significant: • Unnecessary experiments may be run • Time to find casual factors can be long • Do not get a Y = f(x) predictive equation • Making critical decisions based on only one data point

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Example of a Response Surface

• Goal of DOE/EVOP (Evolutionary Operations Plan) is to determine the response surface(s) • Show effects of chosen variables

• Response surface can be used with economics to determine optimum completion design

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Data Analysis – Background Status • Reviewed Haynesville horizontal data trade base

• Used collaborative data base among competitors to build initial Design of Experiment, DOE parameters

• Key parameters were: • Multi-well pad wells compared zipper vs. simul vs. single • Lbs/ft vs. bpm/hole • Lbs/ft vs. cluster length • Bpm/hole vs. cluster length

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Data Analysis – Background Status

• Early data analysis helped identify the performance drivers:

• Cluster spacing footage • Proppant volume per foot of lateral

• Structured Design

Experimentation evolved into a “per cluster” analysis

• Key drivers on well performance proved to be: • Cluster spacing • Proppant volume /cluster • Pump rate/cluster • Pump per/perforation • Fluid volume/cluster

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Data Analysis - Status

• Other Status • Have developed some fairly good correlations (R2 ~ 84%)

• y = f(x1, x2,…,xn) is beginning to come together • Continuing to refine and examine non-linearity's • Desire is to include formation properties, completion targets to try to

better understand differences between formations

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Data Analysis – Current Status

• Modified Haynesville DOE with early learnings • Key parameters became

• Gas Factory wells zipper vs. single (no Simul fracs) • EW vs. NS across a large area using ANOVA • Lbs/ft vs. Cluster length • Bpm/hole vs. cluster length • Mid Bossier wells vs Haynesville wells

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Caveats & Considerations

• Difficult to perform “actual DOE” • Executing precisely per plan is rare • Business case decisions sometimes conflict

• Max RP variance unknown, the eventual solution was to wait on the reservoir group to come up with their EUR

• DOE framework provides ancillary benefits

• Experiments will change with the economic environment

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More lbs/ft is Not Always Better

Prop (lbs/ft)

Max RP/1000’

Cluster Spacing (ft)

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Scatter Plot

Proppant/ Cluster ft (klbs/ft)EUR/ Cluster-Ft

40 60 80 100 120 140 160 180

0.22

0.2

0.18

0.16

0.14

0.12

0.1

0.08

0.06

0.04

NLA Completions – Current Model 2012

Decreasing Cost

Working to understand what drives this variation

EUR/Cluster Spacing vs. Proppant/Cluster Spacing

Tota

l EU

R/C

lust

er S

paci

ng (B

cf/ft

)

Total Proppant/Cluster Spacing (klbs/ft)

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Value Based Completion Designs

Varying Cluster SpacingKeeping klbs/cluster Constant

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

30 35 40 45 50 55 60 65 70 75 80

Cluster Spacing, ft

EUR

/ 1,

000'

, BC

F

0.00

0.25

0.50

0.75

1.00

1.25

1.50

NPV

9 / 1

,000

', $M

M

EUR - 50 klbs/clusterEUR - 70 klbs/clusterEUR - 90 klbs/clusterNPV9 - 50 klbs/clusterNPV9 - 70 klbs/clusterNPV9 - 90 klbs/cluster

Not Enough Data

Target of 2011 DOE Work

Increased Operational Risk with Increased Proppant, Fluid, & Stages

2010 Standard Design • 65K lbs/cluster • 1,300 lb/ft • 50’ Cluster Spacing • 14 Stages, 5.3 MMlbs • $4.0 MM per well

2011 New Standard Design • 90K lbs/cluster (+38%) • 1,650 lb/ft • 55’ Cluster Spacing • 17 Stages, 7.2 MMlbs • ∆ $0.2 MM

XP DESIGN • 110K lbs/cluster • 2,000 lb/ft • 55’ Cluster Spacing • 18 Stages, 8.8 MMlbs • 4 Wells • ∆ $0.4 MM

XPC DESIGN • 110K lbs/cluster • 2,750 lb/ft • 40’ Cluster Spacing • 24 Stages, 12.1MMlbs • 2 Well • ∆ $1.5 MM

XC DESIGN • 90K lbs/cluster • 2,250 lb/ft • 40’ Cluster Spacing • 24 Stages, 9.9 MMlbs • 1 Well • ∆ $1.3 MM

XP² DESIGN • 150K lbs/cluster • 2,725 lb/ft • 55’ Cluster Spacing • 18 Stages, 12.0MMlbs • ∆ $1.3 MM

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Well Design

Fluid Type Gas

Depth (TVD ft) ± 12500 – 13500 ft

Depth (MD ft) ± 16500 - 20500 ft

BHP (psi) 11000

BHT (F) > 350

H2S (ppm) 10-40

CO2 (%) 4-5

15 ksi Well Head, PSL-3 Primary Component, stainless steel tubing hanger and stainless steel primary master valve, FF rated

10 3/4” Surface Casing 40.5# J-55, landed @ ~1850 ft TVD

Intermediate casing 7 5/8” casing 29.7# P-110 @~ 11200 TVD

Old Design

5” Production casing 23.2# T-95 E @~ 6000 ft TVD, 23.2# P-110 to 13400 ft TVD, (~17500 MD ft)

New Design

5.5” 26 # P-110 @~6000 ft TVD, 5.5” 23.11# @~10900 ft TVD, 5” 23.2# P-110 to 13400 ft TVD, (~17500 MD ft)

12-15-29 fracs / well

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Sequence of Operation Operation Objectives/Operation Benefit/Result

(1) Well Clean Up - RIH with Coiled Tbg (with mill motor) to PBTD -Circulate the well -Run Sweeps - Ensure well is clean and ready to pump down Bridge Plugs

Clean well bore

(2) TCP Perforation - RIH TCP guns assembly on Coil - Perforate the toe stage (proposed at pressure 5500-6000 psi over hydrostatic pressure)

5500-6000 psi over hydrostatic pressure – overbalanced perforating to reduce breakdown issues and shale flowback

(3) 1st Frac - Pump the frac, 67-75 bpm (based on DOE parameters), Frac 1st zone

Frac toe stage

(4) Pump down Plug

- Pump down composite (flow through) plug and perforating gun on wireline - Isolate previously fractured stage and perforate the new zone

Frac diversion and perforation

(5) multi-staged frac

-Repeat operation 3 and 4 to complete all 11-14 stages of frac per well

Note: Average number of fracs (15-25)

350 ft stage spacing

(6) Plug Drill Out - Rig up and RIH with Coiled Tubing to mill out plugs(93% gauge mill) - Clean the well bore (Plug Debris)

Prepare well for production Testing

(7) Production Testing and clean up

- Flow back the well - Clean the well and perform basic measurements - Prepare the well for production

Measurements and prepare well for production

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Well Head

15K PSL- 3 Primary Components

4 1/16" 15K X 2 9/16" 15K – Old Tree

5 1/8" 15K X 2 9/16" 15K – New Tree

Tbg Hanger: 10K Tubing Hanger, FF rated body, 15K flange, NACE qualified, temperature rating P + U ( 0 to -20 F and 0 to 250 F), 0.5 ppm H2S resistance

Primary Master Valve: Material Class FF-360 Internal components (15K Flange, Temperature class U+X, Stainless steel body

All other well wetted surfaces are 4130 steel alloy

Temperature Rating classification of X, above 325 F tested

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Perforating

•Stage Length: 240-350 ft •Gun System: •3 1/8”, 6 SPF, 60 deg Phasing gun carriers •25gram HMX Charges, EXP-3323-423T •CT Conveyed @ toe gun (3 to 6 clusters) & Pump Down on Wireline on all subsequent gun runs •Coil guns were replaced with a absolute pressure activated sleeve •Multiple cluster perforations ( 4-7 clusters/stage) – optimization based on DOE lead to 4-5 clusters per stage •-Composite Frac plugs(flow through type with poppet valve evolved to ball drop type) run on the wireline with perforating guns

•Key Success Factor: •Being able to reach bottom with Mill (before TCP run), depth correlation, Repeatability, equipment readiness, back up equipment and strong maintenance plan

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Zonal Isolation: Bridge Plugs

Service Provider: XXXXX System: -4.5” Composite Bridge Plugs in 5” 23.2# casing

-No cast iron components in the plug (except slips) - No Aluminum components in the composite bridge plug

-Flow through ball drop plug replaced the poppet valve plug Key Success Factor: Readiness of Baker Setting Tool, Plug type would largely depend on frequency of perforating guns not firing and frequency of having problems with plug being set

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FRAC

Frac Design: Optimization through DOE

Initially ~ 11500 bbl/stage of fluid, ~ 390 K lb/ stage proppant

67-75 BPM optimum rate (DOE)

Evolved to 100 mesh 90K lbs, 30/70 sand 460 K lbs, 30/50 ISP or light weight ceramic 50K lbs

15-29 stages per well

Multi parameter optimization process evolved into designs to fit with excessive price increases

Key Success Factors:

- Operational Efficiency of the crew

- Rigorous onsite inspection plan

- Effective Rig up

- 24 hour operations

- Conversion of the crew to 24 hr operations

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Well Testing / Flow Back

Service Requirements: 2” 15Kpsi ESD 2 1/16” piping upstream-flanged 2” piping - downstream-hammer unions 2” 15Kpsi Choke Manifold 1440 psi separator vessel – Production Line pressure 5K psi downstream pressure on Sand Trap 15K psi upstream pressure capability on sand Trap with sand screen ability to store and measure produced sand Flare stack (if required), Constant monitoring of flowback

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2012 evolved from 2011, 2010 & 2009 Design of Experiment

Service Provider: Tetra/Fesco Requirements: 2” 15Kpsi ESD 2 1/16” piping upstream-flanged 2” piping - downstream-hammer unions 2” 15Kpsi Choke Manifold 1440 psi separator vessel – Production Line pressure 5K psi downstream pressure on Sand Trap 15K psi upstream pressure capability on sand Trap with sand screen ability to store and measure produced sand Flare stack (if required), Constant monitoring of flowback

Changes in the Program

More frac stages per well with longer laterals

Average number of clusters per well 140 vs. (90) vs. (75) vs. (42)

Frac stages per month 174 vs. (160) vs. (88) vs. (52)

Lateral length to 7914’ ft (4575 ft) vs. (3500 ft)

Introduction of 5.5” and 5” production casing

Multiple wells with fresh water blended with recycled water and pit water

Well site supervisor manual in place

Flow back best practices in place (SOP)

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Key Success Factors Service Provider: Tetra/Fesco Requirements: 2” 15Kpsi ESD 2 1/16” piping upstream-flanged 2” piping - downstream-hammer unions 2” 15Kpsi Choke Manifold 1440 psi separator vessel – Production Line pressure 5K psi downstream pressure on Sand Trap 15K psi upstream pressure capability on sand Trap with sand screen ability to store and measure produced sand Flare stack (if required), Constant monitoring of flowback

•KEY SUCCESS FACTORS •“Efficiency in the Operations

Strong Field Supervision (Encana and Service Providers) Lean Program awareness and implementation 24 hr operations of frac crews Streamlined frac operations with two frac crews

•Better equipment maintenance plan •Partial water recycle •Minimize cycle time for Services on Critical Path (Frac, Pump Down, Coil Contingency) – 24hrs Ops

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Thank you and Acknowledgements

• Encana’s Completions and Reservoir Characterization Teams

• You in the audience and for your attention

• Do you have any questions?