Cold Heavy Oil Production with Sand Workshop

9/22/2011

1

Cold Heavy Oil Production with Sand Workshop

Calgary

September 21,

2011

Recon CHOPS Workshop Calgary Sept 21, 2011

For More information

Visit The OTS (Oilfield Technical Society) Heavy

Oil Science Center

Lloydminster

Visit www.lloydminsterheavyoil.com

References are on the CD

Visit www.kirbyhayes.com

http://www.lloydminsterheavyoil.com/

9/22/2011

2


Kirby Hayes

runs his own company, Kirby Hayes Incorporated

(KHI), which represents several corporations offering

services and productions primarily involved in heavy

oil production

extensive background in cased hole wireline

has co-authored several technical papers, patent

applications, conducted seminars, short courses,

workshops and presentations on wide-ranging topics

of interest to heavy oil producers


4

9/22/2011

3


Integrated Production

Services

Recon

Petrotechnologies Ltd.

Wavefront Technology

Solutions Inc.

Ace Oilfield

Endurance

Technologies

Alberta Innovates

Technology Futures


Thank you Presentation contributions: Ron Sawatzky, ARC

Bob Mottram, Weatherford

Rob Morgan, Harvest

Murray Tluchak, Bonavista

Ryan Rueve, Nexen

Floyd Isley, CNRL

Rick Walker, Devon

Jerry Schoenroth, Husky

Mike Kremer, Husky

Cedric Gal, CAG Consulting

Dave Love

John Newman

Janelle Irwin

Maurice Dusseault, U of W

Ace Oilfeild

Schlumberger

G-Chem

IPS

Wavefront

And others

9/22/2011

4


Outline

CHOPS – an overview

Perforating for heavy oil – the issues

Break

Alternate completions

Interventions examples

Lunch

Next steps prior to thermal or solvent EOR

processes

Interesting log examples

Discussion


Cold Production

“Other things being equal, the maximum

recovery of oil from an unconsolidated sand is

directly dependent upon the maximum

recovery of the sand itself”

William H. Kobbe,

in Trans. A.I.M.E., Vol. LVI, pp. 799-830

February, 1917 (New York)

9/22/2011

5


How Big Is It?

Canada & US consume ~ 20 MBOD

~ 2,600,000,000,000 barrels in place (heavy oil and oil sands) in Canada

If we achieve 30% recovery…

100% of current consumption for 100 years

So… why fight over Middle East Oil?

production problems are being solved


Operating Costs

Co

st

per

Barr

el ($

)

Befo

re 1

990

CH

OP

S

CS

S

SA

GD

} }

cold + steam

9/22/2011

6


Recovery Efficiency

0

10

20

30

40

50

60 R

eco

very

(%

)

Befo

re 1

990

CH

OP

S

CS

S

SA

GD

} cold

}

+ steam


Could we get there?

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

Jan-70 Jan-75 Jan-80 Jan-85 Jan-90 Jan-95 Jan-00 Jan-05 Jan-10 Jan-15 Jan-20

Pro

du

cti

on

(b

op

d)

9/22/2011

7


Technology is the Key

What are the technologies?

Thermal Processes

steam, SAGD, electrical heating

need to manage energy equation

Chemical Processes

solvent, upgrading

full value chain enhancement

Displacement Processes

enhanced floods water, polymer, chemical

Pink Smoke and Marbles???


35 Billion Barrel Resource

6.5% 2.1%

73.8%

17.6%

Cumulative Recovery Remaining Recoverable

Remaining Resource Incremental Technology Wedge

Slides courtesy of Rob Morgan, Harvest

The industry needs to improve recovery factors

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8


Heavy Oil & Bitumen Production

Western Canadian

Crude Oil Production

Production statistics at December, 2006 Sources: Alberta Dept. of Energy, NEB

Source Production (bbl/day)

Oil Sands Mining 760,000

Oil Sands In Situ 330,000

Conventional Heavy 500,000

(Cold Production) (230,000)

Conventional Light 500,000

TOTALS 2,190,000


Deltaic Depositional Environment

The Mississippi Delta

A satellite photo of the Ganges Delta in India

9/22/2011

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Exploration

In general exploration for CHOPS is easy in

Lloydminster

Best tool is offset mapping and production – high

existing well density lends itself to good mapping

3D seismic is the norm

Success rate is high (> 85%)

Large regional sands are dependable and predictable

Channels are a bit more tricky in terms of traps and

water content – but big prizes


Heavy Oil Leases

There are three basic

configurations for a

CHOPS well

Vertical

Slant

Directional

9/22/2011

10


Producer PanCanadian Mobil Suncor Amoco Texaco

Formation Mannville Mannville Clearwater Clearwater Mannville

Field Lindbergh,

Frog Lake Celtic Burnt Lake Elk Point Frog Lake

Oil Saturation (%) 80 87 70-80

Gas/Oil Ratio

(std m3/m3) 10 5-11 11-15.2 10

Live Oil Viscosity

(mPa s)

3,000 to

10,000

1,200 to

3,000

40,000

(dead)

2,000 to

55,000

20,000 to

50,000

Pressure (MPa) 4 3.3 3.3 3.8 2.8-3.4

Permeability (darcy) 1.5-2.5 0.5-4.0 2.0 1.0-5.0

API gravity 12-14 12 11

Net pay (m) 14 3-5 20 11-14 4-11

Porosity (%) 32 33 34 34 33

Cold Production

Field Examples

Typical field oil production rates 5 – 25 m3/day


Cold Production

Lloydminster-Area

Cold Production Blocks

Production statistics at December, 2001

Block

Producing

Well Count

#

Oil Production

(m3/day)

Avg Rate

per Well

(m3/day)

Lloyd 3,667 21,757 5.9

Lindbergh 1,322 8,348 6.3

Cold Lake 600 4,486 7.5

SW Sask 306 2,220 7.3

TOTALS 5,895 36,811 6.2

9/22/2011

11


0.01

0.1

1

10

100

100 1,000 10,000 100,000

Oil Viscosity (mPa.s)

Oil R

ate

(m

3/d

ay)

1 darcy 3 darcy

10 darcy 30 darcy

100 darcy 300 darcy

5 m net pay

2,500 kPa draw down

7 in wellbore diameter

200 m far-field radius

Effective Permeability

without

sand

with

sand

typical for

cold production

Cold Production

Oil Production Rate Estimates


CHOPS

Development of high permeability channels – “wormholes”

much greater reservoir access

Large, local drawdowns at ends of channels

high pressure gradients – gas exsolution

Substantial increase in oil rates

Successful commercial process

continued sand production

at cuts 0.5%

depth ~

400 - 600 m

thickness ~

2 - 7 m

9/22/2011

12


Example of a Wormhole on Surface


Far Field Reservoir Drainage

Andrew Squires and Earl Jensen

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13


Stimulating Sand Production

Where does new failure occur?

In reservoir at tip of wormhole network enhances drainage

Near well at edge of cavity neutral or negative impact on inflow

Reservoir Near well


Completion Objectives

To initiate sanding: Initial sand production

history of a well affects its long term productivity

9/22/2011

14


0

5

10

15

20

25

0 360 720 1,080 1,440

Production Time (days)

Oil

Ra

te (

m3/d

ay

)

with

sand

without

sand

Cold Production

Field Oil Production Rates


0

5

10

15

20

25

0 360 720 1,080 1,440


Oil R

ate

(m

3/d

ay)

0.0

0.2

0.4

0.6

0.8

1.0

Sa

nd

Rate

(m

3/d

ay)

Field Oil Rates

Field Water Rates

Field Sand Rates

Field Behavior

Typical Good Well

9/22/2011

15


0

5

10

15

20

25

0 360 720 1,080 1,440


Oil R

ate

(m

3/d

ay

)

0.0

0.2

0.4

0.6

0.8

1.0

Sa

nd

Ra

te (

m3/d

ay

)

Field Oil Rates

Field Water Rates

Field Sand Rates

Foam Job for 6-33

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

07/11/19

99 9:36

07/11/19

99 14:24

07/11/19

99 19:12

08/11/19

99 0:00

08/11/19

99 4:48

08/11/19

99 9:36

08/11/19

99 14:24

08/11/19

99 19:12

09/11/19

99 0:00

09/11/19

99 4:48

09/11/19

99 9:36

09/11/19

99 14:24

Perc

en

tag

e R

eco

vere

d (

%)

Series1 Series2 Series3 Series4

Achieved during a stable foam

operation on a new complletion

In 40 hours produced:

117m3 sand

222m3 oil

90m3 water

Aggressive Sand Production


inflow

Imposed p

matrix failure when: p pc

wormholes

filled with sand

wormholes

partially filled with sand

Sand Matrix Failure

Wormhole Growth

Sand and Fluid Transport

Stages of Development

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Tip of wormhole network to well

EITHER: Plug flow in filled wormholes

high produced sand cut

~ 20-40%

Mobile SandMobile Sand



OR: Stratified flow in open wormholes

low produced sand cut

~ 1-2%

Flowing Oil

Immobile Sand

Mobile Sand

Flowing Oil

Immobile Sand

Mobile Sand


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Wormhole Growth


Wormhole Growth

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18


Field Predictions

Dynamic Wormhole Growth


Wormhole Growth

Wormhole Structure

20 cm 10 cm

wormhole cast after

removal

imprint left when cast

was removed

Tensile failure bands

loose sand

9/22/2011

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Wormhole Growth

Wormhole Configuration

Sand Pack

36 cm

80 cm

30 cm

Top

Orifice

Bottom

Orifice


Wormhole Growth


80 cm

30 cm

Top

Orifice

Bottom

Orifice

Sand Pack

24

cm

9/22/2011

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Wormhole Growth


44 cm

80 cm

30 cm

Top

Orifice

Bottom

Orifice

Sand Pack


Wormhole Growth

Critical Pressure Gradient

reduced by foamy oil expansion of gas bubbles

Growth Rate

increases with pressure gradient

Diameter

increases with drained region

open (sand-free) area likely less than 10 cm in

diameter

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Wormhole Growth

Interaction

wormholes compete for drainage

Darwinian behaviour some grow, some wither


Sand Matrix Failure

Formation Strength

unconsolidated sand low cohesive strength 5 – 20 kPa

fines content increases strength

capillary pressure capillary cohesion

high oil viscosity dynamic strengthening

slight cementation substantial strength increase

9/22/2011

22


Field Implications

Operate wells at low enough pressure to allow

continuing sand production

Wormholes tend to grow first and

predominantly in weakest sand and toward

highest pressure gradient

Wormholes don‟t necessarily grow from each

perforation – dependant on sand strength

Wormholes usually stable


44 Petrovera, Elk

Point Battery

9/22/2011

23


Foamy Oil

Large numbers of

persistent gas

bubbles in oil

Generated by de-

pressurization of live

heavy oils


Dissolved

Gas

Small

Bubbles

Connected

Bubbles

Large

Bubbles

Oil Phase Gas Phase Immobile

Bubble Growth and Gas Transport

Dynamic Partitioning

9/22/2011

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Bubble Growth and Gas Transport

Microbubbles

Interconnected

bubble clusters

Small bubbles

( pore throat)

Flow with oil

Immobile

Free gas flow

Incre

asin

g t

ime,

and/o

r expansio

n

Large bubbles

( pore throat)


Field Implications

Operate wells at low enough pressure to

obtain rapid local gas exsolution

Surprisingly high ultimate recoveries, due to

high apparent critical gas saturations

Large blasts of gas when growing wormhole

network and growing zones of interconnected

bubble clusters connect

9/22/2011

25


Conclusions Courtesy of Ron Sawatzky AITF

Gas Production

dissolved gas likely only source of produced gas for 2 wells

additional external gas source may exist in 2 wells

(petrophysics indicates source present, flow path uncertain)

Oil Production

reasonable rates can be maintained at fairly high producing GOR:

i.e. ~ 10-20 initial GOR

Draw Down

oil production rates and recovery enhanced by rapid draw down


When Cold Production Fails

Well

well bore sands off

Near well

perforation plugging

shale / coal failure collapse or blockage

casing failure

Reservoir

wormholes plug, collapse, stop growing

watering out

gas breakthrough

permeability reduction from fines, formation debris, wax precipitation and wasted solution gas

Important to understand for diagnosis

9/22/2011

26


Complex Flow

Phases - gas, water, oil , sand and solids

Variables

Mobility

Cuts - time

Viscosity (oil) – time – depth

Sources of water and gas in the drainage geometry

Sources (gas) – free or solution?


Where Blockage Can Happen

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Debris Causing Blockage Material

Formation

Pyrite

Shale

Coal

Chert

Asphaltenes

Waxes

Complex sands, silts and

clays

Will probably re-occur

Other

Drilling mud

Cement

Perf debris

Possible to remedy with

workover/s


Example of Debris

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Sand plugging, bridging and arching

From gravel pack literature: Tendency for bridging = k Dsand grain/Dgravel

Capacity for unrestricted flow = k` Dperf/Dsand grain

Dr.Tariq Schlumberger

Studies concluded ratios from 3:1 to 16:1 hole

size to flowing solid size

Coal

Can Be a water source, check offsets

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Carbonate Example

Note SP and Pe response


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Can be useful to identify shale collapse

Warning: GR is statistical… don‟t read too much

into subtleties if the logs show different character

- the borehole has changed (casing & cement)

Gamma Ray (GR)

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Compensated Neutron Log (CNL) Diagnostic Log

Note GR and N Porosity Differences

CNL Diagnostic Log

Open Hole Log


Can be useful to identify coal shifts

Warning: N is statistical… don‟t read too much

into subtleties if the logs show different character

- the borehole has changed (casing & cement)

Cased Hole Neutron Logs (CNL)

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50/50 Deep Penetrator(DP) / Big Hole (BH) or eXtra Big Hole (XBH)

Politically correct – why didn‟t you use …?

How thick is the cement sheath? – use

manufacturer‟s model to determine

penetration through the sheath – usually the

cement sheath is not that thick

Can you shoot through drilling fluid loss

damage?

Increased volume of traumatized zone?

Sacrifice of flow area


Traumatized zone DP vs. XBH

XBH

DP

Damaged zone

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A New (Better) Configuration Than 50/50

26 Shots Per Meter (SPM) – 20 XBHs and 6

DPs

1/3 DP by 2/3 XBH 26spm

Or

2:1

Less sacrifice of flow area

Consistent with production performance data

New - suppliers need lead time


Penetration versus compressive strength

Steel

Rock

Unconsolidated

sand

Target Charge

< + -1000 psi

compressive

strength

Penetration increases

Jet dispersion increases - penetration decreases

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9/22/2011

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Casing and Cement Issues

Un-supported casing and cement is more likely

to fail

Do you perforate through collars?

Not recommended for thermal operations

Depends on how thick the zone is

many don‟t


Overburden

Completely

failed region Probable

casing

failures

Current Trend Is Not To Shoot Through Collars

Do not perforate on the same

horizontal plane in environments

where this occurs

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Example of perforation damage to unsupported casing

Before After

No severe

damage

from

perforating

9/22/2011

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Re-perforating Trends

Not popular ‟70s Bob Hayes “ Do we need more

holes or are we just shaking things up?”

Early ‟80s +- 10% successful

Mid ‟90s optimizations with PCPs – 90%

successful

2000 – casing and cement damage!!

2005 – missed pay and stimulation


Perforating debris from a

127mm 6 meter 26 spm

DP / XBH gun

Debris magnets are

recommended

Perforating Debris

9/22/2011

39

77

Questions and

Discussions


Extending Cold Production Applications

Stepping out from core heavy oil region NW ~ sands weaker, oil more viscous

SE ~ sands stronger, oil less viscous

Kuwait, Alaska, Venezuela, Columbia, Albania, Argentina

Broader variation in reservoirs heavy oil sands are not uniform

differences occur over many scales field to field

pool to pool

zone to zone

interval to interval

well to well

9/22/2011

40


Heavy Oil Completions

Can we throw out the cookie cutters?

Alternate cookie cutters (methods)

Methods specific to the reservoir


The cookie cutter:

Perforate aggressively under balanced Tight phasing, big hole, high shot density

Most of the zone

Rapidly clean out with Pump To Surface (PTS), bailer or put on production with a Progressive Cavity Pump (PCP)

Produce aggressively with PCP with as low as possible fluid level

30% of CHOPS wells fail

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41


Shale Spalling

Establish a buffer layer

Buffer Layer

De-pressurized shale from large draw

down causes tiny particulate shale debris


Minimize shale spalling

Strategy for reducing risk

identify a buffer layer below shale to be not perforated

thickness of buffer layer may depend on thickness of

zone

maintain a conservative draw down and avoid well

bore trauma

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Shale Collapse


Stable pillars

Casing Failure and Shale Collapse

9/22/2011

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Casing Failure and Shale Collapse

Strategy for reducing risk perforate balanced or slightly under balanced

perforate less aggressively with no more than 120 ,180 or 0 phasing

slowly increase pressure draw down until production is initiated

produce at a constant draw down until risk of destabilizing near well region becomes small (i.e. wormhole network is growing away from well)

stable pillars harder to establish and maintain in thicker zones and are easy to establish between laminations

steady draw down propagates worm hole growth of the weakest sands


Laminate pay example

$400k in rubble workovers

Shale

9/22/2011

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Laminate Pay Collapse

4.0 m perforations -104 shots



Extraneous water path

Fragmentation

9/22/2011

45



•17 SPM

•0 degree phasing

•Or just perforate the permeable lenses

Less density/number and fewer

vertical planes less break up of

shale laminations or alternate

perforating means


Penetrators

Mill a 25.4mm window in casing

Drill a 25.4mm, 2 meter horizontal hole

Tool is controlled and activated by changing

circulation rates and presuures

Minimizes cement and shale fragmentation

Overcomes drilling and fluid loss damage

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Example #2

Penetrated 8 x 1” holes at 90o


Example #2 Production

Well watered out

Discontinuous shale?

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Penetrator conclusions

Sustained production was achieved with a

minimum of holes and flow area

Proper clean up was achieved with chemicals

and 24 -36 hour PTS operations


Cost Comparison Courtesy of Ryan Rueve, Nexen

Pump to Surface (PTS) (with Tubing Conveyed Perforating (TCP) vs Perforating While Foaming (PWF) (TCP)

PTS (4 days with Rig)

Rig (38 hrs) $13,680

Consultant $3,000

PTS Tool $2,500

Pressure/Vac $1,500

Total PTS costs $20,680

PWF (3 days with Rig)

Patented

Rig (29 hrs) $10,440

Consultant $2,250

Foam Unit $8,000

Pressure/Vac $2,200

Total PWF costs $22,890

Extra cost to PWF is approx $2,200. This is saved by less

workovers caused by sand in months after the completion. Costs not included above are: perforating, tubing, rods, pump, etc. These

items are the same in both scenarios.

9/22/2011

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Nexen Cactus Lake Field

19 20

2930

31 32

20 21 22 23 24

2526272829

32 33 34 35 36

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T35

T36

T35

T36

R27W3R28

R27W3R28

Map Software by IHS Energy

Reservoir Properties

•Bakken/Basal Mannville

•~850 mKB (80m Sub Sea)

•Gravity: 16API

•Density @ 15ºC = 965kg/m3

•Viscosity @ 30ºC = 500cP

•Porosity: 30-33%

•Permability: 2,000-4,000 md

Located 130km South of Lloyd in

SK


Sand Cut Comparison of PTS & PWF

0

5

10

15

20

25

30

San

d C

ut

(%)

D1

6-

21

C9-

27

D7-

27

B7-

33

A8-

36

C5-

31

D5-

22

PTS

PWF

9/22/2011

49


Filtered data 3 vs 3 wells – first month

Average Monthly Oil Production for Fields By Completion

0

100

200

300

400

500

600

700

800

900

0 5 10 15 20 25 30

Months Since Completion

Cu

mu

lati

ve

Mo

nth

ly O

il P

rod

uc

tio

n (

m3)

Nexen PWF Wells Nexen PTS Wells Offset Wells


31/09 PTS

9/22/2011

50


21/07 PWF


Economics of more aggressive completions:

3 wells verses 3 wells for the 8 months after the

first month

The aggressive competed wells produced

4850 m3 more oil

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51


Observations From Data

Take it with a grain of salt especially the filtered data

Excellent period of production

PWF wells are to the outside of the pool (good and bad)

PTS well 3.1 meters of perforations did quite well


Perturbation

Definition: Positive or negative pressure change

Can be as minute as varying the hydrostatic head from reciprocating pumps

OR

As large as massive pressure changes from foaming and the use of propellants (i.e. 60 MPa)

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Pressure Perturbation Limits

Dissipates rapidly as it propagates from the

wellbore

Viscosity prolongs pressure rise and fall time

Friction losses occur along permeability

channels


Average Daily CSE Sand Production / Well 25 Well Sample

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

1 2 3

Before During After

m3

Why Do Continuous Sand Extraction

(CSE) (CPTS) Pumps Produce More Sand

???

Drainage Geometry Conformance

9/22/2011

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CSE surge pump CSES

Canadian Patent 2,232,948


Overburden pressure Negative well bore pressure perturbation

De-stabilizing sand bridges

Perforation

or pore throat

9/22/2011

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Overburden pressure

De-stabilizing sand bridges Positive well bore pressure perturbation

Perforation

or pore throat


CSES

0

500

1000

1500

2000

2500

3000

1 2

3 M

th C

um

ula

tiv

e M

3 o

f O

il

Before and After

Comparison of 8 Wells Showing Production 3 Mths Before and 3 Mths after Tool Installation

Includes 3 wells that

were Shut In Prior toinsertion

Avg 4m3/d

9/22/2011

55

Steady draw down worst case scenario


Steady pressure gradient

Greatest pressure

gradient

at tip

Intact formation

Lower pressure gradient

laterally

more stability

Perturbed draw down


Intact

formation

Intact formation

Fluctuating pressure gradient

9/22/2011

56


Drainage Geometry Control

Perturbations conforms drainage

Steady draw down propagates worm hole

growth of the weakest sands


Drainage Geometry Control

Perturbations conforms drainage

Perturbations dissipate rapidly

Employ immediately after completion

9/22/2011

57


Continuous Sand Extraction with surge Tool (CSES) Applied on Completion – Drainage Geometry Conformance

Advantages Pumping equipment is capitalized

The pumps can economically rebuilt in extreme sand cut environments

The surge action enhances sand failure – conforming wormhole initiation and destabilises bridging

Needs to be applied upon completion Surge action only effects near well

Study in progress 3 new completions are being equipped with CSESs


Example of Downhole Pressure Perturbation With CSES

9/22/2011

58


Offset PCP example – 3.46m3/d average

Co

mple

tio

n P

CP

Pum

p C

ha

nge

0

10

20

30

40

50

60

70

80

90

100

-

5.00

10.00

15.00

20.00

25.00

30.00

35.00

30

-Se

p-2

01

0

30

-Oct-

20

10

30

-No

v-2

01

0

30

-De

c-2

01

0

30

-Ja

n-2

01

1

1-M

ar-

20

11

BS

&W

(%

) &

Sa

nd

Cu

t (%

)

Pro

du

cti

on

An

d L

oa

d F

luid

(m

³/d

) Well 06D-20

Average production - 3.46m3/d

Gross Fluid (m³/d) Gross Oil (m³/d) Net Oil (m³/d)


CSES Applied on Completion – 7.33m3/d average 20% sand cut

Co

mple

tio

n

CT

U

CT

U

Pum

p C

ha

nge

CS

ES

CT

U

Pum

p C

ha

nge

P

CP

0

10

20

30

40

50

60

70

80

90

100

-

5.0

10.0

15.0

20.0

25.0

30.0

35.0

30

-Se

p-2

01

0

30

-Oct-

20

10

30

-No

v-2

01

0

30

-De

c-2

01

0

30

-Ja

n-2

01

1

1-M

ar-

20

11

BS

W (%

) &

S

an

d C

ut

(%)

Pro

du

cti

on

An

d L

oa

d F

luid

(m

³/d

)

Well 10B-20


9/22/2011

59


CSES Applied on Completion - 6.74m3/d avg 66 % sand cut

Co

mple

tio

n

Pum

p C

ha

nge

C

TU

CT

U

Pum

p C

ha

nge

Pum

p C

ha

nge

- T

em

p P

TS

Pum

p C

ha

nge

CS

ES

Pum

p S

erv

ice

0

20

40

60

80

100

120

-

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

45.00

50.00

31

-Ma

y-2

01

0

1-J

ul-2

01

0

31

-Jul-2

01

0

31

-Aug-2

01

0

30

-Se

p-2

01

0

30

-Oct-

20

10

30

-No

v-2

01

0

30

-De

c-2

01

0

30

-Ja

n-2

01

1

1-M

ar-

20

11

BS

&W

(%

)

Pro

du

cti

on

An

d L

oa

d F

luid

(m

³/d

)

Well 11B-20



Questions and Discussion

9/22/2011

60


Pump Problems?

Bridging in tubing

Plug off at intake

Plugged off inflow

Bridging in the Annulus

Possible Solutions:

Plug off at intake Loading and continuous loading

Flush by

Scope flush by

Scope foam head

Service rig – circulate down, sand line bail , tubing bail or foam clean out

Charge/booster pump

Extended rotors

Paddle rotors

BHP landing Depth

Gizmo’s

Tail joints

Perforated joints

Perforated tag bars

Hollow rods

Hollow rotors

Multi intake PCPs

CSE – ETU through THIGK valves

Others?

Bridging in annulus Loading and continuous loading

Reciprocating tubing pumps

Coil tubing the annulus

Others?

Bridging in tubing Smaller ID tubing

Sand suspension chemicals

Loading and continuous loading

Flush by

Coil tubing clean out

Downhole gas separators

Others?

Inflow Blockage Loading

Chemicals

Stable foam stimulation

Scope foam head

Re-perforating

Circulating

Perforation wash

Bailing / swabbing

Sebree tool

Propellant stimulation

Abrasi-Jet, Penetrators

Reciprocating tubing pumps

CSES

Others?

9/22/2011

61


Decline Rates for Diagnostics

Catastrophic

Mechanical

Shale collapse

Near well bridging

Hours to a week

Gradual

Loss of foamy oil drive

Flow impairment from

load fluid

Formation bridging

A week to months

Recon CHOPS Calgary Sept 21, 2011

Approaches to Cold Heavy Oil Production: Workover Practices and Strategies

March 15th, 2000

Tropical Inn – Lloydminster AB

M. Dusseault, K. Hayes, M. Kremer, C. Wallin

9/22/2011

62


The Tools Reviewed in the Workshop

Loading

Continuous loading

Circulating

Flushes and superflushes

Swabbing

Sand line bailers

Tubing bailers

Select perf washes and perf

cleaning

Coil tubing and CTU flushes

Pump to surface

Portable PTS

Continuous PTS

Re-perf

Chemical treatments

Propellant stimulation

Stable foam clean outs (tubing)

and stimulations

Coil tubing foam clean outs

Abrazi jet

Proppant/Hydraulic fracturing

Pressure pulsing


Stuff Not Reviewed in the Workshop

Mechanical remedies list

Sebree tool

Scope tool

CTU/ flush units

Gas management

Sand management

CSE with surge tools

Balls checks for PTS

Others?

Completion strategies

Shale strategies

PAPWF

Delayed water

encroachment

Combined and staged

approach

Others?

9/22/2011

63


Staged Approach

Minimize risk

Diagnose, confirm, determine the extent of the problem

Treat and evaluate treatment

Re-treat or attempt a different treatment

Evaluate

Produce with a different production strategy

Abort when necessary

Example: Severe Inflow Blockage Program (SIBP)

A work in progress


Post Workover Production Strategies

Change production rates

Change pumping fluid level and/or annular

gas pressure

Change pumping equipment

Start or modify load program

And so on, and so on …

Congruent with workover strategy

9/22/2011

64


The Pitfalls:

Cookie cutters and magic pills

Without proper diagnosis, too frequently

Flush Production

Flavor of the week and trends

The lure of the latest and greatest

Successes – misplaced credit

Too rapid or slow application – tracking

Complacency

Changing too many variables

Lowered one servicing cost but increasing another

Wrong diagnosis – wrong conclusion (that doesn‟t work)


The 80/20 Rule

Spending 80% of the time working on

20% of the production

Can we make good wells better?

9/22/2011

65


Canadian

Patent

2,232,948


Positive well bore pressure perturbation

Intact formation

Dilation/failure by pressure

9/22/2011

66


Dilation/failure by pressure

Intact formation

Overburden

pressure

Negative well bore pressure

perturbation


Negative Perturbations Naturally More Conformed

Energy

is virgin

reservoir

pressure

More and stronger

perturbations are better

9/22/2011

67


Live Oil Viscosity

0

10,000

20,000

30,000

40,000

50,000

60,000

0 1,000 2,000 3,000 4,000 5,000 6,000

Pressure (kPa g)

Vis

co

sit

y (

mP

a.s

)


Loss of Solution Gas

Reservoir heterogeneity

Asymmetric drainage geometry from wormhole growth

Blockages caused by formation debris

Water and/or gas breakthrough

Casing venting during production interruption or production suspension

While producing the more mobile portions of the reservoir, the less mobile become more so

9/22/2011

68


Viscosity increases Weakest sand

Oil and sand

production

Ex-solving gas Ex-solving gas

Near Well Bore Blockage


Near Well Bore Blockage

Depleted Zone

Dead Oil

SCHMAG

Path of Least

Resistance and

That Is NOT

Where the

Problem Is

Treatment

Fluid

9/22/2011

69


SIBP Example – 11-23

Mid Oct „05 executed SIBP

Cutter stock was pulsed to treat SCHMAG

Fluid level rose

Foam circulation and surging produced debris and oil operation continued for 3 days

Installed CSES to de-stabilize debris and sand bridges

Producing 9 m3/d with 16 joints of fluid


OH GR Diagnostic GR

Diagnostic Logs for 11-23

9/22/2011

70


Production Data for 11-23


Production Data for 11-23

0

4

8

12

16

20

0 1 2 3 4 5

Production Time (months)

Oil

Pro

du

cti

on

Ra

te (

m3/d

)

Post CSES

9/22/2011

71


Another Staged Intervention C1-18

Chemicals were placed by a perf wash tool to

treat SCHMAG and left 7 days to soak

Sebree tool and bailing were used to remove

debris from the well bore and near well area

over a 2 day period


Incremental Production for C1-18 During Intervention

0

5

10

15

20

25

0 3 6 9 12 15

Production Time (hours)

Cu

m O

il P

rod

uc

tio

n (

m3)

Equivalent Calendar

Day

Production Rate

32.8 m3/d

9/22/2011

72


Production Data for C1-18

0

2

4

6

8

10

0 6 12 18 24 30

Production Time (months)

Oil

Pro

du

cti

on

Ra

te (

m3/d

)

Staged

Intervention

144

Questions and

Discussions

9/22/2011

73


Chemical and/or fluid stimulation

Should be done with pressure perturbations

Enhances formation access

Adds energy to the reaction

Dislodges blockage mechanisms

Initiates particulate movement

Volumes should be relative to produced sand


Odyssey Tool

9/22/2011

74


Conventional Perf Wash Tool


148

Perf wash

9/22/2011

75


149

Perf wash


Just load chemical

9/22/2011

76


Chemical placed with positive

perturbations


A Successful Odyssey Tool Job

13C-12-57-2: Production Rate of Oil/Water (m3) Versus Weeks from Before & After Usage of

Pulsating Pulse Powerwave Tool

0

1

2

3

4

5

6

7

8

0 5 10 15 20 25 30

# of Weeks (April 1/2010 - October 1/2010)

Pro

du

cti

on

of

Oil

/Wa

ter

(m3

)

Avg. Measured Oil (m3) Avg. Measured Water (m3) Linear (Avg. Measured Oil (m3)) Linear (Avg. Measured Water (m3))

Sparky Formation

Zone

Post Powerwave Oil & Water Production

Trends

Pre-Powerwave Oil &

Water Production

Trends

Stimulation Intervention

(Approx. @ Week 6)

9/22/2011

77


A successful perf wash Tool Job

9C-24-53-6: Production Rate of Oil/Water (m3) Versus Weeks from Before & After Perf Wash

0

5

10

15

20

25

0 1 2 3 4 5 6 7 8 9

# of Weeks (Aug 1/2010 - November30/2010)

Pro

du

cti

on

of

Oil

/Wa

ter

(m3

)

Avg.Measured Oil Avg.Measured Water Linear (Avg.Measured Water) Linear (Avg.Measured Oil)

Stimulation Intervention

(Approx. @ Week 2)

Sparky Formation Zone

Cum Oil After Intervention: 1179.01 m3

Cum Water After Intervention: 867.28 m3


Odyssey Pulse Tool vs Perf Wash Tool Study

Definitions : Technical success: Sustained production for 3 months or the limit

of the data of at least half of prior peek production

Pay out success: Can not be an economic success if not a technical success and has sustained production for 3 months or the limit of the data of 1.5m3/d

Profitable success: Same as above but with sustained production of 5m3/d

9/22/2011

78



All wells were relatively new (i.e. weeks to 2 months)



Technical Fail Payout Fail Profitable Fail

Perf wash

1 1 1 1

2 1 1 1

3 1 1 1

4 1 1 1

5 1 1 1

6 1 1 1

7 1 1 1

8 1 1 1

9 1 1 1

10 1 1 1

11 1 1 1

12 1 1 1

13 1 1 1

14 1 1 1

TTl 5 9 3 11 1 13

36% 64% 21% 79% 7% 93%

9/22/2011

79



Odyssey Technical Fail Payout Fail Profitable Fail

1 1 1 1

2 1 1 1

3 1 1 1

4 1 1 1

5 1 1 1

6 1 1 1

7 1 1 1

8 1 1 1

9 1 1 1

10 1 1 1

11 1 1 1

12 1 1 1

13 1 1 1

14 1 1 1

15 1 1 1

16 1 1 1

TTl 14 2 9 7 4 12

88% 13% 56% 44% 25% 75%


Odyssey Pulse Tool Different Well Set – older wells – public data

Old wells Technical Fail Payout Fail Profitable Fail

1 1 1 1

2 1 1 1

3 1 1 1

4 1 1 1

5 1 1 1

6 1 1 1

7 1 1 1

8 1 1 1

9 1 1 1

10 1 1 1

11 1 1 1

12 1 1 1

13 1 1 1

TTl 4 9 4 9 3 10

% 31% 69% 31% 69% 23% 77%

9/22/2011

80


Latest Study - ?

Started with Severe Inflow Blockage Program and Inflow and Production Impairments from Loss of Solution Gas in Cold Production - Sawatzky and Hayes

Chemical pill and chase fluid volume is relative to the produced sand (i.e. 20%) Combined intervention using Odyssey tool for chemical

placement and Sebree swab tool to re-establish solution gas drive.

2 wells done to date. The first has 2 weeks of 9.3m/d production with 38.5% BS&W with 13 joint fluid level to chase.

The second well operations were suspended due to extremely high sand cuts – a foam clean out is planned.

6+ jobs are in the works


Loss of Solution Gas

Reservoir heterogeneity

Asymmetric drainage geometry from wormhole growth

Blockages caused by formation debris

Water and/or gas breakthrough

Casing venting during production interruption or production suspension

Under balance events during drilling and/or completions

While producing the more mobile portions of the reservoir, the less mobile become more so

9/22/2011

81


Sebree Swab Stimulation on a Disposal Well

In 9hrs recovered 158m3 of water and 25m3 of sand

Prior injection was less than 300m3/d and inadequate

Currently the well is taking 400m/d on vacuum


Sebree Swab Tool Current Initiative

Rigless Completions: Manage completion and

construction costs on new drills

To ensure inflow is established from problems such as low pressure, drilling damage and reluctant gas break out.

To enhance gas break out and conform sand failure; optimizing drainage geometry

9/22/2011

82


Case History – Alberta Pressure Pulsed Water Flooding

0

50

100

150

200

250

01

/11

/06

01

/12

/06

01

/01

/07

01

/02

/07

01

/03

/07

01

/04

/07

01

/05

/07

01

/06

/07

01

/07

/07

01

/08

/07

01

/09

/07

01

/10

/07

01

/11

/07

01

/12

/07

01

/01

/08

01

/02

/08

01

/03

/08

01

/04

/08

01

/05

/08

01

/06

/08

01

/07

/08

01

/08

/08

01

/09

/08

01

/10

/08

01

/11

/08

Oil R

ate

(b

op

d)

- 3

Po

we

rwa

ve

Pa

tte

rns

Pattern 1 Oil Rate Pattern 2 Oil Rate Pattern 3 Oil Rate 2.6 %/mo Harm. Decl.

Decline Match Points Pattern 1 Powerwave Pattern 2 Powerwave Pattern 3 Powerwave


Pulsed Polymer Flooding

Conventional water flooding is expanding to more viscous reservoirs

Pressure pulsed water flooding currently deployed in 500 – 1000cps reservoirs

CNRL‟s polymer flooding experience is economically successful up to 10,0000cps or greater

Pulsed polymer flooding will be able to increase flooding applications to - ?

Its possible to implement pulsed polymer flooding very soon

Pulsed polymer flooding is the least riskiest EOR option

Imagine pressure supported production in the CHOPS region

9/22/2011

83


Enormous Drainage Geometries

after Andrew Squires and Earl Jensen


.

9/22/2011

84


Dual induction and

SFL curve example

9/22/2011

85



Gas Cap

“Extraneous” Water

Oil

Seal

“Extraneous” Water

Wormhole

Seal

FormationWater

Potential Water Sources in Oil and Gas Wells

9/22/2011

86


-120

-100

-80

-60

-40

-20

0

0 2 4 6 8 10 12 14 16

Time

100%

0%

% Water Cut

Progressive incursion of water

from non-producing zone

(formation "B") results in

intermediate compositions.

Formation "B"

Formation "A"Water Coning Trend

Water Incursion(Behind Pipe)

Water cut may

or may not increase.

Initial Production WaterComposition (Sw)

Mass-Balance equations may determine how

much of each water source is being produced.

Production Water Origin and Isotopic Changes with Time/ Source


9/22/2011

87


HDD Examples 133 Samples Per Meter (SPM)

Demonstrates value for picking intervals to avoid

shale damage

Demonstrates the potential for exploiting oil over

water where vertical permeability impairments

exist – current works in progress Ex 4

Perfs 535 -538

Of interest 547 -550

vertical permeability

impairment may stop

bottom water?

Ex. 1

Mini Plot

9/22/2011

88

Ex. 1

Perforated interval

Ex. 1

Permeability impairment

9/22/2011

89

Perfs 525 – 527.5

Ex. 3

Of interest 534 -535

vertical permeability

impairment may stop

bottom water?

Mini Plot

Ex. 3

Perforated interval

9/22/2011

90

EX 4


EX 4

Permeability impairments

Proposed perfs

9/22/2011

91


HDD Example 5

Demonstrates value for picking gas interval

permeability 442.3 – 442.5 over possible water

???

Demonstrates thin zone between carbonate

lenses at 447.2 – 447.7

Ex 5

9/22/2011

92


Ex 5

Proposed

perfs

Proposed perfs


High Resolution Example

Schlumberger high definition log

Demonstrates laminate cap rock

Example well had severe inflow blockage (see

pictures from intervention)

Perforations 446.0 to 452.0

9/22/2011

93


Normal Resolution


High Resolution

9/22/2011

94



A Completion Example

Proposed 8 meters of perforations

9/22/2011

95


A Completion Example High Definition Data (HDD) Log

Suggested 3.4 meters of perforations

Only shot 1.8 meters too much sand

inflow rigless operation

Well produced about 15m3/d


Top Water Example of Extreme Density Oil

9/22/2011

96


Questions and Discussions

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Cold Heavy Oil Production with Sand Workshop

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