Formation Damage – Effects and Overview

Formation Damage – Effects and Overview

• Where is the damage?

• How does it affect production?

8/25/2015 1 George E. King Engineering

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Impact of Damage on Production

• Look at Effect of Damage

• Type of Damage

• Severity of Plugging

• Depth of Damage

• Ability to Prevent/Remove/By-Pass


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Horizontal Well Formation Damage Theories

Zone of Invasion - Homogeneous Case

50423009

Is damage evenly spread out along the well path or does it go down the highest permeability streaks?


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Horizontal Well Formation Damage Theories Zone of Invasion - Heterogeneous Case

50423010 8/25/2015 5

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Observations on Damage

1. Shallow damage is the most common and makes the biggest impact on production.

2. It may take significant damage to create large drops in production

3. The problem, however, is that the highest permeability zones are the easiest to damage, and that can have a major impact on productivity.


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Pressure Distribution Around a 200 md Oil Well

2000

2100

2200

2300

2400

2500

2600

2700

2800

0 200 400 600 800 1000 1200

Radial Distance, ft

Pre

ss

ure

, p

si

World Oil, Modern Sandface

Completion Practices, 2003

The pressure drop around an unfractured wellbore shows the importance of the near wellbore on inflow. If this area is significant damaged, the effect is immediately noticeable.


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Effect of Depth and Extent of Damage on

Production

0

10

20

30

40

50

60

70

80

90

100

0 1 2 3

Radial Extent of Damage, m

% o

f o

rig

ina

l F

low

80% Damage

90% Damage

95% Damage

1. The most noticeable damage impacts the the well in the first 30 cm or 12 inches of the formation.


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Effect of Damage Layer Thickness

0.001

0.01

0.1

1

0.01 0.1 1 10

Damaged Perm, % of initial

Pro

du

cti

vit

y

Rati

o

0.01" thick

0.05" thick

0.1" thick

1" thick

2. The effect of the damage thickness compared with the amount of damage (as a percent of initial permeability). Only the most severe damage has a significant effect in a thin layer. (Darcy law beds-in-series calculation)


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Productivity Loss From Formation Damage

0.25

0.3

0.35

0.4

0.45

0.5

0.55

0.6

0.65

0.7

0.75

0.8

0.85

0.9

0.95

1

0 2 4 6 8 10

Depth of Damaged Zone, inches

Pro

du

cti

vit

y a

s a

Fra

cti

on

of

Un

da

ma

ge

d P

rod

.

Kd/Ki = 0.5

Kd/Ki = 0.2

Kd/Ki = 0.1

Kd/Ki = 0.05

Kd/Ki = 0.02

World Oil, Modern

Sandface Completion

2. (continued) As the damage layer thickens and becomes more severe, the impact on production builds quickly.


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3. Highest permeability zones are easiest to damage: Pore Size vs. Permeability

y = 1.3661x2.4865

R2 = 0.982

0

50

100

150

200

250

300

350

0 1 2 3 4 5 6 7 8 9 10

mean hydraulic radius (mm)

perm

eab

ilit

y (

mD

)

SDA-01 Balakhany X (SP2) Hg permeability mDSDA-01 Fasila B (SP3) Hg permeability mDSDA-02 Balakhany VIIIC Hg permeability mDSDA-02 Fasila D (SP4) Hg permeability mDK mDPower (K mD)

MI for BP SD field

Large connected pores and natural fractures dominate the permeability of a formation.

The size of particles that can cause damage in these larger pores is larger than 1/3rd and smaller than 1/7th. For a 8 micron pore, the small size

would be 1 micron and less.


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The Effect of Damage on Production

Rate = (DP x k x h) / (141.2 mo bo s)

Where:

DP = differential pressure (drawdown due to skin)

k = reservoir permeability, md

h = height of zone, ft

mo = viscosity, cp

bo = reservoir vol factor

s = skin factor

What are the variables that can be improved, modified or impacted in a positive way? 8/25/2015 12


Productivity and Skin Factor

• Q1/Qo = 7/(7+s)

Where:

Q1 = productivity of zone w/ skin, bpd

Qo = initial productivity of zone, bpd

s = skin factor, dimensionless

Just an estimation, but not too far off between skin numbers of zero and about 15.


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Productivity Ratio vs. Skin Factor

0

50

100

150

200

250

-5 5 15 25 35 45 55

Skin Factor

Pro

du

cti

vit

y F

ac

tor,

%

Range of Skin Factors

Associated with Frac Pack

Range of Skin Factors Associated with

Cased Hole Gravel Pack Completions

A better presentation of the damage from increasing skin factor. Skin only has an impact if the well can really produce the higher rate and the facilities can process it.


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Example

• Productivity for skins of -1, 5, 10 and 50 in a well with a undamaged (s=0) production capacity of 1000 bpd

• s = -1, Q1 = 1166 bpd

• s = 5, Q1 = 583 bpd

• s = 10, Q1 = 412 bpd

• The best stimulation results are usually for damage removal and damage by-pass.

8/25/2015 15


Another way of stating damage - Damage in a horizontal well – increasing skin makes the well behave like the drilled lateral was much shorter.


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Damage Causes

• Obstructions in the natural flow path in the reservoir.

• “Pseudo” damage such as turbulence - very real effect, but no visible obstructions

• “Structural” damage from depletion – matrix compression, etc.


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Flow Path Obstructions

• Scale, paraffin, asphaltenes, salt, etc.,

• Perforations – 12 spf w/ 0.75” / 1.9 cm holes only opens 2% of the casing wall.

• Tubing too small - too much friction

• Any fluid column in the well, even a flowing fluid column holds a backpressure on the well: – Salt water = 0.46 psi/ft

– Dead oil = 0.36 psi/ft

– Gas lifted oil = 0.26 psi/ft

– Gas = 0.1 psi/ft (highly variable with pressure)


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“Pseudo” Damage

• Turbulence – high rate wells

– gas zones most affected

• Affected areas: – perfs (too few, too small)

– Near wellbore (tortuosity)

– fracture (conductivity too low)

– tubing (tubing too small, too rough)

– surface (debottle necking needed)


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“Structural” Damage

• Tubular Deposits

– scale

– paraffin

– asphaltenes

– salt

– solids (fill)

– corrosion products


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Perforation Damage

• debris from perforating

• sand in perf tunnel - mixing?

• mud particles

• particles in injected fluids

• pressure drop induced deposits – scales

– asphaltenes

– paraffins


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Near Well Damage

• in-depth plugging by injected particles

• migrating fines

• water swellable clays

• water blocks, water sat. re-establishment

• polymer damage

• wetting by surfactants

• relative permeability problems

• matrix structure collapse


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Deeper Damage

• water blocks

• formation matrix structure collapse

• natural fracture closing


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Other Common Damages

• fines migration (increasing skin)

• water blocks

• scale

• emulsions

• paraffin and asphaltenes

• turbulence – rate dependent skin

• perf debris

• Initial damage from mud and DIF’s 8/25/2015 24


Skin Components and Determination

• Total Skins (s’) = So + Stp + D Q

Where:

So = laminar skin

Stp = 2-phase skin

D = rate dependent skin

Q = rate


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Skin Components and Determination

• Multi-rate tests => So, Stp, D

• B/U Test => total skin, k

• 2 B/U Tests => So, D, k


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Cleaning Damage

• Most damage is removed by simple clean-up flow.

• How much drawdown?

• How long to flow it?

• How soon to flow it?

• To do it?


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Root Causes of Residual Damage After Clean-up Flow….

• High perm formations less affected?

– Major damage removers:

• Flow Rate per unit area,

• Flow Volume per unit area,

• Pressure pulse?

• Drawdown per unit area – a control?


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First Problem

We don’t understand cleanup by flow…

It’s a matter of flow rate and volume through a given area.


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For the same pay

thickness, a horizontal

well or a fractured well

may contact 100’s of

times more pay zone area

than a vertical well.

Now, think about the set drawdown – say

500 psi - per unit area, the velocity

generated, and the total volume per area.

A 10 ft pay in a

vertical well w/ 6”

diameter yields

contact area of 16 ft2

A 1000 ft pay in a

horizontal well w/ 6”

diam. yields contact

area of 1600 ft2

Clean-up flow is

“diluted” by the

length of interval

open at once for

cleanout.


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Which has the potential of cleaning

up faster and more completely?

Vertical well - 500 psi dd and

an inflow of 100 bbl/day/ft

spread out over just 16 ft2 will

generate a clean-up flow of

110 gal per hour per ft.

Horiz. Well – assume 5x more than vertical

flow (typical) – would generate 5000 bpd,

but spread over 1600 ft2 – and release a

clean-up flow of only 3 gal per hour per ft.

1000 bpd

5000 bpd


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Second Problem

• We don’t understand damage.

– How it got there

– How it is removed.

– How to prevent it.

– What operations put the well’s productivity at risk.


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Industry Frac Pack Oil & Gas Well Performance(permeability-thickness vs. skin)

-5

0

5

10

15

20

25

30

35

40

100 1,000 10,000 100,000 1,000,000

Permeability Thickness (md-ft)

Sk

in

Heidrun Gp

Harding Appraisal GP

MC109 Frac-Enzyme - Oil

Pompano - Oil

Mars FP - Oil

Mars HRWP

Marathon Data

Oryx HRWF- HI 379 - Oil & Gas

Elf Hylia X/L + HEC Tail - Oil

Ew ing Bank FP- Oil

DD FF EE

Some examples of GOM skins versus md-ft

Note the increasing skin in higher conductivity wells – why? It should be easier to remove

damage in higher perm formations. The key here is that turbulent (non-darcy or non

mechanical) skins are nearly always higher in high capacity wells – especially gas.

There are many damage mechanisms, but few are permanent if we learn how to remove them.


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Fluid Loss Rate from Pre Workover PI - Alaska

0

500

1000

1500

2000

2500

0 2 4 6 8 10

PI, bbls/day/psi

Da

ily

Lo

ss

, b

bls

SPE 26042

Cleanup examples from Alaska wells – high losses into high PI wells,

but…….


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% change in PI

-100

-80

-60

-40

-20

0

20

40

60

0 2000 4000 6000 8000 10000 12000

Total Fluid Loss, bbls

% c

han

ge i

n P

I o

n W

ork

over

…there was actually little correlation with amount lost.


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PI Change, Perfs Not Protected

-100

-80

-60

-40

-20

0

20

40

1 3 5 7 9

11

13

15

% C

ha

ng

e i

n P

I

Short Term PI Change

Long Term PI Change

0.3 0.5 1.1 2.1 3.1 6 18.9

PI of Wells

SPE 26042

Of higher importance was whether the perfs were protected or not.


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PI Change After Workover - Perfs Protected

-40

-30

-20

-10

0

10

20

30

40

50

1 2 3 4 5 6 7 8 9 10 11

% C

han

ge in

PI


Long Term PI Change

0.3 1.2 3.1 4.6 8.4

PI of wells

SPE 26042

When perfs were protected, that was little risk of long term damage.


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Damage in Fractured Wells with Unprotected

Perforations

-80

-70

-60

-50

-40

-30

-20

-10

0

1 2 3 4 5

% D

am

ag

e

PIi = 1.92

PIi = 6.21

PIi = 7.55

PIi = 7.55

PIi = 18.1

When the perfs were not protected, the well was damaged.


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Effect of Scraping or Milling Adjacent to Open

Perforations

-60

-50

-40

-30

-20

-10

0

10

20

1 2

% C

ha

ng

e in

PI


Long Term PI Change

Perfs not protected by

LCM prior to scraping

Perfs protected by

LCM

SPE 26042

One very detrimental action was running a scraper prior to packer

setting. The scraping and surging drives debris into unprotected

perfs.


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Kill Pills: Summary of Overall Effectiveness in

Non Fractured Wells

-25

-20

-15

-10

-5

0

5

10

1 2 3 4 5 6 7

% C

han

ge i

n P

I

Sized Borate Salts

(4)

Cellulose

Fibers (3)

Sized Sodium

Chloride (12)

No Near Perf Milling

(6)

Near Perf Milling or

Scraping (3)

No Near Perf

Milling (8)

SPE 26042

Near Perf Milling

or Scraping (10)

HEC Pills No Pills

Sized particulates, particularly those that can be removed, are much less

damaging than most polymers, even the so-called clean polymers.


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Third Problem

• We don’t know enough about timing of damage removal.

– Variety of causes • Polymer dehydration

• Decomposition of materials

• Adsorption, absorption and capillary effects

• Field data from Troika (100,000 md-ft) show initial flow improves PI, but later flow does not.


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Deepwater Well Cleanup Lessons

• On initial cleanup, PI erratically increased as choke opened. Typical response was a decrease, as if well / flow path were loading up, then sharp PI increase, seemingly when the obstruction was unloaded.

• Little partly broken polymer recovered, but early load water recovery matched PI incr.

• Lower skins were linked to both sand flow before completion (sand surge removed damage), increased cleanup flow volumes (and drawdown) on initial cleanup, and more effective frac stimulations.


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Deepwater Cleanup Lessons

• Wells cleaned up with increasing drawdown immediately following backflow start. Cleanup was increasing, measured by increasing PI, at the end of the first short cleanup periods prior to shut-in of the well.

• After initiation of production operations - after first cleanup flow, no further cleanup of damage was seen, regardless of drawdown. The reason is not known, but may be due to polymer adhering or cooking out?

8/25/2015 43


Fourth Problem

• We don’t understand how damage impacts economic return.


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Example Economics - Skin Sensitivity

100

110

120

130

140

150

160

170

0 5 10 15 20 25

Skin

PV

-10,

$ m

m

10

15

20

25

30

35

40

PV10

ROR


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An example of a completion method that minimizes damage.

• Perforating, but with enough underbalance to create the flow necessary to clean the perforations.


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Type of

Damage

Most

Probable

Location

Impact on

Productivity

if not

Removed

Surge

Pressure

Needed for

Removal?

Flow Vol.

Or Time

Needed for

Removal?

Removal

Hampered by

Limits on

Cleanup Vol?

Alternate

Methods of

Removal or

Prevention

Mud Cake

in Pay Zone

Formation

Face

Moderate to

Severe

Yes Spurt

Volume

Yes Acids, Soaps,

Enzymes

Mud Filt. <12” Minor - mod. No No

Whole Mud

Loss

Fractures

and large

vugs

Severe Possible,

Can help in

few cases.

Depend on

Cond. few

cases

similar

Yes, flow

combined with

solvent

treatment

Few successful

whole mud

removals when

vol. > 200 bbls.

Cement

Filtrate

<12” into

pay

Only if clay

damage

No No

Perforation

Crush Zone

½” around

perf

Moderate to

Severe

Yes 4 to 12

gal/perf

Yes Surge small

zones into

chamber, acids,

pulses, fracs

Formation

sand in

perfs

perf

tunnels

Most severe Cleanup

and reperf

Depends on

initial &later

actions

Develop good

perf and

prepack actions

Look at some of the most common damage mechanisms. In some formations, a specific damage is very detrimental, while in another formation, the damage is insignificant.


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Type of Damage Skin range Comments

Mud Cake in Pay

Zone

+5 to +300,

+15 is typical

Mud skin is usually shallow and has more impact when

turbulence and non-darcy skin problems are most severe. Mud

cake is usually by-passed by perforating.

Mud Filtrate +3 to +30 Filtrate usually recovered by steady flow and time. Related to

relative perm effects. This is usually a short lived problem (1 to

3 weeks)

Whole Mud Loss (in

pay zone)

>+50 Options depend on mud volume lost. Enzymes, solvents and

acids for small volumes (<10 bbls). Sidetrack if over 1000 bbls.

Low solids mud can be removed by concentrating on viscosifier

destruction or dispersment.

Cement Filtrate +10 to +20 Very shallow clay problems. Perforate with deep penetrating

charges to get beyond. Use leakoff control on cement.

Perforation Crush

Zone

+10 to +20 Perf small intervals underbalanced. Isolation packer breaksown,

explosive sleeve breakdown (very simple) - must be

accomplished prior to gravel packing.

Formation sand in

perfs

>+50 Most severe typical damage - cleanout and recompletion

required

When looking at the range of skins, it is useful to know that some wells have high skins but are really restricted by other factors such as tubing flow limits, facility limits, etc., and are not really limited by the skins.


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Table 3: Completion Efficiency Factors (Stracke, SPE 16212) Shown as a percent of wells

in each bracketed completion efficiency range.

Factor 100-75% 75-50% 50-25% 25-0%

Underbalance perf w/ surge chamber 26 26 26 23

Perforate and wash perfs 25 40 19 15

Underbalance perf w/ surge chamber + wash perfs 71 14 14 0

Surge Vol < 4 gal/ft 23 19 35 23

Surge Vol > 4 gal/ft 43 29 14 14

Surge differential < 1000 psi 27 24 24 24

Surge differential >1000 psi 19 27 31 23

Drilling overbalance <300 psi 15 48 19 19

Drilling overbalance >300 psi 31 31 23 16

Drilling overbalance >1000 psi 27 31 23 19

Completion overbalance <300 psi 25 39 25 12

Completion overbalance >300 psi < 600 psi 21 36 21 21

Completion overbalance >600 psi 47 21 5 26

This data is difficult to understand unless the attention is focused at those factors which deliver the most wells in the 100% to 75% efficiency range, e.g., underbalance perf w/surge chamber and wash perfs.


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Table 4: Perforation Tunnel Volume Following Perforating at Different Conditions

(Regalbuto and Riggs, SPE PE, Feb 1988)

Pressure Differential Hole Volume, perforated Hole Volume, perforated/surged

Overbalanced,500 psi, no surge

18 cc

Balanced perforated, no surge 31 cc

Underbalanced perforated, 500psi

20 cc 42 cc

Balanced perforated, delayed1000 psi surge

31 cc 48 cc

Underbalanced perforated, 1000psi

50 cc 75 cc

Notice that underbalance perforating at high underbalance (which causes flow) delivers a perforation that is from 40% to nearly 300% larger than the other methods of perforating.


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Back to over-all damage – What is it?

• Divide the well into three parts: – Inflow: area from reservoir to the wellbore

– Completion potential: flow to surface

– Surface restrictions: chokes, lines, separators.

• Basically, anything that causes a restriction in the flow path decreases the rate and acts as “damage.”


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4600 psi

1000 psi 15 psi

10 psi

25 psi

100 psi

Column Densities:

Gas = 1.9 lb/gal = 0.1 psi/ft = 1900 psi in a 10,000 ft well

Dead oil = 7 lb/gal = 0.364 psi/ft = 3640 psi in a 10,000 ft well

Fresh water = 8.33 lb/gal = 0.433 psi/ft = 4330 psi in a 10,000 ft well

Salt water = 10 lb/gal = 0.52 psi/ft = 5200 psi in a 10,000 ft well

Gas cut flowing oil = 5 lb/gal = 0.26 psi/ft = 2600 psi in a 10,000 ft well

10,000 ft

Press.

Drop

Differential pressure, DP, is actually a pressure balance

4600 psi reservoir pressure

-2600 psi flowing gradient for oil

- 150 psi press drop

- 100 psi through the choke

- 25 psi through the flow line

- 10 psi through the separator

- 15 psi through downstream flow line

-1000 psi sales line entry pressure

----------------------

DP = 700 psi drawdown pressure

Where does

the DP come

from?

1000


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The first step…..

• For the purposes of this work, consider the flow connection between the reservoir and the wellbore as the primary but not the only area of damage.

• Now, is it “formation damage” or something else that causes the restriction?


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Some sources of the “damage” in the reservoir-wellbore “connection”

• Wetting phases (from injected or “lost” fluids)

• Debris plugging the pores of the rock

• Polymer waste from frac and drilling fluids

• Compacted particles from perforating

• Limited entry (too few perforations)

• Converging radial flow – wellbore too small

• Reservoir clay interactions with injected fluids

• Precipitation deposits (scale, paraffins, asphaltenes, salt, etc)

Note that not all are really formation damage – How do you identify the difference?


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0

2

4

6

8

10

12

14

16

18

20

Tg 308 Tg 312bis Tg 315bis Teg 15y tg 307ter Tg 305bisz Teg 14z Teg 11z Teg 12z Teg 10z

To

tal S

kin

Turbulent Skin

Mechanical Skin

Cased Hole - Vertical - 5" Tbg

Open Hole - Vertical - 7" Tbg

Open Hole - Slanted - 7" Tbg

2001 2002

Turbulent Skins

Normalized to

Rates of 100

mmscfd

65-75 degree

15-20 degree

65-80 degree

50-65 degree

ALGERIAN GAS WELL COMPLETION EFFICIENCIES

60-70 degree

65-75 degree

And some restrictions – in very high perm wells – is the casing and the

very limited amount of open area that perforations create.

Data comparing cased and perforated skin with skins from open hole

completed wells from Algeria.


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Identification of Damage.

• How good are you at deductive reasoning? – Identifying the cause and source of damage is

detective work. • Look at the well performance before the problem

• Look at the flow path for potential restrictions

• Look to the players: – Flow path ways

– Fluids

– Pressures

– Flow rate


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What is Completion Efficiency?

• A measure of the effectiveness of a completion as measured against an ideal completion with no pressure drops.

• Pressure drops? – these are the restrictions, “damage”, heads, back-pressures, etc. that restrict the well’s production.


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Look again - The Effect of Damage on

Production Rate = (DP x k x h) / (141.2 mo bo s)

Where:

DP = differential pressure (drawdown due to skin)

k = reservoir permeability, md

h = height of zone, ft

mo = viscosity, cp

bo = reservoir vol factor

s = skin factor


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What changeable factors control production rate?

• Pressure drop – need maximum drawdown and minimum backpressures.

• Permeability - enhance or restore k? - yes

• Viscosity – can it be changed? – yes

• Skin – can it be made negative?

• These factors are where we start our stimulation design.


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Formation Damage

• Impact

• Causes

• Diagnosis

• Removal/Prevention?

• Basically, the severity of damage on production depends on the location, extent and type of the damage. A well can have significant deposits, fill and other problems that do not affect production.


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Conclusions

• Damage is usually shallow.

• Remove it or by-pass damage if it really causes a problem.

• Not every “damage” is in the formation.

• Not every drop in production is caused by damage.

• First, remove the pressure drops, everything else will take care of itself.


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Formation Damage – Effects and Overview

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