Formation Damage Top.pdf

Formation Damage

Taller de Optimización de Producción Maracaibo, 2006

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Well, Reservoir & Boundaries A reservoir might have a boundary. Reservoir boundaries: •“no flow” – sealing fault, dividing line between drainage areas •Constant pressure boundary – acquifer, injector/producer interface

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Wellbore, Altered Zone & Undamaged Zone Any alteration on the flowing properties of the a zone around the well will induce a correspondent change on the well production. A decrease of the conductivity will correspond to a restriction to produce. If production is restricted in any zone of the formation due to whatever mechanism, the formation is said to be damaged.

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(Dowell Matrix Engineering Manual, 1998)

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Permeability changes in Radial Flow Flow restrictions, light or severe, have a higher impact at close penetration. As penetration increases the restriction “stabilizes”. Near the wellbore, in the “critical area”, the restriction is maximal. Copyright 2006, NExT, All rights reserved

k/ka ra

s=1

s=5

s = 10

s = 100

0.36

36.5

178.5

356.0

3,550.8

0.5

3.8

15.0

29.0

281.4

1

2.0

5.8

10.5

96.3

2

1.6

3.9

6.7

58.4

3

1.5

3.3

5.7

47.5

5

1.4

2.9

4.8

38.6

10

1.3

2.5

4.0

30.8

20

1.2

2.2

3.5

25.7

50

1.2

2.0

3.0

21.2

100

1.2

1.9

2.8

18.7 4

Permeability changes in Radial Flow

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Percent of original productivity

Effect of shifting a 80% damage collar 100 80

3-in collar 6-in collar 12-in collar

rc-rx = collar thickness Damage collar

rc

60 rx

40 20 0 0

Wellbore

re

1

2

3

4

5

6

Inner radius of damage (ft)

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Critical Area Area 3 to 5 ft around the wellbore where flow restriction is higher . Flow linear velocity is higher in the critical area and varies with the square of the radius. Critical Area velocity

rw

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re

7

Radial Flow & Skin Effect

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Flow Regimes Transient (variable slope)

Pseudo Steady State (constant slope)

Steady State ( slope zero)

Q

time

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Darcy’ Law in Transient Flow •Infinity acting radial flow period •No outer boundary •Pressure vs. time slope changes Solution in field units (zero skin) q=

k h (Pe − Pwf ) ⎛ ⎞ k − 3.23 ⎟⎟ 162.6 µ Bo ⎜⎜ log t + log 2 φ µ Ct rw ⎝ ⎠

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Darcy’s Law in Pseudo Steady State Flow • No flow across outer boundary • Reservoir is finite • Pressure decline with time is constant

∂P = const. ∂t

rw < r < re

Solution in field units (skin zero)

k h (Pe − Pwf ) q= re ⎛ 141.2 µ Bo ⎜ ln − 0.5 ⎞⎟ rw ⎝ ⎠

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Darcy’s Law in Steady State Flow • No flow at the boundary • Reservoir is finite • Pressure is constant with time

∂p =0 rw
Solution in field units (skin zero)

k h (Pe − Pwf ) q= re ⎞ ⎛ 141.2 µ Bo ⎜ ln ⎟ r w ⎠ ⎝

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12

Skin Effect Any alteration (restriction or enhancement) to the radial flow in the formation and at the wellbore is represented by the Skin Factor (s). When the alteration is a restriction to the flow, the skin is positive (s>0). When the alteration is an enhancement to the flow, the skin is negative (s<0). Copyright 2006, NExT, All rights reserved

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Darcy’s Law including Skin (Pseudo Steady State) k h (Pr − Pwf ) q= re ⎛ − 0.75 + s ⎞⎟ 141.2 µ Bo ⎜ ln rw ⎠ ⎝

Pr

is the average reservoir pressure

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Darcy’s Law including Skin (Steady State) k h (Pr − Pwf ) q= re ⎛ − 0.5 + s ⎞⎟ 141.2 µ Bo ⎜ ln rw ⎠ ⎝

Pr

is the average reservoir pressure

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15

Skin & Formation Damage • A well without restriction to flow has a zero skin (s = 0), • A positive skin represents a restriction to flow but not necessarily a formation damage, • Can be due to a mechanical restriction to flow (e.g. collapse perforations, gravel pack, etc), • The purpose of matrix treatment in sandstones is to remove the damage and reduce the skin to zero (typically, s < 5), • There is no limit of a positive skin – a cased well before perforating has an infinite skin (s = ∞). Copyright 2006, NExT, All rights reserved

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Skin & Flow Enhancement • A negative skin represents an improvement over the natural flow capacity, • A well with a negative skin is said to be Stimulated, • After acidizing, carbonate formations might present negative skins, • Deviated wells have negative skins, • Hydraulic fractures provoke negative skins, • Is there a limit for a negative skin?

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Negative Skin k h (Pe − Pwf ) q= r 141.2 µ Bo ⎛⎜ ln e + s ⎞⎟ rw ⎠ ⎝ k h (Pe – Pwf) ≥ 0 141.2 µBo(ln re/rw + s) > 0 S > - ln re/rw

re

ln re/rw

300 500 1000

6.74 7.26 7.97

rw = 4.25” = 0.35 ft

s>-8 Copyright 2006, NExT, All rights reserved

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Reservoir Model of Skin Effect

Bulk formation Altered zone ka

h

rw ra Copyright 2006, NExT, All rights reserved

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Reservoir Pressure Profile

Pressure, psi

2000

1500

1000

∆ps

500 1

10

100

1000

Distance from center of wellbore, ft Copyright 2006, NExT, All rights reserved

10000 20

Skin and Pressure Drop

0.00708 k h s= ∆p s qBµ

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Skin and Pressure Drop

141.2qBµ ∆p s = s kh

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Skin Factor and Properties of the Altered Zone

⎛k ⎞ ⎛ ra ⎞ − 1⎟⎟ ln⎜⎜ ⎟⎟ s = ⎜⎜ ⎝ ka ⎠ ⎝ rw ⎠

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23

Skin Factor and Properties of the Altered Zone

ka =

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k 1+

s

ln(ra rw )

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Effective Wellbore Radius

⎛ rwa ⎞ ⎟⎟ s = − ln⎜⎜ ⎝ rw ⎠

rwa = rw e Copyright 2006, NExT, All rights reserved

−s

25

Geometric Skin - Converging Flow to Perforations

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Geometric Skin - Partial Penetration

hp h

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Partial Penetration

h1 hp

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ht

ht sd + s p s= hp

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Partial Penetration Apparent Skin Factor h1D = h1 ht

A=

h pD = h p ht rw ⎛ kv ⎞ rD = ⎜⎜ ⎟⎟ ht ⎝ kh ⎠

1

2

B=

h1D

1 + h pD 4

h1D

1 + 3h pD 4

1 ⎤ ⎡ ⎛ 1 ⎞ π h pD ⎛ A − 1 ⎞ 2 1 sp = ⎜ ln ⎢ − 1⎟ ln + ⎜ ⎟ ⎥ ⎜ h pD ⎟ 2rD h pD ⎢ 2 + h pD ⎝ B − 1 ⎠ ⎥ ⎝ ⎠ ⎦ ⎣ Copyright 2006, NExT, All rights reserved

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Geometric Skin - Deviated Wellbore

s = sd + sθ

θ

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h secθ

h

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Deviated Wellbore Apparent Skin Factor

θ w'

⎛ kv ⎞ = tan tanθ w ⎟ ⎜ kh ⎟ ⎝ ⎠ −1 ⎜

⎞ ⎟ sθ = − ⎜ 41 ⎟ ⎝ ⎠ ⎛ θ w' ⎜

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2.06

hD =

1.865

⎞ ⎟ − ⎜ 56 ⎟ ⎝ ⎠ ⎛ θ w' ⎜

h rw

kh kv

⎛ hD ⎞ log⎜ ⎟ ⎝ 100 ⎠ 31

Geometric Skin - Well With Hydraulic Fracture

Lf

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Completion Skin rw

s = s p + sd + sdp rp

kdp

rdp kR

Lp kd

sdp

⎛ h ⎞⎛ rdp ⎞⎛ k R k R ⎞ ⎟⎜ ⎟⎜ ln − ⎟ =⎜ ⎜ L p n ⎟⎜ rp ⎟⎜ k dp k d ⎟ ⎠ ⎠⎝ ⎠⎝ ⎝

rd Copyright 2006, NExT, All rights reserved After McLeod, JPT (Jan. 1983) p. 32.

33

Gravel Pack Skin Cement

s gp =

k R hLg 2 2nk gp rp

Lg Copyright 2006, NExT, All rights reserved

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Productivity Index

q J≡ p − p wf

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Flow Efficiency

Jactual p − p wf − ∆p s = Ef ≡ Jideal p − p wf

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Damage Characterization • Damage characterization is complex • Normally, more than one type of damage • Production history is fundamental to identify source of damage and damage mechanisms Damage Mechanisms

Production data

Damage types

Expert system (StimCADETM) Copyright 2006, NExT, All rights reserved

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Types of Damages Induced • Solids • LCM/Kill Pills • Incompatibility of waters • OBM (cationic emulsifiers) • Invasion of fluids (water & emulsion block) • Bacteria • etc Copyright 2006, NExT, All rights reserved

Produced • Fines migration • Swelling clays • Organic deposits (paraffins, asphaltenes) • Mixed deposits • etc

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Solids Invasion Solids invasion can be produced by an external source (during a work-over, for example) or during production (fines migration). Solids have to be extremely small to penetrate into the pore throat. k D pore = 2 × 6 10 Π φ

Dpore in mm k in Darcies f in fraction

Normally, external solids plug the formation at sand face. Copyright 2006, NExT, All rights reserved

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Solids Invasion - Mitigation Mitigation: Any treatment fluids to be filtered to 2µ. 500

Permeability (md)

A (2.5 ppm)

(A) Bay Water Filtered Through 2um Cotton Filer

100 (B) Bay Water Through 5um Cotton Filter (C) Produced Water Untreated

50

C (94 ppm) (D) Bay Water Untreated

D (436 ppm) 10

0

0.02

0.04

0.06

0.08

0.10

Volume Injected (gal/perf)

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Fines Migration • Fine = particle with 44 µ or less. Normally, clays and silts. • Some clays (kaolinite, for example) may be destabilized and will produce fines that will plug, partially or completely, the wellbore. • Fines can not be controlled, they need to be dissolved. • Contrarily to sand grains, fines due to their very small dimension do not cause any harm to the well completion equipment.

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Identification of Fines Migration • Turbidity of produced water • Production declines with increased flow rate (increased wellhead choke size) • Fines are not soluble in HCl

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Fines Migration Mitigation Sandstone Formations: • Reduce production rate • Acidize with HCl-HF • Remove with suspending agents and use N2 fluids Carbonate Formations: • Reduce production rate • Acidize with HCl (don’t use HF) • Remove with suspending agents and use N2 fluids Copyright 2006, NExT, All rights reserved

43

Pore throat

Pore Throat

Pores Provide the Volume to Contain Hydrocarbon Fluids Pore Throats Restrict Fluid Flow

Scanning Electron Micrograph Norphlet Formation, Offshore Alabama, USA

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Kaolinite

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Swelling clays: Smectite • Some clays “swell” when in contact with water with different salinity. • The increase in volume restricts the pore throat and consequently reduces the permeability. • Smectite is a common swelling clay.

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Smectite

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Scale

•Inorganic mineral deposits. •Formed due to supersaturation at wellbore conditions or commingling of incompatible fluids. •Form in the plumbing system of the well, in the perforations/near wellbore formation

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48

The Scaling Process Saturated brines may form precipitates when mineral equilibrium concentrations are exceeded (supersaturation) due to: ƒ Increased mineral concentration ƒ Change in temperature, pressure or pH ƒ Mixing incompatible waters

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The Scaling Process Dissolution Mineral matter dissolves in water Transportation Produced water carries minerals through formation wellbore and tubing Deposition Changes in water causes supersaturation and precipitation. Scale adheres and grows

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The Nucleation

Supersaturation Ba2+

SO42

Ion pairs

Clusters / Nuclei

Ba2+ SO42

Transient Stability Ba2+ SO42

Further growth at sites of crystal imperfections

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Imperfect Crystallites

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Solubility of various minerals

Scale

Solubility mg/liter

Sodium Chloride Calcium Sulfate Calcium Carbonate Barium Sulfate

318,300.0 2,080.0 53.0 2.3

In distilled water

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Calcium Carbonate precipitation Pressure ↓

pH ↑

Solubility ↓

Precipitation

In presence of CO2

Solubility ↓

Without CO2

Slight Solubility ↑

Temperature ↑

NaCl concentration higher than 10% decreases CaCO3 solubility Mitigation: CaCO3 and MgCO3 dissolve in HCl Copyright 2006, NExT, All rights reserved

53

Calcium Sulfate precipitation Forms ƒ Gypsum (CaSO4 2H2O) ƒ Anhydrite (CaSO4)

Mitigation Mechanical removal

Precipitation caused by ƒ Pressure drop ƒ Temperature change ƒ Incompatible waters Copyright 2006, NExT, All rights reserved

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Barium Sulfate precipitation ƒ Mixing incompatible waters ƒ Common occurrence during water flood breakthrough ƒ Decreasing temperature (more significant at high salt concentration) ƒ Decreasing pressure Mitigation Mechanical Removal Copyright 2006, NExT, All rights reserved

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Iron Scales Types ƒ Iron Carbonate ƒ Iron Sulfide

Mitigation

ƒ Iron Oxide

Precipitation mechanism

Dissolve in HCl

ƒ Aeration (oxidation) ƒ pH, pressure or temperature change ƒ Corrosion products Copyright 2006, NExT, All rights reserved

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Precipitation of Iron Compounds

•Ferric ion – Fe+3 precipitates as Fe(OH)3 at pH < 2 •Ferrous ion – Fe+2 precipitates as Fe(OH)2 at pH ≈7 •As the pH of spent acid is around 5, ferrous ion precipitates on surface Copyright 2006, NExT, All rights reserved

Fe+3, ppm 3000

2000

1000

0 0.5

1

1.5

2

2.5

3

7.2

8

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Precipitation of Iron Compounds - Mitigation Mitigation: • Iron concentration in treatment fluid < 100 ppm (clean tanks and equipment) • In matrix acidizing, maintain pH very to prevent precipitation of Fe+3 • Use reducers to reduce Fe+3 to Fe+2

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58

Paraffins • Complex molecules (C18H38 to C40H82) • Precipitates at cloud point (temperature at which first fraction precipitates). Mitigation: Soluble in distillates, aromatics and carbon disulfide. Keep temperature above cloud point (if possible).

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59

Asphaltenes •Precipitation of asphaltic colloidal molecules dispersed by maltenes. •Precipitation of hard deposits just below bubble point. •Precipitation of sludge and solid emulsions due to contact with acids or addition of surfactants. Mitigation: Prevention with addition of special agents, replacing the maltenes. Difficult to dissolve. Mechanical removal necessary in many cases. Copyright 2006, NExT, All rights reserved

60

Mixed Deposits • Mixtures of fines, organic and inorganic deposits. • Require extensive laboratory studies to design treatment and define treatment fluids. Mitigation: Aromatic solvents normally used to dissolve organic precipitates. Acids to dissolve fines. Special solvents to dissolve scales.

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61

Drilling Damage •

Filter cake should prevent extensive damage to formation during drilling

•

Mud filtrate might cause clay destabilization, emulsions, water blocks

•

Low permeability (~ 0.001md) filter cake will be damaging during production ƒ formation permeability may be impaired ƒ potential plugging of screen/ gravel pack

•

Openhole completions do not have perforations or fractures to bypass any damage

•

Filter cake removal maybe a necessity!

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Filter Cake

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63

Drilling Fluids Damage Drilling Fluids Solids • Plugging formation face • Very small solids invasion Drilling Fluid Filtrate • pH, Salinity • Capillarity (high penetration) • Scales • Clays disturbance • Cooling Copyright 2006, NExT, All rights reserved

Oil Based Muds • High solids content • Relative permeability • Emulsifiers (cationic)

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Cementing Damage Washes & spacers ƒ Destroy mud cake ƒ Dispersants ƒ Filtrate invasion (few inches)

Mitigation: Mitigation: Controlled Controlledfluid fluidloss loss Perforation Perforationlength length

Cement slurries ƒ High pH ƒ Precipitation CaCO3 ƒ Free H2O

water block (small penetration)

Squeeze ƒ Formation breakdown Copyright 2006, NExT, All rights reserved

65

Radial Distance (mm)

Perforation Damage

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66

Damage in Water Injectors • • • •

Solids plugging (filter to 2µ) Disturbance of clays (include clay stabilizer in injection water) Scales due to incompatibility of waters (lab tests) Plugging by ferric compounds (include iron sequestering agents) • Bacteria (include bactericide)

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67

Damage in Steam Flooding • Caused by the dissolution of materials due to temperature and high pH. • Dissolution of calcareous materials provoke sand deconsolidation. • Dissolution of siliceous materials can provoke precipitation in zones with lower temperatures and pH. • May for scales of calcium carbonate and amorphous silica.

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68

Damage in CO2 Flooding • Precipitation of asphaltenes when in contact with oil (specially in presence of water). • Precipitation of scales due to acidic conditions. • Dissolution of rock cementing materials and deconsolidation of sand.

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69

Damage in Polymer Flooding • Gel residues. • Fines transportation by gels.

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70

Damage in Injectors

In Injectors Wells, damage materials can deposit very deep in the reservoir and their removal might be very difficult.

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71

Emulsions (Emulsion Block) • A stable dispersion of two immiscible fluids. • Formed by invasion of filtrates into all zones or co-mixing of oil-based filtrates with formation brines. • Stabilized by fines and surfactants • Mitigation: Solvents

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72

Wettability Changes • Caused by invasion of completion or workover fluids. • Surfactants may displace the water film around pores surfaces and replace it by a oil film. • Changes in relative permeability. • Mitigation: Solvent & Water-Wet Surfactant.

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73

Water Block A reduction in effective or relative permeability to oil due to increased water saturation in the near wellbore region. Favored by pore-lining clay minerals (Illite) Mitigation: Reduction of interfacial tension using surfactants/alcohol's in acid carrier Copyright 2006, NExT, All rights reserved

1

1 Water Wet Oil Wet Kro

Kro

Krw

Krw

0 1-Sor

0 Swc

1

Sw

Wettability change 74

Gravel Pack • Poor or incomplete gravel placement ƒ (too many perforations, small diameter)

• Polluted pack ƒ (formation sand, fines, wellbore residues, gel residues)

• Poor screen selection (pseudo-skin)

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75

Production Damage Fines Migration/Bridging Precipitation

Scale, Paraffins..

Increased Effective Stress

High Drawdown

In Situ Distillation/Wettability Changes

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76

Identification of Formation Damage and Lithology in Cased Hole

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Identification of Formation Damage Pressure gauge ƒ drawdown and buildup tests (skin factor) ƒ real-time gauges ƒ memory gauges

Production Logging (PLT) ƒ identify flowing interval and flowing anomalies (x-flow) ƒ real-time or memory

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78

Identifying Lithology across Casing • Infer formation damage by lithology • Select right remedy for different lithology • RST SpectroLith processing ƒ Quantify formation rock volume behind casing ƒ Formation evaluation in the absence of openhole logs

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79

Elements Measured with Wireline Tools Natural Gamma Ray spectroscopy (NGT) ƒ Th, U, K

Induced neutron activation (AACT) ƒ Al

Induced thermal neutron gamma ray spectroscopy (RST) ƒ Si, Ca, Fe, S, Ti, Gd

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80

Reservoir Saturation Tool (RST)

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RST Spectral Analysis

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82

Spectrolith® Processing

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Spectrolith® Processing

Volume of oil corresponds to inputs from lithology and porosity.

Client Porosity & Lithology Copyright 2006, NExT, All rights reserved

RSTPro Porosity & Lithology

84

Damage Sample Testing and Diagnosis START

No Yes Organics

No

No

No Yes

Yes

Yes

Yes Yes

Yes

No No

Yes

No Yes

Yes

No Yes

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