pab 4323 - l2

7/29/2019 PAB 4323 - L2

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PAB 4323 – WELL STIMULATION

TECHNIQUES

SEMESTER 7

By

Dr. Aliyu Adebayo Sulaimon([email protected])

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Lecture 2 – Formation Damage

Causes, Sources and

Diagnosis

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Learning Outcomes

At the end of this lecture, students should be able to:

Understand and explain the concept of formation damage

Identify and describe different types of formation damage

Describe with illustrations, causes of formation damage

Mention and explain the sources of formation damage

during well operations

Suggest ways by which formation damage could beprevented and/or recommend mitigation strategies

Recommend diagnostic tools for identifying formation

damage

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Formation damage

Introduction

Damage mechanisms• Mechanically induced

• Chemically induced

•

Biologically induced• Thermally induced

Operational sources of formation damage• Drilling operation

• Completion operation• Production operation

• Injection operations

Reference: Bennion et al (SPE 30320)

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Introduction

Investigations show that significant portions of the sand-face do

not contribute to fluid inflow Characterized by reduction in permeability around the wellbore

(Figure 1)

Formation damage means reduced current production

Reserves may remain trapped in a high percentage of thepotentially productive zone

With radial flow, the ‘Critical Area’ is the first few feet away fromthe wellbore

Production reduces through• Decrease in absolute permeability due to plugging

• Decrease in relative permeability to oil due to increase in watersaturation or wettability reversal

• Increase in oil viscosity due to emulsion or high-viscosity treating fluids

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Figure 1: Schematics of Formation Damage

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Damage mechanisms

Mechanically induced

• Plugging by solid particles

• Large particles bridge over the pore surfaces and form a filter cake

• Small fines adhere to the surface of the pore bodies or bridge in the pore

throats

• Bridging occurs when the size of the particles are more than one-third (1/3)

the size of the pore throat

Fig.2A:cake formation by large particles Fig. 2B:surface deposition of adhering particles Fig. 2C:plugging by depositing particles

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Mechanically induced (Cont’d)

• Pulverization and compaction of the rock around perforation

(Figure 3)• Collapse of weak formation material around the wellbore

• Friable formations or those by acidizing in the near wellbore region

Figure 3: Damage Due to Perforation

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Chemically induced (Cont’d)

• Clay Dispersion•

Dispersion of clay particles occurs when• the interstitial water salinity is suddenly reduced

particularly during flow in sandstone reservoir – ‘WaterSensitivity’.

• the ionic composition changes

• Water sensitivity depends on• Type of cations (monovalent types more damaging)

• PH (the higher the more sensitive the formation becomes as salinity

changes)• Rate of change of salinity

To prevent clay dispersion, the injection fluid should containmore divalent cations

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Chemically induced• Inorganic and Organic precipitation – From Brine & Oil

• Initially, ionic species in connate water in chemical equilibrium with

formation minerals• Changes in Pressure & Temperature near the wellbore

• Alteration in phase composition (X) by injected fluid

• Inorganic precipitates are commonly divalent cations (Ca2+, Ba2+,HCO3

-, SO42-)

Ca2+ + 2HCO3- CaCO3 (s) + H2O (l) + CO2 (g)

Addition of Ca2+ (through fluid injection e.g. CaCl2 completion fluid)into a reservoir with high bicarbonate conc. or removal of CO2 (dueto pressure reduction) may lead to precipitation

• Organic species that usually cause formation damage are waxesand asphaltenes• Waxes due to Temperature reduction below the cloud point and/or

when Pressure drops, Composition changes due to liberation oflighter components

• Asphaltenes in colloidal state flocculates when resins are removed

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Biologically induced

Common in water injection wells and largely due tobacteria (aerobic and anaerobic) growth

• Bacteria normally injected to reduce permeability ofthief zones during drilling operations

• They plug pore spaces• They cause precipitates due to their biological

activities

Best prevented by aggressive treating of injection fluidswith biocides

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Thermally induced

Damage unique to heavy oil production by EOR methods:

• Hot water

• Steam

• In-situ combustion

• Mineral transformation• T > 200oC

• Inert clay (kaolinite) transform to water-sensitive clay

(smectite)

• Subsequent swelling and expansion resulting from contact

with steam condensate lead to permeability reduction

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• Solubilization and precipitation

• At high temperatures, carbonates and silica become more

soluble in aqueous solution

• Dissolution of partially soluble clasts (fragments) ofcarbonaceous and silicates material releases the immobilized

the fines that migrate to plug pore throats (Figure 4a)

•

Mineral saturated brine can encounter colder formationmaterials which may trigger re-precipitation (Figure 4b)

Thermally induced (Cont’d)

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Figure 4: Mineral dissolution (Source: Bennion et al, SPE 30320)

(a) (b)

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Figure 5: Temperature effect on relative permeability/wettability(Source: Bennion et al, SPE 30320)

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Operational sources of formation damage• Drilling operation

• Most common, most severe

• Damage due to invasions by both the drilling fluid particles and

filtrates

• Depth of particle invasion usually small (< one foot)

Minimized when mud particles are designed larger than the pores,

by perforating, or by acidizing• Depth of filtrate invasion usually more ( 1.0 – 6.0ft)

• Mud filtrate can damage the formation by

• Fines movement

• Precipitation

• Water blocking

Fines migration and precipitation damage are mitigated by ensuring that

the ionic composition of the mud is compatible with the formation fluid. To

avoid water blocking, drilling fluids order than the water-based mud should

be used.

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Operational sources (Cont’d)

• Production operation

• Damage caused by fines migration or by precipitation

• Above critical velocity (determined by core-flood tests) near

the w/b, fines are capable of plugging pore throats

• Fines move when the phase they wet is mobile (water-wet);

fines migration subsequently leads to formation damage(Figure 6)

• Precipitation of solids (inorganic/organic) may commence

as pressure drops near the wellbore

Damage is overcome with stimulation treatment i.e. acids to removecarbonate precipitates and solvents to remove waxes.

It can be prevented with chemical squeeze treatment using

sequestering agents

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Figure 6: Fines migration (Source: Bennion et al, SPE 30320)

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Operational sources (Cont’d)

• Injection operations

Damage caused by

• Precipitation due to incompatibility of injected and formation

fluids

• Pronounced when water with relatively high concentration of

sulphate or carbonate ions is injected into formation with divalentcations (Ca,Mg, Ba)

• Filtration to remove all particles larger than 2µm is desirable

• Growth of bacteria

• Injection water may contain bacteria which can plug the formation

• Bacteria may grow near the wellbore to cause damage

• Injected fluids should be tested for bacteria and biocides should be

added if there is risk of damage by bacteria.

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Formation damage can be recognized through the following

techniques:Well tests – Pressure build-up or fall-off test may indicate

the extent of damage.

Production logging surveys may identify zones notcontributing to the total inflow

Comparison of well’s productivity with offset wells’ may

indicate possible damage

Careful analysis of well completion or workover reports

utilizing adequate knowledge of damage mechanisms and

sufficient field experience in well operations could be very

useful

Identification of Formation Damage

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Read Appendix 5A of Allen & Roberts, ‘Production

Operations 2, pages 5-14 to 5-15 for a different

enumeration of formation damage during well

operations

Refer also to the excellent presentation on

‘Laboratory Identification of Minerals’ in Appendix

5B, pages 5-16 to 5-43

HOMEWORK

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ASSIGNMENT 1

A well has a radius rw = 0.328 ft and damage penetration of 3.0ft

1) What is the damage skin factor if permeability impairment

results in k/ks = 5 and 10, respectively?

2) What would be the required damage depth to give the same

skin as with k/ks= 10 but the actual permeability impairment

being k/ks = 5?

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ASSIGNMENT 2

• A well has a drainage area of 640 acres (re = 2980 ft)and wellbore radius of 0.328 ft with 3 ft of damage

beyond the well (rs = 3.328 ft) and permeability

impairment in the damage zone of k/ks equal to 10.

• Compare portions of the pressure drop due to damage

within the near-wellbore zone versus total pressuredrop.

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THANK YOU

pab 4323 - l2

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