1

Primary funding is provided by

The SPE Foundation through member donations

and a contribution from Offshore Europe

The Society is grateful to those companies that allow their

professionals to serve as lecturers

Additional support provided by AIME

Society of Petroleum Engineers

Distinguished Lecturer Program www.spe.org/dl

Advancement in Sand Control

Fluid Technology

Bala Gadiyar

Schlumberger

2

• Introduction

Sand control, fluid need and selection

• Challenges

• Technologies

• Gaps

• Remarks

Lecture Outline

3

What is Sand Control

• Unconsolidated formations typically are weak

• Sand control goal is to produce hydrocarbons

without formation sand

• Many (if not most) offshore projects require

sand control

• Downhole filter – screen or screen and gravel

pack 4

Screen Formation

Sand Control Completion Types

5

Gravel Pack

Cased Hole

Frac - pack Gel Gravel Pack Water Pack STIMPAC

($200-$1500K) ($150-$500K) ($300-$2000K)

Technical Limit (Length) Technical Limit ( Length) Technical Limit ( Length)

1000+ ft 1000+ ft 400 ft per zone

Gel Gravel Pack Water Pack STIMPAC

($200-$1500K) ($150-$500K) ($300-$2000K)

Technical Limit (Length) Technical Limit ( Length) Technical Limit ( Length)

1000+ ft 1000+ ft 400 ft per zone

Sand Control Completion Types

6 Gravel Pack

Open Hole

Stand Alone Screen

Open Hole Gravel Pack Animation

7

Why do we Need Fluids?

Cased Hole

• Control losses post perforation and/or

completion

• Create desired fracture geometry in frac-

pack completion

• Transport proppant

• Deploy chemicals to mitigate fines

migration and/or scale inhibition

8

Why do we Need Fluids?

Open Hole

• Displacement and wellbore cleanup

• Well control and stability

• Transport proppant

• Filtercake cleanup

• Friction reduction and/or shale

stabilization

9

Selection Criteria

• Bottom hole temperature (cool-down temperature for frac-pack)

• Brine density – well control

• Compatibility of viscosifier with brine, additives

10

Good

Bad

10

100

1000

10000

1 10 100 1000

Vis

co

sit

y (c

P)

Shear Rate (s-1)

54 150 220

0

10

20

30

40

50

60

70

80

90

100

0 10 20 30 40 50 60

Se

ttle

d S

an

d (

%)

Time (min)

Fluid A

180 degF

170 degF

160 degF

Selection Criteria – Contd

• Friction in critical flow path

• Need for filtercake cleanup

• Environmental

• Availability and cost

11

Brines

12

8.4 9.4 10.4 11.4 12.4 13.4 14.4 15.4 16.4 17.4 18.4 19.4

Zinc Bromide

Cesium Formate

Calcium Bromide

Potassium Formate

Sodium Bromide

Calcium Chloride

Sodium Formate

Sodium Chloride

Potassium Chloride

Ammonium Chloride

Maximum Density (ppg)

Fluids

13

Brine; Gravel Pack

Linear Gel; Gravel Pack

Viscoelastic Surfactant; Gravel Pack; Frac-pack

Crosslinked gel; Frac-pack

Viscosity

• Fines migration

• Frac-packing long intervals

GoM ultra deepwater HPHT wells

• Fresh water availability in offshore areas

• Overcoming potential low fluid efficiency of

conventional frac fluids

Rig based frac-pack in Darcy permeability formation

Cased Hole Challenges

14

Challenges in Open Hole High Rate

Water Pack

Excessive Fluid Loss

Exceeding Frac

Pressure

• Premature

screenout –

incomplete pack

Challe

nges

Issues

15

Challenges in Open Hole High Rate

Water Pack

Challe

nges

Failure of Well Bore Integrity

Reactive Shales

• Shale collapse –

inability to run screens or

incomplete pack

• Shale dispersion – High

skin gravel pack

Issues

16

Screen

Screen

Fines Migration Background

• What are fines?

Formation material < 44 m

Particles that can flow through pore network

• Concerns of fines migration

Productivity decline due to plugging of proppant pack

Erosion to downhole/surface hardware

Surface facility upset

• Fines migration mechanism

Fluid velocity

Change in chemistry – pH, salinity

Two phase flow (onset of water)

17

Frac-Pack

• High perforation density –

12 to 21 spf

• Production from:

Fracture

Offset perforations not

aligned with fracture

• Significant production -

offset perforations in high

perm formation

• Fines migration more

critical near wellbore

18

• Surface modification agent (SPE

39428) and nano particles (SPE

115384)

Slurry stages – proppant is treated

Fly paper concept - capture fines at

fracture face/proppant pack interface

• Zeta potential (SPE 106112)

Alters particle charge

Remedial treatment

Fines Migration Solutions

19

• Polymer chemistry – entire job (SPE 143947)

Addresses fines migration near wellbore and

fracture

Stabilizes fines by agglomeration in the formation

Liquid form – operationally simple

Fines Migration Solutions - Contd

20

• Offshore Adriatic, Italy –

dry gas

• Depleted, high fines (up to

30%), water

• Untreated frac-pack well –

drastic decline in 2 years

• 2 wells (7 zones) – treated

frac-pack

Producing fines free – 19

months

No productivity decline

Case History: Polymer Chemistry

21

Untreated Frac-Pack Well

Production decline due to fines migration

• No industry standard

• Some ignore temperature

Fines Migration Lab Testing

Pump A

(fluid) Pump B

(confining)

Hassler Cell

Rosemount

Synthetic sand pack – Hassler cell

• Controlled rate and temperature Synthetic sand pack - clear cylinder

• Room temperature

• No control on rate

22

• Deep wells (> 25,000 ft) and reservoir

pressure > 20,000 psi

• Long interval length (> 500 ft)

• Multi-zone

• Require high pump rate (> 50 bpm) for

frac-pack

Surface treating pressure may exceed

15,000 psi

• Lower tertiary Gulf of Mexico

Ultra-deepwater HPHT Wells

23

• Solution for high rate frac-pack

• Chemistry: NaBr based borate

polymer crosslinked system

Increases hydrostatic pressure

Some fluids can be delayed –

lower friction

• Maximum density 12.5 ppg and

temperature 350OF

• Yields higher viscosity

compared to non-weighted fluid

High Density Frac Fluid

24

SPE 112531

• 11 jobs; fluid density 11.5

ppg

• TVD: 23,800 – 26,800 ft

• Reservoir pressure:

18,807 – 19,890 psi

• Pump rate: 15 – 45 bpm

• Reduction in surface

treating pressure

between 22 – 40%

Case History

26

• Freshwater availability– offshore/remote areas

Non-productive time

• Chemistry: Borate crosslinked system

Mitigate scaling by incorporating scale inhibitor

Limited scale inhibitors are compatible

Hinders breaking

Good buffering required

Tailored as per seawater composition

Seawater Frac Fluid

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• Application: Darcy permeability formation

Conventional frac fluid – low fluid efficiency

• High temperature borate crosslinked fluid

Partially neutralized degradable fluid loss

• Reduction in spurt and wall building coefficient

Static test - 190O F, 1 Darcy, 1000 psi differential

• Higher regain permeability - faster cleanup

High Efficiency Frac Fluid

Fluid Cw (ft/min1/2) Spurt (gal/100 ft2)

Conventional 0.00342 57.98

High Efficiency 0.00149 35.88

28

Challenges in Open Hole High Rate

Water Pack

Excessive Fluid Loss

Exceeding Frac

Pressure

• Premature

screenout –

incomplete pack

Challe

nges

Issues

29

SPE 123155

• Chemical solution – low frac gradient

wells

Operationally easy, less complex, and

reliable

• Compatible with both mono and

divalent brines up to 12.5 ppg

• Alpha wave height not affected

• Non-damaging

• Cost effective technique compared to

alternatives

Friction Reducer

30

• Understanding friction pressure

behavior in critical flow path helps

in determining:

Appropriate fluid selection

Pump rate

Open hole length that could be

packed without exceeding

fracturing pressure

Friction Pressure Characterization

Field Scale

3.5” Pipe

2.875” Pipe

5.5/4” &

5/3.5” Annuli

Shunt tube

31

Friction Reducer in 9.2 ppg Brine

• Friction reduction achieved between 20 to 65%

• Friction reduction depends on flow rate

Increasing friction reduction with increased flow

rate

Annulus Straight Pipe

32

No friction reducer

Friction

reducer

Fracture pressure

Simulation of Bottom Hole Pressure

Simulations show frac pressure can

be avoided with the addition of

friction reducer as well

as maintaining desired wave height.

Assumed well profile

Well Characteristics:

• MD 13,040ft

• TVD 9,400ft w/ 2,000ft

OH

• 5.5” screen & 3.5” WP

• 8.6” OH diameter

• 11.0ppg CaCl2

• rate 6bpm w/ 1ppa

33

Challenges in Open Hole High Rate

Water Pack

Challe

nges

Failure of Well Bore Integrity

Reactive Shales

• Shale collapse –

inability to run screens or

incomplete pack

• Shale dispersion – High

skin gravel pack

Issues

34

SPE 103156

• Minimize shale destabilizing effects

with water based fluids

Reduce risks associated with

reactive shale

• Compatibility – all brines and

common viscosifiers

• Non-damaging

• Field practice - Incorporate in

screen run-in and gravel pack fluids

Shale Stabilizer

35

SPE 103156

• Simulates shale reactivity under gravel pack

conditions

Dynamic Flow Through Test

X

X X

XX

X XX X36

X

X X

XX

X XX X

X

X X

XX

X XX X

Case History Successfully completed 14 wells

• OH length: 157 to 1181 ft

• Only 2 wells with clean sand and less

than 15% shale

12 wells with shale streaks between

20% and 60% (79 to 492 ft)

Field trial: 2 wells water-packed

(a) KCl w/o shale stabilizer

Premature screenout

(b) Shale stabilizer

Complete pack

Streaks of highly reactive shale

37

Performance Indicators

• Ability to run screens to TD

• 100% pack efficiency

• Return brine turbidity

Low Viscosity Oil Based Fluid SPE 110440

Alpha/beta gravel pack in sensitive

shale environment

• Invert emulsion (oil external)

Near Newtonian behavior

Viscosity < 10 cP

• Density: up to 10.5 ppg

• Temperature: up to 250O F

• No swapping of fluids

• Higher friction than brine

• Economical only if fluid is recycled 38

• 8.5” open hole – 1223 ft

• 5.5” (250 micron) premium screen

• BHT – 170O F

• Pack efficiency of 107%

• Skin of 0

Case History

Pump Rate

39

• High pressure effects

• High temperature and density viscous

gravel pack fluids

• Gravel pack fluids for arctic conditions

• Next generation fluid loss pills –

controlled break, solids free, high

temperature

• Single stage consolidation fluid

Technology Gap

40

• Proper engineering guidelines should be

used in the decision making for

developing and selection of fluids

• Fines migration has been a recurring

theme in cased hole and several

solutions have been developed

addressing the problem in a different

manner

Remarks

41

• Solutions for the open hole challenges

have been developed and successfully

implemented in the field

• The industry has put in efforts to develop

fluid technology to address most

challenges and there are still some that

remain

Remarks - Contd

42

43

Questions?

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Distinguished Lecturer Program www.spe.org/dl 44

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Click on: Section Evaluation

Backup Slides

45

Fluid Requirements

• Compatibility: formation rock and fluids

• Controllable rheological properties

• Fluid loss within reasonable range (frac-

pack)

• Fast breaking and good cleanup

• Low friction pressure

• Good proppant suspension

• Simple to prepare, QC, and pump

46

• Holy grail of sand control

• Eliminates hardware and

reduces pumping equipment

• Goal: glue/bond sand grains to

increase strength

• Limited applications in cased

hole – marginal reserves, low

cost

• Chemistries: mainly resins

Multi-stage treatment

Consolidation

47

• Placement/diversion

Limits to small interval

length (< 20 ft)

• Dependency on overflush

volume – affects strength

• No clear technical

guidelines on drawdown

limit

• Single stage treatment

does not exist

Consolidation - Issues

48

General Qualification Process Open Hole Gravel Pack Fluids

• Rheology profile from low to high shear

rate Optimization of viscosifier concentration

Identifies any incompatibility between

additives

• Sand settling

Evaluate sand suspension of carrier fluid

• Fluid-fluid compatibility

Design of spacer chemistry for mud

displacement

Emulsion tendency

• Filtercake cleanup

Breaker performance (reaction rate and %

cleanup) 49

General Qualification Process Frac-Pack Fluids

• Dynamic break/rheology

Optimization of polymer and breaker

concentration

• Shear history – simulate wellbore

conditions

Fluid behavior under changing shear

rate and temperature

• Core regain permeability

Assess extend of formation damage due

to fluid invasion

• Proppant pack conductivity

• Fluid-fluid compatibility

Emulsion tendency

50