Cementing problems in HPHT wells and possible solutions ...

India’s only Energy Company in Fortune’s ‘World’s Most Admired’ List

Institute of

Drilling Technology, Dehradun

OISD 28-29 December 2016

Cementing problems in HPHT wells and possible solutions. By Dr Kishori Lal & Parvinder Singh

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Presentation overview

1 Introduction

2 Cementing challenges in HPHT wells

3 HPHT cementing remedy

4 Challenges in Slurry Design

5 Solutions: Criteria adopted

#2 E&P Company in the world

6 Slurry designs

7 Conclusions

Mechanical well integrity during drilling • Isolation of weak & incompetent formations, • Sealing of problematic zones/lost circulation. .

Reservoir Isolation and Protection • Zonal isolation/isolating production from other fluids, preventing migration & restricting fluid movement between formations.

Production Optimization •Optimizing stimulation treatments •Water shut off jobs/ sealing of micro - annulus

Why cementation is important ? ‘’Effective Zonal Isolation for life of well to produce oil and Gas safely and economically’’ .

FG PP

Mud Wt

Dep

th

•Structural support (to bond & support casing, •Protecting the casing from corrosion & shock loads.

Search for new hydrocarbon resources has led to discovery of several High Pressure High Temperature (HPHT) fields world wide.

Drilling, completion, testing and production in HPHT environment are technically complex operations with very high risk and exhibits major HSE issue and are further aggravated with the presence of H2S and CO2.

More challenging in off-shore environments.

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HPHT Classifications

HPHT locations around the globe

5 Most valuable Indian PSU

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FIG: HPHT Technology Gaps (HPHT Well Summit)

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Cementing challenges in HPHT wells

ONGC a Wealth Creator

Effect of temperature Accurate prediction of temperature Thermal thinning Decrease in rheological properties Strength retrogression

Effect of pressure Slurry density Narrow margin between pore pressure & fracture gradient Small ECD window

Gas migration

Low annular clearance

Degradation of set cement sheath

30”

20”

13 3/8”

9 5/8”

7”

Result : HPHT cement failure

HPHT cementing remedy Accurate estimation of temperature

Monitoring of down-hole conditions

Cementing simulator

Efficient displacement of mud

o Proper mud rheology

o Suitable spacer

o Density train

o Rheological hierarchy

o Wettability change

o Contact time

o Annular velocity Induced stresses during testing

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HPHT cementing remedy

Software assisted prediction of temperature profile

Temperature prediction using API Table

20 40 60 80 100 120 140 160degC

Temp. Profile At 78 min

AnnulusTubular FluidsGeoth.Profile

090

018

0027

0036

00

m

9


10


Software-Optimized displacement rate : @ 0.8 m3/min for 15.0 m3 @ 0.7 m3/min for 10.0 m3 @ 0.5 m3/min for 1.3 m3

(Plug bumping) Expected maxim pump pr. : Around 3100 psi

Normal displacement rate : @ 1.0 m3/min for 25.0 m3 @ 0.5 m3/min for 1.3 m3

(Plug bumping) Expected maxim pump pr. : Around 4300 psi

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Sample No.

Cement sheath radius for stress check (inches)

Induced stress at depth 3585m (Y=2610679 psi, 𝜗𝜗 =0.33) in PSI

Induced stress at depth 3590m (Y=5801509 psi, 𝜗𝜗 =0.28) in PSI

Remarks

Hoop (𝝈𝝈𝝈𝝈) Radial (𝝈𝝈𝝈𝝈) Hoop (𝝈𝝈𝝈𝝈) Radial (𝝈𝝈𝝈𝝈) 1 3.5 -742 930 -383 1341 Fails at both

depth in tensile. 4.5 -412 600 -42 1000 2 3.5 -561 869 -302 1246 Fails at both

depth in tensile. 4.5 -278 587 3.75 941 3 3.5 -68 667 114 946 Fails at both

depth in tensile. 4.5 77 521 278 781 4 3.5 -210 747 19 1080 Fails at both

depth in tensile. 4.5 -21 558 228 870 5 3.5 -264 773 -14 1122 Fails at both

depth in tensile. 4.5 -59 568 210 897 6 3.5 -266 785 18.6 1151 Fails at both

depth in tensile. 4.5 -58 577 242 927

No cement sample fulfills the

criteria of stress failure.

Complete replacement of

drilling fluid with drill site water

is not suggestible.

Partial replacement facilitates

high pressure testing as well as

minimizes negative effect of

draw down.

Casing Integrity Testing (H/Testing) with water ??

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Challenges of HPHT Slurry Design


- Long thickening time - Thermal thinning - Low rheology

- Unstable slurry - Settling of heavy wt material - Poor displacement - Channeling

- API Fluid loss > 50 ml - Others: High initial consistency- difficult to prepare & pump

Poor

cementation

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Cement slurry Design Issues for HPHT Wells Efficient slurry design

Cement

Fluid loss control additive

Retarders

Weighting agent

Anti-gas migration

Stopping of strength retrogression

Use of expansive additive for improved cement bond

Stability of cement system

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API CLASSIFICATION OF CEMENTS

Two basic concepts / criteria of classification suggested by API Principal chemical criteria is based on the distribution of main clinker phase Physical criteria is based on physical parameters of cement such as particle size distribution, density and performance tests

API recommendation for oil well cement classification : 6 categories A, B, C, D, G and H Further divided into 3 categories depending upon C3A content: ordinary, moderate & high sulphate resistant 15

Highest Profit-Making Company in India

Cement Quality Issue for HPHT wells ONGC procures API Class G HSR Cement for all cementing operations from two Indigenous sources namely, M/s Digvijay Cement M/s Dalmia Cement. Challenges faced during past 2-3 years with Digvijay cement due to, In-consistent behavior High gelation problem in-spite of fulfilling criteria of API. Erratic behaviour while designing slurry for HPHT wells. High consumption of cement additives. Problems sorted out by IDT and filed Patent on

Innovative methodology to ensure quality cement.

Challenges faced during cementing HPHT wells - Case studies

Institute of Drilling Technology

Case study: Poor cementation of few HPHT wells

Asset / Basin

Well Salient Features Observations

K G Basin

A • Depth /Csg. Size: 4823 m / 7” csg with stage collar @ 3797.5 m • BHST/BHCT/BHP: 220 0C/195 0C /14,800 psi • Drg Fluid: WBM, MW: 2.05 •Cmt Slurry Density: 2.15 •Drg depth increased by 400 m, temp increased from 180 0C to 220 0C. •Dynamic loss & activity condition. MW redn from 2.05 to 1.65 •Job carried out at controlled displacement rate.

• Poor CBL / VDL. • Unstable slurry. • Settling of heavy weight material. • No FLCA used. F/L < 50 ml/30 min. due to settling of heavy weight material on sieve during test. • Consistency very low after attaining temp. : chances of settling of heavy weight material after displacement & channeling.

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Cement slurry design: Well A

Conditions

Composition, % BWOC

Results

Sp. Gr. of slurry BHCT, 0C BHP, psi RT, min

2.15 195 14,800 60

W SiO2 Mn3O4

Disp. (CFR3)

FLCA HTR (HR 12)

HTR-E (Comp. R)

ASA (Susp. HT)

GBA (Gas Top

HT)

48 35 30 0.3 0.0 2.0 1.0 0.5 0.2

T T min

F/L ml/30 min

In Cons Bc

Comp. Str. psi

PV/YV F F %

Stability

435/ 453

40/70 20/<10 n.d. 39/< 01 n.d. n.d.

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Thickening time & consistency graph : Well A (Sp. Gr. 2.15, BHCT: 195 0C, BHP: 12,000 psi, TT: 453 min)

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Temperature, 0C

Pressure, Kpsi

Consistency, Bc

Case study: Poor cementation of few HPHT wells

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Asset / Basin

Well Salient Features Observations

K G Basin

B •Depth /Csg. Size: 5450 m / 7” Liner • BHST/BHCT/BHP: 242 0C/220 0C /15,632 psi • Drg Fluid: SOBM, MW: 1.94 •Cmt Slurry Density: 2.20 •Liner stuck during RIH, POOH & re-run without centralizers.

• Poor CBL / VDL • No centralizers • No reciprocation • Wettability change ? • Consistency low after attaining temp. : chances of settling of heavy weight material after displacement & channeling.

Cement slurry design: Well B by Service Provider

Conditions

Composition, % BWOC

Results


2.20 242 15,632 60

W SiO2 Fe2O3 Mn3O4

Disp. (DO 65)

FLCA (D167)

HTR (D161L)

HTR-E (D121)

ASA (B316)

42 35 25 25 2.5 0.8 9.0 0.8 0.1

T T min

F/L ml/30 min

In Cons Bc

Comp. Str. psi

F F %

Stability

324 44 22 n.d. Nil n.d.

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Thickening time & consistency chart : Well B

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24 # 21 Energy Company in the World

Molds Cured at 2100C for 24 Hrs in curing Chamber .

Shrinkage study at BHST: Particle packing concept minimized shrinkage of set molds


Way Forward………..

Capability & self-reliance of cement slurries for HPHT wells.

Identification of thermally stable high performance cement

additives and their evaluation - Indigenously - Commercially available To design ultra high density cement slurries (2.1 g/cc to

2.5 g/cc) for extreme temperature conditions (175 0C to 260 0C BHST).

To provide reliable, cost effective and compatible

solutions for better cementations.

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Criteria adopted for HPHT cement slurry


Particle packing concept: silica (coarse & fine), weighting material (fine/micro-fine)

Control of strength retrogression: use of two blends of silica (fine & coarse)

Weighting material: Use of blend of Hematite & Manganese tetra-oxide, up to 2.25 sp. gr.

Use of non-viscosifying fluid loss additives Use of thermally stable retarders to achieve better thickening

time control Anti-settling agents to prevent settling and to raise the low-end

rheology of cement slurries Effective gas migration control Short transition time (vertical setting) Fluid loss control

Stable Slurry

Slurry Stability

Low strength

Medium strength cement

Effect of slurry stability on annular isolation

High strength cement

Free water

Sp. Gr. 2.31

Sp. Gr. 2.34

Sp. Gr. 2.36

Top

Bottom

Middle

Sedimentation test on cement slurry of sp. gr. 2.35

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28 # 21 Energy Company in the World

Testing conditions

Sp. Gr.

of slurry BHP psi

BHST 0 C

BHCT 0 C

Raising Time min

2.10 10,000 175 150 50

2.20 12,500 200 170 60

2.25 15,000 225 200 60

2.35 18,000 240 225 65

2.50 20,000 260 240 70

Testing conditions are visualised on the basis of future journey of deep HPHT wells.

Desired parameters for HPHT cement slurry

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Properties Parameters

Initial consistency 30 Bc (Max)

Thickening Time 330 ± 30 min

Free Fluid Nil

API Fluid Loss < 50 ml/30 min

Compressive Strength in 24 Hrs

>2000 psi

Stability ± 0.05 g/cc

Gas Migration Study Gas tight slurry


Slurry design for BHST: 175 0C

Conditions

Composition, % BWOC

Results


2.10 150 10,000 50

Water Silica Hematite Manganese Tetra Oxide

Dispersant

F/L Control Additive

High Temp.

Retarder

Gas Block Additive

48 25+10 15 15 1.4 0.5 0.8 0.5

Thick. Time min

Initial Consistency

Bc

F/L ml/30 min

Rheology PV/YP

Comp. Str. psi

Gas Migration

Study

Free Fluid

%

Stability

320 30 26 93/20 2500 Gas tight Nil T-2.09 M-2.10 B-2.11

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Consistency graph of cement slurry of sp gr 2.10 (BHCT: 150 0C, BHP: 10,000 psi, T T: 320 min)

Temperature, 0C

Pressure, Kpsi

Consistency, Bc

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Gas migration control

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Gas migration test of cement slurry of sp gr 2.10 at 150 0C (BHCT)

# 21 Energy Company in the World


Conditions

Composition, % BWOC

Results


2.20 170 12,000 60

Water Silica Hematite

Mn. Tetra Oxide

Dispersant (Liquid)

Fluid Loss

Additive

Retarder -1

(Liquid)

Retarder -2

(Liquid)

Retarder Enhancer

48 30+10 25 20 4.0 0.8 5.0 2.5 2.5

Thick. Time min

F/L ml/30 min

In Cons Bc

Comp. Str. psi

Free Fluid

%

Stability

345 22 24 2100 Nil T-2.18 M-2.20 B-2.23


Consistency curve of cement slurry of sp gr 2.20 (BHCT:170 0CBHP: 12,000 psi, T T : 345 min)

Temperature, 0C

Pressure, Kpsi

Consistency, Bc



Conditions

Composition, % BWOC

Results


2.25 200 15,000 60

Water Silica Hematite

Mn. Tetra Oxide

Dispersant Fluid Loss

Additive

Retarder-1 (Liquid)

Retarder-2 (Liquid)

Retarder Enhancer

Gas Block

Additive

44 30+10 25 30 0.8 0.6 5.0 2.5 2.5 0.4

Thick. Time min

F/L ml/30 min

In Cons Bc

Comp. Str. psi

Free Fluid

%

Stability

368 26 30 2300 Nil T-2.23 M-2.24 B-2.26


Consistency curve of cement slurry of sp gr 2.25 ( BHCT: 200 0C, BHP: 15,000 psi, T T : 368 min)

Pressure, Kpsi

Temperature, 0C

Consistency, Bc

Pressure, Kpsi

Temperature, 0C

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Conditions

Composition, % BWOC

Results


2.35 225 18,000 60

Water Silica Mn. Tetra Oxide

Anti Settling Agent


Additive

Retarder -1

Retarder -2

Retarder Enhancer

Gas Block

Additive

46 35+10 65 0.8 0.7 0.5 0.6 1.2 2.0

0.5

Thick. Time min

F/L ml/30 min

In Cons Bc

Comp. Str. psi

Free Fluid

%

Stability

317 20 30 3100 Nil Stable


Consistency curve of cement slurry of sp gr 2.35 (BHCT: 225 0C, BHP: 18,000 psi, T T : 317 min)

Temperature, 0C

Pressure, Kpsi

Consistency, Bc



Conditions

Composition, % BWOC

Results


2.50 240 20,000 70

Water Silica Mn. Tetra Oxide

Anti Settling Agent


Additive

Retarder -1

Retarder -2

Retarder Enhancer

46 35+10 100 0.8 0.8 1.0 0.8 2.3 2.0

Thick. Time min

F/L ml/30 min

In Cons Bc

Comp. Str. psi

Free Fluid

%

Stability

309 35 20 3000 Nil Stable


Consistency graph of cement slurry of sp. gr. 2.50 ( BHCT: 240 0C, BHP: 20,000 psi, TT: 309 min)

Consistency, Bc

Pressure, Kpsi Temperature, 0C Temperature, 0C

Pressure, Kpsi

Consistency, Bc


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Performance & Testing Conditions

Specification: (Temp range 140-170 deg C BHCT)

Parameter Specification Unit

Pressure 12500 Psi

Temperature BHST/BHCT 200/ 170 Deg C

Raising Time 60 Minute

Initial consistency (Max) 20 BC

Sp. Gravity 2.0

Thickening Time 300±30 Minute

API Fluid loss ( Max) <50 Ml/ 30 minutes

Compressive strength after 48 hrs. ( Min) 2000 Psi

Free fluid Nil

Slurry Stability and BP test ( density difference Top & Bottom ) ( Max)

0.05 g/cc

Gas migration test Shall be gas tight slurry

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Pressure 15000 Psi




Sp. Gravity 2.35




Free fluid Nil


0.05 g/cc


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Pressure 18000 Psi




Sp. Gravity 2.5




Free fluid Nil


0.05 g/cc


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Comparative study: Digvijay v/s Dalmia

Condition Sp. Gr. Of Slurry BHST (˚C) BHCT (˚C)

BHP (psi) RT (Minute)

2.5 255 230 18000 70

Composition- % BWOC Cement (100gm)

Water Silica Mn3O4 Dispersant CFR-3

F/loss Additive H-413

Retarder-1 FDP-742

Retarder-2 Comp-R

Retarder-3 HR-12

Anti Settling S/ HT

Digvijay 46 40 100 0.8 0.8 2.3 2.0 0.8 0.8

Dalmia 46 40 100 0.8 0.8 1.7 1.3 -- 0.8

Results Cement (100gm)

TT F/Loss Ml/ 30 Min

Initial BC CS @ 24 Hrs

Free Fluid Stability Rheology Pv/Yp

Digvijay 309 30 30 3300 Nil ND 120/ 31 Vc - 10.2 fps

Dalmia 330 36 25 2800 Nil ND 125/ 25 Vc - 8 fps

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Comparative study: Dalmia v/s Dyckerhoff

Condition Sp. Gr. Of Slurry BHST (˚C) BHCT (˚C)

BHP (psi) RT (Minute)

2.5 255 230 15000 70

Composition- % BWOC Cement (100gm)

Water Silica Mn3O4 Dispersant CFR-3

F/loss Additive H-413

Retarder-1 SCR-742

Retarder-2 Comp-R

Anti Settling S/ HT

Digvijay 44 40 100 0.8 0.8 1.6 1.2 0.8

Dalmia 44 40 100 0.8 0.8 1.6 1.3 0.8

Results Cement (100gm)

TT F/Loss Ml/ 30 Min

Initial BC CS @ 24 Hrs

Free Fluid Stability Rheology Pv/Yp

Dalmia 330 36 25 2800 Nil ND 125/ 25 Vc - 8 fps

Dyckerhoff 282 40 15 3000 Nil ND 78/ 17 Vc - 6 fps

Typical T T consistency chart of SG 2.5 at 230 Deg C

Typical consistency Graph @ 2.50 SG

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Temperature, 0C

Pressure Consistency Bc


New Addition : SGSA

MACS-II

a) Evaluates Static Gel Strength (SGS) dynamically.

- by measuring torque in accordance with the resistance in shear of the paddle with the cement slurry.

b) Speed Range: ~0.2 deg/min (0.000556 rev/min) to 150 rev/min. c) Maximum Temperature: 600 °F (315.6 °C) d) Maximum Pressure: 30,000 psig (206.8 M Pascal) e) 100 to 500 lb/ 100ft2 within 45

minute indicate gas tight slurry.


New Addition : SGSA


New Addition : HT-UCA

a)The compressive strength,

along with temperature and

pressure, are monitored as a

function of time for the

purpose of providing a

strength history of a setting

cement slurry.

b) Max. Temperature: (260 °C)

c) Max. Pressure: 20,000 psi


New Addition :HT-UCA


Highlights of Cementing (R&D) TG,IDT

1. IDT identifies that high temperature thinning and high temperature settling of cement slurries are most critical parameters in designing cement slurries for 175-260 0C and of Sp. Gr. 2.10 - 2.50.

2. The problems of gas migration, ultra HPHT fluid loss and high temperature settling were found to be excellently controlled with the combination of particle packing with fine silica along with Hematite and Manganese Tetra-oxide.

3. Such a design is able to arrest gas migration and sedimentation even at ultra high temperature of 260 0C.

4. The particle range of 0.25-100 microns fine silica is critical to performance.

5. The suggested systems have synthetic retarders, non-viscosifying fluid loss control additives with a blend of Hematite and Manganese tetra-oxide to obtain best results.

6 IDT has inducted two new state of art technology i.e SGSA and HT-UCA.


Summary

Determine the Parameters as per API Recommended Practice 10B-2, Second

Edition April 2013 or as amended from time to time.

Fluid loss to be determined at bottom hole circulation temperature (BHCT)

&1000 psi , performing conditioning with Stirred fluid loss cell /Non stirred

Fluid- loss Cell using pressurized consistometer at the test temperature.

Determine the Rheology, Free fluid after raising the slurry to BHCT and cool

down to 88 deg C.

Sensitivity testing with ± 5% retarder concentration (same for retarder aids)

and ± 0.25Ib/gal (0.03 gm/cc) slurry density.

Gas Migration Test should be conducted on SGSA


Conti----

For strength retrogression additives 40% (Min) to be used.

Mn3O4(Manganese Tetra Oxide) miscible/dispersible in water without settling

/sedimentation to achieve the desired parameters is required.

Initial consistency to be recorded after 5 min conditioning at ambient

temperature.

Break required after raising temperature & pressure for 45 min .Hump shall

not elapse more than 30 sec from the time motor is switched on.

Computer software assisted planning helps to optimize the operation.

Rheological hierarchy has to be maintained.

Casing integrity testing is suggested with partial fluid replacement with water.

Thanks

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Cementing problems in HPHT wells and possible solutions ...

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