1. To Study Well Design Aspects in
HPHT Environment
Presented By:
Nikhil G Barshettiwar
Drilling Engineer
nikhilbarshettiwar@gmail.com

2. Index
• Introduction
• Literature survey
• HPHT well design
• Case study
• Result
• Observations
• Conclusions

3. Introduction
API Guideline 17TR8 [2015]
defines,
• Requirement of pressure
equipment (PE) or well control
equipment (WCE) greater than
15,000 psi.
• Or maximum anticipated surface
pressure (MASP) greater than
15,000 psi
• Flowing temperature greater than
350°F
Health & Safety Executive
(UK) defines,
• Non-disturbed bottom-hole
pressure (BHP) > 300° F
• Pore pressure gradient > 0.8
psi/feet
• Pressure control equipment >
10,000 psi
What is High Pressure High Temperature Environment (HPHT) ?

4. Introduction (Cont..)
Envelope-I :
150 C & 10,000 psi
• Behavior of standard elastomeric
seals
Envelope-II:
205 C & 20,000 psi
• Limitations of electronic tools
Envelope-III:
260 C & 35,000 psi
• Limitations of current technology
Reference- Oilfield Review, 2016

5. Literature Survey – Global Fields
References – Oilfield Review, 2008
HPHT FIELDS SPREAD

6. Literature Survey- HPHT Mechanism
• Depositional Effect
• Diagenetic Effects
• Tectonic Effect
• Structural Causes
• Thermodynamic effects
Depositional Effect Fields
Under-compaction of sediments Globally
Deposition of evaporites Pre-salt wells in Santos, Campos & Espirito
in Brazil
Salt diapirism Gulf of Mexico
Effective stress
velocity
Loading Curve
Elastic Behaviour U=1
Unloading
Curve
U=3-8

7. Literature Survey- HPHT Challenges
Drilling
• 30 % NPT due to frequent hole problems
• Unsuitability of conventional tubulars
• Limitation on current wellhead technology up to 350F & 15000 psi
• Frequent well integrity issues due improper cementing technology
Completion
• Current limit of completion fluids up to 20 ppg.
• Compatibility of completion fluids above 500F.
• Current seal limitations up to 400F in dynamic conditions.
• Limited high pressure retrievable packers. Use of permanent
packers again limited by availability milling tools.

8. Literature Survey- HPHT Challenges
Testing & Simulation
• Currently used proppant limited to 500F.
• Pressure equipments limitation to 20000 psi.
• Frequent pump break-downs
• Elastomers sensitivity at higher temperatures
• High rates of memory gauge failures due to high temperatures.
Data acquisition
• Poor data quality in seismic due to deeper reservoirs.
• Real time data acquisition (MWD-LWD) above 365F very rare.
• Logging tools working limit up to 425F.
• MWD battery working limit only upto 400F.

9. Literature Survey- HPHT Standards
• Protocol for verification and
validation of High Pressure High
Temperature equipment (API
TR 1PER 15K March 2013)
• High pressure high temperature
guidelines (API 17TR Feb 2015)
• Specification for subsurface
safety valve equipment (API 14A
Jan2015)
• Packers and bridge plug (API
11D1 April 2015)
• Riser system for floating
production facilities (APT STD
2RD, 2013)
• Christmas tree and wellheads
(API 6A/6X, 2014)
• Subsea wellheads and trees
(API Spec 17D, 2011)
• Drill through equipment (API
Spec 16 A, 2015)
• Subsea completion & work-over
intervention (API 17G)
• Tubular threaded connectors
(API 5C2, 2015)

10. HPHT well design- Casing Design
Effect of high pressure
• Use of thick tubulars in design
• Unsuitability conventional casing sizes
Effect of high temperature
• Yield strength reduction
• Tubular expansion
• Buckling of unsupported casing section
• Casing collapse due to annular pressure buildup Mechanical
considerations
Metallurgical
issues
Corrosion
resistance
Metallurgical
considerations

11. HPHT well design- Thermal Stress Analysis
TSA is useful to estimate thermal forces generated in casings, prevention of
buckling of unsupported section of casing, selection of cement tops, lock-down pin
selection & wellhead growth.
Input required for thermal stress
analysis:
• Wellhead undisturbed static temperature
• Seabed static temperature (Only for offshore)
• Bottom hole undisturbed static temperature.
• Operational conditions at surface
• Casing program.
• Heat transfer coefficient of formation fluids,
tubing, annular fluid, casing & formation.

12. HPHT well design- Drilling Fluids
Selection of HPHT mud system:
• Compatibility of drilling fluid with bottomhole tools.
• Less compression & expansion characteristics under downhole conditions.
Pressure profile measurement:
-Use of compositional model for accurate measurement of density of with respect to
pressure and temperature.
Temperature modeling:
-Prediction of flow line temperatures (FLT) & bottomhole circulating temperature
(BHCT)
- Generally flow line temperature should be restricted to 200F & 350F.
Rheology Model Selection:
-Power law model, Robertson-Stiff model & Herscel-Buckley model more accurate
at higher temperatures than Bingham plastic & Cason Model
- RS model most accurate above 180F.

13. HPHT well design- Drilling Fluids
Advanced drilling systems for HPHT systems:
Mud System Stability Characteristics
Chrome-Lignite & Chrome
Lignosulphonate
Up to 176 C • solid tolerant
• Highly stable
KCL-K-Lignite system Up to 170 C • shale inhibition
• solid tolerant
PHPA (Partially hydrolysed
Poly acrylomide)
- • encapsulates the cuttings &
coat borehole walls by
polymer
Polyol system - • clouding of shale by
manipulating clouding polyol
at required BHT with salt
Invert emulsion fluids Up to 260 C • can be weighted up to 19.5
ppg with barite emulsion

14. HPHT well design- Cementing
General Cementing Issues in HPHT:
• Strength retrogression
C-S-H (Excellent biding material till 230 F) => Alpha Dicalcium Silicate Hydrate
(Highly crystalline & shrinks).
Addition of silica forms ‘Tobermorite’
• ECD Management
Major issue in narrow window wells.
Range is as small as 0.1-0.5 ppg.
• Annular gas Migration
Result of unable to control density
& fluid loss.
‘Gas Flow Potential- a measure of
Severity due to gas migration’

15. HPHT well design- Cementing
HPHT Cement Types Characteristics
Portland cements • susceptible to strength retrogression above 230F.
Addition of silica preserves strength and lower the
permeability.
• Class G or Class H cements generally used with
combination of 40 % combination of silica (BWOC)
Class J cements • Generally use for wells with temperature above 260 F.
• Not covered under API list
• Addition of silica and retarders not required for
temperature below 300 F.
High alumina cement • Suitable for wide temperature fluctuations.
• Strength and durability can be simply maintained by
initial water to cement ratio.
HPHT cement systems

16. HPHT well design- Cementing
HPHT Cementing
additives
Characteristics
Retarders • Ligosulphonate or synthetic retarder
• more retarder => gas migration issues
Weighing agent • Above 16.5 ppg required weighing agent
• Barite weighted slurries (up to 19 ppg)
• Hematite weighted slurries (up to 22 ppg)
Extenders • Fly ash, Bentonite & Perlite
• Below 12.5 ppg, microsphere extension or foamed
cements.
Expanding additives • MgO upto 550F
• Expands with increase in temperature, improves
shear bond strength
Fluid loss additives • Must be restricted to 200 ml/30 min for oil wells &
50 ml/30 min for gas wells.
HPHT cement additives

17. HPHT well design- Material Selection
Material selection issues:
• No clear HPHT design methodology
Conventional approach of ‘leak before burst’ is no longer right approach, newer
designs using ‘fatigue and fast fracture’ as mode of failure.
Conventional standards API 6A, 16A & 17D do not use fatigue analysis. Assumption
of keeping max load & stresses below 2/3rd of yield stress proven wrong for thicker
wall sections.
ASME division 2 & division 3 are recommended
• Poor knowledge of test to validate design
Lack of information about material’s yield strength, fracture toughness & fatigue
resistance in HPHT environment.
Require new standards of material selection, qualification & testing.
• Limited publish data

18. HPHT well design- Material Selection
• 13 % Cr is applicable up to 145 psia partial pressure of CO2 with 250 gm/lit at
260 F.
• 22 & 25 % Duplex steels can be used up to 490 F. There is no limit of partial
pressure of CO2.

19. Case Study- HPHT in India
ONGC-COD has reported eight HPHT fields in South India. Out of which five
discovered in KG Basin & three in Cauvery Basin.
Sedimentary Basin Fields Properties
KG Basin Kottalanka HP, UHT, TR
Bantumilli HP, HT
Bhimanapalli HP, HT
Nagaylanka HP, TR
Yanam SW HP
Cauvery Basin Bhuvanagiri HP, TR
Periyakudi HP, HT, TR
Pallivaramangalam HP
* HP- High Pressure, HT- High Temperature, TR- Tight Reservoir, SW- Shallow
Water

20. Case Study- HPHT in India
• Seven oil field holds 350 Million tones of equivalent
• Out of which 50 Million tones recoverable with current technology
KG Basin
Depth (m) Temperature (F) Pressure (psi) Perm (%) CO2 content
4800-5400 400-470 12,400-13,500 3-5 Max 21%
Ave 8-10 %
Cauvery Basin
4800-5000 305-310 12,500 0.01-0.05 -

21. Results
• The wells identified for well engineering has an average depth of 5000 m.
• The main objective is to penetrate ‘sands’ between 4180 m- 4820 m.
• Expected temperature in area varies between 321F-444F. Maximum
temperature for candidate well equals to 155 C.
• Expected bottomhole pressure in region 11,000-13,000 psi. Pore pressure
and fracture pressure in candidate well pre-determined equals to 13.8 ppg &
17.6 ppg respectively.
• Maximum well depth = 4750 meter
• Maximum permeability = 0.01-0.05 md

22. Results- Regional Mud Weigh Model

23. Results- Casing seat selection
Casing Policy
Type of casing Depth Casing Size Hole Size
Surface Casing 650 m 18 5/8” 20”
Intermediate
Casing
2500 m 13 3/8” 16”/ 17 ½”
Production
Casing
4100 m 9 5/8” 12 ¼”
Production Liner 4750 m 5 ½” 8 ½”

24. Results- Casing stress analysis
* Production liner recommended is not as per inventory. New grade with higher weight
is chosen to satisfy expected load condition.

25. Results- Mud Program

26. Results- Mud recommendations
• Viscosity of mud should be as low as possible in order to reduce the ECD.
• Gel strength should be sufficient to prevent sagging of solids.
• HPHT fluid loss should be minimum to prevent formation damage and also to
prevent differential sticking.
• Rheology should be mentioned to prevent sag, gelation and higher ECD’s.
• Mud should be stable with the contaminants. As generally HPHT reservoirs
consists CO2 and H2S, it should be accommodate the initial effects of it.
• It must be weighted up rapidly in case of well kicks.
• Base-fluid density must be adjusted at downhole pressure & temperature
conditions using PVT measured behaviour of fluid.
• During hydraulics calculations, use of Herschel-Buckley model can yield better
results. Hence it should be preferred for circulating pressure loss calculations.

27. Results- Mud recommendations
• Gases are soluble in oil-based mud. It may take longer duration to confirm
observable pit gain in such conditions. So extended flow checks are advisable during
use of OBM. Generally 10 minutes or more.

28. Results- Thermal Growth Analysis
Assumptions:
• The wellbore is shut-in for longer time of production thus well temperature is in
equilibrium with reservoir temperature.
• There is complete heat transfer between the casing. Wellbore is assumed as single
vessel with specific temperature equals to reservoir temperature.
Maximum Thermal Forces Generated (At Tw = Tr)
Surface casing 1354937 lbf
Intermediate casing 785153 lbf
Production casing 540567 lbf
Production liner 204595 lbf
Wellhead growth = 82.54”

29. Results- Thermal Growth Analysis
If Intermediate casing string cemented till surface = 0.0021”

30. Results- Thermal Growth Analysis
If production casing string cemented till surface = 0.0028”

31. Results- Cementing Program
* Gas block additives for every string except surface string.
* As use SOBM/OBM weakens bonding due to oil-wet conditions, spacer
with surfactant is recommended to change wettability.

32. Results- Cementing recommendations
•Reason for poor cementation job includes mixing of fluids during cementation,
improper centralization, insufficient displacement velocities, and wrong job design
due to improper BHCT measurement.
• Generally cementing design mainly focused on short term early compressive
strength. In long term point of view, one should consider cyclic stresses on the well
cements (fatigue stresses). Cement can sustain with compressive strength but tensile
strength of cement needs to be considering for stimulation operations.
• Length of the spacer should be long enough to prevent thermal shock to the cement.
Otherwise it may lead early setting of cement.
• Managed Pressure Cementing (MPC) is viable option in tight drilling window
environment i.e. 0.1-0.3 ppg window.
• Caliper measurement must be use for good centralization design. More the
centralizers per unit joint better the centralization. Good centralization helps for
efficient displacement of drilling fluid behind the casing which ultimately helps for
good cementing job.

33. Results- Cementing recommendations
• Fluid Displacement Modeling (FDM) should be essential part of cementing plan.
• API over predicts the BHCT values which may mislead the job design. Temperature
simulators must be used to determine well temperature in dynamic conditions.
• Casing movement must be performed while circulating drilling fluid and pre-flushes
as it helps to reduce drilling fluid viscosity and dislodged gelled fluid trapped in
annulus.
.

34. Results- Gas Migration Severity Analysis
Gas flow potential Severity
< 4 Minor
4-8 Moderate
8 > Severe

35. Results- Wellhead Selection
Maximum Anticipated Surface Pressure = 9,625 psi
Designed pressure = 10,586 psi
15K Wellhead is recommended with PSL 3G specifications.

36. Observations
• Consideration of PVT properties as in input in design
process can optimize casing design.
• Presence of H2S restrict use high strength tubulars. As only
CO2 was present in the well Q-125 is used.
• 18 5/8” casing has comparatively higher strength than 20”
casing thus it is use as surface casing in commonly HPHT
applications.

37. Conclusions
• PVT properties of hydrocarbon has major impact on casing policy. It can be
optimized if PVT properties of hydrocarbon consider in simulation.
• Regional models of pore pressure, fracture pressure & mud weight from offset
wells can be useful to cross check correctness of predicted parameters. Well
profiling and trend analysis can save cost due to NPT.
• Temperature modeling must be an essential part of HPHT well design. It helps to
optimized fluid programs and thermal stress analysis of well system.
• Material technology in HPHT environment is most neglected area. Advancement
in material technology can improve cost of HPHT wells drastically.
• Qualification and testing of materials in HPHT environment need immediate
attention. API standards doesn’t cover material testing for HPHT environment.

38. References
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Approaches”, Oil & Gas Technology-Rev IFP, vol 54, 1999 pp. 667-678
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Conference, Houston, Texas, 1998.
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Offshore Technology Conference, Houston, Texas, 2003.
• DeBruijn G et al: “An Integrated Approach to Cement Evaluation”, Oilfield Review
28, no.1 (January 2016): 10-29.
• Docherty K: “Mud Removal- Clearing the Way for Effective Cementing”, Oilfield
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157977, SPE Asia Pacific Oil & Gas Conference, Perth, Australia, 2012.
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development in offshore Vietnam”, OTC 26374-MS, Offshore Technology Conference,
Kuala Lumpur, Malaysia, March 2016.

39. References
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SPE 155320, SPE Oil & Gas conference & exhibition, Mumbai, India, 2012.
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40. THANK YOU