To Study Well Design Aspects in HPHT Environment

Presented By:Nikhil G BarshettiwarDrilling Engineernikhilbarshettiwar@gmail.com

Index• Introduction

• Literature survey

• HPHT well design

• Case study

• Result

• Observations

• Conclusions

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) ?

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

Literature Survey – Global Fields

References – Oilfield Review, 2008

HPHT FIELDS SPREAD

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

velocityLoading CurveElastic Behaviour U=1

Unloading Curve U=3-8

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.

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.

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)

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

HPHT well design- Thermal Stress AnalysisTSA 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.

HPHT well design- Drilling FluidsSelection 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.

HPHT well design- Drilling FluidsAdvanced drilling systems for HPHT systems:

Mud System Stability CharacteristicsChrome-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

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’

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

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

HPHT well design- Material SelectionMaterial 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 designLack 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

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.

Case Study- HPHT in IndiaONGC-COD has reported eight HPHT fields in South India. Out of which five discovered in KG Basin & three in Cauvery Basin.

Sedimentary Basin Fields PropertiesKG 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

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 BasinDepth (m) Temperature (F) Pressure (psi) Perm (%) CO2 content

4800-5400 400-470 12,400-13,500 3-5 Max 21%Ave 8-10 %

Cauvery Basin4800-5000 305-310 12,500 0.01-0.05 -

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

Results- Regional Mud Weigh Model

Results- Casing seat selection

Casing PolicyType 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”

Results- Casing stress analysis

* Production liner recommended is not as per inventory. New grade with higher weight is chosen to satisfy expected load condition.

Results- Mud Program

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.

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.

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 lbfIntermediate casing 785153 lbfProduction casing 540567 lbfProduction liner 204595 lbf

Wellhead growth = 82.54”

Results- Thermal Growth Analysis

If Intermediate casing string cemented till surface = 0.0021”

Results- Thermal Growth Analysis

If production casing string cemented till surface = 0.0028”

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.

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.

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. .

Results- Gas Migration Severity Analysis

Gas flow potential Severity

< 4 Minor

4-8 Moderate

8 > Severe

Results- Wellhead SelectionMaximum Anticipated Surface Pressure = 9,625 psi

Designed pressure = 10,586 psi

15K Wellhead is recommended with PSL 3G specifications.

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.

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.

References• Grauls D, “Overpressure: Casual Mechanisms, Conventional and Hydromechanical Approaches”, Oil & Gas Technology-Rev IFP, vol 54, 1999 pp. 667-678• Oakes.N.E.:“HPHT, development of subsea option”, OTC 8741, Offshore Technology Conference, Houston, Texas, 1998. • Rommetviet.R. et.al.: “HPHT Well Control; An Integrated Approach”, OTC15322, 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 Review 28, no.1, (January 2016): 20-25. • Liang Q. Jim, “Casing thermal stress & wellhead growth behavior analysis”, SPE 157977, SPE Asia Pacific Oil & Gas Conference, Perth, Australia, 2012. • Brownlee.J.K et.al, “selection & qualification of materials for HPHT wells”, SPE 97590, SPE Sour well design applied technology workshop, Taxas, USA, 2005. • Nguyen T et al, “ Effect of high pressure high temperature condition on well design development in offshore Vietnam”, OTC 26374-MS, Offshore Technology Conference, Kuala Lumpur, Malaysia, March 2016.

References• Shah P.H et al, “Offshore drilling & well testing of a HPHT gas well: A case study”, SPE 155320, SPE Oil & Gas conference & exhibition, Mumbai, India, 2012. • Haider S et al, “HP/HT cement system design- East Coast Case History”, SPE/IADC 104048, SPE Indian Drilling Technology Conference and Exhibition, Mumbai, India, 2008. • Godawin Woha et al, “Advances in mud design and challenges in HPHT wells”, SPE 150737, Nigeria Annual International Conference and Exhibition, Abuja, Nigeria, August 2011. • Lehr D & Collins S, “The HPHT completion landscape- Yesterday, Today and Tomorrow”, SPE 170919, SPE Annual Technical Conference and Exhibition, Amsterdam, The Netherlands, October 2014. • Lugo Miguel, “Design and drilling of a ultra HPHT exploratory well on Gulf of Mexico”, SPE 178809, IADC/SPE Drilling conference and Exhibition, Texas, USA, March 2016• Shadravan A & Amani M, “HPHT101-What Petroleum Engineers and Geoscientist Should Know About High Pressure High Temperature Wells Environment”, ISSN 1923-8460, Energy Science & Technology, CS Canada, vol-4, No. 2, 2012, pp.36-60 • Yuan Z, “Casing failure mechanism and characterization under HPHT conditions in South Texas”, IPTC-16704-MS, International Petroleum Technology Conference, Beijing, China, March 2013

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