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Module F: Drilling in Unusual Stress Regimes Part I – Overpressured Cases Maurice B. Dusseault University of Waterloo

Drilling in Overpressured Zones
For practical purposes ($), reducing the number of casings or liners is desirable However, drilling in OP zones carries simultaneous risks of blowouts and lost circulation that are difficult to manage. There now exist new options that help us: Drilling slightly above shmin with LCM in the mud Bicentre bits and expandable casings Understanding overpressure and also the deep zone of stress reversion will help

Normally pressured range:
Pressures at Depth Fresh water: ~10 MPa/km 8.33 ppg 0.43 psi/frt Sat. NaCl brine: ~12 MPa/km 10 ppg 0.516 psi/ft pressure (MPa) ~10 MPa Hydrostatic pressure distribution: p(z) = rwgz 1 km Underpressured case: underpressure ratio = p/(rwgz), a value less than 0.95 Overpressured case: overpressure ratio = p/(rwgz), a value greater than 1.2 underpressure overpressure Normally pressured range: 0.95 < p(norm) < 1.2 depth

Some Definitions For consistency, some definitions:
Hydrostatic: po = “weight” column of water above the point, r = 8.33 ppg to 10 ppg in exceptional cases of saturated NaCl brine Underpressure is defined as po less than 95% of the hydrostatic po, usually found only at relatively shallow depths (<2 km) or in regions of very high relief (canyons…) Mild overpressure: po of 10 ppg to 60% sv Medium overpressure: po of 60 to 80% sv Strong overpressure: po > 80% of sv

Abnormal Pressure, Gradient Plot
1.0 2.0 Typically, po is close to hydrostatic in the upper region shmin is close to sv in shallow muds, soft shale, but lower in stiff competent deeper shale A sharp transition zone is common ( m) The OP zone may be 2-3 km thick A stress reversion zone may exist below OP 1 16.7 ppg po hmin 2 v thick shale sequence 3 po 4 Target A 5 Target B 6 Target C depth - kilometres

GoM –The Classic OP Regime

Other Well-Known Strong OP Areas
Iran, Tarim Basin (China), North Sea, Offshore Eastern Canada, Caspian In many thick basins, OP is found only at depth, without a sharp transition zone Most common in young basins that filled rapidly with thick shale sequences Good ductile shale seals, undercompaction Watch out for OP related to salt tectonics! These are most common offshore: Land basins have often undergone uplift Tectonics have allowed pressures to dissipate

Eastern Canada Overpressured Areas
Nova Scotia Gas Belt Importance of Geomechanics Exports

Porosity vs Depth & Overpressure
0.25 0.50 0.75 1.0 porosity sands & sandstones mud clay Anomalously high f, low vP, vS, and other properties may indicate OP clay & shale, “normal” line mud- stone In some cases, 28% f at depths of 6 km! shale effect of OP on porosity 4-8 km +T depth slate (deep)

Permeability and Depth
Permeability – k – Darcies Muds and shales have low k, < D, and as low as D Exception: in zones of deep fractured shale, k can approach D Sands decrease in k with z Exception, high f sands in OP zones can have high k Anhydrite, salt k = 0! Carbonates, it depends 1 2 3 4 5 Muds and Shales Sands and Sandstones 5 10 15 20 25 Intact muds and shales have negligible k Depth – z – 1000’s ft High porosity OP sands have anomalously high porosity & permeability Fractured shales at depth may have high fracture permeability

Abnormal po Causes Delayed compaction of thick shale zones
Water is under high pressure Leak off to sands is very slow (low k) Thermal effects (H2O expansion) Nearby topographic highs (artesian effect) Hydrocarbon generation (shales expel HCs, they accumulate in traps at higher po) Gypsum dewatering ( anhydrite + H2O) Clay mineral changes (Smectite  Illite + H2O + SiO2) Isolated sand diagenesis (Df, no drainage)

Mechanisms for OP Generation
Compaction = H2O expelled to sand bodies, especially from swelling clays Mud, clays m H20 H20 Sand H20 Shale m Montmorillonite = much H2O Sandstone Diagenesis m Illite Kaolinite Chlorite Compaction and Clay Diagenesis + Free H2O + SiO2

Mechanisms for OP Generation
Artesian effect (high elevation recharge) Thrust tectonics (small effect) Deep thermal expansion rain clays and silts Artesian charging 3-10 km Artesian charging is usually shallow only Thrusting can lead to some OP +DT = +DV of H2O: thermal expansion at depth km

Offshore: Trapping of OP
Listric faults on continental margins lead to isolated fault blocks, good seals, high OP in the isolated sand bodies from shale compaction “down-to-the-sea” or “listric” faults sea stress shale v h po slip planes shale Sand bodies that have no drainage because of fault seals, OP is trapped indefinitely depth Stress reversion zone

HC Generation and OP HCs generated in organic shales sv Semi-solid
T, p, s increase shale Semi-solid organics, kerogen, po < sh < sv kerogen micro- fissure sv high T, p, s po = sh < sv, Fractures develop and grow sands Pressured fluids are expelled through the fracture network, po “stored” in OP sands fluid flow oil and gas generation of hydrocarbon fluids

OP From Gas Cap Development
Thick gas cap development, perhaps charged from below, can generate high OP A pressures along A-A stress gas cap, low density gas cap effect oil, density = A Gas migration along fractured zones, faults, etc. po sh Fractured rock around fault Deep gas source depth Gas rises: gravitational segregation

Abnormal Pressure – Sand-Shales
Overpressure is often generated due to shale compaction and clay diagenesis Montmorillonite (smectite) changes to lllite/Chlorite at depth. H20 is generated and is a source of OP. Pressure is generated in shales, sands accumulate pressure PF commonly higher in shales than sands Sand-shale osmotic effects (salinity differences) can also contribute to OP

PF in GoM Sand-Shale Sequences
Absolute stress values Stress gradient plot stress shmin sv PF in sand line shmin sv z z shale sandstone shale sandstone limestone shale depth depth Pore pressure distribution, top of OP zone

Some Additional Comments
Casing shoes are set in shales (98%) The LOT value reflects the higher shmin in the shales, therefore a higher PF As we drill deeper, through sands, the actual shmin value is less! By as much as 1 ppg in some regions Can be unsafe, particularly when we increase MW rapidly at the top of the OP zone You should test this using FIT while drilling

Examination of a “Typical” Synthetic OP Case

Particularly Difficult OP Case
1.0 (8.33 ppg) 2.0 (16.7 ppg) Deep water drilling, mud heavier than H2O Thick soft sediments section, PF ~ sh ~ sv Thin, shallow, gas-charged sand Zone where sh is roughly unchanged Sharp transition zone High OP, 90% of sv Deep zone of stress and pressure reversion Sea water depth 800 m 1 800 m soft sediments 2000 m medium stiff shales and silts 2 po sh sv 3 seal sharp transition 4 1400 m OP zone 5 Reversion zone 6 Z – kilometers (3279 ft/km)

Medium stiff shales and silts
Upper Part of Hole 1.0 (8.33 ppg) 2.0 (16.7 ppg) The vertical lines are several MW choices Riser and first csg. MW 9.16 ppg does not control gas, but only fractures above 950 m 10.0 ppg controls gas, but losses above 1200 m will be a problem. It does allow deeper drlg. Solution, riser seat at ~1000 m Casing shoe at ~1400 m Sea water m 9.16 ppg 10.0 ppg 800 m soft sediments 1 2 Medium stiff shales and silts Z – kilometers (3279 ft/km)

Riser Issues in this Example
Sea water is ~ 1.03 ~8.6 ppg At great depth, MW may be as high as 2.02 (17 ppg) if the riser is exposed fully The D-pressure at the riser bottom is very large: 800m  9.81  (2.02 – 1.03) = 7.8 MPa The riser must be designed to take this Or, special sea-floor level equipment must be installed Special mud lift systems from the sea floor, etc.

Approaching the Transition Zone
1.0 (8.33 ppg) 2.0 (16.7 ppg) LOT of 1.3, ppg This limits us to 3.6 km for the next casing However, this will require a liner to go through transition zone Liner from 3600 m to 3750 – 3800 m If it is possible to drill 100 m deeper initially, to 3700 m, we may save the liner ($1,000,000) Sea water m 800 m soft sediments 1 2000 m shales and silts 2 po sh sv 3 sharp transition 4 OP zone Z – kilometers (3279 ft/km)

Solution A: Casing or Liners
1.0 (8.33 ppg) 2.0 (16.7 ppg) This is the most conservative, safest, and the most costly Black line is MWmax If shale problems occur in the km shale zone, requiring an extra casing… (i.e., little margin for error) Sea water 1 2000 m shales and silts 2 po sh sv 3 4 OP zone Z – kilometers (3279 ft/km)

Sol’n B: Drill OB With LCM?
1.0 (8.33 ppg) 2.0 (16.7 ppg) Dashed line is from the previous slide Drilling with the purple line, saves a liner! This is ~1.2 ppg OB at the shoe (quite a bit!) Place upper casings deeper if possible Drill with LCM in mud (see analysis approach in Additional Materials) Place a denser pill at final casing trip (Approach with caution) Sea water 1 2000 m shales and silts 2 po sh sv 3 4 OP zone Z – kilometers (3279 ft/km)

Solution C: Deeper Upper Casings
1.0 (8.33 ppg) 2.0 (16.7 ppg) 300 m subsea primary casing depth Casing at 1850 m depth Drill long shale section with MW shown as dashed black line Increase MW only in last 100 m (LCM to plug ballooning at the shoe) Slight OB of ppg needed Casing may be saved (?) Sea water 1 2 Slight OB needed 3 sh sv po OP zone 4 Z – kilometers (3279 ft/km)

Deeper Upper Casing Shoes
Depending on the profile of OP stresses and pressures, this approach can be effective, but in some cases it is not Of course, the best approach is always to place the shoes as deeply as possible This may give us a one-string advantage deeper in the well if problems encountered At shallow depths (mudline to ~4000 ft), use published correlations with caution because there are few good LOT data

Comments on the Approaches
There is risk associated with saving a casing string: risks must be well-managed … The stress/pressure distribution sketched is a particularly difficult case: Shallow pressured gas seam at 1500 m subsea PF (sh) is quite low around 3000 m subsea Transition zone is very sharp (~250 m) OP is high (88-90% of sv) However, it could even be worse! More gas zones, depleted reservoirs at 3.6 km Etc…

Drilling Through a Reversion Zone
Below OP, usually a zone where po, sh (PF) gradually revert to “normal” values. This is rarely a sharp transition as at top of OP This is related to fractured shales that “bleed off” OP (i.e. lower OP seal is gone) Also, when shales change and shrink, the sh value (PF) drops as well “Reverse” internal blowout possibility Blowout higher in hole Fracturing lower in hole

Stress Reversion at Depth
stress (or pressure) vertical stress, v horizontal stress, h pore pressure, po Note that hmin can become > v 4 km depth Region of strong overpressure Stresses “revert” to more ordinary state Higher k rocks (fractured shales) Z

Same Example… OP casing was set at 3800 m depth Drill with 16.7 ppg MW
At 5.5 km, large losses If we reduce MW, high po at 4.6 km can blow out, flow to bottom hole at 5.5 km (reverse internal BO) Set casing at 5450 m Drill ahead with reduced MW 4 1400 m OP zone 5 Reversion zone po sh sv 6 Z – kilometers (3279 ft/km)

Real Deep Overpressure Drilling
Watch out for shallow gas sands Dark black line: MWmax for the interval Dashed black line is the actual drilling MW Red stars: excessive shale caving, blowouts Green stars: ballooning and losses Surface casing string not drawn on figure This is a deep North Sea case, west of Shetlands

Detecting OP Before Drilling
Seismic stratigraphy and velocity analysis Anomalously low velocities, high attenuations Can often detect shallow gas-charged sands (unless they are really thin, < 3-5 m) Geological expectations (right conditions, right type of basin and geological history…) Offset well data, good “earth” model, so that lateral data extension is reliable

Detecting OP While Drilling
Changes in the “Dr” exponent, penetration rate may increase rapidly in OP zone Changes in seismic velocity (tP increases) Changes in porosity of the cuttings (surface measurements or from MWD) Changes in the resistivity of shales from the basin “trend lines” Changes in the SP log Changes in drill chip and cavings shapes, also volumes if MW < po Mud system parameters, etc

Comments on LWD Methods of data transmission…
Mud pulse – 2 30,000’, b/s is good at any depth Issues in data transmission: Long wells, extended reach OBM, electrical noise, drilling noise ID changes in the drill string Pump harmonics, stick/slip sources “Wire” pipe – extremely expensive High rate on out-trip, then download on rig New technologies will likely emerge soon…

Reasons for Pore Press. Prediction
Drilling Problems Due to Pressure Imbalance: Overbalance: Slow drilling, Differential Sticking, Lost circulation, Masked shows, Formation damage. Underbalance: Imprudently fast drilling, Pack- offs, Sloughing shales, Kicks, Blowouts.

Pore Pressure Prediction Basics I
Data from offset wells Logs, Dr data, sonics, neutron porosity, resistivity, etc. Transfer data to new well stratigraphy, z Plot sv gradient, sonic transit time, Dr, resistivity, porosity, etc. with depth Use trend analyses and published methods, to determine the “normal compaction line” Use an Eaton correlation chart if you have it for this area (use offset and other data) This is the prognosis profile for new well

Pore Pressure Prediction Basics II
With seismic data and geological model of the new well region, assess: Existence of OB conditions (seals, sources…) Existence of faults, salt tectonic features… Plot depth corrected velocities on profile: Carefully compare the two: Lower velocities = greater OP risk… Explain existence of any undercompacted zones and anomalies you have identified You now have as good a prognosis as you can develop with existing data

Sonic Transit Time Differences
1.0 (8.33 ppg) 2.0 (16.7 ppg) Log of sonic transit time Sea water depth 800 m 650 ms/m 1 Soft seds. Normal trend from the basin, offset data Seismic velocity model Stiff shales and silts 2 po sv 3 Sonic transit time from offset wells seal Expected OP transition 4 PROGNOSES FROM OFFSET WELL DATA, CORRECTED FOR Z, ETC… Critical region OP zone 5 Reversion zone 6 Z – kilometers (3279 ft/km)

Prognoses Based on Seismics
Normal compaction line for the basin General seismic profile data, depth corrected for new well Corrected sonic transit time, calibrated with the general seismic velocity data Regions of substantial deviation are highlighted as “critical”, experience used to choose likely top of OP OP magnitude estimated, based on correlations OP beginning Large OP expected

Seismic Cross-Sections
Depth Converted 1:1 Horizontal / Vertical Ratio Offset Well Ties (Regional) Planned Wellbore (Local) Full Structural Picture Fully Annotated Radial Animation

North Sea Seismic Section - Diapir
Gas Pull Down Top Balder Top Chalk Intra Hod/Salt Well A 1b Mid-Miocene regional pressure boundary Courtesy Geomec a.s.

Other “Trend Line” Approaches
Methods exist for using trend analysis for many different measures, including: Drilling exponent data Resistivity trends lines (salinity of strata) Deviations from expected porosity (less sensitive) SP log characteristics Perhaps some others… Shale data are used because sand porosity is less “predictable” in general

Gas Cutting of the Drilling Mud
Shale behaves plastically at elevated pressure and temperature gradients. Significance (and insignificance) of gas cut mud (GCM). Gas from CH4 in shales? Very large gas units: 2,000 to 4,000 units ? Connection gas (CG) - better indicator. Use it for well to talk. Ineffective when too much overbalance. CG increase from 20, 40, 60 to 80 points. Yes, you are underbalanced.

Is MW a Pressure Indicator?
No. The lower limits of MW in most OP regimes are related to shale stability, rather than to pore pressure Usually, in difficult shales, 1 to 2 ppg above po is needed to control excessive shale problems HOWEVER! MW limits from offset well drilling logs are useful to estimate MWmin Of course, this can change as well: More inhibited WBM, using OBM instead, etc… Faster drilling, less exposure, etc…

MWmin Prognosis Offset well pressure, stress, drilling data…
Estimate target MWmin for new well prognosis If this generates too narrow a MW window, assess approaches Will OBM allow a lower MWmin? (on the plot, the dashed blue line is the estimated OBM MW for shale stability) Other factors?

MWmin, MWmax Well Prognosis
1.0 (8.33 ppg) 2.0 (16.7 ppg) Use a rock mechanics borehole stability model, calibrated, to estimate MWmin from geophysical logs and lab data Use offset well losses, ballooning, LOT, etc. to estimate MWmin This defines the local “safe” MW window Now, combine with casing program prognosis to plan the MW for the well Sea water depth 800 m 1 Soft seds. Weak rocks Stiff shales and silts 2 sv 3 po Expected OP transition 4 PROGNOSES FROM OFFSET WELL DATA, CORRECTED FOR Z, ETC… OP zone 5 Reversion zone Strong rocks 6 Z – kilometers (3279 ft/km)

During Drilling… Remember, in OP drilling we are trying to “push the envelope” to reduce casings Update the well prognosis regularly with actual LOT, MWD, ECD data Monitor, measure, observe… Kick tolerances, ballooning behavior, gas cuts Chip morphology and volumes Flow rate gauges on flowline, pumps Mud temperature monitoring MWD temperature Sticky pipe, torque, ECD, mud pressure fluctuations Cuttings analyses: vP, Brinnell hardness are used

Increasing Depth of Casing Shoe
(2.0 = 16.7 ppg) 1.1 1.3 1.5 1.7 1.9 2.1 2.3 density, g/cm3 prognosis for shmin MW =1.92 Previous casing string prognosis for po sv XLOT shmin value overpressure transition zone shoe deeper shoe for casing string! area indicates possible MW strong overpressure zone depth Using high weight trip pills and careful monitoring, the lower limit can be extended

High Weight Trip Pills Drill ahead beyond “limit” (if shales permit) with MW = LOT at the shoe PF Some gas cutting of the mud and shale sloughing… If too severe, casing For trip, set a pill of higher weight This creates a change in slope of the mud pressure line in the “window” (see figure) Pull out carefully, no swabbing please Set casing (best with top drive and some ability to pump casing down a bit) Unlikely to succeed with gas sands present

An OP Well Prognosis WELL DESIGN - HI 133 No. 1 MW, PF, & EST. po
PORE PRESSURE (PPG) WELL DESIGN - HI 133 No. 1 EXPECTED MW (PPG) FRAC GRAD. (SAND) MW, PF, & EST. po FRAC. GRAD (SHALE) 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 DEPTH - ft 8 9 10 11 12 13 14 15 16 17 18 19 MUD WEIGHT - ppg

Same Overpressured Well, GoM
WELL DESIGN - HI 133 No. 1 MW, PF, & ESTIMATED po 1000 2000 PORE PRESSURE (PPG) EXPECTED MW (PPG) 3000 FRAC GRAD. (SAND) FRAC. GRAD (SHALE) 4000 5000 6000 DEPTH 7000 8000 9000 10000 11000 12000 13000 14000 8 9 10 11 12 13 14 15 16 17 18 19 MUD WEIGHT

Approach for this Well - I
From 8600´to 9400´po goes from 9.5 ppg to 15.7 ppg (1.14  1.89 g/cm3)! A liner over a ´length is necessary, but we don’t want to install a second liner Strategy: Below the 3000´ shoe, drill as close to po as possible, as fast as possible to avoid shale issues Below 8200´, weight up while drlg. to as high as possible (upper part of hole will be overbalanced) This is a case where we may add carefully graded LCM to help build a stress-cage higher in the hole Drill as deep as possible, hopefully to 9100´…

Approach for this Well - II
Strategy (cont’d) Push the envelope for depth, managing your ECD carefully, living with a bit of ballooning To trip out and case, place a high density “pill” for safety (e.g. 18 ppg mud for bottom 1500´) Set casing (partly cemented only) at ´ Mud up to MW slightly higher than po, drill out, do XLOT, advance carefully, gradually increasing MW Set a liner as deep as possible, 9900´ if possible Mud up before drilling out with 16.5 ppg mud with carefully designed LCM to “strengthen the hole” Do a precision XLOT, drill ahead to TD, increasing MW only as required

Deep Water Drilling & Stability
Narrow operating window is common Circulating risks, ECDs, monitoring…. Special mud rheology: low T, riser cools the mud massively, down to 5-10° is common Casing design often requires many short casing strings, shallow muds, overpressure, and the zone of pressure reversion Well control is tricky because of the narrow window, long risers, etc… Rig positioning and emergency disconnect critical for safety (no circulation for days)

Gullfaks North Sea case Overpressure Reversion zone Depletion effect

Franklin Field, UK West Sector
MPa po in deep Triassic zones T to °C measured 6300 m deep (~20,000 feet) Mud weights of ppg required Very narrow MW window near reservoir Retrograde condensate field, liquids are generated near the well, reducing k Surface pres. up to 101 MPa (15000 psi)! Reservoir experienced rapid depletion and this led to very high effective stresses, as well as massively reduced lateral stresses

Lessons Learned OP drilling: a major challenge, particularly:
In young offshore basins In deep water (riser length issues) Careful well prognoses are critical (PF, po…) Prognoses must be updated while drilling The envelope can be pushed! Living with breakouts for lower MW Using LCM to generate somewhat higher PF Special trip practices, special equipment… In OP drilling, vigilance is absolutely critical Increase your observations, understand them

Additional Materials Also, visit the following website for a comprehensive list of formulae for your pressure calculations in drilling:

Courtesy of: Francesco Sanfilippo Geomec a.s., Norway
Fracture Pressure Enhancement in Drilling Through Use of Limited Entry Fracturing and Propping Courtesy of: Francesco Sanfilippo Geomec a.s., Norway Courtesy Geomec a.s.

The Concept To enhance fracturing pressure by drilling slightly overbalance and, at the same time, by effectively plugging and sealing the induced hydraulic fractures Already plugged Not plugged Induced fracture Courtesy Geomec a.s.

How Can this be Analyzed?
Find a simple description of this process First-order physics Estimate the fracturing pressure enhancement Evaluate the importance of the involved factors and identify the first-order parameters Courtesy Geomec a.s.

Methodology Estimate the enhancement through the classical results (England and Green equation) Modify the Perkins-Kern-Nordgren model to take into account the effect of progressive plugging Courtesy Geomec a.s.

Classical results England and Green’s equation can be used once the geometrical parameters of the fracture are known. It estimates the hoop stress increase from the mechanical properties of the rock and and the geometrical parameters of the fracture Two shapes have been considered: ”Penny shape”-like fractures PKN-like fractures (length>>height) Base case for the parametric study: Young modulus: 40 GPa Poisson’s ratio: 0.2 Fracture width: 3 mm Fracture height/radius: 10 m Courtesy Geomec a.s.

Classical results: effect of the Young modulus
Courtesy Geomec a.s.

Classical results: effect of the Poisson coefficient

Classical results: effect of the fracture width

Classical results: effect of the fracture height

Modified PKN model With this model the geometrical parameters of the fracture are estimated according to the measurements while drilling Plugging is considered through a reduction of the fracture permeability with time up to complete sealing Base case for the parametric study: Young’s modulus: 40 GPa Poisson’s ratio: 0.2 Mud viscosity: 5 cP Mud loss rate: 1 bbl/min Time required to plug the fracture at a given depth: 30 min Rate Of Penetration: 10 m/hr Courtesy Geomec a.s.

Modified PKN model: fracture aperture vs. time

Modified PKN model: effect of Young modulus

Modified PKN model: effect of Poisson coefficient

Modified PKN model: effect of mud viscosity

Modified PKN model: effect of mud loss rate

Modified PKN model: effect of plugging time

Modified PKN model: effect of Rate of penetration

Role and Design of Plugging Material
The plugging material is a mixture of mud clay, barite, formation debris (cuttings), plus carefully sized LCM It plugs the induced fracture rapidly, and sq is increased permanently by propping The effect is limited in extent, but the sq stress does not relax during drilling The LCM is designed (concentration, size range) based on the mud parameters : for further details

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