Pore Pressure Basic Level 1a6443
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Introduction to Formation Pressures Course for Schlumberger, Sept 26-27, 2000
A Division of Knowledge Systems, Inc.
World-wide occurrence of abnormal formation pressures
2.16/ 18+ 2.05/ 17 2.3/ 19+ 2.37/ 22 2.34/ 22+
2.4/ 22+
2.2/ 18+
1.92/ 16
2.22/ 19 1.92/ 16
2.34 = Pf in sg EMW 19 = Pf in ppg EMW
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Motivations for Understanding Pore Pressures
Mud Casing ++
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Risk to Environment
Well Costs
Knowledge of Area
Well/Human Safety
Best PP evaluation while drilling
Drilling Efficiency
Drilling Prog. Quality
Accurate PP prognosis
Rigtime Optim MW
Kicks Blowouts
3
Pore Pressure Concepts (1) Pressure = Force/Area (also stress) - kPa, psi, bars Hydrostatic pressure - Pressure exerted by the weight of a column of fluid; - Varies by basin, fluid salinity, water table level Pressure Gradient = Absolute Pressure/Vertical Depth - kPa/m, bars/m, psi/ft, etc Equivalent Mud Weight, EMW Pressures quoted, for convenience in same units as mudweight - sg, g/cc, ppg, kPa/m Effective Circulating Density, ECD Mudweight + Additional effect of overcoming frictional forces in borehole during circulating - sg, g/cc, ppg, kPa/m
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Pore Pressure Concepts (2) Formation pressures Overburden pressure Pore pressure Effective stress
= weight of sediments + fluids = pressure of fluid in rock pores = difference between above
Tectonic pressures Caused by stresses/movement in earth Abnormal formation pressure Pressure which is greater than normal hydrostatic pressure Subnormal pressure Pressure which is less than normal hydrostatic pressure Overbalance/Underbalance Relationship between mud hydrostatic, ECD and formation pressure
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Origins of Abnormal Pressures (1) Undercompaction - most widely accepted mechanism: Pressure seal / Vertical permeability restriction Compaction = consolidation + compression Consolidation is plastic / Compression is elastic Aquathermal expansion: Complete isolation early in sedimentation. Constant volume Clay diagenesis: Smectite/Montmorillonite to Illite as intermolecular water is removed Tectonics: Shear deformations -> overpressures in undrained rock Hydrocarbon Generation: Breakdown of organic material -> gases in enclosed volume
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Hydrostatic Pressure during Normal Compaction Fluid Pressure, Pf
Sea level River delta
Pf=0.0981*pfl*D
Vertical Depth, D
Free water expelled as sediments compact
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Weight of overlying sediment ed via grain-to-grain
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Sediment Grains
Pore Fluid
7
Abnormal Pressure due to Compaction Disequilibrium Fluid Pressure, Pf
Sea level
Hydrostatic Pressure
Free water expelled as sediments compact Vertical Depth, D
Pressure Transition Zone
Sediment Grains
Abnormal Pressure
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Pore Fluid
Some of weight of overlying sediment ed by pore fluids
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Dehydration of Clays during Compaction Recent Burial
300m
1000m
3000m = Expelled Water
= Pore (free) Water = Interstitial Water 66.7%
75.9%
73%
= Clay
80%
13.3% 4.1%
20%
20%
20%
20%
(after Dickinson,Gulf Coast, 1953)
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Bulk density increase with burial Depth = 8m Density = 1.48 g/cc Solids = 33% 2.5
Fluid = 67% Depth = 100m Density = 1.71 g/cc Solids = 52%
Weight, kg/m3
2
Fluid = 48% Depth = 210m
1.5
1
0.5
0 0
50
100
150
200
250
Depth, m
Density = 1.97 g/cc Solids = 73% Fluid = 27%
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Computed porosity decrease with burial, US Gulf Coast Porosity 0.01 0
0.1
=0.41e-0.000085Ds
1
Sedim ent Depth, Ds, ft
2000 4000 6000 8000 10000 12000 14000 16000 18000 20000
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Conversion of Montmorillonite to Illite via de-watering
A. Montmorillonite before diagenesis
B. Removal of some pore and interlayer water
C. Loss of last interlayer water, Montmorillonite-> Illite
D. Final stage of compaction
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Aquathermal pressures (1) During burial: 1. Temperature increases a. Fluid expands
~ 220x10-6 v/v/degF
b. Pore volume expands
~ 3x10-6 v/v/degF
2. Pressure increases a. Fluid compresses
~ 3x10-6 v/v/psi
b. Pore volume compresses
~ 7x10-6 v/v/psi
Low volume systems - overpressure easily dissipated by leakage Example: Ameland, Holland; Middle East salt diapirs
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Origins of Abnormal Pressures (2) Osmosis: Movement of fluid through a semi-permeable membrane Faults and Fractures: Conduits for pressures from deeper zones, or Seals against fluid movement Poor drilling practices on offset well: Insufficient sealing of permeable zones eg, leakage via poor cement around a casing string or across permeable zone Topography: Well elevation relative to potentiometric surface Structure: In HC-bearing zone, because of buoyancy differences
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Osmotic pressures (1) Osmosis - movement of water through semipermeable membrane separating 2 solutions of differing densities, until concentration of both solutions is the same H2O H2O H2O
H2O
H2O H2O H2O
Fresh Water
H2O H2O H2O H2O H2O H2O
Saline Water
P1 P2 P2>P1 but does not overcome osmotic pressure
Semi-permeable membrane
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Possible mechanism for creating and maintaining abnormal formation pressures via osmosis
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Faults as pressure seals and drains
Normally pressured sand Pressure drained
Pressure drained Overpressured sand
Overpressured sand
Overpressured sand Overpressured sand
Fault seal can be created by: Fault ‘places’ sand against sand allowing pressure drainage
• mineralization along fault face • plastic formations - clay, salt etc • attitude - reverse faults are often seals
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Fault can also be duct from deeper o-p system
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Fault face seals sands against shale, preventing pressure drainage
16
Salt movement effects on pore pressures Salt intrusion causes stresses in formations, and impermeability prevents drainage of pressures
Paleopressured sands
Osmosis effect because of salinity differences
Similar structures are mud volcanoes or shale diapirs, caused by rapid loading and/or plastic flow in young sediments; eg central Asia or N. Sea.
Salt seals off sands
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Pressure leakage via faults or poor well seals
A. Communication along fault
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B. Poor cement or damaged casing
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C. Leaking cement plugs in abandoned well
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Aquifer pressures and potentials (1) Normal Pressure -
A
Potentiometric Surface
Well elevation same as outcrop elevation
B A
Underpressure -
Potentiometric Surface
Well elevation higher than outcrop elevation
B Flowing artesian well
Overpressure Well elevation lower than outcrop elevation
A
Potentiometric Surface
B
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Pressure gradients in reservoir with constant overpressure (1500*1.05*0.0981)+100=254.5bars 409/3000 = 0.1697 bar/m = 1.73sg EMW
Pressure, bars
os Ge
Depth, m
i en t rs 100ba
P/Z=0.1363bar/m ‘Soft’ overpr.
g tatic nt radie
(3000*1.05*0.0981)+100=409bars 409/3000 = 0.1363 bar/m = 1.39sg EMW
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ad gr
1500m
‘Hard’ overpressure
os Hydr
5sg e 0 . 1 r fer ressu i u aq verp s u o ars o u n i t b Con w/ 200 er wat
P/Z=0.1697bar/m
tic ta
3000m
1500m
3000m
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rs 100ba
20
Effect of hydrocarbon buoyancy on reservoir pressure Fluid Pressure, Pf, bars
D Gas, d= 0.25g/cc Pg = Po + (0.0981*0.25*H2)
Oil, d= 0.80g/cc H2
Po = Pw + (0.0981*0.80*H1)
H1 Pw=0.0981*1.03*D
Formation water, d= 1.03g/cc
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Effect of hydrocarbon buoyancy on aquifer pressure Abnormally high aquifer pressure caused by presence of hydrocarbons in combination with a shale-out
PB = PA + 140psi Oil, 0.30 psi/ft
B 11,000ft TVD
A
10,000ft TVD
Water, 0.44 psi/ft
Inflated Aquifer eg N.Brae, Ula, Oseberg Gamma
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Origins of Abnormal Pressures (3) Paleo Pressures: Uplift of sealed compartments Pressure compartments: Sealing faults Pingos: Entrapment of unfrozen zones under permafrost Hydrate dissolution: Just under seabed in deepwater wells Massive salt: Perfect impermeable seal for pressure entrapment Capillary action or mineralization: Normally create 'zero' permeability to vertical fluid movement
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Abnormal pressures caused by uplift Fluid Pressure, Pf, bars
500
Vertical Depth, metres
1000
Pf=0.0981*pfl*D
1500
Formation pressure increases normally with normal compaction sequence
2000 2500 3000
Pf at 2000m = 455bars = 2.32sg
Uplift because of faulting, etc.
Pf at 2000m = 455bars = 1.855sg
3500 Pf at 3500m = 455bars = 1.325sg 4000
Pf at 4500m = 455bars = 1.03sg
4500
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Assume system completely sealed at burial depth of 4500m, retaining normal Pf of 455bars, 1.03sg.
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Formation of cap-rock
Clay
Clay
Preferential absorption of fresh water
Clay
Zone of higher pressure and permeability Remaining water more saline Precipitation of carbonates and silicates at formation boundary creates permeability barrier
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Indicators of Abnormal Pressure (1) Compaction trends: Deviation from normal trend on Res/Cond, Vel/dT, Dxc, ROP, RhoB Pressure cap: ROP slows, less gas, etc because of tighter, sealing formation Regional geology - correlation Torque, drag/overpull, hole fill: Hole wall unstable; 'squeezing' drillstring or collapsing into hole Losses/kicks, PWD, mud flows, pit levels, mud resistivity (a bit late!): Underbalanced situation - formation fluids enter borehole Clay typing: Shale factor / CEC test for Smectite->Illite
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N-pressure
A
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Reaction times in A & B depend on differential pressure and shale rheology in overpressured zone.
Normal pressure
If diff-p is -ve, hole wall may start to slough. As cavings build up on stab and bit, circulation becomes restricted, standpipe pressure and ECD increase. Develops into packing off then partial or full loss of mud to formation as ECD exceeds Frac Grad.
Overpressure
Overpressure
Bit may drill through op zone with no change in rotary torque, then hole ‘moves in’ on stabiliser blades causing increase in torque. A second effect may be that pieces are knocked off and fall onto the bit, further increasing torque.
N-pressure
Normal pressure
Tight hole, overpull/drag, fill (1)
B
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Normal pressure
Normal pressure
Tight hole, over-pull/drag, fill (2)
In these cases there is the danger of swabbing/surging
C
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Overpressure N-pressure
N-pressure
Overpressure
Upward movement of pipe, eg on connection or trip, creates overpull as stabilisers and bit accumulate cavings.
Downward movement of pipe, eg after connection or trip, shows drag as stabilisers and bit encounter reduced hole diameter in o-p section. Cavings accumulate on bottom as fill. Will need to wash and ream to bottom.
D
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Indicators of Abnormal Pressure (2) Gas: Drill gas (Background gas) Connection gas Trip gas Pumps-off gas C2/C3 ratio Temperature: Compare mud temperatures into and out of hole. ‘Useless’ offshore Cuttings/cavings: Easy to spot PDC cuttings Cavings - size and shape; splintery, 'rotor'-shaped
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Gas response vs. borehole pressure differential (1) Gas, %
Gas, %
Gas, %
Constant BG in homogeneous ‘nonporous’ shale
Porous Zone
Pm>>Pf
Pm>=Pf
BG reduced in porous zone because of flushing into formation Gas into mud from porous zone cuttings. Faster ROP -> more rock/min -> more gas
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Pm
30
Swab effects when moving drillstring upwards
Main factors affecting swab/surge pressures are pipe speed, mud gel strength and viscosity, mud filter cake, bitand stabiliser balling, blocked bit jets
Formation fluids swabbed into borehole
Drillpipe moving upwards
Frictional effects between mud and moving drillpipe create pressure differentials across annulus.
+ ++
+
----
+ ++
+ ----
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A high percentage of kicks occur because of swabbing during trips out of hole. It is vital that swab/surge pressures are calculated before a trip to ensure correct tripping speed.
+++
+
---
-
++
++
----
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Accumulation of cuttings/cavings on stabiliser blades prevents equalisation of pressures during pipe movement, resulting in pressure differential above and below stab. A similar situation can occur above and below bit, especially with bit balling or blocked jets.
31
Gas response vs. borehole pressure differential (2) Homogeneous Shale, Zero
Gas, %
Gas, %
CG CG CG
Pm>>Pf
CG
Pm>=Pf CG
‘Homogeneous’ Shale, Increasing
Constant BG in homogeneous ‘non-porous’ shale
Gas, %
CG CG CG CG
Pm
CG
CG
CG Positive, stable differential pressure
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Positive, decreasing differential pressure
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CG Negative differential pressure
32
Geothermal temperature as indicator of overpressure (1)
s Isotherm
Depth
Heat Flow Insulating body
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Geothermal temperature as indicator of overpressure (2) Use of temperature data:
Fluid content in o-p shales > than in n-p shales.
1. Record MTI and MTO
Thermal Cond water < Thermal Cond shale
2. Plot ‘end-to-end’
O-p zone is insulator and temp grad >> in n-p shales
3. Plot T ‘surface to surface’ 4. Plot ‘gradient factor’ 5. Record all MWD and WL temps
Limitations: 1. Changes in circulation rate
O-p Zone
2. Water depth offshore 3. Additions to mud system 4. Major lithology changes
Temperature
Temperature Gradient
Advantage:
Porosity
Not affected by many of factors affecting other o-p indicators
Increase
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Hole cavings as indicator of overpressure Amount, shape, size and colour of cavings are important. With low or negative differential pressure or stress relief at borehole wall -> sloughing of rock into the hole as cavings. Cuttings released easily from under bit; may even be 'ejected' by formation pressure, -> different-shaped cutting little affected by bit , eg less rounded. PDC cuttings have special character, easy to distinguish from cavings. Top
Top Shale cavings resulting from underbalance
Concave cross-section, thin and spiky shape, may be striated
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Front
Side
Shale cavings resulting from relief of rock stresses during drilling - indicate excess lateral stresses in formation
Front
Side
Blocky, rectangular shape, often cracked
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Indicators of Compaction and Porosity (1) Acoustic velocity / Formation slowness, dT: Seismic (conventional, VSP, while drilling) Wireline (BHC, LSS) and LWD Microseconds/foot, feet/second, meters/second 'Quantitative’, but: Gas effect Interval velocity interpreted for structure, not pressure Cycle skipping and eccentering Resistivity Short normal, induction, propagation: Use deepest reading sensor - ILD (WL), DP (SS MWD) 'Quantitative’, but: Conductive pore space Salinity Temperature
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Indicators of Compaction and Porosity (2) Density Wireline and LWD: Reflected Gamma Rays Strong hole size effect: Need compensation curve for log quality Generally used only for overburden Density column: Individual cuttings; Technique sensitive; Not in situ Toxic fluids involved normally Not 'quantitative' but useful to have D-exponent Drill rate normalized for WOB, RPM, and bit diameter Mud weight or ECD correction Cutter and bearing wear corrections exist: Complicated; Questionable accuracy; Generally ignored Bit type change necessitates trend line shift 'Quantitative'
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Calculation of drilling exponent, dx Original d-exponent from Bingham: R / N = a * (W / D) ^ d where: R = ROP in ft / min N = bit rotary speed in RPM W = WOB in pounds D = bit diameter in inches a = "lithological" constant d = dimensionless compaction exponent Jordan & Shirley solved for "d": dx = log10 (R / 60N) / log10 (12W/10^6 * D) or, in metric units: dx = [1.26 - log10 (R / N)] / [1.58 - log10 (W/D)] where: R = meters per hour N = bit rotary speed in RPM W = WOB in tonnes D = bit diameter in inches
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d-exponent does not for: • hydraulics, • lithology changes, • bit type, • bit wear (although complex ways of ing for bitwear do exist). D-exponent should be corrected for Mudweight: dxc = Dx * (Pn / MW) or for ECD): dxc = Dx * (Pn / ECD) It can work with PDC bits, but use with care!
38
Formation drillability vs. overbalance vs. bit type Rock Bit
Pm>Pf
Pm=
Bit tooth Mud Hydrostatic Pressure, Pm
Formation Pressure, Pf
Bit tooth in with formation
PDC Bit
Fractures created by bit tooth action
With large overbalance, cuttings held on bottom
With underbalance or small overbalance, cuttings released
PDC Cutter
Bit cutter in with formation
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Bit cutter shears formation
Cuttings ‘pushed’ away from formation by bit cutter and lifted by mud flow
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Cutting action of PDC means Pm/Pf less important for cuttings removal; hence Dxc less reliable
39
Models and Methods for Quantifying Abnormal Pore Pressures All based on Terzaghi Effective Stress concept from 1948 Horizontal, trend-line methods: Eaton method for: Resistivity Sonic D-exponent Equivalent depth method Ratio method Vertical, Explicit methods: Bowers, Alixant; Rasmus; Holbrook Consider temperature effect
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Formation Stresses and Pressures (1) Sv S = Total external stress Sv = (Overburden) Vertical Stress Sx, Sy = Horizontal Stresses Sy
Sx
Terzaghi Effective Stress Model S
- matrix or effective stress
h
H
Pf - pore fluid pressure h - minimum horizontal stress
Pf March 18, 201
H - maximum horizontal stress Geopressure Systems - I
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Formation Stresses and Pressures (2) Terzaghi (1948): S/Z = /Z + Pf/Z
----->
S = + Pf
S/Z = 0.8 - 1.05 psi/ft Pf/Z = 0.433 - 0.465 psi/ft but can be as low as 0.41 psi/ft or as high as 0.5 psi/ft depending on dissolved gas and salinity
In North Sea: h = 0.6 v to 0.75 v H = 0.85 v to 1.2 v March 18, 201
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Methodology (1) Pf = S - Requires accuracy in OBG (S) and Effective Stress (): OBG is usually straightforward Effective stress requires more assumptions Overburden Gradient Computation: Air gap + Water column + Sediment • Best is to integrate LWD density log • Can integrate offset density log: Common depth reference important Regional OBG corrected for water depth • Synthesize from seismic velocity via empirical formulae -> Gardner: Density(g/cc) = 0.23 Velocity0.25 (ft/sec)
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Overburden Stress Area = 1 in.2
Density (g/cc)
Thickness (ft.)
Weights (lbs. / in.2)
t1
1
0.4341t1
t2
2
t3
3
0.4342t2 0.4343t3
3
t4
4
0.4344t4
4
t5
5
0.4345t5
1 2
5
Overburden Stress = Total Weight / in.2 = 0.434(1t1 + 2t2 + 3t3 + 4t4 + 5t5) 6
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Sediment Stress Calculation = 0.434*2.38*100
Rhob (g/cc) 8000
2.0
2.2
Depth (ft)
8100
2.4
2.6
Interval Bottom (ft.) 8000
Avg. Density (g/cc) 2.37
8100
2.38
8200
Interval Thick. (ft.) 100
Stress Change (psi) 103
Sediment Stress (psi) 7404
100
103
7507
2.33
100
101
7608
8300
2.35
100
102
7710
8400
2.32
100
101
7811
8500
2.29
100
99
7910
8200
8300
8400
8500
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= 7404 +103 Geopressure Systems - I
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Sediment Stress vs Overburden Stress
1
t1
2
t2
3
t3
4
t4
5
t5
WD2
1 2 3 4
Sediment Stress Depends on Depth Below Mud Line = 0.434(1t1 + 2t2 + 3t3 + 4t4 + 5t5)
5
Depth Below Mud Line
Depth Below Mud Line
WD1
Overburden Stress = Sediment Stress + 0.444*WD
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Methodology (2) Shale Discrimination All trendline-based methods attempt to quantify PP in shales where it is ‘impossible’ to measure PP directly Need ‘clean’, thick shales: Use GR in realtime Use SP in post-well Refine this using: Photoelectric effect Spectral Gamma Ray Caliper Dimensionless torque Note: GR baseline often changes with hole size
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Methodology (3) Normal Compaction Trend Lines All trendline-based methods attempt to quantify PP by considering deviation of porosity indicator from a normal compaction trend Compaction Trends for Pore Pressure: Requires experience, judgment, interpretation Least squares fit of shale points sometimes appropriate Must for log shifts, bit and hole size changes Single or multiple trendlines depending on geological history Regional trends sometime appropriate For acoustic: seabed trend value = about 190 sec/ft (dT of seawater) Calibrate trends in real-time by using drilling info in relation to current MW/ECD: Gas - BG / CG / TG / etc Hole condition - cavings / torq / fill / etc Mud temperature and/or MWD tool temperature Kicks - a last resort! LOT - compare result against Frac Grad calculated using PP RFT-type data as it becomes available
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Empirical Methods for Calculation of Pore Pressure (2) Eaton's Method Pore Pressure from Resistivity (usually as gradient, not pressure) Pf = OBG - ((OBG - Pn) * (Ro / Rn)1.2) where: Pf = formation pressure gradient OBG = overburden pressure gradient Pn = normal pore pressure gradient Ro = observed shale resistivity Rn = normal shale resistivity, from trend line Pore Pressure from Sonic Pf = OBG - ((OBG - Pn) * (dTn / dTo)3) where: dTn = normal shale transit time, from trend line dTo = observed shale transit time Pore Pressure from D-exponent Pf = OBG - ((OBG - Pn) * (Do / Dn)1.2) where: Do = observed D-exponent Dn = normal D-exponent, from trend line
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Empirical Methods for Calculation of Pore Pressure (4) Equivalent Depth Method Each point in undercompacted section has porosity equivalent to point at a shallower depth in normally compacted section. Pa = OBa - De*(OBe - Pe)/ Da where
Pa = Pressure gradient at actual depth, sg Pe = Pressure gradient at equivalent depth, sg (1.03) OBa = Overburden gradient at actual depth, sg OBe = Overburden gradient at equivalent depth, sg Da = Actual Depth of undercompacted point, m De = Equivalent Depth of shallower point, m
Draw a vertical line up from point at Da on data curve; depth at which this line meets normal trend line is De. Drawback of method is that it assumes a constant uninterrupted compaction history, thus becomes unreliable when data crosses stratigraphic or structural boundaries, or when hiatus/uplift has occurred during sedimentation history
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Empirical Methods for Calculation of Pore Pressure (5)
Ratio Method Difference between a point on 'undercompacted' portion of a plot and a point at same depth on normal trend line is proportional to difference in pore pressure between the two points: Pa = Pn * DatN/ DatO where:
Pa = Pressure gradient at actual point on plot, sg Pn = Pressure gradient at point on normal trend, sg DatN = Data value on normal trend, * DatO = Data value at actual point on plot, * * - can be usec/ft, Dxc, g/cc, ohmm, or m/sec
Use a correction factor to adjust to actual pressure values from RFT/DST; eg, if estimated pressure = 1.3sg, and RFT pressure = 1.4sg, then c = 1.4/1.3 = 1.077 and above becomes: Pa = c * Pn * DatN / DatO The correction coefficient can apply as long as the factors affecting the abnormal pressure remain the same. This method is easy to use but should be used with care because it is empirical.
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Use of porosity indicators Resistivity normal compaction trendline
Sonic normal compaction trendline
MW
Resistivity porosity trend
Sonic porosity trend
OBG
PP from Eaton + Sonic
PP from EqDep + Res
PP from Eaton + Res PP from EqDep + Sonic
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Formation Strength / Fracture Gradient (1) Attempt to define:
Z
pressure necessary to create or open fractures at the wellbore, or the least principal stress, x, in borehole
Y X
Rock fractures perpendicular to direction of least principal stress
Very important to estimate fracture gradient in order to: 1. Determine correct setting depths for casing strings 2. Help evaluate quality of Leakoff Test by knowing expected result 3. Determine the maximum mud weights allowed for each hole section while drilling 4. Determine maximum allowable pressures while killing a kick 5. Plan hydraulic fracturing program for a well
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Formation Strength / Fracture Gradient (2) Fracture gradient values affected by: In situ stresses - X, Y, Z
Mud density, rheology and hydraulics
Hole orientation and geometry
Formation temperature
Lithology and mineralogy
Theoretical or empirical methods currently in use: Hubbert & Willis
1957
Pilkington
1978
Matthews & Kelly
1967
Cesaroni et al
1981
Eaton
1969
Daines
1981
Anderson et al
1973
Breckels & van Eekelen
1982
Christman
1973
Bryant
1983
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Surge effects when moving drill-string downwards Drillpipe moving downwards
Frictional effects between mud and moving drillpipe create pressure differentials across annulus.
---
++
Drilling mud flushed into formation
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A weak formation may be fractured by surge pressures occurring during tripping into the hole. Swab/surge pressures calculated before POOH should be used to ensure correct pipe speed during RIH unless mud properties have been changed significantly.
-
---
++
++
+ ++
++
+ ----
-
++
++
Pipe movement on RIH can result in pressure differential above and below stabilisers and/or bit, causing mud to be forced into the formation.
----
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Estimation of Fracture Gradient (1) Hubbert & Willis, 1957: From lab tests;X = 0.333Z to 0.5Z where Z = total stress = overburden = 1psi/ft As S = Z +Pf, then Z = S- Pf then Pfrac = 0.333*(S- Pf )+ Pf X later amended to between 0.25*Z and 0.5*Z, ie Pfrac = Between [0.25*(S- Pf )+ Pf] and [0.5*(S- Pf )+ Pf] Method OK for some sands in Gulf Coast but not reliable elsewhere. Assumed OBG of 1 psi/ft is not correct. Matthews & Kelly, 1967: Introduced a Matrix Stress Coefficient, Ki to allow for observed changes in Pfrac with depth Pfrac = Ki *+ Pf From Gulf Coast data a set of values were obtained for Ki vs depth. Drwabacks - Gulf Coast data, and assumed OBG of 1 psi/ft.
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Estimation of Fracture Gradient (2)
Eaton, 1969: Replaced Ki with a value Kx derived from Poisson’s Ratio which also changes with depth -> Pfrac = (/(1-))*+ Pf Eaton published curves of Kx vs depth for various Gulf Coast and W. Texas areas and suggested the following equation to calculate Kx locally (/(1-)) = Kx = [(PLOT/L) - (Pf/L)] / [(S- Pf)/L], ie
Kx = (PLOT - Pf) / (S- Pf)
ie using a shallow LOT value to calibrate the calculation. Drawbacks - Gulf Coast data, and assumes PLOT represents the Pfrac for the weakest formation in open hole, not always true.
Recently (1997), additional “Poisson Ratio” curves for deepwater were published.
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57
Poisson’s Ratio, 1 (maximum)
Ratio of Horizontal to Vertical stresses in a material under compression
(minimum)
L1
L1 L2 L3
2
Matrix Stress Coefficient, Ki:
L1 L3 L3
Depends on Varies with depth (young basins only) Ki = / (1-)
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Poisson’s Ratio, Suggested values for for different lithologies: Clay, very wet
0.50
Shale, calc
0.14
Clay
0.17
Shale, silty
0.17
Greywacke, fine
0.23
Shale, sandy
0.12
Greywacke, medium
0.24
Shale, silic
0.12
Greywacke, coarse
0.07
Shale, dolom
0.28
Sandstone, fine
0.03
Siltstone
0.08
Sandstone, medium
0.06
Limestone, fine
0.28
Sandstone, coarse
0.05
Limestone, med
0.31
Sandstone, coarse, cmtd
0.10
Limestone, shaly
0.17
Sandstone, clayey
0.24
Limestone, porous 0.20
Conglomerate
0.20
Dolomite
0.21
After Daines, JPT, 1982
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Importance of Fracture Gradient estimate (1) Use of PP + FG to optimize casing depths, offshore well:
Yellow area shows allowed MW 16” shoe to 11000ft. Green area shows max MW of 13ppg allowed below 13 3/8” shoe, while PP at 14000ft almost equals this
March 18, 201
Safe MW margin created by setting 13 3/8” at 11000ft
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Summary 1. 2. 3. 4. 5. 6. 7. 8. 9. 10.
Several physical and chemical causes of earth stresses Burial processes, especially compaction, are the most important Undercompaction is the most prevalent cause of overpressures Undercompaction is detectable, most other causes are not Shale is most prevalent sedimentary rock Compaction in shale is more readily observed than in other rocks There are several indicators of over/underbalance while drilling Methods exist to quantify pore pressure based on shale analysis Methods exist to estimate fracture gradient Geopressure analysis improves optimization of casing and mud weight plans
March 18, 201
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Methodology for Geopressure Analysis 1. 2. 3.
Determine where shales are located. Obtain shale values in porosity sensitive measurement. Interpret shale porosity trends: - Normal compaction trend - Actual compaction trend
4. 5. 6. 7.
Obtain overburden gradient Calculate pore pressure Calculate fracture gradient Calibrate results using real measurements/well response
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62
Data Flow Wireline Log
Offset Wells SWD (Seismic-While-Drilling)
MudLog VSP
Drillworks/ PREDICT EPP
MWD PPP Continuous Wave dT Measurement from Cuttings
March 18, 201
Realtime Estimated/Prognosed PP for whole well
Geopressure Systems - I
DrillWorks/ BASIN Basin Modeling and 3-D Visualisation
63
DrillWorks/BASIN
March 18, 201
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64
A Division of Knowledge Systems, Inc.
World-wide occurrence of abnormal formation pressures
2.16/ 18+ 2.05/ 17 2.3/ 19+ 2.37/ 22 2.34/ 22+
2.4/ 22+
2.2/ 18+
1.92/ 16
2.22/ 19 1.92/ 16
2.34 = Pf in sg EMW 19 = Pf in ppg EMW
March 18, 201
Geopressure Systems - I
2
Motivations for Understanding Pore Pressures
Mud Casing ++
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Geopressure Systems - I
Risk to Environment
Well Costs
Knowledge of Area
Well/Human Safety
Best PP evaluation while drilling
Drilling Efficiency
Drilling Prog. Quality
Accurate PP prognosis
Rigtime Optim MW
Kicks Blowouts
3
Pore Pressure Concepts (1) Pressure = Force/Area (also stress) - kPa, psi, bars Hydrostatic pressure - Pressure exerted by the weight of a column of fluid; - Varies by basin, fluid salinity, water table level Pressure Gradient = Absolute Pressure/Vertical Depth - kPa/m, bars/m, psi/ft, etc Equivalent Mud Weight, EMW Pressures quoted, for convenience in same units as mudweight - sg, g/cc, ppg, kPa/m Effective Circulating Density, ECD Mudweight + Additional effect of overcoming frictional forces in borehole during circulating - sg, g/cc, ppg, kPa/m
March 18, 201
Geopressure Systems - I
4
Pore Pressure Concepts (2) Formation pressures Overburden pressure Pore pressure Effective stress
= weight of sediments + fluids = pressure of fluid in rock pores = difference between above
Tectonic pressures Caused by stresses/movement in earth Abnormal formation pressure Pressure which is greater than normal hydrostatic pressure Subnormal pressure Pressure which is less than normal hydrostatic pressure Overbalance/Underbalance Relationship between mud hydrostatic, ECD and formation pressure
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Geopressure Systems - I
5
Origins of Abnormal Pressures (1) Undercompaction - most widely accepted mechanism: Pressure seal / Vertical permeability restriction Compaction = consolidation + compression Consolidation is plastic / Compression is elastic Aquathermal expansion: Complete isolation early in sedimentation. Constant volume Clay diagenesis: Smectite/Montmorillonite to Illite as intermolecular water is removed Tectonics: Shear deformations -> overpressures in undrained rock Hydrocarbon Generation: Breakdown of organic material -> gases in enclosed volume
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Geopressure Systems - I
6
Hydrostatic Pressure during Normal Compaction Fluid Pressure, Pf
Sea level River delta
Pf=0.0981*pfl*D
Vertical Depth, D
Free water expelled as sediments compact
March 18, 201
Weight of overlying sediment ed via grain-to-grain
Geopressure Systems - I
Sediment Grains
Pore Fluid
7
Abnormal Pressure due to Compaction Disequilibrium Fluid Pressure, Pf
Sea level
Hydrostatic Pressure
Free water expelled as sediments compact Vertical Depth, D
Pressure Transition Zone
Sediment Grains
Abnormal Pressure
March 18, 201
Pore Fluid
Some of weight of overlying sediment ed by pore fluids
Geopressure Systems - I
8
Dehydration of Clays during Compaction Recent Burial
300m
1000m
3000m = Expelled Water
= Pore (free) Water = Interstitial Water 66.7%
75.9%
73%
= Clay
80%
13.3% 4.1%
20%
20%
20%
20%
(after Dickinson,Gulf Coast, 1953)
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Geopressure Systems - I
9
Bulk density increase with burial Depth = 8m Density = 1.48 g/cc Solids = 33% 2.5
Fluid = 67% Depth = 100m Density = 1.71 g/cc Solids = 52%
Weight, kg/m3
2
Fluid = 48% Depth = 210m
1.5
1
0.5
0 0
50
100
150
200
250
Depth, m
Density = 1.97 g/cc Solids = 73% Fluid = 27%
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Geopressure Systems - I
10
Computed porosity decrease with burial, US Gulf Coast Porosity 0.01 0
0.1
=0.41e-0.000085Ds
1
Sedim ent Depth, Ds, ft
2000 4000 6000 8000 10000 12000 14000 16000 18000 20000
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Geopressure Systems - I
11
Conversion of Montmorillonite to Illite via de-watering
A. Montmorillonite before diagenesis
B. Removal of some pore and interlayer water
C. Loss of last interlayer water, Montmorillonite-> Illite
D. Final stage of compaction
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Geopressure Systems - I
12
Aquathermal pressures (1) During burial: 1. Temperature increases a. Fluid expands
~ 220x10-6 v/v/degF
b. Pore volume expands
~ 3x10-6 v/v/degF
2. Pressure increases a. Fluid compresses
~ 3x10-6 v/v/psi
b. Pore volume compresses
~ 7x10-6 v/v/psi
Low volume systems - overpressure easily dissipated by leakage Example: Ameland, Holland; Middle East salt diapirs
March 18, 201
Geopressure Systems - I
13
Origins of Abnormal Pressures (2) Osmosis: Movement of fluid through a semi-permeable membrane Faults and Fractures: Conduits for pressures from deeper zones, or Seals against fluid movement Poor drilling practices on offset well: Insufficient sealing of permeable zones eg, leakage via poor cement around a casing string or across permeable zone Topography: Well elevation relative to potentiometric surface Structure: In HC-bearing zone, because of buoyancy differences
March 18, 201
Geopressure Systems - I
14
Osmotic pressures (1) Osmosis - movement of water through semipermeable membrane separating 2 solutions of differing densities, until concentration of both solutions is the same H2O H2O H2O
H2O
H2O H2O H2O
Fresh Water
H2O H2O H2O H2O H2O H2O
Saline Water
P1 P2 P2>P1 but does not overcome osmotic pressure
Semi-permeable membrane
March 18, 201
Possible mechanism for creating and maintaining abnormal formation pressures via osmosis
Geopressure Systems - I
15
Faults as pressure seals and drains
Normally pressured sand Pressure drained
Pressure drained Overpressured sand
Overpressured sand
Overpressured sand Overpressured sand
Fault seal can be created by: Fault ‘places’ sand against sand allowing pressure drainage
• mineralization along fault face • plastic formations - clay, salt etc • attitude - reverse faults are often seals
March 18, 201
Fault can also be duct from deeper o-p system
Geopressure Systems - I
Fault face seals sands against shale, preventing pressure drainage
16
Salt movement effects on pore pressures Salt intrusion causes stresses in formations, and impermeability prevents drainage of pressures
Paleopressured sands
Osmosis effect because of salinity differences
Similar structures are mud volcanoes or shale diapirs, caused by rapid loading and/or plastic flow in young sediments; eg central Asia or N. Sea.
Salt seals off sands
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Geopressure Systems - I
17
Pressure leakage via faults or poor well seals
A. Communication along fault
March 18, 201
B. Poor cement or damaged casing
Geopressure Systems - I
C. Leaking cement plugs in abandoned well
18
Aquifer pressures and potentials (1) Normal Pressure -
A
Potentiometric Surface
Well elevation same as outcrop elevation
B A
Underpressure -
Potentiometric Surface
Well elevation higher than outcrop elevation
B Flowing artesian well
Overpressure Well elevation lower than outcrop elevation
A
Potentiometric Surface
B
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Geopressure Systems - I
19
Pressure gradients in reservoir with constant overpressure (1500*1.05*0.0981)+100=254.5bars 409/3000 = 0.1697 bar/m = 1.73sg EMW
Pressure, bars
os Ge
Depth, m
i en t rs 100ba
P/Z=0.1363bar/m ‘Soft’ overpr.
g tatic nt radie
(3000*1.05*0.0981)+100=409bars 409/3000 = 0.1363 bar/m = 1.39sg EMW
March 18, 201
ad gr
1500m
‘Hard’ overpressure
os Hydr
5sg e 0 . 1 r fer ressu i u aq verp s u o ars o u n i t b Con w/ 200 er wat
P/Z=0.1697bar/m
tic ta
3000m
1500m
3000m
Geopressure Systems - I
rs 100ba
20
Effect of hydrocarbon buoyancy on reservoir pressure Fluid Pressure, Pf, bars
D Gas, d= 0.25g/cc Pg = Po + (0.0981*0.25*H2)
Oil, d= 0.80g/cc H2
Po = Pw + (0.0981*0.80*H1)
H1 Pw=0.0981*1.03*D
Formation water, d= 1.03g/cc
March 18, 201
Geopressure Systems - I
21
Effect of hydrocarbon buoyancy on aquifer pressure Abnormally high aquifer pressure caused by presence of hydrocarbons in combination with a shale-out
PB = PA + 140psi Oil, 0.30 psi/ft
B 11,000ft TVD
A
10,000ft TVD
Water, 0.44 psi/ft
Inflated Aquifer eg N.Brae, Ula, Oseberg Gamma
March 18, 201
Geopressure Systems - I
22
Origins of Abnormal Pressures (3) Paleo Pressures: Uplift of sealed compartments Pressure compartments: Sealing faults Pingos: Entrapment of unfrozen zones under permafrost Hydrate dissolution: Just under seabed in deepwater wells Massive salt: Perfect impermeable seal for pressure entrapment Capillary action or mineralization: Normally create 'zero' permeability to vertical fluid movement
March 18, 201
Geopressure Systems - I
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Abnormal pressures caused by uplift Fluid Pressure, Pf, bars
500
Vertical Depth, metres
1000
Pf=0.0981*pfl*D
1500
Formation pressure increases normally with normal compaction sequence
2000 2500 3000
Pf at 2000m = 455bars = 2.32sg
Uplift because of faulting, etc.
Pf at 2000m = 455bars = 1.855sg
3500 Pf at 3500m = 455bars = 1.325sg 4000
Pf at 4500m = 455bars = 1.03sg
4500
March 18, 201
Geopressure Systems - I
Assume system completely sealed at burial depth of 4500m, retaining normal Pf of 455bars, 1.03sg.
24
Formation of cap-rock
Clay
Clay
Preferential absorption of fresh water
Clay
Zone of higher pressure and permeability Remaining water more saline Precipitation of carbonates and silicates at formation boundary creates permeability barrier
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Geopressure Systems - I
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Indicators of Abnormal Pressure (1) Compaction trends: Deviation from normal trend on Res/Cond, Vel/dT, Dxc, ROP, RhoB Pressure cap: ROP slows, less gas, etc because of tighter, sealing formation Regional geology - correlation Torque, drag/overpull, hole fill: Hole wall unstable; 'squeezing' drillstring or collapsing into hole Losses/kicks, PWD, mud flows, pit levels, mud resistivity (a bit late!): Underbalanced situation - formation fluids enter borehole Clay typing: Shale factor / CEC test for Smectite->Illite
March 18, 201
Geopressure Systems - I
26
N-pressure
A
March 18, 201
Reaction times in A & B depend on differential pressure and shale rheology in overpressured zone.
Normal pressure
If diff-p is -ve, hole wall may start to slough. As cavings build up on stab and bit, circulation becomes restricted, standpipe pressure and ECD increase. Develops into packing off then partial or full loss of mud to formation as ECD exceeds Frac Grad.
Overpressure
Overpressure
Bit may drill through op zone with no change in rotary torque, then hole ‘moves in’ on stabiliser blades causing increase in torque. A second effect may be that pieces are knocked off and fall onto the bit, further increasing torque.
N-pressure
Normal pressure
Tight hole, overpull/drag, fill (1)
B
Geopressure Systems - I
27
Normal pressure
Normal pressure
Tight hole, over-pull/drag, fill (2)
In these cases there is the danger of swabbing/surging
C
March 18, 201
Overpressure N-pressure
N-pressure
Overpressure
Upward movement of pipe, eg on connection or trip, creates overpull as stabilisers and bit accumulate cavings.
Downward movement of pipe, eg after connection or trip, shows drag as stabilisers and bit encounter reduced hole diameter in o-p section. Cavings accumulate on bottom as fill. Will need to wash and ream to bottom.
D
Geopressure Systems - I
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Indicators of Abnormal Pressure (2) Gas: Drill gas (Background gas) Connection gas Trip gas Pumps-off gas C2/C3 ratio Temperature: Compare mud temperatures into and out of hole. ‘Useless’ offshore Cuttings/cavings: Easy to spot PDC cuttings Cavings - size and shape; splintery, 'rotor'-shaped
March 18, 201
Geopressure Systems - I
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Gas response vs. borehole pressure differential (1) Gas, %
Gas, %
Gas, %
Constant BG in homogeneous ‘nonporous’ shale
Porous Zone
Pm>>Pf
Pm>=Pf
BG reduced in porous zone because of flushing into formation Gas into mud from porous zone cuttings. Faster ROP -> more rock/min -> more gas
March 18, 201
Geopressure Systems - I
Pm
30
Swab effects when moving drillstring upwards
Main factors affecting swab/surge pressures are pipe speed, mud gel strength and viscosity, mud filter cake, bitand stabiliser balling, blocked bit jets
Formation fluids swabbed into borehole
Drillpipe moving upwards
Frictional effects between mud and moving drillpipe create pressure differentials across annulus.
+ ++
+
----
+ ++
+ ----
March 18, 201
A high percentage of kicks occur because of swabbing during trips out of hole. It is vital that swab/surge pressures are calculated before a trip to ensure correct tripping speed.
+++
+
---
-
++
++
----
Geopressure Systems - I
Accumulation of cuttings/cavings on stabiliser blades prevents equalisation of pressures during pipe movement, resulting in pressure differential above and below stab. A similar situation can occur above and below bit, especially with bit balling or blocked jets.
31
Gas response vs. borehole pressure differential (2) Homogeneous Shale, Zero
Gas, %
Gas, %
CG CG CG
Pm>>Pf
CG
Pm>=Pf CG
‘Homogeneous’ Shale, Increasing
Constant BG in homogeneous ‘non-porous’ shale
Gas, %
CG CG CG CG
Pm
CG
CG
CG Positive, stable differential pressure
March 18, 201
Positive, decreasing differential pressure
Geopressure Systems - I
CG Negative differential pressure
32
Geothermal temperature as indicator of overpressure (1)
s Isotherm
Depth
Heat Flow Insulating body
March 18, 201
Geopressure Systems - I
33
Geothermal temperature as indicator of overpressure (2) Use of temperature data:
Fluid content in o-p shales > than in n-p shales.
1. Record MTI and MTO
Thermal Cond water < Thermal Cond shale
2. Plot ‘end-to-end’
O-p zone is insulator and temp grad >> in n-p shales
3. Plot T ‘surface to surface’ 4. Plot ‘gradient factor’ 5. Record all MWD and WL temps
Limitations: 1. Changes in circulation rate
O-p Zone
2. Water depth offshore 3. Additions to mud system 4. Major lithology changes
Temperature
Temperature Gradient
Advantage:
Porosity
Not affected by many of factors affecting other o-p indicators
Increase
March 18, 201
Geopressure Systems - I
34
Hole cavings as indicator of overpressure Amount, shape, size and colour of cavings are important. With low or negative differential pressure or stress relief at borehole wall -> sloughing of rock into the hole as cavings. Cuttings released easily from under bit; may even be 'ejected' by formation pressure, -> different-shaped cutting little affected by bit , eg less rounded. PDC cuttings have special character, easy to distinguish from cavings. Top
Top Shale cavings resulting from underbalance
Concave cross-section, thin and spiky shape, may be striated
March 18, 201
Front
Side
Shale cavings resulting from relief of rock stresses during drilling - indicate excess lateral stresses in formation
Front
Side
Blocky, rectangular shape, often cracked
Geopressure Systems - I
35
Indicators of Compaction and Porosity (1) Acoustic velocity / Formation slowness, dT: Seismic (conventional, VSP, while drilling) Wireline (BHC, LSS) and LWD Microseconds/foot, feet/second, meters/second 'Quantitative’, but: Gas effect Interval velocity interpreted for structure, not pressure Cycle skipping and eccentering Resistivity Short normal, induction, propagation: Use deepest reading sensor - ILD (WL), DP (SS MWD) 'Quantitative’, but: Conductive pore space Salinity Temperature
March 18, 201
Geopressure Systems - I
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Indicators of Compaction and Porosity (2) Density Wireline and LWD: Reflected Gamma Rays Strong hole size effect: Need compensation curve for log quality Generally used only for overburden Density column: Individual cuttings; Technique sensitive; Not in situ Toxic fluids involved normally Not 'quantitative' but useful to have D-exponent Drill rate normalized for WOB, RPM, and bit diameter Mud weight or ECD correction Cutter and bearing wear corrections exist: Complicated; Questionable accuracy; Generally ignored Bit type change necessitates trend line shift 'Quantitative'
March 18, 201
Geopressure Systems - I
37
Calculation of drilling exponent, dx Original d-exponent from Bingham: R / N = a * (W / D) ^ d where: R = ROP in ft / min N = bit rotary speed in RPM W = WOB in pounds D = bit diameter in inches a = "lithological" constant d = dimensionless compaction exponent Jordan & Shirley solved for "d": dx = log10 (R / 60N) / log10 (12W/10^6 * D) or, in metric units: dx = [1.26 - log10 (R / N)] / [1.58 - log10 (W/D)] where: R = meters per hour N = bit rotary speed in RPM W = WOB in tonnes D = bit diameter in inches
March 18, 201
Geopressure Systems - I
d-exponent does not for: • hydraulics, • lithology changes, • bit type, • bit wear (although complex ways of ing for bitwear do exist). D-exponent should be corrected for Mudweight: dxc = Dx * (Pn / MW) or for ECD): dxc = Dx * (Pn / ECD) It can work with PDC bits, but use with care!
38
Formation drillability vs. overbalance vs. bit type Rock Bit
Pm>Pf
Pm=
Bit tooth Mud Hydrostatic Pressure, Pm
Formation Pressure, Pf
Bit tooth in with formation
PDC Bit
Fractures created by bit tooth action
With large overbalance, cuttings held on bottom
With underbalance or small overbalance, cuttings released
PDC Cutter
Bit cutter in with formation
March 18, 201
Bit cutter shears formation
Cuttings ‘pushed’ away from formation by bit cutter and lifted by mud flow
Geopressure Systems - I
Cutting action of PDC means Pm/Pf less important for cuttings removal; hence Dxc less reliable
39
Models and Methods for Quantifying Abnormal Pore Pressures All based on Terzaghi Effective Stress concept from 1948 Horizontal, trend-line methods: Eaton method for: Resistivity Sonic D-exponent Equivalent depth method Ratio method Vertical, Explicit methods: Bowers, Alixant; Rasmus; Holbrook Consider temperature effect
March 18, 201
Geopressure Systems - I
40
Formation Stresses and Pressures (1) Sv S = Total external stress Sv = (Overburden) Vertical Stress Sx, Sy = Horizontal Stresses Sy
Sx
Terzaghi Effective Stress Model S
- matrix or effective stress
h
H
Pf - pore fluid pressure h - minimum horizontal stress
Pf March 18, 201
H - maximum horizontal stress Geopressure Systems - I
41
Formation Stresses and Pressures (2) Terzaghi (1948): S/Z = /Z + Pf/Z
----->
S = + Pf
S/Z = 0.8 - 1.05 psi/ft Pf/Z = 0.433 - 0.465 psi/ft but can be as low as 0.41 psi/ft or as high as 0.5 psi/ft depending on dissolved gas and salinity
In North Sea: h = 0.6 v to 0.75 v H = 0.85 v to 1.2 v March 18, 201
Geopressure Systems - I
42
Methodology (1) Pf = S - Requires accuracy in OBG (S) and Effective Stress (): OBG is usually straightforward Effective stress requires more assumptions Overburden Gradient Computation: Air gap + Water column + Sediment • Best is to integrate LWD density log • Can integrate offset density log: Common depth reference important Regional OBG corrected for water depth • Synthesize from seismic velocity via empirical formulae -> Gardner: Density(g/cc) = 0.23 Velocity0.25 (ft/sec)
March 18, 201
Geopressure Systems - I
43
Overburden Stress Area = 1 in.2
Density (g/cc)
Thickness (ft.)
Weights (lbs. / in.2)
t1
1
0.4341t1
t2
2
t3
3
0.4342t2 0.4343t3
3
t4
4
0.4344t4
4
t5
5
0.4345t5
1 2
5
Overburden Stress = Total Weight / in.2 = 0.434(1t1 + 2t2 + 3t3 + 4t4 + 5t5) 6
March 18, 201
Geopressure Systems - I
44
Sediment Stress Calculation = 0.434*2.38*100
Rhob (g/cc) 8000
2.0
2.2
Depth (ft)
8100
2.4
2.6
Interval Bottom (ft.) 8000
Avg. Density (g/cc) 2.37
8100
2.38
8200
Interval Thick. (ft.) 100
Stress Change (psi) 103
Sediment Stress (psi) 7404
100
103
7507
2.33
100
101
7608
8300
2.35
100
102
7710
8400
2.32
100
101
7811
8500
2.29
100
99
7910
8200
8300
8400
8500
March 18, 201
= 7404 +103 Geopressure Systems - I
45
Sediment Stress vs Overburden Stress
1
t1
2
t2
3
t3
4
t4
5
t5
WD2
1 2 3 4
Sediment Stress Depends on Depth Below Mud Line = 0.434(1t1 + 2t2 + 3t3 + 4t4 + 5t5)
5
Depth Below Mud Line
Depth Below Mud Line
WD1
Overburden Stress = Sediment Stress + 0.444*WD
March 18, 201
Geopressure Systems - I
46
Methodology (2) Shale Discrimination All trendline-based methods attempt to quantify PP in shales where it is ‘impossible’ to measure PP directly Need ‘clean’, thick shales: Use GR in realtime Use SP in post-well Refine this using: Photoelectric effect Spectral Gamma Ray Caliper Dimensionless torque Note: GR baseline often changes with hole size
March 18, 201
Geopressure Systems - I
47
Methodology (3) Normal Compaction Trend Lines All trendline-based methods attempt to quantify PP by considering deviation of porosity indicator from a normal compaction trend Compaction Trends for Pore Pressure: Requires experience, judgment, interpretation Least squares fit of shale points sometimes appropriate Must for log shifts, bit and hole size changes Single or multiple trendlines depending on geological history Regional trends sometime appropriate For acoustic: seabed trend value = about 190 sec/ft (dT of seawater) Calibrate trends in real-time by using drilling info in relation to current MW/ECD: Gas - BG / CG / TG / etc Hole condition - cavings / torq / fill / etc Mud temperature and/or MWD tool temperature Kicks - a last resort! LOT - compare result against Frac Grad calculated using PP RFT-type data as it becomes available
March 18, 201
Geopressure Systems - I
48
Empirical Methods for Calculation of Pore Pressure (2) Eaton's Method Pore Pressure from Resistivity (usually as gradient, not pressure) Pf = OBG - ((OBG - Pn) * (Ro / Rn)1.2) where: Pf = formation pressure gradient OBG = overburden pressure gradient Pn = normal pore pressure gradient Ro = observed shale resistivity Rn = normal shale resistivity, from trend line Pore Pressure from Sonic Pf = OBG - ((OBG - Pn) * (dTn / dTo)3) where: dTn = normal shale transit time, from trend line dTo = observed shale transit time Pore Pressure from D-exponent Pf = OBG - ((OBG - Pn) * (Do / Dn)1.2) where: Do = observed D-exponent Dn = normal D-exponent, from trend line
March 18, 201
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Empirical Methods for Calculation of Pore Pressure (4) Equivalent Depth Method Each point in undercompacted section has porosity equivalent to point at a shallower depth in normally compacted section. Pa = OBa - De*(OBe - Pe)/ Da where
Pa = Pressure gradient at actual depth, sg Pe = Pressure gradient at equivalent depth, sg (1.03) OBa = Overburden gradient at actual depth, sg OBe = Overburden gradient at equivalent depth, sg Da = Actual Depth of undercompacted point, m De = Equivalent Depth of shallower point, m
Draw a vertical line up from point at Da on data curve; depth at which this line meets normal trend line is De. Drawback of method is that it assumes a constant uninterrupted compaction history, thus becomes unreliable when data crosses stratigraphic or structural boundaries, or when hiatus/uplift has occurred during sedimentation history
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Empirical Methods for Calculation of Pore Pressure (5)
Ratio Method Difference between a point on 'undercompacted' portion of a plot and a point at same depth on normal trend line is proportional to difference in pore pressure between the two points: Pa = Pn * DatN/ DatO where:
Pa = Pressure gradient at actual point on plot, sg Pn = Pressure gradient at point on normal trend, sg DatN = Data value on normal trend, * DatO = Data value at actual point on plot, * * - can be usec/ft, Dxc, g/cc, ohmm, or m/sec
Use a correction factor to adjust to actual pressure values from RFT/DST; eg, if estimated pressure = 1.3sg, and RFT pressure = 1.4sg, then c = 1.4/1.3 = 1.077 and above becomes: Pa = c * Pn * DatN / DatO The correction coefficient can apply as long as the factors affecting the abnormal pressure remain the same. This method is easy to use but should be used with care because it is empirical.
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Use of porosity indicators Resistivity normal compaction trendline
Sonic normal compaction trendline
MW
Resistivity porosity trend
Sonic porosity trend
OBG
PP from Eaton + Sonic
PP from EqDep + Res
PP from Eaton + Res PP from EqDep + Sonic
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Formation Strength / Fracture Gradient (1) Attempt to define:
Z
pressure necessary to create or open fractures at the wellbore, or the least principal stress, x, in borehole
Y X
Rock fractures perpendicular to direction of least principal stress
Very important to estimate fracture gradient in order to: 1. Determine correct setting depths for casing strings 2. Help evaluate quality of Leakoff Test by knowing expected result 3. Determine the maximum mud weights allowed for each hole section while drilling 4. Determine maximum allowable pressures while killing a kick 5. Plan hydraulic fracturing program for a well
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Formation Strength / Fracture Gradient (2) Fracture gradient values affected by: In situ stresses - X, Y, Z
Mud density, rheology and hydraulics
Hole orientation and geometry
Formation temperature
Lithology and mineralogy
Theoretical or empirical methods currently in use: Hubbert & Willis
1957
Pilkington
1978
Matthews & Kelly
1967
Cesaroni et al
1981
Eaton
1969
Daines
1981
Anderson et al
1973
Breckels & van Eekelen
1982
Christman
1973
Bryant
1983
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Surge effects when moving drill-string downwards Drillpipe moving downwards
Frictional effects between mud and moving drillpipe create pressure differentials across annulus.
---
++
Drilling mud flushed into formation
March 18, 201
A weak formation may be fractured by surge pressures occurring during tripping into the hole. Swab/surge pressures calculated before POOH should be used to ensure correct pipe speed during RIH unless mud properties have been changed significantly.
-
---
++
++
+ ++
++
+ ----
-
++
++
Pipe movement on RIH can result in pressure differential above and below stabilisers and/or bit, causing mud to be forced into the formation.
----
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Estimation of Fracture Gradient (1) Hubbert & Willis, 1957: From lab tests;X = 0.333Z to 0.5Z where Z = total stress = overburden = 1psi/ft As S = Z +Pf, then Z = S- Pf then Pfrac = 0.333*(S- Pf )+ Pf X later amended to between 0.25*Z and 0.5*Z, ie Pfrac = Between [0.25*(S- Pf )+ Pf] and [0.5*(S- Pf )+ Pf] Method OK for some sands in Gulf Coast but not reliable elsewhere. Assumed OBG of 1 psi/ft is not correct. Matthews & Kelly, 1967: Introduced a Matrix Stress Coefficient, Ki to allow for observed changes in Pfrac with depth Pfrac = Ki *+ Pf From Gulf Coast data a set of values were obtained for Ki vs depth. Drwabacks - Gulf Coast data, and assumed OBG of 1 psi/ft.
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Estimation of Fracture Gradient (2)
Eaton, 1969: Replaced Ki with a value Kx derived from Poisson’s Ratio which also changes with depth -> Pfrac = (/(1-))*+ Pf Eaton published curves of Kx vs depth for various Gulf Coast and W. Texas areas and suggested the following equation to calculate Kx locally (/(1-)) = Kx = [(PLOT/L) - (Pf/L)] / [(S- Pf)/L], ie
Kx = (PLOT - Pf) / (S- Pf)
ie using a shallow LOT value to calibrate the calculation. Drawbacks - Gulf Coast data, and assumes PLOT represents the Pfrac for the weakest formation in open hole, not always true.
Recently (1997), additional “Poisson Ratio” curves for deepwater were published.
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Poisson’s Ratio, 1 (maximum)
Ratio of Horizontal to Vertical stresses in a material under compression
(minimum)
L1
L1 L2 L3
2
Matrix Stress Coefficient, Ki:
L1 L3 L3
Depends on Varies with depth (young basins only) Ki = / (1-)
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Poisson’s Ratio, Suggested values for for different lithologies: Clay, very wet
0.50
Shale, calc
0.14
Clay
0.17
Shale, silty
0.17
Greywacke, fine
0.23
Shale, sandy
0.12
Greywacke, medium
0.24
Shale, silic
0.12
Greywacke, coarse
0.07
Shale, dolom
0.28
Sandstone, fine
0.03
Siltstone
0.08
Sandstone, medium
0.06
Limestone, fine
0.28
Sandstone, coarse
0.05
Limestone, med
0.31
Sandstone, coarse, cmtd
0.10
Limestone, shaly
0.17
Sandstone, clayey
0.24
Limestone, porous 0.20
Conglomerate
0.20
Dolomite
0.21
After Daines, JPT, 1982
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Importance of Fracture Gradient estimate (1) Use of PP + FG to optimize casing depths, offshore well:
Yellow area shows allowed MW 16” shoe to 11000ft. Green area shows max MW of 13ppg allowed below 13 3/8” shoe, while PP at 14000ft almost equals this
March 18, 201
Safe MW margin created by setting 13 3/8” at 11000ft
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Summary 1. 2. 3. 4. 5. 6. 7. 8. 9. 10.
Several physical and chemical causes of earth stresses Burial processes, especially compaction, are the most important Undercompaction is the most prevalent cause of overpressures Undercompaction is detectable, most other causes are not Shale is most prevalent sedimentary rock Compaction in shale is more readily observed than in other rocks There are several indicators of over/underbalance while drilling Methods exist to quantify pore pressure based on shale analysis Methods exist to estimate fracture gradient Geopressure analysis improves optimization of casing and mud weight plans
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Methodology for Geopressure Analysis 1. 2. 3.
Determine where shales are located. Obtain shale values in porosity sensitive measurement. Interpret shale porosity trends: - Normal compaction trend - Actual compaction trend
4. 5. 6. 7.
Obtain overburden gradient Calculate pore pressure Calculate fracture gradient Calibrate results using real measurements/well response
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Data Flow Wireline Log
Offset Wells SWD (Seismic-While-Drilling)
MudLog VSP
Drillworks/ PREDICT EPP
MWD PPP Continuous Wave dT Measurement from Cuttings
March 18, 201
Realtime Estimated/Prognosed PP for whole well
Geopressure Systems - I
DrillWorks/ BASIN Basin Modeling and 3-D Visualisation
63
DrillWorks/BASIN
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