Fundamentals of Pore Pressure: An Introduction Instructor: Hatem A.
Date: May, 2018 UEP UEP - Kara Karach chii - Paki Pakist stan an
Safety Moment
2
Ag A g end en d a fo f o r t h e Week • 1st Day: Introduction and Pore Pressure Theory • 2nd Day: Continue Pore Pressure Theory – Class
Exercise. Fracture Pressure • 3rd Day: Buoyancy and Centroid. Exercise
• 4th Day: Wellbore Stability. • 5th Day: Continue Wellbore stability. •
Conclusion and Questions.
“Human Error”
But which human(s) human(s)? ? What err error or? ? 4
What is Geomechanics? • “Geo”
Earth
• “Mechanics” – Statics – Dynamics
•
the analysis of physical systems in static equilibrium the analysis of physical systems in which motion occurs
Geomechanics deals with understanding the mechanical behavior of the Earth. The interplay of various forces, pressur es and stresses with various properties of Earth materials is key to this understanding.
Geomechanics Applications in Petroleum Industry Characteristi cs of problems: mechanical im pact related
Start
Exploration
Drilling
Completion
Production
Finish
Subsidence Casing integrity
Fault reactivation Wellbor e stabili ty Hydraulic fracturing
Fault sealing
Compaction
Unconventional reservoirs
Sand cont rol
Geomechanics Subdivisions/Applications • “Drilling” – Pre-Drill – While-Drilling • Well-site • Remote
• “Reservoir” – Sanding – Frac job design – Completion design – Subsidence – Reservoir performance
Component Discipline(s) of Geomechanics • Parts of several disciplines • Petrophysics
• Geology • Geophysics • Drilling Engineering • Rock Mechanics
• Soil Mechanics • Reservoir Engineering • Basin Modeling
• Geochemistry
8
Value Proposition :
Pore Pressure and Wellbore Stability Problems 44% Kicks Stuck Pipe Lost Circulation Hole Collapse Pack-off Low ROP Tight Hole High Torque
Reduce Non-Productive Time Service Company Equipment Rig Contractor 7% Equipment
41%
8%
Pore Pressure Prediction 27%
Drilling Equipment 59% 11% Drilling Management
Drilling Environment
7% Other 17%
Wellbore Stability
Procedures & Training
Risk Management
14% 9%
Other
Weather
US $8 Billion in Costs to the Industry (James Dodson survey, 2001)
Types of Non-Productive Time • “Visible” – – – – – – – –
stuck pipe lost circulation well control tool failures rig downtime wellbore instability sloughing shales Influx
• “Invisible” – – – –
Excess MW, reduced ROP Excessive bit trips Hole conditioning Other sub-optimality in the drilling process
Lost Opportunity
12000’
Case hist ory of needless hol e problems •PP pre-planning from vertical of fset well MW •No wellbore stabili ty pr e-planning •GOM conti nental shelf w ell •High deviation
KOP 10000’ To 50
Lost Opportunity
Time Value of Information
VP #3 - Create a High Quality Wellbore •Reduce - Washouts, Breakout, Drilling Induced Fractures, Lost Circulation •Improve - Logging Conditions, Casing Runs, Cement Jobs, Productivity
Allowable Mud Weight Range
Mud Weights • Must lie within the range bounded by:
- Maximum of pore pressure or shear failure gradient - Fracture gradient minus safety margin Casing
• Used when mud weights must be increased
above shallower fracture gradients to keep pace with deeper pore pressures. “Safe Mud Weight Window”
Consequences!
Data Sources and Types • • • • • • • • • •
Well logs Well reports Seismic/checkshots LOT/FIT/loss circulation Direct pore pressure measurements (DST, RFT, MFT) Mud weight Well flow/kicks Gas shows Directional Casing setting depths
A pressure is a force divided by the surface where this force applies. Pressure Pascal = Force Newton / Surface m2 The official pressure unit is the Pascal It is a very small unit: 1 Pascal = 1 Newton/m 2 1 bar = 105 Pascal 1 Mega Pascal = 10 bars A practical unit on the rig is the kgf/cm 2 1 kgf/cm 2 = 0.981 bar In API , the unit is the pound per square inch (psi) 1 bar = 14.4988 psi
So, What is the difference between a Force & Pressure?
A Force is Unidirectional And can be either :
1-Tensional
2-Compressional
Pressure – Omnidirectional = All directions
1.Hydrostatic pr essure : Ph
Pressure exerted by the weight of a static column of fluid It is a function of fluid specific gravity and of vertical height of the fluid
Ph = d * g * H
With Ph = hydrostatic pressure (Pascal) d = Fluid specific gravity (kg/m3) H = Vertical height of fluid (m) g = 9.8 m / sec^2
Using well site units, the formula becomes : Ph = H*d 10
Consequently, in the following sketches, the Ph is xxxxxxxxx
H
Pascal was betting he could destroy a barrel with just a pint of water:
He fixed a long and thin tube on the barrel and poured the water, the volume of water was small, but the height was enough to make the barrel explode !
With
Ph= hydrostatic pressure (bar or kg/cm 2)
With Ph= hydrostatic pressure (bar or kg/cm 2) d = Fluid specific gravity (kg/l) H = Vertical height of fluid (m)
NB : the term 10 is approached, for precision, you should use 10.2 with pressure in bars and 9.6 for pressure in kg/cm2 In API, the formula is: Ph = 0.052 * H * d
With Ph= hydrostatic pressure (psi) d = Fluid specific gravity (ppg)
H = Vertical height of fluid (ft)
Hydrostatic Pressure Gradient:
Or 3.28 psi / m
HG = (P2 –P1 / D2 – D1) x 10 HG = (P2 – P1 / D2 – D1 )
kg/m^2 / m PSI / m
The conversion factor for pressure gradient to mud weight equivalent is as follows: 1.0 lbf/in2
X
144
in2
X
BBL
2
ft
5.615 ft3
ft
19.25 lbf
1 BBL
X
= 42 GAL
GAL = 19.25 ppg
Therefore, 1.0 psi/ft is equivalent to 19.25 ppg mud or (the inverse) equal to 0.052 GAL/lbf. Height of fluid (ft):
1000
Fluid SG (ppg):
10 Ph psi:
520.00
Fluid Density Gradients Pressure Fluid Density Gradient:
= DPressure / DTVD due to ) D V T ( h t p e D l a c i t r e V e u r T
a fluid’s weight.
0.15 psi/ft (gas)
In a permeable zone, equals the local pressure gradient. 0.30 psi/ft (oil)
Typical Fluid Densit y Gradients 0.45 psi/ft (water)
Normal Pressure
RFT’s
Fluid
Density (g/cc)
Gradient (psi/ft)
Gas
0.23-0.46
0.10-0.20
Oil
0.64-0.80
0.25-0.35
Water
1.00-1.20
0.43-0.52
Wellbore Pressure Terms Equivalent Mud Weight (EMW) : mud density required to produce a given
pressure at a give depth. EMW in lbs/gal (ppg) = Pressure Gradient (psi/ft) / 0.052 EMW in g/cc = Pressure Gradient (psi/ft) / 0.434 Equivalent Circ ulatin g Densi ty (ECD): sum of the hydrostatic pressure of the
mud column plus friction losses caused by pushing the mud up the annulus. Usually given as EMW, but may also be expressed as pressure. Balanced Wellb ore Pressur e: wellbore pressure exactly equals the pore
pressure. Underbalance/Overbalance: wellbore pressure less than/greater than the pore
pressure. 11/29/98
Applied Mechanics Technologies
32
Normal (Hydrostatic) Pressure vs Connate Water Salinity
0.52 psi/ft Saturated SW Specific Gravity = 1.2
0.455 psi/ft SW Specific Gravity = 1.05 .433 psi/ft FW Specific Gravity = 1.0
Theory of Equivalent Density Jjjjjjjjjjjjj Jjjjjjjjjjjjjjj jjjjjjjjjjjjjjjjj
Definitions Pressure
Stress/Pressure
Overburden Stress
Normal Pressure = Hydrostatic pressure of column of pore water from current depth to surface. Abnormal Pressure = Pore pressure which exceeds normal pressure. The terms Abnormal Pressure and Overpressure are sometimes used interchangeably..
Abnormal Pressure
Subnormal Pressure = Pore pressure < Normal pore pressure. Pore Pressure
Normal Pressure
Overburden Stress = Vertical stress caused by the weight of overlying formations and fluids.
Overburden Stress Density (g/cc)
Area = 1 in.2 Thickness (ft.)
Weights (lbs. / in.2)
t1
r1
0.434r1t1
t2
r2
t3
r3
0.434r2t2 0.434r3t3
r3
t4
r4
0.434r4t4
r4
t5
r5
0.434r5t5
r1 r2
r5
Overbu rden Stress = Total Weight / in. 2
= 0.434(r1t1 + r2t2 + r3t3 + r4t4 + r5t5) r6
and Water
Overburden Stress
-
Pore Pressure
=
Effective Stress
Overbur den Stress: S At a given depth, the overburden is the pressure (applying on fluids) or stress (applying on matrix) exerted by the weight of the overlying sediments.
S=H* 10
b
With S = Overburden stress (kg/cm2) rb = Formation bulk density H = Vertical Thickness of sediments (m) In API, the formula is: S=H*
With
b
* 0.433
S = Overburden stress (psi)
r b = Formation average bulk density (no unit) H = Vertical thickness of overlying sediments (ft)
The bulk density of a sediment is a function of the matrix density, the porosity and the density of the fluid in the pores. b
=( *
With rb
f )
+ (1- ) *
m
= Bulk density (no unit)
rf
rm
= Formation fluid density (no unit) = Porosity (from 0 to 1) = Matrix density (no unit)
With depth, the sediment porosity will decrease under the effect of compaction (proportional to overburden) and of course, the bulk density will increase.
Relationshi p between bulk density and depth
Off shor e
On shor e 2.31
r b
2.31 Sea botttom
Depth Depth
r b
Normal Pressure Regimes
Definitions: Overpressure Pressure
Pob = Pm + Pw Pob = Overburden Pressure Pm = Matrix Pressure
h t p e D
Pw = Fluid Pressure Pob [Rhom (1 - f ) Rhow (f )]D
Rhom = Matrix Density Rhow = Water Density
Pm
Pw
D = Depth
f porosity
Pressure
Abnormal Pressure Regimes (Over or Underpressure)
h t p e D
OBG = ES + PP ES
OBG = Overburden Pressure ES = Effective Stress PP = Pore Pressure
PP OP
Velocity, Density and Resistivity all React to Changes in PP & Effective Stress, Especially in Shales - Less in Sandstones & Carbonates
Clay Compaction (Terzaghi’s Effective Stress Principle)
sponge + H20
plastic bag sponge + H2O
weight
weight H20
H20
weight H20
H20
H20
weight
KICK
H2O
NORMAL COMPACTION
UNDERCOMPACTION <=> OVERPRESSURE
Overpressure verpressur e from fr om increa in creasin sing g stre str ess
S = Sob + ST Total Stress = OB + Tectonic Increase
stress on sediment faster than it can drain, controlled by rate of increase and permeability
Terzhagi and Peck springs
Permeability
Effective Stress
The Effective Stress is the difference between the PP and the OBP
Terzaghi’s Equation states that the overburden (Sv) is supported by a
combination of the pore pressure ( Pf ) and the effective stress ( σe).
Sv = Pf + σe Overburden Pressure
Effective Stress = Sv - Pf At In Situ Conditions: Vertical Effective Stress = Sv - Pf .
Pore Pressure Pressure
This portion of the overburden is carried by the rock grains. It is t he effective effective str ess that causes comp action. Most of the pore pressure models calculate σ e and then back out the corr esponding por e pressure.
Origins of Abnormal Pressure (1) Undercompaction Undercompaction (Compaction Disequilibrium)
- Trapped rapped pore fluid squeezed squeezed by the overburden overburden Fluid Expansion
- Trapped Trapped pore fluid constrained constrained from increasing increasing in volume volume * Heating (Aquathermal pressuring) * Clay Diagenesis * Hydrocarbon Maturation * Charging from other overpressured zones * Up-dip Transfer of Reservoir Pressures (Lateral Transfer) Tectonics
- Trapped Trapped pore fluid squeezed by tectonic tectonic stresses
Origins of Abnormal Pressure (2)
Faults and Fractures: Conduits for pressures from deeper zones, or Seals against fluid movement Poor drilling practices on offset well: Insufficient sealing sealing of permeable zones eg, leakage via poor cement around a casing casing string or across permeable zone Topography: Well elevation relative to potentiometric surface Structure: Centroids
Clay
Clay Platelet Structure
Clay and Formation Water Molecular dynamics "snapshot" of water molecules (blue and white), sodium ions (purple), and methane molecules (yellowbrown) intercalated simultaneously between two layers of montmorillonite, a common clay mineral.
Water Expulsion
Thats a lot of water. It all has to go somewhere.
Bulk density increase with burial Depth = 8m Density = 1.48 g/cc Solids = 33%
2.5
Fluid = 67% 2
Depth = 100m Density = 1.71 g/cc Solids = 52%
3 m 1.5 / g k , t h g i e 1 W
Fluid = 48% 0.5
Depth = 210m Density = 1.97 g/cc Solids = 73% Fluid = 27%
0 0
10 0
200
Depth, m
300
Hydrostatic pressure during normal compaction Fluid Pressure, Pf, bars
Sea level
River delta
D Pf=0.0981*pfl*D
s e r t e m , h t p e D l a c i t r e V
Free water expelled as sediments compact
Weight of overlying sediment supported via grain-to-grain contact
Sediment Grains
Pore Fluid
Abnormal pressure due to compaction disequilibrium Sea level
Hydrostatic Pressure Free water expelled as sediments compact
Low permeability zone impedes normal water expulsion
Some of weight of overlying sediment supported by pore fluids
Sediment Grains
Pore Fluid
Computed porosity decrease with burial, US Gulf Coast Porosity 0.01 0 2000 4000
, s 6000 D , h t 8000 p e D t 10000 n e m 12000 i d e S 14000 16000 18000 20000
0.1
=0.41e-0.000085Ds 1
Porosity decrease with burial 0 0
10
20
30 % Por
40
50
50 0
1000
1500
2000
A th y, P en ns ylv , P erm vo n Engelwardt, Germ ., Lias
2500
S t o r e r , P o , M i o c / P l io c Dick inso n, Gulf Coas t, Tert
3000
mTV D 3500
4000
4500
5000
M agara, Japan, Tert
60
Compaction depends on shale de-watering
Water escape Controlled by permeabili ty
Shale Permeability How one conceives the shale permeability in overpressured rocks affects how all aspects of pressure prediction and detection are interpreted. Two schools (with plenty of gray in between):
1) Slow Darcy flow , permeability well known from Core measurements and basin models 2) Near impermeability due to non-Darcy flow in extremely small pores (shale) and affect of adsorbed, crystalline-like water on clay; threshold gradient (Miller and Low, 1963)
Shale Permeability Consequence of FLOW school: Pressure of sands and adjacent shale should be very similar (flow!) Therefore: Log and seismic methods should be calculating pressure in shale which is very close to sandstone pressure. Frustrated at times. Consequence of SEAL school: Sandstone and adjacent shales can be at very different pressure. Log calculations may not directly estimate adjacent sandstone pressure.
Shale Permeability - Flow
Mouchet and Mitchell (1989)
Hydrocarbon Generation Hydrocarbon Generation & Crackin g of Oil to Gas : Generates High
Pressures and Fractures the Source Rocks in Order to Migrate from them. 0
Conversion of Oil to Gas @ 3000 Cu.Ft./BBL
5
0 0 0 1 / t f , 10 h t p e D
Effect of 25% Oil in a Reservoir 15
20 0
10
20 Pressure, psi/1000
30
40
Other OverPressure Causes: Clay Diagenesis Bound Water Layer (3 A o) 10 Ao
Smectite Grain
Illite Dry Grain Clay
Smectite “Particle”
Smectite
100 Ao
Illite Illite “Particle” Illite Grain
Smectit e-Illite Transform ation
• Requires temperature of 100 o C.
o
100 C
• Smectite’s bound water expelled
Expelled Bound Water
into pore space. • Bound water tries to expand 1.04-
1.1 times as it turns into pore water.
Aq A q u ath at h erm er m al Pres Pr ess suring
20 DL
Pore Water L
DL
Excess Pressure Necessary to Make Water Fit Inside Pore Space
Pore water expands 1520 times more rapidly than the pore space.
Aq A q u ath at h erm er m al p r ess es s u r i n g Often Often cited for o rigin o f underpressure due to cooling contraction during uplift
Uplift Burial
“Pump” origins – Diagenesis Diagenesis & Osmo Osmosis sis:: Clay sediment at point of “sealing”
Cementation takes up
pore space displacing water. Decreasing Decreas ing pore volume increases pressure; PVT. Cement Osmosis – water “pumped” in due to
salinity differences across the clay / shale membrane. Osmosis
Pressure ressu re lea leakage via vi a faults fault s or o r poo p oorr we w ell seals seals
A. Communication along fault
B. Poor cement or damaged casing
C. Leaking cement plugs in abandoned well
Pressure gradients in reservoir with constant overpressure (1500*1.05*0.0981) + 100 = 254.5 bars 254.5/1500 = 0.1697 bar/m = 1.73 sg EMW
P/Z=0.1697 bar/m
1500m 3000m
m , h t p e D
1500m
(3000*1.05*0.0981) + 100 = 409 bars 409/3000 = 0.1363 bar/m = 1.39 sg EMW
Pressure, bars
3000m
‘Hard’ overpressure
P/Z=0.1363 bar/m ‘Soft’ overpressure
Effect of hydrocarbon buoyancy on reservoir pressure Fluid Pressure, Pf, bars
D Gas, r = 0.25g/cc Pg = Po - (0.0981*0.25*H2)
Oil, r = 0.80g/cc
Po = Pw - (0.0981*0.80*H1) H2 H1 Pw = 0.0981*1.03*D
Formation water, r = 1.03g/cc
Hydrocarbon Column Due to the difference of densities between water and hydrocarbons, the pressure at the top of the reservoir is almost the same that at hydrocarbon – water contact
Pressure
gas
Water
Depth
The formula for the pressure anomaly (excess of pressure respect to normal) is
Phc = H * (d w – d hc ) 10
With Phc = Pressure anomaly at the top of the hydrocarbon column (kg/cm 2) H = Height of the hydrocarbon column (m) dw = Water SG (kg/l) dhc = Hydrocarbon SG (kg/l) Note that this anomaly is proportional to the height of the hydrocarbon column and to the diffeence of SG between water and hydrocarbon.
C A B
Water SG (kg/l) Hydrocarbon SG (kg/l) Point A & C depth (m) Point B depth (Hydrocarbon/water contact)(m) Calculate Pf in A (kg/cm2) Calculate Pf in B (kg/cm2) Calculate Ph of the column of water AB (kg/cm2) Calculate Ph of the hydrocarbon column (kg/cm2) Calculate the Pf in C (kg/cm2) Pressure anomaly at top of hydrocarbon (kg/cm2)
1.05 0.25 2000 2590
210.00 271.95 61.95 14.75 257.20 47.20
Origins of Abnormal Pressure (cont’d)
Paleo Pressures: Uplift of sealed compartments Pressure compartments: Sealing faults Massive salt: Perfect impermeable seal for pressure entrapment
Lithologic Pressure Seals Sea Level Normal Pressure
Normally Pressured Sands
Top of Overpressure (Shales)
Sand
Overpressured Sand
Shale
Fault Seal Fault
Normally Pressured Sand
Top of Overpressure (Shales) Overpressured Sand
Sand
Shale
Checking for Pressure Cells Pressure
Fault
Fault
RFT1
RFT3 RFT2
Sands 1 & 2 are in same pressure cell; Sand 3 is not.
h t p e D
RFT1 0.45 psi/ft
0.45 psi/ft
Normal Pressure Sand
Shale
RFT3
RFT2
Constant Overpressure
Up-Dip Transfer of Reservoir Pressures Pressure “Far Field” Shale Pore Pressure
Shale A
B
C
Sand Pore Pressure
h t p e D
D
Pressure Shale Pore Pressure Sand Pore Pressure
h t p e D
A Boundary Of Zone Affected By Sand
B
Pressure Shale Pore Sand Pressure Pore Pressure h t p e D
Pressure Shale Pore Sand Pressure Pore Pressure h t p e D
Water Sand C
D
Salt movement effects on pore pressures Salt intrusion causes stresses in formations, and impermeability prevents drainage of pressures
Paleopressured sands
Salt seals off 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.
Artesian Spring
Formation of Cap-rock
Clay
Preferential absorption of fresh water
Clay Clay
Zone of hi gher pressur e and permeability
Remaining water more saline
Precipit ation of carbonates and sili cates at fo rmation b oundary cr eates permeability barrier
Significance of Pore Pressure Mechanism Very important in Basin Modeling: controls how the model is populated with algorithms to handle these various factors. Resistivity and sonic / velocity techniques less so. These techniques depend on a direct relationship of porosity to pressure – presume undercompaction mechanism. If another mechanism is suspected, then another method of calculating overpressure should be used.
Outline • • • •
Review of Sources of Abnormal Pressure Pressure Seals and Compartments
Pore Pressure Indicators Quantitative Pore Pressure Estimation – Overburden Gradient – Conventional undercompaction analysis – “Advanced” topics: centroid/buoyancy, seal failure, unloading, basin modeling, tectonics
• Fracture Gradient • Wellbore Stability • Summary
Pressure Seals A pressure “seal” is any barrier that separates rocks that are
demonstrably not on the same hydrostatic pressure gradient; The sands / limestones are at different pressure forming a Pressure Compartment or Cell
(3000) 10000
10500 (3250)
11000
) m ( t e e f , H T P E D
(3500) 11500
4500
5000
5500
6000
PRESSURE (psig)
6500
0
100 GR
0.2
20
RESISTIVITY
Pressure Compartments A c om pl etel y sealed porou s and per meabl e roc k. Internally pr essure changes vertically d ependent on the dominant fluid; foll ows a water gradient if no oil or gas.
Rate of press ure change dependent on fluid dsensity Water Gradient
Seals
X psi above normal Z psi above normal Bradley and Powley (1994)
Pressure Compartments May be very c omplex. Each thi n sandstone or siltst one lens may be a separate pressure compartment, or very large such as the Cretaceous Chalk of the Central Graben.
Bradley and Powley (1994)
Note: Wide Swings in PP from DT & Res. Pressure Bleed-off in Sands. Higher Shale PP.
Note: This is part of a Field-Wide Pressure Compartment.
Abnormal Pressure Indicators - Drilling Gas: Drill gas (Background gas) Connection gas Trip gas Pumps-off gas ROP: Normalized ROP (d-exponent and other) Cuttings/cavings and Hole Instability: Cavings - size and shape; splintery, 'rotor'-shaped Torque, Drag, Hole Washout Formation Temperature: Formation temperatures is usually inferred from downhole circulating temperature or flowline temperature. Mud Chlorides Background Chlorides Trip Chlorides
Wellsite Pressure Parameters Dx % Sand
ROP
Gas Units
Flow Line Temperature (F)
Mud Wt. (ppg)
Dx ROP 10.5
2000 12.5 1250
Wellsite Overpressure Indicators • Increase In:
dx
- Rate of Penetration - Gas
ROP
- “Splintery” Shale Cuttings - Volume of Shale Cuttings - Flowline Temperature - Chlorides - Shale Travel Time (MWD)
• Decrease In: - d-exponent - Shale Density
- Resistivity (MWD) • No Sing le Indi cator Is 100% Foolproof !
dx ROP
Gas Units
Swab/Surge Pressures Drill Pipe Static
Mud Hydrostatic Pressure
Drill Pipe Raised
Drill Pipe Lowered
Swab Pressur e -
Surge Pressure -
pressure drop when drill pipe is raised
pressure jump when drill pipe is lowered
Mud Log Gas
Drill Gas
Underbalance
Background Gas
Connection/ Trip Gas
Factors That Affect Mud Gas • Backgrou nd Gas
Gas Unit s
- Mud Properties
- Permeability
- Pump Rate
- Porosity
- ROP
- Gas Composition
- Mud Weight
- ECD
Connecti on/Trip Gas
- Pump Shut Down Time
- Permeability
- Swabbing
- Porosity
- Mud Weight
- ECD
1250
Overpressure Detection - Gas Readings Constant ROP Hydrostatic Pressure Mud Weight
ROP
Pore Pressure
ECD 1 Connection
Swab Pressure
2 3 4
Background Gas Connection Gases
Overpressure Detection - Gas Readings Increasing ROP Hydrostatic Pressure Mud Weight
ROP
Pore Pressure
ECD Background Gas 1 Connection
Swab Pressure
Connection Gas
2 3 4
“Normalized Gas Units” To Compensate for Gas Changes Not Due to Differential Pressu re Gn = G * (ROPn/ROP) * (Dn/D)2 * (Q/Qn ) * (1/E)
Gn =
Normalized Total Gas Units
G=
Measured Gas Units
ROPn = Reference ROP ROP =
Actual ROP
Dn =
Reference Bit Diameter
D=
Actual Hole Size
Qn =
Reference Pump Rate
Q=
Actual Pump Rate
E=
Gas System Efficiency (Take as 1?)
Alun Whitaker & George Sellens, “Normalization of gas shows improves evaluation”, Oil & Gas Jr., April 20, 1987.
Overpressure Detection - Gas Readings “Raw” vs Normalized Gas Units
Hydrostatic Pressure Mud Weight
ROP
Pore Pressure
ECD Background Gas 1 Connection
Swab Pressure
Connection Gas
2 3
1
2 3
4
4
Normalized Background Gas
ROP
ROP vs Differential Pressure Underbalanced -7
-6
-5
-4
-3
-2
Overbalanced -1
0
1
2
3
4
5
6
7
80 70 60
% , P O R n i e g n a h C
Faster ROP
50 40 30 20 10 0 -10 -20
Slower ROP
-30 -40 -50 -60 -70 -80
Diff . Pressure, Pm-Pf, psi x 100
After Vidrine & Benit, 1969
Factors That Affect Rate of Penetration (ROP) • Drilling Parameters
- Weight on Bit
- Torque
- Rotary Speed
- Bit Type, Condition
- Mud Weight
- Hydraulics
• Formation Properties
- Lithology
Mud Pressure
Bit Tooth
- Porosity
- Permeability • Differential Pressure =
Mud Pressure - Pore Pressure
Pore Pressure
Roller Cone Vs PDC Bits Sensitivity of ROP to Differential Pressur e Mud Pressure
Roller Cone Bit Tooth
Pore Pressure
PDC Bit Tooth
Mud Pressure
Pore Pressure
• Roller Cone Bits tend to have higher sensitivity.
• Roller Cone Bits Break Rock Like A Hammer - Chips subject to hold-down by differential pressure • PDC Bits Scrape Rock Like A Lathe
- Cuttings less affected by differential pressure
Formation Drillability vs Overbalance vs Bit Type Rock B it
Pm>Pf
Pm=
With large overbalance, cutt ings held on bottom
With underbalance or small overbalance, cuttings released
Bit tooth Mud Hydros tatic Pressure, Pm
Formation Pressure, Pf Bit tooth in contact with formation
Fractures cr eated by bit tooth action
PDC Cutt er
PDC Bit
Bit cutter in contact with formation
Cutting action of PDC means Pm/Pf less important for cuttings r emoval; hence Dxc less reliable Bit cut ter shears formation
Cuttings ‘pushed’ away from formation by bit cutt er and lifted by mud flow
Differential Pressure vs d-exponent 2.0
d-expo nent (dx):
Roller Cone
Tries to Compensate for Changes in ROP Not Due to Pore Pressure 1.5
log(ROP/60N)
dx =
PDC
log(12W/10 6D)
ROP = Rate of Penetration (ft /hr)
1.0
N = Rotary Speed (rpm ) W = Weight on Bi t (lbs) D = Hole Diameter (in) dx May Not Be Reliable Overpressure Indicator fo r PDC Bits!
0.5
0
500
1000
1500
Differenti al Pressure (psi)
2000
Hole Instability
Cavings Due to Underbalance vs Mechanical Instability
Underbalance Front
Top
Side
Delicate, Spikey Shapes Concave Surface
Mechanical Instability Front
Top
Side
Blocky, or Angular Shapes
Cavings Due To Underbalance In Situ Horizontal Stress
Sh
Path of Least Resistance for Fracture Pmu d
Wellbore
Sh
Pore Pressure “Blows”
Chips Into Wellbore Pmu d
Concave Shape
Cavings Due To Mechanical Instability In Situ Horizontal Stress
Hoop Stress Sh
Hoop Stress Pmu d
Wellbore
Sh
Shear Plane
Pmu d
Blocky Shape
“Squeezes”
Chips Into Wellbore
Hole Cavings as Overpressure Indicator Amount, sh ape, s ize and col ou r of cavings are im po rtant. With low or negative differential pressure or s tress relief at borehole wall -> slou ghing of ro ck into t he hole as cavings. Cuttings released easily from under bit; may even be 'ejected' by form ation pressure, -> different-shaped c uttin g li ttle affected by bit c ontact, eg less rou nded. PDC cuttings have special character, easy to dis tingui sh f rom cavings. Top
Top Shale cavings resulting from underbalance
Concave crosssection, thin and spiky shape, may be striated
Side Front
Shale cavings resulting from r elief of rock str esses during drilling indicate excess lateral stresses in formation Blocky, rectangular shape, oft en cracked
Front
Side
Formation Temperature
Formation Temperature as Overpressure Indicator
Heat Conducti vit y Relative to Water Water = 1.0 Clay = 1.7 Quartz = 4.8 – 13.5
O-P Zone
Temperature Increase
Temperature Gradient Porosity
Mud Chlorides
Factors That Affect Chlorides
14
Pressure (ppg ) 16
Chlori des (ppm) 18
0
50000
• Pore Fluid Salinity
13300
PPresistivity
13400 13500 13600
PPsonic
• Mud Weight/ECD • Pore Pressure
13700
) t f ( b 13800 k r D 13900 V T
• Mud Salinity
Mud Weight
14000
• Porosity • Permeability
14100 14200 14300 14400
Tight
• Circulation Rate
Flow Kick
• Penetration Rate
Calibration: Cavings
Angular cavings have irregular shape and rough surface texture. Their surfaces intersect at acute angles <<90 degrees. The surfaces are distinctively fresh, reflecting newly created fractures (shear fractures)
Calibration: Cavings The shape of these cavings indicates that they are the product of preexisting weaknesses at the borehole wall
Cavings with parallel edges/tabular form: from tangent section drilled close to parallel with bedding. Fissile bedding planes contributed to the formation of these cavings. These bounding surfaces are bedding planes.
1 1 9
Caving Shapes to Reveal Failure Mode
Platy shape due to bedding
Wedge shape due to shearing
Calibration – Normal Cuttings At 17280 ft normal
Diagnosing Wellbore Failures
M U D W E I G H T T O O L O W
A wellbore can fail for a variety of reasons. Formation fluid influx, drilling fluid loss, tight hole, hole fill, ballooning and washout are all symptoms of wellbore failure. By studying the available information, one can better understand the mode of wellbore failure, and take proper remedial actions. This poster is designed to help oilfield professionals improve their diagnostic abilities by providing information and references that Knowledge Systems’ Geopressure Analysts have found useful in supporting our clients in the creation of functional wellbores free of fluid influx, loss or instability.
Splintered Shale
LOOK FOR PLUME STRUCTURE ON CAVINGS
Splinteryshaleis caused by a tensilefailureall longthe circumferenceof thewellbore. Thistype of failure typicallyoccurswhenever thepore pressure in theshales exceedsthe hydrostatic pressure exertedby thedrillingfluid column. Thefluid pressurein theshale literallypops the cuttingsinto the wellb ore. These cuttingsare usually long,splintery, andconcavein shape. In general,wellboreenlargement fromthis typeof failure will occur all along thecircumference of thewellbore rather thanonly in specificdirections. In cases where horizontal wellborestresses areunequal, there maybe morewashoutin some directions thanin others,but theentire wellborecircumferencewill stillbe enlarged. Thistypeof failurecan becontrolledby increasing mudweight.
FailureOrigin
Wellbore Collapse
A borehole collapses when the effective wellbore stresseson the wellbore wall exceed the rock strength. This type of failure is also know as shear failure. Wellbore pressure, exerted by themud,can reduce thewellbore stresses. Well bore Collapse occursif mud weight is insufficie nt to reducethe wellbore stresses. Although wellborecollapse or wellboreinstabil ityis in parta functionof porepressure,drilling witha mudweightless thanthe ‘collapsepressure’ doesnotmeanthatthewellis bein gdrilledunder balance inthe sense that formati onporepressureis equal to or greaterthanthe mud weight (see splintery shales.)It is important to accountfor wellbore azimuth and inclin atio n when considering wellbore collapse, the mud weight required to prevent wellbore collapse may require significant modification dependent onwell trajectorywhileall other parametersremainthesame. Thistypeof failurecan becontrolledby increasing themud weight.
Safe Operating Envelope
In thisregionthe wellborepressure is sufficient to preventformation fluidinflux or wellb orecollapse andis insufficient to exceed the minim umhorizontal stress and create a hydraulic fracture. Whileoperatingin thezone, gas, holefill, tighthole andcavingswould be minim alor non-existent. Thesafe operating envelopecan be identified andmanaged throughthe use of modelingthat computesthis window in real-time based on encountered conditions. Furthermore, this window should be communicatedto operations personnel as it changessuch thatdrilling, tripping, logging andcementing operations do notallow the wellborepressure to dropbelow thewellbore collapsepressure or exceedthe minimum stress. By doin g so, non-productive time will be reduced and thewellboreintegrity will be preserved for evaluationor production.
Rubble Zones M U D W E I G H T T O O
Rock maybe natural rubbelized, or existin a rubblestate due to changesin thesubsurface stressenvir onment. Rubblezoneare oftenfound near salt bodies and activefaults. This type offailure is generall y associa ted with brittle rocksthatfail in place underthe far field stressesin theEarth.Rocksthatare more plastic may simplydeformunder thesame stress environment and not be asdangerousas this specific case. Asthe wellbore schematic (left)and picture rightshows, therock exis tslikebuildingblocksin theEarth . Asfluidpenetratesthe cracks inthe rock,theyenter thewellb ore andthewellborestressesare redistributed. Increasing the mudweight causes greater infiltration andfailure. Reducing themud weight allo ws thefluidto exit thecracks and wellbore fail ure. Therefore, any change in mud weight will destabili ze the wellbore. Diagnoseproperly, minim ize all changesin mud weight andemploy “gentle” drill ing practices. Avoidreaming andmonitortrips throughdestabilized intervals.
Ballooning Wellboreballooningor breathingis caused bythe creationand activ ation of a hydraulicfracture. Thisconditionis ALWAYSassociatedwith drilli ngfluid losses andmay occurin sandsor shales. It is very commonto have shalesthatfracture more easily than sands, andthe fracturemay be located usingtimelapse resistivit y logging (SPE67742, 74518,78205). Withthe mudcirculati ngthe ECD is greaterthan thefracture extension pressure. Mudlossesare observedand thefracture is enlarged. When the mud pumps are not creatin g ECD, the static mud weight is less than the minim um closure pressure and the fracture returns fluid to the wellbore. Understandingthe fracture gradient and preventio n is highly advised; however, if this condition occurs, Locate the fracture, manage wellbore pressures to minimize fracture growth, andconsider a polymer treatment if condit ions deteriorate. Typical LCM treatm ents areusually ineffectiv e and may even act as proppants forthe fracture.
DRILL LOG
REAMLOG
Outline • • • •
Review of Sources of Abnormal Pressure Pressure Seals and Compartments Pore Pressure Indicators Quantitative (Petrophysical) Pore Pressure Estimation – Overburden Gradient – Conventional undercompaction analysis – “Advanced” topics: centroid/buoyancy, seal failure, unloading, basin modeling, tectonics
• Fracture Gradient • Wellbore Stability • Summary
Overpressure Indicators - Wireline/LWD Response Normal Compaction Trends Vsh (ft/s)
Rsh (ohmm)
h t p e D
dt sh (us/ft)
sh
(g/cc)
Freshwater / Temperature Effect
Normal Trend
Normal Trend
Normal Trend
A nor mal co mp act ion tr end is an es ti mate of th e log resp on se in a normally pressured environment.
Overpressure Indicators – Seismic Interval Velocity Interval Velocit y (kft/s)
Top Of Overpressure
“Normal” Trend
PP Pred. With Seismic Data Velocity
Pressure Pp = Pore Pressure (Red)
Effective Stress
25 k
Carbonates
h t p Normal Pressures e D
h t p e D
ES = Effective Stress or Eff. Pressure
Overpressures
) c 20 e s k / t f ( y t i c15 o l e k Unloading Curves V
10 k
Op = Overpressure
5 k
Shales
PP Pred. With Seismic Data Velocity
Pressure Pp = Pore Pressure (Red)
Effective Stress
25 k
Carbonates
h t p Normal Pressures e D
h t p e D
ES = Effective Stress or Eff. Pressure
Overpressures
) c 20 e s k / t f ( y t i c15 o l e k Unloading Curves V
10 k
Op = Overpressure
5 k
Shales
Overpressure Indicators - Wireline/LWD Response Vsh (ft/s)
Rsh (ohmm)
h t p e D
dt sh (us/ft)
sh
(g/cc)
Freshwater / Temperature Effect Top of Overpressure
Normal Trend
Normal Trend
Normal Trend
Effective Stress and Calculations that Use It
Effective Stress
The Effective Stress is the difference between the PP and the OBP
Terzaghi’s Equation states that the overburden (Sv) is supported by a
combination of the pore pressure ( Pf ) and the effective stress (σe).
Sv = Pf + σe Overburden Pressure
Effective Stress = Sv - Pf At In Situ Conditions: Vertical Effective Stress = Sv - Pf .
Pore Pressure
This portion of the overburden is carried by the rock grains. It is t he effective str ess that causes comp action. Most of the pore pressure models calculate σ e and then back out the corr esponding por e pressure.
Insensitivity of Effective Stress to Water Depth Stress/Pressure
Stress/Pressure
Sea Floor Overburden Stress
Sea Floor TVDbml
Pore Pressure
Effective Stress Pore Pressure Effective Stress (Compaction, Strength) Only Depends on Depth Below Mud Line
Overburden Stress TVDbml
Pore Pressure
Effective Stress
Outline • • • •
Review of Sources of Abnormal Pressure Pressure Seals and Compartments Compaction and Pore Pressure Indicators Quantitative (Petrophysical) Pore Pressure Estimation – Overbu rden Gradient – Conventional undercompaction analysis – “Advanced” topics: centroid/buoyancy, seal failure, unloading, basin modeling, tectonics
• Fracture Gradient • Wellbore Stability • Workflow and Example
Overburden Pressure Calculation from Density
OBP where OBP i
Li C
n
= i=0 = = = =
i *(
L i )*C
Total Overburden Pressure Average Density within ith Interval Interval length over which i is calculated Units conversion constant
Recommendations for Calculating OBG • All cases should account for very high near-mudline porosities • Density can be calculated from porosity ( Φ) data as follows ρb
=
where
•
Φ * ρwater + (1 – Φ) * ρmatrix
= Φ ρwater = ρmatrix =
Water fraction Water Density, g/cc Rock matrix density, g/cc
The rest depends on the data available: – Velocities only – Good offset, but incomplete, RHOB data – No data
Many Methods to Calculate Rhob
•
From Density log or Density Porosity log ρb = Φ * ρwater + (1 – Φ) * ρmatrix
• Miller Metho d : See later
•
Gardner Transfer of Interval Velocity:
• Gardner Transfer of Sonic DT
Near-Mudline Sediment Densities •
Figure on right f rom Ostermeier, et al SPE/IADC 67772, “Trends in shallow sediment pore pressures deepwater Gulf of Mexico.”
•
Other data from ODP are consistent wi th these measurements.
• At f = 0.70, r g = 2.68, and r w = 1.03; r b = 1.53 gm/cc. •
Curve equation given b y f = f 1 +f 2exp(-ld 1/n) f 1 = 0.35, f 2 = 0.35 l = 0.0035, n = 1.09
OBG Theory 1.
Overburden pressure can be estimated by calculating the pressure contribut ion of each l ayer.
2.
To do th is , w e m us t k no w t he B ul k Densit y of each layer. a) b) c)
Sea w ater rb = 1.027g/cc 500 BML rb = Ostermeier or ODP rb (Miller Method ) Rock rb = rb log, or velocity to rb transform i. Gardner ii. DEA-119 Transform ’
1.
Calculate pressure contribution of each layer:
2.
rb * .4335 (layer thickness (ft) ) = psi
Where ρb = Layer Density, g/cc 5.
Su m p res su res an d c on ver t to pp g equivalent at desired depth
Overburden Gradient Calculation (Example)
OBG from Velocity Data • Use densities calculated from KSI near mudline porosity correlation for depths < 1000 ft BML. • Use Gardner’s equation calibrated to offset data, ρb = A*VB, A ≈ 0.235 for depths > 1500 ft BML in Gulf of Mexico.
OBG Calculatio ns
• From Integrating Actual Rhob values from Density log •From Miller Method for near Mud line sediments. • Amoco Method
Outline • • • •
Review of Sources of Abnormal Pressure Pressure Seals and Compartments Compaction and Pore Pressure Indicators Quantitative (Petrophysical) Pore Pressure Estimation – Overburden Gradient – Conventional undercompactio n analysis – “Advanced” topics: centroid/buoyancy, seal failure, unloading, basin modeling, tectonics
• Fracture Gradient • Wellbore Stability • Workflow and Example
Basic 1-D PP Estimation Process Conventional pore pressure analysis is based on Terzaghi’s effective stress principle which states that vertical stress ( Sv ) is equal to the sum of the effective vertical stress (σe) and the formation pore pressure ( Pf ) as follows: Sv =
e+
Pf
The basic steps in performing a conventional 1-D pore pressure analysis are : 1.
Calculate total vertical stress (Sv) from rock density
2.
Estimate vertical effective stress ( e) from log measurements or seismic (LWDWL, Vel)
3.
Pore pressure Pf = Sv -
4.
The analysis is then calibrated to credible information as it becomes available: – MDT/RFT – SIDPP – SPLINTERED CAVINGS – EXCEPTIONAL CONNECTION GAS – HOLE FILL – EXCESS DRILLSTRING DRAG
e
“Vertical” Effective Stress Methods: Miller
& Bowers Velocity (km/s) 1.5
2.5
3.5
Pressure (MPa) 4.5
0
40
80
120
0
1000 ) 2000 m ( h t p e 3000 D
4000
5000
Overbrd Pnorm
Normal Trend
A
V A = VB
Equivalent { Depth
A
4.5
) 4 Compaction Trend s / m3.5 k ( y t i 3 VB = V A c o l e 2.5 V 2
B
VB
PB
B = A
1.5
{
B = A
0
10
20
30
40
50
Eff. Str ess (MPa)
60
“Horizontal” Effective Stress Methods: Eaton Velocity (km/s) 1.5
2.5
3.5
Pressure (MPa) 4.5
0
40
80
120
0
1000
Overbrd Pnorm
Normal Trend
) 2000 m ( h t p e 3000 D
4000
5000
4.5
Eaton’s Eq. VNB ) 4 3 s = NB (V/VNB) / m3.5 k ( y t VB Normal i 3 c Trend o l e 2.5 V 2
B
VB
VNB
NB
1.5
{ PB
B
NB
B 0
10
20
30
40
50
Eff. Str ess (MPa)
60
Eaton’s Effective Stress Methods (Horizontal) Assumes: Pf = Sv - e Pf = Pore pressure Sv = Overburden Stress Mn = Normal trend value for M
e = Effective stress (vertical) n = Effective stress for normal
pressure at current depth Mo = Observed value for M
General Form :
Resistivity: Sonic:
e e
e
= =
=
n
(Mo /Mn )x
n (Ro/Rn)1.2 n ( Δtn/ Δto)3
Bowers Velocity / Effective Stress (1994) V
=
Vml + A(e)B
Where: V
=
Velocity, ft/sec
A
=
Empirical coefficient
B
= =
Empirical exponent Effective Stress (S v – Pf )
e
A and B are empirical calibration constants. A and B should be derived from offset well data. For Gulf of Mexico wells, A 10-20 and B 0.7 – 0.75.
Miller’s Velocity – Effective Stress Relationship Miller’s Velocity-Effective Stess Relationship
V = Vmatrix – (Vmatrix – Vfluid)(e-l) Where: V Vmatrix Vfluid e l
velocity matrix velocity fluid velocity base of natural logarithms lambda, calibration constant effective stress
The physical relationships built into this equation: • at zero effective stress, the velocity is simply the fluid velocity • as the effective stress approaches infinity, the velocity approaches the matrix velocity
Miller Velocity-Effective Stress Relationship Miller velocity curve, assuming that the effective stress results from a normal pore pressure gradient. V = Vmatrix – (Vmatrix – Vfluid)(e-l) Lambda is used for calibrating the relationship to actual conditions.
Vertical scale in meters Velocity scale in m/s OBG scale in g/cc
Example Fits Through Data 14000 12000 ) 10000 c e s / t f ( 8000 y t i c o l e V
6000
Data from 20 Deepw ater GOM Wells
4000
Bo wer s, A = 14.2, B = 0.72
2000
lamd a = 0.00016
Vmatrix = 15,500 ft/sec lamd a = 0.00022
0 0
1000
2000
3000
4000
Effectiv e Stress (psi)
5000
6000
Outline • • • •
Review of Sources of Abnormal Pressure Pressure Seals and Compartments Compaction and Pore Pressure Indicators Quantitativ uanti tative e (Pe (Petrop tr ophys hysical) ical) Por Pore e Pressure ressu re Esti Estimatio mation n – Overburden Gradient – Conventional undercompaction analysis – centroi d/buoyancy, seal seal failure, unlo ading, basin mod eling , tectonics
• Fracture Gradient • Wellbore Stability • Workflow and Example
Centroids/Buoyancy
Centroid • The point at which the sands and shales are
equal in pressure • This is our implicit assumption when we adjust
the shale pressure curve to match the RFT and DST measurements in the sands
Causes of elevated pressures in sands • Water Water pressure transmitted along a permeable conduit (i.e. sand or fault) • Buoyancy forces of trapped Hydrocarbons
Pr es s ure ur e Tr an s f er and HC Buoy Bu oya ancy nc y are Re Respon sp onsi sibl ble e for fo r
• Kicks in sa s ands • To p s eal Fai l u r es
Limi Li mitation tations s on o n Shale Shale Pressure ressu re Estimation hale permea permeabi bilit lity y is to low to allow • Shale direct di rect me m easurement. su rement. Therefo Therefore re Sa Sand Fluid lu id Pressure Pressur e is measu measured. red. ressu re De Develops velop s in i n Shales Shales and and is • Pressure tra tr ansmit nsm itte ted d to t o Sands Sands sti matio tion n Phy Physic sics s is only on ly • Pressure Estima appro pp ropr priate iate to Shales. hales.
Calibra libr ation Assumpti Assu mption on Pressure e Equilib qui libriu rium m with wi th the t he • Sands are in Pressur Surround urr ounding ing Shales hales therefore ressu res ca c an be b e Used as Ca Calibr li bra ation ti on • Sand Pressures Points oin ts for Pressure ressur e Estimation sti mation in Shales hales
Factors Affecting Sand Pressure Deviating from Shale Pressure • Lateral extent
• Structural Dip • Permeability (sand and shale) • Centroid position • Temperature
Probabilistic exercise, not deterministic
• Fluid distribution – Hydrocarbon phases
• Fluid properties - Density
Centroid Position • • • •
Flow into the sand increases its pressure Flow out of the sand reduces its pressure Flow/ unit area is f (pressure diff. and shale perm.) Centroid position in a sand shifts with different shale pressure, permeability, and contact area for flow in and flow out.
Factors Governing Centroid Position
• Pressure path continuity • Pressure changes in adjacent shale with depth and location in the basin • Geometry (contact area efficiency) • Permeability of adjacent shale
Pressure path continuity
Some Possible Geometries
At Mid-depth
*
*
Above Mid-depth * Below mid-depth
*
Permeability of adjacent shale
Effect of Hydrocarbons
Decreases water flow out of the upper portion of the sand
*
Capillary Seals for two fluid phases only
Moving oil through a low permeabil ity pore is “Like shoving a basketball through a keyhole” -- Roy Hill e, 1981 (from J. Dolson, BP Egypt)
Centroid and Buoyancy Pressure Shale
“Clean” Shale Picks Shale Pore
B
Pressure Boundary Of Zone Affected By Sand
Actual Sand Pore h t p e D
Pressure Missed By Shale Picks Sand Pore Pressure Estimated From Clean Shale Picks
Water Sand
“Clean” Shale Picks
The “Centroid” Overburden
Kick pressure
Flow from sand to shale
Flow Balance Point “Centroid”
D E P T H
Sand Pore Pressure
“Centroid”
Flow in sand Flow from s hale to sand
Sand
Shale
Hydrostatic Pressure PSI
Shale Far Field Pore Pressure
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
Pore pressure in a sand as a result of transmitted shale pressure and buoyancy. Fracture Pressure
16000
Deviation
Gas Leg 16500 Oil Leg
D E P 17000 T H
Water Leg Shale Pore Pressure
17500
“Centroid”
18000 13000
PSI
13500
14000 15
PPG
16
17
Seal Fracture Criterion (Maximum Hydrocarbon Column Height) Pressure Reservoir Pressure In Hydrocarbon Zone
h t p e D
Minimum Shale Stress
1
Fracture
Shale
Smi n Pres
1 2
2
3
3 Reservoir Pressure In Water Zon e
Water Hydrocarbon
Reservoir AMT
Testing for Breach of Seal • RFT provides a
pressure value in a sand • Assume that up dip is gas-filled to the crest at 14,250’
• Projected PP
does not exceed shale FG – seal likely not breached
What MW to drill out with? What FG is needed?
Secondary Pressuring/Unloading
Velocity Depends on Stress History
C B' A'
B
A
Effective Stress
Along the red line, we have a large change in the effective stress but only a small change in f. Therefore, the PP model must be modified to account for this.
Secondary Pressuring Example
Effective Stress
Overburden Pressure Increasing Effective Stress
Estimated PP (Eaton) Porosity trend reversal indicates decreasing effective stress
Decreasing Effective Stress
In a strictly undercompacted environment with a near-perfect seal, effective stress should remain constant or increase slowly. It should not decrease, as shown here. A decrease in effective stress is an indication that something besides undercompaction is affecting the formation pressure. Typically, an undercompaction model will underestimate PP’s in an underloading situation.
Bowers Velocity / Effective Stress Relationship Unloaded Case Where:
1/U B
V
=
Vml + A[(
V
=
Velocity, ft/sec
Vml
=
Velocity at mud line, ft/sec
A
=
Empirical coefficient
B
=
Empirical exponent
e
=
Effective Stress (Sv – Pf )
max
=
Effective Stress at onset of unloading (Sv – Pf )
max (
e
max)
]
Rearranging and combining with Terzaghi’s Equation, we get: Pf = Sv – [(V - Vml) / A]U/B * (σmax)1-U
A and B are empirical calibration constants. A and B should be derived from offset well data. For Gulf of Mexico wells, A 10-20 and B 0.7 – 0.75. U must be empirically derived for each area. Usually, U ranges between 3 and 5.
So: What is the True Pore Pressure? • Analyze All Data
• Consider All Possibilities • Match All Calibration Information • Make an Interpretation
Interpret Def (“True”) PP fm All Avail. Data Shale Pt fm GR
PP Res (Eaton)
PP DT & Chk (Bowers)
PP Rhob (Eaton)
Outline • • • •
Review of Sources of Abnormal Pressure Pressure Seals and Compartments Compaction and Pore Pressure Indicators Quantitative (Petrophysical) Pore Pressure Estimation – Overburden Gradient – Conventional undercompaction analysis – “Advanced” topics: centroid/buoyancy, seal failure, unloading, basin modeling, tectonics
• Fracture Gradient • Wellbore Stability • Workflow and Example
Cause of In Situ Horizontal Stress Free Standing Elements Squash Out
Horizontally As They Are Squeezed Vertically
Closely Packed Elements Push Against
Each Other, Generate Horizontal Pressure
S1 (overburden)
S2
S3
S1 = Pp +
S2 = Pp + S3 = Pp +
Effective Stress - review
Randy Smith
Effective Stress Ratio
Overburden SV Stress
Pressure Required to Keep Water & Rock Grains from Squashing Out Horizontally P
Stress EffectiveOverburden Stress
=
Pore Pressure
SV = P + V Sh = P + h = P + K V
h
P
Sh
Total Stress
V
Pore Pressure
+
Effective Stress
h K= = Effective Stress Ratio; V “K” increases with ductility.
Empirical Linear Elastic Minimum Stress MethodsMethod S’hmin = K S’v S 0.3S - P P Hubbert and Willis 0.3
h min
h min
v
P
P
(1957) Mathews and Kelly (1967) Eaton (1969)
(K=0.3)
v
S h min
S h m in
K i ( z )S v
-
PP PP
h min
K i z
v
S v - PP PP 1 -
h m in
v
(K=0~1)
1
0~0.5, K=0~1; =0.25, K=0.33)
Zoback and Healy (1984)
S h min S v
-
-
PP
PP
2 1/ 2
1
-2
h min v
2 1/ 2
1
-2
0.6~1, K=0.32~0.17; μ=0.6, K=0.32)
Holbrook (1990)
S h min
1 - f S
v
PP
P
P
h min v
1-
f
f0~1, K=0~1; f=0.3, K=0.7)
Effective Stress Ratio, K K o - effective stress ratio 0.5
0
sands & sandstones
clays & shales
'
K
( 1
-
)
h
'
v
sh/sv sh/sv
depth
1.0
Fracture Gradient Calculation Terms and Definitions:
•Leak-Off Pressure (LOP): wellbore pressure at which fractures in the
wellbore wall will open and start taking mud. • Fracture Gradient (FG) : leak-off pressure equivalent mud weight. • Minimum Stress (MS): minimum in situ stress; fractures will try to
propagate perpendicular to the MS. • MSEMW: minimum stress equivalent mud weight. • Overburden Gradient (OBG) : overburden stress equivalent mud weight. • PPEMW: pore pressure equivalent mud weight. Equations (for tectonically relaxed basins):
MS = K (S V-PP) + PP;
MSEMW = K (OB-PPEMW) + PPEMW
LOP = K* (SV-PP) + PP;
FG = K* (OB-PPEMW) + PPEMW
Leak-Off Test
1200
Cement Pump
Pressure Gauge
Leak-Off Pressure (LOP)
1000
Shut-In Valve
Drill Pipe
Drilling Fluid
Rig Floor
Stop Pump Minimum Stress (MS)
) i s 800 p ( e r u s 600 s e r P
Shut-In Time
400
(Minutes)
BOP 200
Casing 0
0
2
4
6
8
Volume (bbls)
Cement
Fracture Formation
PFRAC = PLOT + Mud Hydrostatic Pressure in the well
10
FIT and LOT Interpretation
•There is NO relation between FIT and Sh! •For a LOT with no leak off the FIT could be <> Sh and up to almost Pb! •For a LOT with leak off the FIT could be <> Sh and up to almost LOP!
S1 (overburden)
The fracture plan is perpendicular to the weakest stress S3 Direction
S2
S3
Idealized Leak-off Test (LOT)
Fracture Propagation Theories
Events During Extended LOT
Types of LOTs
Near-wellbore stress concentration
Borehole Ballooning (“Breathing”)
Fractures open when pumps are turned on, resulting in loss of drilling mud. Fractures close when pumps are turned off, returning lost mud. Randy Smith
Constructing a Stable Wellbore
Examples of Drilling Challenges in Narrow Drilling Window Chevron : MC 713 (GoM East)
After Karpa, 2001
Allowable Mud Weight Range Mud Weights Sea Floor
• Must lie within the range bounded by:
Fracture Gradient
- Pore Pressure - Fracture Gradient
Casing Point
Casing • Used when mud weights must be increased
above shallow fracture gradients to keep
Mud Weight
pace with deeper pore pressures. Pore Pressure
Equivalent Mud Weight
Outline • • • •
Review of Sources of Abnormal Pressure Pressure Seals and Compartments Pore Pressure Indicators Quantitative (Petrophysical) Pore Pressure Estimation – Overburden Gradient – Conventional undercompaction analysis – “Advanced” topics: centroid/buoyancy, seal failure, unloading, basin modeling, tectonics
• Fracture Gradient • Wellbore Stability • Summary
