pore pressure basic level

Introduction to Formation PressuresCourse for Schlumberger, Sept 26-27, 2000A Division of Knowledge Systems, Inc.

Geopressure Systems - Introduction to Formation Pressures

1.92/162.4/22+2.34/22+2.05/172.2/18+2.22/192.3/19+1.92/162.16/18+2.37/222.34 = Pf in sg EMW19 = Pf in ppg EMWWorld-wide occurrence of abnormal formation pressures


Accurate PP prognosisBest PP evaluation while drillingRisk to EnvironmentRigtime Optim MWMud Casing ++Kicks BlowoutsWell CostsMotivations for Understanding Pore Pressures


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 levelPressure 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/mEffective Circulating Density, ECD -Mudweight + Additional effect of overcoming frictional forces in borehole during circulating - sg, g/cc, ppg, kPa/m


Pore Pressure Concepts (2)Formation pressures -Overburden pressure = weight of sediments + fluidsPore pressure = pressure of fluid in rock poresEffective stress = 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 pressureOverbalance/Underbalance -Relationship between mud hydrostatic, ECD and formation pressure


Origins of Abnormal Pressures (1)Undercompaction - most widely accepted mechanism:Pressure seal / Vertical permeability restrictionCompaction = consolidation + compressionConsolidation 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


Pf=0.0981*pfl*DVertical Depth, DFree water expelled as sediments compactSediment GrainsPore FluidWeight of overlying sediment supported via grain-to-grain contactFluid Pressure, PfRiver deltaSea levelHydrostatic Pressure during Normal Compaction


Hydrostatic PressureFree water expelled as sediments compactSediment GrainsPore FluidSome of weight of overlying sediment supported by pore fluidsSea levelAbnormal Pressure due to Compaction DisequilibriumAbnormal PressurePressure Transition ZoneVertical Depth, DFluid Pressure, Pf


300m1000m3000m = Expelled Water = Pore (free) Water = Interstitial Water = Clay75.9%73%20%4.1%20%20%20%80%13.3%66.7%RecentBurial(after Dickinson,Gulf Coast, 1953)Dehydration of Clays during Compaction


Depth = 8mDensity = 1.48 g/ccSolids = 33%Fluid = 67%Depth = 210mDensity = 1.97 g/ccSolids = 73%Fluid = 27%Depth = 100mDensity = 1.71 g/ccSolids = 52%Fluid = 48%Depth, mWeight, kg/m3Bulk density increase with burial


f=0.41e-0.000085DsComputed porosity decrease with burial, US Gulf Coast


A. Montmorillonite before diagenesisB. Removal of some pore and interlayer waterC. Loss of last interlayer water, Montmorillonite-> IlliteD. Final stage of compactionConversion of Montmorillonite to Illite via de-watering


During burial:1. Temperature increases - a. Fluid expands~ 220x10-6 v/v/degFb. Pore volume expands~ 3x10-6 v/v/degF2. Pressure increases -a. Fluid compresses~ 3x10-6 v/v/psib. Pore volume compresses~ 7x10-6 v/v/psi

Low volume systems - overpressure easily dissipated by leakageExample: Ameland, Holland; Middle East salt diapirsAquathermal pressures (1)


Origins of Abnormal Pressures (2)Osmosis:Movement of fluid through a semi-permeable membrane

Faults and Fractures:Conduits for pressures from deeper zones, orSeals 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


Osmosis - movement of water through semi-permeable membrane separating 2 solutions of differing densities, until concentration of both solutions is the sameFresh WaterSaline WaterSemi-permeable membranePossible mechanism for creating and maintaining abnormal formation pressures via osmosisP1P2P2>P1 but does not overcome osmotic pressureOsmotic pressures (1)


Pressure drainedPressure drainedOverpressured sandOverpressured sandOverpressured sandOverpressured sandNormally pressured sandFault seal can be created by: mineralization along fault face plastic formations - clay, salt etc attitude - reverse faults are often sealsFault can also be duct from deeper o-p systemFaults as pressure seals and drains


Paleopressured sandsSalt seals off sandsOsmosis effect because of salinity differencesSalt intrusion causes stresses in formations, and impermeability prevents drainage of pressuresSimilar 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 movement effects on pore pressures


A. Communication along faultB. Poor cement or damaged casingC. Leaking cement plugs in abandoned wellPressure leakage via faults or poor well seals


Potentiometric SurfaceANormal Pressure -Well elevation same as outcrop elevationPotentiometric SurfaceUnderpressure -Well elevation higher than outcrop elevationAPotentiometric SurfaceOverpressure -Well elevation lower than outcrop elevationAFlowing artesian wellBBBAquifer pressures and potentials (1)


3000m1500mContinuous aquifer 1.05sg water w/ 200bars overpressure(3000*1.05*0.0981)+100=409bars409/3000 = 0.1363 bar/m = 1.39sg EMW(1500*1.05*0.0981)+100=254.5bars409/3000 = 0.1697 bar/m = 1.73sg EMW3000m1500m100bars100barsP/Z=0.1697bar/mP/Z=0.1363bar/mHard overpressureSoft overpr.Geostatic gradientHydrostatic gradientPressure, barsDepth, mPressure gradients in reservoir with constant overpressure


Formation water, d= 1.03g/ccGas, d= 0.25g/ccOil, d= 0.80g/ccPg = Po + (0.0981*0.25*H2)Pw=0.0981*1.03*DFluid Pressure, Pf, barsPo = Pw + (0.0981*0.80*H1)DH1H2Effect of hydrocarbon buoyancy on reservoir pressure


Abnormally high aquifer pressure caused by presence of hydrocarbons in combination with a shale-outWater, 0.44 psi/ftOil, 0.30 psi/ft11,000ft TVD10,000ft TVDPB = PA + 140psieg N.Brae, Ula, Oseberg GammaInflated AquiferABEffect of hydrocarbon buoyancy on aquifer pressure


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


Pf=0.0981*pfl*DVertical Depth, metresFluid Pressure, Pf, barsFormation pressure increases normally with normal compaction sequence50010001500200025003000350040004500Pf at 4500m = 455bars = 1.03sgAssume system completely sealed at burial depth of 4500m, retaining normal Pf of 455bars, 1.03sg.Uplift because of faulting, etc.Pf at 3500m = 455bars = 1.325sgPf at 2000m = 455bars = 1.855sgPf at 2000m = 455bars = 2.32sgAbnormal pressures caused by uplift


ClayClayClayZone of higher pressure and permeabilityPreferential absorption of fresh waterRemaining water more saline Precipitation of carbonates and silicates at formation boundary creates permeability barrierFormation of cap-rock


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


Bit may drill through o-p 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.OverpressureNormal pressureN-pressureIf 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.OverpressureNormal pressureN-pressureABReaction times in A & B depend on differential pressure and shale rheology in overpressured zone.Tight hole, overpull/drag, fill (1)


Upward movement of pipe, eg on connection or trip, creates overpull as stabilisers and bit accumulate cavings.OverpressureNormal pressureN-pressureCOverpressureNormal pressureN-pressureDDownward 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.In these cases there is the danger of swabbing/surgingTight hole, over-pull/drag, fill (2)


Indicators of Abnormal Pressure (2)Gas:Drill gas (Background gas)Connection gas Trip gasPumps-off gasC2/C3 ratio

Temperature:Compare mud temperatures into and out of hole. Useless offshore

Cuttings/cavings:Easy to spot PDC cuttingsCavings - size and shape; splintery, 'rotor'-shaped


Gas, %Gas, %Gas, %Pm>>PfPm>=PfPm more rock/min -> more gas Gas response vs. borehole pressure differential (1)


+ + + ++ + + +- - - - - - - - Accumulation of cuttings/cavings on stabiliser blades prevents equalisation of pressures during pipe movement, resulting in pressure differential above and below stab.Frictional effects between mud and moving drillpipe create pressure differentials across annulus.Drillpipe moving upwards+ + + ++ + + +- - - - - - - - A similar situation can occur above and below bit, especially with bit balling or blocked jets.Formation fluids swabbed into boreholeA 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.Main factors affecting swab/surge pressures are pipe speed, mud gel strength and viscosity, mud filter cake, bit- and stabiliser balling, blocked bit jetsSwab effects when moving drillstring upwards


Gas, %Gas, %Gas, %Pm>>PfPm>=PfPm

DepthHeat FlowInsulating bodyIsothermsGeothermal temperature as indicator of overpressure (1)


O-p ZoneTemperatureIncreaseTemperature GradientPorosityUse of temperature data:1. Record MTI and MTO2. Plot end-to-end 3. Plot DT surface to surface4. Plot gradient factor5. Record all MWD and WL temps

Limitations:1. Changes in circulation rate2. Water depth offshore3. Additions to mud system4. Major lithology changes

Advantage:Not affected by many of factors affecting other o-p indicatorsFluid content in o-p shales > than in n-p shales. Thermal Cond water < Thermal Cond shale O-p zone is insulator and temp grad >> in n-p shalesGeothermal temperature as indicator of overpressure (2)


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 contact, eg less rounded. PDC cuttings have special character, easy to distinguish from cavings.SideFrontTopShale cavings resulting from underbalance

Concave cross-section, thin and spiky shape, may be striatedShale cavings resulting from relief of rock stresses during drilling - indicate excess lateral stresses in formation

Blocky, rectangular shape, often crackedSideFrontTopHole cavings as indicator of overpressure


Indicators of Compaction and Porosity (1)Acoustic velocity / Formation slowness, dT:Seismic (conventional, VSP, while drilling)Wireline (BHC, LSS) and LWDMicroseconds/foot, feet/second, meters/second'Quantitative, but:Gas effectInterval velocity interpreted for structure, not pressureCycle skipping and eccenteringResistivityShort normal, induction, propagation:Use deepest reading sensor - ILD (WL), DP (SS MWD) 'Quantitative, but:Conductive pore spaceSalinityTemperature


Indicators of Compaction and Porosity (2)DensityWireline and LWD: Reflected Gamma RaysStrong hole size effect:Need compensation curve for log qualityGenerally used only for overburdenDensity column:Individual cuttings; Technique sensitive; Not in situToxic fluids involved normallyNot 'quantitative' but useful to have

D-exponentDrill rate normalized for WOB, RPM, and bit diameterMud weight or ECD correctionCutter and bearing wear corrections exist:Complicated; Questionable accuracy; Generally ignoredBit type change necessitates trend line shift'Quantitative'


Original d-exponent from Bingham: R / N = a * (W / D) ^ dwhere:R= ROP in ft / minN = bit rotary speed in RPMW= WOB in poundsD= bit diameter in inchesa= "lithological" constantd= dimensionless compaction exponentJordan & 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 hourN = bit rotary speed in RPMW= WOB in tonnesD= bit diameter in inchesd-exponent does not account for: hydraulics, lithology changes, bit type, bit wear (although complex ways of accounting 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!

Calculation of drilling exponent, dx


Bit toothPm>PfFractures created by bit tooth actionBit tooth in contact with formationWith large overbalance, cuttings held on bottomPm=

Models and Methods for Quantifying Abnormal Pore Pressures

All based on Terzaghi Effective Stress concept from 1948Horizontal, trend-line methods:Eaton method for:ResistivitySonicD-exponentEquivalent depth methodRatio method

Vertical, Explicit methods:Bowers, Alixant; Rasmus; HolbrookConsider temperature effect


SvSySxS = Total external stressSv = (Overburden) Vertical StressSx, Sy = Horizontal StressesSsPfsHshTerzaghi Effective Stress Model s - matrix or effective stressPf - pore fluid pressuresh - minimum horizontal stresssH - maximum horizontal stressFormation Stresses and Pressures (1)


Terzaghi (1948):S/Z = s/Z + Pf/Z -----> S = s + PfS/Z = 0.8 - 1.05 psi/ftPf/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:sh = 0.6sv to 0.75svsH = 0.85sv to 1.2svFormation Stresses and Pressures (2)


Pf = S - s

Requires accuracy in OBG (S) and Effective Stress (s):OBG is usually straightforwardEffective 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 importantRegional OBG corrected for water depth Synthesize from seismic velocity via empirical formulae ->Gardner: Density(g/cc) = 0.23 Velocity0.25 (ft/sec)Methodology (1)


Overburden Stressr6Overburden Stress = Total Weight / in.2= 0.434(r1t1 + r2t2 + r3t3 + r4t4 + r5t5)r2r3r4t1t2t3t4t5Area = 1 in.2Weights (lbs. / in.2)r1r2r3r4r5Thickness (ft.)r5r1Density (g/cc)


Sediment Stress Calculation= 0.434*2.38*100= 7404 +103800081008200830084008500Rhob (g/cc)Depth (ft)


Sediment Stress vs Overburden Stresst1t2t3t4t5r1r2r3r4r5r1r2r3r4r5WD1WD2Depth Below Mud LineDepth Below Mud LineSediment Stress Depends on Depth Below Mud Line = 0.434(r1t1 + r2t2 + r3t3 + r4t4 + r5t5)Overburden Stress = Sediment Stress + 0.444*WD


Shale DiscriminationAll trendline-based methods attempt to quantify PP in shales where it is impossible to measure PP directly

Need clean, thick shales:Use GR in realtimeUse SP in post-wellRefine this using:Photoelectric effectSpectral Gamma RayCaliperDimensionless torqueNote:GR baseline often changes with hole sizeMethodology (2)


Normal Compaction Trend LinesAll 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, interpretationLeast squares fit of shale points sometimes appropriateMust account for log shifts, bit and hole size changesSingle or multiple trendlines depending on geological historyRegional trends sometime appropriateFor acoustic: seabed trend value = about 190 msec/ft (dT of seawater)Calibrate trends in real-time by using drilling info in relation to current MW/ECD:Gas - BG / CG / TG / etcHole condition - cavings / torq / fill / etcMud temperature and/or MWD tool temperature Kicks - a last resort!LOT - compare result against Frac Grad calculated using PPRFT-type data as it becomes availableMethodology (3)


Eaton's MethodPore Pressure from Resistivity (usually as gradient, not pressure)Pf = OBG - ((OBG - Pn) * (Ro / Rn)1.2)where:Pf = formation pressure gradientOBG= overburden pressure gradientPn = normal pore pressure gradientRo= observed shale resistivityRn= normal shale resistivity, from trend linePore Pressure from Sonic Pf = OBG - ((OBG - Pn) * (dTn / dTo)3)where:dTn= normal shale transit time, from trend linedTo= observed shale transit time

Pore Pressure from D-exponentPf = OBG - ((OBG - Pn) * (Do / Dn)1.2)where:Do= observed D-exponentDn= normal D-exponent, from trend lineEmpirical Methods for Calculation of Pore Pressure (2)


Equivalent Depth MethodEach 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 historyEmpirical Methods for Calculation of Pore Pressure (4)


Ratio MethodDifference 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.Empirical Methods for Calculation of Pore Pressure (5)


Sonic porosity trendSonic normal compaction trendlineResistivity porosity trendResistivity normal compaction trendlinePP from Eaton + ResPP from Eaton + SonicPP from EqDep + SonicPP from EqDep + ResMWOBGUse of porosity indicators


Very important to estimate fracture gradient in order to:1. Determine correct setting depths for casing strings2. Help evaluate quality of Leakoff Test by knowing expected result3. Determine the maximum mud weights allowed for each hole section while drilling4. Determine maximum allowable pressures while killing a kick5. Plan hydraulic fracturing program for a wellAttempt to define:pressure necessary to create or open fractures at the wellbore, orthe least principal stress, sx, in boreholeFormation Strength / Fracture Gradient (1)


Theoretical or empirical methods currently in use:Hubbert & Willis1957Pilkington1978Matthews & Kelly1967Cesaroni et al1981Eaton1969Daines1981Anderson et al1973Breckels & van Eekelen1982Christman1973Bryant1983Fracture gradient values affected by:In situ stresses - sX, sY, sZMud density, rheology and hydraulicsHole orientation and geometryFormation temperatureLithology and mineralogyFormation Strength / Fracture Gradient (2)


+ + + ++ + + +- - - - - - - - Drillpipe moving downwards+ + + ++ + + +- - - - - - - - Drilling mud flushed into formationPipe movement on RIH can result in pressure differential above and below stabilisers and/or bit, causing mud to be forced into the formation.Frictional effects between mud and moving drillpipe create pressure differentials across annulus.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.Surge effects when moving drill-string downwards


Hubbert & Willis, 1957:From lab tests; sX = 0.333sZ to 0.5sZ where sZ = total stress = overburden = 1psi/ftAs S = sZ +Pf, then sZ = S- Pf then Pfrac = 0.333*(S- Pf )+ PfsX later amended to between 0.25*sZ and 0.5*sZ, 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 *s+ 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.Estimation of Fracture Gradient (1)


Eaton, 1969:Replaced Ki with a value Kx derived from Poissons Ratio which also changes with depth -> Pfrac = (m/(1-m))*s+ 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 - (m/(1-m)) = 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.Estimation of Fracture Gradient (2)


s1 (maximum)Poissons Ratio, m (1)


Suggested values for m for different lithologies:Clay, very wet0.50Shale, calc0.14Clay0.17Shale, silty0.17Greywacke, fine0.23Shale, sandy0.12Greywacke, medium0.24 Shale, silic0.12Greywacke, coarse0.07 Shale, dolom0.28Sandstone, fine0.03Siltstone0.08Sandstone, medium0.06Limestone, fine0.28Sandstone, coarse0.05Limestone, med0.31Sandstone, coarse, cmtd0.10Limestone, shaly0.17Sandstone, clayey0.24Limestone, porous0.20Conglomerate0.20Dolomite0.21After Daines, JPT, 1982Poissons Ratio, m (2)


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 thisSafe MW margin created by setting 13 3/8 at 11000ftImportance of Fracture Gradient estimate (1)


SummarySeveral physical and chemical causes of earth stressesBurial processes, especially compaction, are the most importantUndercompaction is the most prevalent cause of overpressuresUndercompaction is detectable, most other causes are notShale is most prevalent sedimentary rockCompaction in shale is more readily observed than in other rocksThere are several indicators of over/underbalance while drillingMethods exist to quantify pore pressure based on shale analysisMethods exist to estimate fracture gradientGeopressure analysis improves optimization of casing and mud weight plans


Methodology for Geopressure AnalysisDetermine where shales are located.Obtain shale values in porosity sensitive measurement.Interpret shale porosity trends:- Normal compaction trend- Actual compaction trendObtain overburden gradientCalculate pore pressureCalculate fracture gradientCalibrate results using real measurements/well response


Drillworks/PREDICTWirelineLogMudLogMWDOffset WellsContinuousWave dTMeasurementfrom Cuttings SWD(Seismic-While-Drilling)VSPDrillWorks/BASIN

Basin Modeling and 3-D VisualisationRealtime Estimated/PrognosedPP for whole well EPPPPPData Flow


DrillWorks/BASIN


Geopressure Systems - Introduction to Formation PressuresGeopressure Systems - Introduction to Formation PressuresGeopressure Systems - Introduction to Formation PressuresGeopressure Systems - Introduction to Formation PressuresGeopressure Systems - Introduction to Formation PressuresGeopressure Systems - Introduction to Formation PressuresGeopressure Systems - Introduction to Formation PressuresGeopressure Systems - Introduction to Formation PressuresGeopressure Systems - Introduction to Formation PressuresGeopressure Systems - Introduction to Formation PressuresGeopressure Systems - Introduction to Formation Pressures

pore pressure basic level

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