OverpressurePrediction, Detection and ConsequencesTraining course

Module 2Quantifiable Pressure Detection

Key Terms

Overburden GradientDxCNormal Compaction TrendCutbackShiftEatonFracture PressureDainesPoissons Ratio

Overburden

This equation forms basis of all pressure engineeringOverburden Pressure

Terzaghi model

Subsurface Pressure Trends

Log Response for Normal Shale Compaction

Applicable LithologiesBest Indications - Shales / ClaystonesLow Permeability, affected by compaction.Small matrix particles retard pore fluid flow.Allows part of overburden to be supported by the pore fluid.

Poor Indications - Sands, Silts, Limestones, DolomitesPoor pressure trap when compacted.LS / Dol - Dependent on solution and chemical processes.

FormationPressureProfile

Typical North Sea Formation Density FiguresSG to PPG = SG x 8.345PPG to PSI/FT = PPG x 0.052

Overburden Calculations # 1The calculation of OBG is a 3 stage process First, an interval overburden is calculated which is the total mass of sediments within an interval. (Si)Secondly, a total overburden is calculated for a given point which is the sum of all intervals above that point.(Si)Thirdly, the Overburden Gradient is calculated which is the Total Overburden per unit depth. (So)

Overburden Calculations # 2Density Sources For Overburden Calculations

LWD or Wireline Formation Density

LWD or Wireline Sonic Calculated Density(Sonic log transit times are Calculated from the AGIP formula)

SDL Measured Shale Density

Overburden Calculations - FormulaSi = b x 0.433 x DIWhereSi = Interval Overburden in PSIb = Interval density in SG0.433 = Conversion ConstantDI = Depth of interval in FeetSo = (Si) / DWhereSo = Overburden Gradient in PSI/FTSi = Cumulative SiD = Vertical Depth

Overburden Calculation Question 1A rig has an air gap of 98 ft and a water depth of 348 ft. What is the Overburden Gradient at the sea bed?Give your answer in psi/ft, ppg-EMW and SG.The density of sea water is 1.04 SG.

Overburden Calculation Answer Q1Two intervals exist, air and water.Given that air has a negligible density, then Si has to be calculated for the water only.Using: Si = b x 0.433 x DI, thenSi = 1.04 x 0.433 x 348 = 157 psiSo is calculated for the whole interval (air and water).Using: So = (Si) / DSo = 157 / 446 = 0.35 psi/ft0.351 psi/ft = 6.75 ppg Emw = 0.81 SGPsi/ft / 0.052 = ppgPpg / 8.345 = SG

Overburden Calculation Question 2A rig has an air gap of 98 ft and a water depth of 348 ft, the well has been drilled to a depth of 1000 ft. Calculate the overburden for the drilled interval(in psi)? Also calculate the Overburden Gradient at TD?

The density of sea water is 1.04 SG.Average formation density is 1.8 SG

Overburden Calculation Answer Q2The drilled interval is 554 ft and has a density of 1.8 SG.Using: Si = b x 0.433 x DI, thenSi = 1.8 x 0.433 x 554 = 432 psiSo is calculated for the whole interval (air, water & rock).Using: So = (Si) / DSo = (157 + 432) / 1000 = 0.59 psi/ft0.59 psi/ft = 11.35 ppg Emw = 1.36 SGPsi/ft / 0.052 = ppgPpg / 8.345 = SG

Overburden Calculations from Sonic LogsIf actual density data is not available then it can be calculated from Sonic Transit times.Sonic Transit time data is often available more readily and for more hole sections eg top hole.Always use density data if available.

AGIP Formulab = 2.75 2.11 ((ET 47) / (ET + 200))For unconsolidated formations

b = 3.28 (ET / 89)For consolidated formations

Where: b = Formation density in SGET = Sonic Transit time in sec/ft

Gaps in Sonic DataIf gaps exist in sonic data, it is possible to extrapolate between existing data.Remember near surface (where data is often missing) the sonic values become high as the formation becomes less compacted.

Dc Exponent

DEVELOPMENT OF THE DRILLING RATE EQUATION Rotary SpeedWeight on BitHydraulicsTooth EfficiencyDifferential PressureOverburden PressurePore PressureDrillstring Effects / TorqueMatrix StrengthLithologyDrilling rate is a function of the following parameters

Rotary SpeedTheoretically Rotary Speed would be directly proportional to Drill Rate.In Practice this is not so and the relationship is none linear.-Imperfect hole cleaning due to overbalance(chip hold down effect)-Insufficient circulation rates

Weight on BitIncludes variations in bit size, tooth shape / distribution, actual WOB and threshold weight.Threshold weight is the minimum weight at which the bit will commence to drill.Soft formation can be drilled by jetting action alone i.e. zero weight.Again as for RPM as WOB increases the initially linear relationship with ROP is diverged from due to insufficient hole cleaning

Tooth EfficiencyEfficiency of the original cutting structureThe minimum effective cutting structureThe rate at which the bit will lose its efficiency

A dull bit can mask changes in drilled formation.

HydraulicsPump pressureNozzle sizeNozzle typeMud rheology

If too little hydraulic action is applied then bottom hole cleaning will be reduced. Excessive hydraulic action will increase jetting action

Differential PressureDifference between mud hydrostatic and formation pressure ie OverbalanceAffects hole cleaning, a high Differential pressure tends to hold cuttings to the bottom of the well.

Overburden PressureIncreased depth of burial results in increased compaction, and hence increased compressive strength. This results in a slow decrease in bit performance with depth.

Pore PressureDrill rate increase with pore pressure

Drillstring EffectsChanges in Torque, maybe even vibration, energy is spent vibrating and not drilling, hence lower ROP.BHA design

Matrix StrengthOther wise known as DrillabilityResistance of formation to failure or chipping

Rock Bits Drill by Impact Fracturing

LithologyMatrix strength varies with rock type, and so lithology changes may considerably affect ROP.

Drilling Rate Equations

D ExponentDrillability Exponent

R = ROP (ft/hr)N = RPMW = WOB (lbs)D = Bit Size (ins)

d exponent is not compensated for mud weight, SPP (ie hydraulics), and bit wear. These variables should therefore be kept as constant as possible.

Dc ExponentCorrected D Exponent

dc = modified d ExponentMW1 = Normal Hydrostatic PressureMW2 = Mud Weight (pref. ECD)Pn = MW1

Either ppg or SG

or

DxC CalculationGiven the following information calculate the DxC. Assume you are drilling a well in the North Sea.ROP = 50 ft/hrRPM = 40WOB = 10 KlbsHole Size = 12.25ECD = 10.0 ppg

DxC AnswerFirstly Calculate D Exponent, use:

This gives a D Exponent of 0.84.Correcting to DxC, use:

Gives a DxC of 0.73Note: DxC is unitless

DxC LimitationsWhere the overbalance is very high the correction to the D exponent is large, values become low and vary little.Dc is a valid indicator of undercompaction in impermeable, but porous formations, undergoing increasing compaction with depth. So use for Shales, clays, arg. siltstones, calc. claystones.

DxC Limitations #2Does not show trend is sand (grain supported)Siltstones may or may not be grain supported, perhaps grading from one to the other.Carbonate deposits, such as limestone stringers shift trend to right, but also may be seal to overpressured zone.Calcareous claystones shift trend to right, % of calcareousness affecting degree of shift. (compare to calcimetry results)

Schematic DxC Response

DxC Limitations #3Equations are based on rock bits, not more modern PDC bits etc.Equations do not allow for changes in hardness and abrasiveness in lithology. It assumes for example that all claystones are uniformThe use of mud motors or turbines and the affect they have on drillability is not factored into the equationIn high angle wells, energy dissipation alters with much more energy being used to overcome well trajectory / drillstring component interaction. Eg the driller may show 40 Klbs WOB, but only 10 Klb gets to the bit

DxC Response to Bit Wear and Type

Use of DxC #1Dont use instantaneous values for calculation, average to 1 ft or 0.5 m.Start recording data as soon as possible ie Spud. Values to start with will be for soft surface rocks. But this ensures you will get data for the start of compacted strata at around 1000 ft (offshore).Display on a condensed scale 1:2000 to 1:5000Use a linear vertical scale and a logarithmic horizontal scale.

Use of DxC #2It may be easier to spot trends if individual data points are plotted opposed to curves.Use TVD if possible.Use lithology / gamma to base analysis on areas of claystone.

Use of DxCCompact, linear vertical scaleLogarithmic horizontal scaleResistivity0.22TVDD Exponent0.2213000140001500016000170001800Resistivity0.22TVDD Exponent0.22

Quantitative Pore Pressure AnalysisThree phases are required to allow pore pressure estimates from DxC data.

Shifting of the DxCFitting of a Normal Compaction Trend (NCT)Production and fitting of overlays*

*Overlays are best calculated by PC, we shall only calculate actual pore pressure estimates by hand. The principal is the same.

DxC Trend Shifting

Normal Compaction TrendsDxC trend should increase with depth. (as will Resistivity and Density)Trend shift to left, in lower half of plot, indicates increase in undercompaction and therefore, overpressure.

Overlay CalculationOverlays are dependent on position of NCT.Two main methods existRatioEaton

In both methods Dc normal is the NCT value at that depth. This would represent the DxC value if pore pressure was normal at this depth. Any deviations may be overpressure.

Ratio Method

Use formula:Where:Po = actual pore fluid pressurePn = normal pore pressure dco = observed dc exponent dcn = dc exponent from normal trend

Eaton MethodThe Eaton method is more widely used and more accurate.Requires Overburden Gradient.Can be used for DxC, Sonic and Resistivity data (Differing forms of equation for each)

Eaton Formula

P = So ((So Pn) (Dco / Dcn)1.2)Where:P = Formation PressureSo = Overburden PressurePn = Normal Pore PressureDco = DxC ObservedDcn = DxC from NCT

Note the 1.2 is the beta factor and may change Note units are psi/ft, ppg or SG for pressures

b ExponentThe b exponent value of 1.2 is not fixed. If a more accurate figure is available use it.Using the Eaton equation, if the actual pore pressure is known, from a kick or RFT then a more accurate figure may be back calculated.Also using this same principal if b is taken as correct and the actual formation pressure is known the Dcn can be recalculated.

Pore Pressure Calculation using Dxc / Eaton Given that this well is vertical the formation is shale and no shifts are required to the DxC Using the DxC Trendline graph draw an NCT onto the graph.At a depth of 1500 ft estimate values for Dco and DcnGiven that the OBG is 1.0 psi/ft at this depth what is the pore pressure here?Give your answer in ppg EMW.

Pore Pressure Calculation - AnswerAnswers may vary (slightly)Draw trendlineThis gives Dco of 1.8, Dcn is 1.2 at this depthUse the Eaton Equation: P = So ((So Pn) (Dco / Dcn)1.2)P = 1 ((1-0.45) (1.2 / 1.8) 1.2) = 0.66 psi/ft12.7 ppg EMW

(0.66 / 0.052)

Fracture PressureKnowledge of the magnitude of formation fracture gradients is vital, especially when drilling into an abnormally pressured zone. Formation fracture gradient determines the maximum allowable mud weight that can be used (after incorporating an operational safety factor).

Mechanism of Formation FractureA formation can be made to fracture by the application of fluid pressure to overcome the least line of resistance within the rock structure. Normally fractures will be propagated in a direction perpendicular to the least principal stress. Which of these three stresses is the least can be predicted by the fault activity in the area.

Stress Planes in Rock Formation

Leak-Off Test

Fracture Pressure Estimates Whilst DrillingA L.O.T / F.I.T only gives you a value for Fracture pressure at the shoe.As drilling continues down through new formations the Fracture Pressure will alter depending on lithology, faults, fractures etc.Where Fracture Pressure is critical i.e. on overpressured wells where you need to keep the mud weight high, but dont want losses.

Fracture Pressure GraphGraph shows 2 estimated fracture gradients, pore pressure and Overburden.Note the relationship between them in terms of magnitude.

Methods of Fracture GradientHubbert and WillisEatonMathews and KellyAnderson et alDaines

DainesDaines states that there are two unequal horizontal stresses which must be overcome before fracturing occurs.1That caused by the weight of overlying sediments (h)2A superposed tectonic stress (T)Proof that this tectonic stress exists is evidenced by folding, faulting, etc, which rely on unequal stress states for their occurrence and maintenance.

Daines FormulaFP = T + ((S P)(( / 1- )) + P)Where:FP = Fracture Pressure = Poissons RatioT = Superimposed Tectonic StressS = Overburden PressureP = Pore PressureUnits ppg EMW, SG or psi/ft

Superimposed Tectonic StressT is calculated from the first LOT on drilling. It is regarded as being constant for the rest of the well.T = LOT - ((S P)(( / 1- )) + P)

Poissons Ratio

Fracture Gradient Calculation - QuestionUse the Daines method.Calculate the Fracture Gradient at 7000 ft.The formation at the LOT was claystone.The formation at 7000 ft is siltstone.

Frac. Grad. Calc. Answer #1 Calculate T Use: T = LOT - ((S P)(( / 1- )) + P)LOT from graph = 9.5 ppg EMWPoissons Ratio at LOT = 0.17Overburden at LOT = 11.0 ppgPore Pressure at LOT = 9.0 ppgT = 9.5 ((11 9)(0.17/1-0.17) + 9) = 0.09

Frac. Grad. Calc. Answer #2Calculate Fracture GradientUse: FP = T + ((S P)(( / 1- )) + P)Overburden at 7000 ft = 15.0 ppg EMWPore Pressure at 7000 ft = 9.25 ppg EMWPoissons Ratio at 7000 ft = 0.08T = 0.09FP = 0.09 + ((15 9.25)((0.08/1 0.08) + 9.25)FP = 9.84 ppg EMW

End of Module Summary Key Terms

Overburden GradientDxCNormal Compaction TrendCutbackShiftEatonFracture PressureDainesPoissons Ratio

PanCanadian Energy Corporation PanCanadian Energy Corporation PanCanadian Energy Corporation PanCanadian Energy Corporation