Pore Pressure & Fracture Gradients

Click on the ‘speaker’ to hear presentation

By Tom Arnold

Why Do we Need to Understand Geo-Pressures?

DefinitionsPore Pressure - The pressure of the fluids within the pores of a reservoir, usually hydrostatic

pressure, or the pressure exerted by a column of water from the formation’s depth to sea level.

Transition Zone – impermeable rock cap topping an abnormal pressure zone that is

usually highly mineralized and well cemented with salt, calcite, anhydrite, etc.

Fracture Gradient -The minimum pressure required to break a formation at a given

depth in either a fresh water or salt water environment.

Mud Weight - Is the measure of the density of the drilling fluid which controls the

hydrostatic pressure in the bore hole. The drilling fluid is the medium which keeps formation fluids from entering the well bore.

Casing seat - The lowest point at which the casing is set. It is usually the WEAKEST place in

the hole in terms of the pressure needed to fracture the formation.

Overburden Stress -Pressure exerted on a point from the material over lying it.

Hydrostatic Pressure - Relates to the pressure exerted by a fluid at a given depth.

Swab - Pressure reduction in the well bore due to pulling the pipe. This can cause formation

fluids to be ‘sucked’ into the well bore starting the well to flow and creating a kick.

Surge - Pressure increase in the well bore due to running the pipe into the hole. If the surge is

high enough, the fracture pressure can be exceeded and an ‘under-ground’ blow-out is possible.

Pressure (PSI / PPG)

Depth

(TVD

)

Normal Pressure GradientsSalt Water: .465 Psi/Ft [9 ppg]Fresh Water: .433 Psi/Ft [8.33 ppg]> .433 psi/ft is Under Pressured

Transition Zone

Primary Causes of Abnormal Pressures

Rapid Deposition of Shale

Artesian Aquifer

Uplift, Erosion, & Intrusion

PsuedoplasticFormations

Fluid Density Differences & Hydrocarbon Generation

All abnormal pressures are created and maintained by the restriction of pore fluidmovement within a formation! These zones don’t have the freedom of pressurecommunications. If they did, the high pressures would rapidly dissipate reverting tonormal pressure.

Abnormal pore pressures are generated under rapid deposition because the shale matrix can’t support the overburden stress. Trapped water doesn’t have enough time to escape under these circumstances and is still helping support the overburden.

Rapid Deposition of ShaleThis situation occurs during flooding in rivers like the Mississippi. Rapidly depositing sediments into a continuous depositional basin like the Gulf of Mexico.

Artesian AquiferAquifer recharge is from an elevation higher than the drilling

location causing a very high formation pressure encountered at a shallow depth.

30

00

’7

00

0’ 1

00

00

’

Formation Pressure = (Total Vertical Displacement * .465 psi/ft * 19.23 )/ Depth of encounter

FP ppg = (.465 * 10000 * 19.23) / 7000FP ppg = 12.7

Erosion and Uplift Causes Under Pressured Reservoirs

Underpressured reservoirs are common is rocks that have subjected to uplift and erosion. Many fields in the western US are underpressured for this reason. The Keyes field in Oklahoma

produces gas from a depth of 5550 ft. Two evaporite seals are present, the Blaine Anhydrite at 1000ft. and the Wellington salt at 3000 ft. The extent of the underpressure in the Keyes sandstone at 5100 ft is 1305 psi or 4.9 ppg. Normal should be 2208 psi or 8.33 ppg.Final burial of the formation after deposition was 8113ft. It was uplifted by 3013 feet and encountered at 5100ft.

Under Pressure: 1305 PSI = (8113ft – 5100ft) * .433

Intrusion & Psuedoplastic Formations

Salt dome intrusions create situations where beds pressured at lower depths are pushed higher in the subsurface. Such situations will create underpressuredzones. Pressures here are determined in the same manner as those in uplift and erosion discussed earlier.

…another example of a cause of under pressured formation.

Fluid Density Difference & Hydrocarbon Generation

Bakken Reservoir9840 ft

8000 ft

6000 ft

11000 ft

14.1 ppg

8.33 ppg 15 ppg

Regional overpressured reservoirs are common in rocks that have been subjected to rapid burial and oil generation. Many fields in the Gulf Coast are overpressuredin this way.

The Bakken Field of the Williston Basin is a typical example of a locally overpressured oil reservoir.

The dense organic shale source rock has a central silty-sand interval that forms a reservoir. Local oil generation creates higher formation pressure and is the reason for the large overpressures of more than 14 ppg. at only 9800 feet. Normal would be 8.33 ppg.

Thick impermeable beds of shale or salt restrict the movement of water. These are called ‘transition zones’ and should be watched carefully while drilling! Below such beds abnormal pressure may be found.

More Considerations in Abnormal Formation Pressure

Hydrostatic pressure gradient is lower in gas or oil than in water.

More Considerations in Abnormal Formation Pressure

When crossing a fault it is possible to go from normal pressure to abnormal pressure in a short interval. Faults also will often ‘leak’ pressures into other formations causing another potential hazard.

More Considerations in Abnormal Formation Pressure

Here we see a formation charged with high formation pressure from a much deeper formation in an offset well. This is clearly human induced abnormal formation pressure!

More Considerations in Abnormal Formation Pressure

Underground Blow-Out{Fractured Formation}

Pressure

Dep

th

Dangerous and Delicate SituationConsider a scenario where you have crossed a transition zone and the pore pressure has risen to 14.5 ppg. The fracture pressure is 15 ppg at the casing seat. You have just taken a kick. The well is flowing salt water and the gas is rising steeply. Calculations show that you need a 14.7 mud weight to kill the kick. Coupled with the ECD, Equivalent Circulating Density, the effective mud weight at the casing seat, the WEAKEST PLACE IN THE HOLE, will be 15.1. The fracture pressure

at that depth is 15 ppg. What do you DO???This is a nightmare!

The answer is drop the pump rate and pump pressure to a point where the ECD is below the fracture pressure while pumping the kill weight mud. Kill the well and set a drilling liner or an intermediate casing! ..drill ahead, and hope you don’t cross anothertransition zone!

Often you will find a delicate balance between balancing the mud weight with the pore pressure and keeping the ECD below the fracture pressure at the casing seat or some other weak formation encountered while drilling.

Abnormal Pore Pressure IndicatorsSeismic Data (not discussed)Wire-Line Logs (separate module)Sloughing Shale & cutting sizeGasShale DensityChloride ContentPit Level and Volume

TemperaturePaleo InformationDrilling Rate‘d’ exponentNormalized Rate of Penetration

Indicator – Cutting Size and Sloughing Shale

The size of the cuttings coming out of the hole can be a very useful tool in the detection of abnormal pressure. Sloughing shale may be the result of the following hole conditions.

1. Formation fluid pressures are in excess of the hydrostatic pressure of the mud column.2. Hydration or swelling of shale3. Erosion caused by the fluid circulation or pipe movement.

In some situations the problems of sloughing, also called heaving, may be a combination of more than one of the above causes. For this reason the PML Surface Logger must always try to diagnose the cause.

Sloughing or Heaving shale associated with abnormal pressure is easily recognizable in the samples at the shale shaker. The size of the cuttings will increase and become larger than what you were seeing before. These shale cuttings become long and splintery or long and concave.

Indicator – Gas IncreaseGas cut mud has always been considered a warning signal, but is not necessarily a serious problem, Gas may enter the mud system as a result of any of the following:

1. Gas in shale (background gas)2. Gas from sands3. Connection gas4. Trip gas5. Gas that enters the mud due to

insufficient mud weight to control formation fluids.

Connection and trip gas are introduced into the mud by swabbing or just by the reduction in total annulus back pressure when the pump is stopped. Any increase in either of these types of gas should be watched carefully. It may be the result of abnormally high formation pressure. Both gases will show an increasing trend when entering abnormally high formation pressure.

Indicator – Mud TemperatureAs formation pressure rise, formation temperatures rise as well. Therefore paying close attention to flow-line temperatures is another important procedure when watching for abnormal down-hole pressures.

Indicator- Shale Density Shale density is one of the most reliable and best of the abnormal pressure detection methods.It is based on the assertion that the fluids and gas trapped between the shale platlets decrease the density of the cutting. Look at the plot below. There is a marked decrease in the density of the

shale from the normal trend line. This is a clear indicator of the rise in formation pressure due to the increased fluid and gas content in the shale.

The determination of shale density is defined by two methods upcoming.

totW66.16

33.8Gravity.Spec

1. Fill mud cup with shale until the weight is 8.33.2. Fill to top with water, and record the reading Wtot.

Note: Dry sample carefully with towel.

Do not apply heat.

Indicator- Shale Density (Mud Balance Method)

.

Indicator- Shale Density (Fluid Column)

A shale density column is composed of chlorotheneand bromaform. Both of the chemicals are toxic and cancer producers. Setting up the column takes practice and patience.

Indicator- Chloride TrendsChloride trends in the mud are not easily recognizable as changes in gas concentration. Methods of measurement make it more difficult to obtain information on chloride changes. Also, in many cases , the water in the mud is either brackish or salt water with a high level of salinity. A comparison of chloride trends both going in the hole and coming out of the hole may provide a warning of increasing pore pressure.

The theory behind chloride trends is when entering an abnormally high pressure zone, we enter a formation which is under-compacted. Comparing this information to those drilled at shallower depths, there is an increase of native fluid. Therefore, we should see an increase in chloride content in the mud system.

There are two methods that can be used to determine the mud chlorides. The first method is the same as the one used by the mud engineer. It involves adding a sample of drilling mud to a filter press and driving off the native fluid. By the use of titration and indicator chemicals, the chloride ion concentration can be determined. Or you can simply read the chlorides off the mud report!

The second method we will discuss next.

Indicator- Chloride Trends By knowing the resistivity and temperature of the mud, the chloride ion concentration may be determined.

Standard surface logging practice provides resistivity probes and temperature probes where these values may be determined.

Enter the chart at the bottom with the resistivity. Read up to the mud temperature. Then follow the slope to the top and read the chloride ion.

A copy of this chart is available for download on this site.

Indicator- Chloride Trends

Where:CH = chlorides in ppmT = mud temperature in Deg F from a probeR = mud resistivity from a probe

Then to convert to true NaCL equivalent we have:

NaCL = Ch * 1.65

If you are so inclined as to wish to make the calculation rather than bother with the TINY lines on the chart, here is the equation on which the chart is made.

Example for a computer or calculator:Temp = 175R = .0571072.3 PPM = ( ( (175 / .05 ^ -1.0185) / 201315.6) ^ (1 / -.971692) * 1.65)

Putting It TogetherHere is a typical response of several pressure indicators through a transition zone and into abnormal pressure.

Transition Zone

Temperature Chloride ppm Total Gas Pore Pressure

Indicator- Pit Volume Increase

Variations in the total mud volume can be monitored by pit level indicators. These devices monitor the level of the mud in the pits and tell us when mud is being lost into the formation or when fluids within the formation enter the well bore and the well starts flowing.

The first indication of a kick while going into the hole following a trip is the observation that a pit level increases in excess of the mud displacement by the pipe run into the hole.

HOLE FILL-UP: As the drill string is being pulled, the mud volume required to fill the hole should equal the pipe displacement. Keeping the hole filled is even more critical at the time the drill collars are pulled, since if the same length of collars as that of the drill pipe is pulled , the level of the mud in the hole will fall 4 or 5 times as fast. Furthermore there may be a temporary pressure reduction while the string is pulled due to the bit being balled, high mud viscosity, thick mud cake……

If salt water, oil, or gas, or a combination of the three, from the formation has entered the well bore, the mud volume required to fill the hole will be less than the volume of the pipe pulled and gives the first indicator of a kick. The amount of mud required to fill the hole can be monitored by the number of strokes required to fill the hole.

------ MORE ------

Indicator- Pit Volume IncreaseAny abnormal rise in pit level by the mud flow from the annulus will also be reflected in an increased flow rate, which can be measured by a standard flow-meter. Actually, a flow rate measurement is superior to pit level checks since small flow rate increases can be detected before they become sufficiently large enough to show on any pit level device. If such small flows are noticed immediately, they are not as critical at this point and there is still time available to take proper control measures.

Pits

Indicator- Paleo Data

Abnormally high pore pressures are frequently related to certain environmental conditions within given geologic time periods of deposition. Formations are marked, depending on the depth of the water during a particular stage of deposition, by the presence of certain fossils. People who work with paleo information, -bug hunters-, examine samples from the well bore looking for these fossils. Encountering certain fossils reveal the potential problem of entering abnormally high formation pressures.

PHYD - PPORE , psi

Indicator- Drill RateDrilling rate alone is an important indicator of abnormally pressured formations. Seen below, as the pressure in the well bore is reduced, the drilling rate will increase. This is the foundation of this procedure as well as ‘d’ exponent and Normalized Rate of Penetration. The latter two procedures will be discussed in great depth later.

Decrease can be due to:• Chip hold down effect•Well bore pressure on rock strength

Differential Pressure is the difference between wellbore pressure and pore pressure.NOTE: Drilling

underbalanced can INCREASE drilling rate!

The drilling rate in a normally pressured, solid shale section will generally generate a very steadyand smooth drilling rate curve.

The penetration rate will be steady and not erratic (normally pressured, clean shale).

Indicator- Drill Rate

Typical drilling rate profile in shale.

Indicator- Drill RateAny deviation from the expected decrease in drilling rate

with depth, when you are drilling in a clean shale, might

indicate a transition zone.

Note:If you are drilling overbalanced in a transition zone, it will be very difficult to pick up the transition zone initially. This will allow you to move well into the transition zone before detecting the problem.

This could cause you to move into a permeable zone which would probably result in a kick. The conditions you create with overbalanced hydrostatic head will so disguise the pending danger that you may not notice the small effect of the drilling rate curve change. This will allow you to move well into that transition zone without realizing it.

Disastrous!

Pore Pressure Prediction MethodsGeneral Comments

1. Most pore pressure prediction techniques rely on measured or inferred porosity.

2. The shale compaction theory is the basis for these predictions.

3. All measurements of the porosity indicator (density) must be done in NORMAL, clean shales in order to establish a NORMAL trend line. Trends are THE key part of abnormal pressure detection.

4. When the indicator suggests porosity values that are higher than the trend, then abnormal pressures are suspected to be present.

5. The magnitude of the deviation from the normal trend line is used to quantify the abnormal pressure.

34

2. Extrapolate

normal trend line

1. Establish “Normal” Trend

Line in good “clean” shale

Transition

Porosity should decrease with depth

in normally pressured shales

3. Determine the

magnitude

of the deviation

Establishing a Normal Trend

What is meant by a TREND line?

Trend lines are plotted on semi log paper by increasing depth: 1”=100”. Divisions are labeled according to the type of measure.

Trend lines are KEY in evaluation of ‘d’ exponent, Normalized Rate of Penetration, and other prediction methods!

Older shales have had more time to compact, so porosities would tend to be lower (at a particular depth).

Use the trend line closest to the transition.

Lines may or may not be parallel.

Establishing a Normal Trend

d

bd

WNKR

3

Indicator – ‘d’ Exponent

The theoretical base for the quantitative method for abnormal pressure detection using drill rate and engineering mechanics is:

Where:R = Penetration Rate K = Formation DrilliabilityN = Rotary SpeedW = Weight on Bitb = Bit Diameterd = Weight on Bit Exponent (‘d’-exponent)

Indicator – ‘d’ Exponent

in Diameter,Bit D

lbf ,Bit WeightW

exponentdd

rpmN

ft/hrR

10

12log

60log

6

D

WN

R

d

The d-exponent normalizes R for any variations in W, db and N

Under normal compaction, R should decrease with depth. This would cause d to increase with depth.

Any deviation from the trend could be caused by abnormal pressure.

Mud weight also affects R…..

An adjustment to d may be made:

dc = d (rn /rc)

where

dc = exponent corrected for mud density

rn = normal pore pressure gradient

rc = effective mud density in use

Indicator – ‘d’ Exponent

While drilling in a Gulf Coast shale,

R = 50 ft/hr

W = 20,000 lb

N = 100 RPM

ECD = 10.1 ppg (ECD)

D = 8.5 in

Calculate d and dc

Example

34.1d

554.1

079.2

5.8*10

000,20*12log

100*60

50log

d

6

19.1d

1.10*052.0

465.034.1d

c

c

D

WN

R

d

610

12log

60log

r

r

c

nc dd

Indicator – ‘d’ ExponentPlotted example of ‘d’ exponent data in the table.

Normal ‘dx’ Trend Line

‘dx’ indicated transition zone

Notice how the ‘dx’ breaks left from the normal trend line indicating the transition zone.

Should a new trend beEstablished or is this atransition zone?

gp = gn (dcn/dco)

gp = 0.465 * (1.18/.95)

gp = 0.578 psi/ft

rp = 0.578/0.052

rp = 11.1 ppg

Indicator – ‘d’ ExponentHow to determine the Pore Pressure from the ‘dx’ trend line shift.

Normal hard rock gradient = .465 psi./ft.Normal ‘dx’ trend = 1.18Observed ‘dx’ = .95

0.95 1.18

Indicator – ‘d’ Exponent

This is a pore pressure overlay. A copy is available for download from the PML training web site.

When creating a pore pressure plot be carful that the scale is correct for the graph paper being used. Plot using 1”=1000’. Be sure the slope is correct for normal trends. You must also be sure that the overlay is correct for the formation.

Indicator – ‘d’ Exponent

Improvements in Pore Pressure prediction.Try to keep the weight and rpm relatively constant when making measurements

Use donwhole (MWD) bit weights when these are available. (Friction drag in directional wells can cause LARGE errors.

Add geological interpretation when possible.

Keep in mind that tooth wear can greatly influence penetration rates.

Use common sense and engineering judgment.

Use several techniques and compare results.

Indicator – Normalized Rate of Penetration (NROP)

Normalization Considerations

•Lithology•Formation compressive strength variations•Bit Weight•Rotary Speed•Tooth Wear•Hydraulics at the face of the hole•Differential Pressure

The normalization process eliminates the influence of these variations with the exception of Differential Pressure.

Affect of WOB on ROP

PR ~ N

Where: N = Bit Weightλ = Rotary Exponent

λ

Where: W = Bit WeightM = Threshold Weight

PR ~ Sp

HHP =

Where: Q = Flow RatePB = Bit Pressure Drop

d = Bit Size

PR ~ W – M

HHP =AVERAGE VALUES OF M AND λ

DEPTH M λ0-9000- 5000 lbs. .69000- 11000 0 lbs. .611000-25000 5000 lbs. .6

PRn = PRo X X X

Equation for Normalized Rate of Penetration

Note: Values subscripted n refer to ‘normal’ ValuesSubscripted o refer to actual or ‘observed’ values.

Pr = Penetration RateW = Weight on BitM = Weight on bit exponentN = Rotary Speed (rpm)PB = Pressure Drop at BitQ = Flow Rate (gpm)

λ = Rotary Exponent

X X

PRn = 16 x (.8333) x (.9117) x (1.374)PRn = 16.7 ft/hr

PRn = 16 X

Constants: M = 5000 lb.s

λ = .6

NROP ExampleNORMAL CONDITIONS - Wn = 30000 Lbs.

Nn = 150 RPMPBn= 1500 psiQn = 250 gpm

OBSERVED CONDITIONS - PRo = 16 FT/HR Wo = 35000 Lbs.No = 175 RPMPBo = 1300 psi Qo = 210 RPM

NROP vs DEPTHThe vertical scale (ordinate) is for depth and should be linear. It should be the same as the depth scale on any correlation logs being utilized.

NOTE: The normalized penetration rate plot is an excellent lithology log and is very useful for geologic correlation.

Normalized penetration rates for each interval are plotted, and the points connected to create a continuous curve.

Consulting the composite curve (Vidrine & Benit) for percent decrease versus differential pressure at a δP of 728 psi: yields a percent decrease of 46.5%. This means that penetration rates achieved while drilling 728 psi overbalanced are reduced 46.5% from the rates which would have occurred if the drilling was done at exact balanced conditions.

Utilizing the extrapolated dulling trend to determine the penetration rate which would have occurred if the formation pressure had not changed, yields 13.5 ft/hr.

% Decrease vs Differential Pressure

=

X = 25.23 ft/hr

%DECREASE = X 100

X 100

%DECREASE = -10.98%

The negative % decrease means drilling is proceeding at a rate faster than would be expected at zero differential pressure. This means drilling is underbalanced. The formation pressure is greater than the ECD.

% Decrease vs Differential Pressure

Formation Pressure =ECD - X 19.23

Formation Pressure = 10.7 ppg

X 19.23

Determine Pore Pressure

-10.98

-160 psi

% decrease from calculation

Plotted Example

Following along with the example plot a deviation from the dulling trend is noted to occur at approximately 10100 ft. This penetration rate is seen to be higher than expected according to the dulling trend, reflecting an increase in formation pressure.

The calculation of the magnitude of formation pressure is made at 10200 ft. where an actual penetration rate of 27 ft/hr is observed.

This procedure, with the special considerations discussed, can be utilized to maintain differential pressure at a desired value throughout the drilling of a well. Mud weights can be properly maintained, casing points located, differential sticking and lost circulation minimized, and penetration rates maximized, all without the necessity of prior knowledge of the Geologic section or Geographic area. However, the most attractive aspect of this procedure, in the author's viewpoint, is the large response to relative small increases in formation pressures. There should never again be heard "We got kicked and none of our indicators showed anything - we got no warning at all".

Conclusion