1 - Drilling Technology - Gradients

PRESSURE GRADIENTS

WELL PLANNING PURPOSE OF THE WELL PLANNING • • •

The primary purpose of the well plan is to provide guidelines for the safe and efficient drilling and completion of the well. A secondary, but important purpose, is to provide a reasonably accurate time and cost estimate. estimate The third purpose of the well plan is to drill a hole that is usable once drilling is finished. This will be the automatic result after a well-thought-out plan is created and followed.

Important topics: • • • • •

Casing Point Selection Casing Design Mud Density Fracturing Gradient Drilling Rig Selection

Where does the well plan come from? The well p plan is a p product of many y different p people p in the oil company. p y

Team Members Geoscience Department

Engineering Department



Geophysicist



Drilling



Geologist



Production



Reservoir

Operations Department

Support Department



Drilling manager



Loss prevention – safety



Drilling superintendent



Environmental



D illi supervisor Drilling i



P h i Purchasing



Drilling coordinator

Contents of a well Plan • Well summary 1.Drilling g and g geological g p prognosis g 2.Drawings a.Well schematic b.BOPs and manifold c Wellhead c.Wellhead d.Location e.Structural map 3.Pore pressure analysis 4.Type log 5.Drilling time curve 6.Drilling cost curve and estimate or AFE 7.Support a.Vendors list b.Transport c.Communications 8.Directional plan

• Drilling procedure 1 Location / pre-spud 1.Location pre spud 2.Conductor hole 3.Surface hole 4.Intermediate hole 5.Production hole 6.Completion 7.Standard p procedures 8.Abandonment

Contents of a well Plan • Drilling parameters 1 Mud program 1.Mud 2.Drilling mechanics 3.Bits a.Weight and RPM b.BHA / drillstring c.Hydraulic program 4.Casing gp program g 5.Cement program 6.Well control program 7.Wellhead equipment 8.Rig specs 9.Logging, coring, and testing 10.Emergency procedures a.Hurricane procedures b.Fire drills and rig evacuation c.Blowout control procedures

DRILLING TIME CURVES 0

Phase 16"

csg 13 3/8 3/8" 500

Depth vs. Time

Phase 12 1/4"

csg 9 5/8" 1.000

Phase 8 1/2"

1.500

2.000

csg 7"

2.500 0

5

10

giorni

15

Well Testing

20

25

Types yp of casings g

    

Conductor pipe Surfaces Intermediate Production Liner

Most common diameters The normal dimensions of the casing or liner and in which open-hole they are run-in are shown below; the dimensions are g given in inches:

casing/ liner dimension (inches)

open-hole dimension (inches)

20 20” 18 5/8” 13 3/8” 9 5/8 5/8” 7” 5”

26 26” 24” 17.5” 12.25” 5 8.5” 6.5”

CONDUCTOR PIPE Setting depth is usually shallow, from 24 to 50 m. (80 to 150 ft) and selected so that drilling fluid may be circulated to the mud pits while drilling the surface hole. The casing seat must be in an impermeable formation with sufficient ffi i t fracturing f t i resistance i t to t allow ll fluid fl id tto circulate i l t tto th the surface. Large sizes (usually 16 to 30 in.) are required as necessary to accommodate subsequent required strings.

SURFACE CASING Setting depth should be in an impermeable section below fresh-water formations. In some instances, near-surface gravel or shallow gas may need to be cased off. The depth should be great enough to provide a fracture gradient sufficient to allow drilling to the next casing setting point and to provide reasonable assurance that broaching to the surface does not occur in event of closure on a kick kick. In hard-rock areas the string may be relatively shallow, from 90 to 240 m. (300 to 800 ft), but in soft-rock areas deeper strings are necessary. Surface casing setting depths are often specified by government regulatory bodies to protect fresh-water sands.

INTERMEDIATE CASING A protective string may be necessary to case off lost circulation, salt beds, or sloughing shales. In cases of pressure reversals with depth, depth protective casing may be set to allow reduction of mud density. The most predominant use is to protect normally pressured formations from the effects of increased mud density needed in deeper drilling. drilling It is sometimes necessary to alter the setting depth of the intermediate casing during drilling if: •hole problems prohibit continued drilling •pore pressure changes occur substantially shallower or deeper than originally calculated or estimated

PRODUCTION CASING Production casing is used to isolate production zones and contain f formation ti pressures in i th the eventt off a tubing t bi leak. l k It is set into the reservoir and may also be a liner. A good primary cement job is very critical for this column. Liner Liner is a casing g string g that does not extend back to the wellhead, but is hung from another casing string. Liners are used instead of full casing strings to: • Reduce cost • Improve hydraulic performance when drilling deeper • Allow the use of larger tubing above the liner top • Not represent a tension limitation for a rig Liners can be either an intermediate or a production string. Liners are typically cemented over their entire length.

PRESSURES AND PRESSURE GRADIENTS Importance of knowing formation pressure gradients While Drilling: •

• • •

To use adequate mud density: > to avoid kicks o blow-outs > To avoid mud absorption and/or mud loss circulation > to avoid sticking of drilling string for differential pressure > to avoid sticking of drilling string due to caving hole > to reduce drilling times To change change, in case of need need, the casing point depth while drilling drilling. To reduce the drilling problems and reach the planned well depth. To cut drilling costs.

PRESSURES AND PRESSURE GRADIENTS

• Pressure and “HYDROSTATIC HYDROSTATIC Gradient” Gradient . • Pressure and “OVERBURDEN Gradient”. • “Pressure of COMPACTION”. • Pressure and “FORMATION FORMATION Gradient” Gradient .

HYDROSTATIC PRESSURE Hydrostatic pressure at a certain depth is defined as the pressure exerted by the weight of the fluid column with a given density.

f  H P  10

where

P = hydrostatic pressure expressed in kg/cm2 H = examined depth expressed in meters  f = fluid density expressed in kg/dm3, usually for water assumed to be equal to 1 1.03 03 kg/dm3

Hydrostatic Pressure Gradient Pressure Gradient is defined as a ratio of pressure value and depth:

G

hyd



P H

 10

where: Ghyd = hydrostatic gradient expressed in kg/cm2/10m P = pressure expressed in kg/cm2 H = examined depth in m

OVERBURDEN PRESSURE SEDIMENT PRESSURE or GEOSTATIC PRESSURE or OVERBURDEN PRESSURE is the pressure exerted on bottom of a vertical column by the weight of sediments of a certain density, that extends from the surface to the considered depth. 2 by It’s expressed p in Kg/cm g y use of the following g formula:

POV 

 Sed  H 10

where: POV = overburden pressure expressed in kg/cm2 H = examined depth expressed in m sed = average sediment density expressed in kg/dm3

SEDIMENTARY ROCK DENSITY The sedimentary rock density (bulk density) is given by of the density of the matrix ( lid part) (solid t) multiplied lti li d b by plus l th the d density it off th the flfluid id contained t i d iin itits pores b by th the rock k porosity:

sed =  f + (1 - ) m where: sed = sediment density (bulk density) in kg/dm3  = rock porosity expressed as a ratio 3 m = matrix densityy expressed p in kg/dm g f = fluid density contained inside pores expressed in kg/dm3

OVERBURDEN GRADIENT - GOV •

The OVERBURDEN GRADIENT is the value of the pressure variation as a

function of depth. p • It’s generally expressed in kg/cm2 /10 m and is obtained by dividing pressure by depth. The Overburden Gradient will therefore be equal to:

POVERBURDEN GOV =

H

x 10

where: POVERBURDEN = Overburden pressure in kg/cm2 at H meters H = E Examined i dd depth h iin m

COMPACTION PRESSURE COMPACTION Pressure is the pressure exerted by the weight of the rock matrix that, in normal compaction p condition, is totally y supported pp byy the rock matrix by y means of intergrain contacts. It’s expressed by the formula:

CP = (1 – Φ x m) x H CP Φ m

where h

= compaction pressure in kg/cm2 = rock porosity expressed as a ratio = rock matrix density expressed in kg/dm3

“SEDIMENT PRESSURE“ (or Overburden Pressure) in kg/cm2 , can be expressed by the formula:

PSED = CP + FP

where: CP = Compaction Pressure in kg/cm2 FP = Fluid Pressure in kg/cm2

6(',0(17RU³%8/.´ '(16,7 than the hydrostatic Pressure

• UNDERPRESSURE. Its value is < than the hydrostatic Pressure

Formation Gradient FORMATION GRADIENT NORMAL

ABNORMAL

Pore Gradient is considered normal when its value is between 1.03 and 1.07 kg/cm2/10m.

Pore Gradient is considered abnormal when its value is different from the ones mentioned above. Hence there might be:

• OVERPRESSURED:

Gradient > 1.03-1.07 kg/cm2/10m

• UNDERPRESSURED: Gradient < 1.03-1.07 kg/cm2/10m

ABNORMAL PRESSURES ABNORMAL PRESSURES OVERPRESSURES

UNDERPRESSURES

Sedimentation Speed Tectonics

Depleted Reservoirs

Reservoir Geometry Artesian Pressure

D Drop off Water W t Table T bl

Diapirism Reservoir Repressurized Osmosis Clay Diagenesis Sulfate Diagenesis Volcanic Ash Diagenesis

Dilatation due to Tectonic Phenomena

Gp >

kg/cm2/10 m Overpressure Index

ORIGIN OF OVERPRESSURES

•Sedimentation Velocity • Tectonics T t i • Reservoir Geometry • Artesian Pressures • Diapirism • Diagenesis • Osmosis

TECTONICS - FAULT CREATION

Normal Side

Compressed Side

Fault Plane

1) Overturned Fold

2)) Compressed p Fold 3) Fault

TECTONIC UPLIFT

B

A

C

A - C = Normal Pressure B = Overpressure

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= =

Normal pressure Overpressure

POSSIBLE EFFECTS OF A FAULT

B

A

C

D F

E

I

H

G

A - B - C - D = Normal Pressure F - G - H - I = Overpressure

OVERPRESSURES DUE TO COMPRESSIVE TECTONIC PHENOMENA

A B

1

C

A B C

2

RESERVOIR GEOMETRY

1800

Hydrocarbons

Overpressure

0.1

2100

Water 2500

RESERVOIR GEOMETRY Overpressure 1000

Oil d = 0.7 Water d = 1.03

1500

2000

2000 m PPORE = (2000 * 1.03)/10 k / 2/10 m kg/cm

= 206 kg/cm2 ; GPORE = (206/2000) * 10 = 1.03

1500 m PPORE = 206 - (1.03 * 500/10) = 154.5 kg/cm2; GPORE = (154.5/1500) * 10 =1.03 kg/cm2/10m

1.195 > 1.03

1000m PPORE=154.5 kg/cm2 -(0.7 * 500/10) = 119.5 kg/cm2 - GPORE = (119.5/1000) * 10 = = 1.195 kg/cm2/10 m

RESERVOIR GEOMETRY Overpressure

1000

Gas d. = 0.1 1500

Water d = 1.03 2000

2000 m PPORE = (2000 * 1.03)/10 k / 2/10 m kg/cm

= 206 kg/cm2 ; GPORE = (206/2000) * 10 = 1.03

1500 m PPORE = 206 - (1.03 * 500/10) = 154.5 kg/cm2; GPORE = (154.5/1500) * 10 =1.03 kg/cm2/10m

1.495 > 1.03

1000m PPORE=154.5 kg/cm2 -(0.1 * 500/10) = 149.5 kg/cm2 - GPORE = (149.5/1000) * 10 = = 1.495 kg/cm2/10 m

Depth (m) from sea level D

PRESSURE GRADIENT Vs DEPTH IN THE CARBONATE ROCKS OF THE PO VALLEY (ITALY) ( )

Pressure essu e G Gradient ad e t - Kg/cm g/c 2//10 0m

PIEZOMETRIC LEVEL

+ 300 m

RKB 0 m

- 250 m

DIAPIRITIC STRUCTURES CREATION OF A SALINE DOME

1

2

3

DIAPIRISM

Overpressure

Salt

CLAY DIAGENESIS

Montmorillonite ontmorillonite is a very plastic clay whose original water content is reduced to about 30% during the depositional phase. This clay, which is found at low depths, reaches the hydrostatic value rather rapidly, and its pore pressure has a normal gradient.

When, by effect of subsidence, this clay is found at a lower depth and under the action of pressure and temperature it undergoes a metamorphosis, losing some features while acquiring a MONTMORILLONITIC - ILLITIC composition and has a overpressure gradient.

CLAY DIAGENESIS 1000 - 2000 m MONTMORILLONITE

before diagenesis

2000 - 3000 m

Free Water inside Pores

After the ILLITE diagenesis

After diagenesis and compaction

3000 - 4000 m Volume Loss

UNDERPRESSURES

OSMOSIS

If two saline solutions with different concentrations and (initially) equal pressure are separated by a membrane, an “OSMOTIC” flow takes place as ions pass from a solution to the other until saline concentrations are balanced, but final pressures are different. The solution that initially had lower concentration loses pressure in favor of the solution that initially had higher concentration. (In nature this phenomenon can take place when two porous formations, with different salinity, are separated by a clayey septum.)

Gp <

kg/cm2/ 10 m

Underpressure index (i d (in depleted l t d wells, ll ffor iinstance t )

UNDERPRESSURE DUE TO EXTENDED PRODUCTION

Underpressure

Water

Underpressure

UNDERPRESSURE DUE TO WATER TABLE LOWERING

OVERPRESSURE ANALYSIS METHODS

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ALL THE ANALYSIS METHODS FOR OVERPRESSURE DETERMINATION ARE BASED ON THE FOLLOWING ASSUMPTIONS: • Sediment compaction increases in function of depth (at higher depths a higher sediment compaction is expected). • Overpressure analysis is carried out, where possible, taking into consideration pure clay levels. • Shales are overpressured when they did not have the possibility to throw out interstitial water, thus resulting more porous and undercompacted.

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All the overpressure analysis methods are based on normal-compaction concept

•

The available methods are different in fuction of their utilization time: before, during or after drilling

•

Their effectiveness increases if they are used successively: before drilling to build the model, during and after drilling to update and refine the model

•

The use of different methods within one phase increases prediction capability

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PRE-DRILL METHODS FOR OVERPRESSURE ANALYSIS FROM SEISMIC DATA

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INTERVAL VELOCITY (2 4

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TRANSIT TIME (∆-4 of sonic waves between two reflections (µsec/ft)

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DEPTH (attention to reference “datum” from seismic!)

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SEDIMENT DENSITY

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SEDIMENT PRESSURE

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“R” RATIO

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1. Seismic section with interpretation (it shows the curve on which two way time and average velocities can be read). 2. Table with the following couple of values for each reflection: - two way time - average velocities of sound waves through formations 3. The following couple of values: - depth - interval velocity between two reflections

*/ (/*-+ , 'C(', ' STARTING FROM TWT AND VELOCITY FUNCTION 1) Interval velocity calculation

2) Transit time calculation 3) Calculation of the distance between two reflectors

4) Calculation of average density between two reflectors

vm2 2t2 − vm2 1t1 vi = t2 − t1

Vm average velocity t TWT

304800 ∆t = vi

vi interval velocities

t2 − t1 vi ∆h = 2

∆t in µs/ft

δ sed = δ max − 2.11

1− 1+

vi vi

vmax vmin

δmax = 2.75 g/cm3 vmax = 7000 m/s vmin = 1500 m/s

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Overburden gradient is calculated by integrating sediment density after having added to the latter curve the missing portion of data from ground surface to the first seismic datum (extrapolation the first available data to the surface) .7 %)

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In absence of offset wells, interstitial pressure gradient trend forecast is done by elaborating seismic data coming from one or more shot points in the nearby of well location. Pore gradient estimation is drawn by applying two different methodologies: • Transit time method (µsec/ft) • “R” ratio method

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The calculation is based on the assumption that transit time of sonic waves is a linear function that decreases in semi-logaritmic scale with depth (sediment burial by meands of other sediments increases their density and, consequently, sonic waves propagation velocity increases) +

(h0,v0 )

(h1,v1 )

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(h2,v2 )

(hn, vn )

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Transit time of sonic waves through formations

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TRANSIT TIME ( t in sec/ft):

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Being transit time input data available, to calculate pore gradient transit time method can be applied. Its application is done mainly through the use of two different methodologies: • EQUIVALENT DEPTH method • EATON’S method

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Overburden pressure acting at depth “z” is the sum of effective and pore pressure

p

ovbd

=

p

eff

+

p

p

2.

If, at depth ”z1”, the rock has had time to dissipate the pore pressure that generates during burying process, pore pressure will be hydrostatic

3.

If, instead, at depth ”z2” the rock has had no time to dissipate the pore pressure that generates during burying process, pore pressure will be higher than hydrostatic

4.

If at the two depth transit time is equal (obviously, in case of equal lithology) the two points have the same effective pressure

5.

Finally, having calculated the two overburden pressures and the two gradients, the difference between overburden and effective pressures will be: • •

hydrostatic pressure “p1“at depth ”z1” overpressure “p2“at depth “z2”

*/ (/*-+ , 'C(', ' 1.

Define normal compaction trend

2.

Choose the depth at which pore gradient (assumed overpressured) will be calculated

3.

Draw a vertical line from the chosen depth (point 2) until Normal Compaction Trend is reached (point 1). This depth and point 2 one have the same effective pressure

4.

From overburden gradient curve, calculate overburden pressure of the two chosen points

5.

Calculate effective pressure of point 1, given overburden and pore (hydrostatic) pressures

6.

Calculate pore pressure at point 2 from the difference between overburden and effective pressure calculated at step 5

7.

Calculate pore gradient

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100

+ Dt (ms/ft)

69

1000

1000

p =p 1 eff

2 eff

( G =

ovbd

2000

Depth (m)

= 2 ovbd

p

=

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000

=

(2.275−1.03)×23008 10

Govbd × z2 2.335× 3500 = = 10 10

8

2 2 p 2p = povbd − peff = 817.25 − 286.35

5000

6000

G p2 =

z2

=

530.9 × 10 3500

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4000

p 2p × 10

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G p = G sed −

(G sed

∆ t NCT − 1 . 03 )× ∆ t meas

n

The exponent n depends on available input data. A value equal to 3 is used in case of Sonic Log, while 1.5 is used for Resistivity Log.

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It’s an empirical graphic method developed by eni (formerly Agip) based on calculating and plotting R ratio

vi R= va vi and va, expressed in µs/ft, are, respectively interval velocity and reference velocity in clean clay, considered at normal pressure. In function of the value of R ratio, the interpretation will be: R = 1 Formations with Normal Pressure Gradient R > 1 Overconsolidated or carbonatic Formations R < 1 Porous or overpressured Formations

*/ (/*-+ , 'C(', ' With Two Way Times and average velocities (vm) of the nearest shot point to well location, interval velocity (vi), depth, pore pressure (pp), overburden pressure (povb) and effective pressure (peff) can be calculated. Velocity in shales assumed at normal pressure (va) is calculated according to the correlation: va =

vmax × peff A × peff + B

+ vmin

R ratio is calculated in function of depth according to the correlation:

R=

vi va

Coefficients A and B vary in function of the analyzed area. For example, in Pianura Padana their value is, respectively, 0.85 e 650

A

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Example of R ratio trend in function of depth in Pianura Padana

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Very porous or overpressured formations

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Overcompacted Formations

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Very porous or overpressured formations

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Example of R ratio trend where in the upper part R>1 values can be seen (undercompacted Formations or carbonates)

OVERPRESSURES ?WHILE DRILING@ ANALYSIS

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The two methods used in this case are: Dc Exponent

and

Σ-log

They are semi-empirical methods based on the following assumptions: 1. The index obtained by combining drilling parameters is an indication of rock DRILLABILITY, intended as rock capability to be drilled by the bit 2. This drillability index, assumed everything else fixed, is inversely proportional to depth, therefore it decreases while depth increases 3. Being this index linked to rock density (higher rock matrix content, lower pore volume in a bulk volume), where an overpressure can be located (less rock matrix, more voids) the rock becomes more drillable . .

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Conceived by Jorden & Shirley in 1966, it represents rock drillability as normalization of ROP (Rate Of Penetration) according to the following correlation: ROP log 60 * RPM dExp = 12 *WOB log 10 2 * D where ROP, RPM, WOB and D are expressed, respectively, in ft/h, rpm, lb and in Using m/h, rpm, t and in, the correlation becomes:

3.281* ROP 60 * RPM dExp = WOB log 0.0264 * D log

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In the example here beside, the well is characterized by formations with hydrostatic pore pressure (normal gradient). d-Exponent increases with depth and follows a NCT

Depth

d-Exponent

d-EXPONENT METHOD - LIMIT The main d-exponent limit consist s in the fact that mud density effect is not considered. considered

Since ROP is influenced by this parameter, d-exponent values must be corrected according to itit.

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Due to Mud Weight density (MW), d-Exponent is corrected according dExp to the following correlation: dcExp = MW

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A

+ :-

dc-Exponent

• lithology, • transgressions/regressions, • different hole diameter, • bit type, • bit wear, • etc. In this case the curve appears shifted, but its slope remains constant.

Depth

NCT line continuity, when it is drawn on d-exponent, can be interrupted due to effects not depending from overpressures:

A'=% ,',-

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+ :-

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Shifts can be composed in a continuous curve by translating the shifted portions until they overlay to Normal Compaction Trend

Depth

dc-Exponent

A'=% ,',-

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As well as overpressures calculation procedures from seismic data, it is possible to perform a similar estimation while drilling, by using the following methods: • Equivalent depth • Eaton’s

A further estimation method, formerly used, consists in using abacuses opportunely built.

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p

G

× z2 10

( G =

)

z1 − G × z1 ovbd p z1

p =p

z1 eff

p =p z2 p

G = z2 p

p

z2 ovbd

z2 p

z2

−p

'%-

dc-Exponent

z2 ovbd

=

z2 eff

'C(+ 2*/',-

10 z1 eff

Vertical depth

z2 ovbd

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=

×10 =

A'=% ,',-

'-

'*- ,

dcmeas Gp = Govbd − (Govbd −1.03)× dcnorm

1.2

Vertical depth

dc-Exponent

=

"

"

A'=% ,',-

dcnorm GA = 1.03× dcA

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.

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ΣA

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This system was developed in eni (ex AGIP) in the ’70s in occasion of Pianura Padana wells drilling. The need of a new interpretation criterion came out due to dcExponent inability to “see” overpressures in carbonatic layers. The method takes directly into consideration Mud Weight influence and is based on drillability concept. Drillability is drawn from ROP normalization. The used drilling parameters for this calculation are (m/h), RPM (rpm), WOB (t) and Bit Size (in). The method foresees the calculation of

F

corrected by factor, which accounts pressure and formation pressure and This depends on

σ

t and

σ'

t

∆p as pressure difference between mud

n

σ'

t

value

The final value on which the analysis is performed is obtained by the following correlation:

σ 0 = F σ t'

ΣA

'-

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0.5 × RPM0.25 WOB */ (/*-' σ t = dbit × ROP0.25

- ',

σ t' = σ t + 0 .028 7 −

σ ≥1 ' t

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0.75 1 n= 4− 640 σ t'

z 10 3

σ ≤1 ' t

2 2 1 1 n p − + ∆ * *, :+ ,*//$ F = 1 + n∆p

σ0 = F σ *

' t

n=

3.25 640 σ t'

z ∆p = (Gmud − Gp )× 10

ΣA Function

'-

σ0

*/ (/*-+ , %&

' (&' 7

is plotted, and for it a NCT is defined

NCT is a line defined by the equation

z σr = a + b which crosses the 1000

abscissa axis at point = 0.088 PORE GRADIENT IS CALCULATED BY THE CORRELATION:

∆p ×10 Gp = ρmud − z And by calculating again differential pressure between mud and formation with the following correlation

F =

σr σ t'

2 (1 − F ) −1 ∧ ∆p = n × 1 − (1 − F ) 2

@ B

σ

0

∧

σ

' t

Vertical depth m

σ0

σσ Normal Normal compaction compaction trend trend

NCT INTERPRETED ON FUNCTION

σ0

σ0

Lithology Transgressions/regressions Different hole diameter Bit type Bit wear Etc… In this case NCT will appear shifted, but angular coefficient will remain constant.

Vertical depth m

As well as dc-Exp, also Σ-log can show some translations (shifts) caused by:

ΣA

+ ,-'&%&'-*-+ , "7 D

In presence of shifts in overpressured Formations, the curve is characterized by a visible variation of angular coefficient

OVERPRESSURES TOP

Vertical depth m

σ0

ΣA

+ ,-'&%&'-*-+ , 7 D

Calculation of coefficient “b” in Formations with normal gradient

Vertical depth m

σ0

ΣA

+ ,-'&%&'-*-+ , ;7 D σ0

σ r2 =

σ r1 × σ 02 σ

1 0

Vertical depth m

Shifts can be calculated by means of an analytical method (method I)

σ 01

σ

2 0

σ

1 r

σ r2

ΣA

+ ,-'&%&'-*-+ , D7 D A

#

#

σ0 A D

A 3

b2 = b1 ×

σ

2 0

σ

1 0

Vertical depth m

Shifts can be calculated by means of an analytical method (method II)

σ 01

σ 02

'=* %/' :+ ,-'&%&'-' ΣA

E 8 7

'-

Vertical depth m

Vertical depth m

- '& 5# + /' &+ //+ ,)6

2,2 2,3 2,4 2,5 Density Kg/dm3

/*$ ', + -$

OVERPRESSURES TOP

2,2 2,3 2,4 2,5 Density Kg/dm3

If overpressured shales are UNDERCOMPACTED (porosity is higher than what expected at the depth where they are located), their density is lower then theoretic one. Its measurement can be performed on cuttings.

- '& 5# + /' &+ //+ ,)6

Overpressured shales are more porous and, for this reason, they represent a sort of thermal barrier which prevents heat coming from below to pass uniformly towards the upper layers. Where overpressures can be spotted, the Geothermical Gradient (usually 3°/100m) shows a sharp increase.

'-

-' %'&*-(&'

Depth m

- '& 5# + /' &+ //+ ,)6

'-

&' + -+ 2+ -$

OVERPRESSURES TOP

Resistivity

MUD RESISTIVITY – Mud contamination by means of formation water due to overpressure not sufficiently balanced causes a decrease of resistivity value, since formation fluid is assumed with higher salinity than drilling mud.

Depth m

- '& 5# + /' &+ //+ ,)6

'-

/ &+ '

OVERPRESSURES TOP

Chlorides

MUD CHLORIDES CONTENT – The chemical analysis of chlorides in drilling mud as it comes out of the well can highlight an overpressure since the contamination could have been caused by formation fluid influx. Formation fluid is assumed with higher salinity than drilling mud.

- '& 5# + /' &+ //+ ,)6 GAS INFLUXES Pipe connection gas Trip gas Background gas HOLE TIGHTENING High torque Overpull/drag Reaming/backreaming Presence of cavings Breakouts MUD PUMPING PRESSURE

'-

+ ),*/7 '2',-

- '& 5# + /' &+ //+ ,)6

'-

# 7 /#

MWD systems (Measurement While Drilling) can perform real time downhole measurement of some drilling parameters that can be used as indicators for overpressures interpretation: • Well inclination and orientation • Resistivity log • Neutron log • Temperature • Torque • Weight on bit LWD tools (Log While Drilling) can measure and transmit in real time some useful data for petrophysical characterization. The same data, with a better resolution, are memorized in the tool and unloaded when it is pulled out of hole: • Gamma ray log • Sonic log • Caliper log (ultrasonic !!)

POST-DRILLING METHODS OVERPRESSURE ANALYSIS FROM LOGS

*,*/$ +

'-

The analysis methods are based on the measurement of clay electrical behavior. In particular the methods are: •

∆t Shale method, based on transit time measurement, by sonic logs, of an elastic perturbation which propagates along wellbore walls

•

Resistivity method, based on the measurement of resistivity met by electric field transmitted through borehole walls and generated by electric logs

∆-

*/' '∆t (µs/ft) D

*

Vertical depth (m)

The assumption is, again, that propagation velocity of elastic waves increases with depth (for higher rock density). Consequently, transit time (∆t) decreases regularly and it is therefore possible to draw a NCT.

*

*

∆-

*/' '-

3* + %&+ , + %/' ∆t (µs/ft) D

*

Vertical depth m

Assuming that density, porosity and relative pressures (effective and pore ones) are intercorrelated, if by increasing depth and assuming other conditions unvaried the transit time decreases (deviating from clean shales NCT), the interested layers are overpressured

)

OVERPRESSURES TOP *

*

∆-

*/' '-

%&' ', ' : ∆t (µs/ft) D

*

Vertical depth m

In ∆t-shale method shifts can be identified, even if they are not so frequent. These must be distinguished from NCT slope variation. The main cause of shifts can be related to geological issues.

*

)

+ :-

∆-

*/' '-

, -

'-'& + ,*-+ ,

Availability of an electrical log (resistivity, SP)/geological (GRay) Availability of acoustic log (ex. BHC Sonic Log) Availability of Caliper/Image log Identification of CLEAN shales (and isolate the corresponding ∆t values) Plotting ∆t vs depth (in a semilog plot) Drawing NCT INTERPRETING ∆t Shale trend. IN DEVIATED WELLS, DEPTH SHALL BE VERTICALIZED

GR

Res

SP

/*$+ ',-+ :+ *-+ ,

∆-

*/' '-

/+ + -

It cannot be applied in carbonatic layers Shales must be clean Fluids contained in shales (gas or oil) can modify ∆t value The wellbore wall shall be in gauge Geological age interpretation

changes

increase

the

risk

of

wrong

∆ 1µ 7 4 !

"!

"!!

"!!!

E!!

1 4

"!!!

"E!!

, !!!

2

E!!

;!!!

;E!!

D!!!

∆-

*/' '-

*/ (/*-+ , 'C(', '

• Estimation of bulk density from acoustic log (if density log not available or incomplete); • Calculation of overburden gradient, by integrating density curve; • Acoustic (sonic) log analysis and NCT determination; • Pore pressure gradient calculation by means of equivalent depth or Eaton’s method

∆-

*/' '-

', + -$' -+ *-+ , "7 ;

δ sed = φ δ f + (1 − φ )δ m ROCK MATRIX

Densit! g/cc

∆t µsec/ft

Dolomite

2.87

43.5

Limestone

2.71

43.5 - 47.5

Anhydrite

2.96

50

Clay

2.70

47

∆-

*/' '-

', + -$' -+ *-+ , 7 ;

∆t VS. POROSITY CORRELATIONS

∆t − ∆tm φ= 153

Consolidated soils and rocks

∆t − ∆tm φ = 1.228× ∆t + 200 ∆t − ∆tm φ = 1.568× 153

Slightly or not consolidated terrigenous Consolidated soils and rocks (alternative) ∆t VS. BULK DENSITY CORRELATIONS Consolidated soils and rocks Slightly or not consolidated soils

δ sed

∆t = 3.28 + 89

∆t − ∆tm δ sed = 2.75 − 2.11× ∆t + 200

∆-

*/' '-

', + -$' -+ *-+ , ;7 ;

The following correlation, developed by Agip, was built by comparing its results to density values coming from Formation Density Correlated Logs. The results of this comparison revealed the wide validity of this correlation, which can be used with good reliability for every formation type.

δ sed

∆ t − 47 = 2 . 75 − 2 . 11 × ∆ t + 200

&' + -+ 2+ -$ 'Resistivity depends on rock porosity (fluid in rock pores). Rocks characterized by low porosity have high resistivity (ex. compact limestone, volcanic rocks..). Having other conditions fixed, rock resistivity depends on: • • •

salt concentration rock composition temperature

Shales density increases with increasing depth, thus increasing compaction and decreasing porosity. For this reason, resistivity increases.

&' + -+ 2+ -$ '-

*/ (/*-+ , '-

The methods based on shales resistivity for pore pressure estimation are basically two: I° method – from an electric log, shales resistivity is obtained and then it is plotted vs depth in a semi-logarithmic scale. Log interpretation is performed directly on this curve, without further calculation. II°method – F-shale factor (clay formation factor) is identified from resistivity curve and is used for the interpretation by plotting it vs depth in a semi-logarithmic scale.

&' + -+ 2+ -$ '-

'-

+"7

Resistivity of clean shales is plotted in semi-logarithmic scale in function of vertical depth. The correlation between resistivity and porosity (fluid content, since saturation = 1 is assumed) is inversely proportional and generates an increasing Normal Compaction Trend. In case of Formations with normal pore gradient, resistivity values allign around a line with increasing trend in function of depth.

Depth

Clay resistivity

&' + -+ 2+ -$ '-

'-

In case of overpressured levels, the trend of measured resistivity values depart from Normal Compaction Trend. The deviation is high or low in function of absolute pressure value.

Depth

Clay resistivity

+

+ 7

&' + -+ 2+ -$ '-

'-

+ +"7 ;

In this cases the analyzed trend is not resistivity one, but shales formation factor F-Shale. It is calculated from the ratio between measured shales resistivity and formation fluid one: % D

% )

%

%

Fshale

R shale 1 = = Rw C shale × R w

Vertical depth m

“F shale” Normal gradient Formations *

*

*

&' + -+ 2+ -$ '-

'% D

+ + 7 ; % )

%

%

“F shale” OVERPRESSURED Formations

Vertical depth m

Also with clay formation factor, in presence of overpressured layers curve trend departs from Normal Compaction Trend line.

*

*

*

&' + -+ 2+ -$ '-

'-

+ +;7 ;

The operational sequence to be followed for F-Shale analysis is illustrated here below: 1. Calculate, or measure, formation water resistivity Rw throughout the well. 2. Plot Rw values on a semi-logarithmic scale. 3. Read resistivity value from log data for clean shales throughout the wellbore profile. 4. Calculate F-Shale value for the analyzed clay points. 5. Plot F-Shale values on a semi-logaritmic scale. 6. Draw F-Shale Normal Compaction Trend. 7. Evaluate the presence of overpressures and interpret their trend.

&' + -+ 2+ -$ '-

/+ + -

The main limits of resistivity log analysis can be resumed as follows: •

It can not be applied in carbonatic layers

•

It can be applied only in wells with frequent shale-sand interbedding

•

Spontaneous Potential (SP) value shall be easily distinguished between sands and shales

•

Shales shall be clean

•

Hydrocarbons in shales (oil or gas) can modify conductivity values

•

Wellbore must be in gauge

FRACTURE GRADIENT ESTIMATION AND VERIFICATION

+ ,-&

( -+ ,

Once having calculated Overburden and Pore curves, in order to complete the pressure model Fracture Gradient shall be estimated. This value is an indication of borehole wall propension to break (fracture opening) due to excessive Mud Weight. Knowing fracture ggradient curve throughout the whole well length, together with pore gradient one, is of the utmost importance for the main planning and drilling phases of a well: •

During planning phase, it allows establishing the optimal casing shoe depth in function of choke margin and differential pressure

•

During drilling phase, it allows safe operations in case of kick/blowout

:&*

*/ (/*-+ , "7

The correlations used for fracture gradient calculation are based on the assumption that, in case of homogeneous, elastic and isotropic mean, in situ stress state is modified by the presence of the well and stresses redistribute around its lateral surface.

σ

pw

σθ′

σ r′

:&*

*/ (/*-+ , 7

The value of tangential stress is maximum in case of empty hole and decreases in function of mud weight increase, since mud weight pressure applied at wellbore replaces the action of the previously removed rock. An excessive mud density increase could cause wellbore wall fracturing.

σ

σθ′ ↓

σ r′ ↑ pw =↑

&&'/*-+ , : & :&*

*/ (/*-+ , "7

From the solution of elastic equations and in function of formation type, in particular concerning Poisson’s Ratio coefficient, fracture pressure is obtained from the following correlations: ELASTIC FORMATIONS with low permeability and minimum filtrate invasion:

p frac

2ν ( povbd − p p ) = pp + 1 −ν

INCONSOLIDATE OR SLIGHTLY CEMENTED FORMATIONS with high permeability and sensible filtrate invasion:

p frac = p p + 2ν ( povbd − p p )

PLASTIC FORMATIONS:

p frac = povbd

&&'/*-+ , : & :&* +

*/ (/*-+ , 7

B 9

-

% B

G frac = G p +

9

ν 1 −ν

J

&

ν8!

E

9

(G

ovbd

− Gp )

G frac

The 2/3 coefficient shall be modified as follows: •

in slightly consolidated sands = 1/2;

•

in shales or silty marl = 3/4.

2 = (Gsed − G p ) + G p 3

94 5" A

A *

"-

5

A

: A *

, #&

&

& 0

3

Adding fracture gradient calculation to the previously mentioned curves generates a plot similar to the one in figure.

:&* -(&')&* + ',- 2'&+ :+ *-+ , Seen the importance of fracture gradient for operative practice, it is necessary to verify the estimation done in planning phase by means of direct measurements. The direct measurements can be performed during drilling phase and provide a good estimation of fracture gradient limits, even though they can not measure its real value. This introduces automatically a safety margin. The two main sources of calibration values in drilling phase are: Leak Off Test (LOT) Formation Integrity Test (FIT)

/'*. ::-' -

The LOT is performed in a well during drilling phases. It is carried out in open hole and consists in pressurizing the well until pressure causes a reaction to the well. The LOT can be performed for two main reasons: •

Verification, after casing setting, of the real value of fracture gradient below the last casing shoe;

•

Verify, after crossing a level characterized by high porosity and permeability, a more realistic value of fracture pressure and gradient.

/-

%'&*-+ 2'%&

' (&'

1.

Drill cement and casing shoe and then drill 10m of virgin formation.

2.

Circulate for mud density conditioning in the whole well.

3.

Close BOP.

4.

Pump at low flow rate (¼ - ½ bbl/h) and plot flow rate and pressure values on a diagram.

5.

Carry on pumping until no more than two values depart from linear pumping trend.

6.

Wait for pressure stabilization and read final value.

7.

Add to the read value the hydrostatic pressure applied at bottom depth by mud column. This will be the value of fracture pressure.

8.

Calculate fracture gradient.

/-

%/ -

0

*

Pressure (psi)

7

*

*

Pumped volume (bbl)

/-

:&* -(&+ ,) "7

ATTENTION: the fracture gradient value calculated with the previously described procedure is NOT the real fracture gradient, though for operative purposes it can be considered a good approximation. The LOP (Leak Off Point), at best, is coincident to the beginning of mud leak phase but the real fracture limit is not reached. The real fracture gradient can be obtained only by applying to the formation a pressure equal or higher than minimum horizontal stress plus traction resistance of the analyzed rock. According to our internal procedures, LOT is a good but VERY CONSERVATIVE control test.

/-

:&* -(&+ ,) 7 7

Pressure

;;

7 > > "; . -

(

-

6- ;

7

-

"!

+

8

;;

+ +

+ +

Time

-

'=-', ' /'*. ::-' -

=/ - 1'?

/ @

-

4

/M

A

M

M

B

@

@ B B 9 B

B

B

: & *-+ , + ,-')&+ -$-' + -

?

-

:+ B

B

/-

9

A

@

@

M

"!

M

B

M M

M

A B

B

3 % %

B

B

1N A O

997 4

A

B

1 B

4

9

( INPUT: seismic

*&$

' ' %&'A &+ // vm e TWT vi vs Depth ∆t vs Depth

ρ bulk

NCT Equiv.depth, Eaton, R ratio

PPG

OBG FG

(

*&$

INPUT: mudlog

' ' # + /' &+ //+ ,) ROP, RPM, WOB, D, MW

Dc-Exp, ΣALog

NCT Equiv.depth, Eaton, abacus

PPG

(

*&$

' ' %

-A &+ //

INPUT: logs Caliper

GR, Res, SP

Sonic, Res

Density

Shale Sonic Filtered Sonic

OBG

NCT PPG

FG