Data Engineer Manual

 

SG

DATA NAME:

ENGINEERING COURSE NOTES

DATE:

AN INTRODUCTORY GUIDE TO DATA ENGINEERING

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Data Engineering Course

CONTENTS

I ntrod ntroduction uction _________________________________________________________ _______________________________ __________________________4 4 F orma ormation tion Pre Pr essure ssur es a and nd H ydr ydr ost ostat atii cs____________________________________5 cs__________________________________ __5 Equivalent mud weight_____________________________ weight________________________________________ _____________________ ____________ __ 5 Problems caused by abnormal pressures ___________ _____________________ _____________________ ________________6 _____6 Problems associated with excess overbalance __________ _____________________ _____________________ ____________ __ 6 Problems associated with deficient overbalance __________ _____________________ _____________________6 __________6 Problems associated w ith underbalance __________ _____________________ _____________________ _________________7 _______7

Overr burden Ove burden G r ad adii ents ___________________________________ _________________________________________________ ______________8 8 Calculation of overburden __________ _____________________ ______________________ _____________________ _________________8 _______8

F orma ormation tion Pr essure ssur es _________________________________________________ ____________________________________ _____________11 11 Pressure mechanisms ___________ _____________________ _____________________ ______________________ ____________________11 _________11 Mechanisms __________ _____________________ _____________________ _____________________ _____________________ __________________11 ________11 Tectonic movement _________ ____________________ ______________________ _____________________ _____________________ _____________ __ 12 Underpressure __________ ____________________ _____________________ ______________________ _____________________ ________________13 ______13

D ri lling E xpo xpone nent nt _______ _______________ _______________ ______________ ______________ ______________ _______________14 ________14 Calculation of overpressure values from dc  ___________ _____________________ _____________________ _____________ __ 16

Pore Por e pressur pressure e eva valuat luatii on w whi hile le dri drilli lling ng _________________________________ __________________________________18 _18 Depth of Seal ___________ _____________________ _____________________ ______________________ _____________________ ________________18 ______18 Gas levels __________ _____________________ _____________________ _____________________ ______________________ ____________________21 _________21

Post drilling analysis _________________________________________________25 Pore pressure from sonic logs ______________________ ________________________________ _____________________ _____________ __ 25 Pore pressure from Density logs ___________ _____________________ _____________________ _____________________ ___________ _ 28

F r act cture ure Pr essure _______ _______________ _______________ ______________ ______________ ______________ _______________29 ________29 Mechanisms __________ _____________________ _____________________ _____________________ _____________________ __________________29 ________29 Leak off tests ___________ _____________________ _____________________ ______________________ _____________________ ________________29 ______29 Poissons Ratio (µ) __________ _____________________ ______________________ _____________________ _____________________ _____________ __ 33

B asic Dr illi ng F luid luid________ _______________ ______________ ______________ ______________ _______________ ______________35 ______35 Functions of drilling fluid_____________ fluid________________________ _____________________ _____________________ _______________35 ____35 Definitions of some drilling fluid terms __________ _____________________ _____________________ ________________35 ______35 Clay chemistry_______________ chemistry__________________________ _____________________ _____________________ _____________________ ___________ _ 36 Basic types of drilling fluids _________ ____________________ ______________________ _____________________ ________________37 ______37  2 of 53

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Drilling f luid additives __________ ____________________ _____________________ ______________________ ____________________37 _________37

D ri lling H ydraulics ydraulics ________ _______________ ______________ ______________ ______________ _______________ ______________39 ______39 Flow regimes ___________ _____________________ _____________________ ______________________ _____________________ ________________40 ______40 Pressure losses and hydraulic horsepower __________ ____________________ _____________________ _______________41 ____41 Annular pressure losses and ECD __________ ____________________ _____________________ _____________________ ___________ _ 41 Hole cleaning ___________ _____________________ _____________________ ______________________ _____________________ ________________41 ______41 Swab / Surge ___________ _____________________ _____________________ ______________________ _____________________ ________________41 ______41 Problems associated with swab / surge ___________ ______________________ _____________________ ________________42 ______42

Well Control ________________________________________________________ _______________________________ _________________________45 45 Procedures for killing a well __________ _____________________ _____________________ _____________________ _______________47 ____47

PWD and E ECD CD - a quick quick gguide uide ______________ _____________________ _______________ _______________ ____________49 _____49 Swab and Surge _____________________ ________________________________ _____________________ _____________________ _______________51 ____51 Hole cleaning ___________ _____________________ _____________________ ______________________ _____________________ ________________52 ______52

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Data Engineering Course Introduction Data Engineers are responsible for the safe and efficient operation of the surface acquisition system. This includes monitoring rig activity, pore pressure and fracture gradient estimation, hydraulics optimisation, systems maintenance, reporting and supervising logging geologists. Crossing the floor to the “dry” end requires a change of focus. Data engineers must know what is happening on the rig at any time and what will be happening. They have much more contact with rig and operator personnel and should be able to give advice as required. Morning meetings came into vogue in the early 1990s, but they really only served to formalise an existing forum. Many rig meetings are now video confrenced by satellite to the beach. Data engineers should present a professional image and be prepared to be pragmatic. The learning curve for a newly promoted data engineer is very steep. By this stage a senior  logger should be able to run the logging unit on their own and have some idea of ADT work. Hopefully this course will at best clarify this work or at worse introduce a different aspect of  Logging Systems’ activities.

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Formation Pressures and Hydrostatics In ADT work, engineers use a variety of conversion factors and constants to calculate the various pressures and gradients (and to convert between them) involved in drilling wells. The most common is 0.052.  A column of fresh water water 1” square a and nd 12” tall w will ill exert a pre pressure ssure of 0.433 p psi/ft: si/ft: P = 62.4 62.4 lb/ft  lb/ft  

3

= 0.433 0.433 psi/ft  psi/ft

144 (in 144 (in2 per

ft2)

So, a fluid column of 8.33ppg (fresh water) exerts a pressure of 0.433psi/ft ∴a column of any fluid of any density will exert a pressure of  

0.433 = 0 0.0519 .0519 psi/ft per ppg 8.33

The metric equivalent (for use with specific gravity and metres) is 1.421

E quivalent quivalent mud mud weig ht  Very few operators use psi/ft to express pressure gradients. It is easier to deal with gradients expressed as equivalent mud weights. Pounds per gallon (ppg), specific gravity (sg), psi per  thousand feet (pptf) are the most common. Shell are particularly keen on pptf, which is basically psi/ft multiplied by 1000. Calculating pressures and gradients is a frequent task in ADT work and the ability to work in the various units involved is rapidly acquired. The basic equations are as follows: To convert a mud weight to a pressure in psi : ppg x 0.0519 x TVDft sg x 1.421 x TVDm To convert a pressure to a mud weight (EMW) psi / TVDft / 0.052 psi / TVDm / 1.421 To convert a EMW to a gradient : ppg x .052 sg x 1.421 NOTE : NOTE  : when calculating pressures using these equations always always use True Vertical Depth. Using the above, the ADT engineer can calculate the pressure exerted at a specific point in the well. The use of these constants and formula soon become second nature.

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Pr oblems oblems caus ed by abnorma abnormall press ures  An optimum mud weight is required to drill a hole in the most safe and efficient manner. High mudweights lead to lost circulation, differential sticking, poor quality wireline / MWD logs and formation damage which has an adverse effect on any future production. Low mud weights lead to borehole instability kicks and problems with casing. Knowledge of the pore pressure regime the well allows this optimum mud weight to be where run. Ideally mud weight be close toinBUT above the formation pressure. The point pore the pressure equalsshould the mud weight is called the balance point. point. When the mud weight is greater than the pore pressure this is an overbalanced overbalanced   situation, while when mud weight is below the pore pressure this is underbalanced.. underbalanced

Pr oblems oblems ass ociate ociated d with e exces xces s over ba bala lance nce Lost circulation circulation - probably the commonest hole problem encountered. Lost circulation can range from the slow seepage losses which can be treated with a little addition of LCM (Lost Circulation Material) into the mud, to catastrophic losses which can be incurable and may ultimately lead to a kick due to loss of hydrostatic head. Mud is lost into natural fractures and fissures in the formation, but these may be opened or even generated by the mud weight exceeding the fracture pressure of the formation. Once these fractures have been opened it is not always possible to close them by reducing the mud weight. Formation damage  damage  - reservoir flushing and loss of porosity and permeability are also associated with high overbalance. Borehole erosion and washouts may also occur leading to poor quality logs. Differential sticking sticking - thick filter cake may build up on the borehole increasing the area in contact with the drill string. Low ROP ROP - rock bits work by initiating and propagating fractures in the rock. If the differential between the rock and the mud in the borehole is low, the rock chips fly off into the borehole. If  the differential is too high the chips will not fly off and the ROP will be reduced. This is called the chip hold down effect.

Pr oblems oblems ass ociated ociated with defic ient overbala overbalance nce Borehole instability - Swelling clays can be caused by low overbalance, as can caving of  formation into the borehole. These will manifest themselves as drag or fill. Stuck pipe - borehole instability can cause the formations to swell or cavings to enter the borehole which can then stick the drillstring mechanically. High gas levels levels - usually associated with lack of overbalance, especially if background and trip gasses are high. Connection gas is also a good indicator of low overbalance. Low overbalance is not necessarily a bad thing, but requires vigilance to prevent the situation moving to the underbalance underbalanced d case.

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Pr oblems oblems ass ociated ociated with underbala underbalance nce Kicks   - if porosity and permeability are encountered when in an underbalance condition, or  Kicks underbalance is created by swabbing, a kick may occur.  ADT work can allow this overbalance and therefore optimum mud weight to be achieved.  Accurate and timely analysis analysis of information can allow allow engineers to have a good hand handle le on the formation pressure regime.

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Overburden Gradients Much of the ADT and data engineers work in establishing the pressure regime of a well involves the use of overburden gradients. Overburden plays a pivotal role in the analysis of the pressure regime of a well. Overburden (for our purposes) is the cumulative pressure exerted pressure exerted by the, air, water and rock formations above the point of interest. Without an accurate value for the overburden, calculat calculations ions relying on overburden (such as pore and fracture pressure) will be correspondingly inaccurate.

 AIR GAP WATER

LITHOLOGY

DEPTH

OVERBURDEN GRADIENT

 As can be seen in the diagram (where the curve represents a gradient) air has a gradient of  0.028ppg, sea water a gradient of 8.6ppg / 1.04 SG. These gradients are fairly constant for an offshore well. Water depth can have a great effect on the overburden, especially in the more recent deepwater projects west of Shetland. On the other hand, the diagram shows that the gradient of the lithology increases with depth following the Normal Compaction Trend. As compaction of the sediment occurs with depth, dewatering of the formation causes the density of that formation to increase. In deep or  mature basins the density of the formations may reach a maximum as the diagenetic process runs it course.

Calculation of overburden  As noted above, overburden is a function of formation density density.. To calculate overburden requires an estimation of formation density. There is a variety of methods to acquire density data: Bulk density  density  - obtained by using drilled cuttings and a mud balance. Shale density can also be used, but involves potentially hazardous chemicals.

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Sonic  - using wireline data to calculate formationdensity from the wireline sonic log. The Sonic transit time in the rock is related to the density.

Density = 2.75-(2.15*(T-47)/(T+200)) This converts the transit time to a density by using known velocities for the lithology. Density log  log  - data from the wireline density log. These values, usually in sg, can be input directly without any conversion Of these the use of the density log is easiest, especially if you can get the data in ASCII format. Bulk and shale density can be suspect if hydration of the cuttings is occurring. Bulk and shale density do have the advantage of being used while drilling. This data is acquired as an interval average, for example over 10 metres or 50 feet. If ascii data is available it can be imported to XL and an averaging macro run. If ASCII data is unavailable and all you have is a log, eyeball an average for the interval. Take a piece of paper and copy the track scale. Use this as a scale for your estimation of the interval average. Having acquired your interval averages, input the values into a spread sheet. If using sonic you will also need a column for the relevant lithology transit times. Refer to the mudlog for the lithology over the interval and input the relevant transit time. Next, use the XL spreadsheet to produce an overburden data sheet similar to that shown below

OVERBURDEN DATA TABLE

Well 399/12b-2 (Formation density from petrophysical log) Depth (mMD) 0 26 861 1450 1460

Depth (mTVD) 0 26 861 1450 1460

Interval (mTVD)

Density (SG)

26 835 589 10

0.23 1.04 1.90 1.95

Interval Cum ulative Density verbur verburden den (psiOv (psiOverb erburd urden en (ps (psiGradie iGradient nt (psi (psi/m) /m) 15 1234 1590 28

15 1249 2839 2867

0.58 1.45 1.96 1.96

EMW (SG) (SG) 0 0.41 1.02 1.38 1.38

In the above example the units are metric (metres, Specific Gravity or Grammes per cubic centimetre), the density data is taken from the wireline log and is averaged over 10 metres. The first interval (from RKB, 0m) to sea level (26m) is the airgap. This has a density of 0.23 sg, multiply the density by 1.421 and multiply that by the interval producing an interval overburden of 15 psi. The next interval is from sea level (26m, to seabed (861m). This interval comprises 835m of seawater with a density of 1.04 sg with the interval overburden being 1234 psi. These interval overburden values are added together to produce an cumulative overburden with a value of 1249 psi. Since logs were not run until 1450m and there were no surface returns, there is an information gap from 861m to 1450m. An estimation of the formation density is used to calculate the missing interval. In this case an estimated density of 1.9 sg over an interval of 589m gives an interval overburden overburden of 1590 psi. This is added to the cumulative to produce a new cumulative overburden of 2839 psi.

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From 1450 m the wireline density data is available and this is input into column 4 of the table. The interval overburden and cumulative overburden are calculated for each 10m interval for  the entire section or well. Up to this point all the overburden data is expressed as a pressure in psi. For our purposes the overburden should be expressed as a Gradient. Column 7 of the table converts cumulative overburden (in psi) to a density gradient in psi per metre (psi/m) by dividing the cumulative overburden by the vertical depth. The last stage, in column 8 is to convert the density gradient to an equivalent mud weight in sg by dividing the gradient in psi/m by 1.421. This is the data used in pressure evaluation work and imported into the INSITE database for use in logs.

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Formation Pressures Work on formation pressures by Terzaghi and Peck established the following relationship:

S = σ + P Where :

S is the overburden pressure P is the pore pressure

σ is the formation matrix stress This relationship is the foundation on which all pressure engineering is built. During normal compaction, water in the pore space will be squeezed out and the rock will be supported by the matrix. If the fluid is unable to escape, the rock will become supported by the fluid in the pore space. The overlying overlying rock will cause this pore fluid to become overpressured. Matrix stress is stress is the difference between the pore pressure and the overburden pressure. Under normal compaction the porosity of the f ormations should decrease and the bulk density should increase with depth. Plotting these on semi-logarithmic graph paper produces a straight line. This line is called the Normal Compaction Trend. Trend. If shale density is plotted any points on the Normal Compaction Trend will be normally pressured.

Pres s ure m mecha echanis nis ms Normal formation pressure is expressed as :

P = ρ x g x D Where

ρ = average density of the fluid g = gravitational acceleration D = height of the column

e.g. fresh water would give a pressure gradient of 0.433psi/ft. In most drilling environments the salinity of the pore fluid ensures that normal pressure gradients will rarely be equal to that of fresh water. Normal pressure gradients (for the sake of overpressure detection) vary from area to area, e.g. the North Sea has a normal gradient of 0.452psi/ft whereas the Gulf Coast has a typical normal normal gradient of 0.465psi/ft. Underpressure is any formation pressure below the recognised normal gradient of the area. Overpressure development relies on the inhibition of fluid flow, both laterally and vertically, within the rock column. This seal prevents the dewatering sediments undergo as they are compacted and buried. Generation of hydrocarbons hydrocarbons may also produce overpressure.

 Mechanis  Mech anis ms Hydrocarbon reservoirs  reservoirs  - Oil and gas bearing formations may be overpressured through being in communication with the deepest formations of the sequence. Undercompaction   - sometimes called sedimentary loading. Low permeability and rapid Undercompaction deposition restricts the escape of pore fluid from argillaceous sediments thus preventing the  11 of 53

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establishment of hydrostatic equilibrium. These mechanisms usually result in overpressured shales such as those found in the tertiary of the Central North Sea. The rate of overpressure increase within these shale sequences depends on the integrity of the seal. Some sequences contain thin limestones that act as a perfect seal, producing very rapid increases in overpressure. Sequences with imperfect seals are characterised by a gradual increase in overpressure with depth, possibly over hundreds of metres.  Another form of undercompaction is tectonic loading. If a thrust fault moves rock over an uncompacted sequence, an effect similar to sedimentary loading my generate overpressure. Aquifers   - While not strictly geopressure, the overpressure in this case is the result of the Aquifers  hydrostatic hydrostati c effect of the water column.

 Aquifer 

Tectonic movement  Faulting  - allows communication between deeper, pressured formations and shallow Faulting  formations. If these fluids cannot escape to the surface, overpressure will result. Overpressure can also be produced if a permeable zone is faulted against an impermeable zone, thus sealing the permeable zone and preventing de-watering. Associated uplift may also cause pressure

Faulting and or uplift Uplift - if a formation, which is normally compacted and pressured at depth, is uplifted, the Uplift original formation pressure may be maintained. Any uplift of a sequence usually results in some erosion of the overlying formations (overburden). For the same degree of movement,

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uplift from shallower depths produces a greater increase in overpressure than from much deeper.

Uplift Aquathermal pressuring pressuring - a formation that is totally isolated will generate overpressure as it is buried as a result of the geothermal gradient. Charged Sands  Sands  - a shallow sand sequence can be charged up by gas migrating from a deeper formation. This will normally be encountered in areas where wells drilled previously have suffered subsurface blow out or have been poorly plugged and abandoned.

Charged formation

Clay diagenisis  diagenisis  - Montmorillonite alters to Illite during diagenisis. The interlayer bound water  in Montmorillonite becomes free and is released into the pore space, causing over pressure. Salt domes domes - the plastic movement of salt formations can cause pressure anomalies due to the faulting and folding accompanying diapirism. In addition, formations within the salt such as dolomites may become overpressured due to uplift within the salt, e.g. the Plattendolomit. Salt may also seal clay formations, preventing dewatering.

Underpressure  Also referred to as subnormal pressures due to the pressure gradients being less that 0.433 psi/ft. The main form of underpressure encountered in the North Sea area is caused by depletion of reservoirs due to production. The gas reservoirs of the southern North Sea can be depleted to 6ppg EMW.  13 of 53

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Drilling Exponent While indicators like gas, drag or fill allow the ADT engineer to suggest the presence of  overpressure, an operator needs to know how to restore an effective overbalance. This requires quantitative evaluation to produce an estimate of the overpressure as an equivalent mud weight. In short the operator wants to know how much to increase the mud weight. This would normally happen while drilling, so drilling parameters supply the data required. The data is used in a drilling model, which attempts normalise all the parameters to produce a figure independent of parameter variations, but generating a value that represents the formation characteristics. There are a few drilling models, Modified Log Normalised Drill rate being Sperry-Sun developed, Instantaneous Drilling Evaluation Log was developed by Anadril and Sigmalog, developed by AGIP abd Geoservice. MLNDR and Sigmalog suffer from being area specific (MLNDR to the Gulf of Mexico, Sigmalog to the Po valley). The commonest and most understood drilling model is d exponent. Various workers had looked at the problem of using drilling data to generate pore pressure values, but until 1966 the results were unsatisfactory. Jordan and Shirley derived an earlier  drill rate equation to produce an equation for drillability, d, or the d exponent. exponent. The d exponent varies inversely with ROP, but will increase with depth in a normally compacted argilaceous formation. The next step was to modify the equation to incorporate mud weight changes, using the normal pore pressure divided by ECD (Effective Circulating Density). This is called the Corrected (or Modified) d  d exponent, dc. The days of hand calculating d exponents are long gone, so suffice to say that dc is plotted on semilog paper against TVD and allows the ADT engineer to calculate pore pressures based on deviation from the normal compaction trend.

Plot of dC  14 of 53

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 As can be seen in the plot above, plots of d c require careful interpretation. Having to rely on picking up deviations from the trend line is fraught with problems. The initial problem is where to place the trend line. Dc  is also sensitive to changes in formation, hole size and bit type. Shales and claystones give the most reliable d C, so the trendline is placed so that it intercepts as many “shale points” as possible. Normal compaction should increase to the right, while the deviations that indicate indicate overpressure should be seen as a “cut back” to the left. Dc exponent is often criticised for inaccuracy and its reputation is not enhanced by poor interpretation. D c should only be used in conjunction with other indicators.

Dc plot showing the information required for accurate interpretation There are many debates about the movement of trend lines. In the case above had the trend line not been moved to the left for the 12 1/4” hole the calculated pore pressures would have been wildly inaccurate. Also visible in the plot above is the effect of using PDC bits, which also move the dc to the left. As dC is in effect an indicator of drillability, sandy formations may drill faster making dc shift to the left while hard limestones shift it to the right. A fining up sequence will generate a dc trace that appears to cut back, but is in fact due to the formation becoming more arenaceous. The dc exponent is unreliable when coring. Most important feature of the above plot is that the clay section where the PDC bit was run is overpressured. The dc  can be seen cutting back to the left before entering the limestone sequence. Bit dulling causes the dc to trend to the right, due to decrease in ROP. This may mask a cut back due to overpressure, but is only a pronblem towards the end of the run. Thin carbonates will effect the trend, but can also seal an overpressured zone. Marls cause the trend to shift to the right, which can give the impression that any overpressure is lower. In summary, the dc  exponent plot shows where overpressure probably is, but must be interpreted with care (especially when shifting trend lines) and with reference to other  parameters.

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C alcula alculation tion of overpress ure values values f rom d c  c  The commonest method of calculating pore pressure while drilling is the Eaton Equation, using the corrected d exponent (d c).   p =

S  -

(S  - pn) x (dco / dcn)  [ (S

Where

1.2

 

]

p =

Pore Pressure

S =

Overburden

pn  pn =

Normal Pore Pressure

dco =

Observed dc exponent

dcn = Normal dc exponent

dc exponent v depth plot

0 Normal Compaction Depth

Trend

Ft

TVD 5000  Abnormally Pressured Shale Dco = 1.0 Dcn = 1.25

10000 0.5

1.0

1.2

Dc Exponent

Using the data from the dc plot:  

p  =

Calculated Pore Pressure

S  =

Overburden

=

19 ppg  16 of 53

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pn  pn =

Normal Pore Pressure =

8.7 ppg

dcn =

No Norm rmal al D Dc c ex expo pone nent nt =

1.25

dco =

Obs Observ erved ed dc expone exponent nt

p =

19 -

p =

19 -

p =

19 - 7.879

p =

11.12 ppg 11.12  ppg

=

1.0 1.2

.25)   ] [  (19 - 8.7) x (1.0 / 11.25) (10.3 x 0.765)

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Pore pressure evaluation while drilling

There are other m ethods of estimating formation pressure while drilling in addition to dc. They do, however, depend on samples of formation being available. Bulk density  density  - Cuttings are washed and placed in a Baroid balance until the balance reads 8.33ppg / 1.0sg. Top up with fresh water (stirring to expel air) and replace cap. After wiping off  any excess water, reweigh and take the reading from the scale. Use the reading in the relevant formula. 1 sg =

------------------------

8.33 ppg =

2 - Final W eight

------------------------------16.66 - Final W eight

Values tend to be lower than shale density due to absorption of drilling fluid and the washing water by hydroturgid shales, but trends can be seen. Useful in argillaceous rocks. Watch for  decrease in trend, this is indicative of overpressure. Shale density density - a graduated column filled with variable density fluid and 4 - 5 glass beads of  different (known) density is used to test the density of shale fragments. A calibration chart is drawn with density against against the graduations on the column. Shale fragments are dropped in the column and the point where they stop is read off and checked against the calibration chart.  Again, the density is plotted against depth and any deviation from the trend may indicate overpressure. Shale factor   -- also known as the Methylene Blue TesT (MBT) test. Measures the cuttings’ Cation Exchange Capacity. As diagenesis proceeds, the Montmorillonite in the sediments converts to Illite, so the amount of Montmorillonite should decrease with depth. Overpressured zones are more likely to have increased Montmorillonite due to normal dewatering not having taken place and the pore fluid supports more of the overburden. Diagenesis, being pressure related, does not occur to the same extent due to this f luid supported condit condition, ion, so the ratio of  Montmorillonite to Illite in a given formation will increase. Montmorillonite has a higher Cation Exchange Capacity than Illite, so the higher the CEC, the more Montmorillonite. Shale factor  should decrease with depth, following following a normal compaction trend. Deviatio Deviations ns from the normal compaction trend should indicate overpressured zones. Calculating pore pressure from the above involves plotting the data against depth, identifying the normal compaction trend and any deviations from that trend. The method used to calculate a formation pressure is called the Depth of Seal method.

Depth of S eal eal May be used with formation density, seismic velocity, formation resistivity, interval transit time, Dc Exponent or shale factor. Based on the density of an overpressured shale at the depth of interest being the same as the density at the "depth of seal" on the normal compaction trend.  As a result of this this relationshi relationship, p, the Matrix Stress at these d depths epths wil willl be the same.

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Formula

S = σ + P

where S  = Overburden σ = Matrix Stress

P  = Pore Pressure

EXAMPLE

This example uses a plot of shale density.

To calculate the Pore Pressure at 5400ft

Depth of seal (ds)

1400ft

Overburden at 1400ft S (ds)

0.68 psi/ft

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Overburden information from the well overburden table or offset data Pore pressure pressure at 1400ft P(ds) = normal 0.45 psi/ft Depth of interest (di) =

5400ft

Overburden at 5400ft S(di)=

0.83 psi/ft

Using the relationship relationship   S = σ + P  

σ = S(ds) - P(ds) σ =

0.68 - 0.45 psi/ft

σ =

0.23 psi/ft

Since all pressure variables should be in units of absolute pressure, they must all be converted to psi. Calculate the matrix stress s at depth of seal (ds) σ psi = σ x (ds)ft σ psi = 0.23 0.23psi/ft psi/ft x 1400 1400ft ft σ psi = 322psi 322psi

Calculate S(di)the overburden at depth of interest, S(di) = S(di) psi/ft x (di (di)ft )ft = S(di) psi S(di) = 0.83 0.83 psi/ft  psi/ft x 5400 5400ft ft = 4482 4482 psi  psi To calculate the pore pressure at 5400ft, P(di), use: P(di) = S(di) - σ P(di) = 4482 4482 psi  psi - 322 psi 322 psi P(di) = 4160 4160 psi  psi Convert to ppg = 4160 psi 0.052 x 400ft = 14.8ppg

Calculated Pore Pressure at 5400ft = 14.8ppg  20 of 53

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Other Pore Pressure Indicators

Gas levels, drag, fill, temperature, cavings and torque can indicate the presence of  overpressured formations. They can been used qualitatively to lend support to information obtained from quantitative methods such as dc.

G as levels levels  After dc exponent, gas is probably the best indication that an overpressured formation is being penetrated. Although affected by lithology and ROP, gas remains a good qualitative indicator. indicator.

The diagram above shows the effect of increasing pore pressure on gas levels

Background gas   - The amount of gas in the mudstream is dependent on the ROP, amount of gas in the drilled formation and the pressure differential in the borehole. As the differential between pore pressure and mud hydrostatic is reduced by increasing pore pressure, background gas gradually increases. Connection gas  

- as the differential approaches balance, additional gas can be introduced to the well bore by the action of pipe movement at connections causing swab pressures. Connection gas appears as sharp peaks above the drilling background gas level. The peaks will appear at bottoms up from the connection. Connection gas can be used to quantify the pore pressure by using the swab/surge application to calculate swab pressures. NB connection gas is reported as a peak above background.

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Snapshot showing connection gas

Trip g as  - the size and arrival time of trip gas can give an idea of the downhole environment. environment.  Although also caused by the the swab action of the pipe, trip gas is thought to be caused by poor  filter cake formation, due to low overbalance overbalance.. Non-drilling Non-dril ling ba backg ckg round g as   - a very useful tool as it indicates the state of the hole when the bit is off bottom and circulating. On high pressure / High temperature wells it is good practice to circulate off bottom to establish a non-drilling background. As this is unaffected by drilling effects, variations in NDB can indicate changes down hole. Cavings  - as balance is approached the confining pressure on the drilled formation may be reduced enough to allow fragments of rock to slough off and cave into the borehole. The cavings will be carried to the surface by the mud, but if too large to be lifted, will remain in the hole to cause further problems. When examined, pressure cavings are normally larger than drilled cuttings, splintery and curved. Note some formations may react with mud to produce similar cavings e.g. the Kimmeridge Clay. Drag on connections  - indicates that the borehole is unstable and the shale behaving plastically. As overpressured (undercompacted) shales can behave in a plastic manner the borehole wall encroaches on the bit and stablisers, showing as drag when the string is picked up. Pressure cavings can also enter the hole and accumulate around the bit. Note - in high angle directional holes drag is normal, so it is unreliable as a pore pressure indicator.

Torque  - As with drag, torque is caused by the borehole encroaching on the drilling tools.  Again torque is is unreliabl unreliable e in high an angle gle holes. Fill  - on going back on bottom after a connection cavings that have accumulated at the bottom of the hole have to be "drilled out". T he caving process may be aggravated by the lack of additional overbalance when the pumps are shut down.

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The snapshot above shows the effect of hole fill after a short trip.

Temperature  - overpressured zones are characterised by having a increased thermal gradient. Flow line temperature and ∆T (temp out - temp in) are normally plotted and should give an indication that an overpressured zone is being approached. Entering an overpressured zone will normally be associated with an increase in flow line temperature.

Plot showing temperature against depth when drilling into an overpressured zone. Note how the temperature gradient decreases in the cap rock.  23 of 53

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Drilling the cap rock above the zone may show a decrease in flowline temperature due to its higher thermal conductivity, but as the undercompacted zone is entered, flow line temp should increase. Temperature readings can be affected by many surface factors such as mud additions or riser length, so much so that in some cases it is useless.

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Post drilling analysis

Wireline logs allow the ADT to check the pore pressure values obtained while drilling. The main parameters used are Sonic, Density and Resistivity. Direct formation pressure readings can be obtained from RFT (Repeat Formation Tester) tools, which measure the pressure in the formation by clamping a pressure tool to the borehole wall. RFTs require some porosity and permeability to obtain good readings, so are not suitable for measuring presures from claystones.

Pore press ure from from s onic llog og s Post drilling pore pressure analysis can be done using sonic logs, again using the   Eaton Equation. Sonic transit time, ∆T, will decrea decrease se with depth as the densi density ty of the formation increases due to reduction in porosity. Sonic is plotted against depth on semilog paper and a normal compaction trend identified. Deviations Deviations from the trend m ay be due to overpressured formation.    

p =  S -  (S - pn) pn)  x ( ∆Tn / Tn /  ∆To) To)3.0 Where p

= Pore Pressure

S

= Overburden

pn  pn 

= Normal Pore Pressure

∆Tn  Tn 

= Normal Sonic ∆T

∆To  To 

= Observed Sonic ∆T

Pressure variables used in these calculation calculations s should be expressed as gradients (psi/ft)

0

Normal Compaction

Depth

Trend

Ft ∆ Tn

∆ To  Abnormally

5000

Pressured Shale

∆ Tn = 138 ∆ To = 191

10000

80

100

200

µ Sonic Velocity ( sec/ft) Using the data from the sonic plot: p

= Calculated Pore Pressure  25 of 53

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S

= Overb erburd urden

= 0.68 0.68 psi/ft  psi/ft

pn

= Normal Pore Pressure

= 0.452 0.452 psi/ft  psi/ft

∆Tn  Tn 

=Normal Sonic ∆T

= 138 usec/ft 138 usec/ft

∆To  To 

= Observed Sonic ∆T

= 191 usec/ft 191 usec/ft

p  = 0.68 0.68   - (0.68 (0.68 - 0. 0.452 452)) x ( 138 / 191 ) 191 )3.0 p =  0.68 0.68   - 

(0.228 0.228   x 0.377 0.377))

p =  0.59 0.59 psi/ft  psi/ft p = 0.59 0.59   /  / 0.052 0.052 ppg  ppg p = 11.42 ppg

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Pore pressure from resistivity logs Post drilling pore pressure analysis can be done using resistivity logs, again using the Eaton Equation. If MWD resistiivity tools are being run it is also possible to calculate the pore pressure while drilling, in a similar manner to that employed for d c. Deep resistivity is the most relevant for pore pressure detection as it will ideally be reading uninvaded formation. Resistivity should increase with depth through a normally compacted shale section, due to the decrease in the volume of pore fluid. Deviations from the normal trend may be due to undercompacted sediments, but be aware that resistivity changes with the salinity of the pore fluid.    

1.2

p = S - (S - pn) x ( Rn / Ro) Where p 

= Pore Pressure

S

= Overburden

pn  pn 

= Normal Pore Pressure

Rn  Rn 

= Normal Resistivity

Ro  Ro 

= Observed Resistivity

Pressure variables used in these calculation calculations s should be expressed as gradients (psi/ft)

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p 

= Calculated Pore Pressure

S 

= Overb erburd urden

pn  pn 

= Normal Pore Pressure = 0.452 psi/ft

Rn  Rn 

=Normal Resistivity

= 1.1 1.1 Ohm/m  Ohm/m

Ro  Ro 

= Observed Resistivity

= 0.6 Ohm/m 0.6 Ohm/m

  = 0.68 0.68 psi/ft  psi/ft

1.2

p = 0.68 0.68   - (0.68 (0.68   - 0.452 0.452)) x ( 0.6 / 0.6 / 1.1 1.1 )  )

p = 0.68 -

(0.228 0.228   x 0.438 0.438))

p = 0.59 0.59 psi/ft  psi/ft

p = 0.59 0.59 /  / 0.052 0.052 ppg  ppg

p = 11.15 ppg

Pore press ure from Density logs Uses the same depth of seal method as described for “while drilling”, but with wireline density data.

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Fracture Pressure

Fracture pressure determines the maximum mud weight which can be run in a particular hole section. While high mud weights are used to control overpressured zones, severe problems can be encountered if the m ud weight, or rather its hydrostatic pressure, exceeds the fracture pressure of the form ation. Accurate knowledge of the formation fracture pressure is necessary to prevent problems such as lost circulation or subsurface blow outs.

 Mechanis  Mech anis ms  Applying pressure to a formation will initiate fractures along the line of least resistance within  Applying the rock. To propagate these fractures the pressure must be greater than that of the least principal stress. Fractures will propagate normal to the direction of least principal stress. This direction can be ascertained by looking at the region’s faults. Normal faults indicate the least principal stress is horizontal. Reverse faults indicate least principal stress is vertical. Transcurrent faults, although indicating horizontal, means that the stress is higher than for  normal faults but insufficient to cause reverse faulting.

Leak off tests LOTs are performed to establish the formation breakdown gradient after a casing string has been set. After drilling out the casing tools and a few metres of new formation the hole will be circulated clean and the annular preventer closed. Using the cement pump, the pressure is increased by pumping in increments until leak off is attained.

Leak off test graph

To the leak then off asconvert an EMW, theweight. mud weight to a hydrostatic pressure, add the calculate surface pressure, backconvert to a mud  29 of 53 Data Data Eng ineering

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Casing is normally set in a competent formation like a claystone and the LOT is usually performed in a similar formation. Unfortunately if the formation changes to a less competent lithology such such as a sandstone, the maximum allowable mudweigh mudweightt (obtained from the LOT) is no longer valid. In order to maintain borehole integrity the ADT engineer calculates fracture gradient while the hole is being drilled. This requires a model which can be updated with depth.  Daines Fracture Gradient The Daines method is the most widely u used sed technique for the estimation of fracture gradients. Its use is recommended by most operators operators and is specified by BP on all of their their wells. Our  systems offshore are configured to produce fracture gradients using this method. Fracture gradients can be estimated by employing the Daines technique which incorporates the use of a tectonic stress which is either known for a region or is calculated from Leak Off  Test values. Tectonic stresses are calculated at each Leak Off Test using the Daines relationship: µ  )+ P ]

Tectonic Stress ( T ) = F - [ (S-P) x (  

-µ

Where,

 

S (sg emw) =

Overburden pressure

 

P (sg emw) =

Pore pressure

 

F (sg emw) =

Fracture pressure

 

µ

=

Poissons Ratio.

Poissons ratio (µ) is a value between 0 and 1 that attempts to reflect the relationship between elasticity and rigidity of different lithologies. There is a predefined list of figures available that have been collated from the work of various authors, notably Wuerker (1961) and Daines (1982). Fracture gradients gradients can then be calculated at regu regular lar depth interval intervals, s, inputting appropriate values for Poisson's Ratio at each lithology change. As each leak off test /formation integrity test is performed the equation abo above ve can be rearranged to give :Fracture Gradient Gradient ( F ) = T +  [ (S-P) x (  

µ  ) + P ]

-µ

Daines’ method uses the actual actual formation fracture pressure as a basis for further calculations as the well deepens. This fracture pressure is the Leak Off Test Pressure gradient. By knowing the formation at the test depth (from the log) it is possible to look up the Poisson’s ratio of that formation. Since the overburden gradient and the formation pressure is known, the tectonic stress ratio for the well can be calculated. The tectonic stress ratio is then used to calculate fracture pressures as drilling proceeds, only requiring the Poisson’s ratio to be changed. Good geological control is required for Daines to work as advertised. As it is the rock matrix which is involved in the fracturing, attention should  30 of 53

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be paid to any matrix or cement in the formation. The Poisssons ratio should be selected on this basis. One feature of the Daines method is that it does require a Leak Off Test. Many operators only conduct formation integrity tests. An FIT is conducted to ensure that the formation will be able to hold a specific pressure without breaking down. As a result this FIT does not represent the true fracture properties of the formation at that depth. This can produce spurious results when the FIT values are applied to fracture gradient prediction. prediction. The diagram below shows the effect of using FIT data compared with LOT data. Engineers should be aware of this.

 AIR GAP WATER

30” CSG 20” CSG D E

FIT =

*

 

LOT = 1.74 SG

1.56

P

L

T

I

H

T H O

FRACTURE GRADIENT

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Calculation of fracture gradients in practice  As in the case of overburden, the fracture gradient calculations calculations are best done on a spreadsheet. The first step is to calculate the tectonic stress ratio from the leak off data. This uses the overburden, pore pressure gradient  gradient  and the Poisson’s Ratio  Ratio  at the leak off  depth. Having calculated the tectonic stress ratio, it is used as the reference cell for the rest of the drilled interval. Set up the next section of the spreadsheet using the same depth interval as the overburden. Copy the overburden gradient data into the fracture sheet as column 2 , and input the pore pressure in the next column. The fourth column calculates the matrix stress which is overburden minus the pore pressure. Column five contains the Poisson’s ratio, and is input manually depending on the lithology. Column 6 contains the µ ratio that is the Poissons ratio divided by 1 minus Poisson’s ratio. The horizontal stress is calculated in column 7 and is the matrix stress multiplied by the µ ratio. Column 8 calculates the tectonic stress, which is the tectonic stress ratio multiplied by the matrix stress. the final column calculates the fracture gradient gradient using the Daines equation.  The fracture gradient data can then be used for reports and plots. Daines fracture gradient spreadsheet

FIRST LEAK OFF TEST DATA

LOT DEPTH:

1 6 9 8 mM D

LOT

Overburden

Pore Press.

Matrix Stress

Daines

Ratio

Horiz.

Tectonic

Tectonic/Matrix

sg

S

P

S-P

µ

µ/(1−µ)

Stress

Stress

Stress Ratio

1. 31

1. 48

1.04

0.44

0. 17

0. 20

0.0 9

0. 18

0.41 (Const. for the w ell)

GIV EN:

where

F = P + ( S - P ) ( µ / 1−µ ) + σ

σ = Tectonic Stress

Well 399/12b-2 Depth

Ov ve er burde n

Pore Press.

Matrix

m

S (sg)

P (sg)

S-P

1 7 10 1 7 20 1 7 30 1 7 40 1 7 50

1. 3 9 1. 3 9 1. 4 0 1. 4 1 1. 4 1

1.04 1.04 1.04 1.04 1.04

0. 35 0. 35 0. 36 0. 37 0. 37

µ

0 .17 0 .17 0 .17 0 .17 0 .17

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µ

Horiz.

Tectonic

Fracture

Rat io

Stress

Stress

Pressure

0. 20 0. 20 0. 20 0. 20 0. 20

0. 07 0. 07 0. 07 0. 07 0. 08

0.14 0.14 0.15 0.15 0.15

1.25 1.26 1.26 1.26 1.27

Data Data Eng ineering

 

  Poiss ons R atio (  µ )

Clay (v. wet)

0.5

Clay

0.17

Coal

0.19

Conglomerate

0.2

Dolomite

0.21

Greywacke

Limestone

Sandstones

Shale

course

0.07

fine

0.23

medium

0.24

fine micritic

0.28

medium calcarenitic

0.31

porous

0.2

stylolitic

0.27

fossiliferous

0.09

bedded fossils

0.17

shaley

0.17

coarse

0.05

coarse, w cemented

0.01

fine

0.03

very fine

0.04

medium

0.06

poorly sorted, clayey

0.024

fossiliferous

0.01

calcareous (