Abnormal Formation Pressure Analysis

ABNORMAL FORMATION PRESSURE ANALYSIS

Version 2.1 February 2001

Dave Hawker

Corporate Mission To be a worldwide leader in providing drilling and geological monitoring solutions to the oil and gas

industry, by utilizing innovative technologies and delivering exceptional customer service.

DATALOG: ABNORMAL FORMATION PRESSURE ANALYSIS, Version 2.1, issued February 2001


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CONTENTS

1. INTRODUCTION................................................................................................................................................ 4

2. PRESSURES & GRADIENTS............................................................................................................................ 5 2.1 HYDROSTATIC PRESSURE.................................................................................................................................. 5 2.2 FORMATION PRESSURE ..................................................................................................................................... 8

2.2.1 Direct Pressure Measurements ................................................................................................................. 9 2.2.1.1 Repeat Formation Test ....................................................................................................................... 9 2.2.1.2 Drill Stem Test ................................................................................................................................... 9

2.2.2 Indirect Pressure Measurements............................................................................................................. 10 2.2.2.1 Kick Shut-In Pressures ..................................................................................................................... 10 2.2.2.2 Connection Gases............................................................................................................................. 11

2.3 FRACTURE PRESSURE ..................................................................................................................................... 12 2.3.1 Leak Off Tests.......................................................................................................................................... 13

2.4 OVERBURDEN STRESS..................................................................................................................................... 16 2.4.1 Determination of Bulk Density................................................................................................................ 17

2.4.1.1 Bulk Density from Cuttings.............................................................................................................. 18 2.4.1.2 Bulk Density from Sonic Logs ......................................................................................................... 19

2.4.2 Calculation of Overburden Gradient ...................................................................................................... 20 2.5 BALANCING WELLBORE PRESSURES............................................................................................................... 24

2.5.1 Mud Hydrostatic ..................................................................................................................................... 24 2.5.2 Equivalent Circulating Density............................................................................................................... 25 2.5.3 Surge Pressures....................................................................................................................................... 26 2.5.4 Swab Pressures ....................................................................................................................................... 26 2.5.5 Kick Tolerance ........................................................................................................................................ 28

2.5.5.1 Kick Tolerance, worked example..................................................................................................... 30 2.6 SUMMARY OF FORMULAE ................................................................................................................................33

3 OCCURRENCES OF ABNORMAL FORMATION PRESSURE................................................................. 35 3.1 UNDERPRESSURED FORMATIONS..................................................................................................................... 35

3.1.1 Reductions in Confining Pressure or Fluid Volume ............................................................................... 35 3.1.2 Apparent Underpressure......................................................................................................................... 35

3.2 OVERPRESSURE REQUIREMENTS..................................................................................................................... 37 3.2.1 Overpressure Model................................................................................................................................ 37

3.2.1.1 Permeability ..................................................................................................................................... 37 3.2.1.3 Fluid Type ........................................................................................................................................ 38

3.3 CAUSES OF OVERPRESSURE............................................................................................................................ 39 3.3.1 Overburden Effect ................................................................................................................................... 39 3.3.2 Tectonic Loading .................................................................................................................................... 41

3.3.2.1 Faulting ............................................................................................................................................ 41 3.3.2.2 Deltaic Environments ....................................................................................................................... 42 3.3.2.3 Diapirism/Domes ............................................................................................................................. 43

3.3.3 Increases in Fluid Volume ...................................................................................................................... 44 3.3.3.1 Clay Diagenesis................................................................................................................................ 44 3.3.3.2 Gypsum Dehydration ....................................................................................................................... 45 3.3.3.3 Hydrocarbon or Methane Generation............................................................................................... 45 3.3.3.4 Talik and Pingo Development.......................................................................................................... 45 3.3.3.5 Aquathermal Expansion ................................................................................................................... 46

3.3.4 Osmosis ................................................................................................................................................... 46



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3.3.5 Hydrostatic causes .................................................................................................................................. 47 3.3.5.1 Hydraulic Head ................................................................................................................................ 47 3.3.5.2 Hydrocarbon Reservoirs....................................................................................................................47

4 OVERPRESSURE DETECTION...................................................................................................................... 48 4.1 BEFORE DRILLING........................................................................................................................................... 48 4.2 REAL-TIME INDICATORS ................................................................................................................................. 49

4.2.1 Rate of Penetration ................................................................................................................................. 49 4.2.2 Drilling Exponent.................................................................................................................................... 50 4.2.3 Corrected Drilling Exponent................................................................................................................... 51 4.2.4 Trend/Shift Changes and Limitations...................................................................................................... 53

4.2.4.1 Lithology.......................................................................................................................................... 53 4.2.4.2 Bit Type and Wear ........................................................................................................................... 55 4.2.4.3 Fluid Hydraulics............................................................................................................................... 56 4.2.4.4 Significant Parameter Changes......................................................................................................... 56 4.2.4.5 Directional Drilling .......................................................................................................................... 56

4.2.5 Torque, Drag and Overpull ..................................................................................................................... 57 4.2.6 Tripping Indicators ................................................................................................................................. 57

4.3 LAGGED INDICATORS...................................................................................................................................... 58 4.3.1 Background Gas Trends.......................................................................................................................... 58

4.3.1.1 Sealed Overpressure......................................................................................................................... 59 4.3.1.2 Transitional Overpressure ................................................................................................................ 59

4.3.2 Connection Gas....................................................................................................................................... 61 4.3.3 Temperature............................................................................................................................................ 66

4.3.3.1 Geothermal Gradient ........................................................................................................................ 66 4.3.3.2 Flowline Temperature ...................................................................................................................... 67 4.3.3.3 Delta T ............................................................................................................................................. 68 4.3.3.4 Trends .............................................................................................................................................. 69

4.3.4 Analysis of Drilled Cuttings .................................................................................................................... 70 4.3.4.1 Shale Density ................................................................................................................................... 70 4.3.4.2 Pressure Cavings .............................................................................................................................. 71 4.3.4.3 Shale Factor...................................................................................................................................... 72

4.4 INFLUX INDICATORS ....................................................................................................................................... 73 4.5 WIRELINE / LWD INDICATORS ....................................................................................................................... 74

4.5.1 Sonic Transit Time .................................................................................................................................. 74 4.5.2 Resistivity ................................................................................................................................................ 75 4.5.3 Density .................................................................................................................................................... 76 4.5.4 Neutron Porosity ..................................................................................................................................... 76 4.5.5 Gamma Ray............................................................................................................................................. 77 4.5.6 Wireline Examples .................................................................................................................................. 78

5. QUANTITATIVE PRESSURE ANALYSIS.................................................................................................... 81 5.1 CALCULATION TECHNIQUES............................................................................................................................ 81

5.1.1 Eatons Method ........................................................................................................................................ 82 5.1.2 Equivalent Depth Method ...................................................................................................................... 85 5.1.3 Ratio Method........................................................................................................................................... 87



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6. CALCULATION OF FRACTURE GRADIENT............................................................................................ 88 6.1 GENERAL THEORY.......................................................................................................................................... 89 6.2 CALCULATION METHODS................................................................................................................................ 90

6.2.1 Eatons Method ........................................................................................................................................ 90 6.2.2 Poissons From Shaliness Index............................................................................................................... 90 6.2.3 Daines Method ........................................................................................................................................ 92

7. USE OF THE QLOG SOFTWARE ................................................................................................................. 94 7.1 GENERAL PROCEDURE.................................................................................................................................... 94 7.2 OVERBURDEN PROGRAM ................................................................................................................................ 95 7.3 OVERPRESSURE PROGRAM ............................................................................................................................. 97

7.3.1 Multiple NCTs....................................................................................................................................... 100

8. EXERCISES..................................................................................................................................................... 101

9. BIBLIOGRAPHY ............................................................................................................................................ 112



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1. INTRODUCTION In order to properly plan a well program and to drill a well, both safely and economically, knowledge and understanding of formation pressures and fracture gradients is essential. This allows mud densities, and positioning of casing shoes, to be optimised to provide sufficient balance against formation pressures while not being to high so that formations are at risk of being damaged or fracture. Formation pressure analysis is, therefore, an integral part of any drilling operation. It is one of the most important services provided by a mud logging service, but is almost one of the, technically, most demanding. Pressure Engineers assume a great deal of responsibility since their analyses and predictions are of genuine importance to the success of a drilling operation. Many sources of data have to be evaluated alongside each other before a reliable analysis can be made. Often, different sources of information may give conflicting results, in terms of predicting pressure changes, so that the engineer has to evaluate which sources of data are the most reliable. Often, different environments or different drilling regimes will result in different data sources being the most reliable, so from a pressure analysis perspective, two wells are seldom the same. Seismic data, or offset electrical data can be the initial data source. Any predictions can then be verified or improved upon, by data collected while drilling, by wireline at the end of each hole section, or through testing or the occurrence of specific drilling events. A good pressure report requires complete analysis and evaluation of all data sources; it must be extremely accurate, and all conclusions have to be substantiated. The new pressure engineer will discover that theory can indeed be read from a book and learnt in the classroom, but accurate pressure engineering only comes with experience and exposure to different pressure regimes, increasing the level of understanding of this complex science. This manual therefore serves as a starter kit to your challenging new position!



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2. PRESSURES & GRADIENTS

2.1 Hydrostatic Pressure Hydrostatic Pressure, at any given vertical depth, is defined as the pressure exerted by the weight of a static column of fluid. It is, therefore, pressure resulting from a combination of the fluid density and the vertical height of the fluid column. At any true vertical depth: Phyd = g h where Phyd = hydrostatic pressure = fluid density h = vertical depth g = conversion factor i.e. KPa = kg/m3 x 0.00981 x TVD(m) KPa = kilo Pascals m = metres PSI = ppg x 0.052 x TVD(ft) PSI = pounds per square inch ppg = pounds per gallon ft = feet

OVERBURDEN STRESS

Mud Hydrostatic Pressure

Formation Pore Fluid Pressure

Fracture Pressure



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Considering that water density will vary depending on the concentration of salt, this formula gives the following example range of normal hydrostatic gradients: - Hydrostatic Gradient is the rate of increase of pressure with depth,

i.e. Hydrostatic Gradient = pressure/unit height = density x conversion factor

Freshwater: Density = 8.33 ppg or 1.0 SG (1 gm/cc or 1000 kg/m3) Hydrostatic Gradient = 8.33 x 0.052

= 0.433 psi/ft or = 1000 x 0.00981

= 9.81 KPa/m Brine: Density (e.g) = 9.23 ppg or 1.11 SG (1.11 gm/cc or 1108 kg/m3) Hydrostatic Gradient = 9.23 x 0.052

= 0.480 psi/ft or = 1108 x 0.00981

= 10.87 KPa/m The diagram below illustrates these two hydrostatic gradients and the resulting pressures:



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At 3000m,

Freshwater, density 1000 kg/m3, exerts a pressure of 1000 x 3000 x 0.00981 = 29, 430 KPa

Saline water, density 1108 kg/m3, exerts a pressure of 1108 x 3000 x 0.00981 = 32, 608 KPa

3000m

PRESSURE (KPa)

DEPTH

9.81 KPa/m

10.87 KPa/m

29,430 32,608



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2.2 Formation Pressure Formation Pressure is defined as the pressure exerted by the fluid contained within the pore spaces of a sediment or rock. It is often termed Pore Pressure. In reality therefore, formation pressure refers to the hydrostatic pressure exerted by the pore fluid and is therefore dependent on the vertical depth and the density of the formation fluid. Normal formation pressure will be equal to the normal hydrostatic pressure of the region and will vary depending on the type of formation fluid. For example, in the northern North Sea, Normal pore fluid density is equal to 1.04 SG (here, the formation connate water is actually very close to the present day seawater density) This density (8.66 ppg or 1040 kg/m3) gives a normal formation pressure gradient of 0.450 psi/ft or 10.20 KPa/m: 8.66 ppg x 0.052 = 0.450 psi/ft 1040 kg/m3 x 0.00981 = 10.20 KPa/m In the Gulf of Mexico, Normal pore fluid density is 1.07 SG, giving a normal pressure gradient of 0.465 psi/ft or 10.53 KPa/m: 8.94 ppg x 0.052 = 0.465 psi/ft 1074 kg/m3 x 0.00981 = 10.53 KPa/m In other words, even though the pressure gradients are different, both are normal formation pressure gradients for the given regions. For a given region then, If Formation Pressure = Hydrostatic Pressure, the formation pressure is normal If Formation Pressure < Hydrostatic, the formation is underpressured If Formation Pressure > Hydrostatic, the formation is overpressured



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Pressure analysis, in any given region, therefore requires knowledge of the normal fluid density and the resulting fluid pressure. This can either be determined by laboratory analysis of fluid samples, or by direct pressure measurements: Direct measurement of the formation pressure can only be achieved where the formation has sufficient permeability for the formation fluid to reach equilibrium with a pressure gauge over a short period of time. For low permeability formations, formation pressure can only be estimated, and this forms a significant component of formation pressure analysis. 2.2.1 Direct Pressure Measurements 2.2.1.1 Repeat Formation Test This is an open hole wireline tool that, per run, allows the collection of two formation fluid samples and an unlimited number of formation pressure measurements. A spring or piston type mechanism holds a probe firmly against the borehole wall and a hydraulic seal (from the drilling mud) is formed by packer. The piston creates a vacuum in a test chamber, allowing formation fluids to flow into sample chambers. The pressure during the flow, and the subsequent build up, is measured. The initial shut-in pressure is recorded. The test valve is opened to allow the formation fluids to flow into the chamber the flow rate is recorded as the chamber fills. Once full, the final shut-in pressure is recorded. The build up or shut-in pressures may need to be corrected to yield true formation pressure, since, particularly with lower permeability formations, pressure build up may not have stabilized. Tight formations, certainly, may result in the test being aborted, because the fear of becoming stuck will discourage most operators from allowing the test to continue for too long a period. Seal failure may result if the probe cannot be properly isolated from the mud (due to low permeability rocks, poor filter cake development, or material stuck to the probe), so that pressure does not increase much beyond the mud hydrostatic pressure. Higher, or supercharged, formation pressure measurements may result where low permeability zones have been invaded by higher pressured muds. 2.2.1.2 Drill Stem Test This is a production test of a reservoir zone where hydrocarbons have been encountered. The test can be performed in open or cased (i.e. production liners) holes. Typically, the borehole is cased; the interval to be tested is then sealed off with packers; the isolated zone can then be perforated to allow formation fluids to flow to surface.



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The differences between starting and end pressures, during a period of flow, yields information related to both the reservoir productivity and the volume of hydrocarbons. When the DST tool is in place, a packer (single or straddled packer arrangements may be used to isolate a particular zone of interest) is set to form a seal and the test can begin. Most DSTs incorporate 2, perhaps 3, flow and shut-in periods. Formation Pressure is most accurately estimated from the Initial Shut-In Pressure (ISIP) at the end of the Initial Flow. This flow may last up to an hour and allows fluid to flow to surface with the purpose of removing any pressure pockets from the wellbore; cleaning out any mud filtrate fluids that may have invaded the formation and removing mud from the drillstem.. Subsequent flow periods will result in Final Shut-In Pressures (FSIP) that will be slightly lower than the ISIP since some of the reservoir fluids have already been produced, therefore formation pressure is determined from the ISIP. Sometimes, a stable ISIP may not be reached over the relatively short time before the test is ended, so that the pressure has to be extrapolated. The lower the permeability of the zone, the more likely this is. 2.2.2 Indirect Pressure Measurements 2.2.2.1 Kick Shut-In Pressures If formation pressure exceeds the hydrostatic (or balancing) pressure of the mud column, then, as long as fluids can flow, a kick will result. Following a successful well control operation, the mud hydrostatic pressure required to balance, or kill, the well, is clearly equal to the actual formation pressure. An important criterion for this estimation is knowledge of the exact depth of influx, but, as long as this is known, the formation pressure can be accurately, although indirectly, measured from the well shut-in pressures. The shut-in (drill pipe) pressure is the additional pressure, in addition to the mud hydrostatic pressure, required to balance the higher formation pressure. At depth of influx: Mud Hydrostatic Pressure + SIDP = Formation Pressure For example,

At 2500m (TVD), a kick is taken while drilling with a mud weight of 1055 kg/m3. The well is shut in and a shut-in drillpipe pressure of 1300 KPa is recorded.

Formation Pressure = (1055 x 2500 x 0.00981) + 1300 = 27, 174 KPa KMW = 27174 / (2500 x 0.00981) = 1108 kg/m3



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2.2.2.2 Connection Gases Connection gas is the term giving to a gas response, of short duration, that occurs as a result of a momentary influx of formation fluids into the wellbore, when the annular pressure is momentarily reduced below the formation pressure. This reduction may be as a result of simply turning the pumps off so that the annular pressure drops from a circulating pressure to static mud hydrostatic pressure, or, it may be as a result of a pressure reduction caused by the act of lifting the drillstring (swabbing). Knowledge of the balancing pressures (i.e. circulating pressure, hydrostatic pressure, swab pressure) when a connection gas is recorded, allows an indirect determination of formation. Although an exact value cannot be determined, a relatively small pressure range can be determined, and other than the techniques detailed above, connection gases are the most accurate determination of formation pressure while a well is being drilled. Analysis of connection gases will be discussed in more detail in Section 4.3.2.



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2.3 Fracture Pressure All materials, including rocks, have a finite strength. Certainly, rock samples (recovered through coring operations, for example) can be tested in laboratories for strength by using conventional analysis. However, the in situ strength of a rock exposed by a wellbore may vary from a laboratory determination, because there are many other factors and stresses involved. This makes the determination and analysis of fracture pressure and gradient, very difficult at the wellsite. Simply, Fracture Pressure can be defined as the maximum pressure that a formation can sustain before its tensile strength is exceeded and it fails. Factors affecting the fracture pressure include: Rock type In-situ stresses Weaknesses such as fractures, faults Condition of the borehole Relationship between wellbore geometry and formation orientation Mud characteristics If a rock fractures, a potentially dangerous situation exists in the wellbore. Firstly, mud loss will result in the fractured zone. Depending on the mud type and the volume lost, this can be extremely costly. Mud loss may be reduced or prevented by reducing annular pressure through reduced pump rates, or, more expensive remedial action may be required, using a variety of materials to try and plug the fractured zone and prevent further loss. Obviously, all of this type of treatment is extremely damaging to the formation and is to be avoided if at all possible. However, if mud loss is so severe, then the mud level in the wellbore may actually drop, reducing the hydrostatic pressure exerted in the wellbore. This may result in a zone, elsewhere in the wellbore, becoming underbalanced and flowing we now have an underground blowout! Knowledge of the fracture gradient is therefore essential while planning and drilling a well, yet there are only two ways of direct determination. The first is an undesirable method if mud losses to the formation occur while drilling, then one of two things has occurred. Either an extremely cavernous formation has been penetrated, or a formation has been fractured. Knowing the depth of the fractured zone and the circulating pressure balancing the wellbore at the time of fracture, will enable the fracture pressure to be calculated.



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2.3.1 Leak Off Tests This is a test performed at the beginning of each hole section to determine the fracture pressure at that point. At the end of a hole section, after logging has been completed, casing will be run, and cemented in place, to isolate all formations drilled. Before drilling ahead the next hole section, it is critical to determine that the cement bond is strong enough to prevent high pressure fluids, that may be encountered in the next hole section, from flowing to shallower formations or to surface. If as intended, cement holds the pressure exerted during the test, then formation fracture will occur, under controlled conditions. The formation at this depth, because it is the shallowest point, will typically be the weakest formation encountered in the next hole section, so that the fracture pressure determined from the test will be the maximum pressure that can be exerted in the wellbore without causing fracture. Two types of test may actually be conducted: - A Formation (or Pressure) Integrity Test (FIT or PIT) is often performed when the operator has a good knowledge of the formation and fracture pressures in a given region. With this test, rather than inducing fracture, the test is taken to a pre-determined maximum pressure, one considered high enough to safely drill the next hole section. A true Leak Off Test (LOT) does involve the actual fracturing of the formation: - After drilling through the casing shoe and cement, a small section (typically 10m) of new hole is drilled beneath the cement. The well is shut in, and mud pumped at a constant rate into the wellbore to increase the pressure in the annulus. The pressure should increase linearly and is closely monitored for signs of leak off, when the pressure will drop. The pressure plot against time, or mud volume pumped, shows that there are 3 principle stages to a complete Leak Off Test. It must be the operator who makes the decision as to which particular value is taken as the leak off pressure, but obviously, it should be the lowest value. This way well be the initial Leak Off Pressure, if the test hasnt been taken further to cause complete rupture. If it has, then the Propagation Pressure is likely to be the lowest, indicating that the formation has actually been weakened as a result of the test.



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During the Leak Off Test, a combination of two pressures actually induces the fracture: -

1. The Mud Hydrostatic Pressure 2. The Shut-in Pressure applied by pumping mud into the closed well

Pfrac = HYDshoe + LOP Where LOP is the shut-in pressure applied at surface, whether from a LOT or FIT For example: A Leak Off Test is performed at a shoe depth of 1500m; the mudweight is 1045 kg/m3 and the recorded leak off pressure is 15000 KPa Pfrac = (1045 x 1500 x 0.00981) + 8000 = 23, 337 KPa Pfrac (emw) = 23337 / (1500 x 0.00981) = 1589 kg/m3

The pressure engineer should be aware, that although the Leak Off Test is the only way of determine the fracture pressure, there are certain circumstances that can lead to inaccuracy or unreliability: -

Surface Shut In

Pressure

Mud Volume Pumped

Leak Off Pressure Slower pressure increase - reduce pump rate as mud begins to inject into the formation

Rupture Pressure Complete and irreversible failure has occurred when pressure drops - stop pumping

Propagation Pressure If pumping is stopped at the point of failure, the formation may recover, but weakened

HYD

LOP

Fracture



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A Formation Integrity Test gives no determination of actual fracture pressure, only an accepted maximum value for the drilling operation. Although not providing accurate data, this test does provide a safety margin.

Well consolidated formations are typically selected to set the shoe this formation may not be

the weakest if subsequent unconsolidated formations are encountered within a short interval from the shoe.

Apparent leak off may be seen in high permeability, or highly vugular formations, without

fracture actually occurring.

Poor cement bonds may result in leak off through the cement, rather than the formation.

Localized porosity or micro-fractures can result in lower recorded fracture pressures.

Well geometry, in relation to horizontal or vertical stresses, can also lead to deceptive fracture pressures, with different results being produced, in the same formations, between vertical and deviated wells.

Quantitative analysis of fracture gradients will be discussed in Section 6.



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b

2.4 Overburden Stress At a given depth, the overburden pressure is the pressure exerted by the cumulative weight of the overlying sediments. The cumulative weight of the overlying rocks is a function of the bulk density, the combined weight of matrix and formation fluids contained within the pore space. Overburden increases with depth, as bulk density increases and porosity decreases. With increasing depth, cumulative weight and compaction, fluids are squeezed out from the pore spaces, so that matrix increases in relation to pore fluids. This leads to a proportional decrease in porosity as compaction and bulk density increase with depth. An average value of 2.31 gm/cc can be assumed to be a reasonable average value of bulk density at depth (approximating to an overburden gradient of 1.0 psi/ft), but more accurate determinations should be made when more accurate measurements or data becomes available. Typical overburden profiles, with depth, are shown below: On land wells, the overburden at surface is obviously zero, but will increase very rapidly, with depth, as cumulative sediments and compaction increase. Offshore, the gradient must be referenced to RKB or RT, as is practice, there will be zero overburden between RKB and mean sea level, then the weight of the water has to be considered in the overburden gradient, which will start increasing from the seabed once sediments are encountered.



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2.4.1 Determination of Bulk Density Bulk density is a function of the matrix density, porosity and pore fluid density, and can be determined from the following formula: b = f + (1 )m = porosity, value between 0 and 1 e.g. 12% = 0.12 f = pore fluid density m = matrix density Accurate determination of the overburden gradient is critical for accurate formation and fracture gradient calculations. Naturally, then, the source of bulk density measurement, and the quality of that data, is very important. It follows then, from the bulk density equation, that porosity determination techniques such as neutron porosity or sonic transit times can be used to provide the porosity value. In practice, sonic logs are readily available and can be used to determine the bulk density. Direct measurements of bulk density are preferable, so density values from wireline logs are extremely useful. However, this source of data is rarely available for an entire well interval. Finally, direct measurements from cuttings can be made while the well is being drilled. If no offset data is available, or if there is doubt as to its accuracy, then direct bulk density measurements should be taken from the cuttings.

Rotary Kelly Bushing

Mean Sea Level

Sea Bed

OBG (EMW)

OBG

Depth Depth

Land Surface



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If, at the end of a hole section, better bulk density data can be obtained from wireline, whether sonic or density, then overburden calculations should be revised with the new data source. 2.4.1.1 Bulk Density from Cuttings Whilst drilling a well, the Overburden Gradient can be directly calculated from surface bulk density measurements. This would be done every 5 or 10m or whatever the sample interval is. Obviously, the more frequent the measurements, the more accurate the gradient will be. A simple displacement technique can be used to determine bulk density, and, as long as the engineer is precise and consistent, the data quality is typically satisfactory for overburden calculations. The technique is described below: -

Cuttings need to be washed (to remove drilling mud) and towel dried to remove excess water. Obvious cavings should be removed so that the sample selected is representative of the drilled

interval.

Accurately weigh a sample of 1 or 2 grams, for example. Obviously, the larger the sample size, the smaller any error.

With distilled water, fill a 10cc graduated cylinder to exactly 5cc (so that there is sufficient

volume to submerge all the cuttings but not too much so that the cylinder overflows). There will be a substantial meniscus on the water surface, so be consistent and take the measurement either from the top, or bottom, of the meniscus.

Carefully drop the cuttings

into the cylinder, being mindful of splashes and trapped bubbles.

Lightly tap the side of the

cylinder to release any trapped bubbles and to help splashes, on the side of the cylinder, run back into the water.

Read the new level of the

water, again being consistent with where, on the meniscus, you take the reading.

5

6 1.1cc



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From these measurements: -

bulk density (SG or gm/cc) = weight of sample (gm) volume of displaced water (cc) For example, if 2.00 gm of sample displaced 1.10 cc of distilled water: - Bulk density = 2.00 / 1.10 = 1.82 gm/cc Sources of error in this method include the following: -

Poor quality drilled cuttings Shale hydration or reactivity with mud Sample not representative of drilled interval Inaccuracy in weighing Inaccuracy/Inconsistency in determination of water displacement Eye level not being parallel to water meniscus Trapped bubbles, within bulk sample, increasing water volume

2.4.1.2 Bulk Density from Sonic Logs The Sonic log, since it is a porosity log reflecting the proportions of matrix to fluid, can be used to derive bulk density using the following formulae (Agip adapted from Wyllie, 1958): -

For consolidated rocks, b = 3.28 T 89

For unconsolidated rocks, b = 2.75 2.11 (T 47) (T + 200) where b = gm/cc T = formation transit time (actual sonic sec/ft)

47 = default matrix travel time 200 = default fluid travel time

Rather than the default 47, the following formation values for the matrix transit time can be used: - Dolomite 43.5 Limestone 47.6 Sandstone 51 (consolidated) to 55 (unconsolidated) Anhydrite 50 Salt 67 Claystone 47



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2.4.2 Calculation of Overburden Gradient Knowledge of the overburden gradient is essential for accurate formation pressure and fracture gradient calculations. As stated previously, the overburden stress, exerted at any given depth, is a function of the bulk density of the overlying sediments. Hence, whatever the source of the bulk density data, calculation of the overburden gradient is based on the average bulk density for a given depth interval: Overburden S = b x TVD TVD = metres 10 S = kg/cm2 b = average bulk density g/cm3 S = b x TVD x 9.81 TVD = m S = Kpa b = g/cm3 S = b x TVD x 0.433 TVD = ft S = psi b = g/cm3

From the average bulk density, calculate the overburden pressure for a given interval

Calculate the cumulative overburden pressure for that overall depth

Calculate the overburden gradient Three examples are illustrated, using the different units of measurement.



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Example 1

Interval Thickness Av b Interval Cumul OBG Grad EMW OB Press OB Pres

(m) (gm/cc) (KPa) (KPa) (KPa/m) (kg/m3)

0 - 50 50 1.25 613 613 12.26 1250 50 - 200 150 1.48 2178 2791 13.95 1422 200 - 300 100 1.65 1619 4410 14.70 1498 300 - 400 100 1.78 1746 6156 15.39 1569

For the interval 0 to 50m Overburden Pressure = 1.25 x 50 x 9.81 = 613 KPa Cumulative Pressure = 0 + 613 = 613 KPa Overburden Gradient = 613 / 50 = 12.26 KPa/m O/B Gradient EMW = 12.26 / 0.00981 = 1250 kg/m3 emw For the interval 50 to 200m Overburden Pressure = 1.48 x 150 x 9.81 = 2178 KPa Cumulative Pressure = 0 + 613 + 2178 = 2791 KPa Overburden Gradient = 2791 / 200 = 13.95 KPa/m O/B Gradient EMW = 13.95 / 0.00981 = 1422 kg/m3 emw



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Example 2

Interval Thickness Av b Interval Cumul OBG Grad EMW OB Press OB Pres (m) (gm/cc) (kg/cm2) (kg/cm2) (kg/cm2/10m) (kg/m3) (~ gm/cc)

0 - 100 100 1.35 13.5 13.5 1.35 1350 100 - 300 200 1.65 33.0 46.5 1.55 1550 300 - 450 150 1.78 26.7 73.2 1.63 1630 450 - 700 250 1.85 46.3 119.5 1.71 1710

For the interval 0 to 100m Overburden pressure = (1.35 x 100) / 10 = 13.5 kg/cm2

Cumulative pressure = 0 + 13.5 = 13.5 kg/cm2 Overburden gradient = (cumulative x 10) /(0 + 100) = (13.5 x 10) / 100 = 1.35 kg/cm2/10m

O/B Gradient EMW = 1.35 x 1000 = 1350 kg/m3

NOTE 1 kg/cm2/10m = 1 gm/cc = 1000 kg/m3 emw

For the interval 100 to 300m Overburden pressure = (1.65 x 200) / 10 = 33.0 kg/cm2 Cumulative pressure = 0 + 13.5 + 33.0 = 46.5 kg/cm2 Overburden gradient = (46.5 x 10) / (0 + 100 + 200) = 1.55 kg/cm2/10m O/B Gradient EMW = 1.55 x 1000 = 1550 kg/m3



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Example 3

Interval Thickness Av b Interval Cumul OBG Grad EMW OB Press OB Pres (ft) (gm/cc) (psi) (psi) (psi/ft) (ppg)

0 - 50 50 1.10 23.8 23.8 0.476 9.15 50 - 150 100 1.46 63.2 87.0 0.580 11.15 150 - 350 200 1.72 148.9 235.9 0.674 12.96 350 - 500 150 1.80 116.9 352.8 0.706 13.58

For the interval 0 to 50ft Overburden Pressure = 1.10 x 50 x 0.433 = 23.8 psi Cumulative Pressure = 0 + 23.8 = 23.8 psi Overburden Gradient = 23.8 / 50 = 0.476 psi/ft O/B Gradient EMW = 0.476 / 0.052 = 9.15 ppg emw For the interval 50 to 150 ft Overburden Pressure = 1.46 x 100 x 0.433 = 63.2 psi Cumulative Pressure = 0 + 23.8 + 63.2 = 87.0 psi Overburden Gradient = 87.0 / 150 = 0.58 psi/ft O/B Gradient EMW = 0.58 / 0.052 = 11.15 ppg emw



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2.5 Balancing Wellbore Pressures This section has, so far, detailed the lithological pressures and gradients that are encountered when drilling a well. It is now important to detail the wellbore pressures that act against the lithological pressures. 2.5.1 Mud Hydrostatic At the beginning of the section, Hydrostatic Pressure was defined as the pressure exerted at a given depth by the weight of a static column of fluid. It therefore follows, that when a given drilling fluid, or mud, fills the annulus, the pressure at any depth is equal to the Mud Hydrostatic Pressure. At any depth: - HYDmud = mudweight x TVD x g PSI = PPG x ft x 0.052 KPa = kg/m3 x m x 0.00981 This will tell us the balancing pressure, in the wellbore, when no drilling activity is taking place and the mud column is static.

emw

depth

FP - Formation Pressure Pfrac - Fracture Pressure OB - Overburden Gradient

FP Pfrac OB



25

As soon as any movement of the mud is initiated, then frictional pressure losses will result in either an increase, or decrease, in the balancing pressure, depending on the particular activity, which is taking place. At all times, it is important to know what the annular balancing pressure is, and the relationship with the lithological pressures acting against them: -

If formation pressure is allowed to exceed the wellbore pressure, then formation fluids can influx into the wellbore and a kick may result.

If the wellbore pressure is allowed to exceed the fracture pressure, then fracture can result,

leading to lost circulation and possible blowout. 2.5.2 Equivalent Circulating Density During circulation, the pressure exerted by the dynamic fluid column at the bottom of the hole increases (and also the equivalent pressure at any point in the annulus). This increase results from the frictional forces and annular pressure losses caused by the fluid movement. Knowing this pressure is extremely important during drilling, since the balancing pressure in the wellbore is now higher than the pressure due to the static mud column. Higher circulating pressure will result in: -

Greater overbalance in comparison to the formation pressure Increased risk of formation flushing More severe formation invasion Increased risk of differential sticking Greater load exerted on the surface equipment

The increased pressure is termed the Dynamic Pressure or Bottom Hole Circulating Pressure (BHCP). BHCP = HYDmud + Pa where Pa is the sum of the annular pressure losses When this pressure is converted to an equivalent mudweight, the term Equivalent Circulating Density is used.

ECD = MW + Pa (g x TVD) The weight of drilled cuttings also needs to be considered when drilling. The weight of the cuttings loading the annulus, at any time, will act, in addition to the weight of the mud, to increase the pressure at the bottom of the hole.



26

Similar to the increase in bottom hole pressure when circulating (ECD), pressure changes are seen as a result of induced mud movement, and resulting frictional pressures, when pipe is run in, or pulled out, of the hole. 2.5.3 Surge Pressures Surge Pressures result when pipe is run into the hole. This causes an upward movement of the mud in the annulus as it is being displaced by the drillstring (as seen by the mud displaced at surface into the pit system), resulting in frictional pressure.

This frictional pressure causes an increase, or surge, in pressure when the pipe is being run into the hole. The size of the pressure increase is dependent on a number of factors, including the length of pipe, the pipe running speed, the annular clearance and whether the pipe is open or closed. In addition to the frictional pressure, which can be calculated, it is also reasonable to assume that fast downward movement of the pipe will cause a shock wave that will travel through the mud and be damaging to the wellbore. Surge pressures will certainly cause damage to formations, causing mud invasion of permeable formations, unstable hole conditions etc.

The real danger of surge pressure, however, is that if it is too excessive, it could exceed the fracture pressure of weaker or unconsolidated formations and cause breakdown. It is a common misconception, that if the string is inside casing, then the open wellbore is safe from surge pressures. This is most definitely not the case! Whatever the depth of the bit during running in, the surge pressure caused by the mud movement to that depth, will also be acting at the bottom of the hole. Therefore, even if the string is inside casing, the resulting surge pressure, if large enough, could be causing breakdown of a formation in the open wellbore. This is extremely pertinent when the hole depth is not too far beyond the last casing point! Running casing is a particularly vulnerable time, for surge pressures, due to the small annular clearance and the fact that the casing is closed ended. For this reason, casing is always run at a slow speed, and mud displacements are very closely monitored. 2.5.4 Swab Pressures Swab Pressures, again, result from the friction caused by the mud movement, this time resulting from lifting the pipe out of the hole. The frictional pressure losses, with upward pipe movement, now result in an overall reduction in the mud hydrostatic pressure.



27

The mud movement results principally from two processes: -

1. With slower pipe movement, an initial upward movement of the

mud surrounding the pipe may result. Due to the muds viscosity, it can tend to cling to the pipe and be dragged upward with the pipe lift.

2. More importantly, as the pipe lift continues, and especially with

rapid pipe movement, a void space is left immediately beneath the bit and, naturally, mud from the annulus will fall to fill this void.

This frictional pressure loss causes a reduction in the mud hydrostatic pressure. If the pressure is reduced below the formation pore fluid pressure, then two things can result: -

1. With impermeable shale type formations, the underbalanced situation causes the formation to

fracture and cave at the borehole wall. This generates the familiar pressure cavings that can load the annulus and lead to pack off of the drill string.

2. With permeable formations, the situation is far more critical and, simply, the underbalanced situation

leads to the invasion of formation fluids, which may result in a kick. In addition to these frictional pressure losses, a piston type process can lead to further fluid influx from permeable formations. When full gauge tools such as stabilizers are pulled passed permeable formations, the lack of annular clearance can cause a syringe type effect, drawing fluids into the borehole. More than 25% of blowouts result from reduced hydrostatic pressure caused by swabbing. Beside the well safety aspect, invasion of fluids due to swabbing can lead to mud contamination and

necessitate the costly task of replacing the mud. Pressure changes due to changing pipe direction, eg during connections, can be particularly

damaging to the well by causing sloughing shale, by forming bridges or ledges, and by causing hole fill requiring reaming.



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2.5.5 Kick Tolerance

From the previous sections, it is clear to see that the mud weight must be sufficient to exert a pressure that will balance the formation pressure and prevent a kick, but it cannot be so high that the resulting pressure would cause a formation to fracture. This would lead to lost circulation (mud being lost to the formation) in the fractured zone. This, in turn, would lead to a drop in the mud level in the annulus, reducing the hydrostatic pressure throughout the wellbore. Ultimately then, with reduced pressure in the annulus, a permeable formation at another point in the wellbore may begin to flow. With lost circulation at one point and influx at another, we now have the beginnings of an underground blowout!

A critical condition exists should the wellbore has to be shut in. While drilling, high formation pressures can be safely balanced by the mudweight. However, if a kick is taken (either through a further increase in formation pressure, or through a pressure reduction cause by swabbing, for example), then the well would have to be shut in. If the pressure caused by the mudweight is too high, then weaker formations at the shoe may fracture when the well is shut in. This situation would be worsened if higher shut-in pressures are required to balance low density influxes, especially expanding gas! KICK TOLERANCE is the maximum balance gradient (i.e. mudweight) that can be handled by a well, at the current TVD, without fracturing the shoe should the well have to be shut in. KICK TOLERANCE = TVDshoe x (Pfrac MW) TVDhole Where Pfrac = fracture gradient (emw) at the shoe MW = current mudweight If the mudweight, that is required to balance the formation pressures while drilling, would result in shoe fracture during well shut in, then a deeper casing shoe (with greater fracture pressure) must be set. In order to account for a gas influx, the formula is modified as follows: -



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KT = [TVDshoe x (Pfrac MW)] - [influx height x (MW gas density)] TVDhole TVDhole The method illustrated is based on three criteria:

A maximum influx height and volume (zero kick tolerance) Point X A typical or known gas density (from previous well tests for example)

The maximum kick tolerance (liquid influx with no gas) Point Y

This defines limits on a graphical plot, which provides easy reference to this important parameter. The values are determined as follows: Maximum Height = TVDshoe x (Pfrac MW) MW gas density If gas density is unknown, assume 250 kg/m3 (0.25 SG or 2.08ppg)

Maximum Influx Volume is determined from the maximum height and the annular capacities this defines Point Y on the graph.

Maximum KT, as shown before, = TVDshoe x (Pfrac MW) TVDhole This defines Point X on the graph, a liquid influx without any gas. The graph is completed by dividing it into the different annular sections covered by the influx, i.e. in the event that there are different drill collar sections, or if the influx passes above the drill collar section, or even if the influx passes from open hole to casing. This is necessary since the same volume of influx will have different column heights in each annular section.



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2.5.5.1 Kick Tolerance, worked example Using the following well configuration: Casing Shoe = 2000m Hole Depth = 3000m Pfrac at shoe = 1500 kg/m3 emw Current MW = 1150 kg/m3 Drill Collar length = 200m Annular Cap = 0.01526m3/m (216mm open hole, 165mm drill collars) Annular Cap = 0.02396m3/m (216mm open hole, 127mm drillpipe) Gas Density = 250 kg/m3 Maximum Height = TVDshoe x (Pfrac MW) = 2000 (1500 1150) = 777.8m MW gas density 1150 250 Maximum Volume, determined from 200m around the drill collars, and 577.8m around drillpipe: DC = 200 x 0.01526 = 3.05m3 DP = 577.8 x 0.02396 = 13.84m3 Max Vol = 3.05 + 13.84 = 16.89m3 Maximum KT = TVDshoe x (Pfrac MW) = 2000 (1500 1150) = 233.3 kg/m3 TVDhole 3000 Therefore, Point X = 16.7m3, Point Y = 233 kg/m3 Now, determine the break point of the graph, for the drill collar / drill pipe annular sections:

To do this, calculate the KT related to a 3.05m3 gas influx, which would reach the top of the 200m length of drill collars:

KT = [TVDshoe x (Pfrac MW)] - [influx height x (MW gas density)]

TVDhole TVDhole = 2000 (1500 1150) - 200 (1150 250)

3000 3000

= 173.3 kg/m3 Therefore, 3.05m3 and 173.3 kg/m3 define the break point on the graph. The graph can now be plotted, as follows:



31

From this graph, the following information can be determined: For a liquid influx, with no gas:

The kick tolerance is 233 kg/m3 above the present mudweight.

This would mean that the maximum formation pressure that can be controlled, by well shut-in, without resulting in fracture, is 1383 kg/m3 (1150 + 233).

If formation pressures greater than this are anticipated, then a new casing shoe would have to be

set. Lighter and expanding gas changes this scenario dramatically:

If more than 16.7 m3 of gas was allowed into the annulus, there is no kick tolerance on well shut-in, the shoe would fracture!

Operators will often work on an acceptable maximum kick influx to determine kick tolerance:

For example, a 10 m3 gas influx would give a kick tolerance of 86 kg/m3 above the present

mudweight.

0 2 3.05 4 6 8 10 12 14 16 18 20

240

200

173 160

120

80

40

0

KT kg/m3

Influx Volume m3 X

Y Drill Collars Drill Pipe



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This can be verified with the formula:

Of the 10m3, 6.95m3 would be around the drillpipe annular section, since 3.05m3 fill the drill collar section:

Height around DP = 6.95 / 0.02396 = 290m Height around DC = 200m Total Height = 490m KT = 2000 (1500 1150) - 490 (1150 250) 3000 = 86.3 kg/m3



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2.6 Summary of Formulae Hydrostatic Formula: Pressure = Density x TVD x constant PSI = PPG x ft x 0.052 KPa = kg/m3 x m x 0.00981 PSI = g/cc x ft x 0.433 Conversions: kg/m3 = g/cc x 1000 kg/m3 = PPG x 1000 x (0.052/0.433) Oil Density g/cc = 141.5 / (API + 131.5) g/cc = (psi/ft) / 0.433 Formation Pressure = mud hydrostatic + shut-in drillpipe pressure

From a kick, if depth of influx is known Fracture Pressure = mud hydrostatic (shoe) + Leak Off Pressure

From a Leak Off Test after drilling out casing Overburden Stress S kg/cm3 = b (g/cc) x TVD(m)

10

KPa = b (g/cc) x TVD(m) x 9.81 PSI = b (g/cc) x TVD(ft) x 0.433 Equivalent Circulating Density ECD = MW + Pa (annular pressure losses) (g x TVD)



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Kick Tolerance (assuming influx without gas) = TVDshoe x (Pfrac MW) TVDhole Kick Tolerance (assuming given volume of known gas density)

= [TVDshoe x (Pfrac MW)] - [influx height x (MW gas density)] TVDhole TVDhole Annular Capacity m3 / m = 0.785 x (Dh2 - ODpipe2) diameters in metres bbls / ft = (Dh2 - ODpipe2) / 1029.46 diameters in inches Typical Influx Densities Gas 2.08 ppg 250 kg/m3 Oil 7.08 ppg 850 kg/m3 Freshwater 8.33 ppg 1000 kg/m3 Saltwater 8.66 ppg 1040 kg/m3



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3 OCCURRENCES OF ABNORMAL FORMATION PRESSURE

3.1 Underpressured formations Underpressure is rarely given the same attention as overpressure, but encountering such zones with an overbalanced mud system can certainly lead to problems, and possible loss of hydrostatic control with catastrophic consequences:

Mud invasion Formation damage Differential sticking Lost circulation Formation fracture Loss of hydrostatic pressure Underground blowout

3.1.1 Reductions in Confining Pressure or Fluid Volume Imagine an enclosed system containing a given fluid volume; if either the pressure imposed on that system, or the actual fluid volume, is reduced, then there is the potential for that system to become sub-normally pressured. Such situations include:

Depletion of water (aquifers) or hydrocarbon reservoirs through production. Removal of overburden pressure, through erosion, may lead to an expansion of pore space in

more elastic clays. If there is communication with interbedded or lenticular sands, for example, fluids will be drawn away from the sands, leading to a depletion in pressure.

3.1.2 Apparent Underpressure Postions of the water table, or point of outcrop, can lead to lower than expected fluid columns, which, to all intents and purposes, appear underpressured in relation to the drilling process and mud column.

Water reservoir outcropping at a lower altitude than the elevation penetrated during drilling. Therefore, the part of the formation penetrated will be above the water table and at atmospheric pressure.

WT

Atmospheric pressure



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The position of the water table in relation to the land surface. If the location of the well is topographically above the water table, the height of the fluid column will be less than the actual total depth. Therefore the hydrostatic pressure caused by the fluid column would be less than expected for a complete water column.

Both of these situations could be common in uplifted regions.

Large gas columns can also result in underpressured formations, since the low density gas reduces the effective hydrostatic pressure, in comparison to a liquid column.

WT Fluid column



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3.2 Overpressure Requirements 3.2.1 Overpressure Model Over the years, many models concerning the occurrence of abnormal formation pressures have been proposed. A very simple definition, as detailed in Section 2.2, is that overpressure is any formation pressure that exceeds the hydrostatic pressure, which is exerted by the formation water normal for that region. This concept proposes that any subsurface pressure can be compared to the pressure exerted by a formation water column that exists from surface to the same depth. What virtually all mechanisms of overpressure have in common, is that the zone in question has retained, or contains, an abnormal volume of formation water, leading to an inequilibrium. What this suggests is that, whatever the mechanism leading to excessive pore fluid volume, overpressure results from the inability of the retained fluids to escape at a rate which will maintain a pressure equilibrium with a water column that extends to surface. The following requirements are after the model proposed by Swarbrick and Osborne, 1998. This brings in two very important factors in the generation of overpressured systems, namely permeability and time. A third factor in the occurrence of overpressure is the fluid type and properties such as viscosity, which also have a determining effect on fluid flow. 3.2.1.1 Permeability Given communication, fluids will always flow from a zone of higher pressure to a zone of lower pressure. Permeability relates the rate at which a given fluid will flow, per unit time, along the line of such a pressure drop. Permeability is measured in Darcys (or rather, milli-Darcies) and is a function of the rock properties such as grain size, grain shape, and tortuosity (irregularity of flow paths) and also the fluid properties (i.e. density and viscosity). The degree of permeability will be a determining factor in how easy initial pore fluids can escape during a rocks history.

Overpressure resulting from fluid retention will obviously be more common in low permeability, non-reservoir type lithologies, such as clay.

Overpressure resulting from fluid retention in permeable, reservoir type rocks, will be

determined by the lack of permeability (i.e the quality of seal) in the overlying and surrounding rocks.



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3.2.1.2 Time As stated in section 3.2.1, overpressure, by definition, is a zone which is in a state of inequilibrium. All conditions of inequilibrium, with suitable conditions, will, over time, stabilize to a condition of equilibrium. Geological time is more than sufficient for such changes in equilibrium to change, and given even the smallest degree of permeability, fluids will redistribute if there is a pressure gradient. Over the course of a formations history, therefore, the degree of overpressure will decrease as fluids, and pressure, redistribute to surrounding zones. The only exception is if there is an absolute perfect seal, zero permeability, preventing fluids from redistribution, but, again, a perfect seal is very difficult to maintain over geological time given the overburden, tectonic, and other stresses that continually act on any given zone. 3.2.1.3 Fluid Type The density of formation waters, in other words the amount of dissolved salts, determines the pressure gradient in any given region. Even though individual zones may have varying degrees of salinity within their pore, or connate, water, and thus varying pressure gradients, the pressure would still be regarded as normal. Where, however, chemical processes (osmosis) lead to an exchange of dissolved salts between fluids, the resulting change in density and pressure would be regarded as a deviation from the normal formation pressure gradient. More importantly, in terms of the overpressure model, the fluid type determines the flow properties of that fluid and therefore relates to permeability and time in the occurrence of overpressured zones. For example, the presence of oil and gas, producing a multi-component fluid, reduces the relative permeability of the original pore fluid. This will actually enhance the effective seal of surrounding rocks and increase the likelihood of overpressure resulting. Specific flow characteristics not only vary with viscosity or multi-phase fluids, but on a number of properties, such as temperature, hydrocarbon composition, degree of saturation, phase, etc. As can be seen, the three criteria for the occurrence of overpressure, permeability, time and fluid type, are all interactive and/or interdependent. The actual occurrence of overpressure, the degree of overpressure, and how quickly it can build or dissipate, depends on the particular environment or cause of the abnormal volume of pore fluid. In other words, for overpressure to occur, there has to be a specific mechanism that generates the excess fluid in the first instance. These will be discussed in section 3.3.



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3.3 Causes Of Overpressure As we did when looking at the causes of underpressured zones, in section 3.1.1, imagine an enclosed unit of rock containing a given volume of pore fluid. Any reduction in the volume of that unit of rock, or any increase in the volume of enclosed pore fluid, will lead to fluid being necessarily expelled. Now that we have seen the principles of permeability, fluid type, and time, and the role they play, if the required fluid expulsion is not achieved at a rate that will maintain a pressure equilibrium, then overpressure will result. The specific mechanisms that may result in this can be divided into the following 5 categories: -

1. Overburden effect 2. Tectonic stresses 3. Increases in fluid volume 4. Osmosis 5. Hydrostatic

3.3.1 Overburden Effect In terms of our two causes, reduction in rock/pore volume or increase in fluid, this obviously fits into the reduction in pore volume category and is common in deltaic environments and subsiding sedimentary basins, evaporite deposits, etc. As sedimentation and burial increases the vertical thickness of overlying sediments, vertical loading (i.e. overburden) results. Vertical loading during burial results in a normal compaction of the sediments, and necessarily requires the expulsion of pore fluids as pore volume is reduced. Typically, a slow burial rate will result in a normal compaction rate with fluids being expelled allowing pore volume to decrease as overburden increases. A normal compaction rate will result in a normal fluid pressure gradient.

SLOW BURIAL

NORMAL COMPACTION

EFFICIENT DE-WATERING

NORMAL PRESSURE



40

However, if normal compaction and normal de-watering does not take place, then overpressure can occur as a result of fluids being retained by the sediments. Clays are more prone to overpressure from this mechanism due to the following mechanical properties:

Higher initial pore fluid volume, up to 70 or 80% of the total volume. This compares to sands which may have around 40% initial pore volume.

Higher rate of compaction.

Continued compaction (to around 5% pore volume) to greater depths (~ 5km), requiring a huge

volume of water to be expelled over a long period of time. This compares to sands, which may have a pore volume reduction to 15 20%, but do not continue compaction to the same depths as clays.

Therefore, with higher normal fluid volumes to begin with, and longer compaction periods requiring continued fluid expulsion, there is greater potential for undercompaction to occur.

In addition, during normal burial and diagenesis, additional fluid volume is generated by changes in the clay chemistry, increasing the amount of de-watering that is required to maintain normal pressure.

If there is not equilibrium between loading and compaction, and the fluid is not expelled at the required rate during burial, then undercompaction results and the zone will be overpressured. There are two principle causes of this inequilibrium:

1. Rapid burial so that there is insufficient time for the large fluid volume, resulting from the high sedimentation rate, to be expelled. Rapid burial rates are certain to cause overpressure when combined with low permeability sediments.

2. Drainage restrictions preventing normal fluid expulsion.

Low permeability Lack of sandy or silty layers facilitating de-watering Impermeable layers, such as evaporates or carbonates, creating a barrier to fluid

expulsion

Where there is incomplete de-watering of shales, within a shale-sand sequence, porosity and pressure is often seen to be higher towards the centre of the clay sections, and lower towards the contact with the normally pressured sands (Magara, 1974). Pressure in shale

Normal pressure



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3.3.2 Tectonic Loading In the previous section, the compaction of rocks, and reduction in pore space resulting from vertical loading, was discussed. In the same way, tectonic stresses may lead to horizontal compression and associated reduction in pore volume. This is not well documented or proven and, to be a cause of overpressure, would tolerate none of the normal fracturing or faulting (facilitating fluid expulsion) that would normally be associated with such tectonic stresses. Tectonic activity, on the other hand, caused by uplift, faulting or folding of rocks, can lead to the occurrence of overpressure, through hydrodynamic activity and the modification and redistribution of fluids and pressures. Tectonic stresses may actually restrict fluid expulsion, yet conversely, they can result in fracturing that will facilitate fluid drainage. If a formation is uplifted, yet remains sealed and incurs no fracturing, it will retain its original (deeper) fluid pressure at the shallower depth. This retained palaeopressure will be overpressured in comparison to the surrounding formations. 3.3.2.1 Faulting Faulting can lead to the occurrence of overpressured formations through forming an effective seal or, conversely, acting as a drain: - Faults and fractures may provide a conduit

allowing deeper fluid pressures to be released to shallower formations. Thus, pressure in the deeper formation is depleted and the pressure in the shallower formation is charged, until equilibrium is reached.

Permeable and impermeable layers may be juxtaposed

by a fault restricting normal fluid migration, so that palaeopressure is retained.

Fluid drainage

Uplifted & sealed



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3.3.2.2 Deltaic Environments Naturally, sedimentation and subsistence are important components to a deltaic environment in the formation of sedimentary basins. Where sedimentation rates are fast and where drainage is poor, sediments will not dewater effectively and water-logged, overpressured zones will result. Growth faults and shale diapirism are two structural situations, common to deltaic environments, that can result in overpressure.

Shale diapirism, intrusive flow from underlying layers, results in domes, which are always undercompacted and overpressured. Many characteristics of shale (and salt) domes can result in further zones of overpressure and these will be detailed in section 3.3.2.3.

Growth faults have a curved fault plane, steep in the upper part, and shallower at the base.

Basement tectonics, slumping, diapirism, overburden effect, may all be responsible, in part or whole, in the generation of growth faults.

Sediments on the downdip of the fault will thicken and form an anticlinal rollover against the fault plane. This is often the site for hydrocarbon accumulations and the reason for drilling in these areas. At the base of the growth fault, on the updip side, a ridge of undercompacted and overpressured shale often forms where dewatering is ineffective as the sediments rapidly accumulate and fill the basin.

Sediment influx

Overpressured Shale



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3.3.2.3 Diapirism/Domes As said in the previous section, diaprisim is where there is intrusive flow of salt or shale, into overlying sediments, forming domes, which can be on a massive scale. Shale diapirisim will always result in a mass of undercompacted and overpressured shale, but both shale and salt domes have many mechanisms that can result in overpressured zones. Salt is completely impermeably, thus providing perfect seals for fluid pressures as well as hydrocarbons. These are illustrated below: - As detailed in section 3.3.1, remember that salt or evaporite layers within a sedimentary sequence, provide a completely impervious boundary to vertical fluid expulsion resulting in underlying, overpressured clays.

Isolated, uplifted rafts, perfectly sealed in the salt, retain palaoepressure. In addition, multi-directional stresses act on the raft.

Uplifted and pierced layers are sealed against the dome (especially salt). Associated faulting can produce additional seals as well as hydrocarbon traps

Pressure transfer from undercompacted shale dome, to adjacent, pierced, permeable formations Osmotic effects where formations

adjacent to salt domes have raised

Uplifted zones, retaining palaeopressure from depth



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3.3.3 Increases in Fluid Volume As already detailed, within a confined unit of rock, with a given pore volume, any increase in fluid volume within that confined space will generate an increase in pressure. There are many mechanisms that may lead to this volume increase; some are well understood, others are not; some are proven and accepted, others still disputed! 3.3.3.1 Clay Diagenesis As young sediments are undergoing diagenesis during early burial stages, clay mineralogy changes (largely due to increasing temperature) and, as a result, water is generated. Smectite clay is chemically altered, during diagenesis, to illite. Many clay basins show this gradual transformation, with depth, of smectite to illite. Water is absorbed into the lattice structure of smectite, but illite does not have the same capacity to absorb water. Thus, lattice-bound water released during the chemical transformation of smectite, remains free water. In terms of generating overpressure, there are two important things to note:

1. The release of lattice-bound water is effectively a volume increase of water, a cause of overpressure in itself. Although there is some question as to the precise volume increase, many overpressured zones coincide with the smectite-illite transition (Bruce, 1984).

2. During the early stages of diagenesis, when this water is being released, the clays are undergoing

normal burial, de-watering and compaction. As mineralogy changes and water is released, the clay structure becomes more compressible so that the released water is adding to the volume of water that has to be expelled to maintain equilibrium with the vertical loading and subsidence rate. As described in section 3.3.1, any inhibition to de-watering, now with a larger volume of water, will result in overpressure.

There are additional points to note regarding clay diagenesis and mineral transformation:

As smectite is transformation to illite, silica is being produced, and this could effectively reduce any permeability and inhibit the de-watering process and release of water.

As well as being a possible cause of overpressure, the situation could be reversed, in that,

overpressured zones could actually enhance or facilitate the clay alteration. Temperature is the main cause of the mineralogy change, and the higher temperature gradients could well lead to, or increase, the transformation of smectite to illite. The overpressure zone could easily, therefore, be subject to a further rise in formation fluid pressure if the additional water is retained.



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3.3.3.2 Gypsum Dehydration Similar to the clay diagenesis just described, this is, again, a mineralogy change resulting from relatively shallow burial temperatures. As gypsum transforms to anhydrite, bound water is again released and capable of generating considerable formation pressures if it is not expelled. Where salt is associated with the evaporites, the temperature required for transformation is lowered further (25C, Kern & Weisbrod, 1964) so that water is released at very shallow depths, virtually at surface. In this situation, it is perhaps more likely that the excess water will be expelled, unless associated salt provides an impervious barrier. 3.3.3.3 Hydrocarbon or Methane Generation Biogenic Methane Although seals are rarely perfect, so that gas will typically migrate harmlessly to surface, shallow gas pockets can be encountered while drilling. This poses a great danger since very little warning time is given before gas from a penetrated pocket reaches surface. This methane gas is generated from the bacterial decay of organic material trapped within sediments, at shallow depths. If the sediments are isolated, then the volume expansion associated with the production of methane can generate overpressure. Hydrocarbon Generation from Kerogen With deeper burial and higher temperatures (2 to 4km, 70 to 120 C, Tissot & Welte, 1984), as kerogen passes through the oil window, kerogen matures to generate oil and gas. The associated volume increase is not understood or accurately known, but it may result in a pressure increase, since there has to be some sort of pressure increase to initiate the primary migration of hydrocarbons. Thermal Cracking Beyond the oil window, at greater depths and temperatures (3 to 5.5km, 90 to 150C, Barker, 1990), thermal cracking takes place, where oil is broken down to lighter hydrocarbons and ultimately, methane (often referred to as dry gas). Again, t

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Abnormal Formation Pressure Analysis