@Normal= @Normal=[S"","Normal","Normal"]<*L*h"Standard"*kn0*kt0*ra0*rb0*d0*p(0,0,0,0,0,8.504,g,"International English")> @heading 1=[S"Normal","heading 2"]<*C*kn1*p(0,0,0,0,9,8.504,g,"International English")PBKs100t0h100z18k0b0cKf"Helvetica"> @heading 2=[S"heading 1","Normal"]<*L*p(51.024,-51.024,0,0,6,8.504,g,"International English")PBKs100t0h100z14k0b0cKf"Helvetica"> @Indent1=[S"Normal","Indent1"]<*p(17.008,0,0,0,0,8.504,g,"International English")*t(34.016,0,"1 ")Ps100t0h100z12k0b0cKf"NewCenturySchlbk-Roman"> @xfigure=[S"Normal",""]<*p(76.55,-76.55,0,0,0,8.504,g,"International English")Ps100t0h100z10k0b0cKf"Helvetica"> @extra space before=[S"Normal","xfigure"]<*p(0,0,0,0,6,8.504,g,"International English")Ps100t0h100z12k0b0cKf"NewCenturySchlbk-Roman"> @heading 3=[S"heading 2","Normal"] @Indent2=[S"Normal","Indent2"]<*p(34.016,0,0,0,0,8.504,g,"International English")*t(51.024,0,"1 ")Ps100t0h100z12k0b0cKf"NewCenturySchlbk-Roman"> @Indent2(-1)=[S"Indent2","Indent2(-1)"]<*p(34.016,-17.008,0,0,0,2.835,g,"International English")*t(51.024,0,"1 ")Ps100t0h100z12k0b0cKf"NewCenturySchlbk-Roman"> @heading 4=[S"heading 3","Normal"]<*p(56.693,-56.693,0,0,6,8.504,g,"International English")PBs100t0h100z12k0b0cKf"Helvetica"> @heading 5=[S"heading 4","Normal"] @List2=[S"Indent2(-1)","List2"]<*p(34.016,-17.008,0,0,0,0,g,"International English")*t(51.024,0,"1 ")Ps100t0h100z12k0b0cKf"NewCenturySchlbk-Roman"> @Indent3=[S"Normal","Indent3"]<*p(51.024,0,0,0,0,8.504,g,"International English")*t(68.031,0,"1 ")Ps100t0h100z12k0b0cKf"NewCenturySchlbk-Roman"> @Indent3(-1)=[S"Indent3","Indent3(-1)"]<*p(51.024,-17.008,0,0,0,2.835,g,"International English")*t(68.031,0,"1 ")Ps100t0h100z12k0b0cKf"NewCenturySchlbk-Roman"> @List3=[S"Indent3(-1)","List3"]<*p(51.024,-17.008,0,0,0,0,g,"International English")*t(68.031,0,"1 ")Ps100t0h100z12k0b0cKf"NewCenturySchlbk-Roman"> @heading 2:3.2.1<\#9>Origins @$:<*p(0,0,0,0,0,8.5,g,"International English")>Two values are significant during the planning and drilling of a well; the pore pressure gradient and the overburden pressure gradient. To understand these gradients and the pressures that they can generate and therefore be encountered whilst drilling it is necessary to appreciate the origins of the pressures. The majority of the formations drilled through in hydrocarbon exploration and production operations is sedimentary<$>. The material has settled out either in air or water and is subsequently covered by more material and buried. The majority of this action occurs in water. Depending on the nature of the material it behaves differently when compressed. Fine clay particles tend to have little inherent strength and so deform and compress tightly together, squeezing out the water around it to form claystones and shales with little or no porosity<$> or permeability<$>. Coarser and stronger, sand particles tend to retain some strength and support each other leaving gaps between, called pores, which will generally be initially filled with water. Over time, minerals in the water that they are deposited in can precipitate and cause the grains to become cemented together. Limestone, originating from calcareous material in the water, tends to lose porosity under pressure and temperature. However, its friable nature often causes it to crack or fracture over time and these then can become filled with water or other fluids. Consequently, under ideal circumstances, a stratigraphic column of rock formation consists of two phases, a solid and a fluid phase. The solid phase is formed by the rock material, and the fluid phase by water, oil, or gas which fills any pore or fracture space between the grains. The degree to which these pores or fractures are linked such that fluid can flow through the rock is the permeability<$>. <*p(0,0,0,14.5,0,8.5,g,"International English")>The total weight of any volume of porous rock (Wt) equals the sum of the weight of the grains or matrix (Wm) and the weight of the pore contents (Wo). <*C>W<-z9f"Helvetica">t = W<-z9f"Helvetica">m + W<-z9f"Helvetica">o <*L>Considering a column of unit cross-sectional area from surface to a given depth gives the vertical load per unit area at that depth, i.e. the vertical stress or pressure in the formation. W<-z9f"Helvetica">t yields what is known as the overburden stress denoted by S; W<-z9f"Helvetica">m yields the vertical matrix stress s<-f$>v<$> and W<-z9f"Helvetica">o yields the fluid pressure or P<-z9f"Helvetica">o <*C*p(0,0,0,14.5,0,8.504,g,"International English")>S =s<-f$>v<$> + P<-z9f"Helvetica">o <*L*p(0,0,0,14.5,0,8.5,g,"International English")>The rates of change of these stresses with depth are called gradients. <@$p>in units of psi/ft or kPa/m, which are just a different way of expressing the density of the material. Taking the depth as Z, which is conventional practice: @Indent1: <*t(34.016,0,"1 "175,0,"1 ")>the bulk density<\#9> <*t(34.016,0,"1 "175,0,"1 ")>the matrix density<\#9> <*t(34.016,0,"1 "175,0,"1 ")>and the pore fluid density<\#9> @$:<*p(0,0,0.6,0,0,8.5,g,"International English")> <$>A convenient concept is the equivalent gradient which is the total stress (or pressure) divided by the total depth. The convenience comes because the only way in which pressure can be applied in a bore-hole is to fill it with a liquid of a certain density and, if necessary, apply additional pressure at the top of the column. The equivalent gradient at any depth is the gradient of the liquid column which would produce the same stress/pressure as exists in the formation without the application of additional pressure. <*p(0,0,0,14.3,0,8.5,g,"International English")>The relationship between pressure and depth can be illustrated using a graph. Custom is such that these graphs are plotted with pressure (P) on the horizontal axis and depth (Z) on the vertical axis, with zero (= datum level) at the top corresponding to the physical system. A constant gradient is plotted as a straight line (see Figure 2.3.1). For pressure and gradient calculations during day-to-day operations the datum level is usually derrick floor elevation (dfe), since that is the top of the column of drilling fluid (in some areas the top of the kelly bushing is taken as datum but in practice the difference is negligible). Pressure plots are also frequently used to compare data from different wells. For this purpose a common datum plane has to be defined. The datum level is usually mean sea level for offshore wells; for land wells it can be any convenient level such as the average elevation of the area above mean sea level (rounded off to a convenient figure). In the latter case the datum level has usually been defined during the seismic campaign. The overburden gradient or bulk density<$> of formations penetrated can be measured by the bulk density logging tool. When these densities, measured in a well, are plotted, a step-like function of the bulk densities versus depth is obtained. Each step represents a change in lithology. Integrating the bulk density measurements to a given depth gives the overburden stress at that depth, and averaging these in an area will give a general trend like the curved line in Figure 2.3.2b. If no existing well data exists it is possible to make an estimate of the overburden gradient. Assuming formation rock has a density of approximately 2650 kg/m<+z9f"Helvetica">3 <$>(26 kPa/m or 1.15 psi/ft): A clay formation near the sediment/water interface has a porosity of say 75%. Therefore the gradient of the bulk clay/water mixture is: @Indent1:<@$><*p(17.008,0,0,14.3,0,8.504,g,"International English")>0<\#183>25 x 26 kPa/m + 0<\#183>75 x 9<\#183>81 kPa/m = 13<\#183>85 kPa/m or 0<\#183>25 x 1<\#183>15 psi/ft + 0<\#183>75 x 0<\#183>433 psi/ft = 0<\#183>612 psi/ft @extra space before:<@$><*p(0,0,0,14.3,6,8.504,g,"International English")>A sand formation near the sediment/water interface has a porosity of 35%. The combined bulk gradient of the mixture in this case is: @Indent1:<@$><*p(17.008,0,0,14.3,0,8.504,g,"International English")>0<\#183>65 x 26 kPa/m + 0<\#183>35 x 9<\#183>81 kPa/m = 20<\#183>33 kPa/m or 0<\#183>65 x 1<\#183>15 psi/ft + 0<\#183>35 x 0<\#183>433 psi/ft = 0<\#183>899 psi/ft @$:<*p(0,0,0,14.3,0,8.504,g,"International English")>The overburden gradient line (Figure 2.3.2a) is, in actual fact, a curved line as compaction normally causes the density of rock to increase with depth. This behaviour depends on rock composition and porosity. As a rule of thumb the overburden gradient is usually taken to be 22<\#183>6 kPa/m (1<\#183>0 psi/ft although it can vary between 13<\#183>8 kPa/m (0<\#183>6 psi/ft) and 24<\#183>86 kPa/m (1<\#183>1 psi/ft). In areas where active sedimentation takes place like the Gulf Coast, offshore North West Borneo and Nigeria a value of 20<\#183>6 kPa/m (0<\#183>9 psi/ft) is more accurate due to the amount of water retained in the rock. <*p(0,0,0,0,0,8.5,g,"International English")>Formation pore fluid density can be obtained by using logging tools which measure the pressure at a series of depths within the formation. Measured water gradients are usually between 9<\#183>81 kPa/m (0<\#183>433 psi/ft) for pure fresh water and 10<\#183>52 kPa/m (0<\#183>465 psi/ft) but may be as high as 11<\#183>31 kPa/m (0<\#183>5 psi/ft) for saturated salt water pore fluid. Sea water is assumed to have a gradient of 10<\#183>07 kPa/m (0<\#183>445 psi/ft). @heading 2:3.2.2<\#9>Pore Pressure Profiles @extra space before:<@$>Formations are conventionally classified as normally pressured, under-pressured or over-pressured. @$:<*p(0,0,0,0,0,8.5,g,"International English")>Any pore pressure of the liquid or gas phase in the formation, as measured by logging tools, may be plotted on a graph similar to the one shown in Figure 2.3.1, and as indicated on that graph the position in which it is plotted will indicate into which pressure regime it falls. These pressure regimes do not have strictly quantitative definitions, being based on the practical matter of what drilling fluid gradient is required to balance the pore pressure. Because of this the boundaries between them are less well defined than shown in the graph and may vary according to the context and to local custom. @heading 3:3.2.2.1<\#9>Normal Pressure Regime @$:<*p(0,0,0,0,0,8.5,g,"International English")>Looking at Figure 2.3.1 it can be seen that two cases of hydrostatic gradient are shown; these correspond to water with zero salinity and water with a highish (but not extreme) salinity. In general if a plotted pressure falls between these two lines the formation is said to be normally pressured at that depth and a normal unweighted drilling fluid can be used while drilling through it. A normally pressured formation will usually have a hydraulic connection to the water table level although this does not have to be vertical, i.e. the connection could happen some distance away via connections with other formations, non-sealing faults etc. In this case the water table will generally be at approximately the same elevation as the drilling location. In a region known to have unusually high formation water salinities, and thus densities, the formation pressure would still be called "normal" or "hydrostatic" even though the plotted pressure is in the overpressure region of the chart (as long as it is consistent with the known pore fluid densities). @heading 3:3.2.2.2<\#9>Sub-Normal Pressure Regime @$:<*p(0,0,0,0,0,8.5,g,"International English")>Formations with pore pressures which plot below the hydrostatic region shown in Figure 2.3.1 (or below the locally accepted normal pressure region) are said to have a Sub-Normal<$> or Sub-Hydrostatic<@$p> pressure regime. If a formation in the region mentioned above has a pore pressure equivalent to a gradient of 10.2 kPa/m (0.45 psi/ft) it would probably be referred to as under-pressured, depending on local custom, even though it would be a normal pressure elsewhere. Sub-normal pressures can be caused by the following situations: @Indent2(-1):*<\#9>Low water table or high drilling location elevation *<\#9>Reservoir depletion *<\#9>Tectonic extension after compression @heading 4:3.2.2.2.1<\#9>Low water table or High Elevation @$:<*p(0,0,0,0,0,8.5,g,"International English")>In mountainous or arid areas it is possible for the water table to be deep below the surface at the drilling location. The top hole is then drilled through dry rock. Here the pore pressure is zero and the matrix stress alone defines the overburden down to the water table. Below the water table r<-z9f$>o<@$p> then plays a part. This situation is illustrated in Figure 2.3.3. For example if the water table is at 1000 m (3,281 ft) bdf and the formation fluid gradient is 10 kPa/m (0<\#183>442 psi/ft) then the pressure P at a depth D will be given by: @Indent2(-1):P<-z9> <$z$>= 10 kPa/m x (D - 1,000) m<\#9><\#9><\#9>P<-z9> <@$>= 0<\#183>442 psi/ft x (D - 3,281) ft @$:<*p(0,0,0,0,0,8.5,g,"International English")>From surface it is said that the formation pressure is underpressured by 1,000 m x 10 kPa/m = 10,000 kPa or 3,281 ft x 0<\#183>442 psi/ft = 1,450 psi. @heading 4:3.2.2.2.2<\#9>Depleted Reservoirs @$:<*p(0,0,0,0,0,8.5,g,"International English")>It has been stated that a normally pressured reservoir usually has a hydraulic connection to the local water table level. This connection can be tenuous and of low permeability, and can sometimes even have been lost as a result of sealing faults, salt intrusions etc. This situation is often described by saying that a reservoir has little or no natural water drive<$>. Consequently, if such a reservoir is produced the pressure in the reservoir will drop by the process of expansion to less than that calculated from the normal gradient (unless it is artificially maintained by gas or water injection). @heading 4:3.2.2.2.3<\#9>Tectonic extension after compression @$:<*p(0,0,0,0,0,8.5,g,"International English")>If a reservoir rock with permeability and porosity becomes sealed after deposition, and is then extended or expanded due to tectonic stresses acting on it, the effect can be to expand the fluid in the pore spaces and so reduce the pressure. The effect will be to reduce the pore pressure to less than that generated by the local hydrostatic pressure gradient. @heading 3:3.2.2.3<\#9>Over-pressured Pressure Regime @$:<*p(0,0,0,0,0,8.5,g,"International English")>Formations with pore pressures which plot above the hydrostatic region shown in Figure 2.3.1 (or above the locally accepted normal pressure region) are said to have an Abnormal<$> or Over-Pressured<$> pressure regime. Over-pressures may be the result of: @Indent2(-1):<@$>*<\#9>High water table or low elevation *<\#9>Hydrocarbon bearing formations *<\#9>Abnormal sedimentary burial circumstances *<\#9>Osmotic action @$:<*p(0,0,0,0,0,8.5,g,"International English")>Whilst sub-normal or sub-hydrostatic formations can cause drilling problems such as losses or stuck pipe due to the pressure difference between the well bore and the formation pores (assuming that the well is kept full with water as a minimum!), over-pressures can cause more significant problems such as borehole instability, kicks and blow-outs. Consequently it is important to understand how over-pressures can occur and how they can be predicted and identified at an early stage. @heading 4:3.2.2.3.1<\#9>High Water Table / Low Elevation @$:<*p(0,0,0,0,0,8.5,g,"International English")>This is the opposite situation to a low water table/high elevation described above. When the well is drilled from a location below the water table or into a permeable formation linked to an aquifer at a higher level, the formation pressure will be greater than that generated by a hydrostatic gradient from the rig floor. This situation can lead to artesian flow<$> from shallow aquifers (as used in London and Paris for drinking water production). Typically, problems can occur when entering the first porous, permeable formation after drilling through surface clays, claystones or shales. @heading 4:3.2.2.3.2<\#9>Hydrocarbon Bearing Formations @$:<*p(0,0,0,0,0,8.5,g,"International English")>The permeability of shale to hydrocarbons is extremely low and can be considered to be zero. Once hydrocarbons are trapped below a sealing shale the system is closed at the top. Figure 2.3.4 shows the basic principle. As the aquifer is open to the base, the water bearing part of the reservoir will be hydrostatically pressurised. Although a normal hydrostatic pressure may exist at the hydrocarbon-water contact, the column of low density oil, condensate or gas on top will result in pore pressures above hydrostatic. The difference between the pore pressure and the hydrostatic pressure increases with distance from the Oil-Water Contact<$> (OWC) or Gas-Water Contact<$> (GWC) with the highest over-pressure at the top of the reservoir (see Figure 2.3.4). This abnormal pressure resulting from displacement of water by less dense fluids or gas is called genetic<$> pressure. Often there is a small pressure difference at the OWC as oil is pushed down through the pore throats replacing the formation water. This pressure difference can be substantial if pore throats are very small (e.g. in chalk). The pressure is a result of the gradient required to produce flow and of working against the capillary effect. @heading 4:3.2.2.3.3<\#9>Abnormal Burial Conditions @$:<*p(0,0,0,0,0,8.5,g,"International English")>The conditions under which the sedimentary material is deposited and subsequently buried can give rise to abnormally pressurised formation. A number of these mechanisms are reviewed below. @heading 5:Undercompaction @$:<*p(0,0,0,0,0,8.5,g,"International English")>Abnormal pressures arising from rapid burial of water saturated sediments are referred to as geopressures (sometimes referred to as depopressures or undercompaction pressures). This phenomenon is the mechanism that has caused the majority of overpressured formations in existence. Depo-, geo- or undercompaction pressures are created by the resistance of low permeability rock to the escape of trapped fluid. The permeability of clean sandstones, limestones and dolomites is generally too high to develop overpressures from undercompaction. However, the permeability of clay or shale decreases with compaction to extremely low values. As the process of burial proceeds a specific increment of overburden load normally causes a rock matrix to compact by a specific corresponding amount, provided that there is enough time available for the pore fluid to escape from the reducing pore space. Under such conditions the pore pressure in the rock remains in hydrostatic equilibrium with that in the overlying formations and remains normal. If, however, the burial process proceeds too quickly the pore fluid will not be able to flow out of the formation at a rate which allows the same matrix compression rate to be achieved. The fluid will then have to support part of the overburden load and will therefore become overpressured. The formation is said to be undercompacted. An alternative way of looking at the situation is that as the rock is put under compressive stress by the increasing overburden the pore fluid always supports part of this increasing load. The increasing pore pressure thus creates a differential which causes the pore fluid to flow out of the formation. If the ratio of permeability to rate of increase of load is high enough the system will stabilise with a low elevation of the pore pressure. If the converse is the case equilibrium will be reached with a high pore pressure. Significant factors in creating an overpressure under these conditions are: @Indent2(-1):<@$>*<\#9>the permeability of the clay or shale which decreases with compaction. *<\#9>the thickness of the shale through which the water must escape. *<\#9>the potential compaction that could occur in the shale at the applied load. *<\#9>the rate of burial. @$:<*p(0,0,0,0,0,8.5,g,"International English")>As mentioned above continuous beds of sandstones, limestones and dolomites do not become undercompacted because their permeability is high. If, however, a lens of a high permeability material is completely enclosed in a compacting clay (later to become shale) the pore fluid can no more escape from that than from the clay itself. The pore fluid will thus remain in pressure equilibrium with the fluid in the clay immediately surrounding it and the lens will become undercompacted and overpressured Due to the minimal permeability of shales, drilling into an undercompacted and therefore overpressured shale will normally only lead to borehole stability problems. Drilling into an overpressured porous lens can lead to a kick. However, if the lens is only water filled even a very small expansion of the sealed system will result in a substantial drop in fluid pressure, given the low compressibility of the pore water (4<\#183>35 x 10<+z9>-7<$z$> kPa<+z9>-1 <$>or 3 x 10<+z9>-6<$z$> psi<+z9>-1)<$>. If, for example, the pore space is allowed to expand by as little as 0<\#183>1 of a per cent, the pressure of the pore water will decrease by 0<\#183>001/4<\#183>35 x 10<+z9>-7<$z$> kPa<+z9>-1<$z$> = 2,299 kPa (0<\#183>001/3 x 10<+z9>-6<$z$> psi<+z9>-1 <$>= 333 psi). If, on the other hand, the formation has become partially gas filled due to degradation of material in the surrounding shale, the potential exists for a high pressure, high volume gas kick. @heading 5:Diagenesis @$:<*p(0,0,0,0,0,8.5,g,"International English")>Phase changes in the matrix material of the rock can cause overpressures. Some types of rock under the influence of pressure and temperature alters their structure and composition, resulting in a reduction in pore volume and/or an increase in the amount of formation fluid. Such a change could cause a pore pressure increase in a sealed system. For example in sand/shale sequences montmorillonite or smectite clays change to illite at about 220<\#176>F. This alteration frees water with a volume in excess of the reduction in volume of montmorillonite or smectite altered. If expulsion is inhibited, these liquids will, with continued burial, absorb increasing load. The effective stress will increase more slowly and abnormal pore pressures will result. @heading 5:Tectonic pressures @$:<*p(0,0,0,0,0,8.5,g,"International English")>Tectonic phenomena such as sliding, piercements (volcanic), shearing, diaperic movements (salt, clay), uplifts (mountain building), thrust, etc. can add energy to the pressure system in a geological area resulting in abnormal pore pressures in formations from which fluids cannot escape. @heading 4:3.2.2.3.4<\#9>Osmosis @$:<*p(0,0,0,0,0,8.5,g,"International English")>Two reservoirs separated by an impermeable membrane may develop a pressure differential across the membrane as a function of a difference in the salinity of the formation liquid. As clay may act as such a membrane and because salinity changes occur in the subsurface, osmosis could have some potential to create abnormal pressures. Tests have proved that a pressure differential of 21 to 28 kPa (or 3 to 4 psi) could be generated by osmosis across a clay membrane. @heading 2:3.2.3<\#9>Prediction @$:<*p(0,0,0,0,0,8.5,g,"International English")>Due to the drilling problems that both abnormally and sub-normally pressured formations can cause it is important to be able to predict them. Depending on the nature of the drilling operation this may be during the planning stages of a well or whilst actually drilling the well. @heading 3:3.2.3.1<\#9>Prediction whilst Planning @heading 4:3.2.3.1.1<\#9>Offset Well Information @$:<*p(0,0,0,0,0,8.5,g,"International English")>When planning a development or appraisal well, information from offset wells<@$p> can provide indicators of over-pressure. Key information is: @Indent2(-1):*<\#9>Pore Pressure measurements (e.g. RFT logs) *<\#9>Drill-speed logs - drillability <@$>should reduce with depth in shales (see later section on "d" exponent) *<\#9>Formation bulk density logs (compaction and thus bulk density should generally increase with depth in shales) *<\#9>Formation Fluid contact levels (OWC, GOC, GWC) - these tend to remain almost constant across a field (assuming the absence of sealing faults) and thus their depths, combined with formation depth estimates, can provide sufficient information to estimate formation pressure gradients along the proposed well path. Given that depth prognoses tend to have margins of error associated with them, it is normal to make pore pressure prediction estimates based on the worst reasonable case scenario (but not on the worst theoretically possible case). This is generally a combination of a reasonable estimate of the maximum reservoir height combined with a reasonable estimate of the maximum hydrostatic pressure. @$:<*p(0,0,0,0,0,8.5,g,"International English")>This data can be used to make a good estimate of the pore pressures that may be encountered in the new well and so the casing scheme<$> and drilling fluid program<$> can be designed accordingly. However, pressure data has to be checked carefully to ensure that field production operations have not caused changes in the reservoir characteristics since the source well was drilled. These issues will be discussed further later in the Part<$> @heading 4:3.2.3.1.2<\#9>Regional Geology @$:<*p(0,0,0,0,0,8.5,g,"International English")>Because the majority of causes of overpressures are related to the depositional environment or history of the sedimentary rock, the prediction of overpressures during well planning, in the absence of any offset well information (e.g. when drilling a wildcat<$> or first well in an area), relies on either looking for indications of sedimentary activity that has the potential to generate overpressures or, alternatively, extrapolating symptoms of overpressure that are visible at or near the surface to underlying formations. In common with hydrocarbons, often the only way to determine if overpressures actually exist is to drill! Complex studies of stratigraphic and hydrodynamic features have been conducted in some areas of the world. These can be useful to identify shallow overpressures caused by artesian flow conditions etc. but are less likely to yield information about overpressures in hydrocarbon bearing formations. Studies into the depositional environment<$> of an area may indicate the type of rapid burial that can lead to over-pressures. Mathematical modelling is being applied to the action of sedimentation and burial with the objective of simulating the process of compaction and so identify areas where overpressures may exist. @heading 4:3.2.3.1.3<\#9>Geophysics @$:<*p(0,0,0,0,0,8.5,g,"International English")>It is rare that exploration or appraisal drilling is initiated prior to the completion of seismic profiling of the area. With modern processing techniques it is possible to identify characteristics in the survey that suggest the existence of over-pressured formations. Primarily they identify undercompacted material due to poor response or slow transit times. These techniques become more reliable when combined with log data from wells in the same province. Actual sonic transit times in these wells can be compared to seismic data to identify where undercompaction appears to have occurred. Seismic surveys can show the presence of geological features known to cause overpressures such as salt domes<$> (causing formation distortions), growth faults<$> (in areas of rapid burial) etc. In addition, the presence of gas can increasingly be suggested by seismic data; bright spots indicating high amplitude reflections from gas filled (and so relatively low bulk density) formations being identified on the seismic maps. @heading 3:3.2.3.2<\#9>Warning Signs whilst Drilling @$:It is normally possible to identify that the well is entering an area of overpressure before the latter manifests itself by a kick from a porous and permeable formation. To exist, an overpressured formation must be sealed, at least from above, by an impermeable layer. Consequently a pressure gradient will exist across the impermeable layer and the effects of this gradient provide the warning signs. The nature of the impermeable layer is important; a very thin but extremely impermeable layer (such as salt and limestone) will not provide as many clues as one where the pressure gradient permeates the formation (e.g. shale). The formation where pressure moves from normally pressured is called the transition zone<$>. @heading 4:3.2.3.2.1<\#9>Drilling Parameters @$:In general, the onset of abnormally pressured formations is associated with an increase in the drillability of the formation. This is a deviation from a general trend of reduced drillability with depth due to compaction, increased stresses etc. Basically this increase can manifest itself in two ways. In shale, where this shale is a pressure transition zone, the increase will be gradual, while, when entering the overpressured reservoir itself the increase will be more sudden. The latter is normally called a drilling break. It should be noted that not all increases in the drilling rate are a result of an increase in formation pressure. It could simply have been the result of a change in lithology. However, any unexplained increase in drilling rate should always be investigated. A number of attempts have been made to link the drilling parameters to generate a measure of drillability . The best known was by Jorden and Shirley * who demonstrated empirically that in homogeneous shale formations, and with all other factors being equal, penetration rate is proportional to the rotation rate of the bit. @List2: where: @List3:<*p(51.024,-17.008,0,14.5,0,0,g,"International English")>R is the rate of penetration N is the rotation rate is a constant of proportionality (that is only valid for one set of<\n> circumstances) @extra space before:Jorden and Shirley also showed empirically that the penetration rate depends on the weight on bit and hole size according to an exponential relationship : @Indent1: @List2:where: @List3:W <\#9>is the weight on bit D is the hole diameter is a constant of proportionality (that is, like <@$>, only valid for one set<\n> of circumstances) d is an exponent which, relating penetration rate to weight on bit per unit hole diameter, gives a measure of the "drillability" of the formation @$:It was shown, still empirically, that combining the two above equations into one: <\#9> gives a good approximation to the behaviour of a real system in practice. <*p(0,0,0,0,0,0,g,"International English")>Given that the utility of such a relationship is to compare the drillability of similar formations in similar circumstances, rather than to establish the absolute value of a well defined parameter, the equation is simplified by dropping the constant. The relative drillabilities of similar formations in which only the penetration rate, weight on bit, rotation rate and hole diameter vary is then given by the value of "d" in the equation @Indent1: in which case "d" is known as "the d exponent" and <\n> <@$> @$:Given again that the objective is to make comparisons rather than establish absolute values, the units in which penetration rate, weight on bit, rotation rate and hole diameter are expressed do not affect the final result. When working in oilfield units, in which penetration rate is measured in ft/hour, weight on bit in lbs, rotation rate in rpm and hole diameter in inches, the convention has grown to insert factors to convert diameter to feet, to make the time units consistent and to convert the weight on bit units into lbs x10<+z9>6<$z$>. <*p(0,0,0,0,0,0,g,"International English")>Conventionally thus <*p(0,0,0,0,0,8.504,g,"International English")><\#9> <*p(0,0,0,0,0,0,g,"International English")>It has been found that the "d exponent" can additionally be adjusted for drilling fluid density variations. This gives the compensated d exponent, "d<->c<$>" . <*p(0,0,0,0,0,8.504,g,"International English")><\#9> Although the connection cannot be justified mathematically, the use of this compensated d ("d<->c<$>") exponent has proved advantageous. These exponents were developed for application in homogenous shale intervals. They are less reliable in variable lithology, sandstone and limestone. However, it is very likely that a sealing cap rock is a shale so it does have relevance. Additionally, the equation was specifically developed for Gulf Coast conditions where drilling shale is the norm; it should therefore be used with caution in other areas. Figure 2.3.5 illustrates the indication of change given by the "d exponent" <*p(0,0,0,0,0,8.5,g,"International English")>Other algorithms have been developed that require significant processing of raw data such as Geoservice's Sigmalog<$>, Baroid's Log Normalised Drilling Rate (LNDR) <$>and Anadrill's Instantaneous Drilling Evaluation Log<$> (IDEL) or A-exponent. These and others may be provided as a standard or additional Mud-Logging<$> service. @heading 4:3.2.3.2.2<\#9>Drilling fluid parameters @$:<*p(0,0,0,0,0,8.5,g,"International English")>A number of indications can be observed in the drilling fluid returns. These, again, have to be assessed in conjunction with the drilling parameters and the drilling environment. Relevant parameters include: @heading 5:Drilling fluid gas levels @Indent1:<*p(17.008,0,0,14.5,0,8.504,g,"International English")>The gas content of the drilling fluid can be measured crudely using standalone methane (CH<-z9>4<$z$>) meters or more sophisticated gas chromatographs (usually in Mud Logging units). The following parameters may be useful: @Indent2:<*p(34.016,0,0,14.1,0,8.504,g,"International English")>Background gas<$> levels (very small quantities of gas contained in claystone/shale ) generally increase from ambient values when drilling into undercompacted shales. Gas shows<$> (from the pores of gas-containing reservoir rock being drilled) will be apparent when a hydrocarbon reservoir is entered. The degree of the shows is dependant on the pore pressure of the rock. Excessive gas shows suggests a minimal overbalance on bottom. Trip / Connection gas<$> may be observed due to slight reductions in bottom hole pressure due to a loss of the back pressure due to fluid friction in the annulus when the pumps are stopped plus a swabbing effect whilst picking up to make a connection or when tripping. Again, high readings tend to suggest that there is minimal overbalance on bottom. Gas composition<$> from a gas chromatograph - a service offered by Mud Logging Units - can also provide indications of overpressures. The ratio of methane to ethane generally reduces as levels of ethane increase in transition zones or overpressured formations. H<-z9>2<-z$>S levels<$> - The presence of increasing levels of H2<$z$>S in the drilling fluid whilst drilling evaporites can also be an indication of the onset of overpressures @heading 5:<*p(56.693,-56.693,0,14.1,6,8.504,g,"International English")>Drilling fluid density @Indent1:<*p(17.008,0,0,14.1,0,8.504,g,"International English")>Reductions in drilling fluid density may be caused by increased gas content (see earlier) or increasing water content. In low permeability formations this may be observed in place of a higher volume kick. @heading 5:<*p(56.693,-56.693,0,14.1,6,8.504,g,"International English")>Drilling fluid temperature @Indent1:<*p(17.008,0,0,14.1,0,8.504,g,"International English")>Temperature gradients (dT/dZ) in undercompacted formations tend to be greater than in normally compacted formations. Normally, the flow line temperature of the drilling fluid, under conditions of uniform cooling etc. should increase regularly with depth. If the increase deviates from the established pattern it can indicate the onset of over-pressures. This effect is, however, generally masked by changes in circulation rate, drilling fluid characteristics, tripping as well as riser cooling effects, particularly in deep water operations. @heading 5:<*p(56.693,-56.693,0,14.1,6,8.504,g,"International English")>Drilling fluid resistivity @Indent1:<*p(17.008,0,0,14.1,0,8.504,g,"International English")>Associated with increased formation water content in the drilling fluid, this parameter can back up others such as density provided there is sufficient contrast in the salinity of the drilling fluid and formation water. Increased levels of sulphur salts in the drilling fluid whilst drilling evaporites can indicate over-pressures (see H<-z9>2<-z$>S<$>). @heading 4:3.2.3.2.3<\#9>Cuttings analysis @$:<*p(0,0,0,14.2,0,8.5,g,"International English")>Careful analysis of cuttings samples can provide warning signs of impending overpressures: @heading 5:<*p(56.693,-56.693,0,14.2,6,8.504,g,"International English")>Shale density @Indent1:<*p(17.008,0,0,14.2,0,8.504,g,"International English")>Shale density can be measured relatively easily at the well site by Mud-Loggers. In areas of undercompaction the density will not increase with depth as fast as in normally pressured formations and may even decrease. Plotted against depth this is a useful tool in areas of long shale sections. @heading 5:<*p(56.693,-56.693,0,14.2,6,8.504,g,"International English")>Cation Exchange Capacity (CEC) @Indent1:<*p(17.008,0,0,14.2,0,8.504,g,"International English")>Shale is composed of four different clay minerals, kaolinite, illite, montmorillonite and smectite. The ratios of these minerals change with depth due to the transformation of smectite into illite with increased pressure and temperature. A simple test can be performed to estimate the amount of smectite in a sample of cuttings and this value, when plotted against depth should show a negative gradient. Deviation from this trend in a shale formation is indicative of entering a transition or overpressured zone. @heading 5:<*p(56.693,-56.693,0,14.2,6,8.504,g,"International English")>Cuttings shape, size and abundance @Indent1:<*p(17.008,0,0,14.2,0,8.504,g,"International English")>In general, as a transition or over-pressured zone is penetrated, increased borehole instability caused by a reduced drilling fluid pressure overbalance can lead to increased volumes of larger, more angular cuttings. This may be associated with other indications of borehole instability such as over-pulls etc. It is important to realise, however, that such features are not indicative in isolation as they can be caused by other factors such as tectonic stress etc. @heading 4:<*p(56.693,-56.693,0,14.2,6,8.504,g,"International English")>3.2.3.2.4<\#9>Wireline logs & formation pressure evaluation @$:<*p(0,0,0,14.2,0,8.5,g,"International English")>Many logging tools used for petrophysical analysis can give indications of overpressured formations or transition zones, predominantly through identifying shale undercompaction. @heading 5:<*p(56.693,-56.693,0,14.2,2.835,2.835,g,"International English")>Density @Indent1:<*p(17.008,0,0,14.2,0,8.504,g,"International English")>Under normal compaction conditions, shale density increases with depth. Consequently, a change in the density gradient can suggest a transition zone or overpressures. @heading 5:<*p(56.693,-56.693,0,14.2,2.835,2.835,g,"International English")>Resistivity @Indent1:<*p(17.008,0,0,14.2,0,8.504,g,"International English")>Shale density and therefore resistivity tends to increase with compaction and depth. Reductions in resistivity can indicate overpressures. @heading 5:<*p(56.693,-56.693,0,14.2,2.835,2.835,g,"International English")>Sonic @Indent1:<*p(17.008,0,0,14.2,0,8.504,g,"International English")>Sonic transit times reduce as density increases. Thus, an increase in the transit time can indicate overpressures. @heading 5:<*p(56.693,-56.693,0,0,2.835,2.835,g,"International English")>Formation pressure @Indent1:Ultimately, a series of formation pressure measurements will provide quantitative evidence of the existence of over-pressures. However, these require porous, permeable formations and cannot give warning of the existence of a transition zone. @heading 4:3.2.3.2.5<\#9>Well seismic evaluation @$:<*p(0,0,0,0,0,8.5,g,"International English")>Seismic check shots<$> or a Vertical Seismic Profile<$> can be conducted in the well and the time/depth data used to correct the original seismic interpretations which may have been based on assumed velocities in various rock formations. These corrections can assist in more accurately predicting the depth of deeper sites of undercompaction and thus possible overpressures. @heading 2:3.2.4<\#9>Shallow Gas @heading 3:3.2.4.1<\#9>Introduction @$:<*p(0,0,0,0,0,8.5,g,"International English")>Shallow gas deposits account for 41% of all recorded blowouts in the Gulf of Mexico and the North Sea since 1980. Over 50% of these blowouts resulted in major damage to the drilling unit and many have resulted in serious injury and death to personnel. Characteristics of shallow gas blowouts are very little warning, very high flow-rates, large volumes of abrasive sand, rapid equipment failure, gas leaks, ignition and fires, all in conjunction with excessive noise. If one commences it is virtually impossible to recover control until the gas flow stops naturally, either due to exhaustion of the reservoir or collapse of the bore hole. @heading 3:3.2.4.2<\#9>Definition @$:<*p(0,0,0,0,0,8.5,g,"International English")>Various definitions for shallow gas deposits exist: @Indent2(-1):EP 88-1000 SIPM Shallow Gas Procedure Guidance Manual<$>: "gas that is encountered in the well which cannot be closed in, because well shut-in pressures combined with the hydrostatic head of the fluid in the well bore will probably result in formation breakdown and subsequently cratering of the well. If BOP protection and normal well killing procedures can be applied the gas is not considered to be shallow gas". Shell Expro: Well Engineering Information System (1995) <$>: Shallow gas shall be taken to mean: @Indent3(-1):i.<\#9>Hydrocarbon Gas accumulations encountered before setting surface casing (first casing on which a BOP is installed) ii.<\#9>Hydrocarbon gas accumulations encountered after setting the surface casing but where the well cannot be closed in. @heading 3:3.2.4.3<\#9>Origins of Shallow Gas @$:<*p(0,0,0,0,0,8.5,g,"International English")>Shallow gas can derive from two sources: @heading 4:<*t(17.008,0,"1 ")><\#9>Biogenic Gas @Indent1:Biogenic gas is formed at shallow depth from the decomposition of organic material (i.e. "swamp gas"). It is primarily methane and tends to be found in-situ in the decomposing material or in a very close reservoir. This type of shallow gas is particularly prevalent in swampy areas as well as in areas of rapid sedimentary deposition where there is a significant amount of organic material being deposited. @heading 4:<*t(17.008,0,"1 ")><\#9>Petrogenic Gas @Indent1:<@$>Petrogenic gas is generated at depth from the degradation of hydrocarbon source material at elevated temperature and pressure and has subsequently migrated into a shallow reservoir rock overlain by a seal. Migration can have occurred naturally over geological time or may have occurred recently due to poorly cemented casing strings, internal blow-outs etc. Alternatively, in rare circumstances, a deeply buried gas reservoir can become uplifted or exposed near surface by erosion of the original overburden. Petrogenic gas is predominantly composed of Methane, Ethane and Propane. @$:<*p(0,0,0,0,0,8.5,g,"International English")>Gas of either origin will only form a reservoir if it exists or subsequently migrates into a permeable and porous formation overlain by a sealing formation. The gas is commonly found in highly porous and permeable unconsolidated sands overlain by clay or claystone. Due to the depth of burial it is unusual for the reservoir to be overpressured however, the "gas effect" can cause the top of the reservoir to be abnormally pressured with respect to the local hydrostatic gradient. Shallow gas pockets can also form in cold environments without the presence of an impermeable formation. Migrating gas cools to form hydrates<$> (solid mixtures of water and gas molecules) which, being impermeable, trap additional gas. This environment is becoming increasingly significant in deep water drilling operations where sea bed temperatures can approach 0<\#186> C. @heading 3:3.2.4.4<\#9>Operational constraints @$:<@$p><*p(0,0,0,0,0,8.5,g,"International English")>Given the shallow depth of burial and the very low formation strength of overlying formations it is not normally possible to drill with sufficient drilling fluid gradient to control shallow gas formations that are overpressured due to the "gas effect". In addition it is generally not possible to close in a well in the early stages of a shallow gas blowout without the risk of breaking down the formation at the previous casing shoe (if any) and cratering the formation around the well. Consequently the only well control method available is to divert the flow away from the rig whilst attempting to regain control of the well or evacuating the location. The entrained sand and other material causes significant damage to the diverting equipment and its subsequent failure has been the primary cause of major shallow gas incidents, many tragically with fatal consequences. The plume of a flow of shallow gas has been postulated to cause stability problems for floating drilling vessels, particularly drill-ships. The flow of gas can also ignite at surface forming a hazard to the rig itself as well as to evacuating personnel. Other characteristics of a shallow gas kick/blowout are: @Indent2(-1):*<\#9>difficulty in identifying initial well flow - particularly when drilling from floating units and there is no return of drilling fluid to surface. *<\#9>a rapid increase in flow - as the well starts to flow additional gas rapidly reduces the hydrostatic head in the well and so increases the flow rate. Total unloading of the well to gas can happen in less than a minute leaving very little time for analysis and reaction and making controlled reaction to a shallow gas kick extremely difficult. If returns are to surface the noise levels are exceedingly high, adding to the difficulty of carrying out emergency procedures. *<\#9>whilst control may be held whilst drilling, rapid flow can start when circulation ceases or when the hole is circulated clean of drilled cuttings. Swabbing whilst tripping can initiate a shallow gas kick and is difficult to identify when there are no returns to surface. For this reason the standard procedure is to pump out of the hole if there is any possibility of shallow gas. @heading 3:3.2.4.5<\#9>Prediction @$:<*p(0,0,0,0,0,8.5,g,"International English")>The primary defence against shallow gas is its identification and avoidance at the well planning stage. As mentioned earlier, certain depositional environments are more prone to shallow gas, particularly of the Diagenic origin. However, Petrogenic shallow gas has the potential to exist wherever a shallow sealing formation exists. In addition, deep water hydrate formations can exist even in the absence of a seal. The principle method of identification is through the use of Seismic Surveys. These can be either analogue<$> or digital<$> Shallow seismic<$> surveys. @Indent1:Analogue surveys<$>, combined with bathymetric measurements and a sea bed sonar survey, provide a very limited penetration into the sea bed, being primarily of use for selecting a suitable drilling location. Digital surveys<$> can be processed and analysed to identify bright-spots<@$> in formations down to around 3,000 ft (1,000 m) and with thicknesses in excess of 15 ft (5 m)which are indicative of the presence of shallow deposits of gas. (refer to EP 88-1000 for additional data on shallow seismic surveys). @$:<*p(0,0,0,0,0,8.5,g,"International English")>Shallow seismic can be augmented by small diameter soil boring surveys (usually limited to 50 m penetration) and pilot hole drilling from a conventional drilling rig. Pilot holes can be logged using conventional petrophysical tools (Induction / SP / Sonic / Gamma Ray / Caliper) to identify the presence of shallow gas deposits and evaluate its characteristics. Additional information on the operational precautions to be taken if shallow gas is present can be found in Topic 4.3.3.