HYDRAULICS/WELL CONTROL/PRESSURE ANALYSIS

PART 3 FORMATION PRESSURE ANALYSIS

3.1 Pressure Gradients Hydrostatic Pressure Formation Pressure Formation Balance Gradient Overburden Pressure Gradient 3.2 Typical Occurances of Abnormal Formation Pressures Underpressured Overpressured ....... Hydrostatic ....... Non Hydrostatic 3.3 Detection Techniques 1. Rate of Penetration 2. Drilling Exponent 3. Gas Trends 4. Drag and Torque 5. Temperature 6. Cuttings Analysis 7. Mud Parameters 8. Indications while Tripping 3.4 Analysis using Geophysical, MWD and Wireline Data 3.5 Direct Measurements of Formation Pressure 3.6 Summary of Typical Trends

3.7 Quantitative Analysis of Formation Pressure a.1 Correct Determination of the Drilling Exponent Compaction Trend a.2 Lithological Effects on Compaction Trend a.3 Causes of Trend Changes or Shifts b. Determination of Overburden Gradient c. Calculation of Formation Pressure 1. Eatons Method 2. Equivalent Depth Method 3.8 Calculation of Fracture Gradients a. Theory b. Eatons Method c. Daines Method 3.9 Use of the QLOG software Appendix

3.1 Pressure Gradients Hydrostatic Pressure Gradient The Hydrostatic Pressure at any given depth (vertical) is defined as the pressure exerted by the weight of a static column of fluid. Phyd = ρ g h ie KPa = kg/m3 x 0.00981 x TVDm PSI = ppg x 0.052 x TVDft This gives the following normal hydrostatic gradients:- Freshwater = 0.433 psi/ft (8.33ppg emw, 1.0 sg) Brine = 0.480 psi/ft (9.23ppg emw, 1.11 sg) Freshwater = 9.81 KPa/m (1000 kg/m3 emw) Brine = 10.87 KPa/m (1108 kg/m3 emw) Formation Pressure Gradient This is defined as the pressure of the fluid contained within the pore spaces of a sediment or rock, which will be 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. eg North Sea 0.450 psi/ft (8.66ppg emw) or 10.20 KPa/m (1040 kg/m3 emw) US Gulf 0.465 psi/ft (8.94ppg emw) or 10.53 KPa/m (1074 kg/m3 emw) if Formation Pressure < Hydrostatic...............underpressured if Formation Pressure > Hydrostatic...............overpressured

Formation Balance Gradient This is defined as the equivalent mud density required to balance the formation pressure at any given depth. example: If the hydrostatic gradient is 0.45 psi/ft, the hydrostatic pressure at 5000 ft TVD will be 2250 psi. Assuming normal formation pressure, The formation balance gradient would be:- 2250/(0.052 x 5000) = 8.65 ppg emw The position of the rig in relation to the depth of the formation and local topography will cause the formation balance gradient to vary enormously. example A B 3000ft 914.4m 2000ft 609.6m Formation Pressure 1350 psi / 9308 KPa At Site A, FBG = 1350 = 8.65ppg 3000x0.052 At Site B, FBG = 1350 = 13.00ppg 2000x0.052

At Site A, FBG = 9308 = 1038 kg/m3 914.4x0.00981 At Site B, FBG = 9308 = 1556 kg/m3 609.6x0.00981 So, even though the same formation and pressure is the concern for both wells, the mudweight required to balance that formation pressure will be different for each well.

Overburden Pressure Gradient At a given depth, the overburden pressure is the pressure exerted by the weight of the overlying sediments. It is usually termed stress to distinguish fluid and matrix pressures. Overburden S = ρb x TVD where TVD is metres 10 S = kg/cm2 ρb = average bulk density g/cm3 S = ρb x TVD x 9.81 TVD = m S = Kpa ρb = g/cm3

S = ρb x TVD x 0.433 TVD = ft S = psi ρb = g/cm3

Bulk density is a function of the matrix density, porosity and pore fluid density. ρb = ∅ ρf + (1 − ∅)ρm ∅ = porosity 0 − 1 eg 12% = 0.12 ρf = pore fluid density ρm = matrix density In practice, the bulk density can be taken directly from wireline logs or from sample measurements. Overburden will increase with depth with a proportional decrease in porosity. An average value of 2.31 gm/cc can be used for bulk density until more accurate measurements or data becomes available.

eg 2.31 ρb Typical Onshore Profile depth Typical Offshore Profile 2.31 air gap water depth

Taking an average value of bulk density to be 2.31 gm/cc gives an overburden pressure gradient of 1.0 psi/ft. Thus, a typical profile would look like: Overburden Gradient 1.0 psi/ft 2.31 gm/cc Pform < Phyd Pform > Phyd underpressured overpressured Hydrostatic Pressure Gradient 0.433 to 0.48 psi/ft 8.33 to 9.23 ppg emw 1.0 to 1.11 gm/cc 9.79 to 10.81 KPa/m 998 to 1102 kg/m3 emw Accurate determination of the overburden gradient is critical for accurate formation and fracture gradient calculations.

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. If more accurate data becomes available from wireline logs, the overburden gradient can be derived from the Bulk Density log or from the Sonic Log. The Sonic log can be used to derive bulk density if no log is available. For consolidated rocks, ρb = 3.28 − ∆T 89 For unconsolidated rocks, ρb = 2.75 − 2.11 (∆T − ∆Tm) ( ∆T + 200 ) where ρb = gm/cc ∆T = formation transit time (actual sonic) µsec/ft ∆Tm = matrix transit time Default values for the matrix transit time: Dolomite 43.5 Limestone 43.5 to 47.6 (argillaceous) Sandstone 47.6 (argillaceous) to 55.6 Anhydrite 50 Salt 67 Claystone 47 47 is used as the default for other lithologies

Exercise 3a Gradient Calculations 1. Convert the following mud densities into pressure gradients:- a. 9.5 ppg (psi/ft) b. 12.6 ppg (psi/m) c. 1.8 sg (psi/m) d. 1055 kg/m3 (KPa/m) e. 1250 kg/m3 (KPa/m) 2. What hydrostatic pressure is exerted by the following mud densities at the given depths ? a. 13.2 ppg at 7500 ft (psi) b. 10.5 ppg at 2300 m (psi) c. 1.45 sg at 5000 ft (psi) d. 1150 kg/m3 at 4000m (KPa) 3. What mud density would balance the following formation pressures ? a. 4000 psi at 5000 ft (ppg) b. 4000 psi at 7000 ft (ppg) c. 6500 psi at 4000 m (ppg) d. 6500 psi at 3000 m (ppg) e. 40000 KPa at 3000 m (kg/m3) f. 40000 KPa at 4000 m (kg/m3)

3.2 Typical Occurances of Abnormal Formation Pressures Underpressured formations 1) 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. 2) 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 (h) will be less than the actual total depth (D). 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. water intake at outcrop w.t. D h 3) Depletion of water or hydrocarbon reservoirs leading to a reduction in the hydrostatic pressure. 4) Large gas columns - again, a reduction in the hydrostatic in comparison with a fluid column.

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Overpressured formations Hydrostatic causes 1) Hydrocarbon reservoirs - in a sealed reservoir, the formation pressure throughout will be the same and will be equal to the pressure at the deepest part of the reservoir. This pressure would therefore be transmitted to the uppermost part of the reservoir. pressure sealed reservoir section depth 2) Aquifers - where the water intake is at a higher elevation than the local topography, therefore the actual height of the fluid column (h) is greater than the drilled depth. water intake h D

Non Hydrostatic causes 1) Undercompaction Under normal deposition and compaction rates, formation fluid will be squeezed out in to overlying sediments. Due to rapid deposition with respect to geological time, fluid flow becomes restricted and is not allowed to escape as normal. Thin impermeable layers such as limestone could cause the same flow restriction to underlying sediments. 2)Tectonic Loading caused by uplift, faulting or folding of rocks. If a formation is sealed and uplifted, it will retain its original fluid pressure at the shallower depth, therefore having a higher pressure than surrounding formations. Faulting can cause overpressured formations in many ways:- • faults and fractures may provide a conduit allowing deeper fluid pressures to be

released to shallower formations. • permeable and impermeable layers may be juxtaposed by a fault restricting normal

fluid migration. (fluid migration is normally governed by pressure gradient - it will always try to move from high to low pressure). • Salt and shale diapirism can cause locallised zones of high pressure due to all 3

tectonic processes. 3) Clay Diagenesis - during normal diagenesis, montmorillonite is altered to illite. This is a normal process leading to interlayer-bound water being desorbed and becoming free. The situation may occur that this released water may not be able to escape leading to an increased fluid content and increased pressure. Fluid will always try to move to zones of lower pressure, therefore unless an overpressured formation is perfectly capped, transition zones will exist. Detecting these zones by the interpretation of all available data is the major part of pressure analysis while a well is being drilled.

3.3 Detection Techniques 1) Rate of Penetration ROP will decrease normally with depth due to increased compaction and therefore reduced porosity. An overpressured zone will be undercompacted resulting in a relative increase in ROP. On its own, the ROP cannot be taken as a direct indicator because it can be affected by many parameters such as lithology weight on bit rotary speed torque fluid hydraulics bit type bit wear differential pressure To compensate for as many as these parameters as possible, a drilling exponent is used. 2) Drilling Exponent This will demonstrate the drillability of a particular formation, relating the ROP to the ease at which a formation can be drilled. In 1964, the drilling exponent was formulated by Bingham : R = a (W)d where R = ROP N (D) N = RPM W= WOB D = bit diameter a = lithology constant d = compaction exponent

Jordan and Shirley developed this theory in 1966: Dexp = 1.26 −− log (R÷÷N) R = m/hr 1.58 −− log (W÷÷D) N = rpm W = tonnes D = inches This formula was designed for use in shale, and where the formation is constant, the Dexp is a good indicator of porosity (ie compaction) and differential pressure. The Dexp evaluates the drillability of a particular formation, and as porosity decreases with depth, drilling will become proportionally more difficult, resulting in an increase in Dexp. A normal trend (normal compaction trend or NCT) can therefore be established with depth, and changes in differential pressure will be indicated by a decrease in the Dexp. The differential pressure is obviously defined by the relation between the formation pressure at any given depth and the hydrostatic pressure caused by the mud column at that depth. A change in mud density would alter the hydrostatic pressure and therefore change the differential pressure. This would affect the Dexp in the same way as an increase in formation pressure. The drilling exponent must therefore be corrected for changes in mud weight so that it only reflects changes in formation pressure. Rehm and McClendon, in 1971, developed the Corrected Drilling Exponent. DCexp = Dexp x d1 d2 where D1 = formation fluid density for the hydrostatic gradient D2 = mud weight

Affect on ROP and DCexp with changes in pressure Normal Pressure Gradient Transition Overpressured Depth ROP DCexp Formation Pressure Limitations to the drilling exponent a) Lithology type The drilling exponent was designed for and is only ideally suited for shale and claystone type lithologies. The porosity and grain size variabilty of other lithologies cannot be ideally accounted for. Different lithologies will therefore tend to show up as a shift, or repositioning of the drilling exponent trend eg limestones tend to shift the trend to the right sandstones tend to shift the trend to the left.

This is not always the case, the value of the drilling exponent will depend on the hardness; on how competent a lithology is; degree of granularity and cementation etc. Even with a shale interval, the trend can be affected by any degree of siltyness, cementation, or presence of accessory minerals. Even though the drilling exponent is only designed for shales, in practice, different lithologies, if they are uniform with depth, can reveal reasonable trends. All of the above has to be taken into a great deal of consideration when evaluating a drilling exponent trend. b) Hydraulics These are not considered in the calculation of the exponent, therefore any significant change could affect the drilling efficiency to such a degree that the drilling exponent is affected. Another consideration is that for unconsolidated lithologies, the jetting action of the bit is actually more important than the drilling action, so the drillability, reflected in the drilling exponent, can be totally erroneous. c)Bit Type and Wear These variabilities can significantly affect the value of the drilling exponent: • different bits are suited to different lithologies • diamond or PDC bits tend to yield constant drilling exponents regardless of lithology

type or depth. • as a bit becomes worn, drilling obviously becomes harder, causing the drilling

exponent values to erroneously increase.

Detection Techniques continued 3) Gas Trends A steady increase in background gas level could be an indication of an increase in formation pressure resulting in an increased pressure differential. This trend would have to be considered against such things as;- • changes in lithology • natural increase in formation gas • removal of gas at surface ie whether its being recycled • changes in penetration rate due to parameter change ie if the WOB is increased, the

ROP would show a corresponding increase, affectively releasing more gas over a given time interval

• reduction in mudweight increasing the differential pressure The occurrance of connection gases - these occur when the formation pressure becomes close to/equal to/greater than the mudweight. The dynamic overbalance (ie bottom hole circulating pressure) may be sufficient to balance the formation pressure, but when the pumps are stopped for a connection, the static overbalance (ie mud hydrostatic) may be insufficient, leading to an influx of formation fluid/gas. This will yield connection gas. This may be further enhanced by the effects of swabbing causing a further reduction in the hydrostatic. Knowing these 3 pressures ie bottom hole circulating pressure mud hydrostatic pressure swab reduced hydrostatic pressure ........can lead to an accurate determination of the actual formation pressure.

Connection gas is generally short in duration and sharp in distinction, although the longer the bottoms up time, the more drawn out the peak since the gas has more time to expand and become dispersed. The shape and symmetry of the peak can also yield useful information about the pressure differential: close to or at balance underbalanced Trends in the value of trip gases can also be an indicator. If no significant change in trip time or mud weight, an increase in trip gas could indicate an increase in formation pressure. 4) Increased drag and torque, overpull Indications of tight hole caused by overpressured formations:- - due to reduction in hole size from undercompacted/sloughing shales; - due to shale cavings falling in on the hole - this will also show up as hole fill on bottom after connections and trips. The operator has to carefully consider the causes of drag and torque, because they can be caused by many other factors such as: bit balling deviated holes doglegs or ledges differential sticking

5) Temperature Since heat eminates from the earth’s core, a geothermal gradient, with temperature increasing with depth, will exist as heat dissipates out towards the earth’s surface. Typical gradients may be in the range of between 2 and 5 °C per 100m but will not be constant throughout a well. The geothermal gradient will vary according to the thermal conductivity of the ‘components’ of a particular rock type or sedimentary sequence. For example:- Pure Quartz high conductivity Clay minerals low conductivity Evaporites high conductivity Pore fluid low conductivity The lower the conductivity of a particular sequence, the more resistance there is to the flow of heat away from the earth’s centre, therefore a greater geothermal gradient will exist. Measurements of mud temperature can be used to detect overpressured zones and even to anticipate their approach:- The thermal conductivity of water is less than that of rock matrix, therefore formation fluids act as a natural barrier to the normal flow of heat. Overpressured formations, being undercompacted, have greater porosity and therefore a relatively greater fluid content. This means that they are less conductive to the flow of heat, producing a higher geothermal gradient. An overpressured zone will act as a barrier to heat flow and therefore behaves as an insulating body. It has been shown that such insulating bodies (porous reservoirs and thick coals are other examples) disturb the distribution of isotherms directly above them, producing a reduction in the geothermal gradient. Thus, as an overpressured or transitional (increasing pressure) zone is approached, a reduction in temperature may be seen. This temperature will then rapidly increase once the overpressured zone is penetrated. This is illustrated over the page.

Formation Temperature Normal Pressure Transition Zone Overpressured Normal Pressure Depth Even though we (the mudloggers) can’t directly measure the bottom hole temperature, the heat generated by penetrated formations will be transferred to the drilling fluid. We can therefore measure the temperature of the mud leaving the hole, and a thermal ‘profile’ can be established as the depth increases. This profile will not be identicle to the actual geothermal gradient because as well as heat generated from the formation, additional processes such as drilling action and pump rate will be producing heat.

However, there are many factors that can affect the temperature of the mud: type of mud - different degrees of conductivity hole/pit size - volume of mud to heat duration of bit run drilling halts - periods allowing the mud to cool, especially at surface and in the upper part of the hole water depth - the larger the riser, the larger the cooling effect trips - the duration of which will determine how much the mud will cool off. The start of bit runs will see a rapid increase in temperature as the mud warms back to equilibrium surface additions - obvious cooling effect climate - different degrees of cooling at surface All of these factors will affect the actual value of the temperature of the mud leaving the hole. To gain as much information as possible from temperature measurements, it is more useful to remove variations in flowline temperature that are actually caused by changes in the temperature of the mud entering the hole. Delta T By eliminating, as much as possible, variations due to surface changes, the differential temperature Delta T (temperature out minus temperature in) can be used to provide a trend indicator. At the start of the bit run, the flowline temperature will show a rapid increase as the cooler mud becomes heated principally by the drilling and pumping action but also by newly drilled formations. Over a period of time, increases in flowline temperature due to drilling and pumping will become more uniform so that increases in the temperature are representative of changes due to the geothermal gradient. A period of 2 days or more may be required for this ‘equilibrium temperature’ to be reached

The presence of an overpressured zone will be indicated by a greater degree of increase in the flowline temperature. Conversely, Delta T at the start of a bit run will be high and show a rapid decrease. With the duration of a bit run, the normal Delta T trend will be a gentle decrease. A particularly long bit run may see Delta T become constant. An overpressured zone will be indicated by an increase in Delta T. Temperature Parameter Duration of Bit Run / Depth ∆T MTO

6) Cuttings Analysis a) Shale Density With increased depth and greater compaction, shale density will show a normally increasing trend. An overpressured zone will be indicated by a decrease in shale density owing to decreased compaction and higher porosity ie a higher proportion of formation fluid in relation to rock matrix. b) Volume, size and shape The presence of shale cavings or increased volume of cuttings is usually a good indicator of overpressure, but the engineer has to be careful in their interpretation because other stress conditions may be responsible. Cavings are generally considerably larger than the observed cuttings and have two typical shapes; elongated and concave, blocky and fractured. c) Shale Factor With normal diagenesis and cation exchange, clay minerals such as montmorillonite and smectite will transform to illite, thus a reduction in CEC (cation exchange capacity) will be seen with depth. An approximation to CEC is achieved by using Methylene Blue to determine the shale factor. As with the CEC, the shale factor will normally decrease with depth as the amount of illite increases. In an abnormally pressured zone, the increased temperature actual speeds up the process of cation exchange, therefore the shale factor would show a more rapid decrease. NB as well as this ‘result of overpressure’ detailed above, note that the cation exchange can also be a cause of overpressure. A lot of bound water is freed during the cation exchange and if this water is not released during compaction (as in the normal dewatering process), increased fluid pressure will result.

7) Mud Parameters We have already seen how mud temperature can be used to recognise changing trends in formation pressure. Other mud parameters will also indicate changes in pressure but are generally ‘later’ indicators, occurring when an influx is already present:- • Pressure - an influx into the well bore of formation fluid or gas will decrease the mud

density causing a reduction in the hydrostatic pressure. This will be indicated by a gradual reduction in the standpipe pressure as the influx occurs.

• Chloride content - The presence of an undercompacted/overpressured zone would

lead to an increased porosity, therefore an increased volume of pore fluid. This means an increase in salinity. From a mudloggers point of view, this will be indicated by an increase in conductivity (NB this would correlate to a decrease in resistivity from wireline logs or MWD). These parameters however have to be treated with a great deal of caution, because factors can affect the apparent resistivity/conductivity such as temperature, presence of hydrocarbons, mud type and filtration, nature of pore fluid, changes in lithology or organic matter.

• Density - an increased amount of formation fluid or gas within the mud would clearly

be identified by a reduction in mud density. • Mud flow and mud level - any increase would clearly indicate the possibility of an

influx. 8) Indications while Tripping Incorrect mud displacements:- a) Excessive mud returns while running in the hole. b) Lower than expected fill (or even a pit increase) while pulling out of the hole. Any swabbing effects should be analysed. A degree of swabbing may be acceptable depending on how fast the pipe is being pulled, but excessive swabbing could be due to formation pressure being close to, or over balanced.

3.4 Pressure analysis using Geophysical, MWD and Wireline indicators 1) Seismic Profile This will be done once the well has been drilled, so can be used to compare with data accumulated during drilling. It could also be useful data when determing pressure profiles for future well planning. The two-way travel times used to produce the seismic profile can be recomputed to calculate interval transit times, thus resembling sonic data. The normal trend would be one that decreases with depth, ie as compaction increases and porosity decreases. 2) MWD and Wireline Parameters such as resistivity, sonic, gamma, density may be measured by either of the above operations. Clearly, if this data is available from MWD, then these indicators will provide accurate realtime data that should be used in conjunction with our own realtime measurements. Wireline data will be produced once the well or hole section has been drilled, so the data would be used to confirm or negate predictions already made. This data becomes invaluable for future well planning when establishing pressure profiles. NB be aware that the accuracy of all wireline readings is subject to the thickness of individual beds allowing a full response. a) Gamma Ray Primarily for the accurate determination of lithology types. Gamma is a measurement of the natural radioactivity of rocks by detecting such elements as Uranium, Thorium and Potassium. A thick shale sequence that has undergone constant depositional conditions such as burial rate, compaction and source material, will be subject to increased dewatering with compaction. During the dewatering process, Potassium ions adsorbed onto clay particles are not totally released, so that an increase in Potassium and therefore gamma will be seen with depth.

As a reliable pressure indicator, the constant history required is generally unrealistic. Actual gamma values will also be affected by varying Thorium and Uranium content. b) Sonic The sonic transit times are a function of lithology and porosity. Under normal compaction, porosity will decrease with depth, thus sonic transit times will show a normal decrease with depth. With constant lithology, an increasing sonic trend indicates increased porosity, undercompaction and possible overpressure. It is often the case that the sonic trend is a good mirror image of the drilling exponent. Therefore, when drilling exponent data is not reliable due to many possible reasons as already described, the sonic log can provide invaluable information for trend analysis. c) Resistivity Resistivity measures the ability of a formation to conduct electricity and is a function of the amount and nature of the pore fluid, therefore a function of porosity. Deep resistivity readings should be used in preference to shallow ones because the data is generally a true indication of formation fluid and not affected by mud filtrate invasion. With depth and increased compaction, there is a reduction in the formation pore fluid. Since fluid is a better conductor than rock matrix, this will reduce the conductive ability of the formation. Thus, with depth, resistivity will normally increase. A decreasing trend will be an indication of undercompaction. The reliability of resistivity as a pressure indicator will be greatly affected by any changes in the salinity of the formation pore fluid. d) Bulk Density As with shale density, the trend should clearly increase with depth as the degree of compaction increases.

3.5 Direct Measurements of Formation Pressure The only direct measurements are provided by Repeat Formation Tests and Drill Stem Tests. Formation tests such as DST’s are generally only performed to determine pressures of potential reservoirs. Therefore, only as a by-product, do they yield information that can be used in formation pressure evaluation. RFT’s, on the other hand, are often used to confirm evaluations or to solve any doubts that may have arisen from previous evaluation techniques while drilling. With many measurements possible on a single wireline run, RFT’s are a useful tool in pressure evaluation especially in wildcat areas. Although not a direct measurement, a bottom hole kick resulting in well shut in will obviously provide an accurate determination of the formation pressure. Only bottom hole kicks can be considered in this type of evaluation; kicks due to gas expansion from shallower depths cannot provide a direct evaluation of formation pressure. If the well has been shut in, an accurate determination of the formation pressure can be made by using the shut in pressures as described in Part B of this manual. If the mud weight is close to balance, close consideration of gas trends can also provide accurate estimations of the formation pressure. This is possible by the monitoring of background gas and connection gas, together with swab gas, and the affect of these trends with adjustments in the mudweight.

3.6 Summary of typical trends while drilling Dxc Sh.Dens ∆T MTO Background/Conn Gas NOTE These trends are illustrated with the assumption that the mudweight is not increased while drilling through the undercompacted zones. Under normal situations, the mudweight would be increased at signs of underbalance. This would obviously reduce the pressure differential and bring the well back on balance. Clearly, some of the trends would then be different. There would be a reduction in background and connection gas. The connection gas would disappear if the mudweight was increased above formation pressure (unless due to effects of swabbing). The temperature trends would be affected by surface additions to the mud system in order to increase the density. The drilling exponent may even be affected if the the increase in mud weight required was large.

Normal Pressure

Increasing Pressure (Transition Zone)

Overpressured

Summary of typical wireline trends Sonic Resistivity FDC

Normal Pressure

Transition Zone

Overpressured

3.7 Quantitative Analysis of Formation Pressure Up to this point, we have been looking at the way in which trends of various parameters and measurements can be an indication of increasing formation pressure ie Qualitive Analysis. This information then needs to be processed in order to determine an accurate estimate of the actual formation pressure ie Quantitative Analysis. Our main tool for doing this while the well is being drilled is the Corrected Drilling Exponent. Wireline measurements can then be used after the event to compare or correct results. Before the calculation method is looked at, the determination of the correct compaction trend, and influences requiring a shift in the trend, should be explored in greater detail. 3.7a.1 Correct determination of the Drilling Exponent Compaction Trend As already discussed, the Dxc was designed for, and is of most use, where there is a reasonable sequence of homogeneous shale. Differences will be seen wherever there are ‘impurities’ such as siltiness and accessory minerals. Therefore, preference should be given to pure shale points which will normally appear to the right of the data points. Difficulty in accurately determining the trend will be experienced if there are no pure shales. • A silty shale sequence for example will tend to move data points to the left. The

compaction trend for shale would therefore actually be positioned to the right of the observed trend.

• Conversely, the opposite will generally happen with a sequence of calcareous shale.

The compaction trend for shale would actually be to the left of the observed trend. The selection of the compaction trend is therefore highly prone to different interpretations by different engineers. There is no substitute for experience in this process.

Although not considered when this method was first formulated, lithologies other than shale can still yield reasonable trends at times, although the engineer has to be aware of the typical differences in trends between different lithologies. • tight, well cemented sandstone will move the trend to the right • weaker, unconsolidated sandstone will move the trend to the left • well cemented crystalline limestone will move trend to the right • argillaceous or porous limestone will move the trend to the left • siltstone will move the trend to the right These differences are illustrated over the page. In general: The harder; the tighter; the more cemented the lithology; the higher the Dxc value. The weaker; the higher the porosity; the lower the Dxc value. NB the pressure program calculates actual formation pressure from the offset of the actual Dxc values from the selected compaction trend (which is assumed normal), when compared to the overburden gradient. Therefore, for reasonable depth intervals, the trend should be selected from the observed points for each lithology. Thin stringers are difficult to compensate for.

3.7a.2 Example of lithological effects on the corrected drilling exponent trend. Shale Cemented Siltstone Shale Cemented Limestone Calcareous Shale Unconsolidated Sst Cemented Siltstone Tight Sandstone Silty Shale NCT Normal Compaction Trend for shale

3.7a.3 Causes of Trend shifts or changes. Unconformities An unconformity seperates formations of different stratigraphic ages which may have undergone a different burial and compactional history. As such, a trend shift may be necessary. It is quite possible, also, that the trend may have a different slope. NCT 1 Unconformity NCT 2 Trend changes due to bit wear As a bit becomes worn, it would become progressively more difficult to drill the same, homogeeous lithology. This would result in higher values of the drilling exponent, with the trend increasing to the right (diagram 1). If an overpressured zone was encountered at this point, the change could well be masked because the values of Dxc would not decrease as much as would be normally expected (diagram 2). NCT Bit becoming worn normal bit NCT worn bit

DIAG 1 DIAG 2

Normal Pressure

Transition Zone

Other situations requiring a shift change Bit Type Different bit types such as tooth or insert, together with different hardnesses, will be suited to different lithologies. Therefore, for the same lithology, different types may well produce different values of drilling exponent for the same parameters. This type of trend shift is common. PDC bits are the extreme, often producing constant drilling rates and drilling exponent regardless of depth and compaction. A near vertical trend for large depth intervals is not unusual. Hydraulics If the hydraulics are not such that optimum bit and hole cleaning is not present, the value of the drilling exponent will be affected. Significant changes in the hydraulics may require a shift change. Drilling Parameters Although accounted for in the drilling exponent calculation, any major change in weight or rotary speed may see a trend shift. This will most often be seen in directional drilling, where not only high RPMs are present, but the WOB seen at surface is not representative of the weight at the bit due to poor weight transfer. Hole Diameter Not only the diameter has an affect here, but with new hole sections, different bits, drilling parameters and hydraulics will affect the drilling exponent. examples: 12 1/4” hole Opt hydraulics Tooth bit 8 1/2” hole Poor hydraulics Insert bit Hole Diameter Hydraulics Bit Type

3.7b Determination of the Overburden Gradient The overburden pressure at any given depth is the pressure due to the cumulative weight of the overlying sediments and, for calculation purposes, is essentially a function of the average bulk density of these sediments. As bulk density increases exponentially with depth, so does porosity decrease. Plotted on a log scale, straight lines will be produced (NCTs). Shale points falling on these lines will be normally pressured. Knowing the overburden gradient (OBG) is essential for accurate formation pressure and fracture gradient calculations. The OBG tends to increase rapidly near surface, then stabilize with depth as compaction and density increases. For offshore wells, the air gap and water depth must be taken into consideration when calculating the overburden for the first interval. Calculation Method As described before, the bulk density will preferably be derived from FDC wireline data. If this is not available, it can be derived from sonic transit times or seismic interval velocities. If offset data is not available prior to drilling a well, the overburden gradient must be derived from our own bulk density measurements while the well is being drilled. Recalculation would be advisable when better data becomes available. Calculation of the overburden gradient is then based on the average bulk density for a given depth interval.

let S = overburden stress ρb = average bulk density (gm/cc) D = depth Metric S = ρb x D where S = kg/cm2 10 D = m SI units S = ρb x D x 9.81 where S = KPa D = m Imperial S = ρb x D x 0.433 where S = psi D = ft Procedure • From the average bulk density, calculate the overburden pressure for a given interval • Calculate the cumulative overburden pressure • Calculate the overburden gradient

Example 1 Interval Thickness Av ρρb 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

Example 2 Interval Thickness Av ρρb 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 NOTE 1 kg/cm2/10m = 1 gm/cc = 1000 kg/m3 emw O/B Gradient EMW = 1.35 x 1000 = 1350 kg/m3

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

Example 3 Interval Thickness Av ρρb 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

Exercise 3b Overburden Gradient Calculations From the table shown in the first example, complete the calculation of the overburden gradient. Interval Thickness Av ρρb 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 400 - 500 100 1.83 500 - 600 100 1.89 600 - 750 150 1.95 750 - 850 100 1.99 850 - 900 50 1.96 900 - 1000 100 2.02

Exercise 3c Overburden Gradient Calculation Using the procedure shown in example 3, complete the table for the following overburden calculation: This example will be used in future exercises. Interval (ft) bulk density

(gm/cc) Interval OB Pressure psi

Cumulative Pressure psi

OB Gradient psi/ft

OB Gradient EMW (ppg)

0 - 50

1.05

50 - 100

1.20

100 - 200

1.29

200 - 300

1.36

300 - 400

1.40

400 - 500

1.46

500 - 600

1.53

600 - 700

1.55

700 - 800

1.59

800 - 900

1.64

900 - 1000

1.69

1000 - 1100

1.67

1100 - 1200

1.75

1200 - 1300

1.78

1300 - 1400

1.77

1400 - 1500

1.80

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0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

DEPTH (ft)

EQUIVALENT MUDWEIGHT (ppg)

OVERBURDEN GRADIENT

Overburden Gradient

3.7c Calculation of Formation Pressure There are several methods of calculation, most of which are based on the comparison of undercompacted shale with normally compacted shale. This requires the accurate determination of Normal Compaction Trends as already described, and assumes the direct relationship between the porosity and the pressure anomaly. Eatons Method is generally accepted as being the most applicable in most regions of the world, and is therefore widely used in the industry. It is also generally accepted to be the most accurate method when interpreting Corrected Drilling Exponent data. Datalog uses this method. Studies have shown that Eatons Method is the most accurate for formation pressures less than 1.4sg (11.66ppg emw) whereas the Equivalent Depth method has been shown to be the more accurate for formation pressures greater than 1.4sg.

3.7c.1 Eatons Method This method can be used to calculate the formation pressure from the following parameters: Seismic interval velocities Corrected drilling exponent Resistivity / Conductivity Sonic transit times The method assumes that the relationship between the observed parameter and normal parameter (ie lying on the NCT) and the formation pressure is dependant upon changes in the overburden gradient. Let FP = Formation Pressure Gradient (psi/ft) FPn = Normal Formation Pressure Gradient (psi/ft) S = Overburden Gradient (psi/ft) Xo = Parameter, observed Xn = Parameter, normal Resistivity FP = S − (S − FPn) (Ro)1.2 (Rn) Corrected drilling exponent FP = S − (S − FPn) (DCo)1.2 (DCn) Sonic transit time FP = S − (S − FPn) (∆Tn)3.0 (∆To) Conductivity FP = S − (S − FPn) (Cn)1.2 (Co)

Taking the Corrected Drilling Exponent equation as an example: For a given depth, DCn is the value of the exponent that would lie on the Normal Compaction Trend, whereas DCo is the actual calculated exponent value. DCo • • DCn NCT Dcexp At 10000ft, let Normal Formation Pressure Gradient = 0.452 psi/ft (8.7ppg emw) let Overburden Gradient = 1.04 psi/ft (20.0ppg emw) let DCo = 1.75 let DCn = 1.85 Actual Formation Pressure Gradient = 1.04 − (1.04 − 0.452)(1.75)1.2 (1.85) = 0.490 psi/ft = 9.42 ppg emw The exponents (in this case 1.2) are reliable for universal use, but if sufficient data was available, they could be refined on a regional basis.

Calculating Isodensity Lines Isodensity lines are a way of graphically representing the drilling exponent (or other parameter) alongside curves of increasing equivalent mudweights (representing increasing formation pressure). Again, the process relies on the accurate determination of the overburden gradient and normal compaction trend (which represents the normal formation pressure isodensity line). The same formulae are used, but Xo, the observed value of the parameter, is made the subject. This represents the value that positions the isodensity line for a given equivalent mudweight at any given depth. Again, taking the drilling exponent as an example: DCo = (1.2√ (S − FP)) x DCn (S − FPn) FP represents the value of the isodensity line being calculated DCo represents the DXc value where the isodensity line will be plotted From the numbers used in the previous example:- At 10000ft, the overburden gradient = 1.04 psi/ft normal formation pressure = 0.452 psi/ft DCn = 1.85 Let us calculate the position, at 10000ft, for the 10.0ppg Isodensity line 10.0ppg emw = 0.52 psi/ft DCo = (1.2√ (1.04 − 0.52)) x 1.85 = 1.67 (1.04 − 0.452) Therefore, the 10.0ppg isodensity line at 10000ft would be plotted at a ‘drilling exponent’ value of 1.67. This calculation should be repeated for an entire depth interval to produce a complete isodensity line.

Plot illustrating Dxc with NCT and Isodensity Lines 0.5 1.0 2.0 DXc NCT 8.8 9.0 1000 9.2 9.4 2000 9.6 3000 4000 Depth Equivalent Density This type of graphical representation is ideal in that it shows the actual DXc along with the Normal Compaction Trend. With the isodensity lines, any deviation from the normal trend can immediately be seen along with the estimation of formation pressure (equivalent mudweight). In the above example, the onset of the overpressured zone is clearly evident at around 2000ft, seen gradually increasing to a depth of around 3700ft, from where it is constant at 9.25 to 9.30 ppg emw.

Exercise 3d Using the overburden gradient calculated in exercise 3c and the following Corrected Drilling Exponent plot, complete the following tasks. Assume that the normal formation pressure is 8.7 ppg emw, giving a pressure gradient of 0.452 psi/ft. 1. Assuming that the complete depth interval comprises an homogeneous shale, position a Normal Compaction Trend line. 2. Using the following values of the drilling exponent that would lie on the NCT line, calculate and position isodensity lines for the equivalent formation pressures of 9.0, 9.5 and 10.0 ppg. Depth ‘Normal’ Drilling Exponent 100 1.04 200 1.09 300 1.15 600 1.32 900 1.51 1200 1.74 1500 2.00 Example 9.0ppg (0.468 psi/ft) isodensity line at 100ft:- DCo = (1.2√ (0.487 − 0.468)) x 1.04 = 0.625 (0.487 − 0.452) 3. Verify the position of these isodensity lines by calculating the formation pressure at 1200 ft.

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0.1 1 10

DEPTH (ft)

DCexp

CORRECTED DRILLING EXPONENT

DCexponent

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0.1 1 10

DEPTH (ft)

DCexp

DCexp with Normal Compaction Trend

DCexponent

NCT

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1300

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0.1 1 10

DEPTH (ft)

DCexp

DCexp with Isodensity Lines

DCexponent

NCT

9.0ppg EMW

9.5ppg EMW

10.0ppg EMW

10.0ppg

9.5ppg

9.0ppg

3.7c.2 Equivalent Depth Method As with Eatons Method, the Equivalent Depth Method can be applied to all the main parameters. The method assumes that every point in an undercompacted shale (I) is associated with a normally compacted point (E) at a shallower depth; ie that the compaction at both points is identical. For a given depth (DI) of the parameter, the method works by extrapolating that value of the parameter back to a depth (DE) where that same value falls on the NCT. Taking a drilling exponent trend as an example:- DXc DE --------------------- • E DI ---------------------• I Depth NCT Let FPI = formation pressure gradient at depth of interest DI Let FPE = formation pressure grad at equivalent depth DE (ie normal pressure) Let SI = overburden gradient at depth of interest DI Let SE = overburden gradient at depth of interest DE

FPI = SI − DE (SE − FPE) gradients in psi/ft DI

Calculating isodensity lines DXc X DE E NCT DI I Depth Z Y Extend the normal compaction trend XY to the depth origin X Choose point E lying on the NCT For the selected isodensity value deqlI, calculate the depth DI using the formula: DI = 0.545 DE 1.0 − deqlI Derivation of constants: Assume overburden gradient = 1.0 psi/ft (19.2ppg emw) normal formation pressure = 0.455 psi/ft (8.75ppg emw) (0.545 = S − FPn) Naturally, if more accurate data, or the actual values are known, they should be used in the formula.

The isodensity lines produced by the Equivalent Depth method will look as follows: 0.4 0.5 1.0 2.0 3.0 DXc NCT Depth 9.6 9.4 9.2 9.0 Equivalent Density

3.8 Calculation of Formation Fracture Gradient Knowing the fracture gradient of formations and weak zones is essential while planning or drilling a well. We have already seen how the formation at the previous casing shoe depth is assumed to be the weakest zone of the following hole section (because it is the shallowest depth of that section) and how we calculate the fracture gradient for that depth. However, we cannot automatically assume that that will be the weakest zone; highly porous, fractured or low pressured formations may well have a lower fracture gradient even though they occur at a deeper depth. Thus, it is important to have accurate fracture gradient calculations in the same way that it is important to have accurate formation pressure calculations. Accurate knowledge of the fracture gradient, in particular the weak zones, enables: • the planning of a drilling program, casing depths and maximum mud weights • calculation of the maximum annular pressure (MAASP) when controlling a kick • estimation of pressures required for stimulating by hydraulic fracturing

3.8a General Theory To calculate the fracture gradient requires the knowledge of the minimum component of in-situ stresses (S3) Deformation and fracture is controlled by the effective stress (σ) which is the difference between the total stress (ie overburden S) and the formation pore pressure (FP) σ = S − FP For the minimum stress, σ3 = S3 − FP The minimum stress S3 is generally assumed to be the horizontal component, so that S3 = K3σ + FP where σ = effective vertical stress due to the overlying sediments K3 = ratio of horizontal to vertical effective stresses The main differences in the several theories of fracture gradient calculation arise from the determination of K3: • evaluating K3 from regional studies of fracture measurements • assuming that K3 depends on Poisson’s Ratio µ for the in situ material. This assumes

that the formation has not undergone lateral deformation and that it has always deformed elastically. This is obviously an unreasonable assumption, so that these methods have to treated with caution.

The relationship between K3 and µ: K3 = µ 1−µ

3.8b Eatons Method Eatons method assumes that rock deformation is plastic, and on the basis that Poissons Ratio and overburden vary with depth, Poissons ratio has to be derived from regional data for the fracture gradient, formation pressure and overburden gradient. FG = ( µ ) σ + FP where FG = fracture gradient (1−µ) FP = formation pressure σ = overburden − formation pressure µ = Poissons Ratio Poissons ratio has to be calculated from offset data, preferably prior to drilling the well, from the following equation:- µ = FG − FP S + FG − 2FP Eatons method is furthered by Anderson et al, who calculate Poissons ratio on the basis of a Shaliness Index: µ = 0.125q + 0.27 where q = shaliness index Hence, for a clean, shale free sand for example, the minimum for Poissons Ratio is 0.27 because q will be equal to zero. The shaliness index q can be determined from gamma logs:- The maximum and minimum gamma value should be determined for each formation or geological time period. q can then be derived for given depth intervals eg 10 or 20m, from:- q = GRlog − GRmin GRmax − GRmin where GRlog = the average gamma value over the selected depth interval.

3.8c Daines Method Daines takes Eatons formula as a basis and introduces a correction by way of a superimposed tectonic stress, so that... FG = σt + ( µ ) σ + FP (1−µ) where σt = superimposed tectonic stress σt is calculated from the first Leak Off Test, and is assumed to be constant for the whole well. The FG at this point will be the fracture gradient derived from the LOT. There is potential error here, depending on the value of Poissons Ratio selected. Unlike Eatons method, where the Poissons ratio is depth dependant and calculated from known fracture gradient, formation pressure and overburden, Daines method assumes that the Poissons Ratio is dependant on lithology. The following values of Poissons ratio were derived experimentally: Clay 0.17 - 0.5 Shale Conglomerate 0.20 calcareous 0.14 Dolomite 0.21 dolomitic 0.28 Limestone siliceous 0.12 micritic 0.28 silty 0.17 sparitic 0.31 sandy 0.12 porous 0.20 Siltstone 0.08 fossiliferous 0.09 argillaceous 0.17 Sandstone coarse 0.05 - 0.10 medium 0.06 fine 0.03 poorly sorted 0.24 fossiliferous 0.01 For the purpose of deriving the superimposed tectonic stress, if the lithology at the depth of Leak Off is not accurately known, a default value of 0.25 should be selected for Poissons Ratio.

3.9 Use of the QLOG software General Procedure:- • Determine or obtain Bulk Density measurements • Calculate the Overburden Gradient at regular intervals • Select trend indicator and determine the Normal Compaction Trend for the given

interval * • Calculate the Formation Pressure * • Calculate or select the appropriate Poissons Ratio and calculate the Fracture Gradient * NOTE The Normal Compaction Trend selected and hence the accuracy of the calculated Formation Pressure will only be as good as the interpretations made by the engineer. Before selecting the NCT, the engineer will have already made an accurate estimation of the formation pressure by considering changes in all parameters such as gas trends, produced gases, temperature trends, shale density etc. The software cannot do this by itself. In otherwords, the software can be used to do the hard work of the actual calculations, but these calculations should only be confirming the conclusions already arrived at by the engineer. a. Overburden Program (overburd) In order for the Formation Pressure and Fracture Gradient to be calculated, we have already seen that the Overburden Gradient must be known or have been calculated. The overburden program calculates the gradient for each log interval and will update it into the database. The program can normally be run directly from a command line with no user input required. However, the first time that the program is run, the command overburd +m (for manual) should be used. This allows you to specify the start and end depths and is, in fact, the version of the program that is run from the QLOG menu. The overburden gradient is calculated from the Bulk Density. There must therefore be bulk density values, for each record in the database, entered into the JW reference column. This data may be imported from offset wireline data or measured by the mudlogger at wellsite.

If bulk density values are not available for each individual record in the database, you must fill, or copy to, the blank records. Every record must have a bulk density value in order for the overburden calculation to work. Running the program for the first time:- • Ensure that the bulk density value in the equipment table is set to zero and that the

Bulk Density column in the database has values for every record over the required interval.

NOTE that an accuracy problem will exist if the database does not start from surface, ie if we are requested at wellsite at an intermediate stage of the well. For example, if the database is started at 2000m and the first bulk density measurement is 1.95 gm/cc, then that density will be assumed for the whole of the first 2000m given an initial overburden gradient of 1950 kg/m3 emw. This is obviously inaccurate, erring on the high side, since it does not allow for the density increasing from a low value at surface to 1.95 at 2000m. If any data is available from wireline, then we should attempt to calculate the initial overburden gradient as accurately as possible. This value should then be entered, as an equivalent density, into the bulk density column for the first record. For example, if the overburden for 2000m was calculated at 1700 kg/m3, then a value of 1.70 gm/cc should be entered into the first bulk density record. • Enter the command overburd +m, or enter the program from the QLOG menu. • Enter your start depth as the start of the database. Your end depth should be the depth

of the last bulk density value entered into the database. • Choose to update the equipment file and database after the calculation. When the

calculation is done, the equipment table will be automatically updated with the Bulk Density (equivalent for the present calculated overburden), which will then be used for subsequent realtime calculations.

• Calculating to the end of the database will calculate past the end depth entered.

• Press F5 to read in the bulk density values from the database. • Press F7 to calculate the overburden gradient. If you do not select to update the

database, the program will just display the calculated end result for the present end depth.

After the first proper calculation (detailed above) run has been completed, the program should be run at regular intervals while drilling. This should be done from a command line with overburd. The calculation will be automatic - no manual input of depths is required, the program automatically continues from the depth of the last calculation. Even better, the logger can set the system so that the program runs automatically at a pre-determined time interval, by using the cron timing facility (see Advanced QLOG). If you wanted to recalculate for the whole database, then run the program as in the first 2 steps above, using the overburd +m option.

b. Overpressure Program (overpress) This program enables you to calculate the Formation Pressure and Fracture Gradient. Before using this program, the user should be fully familiar with the theory and techniques of Abnormal Pressure analysis. The program requires certain information to be in place before running. To calculate Formation Pressure:- • the Overburden Gradient needs to have been calculated for the given depth interval • the Normal Formation Pressure for the region needs to be entered into the equipment

table. The user can then determine a Normal Compaction Trend based upon a given parameter, normally the Corrected Drilling Exponent. The Fracture Gradient calculation is based upon the calculated Overburden Gradient and the calculated Formation Pressure, together with the appropriate Poisson’s Ratio. These calculations are performed offline for a depth interval already drilled. When the calculations are completed, the Poisson’s Ratio together with Pressure Slope and Offset (relating to the Normal Compaction Trend) are written automatically to the equipment table allowing for realtime calculation of the formation pressure and fracture gradient. The parameter most commonly used to determine a Normal Compaction Trend is the Corrected Drilling Exponent using Jordan and Shirley’s formula. The limitations of this parameter, however, have to be recognized. A trend can, normally, only be accurately determined for homogenous shale or claystone. Varying hydraulics, formation, bit type, size and wear, will all cause changes to the DCexp trend. Always consider the DCexp along with changes in cuttings character, mud temperature and resistivity, connection gas, background gas, torque and drag of drillstring etc. As previously stated, the engineer should have already evaluated all of these parameters and determined where the formation pressure is normal, where it becomes abnormal and what the probable new formation pressure is, before using the software. Based on this evaluation, the selection of the NCT is totally dependent on the engineer. This will determine the pressure calculations made by the software, so that the software should be used in such a way as to give the calculations that the engineer considers correct.

To use the program: Firstly, select the correct NCT using the overlay plot:- • Select the parameter you wish to use for the trend line from the first menu -

normally DCexp. • For the Start and End depths of the interval that you intend to update calculations

for, enter the value of the Normal Compaction Trend (this value is determined from the scale of the source, ie DCexp). Use ‘ball park’ figures initially - you will probably have to run this several times before you have the NCT in exactly the position that you want. The end depth will be the depth to which the data is calculated and updated, so extrapolate your trend if you are in a transition zone and it will give you the calculated pressures within that zone.

• Enter Start and End depths of the plot (in most cases, these will be the same as the

NCT start and end depths), and horizontal plot scales (this is the Equivalent Mudweight, and would normally be left as the default 800 to 2500 kg/m3 EMW).

• Select the calculation method, Eaton or Zamora (otherwise known as the Ratio

method). Eatons is the preferred method. • BEFORE calculating and updating the database, select F8 to produce an Overlay

Plot - this will be a plot of the DCexp together with your selected Normal Compaction Trend and is called overlay.plot, accessed from Reports-XYZ plots. You may have to re-select your Trend start and end values before you are completely happy with its positioning.

Once you are happy with the positioning of the Normal Compaction Trend, you are ready to perform the pressure and fracture gradient calculations: • Enter the Poisson’s Ratio. This is only used in the calculation of the Fracture

Gradient. Properly, this should be a depth based value determined from offset data using overburden, formation pressure and fracture gradient (see section 3.8, Eatons Method). If this data is not available to you, you should use the lithologically determined ratios shown in the help file and this manual (section 3.8, Daines Method).

• Select Average Size. For example, if your database was every metre, and you selected

an average of 10, the calculated data for each record in the database would be averaged over the previous 10 records.

• Select Interval Size. This does not affect the calculated data in the database, but

determines the frequency of data points output to the plot. If 10 was selected for example, only every 10th record would be output to the plot. This means that the XYZ plot created (these have a limited memory capability) is capable of taking a greater depth interval.

• Select whether to Update Database and Equipment Table. Obviously, this would

write all of the calculated formation pressures and fracture gradients to the database and would also write the following parameters to the equipment table to allow for realtime calculations:-

Poisson’s Ratio Pressure Slope and Offset (based on the normal compaction trend) • Calculate to end of database - this would calculate beyond the End Depth already

selected. • Press F7 to calculate. This will update your database and equipment table and also

produce a pressure profile plot; formation pressure and fracture gradient against depth, called press.plot

NOTE that the parameters written to the equipment table allow for realtime calculations of formation pressure and fracture gradient based on your Normal Compaction Trend. Should there be a lateral shift in this trend, caused by such things as change in lithology, bit change, change in hydraulics, then it is quite legitimate for you to change the pressure offset in order to get accurate realtime calculations. This facility should only be used for these types of shift changes and not for changes in your drilling exponent caused by a formation pressure change (ie do not change the pressure slope). You should only change the pressure offset, which effectively shifts your Normal Compaction Trend, if you are fully confident of what your formation pressure is (this only comes with experience and by taking into consideration all pressure indicators), - you can therefore alter the pressure offset so that you get the realtime calculations that you want. Should you have an interbedded lithology sequence, for example sand and shale, then your Normal Compaction Trend is effectively shifting for each lithology change. It would therefore be virtually impossible to keep your realtime calculations accurate. In this situation, so that you have accurate information on display for engineers and geologists, it may be advisable to use the override facilities in the equipment table.

Normal Compaction Trends For calculation purposes, intervals have to be calculated using a single NCT. However, if you were producing overlay plots for a final well report, then multiple trends can be selected. This may be due to a number of causes:- Shift changes due to bit changes change in hole size change in hydraulics or drilling parameters unconformities (this may also produce a different NCT gradient) Multiple trends can be selected by editing the plot data file /datalog/plots/data/trend.dat which would normally contain the start and end depths plus NCT values that you selected in the overpress program. For additional trend sections, simply add depths and NCT values required:- 50 1.26 350 1.42 #NCT 1, 50 to 350m 350 1.56 700 1.68 #NCT 2, 350 to 700m 700 1.44 1100 1.60 #NCT 3, 700 to 1100m Again, this facility can be very useful for providing detailed plots for final well reports but cannot be used for calculation purposes.

Appendix Answers to Exercises Exercise 3a 1. a. 0.494 psi/ft b. 2.150 psi/m c. 2.557 psi/m d. 10.35 KPa/m e. 12.26 KPa/m 2. a. 5148 psi b. 4120 psi c. 3139 psi d. 45126 KPa 3. a. 15.38 ppg b. 10.99 ppg c. 9.53 ppg d. 12.7 ppg e. 1359 kg/m3 f. 1019 kg/m3 Exercise 3b Depth Interval Interval Pressure

KPa Cumulative Pressure KPa

O/B Grad KPa/m

Equivalent MW kg/m3

400 - 500 1795 7951 15.90 1621 500 - 600 1854 9805 16.34 1666 600 - 750 2869 12674 16.90 1723 750 - 850 1952 14626 17.21 1754 850 - 900 961 15587 17.32 1766 900 - 1000 1982 17569 17.57 1791

Exercise 3c Depth Interval Interval Pressure

(psi) Cumulative Pressure (psi)

O/B Grad (psi/ft)

Equivalent MW (ppg)

0 - 50 22.73 22.73 0.455 8.74 50 - 100 25.98 48.71 0.487 9.36 100 - 200 55.86 104.57 0.523 10.05 200 - 300 58.89 163.46 0.545 10.48 300 - 400 60.62 224.08 0.560 10.77 400 - 500 63.22 287.30 0.575 11.05 500 - 600 66.25 353.55 0.589 11.33 600 - 700 67.11 420.66 0.601 11.56 700 - 800 68.85 489.51 0.612 11.77 800 - 900 71.01 560.52 0.623 11.98 900 - 1000 73.18 633.70 0.634 12.19 1000 - 1100 72.31 706.01 0.642 12.34 1100 - 1200 75.77 781.78 0.651 12.53 1200 - 1300 77.07 858.85 0.661 12.70 1300 - 1400 76.64 935.49 0.668 12.85 1400 - 1500 77.94 1013.43 0.676 12.99

Exercise 3d Isodensity Lines Depth 9.0ppg emw 9.5ppg emw 10.0ppg emw 100 0.625 200 0.517 0.08 300 0.983 0.697 0.385 600 1.190 0.973 0.745 900 1.391 1.194 0.990 1200 1.623 1.428 1.228 1500 1.880 1.682 1.479 Formation Pressure at 1200 ft = 10.0 ppg emw