4wellsite ops

Datalog Wellsite Procedures Manual 1999


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Section 2 – Routine operations in drilling a well

MUD TYPES AND RHEOLOGY 39 Purposes of the Drilling Fluid 39 Cool and lubricate the bit and drill string 39 Bottomhole cleaning 39 Control subsurface pressures 39 Wall the hole with an impermeable filter cake 40 Help support the weight of the drill string 40 Cuttings removal and release 40 Transmit hydraulic horsepower to the bit 40 Hole stability 40 Formation protection and evaluation 41

Common Drilling Fluids 41 Air/Gas 41 Foam or Aerated Fluids 42 Water-Base Muds 42 Oil-Emulsion Muds 43 Oil-Base Muds 43

Basic Mud Rheology 43 Mud Density 43 Mud Viscosity 44 Gel Strength 44 High vs. Low Viscosity and Gel Strength 45 Filtrate/Fluid Loss 45 Filter Cake 45 Mud pH Level 45 Mud Salinity 45

Rheology Measurements 46 Shear Stress and Shear Rate 46 Fluid Viscosity 47 Newtonian and Non-Newtonian Fluids 47 Bingham Plastic Flow Model 48 Power Law Model 48 Modified Power Law Model 50

Basic Hydraulics 51 Annular Velocity 51 Pressure Losses 52 Hydraulic Horsepower 53 Optimization 53 Laminar and Turbulent Flow 53

PRESSURE GRADIENTS 55 Measured Depth versus True Vertical Depth 55 Equivalent Mud Weight (EMW) 55 Hydrostatic Pressure 56

Formation Related Pressures 56



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Overburden Gradient 56 Formation Pressure 58 Fracture Pressure 59 Equivalent Circulating Density 60

Well Balance 61 Formation Pressure versus Hydrostatic Pressure 61

Underbalance versus Overbalance 61

DRILLING A WELL 62 Starting Point 62 Surface Hole 62 Intermediate Hole 63 Total Depth 64

Drilling and “making hole” 64

Reaming 65

Circulating 66

Coring 66 Purpose of Coring 66 Coring Methods 66 Core Barrel Assembly 67 Cutting the Core 68 Retrieval and Handling Operations 68

TRIPPING 68 Trip Speed 69 Pulling Out of Hole 69 Swabbing 70 Running In Hole 71 Displacements 72 Hook Load 72 Strapping and Rabbiting the Pipe 73

WIRELINE LOGGING 74

CASING AND CEMENTING 75 Purpose of Casing 75 Types of Casing 75

• Conductor Pipe 75 • Surface Casing 75 • Intermediate Casing 75 • Liner String 75 • Production Casing 76

Surface Equipment/Mixing System 76 Subsurface Equipment 76 Preparing to Run Casing 77 Running the casing 77 Cementing Operation 78 Other Applications 79 Pressure Test 80



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TESTING 81 Leak-Off and Formation Integrity Tests 81 Repeat Formation Testing 82 Drill Stem Testing 83 Drill Stem Test Tools 83 Performing a Drill Stem Test 84



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MUD TYPES AND RHEOLOGY

Purposes of the Drilling Fluid

Drilling fluids have the obvious functions of removing drilled rock chips, or cuttings out of the wellbore, and of cooling and lubricating the bit and drill string. In fact, the mud system has many other functions and is central to virtually all of the operations throughout the drilling of a well. It is very important that the drilling fluid is able to perform all of these functions efficiently.

Cool and lubricate the bit and drill string

The drilling action and rotation of the drill string generates considerable heat at the bit and throughout the drill string due to friction. This heat is absorbed by the drilling fluid and released, to a degree, at the surface. Drilling fluid further reduces the heat by lubricating the bit and drill string to reduce the friction. Basic mud types provide moderate lubrication, but oil emulsion mud systems, coupled with various emulsifying agents, increase lubrication significantly, while, at the same time, reducing torque, increasing bit and bearing life, and reducing pump pressure through reduced friction.

Bottomhole cleaning

Drilling fluid flows through the bit nozzles to jettison cuttings out from under the bit and carry them up through the annulus to surface. This serves to keep cuttings clear of the bottomhole and prevent bit balling (i.e., cuttings building up and clogging the bit), thereby prolonging bit life and increasing drilling efficiency. The effectiveness of the drilling fluid in this process depends on factors such as velocity and impact of the mud as it leaves the nozzles, mud density and viscosity.

Control subsurface pressures

Minimal mud weight is optimum for fast drilling rates and to minimize the risk of damaging formations and losing circulation. However, in conventional drilling, the mud must also be of sufficient density to protect the well against subsurface formation pressures and to maintain stability of the wellbore. The pressure exerted at the bottom of the hole, due to the overlying weight of the static vertical column of drilling fluid, is known as the mud hydrostatic pressure. If the mud hydrostatic pressure is equal to the formation fluid pressure, the well is said to be at balance. If the pressures are not equal, then fluids (either formation fluid or drilling fluid) will flow in the direction of lower pressure. If the hydrostatic pressure is less than the formation pressure, the well is underbalanced and therefore subject to influxes of formation fluid that could lead to well kicks and, ultimately, blowouts. If the hydrostatic pressure is greater than the formation pressure, the well is overbalanced and protected against influxes of formation fluid into the wellbore. Too great an overbalance, however, while controlling formation fluid pressure, can lead to the flushing of drilling mud into the formation, or even to the fracture of weaker formations, resulting in lost circulation.



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Wall the hole with an impermeable filter cake

As a hole is being drilled, filtrate (i.e., the liquid portion of drilling fluid) invades permeable formations. As it does so, solid particles within the mud will be left on the borehole wall. These particles will build up to line the borehole with a thin, impermeable layer of filter cake that will consolidate the formation and minimize further fluid loss. The mud's filter-caking ability can be improved by adding bentonite (thereby increasing the reactive mud solids) and chemical thinners (thereby improving solids distribution). Starch or other fluid-loss control additives may also be required to reduce fluid loss. Note that excessive water-loss can result in an excessively thick filter cake, thereby reducing the diameter of thhole and increasing the possibility of stuck pipe or swabbing the hole when removing the pipe. It can also lead to deep invasion of the formation by the drilling mud, resulting in the loss of initial gas shows and making it difficult to interpret electric logs.

Help support the weight of the drill string

The derrick and blocks must support the increasing weight of the drill string as drilling proceeds deeper. Through displacement, the drill string is buoyed up by the drilling fluid, thereby reducing the total weight that the surface equipment must support. Therefore, increasing mud density and viscosity can considerably reduce surface load at deeper depths.

Cuttings removal and release

Cuttings need to be removed from the well to prevent loading the annulus and to allow for free movement and rotation of the drillstring. They also need to reach the surface and be released in such a condition as to allow for geological interpretation of the downhole lithology. Cuttings slip (i.e., cuttings falling) occurs because the density of the cuttings is greater than the density of the drilling fluid. Therefore, to ensure that cuttings are lifted through the annulus during circulation and yet remain suspended when circulation is stopped, drilling fluids must be thixotropic (i.e., possess gelling properties). When circulating, thixotropic drilling fluids are liquid, allowing them to carry cuttings to the surface. When not circulating, thixotropic drilling fluids will gel, or thicken, to suspend cuttings and prevent them from slipping and settling around the bit. Gel strength must be low enough to release the cuttings and entrained gas at the surface, to minimize swabbing when the pipe is pulled, and to resume circulation without causing high pump pressure.

Transmit hydraulic horsepower to the bit

The drilling fluid transmits the hydraulic horsepower delivered by the pumps at the surface to the drill bit. The circulation rate of the drilling fluid should be such that optimum power is used to clean the face of the hole ahead of the drill bit. Hydraulics are considerably influenced by the flow properties of the drilling fluid, such as density, viscosity, flow rate and fluid velocity. The amount of hydraulic horsepower expended at the bit determines the degree to which hydraulics are optimized, whether for bottomhole cleaning or laminar flow optimization.

Hole stability

Drilling fluids serve to prevent erosion and collapse of the wellbore. When drilling porous and permeable formations, the hydrostatic pressure of the drilling fluid column helps prevent unconsolidated formations (e.g., sand) from falling into the hole. For swelling and sloughing shales, oil-base mud is preferred since, unlike water, oil



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will not be absorbed by the clays. Water-base mud can be used if treated with Ca/K/Asphalt compounds. To prevent the dissolving of salt sections, salt-saturated or oil-base mud can be used to prevent taking the salt into solution.

Formation protection and evaluation

Achieving optimum values of all drilling fluid properties is necessary to offer maximum protection of the formation. Yet sometimes these values must be sacrificed, to a degree, in order to gain maximum knowledge of the formations penetrated. Oil-based drilling fluids can be effective in keeping water out of a producing formation. However, in gas zones, it may be more damaging than a salt-water fluid. To some degree, salt-water and high-calcium fluids have been effectively used to minimize formation damage. The type of flow pattern present in the annulus can facilitate or minimize cuttings damage and erosion. Smooth laminar flow is preferred to chaotic turbulent flow. This not only protects the cuttings, but also minimizes erosion of the well-bore wall as well as reducing circulating pressures. As well, the penetration rate may have to be sacrificed to gain valuable reservoir information. This is known as controlled drilling, where parameters are controlled in order to determine those changes that are due to formation changes.

COMMON DRILLING FLUIDS

Drilling Fluids are circulating mediums used to carry drilled cuttings out from under the drill bit, into the outer annulus and up to the surface. The various fluids that may be used in rotary drilling are: air - gas foam/aerated fluids water-base muds oil emulsion muds oil-base muds A typical circulating system of a rotary drilling rig is described and illustrated in Section 3.

Air/Gas

Using compressed air, natural gas, inert gas or mixtures with water has an economic advantage in hard rock areas where there is little chance of encountering large quantities of water.

Advantages • fastest penetration rate of any drilling fluid • more footage per bit • more near gauge and less-deviated holes • continuous formation tests (high-pressure formations excluded) • cleaner cores • better cement jobs • better completion jobs • no danger of lost circulation • no reaction with shale

Disadvantages • no structural properties to transport cuttings (solely dependent on annular

velocity) • combustible with other gases (possibility of downhole explosions and fire) • pipe corrosion



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• finely crushed cuttings and uneven release (making analysis difficult) • no pressure control (permitting caving or requiring additional equipment) • no filter cake • influx of formation water (creating mud rings and causing stuck pipe) • no buoyancy to help support the drill string (increasing hook weight) • no cooling or lubrication

Foam or Aerated Fluids

Foam fluids are made by injecting water and foaming agents into an air or gas stream to create a viscous and stable foam. They can also be made by injecting a gel-base mud containing a foaming agent. The cuttings transport capacity of viscous foams is dependent more on viscosity than on annular velocity. Aerated fluids are made by injecting air or gas into a gel-base mud. They are used to reduce hydrostatic pressure (thereby preventing the loss of circulation in low-pressure formations) and to increase the rate of penetration.

Water-Base Muds

Water-base muds consist of a continuous phase of water in which clay and other solids (reactive and inert solids) are suspended. Fresh water is used most often. It is commonly available, inexpensive, easy to control even when loaded with solids, and provides the best liquid for formation evaluation. Salt water is commonly used in offshore drilling operations due to its accessibility. Saturated salt water is used in drilling salt sections in order to stabilize the formation and reduce hole washout. Reactive solids are commercial clays and incorporated hydratable clays and shales from drilled formations, which are held in suspension in the water phase. These solids can be enriched by adding clays, improved through chemical treatment, and damaged by contamination. Inert solids are chemically inactive solids, which are held in suspension in the water phase. These solids include inert drilled solids (such as limestone, dolomite and sand), and mud-density control solids such as barite and galena. Some water-base muds can be classified as inhibited muds. Chemicals are added to the drilling fluid to prevent sensitive shale from swelling in reaction to the filtrate, which in turn impairs the permeability of a productive zone with excessive clay deposits. It is also used for sloughing, gumbo, tight hole and stuck pipe conditions. Salt is a mud inhibitor that can be used effectively in reducing shale reactivity. These muds are particularly effective in preventing drilling problems due to heaving (swelling) shales. Native mud is a combination of drilled solids suspended in water. As drilling continues, the mud is chemically treated to achieve special properties.

Advantages • increased drillability when using fresh water (drillability increases with increasing water loss and with decreasing density and viscosity)

• less expensive than oil-base muds Disadvantages • potential formation damage

• subject to contamination • adversely affected by high temperatures



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Oil-Emulsion Muds

Oil-emulsion muds are water-base muds that contain emulsified oil dispersed, or suspended, in a continuous phase of water. Oil-emulsion muds are less expensive than oil-base muds, while still providing many of the benefits of oil-base muds.

Oil-Base Muds

Oil-base muds consist of a continuous phase of oil in which clay and other solids are suspended. With invert-emulsion muds, water is suspended in a continuous phase of oil. Oil-base muds are used in special drilling operations, such as drilling in extremely high temperatures, drilling in water-sensitive formations where water-base muds cannot be used, and in penetrating productive zones that may be damaged by water-base muds.

Advantages • minimizes formation damage • prevents clay hydration • provides better lubrication (reducing torque, drag and pipe sticking) • minimizes drill string corrosion • high temperature stability

Disadvantages • susceptible to water contamination, aeration and foaming

• flammable • significantly more expensive than water-base muds • dirty and hazardous • environmentally unfriendly (due to spillage and disposal)

In recent years, mineral oils have gradually been replacing traditional petroleum as the base for mud systems. While providing much the same properties and drilling advantages, they are friendly to the environment and to the rig personnel who have to handle the mud.

BASIC MUD RHEOLOGY

Mud Density

Mud density is the single-most important factor in controlling formation pressure throughout the wellbore. For a balanced well, the formation pressure must not exceed the hydrostatic pressure exerted by the mud column. SI Units

Hydrostatic Pressure (KPa) = Hole Depth (m) x Mud Density (kg/m ) x 0.009813 Imperial Units Hydrostatic Pressure (psi) = Hole Depth (ft) x Mud Density (lb / gal) x 0.052



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Barite is the standard solid used to increase mud density. For optimum thinning or reduction in density, weighted muds are usually chemically treated. When chemicals no longer work, water can be added to reduce mud density and restore lost water. Centrifuges can also be used to remove excessive solid particles from the mud. Mud density is measured with a mud balance, shown right, where the weight of an exact volume of mud, minus any air bubbles or drilled solids, is determined.

Mud Viscosity Mud viscosity measures the drilling mud's resistance to flow (i.e., the internal resistance due to the attraction of the liquid molecules); the greater the resistance, the higher the viscosity. Viscosity therefore describes the thickness of mud in motion, and must be high enough for the mud to keep the bottomhole clean and carry cuttings to the surface. It is important to note, however, that lower viscosity levels allow for higher rates of penetration. As well, lower-viscosity drilling muds result in lower equivalent circulating densities (i.e., the measured increase in bottomhole pressure due to frictional pressure losses that occur when mud is circulated). A simple measure of viscosity, the funnel viscosity, is made by the derrickman using a Marsh Funnel. The measurement is simply the number of seconds required for the fluid (1 quart) to flow through a calibrated orifice. Rotational viscometers, shown below, are used to provide a more accurate rheological measurement, by measuring the shear stresses resulting from various applied shear rates.

Gel Strength Gel strength measures the attractive forces of suspended particles when the fluid is static. It therefore determines the ability of the drilling fluid to develop a gel structure, or thicken, as soon as it stops moving. Its purpose is to hold cuttings and mud solids in suspension when circulation is stopped so that they do not sink and settle around the bit or bottomhole assembly, or lead to uneven distribution and patchy mud which would result in poor hydraulics and erratic pressure. The gel strength must be low enough to release the cuttings and entrained gas at the surface, minimize swabbing when the pipe is pulled (thereby preventing an under-balanced condition), and resume circulation without high pump pressure (which can fracture a weak formation). Gel strength can be reduced by reducing solids content or by adding an appropriate deflocculant.



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High vs. Low Viscosity and Gel Strength

High viscosity and gel strength leads to: • higher pressure in order to break circulation • higher swab and surge pressures • higher annular pressure losses • better retention of gas and cuttings. Low viscosity and gel strength leads to: • poor removal of cuttings and hole cleaning • poor suspension of cuttings and solids when

circulation is halted.

Filtrate/Fluid Loss Fluid loss is measured to determine the volume of filtrate (i.e., the liquid portion of the drilling mud that enters permeable formations next to the borehole). Excessive fluid loss can dehydrate the drilling mud, in which case it must be treated to restore it to its proper balance. Depending upon the chemical composition of the filtrate and the formations, high-fluid loss can cause hole problems (pipe sticking or washouts) and damage the productive formation by blocking pores and pore-throats. Chemical thinners or other additives, such as bentonite, can reduce fluid loss.

Filter Cake The filter cake is a layer of drilling mud solids deposited on the borehole walls as filtrate enters permeable formations in an overbalanced well. By lining the permeable sections of the borehole, the filter cake helps to consolidate the formation, prevent further fluid invasion and minimize fluid loss. In extremely permeable formations, the mud solids may not be large enough to line the borehole wall. In these exceptional cases, the mud solids may enter the formation and block the pore throats, consequently damaging the permeability of the formation. A thin, hard filter cake is preferable to a thick, soft filter cake. An excessively large filter cake reduces the diameter of the hole and increases the possibility of stuck pipe or swabbing the hole when removing the pipe. In general, the higher the fluid loss, the thicker the resulting filter cake.

Mud pH Level The pH level of drilling mud should be monitored in order to maintain sufficient alkalinity and reduce pipe corrosion. Caustic soda is often added to increase and/or maintain the pH level. A further benefit of monitoring the mud pH is the detection of hydrogen sulphide gas or, at least, its former presence. Scavengers, such as copper carbonate, zinc compounds and iron derivatives, are added to drilling mud for the purpose of combining or reacting with H2S should it enter the borehole. This results in the formation of sulphide compounds and the release of hydrogen ions. The hydrogen ions increase the acidity of the mud resulting in a drop in the pH level. Thus, by monitoring the pH of the mud, it can be seen that H2S had entered the borehole but that the scavengers have been successful in removing it before the mud reached surface.

Mud Salinity A significant change in mud salinity, when no salt additives have been used to treat the mud, signals penetration of a salt formation. The saline content of the drilling mud can then be increased to stabilize the salt formation and reduce hole washout as a result of the salt formation going into solution (i.e., dissolving in the drilling mud). Salt-water muds must be saturated, preferably, with the same type of formation salt. Minor fluctuations can indicate influxes of formation fluid and are therefore a valid indicator of changes in formation pressure.



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RHEOLOGY MEASUREMENTS

The mud rheology determines the deformation and flow behaviour of the drilling mud. Knowledge of the rheology is important in the success of the drilling program, so that hole cleaning and drilling efficiency is optimum and effectively uses the horsepower delivered by the pumps. Fluids are classified as Newtonian or non-Newtonian, depending upon the fluid's behaviour when it is subjected to an applied force.

Shear Stress and Shear Rate

Consider a fluid flowing through a pipe of cross-sectional area (A) due to a force (F):

The fluid will have maximum velocity in the center of the pipe and zero velocity at the wall. The resulting velocity gradient defines the shear rate, which, inversely to the velocity, is maximum at the pipe wall and minimum at the center. For a given "section" of the channel over a distance (h), the fluid will have maximum and minimum velocities of v2 and v1.

Velocity Gradient = Shear Rate γ = v2 – v1 = m/sec = sec-1 h m The flow of the fluid is opposed by the shear stress which is defined as the force per unit area of the pipe wall.

Shear Stress τ = F/A In this case, the force causing movement is due to the differential pressure across the pipe area. Shear stress is typically measured in lbs./100ft2. For a Newtonian fluid, the relationship between the shear stress and shear rate is a direct one, as illustrated below.

At the well site, these measurements are made with a rotational viscometer, typically a Fann Viscometer, where various shear rates can be applied to the fluid. The outer sleeve is rotated at a constant RPM or angular velocity, causing fluid movement relative to a stationary bob in the center of the instrument. The resulting torque on the bob causes an angular deflection on the viscometer dial. For a given rotational speed (shear rate), the angle of deflection is proportional to the shear stress.

v 2

v 1

F

0 v

max v

ττ

h

A

Shear Rate γ

Shear Stress

τ



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Typically, the shear stress is recorded at rotational speeds of: 600 rpm (shear rate = 1022 sec-1) 300 rpm (shear rate = 511 sec-1) 200, 100, 6 and 3 rpm, to produce an overall fluid behaviour profile.

Fluid Viscosity

Fluid viscosity is the fluid's shear stress divided by the corresponding shear rate.

Fluid Viscosity

Shear StressShear Rate

µ =

= =dynes

cmsec

poise2

-1 oise (cP)= 100 centip

1 lb.ft.sec

ft centipose (cP)2 = 47886

Newtonian and Non-Newtonian Fluids

A Newtonian fluid is a fluid in which the viscosity remains constant for all rates of shear if temperature and pressure remain constant (i.e., linear relationship between shear stress and shear rate). Most drilling fluids behave as non-Newtonian fluids, as their viscosity is not constant and varies with the rate of shear (i.e., different shear rates result in a different fluid viscosity). The diagram on the left shows a Newtonian fluid, while the diagram on the right shows a Non-Newtonian, or typical, drilling mud.

ShearStress

Newtonian Fluid

Shear Rate

ShearStress

Non-Newtonian Fluid

Shear Rate

Bob

Fluid

Outer Sleeve

Rotation



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Bingham Plastic Flow Model

The Bingham Plastic Flow Model predicts a linear relationship between shear stress and shear rate (i.e., Newtonian behaviour), but only after an initial yield stress, or yield point, has been overcome (non-Newtonian).

The linear relationship is described by the plastic viscosity, the difference between the 600 and 300 rpm shear stresses (i.e., the slope of the line).

YP 600 300= −θ θ

Plastic viscosity is a measurement of the mechanical friction between the mud solids and the liquid. It provides an indication of the concentration and/or size of mud solids. The higher the solids

content, the greater the plastic viscosity. With the concentration of mud solids remaining constant, plastic viscosity increases as the size of the particles decrease due to the greater surface area of the mud solids. Yield point is a measure of the ionic (attractive) forces between the mud solids under flowing conditions and is a measure of the hole cleaning capabilities of the mud. The yield point can increase by increasing the solids content, by reducing solid particle size or by higher mud temperatures. It can be reduced by reducing the solids content or by adding a deflocculant.

YP 300 - PV=θ For a Bingham fluid: Shear Stressτ γ= +YP PV

While the yield point is a measure of the attractive forces while the fluid is flowing, attractive forces while the mud is static is measured by the gel strength. This is typically measured at two time intervals (10 seconds and 10 minutes) after the viscometer has stopped rotating. This initial and 10-minute gel strength is measured in lbs./100 ft2 (i.e., shear stress). The Bingham Plastic Model quite accurately represents the behaviour exhibited by such fluids as bentonite slurries, class G cements and low gravity oils. A typical Bingham fluid will have high viscosity but no gel strength. For more complex fluids, however, the Bingham model is subject to error. Whereas the Bingham model simulates fluid behaviour in the high shear-rate range (300 to 600 rpm), it is generally inaccurate in the low shear-rate range. Shear stress measured at high shear rates is usually a poor indicator of fluid behaviour at low shear rates, the area of interest for simulating annular flow behavior. Subject to this error, the calculated yield point will tend to result in calculated pressure losses and equivalent circulating densities that are larger than those actually observed.

Power Law Model

The Power Law Model assumes that fluid movement will be initiated immediately upon applying a force. The model then predicts that fluids will exhibit a non-linear relationship between shear stress and shear rate and introduces two index values (n and K) to determine the relationship. The Power Law Model more accurately represents drilling mud behavior than the Bingham Model, particularly in polymer-based fluids.

θ 300

YP

θ 600

RPM

Dial Reading

PV

600 300



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For Power Law fluids, shear stress is calculated as follows:

( )Shear Stress Kτ γ=n

where: K = consistency index

n = flow behaviour index

n = 3 32600

300

. logθθ

K (lb / 100 ft 2 ) n= 1067511

300

.θ

K (dynes / cm2 ) n= 511

511

300

.θ

The drawback of the Power Law Model is that it predicts a shear stress will result from the smallest shear rate whereas, in reality, fluids possess a yield stress. Similar to the Bingham Plastic Model, but to a lesser extent, the Power Law Model accurately predicts fluid behaviour at high shear rates but shows a degree of error at lower shear rates. As a result, annular pressure losses and equivalent circulating densities are under-predicted. In many cases, however, the Power Law Model does closely approximate fluid properties even when calculated from the high shear-rate values. Different values of n are possible, depending on which shear stress/shear rate pairings are used in the calculation. Thus, this model can be applied by using data from a range of annular shear rates, thereby providing more accuracy in predicting drilling fluid performance.

With θθ 200 and θθ 100 With θθ 6 and θθ 3

n = 3 32600

300

. logθθ n = 3 32

6

3

. logθθ

K = n

θ 100

170 3. K = n

θ 3

511.

In the extreme case that n = 1, the fluid behaviour is that of a Newtonian fluid. A low shear rate pairing (i.e., 6 and 3 rpm) can be used to more accurately describe the suspension and hole cleaning potential of a fluid in large-diameter holes and in horizontal drilling operations.

θ 300

θ 600

γ (rpm)

Dial Reading

600 300

K

100

10

gradient = n

log γ

log τ

1000 100 10 1

Plot the log of stress and strain



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In large diameter bore holes, the ratio of low to high shear across the profile is greater.

In horizontal boreholes, the drill string rests on the bottom side of the hole, effectively creating a larger annulus on the top side and a greater component of low shear flow.

Annulus

Pipe

Modified Power Law Model

This model combines the theoretical and practical aspects of the Bingham Plastic and Power Law models. In this model, the "n" and "K" values are similar to those derived by the Power Law model. The model assumes that fluids will require a certain amount of applied stress before movement will take place and, for these fluids having a yield stress, the calculated values of ‘n and K’ will be different.

High Shear

Low Shear Low Shear

Pipe

High Shear

Small Diameter Borehole

Low Shear

Pipe

Low Shear

High Shear

Large Diameter

High Shear

High Shear



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τ0

Shear Rate

(yield point or yield stress)

ShearStress

For Modified Power Law Fluids:

( )Shear Stress K0τ τ γ= + n

where: K = consistency index

n = flow behaviour index

The value τ0 is the fluid’s yield point at zero shear rate and, in theory, is identical to the Bingham Plastic yield point, though it’s calculated value is different. When n = 1, the model becomes the Bingham Plastic Model

τ0 = 0, the model becomes the Power Law model The model works well for both water based and oil based drilling muds because both exhibit shear thinning behaviour and have a shear stress at zero shear rate.

The problem with the model is that the determination of n, K and τ0 is very complex.

BASIC HYDRAULICS

Annular Velocity

Annular velocity is the average rate at which drilling mud travels in the annulus (since velocity changes across the profile, with higher velocity occurring in the center).

Max. Velocity

Min.Velocity

Max. Velocity

Min.Velocity



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The annular velocity must be sufficient to remove and lift cuttings, and should be low enough to give laminar fluid flow and lower circulating pressures, especially when drilling low-pressure formations. The tendency is to select lower annular velocities since higher annular velocities cause a higher pressure drop due to higher frictional exposure in the open-hole section. This increases the pressure in the open hole (ECD) and can cause or contribute to lost circulation. Assuming a constant flow rate, annular velocities decrease as the annular clearance increases (i.e., as the hole diameter increases and/or pipe diameter decreases).

Drill Pipe Liner

Casing

Open HoleDrill Collar

DecreasingAnnularVelocity

If the annular velocity is too high, then turbulent flow (as opposed to laminar flow) may result. Here, although the overall profile of the moving mud is constant, internally, the movement is very chaotic.

Pressure Losses

Pressure losses will occur throughout the system where power delivered by the pumps is lost due to opposing frictional forces.

• through each section of drill pipe • through the bit (largest pressure loss throughout the system) • through each annular section • through surface lines (e.g., standpipe, kelly hose, pumps and lines).

The calculated total system pressure loss should equal the actual pressure measured on the standpipe. While the maximum pressure loss possible is determined by the power rating of the pumps and other surface equipment, this maximum usually far exceeds the acceptable operating pressure. Normally, various parameters are specified to ensure that the resulting hydraulics produce the desired system pressure loss. The amount of pressure loss through the drill string and annulus is dependent upon the flow rate, mud density and rheology, the length of each section and the diameter of each section. The largest pressure loss (i.e., at the bit) is dependent upon the nozzle size and resulting jet velocity.



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The type of flow (i.e., laminar or turbulent) also influences pressure loss. Turbulent flow produces larger pressure losses.

Hydraulic Horsepower

Calculating the optimum hydraulic horsepower involves determining the maximum continuous pressure at which the surface equipment can operate (as delivered by the pump), and the maximum continuous flow rate of the mud pump for various liner sizes (using the maximum pressure rating of either the surface equipment or the pump for each liner size, whichever is lower).

Hydraulic Horsepower (HP) = pressure (psi) x flow rate (gpm) / 1.714

Optimization

Hydraulics can be optimized in two ways. One way is to maximize the impact force (i.e., the force exerted on the formation by the drilling fluids as they jettison out of the bit at the bottom of the hole). Another way is to maximize the bit hydraulic horsepower (i.e., power used by the jetting action of the bit, which has to balance maximum rate of penetration and maximum jetting with effective hole cleaning). The power expended by the bit is a proportion of the total power available to the system. The total power available is determined either by the maximum pressure of the pumps or, more typically, it is based on a desired maximum operating pump pressure together with a maximum flow rate that will give sufficient annular velocity for cuttings removal. Once the maximum power available to the system is known, hydraulic performance can be optimized in the following ways:

• To optimize the impact force, set the bit horsepower at 48% of the total available power for optimum

bottomhole cleaning. • To optimize the hydraulic horsepower, set the bit horsepower at 65% of the total available power for laminar

flow. This percentage is effective in drilling softer formations which require more jetting action to clean the bit and keep it clear of cuttings. A percentage as low as 50% is sufficient in drilling hard formations.

Since the hydraulic horsepower at the bit is dependent on jet velocity and, therefore, on the pressure loss at the bit, hydraulic performance can be optimized by simply selecting jet sizes that will give bit pressure losses equal to 65% of the system pressure losses.

Laminar and Turbulent Flow

Laminar flow is a smooth flow of fluid in which no turbulence or cross-flow of fluid particles occurs between adjacent stream lines. The velocity of each layer of fluid increases towards the middle of the stream until a maximum velocity is reached. Special cases of laminar flow may be encountered, called plug flow, where the center of the flow pattern is flat and there is no shear of fluid layers. In hole cleaning, it is often desirable to flatten the velocity profile by increasing the mud thickness, however, this practice generally increases annular pressure losses.



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Laminar Flow

Viscous laminar flow only affects drilling rate by the additional circulating-pressure loss imposed in the annulus as mud thickens. This additional pressure increases the hydrostatic pressure and reduces the drilling rate. Turbulent flow is a random flow pattern, with chaotic and disordered motion of the fluid particles.

Turbulent flow will develop at higher fluid velocities, with the final velocity profile tending to be reasonably uniform despite the chaotic components. For this reason, turbulent flow is actually more effective in cuttings removal but the disadvantages outweigh this advantage. Disadvantages of turbulent flow include erosion of cuttings (thereby destroying interpretive properties), the possibility of hole erosion, increased pressure losses (due to higher frictional forces from the fluid movement, faster velocities and more contact with the wall), and removal of filter cake. One advantage of turbulent flow occurs prior to cementing. Turbulent flow helps to dislodge filter cake from the walls, thereby allowing the cement to contact fresh surfaces. Many operators may request that turbulent or, more reasonably, transitional flow (where both laminar and turbulent patterns are components of the fluid flow), be present around the drill collar section when drilling. This allows for rapid removal of cuttings from the bottom of the hole and, since the drill collar section is relatively short and drilling is proceeding, formations are subject to the destructive forces for only a relatively short period of time. In deep holes, it may be difficult to maintain laminar flow around the collars and still maintain sufficient annular velocity at the top of the hole to remove cuttings. This is more prevalent in offshore drilling where a long, wide riser is in place. Here, annular velocity may be too low to effectively remove cuttings so that a riser booster pump is often used to aid cuttings lift through the riser.

Turbulent Flow



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PRESSURE GRADIENTS Pressure gradient can be expressed as a scale of pressure differences in which there is a uniform variation of pressure from point to point.

Measured Depth versus True Vertical Depth

When drilling oil and gas wells, the pressure gradients that are encountered are those that vary with depth. It is very important to recognize the difference between measured depth and true vertical depth (TVD). In a truly vertical well, these two depths will be the same, but in deviated and horizontal wells, the measured depth always exceeds the TVD. Pressure gradients are always determined in terms of the TVD, since this represents the amount of overlying weight above a given point.

Equivalent Mud Weight (EMW)

It is typical practice to refer to downhole pressures in terms of equivalent mud weight, so that we have a direct comparison to the surface measurement of mud weight and it is very easy to determine the state of balance of the well. The conversion of pressure to equivalent mud weight (EMW) and vice-versa is one of the most fundamental calculations used in drilling a well and one that every mudlogger should be very familiar with.

Pressure = Density TVD Gravitational Conversion Constant× ×

SI Units KPa = kg / m m 0.009813 × ×

Imperial Units psi = ppg ft 0.052× ×

Pressure Gradient = Density Gravitational Conversion Constant×

SI Units KPa / m = kg / m 0.009813 ×

Imperial psi / ft = ppg 0.052×

Vertical Wells MD = TVD

MD

TVD

Deviated Wells



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Hydrostatic Pressure

The hydrostatic pressure at any given vertical depth is the pressure exerted by the weight of the vertical column of static fluid. The term hydrostatic pressure can be used to describe the pressure exerted by any fluid, but typically is used to refer to the pressure exerted by the vertical mud column (i.e., mud hydrostatic or hydrostatic head).

P = MW TVD gHYD × ×

where: PHYD = Mud Hydrostatic MW = Mud Weight

Example 1 The pressure gradient exerted by a mud weight of 1015 kg/m3:

1015 x 0.00981 = 9.957 KPa/m The hydrostatic pressure due to this mud at 3000 metres TVD:

PHYD = 9.957 x 3000 = 29,871 KPa Example 2 What is the hydrostatic pressure at 10,000 ft. if the wellbore is full of 9.5 ppg mud?

PHYD = 9.5 x 10,000 x 0.052 = 4940 psi

FORMATION RELATED PRESSURES

Overburden Gradient

At a given vertical depth, the overburden pressure is the pressure exerted by the accumulated weight of the overlying rocks and sediments. In offshore drilling, the weight of the water also has to be taken into consideration. The accumulated weight of the overlying rocks is a function of the combined weight of the rock matrix and of the formation fluids (water, oil, gas) contained within the pore space of the rocks.

Overburden = Formation Matrix + Pore Pressure Overburden increases with depth since the rocks are subjected to increased weight and compaction. This results in a decrease in porosity with depth as formation fluid is squeezed out leaving proportionally more matrix (denser) as compared to formation fluid (lighter). Therefore, overburden increases with depth with a proportional decrease in porosity, as shown in the next figure.



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OBGDepth Porosity θ

At the surface, the overburden pressure is obviously zero but rapidly increases with depth as there are more and more overlying sediments and accumulated weight. Therefore, an exponential increase in bulk density and overburden pressure is seen with depth. As compaction becomes more uniform with depth, this increase becomes more uniform, leading to a typical profile as shown below. As previously stated, in offshore drilling, the overburden due to the water must also be considered. So too, since depth is referenced to the rotary kelly bushing (RKB) or the rotary table (RT), does the distance to the sea level (air gap), leading to a profile shown below.

Since overburden pressure is a direct result of the weight of overlying sediments, it can be determined from the bulk density of formations being drilled, bulk density being a function of matrix density, fluid density and porosity. In practice, an average bulk density will be used over a given depth interval, but obviously, the smaller the sample interval, the more accurate the resulting overburden gradient. Bulk density may be taken from wireline logs or from drilled cuttings measurements. SI Units Overburden (KPa) = Pb TVD (meters) x 9.81×

Imperial Overburden (psi) = Pb TVD (feet) 0.433× × where: Pb = bulk density (g/cc or sg)

Rotary Kelly Bushing

Mean Sea Level

Sea Bed

OBG (EMW)

OBG

Depth Depth

Land Surface



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Until more accurate calculations are available, the overburden gradient is typically taken as an average of 1 psi/ft which equates to a bulk density of 2.31 g/cc. This is obviously an oversimplification, since overburden is not constant with depth, and densities of 2.31 g/cc may not be recorded until several thousand metres have been drilled.

Formation Pressure

Formation pressure is the pressure exerted by the fluid contained within the pore spaces of the rock. It is therefore a function of the vertical depth and the density of the formation fluid. Normal formation pressure, or pore pressure, will be equal to the normal hydrostatic pressure of the region and will vary depending on the type (principally salinity) of the formation water. Freshwater (density 1 g/cc) exerts a pressure gradient of 0.433 psi/ft (9.81 KPa/m), whereas a saltwater brine of 1.11g/cc exerts a pressure gradient of 0.48 psi/ft (10.87 KPa/m). Depending upon the salinity of the regional formation water, normal formation pressure will be somewhere between these values which give equivalent mud weights of 8.33 ppg (1000 kg/m3) and 9.23 ppg (1108 kg/m3), respectively. For example: The North Sea has a normal formation pressure of 0.450 psi/ft (10.20 KPa/m) or 8.66 ppg EMW (1040 kg/m3 EMW). The US Gulf has a normal formation pressure of 0.465 psi/ft (10.53 KPa/m) or 8.94 ppg EMW (1074 kg/m3 EMW). Abnormal formation pressure characterizes any departure from the normal regional hydrostatic as described above. There are many mechanisms that can lead to a particular formation being abnormally pressured. If a formation has higher than normal pressure, it is referred to as being overpressured; if it has lower than normal pressure, then it is referred to as being underpressured. Perfectly sealed bodies, such as certain reservoirs or salt domes, may give no prior indication of overpressure before being penetrated. Without knowing of their existence, this situation can obviously give way to kicks or blowouts should the mud system not be of sufficient density to balance the pressure. Some overpressured situations, however, such as undercompacted formations due to rapid burial, thereby not allowing the normal release of formation fluid (de-watering) so that an abnormal volume is retained by the formation, can be identified, as the pressure changes, by the effect on drilling and mud parameters. This is an important component of the mudloggers responsibilities, so that the mud weight can be adjusted accordingly to avoid problems/dangers (i.e., influxes, kicks and blowouts due to an overpressured body exceeding mud hydrostatic; fracture, lost circulation and kicks due to the mud hydrostatic exceeding an underpressured body). The term formation balance gradient is applied to the mud weight that is required to balance a given formation pressure at a given depth. Example A reservoir has a known pressure of 5000 psi. What mud weight would be required to balance this pressure when penetrated at a depth of 10,000 ft?

MW ppg=×

=5000

10 000 0 0529 62

, ..

Note that if the same formation is penetrated at different depths, the balancing mud weight required would be different in each case.



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Example

Location A: Reservoir Pressure = 40000 KPa Penetration Depth = 4000m TVD Formation Balance Gradient = 40,000 = 1019 kg/m3 4000 x 0.00981 Location B: Same Reservoir Pressure,

Penetrated at 3800 m

Formation Balance Gradient = 40,000 = 1073 kg/m3 3800 x 0.00981

This is as a result of the different vertical heights of the mud columns having to provide the same hydrostatic pressure, and is a very important aspect in designing well programs. Note that formation pressure cannot be measured while the well is actually being drilled. The value is determined by the mudlogger by comparing trend changes (drilling parameters, mud parameters, gas level, etc.) with the trends established when drilling normally pressured intervals. Once a hole section or well has been drilled, formation pressures and indeed, reservoir pressure, can be determined by Repeat Formation Tests or Drill Stem Tests. If a change in formation pressure results in a kick, the pressure can be determined from the shut-in pressures when the well is shut in and controlled by the blowout preventors.

Fracture Pressure

Fracture pressure is the maximum pressure that a given formation can be subjected to before it is weakened and fractured. It is therefore principally a function of the strength of the rock matrix and is determined by the mudlogger by considering the overburden pressure, the formation pressure and Poisson's Ratio, a strength modulus which may be determined as a function of depth or lithology. The importance of knowing fracture pressure, specifically the lowest fracture pressure in the open hole section, is that if it is exceeded by the annular pressure, the formation will fracture, leading to lost circulation, loss in hydrostatic pressure, and possible kick or blowout. It is unlikely that the hydrostatic pressure of the mud column will ever exceed a formation's fracture pressure, but such situations include: The occurrence of shallow, weak and unconsolidated formations. The only possible prevention here is to use minimal mud weight, low circulating pressures and low pipe running speeds. High mud weight, required to balance overpressured formations at depth, exceeds the fracture pressure of shallower formations. The prevention method in this case is to set a casing string prior to penetrating the overpressured formation. As well as the hydrostatic pressure of the mud column, additional imposed pressure may shock and fracture a formation (e.g., when shutting in a well, surge pressures when running drill pipe in the hole).



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The fracture pressure can only actually be measured by performing a Leak Off Test, or when a formation is actually fractured (i.e., if lost circulation occurs and the depth can be determined, the hydrostatic at that depth can be determined). Accurately knowing the fracture gradient of a region enables: • planning of the drilling program, mud weights, casing depths • calculation of the maximum shut-in pressure during well control • determining the pressure required for reservoir stimulation.

Equivalent Circulating Density

As already stated, the pressure exerted on the bottom of the hole by the column of drilling fluid is known as the hydrostatic pressure. When the drilling fluid is being circulated, this pressure increases as a result of the frictional forces causing pressure losses throughout the annulus. The higher pressure is known as the dynamic or bottomhole circulating pressure (BHCP).

BHCP P annular pressure lossesHYD= + ∑

This higher circulating pressure means, in turn, that the effective density of the mud increases during circulation; this is known as the equivalent circulating density or ECD. Imperial Units

ECD (ppg EMW) = MW (ppg) + annular pressure losses (psi)

0.052 x TVD (ft)∑

SI Units

ECD (kg m EMW) = MW (kg m ) + annular pressure losses (KPa)

0.00981 x TVD (m)3 3 ∑

The significance of the equivalent circulating density is that during drilling or circulation, it is the ECD and not the MW that is responsible for the pressure acting in the annulus and balancing formation pressures.



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WELL BALANCE

Formation Pressure versus Hydrostatic Pressure

The hydrostatic pressure of the drilling fluid column exerted against the borehole wall helps prevent unconsolidated or overpressured formations from caving into the hole. This pressure also helps to prevent kicks (i.e., the controllable flow of formation fluids into the wellbore resulting in displaced drilling mud at the surface) and blowouts (i.e., uncontrolled flow of formation fluids into the wellbore).

• Underbalance versus Overbalance If the hydrostatic pressure is equal to the formation fluid pressure, the well is at balance. An overbalance exists when the mud hydrostatic is greater than the formation pressure. In permeable formations, an overbalance can result in invasion of the formation (i.e., drilling fluids enter the formation, displacing formation fluids away from the wellbore). In very permeable formations or when the overbalance is excessive, flushing can occur ahead of the bit before the formation is drilled. This may result in no show, or gas response, being seen from a potential productive formation. An important consideration, especially in long-hole sections, is that whereas the mud hydrostatic may provide a marginal overbalance against higher pressure formations at the bottom of the hole, it may be imposing an excessive pressure against shallower, weaker formations. This may lead to formation damage, and in the worst scenario, may even fracture the formation. Once fracture has occurred, drilling fluid will flow freely into the formation. Such lost circulation may lead to the loss of hydrostatic head in the annulus. This is not only costly, but may result in an underbalanced

situation lower in the hole where a kick is then a very real danger. Such a situation of lost circulation and a kick occurring simultaneously can easily lead to an underground blowout. Underbalance occurs when the hydrostatic pressure is lower than the formation pressure. This may allow an influx, or flow, of formation fluids into the wellbore which may, in turn, result in a kick. This influx will be large, or more rapid, where there is good permeability and/or high formation pressure. Where formations are impermeable, the formation fluid is unable to flow freely. In this situation, the differential pressure will result in the fracturing and caving of the formation. This will then not only lead to an increase of formation fluid entering the drilling mud, but also to loading of the annulus with cuttings, squeezing of the hole (leading to tight hole or stuck pipe problems) and to difficult cuttings analysis since they are coming from further up the hole as well as from the formation being drilled. Underbalanced drilling can dramatically improve penetration rates. In fact, with the appropriate surface equipment, underbalanced drilling has several benefits, including limited formation and reservoir damage, no lost circulation or differential sticking, no flushing of formations, and, in effect, a continual formation test.



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DRILLING A WELL

Starting Point

Once a drilling rig has been positioned, whether it be a land rig or offshore vessel, the drilling operation is ready to commence. Typically, a wide conductor pipe, up to 36” in diameter, will be forcibly driven into the surface sediments by repeated hammer blows. The sediments can then be drilled out from the inside of the conductor pipe with returns and cuttings circulated via a divertor. Driving the pipe, rather than drilling a hole first, will prevent the surface sediments from being washed out and weakening the foundations of the rig. A firm anchor is therefore provided for the installation of the blowout preventors. On jackup rigs, this provides an immediate link between the wellbore and the rig and BOP stack. Alternatively, the hole may be drilled first before running conductor pipe. When the surface formation is first penetrated by the bit, the well is said to have been spudded. The hole may be drilled ‘in one go’ with a large bit or it may be drilled first with a smaller bit and then re-drilled with a larger diameter hole opener. Offshore floating rigs will drill this first hole section ‘open’, allowing the seawater to act as the drilling fluid and return the drilled cuttings to the seabed. Before drilling can go any further the hole must be sealed off to provide a closed system. This will then allow a drilling fluid to be continually recycled and drilled cuttings collected and examined. A wide diameter pipe, equivalent to the conductor pipe but now called casing, will be run into and down to the bottom of the drilled hole. A cement mixture will then be pumped into the casing and forcibly displaced so that it fills the space between the casing and the formation. Once this cement has set, the well is ‘sealed’ so that when drilling recommences, the drilling fluid as well as any formation fluid will be safely returned to the surface via the inside of the casing. Again, once set, this casing will prevent any collapse of the surface sediments which may typically be weak and unconsolidated, providing a firm foundation and a firm anchor on which to position the blowout preventors. In general, the BOP stack will be installed once the casing has been set, although in some cases, operators will wait until the surface hole has been drilled and casing set. In the case of jackup rigs and land rigs, the BOP’s are installed directly beneath the rig floor. A flow line will then be connected to return drilling mud and cuttings to the surface circulation system. In the case of offshore floating rigs, the BOP stack is installed on the seabed where the casing strings terminate. A marine riser, which includes a telescopic or slip joint to allow for vertical movement of the rig due to tidal and heave motion, will link the BOP stack to the rig completing the closed system. A divertor is always installed as part of the surface flowline system, so that, if the well is not able to be controlled by the BOP’s, and returns are reaching surface, gas can be directed safely away from the rig.

Surface Hole

This hole section will be drilled to a pre-determined depth and again sealed off by running casing to the bottom of the hole and cementing it in place. The base of the casing, or shoe, will generally be the weakest part of the next hole section simply because it is the shallowest point and subject to the least overburden and compaction. The depth and lithology to which the surface hole is drilled and the casing set is therefore very critical (this applies to any casing point). The lithology should be consolidated, homogeneous and impermeable. The competence of this lithology must provide sufficient fracture strength to drill the next hole section with a sufficient safety margin over any formation pressures expected (see Leak Off Tests; Fracture Pressure; Kick Tolerance). The surface hole will be of wide diameter and will normally drill quite rapidly since the surface sediments will not be too compact or consolidated. A large volume of cuttings will therefore be continually produced. To ensure that these cuttings are removed from the annulus and so to prevent them blocking or impeding the movement and rotation of drillstring and bit, viscous sweeps will be made at regular intervals. This simply involves a volume of



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thick, viscous drilling mud being circulated around the entire hole. The viscosity of the mud enables it to lift and carry all of the cuttings out of the hole. The surface hole will normally be completed with just one drill bit. If the bit should wear out however, it will have to be replaced by lifting the entire drillstring out of the hole (tripping). This is done by breaking the drillpipe into lengths of 3 (triple stand) or 2 (double stand) joints, depending on the size of the derrick. Once the hole section has been completed and before the casing string is set in place, the Operator will normally require the hole to be logged with electrical tools in order to gain specific information about the wellbore and lithology. These tools are run into the hole on a thin wire and are therefore termed wireline tools. The wireline tools are very expensive but the wire can only be subjected to a certain amount of load before it would snap. Therefore, before logging, a wiper trip will be performed. This operation is to ensure that the hole is clean and not closing in at any point. It involves raising the drillstring part way out of the hole or until the bit is out of the open hole and inside the previous casing. The bit will then be run back into the bottom to determine the condition of the hole. Any tight spots will have to be corrected. Minor problems can be corrected simply by working the pipe up and down over the tight spot; circulating at the same time will help to clean tighter sections. If the hole is so tight or undergauge, it may seriously restrict the movement of the pipe or even not allow the bit to pass at all. In this situation, the tight section will have to be effectively re-drilled or reamed with full circulation and rotation. When the bit reaches the bottom of the hole, a bottoms-up circulation will be performed. This ensures that any cuttings that may have fallen, or have been dislodged during the hole cleaning, to the bottom of the hole (fill) are lifted and circulated out of the hole. This will enable the logging tools to be run all the way to the bottom of the hole. Once the hole section has been logged, casing can be run and cemented in position. The main purposes of the surface casing are again to provide a firm and competent anchor for the BOP equipment; to protect formations from further erosion; to seal off fresh water aquifers from any contamination; to prevent collapse of unconsolidated formations; to seal off any subnormal or overpressured formations. Before drilling ahead with the next hole section, the BOP stack and casing will be pressure tested to ensure that there is full integrity and that all prevention equipment is fully functional.

Intermediate Hole

Before this hole section can be started, rubber plugs and cement remaining from the cementing of the previous casing will have to be drilled out before new lithology is encountered. Just a small interval of the next hole section will then be drilled, typically 5 to 10 metres, and then a pressure test performed. This Leak Off or Formation Integrity Test will determine the fracture pressure of the formation at the shoe. This enables us to know the maximum pressure that can be exerted on the wellbore without fracturing that formation, a situation that has to be avoided at all costs. Exactly the same procedures will be followed as outlined above i.e. drilling, tripping, logging, casing and cementing. The exact number of hole sections will be dependent on several factors: • Depth, fracture pressure and kick tolerence of the previous casing shoe. • Hole/formation problems that may be encountered such as zones of lost circulation, unstable formations,

abnormal formation pressures, pipe sticking problems. • Change of mud type to a system that may be unsuitable or damaging to particular formations. All of these situations may result in an intermediate string of casing being set to seal off a particular interval. Each subsequent casing string will be run from the surface, inside the previous casing, to the bottom of the hole. This



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new string may be cemented all the way back to surface, but it is normal to cement it back to the inside of the previous casing which is already cemented back to surface.

Total Depth

As the total depth (TD) of the well is approached, any casing that may need to be run will normally be run into the hole on drillpipe and hung from a hanger inside of the previous casing. In this situation, it will be termed a liner, but procedures for cementing and testing will be exactly the same as for any casing string. Obviously, as the well becomes deeper, the casing requirements become much more expensive if it were to be run all the way back to surface. Situations vary, but the well may be drilled through a prospective production zone to the well’s TD, or it may be drilled to just above the production zone and the liner set in place. This situation would enable any problem zones previously encountered to be sealed off and the production zone isolated; it would allow the mud system to be changed or modified specifically for the zone of interest in terms of formation and production protection and pressures espected. Depending on operator requirements and on indications when drilling into the zone of interest, eg rapid drilling to indicate porosity, gas or oil shows from the drilling fluid, the interval may or may not be cored. Cutting and preserving a core of the reservoir interval allows much more precise laboratory analysis to be carried out regarding the productivity and economical potential of the reservoir. Cutting a core requires the use of a specialized core bit that will cut around and leave a central core of rock, typically around 10cm in diameter, intact. As the bit cuts down and deepens the well, this core will move up into a special sleeve and core barrel that will hold the core. At the end of the coring operation, the core will be held in the barrel and it has to broken off from the bottom of the wellbore by physically lifting the string until the core snaps off. This is a very important operation to ensure that the core is retained and does not fall out from the barrel. At TD, the well will again be logged with wireline tools. A fuller array of evaluating tools may be run if the zone of interest shows good hydrocarbon potential. If a core hasn’t been cut, sidewall cores may be cut with a wireline tool from specific depths of interest. If the zone shows producing potential, the well may be production tested with a drillstem test (DST). A production casing string will be run to the bottom of the hole and cemented in place. This casing can then be perforated at specific depth intervals that correspond to the zone of interest. The casing will have been displaced to a specialized fluid or brine, the density of which will allow formation fluids, including oil and gas, to flow into the wellbore. Testing equipment, known as a christmas tree will be installed at the surface to measure and determine the reservoir pressure and flow rates. Once all work has been completed, the well will be plugged with cement to isolate any open hole or production zones from the surface. If there is no reservoir potential, the well will be abandoned; if there is potential the well will be suspended to allow for further analysis and testing to be completed.

DRILLING AND “MAKING HOLE”

The drilling operation involves lowering the drill pipe into the hole and applying sufficient weight for the drill bit to break down the formation. During drilling, the drill string is rotated by a rotary table or top drive while drilling fluid is circulated down the pipe, through the bit and back up the hole to the surface carrying drilled cuttings. As drilling progresses, joints (or stands when using a top drive unit) of drillpipe have to be continually added to the top of the drillstring, by making a connection. Circulation is temporarily stopped and the drill string set within slips held in the rotary table, to expose the top pipe joint. Tongs are used to unscrew the kelly from the drill string, a new pipe joint is connected to the kelly, and then the kelly and new pipe are connected to the drill string using a pipe



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spinner and tongs. Once these connections have been made, the drill string is lowered back into the hole and drilling resumes. When the bit wears out, it must be replaced by tripping the entire drill string out of the hole.

To ensure that the depth is being accurately monitored, it is important to record the pipe length before it is run into the hole (pipe tally), and regularly check this length with the recorded depth at kelly down intervals (i.e., the point at which the kelly has been drilled down to its fullest extent). If using a kelly, the drilled depth is equal to the Bottomhole Assembly + Pipe Length + Kelly Length. If using a top drive, the drilled depth is equal to the Bottomhole Assembly + Pipe Length. Each length of pipe will be measured, to an accuracy of 2 decimal places, before it is added to the string and run into the hole. These lengths are recorded by the driller in a pipe tally book and a cumulative total maintained. The mudlogger should keep an independent record of the pipe lengths and total, so that pipe tallys can be cross checked to avoid errors. So that depths can be easily referenced at a later stage, it is an important practice for the mudlogger to record or mark down the kelly down depth on all realtime charts.

A drilling break is a sudden increase in the drill bit's rate of penetration. This may result simply from a formation change, but sometimes indicates that the bit has penetrated a high-pressure zone and thus warns of the possibility of a kick. A flow check is a method of determining whether a kick has occurred. The mud pumps are stopped for a short period to see whether mud continues to flow out of the hole. If it does, a kick may be occurring, with the formation fluids entering the wellbore and displacing mud from the annulus at the surface. The flow check may be performed by visually inspecting the annulus through the rotary table, or by directing the mud returns to the trip tank and observing the mud level. The drilling speed, or penetration rate (ROP) directly impacts drilling costs, and is one of the major factors in determining the efficiency and overall cost of a drilling operation. However, a well cannot simply be drilled at maximum speed to minimize costs. To optimize drilling operations, a well should be drilled as fast as prudently possible, with due precaution to maintain hole stability, to allow sufficient time for hole cleaning and to ensure continual well and personnel safety. Adherence to drilling procedures is essential in optimizing drilling operations. Drilling procedures are documented from knowledge and experience drilling wells under various conditions. They set forth the requirements for safe, routine drilling operations, and provide corrective measures for problems encountered while drilling. Because drilling conditions vary from one oil field to another, drilling procedures should be supplemented with records from offset wells (i.e., other wells in the area) which have been drilled successfully.

REAMING

Reaming is performed to open an under-gauge hole to its original full-gauge size. Reaming may be required as a result of under-gauge drilling in abrasive formations or excessive wear on drilling bits. Reaming is also performed to open surface pilot holes, to open ratholes left after coring (i.e., a smaller-diameter hole than the main hole), and to remove doglegs (i.e., a sharp bend in the wellbore, keyseats (i.e., an under-gauge channel or groove cut in the side of the borehole that results from the pipe rotating on a dogleg), and ledges (i.e., an irregularity caused by penetrating alternating hard and soft formations, where the soft formation is washed out and changes the hole diameter). Reaming may be performed to prevent an under-gauge hole from pinching a new bit. A reamer is the tool used to smooth the wall of a well, enlarge the hole to full-gauge size, help stabilize the bit, straighten the wellbore if kinks



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or doglegs are encountered, and drill directionally. Most reamers used today have roller cutters in alignment with the axis of the reamer body which provides a rolling action as the reamer is rotated. The risk of hole deviation can be minimized by selecting the proper weight on bit and rotation speed. While the bit weight is normally a compromise between a penetration rate, bit wear and deviation control, the rotation speed should be controlled by the bit size and type and the formations to be drilled.

CIRCULATING

Circulating is the process of pumping drilling fluid out of the mud pits, down the drill string, up the annulus and back to the mud pits, and is a continual process while drilling. Circulating, while not drilling, may be performed to clean the hole of drill cuttings, to condition the drilling mud ensuring it retains optimum properties, or to remove excessive gas from the mud. The most common circulating operations are performed for the following purposes: • to circulate out drilling breaks which may be an indication that a high pressured zone has been penetrated • to circulate out samples that correspond to drilling changes (ROP, torque) which may indicate that a potential

zone of interest or coring point has been reached. • prior to running casing and cementing, to condition the mud, ensure the hole is clean (so that the casing won't

stick) and to remove filter cake (to ensure good contact between the cement and borehole wall). • prior to running wireline tools, to ensure that the hole is clean and the tools won't become stuck.

CORING

Purpose of Coring

Coring is an operation performed to cut and retrieve a cylindrical rock sample, or core, from a potentially productive formation of interest for laboratory analysis. Through coring, it is possible to recover an intact core sample that retains more formation properties and fluids than drilled cuttings. Coring may be performed for precise formation and structural evaluation or, more specifically, to retrieve core for reservoir evaluation. While coring is an expensive operation to perform, it provides valuable information for determining porosity, permeability, lithology, fluid content, angle of dip, geological age and hydrocarbon-producing potential.

Coring Methods

Conventional coring requires tripping the drill string out of the hole. The core bit and barrel assembly is attached to the bottom of the drill string and run into the hole. After the core is drilled, the whole assembly is tripped out of the hole to retrieve the core. Conventional coring requires expensive equipment and costly rig time. With this method, there is an increased risk of swabbing in formation fluids when tripping out, and there is the danger to personnel should poisonous gas be released at the surface. Conventional core samples usually range from 2-5 inches (50-125 mm) in diameter and from 30, 60 or 90 feet (10, 20 or 30 meters) in length. Their size makes them difficult to handle.



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Sidewall coring is a technique by which core samples are obtained from the wellbore wall in a formation that has already been drilled but not yet cased. It offers the advantage that many cores can be taken at precise depths using one tool. A sidewall coring gun containing sample ports at the intervals required for testing is lowered on wireline. An explosive charge fires up to thirty hollow bullets into the formation. The bullets are then pulled back into the gun along with the core samples. The gun is then lifted out of the hole on wireline. Sidewall core samples usually range from ¾-1¼ inches (20-30 mm) in diameter and from ¾-4 inches (20 to 100 mm) in length. Because samples may be contaminated with filtrate, sidewall coring is not as effective as conventional coring for determining porosity, permeability or fluid saturation. A further disadvantage is that weak or friable formations may be "shattered" by the bullet, preventing good core samples being retrieved. Newer tools avoid this problem by individually "drilling" the core samples rather than using the bullet technique. This method is also necessary to retrieve core samples from very hard lithologies that are otherwise impenetrable with the bullet.

Core Barrel Assembly

The core barrel is a tubular device installed at the bottom of the drill string. The conventional core barrel actually has two barrels. A non-rotating, thin-walled, inner core barrel captures and holds the core after it travels through the core bit. A heavy, thick-walled, outer core barrel protects the inner barrel and takes the place of the bottom-most drill collar. Unlike a drill bit, the core bit does not drill out the center portion of the hole. Instead, it allows the center portion (i.e., the core) to pass through a round opening in the center of the bit and into the core barrel. Diamond-bit core barrels have consistently proven their durability, cutting reliability and recovery capability. Today, they are used almost exclusively in both conventional and wireline coring. Drilling mud is initially circulated through the inner barrel. Just prior to coring, a metal ball is dropped down the drill string to engage a check valve. The check valve closes, thereby diverting mud flow from the inner barrel to the outer barrel so that it does not erode or displace core from the inner barrel. The drilling mud is then discharged through water courses in the bit. A rabbit, or core marker, is a metal device, placed in the inner core barrel before coring. When all of the core has been removed from the core barrel, the rabbit, or core marker, falls out indicating that the barrel is empty.



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Cutting the Core

Conventional coring is performed in much the same way as drilling, but more carefully and slowly. Any vigorous or sudden change in the drill string rotation can cause the core to break and fall into the hole or to jam in the barrel, thereby preventing any further coring. The drill string must then be tripped out of the hole in order to recover the core.

Retrieval and Handling Operations

When a sufficient amount of core has been cut, the core barrel is lifted, causing the rock to break off and leaving the core trapped inside the inner core barrel. In conventional core recovery, when the core barrel arrives at the surface, it is usually hung in the derrick and specially designed tongs are used to grip the core for recovery in sections. Once the core has been completely removed from the barrel, it is measured. If the recovered core length is shorter than the cored interval, it can be assumed that the shortage has been lost at the bottom of the hole. Immediately after measuring, core sections are wiped clean (not washed) to remove drilling fluid, then rapidly sealed in foil and wax and placed in boxes for shipping to the laboratory.

This practice prevents contamination as well as loss of gas and other formation fluids. Boxes are pre-marked with the box number (1 of n), the core number, top and bottom indicators and sample interval. Most commonly, today, fibre glass or aluminum sleeves are used to contain the core as coring proceeds. This simplifies the core recovery procedure. The sleeve containing the core is removed at the surface and is immediately ready for shipping. The sleeve may be kept complete or cut up into sections with each end sealed (e.g., using heat-shrinking caps).

TRIPPING

Tripping refers to hoisting the drill string out of the wellbore (tripping out or pulling out) and then returning it to the wellbore (tripping in or running in). Tripping is performed to change the drill bit or the bottom hole assembly. Tripping is also performed at casing points (depths at which casing is set), coring points (depths at which core samples are taken) and upon reaching the well's total depth. Wiper trips, or dummy trips, are performed to clean the hole during long-hole sections (thus ensuring there are no tight spots, sloughing shale, etc. that may result in tight hole problems if left unchecked). A set number of stands are pulled out of the hole and then run back to the bottom to resume drilling. Sometimes, the drill pipe is pulled back into the previous casing and then run back to bottom of the hole.

Outer Core Barrel

Rabbit

Metal Ball

Check Valve

Inner Core Barrel

Core Bit

Water Courses



69

Such "clean up" trips are also made before running wireline tools and prior to running casing.

Trip Speed

The drill string should be tripped at the fastest, safe running speed. Because drilling ceases for the duration of the trip, the objective is to trip only when necessary and as quickly as possible in order to minimize costs while ensuring proper well maintenance and personnel safety. Excessive tripping speeds cause swabbing and pressure surges, which in turn can cause severe hole problems and loss of pressure control. The maximum safe trip speed can be determined by calculating and preparing a tripping speed table using reliable data and omitting excessive safety factors. The actual tripping speed should then be monitored by measuring the speed of the middle joint of the drill string in a stand.

Pulling Out of Hole

The main concern when pulling pipe out of the hole is to avoid fluid influxes that may result in a kick. This will result from a reduction in hydrostatic pressure as a result of not maintaining the mud level in the annulus and/or causing excessive swabbing pressures. When the drill pipe is pulled from the hole, the mud level in the annulus will drop by an amount equal to the volume of steel of removed pipe. This drop in mud level obviously reduces the vertical height of the mud column, resulting in a lower hydrostatic pressure at the bottom of the hole. To avoid the bottomhole pressure falling below the formation pressure (which will result in an influx), it is critically important that the mud level in the annulus be kept full (i.e., mud is pumped into the hole to replace the volume of steel as pipe is removed). A small pump circulates mud between the trip tank and the wellhead to top up the hole as pipe is lifted from the hole. The trip tank is a small mud tank used to accurately measure small changes in mud level as the hole is filled. The volume of mud pumped into the hole (i.e., drop in trip tank level) must equal the volume of steel removed. This may be done continuously as pipe is lifted or, more typically, the mud level is topped up after very five stands of drill pipe and then individually for stands of heavy-weight drill pipe and drill collars (due to the larger steel volume per unit length).

Owing to their thickness, the most critical time for keeping the hole full occurs when pulling the drill collars since they have a large steel volume per unit length. Each stand pulled therefore results in a much greater drop in mud level than that resulting from one stand of drill pipe. For example, approximately 0.1m3 of mud is required to replace one stand of standard 5" drill pipe, whereas close to 0.8m3 is required to replace one stand of 8" drill collars. It is normal safe practice, especially when using spiral drill collars, to perform a flow check prior to pulling the drill collars out of the hole, to ensure that the well is static (i.e., not flowing) since the preventors cannot close effectively around the collars.

Looking down into an offshore triptank



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Swabbing

When drill pipe is lifted vertically, the resulting mud movement causes frictional pressure losses that reduce the mud hydrostatic. This may result in a temporary condition of underbalance that will allow formation fluid to influx. Swabbing increases with higher mud weight, higher viscosity, lower annular clearance and faster pipe running speeds. The pressure losses occur throughout the annulus with a cumulative reduction in pressure at the bottom of the hole. The reduction is therefore greatest when the pipe is first pulled off bottom. Added to this is the further "piston" effect which is greatest around the drill collars (i.e., where there is the smallest annular clearance). It is therefore normal practice to pull the first five or ten stands very slowly to keep swabbing to a minimum as the drill pipe is being pulled through formations which have not yet had enough time for sufficient filter cake to build up. It is also normal practice to maintain a trip margin. This means maintaining a mud weight that, even with the swabbing pressure reduction, provides a hydrostatic pressure greater than the formation pressure. This can be determined for a maximum running speed, for which the swab pressure can be calculated. Example 1 If the formation pressure at 5000 feet is 8.8 ppg emw, what mud weight is required to provide a trip margin of 60 psi if, for a given running speed the swab pressure is 50 psi?

60 psi at 5000' 0.23ppg=×

=60

5000 0 052.

Therefore, MW = 8.8 + 0.23 = 9.03 = 9.1ppg

Example 2 At 3000 metres, the mud weight is 1035 kg/m3 with an estimated formation pressure of 1025 kg/m3. What is the maximum swab pressure allowable to prevent the well from becoming underbalanced?

Differential or Margin kg m3= 10 Pressure KPa= × × =10 3000 0 00981 294 .

Therefore, the swab pressure cannot exceed 294 KPa. Using a computer, the maximum running speed (X) to avoid exceeding a swab pressure of 294 KPa can be determined.

Pipe Speed (m/min)

Pressure ( KPa)

X

294



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Running In Hole

Mud is normally displaced directly to the suction pit when drill pipe is run in the hole, and, as with pulling out, it is equally important to ensure that the correct volume of mud is displaced for the pipe run in the hole. If too much mud is displaced, the well may be flowing; if not enough mud is displaced, the well may be losing mud. Unlike lifting pipe, when drill pipe is run in the hole, the resulting mud movement and frictional pressure loss leads to an increase or surge in the hydrostatic pressure. Surge pressure is calculated in the same way as swab pressure. Surge pressure can result in formation damage, but, ultimately, may cause the formation to fracture. This would result in lost circulation, loss in hydrostatic head and, finally, a kick. The other important difference from pulling out is that, initially, the pipe is empty. If the drill string is not filled, it is susceptible to potential collapse since there is nothing to balance the pressure imposed by the mud in the annulus. Normally, the drill pipe will fill naturally as it is run in, from mud entering through the bit nozzles. If too much displaced mud is seen (i.e., greater than the open displacement), it may be due to any or a combination of small nozzles, dense or viscous mud, or running in too fast. If this occurs, it is important that the driller be notified so that he can first check that the well is not flowing, then secondly, fill the drill string, and perhaps subsequently, reduce the running speed. Naturally, if the nozzles become blocked, or plugged, with cuttings, mud is unable to enter the drill string, so that a closed displacement is seen (i.e., steel volume plus internal capacity). Again, the driller should be notified so that he can attempt to pump and unplug the nozzles before proceeding with the trip. Closed displacement will also be seen if a float is intentionally placed in the drill string. This is a one-way valve that allows circulation but does not allow mud to pass up through it. Floats are often used when expensive equipment such as mud motors and measurement-while-drilling (MWD) tools are used in the drill string to prevent mud and cuttings from entering and damaging them. When a float is used, the drill pipe will obviously not fill by itself, so the trip should be stopped at regular intervals to enable the driller to fill the pipe with mud. Typically, the driller will continue pumping until the mud is circulating up the annulus to ensure that the drill pipe is completely full. At the point of breaking circulation, the pump pressure (which would have been slowly increasing as the drill string filled) will show a sharp increase. Because the static drilling fluid would have thickened, or gelled, a higher than normal pressure may be required to break circulation. When circulation commences following a trip into the hole, a distinct gas peak, called trip gas, will be recorded upon reaching bottoms up (i.e., the time it takes to circulate the mud from the bit to the surface). Trip gas originates from a number of different mechanisms: • repeated swabbing of formation fluids when the drill pipe was initially pulled from the hole • accumulation of cuttings at the bottom of the hole that will subsequently liberate gas when circulated to the

surface • fluid diffusion when the mud is static during the trip, especially from the bottom of the hole where a filter cake

has not built up sufficiently Naturally, the lower the pressure differential (i.e., hydrostatic versus formation pressure) and the more gaseous the formations, the larger the volume of trip gas. It is often accompanied by an increase in flow rate from the hole.



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Displacements

Mud displacement should be calculated from the pipe volume before tripping. Accurate trip sheets should be maintained to record actual displacement and make necessary adjustments as tripping proceeds. Any deviations recorded by mudloggers should be reported immediately to the driller. Example Trip Sheet

DATE: 12 SEP 97 HOLE SIZE: 311mm BOTTOM HOLE ASSEMBLY SIZE LNTH DISP/m TOTAL BIT RUN NUMBER: 10 HOLE DEPTH: 2500m DC 1 203 300 0.028 8.4 m3 DC 2 BIT TYPE: HTC ATM22 CASING SIZE: 339mm HWDP 127 250 0.0094 2.3 m3 RUN IN / PULL OUT: IN SHOE DEPTH: 1800m DP 1 127 1950 0.0042 8.2 m3 DP 2 STAND NO.

CALCULATED DISPLACEMENT

ACTUAL DISPLACEMENT

CUMULATIVE CALC. DISPL .

CUMULATIVE ACT DISPL .

DIFFERENCE

DC 1 0.84 1.0 0.84 1.0 + 0.16 DC 2 0.84 0.8 1.68 1.8 + 0.12 DC 3 0.84 0.6 2.52 2.4 - 0.12 DC 4 0.84 0.8 3.36 3.2 - 0.16

DC 10 0.84 0.9 8.40 8.5 + 0.10 HW 1 0.46 0.4 8.86 8.9 + 0.04 HW 2 0.46 0.5 9.32 9.4 + 0.08

DP 5 0.63 0.6 11.33 11.4 + 0.07 DP 10 0.63 0.6 11.96 12.0 + 0.04 DP 15 0.63 0.7 12.59 12.7 + 0.11

DP 55 0.63 0.7 17.64 18.0 + 0.36 DP 60 0.63 0.7 18.27 18.7 + 0.43 DP 65 0.63 0.7 18.90 19.4 + 0.50

Final Displacement for Trip: Calculated 18.9 m3 Actual Returns 19.4 m3

Hook Load

Hook load is the weight of the drill string suspended by the hook. As drilling proceeds deeper, the hook must support increasing string weight. Through displacement, the drill string is buoyed up by the drilling fluid, thereby reducing the total weight that the hook must support. When tripping in or out, the buoyancy factor of the drilling fluid must be taken into consideration. The denser the drilling mud, the greater the buoyancy effect and the lighter the apparent weight of the drill string. When tripping out, the resistance of the drilling mud makes the actual hook load greater than the string weight. When tripping in, part of the string weight will be supported by the mud, making the hook load lighter than the actual string weight. If tight spots or sections are encountered, the change in hook load depends on whether the pipe is being tripped out or tripped in. When tripping out, additional resistance must be overcome in order to lift the pipe. This additional



73

hook load is termed overpull. When tripping in, a portion of the string weight will be supported by the tight spot, so that the measured hook load will decrease. This is known as drag.

Strapping and Rabbiting the Pipe

Strapping the pipe refers to manually measuring each stand of drill pipe as it is pulled from the hole. Strapping is performed to confirm the pipe tally and actual hole depth. Rabbiting the pipe refers to cleaning debris from the inside of the drill pipe by dropping a rabbit (usually wooden) down the vertical length of the pipe. Rabbiting is performed more often when using expensive downhole tools such as motors and measurement-while-drilling (MWD) instruments.



74

WIRELINE LOGGING

Formation Evaluation Logs After each section of the hole is drilled (prior to running casing) and at the total depth of the well, wireline logs are run to obtain information for formation evaluation. Various common types of logs are briefly described below and discussed in detail in Chapter 9. Resistivity Logs Resistivity logs measure the resistance of a formation to conducting electricity and are used to determine the type of fluid occupying a rock's pore space, the relative saturation levels of oil and water in formations, and the mobility of the fluid. Porosity Logs Porosity logs measure formation porosity and determine lithology using either sound waves (sonic log), radiation (density log) or a neutron radiation detection (neutron log). Gamma Ray Logs Gamma Ray logs measure the natural radioactivity of the formation and are used to determine lithology and correlate formation tops in adjacent wells. Spontaneous Potential Logs Spontaneous Potential logs measure the electrical potential of the formation (i.e., current flows between formation waters of different salinity) and are used to determine lithology, formation water resistivity and correlate wells. Caliper Log Most holes are not drilled true-gauge (i.e., to bit diameter). They are often enlarged as a result of a bit drilling off borehole center, hole washout and/or sloughing shale. A caliper log, which records hole diameter by depth, is run to determine variations in hole gauge. The caliper tool has two legs or pads that track along the wellbore wall as the wireline is pulled out. The caliper log provides a hole profile indicating hole enlargements and reductions. It is important to know the hole size/gauge in order to calculate cement volumes more accurately and determine the affect that variations have on other electronic logs. Excessive hole enlargements signal caving or washouts. Reduced diameters signal filter cake build-up in permeable formations. Free-Point Log If the drill string becomes stuck when pulling it from the hole, the free point (i.e., the area above the stuck point) can be determined using a free-point indicator. The free-point indicator is run on wireline into the wellbore. As the drill string is pulled and turned, the electromagnetic fields of free pipe and stuck pipe, which differ, are recorded by the indicator and registered on a metering device at the surface. By backing off (i.e., unscrewing the free pipe from the stuck pipe), the free pipe can then be pulled from the wellbore. The stuck pipe, or fish, remaining in the hole can be washed over and recovered or retrieved using various fishing tools. Cement Bond Log A cement bond log is an acoustic, or sonic, log used to verify the integrity (quality and hardness) of the cement bond between the casing and the formation. It is based on the concept that sound travels faster through cement than through air. Therefore, well-bonded cement transmits an acoustic signal quickly, and poorly bonded cement transmits a signal slowly.



75

CASING AND CEMENTING

Purpose of Casing

An essential operation in drilling an oil or gas well is to periodically line the hole with steel pipe, or casing. Successively smaller-diameter lengths of steel pipe are either screwed or welded (in the case of large conductor pipe) together to form a continuous tube to the desired depth. Once installed, this casing is cemented in place to provide additional support and a pressure-tight seal. Casing in a well has a number of functions: • Prevent formations from caving into the hole • Isolate unstable or problem formations (high-pressure zones; aquifers, gas zones, weak zones, etc.) • Protect productive formations • Provide greater kick tolerance (the deeper the casing, the greater the fracture pressure of the formation the casing

is set in, meaning higher formation pressures can be controlled as the well is deepened) • Allow for production testing • Serve as an attachment for surface equipment and artificial lift equipment

Types of Casing

One or more of the following types of casing is required in every well: • Conductor Pipe Conductor pipe is a short string installed to protect surface sediments from erosion by drilling fluids. It raises the drilling fluid high enough to be returned to the mud pits and prevents washing out around the base of the rig. When shallow gas sands are anticipated, it can serve as the attachment for a blowout preventor. • Surface Casing Surface casing is set to protect fresh-water formations and prevent loose formations from caving into the hole. It also serves as an anchor for the blowout preventor to forestall problems with abnormal pressure zones. The casing must be strong enough to support a blowout preventor, and to withstand gas or fluid pressures that might be encountered as drilling proceeds below this casing. Surface casing should be set deep enough, in a strong, consolidated formation with a fracture gradient high enough to support the maximum mud weight that will be needed to drill to the next casing setting point. • Intermediate Casing Intermediate casing is primarily used to protect the hole against lost circulation. It is run to seal off weak zones that may break down as heavier mud weight is needed to control higher formation pressures as the well is drilled deeper. It may also be set below high pressure formations so that lighter mud weights can be used when drilling proceeds. • Liner String A liner string is run in a deep hole to prevent lost circulation in weak upper zones while drilling with normal weighted mud to control normal-pressure formations at deeper intervals. Liners protect against downhole blowouts into normal-pressure formations when drilling abnormal pressure zones.



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Unlike casing which is run from the surface to a given depth and overlaps the previous casing, liner is suspended from the bottom of the previous casing by a hanger and run to the bottom of the hole. Liner string offers a cost advantage due to its shorter length; however, a tie-back string is sometimes run after the hole is drilled to total depth to connect the liner to the surface. • Production Casing Production casing is the last casing string in a well, usually set immediately above or through the producing formation. It isolates the oil or gas from undesirable fluid in the producing formation and from other formations penetrated by the wellbore. It serves as the protective housing for the tubing and other equipment used in a well.

Surface Equipment/Mixing System

As with the standard drillpipe equipment, elevators, casing tongs and casing spinners are designed for specific casing diameters, in order to lift the casing joints and connect to each other at the correct torque. The most common type of cement mixing system is the jet type. Water is forced through a reduced section of line at high velocity and cement is added from a hopper above. Cement pumps are used to control the pressure and the rate of displacement during mixing. Once the cement has been pumped down into the casing, rig pumps will be used to pump mud and displace the cement from inside the casing to the annulus. A cementing head, or retainer head, is an accessory attached to the top of the casing to facilitate cementing the casing. It has passages for cement slurry, and retainer chambers for cementing wiper plugs, so that mud, slurry and plugs can all be pumped consecutively in one continual operation.

Subsurface Equipment

A guide shoe, or shoe collar, is a short, concrete-filled, cylindrical section of steel placed at the end of the casing string. This guides the casing into the hole, past any obstructions and minimizing the risk of the casing from becoming caught up on irregularities in the borehole as it is lowered. A float collar is usually installed between the first and second joint of casing. It is equipped with a check valve assembly, which allows downward movement of fluid, but prevents upward movement. In this way, it prevents mud from entering the casing as it is being lowered into the hole, thereby floating the casing into the wellbore and decreasing the load on the blocks and derrick. It also prevents cement from backing up into the casing during the cementing operation and after it has been displaced.

Wall cake scratcher

Centralizer



77

Variations may include float collars that allow partial filling of the casing with mud as it is lowered into the wellbore, and collars that combine both the guiding and floating apparatus. Wiper plugs are rubber plugs that are used to separate cement and drilling fluid as they are pumped down the casing during cementing. The bottom plug, which is pumped ahead of the cement, wipes residual drilling mud from the inside casing walls and prevents the drilling mud below it from contaminating the cement. The top plug, which is released after the calculated volume of cement has been pumped, wipes residue cement from the inside casing walls and prevents the drilling mud above it from contaminating the cement. Centralizers are secured around the casing at regular intervals to hold the casing away from the wellbore walls. Centering the casing in the hole allows for a more uniform cement sheath to form around the pipe. A scratcher is a stiff-wired device fastened to the outside of the casing that is used to condition the hole for cementing. By rotating or moving the casing string up and down as it run into the hole, the scratcher removes mud cake from the wellbore walls so that the cement can bond solidly to the formation. A liner hanger is a circular, frictional-gripping assembly of slips and packing rings used to suspend liner string from the bottom of the previous casing. Using a liner hanger saves on the expense of running casing all the way back to the surface.

Preparing to Run Casing

Before casing is run into the hole, an electric log is run to confirm the bottomhole formation for setting the casing shoe, and to confirm the hole depth so that the exact length of casing can be run. A caliper log is also run to determine the hole diameter and the volume of cement required. Cement will be pumped to fill the annulus, and into the previous casing. Typically, an extra 25% volume may be pumped to allow for error and losses to the formation. Before running casing, drilling mud is circulated to remove cuttings and excess filter cake from the hole, to condition the hole and to condition the mud to ensure uniform properties. Failure to condition the hole thoroughly and treat the mud properly can lead to stuck pipe, poor cementing, extra well costs for cement squeeze work, and even re-drilling the hole. When conditioning the hole, drilling mud should be pumped around at least twice while weight, viscosity and fluid loss properties are recorded. If mud treatment appears necessary, circulation while slowly rotating and working the pipe must be maintained until the mud fluid is in suitable condition for running casing.

Running the casing

As casing is run, it is periodically filled with drilling mud, unless automatic fill-up float equipment is used. If it wasn’t filled while running in, the hydrostatic pressure of the mud column acting on the outside of the casing would cause it to collapse. Using a light-weight filling line with a quick-opening valve, each joint is filled while the next length is picked up and prepared for stabbing. Because it is usually not possible to fill a joint completely, it is common practice to stop running casing every five to ten joints and fill completely. It is crucial that the mud displacements are accurately monitored for the whole duration of the casing run. Because the casing tubular is effectively closed ended, together with very small annular clearance, surge pressures while running casing will be large. To minimize this, the casing joints are run in at a very slow speed, but if the surge pressure was great enough, weaker formations could be fractured resulting in loss of drilling mud to the formation. Not only might fracturing the formation result in a poor cement job, it might also result in a blowout if sufficient mud is lost from the annulus to reduce the mud hydrostatic below the formation pressure of a permeable formation elsewhere in the wellbore.



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Therefore, mud returns and displacements are closely monitored for any indication of losses to the formation.

The volume of fluid displaced from the hole, as each joint of casing is added to the string, should be equal to the closed displacement (i.e. the casing O.D.) of the casing. Final volume gains in the suction pit should be equal to the volume of steel (i.e., open displacement) that has been run into the well, if there has been no fluid loss. Provided proper mud returns are obtained, it is usually possible to run the casing all the way into the hole before attempting circulation. When establishing circulation, care must be taken not to run the pump too fast as the casing is lowered, so as to minimize pressure surges. If there is any indication of lost returns, the pumping rate should be reduced immediately. Circulating drilling mud through the casing after reaching bottom serves two important functions. One is to test the surface piping system. Another is to condition the mud in the hole, and to flush out cuttings and filter cake prior to cementing. Circulation time will extend for as long as required to condition the mud, and the casing is reciprocated and/or rotated, with or without scratchers, throughout circulation. Minimum adequate circulation before cementing distributes a volume of fluid equal to the volume inside the casing and annulus.

Cementing Operation

Cementing is a process of mixing and displacing a cement slurry (dry cement mixed with water) into the annulus (i.e., between the casing and the open hole). By bonding the casing to the formation, cementing serves several valuable purposes: • Protects the productive formation • Helps control blowouts from high-pressure zones • Seals off lost-circulation or other troublesome formations prior to drilling deeper • Helps support the casing • Prevents casing corrosion Generally, 10 - 15 barrels of water is pumped into the hole before pumping cement slurry. The water acts as a flushing agent and provides a spacer between the drilling mud and the slurry. The water also helps to remove any remaining filter cake and flushes mud ahead of the cement, thereby lessening contamination.

Run 5 joints of casing – Closed end displacement

Fill casing string

Final displacement = steel volume

Mud level in surface pit

Time



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To prepare for cementing, the cementing head is installed on the top casing joint. A discharge line from the cementing pump is attached to the cementing head so that the slurry can be circulated. A bottom wiper plug is placed in the cementing head, followed by the top wiper plug. As the cement slurry from the pump discharge reaches the cementing head, the bottom plug travels down the casing ahead of the slurry. Once the calculated volume of cement has been pumped, a retainer pin is pulled to release the top wiper plug from the cementing head (A).

The plugs and cement are pumped to the bottom of the casing by the mud/rig pumps. The bottom plug seats in the float collar (B). Mud continues to be pumped in order to displace the cement, which passes through the open valve in the float collar, out the guide shoe and into the annulus. Meanwhile, the casing is reciprocated and/or rotated to help displace the mud. Again, it is important to monitor pit levels through this operation to ensure that the much denser cement slurry is not being lost to the formation (i.e. pit level should remain level as displacement is taking place). When all of the cement has been displaced from inside the casing, the top plug seats (bumps) on top of the bottom plug held in the float collar (C). At this point, the pump pressure increases immediately since no mud can get past the solid top plug (i.e. mud is being pumped into a closed space). The pump is then immediately shut down and the pressure is bled off. With the pressure released from the casing, the valve in the float collar closes to keep cement from backing up in the casing. It is important to release the pressure on the casing before the cement sets, as such pressure will cause the casing to bulge. If the cement is allowed to set, then the casing will pull away from the hardened cement when the pressure is released, thereby loosening the bond. Cement should be displaced quickly to create turbulence in the annulus and to remove the maximum amount of mud cake as possible. However, excessive pressure on the casing and surface connection can cause a rupture, excessive flow (or pressure) in the annulus can lead to formation breakdown and result in lost circulation, and excessive flow in the annulus can cause mud waste through overflow.

Other Applications

• Secondary cementing operations are performed as part of well servicing and workover. • During cementing, the cement can fail to rise uniformly between the casing and the borehole wall, leaving

spaces devoid of cement. This is called cement channeling. Cement channeling can be rectified by performing a secondary cementing operation called a cement squeeze. Here, cement is pumped behind the casing under high

A Pump cement and plugs

Bottom Plug

Cement

Top Plug

B Bottom plug seats in float collar

C Cement is displaced until the plugs bump



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pressure to re-cement channeled areas or to block off an uncemented formation. It can be performed to isolate a producing formation, seal off water or repair casing leaks.

• Secondary cementing can also be performed to plug-back a well to another producing formation (and change

testing zones), to plug a dry hole (and abandon the well), and to plug-back a hole in order to sidetrack.

Pressure Test

Once the cement has set, a pressure test is conducted to ensure the casing will withstand the maximum anticipated pressures for the next hole section. The blowout preventors are closed and pressure is applied to the casing by rig pumps (pumping mud into a closed space). This applied pressure, plus the hydrostatic pressure exerted by the mud column, is the test pressure. This pressure is usually maintained for about 30 minutes and if there is no reduction in pressure over this time, the casing is considered satisfactory with successful cement bonding.



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TESTING

Leak-Off and Formation Integrity Tests

A Leak-Off Test (LOT) is performed to determine the formation fracture pressure directly below the casing seat (i.e., in the first formation after the casing shoe) and the maximum possible shut-in pressure. The zone directly beneath the casing seat is assumed to be the weakest point in the next hole section, since it is the shallowest depth. Therefore, LOTs are usually performed after the casing has been set and a small interval of the next section has been drilled. Before conducting an LOT, blowout preventors must be installed and the well must be closed-in. A small volume of mud is pumped slowly to gradually pressurize the casing; the surface pressure rises as this mud is pumped in. When a decrease in pressure is recorded, the test is complete. The highest-recorded pressure, plus the hydrostatic pressure of the mud column, equals the formation fracture pressure. Three pressure stages are evident, and it is the operators decision as to which one will be taken as the pressure on which to base subsequent calculations: 1. Leak-Off Pressure, which is the pressure at which fluid first starts to inject into the formation at the start of

fracture. This will be seen as a slight drop in the rate that the pressure is increasing. At this point, the pump rate should be reduced.

2. Rupture Pressure, which is the maximum pressure the formation can sustain before irreversible fracture occurs.

This will be determined by a sharp drop in the pressure being applied, and pumping should be halted. 3. If no more pressure is applied at this point, most formations will recover to a certain degree, and the

Propogation Pressure is determined when the pressure becomes stable again. The major disadvantage of the LOT is that the formation is actually being fractured and weakened during the test, and the risk is that it may be permanently weakened or that a fracture may be opened. The formation will generally recover to the propogation pressure, but in reality, this means that the fracture pressure has effectively been lowered, and the pressure capabilities for the next hole section have been lessened.

Mud volume pumped / Time

Surface Pressure

2

1

3



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When the formation at the casing shoe is fractured like this, there are two pressures acting on the formation causing the fracture, namely, the hydrostatic pressure due to the mud column and the pressure that is being applied from the surface. Therefore,

Fracture Pressure Mud Hydrostatic at Shoe Applied Surface Pressure= +

SI Units Fracture Gradient (kg / m EMW) = P at Shoe + Applied PressureCasing TVD (meters) x 0.00981

3 HYD

Imperial Fracture Gradient (ppg EMW) = P at Shoe + Applied Pressure

Casing TVD (feet) x 0.052HYD

This use of this type of LOT is typically restricted to wildcat wells, for example, in an area where little is known about the fracture gradient and expected formation pressures. Where offset data is available and fracture/formation pressures are known, a Formation (or Pressure) Integrity Test (FIT or PIT) is typically performed. This test is carried out in the same way as a leak-off test, but the expected pressures and required maximum are known, so a predetermined surface pressure can be applied and held. This predetermined pressure is gauged from offset well data and is determined so as to be sufficient for the largest pressure anticipated during the next hole section. There is a built-in safety margin in performing a FIT since the formation is not actually fractured during the test. If, during subsequent drilling, a kick occurs due to higher formation pressure, the well will be shut in. The driller needs to know the maximum shut-in pressure (MAASP - Maximum Allowable Annular Surface Pressure) that can be allowed before the formation at the shoe will fracture. If this were to happen, the well will be kicking from the higher pressured zone, but with fracturing resulting from the well being shut in, lost circulation will be occurring simultaneously at the shoe. This is known as an underground blowout, where fluids are flowing uncontrollably between formations, and every precaution must be taken to prevent it’s occurrance.

MAASP Fracture Pressure at Shoe Hydrostatic Pressure at Shoe= +

where the Fracture Pressure at Shoe is that which is determined from the LOT. Since MAASP (Maximum Allowable Annular Surface Pressure) is determined from pressures at the shoe, it will only change if the mud weight changes resulting in a change in hydrostatic pressure (at the shoe).

Repeat Formation Testing

Repeat formation testing, or wireline formation testing, is a quick and inexpensive way to sample formation fluids and measure hydrostatic and flow pressure at specific depths. Repeat formation testing provides the information required to predict formation productivity and to plan more sophisticated formation tests, such as drill stem tests. Repeat formation tests can be run in open holes or cased holes (i.e., through perforated production liners), and multiple tests can be performed during one trip in the hole.



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A spring mechanism in the RFT tool holds a pad firmly against the sidewall to form a hydraulic seal from drilling mud in the wellbore, and a piston creates a vacuum in a test chamber. Formation fluids enter the tool chamber through an open valve. The initial shut-in pressure is registered. The test chamber valve is then opened to allow the formation fluids to flow into it. A recorder logs the rate at which the test chamber is filled, then the final shut-in pressure is recorded. Because test chambers can hold only a minute amount of formation fluids, a second sample chamber can be opened to draw more formation fluids.

Drill Stem Testing

Drill stem testing is conducted to record formation pressures and flow rates over large intervals of interest, and to gather formation fluid samples in order to determine the potential productivity of a reservoir formation. Drill stem tests can be run in open holes or cased holes (i.e., through production liners which can be perforated to allow formation fluids to flow into the annulus). Bottomhole Drill Stem Tests are performed with a single packer that is set above the formation of interest. This will isolate the zone between the packer and the bottom of the hole. This type of test minimizes the formation's exposure time to drilling fluid (because only one test can be run) and, therefore, the potential for formation damage. Straddle Drill Stem Tests, with dual packers, allow zones further up the hole to be tested. One set of packers is set above the formation of interest, and the other below, thereby straddling the formation and isolating it for testing. This type of test offers the advantage that multiple tests can be run on the same trip into the hole and reducing costs. However, there is greater potential for formation damage due to extended exposure to drilling fluid during multiple tests.

Drill Stem Test Tools

Packers Packers are expandable rubber sleeves that are used to isolate the formation of interest. When they expand, they form a seal against the wellbore wall, which prevents formation fluids from flowing through the annulus. Perforated Pipe Perforated pipe allows the formation fluid to enter the drill stem during the flow periods of the test and flow to the surface where they can be collected, stored or burned off. Shut-in Valve The shut-in valve controls the flow of fluid into the drill stem over a series of open-flow and shut-in periods. When closed, the shut-in valve stops the flow of formation fluid. When open, the shut-in valve allows the formation fluid to flow. Pressure Recorders Pressure recorders are used to record and plot open-flow and shut-in pressures over time. The outside recorder is set close to the perforated interval, with the pressure sensor on the outside of the drill string between the upper and lower packer. It measures pressure changes in the formation of interest during the test period, and provides the most accurate indication of reservoir pressure.



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The inside recorder is set inside the DST assembly in order to measure the pressure of fluid entering through the perforated interval into the DST tool. The fluid recorder, or flow recorder, is set above the shut-in valve, with the pressure sensor inside the drill string, and measures the hydrostatic pressure of the fluid recovery. A fourth, optional, recorder (called a below straddle recorder) is set below the bottom packer on straddle tests to measure how well the bottom packer seat holds.

Performing a Drill Stem Test

Drilling mud is circulated and conditioned to ensure that the hole is clean and to reduce the possibility of cuttings or other debris damaging the DST tool. The DST tool is typically run into position on drill pipe. A cushion of water or compressed gas may be placed in the drill stem to support the drill stem against mud pressure until the test starts. When the DST tool is in place, the packer is set to form a seal (usually by applying weight on the packer) and the shut-in valve is opened. The cushion, if any, is bled off slowly to allow formation fluids to flow gradually into the drill stem and prevent formation damage caused by an abrupt flow. The wellbore is monitored throughout the DST for pressure changes that warn of poor packer seating. Most DSTs encompass two (and sometimes three) flow and shut-in periods. The first flow and shut-in period, which is the shortest, clears out any pressure pockets in the wellbore and removes mud from the drill stem. The second and third flow and shut-in periods run longer than the first. The purpose of the flow periods is to monitor the flow rate and changes in pressure. The shut-in periods serve to record formation pressure.

where: i = initial HP = Hydrostatic Pressure PFP = Pre-Flow Pressure f = final SIP = Shut-In Pressure FP = Flow Pressure

When the DST is complete, the shut-in valve is closed to trap a fresh, clean sample of formation fluid and the DST tool is unseated. Formation fluid is reverse-circulated out of the drill stem to prevent spillage while tripping out. The drill string and DST tool are carefully tripped out of the hole, and the fluid sample and graphs are retrieved. Information obtained in performing a DST includes reservoir pressure, permeability, pressure depletion rates (volume and production rate) and gas, oil and water contacts. The saved sample provides valuable information on fluid saturation, viscosity, contaminants and harmful gases.

Final Shut-in Period

Main Flow Period

Initial Shut-In Period

Time

Pressure

iHP

fPFP

fHP

iFP

fFP

iPFP

iSIP fSIP

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