Writing 3 pages (Drilling Fluids)
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PEE241Drilling.pptxPEE241 Drilling and Well Completion
Eng. Rashed Alazemi
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OUTLINE
Chapter 1 : INTRODUCTION TO DRILLING
Chapter 4: CASING AND CEMENTING
Chapter 7: WELL COMPLETION &WELL STIMULATION
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Common Systems of Units
Three common systems of units can be found throughout hydrology when assigning a quantity to variables in hydrology:
1. System International (SI)
2. centimeter-gram-second (cgs) system
3. English system
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Conversion Factors
Unit Conversion Factor
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Surface Area and Volume
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Exercises
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1.1 History
Oil has been used for lighting purposes for many thousand years.
Darks Well was the first commercial oil well drilled in 1859 in Pennylvania.
Cable tool drilling technique was used to drill to a final depth of 70 ft (21.18 m). It took one and a half year to reach the above depth.
Onshore drilling for oil began o the coast of Summereld, California, just south of Santa Barbara, in 1896.
In 1900 the rotary drilling technique was invented by Lucas.
The first successful attempts at oshore drilling occurred between 1910 and 1920.
In about 1920 mud was used instead of water to circulate the cutting out the hole.
The first directional drilling recorded instance of a well being deliberately drilled along a deviated course was in California in 1930.
First horizontal well in Kern County ,California at Edison field in 1980.
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1.2 Objectives of Drilling
Drilling is the process of making a hole into a hard surface where the length of the hole is very large compared to the diameter.
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1.3 Types of Drilling
There are two types of drilling for oil and gas wells :
Exploration drilling (often called Wildcat wells): is the Initial phase of drilling for the purpose of determining the physical properties and boundaries of a reservoir.
Development drilling (or Production wells): is drilled to a depth that is likely to be productive, so as to maximize the chances of success.
According to a wells final depth, it can be classified into:
Shallow well: < 6000 ft
Conventional well: 6000 ft− 11,000 ft
Deep well: 11,000 ft−16,000 ft
Ultra deep well: > 16,000 ft
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1.4 Drilling Methods
The two most widely used drilling methods are :
Cable-Tool Drilling
Rotary Drilling
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1.4.1 Cable-Tool Drilling
Cable-tool was the first method used to drill a bore hole and is still in use, particularly for shallow oil or gas wells.
In the cable-tool method, drilling is accomplished by lowering a wire line or cable into the hole.
On the end of the line is a heavy chisel-shaped piece of steel called the drilling bit.
An up-and down motion is applied to the line at the surface.
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Cable-Tool Drilling
Advantages for this well
Cheap
Good and fast for hard formation
Disadvantages for this well
Drilling has to stop for cutting removal
Not compatible with soft formation ( caving of unconsolidated rock)
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1.4.2 Rotary Drilling
A bit used to cut the formation is attached to steel pipe called drillpipe.
The bit is lowered to the bottom of the hole.
The pipe is rotated form the surface by means of a rotary table, through which is inserted a square or hexagonal piece called a kelly.
The kelly, connected to the drillpipe at the surface, passes through the rotary table.
The turning action oft the rotary table is applied to the Kelly, which is turn rotate, the drillpipe and the drilling bit
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1.5 Types of Drilling Rigs
The term ”rig” generally refers to the complex of equipment that is used to penetrate the surface of the Earth’s crust.
Drilling and workover rigs come in a variety of shapes and sizes with each having its own characteristics suited for a particular job.
Although there are many factors to be considered in selecting the best rig for the job, a few are especially critical. They are:
• Surface location (land, inland water, offshore)
• Estimated maximum hole depth
• Horsepower requirements
• Cost
• Availability
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Drilling rigs are classified as
Onshore (Land) rigs.
Offshore (Marine) rigs.
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1.5.1 Onshore Rigs
These rigs are primarily used on land.
Major components of the rig include the mud tanks, the mud pumps, the derrick or mast, the drawworks, the rotary table or topdrive, the drillstring, the power generation equipment and auxiliary equipment.
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1.5.2 Offshore Rigs
The first successful attempts at offshore drilling occurred between 1910 and 1920.
The major types of offshore rigs:
1. Floating rigs
(a) Semisubmersible
(b) Drillships
2. Bottom-supported rigs: There are three types:
(a) Jack-ups
(b) Platform
(c) Submesrsible
(d) Barge
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1.6 Drilling Team
The people directly involved in drilling a well are employed either by the operating company, the drilling contractor or one of the service companies.
Tool Pusher : The tool pusher supervises all drilling operations and is the leading man of the drilling contractor on location. Which is the highest position at the drilling location, responsible for every crew..
Company Man : The company man is in direct charge of all the companys activities on the rig site. He is responsible for the drilling strategy as well as the supplies and services in need. His decisions directly eect the progress of the well.
Driller : The crew supervisor on a drilling rig, working under the toolpusher.
Derrick Man : The derrickman works on the so-called monkeyboard, a small platform up in the derrick, usually about 90 [ft] above the rotary table. When a connection is made or during tripping operations he is handling and guiding the upper end of the pipe.
Floor Man : During tripping, the rotary helpers are responsible for handling the lower end of the drill pipe to make or break a connection.
Mud Engineer, Mud Logger : The service company who provides the mud almost always sends a mud engineer and a mud logger to the rig site. They are constantly responsible for logging what is happening in the hole as well as maintaining the propper mud conditions.
Roustabout : The roustabout is a unskilled worker, especially one who works in a port or at an oil well. Roustabout maintaining equipment, unloading supplies and helping the drilling team.
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2.1 Rotary Drilling
The most common drilling rigs in use today are rotary drilling rigs.
The main components of a rotary drilling rig can be seen in Figure 3-2.
For all rigs, the depth of the planned well determines basic rig requirements like hoisting capacity, power system, circulation system (mud pressure, mud stream, mud cleaning), as well as the pressure control system.
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Main Component Parts of a Rotary Rig are:
1. Power System
2. Hoisting System
3. Fluid Circulating System
4. Rotary System
5. Well Control System
6. Well Monitoring System
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2.1 Power System
Objective : To provide power to the rig equipment.
The power system of a rotary drilling rig has to supply the following main components:
Rotary system
Hoisting system and
Drilling fluid circulation system.
The largest power consumers on a rotary drilling rig are the hoisting and the circulation system, these components determine mainly the total power requirements.
The power itself is either generated at the rig site using internal-combustion diesel engines, or taken as electric power supply from existing power lines.
As guideline, power requirements for most rigs are between 1,000 to 3,000 hp.
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The rig power systems performance is characterised by the output horse- power, torque and fuel consumption for various engine speeds. These parameters are calculated with equations 3.1 to 3.4:
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Example 3-1:
A diesel engine givens as output torque of 1,740 ft-lbf at engine speed of 1,200 rpm. If the fuel consumption rate was 31.5 gal/hr, what is the out- put power and overall efficiency of the engine?
3.2 Hoisting System
The function of the hoisting system is to provide a means of lowering or raising drillstring, casing string, and other subsurface equipment into or out of the hole.
The principle components of the hoisting system are
(1) The derrick and substructure
(2) The block and tackle,
(3) The drawworks.
Two routine drilling operations performed with the hoisting system are called
Making a connection,
Making a trip.
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3.2.1 Derrick
The function of a derrick is to provide the vertical height required to raise sections of pipe from or lower them into hole.
The greater the height, the longer the section of pipe that can be handle and, thus, the faster a long string of pipe can be inserted in or removed from the hole.
The most commonly used drillpipe is between 27 or 30 ft long.
Derricks that can handle sections called stands, which are composed of two, three, or four joints od drillpipe, are said to be capable of pulling doubles, thribbles, or fourbles, respectively.
Derricks are rated according to their ability to withstand compressive loads and wind loads.
Substructure is space below the derrick floor to provide working for pressure control valves called blowout preventers.
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3.2.2 Block and Tackle
The block and tackle is comprised of
The crown block
The travelling block,
The drilling line.
The arrangement and nomenclature of the block and tackle used on rotary rigs are shown in figure 3-7.
The principle function of the block and tackle is to provide a mechanical advantage, which permits easier handling of large loads
The mechanical advantage M of block and tackle is simply the load support by the travelling block, W, divided by load imposed on drawworks, Ff:
The load on the drawworks is the tension in the fast line.
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3.2.3 Drawworks
The drawworks (Figure 3-11) provide the hoisting and braking power required to raise and lower the heavy strings of pipe.
The principle parts of the drawworks are
The drum
The brakes
The transmission,
The catheads
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The drum transmit the torque required for hoisting or braking. It also stores the drilling line required to move the travelling block length of the derrick.
The brakes must have capacity to stop and sustain the great weights imposed when lowering a string of pipe into the hole. Auxiliary brakes are used to help dissipate the large amount of heat generated during braking.
Two types of auxiliary brakes commonly used are (1) the hydrodynamic type and (2) the electromagnetic type. The drawworks transmission provides a means for easily changing the direction and speed of the travelling block.
Power also must be transmitted to catheads attached to both ends of drawworks.
Friction catheads shown in Figure 3-12 turn continuously and can be used to assist in lifting or moving equipment on the rig floor.
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3.3 Circulating System
A major function of fluid circulating is to remove the rock cuttings from the hole as drilling progresses
The principle components of the mud circulation system are:
Mud pumps
Mud pits
Mud mixing equipment
Contaminant removal equipment
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3.3.1 Mud Pumps
Nowadays there are two types of mud pumps in use (duplex pump, triplex pump), both equipped with reciprocating positive-displacement pistons.
The amount of mud and the pressure the mud pumps release the mud to the circulation system are controlled via changing of pump liners and pistons as well as control of the speed [stroke/minute] the pump is moving.
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Duplex Mud Pump
The duplex mud pump consists of two cylinders and is double-acting. This means that drilling mud is pumped with the forward and backward movement of the barrel.
The pump displacement on the forward movement of the piston is given by:
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On the backward movement of the piston, the volume is displaced:
Thus the total displacement per complete pump cycle is:
Since duplex mud pumps are equipped with two cylinders, and assuming a volumetric efficiency Ev , the total pump displacement per cycle is given by:
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Triplex Mud Pump
The triplex mud pump consists of three cylinders and is single-acting. The pump displacement per cylinder for one complete cycle is given by:
Thus the triplex mud pump, having a volumetric efficiency Ev has a total mud displacement of Fp per complete cycle.
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where,
Fp : Pump displacement (also called pump factor), in2/cycle.
Ev : Volumetric efficiency,fraction.
Ls : Stroke Length, in.
dr : Piston rod diameter,in.
dl : Liner diameter,in
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Example 3-3:
Compute the pump factor in units of barrels per stroke for duplex pump having 6.5 in. liners, 2.5 in. rods, 18 in. strokes, and a volumetric efficiency of 90 %.
Solution
The pump factor for a duplex pump is given by Eq.3.14:
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Then convert in3/stroke to bbl/stroke
The flow rate of the pump [in2/min] can be calculated with:
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where,
N : Number of cycle per minute, cycle/min
The overall efficiency of a mud pump is the product of the mechanical and the volumetric efficiency. The mechanical efficiency is often assumed to be 90% and is related to the efficiency of the primemover itself and the linkage to the pump drive shaft. The volumetric efficiency of a mud pump with adequately charged suction system can be as high as 100%.
Therefore most manufactures rate their pumps with a total efficiency of 90% (mechanical efficiency: 90%, volumetric eciency:100%).
Note that per revolution, the duplex pump makes two cycles (double-acting) where the triplex pump completes one cycle (single-acting).
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The terms "cycle" and "stroke" are applied interchangeably in the industry and refer to one complete pump revolution.
Pumps are generally rated according to their:
1. Hydraulic power,
2. Maximum pressure,
3. Maximum ow rate.
Since the inlet pressure is essentially atmospheric pressure, the increase of
mud pressure due to the mud pump is approximately equal the discharge
pressure.
The hydraulic power " hp " provided by the mud pump can be calculated as:
where:
p : Pump discharge pressure, psi.
q : Pump discharge flow rate, gal/min.
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3.4 The Rotary System
The function of the rotary system is to transmit rotation to the drillstring and consequently rotate the bit. During drilling operation, this rotation is to the right.
The main parts of the rotary system are: (1) swivel, (2) rotary hose, (3) kelly, (4) rotary drive (master pushing, kelly pushing), (5) rotary table and(6) drillstring, see figure 3-16.
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3.4.1 Swivel
The swivel is suspended by the hook of the traveling block and allows the drillstring to rotate as drilling fluid is pumped to within the drillstring.
Without the swivel, drilling uid could not be pumped downhole, or the drillstring could not rotate.
The swivel also supports the axial load of the drillstring. see gure for cuts of swivel showing the internal parts.
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3.4.2 Kelly
The kelly has a square or hexagonal cross-section and provides the rotation of the drillstring.
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3.4.3 Rotary Drive
The rotary drive consists of master pushing and kelly pushing. The master pushing receives its rotational momentum from the compound and drives the kelly pushing which in turn transfers the rotation to the kelly.
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3.4.4 Drillstring
A drillstring on a drilling rig is a column, or string, of drill pipe that transmits drilling fluid (via the mud pumps) and torque (via the kelly drive or top drive) to the drill bit.
The term is loosely applied as the assembled collection of the drill pipe, drill collars, tools and drill bit.
The drill string is hollow so that drilling uid can be pumped down through it and circulated back up the annulus (the void between the drill string and the casing/open hole).
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Drillpipe
The major portion of the drillstring is composed of drillpipe.
The drillpipe in common use is pierced, seamless tubing. API has development specications for drillpipe. Drillpipe is specied by its outer diameter, weight per foot, steel grade, and range length.
The dimensions and strength of API drillpipe of grades D, E, G and S-135 are shown in Table 3-4. Drillpipe is furnished in following API length ranges.
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Range 2 drillpipe is used most commonly. Since each joint of pipe has
a unique length, the length of each joint must be measured carefully and
recorded during drilling operations,
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The drillpipe joint are fastened together in the drillstring by means of tool joints. The female portion of the tool joint is called the box and the male portion is called the pin.
The portion of the drillpipe to which the tool joint is attached has thicker walls that the rest of the drillpipe to provide for a stronger joint. This thicker portion of the pipe is called the upset.
If the extra thickness is achieved by decreasing the internal diameter, the pipe is said to have an internal upset.
Table 3-5: Dimensions and strength of API seamless internal upset drillpipe
Drill collars
The lower section of rotary drillstring is composed of drill collars. The drill collars are thick-walled heavy steel tubulars used tp apply weight to the bit. The buckling tendency of the relatively thin-walled drillpipe is too great to use it for this purpose. The smaller clearance between the borehole and the drill collars helps to keep the hole straight.
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Drilling bit
Drill bit depends on several factors, such as the condition of the bit, the weight applied to it, and the rate at which it is rotated.
Also important for a bit performance is the effectiveness of the drilling fluid in clearing cuttings, produced by the bit away from the bottom.
Drill bit selection is in general a complicated process but, when performed properly, has a major impact on the total well cost.
Three principal types of bits are used in a rotary drilling operation:
Drag of fish-tail bits,
Rolling cutter bits more commonly called rockbits, and
Diamond bits.
Most drilling bits are rock bits.
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Capacity and Volume of Drillstring
Capacity is the amount (volume) that something will hold, or its internal volume.
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where, d pipe diameter , in.
Capacity means that each 1 inch of length will be hold 1 cubic inch. : For
the Oilfield units bbl/ft.
Then,
Volume is the amount of space taken up by a solid object. Volume is calculate how much pipe can be hold in barrel (bbl).
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This equation is using to calculate volume of one barrel (bbl) in 1 foot (ft) of pipe which is also the pipe capacity in bbl/ft
For drillpipe and drill collars we using inner diameter (ID) to calculate capacity of pipe to hold one barrel in each one foot.
Which is
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Example 3-4:
5 inch OD drill pipe has an inside diameter of 4.276 inches.length of pipe
1000 feet. Calculate the following: (a) Capacity bbl=ft (b) Volume bbl.
solution
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Example 3-5:
8 inch drill collars ID 3 inch, Length of drill collars 450 ft.Calculate the
following: (a) Capacity bbl=ft (b) Volume bbl.
solution
Capacity and Volume of Annulus
If you place a pipe inside another pipe there is a space between them. This is called an annulus.
The annulus of an oil well refers to any void between any piping, tubing or casing and the piping, tubing, or casing immediately surrounding it.
To calculate annular capacities and volumes (e.g. pipe in hole, pipe in casing).
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- Annulus Capacity opposite drillpipe, bbl/ft
where,
Aadp : Capacity of annulus opposite drillpipe, bbl/ft
dh : Hole diameter, in.
ODdp : Outer diameter of drillpipe, in.
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- Annulus Volume opposite drillpipe, bbl
where,
Vadp : Volume of annulus opposite drillpipe, bbl
dh : Hole diameter, in.
ODdp : Outer diameter of drillpipe, in.
Ldp : Length of drillpipe, ft
- Annulus Capacity opposite drill collars bbl/ft
where,
Aadc : Capacity of annulus opposite drill collars, bbl=ft
dh : Hole diameter, in.
ODdc : Outer diameter of drillpipe, in.
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- Annulus Volume opposite drill collars, bbl
where,
Vadc : Volume of annulus opposite drill collars, bbl
dh : Hole diameter, in.
ODdp : Outer diameter of drillpipe, in.
Ldc : Length of drill collars, ft
Example 3-6:
Calculate the following annulus capacities in bbl/ft.
(a) 5 inch drillpipe in 171/2 inch hole.
(b) 8 inch drill collars in 121/4 inch hole.
solution
Displacement of Drillstring
The term displacement often is used to refer to the cross-sectional area of steel in the pipe expressed in units of volume per unit length. The displacement, Ad , of a section of pipe is given by
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Example 3-7:
A drillstring is composed of 7,000 ft of 5-in., 19.5lbf=ft drillpipe and 500 ft of 8 in. OD by 2.75 in. ID drill collars when drilling a 9.875 in. borehole assuming that the borehole remains in gauge, compute the number of pump cycles required to circulated mud from the surface to bit and from the bottom of the hole to the surface if the pump factor is 0.1781 bbl/cycle.
Solution
Given
Drillpipe Drill collars
OD :5 in OD : 8 in
Weigth: 19.5 lbf/ft ID : 2.75 in
Length:7000 ft Length:500 ft
Hole diameter: 9.875 in Fp = 0.1781 bbl=cycle.
Using Table 3-5, the inner diameter of 5 in., 19.5 lbm/ft drillpipe is 4.276in.
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- First, number of pump cycles required to circulated mud from the surface to bit:
- The capacity of the drillpipe
- The volume of the drillpipe
- The capacity of drill collars
- The volume of the drill collars
- The number of pump cycles
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-Second ,number of pump cycles required to circulated mud from the bit to surface:
- The annulus capacity outside the drillpipe
- The annulus volume of the drillpipe
- The annulus capacity outside the drill collars
- The annulus volume of the drill collars
- The number of pump cycles
3.5 Well control System
The well control system prevents the uncontrolled flow of formation fluids from the wellbore.
When the bit penetrates a permeable formation that has a fluid pressure in excess of the hydrostatic pressure exerted by the drilling fluid, formation fluids will begin displacing the drilling fluid from the well.
The flow of formation fluids into the well in the presence of drilling fluid is called a kick.
The well control system permits :
Detecting the kick,
Closing the well at the surface,
circulating the well under pressure to remove the formation fluids and increase the mud density,
moving the drill string under pressure, and
diverting flow away from rig personnel and equipment
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Failure of the well control system results in an uncontrolled flow of formation fluids and is called a blowout.
Blowouts can cause loss of life, drilling equipment, the well, much of the oil and gas reserves in the underground reservoir, and damage to the environment near the well.
The well control system is one of the more important systems on the rig. Annular preventers, sometimes called bag-type preventers, stop flow from the well using a ring of synthetic rubber that contracts in thefl uid passage.
Annular preventers are available for working pressures of 2000, 5000 and 10000 psig.
Both the ram and annular BOPs are closed hydraulically.
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3.6 Well monitoring System
Safety and efficiency considerations require constant monitoring of the well to detect drilling problems quickly.
Devices record or display parameters such as depth, penetration rate, hook load, rotary speed, rotary torque, pump rate, pump pressure, mud density, mud temperature, mud salinity, gas content of mud, hazardous gas content of air, pit level and mud flow rate.
In addition to assisting the driller in detecting drilling problems, good historical records of various aspects of the drilling operation also can aid geological, engineering, and supervisory personnel.
This unit provides detailed information about the formation being drilled and uids being circulated to the surface in the mud as well as centralizing the record keeping of drilling parameters.
The mud logger carefully inspects rock cuttings taken from the shale shaker at regular intervals and maintains a log describing their appearance.
These systems are especially useful in monitoring hole direction in non-vertical wells.
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Chapter 3: DRILLING FLUIDS
Drilling fluid or also called drilling mud is a mixture of water, oil, clay and various chemicals.
Drilling fluid is a fluid used to aid the drilling of boreholes into the earth.
The three main categories of drilling fluids are water-based muds ,oil-based mud, and gaseous drilling fluid, in which a wide range of gases can be used.
The main functions of drilling fluids include providing hydrostatic pressure to prevent formation fluids from entering into the well bore, keeping the drill bit cool and clean during drilling, carrying out drill cuttings, and suspending the drill cuttings while drilling is paused and when the drilling assembly is brought in and out of the hole
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The drilling fluid used for a particular job is selected to avoid formation damage and to limit corrosion.
Drilling fluid is used in the rotary drilling process to:
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Circulate (clean) the cutting and remove them out of hole
(2) Cool and lubricate the bit
(3) Control formation pressures
(4) Minimizing formation damage
(5) Support of Weight of Drill Pipe and Casing.
(6) Maximise penetration rates
3.1 Functions of Drilling Fluids
In the early days of rotary drilling, the primary function of drilling fluids was to bring the cuttings from the bottom of the hole to the surface. Today it is recognized the drilling fluid has at least ten important functions:
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3.1.1 Removal of Cuttings
The removal of cuttings from the face of the well bore is still one of the most important functions of drilling fluids.
Fluid flowing from the bit nozzles exerts a jetting action that keeps the face of the hole and edge of the bit clear of cuttings.
This insures longer bit life and greater efficiency in drilling.
The circulating fluid rising from the bottom of the well bore carries the cuttings toward the surface.
The effectiveness of mud in removing the cuttings from the hole depends on several factors.
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3.1.2 Cooling and Lubrication
Heat is generated from mechanical and hydraulic forces at the bit and when the drill string rotates and rubs against casing and wellbore.
Cool and transfer heat away from source and lower to temperature than bottom hole.
If not, the bit, drill string and mud motors would fail more rapidly.
Lubrication based on the coefficient of friction.
Oil and synthetic based mud generally lubricate better than water-based mud.
Amount of lubrication provided by drilling fluid depends on type & quantity of drill solids and weight materials plus chemical composition of system.
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3.1.3 Control formation pressures
If formation pressure increases, mud density should also be increased, often with barite (or other weighting materials) to balance pressure and keep the wellbore stable.
Unbalanced formation pressures will cause an unexpected influx of pressure in the wellbore possibly leading to a blowout from pressured formation fluids.
Hydrostatic pressure = density of drilling fluid × true vertical depth × acceleration of gravity.
If hydrostatic pressure is greater than or equal to formation pressure, formation fluid will not flow into the wellbore.
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3.1.4 Minimizing formation damage
Skin damage or any reduction in natural formation porosity and permeability (washout) constitutes formation damage.
Most common damage; Mud or drill solids invade the formation matrix, reducing porosity and causing skin effect.
Swelling of formation clays within the reservoir, reduced permeability.
Mud filtrate and formation fluids form an emulsion, reducing reservoir porosity.
Specially designed drill-in fluids or workover and completion fluids, minimize formation damage.
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3.1.5 Support of Weight of Drill Pipe and Casing
With increasing depths, the weight supported by the surface equipment becomes increasingly important.
Since a force equal to the weight of mud displaced buoys up both the drill pipe and casing, an increase in mud density necessarily results in a considerable reduction in total weight, which the surface equipment must support.
Equally, if the casing is not completely filled up during running, some of the hook load is alleviated and the string can be ”floated in”.
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3.1.6 Maximise penetration rates
The drilling fluid is so intimately involved in the drilling process that it is inevitable that a wide range of fluid properties will influence the rate of penetration, apart from the mechanical considerations, such as the type of bit, weight on the bit and rate of rotation.
Fluid properties, such as low viscosities at high shear rates, low solids, high fluid loss and lower densities than are required to balance pore pressure, all contribute to faster penetration rates.
It can be seen that some of the properties, such as high fluid loss and under balance fluid densities are contradictory to the properties required for a stable hole, and a compromise must be reached.
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3.2 Types of Drilling Fluids
Many types of drilling fluids are used in industry. Major categories include air, water- and oil base fluids.
Each has many subcategories based on purpose, additives, or clay states. (see Figure 4-2)
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3.2.1 Water Based Muds
Water based Muds (WBMs) are used to drill approximately 80% of all wells.
The base fluid may be fresh water, seawater, brine, saturated brine, or a formate brine.
The type of fluid selected depends on anticipated well conditions or on the specific interval of the well being drilled.
For example, the surface interval typically is drilled with a low-density water- or seawater-based mud that contains few commercial additives.
These systems incorporate natural clays in the course of the drilling operation.
Some commercial bentonite or attapulgite also may be added to aid in fluid-loss control and to enhance hole-cleaning effectiveness.
After surface casing is set and cemented, the operator often continues drilling with a WBF unless well conditions require displacing to an oil- or synthetic-based system.
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3.2.2 Oil Based Muds
Oil-based systems were developed and introduced in the 1960s to help address several drilling problems:
-Formation clays that react, swell, or slough after exposure to WBMs
-Increasing downhole temperatures
-Contaminants
-Stuck pipe and torque and drag
Oil-based Muds (OBMs) in use today are formulated with diesel, mineral oil, or low-toxicity linear olefins and paraffins.
The olefins and paraffins are often referred to as ”synthetics” although some are derived from distillation of crude oil and some are chemically synthesised from smaller molecules.
The electrical stability of the internal brine or water phase is monitored to help ensure that the strength of the emulsion is maintained at or near a predetermined value.
The emulsion should be stable enough to incorporate additional water volume if a downhole water flow is encountered.
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4.3 Properties of Drilling Fluids
Drilling Fluid Properties related to its performances such as Density, Viscosity, pH concentration and other properties.
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3.3.1 Mud Balance
Density, or Mud Weight is weight per unit of volume.
Once the density is determined it may be expressed in any convenient unit; for example, in pounds per gallon (lb/gal or ppg), pounds per cubic foot (lb/ft3).
Specific Gravity (SG), or in pressure gradient as pounds per square inch per 1,000 feet (psi/1, 000 ft) of mud in the hole.
Normal pressure gradient by water is equal to (0.433 psi/ft) and equal to 433 psi/1000 ft.
The latter unit is most convenient because it may be readily used to calculate the hydrostatic head of the mud column for any depth of hole in the same units in which the pump pressure and the reservoir or formation fluid pressure are calculated.
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This facilitates control when excessive formation pressure or lost circulation is encountered. The conversion factors are as follows:
The mud balance (Fig.4-3) provides the most convenient way of obtaining a precise volume. It consists of a supporting base, a cup, a lid, and a graduated arm carrying a sliding weight. A knife edge on the arm rests on the supporting base.
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Example 3-1:
If the mud reading is 1.20 SG.
then, it equals 10:0 lb/gal = 74.8 lb/ft3 = 519 psi/1; 000 ft of depth.
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4.3.2 Marsh Funnel
The time required for a mud sample to flow through a Marsh funnel is rapid test of the consistency of a drilling fluid. The test consists essentency of filling the funnel with a mud sample and measuring the time required for 1 quart of the sample to flow from the initially full funnel into the mud cup. The funnel viscosity is reported in unit of second per quart. Fresh water at 75◦F has a funnel viscosity of 26 s/qt.
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The flow rate from the marsh funnel changes significantly during the measurement fluid level in the funnel. This causes the test results to become less meaningful for non-Newtonian fluids, which exhibit different apparent viscosities at different flow rates for a given tube size. Unfortunately, most drilling fluids exhibit a non-Newtonian behavoir. Thus, while the funnel viscometer can detect an undesirable drilling fluid consistency, additional tests usually must be made before an appropiatemus treatment can be prescribed.
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3.3.3 The Rotational Viscometer
The rotational viscometer can provide a more meaningful measurement of the rheological characteristics of the mud then marsh funnel.
Six standard speeds plus a variable viscometer shown in Fig.4-4.
Only two standard speeds are possible on most models designed for field use.
The dimensions of the bob and rotor are chosen so the dial reading is equal to the apparent Newtonian viscosity in centipoise at rotor speed of 300 rpm.
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At other speeds, the apparent viscosity, µa , is given by
where θN is the dial reading in degrees and N is rotor speed in revolutions per minute.
The viscometer also can be used to determine rheological parameters the describe non-Newtonian fluid behavoir.
At present, the flow parameters of the Bingham plasic rheological model are reported on the standard API drilling mud report.
Two parameters are required to characterize fluids that follow the Bingham plastic model.
These parameters are called the plastic viscosity and yield point of the fluid. The plastic viscosity , µp , in centipoise normally is computed using
where θ600 is the dial reading with the viscometer operating at 600 rpm and θ300 is the dial reading with viscometer operating at 300 rpm.
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The yield point, τy , in lbf/100 sqft normally is computed using
A third non-Newtonian rheological parameter called gel strength, in unit of lbf/100 sqft , is obtained by noting maximum dial deflection when the rotational is turned at a low rotor speed (usually 3 rpm) after the mud has remained static for some period of time.
If the mud is allowed to remian static in viscometer dial deflection obtained when the viscometer for a period of 10 seconds, the maximum dial deflection obtained when the viscometer is turned on is reported as the initial gel on the API mud report form.
If the mud is allowed to remain static for 10 minutes, the maximum dial deflection is reported as the 10-min gel.
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Example 3-2:
A mud sample in a rotational viscometer equipped with a standard tor- sion spring gives a dial reading of 46 when operated at 600 rpm and a dial reading of 28 when operated at 300 rpm. Compute the apparent viscosity of the mud at each rotor speed. Also compute the plastic viscosity and yield point.
solution
Use of Eq. 4.3 for the 300 rpm dial reading gives
Similarly, use of Eq. 4.3 for the 600-rpm dial reading gives
Note that the apparent viscosity does not remain constant but decreases as the rotor speed is increased. This type of non-Newtonian behavior is shown by essentially all drilling muds. The plastic viscosity of the mud can be computed using Eq. 4.4:
The yield point can be computed using Eq. 4.5:
3.3.4 pH Determination
The term pH is used to express the concentration of hydrogen ions in an aqueous solution. pH is defined by
where [H+] is the hydrogen ion concentration in moles per liter. at room temperature, the ion product constant of water, Kw , has a value of 1.0x10-14 mol/L. Thus, for water
For pure water,[H+] = [OH-] = 1.0x10-7 and the pH is equal to 7.
Since ,in any aqueous solution the product [H+] [OH-] must remain constant ,an increase in [H+] requires a corresponding decrease in [OH-].
A solution in which [H+] > [OH-] is said to be acidic, and a solution in which[OH-] > [H+] is said to be alkaline.
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The relation between pH, [H+] , and [OH-] is summarized in Table
The pH of a fluid can be determined using either a special pH paper or pH meter.
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Example 3-3:
Compute the amount of caustic required to raise the pH of water from 7 to 10.5. The molecular weight of caustic is 40.
Solution:
The concentration of OH− in solution at given pH is given by
The change in OH− concentration required to increase the pH from 7 to 10.5 is given by:
Since caustic has a molecular weight of 40, the weight of caustic required per litre of solution is given by
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3.4 Mud Weight Calculation
Additives are added to the drilling fluid in order to bring the fluid parameters to required values.
Density and viscosity are the two most basic parameters to control.
The drilling fluid technician or engineer should carry some calculations, and laboratory measurements and tests to determine the correct additive and the correct amount to be mixed to the fluid system.
Fluid volumes are normally measured in barrels. Useful conversion factors are:
Powder and dry additives are normally measured in pounds, and liquid additives are normally measured in gallons or barrels.
Pilot tests are lab- oratory (small scale) tests that aim to determine the amounts of additive required to bring some fluid parameters to determinate values.
Small scale tests are fast and cheap to perform.
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A handy conversion for is that of lbm/bbl to g/cm3 :
Therefore, in a pilot test with 350 ml of fluid, 1 gram of added additive corresponds to the addition of 1 lbm of dry additive to 1 barrel of fluid.
A similar conversion shows that 25 ml of liquid additive in 350 ml or fluid corresponds to 3 gallons of additive per barrel of fluids.
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3.4.1 Density Calculations
It is frequently necessary to compute the density of a mixture from the amount of the substance in the mixture.
It is also important to be able to calculate the amount to be added of a given substance in order to increase or decrease the density of the mixture.
The density and specific gravity of some common substances used in drilling fluids are shown in following table:
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The assumption that the mixture is ideal, that volume of the mixture is equal to the volume of the components (not valid for highly soluble substance like NaCl in water) facilities the volume-density calculations.
The relations are
where Vmix is the volume of the mixture and Vi is the volume of the component i of the mixture, and
where M is mass and ρ is density. In general, the final density of a mixture of sunstances ( assuming ideal mixture) is:
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Example 3-4:
Calculate the volume and density of a fluid composed of 25 lbm of bentonite, 60 lbm of barite, and 1 bbl of fresh water.
solution:
The volume and the mas of the mixture are:
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Mixing Fluids of Different Densities
If two substances having different densities are mixed then the density of the mixture is a function of the quantity and density of the components of the mixture.
This relationship can be expressed as follows:
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Case #1: No limit is placed on volume:
Example 4-5:
Determine the density and volume when the two following muds are mixed together.
V1 = 400 bbl ρ1 = 11.0 ppg
V2 = 400 bbl ρ2 = 14.0 ppg
Solution:
Using Eq.4.10 to Final density and volume:
Therefore, Final Volume = 800 bbl & Final Density = 12.5 ppg
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Case #2: A limit is placed on the desired volume:
Example 4-6:
Determine the volume of 400 bbl of 11.0ppg mud and 400bbl 14.0 ppg mud required to build 300 bbl of 11.5 ppg mud.
Solution:
Let V1 = bbl of 11 ppg mud
V2 = bbl of 14.0 ppg mud
then,
Therefore, V2 = 50 bbl of 14.0 ppg mud
V1 + V2 = 300 bbl
V1 = 300−50 = 250 bbl of 11 ppg mud
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3.4.2 Density Control Computation
The density control of a drilling fluid is obtained usually with use of barium sulfate (BaSO4) commonly called barite.
The specific gravity of pure barite is 4.5, and the average specific gravity of API barite is 4.2, or 35 lbm/gal.
When excess storage capacity is not available and to limit the amount of added, the density increase will required discarding a portion of the mud.
In this case the proper volume of old mud should be discarded before adding weight material. For ideal mixing the mud, V1, and weight material ,VB must sum to the desired new volume,V2:
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Likewise, the total mass of mud and weight material must sum to the desired density-volume product:
Solving these simultaneous equations for unknowns V1 and mB yields
when the volume of mud is not limited, the final volume can be calculated from the initial volume by rearranging Eq. 4.12
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and
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Example 4-7:
It is desired to increase the density of 200 bbl of 11 lbm/gal mud to 11.5 lbm/gal using barite. The final volume is not limited. Compute the weight of barite required.
solution:
From table the density of barite is 35.0 lbm/gal. using Eq. 4.14, the final volume V2 is given by
using equation 4.14, the weight of barite required is given by
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The addition of large amounts of barite to the drilling fluid can cause the drilling fluid become quite viscous. The finely divided barite has extremely large surface area and can adsorb a significant amount of free water in the drilling fluid. This problem can be overcome by adding water with the weight material to make up for the water adsorbed on the surface of the finely divided particles. However, this solution has disadvantage of requiring additional weight material to achieve a given increase in mud density because the additional water tends to lower the density of the mixture. Thus, it is often desirable to add only the minimum water required to wet the surface of the weight material. The addition of approximately 1 gal of water per 100 lbm of barite is usually sufficient to prevent unacceptable increase in fluid viscosity. Including a required water volume per unit mass
of barite, VwB, in the expression for total volume yields:
Likewise, including the mass of water in the mass balance expression givens
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solving these simultaneous equations for unknowns V1 and mB yields:
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Reduce mud weight by dilution
The process of adding fresh mud (or liquid phase) in order to reduce the solids content and maintain the properties of the drilling uid in the active system.
Case #1: No limit is placed on volume:
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