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DRILL STRING DESIGN PROJECT

SUMMARY

The design of the drill string was thoroughly investigated in this project research write up. Particular reference studies were carried out in order to understand the basic Engineering requirements, principles and techniques required in the design of the drill string as a vital tool in the drilling processes employed in the oil exploration industry. Essential design consideration, calculations based on the standard requirements were looked into as well as the mechanical properties of designed tools making up different components of the drill string. This phase is tailored to the design of a drill string which would be suitable in the drilling of wells of over 8 km displacement ERD, (Extended Reach Drilling).

The choice of materials is dependent on the formation strata and different formation intervals and the environment; soft and hard formation is considered in this design. The drill string reliability plays important role in providing Extended Reach Drilling well construction success as a whole. Careful considerations were made in deciding the nature and types of well parameter utilised. A sequence view of well trajectory and sections of the well bore were investigated for effective tensile strength consideration to avoid fatigue build up and failure, which could cause buckling on the drill string and its components. Directional horizontal well drilling is a significant breakthrough achieved in the drilling industry, modern facilities has been used; manufacturers usually work in tandem with companies to make certain that opportunities for design review are identified and implemented.

Extended-reach (ER) drillstring involves making a selection from different variety of available drillstring components that are suitable to drill an extended reach well. The torsional loads should be higher than the tension loads which will be lower than that obtainable for a vertical well of the same measured depth. Differences in applied loads and the need to apply the bit weight with normal weight drill pipe presented a design as well as operational difficulty that were considered in this phase of the project. The use of improved grade steel and its application to the design of the drill string is equally essential.

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INTRODUCTION

The design of a drill string is an important phase in the process of oil exploration production, drilling and completion. Drill string is an essential part of the rotary drilling operation process and procedure. The connection between the rig and the drill bit is the drill string, although it equally contributes to problems such as washouts, collapse failures, and twist – offs, its design could systematically avoid most of these problems. A drill string turns, a bit creates a hole in the earth’s surface or in a seabed, and drilling fluid carries cuttings to the surface. Drill string extends through the water from the rig to the borehole. Selecting a drill string design that is resistant to wear and wear damages is equally essential, in addition to planning a well bore trajectory which will limit wear at the same time. Designing a larger but stronger drill strings thus prevent the accumulation of fatigue, increases hydraulic parameters and the control of hole deviation difficulties. The bottom hole assembly, (BHA) should be designed, such that it can withstand sufficient load and tension influence to eliminate connection failures and provide far superior deviation control and weight concentration directly above the drill bit. The use of stronger box connections insure against developing fatigue cracks and premature failures, in the design of suitable drill string (William. C. Lyons, 2005). The drill string should be designed to be able to endure the complex stresses which occur in the event of all drilling operations and convey the flushing medium to the bottom of the borehole.

PURPOSE AND COMPONENT OF THE DRILL STRING

The drill string could serve several purposes to include the following: (a). It provides a fluid conduit from the drilling rig to the drilling bit. (b). Impartation of rotary motion to the drill bit. (c). It allows weight to be set on the bit. (d). It is designed to lower and raise the bit in the well.

The following will be topics will be examined and discussed in the design of the drill string:

Kelly Drill Pipe Drill collars Accessories; Heavy wall drill pipe HWDP, Jars, Stabilizers, Reamers, Shock

sub and Bit sub. Drill Bits and Bottom Hole Assembly

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Figure 1: Component of the Drill String (Modified from Diaz. P., 2011)

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KELLY

Basic component of a Kelly-drive rotary drilling rig are the derrick and hoist, Kelly, turn-table, drill pipe, bit and pump. The drill pipe comes in lengths that are joined together with respect to the well depth. Connected to the top joint of the drill pipe is the Kelly which is a hollow splined shaft which runs through the turn-table and the Kelly bushing, which is grooved to fit the spines on the Kelly. The Kelly is free to move up and down when rotated by the turntable. The following are the characteristics and functions of the Kelly:

1. It is used to transmit rotation and weight to the bit via the drill pipe and drill collar.

2. Rotation and weight on the bit are necessary for the breaking down of rocks and making holes.

3. The lengths are about 40 ft (12.2m) or 54 ft (16.5m) 4. The shape is hexagonal or square; Hexagonal is stronger than the square

shaped. 5. They are manufactured from high grades of chrome molybdenum steel which

are subjected to heat treatment and are manufactured in various sizes as shown in the table below:

Table 1: Showing Sizes of standard Kelly.

Hexagonal Square 3 2 2 3

4 2

4 4

6 4

6

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KELLY ACCESSORIES

Kelly saver sub: This is a small sub connected to the Kelly at the bottom to protect its threads from excessive wear.

Kelly cock: This is a small sub that is installed on top of the Kelly or below the saver sub to primarily protect equipment above Kelly from the effect of high pressure. Also used to shut in drill pipe in the event of kick.

Upper Kelly cock: The upper Kelly cock is installed between the swivel and the Kelly. It protects the equipment above the Kelly in emergencies and stops the flow of fluids up the drill stem.

Lower Kelly cock: It is installed below the Kelly and is like a standby safety valve for blowout prevention (BOP).

Kelly saver sub: This is short threaded pipe that fits below the Kelly which minimizes wear on the Kelly’s threads.

The master bushing performs two jobs: 1. During drilling operation, it connects the rotary table to the Kelly bushing and

transfers rotation from one to the other. 2. When drilling stops, the master bushing holds the slips.

DRILL PIPE The drill pipe is a seamless pipe with threaded connections, known as tool joint;

most tool joints are made from AISI 4140 steel forgings, tubing or bars stock. The

major portion of the drill string is the drill pipe, which consists of three components: a

tube with a pin tool joint that is welded to one end and a box tool joint welded to the

other.

Drill pipes are subjected to heat treatment to improve its strength as defined by API

specification. The drill pipe is the longest section of the drill string, which transmits

rotation and drill mud under pressure to the bit. The drill pipe is subjected to different

types of loading conditions: a). Axial stress; due to the weight carried and its own

weight. b). Radial stress; due to the well bore pressure. c) Cyclic stress reversal due

to bend in the dog legs.

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The drill pipe must be able to withstand all these loads. It is manufactured as

seamless pipe with external upset (EU), internal upset (IU) or internal external upset

(EIU). An upset is an increment in the metal size. The drill pipe is manufactured in

three ranges: Range 1, (18-22ft), Range 2, (27-30 ft), Range 3, (38-45). There are

five grades of drill pipe available but an improvement grades has been used in

drilling processes as this project utilises the improved type of drill pipe of 5 in., 25.60

lb/ft.

DRILL PIPE SELECTION

The Drill pipe is to provide a fluid conduit for pumping drilling mud, imparting rotary

motion to the bit and for drill stem testing and squeeze cementing. Basic factors for

consideration in drill string design includes: collapse, tension, dogleg severity and

slip crushing. Collapse together with tension primarily applies to weight selection,

grades and couplings. High- strength pipe is required in the lower sections of the drill

string for collapse resistance. Tension is considered to dictate the higher strength at

the top of the well. “Classes” are given to dill pipes to drill pipe to account for its

weight, grade and class. The established guidelines by API for pipes selection is

given below in (table 3). Drill pipe classification is an essential factor in designing a

drill string; the amount and type of wear affect the properties of the pipe and its

strengths.

Table 2: Classes of Pipes and their Properties.

Classes of Pipes Properties

New Never been used, No wear.

Premium Uniform wear and a minimum wall thickness of 80%.

Class 2

Allows drill pipe with a minimum wall thickness of 65% with all wear on one side so long as the cross-sectional area is the same as premium class; that is to say based on not more than 20% uniform wall reduction.

Class 3 Minimum wall thickness of 55%, all wear on the side.

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DRILL PIPE DATA

GRADES OF DRILL PIPE AND STRENGTH PROPERTIES

Table 3: Showing Grades of Drill Pipes. (William. C. Lyons et al 2005)

Grades Yield Strength, psi Tensile Strength, psi

E-75 75,000 100,000

X- 95 95,000 105,000

G -105 105,000 115,000

S-135 135,000 145,000

VM -150IEU 150,000 160,000

V-150 grade drill pipe provides 11% greater tensile strength as compared to the S-135 grade, while maintaining better impact in terms of strength. High toughness values, allows total confidence when running V-150. This drill pipe with high strength, has enabled drilling of today’s deepest wells. Basic specification data is shown in table 3 below.

DRILL COLLAR

Short Drill collars are usually made to suit the basic material parameters such as

sizes, properties and features. They appear in various lengths in slick or spiral. The

standard length for short drill collars are 10, 12, 15.1/2 and 20 feet long. Drill collars

are the main components of the bottom-hole assembly.

The functions of the drill collar are as follows:

- It provides weight for the bit as well as strength needed in compression, minimises

bit stability problems such as wobbling, jumping and vibrations.

- It provides stiffness to the Bottom-hole assembly (BHA) hence reduces directional

control problems.

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Selecting the right drill collars and BHA basically prevents many drilling problems.

They are available in many sizes and shapes, such as square, round, spiral grooved

and triangular. Most common types are the round (slick) and spiral grooved.

Choosing large collars requires fewer drill collars for required weight, fewer drill collar

connections are required, straighter holes can be drilled, less time is lost handling

drill collars during trips.

Figure 2: Schematic picture of a drill collar.

SELECTION OF DRILL COLLARS SIZE

The most important factors to be considered in selection of drill collar size are:

(a). Size of Bit, and (b). Coupling diameter of the casing to be set in the hole.

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The first section of the drill string to be designed is the drill collars. The drill collar

length and its size affect the type of drill pipe that must be used. Buckling effect in

the lower sections of the drill string when weight is set on the bit should be

considered. Sufficient amount of drill collars is used to avoid running the drill pipe in

compression.

DRILL COLLAR CONNECTIONS AND TOOL JOINTS According to (William. C. Lyons 2005), the current practice is to select a rotary shoulder connection which will provide a balanced bending fatigue resistance for the pin and the box. Empirically, the pin and boxes have approximately equally bending fatigue resistance provided the section modulus of the box at critical zone is 2.5 times the section modulus of the pin when at its critical zone. The bending strength ratio (BSR) is denoted by this number.

Figure 2: Drill Collar connection. (Modified from William. C. Lyons 2005). Section modulus, Zb, of the box should be 2.5 times greater than the section modulus, Zp, of the pin in a drill collar connection. On the right side of the connection are spots at which the critical area of both the pin (Ap) and (Ab) should be measured for calculating torsional strength. The section modulus ratio ranges from 2.25 to 2.75 are typically good. In abrasive or corrosive conditions, as corrosion decrease the

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fatigue resistance of materials should be considered whilst deducing the bending strength ratio of the connections. TOOL JOINT DATA Tool joints are short cylindrical piece attached to each end of the drill pipe via a flash weld or inertia weld process. They are threaded internally or externally, the external threaded are called the pin while the internally threaded toll joints are known as the box, joined by stabbing the pin to the box. The thread should posses minimum yield strength of 120,000 psi and a minimum tensile strength of 140,000 psi to withstand loading fatigue. Standard dimensions are utilised to determine the approximate weight of the drill pipe and the tool joint assembly. According to (William. C. Lyons 2005), Drill pipes are connected together individually with the aid of tool joints as defined by the API (American Petroleum Institute). For the purpose of this design NC connection is used. Table 4: Showing NC 50 Connection Properties. (Modified from William. C., 2005) Internal Pressure, (psi) 17,105

Collapse Pressure, (psi) 15,672

Connection Type

NC50

Outside Diameter, OD (in.) 8 Inside Diameter, ID (in.) 4 Torsional Yield Strength, (ft-lb) 63,400

Tensile Yield Strength, (lb.) 1,551,700

Make up Torque, (ft-lb) 32,900

Torsional Ratio Tool joint to Pipe

0.86

Pin Tong Space, (in.) 9

Thread Per inch 4

Taper, (in/ft) 2

Thread Form V-0.38R

Internal Flush, IF. 2

TORQUE FOR DRILL COLLARS According to (William. C. Lyons 2005), high torque is required by the rotary shouldered connections to prevent the makeup shoulders from separating downhole, shoulder separation usually occurs when rotating doglegs, or when drill collars tend

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to buckle due to compressive loads upon it , or when at the application of tensile loads to the drill collars. High torque in the rotary shouldered connection is important because the makeup shoulder is the only seal in the connection, threads do not seal in the connection, since they are designed with clearance between the crest of one thread and the root of its mating thread. The shoulder load must be high enough to create a compressive stress at the shoulder face, with the capacity to offset the bending that occurs due to buckling of the drill collar, to keep shoulders together. DRILL COLLAR BUCKLING Drill collar remain straight in vertical hole under no load condition, with no load on the bit. As soon as the weight on the bit is increased, compressive loads are therefore introduced into the collars; the highest compressive load is just above the bit, which decreases to zero at the neutral point. Increasing the weight further, the drill collars or the drill pipe tend to buckle and contacts are made to the borehole at two points. Further increase in weight on the bit, the third and higher order of buckling occurs. It is essential to address buckling problems, because the drill string will be in compression over some interval. Subjecting the pipe to compressive loads, the pipe undergoes at some stage changes in its configuration. Primarily, the first stage of buckling is known as sinusoidal buckling. The pipe at this stage assume a 2-dimensional waveform shape, winding back and forth along the bottom of the wellbore, increasing the compressive forces further, helical post buckling occurs- second stage. Drag occurs as there is wall contact area between pipe and the wellbore, thereby requiring more axial load to balance up the same bit weight. Adding more load causes high contact force which increases further the drag. Helical post buckling should be avoided.

DRILL BITS AND BOTTOM HOLE ASSEMBLY

Major design will not be dealt with here but a brief description of the functions of the bit will be emphasized. The primary downhole tool is the drill bit capable of cutting up formation as it rotates. Diamond bits are used for hard formations. Most commonly used today are the tri-coned steel-teethed bits.

According to (William. C. Lyons et al 2005), Tungsten carbide is one of the hardest materials known to man. This hardness is utilised for cutting and abrasion resisting material for bits. The comprehensive strength of tungsten is much higher its tensile strength, drill bit cutting elements are normally made of tungsten carbide bearing inserts. The surfaces of the drill bits are protected against wear with Hardfacing materials which contain tungsten carbide grains which are standard tension and shear.

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DRILL STRING DESIGN SECTIONS

According to (Johancsik, C. A. et al 1984), the drill string consisted of six sections as seen in figure below.

Figure 3a: Horizontal well sections.

Figure 3b: Drill String Design Section for Horizontal Wells. (Modified)

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Section I

This is the section that controls the hole trajectory, but does not contribute to the weight on the bit. This consisted of the bottom hole assembly, including the bit, motor non magnetic collars and MWD tool. The section is considered and kept as light as possible to minimize drag and torque.

Section II

This is the horizontal section that transmits axial and torsional loads during drilling or tripping, and supports compressive loads without buckling. It also a light weight section to minimize torque as well as drag. Basically, this section is typically the section with the largest outside diameter conventional drill pipe available.

Section III

In this section, the pipe must be able to transmit axial and torsional loads, as well as sustaining potentially large bending stress induced by the action of the rotating in up section rate. This is the lower build section of 60o - 90o. Since most of the pipe weight in this high inclination section lies on the side of the hole as such contributes very little weight on the bit structure. The pipe is usually the heavy drill pipe. The used of pipe V-150 grade is used here because of its significant increased fatigue strength, an improvement over the S-135 grade commonly used.

Section IV

This is the upper build section ranges between 0o – 60o inclination angle, the pipe in this section must be able to withstand and resist buckling and bending stresses imposed by rotary action in the build up section. The pipe does not benefit from the side wall support available at higher angles of hole inclination. The weight of the pipe as well contributes significantly to the weight on the bit. Heavy weight drill pipe is used or the drill pipe may be used provided there exist a tangent section.

Section V

Vertical well bore above Kick off point: this section produces the remaining weight required on the bit, (after section IV) has been accounted for and usually is the drill collar or the Heavy wall drill pipe. The collars are kept above the KOP if in use to reduce their exposure to higher doglegs minimizing the risk of fatigue failure. This section contributes very little to the drag and torque effects. When drill collars are used in this section The hydraulic must be well defined.

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Section VI

The vertical portion to the surface: The drill string is subjected to tension in this section. The designed pipe should be capable of supporting tensile and torsional loads of drilling and tripping, with adequate margin of overpull. Torque, drag, hydraulics and convenience of rig operation are considered in this section.

DESIGN CRITERIA AND APPROACH Drill string design for horizontal wells is complex, which requires running the drill string in compression to transmit weight to the drill bit through the horizontal section. Drill string should be designed to provide the required weight on bit. DRILL COLLAR DESIGN CALCULATION The Buoyancy Factor Method and the pressure-area method satisfy the criteria above. STEP 1: From the Field Data: Reservoir Pressure = Hydrostatic Pressure (HP) = 2897 psi True Vertical Depth = 6500 ft (i). Determine the Pressure Gradient

TrueVerticalDepthTVD,ft ………………. (1)

6500 = 0.44 psi (ii). Determine the Mud Weight:

Density of Steel s) = 65.5 ppg

0.052………………. (2)

0.052

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= 8.462 = 8.5 ppg (iii). The Buoyancy Factor (BF) equivalent to Mud Weight:

s,ppg ……………………………. (3)

65.5 = 0.869 Where, MW = the Mud Weight,

s = Density of Steel. (iv). Determining the Weight of the Drill Collar in Air, WDC.

Drill Collar Specifications: 4 in. 16 in. Length of standard Drill Collar = 31 ft

0.2945 ……………………………... (4)

4(OD2 – ID2) ……………………………...……… (5)

4(7.252- 2.8125)

ADC = 35.07 in2

0.2945

0.2945

= 119.09 lb/ft (v). KICK OFF POINT, KOP. The Kick off point is a distance 2000ft from the surface. The true vertical depth of the well TVD = 6500 ft. The Hole angle of inclination ∝ is 20 degrees, therefore, the distance from KOP to MD = 4500 ft. represented by distance BD below. is shown in figure

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A 2000 ft B KOP 6500 ft ∝ 20° C D Figure 4: Free hand Sketch of trajectory and angle of departure for drill string. AC = TVD = 6500 ft AD = measured Depth AB = Distance from the surface location to the KOP = 2000 ft BC = Distance from KOP to the true vertical Depth, TVD BD = Distance from KOP to the bottom of the hole, (MD) = 4500 ft CD = Deviation or Departure- Departure of the wellbore from the vertical To calculate the deviation (CD), ft: Distance CD, ft = sin∝ BD........................................................................... (6) KOP at 2000 ft, MD = 4500 ft Therefore, CD = sin 20° 4500 = 1539.09 ft. Measured Depth, MD = 1539 ft away from the vertical.

DRILL COLLAR’S LENGTH CALCULATION

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STEP 2:

(i). Determine the Available Weight on the Bit in Directional Well: Using the formula: P = W cos ∝ ..................................................................... (7) Where P = Partial weight available for the bit, ∝ = Inclination Angle, W = total weight of collars based on the formation is taken as 45000 lbs Hence, P = 45000 cos 20° = 42286.167 42286 lbs NOTE: The Partial available weight on the bit, P is represented as W in the next formula used to deduce the length of the drill collars.

(ii). Determine the Length of Drill collar using:

∝ ……………………………………………………............... (8)

Where, LDC = Length of Drill Collar, DF = Design Factor = 1.3, WDC = Weight on Drill collar in air, W = Desired Weight on Bit from standard specification = 42,000 lb, BF = Buoyancy Factor = 0.869, Hole deviation from the vertical,∝ = 20°

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119.09 0.869 0.9397

= 565.269

565 ft

The number of Joints required can be calculated thus:

Number of Joints = Length of Drill Collar/Standard Length of Drill Collar

= 565/31

= 18.23

18 joints

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The standard drill collar length = 31ft,

Hence, the length of the designed drill collar = 558 ft,

Weight of Drill Collar in Air = Weight in air Length........................................... (9) = 119.09 x 558 = 66452 = 66,452 lbs (iii). Determining the Weight of Drill Collar when immersed in mud: Weight of Drill Collar in Mud = Weight in air, WDC x Buoyancy Factor, BF.............. (10)

= 66452 x 0.869 = 57747 lbs

STEP 3:

TENSION LOAD ON DRILL STRING AND PIPE IN THE VERTICAL SECTION

Tension Load:

The tensile resistance of drill pipe usually derated by a design factor (i.e. divide the

tension rating by 1.15). The tension loading can be calculated from the known

weights of the drill collars and drill pipe below the point of interest. The effect of

buoyancy on the drill string weight, and therefore the tension, must also be

considered. Buoyancy forces are exerted on exposed horizontal surfaces and may

act upwards or downwards. These exposed surfaces occur where there is a change

in cross-sectional area between different sections (Diaz. P. 2011).

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Figure 5: Schematic diagram of Tension Load on Drill String. From (Diaz. P.

2011).

To Calculate the Buoyancy Forces for the Pressured-Area

Buoyancy Force, F1 = Pressure Area........................................................... (11)

Area of Drill Collar, ADC = 35.07 in2

True Vertical Depth = 6500 ft

Mud Weight, MW = 8.5 ppg

Pressure = - (0.052 MW TVD)…………………………………………............. (12)

P = - (0.052 8.5 6500)

= - 2873 psi

Therefore, F1 = - P A

F1 = - 2873 35.07

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= - 100756 lbs

Buoyancy Force, F2 = Pressure Area;

Pressure, P = (0.052 8.5 (6500 – 558)

= 2626 psi

4(IDDP2 – IDDC

2)................................ (13) Where,

ODDC = Outer diameter of Drill Collar

ODDP = Outer diameter of Drill Pipe

IDDP = Inner diameter of Drill Pipe

IDDC = Inner diameter of Drill Collar

4(IDDP2 – IDDC

2)}

4(42 – 2.81252)}

= 28.00 in2

Buoyancy Force, F2 = 2626 28.00

F2 = 73528 lbs

W1 = No of Drill Collars Weight of Drill Collars

= 18 119.09 31

= 66452 lbs

Approximate Weight of Drill Collar = 24.50 lb/ft

Drill Collar New Depth = (6500 – 558) ft

= 5942 ft

W2 = Drill Collars New Depth Approximate Weight of Drill Collars

= (5942 24.50)

= 145579 lbs

Hence,

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Available Bit Weight, ABW = F1 + F2 + Drill Collar Weight in air......................... (14)

= -100756 + 73528 + 66929

= 39701 lbs

TENSION ON THE BODY Calculating the tension at the top and bottom of each section:

Tension at the bottom of collars, T = F1 = -100756 lbs

Tension at top of collars, T = -100756 + 66452 = - 34304 lbs Tension at bottom of drill pipe, T = - 34304 + 73528 = 39224 lbs Tension at top of drill pipe, T = 39224 + 145579 = 184803 lbs Considering 85% tension loading: Tensile Yield Strength of pipe V- 150 grade = 1060300 lbs, obtained from table 5. Then the maximum allowable load = 0.85 x 1060300 = 901255 lbs

Table 5: Showing Tension Load Line

TENSION (lbs)

Depth (ft)

F1 = -100756

- 6500

F2 = -73528

-5942

W1 = 66452

-5942

W2 = 145579

0

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Figure 6: Graph of Tension against Depth on Drill String and Drill pipe sections

Construct Design loading lines, Td:

The standard design values for Margin of over pull (MOP) ranges from 50000-100000 lb, but the new grade of steel pipe selected can withstand 370,710 lb of over- pull. MOP calculated = 222,663 lbs

a. Multiply actual loads by 1.3 to obtain the design loads (Td)

At surface Td = 1.3 x 184807 = 240244 lbs

At 5942 ft, Td = 1.3 x 39228 = 50991 lbs

b. Add 222,663 lbs MOP to obtain Td

At surface Td = 184807 + 222663 = 407470 lbs

At 5942 ft, Td = 145579 + 222663 = 368242 lbs

c. Apply slip crushing factor

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At surface Td = 1.59 x 184807 = 293843 lbs

At 5942 ft, Td = 1.59 x 39228 = 62373 lbs

Above 2000’ the design loading line exceeds the maximum allowable tensile load

Table 6: Showing Tension Load line

         

T ×1.3 Depth (ft)    T+MOP Depth (ft)

240249 0    407470 0

50991 ‐5942     368242 ‐5942 

              

              

T×1.59 Depth (ft)         

293843 0         

62373 ‐5942          

Figure 7: Graph of Tension against Depth.

DRILL STRING DESIGN PARAMETERS/SPECIFICATION AND CALCULATION.

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DRILL PIPE SPECIFICATION AND DESIGN The drill pipe is the longest section of the drill string. The Bottom Hole Assembly (BHA) is usually not longer than 1000 ft, the joint of the drill pipe consists of the tube body as well as the tool joint, and that connects the section of the drill pipe. Drill Pipe is available in several sizes and weights. The following are common sizes of Drill Pipe: Table 4: Showing Pipe sizes and Nominal Weight

Sizes Nominal Weight 2 in. 13.30 lb/ft 2 in. 16.60 lb/ft

5 in. 19.50 lb/ft

5 in.

25.60 lb/ft

Table 5: Standard Pipe specification for V-150

Size Outer Diameter (OD), (in.)

5

Nominal Weight, (lb/ft) 25.60

Grade and Upset Type VM-150IEU

Torsional Yield Strength, (ft-lb) 104,500

Tensile Yield Strength, (lb) 1,060300

Wall Thickness, (in.) 0.500

Nominal ID, (in.) 4.000

Pipe Body Section Area, (sq in.) 7.069

Pipe Body Moment of Inertia, (cu in.) 18.113

Pipe Body Polar Moment of Inertia, (cu in.) 36.226

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CALCULATING LENGTH OF DRILL PIPE STEP 1: The desired length of Drill pipe can be deduced thus: Weight of the Drill Collar, WDC per foot = 119.09 lb/ft From Table 5 above: Outer diameter of Drill Pipe, ODP = 5 in. Inner diameter of Drill Pipe, IDP = 4 in.

4(ODP2 – IDP

2)...................................................... (15)

4(52 – 42) = 7.0695 in2

The design of a suitable drill string could be considered under the following design

criteria: (a) Tension, (b) Collapse, (c) Torsion and (d) Shock Loading.

TENSION ON DRILL STRING

Only submerged weights are considered since all immersed bodies are subjected to

buoyancy forces. Buoyancy forces therefore, cause reduction in the total weight of

the body and the magnitude depends on the density of the fluid. Hence the total

weight, P, carried by the top joint of the Drill pipe can be deduced by:

P = (Weight of Drill Pipe in Mud) + (Weight of Drill Collar in Mud)

P = {(LDP WDP – LDC WDC)} BF………………………………………….. (16)

Where; LDP = length of Drill Pipe; WDP = Weight of Drill Pipe; LDC = Length of Drill

Collar; WDC = Weight of Drill Collars per unit Length and BF = Buoyancy Factor.

Therefore, P = {(LDP WDP – LDC WDC)} BF

P = (LDP x WDP – LDC x WDC) x BF

P = (30258 x 25.60 – 119.09 x 565) x 0.869

= 614660 lbs

Drill Pipe Tensile Resistance.

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The tensile resistance of the drill pipe is usually derated by a design factor (divide the tension by the tension rating 1.15.)

1.15 ……………………………. (17)

= 534486.95 lbs

The Drill Pipe strength can be classified according to its yield strength; defined as

the load at which deformation takes place under any loading condition its subjected

to at a period of time, under load steel elongates linearly in relation to the load

applied until its elastic limit is reached, at this condition of elastic limit when the load

is removed from the steel pipe, the pipe recovers to its original dimensions. If a pipe

is loaded beyond its elastic limit, deformation occurs and the pipe cannot recover to

its original dimensions even after the load is removed. This condition of permanent

deformation is known as its yield. Deformation causes pipe to lose its strength.

Drill string design is based on 90% of the Yield strength in order to provide

additional safety in the resulting design after all. Hence, the maximum tensile design

load can be calculated thus:

The Maximum Tensile Load, PA is given as:

PA = PT 0.9 …………………………………… (18)

Where; PT = Drill pipe Yield Strength = 1060300 lbs

Therefore,

Maximum Tensile Load, PA = PT 0.9

= 1060300 0.9

= 954270 lbs

Margin of over pull, MOP = PA – P................................................................. (19)

= 954270 - 731607.27

= 222,663 lbs

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The standard design values for Margin of over pull (MOP) ranges from 50000-100000 lb, but the new grade of steel pipe selected can withstand 370,710 lb of over- pull.

DETERMINE THE LENGTH OF DRILL PIPE, LDP Length of Drill Pipe can be calculated thus; LDP = {(PT 0.9 – MOP) / [(WDP BF)]} – (WDC/WDP) LDC...........................(20)

= {(1060300 0.9 – 222663) / [(25.60 0.869)]} – (119.09/25.60) 565

= 30258 ft

The Maximum Hole depth that can be drilled with a new pipe of Grade S-150 under the Loading condition is: Maximum Hole Depth = (LDP + LDC)......................................................... (21) = 30258+ 565 ft = 30823 ft COLLAPSE PRESSURE The collapse pressure is the external pressure required causing yielding of the pipe or casing. Under normal situation in drilling operations, the mud column inside and outside the pipe are both equal in height with the same density. There occurs a zero differential pressure across the pipe body resulting to a zero collapse pressure on the drill pipe. Hydrostatic pressure exerted against the formation is reduce when the drill pipe is run partially full, as in drill stem test (DST), formation fluid flow into the well bore. Once the well flows, the drill pipe is filled with fluid; the collapse effects are relatively small. The maximum differential pressure, ∆P across the pipe exists prior to opening of the DST tool, which can be deduced as follows: DETERMINE THE MAXIMUM COLLAPSE PRESSURE, ∆P, The maximum Collapse pressure, which occurs when the Drill Pipe is 100% empty, can be deduced thus: Mud Density 8.5 ppg = 63.75 lbft3

∆P = (LDP m / 144)................................................................................ (22) = LDP MW = 30258 63.75/ 144

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Collapse Pressure = 13395.47 psi 13395 psi Design Safety Factor, SF = 1.125

..... (23)

1.125

= 11906.67 psi

TORSION CONSIDERATION

Basic design rule denotes that, drill pipe are to be kept in tension by using the drill collars and the heavy weight drill pipe as component of the bottom hole assembly to transmit weight to the drill bit. Well enough drill collars are to be used in the bottom hole assembly to ensure that the neutral point,( this is the point whereby the drill string goes from being in tension to being in compression) should be below the drill pipe. This condition applies to the vertical wells.

Designing a horizontal well is much more complicated. To transmit weight in the lateral section of the hole requires drilling in compression rather than drilling in tension, which requires compressive drill pipes with larger diameter so as to reduce buckling conditions targeting needs to reduce torque and drag tendencies.

The drill pipe torsional yield strength when subjected to pure torsion is given by:

,...................................................... (24)

Where Q = Minimum torsion yield (lb-ft); Ym = minimum unit yield strength (psi);

4)............................................. (25)

4 – IDP4)

4)

= 36.23 in3

Where ODP = Outer Diameter (in.), IDP = inside Diameter (in.)

The Yield Strength Ym for V-150 grade pipe = 150000 lbs

29

5

= 104523 lb-ft

Drill pipes could be subjected to both torsion and tension, as the case may be during drilling operations, therefore, we can write:

2m – (P2 / A2) …………………………………....(26)

Where, Q = Minimum torsion yield (lb-ft);

Ym = Minimum unit yield strength (psi);

2);

Where ODP = Outer Diameter (in.), IDP = inside diameter (in.);

Q = (0.096 167 36.23/5)√1500002 – (6146602 / 7.07952) =

Q = 85234.83 lbs

P = total load in Tension (lb); A = Cross-sectional Area (in2).

……………………. (27)

5

= 14.49 in3

TORGUE CONSIDERATION

2……....…………………............ (28)

2

T = 1022382 in-lb

Where,

Z = Polar section modulus of drill pipe, (in.3). Z= 2J/D

A = Cross- Sectional area of drill pipe, (in.2)

P = Axial load, (lb)

Pt = Tensile yield strength (psi)

30

TENSILE STRESS, SHEAR STRESS AXIAL STRESS AND TANGENTIAL STRESS DETERMINATION

Tensile stress at joint under consideration is the ratio of the tensile load to the pipe cross section.

Thus:

(i) Tensile Stress

…………………………………………………………………….(29)

7.0695

ts = 86945 psi

Where ts = Tensile stress

P = Axial load, (lb)

A = Cross-Sectional Area of Drill Pipe, (in2.) = 7.0695 in2

(II) Shear Stress

The shear stress is given by:

………………………………………………………………………(30)

14.49

z = 70558 lb/in2

Where z = Shear stress

T denotes torque (in-lb)

Z denote polar section modulus of drill pipe (in.3) = 2J/Ddp

(iii) Axial Stress

4 ………………………………………………….. (31)

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4 0.5

a = 65625 psi

Where,

a = Axial Stress

Pdp = Internal drill pipe pressure, (psi) = 26250 psi

Ddp = Outside diameter of drill pipe, (in.)

t = Wall thickness of drill pipe, (in.)

(iv) Tangetial Stress

2 ………………………………………………......(32)

t = 26250 x 5

2 x 0.5

t = 32813 psi

Maximum permissible hole curvature

The weight of the drill collar string is:

WDC = 1 ρm/ρs………...............................................(33)

= (558 (119.09) (1 – 8.5/ 65.45) = 57880 lbS

The weight of the drill pipe is, WDP:

(Depth – )(approximated weight)(1 - m / s) ..……………………….......(34)

WDP = (6500 – 558)(24.50)(1-8.5/65.5) = 87023 lbs

It was assumed that the weight suspended below the dogleg (T = 148900 lb)

……………………………………………………….(35)

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Where T = assumed weight of dogleg and A = area of dill pipe

Tensile stress, t = 148900/7.0695

= 21062 psi

145,000 ....………………………………..........(36)

145,000

= 17095 lb

CALCULATION BUCKLING BENDING STRESS RATIO AND AXIAL STRESS

BUCKLING

Updrag/Downdrag Forces on Drill String

According to ( William. C. Lyons, 2005), the problem of drill collars buckling in vertical holes was investigated by A. Lubinski, and the weight on the bit that results in first- and second order buckling can be calculated as follows:

64(D4 – d4) …………… (38)

Where, D is the outside diameter of drill collar (ft.) = 0.60175 ft, d = inside diameter of drill collar (ft) = 0.23344 ft; Conversion factor: 1 inch = 0.08333333 ft.

64(D4 – d4)

64(0.601754 – 0.233444)

= 0.00629 ft4

Unit weight of drill collar in air = 119.09 lb/ft

Unit of drill collar in fluid, p = 119.09(1 – 8.5/65.5)

= 103.64 lb/ft

Recall, Mud Weight = 8.5 ppg, Density of Steel s = 65.5ppg

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(ii) Weight on drill bit during first- order buckling:

Wcrl = 1.94(EIp2)1/3 ………………………………………………………. (39)

= 1.94(4320 106 0.00629 103.642)1/3

= 12869 lb

Where, Wcrl = Weight on drill bit during first- order buckling, E = Modulus of elasticity

E= 4320 106 lb/ft2, p = the unit weight of drill collar in drilling fluid (lb/ft), I = Moment of inertia of drill collar cross-section with respect to its diameter (ft.)

(iii) Weight on drill bit during second-order buckling:

Wcrll = 3.75(EIp2)1/3 ……………………………………………...(40)

= 3.75(4320 106 0.00629 103.642)1/3

= 24875 lb

Design Well bore Hole Data:

Diameter of hole, D = 12 in.

Radius = D/2 = 12/2 = 6 in.

Radius of drill collar = ODDC /2

= 7.25/2

= 3.625 in.

Where, ODDC = Outer Diameter of Drill Collar.

According to (William. C. Lyons, 2005), in an inclined hole the critical, a critical value on weight on the bit that produces buckling may be calculated from the formula given by R. Dawson and P.R Palsy;

)…………………………………………………………(41)

Where, Wcrit = Critical weight on the bit, r = the radial clearance between the drill collar and borehole wall (ft).

The radial clearance = Radius of Hole, (R) – radius of drill collar, (r).

R= D/2 = 12/2 = 6 in. and r = d/2 = 7.25/2 = 3.625 in.

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Thus, Radial clearance = R – r

= (6 – 3.625)

= 2.375 in

= 0.1971 ft

0.1971 ) ………………………...........................................................................(42)

= 94303855 lb

SHOCK LOADING

Shock loading arises between slip area set and the moving drill pipe, which can contribute to parting of the pipe in marginal design. Adding additional tensile force, Fs to the pipe which can be calculated thus:

Fs = 3200 WDP …………………………………………………………(43)

Where, Fs = the shock load

Fs = 3200 25.60 30258

= 2,478735360 lbs

EXTENDED REACH WELLS Extended – Reached Drilling (ERD) is essentially an advanced form of directional drilling, which utilises both directional and horizontal drilling techniques. It has the capacity to achieve horizontal well departures and total vertical depth to horizontal distance ratios well beyond conventional directional drilling. Sophisticated steerable drilling equipment is employed in conjunction with continuous realtime monitoring of conditions in the wellbore. The wellbore must be carefully cleaned through the selection of appropriate drilling mud. Long extended reach wells are classified as wells with more than 8 km of horizontal displacement. Extended reach wells are drilled to reach reservoirs that have a horizontal displacement in excess of 16,400 ft (> 5,000m) from the starting point.

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Fig. 10: Extending Reach Drilling ( Modified from: www.schlumberger.com)

DESIGN COSTING

Costing is necessary to estimate the cost effectiveness of the design based on the prevailing market values of the material used for the design. Consideration were made basically to source for a unique price for components of the drill string affordable to prospective manufacturers.

The values in this table are according the China mainland market

Table 8: Table showing the Estimated cost of a complete drill string unit

Cost  of  each  foot  of  drill  pipe  is $37.00/ft therefore the total cost is: 

 Drill pipe cost = 30258   37    =     $1,119546  

6  Tri‐cone  drill  bits  predicted  to  be used  to drill a  complete well and  the cost   

Cost of Tri‐cone drill bit = $4,500  6 = $27,000  

Each bottom hole assembly of  the 12 to be used cost $2,350 total cost of  it is:  

Bottom hole cost  =   $2350   12   =       $28,200  

3  Kelly  drive  are  required,  each  cost $2,000. Cost of Kelly drive:  

Cost of Kelly drive:      $ 2000 3          = $6,000  

Total cost of drill string = $1,153746 

36

DISCUSSION

The design of drill string has made the drilling for oil an interesting engineering field to research into and possible software application to be used, to aid in the design procedure and consideration. Tensions, fatigue, buckling in horizontal wellbore are major study to contend with today in the design of efficient drill string. It is observed that in the design of drill string for vertical well, the drill string is allowed to run in tension rather than in compression to avoid failures as a result of loading. Conversely, in horizontal wells, the drill pipe is preferred to be in compression to avoid buckling. Heavy weight drill pipe is used to withstand the possible effect of buckling, fatigue and failure. \drag effect is considered and effective design could remedy its effect. In the materials selection, steel with higher tensile strength are preferred and use to prevent failure, and to be able to drill deeper wells as seen today in the industry, more deeper strata are discovered and an effective but efficient drill method with the best available technology are utilised.

CONCLUSION 1- Higher capability of the designed program to detect and recognise the reasons for drill string failure is obtained with less effort and short time, and this program will be a guide for any future case, as it will be used to characterize the reasons that may lead to that failure. 2- Drill string failure does not usually occur due to a unique reason or a unique factor. It depends on a lot of reasons and factors that could be accumulated and lead to the drill string failure. The best way to avoid drill string failure before and while drilling is to run the designed program to carefully diagnose and detect if the drill string is close to fail and hence an immediate action is taken to improve the drilling parameters to prevent the drill string failure. 3- The major factors that lead to drill string failure, for the tested cases are: dogleg severity, rotary bottom hole assembly, higher operating torque while drilling, hard formation, and hole size specially 12.25-inch. 4- New drill pipe material grade that combines ultra-high strength with excellent fracture toughness has been developed. 5- This new drill pipe can help expand the extended reach drilling envelop by enabling drill strings with excellent strength to weight properties. 6- Combining the V-150 material with light weight, thinner wall drill string designs can reduce torque and drag loads while providing high axial tension capacities and torsional strengths necessary to drill the next generation of ERD wells. 7- The ultra-high strength material is also well suited to landing string applications where the loading demands to run longer and heavier casing strings in deep-water continue to increase. • It is anticipated that innovative drilling professionals may also discover additional critical drilling applications that can benefit from this new drill pipe technology.

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REFERENCES

Olugbebi, Adebambo. (2011) Phase Four Drill String Design Project for Horizontal and Extended Reach Wells. [Accessed 27 November 2013] Cunha, J.C. (2002) Drill-String and Casing Design for Horizontal and Extended Reach Wells Part 1. Paper SPE 79001-MS presented at the SPE International Horizontal Well Technology Conference. Dawson, R. And Paslay, P.R.: “Drillpipe Buckling in Inclined Holes,” JPT (October 1984) 1734.

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Diaz, P. eds (2011) Class Lecture Notes, engineering design, London South Bank University. [Online]. Available from Blackboard: <http://blackboard.lsbu.ac.uk> [Accessed 7 March 2011] Mason, C.J. and Judzis, A.: ‘’Extended-Reach Drilling- What is the Limit? ’’Paper SPE 48943 prepared for presentation at the 1998 SPE Annual Technical Conference and Exhibition, New Orleans, 27-30 September.

William, C. Lyons; Plisga, Gary J.. 2005., Standard Handbook of Petroleum and Natural Gas Engineering. [online]. Elsevier Science & Technology. Available from: <http://0-lib.myilibrary.com.lispac.lsbu.ac.uk?ID=100987> 22 March 2011

http://www.oilprimer.com/oil-well-drilling.html [accessed 19th February 2011]

http://www.vamdrilling.com/userfiles/file/DC_March09-VAM.pdf [Accessed 30 March 2011].