Introduction to MWD

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IIntroduction ntroduction t oM WD to MWD

SERIAL NUMBER: Client Company:

THIS MANUAL CONTAINS PROPRIETARY INFORMATION THAT MAY NOT BE DISCLOSED TO OTHERS, REPRODUCED OR USED WITHOUT WRITTEN AUTHORITY FROM

GE POWER SYSTEMS 1840 ROYSTON LANE ROUND ROCK, TEXAS 78664 This document is an unpublished work. Copyright 2003 GE Power Systems. All rights reserved. “This document and all information and expression contained herein are the property of GE Power Systems and is provided to the recipient in confidence on a ‘need to know’ basis. Your use of this document is strictly limited to a legitimate business purpose requiring the information contained herein. Your use of this document constitutes acceptance of these terms.”

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Table of Contents CHAPTER 1: THE FOUNDATION: BASIC SKILLS AND KNOWLEDGE ...........7 1.1 Mathematics Review................................................................................................... 8 1.1.1 Arithmetic .............................................................................................................. 8 1.1.1.1 Basic Operations of Arithmetic ...................................................................... 8 1.1.1.2 Commutative Property .................................................................................... 9 1.1.1.3 Associative Property ..................................................................................... 10 1.1.1.4 Distributive Property..................................................................................... 10 1.1.2 Algebra................................................................................................................. 10 1.1.2.1 Lines and Graphs .......................................................................................... 10 1.1.2.2 Working With Variables ............................................................................... 15 1.1.2.3 Balancing an Equation .................................................................................. 15 1.1.2.4 Solving Quadratic Equations ........................................................................ 17 1.1.3 Trigonometry ....................................................................................................... 21 1.1.3.1 Triangles ....................................................................................................... 21 1.1.3.2 Sine, Cosine, Tangent ................................................................................... 23 1.1.3.3 Practical Application..................................................................................... 24 1.2 Basic Hydraulics........................................................................................................ 26 1.2.1 System Pressures.................................................................................................. 26 1.2.2 Bernoulli’s Principle ............................................................................................ 28 1.2.3 Annular Velocity.................................................................................................. 28 1.2.4 Pressure Pulses..................................................................................................... 31 1.2.5 Drilling Fluid ....................................................................................................... 33 1.3 The Drilling Rig......................................................................................................... 33 1.3.1 Different Types of Drilling Rigs.......................................................................... 33 1.3.1.1 Offshore ........................................................................................................ 34 1.3.1.2 Land .............................................................................................................. 38 1.3.2 Parts of a Drilling Rig .......................................................................................... 38 1.3.2.1 Rig Floor ....................................................................................................... 38 1.3.2.2 Mud Pumps ................................................................................................... 39 1.3.2.3 Standpipe....................................................................................................... 40 1.3.2.4 Draw Works .................................................................................................. 41 1.3.2.5 Kelly.............................................................................................................. 42 1.4 Bottom Hole Assemblies ........................................................................................... 42 1.4.1 Drill Collars ......................................................................................................... 42 1.4.2 Universal Bottom Hole Orienting Subs ............................................................... 43 1.4.3 Stabilizers............................................................................................................. 44

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1.4.4 Crossovers............................................................................................................ 45 1.4.5 Heavyweight Drill Pipe........................................................................................ 45 1.4.6 Jars ....................................................................................................................... 46 1.4.7 Drillpipe Configuration........................................................................................ 46 1.4.8 Positive Displacement Mud Motors..................................................................... 46 1.5 MWD Tools................................................................................................................ 47 1.5.1 What is an MWD Tool?....................................................................................... 47 1.5.2 Different Types of MWD Tools .......................................................................... 47 1.5.2.1 Retrievable MWD Tools............................................................................... 47 1.5.2.2 Non-Retrievable MWD Tools....................................................................... 48 1.5.2.3 Logging Tools............................................................................................... 48 1.5.3 The Role of the MWD Operator .......................................................................... 49 CHAPTER 2: FIELD OPERATIONS ..................................................................51 2.1 Recommended Paperwork ....................................................................................... 51 2.1.1 Equipment Inventory ........................................................................................... 51 2.1.2 MWD Job Sheet................................................................................................... 51 2.1.3 Environmental/Job Site Information.................................................................... 51 2.1.4 Paperwork List ..................................................................................................... 51 2.1.5 Job Charge sheet .................................................................................................. 51 2.1.6 MWD Insurance sheet.......................................................................................... 51 2.1.7 Magnetic Declination/Tool Face Offset............................................................... 51 2.1.8 Survey Tie-in Information sheet .......................................................................... 52 2.1.9 Electro-Magnetic Error Report sheet ................................................................... 52 2.2 Well Site Responsibilities ......................................................................................... 52 2.2.1 Arrival at Rig Site ................................................................................................ 52 2.2.2 Before Rigging Up............................................................................................... 53 2.3 Rigging Up Surface equipment................................................................................ 53 2.3.1 Lines and Cables .................................................................................................. 53 2.4 Directional-Only Service .......................................................................................... 53 2.4.1 Safe Area Rig-Up................................................................................................. 53 2.4.1.1 Set Up in the Safe Area................................................................................. 53 2.4.1.2 Use the UPS (Uninterruptible Power Supply) .............................................. 53 2.4.1.3 Set Up Computer........................................................................................... 54 2.4.1.4 Connect RS-232 Cable.................................................................................. 54 2.4.1.5 Connect Programming Cable........................................................................ 54 2.4.2 Rig Floor Area Equipment................................................................................... 54 2.4.2.1 Set Up Terminal............................................................................................ 54 2.4.2.2 Connect 10-Pin Cable ................................................................................... 55

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2.4.2.3 Connect Power/Communications Cable(s) ................................................... 55 2.4.3 Rig Floor Area Equipment................................................................................... 56 2.4.3.1 Protect the Standpipe Pressure Transducer................................................... 56 2.4.3.2 Install the Standpipe Pressure Transducer .................................................... 56 CHAPTER 3: INTRODUCTION TO SURVEYING ..............................................57 3.1 Reference Points........................................................................................................ 57 3.1.1 Magnetic North .................................................................................................... 58 3.1.2 True North............................................................................................................ 60 3.1.3 Grid North............................................................................................................ 61 3.2 Corrections ................................................................................................................ 65 3.2.1 Magnetic Declination........................................................................................... 66 3.2.2 Grid Correction .................................................................................................... 70 3.3 Quality Factors.......................................................................................................... 72 3.3.1 Magnetic Dip Angle............................................................................................. 72 3.3.2 Total Magnetic Field............................................................................................ 74 3.3.3 Total Gravity Field............................................................................................... 76 CHAPTER 4: TRANSFORMING INFLUENCES ................................................79 4.1 Magnetic Interference From BHA .......................................................................... 79 4.1.1 Hole Angle ........................................................................................................... 81 4.1.2 Hole Direction...................................................................................................... 83 4.1.3 Latitude ................................................................................................................ 84 4.1.4 Not Enough Non-magnetic Material.................................................................... 85 4.1.5 Hot Spots.............................................................................................................. 88 4.2 Magnetic Interference From Formation................................................................. 88 4.2.1 Formation Constituents........................................................................................ 88 4.2.2 Steel Components in the Hole.............................................................................. 89 4.3 Magnetic Interference From Solar Flares .............................................................. 89 4.4 Incorrect Operator Input ......................................................................................... 89 4.5 Incorrect Calibration................................................................................................ 89 4.6 Survey Technique...................................................................................................... 90 4.6.1 Drill String Movement......................................................................................... 90 4.6.2 Bad Detection....................................................................................................... 90 4.6.3 Stored Surveys ..................................................................................................... 90

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4.6.4 Incorrect Survey Depth ........................................................................................ 91 CHAPTER 5: CALCULATING BOTTOM HOLE LOCATION.............................93 5.1 Calculating Bottom Hole Location .......................................................................... 94 5.1.1 Average Angle ..................................................................................................... 99 5.1.2 Radius of Curvature ........................................................................................... 102 5.1.3 Minimum Radius of Curvature .......................................................................... 105 5.2 Plotting Bottom Hole Location .............................................................................. 109 CHAPTER 6: GEOMETRICAL STEERING......................................................111 6.1 Toolfaces .................................................................................................................. 111 6.1.1 Magnetic Toolfaces (mTF) ................................................................................ 113 6.1.2 Gravity or Highside Toolfaces (gTF) ................................................................ 114 6.1.3 Orienting MWD Tools to Steering Tools .......................................................... 116 6.1.3.1 Orienting Retrievable Tools........................................................................ 117 6.1.3.2 Orienting Fixed Collar Tools ...................................................................... 119 INDEX...............................................................................................................123

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Chapter 1: The Foundation: Basic Skills and Knowledge MWD stands for Measurements While Drilling. The measurements considered for the purposes of this manual are directional measurements. An MWD Operator must have certain basic skills to perform at an optimum level. Among the skills necessary is a working knowledge of Mathematics, which encompasses simple arithmetic to trigonometry. The mathematical skills will be necessary when dealing with problems involving hydraulics. While computer programs solve many of the problems for the operator, the operator must be able to calculate hydraulic problems when the need arises. The same may be said of survey calculations. The operator may occasionally need to calculate a survey without the benefit of a computer. The MWD operator must know how a drilling rig operates. Rig operations affect many aspects of the MWD tool operation. The best MWD operators are those who know not only their job but also how the rig runs. Knowledge of rig operations includes knowing what a Bottom Hole Assembly (BHA) is and how it works. The MWD tool is part of the Bottom Hole Assembly. An operator should know as much as possible about this and all other components of the drill string. MWD operators should know the different types of MWD tools available and their basic components. An operator should know how the components work and how they contribute to the drilling process. The MWD operator has an important job in ensuring that problems and rig downtime are kept to a minimum. This job is difficult, demanding and requires many different types of skills. The sum of the skills and knowledge presented in this chapter will be the foundation for a successful career in the MWD field.

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1.1 Mathematics Review An MWD operator’s duties require an understanding of mathematics from arithmetic through trigonometry. This section provides a review of basic mathematical concepts and tests the understanding of those concepts.

1.1.1 Arithmetic 1.1.1.1 Basic Operations of Arithmetic +

means add or put two things together. 5 + 2 indicates that 5 and 2 should be joined together to make 7.

–

means subtract or take something away. – 3 means take 3 away from 6 leaving 3

*

means to multiply something. This is another way of adding. 5 * 6 means add 6 to itself 5 times such as: 6 + 6 = 12 (first and second additions), 6 + 12 = 18 (third addition) 6 + 18 = 24 (fourth addition) and 6 + 24 = 30 (fifth addition). Since 6 was added to itself 5 times, multiplication is often stated as “5 times 6”.

/ or ÷ means divide. Division is another means of multiplying. 12/3 means find out how many times 3 fits into 12 This is another way of saying 12 * ⅓. The result of multiplying any number by a fraction is division. n

X

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means multiply something by itself the number of times shown by the little number (the exponent) next to the big number (the base). Just as multiplication indicates how many times to perform an addition, the exponent indicates how many times to perform a multiplication. In this case, the number

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indicated by X must be multiplied by itself the number of times specified by the little number to the upper right. If X is 6 and n is 3, it means multiply 6 by itself 3 times: 6 * 6 = 36 (first and second multiplication) 6 * 36 = 216 (third multiplication). √X

means “square root”, that is, find the number which, multiplied by itself, equals the number represented by X. For example: √16 asks, “Which number, times itself, equals 16?” The answer is 4, because 4 * 4 = 16, or 42 = 16.

1.1.1.2 Commutative Property Most of Mathematics is plain common sense. For instance, the order in which numbers are added is unimportant. The following equation illustrates this point: 2 + 4 equals 4 + 2

Eq. 1

Note that it does not matter how many numbers are added. The order in which they are added remains unimportant. This fact is called the Commutative Property. However, when multiplication or division are mixed with addition or subtraction, the order in which operations are performed is important. For example, 4 + 2 * 10 is not the same as 2 + 4 * 10

Eq. 2

because the answer depends upon which operation is performed first. If the addition is done first, the answer is 60 in both cases. But if the multiplication is done first, the answer is 24 in the first case and 42 in the second. One of the rules of Mathematics is to perform multiplication and division first, then addition and subtraction. The order in which numbers are subtracted is also important: 8 – 2 is not the same as 2 – 8

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Eq. 3

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Since eight minus two equals six, it is not the same as two minus eight, which equals negative six.

1.1.1.3 Associative Property This property is much like the Commutative Property but it involves adding three or more numbers in groups. The parentheses are used to indicate which numbers should be added first. Adding (5 + 6) + 7 is the same as adding 5 + (6 + 7). In the first case five plus six equals eleven and seven plus eleven equals eighteen. For the second case, five added to the sum of six and seven (which is thirteen) also equals eighteen.

1.1.1.4 Distributive Property The Distributive Property or Distributive Law is a very important and powerful concept. The Distributive Property states that: A * (B + C) = (A * B) + (A * C)

Eq. 5

5 * (10 + 2) is the same as (5 * 10) + (5 * 2)

Eq. 6

Remember, always do the multiplication before the addition. In this example, five times twelve (ten plus two) equals sixty and is the same as five times ten (fifty) plus five times two (ten). Fifty plus ten equals sixty. Application of The Distributive Property permits the solution of most algebra problems.

1.1.2 Algebra 1.1.2.1 Lines and Graphs If you were to take four steps to your right, you would then be four steps from your starting point. Measuring your steps on a number line like the one in figure 1.1.2.1.a, you would be a distance of four from the starting point or origin. The origin is the number zero. Positive numbers are expressed as steps to the right of zero.

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Steps to the left of zero represent negative numbers. Negative numbers are identified with a minus in front of them. Adding a negative number is like subtracting a positive number: 4 + (–2) is the same as 4 – 2

Eq. 7

Both methods give the same answer: go four steps to the right, then two steps to the left. No matter how it is stated, you still end up at the number two.

-4

-3

-2

-1

0

1

2

3

4

Figure 1.1.2.1.a Number line

If we add a second number line perpendicular to the first, passing it through the first number line’s origin, we create a rectangular coordinate system, as in figure 1.1.2.1.b.

c) Intersection of lines a and b

a) Two spaces above the origin

Origin b) Two spaces to the right of the origin

Figure 1.1.2.1b

Rectangular Coordinate System

The rectangular coordinate system allows the location of points not only on the number lines but also in the spaces, or quadrants, between the lines. With two lines for reference, each point gets Introduction to MWD

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two numbers, or coordinates, to define its location. The two numbers are expressed in parentheses with a comma after the first number, for example, (2, 2). The first number, called the “X” coordinate, tells the point’s horizontal distance from the origin. The second number, called the “Y” coordinate, tells the point’s vertical distance from the origin. Both coordinates can be used in an equation to determine a point’s straight-line distance from the origin: a2 + b2 = c2.

Eq. 8

(Where “a” represents the X coordinate (the first number), “b” represents the Y coordinate (the second number) and “c” represents the point’s distance from the origin.) So: a + b = √c

Eq. 9

Using this method, the distance from the origin is: 22 + 22 = c2

or

8 = c2

c2 = 8

or

4 + 4 = c2

Now take the square root (the symbol √ means square root) of both sides of the equation c = √8 or approximately 2.8284 The slope of the line that goes from the origin through point c is calculated by dividing how many spaces go up or down by how many go right or left. This is called dividing the rise (up or down) by the run (left or right). Calculate the slope of the line in Figure 1.1.2.1.a. by: Slope = 2 (the rise) ÷ 2 (the run) so Slope = 1

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A slope of one means that for every space that goes up or down, one space goes to the right or left. (See figure 1.1.2.1.b.) For every one space moving up there is one space moving to the right.

2 1

1

2

Figure 1.1.2.1.b Slope of 1

As the position of the line changes, the slope changes. Suppose that for every space up, there are two spaces to the right. Dividing the rise by the run yields a slope of one half. On the other hand, if there are two spaces up and one to the right the slope is two. See Figure 1.1.2.1.c.

2 1

1 1

2

1

Figure 1.1.2.1.c Two different slopes

The graph on the left has a slope of ½ while the graph on the right has a slope of 2. Suppose that two points along the line are known. Each point is defined by two values, the distance along the x or horizontal axis and the distance along the y or vertical axis. See Figure 1.1.2.1.d. Whenever the x and y values are given they look like

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(3, 2). The x value is always given first. Values for Point 2 are presented as (6, 3). Chapt

Point 1:

Point 2:

X = 3, Y = 2

X = 6, Y = 3

3 2 X

3 Figure 1.1.2.1.d

6

Two points on the line are known.

If two points are known, the difference between their y values divided by the difference between their x values determines the slope of the line: Y value of Point 2 minus Y value of point 1 Divided by X value of point 2 minus X value of point 1 Therefore, the slope of the line in Figure 1.1.2.1.d. is determined in the following manner: (3 – 2) ÷ (6 – 3) = 1 ÷ 3 = 1/3 The slope is 1/3: the line goes one space up for every three spaces to the right.

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1.1.2.2 Working With Variables Sometimes a variable is used to represent the unknown information in a problem. Typically, a letter is used for the variable, as in the following formula: 5n + 3 = 18

Eq. 10

The letter n is a variable standing for an unknown value. To identify the value, solve the equation for n. To solve for n, we will isolate the variable on one side of the equation (normally the left side) with everything else on the other side of the equal sign. Start the process of isolating n by subtracting three from both sides of the equation. 5n + 3 – 3 = 18 – 3 By subtracting three from both sides, the values remain equivalent. Now the equation looks like: 5n = 15 Dividing both sides by 5 completes the process. 5n / 5 = 15 / 5 Since 5n divided by 5 is n and 15 divided by 5 is 3, the solution for n is that n equals 3. n=3 To identify the value of a variable, isolate the variable on one side of the equation by applying identical operations to both sides of the equation.

1.1.2.3 Balancing an Equation Solving an equation for an unknown, as covered in section 1.1.2.2, involves balancing an equation. Balancing means keeping each side equivalent while you solve for the unknown. In the following example, the equivalence of each side of the equation is preserved. Introduction to MWD

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5n + 3 = 8n – 6 Add a negative three to the left side to isolate 5n. Also add a negative three to the right side to preserve equivalence. 5n + 3 – 3 = 8n – 6 – 3 5n = 8n – 9 Now add –8n to the left side to remove n from the left. Add the same to the right side to preserve the balance. –3n = –9 Multiply both sides by –1 3n = 9 Divide both sides by 3 n=3 Notice that all the operations performed maintained the equivalence of both sides. To maintain the equivalence while solving for the unknown is to balancing the equation. Units of measure are also multiplied and divided, just like numbers, to balance equations. Suppose you need to convert 10,000 feet-per-second into miles-per-hour. Ask the question like this: “If you can go 10,000 feet in one second, how many miles can you go in one hour (3,600 seconds)?” Now put it equation form: 10,000 feet 1 second

=

n miles 1 hour

Convert feet-per-second to feet-per-hour:

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10,000 feet * 1 second

3,600 seconds 1 hour

=

n miles 1 hour

10,000 feet * 1 second

3,600 seconds 1 hour

=

n miles 1 hour

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36,000,000 feet 1 hour

=

n miles 1 hour

Note: You can multiply just one side of an equation by a factor only when that factor is equal to 1. The factor

3,600 seconds 1 hour

is equal to 1 because 3,600 seconds equals 1 hour. 3,600 seconds / 1 hour equals 1/1 or 1. Now convert feet-per-hour to miles-per-hour: 36,000,000 feet * 1 hour

1 mile 5,280 feet

=

n miles 1 hour

36,000,000 feet * 1 hour

1 mile 5,280 feet

=

n miles 1 hour

(36,000,000 ÷ 5,280) miles 1 hour

=

n miles 1 hour

36,000,000 ÷ 5,280 ≈ 6,818.2 miles per hour. Note: The ≈ symbol means, “is approximately equal to”. In this case, if the decimal point were carried out to four places the answer would be 6,818.1818. The decimal portion is rounded off to .2. 6818.2 miles 1 hour

=

n miles 1 hour

So the answer is, if you can go 10,000 feet per second, you can go approximately 6818.2 miles per hour.

1.1.2.4 Solving Quadratic Equations Quadratic equations contain a squared variable, that is, a variable with an exponent of 2, such as x2. An example of a quadratic equation is 3x2 + 2x + 5 = 21.

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Many strategies can be used to simplifying these equations so they are not so intimidating. In the above example, 3x2, 2x, 5 and 21 are all terms of the equation. A term, in an equation, is anything that is separated by an operation sign, or operator, such as + , – , * , ÷, or = . Think of terms as packages that can be moved around or opened and repacked. To begin solving this equation for x, reduce one side of the equation to zero by subtracting 21 from each side. 3x2 + 2x + 5 – 21 = 21 – 21 3x2 + 2x – 16 = 0 Now apply the simplifying strategy of grouping. In grouping, you divide the non-zero side of the quadratic equation into two smaller equations, in accordance with the distributive property. Each of the smaller equations will contain the variable adding or subtracting a number. If the term containing the squared variable also has a number, such as the 3 in 3x2, place the number with the variable in the first smaller equation Once you have reduced one side of the equation to zero (and arranged the terms on the non-zero side from greatest to least factors of the variable) you can use the terms and operators as clues to find the smaller equations. You can determine the operation signs of the smaller equations from the signs in the quadratic equation. The fact that the second operation sign is minus tells you that the two smaller equations will have different operation signs. One will be plus, the other will be minus. So far, we know the smaller equations look like this: (3x + __ ) (x – __ ) = 0 Note: When terms are enclosed in parentheses and put close together, it indicates that the terms must be multiplied. ( c ) ( b ) means multiply c times b. You can determine the numbers to add or subtract in the smaller equations from the terms of the quadratic equation. These two numbers, when multiplied by each other, equal the last term in the quadratic equation, in this case 16. They will also equal the Page 18 of 127

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numerical portion of the middle term when added or subtracted according to the operators in the two smaller equations. However, when the first term in the quadratic equation also has a numerical portion, you must also account for this number in finding the second terms for the smaller equations. Two questions will help you find the missing two numbers. First question: “Which sets of two numbers each multiply to equal 16?” Answer: The sets 1 and 16, 2 and 8, and 4 and 4. Each of these pairs, when multiplied, equals 16. Second question, “Which of these pairs of numbers, when one of its numbers is multiplied by 3, add or subtract to make 2 (the numerical portion of the equation’s middle term)? Does 16 – (3 * 1) equal 2? How about (3 * 4) – 4? No, but 8 – (3 * 2) does equal 2. So use 8 and 2 as the second terms in the smaller equations. Now we know the smaller equations will be: (3x + 8) (x – 2) = 0 Let’s verify: use the FOIL (First, Outside, Inside, Last) method to multiply the smaller equations. First, multiply the first terms of each smaller equation: 3x * x = 3x2 Second, multiply the outside terms: 3x * –2 = –6x Note that you include the minus sign with the term. Third, multiply the inside terms: 8 * x = 8x Fourth, multiply the last terms:

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8 * –2 = –16 Now add the results of the FOIL method: 3x2 – 6x + 8x – 16 = 0 and simplify: 3x2 + 2x – 16 = 0 So (3x + 8) (x – 2) does equal our quadratic equation. With the correct combination of terms, we can now solve the equation for x. We have used the distributive property to restate the quadratic equation as: (3x + 8) (x – 2) = 0 With the right side of the equation set to zero, we can know that at least one of the factors on the left side equals zero. The only way a product can equal zero is if at least one of the factors equals zero. So we know that either (3x + 8) = 0 or (x – 2) = 0 Solve (3x + 8) = 0 for x. Subtract 8 from both sides of the equation: 3x = –8 Divide both sides by 3. x = –8/3 Substitute –8/3 for x in the original equation: 3x2 + 2x + 5 = 21 3 * (–8/3) 2 + 2 * –8/3 + 5 = 21 3 * (64/9) + –16/3 + 5 = 21 64/3 – 16/3 + 5 = 21 21 1/3 – 5 1/3 + 5 =21 16 + 5 = 21

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21 = 21 So one value of X is –8/3. Now solve (x – 2) = 0 for x. Add 2 to both sides of the equation: x=2 Substitute 2 for x in the original equation: 3x2 + 2x + 5 = 21 3 * ( 4 ) + 4 + 5 = 21 12 + 9 = 21 21 = 21 So the other value of x is 2. Using the strategies of balancing equations, grouping and the distributive property, we have identified the possible values of x and solved the quadratic equation.

1.1.3 Trigonometry 1.1.3.1 Triangles Triangles have several interesting properties. The three angles of any triangle in a single plane must add up to 180 degrees. All Right Triangles, like the ones shown in Figure 1.1.3.1, have one angle that is 90 degrees. That means that the other two angles must equal 90 degrees when added together. Another property of triangles is that the ratio of sides is always the same for similar triangles (two triangles with identical angle measurements), even if they are of different sizes. In Figure 1.1.3.1, assuming the two triangles are “similar”, the ratios of the sides for triangle A are the same as for those of triangle B. For instance, the ratio of sides c and a on triangle A is the same as the ratio of sides c and a on triangle B.

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c a c A

a b

B b

Figure 1.1.3.1 Two Right Triangles

Another property of Right Triangles that is extremely useful is that the length of any side can be determined if the lengths of the other two sides are known. In Figure 1.1.3.1, the sides are labeled a, b and c. Side c is the hypotenuse. The hypotenuse is the side opposite the right angle (90 degree angle) in a Right Triangle. For any Right Triangle, the sides have the following relationship: c2 = a2 + b2 This means that if you know the length of any two sides, the length of the other side can be calculated. For example, suppose that the length of side a is 10 and side c is 15, the length of side b is: b2 = c2 – a2 b = √(c2 – a2) b = √(152 – 102) b = √(225 – 100) b = √(125) b ≈ 11.1803

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1.1.3.2 Sine, Cosine, Tangent The ratios of the sides of a triangle have peculiar names. An example is the cosine. The cosine is the ratio of the side adjacent an angle to the hypotenuse. See Figure 1.1.3.2 for an example of the cosine function.

β

c

a

χ

α b

Figure 1.1.3.2

Right Triangle with angles and sides labeled

The cosine of angle α is the ratio of side b to side c or in other words, the length of the adjacent side b divided by the length of the hypotenuse c. Suppose angle α is sixty degrees. The cosine of 60 degrees is 0.5, so the ratio of side b to c is 0.5. If side b is 10 feet, side c must be 20 feet 0.5 = 10 ÷ side c side c * 0.5 = 10 side c = 10 ÷ 0.5 side c = 20 As long as the angle is 60 degrees, the ratio of the adjacent side to the hypotenuse will be 0.5, even if the Right Triangle is sized or oriented differently from the one presented in Figure 1.1.3.2. If one angle in Figure 1.1.3.2 is 60 degrees and the right angle is always 90 degrees, then the remaining angle β must be 30 degrees:

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180 – (60 + 90) = 30 180 – 150 = 30. If angle β is 30 degrees, the length of side b can be determined by using the cosine of angle β: Cosine β = length of side b ÷ hypotenuse Cosine 30 = a ÷ 20 0.86602 = a ÷ 20 a = 20 * 0.86602 a = 17.32 Rules for sine, cosine and tangent are: Sine =

the length of the side opposite the angle divided by the length of the hypotenuse

Cosine = the length of the side adjacent the angle divided by the length of the hypotenuse. Tangent = the length of the side opposite the angle divided by the length of the side adjacent the angle. The sine, cosine and tangent values for all angles are found in tables or are available on most scientific calculators.

1.1.3.3 Practical Application Trigonometry is used extensively in drilling a directional well. Directional wells are those not drilled vertically, that is, not drilled straight down. Chapter 2 discusses directional wells in more detail. Chapter 3 discusses the surveying of directional wells. Suppose a well is drilled at a 50-degree angle instead of straight down (see Figure 1.1.3.3. for a theoretical directional well). While the depth of the hole from the surface to the drill bit can be measured directly, the vertical depth cannot. No sensor measures vertical depth. However, vertical depth is important because it establishes a comparison point between a vertical well

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and a directional well. It also allows comparison between two directional wells.

Vertical Depth

Well angle measured from vertical plane

Measured Depth

Offset of well bottom from vertical plane or vertical section Figure 1.1.3.3 Directional well

Notice that the measured depth looks like the hypotenuse of a triangle and the vertical depth is the adjacent side to the angle of offset from vertical. To calculate the vertical depth, you must know two things: 1) The angle of the offset from vertical, called the hole angle and 2) The measured depth of the hole. With a hole angle of 50 degrees and a measured depth of 1,000 feet the vertical depth is calculated by: Cosine 50 ≈ 0.6428 Cosine 50 ≈ vertical depth ÷1,000 Cosine 50 * 1,000 ≈ vertical depth 0.6428 * 1,000 ≈ 642.8 feet. Introduction to MWD

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Using the same hole angle and measured depth, the offset from vertical (vertical section) can be calculated by taking the sine of the hole angle. Remember that the sine is defined as dividing the opposite side, the vertical section, by the hypotenuse, the measured depth. So, Sine 50 ≈ 0.7660 Sine 50 ≈ vertical section ÷ 1000 Sine 50 * 1,000 ≈ vertical section 0.7660 ≈ 766.0 feet In a typical directional well, surveys are calculated at regular intervals with the vertical depth and vertical section part of the survey calculation.

1.2 Basic Hydraulics 1.2.1 System Pressures One of the most important concepts when dealing with hydraulics as it applies to MWD service is that pressure is felt equally throughout a system. While this may seem too sensible to even state formally, it is very important to keep it in mind. When drilling a well, the cuttings, or drilling residue, must be removed from the well bore by some means. The means may be a flow of water, weighted mud, foam, steam or air. Most wells are drilled with either water or some type of weighted mud. The column of water or mud will be called a drilling fluid. Drilling fluids exert hydraulic pressure against the formation. Remember that this pressure is exerted in all directions. The pressure is called the hydrostatic head or hydrostatic pressure. It can be calculated by using the formula: Pressure = 0.052 * Weight of the drilling fluid * Vertical depth Hydrostatic pressure is normally measured in pounds per square inch or psi. In Europe, Asia and some parts of Latin America, the pressure may be measured in Bars. For the purposes of this manual, pounds per square inch will be used. Similarly, Weight of the drilling fluid in the United States is normally stated in pounds per gallon. In parts of

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Europe, Asia and Latin America, it may be stated as grams per cubic centimeter. The example in this manual will use pounds per gallon. When calculating the hydrostatic pressure (also called the Bottom Hole Pressure, or BHP) it is important to remember to multiply by the Vertical Depth if the hole is a directional well. The following example shows how to calculate bottom hole pressure (BHP): Vertical Depth = 10,000 feet Weight of the Drilling Fluid = 10 pounds per gallon BHP = 0.052 * 10 * 10,000 BHP = 0.052 * 100,000 BHP = 5,200 psi The reason it is important to remember that pressure is felt equally throughout the system for a particular depth is that MWD tools are limited to a maximum system pressure, typically 20,000 psi. If the maximum mud weight to be used is 18 pounds per gallon (ppg), what is the maximum vertical hole depth before the system pressure exceeds the tool’s maximum pressure rating? 20,000 psi = 0.052 * 18 * Max_Vertical_Depth Max_Vertical_Depth = 20,000 ÷ (0.052 * 18) Max_Vertical_Depth = 20,000 ÷ 0.936 Max_Vertical_Depth = 18,720 feet Once the tool depth exceeds 18,720 feet, there is a possibility that one or more systems will fail due to excessive pressure.

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1.2.2 Bernoulli’s Principle Squeeze a water hose near the end. Water shoots out of the hose at a high rate. Why? Ask Bernoulli, the person who first explained this phenomenon. In the pinched region of the hose, the cross sectional area of the hose is reduced, an area of low pressure is created and the velocity of the water is greatly increased. The increased velocity causes the water to shoot out of the hose. Figure 1.2.2 illustrates three separate areas with different pressure regions. The pressure is higher before the restriction than in or past the restriction. In the area of restriction, the pressure is relatively low. After the restricted area, the pressure returns to normal.

Higher Pressure Area Direction Of Flow

Pressure is reduced and velocity is increased in this area Pressure returns to normal in this area

Figure 1.2.2 Hydraulic system with a restriction

1.2.3 Annular Velocity Annular velocity (AV) is the speed of a fluid traveling in a closed pressure system such as in the annulus (the ring-shaped space) between the drill pipe and the hole. Erosion on the metal surfaces of the MWD tool as well as around areas where restrictions occur are directly related to annular velocity and the amount of solid material in the mud system. Two types of mud flow will be considered in this manual, turbulent flow and laminar flow. Turbulent flow occurs when the annular velocity reaches a critical point called critical velocity. Below the critical velocity mud flow is laminar (flowing smoothly). Above the critical flow value mud flow is turbulent. Page 28 of 127

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Turbulent mud flow describes a situation in which the fluid column has eddy currents. See Figure 1.2.3.a.

Restriction in this region creates turbulent flow below

Area of turbulent flow

Figure 1.2.3.a Restrictions create turbulence at critical velocity

The area of erosion in Figure 1.2.3.a is right below the two blades on either side of the drill pipe. Laminar flow causes less damage. In the laminar flow region, particles are moving parallel with the object in the hole and very little damage due to erosion occurs. See Figure 1.2.3.b.

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Figure 1.2.3.b

Laminar flow creates very little erosion

Fluid velocity, or as it is commonly called, annular velocity, is usually expressed in units of feet per minute. Use the following formula to calculate fluid velocity: Pump Output * Strokes Per Minute Annular Capacity Pump Output is in Barrels per Stroke

bbls/stk

Strokes Per Minute

spm

Annular Capacity is in Barrels per Foot

bbl/ft

Remember to treat the units as if they were numbers. That is they are added, subtracted, multiplied and divided. Annular capacity is the diameter of the larger cylinder squared minus the diameter of the smaller cylinder squared divided by 1029. Calculate the annular capacity using the following formula: Inside Diameter2 – Outside Diameter2 1029

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If the hole diameter is 9.5 inches and the drill pipe is 5 inches, then the calculation is: 9.52 – 52 1029 90.25 – 25 1029 65.25 1029 0.06341 Assume the pump output is 0.107 barrels per stroke and the pump is operating at 100 strokes per minute: 0.107 bbls/stk * 100 stks/min 0.6341 bbls/ft. 10.7 bbls/min 0.6341 bbls/ft 16.87 ft/min The annular velocity in this case is approximately 16.87 feet per minute.

1.2.4 Pressure Pulses Most of the MWD tools in service today use Bernoulli’s principle to communicate between the tool and the surface computer. The data from the tool are encoded into a series of pressure pulses and decoded at the surface. Figure 1.2.4 shows how the pressure pulses are created.

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Normal state: no restriction

P R E S S U R E

Restriction creates high pressure

Pressure returns to normal

3000 psi High Pressure Pulse = 500 psi

2000 psi

1500 psi 0 psi

TIME Figure 1.2.4 Pressure Pulse Creation

High-pressure pulses are created by a momentary restriction of the hydraulic system (see Figure 1.2.4.). Data are arranged into a series of restrictions. A sensor at the surface converts the mechanical pressure of the pulse to an electrical signal. The electrical signal is sent to a signal converter and then to a computer. The surface computer decodes the data and displays the information on the computer screen.

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1.2.5 Drilling Fluid In the oil and gas industry drilling fluids are collectively called “mud”. Some exceptions are areas where wells are drilled with foam or air. However, the majority of wells drilled in the United States are drilled with mud. For the Tensor MWD system the fluid column of a well acts as part of the communications system or “communications bus”, also called the “qbus”. Instead of communicating with electrical pulses, the system uses changes in fluid pressure to send data. The fluid or “mud” system then becomes part of the qbus, essentially a mud bus. The mud system controls the quality of the mud and is critical to successfully transmitting MWD data through the mud bus. Thicker or more viscous muds affect pulses by creating less sharp peaks. Imagine swimming through molasses compared to swimming through clear water. Just as a swimmer would lose energy more quickly while trying to swim through molasses, the pulse loses energy when transmitted through a viscous fluid. Sometimes gas or air will get into the mud. Both will cause symptoms that look like pulse failures.

1.3 The Drilling Rig The several different types of drilling rigs can be organized into two basic categories: 1) drilling rigs that operate on land and 2) drilling rigs that operate over water, including offshore rigs. Most rigs have some basic parts in common. Learning the names of the basic parts is extremely important since the oil field has developed its own vocabulary. Once the names are mastered, working on a drilling rig will be considerably easier.

1.3.1 Different Types of Drilling Rigs Although the types of drilling rigs are confined to two major categories, the types of rigs that operate in very shallow water in inland lakes, marshes and swamps deserve their own category. These are inland barges. For the purposes of this manual the inland barges will be considered offshore rigs.

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1.3.1.1 Offshore 1.3.1.1.1 Inland Barge As noted in the introduction to this section, the inland barge exists somewhere between land rigs and offshore rigs. They are included in the offshore section because they work over water. An inland barge is a drilling rig that has been mounted on a barge. It is not self-propelled and must be moved by special push boats to the drilling site. It is very rare for an inland barge to drill in more than fifty feet of water. Normally the water depth is less than thirty feet. See Figure 1.3.1.1.1

Figure 1.3.1.1.1 Inland barge

1.3.1.1.2 Platform As the name suggests, the drilling rig sits on a platform. The platform has very long legs on each corner that stand on the bottom of the ocean floor. Generally, the platform rig is involved with production rather than drilling. However, at some platform rigs, new wells are

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being drilled horizontally out from existing wells to increase production. Some platform rigs do not have legs but are anchored to the ocean floor with huge wire cables called tension legs. These type platform rigs are used to drill the initial holes and can be quite large. See Figure 1.3.1.1.2.

Figure 1.3.1.1.2 Platform rig

The depths at which platform rigs operate vary. The tension leg platform rigs can be used in very deep water. Traditional steel leg type platform rigs are usually found in water depths of less than two thousand feet. 1.3.1.1.3 Jack Up Jack up drilling rigs are literally jacked up. They have three or four large legs that are affixed to pontoons. To prepare the rig for transit, the pontoons are filled with air and jacked up to the surface by shortening the rig legs. Tugboats then tow the rig. At the new location, the pontoons are filled with water and jacked down by lengthening the rig legs. The largest jack up rigs may drill in water depths between four hundred and one thousand feet of water. However, the length of their legs limits this type of rig to shallower water. See Figure 1.3.1.1.3.

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Figure 1.3.1.1.3

Jack up Rig

1.3.1.1.4 Semi-Submersible Semi-submersible drilling rigs operate in the deeper waters. These rigs are able to operate in water depths greater than two thousand feet. This type of rig rests on pontoons. Unlike the jack ups the semi-submersible drilling rigs actually float on the pontoons. They are held in position by eight large anchors, with two anchors at each corner of the drilling rig. At one time, the semi-submersible drilling rigs were used only for exploration drilling. Now, the rigs are also used as floating production platforms, especially in the deep water off the coast of Brazil. See Figure 1.3.1.1.4.

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Figure 1.3.1.1.4 Semi-submersible rig

1.3.1.1.5 Drill Ships As the name implies, these ships have been developed specifically for drilling. They operate in very deep water, generally from two thousand to seven thousand feet. See Figure 1.3.1.1.5.

Figure 1.3.1.1.5 Drill ship

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1.3.1.2 Land Land rigs vary less than offshore rigs. The major difference in land rigs is how deep the rigs can drill. No matter what type of drilling rig, land or offshore, the majority of rigs have several parts in common. With few exceptions, the parts will only differ in size. See Figure 1.3.1.2.

Figure 1.3.1.2 Land drilling rig

1.3.2 Parts of a Drilling Rig 1.3.2.1 Rig Floor The rig floor is where the business of drilling a hole takes place. The draw works, traveling block, kelly, rotary table, standpipe and driller’s console are all on the rig floor. Because the majority of work occurs on the rig floor, it is the place where most accidents happen. While on the floor, it is necessary to be alert to avoid being seriously injured. See Figure 1.3.2.1.

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Figure 1.3.2.1 Rig Floor

1.3.2.2 Mud Pumps When the term mud is used, it should be understood to mean a heavier drilling fluid, such as water. Although air or foam may be used to drill a well, the vast majority of wells are drilled with a heavier type of drilling fluid. The mud’s function is to remove the drilling residue (the drilled formation) from the hole. The mud pumps pump the mud downhole and back to the surface where it flows over the shakers. Shale shakers remove the drilled cuttings from the mud. From the shakers, the mud goes to the return pit. It is then sent back to the suction pit where it is pumped back downhole. See Figure 1.3.2.2.

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Figure 1.3.2.2 Mud Pump

If the mud pumps run smoothly, the signal from the MWD tool will be clear and easy to decode. When the mud pumps have problems, the signal from the MWD tool may be compromised. The mud pumps have pulsation dampers that smooth the noise created by the action of the pumps. The pulsation dampers must be set to correct operating pressure for good detection of the MWD pulse signal. Mud pumps come in two varieties, a duplex pump which pumps fluid on the forward and backward stroke of the pump piston and a triplex pump which pumps fluid only on the forward stroke of the piston. Duplex pumps are noisier than triplex pumps and create pulsations that interfere with the MWD signal.

1.3.2.3 Standpipe The mud travels from the mud pumps, through the standpipe, into the kelly, down through the drill string and out the drilling bit. The standpipe is located next to the derrick and is about forty feet tall. Mud goes through a standpipe manifold on the drill floor before traveling up through the standpipe. The pressure transducer, that converts the physical energy of the pulse into an electrical

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signal, is located on the standpipe manifold. It is called the Standpipe Pressure Transducer (SPT).

1.3.2.4 Draw Works Also on the drill floor is a large spool wound with thick wire rope. This is the draw works. It works in conjunction with a huge winch system containing the “traveling block” and the “crown block”. The wire rope, called the drill line, comes off the spool or draw works, is routed to the crown block, goes from the crown block to the traveling block and then to an anchor called the dead line. Both the crown block and the traveling block have a series of pulleys that the drilling line winds around. The crown block is located at the top of the derrick and is stationary while the traveling block moves up and down. See Figure 1.3.2.3.

Figure 1.3.2.3 Typical draw works, land rig example

The drill string is lengthened by picking up a thirty-foot section of drill pipe and screwing it into the pipe already in the hole. The crown block and traveling block hold the weight of the drill pipe while a brake on the draw works controls the release of the weight. Since the drill string is very heavy, the weight of the string pushes the bit into the formation, allowing it to drill. The most common type drill bit has a series of chisel-like teeth on three rollers. The draw works is rotated and as the weight is released, the hole is drilled deeper.

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1.3.2.5 Kelly The kelly is a part of the drilling process, not a person’s name. It is the drive connector at the top of the drill string. Most new rigs use top drives so that fewer connections are necessary to drill the well. Sections of drill pipe are called joints. Joints are usually thirty feet long. Once a joint is drilled down, the kelly is raised and detached from the drill string. The new joint is put in the drill string below the kelly. A typical kelly is about 45 feet long. About 40 feet of the kelly is extended below the surface with the drill string. So the total depth of the hole (called the “measured depth”) equals the length of the drill string plus the part of the kelly extended below the surface. Putting a new joint into the drill string is called making a connection. Directional surveys are often taken when a connection is made. These surveys allow the directional driller to make necessary corrections and keep the hole on the correct course. Much of what the directional driller does involves manipulating the Bottom Hole Assembly to cause the hole to be drilled in the desired direction. Bottom Hole Assemblies are discussed in the next section.

1.4 Bottom Hole Assemblies Bottom Hole Assemblies consist of many different types of specialized drill pipe. These special function pieces are grouped together at the bottom of the drill string, hence the name Bottom Hole Assembly (BHA). The directional driller sometimes needs to change the Bottom Hole Assembly to effect the necessary changes in course direction or angle.

1.4.1 Drill Collars To drill into the formation (the selected volume of earth), the drill bit requires weight, much like a hand drill and drill bit require pressure to drill through wood. Without pressure, the bit will not drill the hole. Pressure on a drill bit is supplied by the weight of very heavy drill pipe called drill collars. The more drill collars in the Bottom Hole Assembly, the more weight that can be imposed on the drill bit. Because drill Page 42 of 127

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collars are larger than normal drill pipe, the number of drill collars that can be used in the Bottom Hole Assembly is limited.

1.4.2 Universal Bottom Hole Orienting Subs Universal Bottom Hole Orienting (UBHO) subs are also called muleshoe subs. A sleeve is inserted into the UBHO sub for the alignment of directional components. See Figure 1.4.2. Names for this sleeve include the muleshoe, the insert, and the orienting sleeve. At the bottom of the MWD tool is a cutaway that mates to a key in the muleshoe insert. This keyed connection orients the directional module to the bend in the Mud Motor (refer to section 1.4.8).

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Orientation Key

Orientation sleeve

Orientation sleeve inserted in the UBHO

UBHO Orientation Sleeve Orientation Key

Top View: Orientation sleeve inserted in the UBHO Figure 1.4.2 Orientation sleeve, key and UBHO

1.4.3 Stabilizers Stabilizers are aptly named. They provide stiffness to the Bottom Hole Assembly (BHA). These specialized pieces have blades on them that are almost the same diameter as the hole being drilled. Putting more stabilizers in the hole creates a stiffer Bottom Hole Assembly. The stiffer the Bottom Hole Assembly, the less the hole will stray from the desired direction. The stabilizer blades’ outside diameter and their placement in the BHA control how the BHA performs while drilling. Additional, smaller Page 44 of 127

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stabilizers, called under-gauge stabilizers are used to either build angle or lose angle, depending on their location in the BHA.

1.4.4 Crossovers Drill pipe, drill collar and other specialized drill string items do not have standardized threads. In order to assemble two drill string elements having different connections, a crossover is used (see Figure 1.4.4).

Box-by-Pin Crossover

Box-by-Box Crossover

Pin-by-Pin Crossover Figure 1.4.4 Different types of crossover subs

A drill string component may have either a protruding, threaded connector, called a pin, or a recessed, threaded connector, called a box. Some drill string components have a box at both. If the end of the piece that it screws into also has a box, a pin-by-pin crossover is used to attach the two pieces. Conversely, the drill string elements may have a pin at both ends of the pipe. To attach this item to another pipe that also has a pin, a box-by-box crossover is used.

1.4.5 Heavyweight Drill Pipe As the name implies, heavyweight drill pipe is heavier than normal drill pipe. Like drill collars, heavyweight drill pipe adds weight to the Bottom Hole Assembly. There is a limit to how much heavyweight drill pipe can be used in the drill string. Too many sections of heavyweight drill pipe make it difficult to adequately control the amount of weight

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transferred to the drill bit. Heavyweight drill pipe is also more expensive than normal drill pipe, so its use may also be limited by cost.

1.4.6 Jars Sometimes the drill string becomes stuck in the formation. It is the job of the jars to help free the drill string. Jars operate by creating a very strong shock in the drill string. This is why the name is appropriate: it jars the drill string loose.

1.4.7 Drillpipe Configuration The drill string is normally configured with the drill collars on the bottom, the heavyweight pipe above the drill collars and drillpipe from the heavyweight to the surface. The mud pumped downhole goes through the kelly then through the drillpipe, the heavyweight, the drill collars and out through nozzles in the drill bit.

1.4.8 Positive Displacement Mud Motors A mud motor rotates the drill bit. It uses the Moineau principle to create rotation. A positive displacement mud motor consists of a molded rubber stator and a steel rotor. The rotor and stator have a helix shape. Rotation results from forcing the mud down through the area between the rotor and stator. A drill string configuration that includes a mud motor allows rotation of the drill bit without rotation of the drill string. Such a configuration therefore allows the drill string to be oriented in new directions. The use of a mud motor to influence drilling direction pre-dates MWD tools. MWD tools complement the mud motor with two critical functions:

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1)

they tell in which direction the hole is being drilled and

2)

they enable the directional driller to orient the mud motor to the desired angle and direction.

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1.5 MWD Tools 1.5.1 What is an MWD Tool? Guiding the hole to its final destination is the job of the MWD tool. It is like a pair of downhole eyes for the directional driller. The MWD tool shows not only how the mud motor is oriented while drilling, but also how successful the orientation has been. MWD stands for Measurements While Drilling. It is part of the Bottom Hole Assembly, typically located right above the mud motor. If no mud motor is installed, the MWD tool is placed as close to the bit as possible. At the most basic level, the MWD tool provides readout of tool facing (how the mud motor is oriented), hole direction and hole angle. MWD tools may also supply a variety of services beyond the basic level. The most revolutionary advance in MWD technology has been the addition of sensors that provide data about hole characteristics while drilling. This advanced level of service is called Logging While Drilling (LWD). It is now common practice to refer to directional-only capable tools as DMWD or Directional Measurements While Drilling. For the purposes of this manual, DMWD tools will be referred to as MWD tools.

1.5.2 Different Types of MWD Tools MWD tools are grouped according to their capabilities and characteristics into two types: retrievable and non-retrievable (also called fixed collar type).

1.5.2.1 Retrievable MWD Tools Retrievable MWD tools are those that may be removed from the drill string in the event the tool fails to function or the drill string becomes stuck. This type of tool has been improved over the years so that it is now comparable in reliability to the non-retrievable type. Retrievable MWD tools tend to have only directional capability. They are used in situations where it is important to control the cost of drilling a hole.

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1.5.2.2 Non-Retrievable MWD Tools The traditional advantage of non-retrievable MWD tools was that they were more reliable than retrievable tools. This is no longer the case. If the tool fails to function downhole, all the drill string must be brought to the surface and the tool replaced. This is an expensive and time-consuming procedure. With a few exceptions, the non-retrievable MWD tools are used for higher-level capabilities.

1.5.2.3 Logging Tools Before the advent of Logging While Drilling, the drilling process had to be stopped and logging tools run in the hole on a wire line in order to obtain both quantitative and qualitative data about the formation through which the hole was drilled. Adding sensors that previously were reserved for wire line operations saved operating companies money and in many cases supplies superior data. The most common type of data supplied by the Logging While Drilling tools are gamma ray activity and formation resistivity. Gamma ray data give an indication of the type of formation being drilled. Resistivity data impart quantitative information about the presence of hydrocarbons. Other developments in Logging While Drilling include providing downhole pressure readings, downhole temperature, formation density, formation porosity, downhole weight on bit and downhole torque on the BHA.

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1.5.3 The Role of the MWD Operator While the primary role of the MWD operator on location is to ensure that the tool works properly, the MWD operator also has a number of supplemental or collateral duties. It is vitally important that the directional driller receive correct data. If a problem occurs with the data, decisions relating to the data will be faulty, causing lost rig time and money. All values relating to the accuracy of directional data must be thoroughly checked. In addition to providing data, the MWD operator on location is the last person in the supply line capable of preventing a defective part or incorrect information from lowering the quality of service provided. The MWD operator must check the equipment to assure that problems are non-existent or minimal. Establishing good communications and having a good working relationship with the directional driller and company man are vitally important. Problems, limitations and requirements for the MWD tools must be communicated to the responsible person(s) in order to plan the work effectively. In a sense, the MWD operator runs a small business at the rig site. Tools and equipment must be kept in good running order. All items sent to the rig or sent from the rig must be accounted for. In some cases, keeping track of daily costs is required. Reports and forms must be filled out in a timely manner and given to the person(s) requesting them with a minimum of delay. An MWD operator represents the MWD service company at the rig site. Unacceptable conduct by the engineer reflects negatively on the service provider. Professional behavior and demeanor are important.

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Chapter 2: Field Operations 2.1 Recommended Paperwork 2.1.1 Equipment Inventory A Tensor MWD “Equipment Inventory Form” accompanies all deployed equipment. The field engineer should fill out this form before returning the equipment box from a job.

2.1.2 MWD Job Sheet Operations provides an “M/LWD Job sheet” which contains basic job information such as Job Number, operating company, well information and directions to the rig.

2.1.3 Environmental/Job Site Information This sheet contains job site magnetic field information including magnetic declination, grid correction and total magnetic field.

2.1.4 Paperwork List This page lists the names of all the forms included in the folder and their locations in the folder.

2.1.5 Job Charge sheet Operations fills out this sheet which details the charges for services provided on the job.

2.1.6 MWD Insurance sheet This form must be filled out before the tool goes downhole. The company man must sign the insurance Form. This form allows the MWD company to provide and charge for insurance on the tool when it is downhole.

2.1.7 Magnetic Declination/Tool Face Offset The company man, directional driller and MWD operator must all sign the Magnetic Declination/Tool Face Offset form to verify that the

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operating company, the directional drillers and the MWD company all agree on the magnetic declination parameter being used.

2.1.8 Survey Tie-in Information sheet The directional driller and MWD operator must both sign the Survey Tie-In Information sheet to verify that the tie-in used by the directional driller agrees with the tie-in used by the MWD company.

2.1.9 Electro-Magnetic Error Report sheet The company man and the directional driller must both review the Electro-Magnetic Error Report sheet to verify the amount of non-magnetic material required above and below the MWD tool.

2.2 Well Site Responsibilities 2.2.1 Arrival at Rig Site Upon arrival at the rig site, check in with the company man and find out whether any special operating procedures are necessary when providing service. Also, meet with the directional driller to determine the following specifications: ■ the flow rate to be used while the tool is in the drill string ■ how often tool face updates are required ■ magnetic declination used by the directional drilling company ■ non-magnetic material required above and below the MWD tool ■ current rig activity For offshore rigs, contact the rig electrician to provide the correct power to the unit and to determine where to run the power line. Contact the tool pusher to check for any special instructions for running cables and installing sensor(s). Land rigs and some inland barges do not have a rig electrician. In such cases, contact the tool pusher to provide the correct power and to determine where to run the power cable and how to connect to rig power.

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2.2.2 Before Rigging Up Quickly check the equipment box inventory. Make sure everything necessary to run the job is available and proper subs and monel drill collars are on location. Call the office immediately if an important piece of equipment is missing.

2.3 Rigging Up Surface equipment Once power to the unit is provided the tool can be programmed and highsided. If power to the unit is not available and time is limited, find a safe area where the SAPS OR SAI and surface computer can be located temporarily, then program and highside the tool from the safe area. Once power is provided to the unit, the SAPS OR SAI and surface computer can be moved to the unit.

2.3.1 Lines and Cables Run all lines and cables so that they are protected from falling objects. This precaution is especially important when running the power cable. Be sure to keep lines away from areas where others might trip over them or where standing water will accumulate. Avoid running sensor cables alongside rig power cables or any other cables that may carry high voltage, as such a layout can interfere with signal detection. Cable connections exposed to weather or moisture should be taped.

2.4 Directional-Only Service 2.4.1 Safe Area Rig-Up 2.4.1.1 Set Up in the Safe Area Set up the SAPS or SAI inside the unit, trailer or other safe area. If offshore, the area should conform to the MMS regulations for a Safe Area (see Appendix A, MMS regulations for Safe Area Rig Up).

2.4.1.2 Use the UPS (Uninterruptible Power Supply) Route power to the SAPS OR SAI through the UPS (Uninterruptible Power Supply) power conditioner to eliminate power spikes. Introduction to MWD

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2.4.1.3 Set Up Computer Set up both the Surface Computer and the Offline Computer.

2.4.1.4 Connect RS-232 Cable Connect the RS-232 cable (a) to the Surface Computer and to the SAPS or SAI. See Figure 2.4.2.1.

2.4.1.5 Connect Programming Cable Connect the programming cable (b) to the tool and to the SAPS or SAI. See Figure 2.4.2.1.

2.4.2 Rig Floor Area Equipment 2.4.2.1 Set Up Terminal Locate an area in the driller’s console to set up the Remote Driller’s Terminal or Rig Floor Display. Use rope, chain or wire to hang the Remote Driller’s Terminal or Rig Floor Display in a visible but unobtrusive location.

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Surface Computer

Remote Driller’s Terminal

Safe Area or Unit SAPS

a

d c

On / Off Switch

Power

Drill Floor

Standpipe Pressure Transducer

b

Outside Unit

Figure 2.4.2.1 Safe area rig up

2.4.2.2 Connect 10-Pin Cable Connect the 10-pin cable from the Standpipe Pressure Transducer (SPT) to the Remote Driller’s Terminal (c). Always connect this cable before connecting the cables on either side of it. This cable is difficult to connect after the other two cables. (See Diagram 3.5.2.).

2.4.2.3 Connect Power/Communications Cable(s) Connect the power and communication cable(s) (d) from the Remote Driller’s Terminal: two cables to the SAPS or one cable to the SAI. Introduction to MWD

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2.4.3 Rig Floor Area Equipment 2.4.3.1 Protect the Standpipe Pressure Transducer Although the Standpipe Pressure Transducer looks rugged, it contains a very sensitive strain gauge element. Be careful when handling the Standpipe Pressure Transducer. Always remove the Standpipe Pressure Transducer before leaving the rig for any reason. Try to position the transducer vertically to prevent mud solids from packing around its base. Mud or debris packed around the transducer can cause signal distortion. Make sure that the transducer is on the pressure side of any valves. Check to make sure that valves in-line with the transducer are open.

2.4.3.2 Install the Standpipe Pressure Transducer 2.4.3.2.1 Locate 2” NPT Female Fitting Find a location on the standpipe that has an available 2” NPT female fitting. 2.4.3.2.2 Connect SPT Insert the Standpipe Pressure Transducer adapter into the available fitting and screw in until hand-tight. 2.4.3.2.3 Tighten SPT Carefully torque the Standpipe Pressure Transducer with a 36” pipe wrench.

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Chapter 3: Introduction to Surveying Surveying is the process of obtaining information about the location of the well bore at multiple depths. The two components of any survey are Inclination (also called angle) and Azimuth (also called direction). Azimuth readings may require correction to fixed reference points. Inclination or hole angle does not require correction. Azimuth and Inclination are both measured in degrees. For Azimuth, the scale is zero to three-hundred-and-sixty degrees. For inclination, the scale is zero to onehundred-and-eighty degrees, but inclination rarely goes over one hundred degrees. Azimuth and compass direction are not identical. Where azimuth direction is measured from 0 degrees at due north and proceeds clockwise to 359 degrees, compass direction can start at either 0 degrees north or 0 degrees south, and proceed to 90 degrees east or west. Compass direction is an older method of identifying direction but is still used in some cases. Whether compass or azimuth is used, the raw azimuth readings must be corrected from Magnetic North to True North and may be corrected to Grid North. Magnetic North, True North and Grid North serve as reference points. They serve as familiar objects to help locate one point in relation to another. It is important to know whether a survey is correct or flawed. Some indicators that help make that determination are Magnetic Dip Angle, Total Magnetic Field and Total Gravity Field. These indicators serve as quality factors when evaluating a survey.

3.1 Reference Points Look around you. How do you know where you are? In a featureless landscape you would have difficulty determining your position. Now suppose you see a tree fifty feet south of a house and thirty feet west of a barn. You are standing half way between the house and the tree and ten feet from the barn. You can now determine your position very precisely. The same principle works with surveying. It is important to establish reference points. Unfortunately, several different reference systems are used in well surveying. The system used depends upon the well’s location. However, all of these reference systems relate to Magnetic North.

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3.1.1

Magnetic North Magnetic North is the most important reference point in directional surveying. In the absence of magnetic interference, magnetometers point to Magnetic North. The earth has a magnetic field like that of a magnet. See Figure 3.1.1.a.

Figure 3.1.1.a The Earth is like a giant magnet.

Magnetic North changes with time on a cyclical basis. Changes in Magnetic North can be modeled using sophisticated computer programs and accounted for when taking surveys. True North and Magnetic North are not perfectly aligned. Survey azimuths must be corrected for the difference between the two. Azimuth is the direction of the hole in relation to north. An azimuth reading is given in degrees from 0 for north, 90 for east, 180 for south, 270 for west and back to 0. Both 0 and 360 degrees signify north.

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N

North is 0° Azimuth

W

E

West is 270° Azimuth

East is 90° Azimuth

S

South is 180° Azimuth

Figure 3.1.1.b Azimuth is measured in circular degrees from north.

Direction is also presented in compass form, especially when using older survey instruments such as a magnetic single shot. In the compass system the circle is divided into quadrants or four equal parts. Compass directions start at zero at north and south and increase to ninety degrees going east or west. Compass quadrants are northeast, southeast, southwest and northwest. When giving direction with compass quadrant, north or south is always stated first, then the degrees from north or south and finally the east or west direction. Direction is in degrees from north or south, so north 30 east (or N30E) is thirty degrees east of north, while south 70 west (or S70W) is seventy degrees west of south. See Figure 3.1.1.b.

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North

North 30 East (N30E) North East

North West West

East

South 70 West (S70W) South West

South East South

Figure 3.1.1.c Compass Direction

3.1.2

True North Geographic North or True North is one end of a line drawn through the center of the earth’s rotational axis. Magnetic North is one end of a line drawn through the center of the earth’s magnetic field. The lines lie near one another and both extend through Antarctica, but they are not aligned. They diverge and provide two different points of reference. See Figure 3.1.2.

Figure 3.1.2 Geographic or True North

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In Louisiana the difference between True North and Magnetic North is about 1 to 3 degrees. Going west from Louisiana, the correction becomes larger. Corrections are always made from Magnetic North to True North.

3.1.3

Grid North Map North or Grid North is another north reference used in surveying. Several different Grid North systems are used, depending upon rig location. This manual will cover Lambert Projection and Universal Transverse of Mercator or UTM. Both systems convert the earth’s curved surface onto a flat plane but use different methods. The Lambert Projection projects the earth’s surface onto a cone. The point or vertex of the cone can be over geographic north or south, depending on which hemisphere is to be mapped. See Figure 3.1.3.a.

These grid lines are projected onto a flat plane

Dashed lines are conic lines projected onto a flat plane

Arrows Point to geographic north

Figure 3.1.3.a

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Geographic north and Map North are different. The difference between them will be greater or smaller depending on where the rig is located on the earth’s surface. Where Lambert Projection uses a conic section, UTM takes points along the earth’s surface and presents it on a cylindrical plane laid flat. To visualize how this is done, assume that the earth is transparent with a light in the center. Now roll a sheet of photographic film in a cylinder around the earth as shown in Figure 3.1.3.b. Light rays travel from the center outward striking the cylindrical film, projecting a flat image of the earth’s curved surface.

P1: The projection touches the outside of the cylinder.

P: A projection from the center of the earth contacts the earth’s surface.

Q1: The projection touches the outside of the cylinder.

Q: A projection from the center of the earth contacts the earth’s surface.

Central Meridian: Any projection on this line points to geographical north. Figure 3.1.3.b Universal Transverse Mercator

Points along the Central Meridian have correct scale values while those to the east or west have distorted scale values. Remember that the earth is divided along lines of Latitude and Longitude. Latitude measures a point’s distance north or south from the Equator. Longitude, also called departure, measures how many

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degrees east or west a point on the earth is from a reference line called the Greenwich Meridian. The Greenwich Meridian goes through Greenwich, England and is Longitude 0°. Latitude and Longitude are both measured in degrees. The UTM system maps the earth’s surface as 60, six-degree-wide, north-south sections, or zones, each centered on a reference meridian. The zones are numbered from one to sixty, starting at 180 degrees west longitude. The UTM zones introduce no scale distortion. Magnified Section

12°

6°

0°

6°

12°

WEST

Figure 3.1.3.c

EAST

UTM maps the earth’s surface as sixty, 6° sections.

Each UTM zone is also divided horizontally in 8° increments of latitude starting at the Equator. The latitude divisions are lettered for identification. For instance, the section covering the Louisiana Gulf coast is Zone 15R. See Figure 3.1.3.d. Zones extend from 80° Latitude south to 84° Latitude north. The location of any point within a zone is stated in meters from the reference meridian and meters from the equator. See Figure 3.1.3.d. The distance above the horizontal lines is called Northing while the distance from a zone’s central meridian is called Easting. UTM has

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assigned starting values for the central meridians and equator to make location values more convenient. The zones are divided into squares of 100 by 100 kilometers and may be further subdivided into squares of 10 by 10 kilometers. One kilometer is 1,000 meters.

Figure 3.1.3.d

UTM Zones of the United States

Figure 3.1.3.e

Location is calculated in meters from reference lines

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Universal Transverse Mercator Zone Locations and Central Meridians (CM) Zone 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

CM 177W 171W 165W 159W 153W 147W 141W 135W 129W 123W 117W 111W 105W 099W 093W 087W 081W 075W 069W 063W 057W 051W 045W 039W 033W 027W 021W 015W 009W 003W

Range 180W-174W 174W-168W 168W-162W 162W-156W 156W-150W 150W-144W 144W-138W 138W-132W 132W-126W 126W-120W 120W-114W 114W-108W 108W-102W 102W-096W 096W-090W 090W-084W 084W-078W 078W-072W 072W-066W 066W-060W 060W-054W 054W-048W 048W-042W 042W-036W 036W-030W 030W-024W 024W-018W 018W-012W 012W-006W 006W-000E

Zone 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

CM 003E 009E 015E 021E 027E 033E 039E 045E 051E 057E 063E 069E 075E 081E 087E 093E 099E 105E 111E 117E 123E 129E 135E 141E 147E 153E 159E 165E 171E 177E

Range 000E-006E 006E-012E 012E-018E 018E-024E 024E-030E 030E-036E 036E-042E 042E-048E 048E-054E 054E-060E 060E-066E 066E-072E 072E-078E 078E-084E 084E-090E 090E-096E 096E-102E 102E-108E 108E-114E 114E-120E 120E-126E 126E-132E 132E-138E 138E-144E 144E-150E 150E-162E 156E-162E 162E-168E 168E-174E 174E-180W

Table 3.1.3 A list of UTM zones: Louisiana is in Zone 1.

3.2 Corrections Since Magnetic North and True North are not aligned, survey calculations must account for the offset. If a grid system is used, further corrections must be made.

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3.2.1

Magnetic Declination Magnetic Declination is the difference, in degrees, between Magnetic North and True North at a given location. An uncorrected azimuth, called a raw reading, is first corrected for Magnetic Declination, and then for other corrections as necessary. Declination correction from Magnetic North to True North may be either east or west. If the declination correction is east, the number is added, if west the number is subtracted. See Figure 3.2.1.a and 3.2.1.b. Values for Magnetic Declination change and are updated every six months. The values are taken from magnetic monitoring stations placed throughout the world. Figure 3.2.1.a shows the correction from Magnetic North to Geographic (True) North. If the measured azimuth is 65° and the difference between Magnetic North and True North is 10° east, add ten to the measured azimuth for a corrected reading of 75° east. The correction from measured azimuth to True North is subtracted if the correction is west. In figure 3.2.1 b, the correction is added because, in this example, Magnetic North is east of True North.

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Geographic North

Magnetic North

The correction between Magnetic North and Geographic North

The tool’s actual measurement Measured Azimuth

EAST

WEST Figure 3.2.1.a

Correcting Azimuth to Geographic North, east declination

East declination is always added, to increase the angle between the measured azimuth and True North. West declination is always subtracted to decrease the angle between measured azimuth and True North. See Figure 3.2.1.b.

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Geographic North

Magnetic North

The correction between Magnetic North and Geographic North

The tool’s actual measurement

Measured Azimuth

EAST

WEST

Figure 3.2.1.b Correcting azimuth to Geographic North, west Declination

If the measured azimuth is 95° and the Magnetic Declination is 20° west, the corrected Azimuth is 75° east. The rule of adding east declination and subtracting west declination only applies to azimuth direction. When dealing with compass direction the rules change. Compass directions are divided into quadrants. See Figure 3.1.1.b. Which quadrant the direction is in determines whether declination is added or subtracted. See Figure 3.2.1.c.

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North

-

+

West

East

-

+ South

East Declination

North

-

+ West

East

-

+ South

West Declination Figure 3.2.1.c

Adding or Subtracting compass declination

If the direction is N30E and the magnetic declination is 10° east, the corrected direction is N40E. If the direction is S70E and the magnetic declination is 10° east, the corrected direction is S60E. If the declination correction is 10° west, N30E is corrected to N20E and S70E is corrected to S80E.

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Compass direction is rarely used with MWD tools. However, single shot instruments, magnetic multishots and gyro survey instruments still use compass direction.

3.2.2

Grid Correction When correcting from Magnetic North to True North, the angle must be adjusted to conform to True North. Further, when correcting from True North to Grid North, the angle must be adjusted to Grid North. The grid correction is subtracted from the True North reading. East grid correction remains positive and west grid correction remains negative. The result of grid correction is called grid convergence. Grid convergence will be zero if the magnetic declination is zero and the hole location falls along a central meridian. Magnetic North

True North

Grid North is 15° West of True North

Measured Azimuth is 85° east

Grid North Measured Azimuth Magnetic declination is 10° west of True North

West

Figure 3.2.2.a

East

Correcting to Grid North

The measured azimuth in Figure 3.2.2.a is 85° east, the Magnetic Declination is 10° west and the Grid correction is 15° west. Calculate Grid convergence: Total Correction = Magnetic declination – Grid correction Total Correction = (-10) – (-15) Total Correction = (-10) + 15

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Total Correction = 5 In this example, 5 degrees are added to the raw azimuth reading of 85 degrees east. The calculated azimuth is: Corrected Azimuth = 85 + 5 Corrected Azimuth = 90° east Corrected azimuth is 90 degrees east. convergence is subtracted.

Notice that the grid

Consider what happens when the magnetic declination correction is east rather than west and grid correction remains west. In this case, magnetic declination is positive while grid correction remains negative. See Figure 3.2.2.b. True North Magnetic North Grid North

Measured Azimuth

West

East

Figure 3.2.2.b 10° east magnetic declination, 15° west grid correction

If the measured azimuth is 55°, the magnetic declination is 10° east and the grid correction is 15° west as in Figure 3.2.2.c, then the corrected azimuth is 80° east. Total correction is calculated by: Total Correction = Magnetic declination – Grid Correction Total Correction = 10 – (–15) = 25

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Total Correction = 25° east Corrected Azimuth = Raw Azimuth + Total Correction Corrected Azimuth = 55° east + 25° east. Corrected Azimuth = 80° east

3.3 Quality Factors Once the survey data are transmitted uphole by the MWD tool, three quality factors are used to determine if the survey data are valid. The quality factors used are:

■ Magnetic Dip Angle (sometimes referred to as Mag Dip) ■ Total Magnetic Field ■ Total Gravity Field It is absolutely essential that an MWD operator know how these factors work and whether or not they indicate bad readings.

3.3.1

Magnetic Dip Angle Lines of magnetic force radiate from the earth’s core. The angle at which magnetic force lines penetrate the earth’s surface determine the strength of the magnetic field. A vector is a line that has both magnitude and direction. Figure 3.3.1 shows that the magnetic dip angle is the angle between the Magnetic North horizontal line (Line C) and the magnetic field vector (Line B).

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Line C: Magnetic North

Location A: Magnetic Dip is 50°

Location B: Magnetic Dip is 1°

Line B: magnetic field vector line

Dashed lines represent earth’s magnetic field

Figure 3.3.1 Magnetic Dip Angle

Magnetic dip angle is also called magnetic inclination. It is rarely either zero or ninety degrees. The dip angle is zero at the Equator and ninety degrees at the point on earth where Magnetic North is located. The places on earth where the dip angle is ninety degrees are called dip holes. For some common magnetic dip angle values around the world see Table 3.3.1. Notice that those areas near or south of the equator show negative values. When the lines of magnetic force enter through the South Pole, the magnetic dip values are negative. Magnetic inclination is calculated for each rig location. The known values are compared to what the MWD tool transmits. Small differences may indicate the presence of magnetic interference. Values should not vary by more than 0.3°.

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Area Assen, Holland

Magnetic Dip Angle 67°

Gulf of Mexico, Louisiana

59°

Lake Maricaibo, Venezuela

44°

Muscat, Oman

35°

Singapore

-17°

Rio de Janiero, Brazil

-35°

Table 3.3.1 Magnetic Dip Angle values to the nearest whole degree

3.3.2

Total Magnetic Field Total magnetic field is measured in units of gauss, tesla, or gamma. In some tables, it will be given the abbreviation “F”. The relationship between the various units is summarized in table 3.3.2. 1 gamma

Is equal to

1 nanotesla

1 micro tesla

Is equal to

1000 gamma

1 tesla

Is equal to

1,000,000,000 gamma

1 gauss

Is equal to

10,000 gamma

1 gauss

Is equal to

.0001 tesla

1 gauss

Is equal to

1 oersted

Table 3.3.2 Magnetic field strength units

Note: The conversion factors in table 3.3.2 are correct, but further conversion factors may not necessarily follow from them. For example, though one tesla equals 1,000,000,000 gamma and one gauss equals 10,000 gamma, one gauss does not

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equal 0.00001 tesla. Rather, one gauss equals 0.0001 tesla, as stated on table 3.3.2. The strength of earth’s magnetic field shows a subtle variation. It varies from roughly 60,000 gamma (or 60 micro tesla) at Magnetic North to around 27,000 gamma (27 micro tesla) at the equator. The most important part of the magnetic field strength is the horizontal component. Sometimes the horizontal component of the magnetic field strength is written as “H”. See Figure 3.3.2. Geographic North

Magnetic Declination

X Magnetic North

H Y

East Magnetic Inclination

Down

F

Z Figure 3.3.2 Horizontal Component of Earth’s magnetic field

The horizontal component determines how strongly a compass needle or any magnetic material is pulled to the north. Magnetic inclination determines the strength of the horizontal component. To calculate the horizontal component Total Magnetic Field strength is multiplied by the cosine of the magnetic dip angle. If the Total Magnetic Field strength for Houston, Texas is 48,838 gamma and the magnetic dip angle is 59.25 degrees, the horizontal component is: 48,838 gamma * cosine 59.25 = 24,970 gamma

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Near Magnetic North the horizontal component is less because the magnetic dip angle is greater. For example, the total magnetic field around Great Slave Lake, Canada is approximately 59,774 gamma and the magnetic inclination is 83.5 degrees. 59,774 gamma * cosine 83.5 = 6,766 gamma Total Magnetic Field (TMF) is the vector sum of the X, Y, and Z components. See Figure 3.3.2. Calculate the vector sum using the following method: TMF = √ X2 + Y2 + Z2 Using the example from Great Slave Lake Canada, the X component is 6153 gamma, Y component is 2753 gamma and Z component is 59393 gamma. TMF = √ 6,1532 + 2,7532 + 59,3932 TMF = √ 3,572,966,867 TMF ≈ 57,774 gamma Notice that most of the force is in the down direction for Great Slave Lake while proportionately less force is in the down direction for Houston. Magnetic component data for Houston show that: H = 24,970

X = 24,894

Y = 2,000

Z = 41,970

Magnetometers are very sensitive instruments and variance between the calculated Total Magnetic Field and that transmitted by the tool should not be more than 350 gamma. If the variance is greater than 350 gamma, magnetic interference may have influenced the measurement.

3.3.3

Total Gravity Field Total Gravity Field (TGF) takes input from three axes. In most cases, the Z-axis is pointed down hole. The Total Gravity Field is the sum of the output from three accelerometers arranged in an orthogonal (three axes) system. See Figure 3.3.3. Accelerometers measure either a change in velocity or a change in the relation between the downhole or Z-axis and the earth’s gravity field. At very low angles, the strength of the gravity field will be relatively small, with input from the X and

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Y-axes providing proportionately larger values than at higher inclinations.

The force of gravity is straight down.

Figure 3.3.3 Z-Axis is down hole

The force of gravity is always straight down. As the Z-axis comes closer to horizontal, the force of gravity is greater on the Z-axis. This is why hole inclination or angle is less accurate at lower angles. Total Gravity Field is the vector sum of the three axes. TGF depends upon the altitude of the rig location and the mass of the earth below the location. However, the values are very close to the value one. TGF = √ X2 + Y2 + Z2 Since gravity’s influence is greater on the Z-axis that value is larger than the X or Y-axes values at hole angles greater than ten degrees. Suppose the hole angle is twelve degrees. Assume the X- axis value is 0.3 and the Y-axis value is 0.1. TGF = √ 0.32 + 0.12 + 0.952 TGF = √ 0.09 + 0.01 + 0.9025 TGF = √ 1.0025 TGF = 1.00125

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Variation from the local Total Gravity Field by more than 0.003 gravity indicates a possible problem. A bad inclinometer might not be the source of the problem. With flow-off surveys, any movement of the drill pipe while the pumps are off may give TGF values that are not within specification.

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Chapter 4: Transforming Influences Before calculating surveys, the MWD operator must check the survey information for validity. Though most surveys are not exposed to transforming influences, one or several transforming influences may cause erroneous readings and corrupt survey data. Magnetic interference is the primary cause of incorrect survey data. The most likely source of magnetic interference is the BHA (bottom hole assembly). Magnetic interference may also come from the formation. Formations may contain natural magnetic material. They may also contain drill strings or casing left from an earlier well. Another potential source of magnetic interference is Solar Wind, which constantly buffets earth’s magnetosphere with polarized magnetic particles. When high solar flare activity increases the amount of particles, solar winds may create errors in azimuth data. Aside from natural phenomenon, operator or service provider errors can create bad data. Certain common errors, such as calibration error, can be costly and must be avoided. An incorrectly calibrated tool may introduce enough error that the hole is drilled in the wrong direction. Errors in survey technique may also create problems. Small errors in technique can result in large errors in survey data. It is imperative that the MWD operator recognize those conditions which may cause error and report them as soon as possible to all responsible parties.

4.1 Magnetic Interference From BHA With some types of electromagnetic waves, shielding or insulation mitigates harmful interference. This is not true of magnetic interference. The only way to ensure that a tool is not influenced by magnetic forces (other than the earth’s magnetic field) is to get the tool away from those forces. Magnetic force varies by the square of the distance from the magnetic material. For instance, if the total magnetic field is 10,000 gamma at 2 feet, it will be 2500 gamma at 4 feet and 625 gamma at 8 feet. See Figure 4.1.

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Resultant field strength = Original field strength distance2 Example: Distance 2’

Strength

Calculation

10,000

4’

2,500

10,000 (4/2)2

8’

625

10,000 (8/2)2

or

2,500 (8/4)2

Strength Distance Figure 4.1 Magnetic field strength varies by the square of the distance

If the essence of real estate is “location, location, location,” the essence of magnetic interference is distance, distance, distance! Non-magnetic spacing is especially important when planning the bottom hole assembly. Enough non-magnetic drill collars and subs should be available to distance the BHA from magnetic drill string components and remove the potential of magnetic interference. The drill string and its steel components are similar to the bar magnet presented in Chapter 3, Figure 3.1.1.a. Each steel component, if separated by a non-magnetic component of sufficient length, will have its

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own north and south poles and will not link magnetic fields with other steel components. See Figure 4.1a.

Non-magnetic material

Figure 4.1.a Steel components separated by a non-magnetic component

4.1.1 Hole Angle As the inclination of the hole increases, the influence of magnetic interference from the drill string increases. See Figure 4.1.1. The influence increases because the horizontal component of the drill string becomes a larger percentage of the magnetic field influencing magnetic measurement.

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Example A: Hole angle is 0°. Magnetic field of steel component

Accelerometer Magnetometer

Distance to magnetometer is 5 feet

Total magnetic field intensity from drill string component is 1000 gamma. Horizontal Component of tool axis relative to vertical is 90° Total magnetic field at 5 feet equals 1,000 ÷ 52 = 40 40 * Cosine 90 = 40 * 0 = 0 The Horizontal Component has no effect on the magnetic reading.

Non-Magnetic Drill Collar Example B: Hole angle is 45°. Horizontal Component of tool axis relative to vertical is 45° Total magnetic field at 3.5 feet equals 1,000 ÷ 3.52 = 87 87 * Cosine 45 = 57 The Horizontal Component contributes 57 gamma to the magnetic reading Distance to Magnetometer is 3.5 feet. Figure 4.1.1 Drill string magnetic interference increases with inclination

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The total field strength does not change. The amount of interference due to the horizontal component does change with drill string inclination.

4.1.2 Hole Direction Drilling due north or south reduces interference from steel components in the BHA, while drilling due east or west increases that interference. In order to understand this, remember that the magnetic inclination near the equator is around one degree. Due east or west is then approximately parallel to the horizontal component of the earth’s magnetic field, while due north or south is almost perpendicular to the horizontal component. Because the east / west direction is roughly parallel to the horizontal component, the influence of the field pulling in the direction of Magnetic North is greatly reduced. As the horizontal component of the magnetic field decreases in strength, magnetic force from the BHA becomes a larger portion of the total magnetic field strength. See Figure 4.1.2.

Borehole perpendicular to the horizontal component of The earth’s magnetic field

Borehole parallel to the horizontal component of The earth’s magnetic field

Figure 4.1.2 Effect of direction on horizontal component

Drilling at high angles along the east / west line produces a greater likelihood of interference from the BHA because the horizontal

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component of the drill string’s magnetic field is a greater proportion of the total magnetic field.

4.1.3 Latitude As discussed in chapter 3, section 3.3.1, moving closer to Magnetic North reduces the contribution from the horizontal component of the earth’s total magnetic field. The magnetometers respond to the horizontal component. Any reduction of the earth’s magnetic influence equals greater influence from the magnetic field of the drill string. See Figure 4.1.3.

Latitude 68° North

Great Slave Lake, Canada

Latitude 24° North

Houston, Texas

The horizontal component is approximately 3.7 times greater at Houston, Texas than at Great Slave Lake, Canada

Figure 4.1.3 Higher latitude reduces horizontal component

At higher latitudes, both north and south, more non-magnetic spacing is required to reduce interference from the drill string. Every company providing MWD services has a method to either calculate the required non-magnetic spacing or has a look up chart for the local conditions.

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4.1.4 Not Enough Non-magnetic Material Since distance is required to reduce a magnetic field’s influence, insufficient non-magnetic spacing will allow magnetic interference. Any company that provides MWD services should have a method to either calculate or look up the non-magnetic spacing required for local conditions.

Shaded area represents the magnetic field of the steel collars Steel Drill Collar Magnetometer in non-magnetic drill collar Steel Drill Collar Figure 4.1.4a Too little non-magnetic spacing

In Figure 4.1.4a there is too little non-magnetic material. The surveys will be influenced by the magnetic field of the drill string. As a result the azimuth reading will be incorrect. Magnetic interference from the drill string is calculated by taking the magnetic force of the drill string and dividing it by the length of non-magnetic material in the string. To calculate the amount of interference takes a little guesswork. The strength of the magnetic field of steel drill collars, mud motors, crossover subs and stabilizers is rarely measured when they are put in the BHA. Some approximations have been made based upon experience. For instance, mud motors can produce anywhere from 500 to 2500 gamma. Steel components separated by non-magnetic spacing may generate 500 to 800 gamma, depending upon length. For the purposes of this document, 2500 gamma are used for a mud motor and 500 gamma are used for other steel components. A short steel sub 2 feet long is assigned a value of 50 gamma. Assume the BHA has the following configuration from the bit up:

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30

M1: Non-magnetic material above magnetometer

NMa

10 M2: Magnetometer in non-magnetic collar 20 NMb

15

30

M3: Non-magnetic crossover

S1: Steel drill collar

Sb

2

S2 : Bit

Figure 4.1.4.b BHA configuration

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In Figure 4.1.4.b the abbreviations mean: NMa

=

Length of non-magnetic material above sensor

NMb

=

Length of non-magnetic material below sensor

Sb

=

Length of steel below sensor

In order to calculate the effect of magnetic interference on the magnetometer use the following formula: IF = LP d2 Where: IF

=

Magnetic Interference force

LP =

Strength of field

d

Distance from field

=

Calculating the effect on azimuth requires the following information about the location: F

=

DM =

Earth’s total magnetic field strength Magnetic dip of the total magnetic field

Obtain from surveys: HI

=

Hole inclination

AR = Uncorrected Azimuth (Azimuth without Magnetic declination or Grid Correction) Obtain from directional driller: Bottom Hole Assembly Report Use common accepted values for: Pole strength of magnetic material (LP) If the pole strength of the magnetic components below the non-magnetic collars is 2500 gamma IF = (2500 ÷ (NMa)2) + (2500 ÷ (NMb) 2) – (2500 ÷ (NMa + NMb +Sb) 2) = (2500 ÷ 402) + (2500 ÷ 352) – (2500 ÷ 1072) ≈ 1.5625 + 2.0408 – 0.2184 = 3.3849 gamma Employ magnetic dip and total field strength for Houston, Texas (See Chapter 3, Section 3.3.2.) Hole inclination (HI) is 60° and uncorrected azimuth (AR) is 45°. To find out the azimuth error (EA) use:

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EA = (48838 * IF * Sine HI *Sine AR) ÷ (48838 * Cosine D) = (48838 * 3.3849 * Sine 60 * Sine 45) ÷ (48838 * Cosine 59.5) ≈ 101232.3567 ÷ 24787.1586 ≈ 4.0841 Azimuth is incorrect by 4.0841 degrees. Since there is no indication of the direction in which the error occurs, this cannot be used to correct the azimuth.

4.1.5 Hot Spots Drill collars and other steel components may develop local areas where the magnetic field strength is greater than normal. These are called “hot spots” in the component. Any component that has a hot spot creates greater magnetic interference than expected. It is difficult to account for theses areas because of the interaction of the steel collar with the mud column. As the mud is circulated, it creates a small magnetic field across steel components. The hot spot may be intensified by this action. Even if the magnetic field is measured at the surface, it may not be discovered until conditions are no longer static.

4.2 Magnetic Interference From Formation Magnetic interference can come from any source. Drilling through a formation that contains magnetic material certainly will create interference. However, the material may not be a natural constituent of the formation. Occasionally a drill string gets stuck in its hole and is left in place. A “fish” or drill string left in its hole will create erroneous readings if a new well is drilled too near the fish. Casing is also a source of magnetic interference. When drilling out from casing, it is important to get far enough away in order to obtain an acceptable survey.

4.2.1 Formation Constituents Wells are generally not drilled in areas containing massive iron ore deposits. Some iron-bearing formation types do affect azimuth readings. For example, a formation may contain oolitic pyrite deposits large enough to present problems. If magnetic interference is suspected check with the well site geologist to find out if magnetic material is in the formation samples.

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4.2.2 Steel Components in the Hole A “fish” is a portion of a drill string left in the hole on a previous well. It is a sure source of magnetic interference. Ensure that the current well bore is far enough from the fish to prevent magnetic interference. At certain intervals during the drilling process, casing is set. Casing, comprised of steel tubes threaded together, keeps the hole stable. Since the drill string passes through the set casing, the magnetometers must be drilled far enough beyond the casing to ensure that surveys are not influenced by magnetic interference.

4.3 Magnetic Interference From Solar Flares About ninety percent of the earth’s total magnetic field is generated internally and approximately ten percent is contributed by solar wind sweeping over the earth’s magnetosphere. Severe changes in the solar activity may affect azimuth readings. Magnetic storms created by solar flares may be intense enough to interfere with magnetic readings on earth. Some of the solar activity occurs on a cyclical basis and is not intense enough to create problems. However, random solar flares have the potential to generate magnetic interference. Most companies that provide MWD service issue warnings if solar activity is causing problems.

4.4 Incorrect Operator Input The best systems in the world will be rendered useless by a careless or inept operator. If the MWD operator incorrectly enters the magnetic declination, then not only will the surveys be incorrect, but the magnetic toolfaces will be incorrect as well. Omitting or incorrectly calculating grid correction creates the same problem. A well drilled in the wrong direction may cost the client a considerable amount of money. A competent MWD operator knows no substitute for careful attention to detail.

4.5 Incorrect Calibration Magnetometers and accelerometers are sensitive to temperature changes, especially accelerometers. The tools must be calibrated to account for changes in temperature. If the tool is calibrated incorrectly, the azimuth readings will be incorrect.

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4.6 Survey Technique Good surveys are no accident. However, they may be difficult to obtain, given the number of things that can create incorrect readings. The MWD operator must be aware of the many hidden problems that can make an apparently good survey give misleading information.

4.6.1 Drill String Movement Surveys can be taken either while the pumps turned off or on. Proper pump status during surveys depends on the type of system powering the tool electronics. If batteries are used, the surveys are normally taken with the pumps shut down. If a turbine/alternator is used, the surveys are taken with the pumps turned on. When taking surveys with the pumps off, the drill string must not be moved. Otherwise, the accelerometers will interpret the movement as acceleration in the plane of movement. In such a case, the inclination and possibly the azimuth will be incorrect. Movement can also cause errors in a “pumps on” survey. After the pumps are turned on, the tool delays before it starts pulsing. The survey is acquired during this delay. If the pipe is moved during the survey acquisition time, the inclination and possibly the azimuth readings will be corrupted. A corrupted survey may appear to be normal. However, movement errors should show up in the total gravity field. If the TGF looks suspicious, retake the survey.

4.6.2 Bad Detection Sometimes a survey may look good but actually be misleading. This problem occurs when the surface system decodes pressure pulses that are not part of the actual data stream or pulses that are slightly out of synch with the surface gear. When a survey appears abnormal, bad detection should be considered as a possible cause. Verify that all detection parameters are set correctly.

4.6.3 Stored Surveys When a battery-operated tool obtains a survey, it keeps the survey data in memory until data from the next survey replaces it. A problem results when the pumps are not shut down long enough to take a new survey. In this case, the tool sends up data from the last survey point,

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not the current depth. correct.

Such out-of-place data may appear to be

Tool operating parameters should be set up so that an old survey is never sent in place of a current one. Additionally, the MWD operator should recognize the problem if it does occur.

4.6.4 Incorrect Survey Depth An error as simple as failing to keep up with the correct depth can cause an otherwise correct survey to give false information. This problem is most severe when the angle or direction changes greatly from one survey to the next. The consequences of incorrect survey depth are severe. See Figure 4.6.4 for an example of taking surveys at the wrong depth. Survey station #1 is at the correct depth but survey station #2a is taken at the wrong depth. The geologist, thinking that Survey station #2a is really at the point indicated by survey station #2b, wants the angle increased to enter the productive sand. The directional driller increases the angle of the hole, but misses the sand because he was given misleading information. Had the well be drilled with correct information, it would have followed the path indicated by survey stations 3a and 3b. Note that the dashed-and-dotted line intersects the productive sand at the desired angle. Related to taking surveys at the wrong depth is using the wrong sensor offset. Survey depth is the depth at which the magnetometers and accelerometers operate. If the survey sensors are not offset from the bit depth or are incorrectly offset, surveys will be taken at the wrong depth.

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Measured Depth

Survey station #1 Survey station #2a True vertical depth

Survey station #3a Survey station #2b Survey station # 3b

Productive sand

Vertical Section Figure 4.6.4 Survey at wrong depth

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Chapter 5: Calculating Bottom Hole Location To survey a well bore, the MWD operator calculates well bore position in two dimensions. True Vertical Depth (TVD) is plotted versus Measured Depth (MD) in the vertical plane. Looking down hole from the surface, the direction is plotted on North/South and East/West or horizontal axis. See Figure 5.

Measured Depth

North

1000 2000 3000

Planned well path plotted in the vertical plane

Actual well path

4000 5000

East

6000 7000

Planned well path on the North/South and East/West axes

8000 9000 10000 11000

True 0 Vertical Depth

100

200

300

400

500

Vertical Section

Figure 5 Location of the drill string in the well bore

This chapter presents several methods of calculating surveys. Although the methods are quite different, the differences are minute as long as surveys are taken close together.

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5.1 Calculating Bottom Hole Location In Figure 5.1, looking at the vertical plane is like looking at the hole from the side, with the Earth sliced down along the well bore. The solid line is the actual path of the well bore and is plotted using information from surveys. Inclination (I, Figure 5.1a) refers to the hole angle relative to an imaginary line perpendicular to the earth’s surface. Azimuth (A, Figure 5.1.b) refers to the direction of the hole in relation to Magnetic North. Measured Depth (M, Figure 5.1a) means how deep the hole is drilled along the well path. True Vertical Depth (V, Figure 5.1.a) is the distance straight down from the surface origin to the level of the survey or bottom hole. Note that Measured Depth and True Vertical Depth are only identical when the hole is drilled straight down. The difference between Measured Depth and True Vertical Depth depends on the angle at which the hole is drilled. The difference increases as hole angle increases. An imaginary horizontal line drawn from the target (the proposed bottom hole location or PBHL) to the vertical line descending from the origin (the bore hole start point on the surface) is called the Vertical Section (S, Figure 5.1.a and 5.1.b).

Earth’s Surface

V

M I

S

Figure 5.1.a Parts of a survey – Vertical Plane

In addition to the vertical plane presented in Figure 5.1.a, a view is taken from the origin of the hole to the bottom hole location along the

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North/South and East/West axes. Displacement in the North/South direction is sometimes called Latitude (L, figure 5.1.b) while displacement in the East/West direction may be called Departure (D, Figure 5.1.b). Displacement values in the North/South direction are positive to the north and negative to the south while those in the East/West direction are positive to the east and negative to the west.

Magnetic North Bottom Hole Location

A L S D Figure 5.1.b View from top of hole looking down

Several methods are available for calculating survey data to derive the bottom hole location. All methods of calculating surveys use the components in Figures 5.1.a and 5.1.b. This document will cover three of the many methods used for calculating surveys. Average Angle takes the average of two survey station values. It is the easiest method of calculating survey data. Differences between average angle and other methods are significant only if surveys are taken too far apart or the angle changes drastically over short distances. The Minimum Radius of Curvature and Radius of Curvature methods are closely related. While Average Angle assumes a straight well bore between two survey stations, both Minimum Radius of Curvature and Radius of Curvature assume that the well bore has the shape of an arc between two survey stations. Once the survey is calculated, it is displayed on a survey sheet. Survey sheets differ from company to company but follow the same general format shown in Table 5.1.

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Measured Depth FT

Incl. Angle Deg

Drift Direction Deg

15510.00

4.60

117.00

15542.00 15562.00 15593.00

5.60 6.40 7.70

118.60 117.90 121.20

Table 5.1

True Vertical Depth

Vertical Section FT

N-S FT

E-W FT

Tie In Survey From Friendly Gyro Co., Inc. 15498.01 378.95 131.09 -361.95 Surveys From Best MWD, Inc. 15529.88 376.25 129.76 -359.43 15549.77 374.27 128.77 -357.59 15580.54 370.69 126.89 -354.29

CLOSURE Distance Direction FT FT

Dogleg Severity Deg/100ft

384.95

289.91

3.51

382.14 380.07 376.32

289.85 289.80 289.70

3.16 4.02 4.39

Survey sheet

Tie-in surveys are those provided by another survey company or method taken before the MWD surveys. Tie-ins allow a continuation of the previously calculated surveys. The direction from the origin to the target is called the Vertical Section Direction or the Plane of Proposal. This is the direction of the vertical section when plotted on the North/South – East/West axes – also called the Horizontal Plane. Measured Depth means the depth of the survey sensors – it is not the same as the hole depth. On survey sheets, measured depth is sometimes called survey depth. Inclination is the hole angle obtained from the accelerometers. Drift Direction or azimuth is obtained from the magnetometers. Azimuth, when used in calculations, must be corrected for magnetic declination and/or grid correction before calculations are executed. Once the survey is calculated, azimuth is displayed on the survey sheet as drift direction. True Vertical Depth is the product of the incremental vertical depths at each survey station. The same is true of vertical section. Incremental vertical section is calculated for each survey station and added together for total vertical section. The North/South (N-S) and East/West (E-W) components of the hole’s direction are recorded as rectangular coordinates in feet from the origin. In most cases the origin is the center of the hole at the surface. Closure Distance and Closure Direction are also known as Closure Azimuth and Horizontal Displacement. Most companies use the first set of terms. Closure Distance is the displacement of the bottom hole from the origin. An imaginary line drawn straight from the origin to the bottom hole location would represent Closure Distance. Closure Direction is the angle between a north/south line (Latitude) and the displacement. See Figure 5.1.c.

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Bottom Hole Location

Latitude

Closure

Closure Direction

Target

Origin

Displacement or Closure Distance

Vertical Section

Figure 5.1.c Closure Distance and Closure Direction

As the hole is drilled to the target, it must be guided along the correct azimuth and inclination. Places where the turns are made are called doglegs and are displayed as Dogleg Severity in degrees per one hundred feet. The dogleg severity depends upon changes in both azimuth and inclination. Figure 5.1.d shows a well drilled with high dogleg in both the vertical and horizontal planes.

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a Vertical Plane

b d c

Vertical Section

Horizontal Plane Figure 5.1.d Dogleg severity

Section a in Figure 5.1.d has a low dogleg severity because the changes in angle and direction are slight. Sections b and d have high dogleg severity because the changes are much greater. Section c has a moderate dogleg severity because the changes are moderate.

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5.1.1 Average Angle The Average Angle method uses simple Trigonometry to calculate bottom hole location. This method assumes a straight line between two survey points. Position can be calculated using a simple hand held calculator, providing it has the Sine, Cosine, and Tangent functions. Table 5.1.1 presents a series of surveys taken by an MWD tool. The bottom hole location will be calculated for each survey. Tie-in survey is: Survey Depth 4980

Incl 29.0

Azi 137.0

TVD 4276.89

Vertical Section 2414.35

N-S -1707.20

E-W 1676.35

Plan of Proposal is 135. Survey #

Depth

Inclination

Azimuth

1

5000

30.0

135.0

2

5030

31.0

135.5

3

5060

31.2

135.5

4

5090

32.0

136.0

Table 5.1.1 MWD Surveys

First calculate the Course Length, then the Average Angle and Average Direction. Course Length: (CL) The difference between the measured depths, of two survey stations. The calculation to determine the course length for the first set of surveys is: Survey Depth2 – Survey Depth1 = Course Length Starting with the Tie-in survey, Survey Depth2 is 5000 while Survey Depth1 is 4980, so the course length calculation is: 5000 – 4980 = 20 Average Angle: The average inclination of the current and previous survey.

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Avg_Ang = (Inclination1 + Inclination2) ÷ 2 Average Direction: The average of the current and previous direction Avg_Dir = (Azimuth1 + Azimuth2) ÷ 2 Next calculate True Vertical Depth (TVD), Vertical Section (VS) and the N-S, E-W portions of the survey. TVD: Take the Cosine of the average angle and multiply it by the course length. In this example Inclination1 is from the Tie-in survey and Inclination2 is from the first MWD survey: Cosine (29 + 30) ÷ 2 = Cosine 29.5 = 0.8704 Multiply the cosine of the average angle by the course length. This calculation gives the incremental change from the previous survey: 0.8704 * 20 = 17.40 Add the result to the TVD of the Tie-in survey: 4276.89 + 17.4 = 4294.29 Incremental Displacement (DI): Incremental Displacement is calculated similarly to Total Vertical Depth except the course length is multiplied by the sine of the average angle: DI = CL * Sine (Avg_Ang) DI = 20 * Sine (29.5) DI = 20 * (0.4924) DI = 9.85 Since this result is only the incremental change from the last survey, it must be added to the previous total displacement (D): D = 2414.35 + 9.85 = 2424.20 N-S: To calculate N-S, use this formula: N-S = CL * Sine (Avg_ Ang) Cosine (Avg_Dir) Calculate N-S for the information provided by the Tie-in survey and the first MWD survey: N-S = 20 * Sine (29.5) * Cosine ((137 + 135) / 2) N-S = 20 (0.4924) * Cosine (136) N-S = 20 (0.4924) * (–0.7193) N-S = –7.0837

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Note that this result is only the incremental change from one survey to the next so it must be added to the previous total for N-S. This formula takes the direction of the average survey angle into account. It yields a negative result because that direction is to the south. Add this incremental change in N-S to the previous survey: N-S = –1707.2 + -7.08 = –1714.28 E-W: To calculate E-W, use this formula: E-W = CL * Sine (Avg_ Ang) Sine (Avg_Dir) Note: Close placement of terms indicates terms must be multiplied. In the equation above, Sine (Avg_ Ang) Sine (Avg_Dir) means the same as Sine (Avg_ Ang) * Sine (Avg_Dir). With the information provided by the Tie-in survey and the first MWD survey: E-W = 20 * Sine (29.5) Sine ((137 + 135) ÷ 2) E-W = 20 (0.4924) * Sine (136) E-W = 20 (0.4924) *(0.6947) E-W = 6.84 Note that this result is only the incremental change from one survey to the next so it must be added to the previous total for E-W. This formula takes the direction of the average survey angle into account. It yields a positive result because that direction is to the east. Adding incremental change in E-W to the previous survey: E-W = 1676.35 + 6.84 = 1683.19 Dogleg Severity, Closure Angle, Closure Distance and Vertical Section are calculated the same regardless of survey calculation method and so will be presented at the end of Section 5.1.3, Minimum Radius of Curvature. When using Radius of Curvature method, degrees must be converted to radians.

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5.1.2 Radius of Curvature Before calculating a survey position with the Radius of Curvature method, the MWD operator must convert all angles from degrees to radians. A radian equals the angle of an arc in which the length of the arc is equal to the length of the radius of a circle.

a

c 1 radian b

Figure 5.1.2 Radian angular measurement

In Figure 5.1.2, the length of the arc c is equal in length to a and b, which are radii of the circle. Radians are converted to degrees by the formula: 1 radian = 180° ÷ π = 57.3° Degrees are converted to radians by the formula: 1° = π radians ÷ 180° = 0.0175 radian First, calculate the vertical radius or Rv. Rv = (CL * 180) ÷ (π * (I2 – I1)) Where: CL = Course Length I2

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NOTE: This expression incorporates the conversion of degrees to radians. I1

= Inclination of previous survey

Using information from the tie-in and survey station #1 from Table 5.1.1: CL = 5000 – 4980 = 20 Rv = (20 * 180) ÷ (π * (30 – 29)) = 1145.9156 Incremental Vertical Depth (VD): Calculate the incremental change in vertical depth: VD = Rv * (Sine I2 – Sine I1) VD = 1145.9156 * (Sine 30 – Sine 29) VD = 1145.9156 * (0.5 – 0.4848) = 17.42 TVD: Add the result to the TVD of the Tie-in survey: 4276.89 + 17.42 = 4294.3 Notice that there is a slight difference between this calculation and the result using average angle. Incremental Displacement (DI): This result is the change in vertical section from the previous survey to the current survey: DI = Rv * (Cosine I1 – Cosine I2) DI = 1145.9156 * (Cosine 29 – Cosine 30) DI = 1145.9156 * (0.8746– 0.8660) = 9.85 Where: DI = Incremental Displacement Displacement: Since DI is only the incremental change from the last survey, it must be added to the previous total displacement: D = 2414.35 + 9.85 = 2424.20 Now, calculate the horizontal radius or Rh: Rh = (180 * DI) ÷ (π * (AZI2 – AZI1)

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NOTE: This expression incorporates the conversion of degrees to radians. Again, using information from the tie-in and survey station #1 from Table 5.1.1: Rh = ABS ((180 * DI) ÷ (π * (135 – 137)) Rh = ABS (180 * 9.85) ÷ (π * (–2)) Rh = ABS (–282.18) = 282.18 NOTE: ABS means absolute value. Absolute values are always positive. N-S: To calculate N-S, use this formula: N-S = Rh * (Sine AZI2 – Sine AZI1) N-S = 282.18 * (Sine 135 – Sine 137) N-S =282.18 * (0.7071 – 0.6820) N-S = 7.08 Survey direction = southeast = negative N-S = – 7.08 Notice the difference between this result and that obtained using average angle. This result is only the incremental change from one survey to the next so it must be added to the previous total for N-S. Also, the number must be negative because the direction is to the south. Adding incremental change in N-S to the previous survey: N-S = –1707.2 + –7.08 = –1715.00 E-W: To calculate E-W, use this formula: E-W = Rh * (Cosine AZI2 – Cosine AZI1) E-W = 282.18 (Cosine 135 – Cosine 137) E-W = 282.18 (0.0242) E-W = 6.83 Survey direction = northeast = positive E-W = 6.83

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Note that this result is only the incremental change from one survey to the next so it must be added to the previous total for E-W. Also, the number is positive because the survey direction is to the east. Adding incremental change in E-W to the previous survey: E-W = 1676.35 + 6.83 = 1683.18

5.1.3 Minimum Radius of Curvature Linear distance between survey points is smoothed using a ratio factor. The ratio factor creates a curved interval. Curvature of the well path is the Dog Leg Severity. DL: Dog leg is the curvature of the well bore at one particular point. Dog Leg Severity makes the same calculation but uses one hundred foot intervals (See Figure 5.1.c.). Calculating Dog Leg: DL = Cosine–1[Cosine(I2 – I1) – SineI1SineI2(1-Cosine(A2 – A1))] NOTE: The notation Cosine-1 indicates the inverse of the Cosine, which is referred to as the Arccosine. If then and

y = Cosine x x = Cosine-1 y x = arccosine y.

The arcosign is used to get an angle from a trigonometric function. The other inverse functions are arcsine and arctangent. Dog Leg Severity: (DLS): divide the given dogleg by the course length and multiply the result by 100. 3 degrees ÷ 30 feet = 0.1 degree per foot DLS = 0.1 degree per foot * 100 feet = 10 degrees Calculate the dogleg and dogleg severity for the tie-in survey and first survey shown in table 5.1.1 DL = Arccosine [Cosine (30 – 29) – Sine30 Sine29 (1-Cosine (135 – 137))] DL = Arccosine [0.7574 * (1 – 0.9993)] = Arccosine (.0005) DL = 0.029

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DLS = DL * 100 = 0.029 * 100 = 2.9° per 100 feet RF: The minimum curvature method then uses a ratio factor (RF) to smooth the line segments defined by the survey points to a curved space. It uses dogleg in the calculation: RF = (360 ÷ (DL * π)) * Tangent (DL ÷ 2) RF = (360 ÷ (.029 * π)) * Tan (.0145) NOTE: If DL is less than 0.25, RF = 1. RF = 3951.43 * .00025 = .98786 RF = 1 VD: The incremental increase (or decrease) in vertical depth is calculated by: VD = (CL ÷ 2) * (Cosine I2 + Cosine I1) * RF VD = (20 ÷2) * (Cosine 30 + Cosine 29) * 1 VD = 10 * 1.7406 * 1 VD = 17.41 TVD: Add the result to the TVD of the Tie-in survey: 4276.89 + 17.41 = 4294.3 Notice that this result differs slightly from the average angle and radius of curvature results. Incremental Displacement (DI): This result is the change in vertical section from the previous survey to the current survey: DI = (CL ÷ 2) * (Sine I2 + Sine I1) * RF DI = 10 * (Sine 30 + Sine 29) * 1 DI = 10 * 0.9848 * 1 = 9.85 Where: DI = Incremental Displacement Displacement (D): Since DI is only the incremental change from the last survey, it must be added to the previous total vertical section: D = 2414.35 + 9.85 = 2424.20 N-S: Use the following formula: N-S = (CL ÷ 2) * (Sine I1 Cosine A1 + Sine I2 Cosine A2) * RF

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N-S = 10 * (– 0.3546 + – 0.3536) * 1 N-S = 10 * – 0.7082 * 1 N-S = – 7.08 Notice that this result agrees with both the radius of curvature and average angle results. This result is only the incremental change from one survey to the next so it must be added to the previous total for N-S. This formula takes the direction of the average survey angle into account. It yields a negative result because that direction is to the southeast. Adding incremental change in N-S to the previous survey: N-S = –1707.2 + -7.08 = –1714.28 E-W: Use the following formula: E-W = (CL ÷ 2) * (Sine I1 Sine A1 + Sine I2 Sine A2) * RF E-W = 10 * (0.3306 + 0.3536) * 1 E-W = 10 * 0.6842 *1 E-W = 6.84 Note that this result is only the incremental change from one survey to the next so it must be added to the previous total for E-W. This formula takes the direction of the average survey angle into account. It yields a positive result because that direction is to the northeast. Adding incremental change in E-W to the previous survey: E-W = 1676.35 + 6.84 = 1683.19 Closure Distance or Displacement (CD): Imagine a straight line drawn directly from the origin to the last survey station: that line is the closure distance or displacement. The abbreviation CD refers to either closure distance or displacement. Latitude (N-S) and departure (E-W) must be known to calculate the closure distance (refer to Section 5.1 and Figure 5.1.b): CD = √ Lat2 + Dep2 Using the data calculated for Table 5.1.1, the CD for survey #1 is: CD = √ –1714.282 + 1682.932 CD = 2402.29

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The displacement is different from the vertical section because the displacement is plotted to the last survey station while the vertical section is plotted to the target. See Figure 5.1.c. Closure Azimuth (CA): Closure azimuth (or closure angle) represents the angular difference between a line drawn from the surface location (the origin) to the last survey station (the termination), referenced to True North. See Figure 5.1.c. Closure azimuth is the arctangent of the Bottom Hole Location (BHL) departure divided by the latitude. CA = Tangent–1 (BHL Departure ÷ Latitude) CA = Tangent–1 (1682.93 ÷ –1714.28) Process the results according to the Latitude and Departure values:

■ If Latitude is positive and Departure is positive, use the result. ■ If Latitude is negative and Departure is positive, subtract the absolute value of the result from 180 ■ If Latitude is negative and Departure is negative, add the result to 180. ■ If Latitude is positive and Departure is negative, subtract the result from 360 and take the absolute value. Since the Latitude is negative and the Departure is positive: CA = (180 – ABS (result)) = 180 – ABS (–58.36) CA = 180 – 58.36 = 121.64 Target Azimuth (TA): Target azimuth represents the angular difference between a line drawn from the surface location (the origin) to the Proposed Bottom Hole Location (PBHL) or target, referenced to True North. Target azimuth is the arctangent of the target departure divided by the latitude. TA = Tangent–1 (Target Departure ÷ Latitude) Vertical Section (VS): After calculating the displacement for each survey station, the Vertical Section is calculated using the formula: VS = Displacement * Cosine (TA – CA) Where: TA = Target Azimuth CA = Closure Azimuth VS = 2402.29 * Cosine (135 – 135.52) VS = 2402.29 * 0.99995 = 2402.17

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5.2 Plotting Bottom Hole Location Figure 5.1.a shows the vertical and horizontal plane views of the borehole. If the earth were sliced along the well bore and stood on end, the view would be the vertical plane. If the earth were transparent and you were standing at the origin, looking down the well bore, you would see the horizontal plane of the well bore. Once survey data are acquired, the bottom hole location is plotted on both the vertical and horizontal planes (See Figure 5.2). Vertical section, true vertical depth and measured depth are plotted on the vertical plane while vertical section and horizontal displacement are plotted on the horizontal plane. Table 5.2 presents the survey data from Table 5.1, calculated with the average angle method.

Plane of Proposal

Course

135

M.D. Feet

Tie In

4,980

Length

Incl. Angle deg.

Azimuth Coords. Angle deg. +N, -S

Vert. Sec. +E, -W

T.V.D. Feet

Feet

29.00

137.00

-1707.20

1676.35

4276.89 2400.35

Dogleg Closure Dist. Deg./100' Feet

Direc. Deg.

2392.63

135.52

5,000

20.00

30.00

135.00

-1714.28

1682.93

4294.32 2402.18

7.02

2402.49

135.52

5,030

30.00

31.00

135.50

-1725.11

1693.92

4320.17 2417.62

3.44

2417.72

135.52

5,060

30.00

31.20

135.50

-1736.16

1704.78

4345.86 2433.11

0.67

2433.22

135.52

5,090

30.00

32.00

136.00

-1747.42

1715.75

4371.42 2448.83

2.81

2448.94

135.52

Table 5.2 Calculated surveys (from data in Table 5.1.1)

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0

1000

1000

2000

1000

2000

2000

3000

4000

5000

1000

2000

3000

4000

Figure 5.2 Survey from Table 5.2 is plotted on graph

The graph or survey plat has the proposed well path. Actual survey data are plotted along with the well plat. In Figure 5.2, thick lines represent the actual well path while the thin line represents the planned well path. Notice that the actual well path is slightly above and to the left of the planned well path.

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Chapter 6: Geometrical Steering Like a ship steered to its final destination, the well must be steered to the target. The directional driller uses various methods to guide the well to the target but all methods depend upon a survey instrument of some kind. The most advanced survey instrument available for steering a well to the target is the MWD tool. Geometrical steering involves using only survey and toolface data to adjust the position of the well bore. Other data necessary to determine the orientation of the well bore in relation to the formations are resistivity, neutron porosity and density or sonic measurements. When data other than survey data are used to guide the well bore, it is called geological steering. This document is only concerned with geometrical steering. One of the problems most people have when first introduced to MWD tools is the notion of toolface. Oilfield terminology is a language all its own and the concept of toolface is no different. This chapter introduces the concept of toolface and delineates two different kinds of toolfaces, those based upon the magnetometers called magnetic toolfaces (mTF) and those based upon the accelerometers called gravity or highside toolfaces (gTF).

6.1 Toolfaces Going from home to work or school involves directions. The directions may be simple, such as “go two blocks and turn right then walk 200 yards and turn right again.” The directions tell which way to turn at specific points. In order to turn right, you must face right, and then move right. The same principle applies to steering a well. Steering tools must be pointed in the direction that the well is to be drilled. The angle at which the steering tool is pointed is called the toolface. See Figure 6.1.

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Current Hole Direction

Toolface

Figure 6.1 Toolface changes the hole direction

At low angles, the accelerometers are not as accurate as the magnetometers so low angle toolfaces are based on magnetic readings. Low angle toolfaces are called magnetic toolfaces. Since the readings are oriented to Magnetic North, they must be adjusted for magnetic declination and grid correction if necessary. Basically, using magnetic toolfaces means pointing the steering tool in the direction of the target. For instance, if the target is at an azimuth of 135 and the current hole direction is 90, the tool is set to point at 135. If drilled long enough in this direction the hole will eventually turn to the desired azimuth. Once the hole direction is established, typically around 5 degrees, the type of toolface changes from magnetic toolface to gravity toolface. The well bore has an established direction and can be turned either to the left or right of the current direction. How much the toolface must be turned depends upon how quickly the well bore is to be turned to the target direction.

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6.1.1 Magnetic Toolfaces (mTF) Magnetic toolfaces are based upon the magnetometer readings. They must be adjusted for magnetic declination and grid correction where appropriate. In Figure 6.1.1.a the well angle (inclination) is 2º and direction is 190º azimuth, which puts the well in the southwest quadrant. If the final well orientation is to be 20º inclination with 290º azimuth, the well must be steered to the northwest.

N

W

E

S

Figure 6.1.1.a Low angle well in the southwest quadrant

If the well currently has a depth of 5,000 feet, and must reach the target angle and direction by 10,000 feet, the build-up rate (the rate at which the angle must increase per 100 feet) is a relatively mild 0.36º per 100 feet. Since the current angle is 2º it will take 833 feet to reach 5º. During the 833 feet, magnetic toolfaces will be used. The hole will turn 16.7º in 833 feet, so the azimuth will be 206.7º. See Figure 6.1.1.b.

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North Desired hole direction: 290 azimuth

West

East

Hole direction after 833 feet: 206.7 azimuth

Figure 6.1.1.b

South

Current hole direction: 190 azimuth

Turn from 190 to 290

To accomplish the turn from 190 azimuth to 290 azimuth, the directional driller will orient the steering tool to 290.

6.1.2 Gravity or Highside Toolfaces (gTF) Although a hole can be guided to the desired direction using only magnetic toolfaces, the crossover to gravity (highside) toolfaces is desirable for several reasons. Magnetic interference creates incorrect mTF. An incorrect magnetic declination and/or grid correction creates error in mTF. As hole angle increases, the accelerometers become more accurate while the magnetometers loose sensitivity. Finally, gravity toolfaces are not influenced by magnetic material in the drillstring, hole direction, hole angle or latitude. See Chapter 3 for a discussion of various factors that potentially create incorrect magnetic readings. From the center of the hole in Figure 6.1.1.b, looking in the original hole direction, the desired hole direction is 100 degrees to the right. If the hole direction is superimposed on a compass with the hole direction straight up, it is obvious that the hole must be steered 100 degrees to the right of the current direction. See Figure 6.1.2.a.

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North

Hole direction is positioned straight up

West

Desired direction is 100 degrees to the right of original direction

East

South Figure 6.1.2.a

Hole direction set straight up and referenced to compass

Once the hole direction is established, the desired direction is either to the right or left of the hole direction. The directional driller then steers the hole to the right or left of the current direction to reach the desired direction. Highside direction changes with each new survey. Unlike magnetic tool faces, highside toolfaces cannot be held constant in the target direction. Consider Figure 6.1.2.a. If the toolface is turned 100 degrees to the right of the current hole direction, the result will be a loss of hole angle. Remember that inclination must be 20º by the time the direction is 290º. When highside toolfaces are used, they are set both to turn and to build angle. In the example, the toolface may be set to 45º right after each survey to both turn to the target and build angle at the same time. See Figure 6.1.2.b.

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Highside

Toolface is 45º Right of Highside

Figure 6.1.2.b Toolface is 45º right of highside

With each survey, the amount of turn and build may be adjusted based upon the survey data.

6.1.3 Orienting MWD Tools to Steering Tools Mud motors are the most common type of steering tools an MWD operator is likely to encounter. It works like a positive displacement pump using a stator and rotor. The stator is the portion that does not turn while the rotor turns and rotates the bit. See Figure 6.1.3.a.

Housing Rotor

Stator

Figure 6.1.3.a

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The mud motor has a bend and causes the bit to drill the hole in the direction the bend is turned. See Figure 6.1.3.b.

Figure 6.1.3.b Bend in the Mud Motor changes hole direction

A scribe line inside the bend of the mud motor allows the bend to be aligned with a reference point on the MWD tool called the MWD scribe line or, in some cases, the MWD highside. When the mud motor bend is aligned to the MWD tool, the tool is said to be oriented to the bend. Two different methods are used to align the mud motor scribe line to the MWD reference point, in accordance with the two basic types of MWD tools. As mentioned in Chapter 1, Section 1.5.2, MWD tools come in two basic types: retrievable and fixed-in-the-collar. Retrievable tools are oriented using one method and fixed collar tools are oriented using another.

6.1.3.1

Orienting Retrievable Tools Retrievable tools are oriented with reference to the highside of the MWD tool. Highside is a physical location at the bottom of the pulser. Before installing the retrievable MWD tool in the drill collar, it must be assembled and programmed so that the highside of the tool aligns with a slotted keyway machined into the pulser. The MWD rests in a subassembly, or sub, below the MWD collar called the muleshoe sub. Inside the muleshoe sub is an orientation sleeve. See Figure 6.1.3.1.a. Within the orientation sleeve is a special key that must be lined up with the mud motor scribe line. The orientation sleeve in the

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muleshoe is rotated to the mud motor scribe line with a special tool. Special setscrews lock the orientation sleeve in the muleshoe sub.

Orientation Key

Muleshoe Sub

Orientation Sleeve

Orientation Sleeve (Top View)

Figure 6.1.3.1.a Muleshoe sub and orientation sleeve.

At the bottom of the pulser is a ramped section that guides the pulser into the orientation key. This ramp seats the pulser orientation key slot onto the orientation key. See Figure 6.1.3.1.b.

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Orientation Key Slot Orientation Ramp

Figure 6.1.3.1.b Section of pulser showing ramp and slot

After the orientation sleeve is aligned with the mud motor scribe line, the tool is inserted into the MWD drill collar where it turns to the correct orientation.

6.1.3.2 Orienting Fixed Collar Tools Unlike the retrievable tool, the fixed collar tool is inserted into the MWD monel drill collar before being deployed to the field. The tool is oriented to an indexed keyway inside the MWD monel drill collar. The highside reference scribe line, milled on the outside of the collar, is aligned with the indexed keyway on the inside of the collar. When the MWD monel drill collar is connected to the mud motor, the MWD scribe line is randomly oriented in relation to the mud motor scribe line. The directional driller uses chalk to transfer the mud motor scribe line up to the MWD tool. The angular difference between the two scribe lines is then measured.

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Figure 6.1.3.2.a Measuring scribe line offset

The angular difference between the mud motor scribe line and the MWD scribe line may be measured several different ways. It is extremely important to know whether the scribe line measurement is to be made from the MWD scribe line to the mud motor scribe line or the other way around. One measurement will produce a negative number and the other will produce a positive number. For instance, if the angle in Figure 6.1.3.2.a is measured from the MWD scribe line to the mud motor scribe line, it will be 80º. However, if the angle is measured from the mud motor scribe line to the MWD scribe line, it will be 280º. The line from which the measurement is made is the primary reference line, while the line to which the measurement is made is the secondary reference line.

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NOTE: Always make the measurement clockwise as if standing on top of the collar facing the primary reference line.

The angular difference may be measured using either a protractor, as shown in Figure 6.1.3.2.b, or using a tape measure.

Secondary Reference Line Primary Reference Line

Figure 6.1.3.2.b Measuring offset angle with a protractor

The protractor is marked off in degrees and matched to drill collar size. The zero edge is placed on the primary reference line and read clockwise to the secondary reference line. In Figure 6.1.3.2.b, the secondary reference line is 80º to the right of the primary reference line. Offset is recorded as 80. If a protractor is not available, the measurement can still be made using a tape measure.

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1 7/8”

Figure 6.1.3.2.c Measuring offset angle with a tape measure

First, measure the circumference with the tape measure, then measure the distance between the primary reference line and secondary reference line. Remember to measure from the primary reference line to the secondary reference line. NOTE: Always make the measurement clockwise as if standing on top of the collar facing the primary reference line. Next, perform the following calculation: Angular offset = (Distance between reference lines ÷ Circumference) * 360 If the circumference is 8½” and the measured distance between reference lines is 1 ⅞ “ the angular offset is: (1 ⅞ ÷ 8½) * 360 0.2205 * 360 = 79.4º Thus the angular offset entered into the software will be 79º.

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Index 1

C

10-Pin Cable, 55 A

Algebra, 10 anchor dead line, 41 semi-submersible drilling rig, 36 angle of inclination, 57 Annular Velocity, 28 Antarctica, 60 Arithmetic, 8 Basic Operations, 8 Associative Property, 10 Average Angle, 99 Average Direction, 100 Azimuth, 57, 96 B

Balancing an Equation, 15 Bernoulli’s Principle, 28 BHA (Bottom Hole Assembly), 42 Bottom Hole Assembly Crossovers, 45 Drill Collars, 42 Drillpipe Configuration, 46 Heavyweight Drill Pipe, 45 Jars, 46 magnetic interference from, 79 Mud Motors, 46 Stabilizers, 44 UBHOs, 43 Bottom Hole Location, 93 calculating Average Angle, 99 Minimum Radius of Curvature, 105 Radius of Curvature, 102 Bottom Hole Location, Plotting, 109

Introduction to MWD

Cable 10-Pin, 55 Power/Communications, 55 Programming, 54 RS-232, 54 Cables (Lines and -), 53 Calculating Bottom Hole Location, 93 calculating Location, 93 Calibration (incorrect), 89 Chapter 1 The Foundation Basic Skills and Knowledge, 7 Chapter 2 Field Operations, 51 Chapter 3 Introduction to Surveying, 57 Chapter 4 Transforming Influences, 79 Chapter 5 Calculating Bottom Hole Location, 93 Chapter 6 Geometrical Steering, 111 communications bus (qbus), 33 Commutative Property, 9 compass direction, 57 compass directions, 59 Computer, Set Up, 54 Constituents (of formations), 88 Corrections (to azimuth), 65 Cosine, 23 Course Length, 99 Crossovers, 45 crown block, 41 cuttings (drilling residue), 26 D

dead line, 41 Declination (Magnetic), 66 Dip Angle, Magnetic, 72

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dip holes, 73 direction Azimuth, 57 of compass, 57 Directional Measurements While Drilling (DMWD), 47 directional wells, 24 Directional-Only Service, 53 Display (Rig Floor), 54 Distributive Property, 10 DMWD. See Directional Measurements While Drilling Draw Works, 41 Drift Direction. See Azimuth drill line, 41 Drill Ships, 37 Drill String Movement, 90 Drilling Fluid, 33 Drilling Rig, 33 Land, 38 Offshore, 34 Drill Ships, 37 Inland Barge, 34 Jack Up, 35 Platform, 34 Semi-Submersible, 36 Parts, 38 Draw Works, 41 Kelly, 42 Mud Pumps, 39 Rig Floor, 38 Standpipe, 40 Drillpipe Configuration, 46

F

Field Operations, 51 fish, 88, 89 FOIL method, 19 Formation, 42 constituents, 88 magnetic interference from, 88 G

gamma, 74 gauss, 74 Geographic North (True North), 60 geometrical steering, 111 Gravity Field, Total, 76 grid convergence, 70 Grid Correction, 70 Grid North, 61 gTF (Gravity Toolface), 111 gyro survey instruments, 70 H

Heavyweight Drill Pipe, 45 highside reference scribe line, 119 Hole Angle, 81 Hole Direction, 83 horizontal component, 75 Hot Spots (magnetic), 88 hydraulics, 26 hydrostatic head (hydrostatic pressure), 26 hydrostatic pressure, 26

E

I

Easting (UTM coordinate), 63 Electro-Magnetic Error Report sheet, 52 Environmental/Job Site Information, 51 Equipment Inventory, 51 Rig Floor Area, 54, 56 E-W (East-West coordinate), 96

Inclination, 57, 96 Incorrect calibration, 89 detection, 90 operator input, 89 survey depth, 91 Inland Barge, 34 inland barges as offshore rigs, 33

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Input, incorrect, 89 Insurance sheet, 51 iron ore, 88 J

Jack Up, 35 Jars, 46 Job Charge sheet, 51 Job Sheet, 51 Job Site Information, 51 K

Kelly, 42 L

Lambert Projection, 61 Latitude, 84 Lines and Cables, 53 Lines and Graphs, 10 Logging Tools, 48 Logging While Drilling, 47 Louisiana Gulf coast, 63 LWD (Logging While Drilling), 47 M

Mag Dip, 72 Magnetic Declination, 66 Tool Face Offset form, 51 Magnetic Dip Angle, 57, 72 Magnetic Field horizontal component, 75 Hot Spots, 88 strength units (table), 74 Total, 74 units of measure gamma, 74 gauss, 74 tesla, 74 magnetic inclination, 73 Magnetic Interference from BHA, 79 from formation, 88 from solar flares, 89 Introduction to MWD

magnetic multishots, 70 Magnetic North, 58 magnetic single shot, 59 Map North (Grid North), 61 Mathematics Review, 8 maximum mud weight, 27 maximum pressure rating. See maximum system pressure maximum system pressure, 27 Measured Depth, 96 Measurements While Drilling. See MWD Minimum Radius of Curvature, 105 Moineau principle, 46 monel drill collar, 119 mTF (Magnetic Toolface), 111 mud (drilling fluid), 33, 39 Mud Motors, 46 Mud Pumps, 39 MWD highside. See MWD:scribe line Insurance sheet, 51 Job Sheet, 51 scribe line, 117 MWD (Measurements While Drilling), 7 MWD operator, role of, 49 MWD Tools, 47 Different Types, 47 Logging Tools, 48 Non-Retrievable, 48 Retrievable, 47 What is an MWD Tool?, 47 N

Non-magnetic Material, 85 Non-Retrievable MWD Tools, 48 Orienting, 119 North Grid, 61 Magnetic, 58 True, 60 Northing (UTM coordinate), 63 N-S (North-South coordinate), 96

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O

oolitic pyrite, 88 operation sign, 18 operator in an equation, 18 MWD, 7 Orienting MWD Tools to Steering Tools, 116 Non-Retrievable (Fixed Collar) Tools, 119 origin, 94 orthogonal (three axes) system, 76 P

Paperwork, 51 Paperwork List, 51 PBHL (proposed bottom hole location) (target), 94 Plan of Proposal (Vertical Section Direction), 96 Platform, 34 Plotting Bottom Hole Location, 109 Power/Communications Cable(s), 55 Pressure Pulses, 31 Pressure Transducer, Standpipe, 56 Programming Cable, 54 proposed bottom hole location (PBHL) (target), 94 Q

qbus (communications bus), 33 Quadratic Equations, 17 Quality Factors, 72 R

Radius of Curvature, 102 Radius of Curvature, Minimum, 105 raw reading (uncorrected Azimuth), 66 rectangular coordinates, 96 Reference Points, 57 Remote Driller’s Terminal, 54 Responsibilities Well Site, 52 Page 126 of 127

Retrievable MWD Tools, 47 Orienting, 117 rig electrician, 52 Rig Floor, 38 Rig Floor Area Equipment, 54, 56 Rig Floor Display, 54 Rigging Up Surface equipment, 53 Lines and Cables, 53 rise, 12 RS-232 Cable, 54 run, 12 S

Safe Area Rig-Up, 53 Semi-Submersible, 36 shale shakers, 39 Sine, 23 single shot instruments, 70 slope, 12 Solar Flares magnetic interference from, 89 Solar Wind, 79 SPT. See Standpipe Pressure Transducer Stabilizers, 44 Standpipe, 40 standpipe manifold, 40 Standpipe Pressure Transducer (SPT), 41 installing, 56 protecting, 56 Steering, geometrical, 111 Surface equipment, Rigging Up, 53 Survey Depth (Measured Depth), 96 incorrect depth, 91 stored, 90 technique, 90 Survey Tie-in Information sheet, 52 Surveying Introduction to, 57 System Pressures, 26

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T

Table of Contents, 3 Tangent, 23 target (proposed bottom hole location), 94 Technique, survey technique, 90 tension legs, 35 term (of an equation), 18 Terminal Remote Driller’s, 54 tesla, 74 three axes (orthogonal) system, 76 tie-in, 96 Tool Face Offset form, 51 tool pusher, 52 Toolfaces, 111 Gravity or Highside (gTF), 114 Magnetic (mTF), 113 Total Gravity Field, 57, 76 Total Magnetic Field, 57, 74 Transforming Influences, 79 traveling block, 41

Introduction to MWD

Triangles, 21 Right Triangles, 21 Trigonometry, 21 True North, 60 True Vertical Depth, 96 U

under-gauge stabilizers, 45 Universal Transverse Mercator (UTM), 62 UPS (Uninterruptible Power Supply), 53 V

Variables, 15 vector, 72 Vertical Section, 94 Vertical Section Direction, 96 W

well plat, 110 Well Site Responsibilities, 52 Arrival at Rig Site, 52 Before Rigging Up, 53

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