Connection Technology
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CONNECTION TECHNOLOGY NOTES
W144 Course
Connection Technology 1
1.1 1.2 1.3 1.4 2
CONNECTION DEVELOPMENT HISTORY ........................................................................................................ 14 TUBULAR END FORMS ................................................................................................................................... 14 CONNECTION FORMS ..................................................................................................................................... 15 CONNECTION CRITERIA ................................................................................................................................. 15 THREAD TERMINOLOGY ................................................................................................................................ 16 PREMIUM CONNECTION D EVELOPMENT ....................................................................................................... 19 SEALING METHODS........................................................................................................................................ 20
INTRODUCTION .............................................................................................................................................. 23 COMPOSITION ................................................................................................................................................ 23 SEALING ......................................................................................................................................................... 24 CO-EFFICIENT OF FRICTION ........................................................................................................................... 24 DEFORMATION ............................................................................................................................................... 26 WORK HARDENING ........................................................................................................................................ 26 PRACTICAL USE ............................................................................................................................................. 26
POOR S URFACE FINISH................................................................................................................................... 28 DEFORMATION OF CONNECTION ON MAKE-UP ............................................................................................ 29
THE PROBLEM - CORROSION .......................................................................................................................... 30 THE SOLUTION - 13% OR 23% CHROME STEEL ............................................................................................. 30 CORROSION RESISTANT ALLOY (CRA) GRADES .......................................................................................... 31 THREAD SELECTION FOR CHROME STEELS .................................................................................................... 31 SURFACE TREATMENT OF CHROME THREADS ............................................................................................... 32 THREAD COMPOUNDS AND TORQUE VALUES ................................................................................................. 32 EFFECT OF CONNECTION SIZE, WEIGHT, AND TONG SPEED ON MAKE-UP ...................................................... 33 PLASTIC COATINGS ........................................................................................................................................ 33
TORQUE-TURN AND GRAPHICAL ANALYSIS THEORY................................................................. 34 7.1
8
TRANSPORTATION AND PREPARATION ..................................................................................................... 55 P RE-JOB CHECKS ...................................................................................................................................... 56 RUNNING AND MAKE-UP .......................................................................................................................... 56
CHROME TUBULARS.................................................................................................................................. 30 6.1 6.2 6.3 6.4 6.5 6.6 6.7 6.8
7
10.1 10.2 10.3
COMMON PIPE PROBLEMS...................................................................................................................... 28 5.1 5.2
6
RECOMMENDED PROCEDURES FOR RUNNING CHROME TUBULARS................................... 55
THREAD COMPOUNDS............................................................................................................................... 23 4.1 4.2 4.3 4.4 4.5 4.6 4.7
5
SIZE .................................................................................................................................................................. 9 WEIGHT ............................................................................................................................................................ 9 GRADE .............................................................................................................................................................. 9 CONNECTION TYPE .......................................................................................................................................... 9 RANGE .............................................................................................................................................................. 9 GRADES OF STEEL FOR CASING AND TUBING ............................................................................................... 10 SELECTION OF GRADES .................................................................................................................................. 11 PROPRIETARY GRADES .................................................................................................................................. 12
10
CONNECTIONS AND SEALING METHODS .......................................................................................... 13 3.1 3.2 3.3 3.4 3.5 3.6 3.7
4
INTRODUCTION ................................................................................................................................................ 5 DEFINITIONS .................................................................................................................................................... 5 APPLICATIONS .................................................................................................................................................. 6 OCTG MARKET ............................................................................................................................................... 7
OCTG - THE FINISHED PRODUCT ............................................................................................................ 8 2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8
3
9.7 THREAD PROTECTORS AND CLEANING ......................................................................................................... 50 9.8 INSPECTION .................................................................................................................................................... 50 9.9 RUNNING PROCEDURES ................................................................................................................................. 50 9.10 P ULLING P ROCEDURES ............................................................................................................................. 53 9.11 COMMON CAUSES OF THREAD DAMAGE .................................................................................................. 54
REVIEW OF CASING AND TUBING .......................................................................................................... 5
EQUIPMENT AND TECHNIQUES....................................................................................................................... 34
COMMON EQUIPMENT PROBLEMS ..................................................................................................... 46 8.1 8.2
INTERPRETATION P ROBLEMS......................................................................................................................... 46 PROPER DATA INPUT ..................................................................................................................................... 47
9 RECOMMENDED PROCEDURES FOR RUNNING NON-CHROME TUBULARS............................ 48 9.1 9.2 9.3 9.4 9.5 9.6
OVERVIEW...................................................................................................................................................... 48 ACCESSORY EQUIPMENT ............................................................................................................................... 48 LIFT NUBBINS OR ELEVATOR PLUGS ............................................................................................................. 48 STABBING GUIDES ......................................................................................................................................... 48 STABBING....................................................................................................................................................... 49 POWER TONGS, GAUGES ETC......................................................................................................................... 49
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1.3
1.1
REVIEW OF CASING AND TUBING
1.3.1 Casing
Introduction Tubular goods in the form of casing or tubing are run in every well that is drilled from rank wildcats to final development wells. They form part of the tangible well costs and are usually the largest single cost item in a well. Typically, a North Sea well may have one million dollars worth of tubulars or more. The primary reasons for using oil country tubular goods (OCTG) are for safety and efficiency. Many branches of the oilfield service industry are involved in the manufacture, handling, running and maintenance of OCTG and during the following discourses the reasons for these individual services will become apparent.
1.2
Definitions The term 'Oil Country Tubular Goods' covers all tubulars including drill-pipe, line-pipe and pup-joints, as well as casing and tubing. This study is confined to casing and tubing which are best differentiated by purpose rather than size. a)
Casing:
is a steel lining run into the wellbore and cemented in place to give permanent protection from contaminating fluids, provide pressure tightness and prevent wellbore collapse.
b)
Tubing:
is a temporary, replaceable pipeline used to convey produced fluids from the reservoir or injected fluids into it.
It is better to classify the tubulars by purpose like this rather than by size, since casing sizes can be used for production tubing and vice-versa. Steel tubulars in different forms have been used since the turn of the century, but it was not until 1923 that standardisation by the American Petroleum Institute (API) brought about uniformity to sizes, strengths and connections for widespread manufacture. Additionally, API recommended practices and bulletins are used in the care, handling and running of these tubulars. Since then many advances have been made in designs and materials, including many non-API (proprietary) types. The number of possible combinations of sizes, grades, weights and connection types is quite staggering, running into many thousands. In effect, for European applications this can be reduced to several hundred combinations, which in itself can be confusing enough. One of the main functions of this part of the training course is to develop an understanding of the properties and designs of tubulars and connections. By this method, the large variety of possible tubulars can be better understood.
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Applications
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Typical standard casing programs for the North Sea are shown in fig 1. After drilling to a specified depth, the casing is lowered into the well and cemented in place. This is done with successively smaller casing until the total depth (TD) is reached and the entire hole is cased-off. Each size of casing string is designed to fulfil one or more of the following functions: a)
Isolate weak or unconsolidated surface formations and prevent washouts b) Isolate overpressures or reactive formations c) Isolate contaminating or corrosive fluids d) Provide a strong lining to control well pressures (including gas lift) e) Provide a smooth internal bore for installing production equipment. To satisfy the first four of these functions, the casing must be backed up by a solid sheath of cement for maximum strength. The cement also presents migration of fluids such as saltwater or gas from occurring behind the casing. Equally, it prevents damage by corrosion to the outside of the casing and reduces thermal expansion of the casing. The methods for choosing size, weight and grade of casing will be explained in more detail in a later section of the course. 1.3.2 Tubing
Figure 1
Tubing is run from near the top of the producing zones to the wellhead to provide a controlled passageway for produced or injected fluids. Since well performance may require some remedial action at an unspecified future date, the tubing is not cemented in place, thus allowing its removal for workover etc. However, its design is just as important as casing since it is subjected to high combinations of loading as well as exposure to corrosion and erosion. The important functions of tubing are: a) To act as a pressure-tight competent pipe line for production of hydrocarbons or injection of fluids. b) To protect production casing from erosive and corrosive fluids. c) To optimise production flow rates d) To provide a smooth bore for running and installation of downhole devices. Version 2.00
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1.4
2
OCTG Market To give some indication of the commercial aspects of the OCTG market, in 1994 the expenditure in the UK for casing and tubing alone was £698 million. The supply of tubulars in the North Sea is dominated by British Steel, Huntings and NSCC with other contributions from Japan (Sumitomo, Nippon, Kawasaki), Germany (Mannesman), France (Vallourec) and Italy (Dalmine). Very little steel now comes from the USA. There is a large variation in the price of pipe depending on its grade etc and best illustrated by comparing to a norm such as N-80, which is commonly used in the North Sea. RELATIVE TYPE
VALUE
K-55 N-80 L-80 C-95 P-110 V-150 13% chrome 23% chrome
0.66 1.00 1.18 1.16 1.21 1.51 3.00 10.00
OCTG - THE FINISHED PRODUCT A joint of casing or tubing is usually described with the following parameters - size, weight, grade and connection type, e.g. 7" 29 pound L-80 New Vam. Joint length may be specified within a given range and recommended drift size will be listed in data books (see table below).
API Drift Sizes Tubular O.D.
Weight (lb/ft)
Drift O.D.
Tubular O.D.
Weight (lb/ft)
Drift O.D.
Tubular O.D.
Weight (lb/ft)
Drift O.D.
23/8 "
4.60 5.10 5.80
1.901" 1.845" 1.773"
5½"
20.00 23.00 26.80
4.653" 4.545" 4.375"
9 5/8" Cont.
47.00 53.50 53.50
8.525" 8.379" *8.500"
27/8 "
6.40 7.70 8.60
2.347" 2.229" 2.165"
6 5/8"
20.00 23.20 24.00
5.924" 5.840" 5.796"
58.40 59.40 61.10
8.279" 8.251" 8.219"
9.80 7.70 9.20
2.057" 2.943" 2.867"
28.00 32.00 35.00
5.666" 5.550" 5.450"
67.50 40.50 45.50
*8.500" 9.894" 9.794"
10.20 12.70 13.70 14.70 15.80
2.797" 2.625" 2.548" 2.476" 2.423"
23.00 26.00 29.00 32.00 35.00
6.241" 6.151" 6.059" 5.969" 5.879"
45.50 51.00 55.50 55.50 60.70
*9.875" 9.694" 9.604" *9.625" 9.504"
9.50 10.90 13.00
3.423" 3.351" 3.215"
38.00 38.00 41.00
5.795" *5.879" 5.695"
65.70 73.20 101.00
9.404" *9.330" *8.750"
14.80 16.50
3.115" 3.015"
41.00 44.00
*5.750" 5.595"
47.00 54.00
10.844" 10.724"
10.50 11.60 12.60 13.50
3.927" 3.875" 3.833" 3.795"
46.00 26.40 29.70 33.70
5.535" 6.844" 6.750" 6.640"
60.00 65.00 71.00 71.00
10.616" 10.526" 10.430" *10.500"
13.50 15.10 16.90 18.80 21.60 24.60
*3.833 3.701" 3.615" 3.515" 3.375" 3.255"
35.80 39.00 42.80 45.30 47.10 51.20
6.568" 6.500" 6.376" 6.310" 6.250" 6.126"
54.50 61.00 68.00 72.00 72.00 77.00
12.459" 12.359" 12.259" 12.191" *12.250" 12.119"
26.50 13.00 15.00 18.00 20.30 20.80 21.40
3.115" 4.369" 4.283" 4.151" 4.059" 4.031" 4.000"
8 5/8"
28.00 32.00 36.00 40.00 44.00 49.00 52.00
7.892" 7.796" 7.700" 7.600" 7.500" 7.386" 7.310"
80.70 85.00 112.00 65.00 75.00 84.00 109.00
12.059" 12.003" *12.259" 15.062" 14.936" 14.822" 14.500"
23.20 24.10 15.50 17.00
3.919" 3.875" 4.825" 4.767"
9 5/8"
36.00 40.00 40.00 43.50
8.765" 8.679" *8.750" 8.599"
WT .438" 87.50 133.00 WT .625"
16.000" 17.567" 18.542" 18.562"
USE Low stress General Sour service Higher strength High strength/deep Very high strength CO2 and chlorine H2S, CO2 chlorine
3½"
4"
For example, 5 1/2" VAM N-80 17lbs/ft may cost £5 per foot but 51/2" NKK 17lbs/ft 25% chrome will cost £50 per foot. Therefore, in a 15,000-foot development well: VAM tubing cost NKK chrome tubing cost
4½"
= £75,000 = £750,000
Either way, it is a very substantial investment and helps understand why it is important to take care of the pipe at all stages from pipe-mill until it is landed downhole.
5"
5½"
Note:
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7"
7 5/8"
9 7/8" 103/4 "
113/4 "
133/8 "
14" 16"
17" 185/8 " 20"
* Denotes “Special Drift”. Drift length should be 42" (can be 12" for casing sizes (normally 7” OD and larger) Drift OD is to be reduced by 0.02" for internally plastic coated tubulars. Drift material should be suitably non-damaging.
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2.1
2.6
2.2
2.3
2.4
2.5
Size Refers to the OD of the pipe body. Tubing is usually used to describe pipe OD's up to and including 41/2", while sizes above 41/2" are usually referred to as casing. Although this is not a good definition any longer, it is still the one which appears in the data tables. Weight The weight of pipe is usually expressed either as nominal weight or plain end weight, in pounds per foot (lb/ft). The former takes into account the extra weight due to a coupling or upsetting the pipe ends and hence the figure is always slightly greater than the plain end weight. The stated weight has a direct relationship to the wall thickness of the pipe by varying the I.D. Thick walled pipe is stronger, but heavier than thin walled pipe. Grade This refers to the type of steel of which the pipe is made. Grades and their classifications will be described in the next section - it is sufficient to say here that the grading corresponds to the strength of the steel so that the higher grades have the greater strength. Thus a string design engineer can sometimes choose between going for a heavier wall pipe in a lower grade of steel or a higher grade of steel in a lighter weight pipe to meet a particular set of design criteria. API tubular joints and couplings are usually colour coded to indicate their grade as listed in API 5CT (see figure 2). Proprietary grades can have API or independent colour coding which indicates: size, weight, grade, connection type, inspection status and coupling specification (i.e., special clearance). Figure 2 Connection Type Refers to the threaded ends of the pipe and is either the thread form in API type connections (8 round, buttress etc) or the maker and proprietary designation in the case of non-API or premium types (e.g. Hydril PH-6, Atlas Bradford TC-4S, VAM ACE). Range Casing is classified also by the length range into which it falls. API Specification 5A establishes three length ranges within limits and tolerances given below : RANGE 1 2 3
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Grades of Steel for Casing and Tubing
We can divide the steel grades used in OCTG into those which are known worldwide as the API grades and which conform to the API specifications 5A, 5AC and 5AX. And those, which have, been developed by individual steel mills (such as BSC, Sumitomo etc) specifically for oilfield applications, but which are not covered by an API designation. These latter steels are usually referred to as the proprietary grades because they conform to the steel mill's own specifications (which exceed the API) and have a designation which often incorporates some reference to the originating mill e.g. BSC-HC-95 or SM95S (Sumitomo). 2.6.1 API Grades The API casing and tubing grades are designated by a prefix letter followed by a number. The number always refers to the minimum yield strength for that grade of steel, expressed in ksi (1ksi = 1000 psi). For example, the minimum yield strength for C-75 grade is 75 ksi, for L-80 grade it is 80 ksi etc. The table below shows the API grades of steel and some of their properties.
API GRADES IN OCTG
GRADE J-55 (Tubing) K-55 (Casing) C-75 L-80 N-80 C-95 P-105 (Tubing) P-110 (Casing)
YIELD STRENGTH (KSI) Minimum Maximum 55 80 55 80 75 90 80 95 80 110 95 110 105 135 110 140
* NOTE -
HEAT TREATMENT N&T, Q&T Q&T N, N&T, Q&T Q&T Q&T Q&T
TYPICAL HARDNESS (ROCKWELL) 14-26 23 max 16-25 18-25 25-32 27-35
Heat treatments as follows: N = Normalised N&T = Normalised and Tempered Q&T = Quenched and Tempered
LENGTH (ft) 16-25 25-34 over 34
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2.7
2.8
Selection of Grades Selection of the grade of pipe is based on 3 essential factors, namely performance, cost and environment. Performance depends essentially on the yield strength of the grade selected. The correct yield strength must be used so that the pipe will have sufficient performance in tension, burst, and collapse to satisfy all the factors in the string design. The performance properties are published in connection catalogues and steel mill brochures and it can clearly be seen that the performance of the pipe increases as the grade gets higher (i.e. going from J-55 to P-110). Cost is also a major consideration and may influence the choice of pipe weight and grade. Higher grades tend to be more expensive and it can often prove more cost effective to use a heavier wall in a lower grade of pipe. Finally, environmental aspects play a vital role in pipe grade selection. Operating temperature is important because the impact resistance of steels decreases with decreasing temperature so that higher grades such as P105 and P110 should not be used in applications where minimum continuous operating temperatures are lower than 80 degrees C (175 degrees F). The presence of H2S is another important environment factor. It is known that the hydrogen embrittlement effect of H2S also referred to as sulphide stress cracking (SSC), is minimal in steels below a hardness value of about 24 Rockwell. Suitability for sour service will be affected by hardness and the best know example of this is the distinction between L-80 and N-80 grades. N-80 grade material is produced to a looser specification and is acceptable with yield strengths up to 110 ksi and hardness up to 25 Rockwell. This makes N-80 unsuitable for sour service, but also means that it is cheaper to produce than L-80. L-80 is suitable for sour service because it is made to tighter specification with controlled hardness below the critical value. The most common grades of pipe run in the North Sea are N-80 and L-80 because they can satisfy the performance requirements for many North Sea wells at an economic cost. In some cases, however, performance requirements and environmental factors may dictate that a more specialised material is necessary and a proprietary grade is to be used. This is becoming more and more likely as the search for oil brings us into increasingly hostile well environments.
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Proprietary Grades Proprietary grades were developed by the steel manufacturers to overcome some of the restrictions imposed by the limited range of API grades. To illustrate the point by referring to the British Steel Proprietary Grades listed in the table below, we can see that the SR90 and SR95 grades allow the use of steels with higher strength than L-80 in sour environments. This is not possible with the API grade C-95 that does not have the restricted yield and hardness control of the proprietary grades. For applications where there is high external pressure, the HC-95 (high collapse) grade gives collapse ratings which for a given weight of pipe are virtually the same as for the next higher weight of C95. This is of great value where clearances are tight. Finally, the proprietary grades of casing reach strength values, which far exceed the range offered by API. This means that casing strings can now be set at greater depth (important for deep drilling) and the range includes extra toughness grades suitable for low temperature application such as arctic drilling (permafrost etc). BRITISH STEEL PROPRIETARY GRADES GRADE
YIELD STRENGTH
HEAT TREATMENT
SPECIFICATION
SR-90
90-105 ksi
Q&T
Superior to API 5AC Suitable for sour service.
SR-95
95 ksi min
Q&T
HC-95
95-140 ksi
Q&T
Developed to contain high external pressures not for sour service.
Q-125
125-155 ksi
Q&T
V-150
150-180 ksi
Q&T
High strength casing not recommended for low temperatures
XT-130
130-155 ksi
Q&T
XT-140
140-165 ksi
Q&T
XT-155
155-180 ksi
Q&T
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Extra toughness (XT) range of high strength casing grades suitable for low temperature applications.
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3.1
CONNECTIONS AND SEALING METHODS Threaded connectors have been used in the oilfield since rotary drilling first started in 1903. Design and capabilities have changed greatly since then, but the principle of screwing together two pieces of pipe remains the same. The American Petroleum Institute (API) made the first attempts at standardising oilfield tubulars by the introduction of API specification to provide standards for: casing tubing work tubing
Although connection development has been a continuous process, several significant advancements have been listed: 1901 ROTARY DRILLING 1915 COUPLED TUBULARS WITH VEE THREADS 1925 8-ROUND REPLACES VEE 1934 HYDRIL TWO-STEP 1936 FIRST BUTTRESS 1937 HYDRIL CS 1946 HYDRIL CS INTEGRAL JOINT 1947 NATIONAL X-LINE 1948 HYDRIL PH-6 1959 BUTTRESS BECOMES API 1960 X-LINE API 1966 VAM | | CONTINUED PROGRESS OF PREMIUM DESIGN | PRESENT
liners casing and tubing pup-joints drill-pipe
All the above are suitable for use in drilling and production operations, and come under the jurisdiction of the API Committee on Standardisation of Tubular Goods. Through design development and many years of field experience, API connectors have advanced greatly and are still widely used today due to: a)
Relative low-cost manufacture
b)
Reasonable reliability under most field conditions
c)
Widespread availability
Connection Development History
At present, a very general limit to API 8-round and buttress is given as: - < 5000 psi differential - < 250 degrees F downhole - No gas or condensate wells
3.2
However, to meet the increasing demands of operators over the years, many non-API connections have been designed and today many different styles are available. To satisfy the requirements, connectors must show varying degrees of: - Tensile efficiency. - Burst and collapse efficiency. - Pressure integrity. - Torque capability. - Bending resistance. - Acceptable geometry (OD and ID). - Streamlined profile. - Durability for re-use. Demands have also produced a variety of non-API grades of steels for different applications, resulting in different handling, running and make-up procedures.
Tubular End Forms Before being threaded, the ends of the plain pipe can have one of several end forms formed in the mill (see fig 3). The purpose of this is to increase wall-thickness in the thread area to compensate for loss of material after machining. Internal/External Upset is used primarily for drill-pipe tool joints but the all forms can be found in tubing and casing designs. Selection of end forms and coupling is a balance between connection strength or efficiency and physical size of the connection, OD and ID. Hence many variations exist to cover specific requirements. Figure 3
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3.3
3.5
Connection Forms All connections can be defined as: a)
Integral A threaded pin end of pipe is screwed into a threaded box end of pipe.
b)
Coupled Two threaded pin ends of pipe are screwed together using a double box coupling.
Thread Terminology In order to understand the stresses and sealing capabilities of connections, it is desirable to understand basic thread terminology and what influence this has on the make-up process. The following examples show the basic features and nomenclature used in API threads and covers the most common types: -
Round Thread (see Fig 5) Buttress Thread (see Fig 6) Extreme Line (see Fig 7)
CONNECTION FORMS R O UN D T H R E AD F O RM A
P P IT C H LIN E
P IP E A X IS
Figure 4
3.4
PIT C H :
Th e d ista nce from a p oint o n a th rea d to a co rresp ond in g point o n th e n ext thre ad m ea sure d para lle l to th e pipe axis
L EA D :
Th e d ista nce a s crew threa d ad vance s axially in one tu rn
Figure 5
Connection Criteria The criteria for any connection design can be simplified as:
B UT TR E SS TH R EA D F O RM L OA D F LA NK
a)
Load bearing capability This requires sufficient turns to be put into the connection.
CR E ST
ST AB FL AN K
PITC H L INE
RO OT P
b)
c)
10 o
Pressure sealing capability This requires sufficient torque to be put into the connection.
3o
PIP E AX IS
Field suitability The design engineer chooses this.
Figure 6
E X T R E M E L IN E T H R E A D F O R M
L O A D FLA N K
CRE ST
S TA B FL A N K
ROOT
6
o
6
o
P IP E A X IS
Figure 7
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The dimensions and inspection procedures for these are given in API Spec 5B, which includes dimensional manufacturing tolerances. The important features of threads, which affect the make-up, are: a)
Taper
The increase in pitch diameter of the thread, given in inches per foot of thread, or:
From this short review, it can be seen that there are many possible variations in thread dimensions within the machining tolerances and, as will be seen later, these have a strong influence in the connection make-up process.
MODIFIED BUTTRESS THREAD FORM
PITCH LINE
Taper =
b)
c)
Pitch
Lead
To overcome some of the limitation in API threaded connections, several other thread forms have been developed, including:
change in diameter ---------------------change in length
The distance from a point on a thread to a corresponding point on the next thread measured parallel to the axis.
•
Modified Buttress (see Fig 8)
The distance a screw thread advances axially in one turn.
•
Negative Flank (Hooked) (see Fig 9)
•
Dovetail (Wedge Thread) (see Fig 10
In API-type threads, which are machined with a single cutting tool, the pitch and lead should be the same, provided the cutting tool moves at a constant speed. The portion of material remaining between the grooves is the thread. Hence, the sum of the groove width, plus the thread width, must be the pitch of the thread. If the width of the thread is greater than the groove then it will have a 'fast' lead. Conversely, if the groove is wider than the thread it will have a 'slow' lead.
API threads have a nominally constant taper thread. Height and flank angle are also specified in API Spec 5B.
30 o 90
o
PIPE AXIS
Figure 8
NEGATIVE FLANK THREAD FORM (HOOK THREAD)
Each can be found in different designs. Other connection designs have included combinations of thread features such as: • • •
PITCH LINE
Multi-tapered thread form Non-tapered (straight) Two-step thread form
o
30
o
10
PIPE AXIS
Figure 9
WEDGE THREAD FORM
PITCH LINE
PIPE AXIS
Figure 10
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3.6
3.7
Premium Connection Development Requirements for greater and more reliable sealing capability have produced a style of connection known as the PREMIUM CONNECTION and although not yet standardised by API, can best be defined as: A Premium Connection is one which derives its PRIMARY pressure-sealing capability by use of at least one metal-to-metal seal. As well as more reliable seal integrity, premium connections have been designed to satisfy the following criteria:
3.6.1 High Pressure and Temperatures -
need to maintain seal integrity under high combined load stresses. high pressures and temperatures increase corrosiveness of CO2, H2S and chlorine (in combination). large variations in temperatures increase mechanical stresses, e.g. producer to injector conversion. high temperatures can reduce thread compound and seal-ring performance.
3.6.2 High Loads -
Demands for connection designs to give high connection efficiency compared to pipe body. connection design for high combined loads. design for re-usable work string.
3.6.3 Restricted Clearances -
slimmer connections compared to conventional connections. optimised well plans. unexpected extra strings.
3.6.4 Corrosive and Erosive Fluids -
reduced connection stress levels for Hydrogen Sulphide attack. less galling in high-grade steels. smooth internal bore. corrosion barrier rings.
Comparison of design features available in today's premium connections is a substantial project and cannot be considered here, but can be studied further by reference to the bibliography.
Sealing Methods As well as the important function of bearing up to the expected loads in a well, the primary function of tubulars is to provide a leak-free passageway for drilling and production purposes. As will be seen, there are many available connection sealing methods, but all of them rely on controlled make-up to activate the sealing mechanism properly. All of COMMON SEALING METHODS the seals are then subjected to the combined loading of THREAD DOPE SEALS downhole conditions plus the pressures and corrosion of wellbore BOX fluids. PIN
3.7.1 API Sealing API round threads and buttress rely on two sealing methods as shown in Fig 11. Interference of the thread flanks produces metal-to-metal seals and a suitable thread compound plugs the small gaps. Note difference in the sealing surfaces between round threads and buttress. Thread compounds suitable for casing and tubing normally contain particles of soft metals such as lead, copper or zinc and perhaps nonmetallic compounds such as Teflon or graphite. These particles, suspended in a grease for lubrication, deform and pack-off in the thread gaps. The particles also prevent galling between the thread surfaces.
METAL TO METAL SEALS
A.P.I. ROUND THREAD
METAL TO METAL SEALS
BOX
PIN
THREAD DOPE SEALS
A.P.I. BUTTRESS THREAD
Figure 11
Another common sealing method is the flank seal or radial seal. This requires careful machining of the seal surfaces and the seal is achieved by metal-to-metal bearing pressure between the pin and box seal areas. An internal or external shoulder is usually used to prevent possible damage to the flank seal by over-torquing.
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Leakage problems with API threads and deterioration of thread compounds lead to the development of resilient seal rings (see Fig 12). Here, a groove is machined out near the base of the box threads and an elastomer ring is inserted. During make-up, the threads on the pin will cut a path through the material, forming a match to the pin thread. Displaced material will also deform and plug the thread gaps. This type of seal has been successful in many applications. The main reservations of this method are:
SEALING METHODS PLASTIC SEAL RING
SHOULDER SEALS PIN
BOX
Figure 12
a)
Unsuitable seal material can deteriorate under pressure/temperature extremes.
b)
The machined seal groove can cause detrimental stress concentrations in the box
c)
Extra care and cleanliness required for correct seal-ring installation.
d)
An ill-fitting seal ring could lead to the requirement for a full workover.
3.7.2 Metal-to-metal seals Figure 14
Classed in three main categories: a) Primary internal seals b) Primary external seals c) Shoulder seals
SEALING METHODS – PREM IUM CONNECTIONS METAL TO M ETAL SEALS PRIMARY INTERNAL SEALS
PIN
FLANK SEAL
PR IMARY EXTERNAL SEALS
PIN
BOX EXTERNAL SEAL
These are all illustrated in Figs 13 & 14.
BOX
PIN
The seals derive their sealing capability by the wedging action of the pin advancing into the box and some additional pressure produced by a flexing action caused by a torque shoulder. Torque shoulders act as a 'stop' mechanism to prevent over-torquing and possible deformation of the seal area. Any yield or deformation will reduce the sealing capability of the seal and could result in a change to the structure of the metal itself, allowing corrosion to occur at an accelerated pace. In the worst case it will cause a restriction of the ID of the tubular, this is commonly called `Belling'. Most torque shoulders also claim to be a further seal area.
FLANK SEAL BOX
Many connection types contain more than one seal and most have a combination sealing method. PIN
PIN
14 0 EXTERNAL SEAL
ANGLED FLANK SEAL BOX
3.7.3 Galling
BOX
Metal sizing - or galling - is caused by a complex inter-relationship involving chemical composition, hardness, surface contact geometry, relative motion, lubrication (or lack of!!) and differences in the parameters between the contacting metals.
Figure 13
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Connection Technology The inclusion of silicones improves low temperature properties and may improve application to water-wet threads, but does not necessarily improve anti-galling or sealing capabilities. These properties are a function of the specific combination quantities and particle size of the powdered solids. These particle sizes and specifications are set out in API Bulletin 5A2, as is the testing procedure for these compounds.
THREAD COMPOUNDS Introduction Thread compounds are used on every threaded connection in a casing, tubing, line-pipe, or drill string. For the purposes of this course, we will deal only with the type used on tubing and casing, covered in API Spec 5A2.
4.3
The types of solids used in thread compounds are predominantly ductile, relatively weak, low melting point materials which will deform readily when pressure is applied. When the joint is tightened, the metal powder particles will fill all the small tool marks, impressions and imperfections in the joint as they compact together.
Thread compounds for tubing and casing were originally developed by the Mellon Institute of Industrial Research, funded by an API research project, to satisfy the following objectives:
4.2
a)
Adequate lubricating qualities to prevent galling in threaded connections during make-up.
b)
No tendency to disintegrate, nor undergo radical change in volume at temperatures up to 300 degrees F.
c)
No tendency to become excessively fluid at temperatures up to 300 °F.
d)
Sealing properties to prevent leakage at temperatures as high as 300° F.
e)
Absence of any deleterious instability and of any drier or hardener that will evaporate or oxidise, thereby changing the thread compound properties.
f)
Resistance to water absorption.
g)
Sufficient inert filler to prevent leakage of API casing and tubing joints under pressure as high as 10,000 psi.
h)
Readily appliable by brush to pipe joints in cold weather.
Composition The two most common types of compound used in tubular make-up are API and API Modified. Both compounds are a mixture of metallic and graphite powders, uniformly dispersed in a grease base, the proportions being 64% solids and 36% grease base. The solids should be a composition of the following materials: a) b) c) d)
Sealing
In an API connection, the thread compound will fill the voids left between the pin and box thread crests and roots, or flanks, and together with the bearing pressure effected by the mating of the surfaces, will provide a pressure seal. In an API connection, therefore, the primary function of the thread compound is to provide a sealing capability. In a premium connection, the role of the thread compound as a sealing agent is secondary, as the primary seal relies on the mating of at least one set of finely machined metal/metal seals. However, the function of the thread compound as a lubricant is still important. Correct application to the surfaces of mating connections is necessary to prevent galling, ensure smooth running and assist in break-out. 4.4
Co-efficient of Friction The amount of rotation can be controlled by the co-efficient of static and dynamic friction of the compound. Much of the applied torque will be expended in overcoming friction produced by a high co-efficient compound. Therefore, rotation will be limited. The same torque applied to a low co-efficient compound allow more rotation as less torque is required to overcome friction. In general, lubricating oils, Teflon, lead, graphite and sulphur, decrease the friction coefficient, and zinc, copper silicates, zinc-oxide and non-lubricating oils increase the friction co-efficient.
Powdered graphite (28%) Lead powder (47.5%) Zinc dust (19.3%) Copper flake (5.2%)
API and API modified have the same percentage and constituents of solids. The difference between the two is the grease base. Whereas API modified thread compound has a 36% grease only base, the API has a base consisting of 20.5% grease, 12.9% silicone compound and 7.2% silicone fluid.
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EFFECT OF THREAD COMPOUND ON CONNECTION
Deformation
AVERAGE CONNECTION MAKE-UP TORQUE ( FT / LBS )
MAKE-UP TORQUE
Flattening and elongation of the metal powder particles requires energy. This energy is supplied in the form of torque. The greater the density of particles, the more torque required for deformation and crushing. A table of the relative yield strengths of the metal powders is shown in the table below. It can be seen that more torque is required to deform copper or zinc particles than Teflon, graphite or lead. The rate of deformation has a major effect on the angular rotation of the connection. The faster the torque is applied, the more stress is required to deform the particles, and so angular rotation will be reduced for a given torque. Fig 14 shows the rate of application relating to deformation.
1,750 Average torque of 5 connections 1,500
for each type of Thread Compound, all made up to the same position.
1,250 1,000 750 500 250
MATERIAL YIELD STRENGTH PSI
0
A
B
C
D
E
F
G
Copper Zinc Lead Graphite Teflon
THREAD COMPOUNDS EMPLOYED
Figure 15 Fig 15 shows the effect of make-up torque on the amount of angular rotation using A) low friction co-efficient, and G) high friction co-efficient, thread compounds.
4.6
Work Hardening Work hardening is the property of a metal to resist deformation, as deformation continues. Once yield stress is reached, the amount of additional stress required to further deform the particle is significantly higher. In most thread compounds, additives such as lead oxide, zinc oxide and silicates are employed to produce dispersion hardening. These secondary particles become embedded in the metallic powders during crushing, and further increase the resistance to deformation.
EFFECT OF MAKE-UP TORQUE ON ANGULAR ROTATION 25,000 20,000 Make-up torque psi
10,000 3,000 600 200 200
The above properties relate to the importance of the thread compound as a lubricating, anti-galling and sealing agent. The rotation limiting characteristics relate to nonshouldered connections, and it must be remembered that the primary function of the use of thread compounds with premium connections is that of lubricating and anti-galling agents.
15,000
10,000
5,000
4.7 0
0
2
4
6 8
10 12 14 16 18 20 22 24 26 28 30 32 34 36
Angular rotation of make-up torque
Figure 16
A
B
Fig 16 shows the effect of makeup torque on the amount of angular rotation of two thread compounds on a non-shouldering connection. A given torque will produce less angular rotation (makeup) using a high coefficient of friction compound (A). Compound (B) has a lower coefficient of friction and therefore, a given torque results in a greater amount of angular rotation. Excessive make-up causes high stresses to be set up in the thread roots and severe damage can occur in the form of stretched pins, cracked threads or cracks through the joints. Version 2.00
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Practical Use As we have seen, thread compounds have lubricating properties and so reduce friction between pin and box threads during make-up. This has a direct relationship to the torque necessary to properly make-up a connection. The greater the friction present, the greater the torque necessary to overcome it. Different thread compounds lubricate different extents and we take the different properties of various thread compounds into account by using correction factors or thread compound friction co-efficients. Published data on torque figures are based on using a factor of 1 as with API modified dope. The correct torque figure for a different thread compound is then derived by multiplication of the appropriate factor. In practical terms, this means we need to know for certain the connection type and torque figures and when using other than API modified thread compound, we need to be sure of the type of thread compound and its correction factor (if it is more or less than 1).
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Equally important when using any thread compound is to ensure that it is thoroughly stirred after opening a new can, and that it is never mixed or adulterated with any other substance (such as diesel etc). In cold or arctic conditions, warming of thread compound may be necessary to enable it to be brushed on to the threads. 4.8
5
There are a number of common occurrences which can hinder or prevent proper make-up. They include such things as badly cut or recut threads, oval pipe, rusted or dirty threads, poor surface finish and particular problems associated with connection types. Some of these problems can be prevented, or remedied in the field, while others cannot. In all events, it helps to have some prior knowledge which enables action to be taken at the earliest opportunity. The following two examples are typical of problems which have come to light in the recent past.
Environmentally Friendly Compounds New types of thread compound are coming onto the market in an effort to eradicate the use of 'unfriendly' ingredients such as lead. Unfortunately, trials on the compounds seem to lag behind the rush to use them in the field, with the results that some trials are taking place in 'live' situations where important information like - what is the correct correction factor for the compound?, does the compound have good anti-galling properties?, will the compound aid in breaking out the connection?, how does the compound effect the graph profile?, seem to be missing. It will probably take years to determine the benefits of certain compounds in regards to their properties in connection make-up.
COMMON PIPE PROBLEMS
5.1
Poor Surface Finish Generally, all field threads are treated to resist galling and to enable thread compounds to adhere to them, after the threading process is completed. This type of surface treatment depends on the material, and whilst it is probably true to say that a great deal of attention is given to treating the exotic and expensive gall-sensitive grades, the same care is not always given to the plain API or carbon steel grades, especially where re-cutting of the connections has occurred. The surface treatment given to threads on API grades of carbon steel is usually a manganese or zinc phosphate bath treatment. This results in the threads becoming coated with a thin phosphate coating which has a familiar dull black/grey colour. The presence of this coating helps the thread compound adhere to the threads and further helps prevent galling by physically keeping the metal surfaces from direct contact during make-up. Failure to carry out this treatment results in shiny threads (assuming they have not rusted) with a machined finish. Under certain circumstances, threads with this kind of finish are liable to gall giving rise to rejected make-ups or unnecessarily high torques. Obviously this is more liable to occur with larger sizes and heavier wall pipe, and with tapered interference type connections, but this problem is fairly easily corrected in the field by using spray-on molybdenum disulphide coatings such as moly-kote or moly-paul. So, in practice, when running pipe which may be subject to galling due to the size, weight and connection type, it is advisable to apply a moly disulphide spray coating on any shiny threads seen prior to make-up. The sprayed on film should briefly be allowed to dry (it turns from shiny to dull in less than a minute), before the connection is made up. Molybdenum disulphide is a solid lubricant with a very high resistance to compressive stresses and so the characteristics of the sprayed on film are similar to the phosphate coating which is lacking.
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5.2
6
Deformation of Connection on Make-Up This occurs when the stresses in the connection, due to the applied torque, exceed the yield stress of the material and deformation occurs.
The ever increasing effort to find hydrocarbons worldwide has led to drilling in increasingly harsh environments. Drilling conditions in terms of location, pressures, temperatures, formation fluids etc have grown increasingly severe. This has resulted in a need for high quality and reliable casing and tubing, suitable for these environments. The difficulties encountered in drilling in an environment where carbon dioxide (CO2) is present provides us with a prime example of this. Traditional carbon and low alloy steels have proven unsatisfactory in resisting corrosion due to wet carbon dioxide.
This can occur if: a)
The manufacturer's recommended torque is too high.
b)
The indicated torque is lower than the applied torque due to faulty equipment.
c)
The pipe or coupling material is faulty and not to specification.
The first case is an example of how manufacturers sometimes make mistakes. Historically, there has been comparatively little scientific work done on connection torque figures, and many of those published are based on empirical data such as make and break tests with extrapolation of these results to cover sizes of connection not tested. This has, in practice, posed fewer problems than might have been expected, due principally to the fact that most grades of steel produced actually have yield strengths significantly higher than the minimum specified. However, when dealing with lighter weight pipe and where the material is near to its minimum specified yield, a problem can sometimes occur even when using the published torque values. An example of this is where 31/2" VAM tubing, although torqued within published specifications, suffered belling or distortion of the central register. This problem can result in leakage, ID restriction, or at worst, connection failure. The fact that this can occur, and by use of GA equipment can be seen to occur, is one of the reasons which caused VAM to re-think and re-publish their torque figures. The second reason will be discussed more fully later in this section, suffice it to say that inaccurate torque readings are considerably less likely these days with the advent of computerised systems, and at all events should never occur if equipment is properly maintained and operated. Equally, material shortcomings will be unlikely if the source of steel is a major OCTG mill such as SUMITOMO or BSC etc.
CHROME TUBULARS
In order to deal with this problem, the manufacturers of steel have developed high alloy chromium grades such as 9%, 13%, 22% and 25% Cr which have high resistance to CO2 corrosion. 6.9
The problem - corrosion As long ago as 1968, it became evident in the southern sector of the North Sea that standard carbon steel grades, such as N-80, were subject to severe damage in the presence of CO2. The type of damage encountered included severe metal wastage (general corrosion) with instances of holing, and deep pitting (localised corrosion) also with instances of holing. A detailed study concluded that the corrosion was caused primarily by carbonic acid (H2CO3) formed from produced carbon dioxide and water. In the case of high flow rates in production tubulars, the effects of corrosion are further compounded by erosion to which carbon steel grades are also susceptible, and this results in an even greater reduction in the useful life of the pipe. High flow rates will also tend to preclude the successful use of inhibitors to combat the corrosion.
6.10 The solution - 13% or 23% Chrome steel Both 13-Cr and 23-Cr are speciality steels, designed for well environments where the combination of temperatures and corrosive elements make the use of carbon steel unsuitable. Using either will help prevent weight loss, pitting and erosion corrosion associated with API grades such as L-80, N-80 in the presence of water saturated CO2. A comparison of steel grades can be made as follows L-80 - carbon steel - controlled hardness - H2S resistant - resistant to cold working - relatively resistant to handling - damage - threads are phosphate coated - parkerised surface - Relatively resistant to galling of threads
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High Chrome - alloy steel - controlled hardness - CO2 resistant - susceptible to cold working - susceptible to handling - damage - threads cannot be coated - and require special treatment (such as peening and oxalation) - susceptible to galling of threads
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6.10.1 Advantages and disadvantages
6.13 Surface treatment of Chrome threads
To sum up, we can see that the use of chrome steel gives the advantage of excellent corrosion resistance coupled with high yield strength capability but has the disadvantage of significantly greater susceptibility to handling and running damage when compared to the carbon steel grades. 6.11 Corrosion Resistant Alloy (CRA) Grades For OCTG, these are usually stainless steels with the chrome content being dependent on the application. For Wet C02 corrosion, usually 13% chrome steels are used (or sometimes 9Cr-1Mo for less severe applications). For more aggressive environments, where resistance to high temperature H2S attack, possibly in combination with C02 and chloride presence, and where tensile strength up to 140 ksi is needed, a duplex chrome steel with 22% chrome would be used. For the most aggressive environments and where a slightly lower tensile strength is acceptable, a fully austenitic (or super austenitic) stainless steel such as 28% chrome would be used. The minimum yield strength of these stainless steels as well as their main composition is often incorporated in the proprietary designation e.g. Sumitomo SM13Cr-80 or SM22Cr80 which are 13% chrome and 22% chrome respectively, with each having a minimum yield strength of 80 ksi. 6.12 Thread selection for Chrome steels All major thread manufacturers, including Vallourec, Hydril, Hunting and Atlas Bradford, have successfully applied their thread designs to this material. It is not the purpose of this guide to make recommendations on which is the most suitable connection to use with chrome steels, but it is fair to say that successful use of chrome steel tubulars will be more likely if some attention has been paid to the following points. a)
The connection should have a profile suitable for use in a corrosive and erosive well environment, i.e. a streamlined ID and incorporating a metal to metal internal shoulder seal. Selection of a premium connection design usually ensures that this is the case.
b)
The thread manufacturer should ensure that a suitable surface treatment against galling is applied after the threads have been machined (see next page).
c)
The thread manufacturer (in consultation with the steel mill) must lay down appropriate running and handling procedures and these should be strictly adhered to. Appropriate torque figures details of special equipment and thread compounds etc should be included in this.
d)
A service company, which can provide experienced operators and sophisticated make-up monitoring equipment should be employed to actually run the pipe. This type of material should not be entrusted to a rig crew whose main experience is running drill pipe.
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Until the early 1970's J, K and N grades of steel, usually in the normalised rather than Q and T condition, predominated in OCTG applications. These steels had little tendency to gall due to the coarse grain structure and large inclusion content of the steel and the high variation in hardness from joint to joint. Subsequently, the industry turned more and more to using L-80 and proprietary sour service grades which, due to their Q and T heat treatment have uniform fine-grain microstructure, low inclusion content and more consistent and relatively low hardness. As a result, the tendency of these steels to cause galling in connections increased and the use of phosphate coatings (Parkerizing) was widely adopted as a countermeasure against galling. Zinc phosphate coatings applied by spray or by immersion are most commonly used. They achieve their anti-galling properties by helping to prevent direct metal to metal contact and by providing a "key" for thread compound. The phosphating process is a chemical reaction, but this reaction is entirely resisted by steels with a chrome content higher than 5% so for 13-Cr, and higher other surface treatments are employed. The various thread manufacturers each have their preferred surface treatment procedures for the high chrome alloy steel and these include: a) Oxalation process - a chemical process suitable for steels with chrome content above 5%. b) Sand blasting or glass peening - provides shallow surface work hardening and a "key" for thread compound. Grit size selection is critical for successful results. c) Electroplating - usually with copper, and this is done to the coupling threads. Copper plating quality is very variable unless carried out by experts. The copper provides a sacrificial boundary layer to separate the steel surfaces. d) Others - this is an area of continuing development and suitable treatments are constantly being sought. Potential treatments need thorough evaluation to determine their field suitability and this is a time consuming process. For example, New Vam Tubulars undergo the following processes: e) All carbon steel pins have Zinc Phosphate coating (sprayed on) except some sizes below 4½". f) All carbon steel boxes have Manganese Phosphate coating (dipped). g) 13% Cr pins are not treated at all. h) 13% Cr and 22% Cr boxes are copper coated. i) 22% Cr and above (pins) are bead preened (bead blasted). 6.14 Thread compounds and torque values There is a general agreement amongst thread manufacturers and steel mills that API modified thread compound is the best compound for gall resistance and this is the first choice when running chrome steel tubulars. The use of any other thread compound should be treated with extreme caution. However, new types of mainly `environmentally friendly' thread compounds are being sought to eliminate any potential dangers involved when making or handling some of the contents i.e. lead.
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The torque applied to a connection should be as recommended by the thread manufacturer. For 13-Cr and higher grades of material it is not uncommon for a thread manufacturer (perhaps in consultation with the steel mill) to recommend a lower torque value for given size and weight of connection than would be applied to a carbon steel grade of the same yield strength. This is because the higher grades are much more susceptible to galling effects of excess torque. Since there is quite a variation in actual yield strengths of given grades of carbon steel, thread manufacturers historically have erred on the excess side for torque values with comparatively few problems as a result. This is not true of the high chrome steels and consequently we may see recommended torques reduced by as much as 10% for higher grades to give longer thread life with no loss of performance. It cannot be over emphasised, however, that the thread manufacturer's recommendation on thread compound and torque value must be followed. Failure to do so will render any claim invalid in the event of a problem. 6.15 Effect of connection size, weight, and tong speed on make-up As a general rule, as a tubular increases in both OD and weight, more care must be taken in running to avoid the risk of damage to the threads and seals of the connection. This is because increasing radial friction and greater loads will make galling more likely in larger, heavier sizes. When running higher grades, the additional gall sensitivity of the material must be considered. Small OD Light Wall Carbon Steel Grade Steel
Increasing Tendency ------------------> To Galling
Large OD Heavy Wall High Chrome
The gall sensitivity of the connection can be compensated for by careful attention to handling and running procedures and by utilising equipment designed to alleviate any interference problems as outlined in the following sections.
7 7.1
TORQUE-TURN AND GRAPHICAL ANALYSIS THEORY Equipment and techniques
7.1.1 Torque-turn, Historical and Theoretical Background In the early '60's, the American Petroleum Institute conducted a survey of string failures which indicated that 86% of the casing failures, and 55% of the tubing failures occurred in the connection. These statistics encouraged Humble Oil and Refining Company (now Exxon) to instigate a technical programme, with the objective of reducing connection leakage. Humbles' laboratory facility in Pierce Junction, Texas was constructed specifically for this programme, and tests ensued on various connections, with differential pressure and cyclic temperature change conditions applied. It was quickly realised that good connection design and manufacture followed by correct handling and inspection would count for nothing if connections were not properly made up, and so this became the main area of concern. There are a number of significant variables which affect the stresses needed to be fully understood and equipment had to be developed which would allow simple control of these variables in the field. The mating threads in an API connection actually form several helical metal-to-metal seals and there must be a bearing pressure exerted between these mating surfaces in excess of the expected differential pressures. If the differential pressure exceeds the bearing pressure, then the connection will leak. The basic principle of torque turn is to ensure that the connection, when correctly madeup is within the appropriate range of torque and turns. Has sufficient thread engagement to carry the rated axial loads, and has sufficient bearing pressure between pin and box to maintain leak integrity without the connection being over-stressed. In the past, there were two simple alternatives for determining make-up of a connection. Either you could make up a connection to a fixed torque value or else to a fixed position, such as the triangle stamp on a buttress connection.
6.16 Plastic Coatings Another way to lessen the effects of sweet corrosion is to plastic coat the I.D of the tubular.
There are dangers to this simple approach, making up to a fixed torque may allow some protection from over stressing the connection, but it does not allow us to be certain that there is enough thread engagement to carry axial loads. Or that the internal seal in a premium connection is properly energised to provide the requisite leak integrity.
This is a relatively cheaper way to lengthen the life of the string. Plastic is bonded to the inside of the tubular providing a protected passage for the produced or injected fluids. A relatively new development to ensure plastic continuity throughout the string has been to install a plastic seal ring into a groove cut in either the coupling or the pin of the tubular. During inspection it is vital to check the plastic coating at the coupling and pin areas as this is usually where any chipping will occur. Metal drifts, careless drifting procedures or wireline work can also damage the plastic coating. Note: Drift sizes for plastic coated tubulars have generally 0.02" smaller I.D. than normal drift size.
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Make up to position may afford some degree of certainty about thread engagement, but because of dimensional differences between pin and box due to machining tolerances etc, there can be no certainty about the state of stress in a connection made up in this way. The connection may be sufficiently over stressed to fail in service or it may be under stressed and leak due to lack of pin/box bearing pressure. The torque turn method has been devised to control both connection stress and thread engagement. It is based on sound engineering principles and when correctly applied, torque/turn make up criteria are the best method of ensuring correct and reliable connection make-up.
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At Humbles' laboratory facility, several thousand connections were made up to various torque and turns parameters, and were subjected to tensile loads to 80% of the minimum yield of the materials, and to internal gas pressure to 80% of burst rating during temperature cycling. Temperature cycling was achieved by circulating glycol at a temperature of 300 degrees F, followed by glycol at room temperature, to stimulate extremes that occurred in wells between flowing and shut-in conditions. Pressure and temperature cycles were repeated a minimum of 50 times with an automatic system. Recorders were used to indicate when, and at what temperature, leaks occurred. By using various torques and turns, they were able to establish at what point a leak proof connection could be obtained for each size and type of thread. From these tests, allied to field and calculated results, 'torque-turn' figures were produced. These were published in a set of tables, for every size, weight and grade of API connection, i.e. 8 round LTC, STC and buttress. These values, of both minimum and maximum torque and turns are required to induce the required stresses during make-up, and in practice, provide a 'window' in which optimum make-up should fall (see fig 17). They take into account the tolerances found in any batch of pipe. It is periodically revised to include new connection types and to reflect refinements based on laboratory tests and field experience. It became obvious that it was not a practical proposition to attempt to monitor applied torque and angular rotation manually during connection make-up. Exxon licensed a Houston based company, Kestran, to develop an electronic system which would analyse both torque and turns and automatically indicate to the operator when this 'window' of values had been satisfied. This resulted in the 'Kestran Torque Monitoring System' which was sold to Exxon 'Torque turn' licensees, such as ourselves. Torque was monitored by means of a hydraulic load cell and turns by means of a microswitch that counted tenths of a turn. Both torque and turns analogue signals were fed to the computer - which was a TTL (transistor-transistor logic) system, and very "slow" in Figure 17 comparison with today’s microprocessor systems - converted into digital signals, and compared with the pre-set parameters as previously input by the operator. If the values at any point fell within the 'window' of 'torque-turn' values then the computer would accept the connection as 'good' and initiate a solenoid operated dump-valve fitted between the tong and power unit. This would cut the hydraulic flow to the tong and prevent over-torquing of the connection. In addition, a horn would sound, alerting the operator that make-up was complete. A note of the final values would then be taken for inclusion in the customers report. Final values outwith the 'window' of values would be classified as 'bad' by the computer, the dump valve activated, and the horn sounded to indicate incorrect make-up. The connection would then be broken-out, inspected and remedial action taken.
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Although originally developed for API connections, the use of 'torque turn' was soon applied to the running of premium connections. This evolution was broadly based on the fact that in a premium tapered connection, because of the thread tolerances, little torque should be encountered before a reasonably advanced state of make-up was reached. From a reference point, therefore, and presuming manufacturers tolerances to be within specification, maximum turns from this reference point should be of a finite value. These values, for different proprietary connection types, were researched by a leading service company and are in general use by all 'torque-turn' operators today. The reference position used for most premium connections is 10% of the optimum torque, but should the threads be damaged or the tubular be suffering from some kind of deformation, extra torque will be required to overcome the extra friction caused by one or more of these conditions. This will cause the reference torque to be reached at an earlier position in make-up and therefore turns will start being counted early which will result in the computer rejecting the connection on the basis of exceeding the maximum turns before optimum torque is reached. This will allow the problem to be investigated hopefully before any major damage has been done to the connection. As previously described, turns count mechanisms had the ability to resolve one tenth of a turn. It was found, however, in running premium connections, (especially parallel thread low interference connections) that from the reference position it often transpired that final make-up occurred in less than one tenth of a turn, even using a 5% reference torque value. Salvesen Drilling Services pioneered the use of the inductive proximity detector in the application of turns counting to one hundredth of a turn. In addition, no moving parts are involved and the unit is completely environmentally protected. This proximity detector was incorporated into Salvesen's CATT System (Computer Analysed Torque Turn) which was developed in 1981 as a 'high-tech' version of the Kestran system. It incorporated microprocessor based electronics, integral printer, was certified for Zone I use and boasted many features which made it the most advanced 'Torque-Turn' system of its time. It was however, a system not specifically designed for premium connections and the advent of new techniques in the make-up of those connections led to the application of new technology and the use of "graphical analysis technique". 7.1.2 Graphical Analysis The 'Salvo' graphical analysis system was developed primarily for use in the make-up of premium connections as these employ the use of a torque 'shoulder' in their design. This shoulder absorbs a significant portion of the make-up torque. Generally, they employ a metal-to-metal seal as the primary sealing mechanism. The torque shoulder has the effect of wedging the pin nose flank seal together with the corresponding seal on the box. Proper make-up usually requires about one-half to one-third of the manufacturers recommended make-up torque to be applied to the shoulder, thereby ensuring sufficient engagement of the metal-to-metal seals to withstand tensile and other forces down-hole (see fig 18).
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Connection Technology (see Figure 21). • Ensure a sufficient percentage of torque can be applied to the shoulder without final torque being above the maximum allowed. • Ensure a given percentage of torque is applied to the connection before the shoulder is identified (above LSP) (see Figure 22). The analysis system should also dump power to the tong and alert the operator if any of the following occur: • Too much torque applied to the connection (Overtorque) (see Figure 23). • Too many turns applied to the connection after reference torque (Overturns) (see Figure 24). • Not enough turns applied to the connection after ref. torque to allow definitive seal engagement / shoulder detection (see Figure 25). • Detection of turns after a shoulder has been identified (indication of the coupling turning or deformation of the shoulder) (see Figure 26). Torque / Turn curves normally show a steadily increasing slope, this can occasionally level out and still be acceptable. However, where significant dips appear before the shoulder point, some galling, trapped debris, or a lack / surplus of thread compound should be suspected. The shape of the curve is as important as any displayed value and should be consistent once a pattern has been established. Graphs showing profiles, which are deemed to be irregular should be broken out and inspected to try to ascertain the cause of the poor profile and any possible damage to the connection (see Figures 27, 28 & 29).
Figure 18 Each make-up satisfies the same final values of torque and turns, but only a graphic system can distinguish the distribution of torque between threads and internal shoulder. This is why torque-turn alone has limitations when making up internally shouldering premium connections, therefore graphical analysis is desirable. Conventional 'torque-turn' equipment was developed for use on API connections and 'torque-turn' figures issued to 'torque-turn' licensees by Exxon are based on API connections. 'Torque-turn' system per se give only final values of both torque and turns and are therefore unable to pinpoint the 'shoulder' position. They are thus incapable of applying sufficient torque to the shoulder as necessary to energise the metal-to-metal seals. Salvesen Drilling Services undertook an evaluation programme based on microcomputer data-acquisition and interface equipment to assess the feasibility of producing accurate graphical information, and using this information to control the final make-up torque based on the torque at the shoulder position. The result of this study was the development of systems such as BJ Services’ 'Salvo' system. A centralised database is being built of the many types and designs of connections, with important information on characteristic curves, profiles and fault conditions of these connections. The Salvo carries out the following basic functions. • Continuously monitor torque/turn information with turns accuracy of up to 1000 counts per turn and torque in ft/lbs. • Identify a shoulder engaging inside a premium connection (see Figure 20). • If the shoulder position is not identified before torque reaches Maximum Shoulder Position (M.S.P.) (x% OPT torque taken from max torque) the computer will dump power to the tong and stop make-up to prevent any further damage to the connection Version 2.00
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Graphical analysis can now be performed over the complete make-up from initial stab-in to final torque. This graph is called Pre-Turns and displays the initial thread engagement on the first half of the graph with the make-up above reference torque on the second half (see figures 30, 31, 32, & 33). One benefit of the Pre-Turns graph is the ability to show the shoulder torque if it is below reference torque. Important information such as shoulder torque, shoulder turns, final torque, final turns, joint number, tally number, etc are then logged along with the graphic profile of each connection on a non-volatile storage medium (floppy disc) or N.V.R.A.M. for processing to hard copy for further evaluation, analysis or historical record.
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SHOULDER INDICATING TORQUE / TURN GRAPH
SHOULDER INDICATING TORQUE / TURN GRAPH Shoulder Below LSP
Torque applied to Shoulder
Torque
Torque
Typical “Tapered Connection” Profile
Shoulder Engagement
LSP Turns
Turns
Figure 20
Figure 22
SHOULDER INDICATING TORQUE / TURN GRAPH
SHOULDER INDICATING TORQUE / TURN GRAPH
Torque
Over Torque
Torque
No Shoulder Detected
Turns
Turns
Figure 21
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Figure 23
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SHOULDER INDICATING TORQUE / TURN GRAPH
SHOULDER INDICATING TORQUE / TURN GRAPH
Over Turns
Torque
Torque
Shoulder above MSP
Turns
Turns
Figure 24
Figure 26
SHOULDER INDICATING TORQUE / TURN GRAPH
SHOULDER INDICATING TORQUE / TURN GRAPH
Torque
Poor Profile
Torque
Insufficient Detail
Turns
Turns
Figure 27
Figure 25
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SHOULDER INDICATING TORQUE / TURN GRAPH
SHOULDER INDICATING TORQUE / TURN GRAPH Pre Turns
Poor Profile
Torque
Torque
Re-Scaled Make-up graph
Ref Zero Turns
New display Pre-Ref Turns
Ref-Max Turns
Figure 30
Figure 28
SHOULDER INDICATING TORQUE / TURN GRAPH
SHOULDER INDICATING TORQUE / TURN GRAPH
Torque
Pre Turns
Torque
Dip Prior to Shoulder
Ref Zero Turns
Figure 29
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Ref-Max Turns
Figure 31
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SHOULDER INDICATING TORQUE / TURN GRAPH
Salvo equipment has shown itself generally very reliable in the field and major failures are rare, however, it is necessary as with any equipment, to ensure that care is taken when setting up, especially on the rig floor. When using non-integral tongs for example, the back-up line should be horizontal and at right angles to the tong arm for accurate torque readings. The torque gauge used should be correctly calibrated for tong arm length. When using Salvo equipment, this can be compensated for automatically after inputting the appropriate parameters.
Pre Turns
Torque
Care should also be taken to avoid physical damage, e.g. by carefully routing cables and tying them out of the way, any chances of an individual tripping on a cable and wrenching it from its fittings will be minimised. Equally, the effects of water and other contaminants can be avoided by ensuring that steam or water hoses are never played on the electrical equipment and silicone grease is used to seal electrical cable inputs and outputs. 8.1 Ref Zero
Pre-Ref Turns
Ref-Max Turns
Figure 32
SHOULDER INDICATING TORQUE / TURN GRAPH Pre Turns
Interpretation Problems With any system which processes and displays data by means of a microprocessor, the results are only as good as the original programming, and consequently, interpretation will be necessary by the operator to some extent, even in the best of systems. A typical example of this with Salvo is when the shoulder torque is near the critical value, which means the final torque will be very close to the maximum. Due to tong momentum and finite response of the dump valve, the final torque may exceed maximum by a small amount (say 1 - 100 ft/ lbs.). The Salvo will reject this make-up because it is programmed to do so, however, on a large connection such as 7" 35 ppf casing which may have a maximum torque of 12,000 ft lbs. this is a negligible overtorque. Salvo operators should recognise this condition and so the 'bad' decision would most likely be overridden, and the make-up accepted.
Torque
Other forms of interpretation may be less clear. Oil company reps often ask about 'typical' graph forms and appear confident and dogmatic in their interpretation of every dip and bump in a torque/turn graph ascribing to each and every one a particular meaning or significance. This approach is probably the result of not fully understanding this equipment. Experience shows that the shape of a torque/turn graph can be affected by a nu mber of factors, some of which are insignificant and others of which may be very important. Individual tong operators have their 'personal' effect by way of tong speed variations, where they change gear etc, and so do stabbers. Some are better than others, those who are not so good, tend to generate torque earlier than the good ones due to slight misalignment. An experienced operator will know the signs of significant damage such as galling indicated by spiky graphs, high turns and early build up of significant torque levels. He will check this by means of breaking out and inspecting the connection, checking for heat generated during make-up etc. These inspections may be more frequent early on in a job in order to get the feel of it, but once a regular graph pattern has been established with the initial joints, interpretation will become easier. It will then be necessary only to look principally at significant departures from the established norm.
Ref Zero
Pre-Ref Turns
Ref-Max Turns
Figure 33
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8.2
9
Proper Data Input In order to successfully run a string of pipe, it is necessary to know the appropriate data on the pipe so that correct torque values etc can be selected.
9.1
Overview Tubulars used to case and complete a well are more often than not, the greatest item of expenditure on the well. This is particularly true today when tubular technology has made great advances both in terms of material (i.e. metallurgy of higher grades) and of connection design. Such technology is not cheap, and it is essential, therefore, in order to protect this investment, not only to ensure that proper, safe procedures are consistently employed when running tubulars in the field, but also that the development in equipment used to run the tubulars keeps pace with these advances. The major manufacturers of premium threads, Hydril, VAM, NKK NSCC Hunting, etc employ highly trained field representatives to oversee their products being run at the rig site. This function is being offered more and more by the service company running the tubulars. However, it is very much a team effort which is required for complete success, and this will involve communication at various levels with casing crew, drilling crew and operator representatives (drilling or production supervisor). It is necessary, therefore, to ensure that all these personnel have at least an understanding of basic tubular running procedures and equipment.
The first step is to examine the pipe on the pipe rack or deck at the rig and if the pipe is new, it should be possible to read the stencil marks, which will indicate the size (OD.), weight, grade and connection type. This will also give information on manufacturer or origin, range (length of pipe) etc. If the stencilled information has disappeared due to usage or rusting, it may be necessary to get this information from the records (paperwork) in the Company Rep or Drilling Engineers office. It is also necessary to know which thread compound will be used and any correction factor associated with it, which may need to be applied when selecting the correct torque. Once we know the connection type, we can refer to the manufacturer's catalogue. Such a catalogue will contain all the most commonly required information on the manufacturer's range of connections (by size and type) and on the pipe body itself (tubing and casing data tables). From these tables, we can obtain the recommended torque for a particular size of connection type in a given weight and grade, basic dimensions (such as pin length, coupling OD etc) and tensile joint efficiency, as well as other parameters we may need to know. When pressure testing, in order to look up test pressures or to check that a requested test pressure is correct (i.e. not likely to burst the pipe) it may be necessary to look up the casing and tubing data tables. These tables contain the pipe strength data, which not only includes test pressures, but also collapse ratings, pipe body yield strengths and other information required by casing/tubing string design engineers.
RECOMMENDED PROCEDURES FOR RUNNING NON-CHROME TUBULARS
9.2
Accessory Equipment The thread manufacturers usually specify the suitability of elevators and other handling equipment and these recommendations should be adhered to. Slip type elevators are preferred with the proviso that due regard is paid to slip length for the given string weight or pipe material. Alternatively collar elevators may be used provided they have the requisite clearances for the joint in question and that the coupling can withstand the string weight to be run.
9.3
Lift Nubbins or Elevator Plugs These should be of the correct type, and for security, of correct proprietary origin. It is essential that they are cleaned prior to running, and at regular intervals during running to ensure there is no damage or contamination of the threads. They should be made up snug with a short bar, but not over tightened. A particular manufacturer's elevator plug may be designed to support the weight of only three joints or so, and great care must be taken to ensure that the full weight of the string is not supported by a lift plug which is not specifically designed for that purpose. In addition, it is necessary with flushline pipe to use a safety clamp (or dog collar) as well as the lift plugs.
9.4
Stabbing Guides All premium connections incorporate one or more metal to metal seals in the region of the pin nose. These seals are susceptible to damage by mishandling and especially by misstabbing due to their location. A suitable stabbing guide will eliminate the tendency to damage these vital seal areas, and is an absolute requirement when running high chrome alloys and exotic grades of material.
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9.5
9.7
Stabbing When stabbing a joint of pipe it should be controlled at each end. A member of the rig crew will guide the pin into the stabbing guide and then into thread engagement with the box. As the driller* slowly lowers the joint. It is essential to maintain alignment of upper and lower joints during this operation and subsequent make-up. Failure to do so will inevitably result in connection damage and possible leakage or failure downhole. * The use of a Single Joint Compensator, (Loadmaster) will control the lowering / lifting of the joint gently and safely.
Thread protectors are designed to reduce thread damage. Therefore, thread protectors must be kept on the pipe while it is sorted on the rack and when it is being moved prior to running. Thread protectors should be removed, threads thoroughly cleaned and connections inspected for damage. Early detection of minor thread damage will allow sufficient time to make field repairs, and cleaning of the threads will remove foreign particles that could contaminate the thread compound. Where pipe is racked in layers, threads may be cleaned a layer at a time just prior to running the pipe. A good solvent, rags and bristle brush (i.e. non-metallic), or else a high pressure steam cleaner may be used to clean the connections. Diesel should not be used as it never fully dries and will adversely affect thread compound. After cleaning, connections should be dried (e.g. with an air line) and should never be left exposed for long in a potentially corrosive atmosphere as flash rusting may occur within 12 hours.
To control the upper end of the joint being stabbed, a person on the stabbing board is generally recommended. Various alternatives to a stabber include a simple yoke fitted to the stabbing board or a remotely operated hydraulic system. Equally, with a top drive unit securely mounted on guide rails, thus eliminating conventional free-swinging blocks, none of these may be necessary as perfect alignment is more easily achieved. It is probably true to say that a good stabber who knows what he is doing is more reliable than any mechanical system. However, experience has shown that the use of an active load compensator fitted above the single joint elevator will significantly reduce thread damage during stabbing operations. 9.6
Power Tongs, Gauges etc
In connection designs, which incorporate an elastomeric seal ring set in a groove in the box threads, it is important to ensure cleanliness of the groove prior to seal ring installation. 9.8
Power tongs and an accurate system for measuring and controlling torque build up should be used. Torque turn theory has been developed to ensure optimal make-up of connections, and the new generation of equipment that has evolved as a result of torque turn theory now enables an unprecedented amount of immediate data and control of make-up in the field. Systems such as BJ's Salvo ensure that make-up problems are diagnosed early enough to prevent further connection damage and make-up is aborted to allow the connection to be broken out and checked. Load cells are calibration checked for each job, and variables such as tong arm length, snub line angle, thread compound correction factor are programmed into the salvo computer for each job to ensure accuracy of torque measurement. The shoulder point of shoulder connections is identified graphically and make-up is allowed to proceed only within the "window" of correct torque and turns for each particular connection type. Tong RPM must also be controlled during make-up, when running premium connections, and more importantly when running chrome pipe, a Speedmaster tong should be used. This is controlled by the Salvo and will rotate the joint at a 'fast' speed (around 10 RPM) then automatically change to its 'slow' speed (around 2 RPM) when the make-up reaches a reference torque. The tong will continue to rotate at its 'slow' speed until final make-up torque is reached, at this point, a rapid response dump valve cuts off hydraulic power to the tong. Furthermore, the use of non-marking dies (e.g. aluminium or grit faced) in the BJ Chromemaster tong will prevent any tong die damage to the tubulars being run.
Thread Protectors and Cleaning
Inspection While protectors are off, tubulars should be looked through to check for presence of any debris, or metal slivers. If a compressed air line is available, blowing out each joint prior to cleaning threads is a good practice. All joints should be blown from the box end. Before cleaning threads, pipe should be drifted while on the rack. Lengths of rods or a cable attached to the drift mandrel facilitates snaking the drift through each joint on a layer of racked pipe. This is a much safer practice than dropping the drift mandrel down the pipe to the rig floor or pipe rack. (Tubulars should be drifted from the box end) On coated pipe, only a mandrel of suitably non-damaging material should be used. Any field-repaired threads should be carefully cleaned before running to remove all metal shavings and filings. Once the pipe is drifted and threads inspected on the rack, the threads should be lubricated with a thread compound or preferably, anti-rusting storage compound and finally clean thread protectors should be fitted.
9.9
Running Procedures
9.9.1 Pipe Handling Pipe should not be moved without protectors on both ends, when moving pipe from rack to Vee door, both the pin thread protector and either a box protector or lift nubbin should be snugly in place. Tubulars should never be lifted with hooks, and where possible either a pick up machine or crane should be employed to lift pipe to the VEE door.
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With pin protector and lift plug (if required) installed, the joint is lifted to the vertical position. Since it is essential that the pipe is held in vertical alignment for stabbing and make-up, a stabber, side door elevator or slip type elevators should be used to help maintain vertical alignment. Single joint elevator pick up lines hung from a single joint compensating system should hang in line with the rotary table and be steadied by the stabber. Note: (NEVER run a joint into the wellbore with a closed box end protector in place pressure will be created inside the tubular which may expel the protector)
9.9.3 Stabbing and Make-Up Where possible use a stabbing guide and a stabber on the stabbing board. The driller should lower the joint to be stabbed slowly. If the joint is not stabbed cleanly first time, the stabber should not rock the pipe to forcibly uncross the threads. It is not difficult to see that damage can be easily caused to the start threads by what is effectively a 40-ft long lever. The correct procedure is to back the connection slowly until proper thread engagement results. If any force has been used to try to correct a mis-stab, the joint should be lifted and threads cleaned and checked for damage. More time is lost in the long run by trying to rush this procedure in an attempt to gain time.
9.9.2 Applying Thread Compound With the joint lifted clear of the rig floor, the pin protector can be removed (but never when the joint is directly over the rotary) and threads, including the box of the joint in the slips, given a final clean and visual check before application of thread compound. The thread manufacturers recommendation on type of thread compound to be used should be closely followed to ensure correct make-up, and any friction co-efficient correction factors applied, again as per the manufacturer's recommendation. Thread compound should be clean and uncontaminated. Never under any circumstances should thread compounds be thinned with diesel or adulterated in any way. New buckets should be thoroughly stirred before use and where possible, warmed to ease application to the threads. This can be achieved by powered systems which utilises hydraulic power on route to the tong to stir and warm the dope. Care should be taken to apply the compound correctly, manufacturers recommendations on whether to dope pin and /or box should be followed. In general, application of dope is most often on the pin end as this has historically been easier, but in connections with seal rings it is necessary to apply dope to the box especially below the seal ring as the seal ring tends to wipe the pin nose during make-up. Sufficient dope should be applied to cover all threads and seal areas while retaining a visible thread profile. This is crucial for future thread life. Excessive amounts of dope should not be applied as this can cause problems for downhole tools and wireline work or indeed the well formation if excess dope squeezes into the ID on the make-up. Equally, under certain circumstances excess thread compound may damage a connection due to hydraulic pressure. A dope applicator can be used to apply a measured amount of clean, warm, fully mixed dope to the inside of the coupling thus eliminating any problems with too much or too little dope being applied.
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After stabbing, if size and weight of pipe allow, initial make-up should be by hand. This is particularly important for chrome steels and other damage sensitive grades. If larger, heavier wall pipe is used and start make-up is by power tong, a close watch on the torque gauge should be kept. An immediate torque rise with little pipe rotation indicates a cross thread and immediate action should be taken including, if necessary, breaking out the connection and inspecting the threads for damage. During the initial phase of running a tubular string, unless an integral back-up tong is being used, the use of a rig back up will be required until sufficient joints (usually 30-50) have been run. This will be required until sufficient string weight has been developed to keep the joint from turning in the slips within the rotary table. It is essential to ensure that the back-up tongs are wide enough not to damage the pipe body and that they are never set over the box threads. Setting back-ups on the box threads (integral or coupled connections) will compress the box during make-up and irreversibly damage the connection. With the advent of FMS, (Flush Mounted Slips) the need for rig tongs at the beginning of a job has all but been eliminated. An FMS is a positively powered tool and can hold against tubular rotation anything up to 30,000ft/ lbs. Most operators now accept the value of a speed controlled tong and a torque monitoring system and indeed most premium connection manufacturers recommend their use. As well as determining that a make-up is good or bad the system provides a permanent record of each connection for future reference, studies and evaluation. Typically each joint make-up is recorded on a computer disk or N.V.R.A.M. The operator in the field can recall any joint to analyse its’ torque curve to the visual display at any time. On return to base all the data can be transferred from the disc or RAM to a database and if requested, a "hard copy" made of all the make-ups from the whole string for the customers own records.
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9.10 Pulling Procedures
9.11 Common Causes of Thread Damage
9.10.1 Equipment All equipment used to run the tubulars will also be required to pull the string. In addition, where applicable the following should also be available: a)
A wooden mat to be used if pipe is to be stacked in the derrick.
b)
Full body contact, back-up tongs should be used rather than pipe wrenches to prevent crushing or cutting of the pipe body.
c)
Clean thread protectors of the proper size and thread should be available on the rig floor.
d)
Clean rags and suitable solvent to clean any threads needing inspection.
a)
Insufficient, incorrect or contaminated thread compounds. In premium connections, the sealing properties of thread dope are largely a secondary function. The principal purpose of thread compound is to prevent galling, lubricate and ensure long life of the threads.
b)
Misalignment of upper and lower joints during stabbing, make-up or break out.
c)
Excessive make-up speeds.
d)
Continued rotation of pipe after threads have disengaged while pulling pipe.
e)
Setting back-up tongs over box threads.
f)
Improper handling of pipe during storage and shipping.
g)
Use of accessories of non-proprietary origin - i.e. "bootleg" connections.
h)
Using incorrect torque values (human error).
i)
Lack of proper care while running or pulling pipe.
j)
Dirty threads and/or contamination by foreign bodies, e.g. sand, shotblasting material, which can apply equally to thread compound.
k)
Not using a correctly fitting stabbing guide.
9.10.2 Break Out and Lifting a)
b)
Raise the string so that the connection to be broken out is at comfortable working height above slips, and that excessive bending will not be induced at breakout. Alignment of upper and lower joints at break out is vital. Wherever possible, use of a stabber on stabbing board or other alignment guide is recommended. If there are any doubts about alignment due to high wind, or any other reason, threads should be checked for damage immediately on breakout and appropriate action taken.
c)
Break out should be carefully controlled, if necessary using Speedmaster and Salvo in Breakout mode. Connections should run freely within about one turn of breakout (this will depend exactly on individual designs) so prolonged residual torque will indicate misalignment and probable damage. If this occurs, stop and check alignment or check for bent joint. Never apply excessive torque.
d)
Never use a hammer or other hard objects to beat on a connection. The resulting damage could cause a failure.
e)
Stop turning immediately the pin jumps inside the box or beforehand by using break out turns. Tension, using the blocks should not normally be applied during breaking out. With heavy weight casing joints or when pulling stands or chrome tubulars, it is permissible to apply light elevator tension using a single joint compensator (Loadmaster) to minimise compressive and tensile thread loading, and virtually eliminating any instance of thread damage.
f)
Inspect, if necessary, and then install a clean, dry pin end thread protector before pipe is lowered to the floor.
g)
Mark clearly any damaged connections. If pipe is to be laid down, the joint should be carefully lowered to the Vee door, then a clean box protector installed.
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10.2 Pre-Job Checks
RECOMMENDED PROCEDURES FOR RUNNING CHROME TUBULARS
A wooden (or non-metallic) lining should be installed on the catwalk and the Vee Door. If this is not possible, tubulars will have to be lifted directly into the Vee Door by the crane.
10.1 Transportation and Preparation Tubulars should be boxed for transportation and carefully handled at all times. The pipe-deck supports and restraining posts should be lined with wood, or a similar nonmetallic material. Care should be taken at all stages to prevent tubulars having any impact with metal objects.
In order to ensure all handling tools and tong jaw dies conform to the exacting requirements of chrome tubing it is recommended that a single source take responsibility to supply the complete package.
On arrival at the rig site, tubulars should be carefully unloaded onto the pipe-deck.
Check all handling and make-up equipment is on. All tong jaws and handling tool dies shall be checked by the Tong Service Supervisor to ensure they are the specified type for running chrome tubulars i.e.,
Tubulars should be removed individually from transportation racks using polymer slings. Steel slings should not be used as these may damage or impregnate the tubular.
(a)
Layout one layer of tubulars on the wooden lined pipe-deck and (as close to the time the job is to be run as possible): • • • • • • • •
Prevent collision of joints with each other. Remove transportation protectors. Drift each joint (using a non-metallic drift entered from the coupling end). Measure and tally each joint. Thoroughly steam clean and dry both coupling and pin ends (the use of solvents, diesel fuel etc are not recommended, as these can affect subsequent application of thread compound) Conduct deck inspection as per manufacturers recommendations. Do not apply light coating of storage compound. Ensure thread protectors are cleaned thoroughly before re-applying to tubing.
Layout subsequent layers of tubing ensuring at least three wooden supports are between each layer and repeat step 5 until all joints have been laid out. Inspect all sub-assemblies, crossovers, pup joints, etc. are available and in the same condition as the other tubulars.
(b)
Tongs - Smooth faced wrap around type or grit faced, should high torque be required. Handling Tools - Varco flat topped (0.01") or grit faced dies.
All handling tools should be function tested on the tubulars to ensure correct fit and operation. Tong Service Supervisor should agree with the Company Representative the parameters to be used i.e., torque figures, dope correction factors and make-up speeds. For high chrome tubulars make-up speeds should be no more than 8 rpm (high speed) and 1.5 rpm (low speed). All running equipment (power units, power tongs, torque-turn recorders, handling tools, etc.) should be rigged up, calibrated to job parameters and fully function tested. Thorough discussion should take place between the Well Services Supervisor, drill crew and Tong personnel prior to the job regarding the rig floor layout, equipment safety and the exact handling and make-up procedures to be used. 10.3 Running and Make-up As with any job a Tool Box Talk should be held on the drill floor immediately prior to the job starting to identify hazards, familiarise crews with procedures and equipment, and reinforce the message that safety is paramount. Note: (a) Care should be taken at all stages to prevent impact of tubulars against any metal objects. (b) Non-metallic polymer slings should be used for lifting all single joints of tubing. (c) All handling tool dies should be kept clean and changed whenever necessary.
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The tubular can be picked up in one of the following ways (dependant upon rig design): (a)
Pick up individual joint using polymer slings and carefully lay onto the wood lined catwalk. Latch single joint elevator (attached to rig floor tugger) onto the joint and transfer along wooden surfaces of catwalk and Vee Door to rig floor.
(b)
Pick up with crane, using two polymer slings, and transfer joint through Vee Door to drillfloor. Carefully lay tubular pin against stop on catwalk and remove slings. Attach single joint elevator onto the joint below coupling.
A clear signal should be given to the technician on the stabbing board that the pin and box ends have been engaged correctly and to align the joint for efficient make-up. Once stabbed, one man should walk the joint in the first 4-5 turns with a strap wrench ensuring no great force is applied to the connection. Note:
(c)
Pick up with pick-up / lay-down machine and transfer joint through Vee Door to drillfloor. Attach single joint elevator onto the joint below coupling.
(d)
Pick up with crane, using two polymer slings and lift through the Vee Door to drillfloor. Carefully latch single joint elevator onto the joint and slacken off weight on sling closest to coupling. The joint can then be tailed-in with remaining sling attached to crane while joint is lifted to vertical by driller.
Note: It is assumed at this point a downhole packer, tailpipe or sub-assembly has been placed in the rotary table ready for the first joint of tubing. The procedure for sub- assemblies is exactly the same as above, extreme care should be exercised. With joint in Vee Door, remove box end protector and visually inspect the thread and seals in accordance with the manufacturers instructions. At this point apply an even coating of mixed heated thread compound to the box area using the dope applicator. The dope should form an even coating with the thread form still clearly visible through the coating.
Before the connection has reached the hand tight position, remove the strap wrench and carefully place the power tong on the pipe. Great care should be taken to ensure that the tong is positioned centrally on the tubing without any part of the tong or back up heavily impacting the tubing wall. The back-up tong should be activated to grip the tubing, care being taken to ensure that the jaws are correctly positioned and are gripping the tubing evenly. The power tong can now be activated to grip the tubing and the make-up initiated using the Speedmaster control on the tong. The Salvo will monitor the make-up as it takes place and the final graph profile either accepted or rejected by the Salvo operator, if accepted the single joint elevator should be removed and operations continued. If the make-up is aborted for any reason or if the connection requires to be broken out and inspected, the following procedure should be taken:
The travelling blocks should be carefully raised allowing the single joint elevator attached to the Loadmaster to raise the joint to the vertical position with the pin end restrained away from the rotary centre line. The Loadmaster ram should be stroked fully in.
(a) (b) (c) (d)
With the tubular suspended in the single joint elevator, ensure pin end is held a safe working distance from the rotary table, remove protector and inspect threads and seals in accordance with manufacturers instructions to ensure no damage has occurred prior to make-up.
(e) (f)
Using a clean, soft, 2" paintbrush apply a thin, even coating of mixed and heated thread compound, from the Dopemaster to the pin seal and the first third of thread area. The Dope should form an even coating with the threadform still clearly visible through the coating, ensure the seal area is evenly coated.
(g) (h) (i)
A stabbing guide should be fitted to the box end of the joint in the rotary table and the joint of tubing hanging in the single joint elevator carefully moved into position with the pin end held over the stabbing guide.
Be aware of mis-alignment. Do not apply unnecessary force on strap wrench, back out and inspect if this occurs.
(j)
Confirm single joint is in position. Set Loadmaster to pulling position. Change back up Jaws to fit coupling. Slowly rotate the tong in the break out direction with the back up Jaws gripping on the bottom half of the coupling until the torque has dropped below the reference torque. (Normally one to two complete rotations). Re-fit the strap wrench. Slowly walk out the connection with the assistance of the technician on the stabbing board aligning the joint correctly. Do not apply any force to pull the pin from the box. The Loadmaster will slowly raise the joint once the threads have fully disengaged. Thoroughly steam clean both the pin and box prior to inspection, ensuring the pin end is held a safe working distance away from the rotary table. If no problems are found with either the threads or the seals continue with the drying, doping and re-running of the connection as previously described. If the joint has to be laid out apply storage compound, transportation protectors and carefully lift back to the pipe deck area. The drill crews should clearly identify the rejected joint by marking with red paint "reject" and place to one side.
This joint should be slowly lowered by stroking out the Loadmaster ram until pin and box are engaged.
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Connection Technology
After a satisfactory Torque Turn Graph has been recorded and accepted and the tally number logged on the Salvo, slowly lower the main elevator and carefully position it over the tubing string. The elevator can now be latched.
CHECKLIST FOR RUNNING CHROME TUBULARS Do's
Raise the string a short distance to enable the hand slips to be removed. (During the running of the initial 20-30 joints a safety clamp will be required, if fitted, this should be removed).
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Handle with care
Slowly lower the string until the box end is in the correct position for the next connection to be made up. Do not set the slips while the string of tubing is still moving.
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Move with thread protectors in place
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Move and store in boxes whenever possible
Place the hand slips in position and slowly lower the string until the slips take the full weight of the string. Fit the safety clamp if applicable.
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Clean and inspect thoroughly
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Use slip type elevators
Carefully remove or unlatch the elevator, if a door type elevator is being used care should be taken to ensure that the elevator does not impact the tubing/coupling wall.
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Dope pins and boxes, with special attention to coating of all thread and seal areas.
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Use stabbing guide
Repeat the above procedure until the final number of joints has been run.
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Use man on stabbing boards
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Stab/make-up vertically
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Make-up by hand where possible
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Use power tongs with calibrated torque gauge and dump valve
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Make-up in low gear. Not to exceed 5-10 rpm's or lower where recommended (use a speed control tong)
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Use power tongs complete with integral back-up Make-up accessory equipment, power tongs and torque gauge should be suitable type and in good condition
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Check condition of dies and inserts
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Check slips, elevators, master bushing for excessive wear
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Use recommended thread compound (new unopened tin).
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Follow manufacturer's running and pulling procedures
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Keep pipe vertical
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Apply torque slowly via a speed control tong
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Install protectors immediately
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Stand back on wooden mat, or
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Lay down carefully on pipe rack
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CHECKLIST FOR RUNNING CHROME TUBULARS (Continued) Don'ts -
Bang pipe on racks, Vee door or each other
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Move with thread protectors off
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Drag pipe up catwalk to Vee door
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Drop rabbit from rig floor
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Clean threads with diesel fuel or gasoline
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Remove stuck thread protectors by hitting protector with any object
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Put dirty protectors back on clean pipe
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Use spinning chains or rig tongs at any time
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Stab until pipe is vertically aligned
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Stop a moving string with slips
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Set slips on upset area of coupling
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Clean threads with a wire brush
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Thin thread compound with any agent
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Use pipe wrench
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Run joint suspected of damage
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Rotate string to stab into packer
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Hammer slips in place
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