CONNECTION
TECHNOLOGY
NOTES
1 REVIEW OF CASING AND TUBING ... 5
1.1 INTRODUCTION... 5
1.2 DEFINITIONS... 5
1.3 APPLICATIONS... 6
1.4 OCTG MARKET... 7
2 OCTG - THE FINISHED PRODUCT ... 8
2.1 SIZE... 9
2.2 WEIGHT... 9
2.3 GRADE... 9
2.4 CONNECTION TYPE... 9
2.5 RANGE... 9
2.6 GRADES OF STEEL FOR CASING AND TUBING... 10
2.7 SELECTION OF GRADES... 11
2.8 PROPRIETARY GRADES... 12
3 CONNECTIONS AND SEALING METHODS ... 13
3.1 CONNECTION DEVELOPMENT HISTORY... 14
3.2 TUBULAR END FORMS... 14
3.3 CONNECTION FORMS... 15
3.4 CONNECTION CRITERIA... 15
3.5 THREAD TERMINOLOGY... 16
3.6 PREMIUM CONNECTION DEVELOPMENT... 19
3.7 SEALING METHODS... 20 4 THREAD COMPOUNDS... 23 4.1 INTRODUCTION... 23 4.2 COMPOSITION... 23 4.3 SEALING... 24 4.4 CO-EFFICIENT OF FRICTION... 24 4.5 DEFORMATION... 26 4.6 WORK HARDENING... 26 4.7 PRACTICAL USE... 26
5 COMMON PIPE PROBLEMS... 28
5.1 POOR SURFACE FINISH... 28
5.2 DEFORMATION OF CONNECTION ON MAKE-UP... 29
6 CHROME TUBULARS ... 30
6.1 THE PROBLEM - CORROSION... 30
6.2 THE SOLUTION - 13% OR 23% CHROME STEEL... 30
6.3 CORROSION RESISTANT ALLOY (CRA) GRADES... 31
6.4 THREAD SELECTION FOR CHROME STEELS... 31
6.5 SURFACE TREATMENT OF CHROME THREADS... 32
6.6 THREAD COMPOUNDS AND TORQUE VALUES... 32
6.7 EFFECT OF CONNECTION SIZE, WEIGHT, AND TONG SPEED ON MAKE-UP... 33
6.8 PLASTIC COATINGS... 33
7 TORQUE-TURN AND GRAPHICAL ANALYSIS THEORY... 34
7.1 EQUIPMENT AND TECHNIQUES... 34
8 COMMON EQUIPMENT PROBLEMS ... 46
8.1 INTERPRETATION PROBLEMS... 46
8.2 PROPER DATA INPUT... 47
9 RECOMMENDED PROCEDURES FOR RUNNING NON-CHROME TUBULARS ... 48
9.1 OVERVIEW... 48
9.2 ACCESSORY EQUIPMENT... 48
9.3 LIFT NUBBINS OR ELEVATOR PLUGS... 48
9.4 STABBING GUIDES... 48
9.7 THREAD PROTECTORS AND CLEANING... 50
9.8 INSPECTION... 50
9.9 RUNNING PROCEDURES... 50
9.10 PULLING PROCEDURES... 53
9.11 COMMON CAUSES OF THREAD DAMAGE... 54
10 RECOMMENDED PROCEDURES FOR RUNNING CHROME TUBULARS... 55
10.1 TRANSPORTATION AND PREPARATION... 55
10.2 PRE-JOB CHECKS... 56
1 REVIEW OF CASING AND TUBING 1.1 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.
1.3 Applications 1.3.1 Casing
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
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. Figure 1
1.4 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 USE
K-55 0.66 Low stress
N-80 1.00 General
L-80 1.18 Sour service
C-95 1.16 Higher strength
P-110 1.21 High strength/deep V-150 1.51 Very high strength 13% chrome 3.00 CO2 and chlorine 23% chrome 10.00 H2S, CO2 chlorine
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 = £75,000 NKK chrome tubing cost = £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.
2 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 1.901" 5½" 20.00 4.653" 95/8" Cont. 47.00 8.525" 5.10 1.845" 23.00 4.545" 53.50 8.379" 5.80 1.773" 26.80 4.375" 53.50 *8.500" 27/ 8" 6.40 2.347" 65/8" 20.00 5.924" 58.40 8.279" 7.70 2.229" 23.20 5.840" 59.40 8.251" 8.60 2.165" 24.00 5.796" 61.10 8.219" 9.80 2.057" 28.00 5.666" 97/ 8" 67.50 *8.500" 3½" 7.70 2.943" 32.00 5.550" 103/ 4" 40.50 9.894" 9.20 2.867" 35.00 5.450" 45.50 9.794" 10.20 2.797" 7" 23.00 6.241" 45.50 *9.875" 12.70 2.625" 26.00 6.151" 51.00 9.694" 13.70 2.548" 29.00 6.059" 55.50 9.604" 14.70 2.476" 32.00 5.969" 55.50 *9.625" 15.80 2.423" 35.00 5.879" 60.70 9.504" 4" 9.50 3.423" 38.00 5.795" 65.70 9.404" 10.90 3.351" 38.00 *5.879" 73.20 *9.330" 13.00 3.215" 41.00 5.695" 101.00 *8.750" 14.80 3.115" 41.00 *5.750" 113/ 4" 47.00 10.844" 16.50 3.015" 44.00 5.595" 54.00 10.724" 4½" 10.50 3.927" 46.00 5.535" 60.00 10.616" 11.60 3.875" 75/ 8" 26.40 6.844" 65.00 10.526" 12.60 3.833" 29.70 6.750" 71.00 10.430" 13.50 3.795" 33.70 6.640" 71.00 *10.500" 13.50 *3.833 35.80 6.568" 133/ 8" 54.50 12.459" 15.10 3.701" 39.00 6.500" 61.00 12.359" 16.90 3.615" 42.80 6.376" 68.00 12.259" 18.80 3.515" 45.30 6.310" 72.00 12.191" 21.60 3.375" 47.10 6.250" 72.00 *12.250" 24.60 3.255" 51.20 6.126" 77.00 12.119" 26.50 3.115" 85/ 8" 28.00 7.892" 80.70 12.059" 5" 13.00 4.369" 32.00 7.796" 85.00 12.003" 15.00 4.283" 36.00 7.700" 14" 112.00 *12.259" 18.00 4.151" 40.00 7.600" 16" 65.00 15.062" 20.30 4.059" 44.00 7.500" 75.00 14.936" 20.80 4.031" 49.00 7.386" 84.00 14.822" 21.40 4.000" 52.00 7.310" 109.00 14.500" 23.20 3.919" 95/ 8" 36.00 8.765" 17" WT .438" 16.000" 24.10 3.875" 40.00 8.679" 185/8" 87.50 17.567" 5½" 15.50 4.825" 40.00 *8.750" 20" 133.00 18.542" 17.00 4.767" 43.50 8.599" WT .625" 18.562"
Note: * Denotes “Special Drift”. Drift length should be 42" (can be 12" for casing sizes (normally 7” OD and larger)
2.1 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. 2.2 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. 2.3 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).
2.4 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). 2.5 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 LENGTH (ft)
1 16-25 2 25-34 3 over 34
Figure 2
2.6 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
TYPICAL
HEAT HARDNESS
GRADE YIELD STRENGTH (KSI) TREATMENT (ROCKWELL)
Minimum Maximum J-55 (Tubing) 55 80 - - K-55 (Casing) 55 80 - - C-75 75 90 N&T, Q&T 14-26 L-80 80 95 Q&T 23 max N-80 80 110 N, N&T, Q&T 16-25 C-95 95 110 Q&T 18-25 P-105 (Tubing) 105 135 Q&T 25-32 P-110 (Casing) 110 140 Q&T 27-35
* NOTE - Heat treatments as follows:
N = Normalised
N&T = Normalised and Tempered Q&T = Quenched and Tempered
2.7 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.
2.8 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 C-95. 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
SR-95 95 ksi min Q&T
Superior to API 5AC Suitable for sour service.
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
Extra toughness (XT) range of high strength casing grades suitable for
low temperature applications.
3 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 liners
tubing casing and tubing pup-joints work tubing 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
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
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.
3.1 Connection Development History
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
3.2 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.
3.3 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.
3.4 Connection Criteria
The criteria for any connection design can be simplified as:
a) Load bearing capability
This requires sufficient turns to be put into the connection.
b) Pressure sealing capability
This requires sufficient torque to be put into the connection.
c) Field suitability
The design engineer chooses this.
CONNECTION FORMS Figure 4 P A P IT CH LIN E P IP E A X IS 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 R O U N D T H R E A D F O R M PIP E AX IS B UT TR E SS TH R EA D F O RM CR E ST RO O T 10o ST AB FL AN K L O A D F LA NK PITC H L INE P 3o Figure 5 Figure 7 Figure 6 3.5 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)
P IP E A X IS E X T R E M E L IN E T H R E A D F O R M 6o R O O T C R E S T S T A B F L A N K L O A D F L A N K 6o
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:
change in diameter Taper = --- change in length
b) Pitch The distance from a point on a thread to a corresponding point on the next thread measured parallel to the axis.
c) Lead The distance a screw thread advances axially in one turn.
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.
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.
To overcome some of the limitation in API threaded connections, several other thread forms have been developed, including:
• Modified Buttress (see Fig 8) • Negative Flank (Hooked) (see Fig 9) • Dovetail (Wedge Thread) (see Fig 10 Each can be found in different designs.
Other connection designs have included combinations of thread features such as:
• Multi-tapered thread form • Non-tapered (straight) • Two-step thread form
PIPE AXIS
MODIFIED BUTTRESS THREAD FORM
PITCH LINE 30 o
90 o
PIPE AXIS
NEGATIVE FLANK THREAD FORM
PITCH LINE
30o
10o
(HOOK THREAD)
PIPE AXIS
WEDGE THREAD FORM
PITCH LINE
Figure 8
Figure 9
3.6 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.
3.7 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 the seals are then subjected to the combined loading of downhole conditions plus the pressures and corrosion of wellbore fluids.
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 non-metallic 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.
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.
COMMON SEALING METHODS
THREAD DOPE SEALS
PIN
BOX
METAL TO METAL SEALS
THREAD DOPE SEALS A.P.I. BUTTRESS THREAD
PIN BOX
A.P.I. ROUND THREAD
METAL TO METAL SEALS
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:
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 Classed in three main categories: a) Primary internal seals b) Primary external seals c) Shoulder seals
These are all illustrated in Figs 13 & 14.
SEALING METHODS – PREM IUM CONNECTIONS METAL TO M ETAL SEALS
PRIM ARY INTERNAL SEALS PR IM ARY EXTERNAL SEALS
PIN BOX EXTERNAL SEAL PIN BOX FLANK SEAL BOX PIN FLANK SEAL 140 EXTERNAL SEAL PIN BOX ANGLED FLANK SEAL BOX PIN SEALING METHODS PLASTIC SEAL RING
BOX PIN
Figure 12
Figure 13
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.
Many connection types contain more than one seal and most have a combination sealing method.
3.7.3 Galling
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.
The galling tendency increases markedly with the use of speciality materials with high percentages of nickel and chrome.
SHOULDER SEALS
4 THREAD COMPOUNDS 4.1 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.
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:
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.
4.2 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) Powdered graphite (28%) b) Lead powder (47.5%) c) Zinc dust (19.3%) d) 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.
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.
4.3 Sealing
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.
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 co-efficient, and zinc, copper silicates, zinc-oxide and non-lubricating oils increase the friction co-efficient.
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.
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.
EFFECT OF THREAD COMPOUNDON CONNECTION
MAKE-UP TORQUE
THREAD COMPOUNDS EMPLOYED
AVERAG E CONNECT IO N M AKE-U P T O RQUE ( F T / L B S ) 0 250 500 750 1,000 1,250 1,500 1,750
Average torque of 5 connections for each type of Thread Compound, all made up to the same position.
A B C D E F G
Figure 15
EFFECT OF MAKE-UP TORQUE ON ANGULAR ROTATION
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
A B Ma k e -up t o rque ps i 0 5,000 10,000 15,000 20,000 25,000 Figure 16 4.5 Deformation
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.
MATERIAL YIELD STRENGTH PSI Copper 10,000 Zinc 3,000 Lead 600 Graphite 200 Teflon 200 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.
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 non-shouldered 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.
4.7 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).
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 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.
5 COMMON PIPE PROBLEMS
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.
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.
5.2 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.
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.
6 CHROME TUBULARS
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.
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 High Chrome
- carbon steel - alloy steel
- controlled hardness - controlled hardness - H2S resistant - CO2 resistant
- resistant to cold working - susceptible to cold working - relatively resistant to handling - susceptible to handling
- damage - damage
- threads are phosphate coated - threads cannot be coated - parkerised surface - and require special treatment
(such as peening and oxalation) - Relatively resistant to galling of threads - susceptible to galling of threads
6.10.1 Advantages and disadvantages
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.
6.13 Surface treatment of Chrome threads
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.
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 Increasing Tendency Large OD Light Wall ---> Heavy Wall Carbon Steel Grade Steel To Galling 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.
6.16 Plastic Coatings
Another way to lessen the effects of sweet corrosion is to plastic coat the I.D of the tubular.
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.
7 TORQUE-TURN AND GRAPHICAL ANALYSIS THEORY
7.1 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 made-up 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.
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.
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.
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 micro-switch 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 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.
Figure 17
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).
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
Figure 18
(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).
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.
Figure 20
Figure 21
Typical “Tapered Connection” Profile
Torque applied to Shoulder
Shoulder Engagement
SHOULDER INDICATING TORQUE / TURN GRAPH
Turns
To
rq
ue
No Shoulder Detected
SHOULDER INDICATING TORQUE / TURN GRAPH
Turns To rq ue Figure 22 Figure 23 Shoulder Below LSP LSP
SHOULDER INDICATING TORQUE / TURN GRAPH
Turns
To
rq
ue
Over Torque
SHOULDER INDICATING TORQUE / TURN GRAPH
Turns
To
rq
Figure 25 Figure 24
Over Turns
SHOULDER INDICATING TORQUE / TURN GRAPH
Turns
To
rq
ue
Insufficient Detail
SHOULDER INDICATING TORQUE / TURN GRAPH
Turns To rq ue Figure 27 Figure 26 Shoulder above MSP
SHOULDER INDICATING TORQUE / TURN GRAPH
Turns
To
rq
ue
Poor Profile
SHOULDER INDICATING TORQUE / TURN GRAPH
Turns
To
rq
Figure 28
Figure 29
Poor Profile
SHOULDER INDICATING TORQUE / TURN GRAPH
Turns
To
rq
ue
Dip Prior to Shoulder
SHOULDER INDICATING TORQUE / TURN GRAPH
Turns To rq ue Figure 30 Figure 31 Pre Turns Ref
Zero
New display
Pre-Ref Turns Ref-Max Turns
SHOULDER INDICATING TORQUE / TURN GRAPH
To rq ue
Re-Scaled
Make-up
graph
Pre Turns Ref ZeroPre-Ref Turns Ref-Max Turns
SHOULDER INDICATING TORQUE / TURN GRAPH
To
rq
