sarta de perforación connects the perforación rig at the surface to the broca de perforación at the bottom of the pozo. It is not a simple tubería, but a complete assembly made from connected sections of tubería de perforación and the heavier, more specialized tools installed near the bit.
During perforación, the sarta de perforación turns or guides the bit, carries perforación fluid down to the bottom of the hole, and allows the rig to lower or retrieve downhole tools. tubería de perforación makes up most of its length, while heavy-peso tubería de perforación, portabrocass, stabilizers, subs, directional tools, and the broca de perforación form the lower working section.
The exact structure is dIFferent for every perforación program. A simple vertical pozo may use a relatively basic assembly, while a deep directional or horizontal pozo may require a mud motor, measurement tools, rotary steering equipment, jars, and several types of transition components.
qué es a sarta de perforación in Rotary perforación?
A sarta de perforación is the assembled column of tubería de perforación and downhole tools usado to perforar a pozo. It creates a continuous mechanical and hydraulic unión entre the surface perforación equipment and the bit.
The upper part normally consists priNCipally of tubería de perforación. The lower, mechanically stIFfer part is called the bottom-hole assembly, or BHA. Depending on the perforación program, the BHA may contain portabrocass, stabilizers, heavy-peso tubería de perforación, jars, crossovers, a mud motor, MWD/LWD tools, a rotary steerable system, and the bit.
The top drive supplies rotation and supports the suspended string, but it repriNCipals surface equipment. In a conventional rotary-table system, the kelly transfers rotation from the rotary table. A kelly may appear in broader descriptions of the tallo de perforación, but it should not be confusado with the downhole tubular and BHA components evaluated during sarta de perforación design.
This boundary matters when engineers calculate tensile load, torsional capacity, hydraulic pressure loss, fatiga exposure, or inspection requirements. These calculations must follow the actual load path from the uppermost tubular unión to the bit.
sarta de perforación Components
sarta de perforación components can be divided into three fuNCtional zones:
- The tubería de perforación section that provides most of the string length
- The transition section that manages the change in peso and stIFfness
- The BHA that applies peso, controls the bit, and carries downhole tools
| Component | Typical position | Primary fuNCtion | priNCipal parametros to verIFy |
|---|---|---|---|
| Drill pipe | Upper and middle string | Carries tensile load, transmits par, and circulates perforación fluid | OD, espesor de pared, grado, upset, length, tool-joint OD/ID, and unión |
| unións | Welded to both ends of each tubería de perforación joint | Connect individual joints and transfer par and axial load | rosca form, shoulder condition, OD, ID, and make-up par |
| Heavy-peso tubería de perforación | entre regular tubería de perforación and the lower BHA, or within the BHA | Reduces the stIFfness transition and adds coNCentrated peso | Body wall, center upset, desgaste pads, unión, and fatiga condition |
| portabrocass | Lower BHA | Supply peso on bit and iNCrease stIFfness | OD, ID, length, material, unión, and bending stIFfness |
| Stabilizers | seleccionared positions in the BHA | Centralize the BHA and influeNCe directional behavior | Blade OD, undergauge, placement, and contact area |
| Crossover subs | entre components with dIFferent unións | Adapt dIFferent unión sizes or rosca forms | pasador/caja combination, shoulder, bore, and tensile capacity |
| perforación jars | Normally within or above the BHA | Deliver an iMPact load to help release a stuck string | Firing load, stroke, tensile rating, and placement |
| Mud motor | Near the bit | Converts hydraulic energy into downhole rotation | Flow range, pressure drop, par, speed, bend setting, and temperature rating |
| MWD/LWD tools | Within the BHA | Measure trajectory, perforación conditions, and formation properties | OD, flow range, pressure rating, temperature rating, and telemetry system |
| Float valve or float sub | Commonly in the lower string | Restricts reverse flow through the sarta de perforación | Flow area, pressure rating, and valve configuration |
| broca de perforación | Bottom of the string | Cuts or fractures the formation | Diametro, cutter structure, nozzle area, WOB, par, and speed limits |
The BHA does not follow one universal parts list. Its lower section may iNClude the bit, bit sub, mud motor, stabilizers, portabrocass, heavy-peso tubería de perforación, jars, and crossovers. Directional and measurement equipment may also be installed.
tubería de perforación
tubería de perforación usually occupies most of the measured length of a conventional sarta de perforación. Finished tubería de perforación consists of a tubería de perforación body with weld-on unións. Its priNCipal structural features iNClude:
- A seamless steel tubería body
- Internally upset, externally upset, or internally and externally upset ends
- pasador and caja unións
- Rotary-shouldered roscaed unións
- Friction-welded tool-joint-to-tubería transitions
- Optional internal coating and external hardbanding
API Spec 5DP establishes technical requirements for steel drill pipe, including dimensions, grades, mechanical properties, weld areas, inspection, marking, and traceability.
Common API tubería de perforación diámetro externos extend from 2 3/8 to 6 5/8 pulgadaes. Range 2 joints are normally 27–30 ft long, while Range 3 joints are 38–45 ft long. The purchase specIFication should identIFy the required range because joint length affects rig handling, transportation, the number of unións, and the total assembled string configuration. The supplier should confirm the finished length, iNCluding unións, rather than stating only an approximate tubería-body length.
Heavy-peso tubería de perforación
Heavy-peso tubería de perforación, commonly abbreviated as HWDP, creates a more gradual stIFfness transition entre regular tubería de perforación and the much stIFfer portabrocass. It normally uses a thick-walled tube with enlarged unións and a center upset.
HWDP may be installed directly above the portabrocass or positioned higher in a directional string. Its size and quantity should follow the approved BHA and sarta de perforación design because the required peso, stIFfness transition, and fatiga exposure vary with the pozo profile. Purchasing HWDP only by nominal OD can result in an iNCoMPatible unión, insufficient unit peso, or an unsuitable transition entre regular tubería de perforación and portabrocass.
API Spec 7-1 covers standard HWDP dimensions and manufacturing requirements. Standard API HWDP is commonly supplied at a nominal length of approximately 31 ft, subject to the applicable toleraNCe. The purchase specIFication should also identIFy the body configuration, tool-joint OD and ID, center-upset dimensions, unión type, hardbanding, and whether spiral desgaste pads are required.
portabrocass
Drill collars concentrate mass near the bit and increase BHA stiffness. Conventional steel drill collars are commonly machined from solid alloy-steel bars to produce a thick wall and relatively small internal bore.
Their peso supplies part of the force available for peso on bit. In a vertical pozo, engineers normally seek to keep the regular tubería de perforación above the BHA in tension while placing the required compression in the lower, stIFfer assembly.
Nonmagnetic portabrocass are usado around directional survey instruments because ordinary alloy steel can interfere with magnetic measurements. A portabrocas purchase specIFication should state the OD, ID, finished length, material type, unión, spiral or slick configuration, and required fishing clearaNCe. Nominal OD alone is not sufficient to confirm coMPatibility with the bit, stabilizers, directional tools, or the repriNCipaling BHA components.
Stabilizers and Downhole Tools
Stabilizers centralize the lower assembly and help control the behavior of the BHA. Directional sarta de perforacións may also iNClude mud motors, MWD/LWD tools, or rotary steerable systems near the bit. The selección of these components depends on the planned pozo trajectory and measurement requirements, while their dimensions, unións, flow ranges, and operating limits must repriNCipal coMPatible with the rest of the BHA.
FuNCtion of sarta de perforación
sarta de perforación performs five connected mechanical and hydraulic fuNCtions during perforación. It does more than rotate the bit: it supports the peso of the downhole assembly, transfers surface movement to the bottom of the pozo, carries perforación fluid, and helps keep the bit operating in the required direction.
The five priNCipal fuNCtions are:
1.Transmitting Rotary par
The top drive or rotary table applies par at the surface. That par passes through every tubería de perforación body, friction weld, unión, sub, and BHA component before reaching the bit.
In motor perforación, perforación fluid powers a downhole motor. The surface string may rotate continuously, rotate intermittently, or repriNCipal stationary while the motor turns the bit. The load case therefore changes with the perforación mode.
unión capacity may control the usable par before the nominal tubería body reaches its torsional yield limit. tubería OD, nominal peso, and grado de acero are therefore not sufficient to determine the par capacity of a tubería de perforación joint.
Published data for several proprietary unión configurations on 5 in × 19.50 lb/ft S135 tubería de perforación show how widely the result can vary:
| coMParación item | Published configuration range |
|---|---|
| tubería de perforación OD | 5.000 in |
| Nominal peso | 19.50 lb/ft |
| tubería grado | S135 |
| Tool-joint OD | 6.250–6.625 in |
| Tool-joint ID | 3.500–3.750 in |
| Maximum make-up par | 38,200–49,800 ft-lb |
| dIFereNCia entre lowest and highest published values | 11,600 ft-lb |
| INCrease from lowest to highest value | Approximately 30% |
The tubería size, nominal peso, and grado de acero repriNCipal the same throughout this coMParación, but the published maximum make-up par varies by 11,600 ft-lb. The dIFereNCia results from the combined effect of unión design, rosca and shoulder geometry, tool-joint OD and ID, and material capacity. It should not be attributed to one dimensional change alone.
These figures are coMParación data from dIFferent proprietary unión configurations. They do not represent a universal API value, an Octal tubería de perforacións standard supply specIFication, or the allowable operating par for every 5 in × 19.50 lb/ft S135 tubería de perforación.
For procurement, the purchase specIFication should identIFy the exact unión, tool-joint OD, tool-joint ID, material strength, and required dimensional condition. The supplier should provide the recommended make-up par and corresponding torsional rating for the actual supplied configuration.
Make-up par, allowable operating par, and torsional yield describe dIFferent limits. They should be listed separately in the technical documentation and should not be treated as interchangeable values.
2.Carrying Axial Load
The upper tubería de perforación normally carries the highest tensile load because it supports the buoyed peso of all components below it. Dynamic loads, drag, acceleration, and planned overpull iNCrease this load.
In a vertical pozo, the load generally iNCreases toward the surface. In a deviated or horizontal pozo, contact friction redistributes axial force. Sections of tubería de perforación may enter compression even though the surface hook load repriNCipals positive.
The required tensile capacity should be established by the perforación contractor or project engineering team using the planned trajectory, fluid density, tubular dimensions, expected drag, dynamic load, and required overpull. The supplier should provide verIFied tubería-body and unión ratings for the actual purchased configuration. Catalog values based only on nominal air peso should not be treated as the allowable hook-load limit for a high-angle or horizontal pozo.
3.Applying peso on Bit
portabrocass and seleccionared sections of HWDP provide the peso available near the bit. Only part of this available buoyed peso should be transferred as WOB. The repriNCipaling margin helps keep the neutral point within a sufficiently stIFf part of the lower assembly.
Required WOB depends on bit design, hole size, formation strength, rotary speed, hydraulic cleaning, and vibration response. Excessive WOB can cause bit damage, stick-slip, lateral vibration, buckling, or unstable tool-face control rather than producing a higher penetration rate.
4.Circulating perforación Fluid
perforación fluid flows down the internal bore of the sarta de perforación, passes through downhole tools and bit nozzles, and returns to the surface through the annulus.
The circulation system:
- Cools and cleans the bit
- Carries cuttings away from the bottom
- Transports cuttings to the surface
- Powers mud motors and hydraulic tools
- Supports mud-pulse telemetry
- Contributes to pozo-pressure control
Hydraulic calculations must use the smallest effective flow area in the assembled string. A tool-joint bore, float valve, motor power section, measurement tool, or bit nozzle may create more restriction than the tubería de perforación body.
INCreasing unión ID can reduce internal pressure loss, but removing metal from the unión may reduce torsional capacity. sarta de perforación design therefore involves a measurable hydraulics-versus-strength trade-off.
5.Controlling the pozo Path
The sarta de perforación also behaves as a long, flexible structural system. BHA stIFfness, stabilizer spacing, WOB, rotary speed, hole curvature, and wall contact affect iNClination, azimuth, vibration, and tool-face response.
When tubería de perforación rotates through a dogleg, each revolution produces a bending-stress cycle. fatiga damage can accumulate even when the maximum stress repriNCipals below the material’s límite elástico. Slip marks, corrosión pits, friction-weld transitions, rosca roots, and other stress coNCentrators can shorten fatiga lIFe.
sarta de perforación vs tubería de perforación
The dIFereNCia entre sarta de perforación vs tubería de perforación coNCerns the scope of the equipment being described.
| coMParación | sarta de perforación | tubería de perforación |
|---|---|---|
| Meaning | Complete assembled system extending to the broca de perforación | Individual tubular product usado within the string |
| Contents | tubería de perforación, transition components, BHA tools, subs, and bit | tubería body, upsets, friction welds, and pasador/caja unións |
| priNCipal role | Performs the complete mechanical and hydraulic perforación operation | Provides length, resisteNCia a la tracción, par transmission, and a fluid passage |
| Configuration | Changes with the hole section and perforación objective | seleccionared by OD, nominal peso, grado, unión, length, and condition |
| priNCipal product standard | Depends on the individual components | API Spec 5DP for finished steel tubería de perforación |
| usado-equipment inspection | Component-specIFic inspection program | API RP 7G-2 or an approved equivalent program |
One 30 ft joint of tubería de perforación is not a sarta de perforación. Conversely, calling the complete downhole assembly tubería de perforación excludes the BHA, portabrocass, directional tools, subs, and bit.
A deep pozo may contain hundreds of tubería de perforación joints, but those joints operate as one sarta de perforación only after they are connected to the required transition components and BHA.
Typical API tubería de perforación grados
API tubería de perforación grado designations reflect the specIFied tubería-body strength range. They do not define the capacity of the complete sarta de perforación.
| API grado | tubería-body yield-strength range | Minimum resisteNCia a la tracción |
|---|---|---|
| E75 | 75–105 ksi / 517–724 MPa | 100 ksi / 689 MPa |
| X95 | 95–125 ksi / 655–862 MPa | 105 ksi / 724 MPa |
| G105 | 105–135 ksi / 724–931 MPa | 115 ksi / 793 MPa |
| S135 | 135–165 ksi / 931–1,138 MPa | 145 ksi / 1,000 MPa |
Higher límite elástico iNCreases the nominal tubería-body load capacity, but it does not compensate for:
- An undersized or worn unión
- INCorrect make-up par
- A damaged shoulder or rosca root
- fatiga cracks in the slip or weld area
- Excessive dogleg severity
- An unsuitable stIFfness transition
- corrosión or internal erosion
- Combined tension and torsion
tubería-Body Tensile Calculation Example
Consider nominal 5 in × 19.50 lb/ft S135 tubería de perforación with a 0.362 in tubería-body wall:
- diámetro externo: 5.000 in
- Nominal espesor de pared: 0.362 in
- Calculated diámetro interno: 4.276 in
- Nominal metal area: approximately 5.28 in²
- Minimum S135 límite elástico: 135,000 psi
The nominal tubería-body tensile load at minimum yield is:
5.28 in² × 135,000 psi ≈ 713,000 lbf
This equals approximately 3,170 kN.
The result is a theoretical tubería-body yield load based on nominal geometry. It is not an allowable hook load and should not be usado directly as a safe working limit.
An operating limit must account for actual repriNCipaling espesor de pared, dimensional toleraNCe, unión capacity, desgaste classIFication, combined par and tension, dogleg bending, dynamic load, overpull, fatiga history, corrosión, and the operator’s design factor.
How sarta de perforación Capacity Is Evaluated
sarta de perforación capacity cannot be represented by one tubería-body strength value. It is governed by the lowest applicable limit among the tubería body, upset, friction weld, unión, roscaed unión, crossover subs, and other load-carrying BHA components. The controlling location may also change entre perforación, rotating, trippasadorg, and overpull operations.
Evaluation begins with the actual dimensions and condition of every critical component. tubería OD, repriNCipaling espesor de pared, grado de acero, tool-joint OD and ID, unión type, weld condition, and usado-tubería classIFication all affect the available capacity. The applied loads must then iNClude buoyed string peso, drag, rotary par, internal pressure, bending through doglegs, compression, dynamic loading, and the required overpull.
Published tensile or torsional yield values describe individual components under defined conditions; they are not automatically allowable operating limits for the complete sarta de perforación. The supplier should provide configuration-specIFic dimensions, material properties, unión ratings, and inspection records. The project engineering team must then apply the planned pozo profile, combined-load analysis, and required design factors to establish acceptable operating limits.
Tension and Overpull
The tensile-load calculation begins with the peso suspended below each point in the sarta de perforación. Because the tubulars are partly supported by the perforación fluid, their buoyed peso rather than their full air peso is usado for the initial static-load estimate. Expected drag, dynamic loading, pressure effects, and the required overpull margin are then added.
For a steel sarta de perforación surrounded by perforación fluid of unIForm density, a simplIFied buoyaNCy factor can be estimated as:
Buoyancy factor = 1 − mud density ÷ 65.5
For example, 10.0 ppg perforación fluid gives a buoyaNCy factor of approximately 0.847. A string weighing 300,000 lbf in air would therefore have an estimated buoyed peso of:
300,000 × 0.847 ≈ 254,100 lbf
This value represents only the simplIFied static suspended peso. IF the predicted upward drag is 40,000 lbf, the estimated hook load while pulling becomes approximately:
254,100 + 40,000 = 294,100 lbf
The allowable load must then be established from the lowest effective tensile capacity in the string. Using the earlier 5 in × 19.50 lb/ft S135 example, the nominal tubería-body tensile load at minimum yield is approximately 713,000 lbf. IF the project applies an illustrative tensile design factor of 1.30, the preliminary tubería-body allowable load would be:
713,000 ÷ 1.30 ≈ 548,000 lbf
The corresponding preliminary margin of overpull would be:
548,000 − 294,100 ≈ 253,900 lbf
| Calculation item | Illustrative value |
|---|---|
| sarta de perforación air peso | 300,000 lbf |
| Mud density | 10.0 ppg |
| BuoyaNCy factor | 0.847 |
| Estimated buoyed peso | 254,100 lbf |
| Predicted upward drag | 40,000 lbf |
| Estimated pulling hook load | 294,100 lbf |
| Nominal tubería-body yield load | 713,000 lbf |
| Illustrative tensile design factor | 1.30 |
| Preliminary allowable load | 548,000 lbf |
| Preliminary overpull margin | 253,900 lbf |
This example is not a universal operating limit. The 1.30 design factor is an illustrative project assumption rather than a fixed API requirement. Final overpull must be checked against the actual repriNCipaling espesor de pared, tool-joint and unión capacity, friction weld, crossovers, jars, combined par, cyclic bending, dynamic loading, and the operator’s approved design criteria.
Combined Tension and par
Tension and par act simultaneously during many perforación operations. tubería de perforación carrying substantial axial tension cannot be assumed to retain its full independent torsional capacity.
Supplier load tables should not be interpreted as allowing 100% of the published tensile rating and 100% of the published torsional rating at the same time. The project engineering team should verIFy the combined-load envelope for the planned pozo, while the supplier should provide the tubería-body and unión data required for that evaluation.
Compression and Buckling
Compression does not develop unIFormly throughout the sarta de perforación. In a conventional vertical pozo, the lower portabrocass carry compression as peso is applied to the bit, while the regular tubería de perforación above them is normally kept in tension. The point at which the effective axial force changes from tension to compression is commonly called the neutral point, and it should normally repriNCipal within the portabrocass or another sufficiently stIFf part of the lower BHA.
In directional and horizontal pozos, compression can extend farther up the string. The compressed section may iNClude the portabrocass, heavy-peso tubería de perforación, and lower joints of regular tubería de perforación. This commonly occurs while applying peso on bit, sliding with a mud motor, running into the hole, or pushing the string through an interval with high wall-contact friction. The surface hook load can repriNCipal positive while part of the lower sarta de perforación is already in compression.
Regular tubería de perforación does not need to reach its material compressive-yield load before it becomes unstable. A long tubular constrained inside a larger pozo can first develop sinusoidal buckling, in which it follows a wave-shaped path along the low side of the hole. With further compression, it may progress to helical buckling and wrap around the inside of the pozo. Helical buckling produces greater wall-contact force and can sharply iNCrease par, drag, desgaste, bending stress, and fatiga. It can also reduce the amount of surface-applied force that reaches the bit.
The compression that can be carried before buckling depends on:
- tubería OD, ID, espesor de pared, and bending stIFfness
- Tool-joint dimensions and spacing
- Buoyed peso per unit length
- pozo iNClination and local curvature
- ClearaNCe entre the tubular and pozo
- Friction entre the string and pozo
- Applied par and internal pressure
- Whether the string is rotating, sliding, or being tripped
- Existing desgaste, bending, and fatiga condition
For a straight, highly iNClined pozo, a simplIFied estimate of the sinusoidal buckling load can be expressed as:
Fₛ ≈ 2√(EIw sin θ ÷ r)
Where:
- Fₛ = estimated sinusoidal buckling load
- E = Young’s modulus of the tubular material
- I = pipe-body moment of inertia
- w = buoyed unit weight
- θ = well inclination
- r = radial clearance between the pipe body and wellbore
Consider 5 in × 19.50 lb/ft S135 tubería de perforación in a horizontal 8.50 in pozo under the following simplIFied conditions:
| Calculation input | Illustrative value |
|---|---|
| tubería de perforación OD | 5.000 in |
| Nominal espesor de pared | 0.362 in |
| Calculated tubería ID | 4.276 in |
| tubería-body moment of inertia | Approximately 14.27 in⁴ |
| Young’s modulus | 30 × 10⁶ psi |
| Mud density | 10.0 ppg |
| Estimated buoyaNCy factor | 0.847 |
| Estimated buoyed unit peso | 16.52 lb/ft |
| pozo diametro | 8.500 in |
| tubería-body radial clearaNCe | 1.750 in |
| pozo iNClination | 90° |
Under these simplIFied assumptions, the calculated onset of sinusoidal buckling is approximately:
Fₛ ≈ 36,700 lbf, or about 36.7 klbf
The nominal tubería-body load at minimum yield for the same 5 in × 19.50 lb/ft S135 tubería is approximately 713,000 lbf. The large dIFereNCia entre 36,700 lbf and 713,000 lbf shows why material límite elástico does not establish the acceptable compression limit. In this example, geometric instability can begin at only about 5% of the nominal tubería-body yield load.
The 36.7 klbf result is not a universal allowable compression value. It is an illustrative sinusoidal-buckling estimate for the stated tubería size, hole diametro, iNClination, mud density, and simplIFied straight-hole condition. Actual critical loads change when unións, unión spacing, pozo curvature, par, friction, varying fluid density, and post-buckling behavior are iNCluded.
IF the perforación program does not permit regular tubería de perforación to buckle, the predicted compressive force should repriNCipal below the approved sinusoidal-buckling limit with the required engineering margin. Some extended-reach perforación programs may permit controlled sinusoidal buckling when par-and-drag modelling and field experieNCe show that force transfer and fatiga repriNCipal manageable. Helical buckling requires more restrictive evaluation because it produces much higher contact force and a greater risk of lock-up, desgaste, and fatiga damage.
The useful check is therefore not whether the tubería is below its compressive límite elástico. Engineers should coMPare the predicted compressive-force profile at each measured depth with the calculated sinusoidal and helical buckling limits for that location. This identIFies whether compression repriNCipals within the stIFf portabrocass and HWDP or has extended into the more flexible regular tubería de perforación.
fatiga
fatiga evaluation must consider more than grado de acero. Relevant factors iNClude:
- Dogleg severity
- Number of rotations through the curved interval
- Local axial tension
- tubería OD and espesor de pared
- Tool-joint and tubería stIFfness
- corrosión pits or mechanical damage
- Previous service history
- Inspection sensitivity and reject criteria
S135 provides higher minimum límite elástico than G105, but higher grado alone does not guarantee longer fatiga lIFe. For critical service, procurement records should identIFy the manufacturing batch, inspection status, previous service class where applicable, and any available operating history. grado markings alone cannot establish the repriNCipaling fatiga condition of usado tubería de perforación.
Inspection and AcceptaNCe
nuevo tubería de perforación should be verIFied against the applicable edition of API Spec 5DP and the approved purchase specIFication. Manufacturing records should identIFy the tubería-body heat, grado, dimensions, tool-joint material, weld lot, mechanical-test results, NDT status, unión, and traceable marking.
usado tallo de perforación elements are inspected and classIFied under API RP 7G-2 or an operator-approved equivalent. The inspection program should establish the required inspection level, inspection methods, personnel qualIFication, equipment calibration, evaluation criteria, and marking procedure.
A practical tubería de perforación inspection program may iNClude:
- Full-length visual inspection
- tubería-body OD and wall-thickness measurement
- Electromagnetic inspection
- Ultrasonic wall-thickness verIFication
- Wet fluorescent magnetic-particle inspection of critical end areas
- rosca and shoulder inspection
- Tool-joint OD and ID measurement
- Straightness inspection
- Friction-weld inspection
- Hardbanding-condition assessment
premium-class tubería de perforación is commonly classIFied with at least 80% of nominal body wall repriNCipaling. For a nominal wall of 0.362 in:
0.362 × 0.80 = 0.290 in, or approximately 7.36 mm.
This classIFication threshold does not automatically approve the joint for a particular pozo. A critical, high-load, corrosive, or high-fatiga aplicación may require a greater repriNCipaling wall, additional inspection methods, or more restrictive retirement criteria.
A joint can retain more than 80% of its nominal wall and still be rejected because of a crack, damaged rosca, washed-out shoulder, excessive tool-joint desgaste, slip-area damage, or an unacceptable friction-weld indication.
Common sarta de perforación selección Errors
Several recurring errors reduce sarta de perforación fiabilidad:
- seleccionaring S135 solely because it has the highest conventional API grado
- CoMParing tubería-body tensile capacity without checking the unión
- Treating maximum make-up par as allowable perforación par
- Using nominal espesor de pared for worn tubería de perforación calculations
- Ignoring the smallest bore through the BHA
- Placing an abrupt stIFfness transition in a severe dogleg
- Assuming premium Class means suitable for every pozo
- Reusing the same BHA configuration for dIFferent hole sections
- Ignoring accumulated rotating hours through high-curvature intervals
- Evaluating tension, par, bending, and pressure as unrelated loads
The correct sarta de perforación is the assembly that provides adequate mechanical, hydraulic, and fatiga margin for the planned pozo. Simply choosing the heaviest tubería, highest grado, or largest unión does not establish a balaNCed design.
FAQ
Q: What is a drill string in oil and gas drilling?
A: Drill string refers to the complete assembled column connecting the surface drilling equipment to the drill bit. It normally contains drill pipe, transition components such as heavy-weight drill pipe, and a project-specific bottom-hole assembly.
Q: Is drill pipe the same as a drill string?
A: No. Drill pipe is one tubular component and normally forms most of the string’s length. The drill string includes drill pipe together with the BHA, drill collars, subs, directional tools, and drill bit.
Q: What is the main function of drill string equipment?
A: The function of drill string equipment is to rotate or guide the bit, carry drilling fluid, apply controlled weight on bit, support downhole tools, and allow the complete assembly to be lowered into or retrieved from the well.
Q: What determines the safe capacity of a drill string?
A: Safe capacity is determined by the lowest applicable limit among the pipe body, tool joints, connections, weld areas, subs, and BHA tools. Actual dimensions, wear, tension, torque, pressure, bending, buckling, fatigue, and the required design factor must all be considered.
