# Drillpipe

Drillpipe pulled between filling = 10 stands Actual strokes required as illustrated in Table 3.1

## Oil field drill pipes failure

Gudimella V.S. Murthy, in Handbook of Materials Failure Analysis with Case Studies from the Oil and Gas Industry, 2016

### Abstract

Drill pipe is one kind of important tools for drilling in oil field. Drill pipes are subjected to various types of loads and are operated under different environmental conditions. Incidents of drill pipe failure due to fatigue, corrosion (local, i.e., pitting and groove), and stress corrosion are very common in the field. Similarly, the heavy-weight drill pipe fatigue failures often occur in oil fields because drill pipes bear continuously changeable tension load, torsion load, impact load, internal pressure, etc., during drilling. In this chapter, three typical failures in each type of drill pipe as investigated at the author's laboratory will be examined and presented. It is clear from each of these cases that despite the fact that the pipes used by oil industry meet all the standard specifications failures do occur which can be controlled by choice of appropriate material property needed for a specific application.

URL: https://www.sciencedirect.com/science/article/pii/B9780081001172000029

## Pressure Control

William C. Lyons, ... Norton J. Lapeyrouse, in Formulas and Calculations for Drilling, Production, and Workover (Fourth Edition), 2016

### 3.1.2Drill String Volume

Drill pipe capacity: _____ bbl/ft. × ______ length, ft. = ________ bbl

Drill pipe capacity: _____ bbl/ft. × ______ length, ft. = ________ bbl

Drill collar capacity: ____ bbl/ft. × ______ length, ft. = ________ bbl

Total drill string volume: _________bbl

URL: https://www.sciencedirect.com/science/article/pii/B9780128034170000032

## Downhole Equipment

William C. Lyons, ... Tom Weller, in Air and Gas Drilling Manual (Fourth Edition), 2021

### 4.1.2Heavy-Weight Drill Pipe

Heavy-weight drill pipe is an intermediate weight per unit length drill string element. This type of drill pipe has a heavy wall pipe body with attached extra length tool joints (see Figure 4-2). Heavy-weight drill pipe has the approximate outside dimensions of standard drill pipe to allow easy handling on the drill rig [2].

The unique characteristic of this type of drill pipe is that it can be run in compression in the same manner as drill collars. Most heavy-weight drill pipe is fabricated in Range 2 and 3 API lengths. It is also available in custom lengths shorter than Range 2. Heavy-weight drill pipes are available in 3 1/2 inch (89 mm), 4 inch (102 mm), 4 1/2 inch (114 mm), 5 inch (127mm), 5 1/2 inch (140 mm), and 6 5/8 inch (168 mm) nominal outside diameters. Figure 4-2 shows two typical heavy-weight drill pipe elements standing in a regular drill pipe rack in a drill rig. One unique feature of heavy-weight drill pipe is the wear pad in the center of the element. The wear pad acts as a stabilizer and improves the stiffness of the heavy-weight stand in the drill string and thus reduces the deviation of boreholes.

Tables 4-2a and 4-2b give the dimensional and mechanical properties for Range 2 heavy-weight drill pipe (tube body and tool joints). For heavy-weight drill pipe sizes from 3 1/2 inch (89 mm) and greater, the pipe tube body is fabricated of steel alloys with a minimum yield stress of 55,000 psi (797 MPa). The tool joints for these sizes are fabricated of steel alloys with a minimum yield stress of 120,000 psi (828 MPa). The 2 7/8 inch drill pipe is fabricated entirely of 110,000 psi (759 MPa) steel alloy.

Table 4-2a. Heavy-Weight Drill Pipe Range 2 Dimensions and Mechanical Properties in USCS [2]

Nominal OD (inch) Approx Wt (Ib/ft) Tube ID (inch) Wall Thick (inch) Conn Type Tool Jt OD (inch) Tool Jt ID (inch) Tensile Yield (Ib)
2 7/8 17.26 1.5000 0.688 NC26 3 3/8 1.5000 519,750
3 1/2 23.70 2.2500 0.625 NC38 4 3/4 2.2500 310,475
4 29.90 2.5625 0.719 NC40 5 1/4 2.5625 407,500
4 1/2 40.80 2.8125 0.844 NC46 6 1/4 2.8125 533,060
5 50.38 3.0000 1.000 NC50 6 5/8 3.0000 691,130
5 1/2 61.60 3.2500 1.125 5 1/2 FH 7 1/4 3.2500 850,465
5 7/8 57.42 4.0000 0.938 XT57 7 4.0000 799,810
6 5/8 71.43 4.5000 1.063 6 5/8 FH 8 4.5000 1,021,185

Table 4-2b. Heavy-Weight Drill Pipe Range 2 Dimensions and Mechanical Properties in SI Units

Nominal OD (mm) Approx M (kg/m) Tube ID (mm) Wall Thick (mm) Conn Type Tool Jt OD (mm) Tool Jt ID (mm) Tensile Yield (kN)
73 25.68 38 17 NC26 86 38 2,312
89 35.26 57 16 NC38 121 57 1,381
102 44.48 65 18 NC40 133 65 1,813
114 60.70 71 21 NC46 159 71 2,371
127 74.95 76 25 NC50 168 76 3,074
140 91.64 83 29 5 1/2 FH 184 83 3,783
149 86.42 102 24 XT57 178 102 3,558
168 106.26 114 27 6 5/8 FH 203 114 4,542

Heavy-weight drill pipe elements are used in a number of applications in rotary drilling. Since this drill pipe can be used in compression, this drill pipe can be used in place of drill collars in the shallow wells with small single or double rotary drilling rigs. This drill pipe is also used in conventional drill string for vertical drilling operations as transitional stiffness elements between the stiff drill collars and the very limber drill pipe. Their use as transitional stiffness elements reduces the mechanical failures in the bottom drill pipe elements of the drill string. The practice is to run from 6 to 30 heavy-weight drill pipe on top of a conventional BHA.

In off-shore drilling operations, the use of heavy-weight drill pipe has become essential. Heavy-weight drill pipe is used in directional drilling operations where drill collars can be replaced by the heavy-weight pipe. Using heavy-weight drill pipe in place of drill collars reduces the rotary torque and drag, and increases directional control.

In Tables 4-2a and 4-2b, there is an unusual drill pipe size. This is the 5 7/8 inch (149 mm) heavy-weight drill pipe and its associated standard drill pipe companion is used for drilling long-reach highly deviated directional boreholes (particularly in offshore operations). This drill pipe allows higher annulus drilling fluid velocities for improved cuttings removal (particularly in horizontal boreholes) and lower drilling fluid velocities inside the drill string to reduce pipe friction losses.

URL: https://www.sciencedirect.com/science/article/pii/B9780128157923000040

## SPECIAL CONDITIONS, PROBLEMS, AND PROCEDURES IN WELL CONTROL

Robert D. Grace, in Blowout and Well Control Handbook, 2003

### DETERMINATION OF SHUT-IN DRILLPIPE PRESSURES

Generally, the drillpipe pressure will stabilize within minutes after shut-in and is easily determined. In some instances, the drillpipe pressure may never build to reflect the proper bottomhole pressure, particularly in cases of long open-hole intervals at or near the fracture gradient coupled with very low productivities. When water is used as the drilling fluid, gas migration can be rapid, thereby masking the shut-in drillpipe pressure. In these instances, a good knowledge of anticipated bottomhole pressures and anticipated drillpipe pressures is beneficial in recognizing and identifying problems and providing a base for pressure control procedures.

A float in the drill string complicates the determination of the drillpipe pressure; however, it can be readily determined by pumping slowly on the drillpipe and monitoring both the drillpipe and annulus pressure. When the annulus pressure first begins to increase, the drillpipe pressure at that instant is the shut-in drillpipe pressure.

Another popular procedure is to pump through the float for a brief moment, holding the casing pressure constant, and then shut in with the original annulus pressure, thereby trapping the drillpipe pressure on the stand pipe gauge. An additional technique is to bring the pump to kill speed and compare the circulating pressure with the pre-recorded circulating pressure at the kill rate with the difference being the drillpipe pressure. Still another alternative is to use a flapper-type float with a small hole drilled through the flapper that permits pressure reading but not significant flow.

URL: https://www.sciencedirect.com/science/article/pii/B9780750677080500050

## Pressure Control

William Lyons, ... Norton J. Lapeyrousse, in Formulas and Calculations for Drilling, Production, and Workover (Third Edition), 2012

### Drill String Volume

Drill pipe capacity

_________ bbl/ft × _________ length, ft = _________________ bbl

Drill collar capacity

_________ bbl/ft × _________ length, ft = _________________ bbl

Total drill string volume _________________________________ bbl

URL: https://www.sciencedirect.com/science/article/pii/B978185617929400004X

## Fishing in Cavities

Joe DeGeare, in The Guide to Oilwell Fishing Operations (Second Edition), 2003

### Abstract

When drill-pipe parts in a washed-out section of the wellbore, the fish will not be centered in the hole. A straight-overshot tool string may bypass the top of the fish, touch the pipe, and take weight below the top. If this occurs, rotation slows, and the cut-lip guide will build up a slight torque and then “jump off.” It may be impossible to engage the top of the fish with the tool string, but certain tools and techniques can be used to help latch onto the fish.

URL: https://www.sciencedirect.com/science/article/pii/B9780124200043000150

## Corrosion in Drillpipe and Casing

Bill Rehm, ... Katherine Dimataris, in Underbalanced Drilling: Limits and Extremes, 2012

### 13.5.3Drillpipe Rings

The corrosion rate for drillpipe is usually measured with a ring of steel similar to the tool joint. The ring is numbered and carefully weighed. The ring can be the same grade of steel as the drillpipe, or in some cases it can be a more reactive material to accelerate a warning of corrosion. Drillpipe rings are usually placed just above the drill collars and then again half way up the hole.

The drillpipe ring is left in the drillpipe for some period and retrieved on a trip and sent to the supplier to be weighed and the loss per year calculated. The obvious problem with the ring is that it reports corrosion after it has occurred at that point in the well. Changes in the corrosion treatment based on ring data are always lagging behind any problems that are occurring.

URL: https://www.sciencedirect.com/science/article/pii/B9781933762050500206

## Corrosion

James G. Speight, in Subsea and Deepwater Oil and Gas Science and Technology, 2015

### 8.4.1Drill Pipe

To monitor drill pipe corrosion and the effectiveness of mud treatments, coupon rings are installed between joints (left). The rate of corrosion can then be assessed by measuring the amount of metal lost from the rings.

During drilling, mud systems are routinely monitored for chemical and physical properties. Tests specifically related to corrosion control include an analysis of oxygen, carbon dioxide (CO2), hydrogen sulfide (H2S), and bacteria. Hydrogen sulfide is detected by measuring the total tested further by adding acid to liberate hydrogen sulfide, which can be measured using any standard hydrogen sulfide detector. Bacterial attacks can be recognized by a drop in pH, increase in fluid loss or change in viscosity.

URL: https://www.sciencedirect.com/science/article/pii/B9781856175586000088

## Gaseated Fluids (Gas-Liquid Mixtures)

Bill Rehm, ... Arash Haghshenas, in Underbalanced Drilling: Limits and Extremes, 2012

### 3.32.5Pressure Drop in the Drillpipe

In the drillpipe, pressure and velocity are higher than in the wellbore. Therefore, the main dominant flow is bubble flow, which makes pressure profile calculations easier. The flow of gas and liquid can be assumed as a homogenous mixture, and the slippage between the phases can be ignored, reducing the multiphase flow calculation to a single–phase fluid flow.

The Griffith correlation is one of the most widely used for bubble flow calculation in the industry to calculate the frictional pressure loss for bubble flow. The Griffith model assumes a slippage velocity (drift–flux) between the gas and the liquid phase. The velocity of the fluid in the pipe is related to the superficial velocities of gas-liquid phases. Then the density and the viscosity of the liquid phase are used to determine the Reynolds number and frictional pressure drop. The relationship between the liquid velocity and the superficial velocities is given as

(3.44)${E}_{L}=1-\frac{1}{2}\left[1+\frac{{V}_{m}}{{V}_{s}}-\sqrt{{\left(1+\frac{{V}_{m}}{{V}_{s}}\right)}^{2}-4\left(\frac{{V}_{sg}}{{V}_{s}}\right)}\right]$

The value of Vs is 0.8 ft/sec or 0.24 m/sec in SI unit. When the EL is calculated, the velocity of the in–situ velocity of the liquid phase in the tubing is calculated as

(3.45)${V}_{l}=\frac{{V}_{sl}}{{E}_{L}}$

The Reynolds number is then calculated using the properties of the liquid phase.

(3.46)$\mathrm{Re}=\frac{{\rho }_{l}{\text{V}}_{\text{1}}\text{D}}{{\mu }_{L}}$

The friction factor can be calculated using the Reynolds number. For Fanning friction factor, the frictional pressure drop is given in Eq. (3.29). Note that the Moody friction factor is 4 times greater than Fanning friction factor.

(3.47)$\Delta {P}_{f}=\frac{2f{\rho }_{1}{\text{V}}_{\text{1}}^{\text{2}}}{{g}_{c}D}L$

The hydrostatic pressure of the gas and liquid mixture is calculated using the mixture density of the gas and liquid.

(3.48)$\Delta {P}_{h}={\rho }_{m}\text{gL}$