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MAY 1998 63

T U B U L A R U P D A T E

tions. Axial, bending, radial, and hoop stress-es are calculated in the full-length paper.

Contact occurs when the casing touches

the upper side of the wellbore. Because mostof the casing is lying in the lower part of the

hole, the only section that can contact the

upper part is the section between the casing

shoe and point of tangency. Therefore, for a

specific loading condition and radius of cur-vature, if the casing touched the upper part

of the wellbore, the solution was disregard-

ed and only those solutions where no con-

tact occurs were used.

CASE STUDIES

Effect of Hole Curvature. Fig. 1 shows the

bottomhole force as a function of dogleg

severity for various hole-inclination angles

measured at the casing shoe. The 95/8-in.,53.5-lbm/ft P-110 casing is constrained by

a 121/4-in. hole filled with 10-lbm/gal

mud. The load applied at the top of the

curved section is 30,000 lbf, and the coef-

ficient of friction is 0.3. With a doglegseverity as great as approximately 16.5/

100 ft, the casing will not exceed elastic

deformation or contact the hole for hole-

inclination angles from 40 to 80. For a90 inclination, the corresponding doglegseverity is approximately 14.5/100ft.

For hole-inclination angles from 40 to

60, an increase in dogleg severity causes

the bottomhole force to decrease. At 70

inclination angle, the bottomhole force isalmost constant. For 80 and 90 inclination

angles, an increase in dogleg severity causes

the bottomhole force to increase. For exam-

ple, if the casing has to be set at a final angleof 90, the bottomhole force is zero for a

dogleg severity of 4/100 ft. This indicates

that the casing is stuck because the frictionforces are equal to the slackoff force.

Effect of Hole Angle. Fig. 2 compares thelong-dogleg model (Model II) and the con-

tinuous-contact model (Model III). Slackoffforces from 10,000 to 70,000 lbf areapplied. Hole conditions are the same as in

Fig. 1, and the radius of curvature is 400 ft.

Both models predict a decrease in bottom-

hole force as the hole angle increases except

for the case of 10,000 lbf slackoff force. Therate of decrease is different for each model,

and their difference increases with increas-

ing inclination angle.

CONCLUSIONS

1. The maximum hole curvature in

which casing can be run depends on the

force applied at the top of the curved sec-

tion, hole-inclination angle, and the coeffi-

cient of friction.2. A large radius of curvature induces

larger lateral loads than a small radius of

curvature at hole angles greater than 70.

3. Friction forces are greater for larger

radius of curvature because the length ofcasing/hole contact is greater at high hole-

inclination angles.

4. The magnitude of lateral forces at the

casing shoe and of total friction forcedepends on hole size, radial clearance, radiusof curvature, and hole-inclination angle.

5. The models presented in this paper

simulate the influence of the hole curva-

ture and inclination angle on the externalforces acting on the casing during run-

ning operations.

Please read the full-length paper for

additional detail, illustrations, and ref-

erences. The paper from which the syn-

opsis has been taken has not been peerreviewed.

Fig. 2Effect of hole angle on bottomhole force.

Bottomh

oleForce,

lbf

Hole-Inclination Angle, degrees


3/15


64 MAY 1998

Most failures of drillpipe, measurement-

while-drilling equipment, and bits are causedby whirling. To prevent drillstring failure, it is

of prime importance to the drilling industry

to detect this phenomenon when it starts.

Whirling is described as an abnormal rota-

tion of either the bit or drillstring. It is a com-plex movement that generates lateral dis-

placements, shocks, and friction against theborehole wall. Drillstring whirling occurs

mainly in the bottomhole assembly (BHA)but can occur in the drillstring. The BHA is

under compressive loading during drilling

and is susceptible to buckling and whirling.

The drillstring is in tension and has less ten-

dency to whirl. Drillstring whirling causeslateral movements of the traveling block

called whipping. While whipping is easy to

detect, it provides no quantitative measure of

whirling severity.

When BHA whirling begins, componentsof the BHA are subjected to lateral displace-

ments that generate bending stresses.

When these displacements become large,

parts of the BHA contact the borehole wall,

generating lateral shocks. Occasionally,there is continuous contact with the bore-

hole wall that results in pipe wear. These

phenomena increase fatigue of the BHA ele-

ments and their connections. Becausewhirling is difficult to detect, fatigue accu-

mulates, resulting in failure of BHA compo-

nents that requires a costly fishing job.

Before logging-while-drilling (LWD) sys-

tems were developed, the driller had no way

to detect whirling. A shock counter thatcounts lateral shocks greater than a mini-

mum value over a period of time can be

installed in an LWD system. This count is

transmitted to the surface through the stan-

dard mud-pulse telemetry system and indi-

cates the severity of whirling. This system is

available only during LWD. This paper

describes a method to detect whirling by useof the surface measurements available on

most rigs: weight on the hook (WOH), rotary

torque, and drillstring rotational speed.

BHA WHIRLINGBecause BHA components do not rotate

around the center of the well, they come

into contact with the borehole wall, gener-ating lateral shocks. Position of the drill-

string centerline plotted vs. time has a com-

plex shape. During whirling, the BHA is

buckled and has an S-like shape. The drill-

string rotates at one speed, v, but the cen-terline of the drillstring rotates at a different

speed, vc

(Fig. 1). The direction ofvc

can

be the same as (forward whirling) or oppo-

site (backward whirling) to that of v.

Analysis From Downhole Measurements.

A real-time data-acquisition system was

used to measure downhole stresses associ-

ated with whirling. The downhole sub mea-

sures the bending stresses along two axes ofthe BHA, weight on bit, and torque on bit.

When WOH and rotary torque are plotted,

bending-stress amplitude changes signifi-

cantly when whirling begins.

Analysis From Surface Measurements.

Bending vibrations usually are not transmit-

ted to the surface by the drillstring but can be

detected in the WOH measurement. A com-

parison of standard surface measurementsand high-quality sensor measurements made

at the top of the drillstring shows that in the

0- to 5-Hz range, standard sensors found on

any rig have the same frequency behavior ashigh-quality sensors. Therefore, WOH mea-

sured at the cable dead end can be used to

detect whirling. Rotary torque changes dras-tically when whirling begins. These changes

in surface measurements can be used todetect the beginning of BHA whirling.

WHIRLING DETECTION

BHA-whirl detection by use of only surface

measurement is based on correlated phe-

nomena that appear simultaneously down-hole and at the surface. This was verified by

numerous downhole and surface data sup-

plied by a real-time data-acquisition sys-

tem. Surface torque and WOH are consid-

ered random variables in the analysis pre-sented in the full-length paper. The analysis

continuously compares their probability-

density functions over short- and long-time

periods. Analysis of the WOH spectrum

provides an estimate of whirling severitybut cannot distinguish between backward

and forward whirling. Software was

designed to recognize a change in mean

value of rotary torque and a specific fre-quency in the WOH measurement by use of

advanced signal-processing methods.

CONCLUSIONS

1. Advanced signal-processing methodsdescribed in this paper allow BHA whirl to

be detected from surface measurements.2. Whirling is indicated by an increase in

the mean value of torque and a change in

the WOH spectrum.

3. A method was developed to compute awhirling-severity factor that gives the driller

an indication of the whirling severity.





DETECTING WHIRLING BEHAVIOR

OF THE DRILLSTRING FROMSURFACE MEASUREMENTS

This article is a synopsis of paper SPE

38587, Detecting Whirling Behavior

of the Drillstring From Surface

Measurements, by I. Rey-Fabret, SPE,

M.C. Mabile, SPE, and N. Oudin, Inst.

Franais du Ptrole, originally present-

ed at the 1997 SPE Annual Technical

Conference and Exhibition, SanAntonio, Texas, 58 October.

Fig. 1Drillstring shape during whirling.


4/15


66 MAY 1998

As the number of lateral/multilateral wells

increases, there is an increasing need to

understand buckling behavior of drillpipe,

especially coiled tubing (CT), in a hole of

constant curvature. Lateral-/multilateral-

drilling techniques have significant poten-

tial to reduce well costs and to increase

hydrocarbon production. CT drilling plays

a substantial role in lateral/multilateraldrilling. Well-cost reduction in CT drilling

can be achieved by transmitting weight to

the bit effectively and preventing CT

fatigue/failure and lockup. To achieve this,

an accurate buckling model is essential.

The buckling behavior of drillpipe in

deviated wells has been investigated for

many years. Dawson and Paslay1 presented

an equation to predict the axial compres-

sive load necessary to initiate drillpipe

buckling. Miska and Cunha2 derived new

equations for prediction of the axial com-

pressive load required to produce a helicalconfiguration (including rotary torque).

Mitchell3 obtained similar results by use of

a finite-element method. Recently, Miska

et al.4 derived equations to predict the axial

compressive load required to maintain a

stable sinusoidal configuration.

This paper presents a new three-dimen-

sional (3D) mathematical buckling model

to analyze buckling behavior of drillpipe in

a hole of constant curvature (such as the

build section of a horizontal well).

Equations are derived to predict the axial

compressive force necessary to maintain astable sinusoidal configuration and the

axial compressive force required to produce

a helical configuration. These equations

reduce to equations for a deviated well asthe borehole radius becomes infinite.

MATHEMATICAL MODEL

Major Assumptions. The following

assumptions are used in performing

drillpipe post-buckling analysis in a con-stant-curvature borehole.

Drillpipe assumes either a sinusoidal orhelical configuration on buckling.

Drillpipe is sufficiently long so that end

conditions do not affect the force/pitch rela-tionship.

Dynamic effects and friction caused by

drillpipe sliding are ignored.

Drillpipe is initially at the low side ofthe borehole.

The borehole is modeled as a cylinder

with rigid walls and constant cross-section-

al area.

Drillpipe is represented by an elasticline of constant properties.

The centerline of the borehole is a

plane curve.

Effects of drilling-fluid flow are

ignored.

Curvilinear System of Coordinates. As

Fig. 1 shows, the drillpipe is initially lying

on the low side of the borehole. The origin

of the Cartesian system of coordinates (x,y,

and z) is at the center of the bottom of theborehole, withxcoinciding with the oppo-

site principal axes of the cross section, y

pointing into the paper, and z coinciding

with the tangent to the bottom of the cen-

terline. It is assumed that the x-z planecoincides initially with the plane of curva-

ture of drillpipe, that the positive direction

ofx is away from the center of curvature,

that z is positive in the direction corre-

sponding to an increase in Angle , andthat Arc s of the centerline is measured

from the bottom of the borehole. Ordinates is a distance measured along the center-

line of the hole; u is a radial displacement

(opposite to principal normal direction) ofthe drillpipe elastic line; and v is a displace-

ment of the pipe elastic line opposite to the

binormal direction.

The transformation between the

Cartesian and curvilinear (u, v, and s) sys-tems of coordinates is given by

x=(R+u)cos R, . . . . . . . . . . . .(1)

y=v, . . . . . . . . . . . . . . . . . . . . . . . .(2)

and z=(R+u)sin , . . . . . . . . . . . . . .(3)

where R is the radius of the borehole cen-

terline and is the angle given by

=s/R. . . . . . . . . . . . . . . . . . . . . . .(4)

Total-Potential-Energy Change. The change

in the total potential energy of the conserv-ative system, Epc, comprises the changein the strain energy of bending, Ub; the

potential of the axial force, a, and the

potential of the radial force, r. a is equalto the negative work done by the axial

force, and ris equal to the work done bythe weight component in the radial direc-

tion. Ub, a, and rare derived in detail in

Appendix A of the full-length paper.

POST-BUCKLING ANALYSIS

Sinusoidal Configuration. If an external

force acting on the drillpipe constrained

within a curved hole exceeds a certain crit-

ical value, the pipe starts to buckle and

changes its configuration into a sinusoidal

shape (Fig. 2). The angular displacement isgiven by

ANALYSIS OF DRILLPIPE/

COILED-TUBING BUCKLING IN ACONSTANT-CURVATURE WELLBORE


39795, Dri llpipe-/Coi led-Tubing-

Buckling Analysis in a Hole of Constant

Curvature, by Weiyong Qui, SPE,

Baker Oil Tools; Stefan Miska, SPE, U.

of Tulsa; and Leonard Volk, SPE, BDM

Petroleum Technologies, originally pre-

sented at the 1998 SPE Permian Basin

Oil and Gas Recovery Conference,Midland, Texas, 2527 March.

Fig. 1Drillpipe in a constant-curvatureborehole: (a) side view and (b) top view.


5/15

68 MAY 1998


=A sin(2s/), . . . . . . . . . . . . . . .(5)

where A is the amplitude of the sine curveand is the wavelength of the sinusoid.

Epc of the system and the axial compres-sive load necessary to maintain a stable

sinusoidal configuration are derived in

detail in Appendix B of the full-lengthpaper. The minimum axial compressive

force needed to initiate drillpipe buckling

in a constant curvature hole is

.

. . . . . . . . . . . . . . . . .(6)

As the radius of curvature of the boreholeapproaches infinity, Eq. 6 reduces to

Dawson and Paslays1 equation. For practi-

cal applications, r/R is a very small value

and Eq. 6 can be simplified.

Numerical Examples. Fig. 3 shows the

effect of the borehole radius of curvature

and pipe size on the maximum permissible

compressive axial load to maintain a stablesinusoidal configuration in a constant-cur-

vature borehole. As borehole radius

increases, the maximum permissible load

decreases. For a moderately small radius ofcurvature (a few hundred feet), doubling

the radius of curvature reduces the com-

pressive load by half. As would be expect-

ed, the maximum permissible axial load

increases as the pipe size increases for afixed borehole size. As the borehole size

increases for a given pipe diameter, the

axial load drops because of the additional

room in the wellbore for the pipe

to deform.

Helical Configuration. Fig. 4 shows the

angular displacement of drillpipe in a heli-cal configuration. The full-length paper

derives the force/pitch relationship indetail in Appendix C. The axial compres-sive force required to produce a helical

configuration is

.

. . . . . . . . . . . . . . . . .(7)

If the radius of curvature of the borehole

approaches infinity, Eq. 7 reduces to Miskaand Cunhas2 and Mitchells3 equation for

deviated wells. For practical field applica-

tions, r/R is a very small value and Eq. 7 can

be written as

. . . . . .(8)

BUCKLING PATTERNS

Drillpipe constrained inside a constant-cur-

vature borehole takes one of four configura-

tions: straight, sinusoidal, transitional (unsta-ble sinusoidal), or helical. Fig. 5 shows howpipe configuration changes as axial compres-

sive load increases for different wellbore

sizes. One important observation is the limit-

ed range of axial load required to pass from

the sinusoidal configuration, through thetransition stage, and into the helical configu-

ration. If the pipe size is only somewhat

smaller than the hole size, the pipe remains

in the sinusoidal configuration through alarger range of axial loads. This is significant

because lockup does not occur until after the

pipe assumes a helical configuration.

CONCLUSIONS

1. New equations are derived that predictthe maximum permissible axial compres-

sive load for stable sinusoidal configuration

and the axial compressive load necessary to

produce a helical configuration in a con-

stant curvature borehole .2. Numerical results indicate that the

radius of curvature, borehole size, and bend-

ing stiffness of drillpipe are the dominant

parameters in pipe buckling in curved wells.

3. The results can be used to selectappropriate drillpipe to avoid buckling

during drilling and well-completion

operations.

NOMENCLATURE

E=Youngs modulus, m/Lt2, psiEpc= total potential energy of the con-

servative system, mL2/t2, lbf-ft

F= axial compressive force, mL/t2, lbf

I= inertial moment of drillpipe, L4,

in.4

R= radius of curvature of borehole, L, ft

Fig. 3Radius of curvature vs. maximum permissible axial compressive load.Fig. 4Drillpipe in helical configuration:(a) sideview and (b) top view.

Fig. 2Drillpipe in stable sinusoidalconfiguration: (a) side view and (b) top

view.

Radius of Curvature of a Hole, ft

AxialCompressiveLoad,

104lbf

(To Page 77)


6/15


70 MAY 1998

Torque and drag commonly are considered

to be the critical drilling issues for extend-

ed-reach drilling (ERD). Drilling loads must

be sustained by the drillpipes torsional, ten-sile, and combined torsional/tensile capaci-

ties. Torque and drag constraints can be sig-

nificant but are not the governing drillpipe-

design constraints for ERD operations.

Hydraulic limitations usually are morerestrictive. A typical 51/2-in. drillpipe for

ERD is 21.9 lbm/ft S-135 with either a stan-dard American Petroleum Inst. (API) tool

joint or a proprietary high-torque tool joint.

This string can sustain 787 kips in tensionand 33 to 45 ft-kips in torsion, which is ade-

quate for a deep 121/4-in. ERD borehole.

However, hydraulic-pressure losses would

be excessive for the high flow rates (approx-

imately 900 to 1,000 gal/min) required toclean high-inclination-angle, 121/4-in. holes.

In addition to hydraulic and strength issues,

operational efficiency is a significant factor

in developing a drillpipe strategy for ERD.

When Arco evaluated the feasibility ofconducting ERD operations on a space-con-

strained rig on an offshore platform, the com-

pany found that use of 65/8-in. drillpipe cre-

ated a difficult logistics problem before and

after running 95/8-in. intermediate casing.This larger drillstring required more space in

the derrick and increased platform loading

when casing-running loads were at a maxi-

mum. The 65/8-in. drillpipe also would have

to be laid down and offloaded while a stringof smaller drillpipe was picked up. This

process would result in significant downtime

and introduce substantial risk of weather-

related delays. Limitations of standard 51/2-and 65/8-in. drillpipe and operational con-

straints imposed by ERD operations (particu-larly those that are offshore, and space or

weight constrained) created a need to devel-

op an optimized purpose-built drillpipe.

DRILLPIPE-DESIGN TECHNOLOGIES

In many cases, drillpipe design means

taking the existing string configuration and

verifying that it is adequate for a proposedwell. In more critical cases, it means devel-

oping a specific configuration for a drill-

string on the basis of the casing/hole pro-

gram, predicted well loads, and hydraulic

requirements. Even this approach selectsfrom a list of standard drillpipe. This paper

approaches drillpipe design by identifyingthe critical performance properties for

drillpipe and existing technical and manu-facturing capabilities that can generate the

optimal drillpipe design.

High-Strength Metallurgy. Compared

with conventional-grade tool joints with120-ksi yield strength, a 165-ksi tool jointprovides a 38% increase in tool joint torque

and tension capacities. Because of strict

metallurgical requirements and the need for

careful field handling, 165-ksi drillpipe has

failed and practical application of thesegrades has been limited. Metallurgical

advances make high-strength grades more

reliable, and test joints manufactured by

use of these new metallurgical techniques

recently have been field tested successfully.Instead of applying high-strength metal-

lurgy to standard-sized drillpipe, custom

ERD drillpipe must be considered to

improve hydraulics. Because application of165-ksi material to standard drillpipe and

tool joint sizes results in higher load capac-

ities than required and does not improve

weight or hydraulic considerations,

drillpipe design should be optimized withnew weights and dimensions.

The 165-ksi drillpipe tube should be

designed to provide specific torsional and

tensile strengths with a maximized inner

diameter (ID) for a given outer diameter(OD). The tool joint should be optimized

with a suitable material strength. For exam-

ple, 150-ksi tool joints made from 150-ksi

material may provide the strength neces-sary for a specific application while provid-

ing greater ductility and toughness than

165-ksi material. Drillpipe with 15 to 30%

less weight and 10 to 25% less hydraulic-pressure loss than conventional drillpipe

can be manufactured from 165-ksi materi-al. The more efficient hydraulics impact

ERD hole cleaning, while the weight sav-

ings affect torque and drag. Both signifi-

cantly improve drilling efficiency.

High-Torque Tool Joints. Double-shoul-

dered and wedge-threaded tool joints are

available from multiple sources. Theseproducts offer two or more torque shoul-

ders in the same dimensional space whereAPI tool joints provide only one torque

shoulder. High-torque tool joints provide

higher-strength and -dimensional efficiencyand are better designs. These products rep-

resent mature technologies and should be

considered standards for ERD.

PURPOSE-BUILT

DRILLPIPE DESIGN

Design objectives and constraints for pur-

pose-built drillpipe must be established

initially. Design parameters used for opti-

mizing the dimensions of the pipe includethe following.

1. Maximum tool joint OD is limited to 7

in. to facilitate overshot fishing inside 95/8-

in. casing and 81/2-in. open hole.

2. Torsional strength must match that ofhigh-torque top-drive systems in low gear.

3. Collapse resistance must be approxi-

mately 8,000 psi to allow this shut-in pres-

sure below the blowout preventers with

24,000 ft of pipe in tension.4. Elevator bearing stress on the tool

joint is limited to 100 ksi at 500 tons max-

imum load.

5. Tension capacity must allow 20,000 ftof string weight plus 400,000 lbf overpull.

These five constraints cover the key

aspects of the drillpipes torque and tensile

capacities and handling requirements. The

objective is to maximize drillpipe OD and ID

to optimize the hydraulic carrying capacity ofthe string (i.e., provide the highest flow rates

at the lowest pressure loss). Condition 4

restricts the maximum OD of the pipe to

515/16 in., meaning that 53/4-, 57/8-, and 515/16-

in. sizes are feasible. As the pipe OD increas-

es (with a 7-in.-OD tool joint), the projected

area resting on the elevator becomes smallerand the stress exceeds 100 ksi. Table 1 in the

PURPOSE-BUILT DRILLPIPE FOR

EXTENDED-REACH DRILLING


39319, Purpose-Built Drillpipe for

Extended-Reach Drilling, by M.L.

Payne, SPE, Arco E&P Technology, and

E.I. Bailey, SPE, Stress Engineering

Services, originally presented at the

1998 IADC/SPE Drilling Conference,Dallas, 36 March.


7/15

MAY 1998 73


full-length paper shows the results of

drillpipe design calculations for 53/4-, 57/8-,

and 515/16-in.-OD pipe. Design calculations

reveal that the well-control constraint(Condition 3) is more restrictive than the

tension-design constraint (Condition 5) and

dictates the minimum wall thickness.

Because the wall thickness determines pipeweight as well as hydraulic efficiency for acertain OD, well-control scenarios should be

examined. For example, if the maximum

anticipated shut-in pressure is less than 5,300

psi, 53/4- x 0.324-in.-wall drillpipe would be

adequate. This pipe provides a 14% increasein flow area relative to standard 51/2-in.

drillpipe and would provide a substantial

improvement in flow rates for deep ERD hole

sections while reducing pipe weight by 5%.

This can be achieved by use of 140-ksi met-allurgy. Use of higher metallurgical-strength

materials would increase these percentages.

Additional Equipment. Pipe manufactur-

ers have agreed that production and appli-cation of 150-ksi-grade tubes does not pre-

sent any problems for 53/4-, 57/8-, and

515/16-in.-OD pipe. Tool joints will be

slightly longer than standard and have a

makeup torque of approximately 45 to 52

ft-kip. Handling equipment will have

crossover subs to fit proprietary connec-

tions on the drillpipe. Much of the equip-

ment on the drilling rig would not requireany modifications.

MANUFACTURING

CONSIDERATIONSDetailed drillpipe specifications were sent toa number of manufacturers to verify manu-

facturing viability and commercial feasibility

for purpose-built drillpipe. Yield strength

and detailed design of the tool joint were left

to the discretion of the manufacturer provid-ed that functional and dimensional specifi-

cations were met. On the basis of their

responses, the cost for these purpose-built

drillpipe products is competitive with thatfor standard drillpipe. Drillpipe lead times

are currently approximately 12 months,

including break-in, assembly, hardfacing,and coating. Timing should be considered in

long-range planning for major ERD projects.Informal discussions were held with rental-

tool companies concerning the purchase of

purpose-built ERD drillpipe. Purchase of

this equipment is viewed more favorably

when a number of operators and drillingcontractors express an interest in its rental.

SUMMARY

For conventional 20x133/8x95/8-in. ERD

well programs, currently available stan-

dard-size drillpipe is not optimal. Standard5-in. drillpipe is inadequate for ERD

because of hydraulic and torsional limita-

tions. Standard 51/2-in. drillpipe is margin-

ally adequate for some ERD but hashydraulic-pressure loss limitations in long,high-inclination-angle 121/4-in. sections.

Standard 65/8-in. drillpipe is overdesigned

structurally, dimensionally inefficient, and

cannot be used after 95/8-in. casing is set.

Study of important design parametersidentified purpose-built 53/4- or 57/8-in.

drillpipe as optimal drillstrings for ERD. Its

design is optimized by use of high-strength

metallurgy and specific design criteria for

handling, hydraulics, tension, torque, andcollapse. Use of existing 7x4-in. high-

torque tool joints for 51

/2-in. drillpipe per-mits the new ERD drillpipe to be manufac-




opsis has been taken has not been peer

reviewed.


8/15


74 MAY 1998

Drillpipe tool joints have been in use for

many years, but their pressure capacity hasnot been a major concern until recently. As

hydraulic horsepower increases, higher

drilling pressures are experienced. This

paper presents a theoretical approach to

this problem and verification of test resultsobtained in a laboratory. It is now possible

to predict pressure capacity of tool jointswhen selecting a drillstring for a well.

INTRODUCTION

Historically, wells have been drilled with

moderate-pressure hydraulics. Connection

leakage at these pressures usually was

attributed to face damage. When this

occurred, the operator tripped out of thehole, laid down the joint, and continued

drilling. As wells become deeper and

hydraulic horsepower increases, the old

methods cannot be relied on for well plan-

ning. Not only is cost an issue, but safetybecomes a critical factor at high pressures.

FORMULA DEVELOPMENT

Formulas used to calculate tensile and tor-

sional strengths are well documented inAmerican Petroleum Inst. (API) publica-

tions. One recent addition specifies meth-

ods for calculating the combined tensile

and torsional capacity for shouldered rotary

connections but does not include theeffects of internal pressure. Besides connec-

tion geometry and material properties,

influential variables include thread lubri-

cant, fluid type, and sealing-face conditionof the connection. Lubricants currentlyavailable range from the recommended

petroleum base with zinc solids to newer,

environmentally safe compounds. Thread

compounds are thought to have a minimal

effect on sealing capacity; therefore, theywere not evaluated.

Internal-Pressure Effects. The full-length

paper presents equations for the tensile

force in the pin connection and the com-

pressive force acting between the box andpin sealing shoulders. The authors then

incorporate a force caused by internal pres-sure and present equations for the pressure

required to initiate yielding of the pin con-

nection, the pressure equal to the face stressin the box, and the pressure that will cause

the box to fail as a result of hoop stress.

External forces simulating the hook load

are introduced into the equations for pres-sure required to initiate yielding of the pin

connection and pressure equal to face stress

in the box.

Failure Modes. There appear to be threeways that internal pressure causes the con-

nection to fail, resulting in leakage. The

first is when longitudinal force causes the

pin to yield. This occurs under high make-

up torque. The second is when makeup

torque is low, causing the box to leak whenthe internal pressure becomes equal to the

face stress in the box. The third occurs

when hoop stress causes the box to fail.

CALCULATIONS

A computer program was written thatsimultaneously solves the pressure equa-

tions for varying hook loads. The program

iterates on hook load with the tensilecapacity of the pipe as its upper limit. Fora constant hook load, pressure is incre-

mented until one of the failure modes is

reached. Failure pressures were calculated

for a NC38 tool joint with 211/16-in.-inner-

diameter (ID) drillpipe and 60,000-psi

makeup stress.

Verification of Results. Mathematical

results were verified by use of a new joint

of 31/2-in., 13.3-lbm/ft S-135 drillpipe and

an NC38 tool joint with a 43/4-in. outer

diameter (OD) and 211/16-in. ID. A60,000-psi makeup stress was applied.

End caps with 9-in. Acme-type threads

were welded to the end of the pipe. Thethreads were necessary for application of

a tensile load in the 500-ton load frame.

The pipe was placed in the load frame,

and water lines were connected to apply

pressure to the inside of the pipe. A rub-ber boot was glued around the junction

between the box and pin to collect anyleakage and convey it to a collection bot-

tle. Applied pressure was limited to20,000 psi so that drillpipe burst pressure

would not be exceeded. The test sequence

comprised the following.

1. Apply loads from 0 to 400,000 lbf in

100,000-lbf increments.2. Apply pressure.

3. Hold pressure for 5 minutes, then

bleed off pressure.

4. Increase load and repeat Steps 2 and 3.

Test results were as expected until a tensileload of 200,000 lbf was applied. When the

pressure reached approximately 18,500

psi, the digitized display indicated that

something was happening to the test pipe.Initially, it was thought that the connection

had failed, but there was no fluid to indi-

cate leakage. Examination revealed that

longitudinal force had caused the pipe to

yield. Yielding occurred in the weld area oneach end of the drillpipe where the tube

end caps were attached. The weld had

probably tempered the pipe locally, lower-

ing its yield strength.

CONCLUSIONS

1. The derived equations appear to offer

a conservative approach to the prediction ofpressure capacity of shouldered rotary con-

nections.

2. The effects of shoulder condition and

lubricants should be investigated.3. Pipe-burst pressures at high tensile

loads should be studied.





AN INVESTIGATION OF PRESSURE

CAPACITY OF SHOULDEREDROTARY CONNECTIONS


39324, An Investigation of Pressure

Capacity of Rotary Shouldered

Connections, by T.E. Winship, SPE,

Grant Prideco, and B. Vinson, SPE,

Sub-Surface Tools Inc., originally pre-

sented at the 1998 IADC/SPE DrillingConference, Dallas, 36 March.


9/15


76 MAY 1998

The objective of drillstring management is to

reduce drilling-project costs by reducing the

probability of downhole drilling-tool failure.

Drillstrings are not part of an operators corebusiness as they are for drilling contractors,

rental companies, inspection companies,

and repair facilities. However, in the absence

of a shared-risk or turnkey contract, the risk

of a drillstring failure is borne by the opera-tor. While even the most inexpensive failure

results in lost rig time, more severe failurescan junk the well. There is considerable

incentive for operators to manage their useof drillstrings by working productively

through tool and service providers whose

core business is drillstrings. Management of

drillstrings includes the following.

1. Understanding business drivers of thevarious suppliers to establish win-win

working agreements.

2. Assessing the technical requirements

and drilling risks of the drillstring application.

3. Assigning responsibility and account-ability for drillstring components to quali-

fied suppliers.

BACKGROUND

During the 1970s and 1980s, operators spent

significant engineering time optimizing cas-ing- and tubing-string designs, including met-

allurgy, heat treatment, and connection styles.

This was well-spent time because these tubu-

lar goods represent a large portion of the

expenditures on a well. However, drillstringshave not received similar attention from oper-

ators since the development of the current

American Petroleum Inst. (API) specifications

and recommended-practice documents. A rea-son for this may be that operators historicallyhave not been the owners of drillstrings, as is

the case with most casing and tubing.

Operators rented drillstrings for use when

needed either as part of a contract-drilling

package or as a stand-alone item. Because they

were rented equipment, drillstrings tradition-

ally have been the contractors responsibility.Drilling contractors and rental companies

have maintained servicable drillstrings to

stay in business. An average drilling rig has

approximately U.S. $1 million in drillstring

inventory. Typical day-rate contracts requirethe operator to pay any costs resulting from

drillstring failures and associated losses. The

drilling contractor is usually responsible formost downhole wear and any handling dam-age. The true costs incurred for drillstring

usage are often hidden within other costs.

SCOPE OF THE CHALLENGE

The assumption is made that, while opera-

tors want to mitigate the risk of drillstring

failure, they do not want to be in the drill-string business. Therefore, the success of the

drillstring-management effort depends on

business relationships that provide correct

incentives to all participants and the sharing

of various technical responsibilities.

Business Challenges. Imbalances in sup-

ply and demand for drilling rigs are driving

up day rates for all types of rigs, increasing

well costs. Higher well costs increase risk tothe operator, who therefore uses newer

drillstrings to reduce risk. As with many

drilling tools, demand for drillstrings

increases as drilling activity intensifies.

Inadequate production capacity in thesuppy chain causes much longer lead times

and higher costs for replacement strings.

The current inventory of drillstrings is the

result of a peak of drillpipe production in theearly 1980s followed by a dramatic slowing ofpurchases in the early 1990s. The age of some

of the most popular 5-in. drillpipe is more

than 9 years. It is clear that drillstring-invento-

ry replacement will be a major priority for thenext few years as this pipe continues to age.

The shortage of experienced drilling per-

sonnel and increased activity in remote and

logistically critical areas of the world pre-

sents a second series of business challenges.Exploratory wells consistently have more

lost time than development wells. This is

probably caused by less familiarity withexploratory drilling conditions, poor local

infrastructure, difficult logistics, and insuffi-

cient planning time. As exploration opera-tions continue to move into frontier regions,

lost time on an average development well

can be expected to double or triple because

of drillstring failures. Approximately 70% of

drillstring failures in exploratory wells and88% in development wells involve 30 hours

or less of lost rig time. This time is usually

spent on recovery activities ranging from a

simple round trip for a washout to a fishingjob where the fish is recovered on the first

attempt. A small percentage of drillstring

failures (approximately 4% for development

wells and 8% for exploratory wells) resulted

in more than 300 hours of lost rig time.

Technical Challenges. Many drilling opera-

tions use conventional API drillstrings in

applications on the frontiers of technology.

These applications include very-high-curva-

ture wells where the drillstring experiences

large torque-and-drag forces. The drillstring is

an integral part of the circulation, rate-of-pen-etration, and well-control drilling subsystems.

In todays drilling-team environments, how-

ever, specification of drillstring components

often extends no further than stabilizer place-

ment or bent-housing setting on the motor.Detailed string requirements are specified

from the top drive to the bit in only the rarest

of applications. Without these requirements

for comparison, whether the string suppliedby a prospective drilling contractor or rental

company has adequate capacity for the antic-

ipated loads in the well cannot be determined.

The majority of drilling tools placed in

drillstrings are used, meaning that the toolprobably has less capacity to handle loads

than when it was new. The string should be

demonstrably adequate for the project. Too

often, drillstrings are acquired as a part of

the rig equipment and are not designed tomeet the demands of the well. All drillstring

components should be specified, inspected,

and selected on the basis of the performance

properties required by the well.

ACTIONS

Current Inventory. The first step to protect

the current drillstring inventory is to designa drillstring on the basis of the well require-

DRILLSTRING MANAGEMENT TO

REDUCE DRILLING RISKS


39325, Drillstring Management To

Reduce Drilling Risks, by M.A.

Summers, SPE, PetrEX Intl. Inc., and

S.R. Crabtree, Technical and Quality

Solutions Inc., originally presented at

the 1998 IADC/SPE Drilling Con-ference, Dallas, 36 March.


10/15


ments. Sound design requires the considera-

tion of several drilling subsystems to find an

optimum configuration. This may include

modeling of torque and drag, casing wear,hydraulics, and hole-cleaning performance.

The result of the drillstring-design process is

a set of required string-component specifica-

tions, both mechanical and dimensional.An inspection program must be in place to

verify that these specifications are met. Recent

joint-industry efforts have produced a drill-

string design and inspection guideline that

allows design questions to be addressed effi-ciently and appropriate inspection programs

established quickly. A group of qualified ven-

dors is required to support the inspection and

verification program. An auditing process is

recommended for all vendors supplyingequipment or machining services.

Inventory Acquisition. Several mechanical,metallurgical, and dimensional attributes

must be specified when acquiring new API

drillstring components for future operations.Several components, such as heavyweight

drillpipe and stabilizers, have no governing

API specification. Manufacturing design

assumptions of these components may need

to be reviewed. API specifications adequate-ly address several of the most important

mechanical and dimensional properties for

normal drillpipe. However, certain proper-

ties for some grades might benefit from more

detailed specification by the purchaser.Material toughness is the mechanical

property that slows growth of fatigue cracks

and allows the material to sustain a larger

crack before it fails. Higher toughness values

in both drillpipe tube and bottomhole-assembly (BHA) component material can be

a very cost-effective investment in extending

fatigue life of these tools. API specifications

do not address alignment of the BHA boreexcept through verification of the bore with

a drift mandrel. The purchaser should verify

the amount of variation allowed by the man-

ufacturers specification for centralization ofthe bore and body-wall thickness. This pro-vides a more balanced BHA and reduces

drilling vibrations. Although stress-relief fea-

tures are optional, they are recommended to

reduce fatigue stresses in BHA connections.

CONCLUSIONS

1. Maintaining low drillstring-failure risk

can prove difficult because the controlling

functions are performed by several differentdisciplines working for different companies

over a long time frame.

2. Win-win relationships are indispens-

able in successful drillstring management.3. Average cost of drillstring failure is

greater in exploratory drilling than in

development-drilling projects.

4. Improving drillstring-inspection prac-

tices and handling during rig operation canhelp protect the drillstring components

currently in inventory.

5. Several cost-effective enhancements

can be made to drillstring-purchase speci-

fications to improve the performance ofthe tools.

r= radial clearance between bore-

hole and drillpipe, L, in.

Ub= total potential energy of bending,

mL2/t2, lbf-ft

u,v,s=curvilinear coordinatesw=unit weight of drillpipe, m/L, lbm/ft

x,y,z=Cartesian coordinates

=average inclination angle of a bore-

hole, degrees

=wavelength of a sinusoidal config-

uration or pitch of a helix, L, ft

=angular displacement of drillpipe,

radians=defined by Eq. 4

Subscripts

b=bending

h=helical

s= sinusoidal

REFERENCES

1. Dawson, R. and Paslay, P.R.: Drillpipe Buckling

in Inclined Holes,JPT(October 1984) 1734.

2. Miska, S. and Cunha, J.C.: An Analysis of

Helical Buckling of Tubulars Subjected to

Axial and Torsional Loading in Inclined

Wellbore, paper SPE 29460 presented at the

1995 SPE Production Operations Symposium,

Oklahoma City, Oklahoma, 24 April.

3. Mitchell, R. F.: Effects of Well Deviation on

Helical Buckling, paper SPE 29462 presented

at the 1995 SPE Production Operations Sym-

posium, Oklahoma City, Oklahoma, 24 April.

4. Miska, S. et al.: An Improved Analysis of

Axial Force Along Coiled Tubing in Inclined/




opsis has been taken has not been peer

reviewed.

ANALYSIS OF DRILLPIPE . . .(From Page 68)


Please read the full-length paper for addi-

tional detail, illustrations, and references.

The paper from which the synopsis hasbeen taken has not been peer reviewed.

Fig. 5CT-buckling patterns.

Hole Size, in.

AxialCompressiveLoad,

104lbf

MAY 1998 77


11/15


80 MAY 1998

The McElroy field comprises two distinct rod-

pumping applications. In one, artificial-lift

systems are operating beyond recommended

design ranges, pumping at high stroke perminute settings and substantial loads. Failures

caused by rod wear and corrosion are com-

mon and difficult to prevent in these high-vol-

ume, high-water-cut wells. Downtime from

failures is costly because of lost productionand well-servicing costs. Wells in the second

category, marginal producers, are subject torapid pumpoff, resulting in compression and

wear in the lower portion of the tubing androd strings. These wells usually are barely

profitable and cannot justify the cost of a well-

servicing rig or new tubing string. In both

cases, failure caused by corrosion or wear has

a substantial impact on operating cost. High-density-polyethylene (HDPE) -lined tubing

was installed in several candidate wells in an

effort to reduce well failure and operating

costs. Although HDPE-lined tubing is used

regularly to protect tubing in water-injection

wells from corrosion, it has limited applica-tion in rod-pumped wells. It was thought that

the liners would reduce friction between the

rods and tubing to reduce wear and that the

sealed system would reduce failures caused by

tubing-string corrosion.

HDPE-LINING PROCESS

Liners tested in rod-pumped production-tub-

ing strings are HDPE as defined by the PlasticPipe Inst.s Spec. PE 4308 that is identical to

material commonly used in polyethylene gas

and water lines. The liner is extruded to anouter diameter (OD) greater than the internal

diameter (ID) of the tubing to be lined. A

reduction machine mechanically reduces

the polyethylene tube to a smaller OD

through a set of rollers and feeds the reduced-OD liner into the tubing with approximately

8 in. extending beyond each end. The lined

tubing is stored on a rack for a minimum of

24 hours to allow the liner to expand against

the tubing wall. The ends are trimmed to a

specific length, and the excess liner materialis formed over the ends of the tubing pins by

use of an infrared oven and hydraulic mold.

In the initial field test, an HDPE insert sleeve

was placed between the pins to protect the

J section from corrosion. Additional field tri-als determined that the insert was unneces-

sary and it was eliminated. Corrosion

inhibitor is injected to protect the bare rodstrings and also protects the J section of the

POLYETHYLENE-LINED TUBING IN

ROD-PUMPED WELLS


39815, Polyethylene-Lined Tubing in

Rod-Pumped Wells, by E.C. Sirgo,

SPE, and E.D. Gibson, Chevron U.S.A.,

and W.E. Jackson, Western Falcon

Enterprises, originally presented at the

1998 SPE Permian Basin Oil and Gas

Recovery Conference, Midland, Texas,

2527 March.

Fig. 1Days in operation.

HDPE-Lined Tubing Bare Tubing


12/15

MAY 1998 81


tubing. Elimination of the internal insert

sleeve simplifies running the tubing string by

eliminating the need for a field technician

and improves well-service cycle times.

ARTIFICIAL-L IF T DESI GN

The reduction in tubing ID caused by the

liner requires modifications in the designand installation of downhole artificial-liftsystems. Originally, large-bore pumps were

installed in the 27/8-in. tubing to produce

high fluid rates. In some cases, stroke

length or strokes per minute were changed

to maintain production rates in thereduced tubing ID. In other cases, insert

pumps were replaced with tubing pumps.

In some cases, 31/2-in. lined tubing was

run instead of 27/8-in. because of its avail-

ability. Rod-pump designs had to be revisedbecause 1-in. American Petroleum Inst.

(API) rods could not be used in 27

/8-in.lined tubing because their 7/8-in. pins

required couplings that were too large. API

weight bars with a 11/2 in. diameter have a3/4-in. pin that can have a slimhole coupling.

FIELD INSTALLATION

AND HANDLING

HDPE-lined tubing is run in the same wayas normal tubing. Thread protectors should

be used to protect the ends of the tubing

from damage. Excessive wall loss caused

the tubing to split in two wells.

Specifications called for used tubing with atleast 50% of original wall thickness; but, in

these two cases, tubing with less than 20%

original wall thickness was not eliminated

in the quality-control process. In one well,

a 23/4-in. big-bore pump was installedinside 27/8-in. lined tubing to reducestrokes per minute and maintain the pre-

vious production rate. Excessive dis-

charge pressure from the pump caused

failure of a drain plug, and it was replacedwith a 13/4-in.-tubing pump.

PILOT RESULTS

HDPE-lined tubing has been installed in 17wells with the worst well-failure ratios in the

field. Production from these wells variedfrom 40 to 500 B/D. Used 27/8- and 31/2-in. J-

55 tubing was lined with HPDE and

installed in each well. Fig. 1 compares days

in operation of the artificial-lift systemsbefore and after installation of the lined tub-

ing. There have been no failures caused by

internal wear or corrosion of the tubing or

external wear on the rods. Average operation

time between failures increased from 93 to

373 days. Over a 12-month period, average

failure rate declined from 4.3 to .49 andoperating costs were reduced from U.S.

$1.78 to 0.79/bbl of oil. There have been sev-

eral pump failures, three corrosion-caused

rod failures, and one external-tubing-collarcorrosion failure since the pilot project

began. Because one unlined-internal-tubing

anchor failed because of wear, lined-tubing

anchors are now run in new installations.

In many cases, improvement in well-fail-ure rates might have been achieved by opti-

mization of the artificial-lift system without

installation of HDPE liners. However, it is

doubtful that such low failure rates could

have been achieved in such a short periodof time without them.

DYNAMOMETER ANALYSIS

The absolute roughness and coefficient of

friction of HDPE are lower than those of

steel. The decline in wear-related failures inthese wells may be the result of the lower

coefficient of friction. In the three wells thathad the same artificial-lift design before and

after installation of lined tubing, dyna-

mometer data indicated that peak polished-rod load was reduced by 2 to 9%, balanced

torque and its resulting gearbox loading

declined 1 to 10%, and bottom minimum

stress in the rod string declined 2 to 16%. Inthese three wells, the unlined 23/8-in. tubingwas replaced with HDPE-lined 27/8-in. tub-

ing. This increased tubing ID may have con-

tributed to a reduction in contact-surface

area and friction. A change in fluid charac-

teristics, specifically oil cut, could lightenthe fluid load and reduce peak polished-rod

load. The overall fluid load on the pump

increased in one well, declined in another,

and remained the same in the third.

CONCLUSIONS

1. HPDE-lined tubing extended the oper-

ation time between rod- and tubing-wear-

related failure by 400%.

2. Equipment performance proved thatused tubing could be run in marginal wells,

offsetting the capital cost of the liner.

3. Reduction in the coefficient of friction

between the rod string and the HDPE-linedtubing produced a measurable decline inpolished-rod loading, balanced torque and

its resulting gearbox loading, and bottom

minimum rod stress; it also reduced wear-

related failures.

4. Design considerations resulting fromreduced tubing ID can affect initial installa-

tion cost.






13/15


82 MAY 1998

Mineral growth, or scale deposition, in pro-

ducing wellbores is becoming a serious

problem in the oil industry with the

increase in water production from depletedreservoirs. Initial scale growth changes the

surface roughness of the production tubing,

increasing the pressure drop caused by fric-

tion and reducing the production rate.

Additional scale growth reduces the flowarea and can prevent tool access into lower

tubing sections.

CONVENTIONAL TREATMENT

Convention scale treatments depend on thetype of scale present. Soluble scales like calci-

um carbonate (CaCO3) can be dissolved with

hydrochloric acid even though this requires

use of inhibitors to prevent tubing damage

and careful cleanout of the well after treat-ment. If acid cannot be used in the well or if

the scale is insoluble, a positive-displacement

motor and mill, an impact hammer with a

mill, or pure-liquid jetting techniques are con-

ventional solutions for mechanical removal ofscale. Motor and mill sections must be able to

pass through the smallest restriction in the

well and are suitable only for cleaning

straight, unobstructed pipe.

JETTING PERFORMANCE

A study of jetting characteristics showed

considerable difference in jet-cutting perfor-

mance in tests conducted at atmospheric

backpressure and at downhole conditions.Jetting conditions, nozzle size, flow rate,

standoff, and pressure drop were the same

in both tests. In these tests, performed

underwater, the groove cut by the jet atatmospheric backpressure was approxi-mately four times deeper than the one cut at

downhole pressure conditions. At atmos-

pheric backpressure, bubbles caused by cav-

itation form in the jet and implode on the

target with considerable destructive force.

At downhole conditions, formation of thesecavitation bubbles is suppressed and the

erosive performance of the jet is reduced.

An experimental jetting facility was built

to simulate jetting under downhole condi-

tions to quantify the characteristics of waterand abrasive jets and to design a jetting sys-

tem. The facility is powered by a 1,000-hp

cement pump and is capable of testing full-sized rock samples and scaled production

tubing recovered from existing wellbores.

SCALE REMOVAL WITH

JETTING SYSTEMS

Tests on various forms of scale and on bari-

um sulfate demonstrated that cleaning the

tube with a pure-liquid jet without solventsis not effective. Fig. 1 shows tubing with

CaCO3 scale that was jetted with a single

water jet at a 2.4-in./min traverse rate. Some

of the scale was removed, but a considerable

amount remained in place. In a water-jettingsystem, if the jet is held stationary for a sig-

nificant length of time, the jet can break

behind the scale and peel large chunks of

scale away from the tubing surface. Particles

of this size are difficult to transport out ofthe well and can become trapped between

the tool and the wall of the well, preventing

the tool from being pulled out of the hole.

Slurries. An alternative to jetting with pureliquids is the use of abrasive-laden slurries,

with sand typically used in the slurry.

Addition of a small concentration of sand (1

vol%) has a significant effect on system per-

formance. Fig. 2 shows the results of using

a sand-laden slurry on tubing from the same

well as shown in Fig. 1. As before, the tra-verse speed was 2.4 in./min. The scale was

removed from the tubing. In the middle of

the test, the jet was held stationary for 3

minutes to evaluate steel damage, resulting

in a 0.19-in.-deep hole (80% of the wallthickness) being drilled in the tubing. This

demonstrates that the integrity of the tubingcan be destroyed if a tool becomes stuck

during a slurry-laden jetting operation.

ABRA SIVE SE LECTION

The interaction between the individual par-

ticles and the target surface was studied to

select an appropriate abrasive. A particle-

impact tester that can fire particles at speedsgreater than 450 miles/hr and impact the

target surface at angles from 30 to 90 was

built to study damage mechanisms. Tests

identified particle shape as a critical factor

because of the difference in failure mecha-nisms between ductile steel and brittle scale.

A sharp sand particle will erode the sub-

strate of a ductile material by a ploughing

action, while a round particle will bounce

off the surface creating a crater. Scaleexhibits brittle failure, where the impact of a

particle initiates fractures that result in sub-

strate failure independent of particle shape.

By use of rounded rather than sharp parti-cles, erosive performance is maintained and

damage to the steel is reduced but not elim-

inated. An approximately 0.027-in.-diameter

x-0.008-in.-deep crater was formed by

AN ABRASIVE JETTING

SCALE-REMOVAL SYSTEM


46026, An Abrasive Jetting Scale-

Removal System, by Ashley Johnson,

SPE, Schlumberger Cambridge

Research, and David Eslinger, SPE,

and Henrik Larsen, SPE, Dowell, origi-

nally presented at the 1998 SPE/ICoTA

Coiled Tubing Roundtable, Houston,1516 April.

Fig. 1Scaled tubing cleaned withwater jet.

Fig. 2Scaled tubing cleaned with asand-laden abrasive jet.


14/15

84 MAY 1998


impact of a single glass bead on a mild-steel

target. Repeated impacts of this type lead to

fatigue and failure of the steel surface. Fig. 3

shows the scaled tubing cleaned with a glass-bead slurry under the same conditions used

before. The scale is removed, but the 0.07-in.-deep hole drilled by the stationary jet still

represents a risk to tubing integrity.

Steel Damage. Steel damage caused by glass

beads is a result of the beads hardness being

significantly greater than that of the steel.

Reducing particle hardness will reduce steel

damage. A study was performed to determinethe effects on steel of beads with different

hardnesses. A stuck tool was simulated by

moving mild-steel targets under an abrasive-

laden jet, then holding the targets stationary.

For a stationary period of 100 seconds, theAbrasive A (Mohs hardness 7) jet drilled a

0.35-in.-deep hole, Abrasive B (Mohs hard-

ness 4) drilled a 0.19-in.-deep hole, and

Abrasive C (Mohs hardness 3) drilled a hole0.07 in. deep. Physical properties of an ideal

abrasive for removing scale from production

tubing while minimizing damage to the steel

were determined on the basis of this theoret-

ical and experimental study. A special abra-sive material was developed to enhance well-

bore-scale removal. Performance of beads

made from this material has been exception-al. Abrasive slurries containing beads made

from this material removed scale successfullyfrom scaled-tubing samples (Fig. 4). When

the impacting jet was held stationary for 3

minutes, only 0.004 in. of steel was removed.

JETTING SYSTEM

Abrasives development work paralleled thedevelopment of jetting tools. A new genera-

tion of jetting tools was developed with a

rotating head and speed-control system. A

tool-advancing system was developed that

allows weight to be set down on the bottom-hole assembly and advance only when the

tubing is clean, ensuring optimum system

performance. In addition, a software package

was developed to aid in design of a field job.

On the basis of well and treatment geometry,the software will recommend tool configura-

tion to optimize cleaning performance.

FIELD TEST

The first test of the system occurred in

November 1997. The well had suffered an

underground blowout, and a snubbing unitwas in place on the wellhead. The objective of

the job was removal of wellbore deposits to

facilitate the placement and setting of a cast-

iron bridge plug. Gauge-ring runs indicatedthat the drift inner diameter (ID) of the scaled

tubing was 11/4 in. and that the bridge plug

required an ID of 13/4 in. Mills, impact drills,

and a water-jetting system failed to remove

the scale. Conventional acid treatments for

scale removal were not considered because ofthe poor condition of the tubulars. The job

design was optimized by use of the newly

developed software. The small ID through the

scale deposits required use of a 13/16-in.-outer-

diameter jetting head, which required the useof a short string of 11/4-in. high-pressure

coiled tubing. Two high-pressure fluid pumpswere used to achieve a satisfactory fluid flow

rate and the required pressure differential

across the jetting nozzles. The jetting fluidwas formulated with beads from the new

material in an aqueous polymer solution.

The treatment cleaned the tubing at an

initial penetration rate of 30 to 60 ft/hr, as

predicted by the software. Following thetreatment, the client was able to set a pack-

er at the bottom of the cleaned production

tubing and pulled all 1,300 ft out of the

well. Fig. 5 shows a sample of the scaledtubing pulled from the well before jetting

operations and after cleaning. Visual exam-

ination of the tubing joints showed that

they were completely free of scale. The

plastic lining that originally coated the tub-ing was left almost completely intact, and

there was no damage to the steel.

CONCLUSIONS

1. A special abrasive material was devel-

oped to enhance scale removal.2. A new jetting system capable of clean-

ing the toughest scale from production tub-

ing without damage to the integrity of the

wellbore or use of solvents has been devel-oped and demonstrated.

3. Pure-liquid jetting systems are not

effective on scale when solvents cannot

be used.

4. Scale can be selectively eroded and

tubing integrity preserved by careful evalu-ation of steel, scale, and abrasive-bead

material properties.





Fig. 4Scaled tubing cleaned with anabrasive jet containing beads made fromthe new material.

Fig. 3Scaled tubing cleaned with anabrasive jet containing glass beads.

Fig. 5Scaled tubing recovered from well before and after cleaning.


15/15


Internal corrosion of pipelines carrying lift

gas for and production from gas-lifted wells

is a widespread phenomenon and can be

quite severe. Production of water fromwater-drive reservoirs combined with gas

and CO2 is the major cause of corrosion.

CO2 dissolved in saltwater forms an acidic

brine solution that attacks steel pipes. This

corrosive degradation of pipeline materialmay take the form of weight-loss corrosion

or embrittlement. The distinguishing featureof a system attacked by CO2 is heavy local-

ized pitting. High production rates in corro-

sive, high-water-cut wells accelerates corro-sion attack. CO2 and water form carbonic

acid, which interacts with iron to form

water-soluble iron bicarbonate and water-

insoluble iron carbonate corrosion products.

INFLUENCING FACTORS

Corrosion attack by wet, sweet gas is influ-

enced by the partial pressure of CO2, tem-

perature, flowing conditions, and metallur-

gical and surface conditions of the metal.Partial pressure of CO2 is used as a predic-

tor of corrosion in transmission lines. As

the partial pressure of CO2 rises the rate of

corrosion increases. As the fluid moves

from the wellbore to the wellhead, bothtemperature and pressure decrease.

Decreased temperature increases the solu-

bility of CO2, and decreased pressure

decreases its solubility. Once initiated, cor-

rosion rates accelerate under flowing con-ditions. Presence of fine sediments in the

gas stream destroys any protective film

formed by the corrosion process and accel-

erates corrosion on metal surfaces. Low-velocity production produces pitting. High-

velocity production with suspended solids

or gas bubbles causes erosion/corrosion.

High- and low-velocity areas are present inany flow system.

Two-phase flow in horizontal pipe

exhibits various flow patterns. Stratified

flow exists at low-gas- and -liquid-flow

rates, where liquid flows at the bottom ofthe pipe and gas flows at the top. Slug flow

occurs at high-gas-flow rates, where frothy

slugs of liquid move across the upper por-tion of the pipe with a wavy layer of liquid

at the bottom of the pipe between the slugs.At higher gas-flow rates with a low liquid

rate, mist or dispersed flow occurs.

TEST RESULTS

A gas-sample analysis indicated that feed

gas to the compression plant containsapproximately 2% CO2, which is reduced

to approximately 0.8% in the compressed

gas. The gas is not dehydrated in the com-

pression plant. Analysis of the water indi-

cates that it is acidic with low hardness,salinity, and dissolved solids. Water with

these properties can be very corrosive to

pipelines because it does not form a protec-

tive film on the pipe wall. Microbiological

examination of the water indicates thatgeneral aerobic-bacteria counts are low but

that a significant population of anaerobic

sulfate-reducing bacteria (SRB) is present.

The high-gas-flow rate does not form a

favorable environment for bacterial growth.However, bacteria can grow in the water

layer that moves at a slower rate at the bot-

tom of the pipeline. Water can also remain

stagnated in certain areas of the pipelinebecause of its geometry, and scale and other

deposits provide an ideal place for the SRB

population to grow. Analysis of corrosion

products deposited inside the pipeline con-

firmed the presence of iron carbonate.Sulfide deposits could not be confirmed.

Because the pipeline is not pigged, collec-

tion of fresh samples of deposits for analy-

sis was not possible.

FAILURE ANALYSIS

Visual inspection of a burst-pipeline sample

revealed that the external coating of thepipe was damaged in many places but that

the external surface was unaffected by cor-

rosion. The internal surface of the pipe was

heavily corroded. A large number of deep

pits were on the internal surface of the pipe,and pipe-wall thickness was reduced.

Compositional analysis of the pipe material

indicated that it conformed to American

Petroleum Inst. specifications. Microscopic

examination revealed no significant inclu-sions or stringers. These studies indicated

that the pipeline material conformed toaccepted standards and that the cause of

failure was internal corrosion that led tothinning of the pipe wall.

CORROSION CONTROL

Dehydration of the gas before compression

is the best way to control corrosion in the

pipeline but would require installation ofexpensive dehydrating columns. Use of an

appropriate corrosion inhibitor can also

control corrosion in the pipeline.

Oil-soluble, water-dispersible amines

have been found to be effective corrosioninhibitors for wet-gas corrosion. Amine

inhibitors are adsorbed on anodic- and

cathodic-metal surfaces by formation of

metal nitrogen bonds and coulombic

attraction between metal and ammoniumcations. In flowing gas streams with

entrained water, inhibitor films are not dis-

rupted at mass velocities up to 30 m/s.

However, high-velocity solid particles cantear away the film, as demonstrated by cor-

rosion/erosion damage at pipe turns and

elbows where solid particles impinge.

CONCLUSIONS

1. Injection of a film-forming amine

inhibitor is an effective method of corro-sion control for a compressed-gas transmis-

sion line.

2. The amine inhibitor should be sprayed

into the transmission line as a fine mist inthe same direction as the gas flow.





CORROSION FAILURE OF COMPRESSED-

NATURAL-GAS TRANSMISSION LINES


39536, Internal-Corrosion-Failure

Model of Compressed-Natural -Gas

Transmission Lines and Efficient

Mitigation Program, by A.K. Saxena,

V.K. Sharma, S.K. Chugh, S. Velchamy,

Ramesh Kumar, Ram Prakash, B.K.

Sharma, and R.S. Dinesh, Oil and

Natural Gas Corp. Ltd., originally pre-

sented at the 1998 SPE India Oil and

Gas Conference and Exhibition, NewDelhi, India, 79 April.

98may_tubularupdate

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