8/17/2019 SPE-26212-PA

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T

istinguished

uthor Series

Managing

Artificial

Lift

S.M. Bucaram

SPE,

nd J e Patterson SPE, Arco E P Technology

Summary

The goal of this work is to describe an ap

proach to produce a well for maximum prof

itability by managing artificial lift

effectively. Achieving maximum profitabil

ity

from an artificially lifted well begins with

selecting the lift method and continues with

selecting materials, protecting materials,

monitoring production data, and monitoring

equipment performance. Changes suggested

by the monitoring process strive to increase

the profitability on an individual well basis.

Introduction

Managing artificial lift is a continuous proc

ess designed to achieve maximum profita

bility from a producing or service well. We

must keep in mind our ultimate goals.

1 Maximum profits, not maximum

hydrocarbon production; one does not al

ways mean the other.

2. Maximum profits, not minimum equip

ment failures; again, one does not always

mean the other.

3. Maximum profit within the scope of

operating safely and in an environmentally

sound manner.

The purpose of this paper is to detail an

approach to managing artificial lift. This ap

proach is described as a series of steps.

Step 1

Original selection

of

the artificial

lift method.

Step 2 Evaluation of production factors

and expected production problems. This

evaluation results in the selection

of

the orig

inal equipment used in the well, the failure

control methods, and the monitoring deemed

necessary for protecting well equipment.

Step 3 Continuous monitoring

of

mean

ingful production data: rates, fluid levels,

water cuts, amp charts, pressures, etc.

Step

4

Continous monitoring of equip

ment performance data.

Step 5. Evaluation of the production

equipment-failure data regularly and as

needed.

This monitoring/evaluation results in

courses of action that

may

include operation-

Copyright 1994 Society of Petroleum Engineers

JPT

• April 1994

S

Mike

Bucciram is

a senior research adviser

t Arco E P Technology in Plano, TX. His

experience extends to artificial lift, production

problems,

equipment

failure control,

nd

cost

control. He previously worked t Arco Oil nd

Gas Co., Arco's Plano Laboratory, Sinclair

Research,

nd

Battelle Memorial Insf.,

nd

Bucaram Patterson following his gr du tion from Texas A M U.

with n MS degree in physics, served ~ h e f?culty there. Buc;aram

is

a

member of SPE's Editorial Review nd DistingUished Author Series

committees nd

is

a 1994-95 Distinguished Lecturer. John C .

Patterson is

n

engineering consultant

t

Arco

E P

Technology In

Plano. His experience extends to artificial lift p r o d u ~ i o n problems,

equipment failure control, nd cost control. He p ~ e v l o u s l y ~ ~ r k e d for

Arco Oil nd Gas Co. in engineering nd operation supervIsion

t

several locations nd for Arco Alaska. A

gr du te

of Texas A M U.,

Patterson holds a S

degree in

petroleum engineering.

al changes. Changes in the lift type might

be from rod pump to progressing cavity

pump or vice versa, from continuous to in

termittent gas lift, or from rod pump to elec

tric submersible pump ESP) or vice versa.

Equipment changes could include moving

from a bottom holddown to a top holddown

rod pump, from an insert to a tubing pump,

or from steel to fiberglass rods. Another

possible equipment change would be to add

or remove a gas separator on an ESP sys

tem. Alterations in the failure-protection

method might include changing from batch

to

continuous downhole corrosion treatment

or vice versa, starting a scale-control pro

gram, changing the pump metallurgy

or

the

ESP cable type, or running a cable with a

chemical treating string. A change in the

way the well

is

produced could be indicated,

such as increasing

or

decreasing the stroke

speed or changing the stroke length, rais

ing or lowering the pump, anchoring the tub

ing, using a variable-speed drive on an ESP

to reduce water production, or changing the

type of power fluid in a hydraulic pumping

installation.

Thus, the loop is closed; the evaluation

can, and sometimes does, take

us

back to

where

we

started-e.g. to artificial method

selection or, in some cases, to replacement/

substitution. If it is to achieve its goal of

maximum profitability, the process must

look at each well individually. Well-by-well

economics is the basis of the process.

Artificial·Lift

Selection

The selection

of

the lift method considers

the following.

Geographic location An offshore and/or

Arctic location can limit the viable lift

methods through size/weight restrictions or

environmental concerns.

Capital cost

These include not only the

lift equipment, but also the production facili

ties required to support the lift method e.g.,

compression requirements for gas lift).

Operating costs

These costs include the

energy needed to operate the lift and the cost

to repair lift-system failures.

Production flexibility

This means evalu

ating the minimum and maximum rates

available from the lift method based on nor

mal operating conditions compared with ex

pected production.

Reliability Reliability includes expected

run time and is a function of the failure fre

quency and the logistics required to repair

failures.

Normal operating conditions that should

be considered in the equipment selection are

the casing-size limitation, well depth, intake

capabilities minimum bottomhole produc-

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TABLE

1 ROD

PUMP SELECTION GUIDE

Depth Intermittent

Sand Scale

>7,000

ft

Pumping Corrosion

Rod pump traveling barrel

bottom hold down

. . . . .

X

Rod pump stationary barrel

bottom hold down x

. . . .

X

Rod pump stationary barrel top

hold down

. . .

X

. . .

Rod pump three tubes

. .

.

x

. .

X

Stroke through

. . . .

Tubing pump

. .

x

N

. .

Casing pump x x x

N

x

..-..- =

better; ..

=

good; x

=

not recommended; NA

=

not applicable.

ing pressure , prime-mover flexibility, sur

veillance, testing, and time cycle or pump

off controllers. Special well conditions

include corrosion/scale-handling ability,

crooked

or

deviated holes, dual-completion

applications, gas- and paraffin-handling abil

ity, slim-hole completions, solids/sand

handling ability, temperature limitations,

high-viscosity fluid handling, and high- and

low-volume lift capabilities.

1

Thus, the original selection

of

the opti-

mum artificial-lift method is a process of

balancing the artificial-lift capabilities and

constraints against the production rate with

the ultimate goal

of

maximizing ultimate

profits. Clegg et at 2 gave an excellent all

inclusive review

of

artificial-lift choices and

provided extensive references

on

all lift

types. The number

of

viable available-lift

methods depends on the situation. Many

choices may be available for a new field dis

covery for which constraints can be mini

mized by the production facilities and well

design. A new well in an existing field is

constrained by the existing infrastructure;

choices become limited. An existing well

has many fixed constraints that minimize lift

selection possibilities. Fewer choices exist

than for the other two cases.

The original field development plan

should address all known constraints and

consider future changes to the lift method.

During the life of a well, the constraints and

the production rates can change, making the

optimum artificial-lift method a function

of

current conditions. Lift-changing flexibili

ty comes at a cost that must be considered

and evaluated. The optimum artificial-lift

method

s

not the one with the greatest effi

ciency or the greatest rate; it

s

the one that

maximizes ultimate profitability.

Different operators making decisions on

the basis

of

what appear to be similar facts

often arrive at different conclusions. A real

life example

s

dewatering coal seams for

gas production in a field geographically situ

ated in the middle

of

a conventional gas

field. Most operators in the field use rod

pumps, others use progressing cavity pump

ing, and one uses gas lift.

Large

Low Fluid Low

Volumes

Level Gas

Speed

Paraffin

.

X

X

. .

. .

. . .

. . . . .

.

.

X X X X

.

x

. .

. .

N x

.

.

. .

N x

.

x

quipment Selection

After the lift method has been selected, the

specific well equipment and all its compo

nent parts are identified. Numerous selec

tions can be made for one type of lift, and

processes similar to those used to screen the

different lift methods are now used to select

the equipment and its components.

Example

1.

The decision has been made that

ESP's are the optimum choice. Bottornhole

temperature, whether and how much gas

s

produced, whether significant solids produc

tion

s

expected, whether a corrosion and/or

scale problem

s

expected, and whether rate

stability

s

expected will affect the selection

and sizing of the motor, the type

of

isolation

section and power cable chosen, whether a

gas separator

s

chosen, whether abrasion

resistant designs are installed, whether a

shroud

s

required to aid with motor cooling,

or a cable incorporating a chemical treating

string

s

chosen, and whether a variable

speed drive

s

part ofthe initial justification.

TABLE

2 CORROSION

AND EROSION-CONTROL CHOICES

Corrosion

Coating and Metallurgy and

Erosion

Chemical Chemical

Chemical

Equipment Inhibition Coatings

Inhibition Metallurgy Inhibition Metallurgy Coatings

Down hole pumps

Choice Choice First choice

Choice

Sucker rods First choice

Choice if CO 2

Rod-pump well

tubulars

First choice

First jOint

above pump

Wellheads pumping

tees and rod

blowout preventers

First choice

Submsersible-pumped

well tubulars Choice First choice

Water supply or

injection well

tubulars

Choice First choice

Gas gas-condensate

wells flowing oil

wells and gas-lift

well tubulars

Choice Choice First choice if within First choice if

Choice

coating range outside

coating range

Wellheads packers

mandrels

First choice if

Choice First choice if

within coating

outside

limitations coating

limitations

These are guidelines based on experience. A corrosive environment is assumed. Decision should be based on economics if more than orie choice is available. If coating is

chosen refer to RP1 on plastic coatings. If chemical inhibition is chosen refer to RP2 on chemical inhibitors.

336

April 1994 PT

8/17/2019 SPE-26212-PA

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lease

or unit name;

Equipment Performance Report: Subsurface

Tractor j

Soc\(:m

(16-18)

1 1 1

(3-4) (5-11)

T ]

;;;;;;;:I ---,---I--- -I-'---'------'

Lease Accountlr.g

Coda

(19-22)

Well j

(23--24)

oateIT]

Mo_

(25-26) (27-28)

T] T]

Day Yr.

Note:

Enter

code numbers

In IlqUllres

lbove

column

(no

code

number, Ieeve1lqUwes

blink) (ExpI n)

In squw.llibelled

Remerb

Type of well Type of service Failing

equipment

Type of IllIure

(34-35) (36-37) (38-39) (40--41)

[ J J [ J J

rn

[ J J

NON Noo.

OTH

Olhel NON None

NON None

01 FO

Flowmga.t

01

ACD Acidlzelstlmulate

01

PMP RodpulT"p

01

HOL

Ho.

02

FG Flowmggas _ I f '

02

PMH HydraullCpul'T"p,pislon

02

BRK

_

03 GL Gaslif1

02 FRC

Flac_II'

22 PMJ

Hydraulicpurfl),j81

03

STh Stuck

04

PMP Pu rfl)ing (Rod,

03 WWR

Welt NOrkover 03 ESP

Submersiblepurfl)

04

SPT Split or crack

Hyd PlstOO,

04

LTS

Test

-log

04

ROD Rod 05

PLG Plugged

(12·15)

Sob

1 1

E

Oepthoffailure n.feet I

r

m

nurrber

of JOints

from surface.

E

Locltion

of

failure

(42--43)

[ J J

NON None

01 BOY Body

02 PIN Pm

03 ClP Coupling

04

THO

Thread

05 UPS Upset

(29-33)

1 1

HydJet

06

ABA Abandon 05

ROP Rod failure, which caused

06

LEK leak, water in motor 21 UUP Upper upset or wrench tat

Submersible)

08

STM Slaamsoall

purrpdamage

15

WSH Washed 06 PLN Plunger

05

WI Water injection

09

PSI

Pressure survey 06 TBG Tubing 07 DEF

Worn, deformed or 07 SAL Barrel

06

GI Gas inJectIOn

10 INH

n h i b ~ _ 1 )

07

TBP Tubing failure. which caused collapsed

08 vas Valve, balls, seats

07 WS

Watmsupply

11 CAL

C a l ~ r w e l l

pUrfl)damage

08 UNS

Unscrewed 09 CUP Cups

08 WD

Wate/dlsposal

12

RES

Reslzingpuflll

08

CSG

Casing 13

COT

Plasllccoallng

10 PMP

Entllepurrpdamaged

09

PLL Plunger lift

10 PKR

Pad\er dISbandment

10

ROT

Rotary

11

BJT 8 astJOlnt 14 ELC Electrical

11

SEL Seal

31 JNF Jet nozzle (HYD)

"

51

Steam

12

PRD Polish rod or hnm 10 OTR

Othe/(explam)

32 JTH Jet throat (HYO)

InJ . dlOn • Note: If stimulating. please

(explamwhlCh)

COrrple1eSlimulatlonSectlOn 14 GLV

Gas hft vallie

14 ENG Engme end (H'fO)

15 PRE Production end (HYO)

(below). PI .asa record costs

16

MDR Mandnl 16 STY Standing valve (HYO)

21

SSV

SaletyvaNe

17 EAP Engine and production end (HYO)

23

PLL Plunger or

ca1cher

or

Slop

19 PPR pull rod

24

SNP Seatmgnlpple 20 PHD PUrTl> holdown

25

STV Standing valve 22 ESP PUfl \) end (ESP)

26

BHA Bottom holeassentlly. cavity

23 ESG Gasseparalor (ESP)

30 OTR

Other (explain) 24 ESS Seal section (ESP)

25 ESM Motor (ESP)

26 ESX Motol lead extenSIOO (ESP)

27 ESH

Pol head (ESP)

28 ESC Poy"er cabie (ESP)

- - - - - - - - - - - - - - - - - ~ - - - - ~ S t ~ ; m - u ~ l a ~ t i o - n ~ S : - . ~ c t ~ ; o ~ n ~ L 3 0 ~ O ~ T ~ H - ~ O l ~ ~ ~ . ' = . = ~ )

___________

_

-_._-------------  

,------

Cause of failure

MFG

n

(46--47)

Rea.on

(48)

CD

Fw

D

NON

None Not apphcable

"

WER

W.

"

AxelSon (rods)

Fmes/clays

02

ABR Abrasion, iUld Cut

02

UPCO(rods)

Mud damage

03

COR CorrOSion

D3

Continental

EMSCO(rods)

Scala

04

FAT

Fatigue

D4

Noms (rods)

Bacteria

05 SND Sand

DS

Ol well(rods)

EmulsIOn

06

MUD Mod

06

Tuboscopa (coatmg)

Paraffin

07

SeL

Gyp or scale

07 BTS (coatmg)

asphaHenes

08

PAR Paraflm

08 Spmcote(coatlng)

Wale/block

09

RUB Rubber (In thepul1ll

09

VETCO (coaling)

Waterroouction

10 M T Metal {In the pump)

Inillaloompletlon

12

IPA

Improper applICation

1D Reda(ESP)

orOlher (explain m

13 IPH

ImplOperhandling

11 Cenlfilift-Hughes (ESP)

remarks)

"

UNK Unknown

12 Oor(ESP)

15 CRH Crooked hole

13

Trico(ESP)

18

ELe Electfical.llghtntng

14

Saker - Lift (ESP)

17 OTR

Other (explain)

15

Other (ESP)

Cosl-dollarsonly(RoundcosttOfl€larastdollar)

(61

; ;S66)

(67 :; 73)

1 1 1 1 1 I I

1 I I 1 1 1 I 1

u ~ o n l y A1 equlpmentotherthanpurrps.

~ : r n y

(49)

D

BJ

Dowel

Hallibunon

B , ,

Western

ACid

Eng.

SERFCO

S m ~ h E n e r g y

OH19r (explain in

remarks)

If chemica stimulation

HCi.HF

HCI

AcetIC

BOa'

Solvent

150)

D

Scale Squeeze

Other (explamIn

remarks)

(74 311 SO)

1 1 1 1 1 1 1 1

All labor costs: Corrpany + Conlract +

Workovar+ Stimulation + Olher

Typo

Aad

(51)

D

HCI.HF

123%

HCIHF 615%

HCI.HF

6:05%

HCI 28%

HCI 20%

HCI 15%

HCI 10%

HCI

7.5%

Acetic

~ 5 2 - 5 6

LIllI]

~

II chem,cal Slim volume - Gals

II Frac

FracFluKlVol·Bbls

(57·60)

1 Frac' Frac Sand weight· M pounds

1 ;

5 10

15

20 25

35 40)

1 1 1 1 I I 1 I 1 1 1 1 I I I 1 1 1 I 1 I 1 1 1 I 1 I I 1 I 1 1 I 1 I 1 I 1 1 I 1

Remarl\s (left )usl IOO. Please print): For permanent record ellter information

In

remarks squares.

41 ; 45 50 55 60 70 80)

I I 1 I I I I I I I I I I 1 1 1 1 1 I I I I I I I I 1 I I 1 I I I I 1 I I I I I I

Remar Ks(contlnuatlOn)

1-5 10 15 20 25 35 40)

1 I 1 I I I 1 1 1 1 I 1 I 1 1 1 1 1 1 I I 1 1 1 I 1 1 1 I I I I 1 1 I 1 1 1 I I 1

RemarKs (conllnuatlon)

41 ; 45 50 55 60 65 70 75 80)

I I I I 1 I 1 1 1 I I 1 I 1 1 I 1 1 1 1 1 1 1 1 1 1 1 I 1 I I I I 1 I 1 I I I 1 I

RemarXs{contlnuallon)

Nurmer

01 ~ s .

Wei hI

Thread

Ctass

Mud anchor

Anchor

Catcher

Pad\er

AR3B·1162-R

Tubing

Fig. 1-Data input form.

JV f • April 1994

PMPsize

PMPtype

Gas

anchor

Rod Sizes

Nurrber

01 rods

Rod class

PUp

ROeM

Fl8ldrocords:

I I

I I

Signed

}

I

Well

Descriptor

Failure

Descriptor

Costs

Remarks

For Field

Record

Keeping

337

8/17/2019 SPE-26212-PA

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1

WELL FAILURE ANALYSIS

TO OATE: 11-92

IN ORO

WEST DISTRICT. DISTRICT CODE: WM. SUBDISTRICT CODE:3

MIDC

R

BY

DECREASING OF

FAILURES.

WEST MID IWO

LEASE & WELL t NUMBER OF FAILURES IN EACH

YEAR

TO DATE

12 ONTHS TO 11-91 -  12 MONTHS TO 11-92

LEASE & WELL t

ROD

ROO

PMP

OY

CPL PIN TOT TBG GL PMP__

BOY

o

o

o

o

o

o

2

CPL

PIN

TOT TBG GL*

Lease A 1 1 0 o 0 0 0 0 1 4806) o 0

O S

0) 0(

2

ROD

PMP

2 ROD

PMP

2 ROD PMP

3 RODPMP

3 ROD

PMP

2 ROD

PMP

2 ROD

PMP

6 ROD

PMP

6

ROD

PMP

2 SUB PMP

Lease A

3

0

o

0

0

0 0 1( 7659) o 0

O S

0)

O S 0-

LeaseB 1 1 0 o 0 0 0 0

1(

8888) o 0 O S

0)

O S

LeaseC 1 1 0

1 0 1 0 0 1(S 2188) o 0 O S 0) O S

LeaseD 1 1 0 o 0 0 0 0 1( 961) o 0 1 (S 0 1 (S

LeaseE 100 o 0 0 0 0 O S 0) o 0 2(S 0) 2(S

Lease F 01 0 0

o

0

0 0 0

O S

0) o 0 O S 3953) O S 0-

1 1 0

o

0 0 0 0 1 S 2S00)

1

3

o

3 0

O S

12449)

O S

LeaseG 1

0 0

2 0 2 0 0

O S

0)

o

0

3(S

2470)

1 S

1 0 0

0

...

u Ru . ~ . , u .... . ~ ~ ~ u . * * ~ 9 2 0 0 )

o

0 O S 0 0(

FOR 1992:

% PIN FAIL- 0 %

CPL FAIL-

33 %

ROD

END

FAIL- 33

FOR

1992 %

OF

TUBING FAILUR,ES

5)

WHICH

ARE

SPLITS( 4)= 80%

*

COST FOR GAS LIFT FAIL APPEARS

IN

PUMP COST SPACE.

Fig 2 Problem well report.

Example 2. Rod pumping has been chosen.

This opens a variety of selection opportu

nities. The pumping unit selection

is

based

on a compromise between the present and

expected producing requirements. Choices

must

be

made between conventional and

nonconventional geometries. Capital cost

must be considered. Tubing size is selected.

Should the tubing be anchored? The API rod

grade is selected as a function of load and

corrosive conditions. High-strength rods

could be needed. What about continuous

rods and fiberglass rods? Should rod cou

plings be standard

or

spray metal? The pump

should be selected along the lines

of

the in

formation in Table 1. 3

We could give other examples for hydrau

lic pumping (free pump or a closed system;

a field wide power-fluid system or a single

well system); progressing cavity pumping

(the type

of

drive to use; elastomer selection

for the stator); gas lift (tubing- or wireline

retrievable valves); etc.

Equipment Failure·Control

Selection

This step in the process

of

managing artifi

cial lift

is

best described by example.

Assume that rod pumping is the lift

method

of

choice. The choices available for

corrosion and erosion control for each of

these components (pump, tubing, rods, and

wellhead equipment) may be different (Ta

ble 2 .3 Similar choices can be made for

other lift

choices-e.

g., coatings for the ID

oftubulars for ESP and gas-lift installations.

Corrosion, scale, and paraffin control may

require treating either down the casingltub

ing annuli, through a treating string attached

to the outside of the tubing, by continuous

injection to the gas-lift gas in a gas-lifted

well,

or

by the power fluid in a hydraulic

or

jet pump system. The sooner the need is

identified, the sooner the choice for control

can be economically evaluated and im

plemented.

A candidate well for corrosion control by

materials selection is defined as a well (1)

with unacceptable equipment life owing to

corrosion and/or erosion where coatings

338

and/or chemical inhibition are not practical,

economical alternatives;

2)

where the risks

from a corrosion/erosion failure will affect

personnel safety or the environment; and

(3) where failure repair costs will be high

and/or lost production revenue will be ex

cessive.

Monitoring

Production

Producing conditions can and often do

change (sometimes rapidly), and monitoring

these changes

is essential. GOR changes and

increasing water cuts can drastically affect

the lift system performance. Any and all

production changes influence operating ef

ficiency and can lead to equiment failures.

For

example, increasing the water cuts in

a rod-pumped well increases the load on the

rods; an increased water cut also influences

the presence or absence

of

a scale-deposition

problem and the severity

of

a corrosion

problem. As the reservoir pressure de

creases and the production declines, the lift

equipment will be affected. Overproduction

of a rod-pumped well can result

in

pounding

and increased failures. Each criterion affects

how the well is produced and, in some cases,

can make a change in lift method eco

nomical.

Production monitoring

is

essential if

causes

of

equipment failures are to be cor

rectly identified and economic control of

these failures implemented. Our goal is not

to control all failures but to increase profit

ability.

Monitoring Equipment

Performance

In any attempt to optimize operations

through a failure-control program (failure

control in its simplest form is failure analysis

with the goal of applying corrective actions),

basic information is required to define the

nature and magnitude of the problem and to

estimate the economic stakes. Systems for

obtaining this information have the follow

ing goals in common: to determine the cause

of the equipment failure, to help set speci

fications for equipment, to predict future

performance of the equipment, and to fol-

low the economic impact

of

implemented ac

tion. Premature equiment failures are

usually the result

of

design deficiencies, im

proper material selection, manufacturing

deficiencies, errors in assembly, and/or

service conditions that were not considered

in design.

Minimizing equipment failures requires a

tracking system that identifies the failures

by type (rod, tubing, pump), location (pin,

body, barrel, plunger), cause (abrasion,

stuck, corrosion, split, plugged), and ap

proximate cost. One such system has been

in operation since 1969.

4

.

5

With this data

base, the failures can be trended to indicate

the overall performance with time. Trend

ing helps provide a comparison among

producing areas. Analysis of the data will

point out problems with the chemical treat

ment program; problems associated with a

specific equipment component, such as balls

and seats; whether the rod failures are body

or

end (pin

or

coupling); and whether the

tubing leak

is

the result of a corrosion

caused hole

or

a rod-wear-caused split. Peri

odic meetings to discuss problem wells

(those wells with excessive premature

failures) help provide guidance and en

courage failure control.

A successful failure-control program can

be summarized as follows. First, failure and/

or performance/activity data are collected

on a form like that in Fig.

1.

Then failure

data are reviewed continuously and dis

cussed periodically by a panel consisting

of

involved production and engineering person

nel, staff support engineering, and chemi

cal treating personnel, both company and

contract. The wells reviewed are those for

which the type and/or pattern

of

failure ex

ceeds certain criteria. These wells are known

as problem wells. The criteria that define

a problem well continually get tougher as

failure control is achieved.

For

example, a

problem well can be defined as one with a

failure performance.

1. A rod pump failure in less than 12

months.

2. A tubing failure in less than 12 months.

April 1994 • JPf

8/17/2019 SPE-26212-PA

5/6

FAILURE USTING

FOR

PERIOD

4-YRS PRIOR

THROUGH

TO-DATE

COST(

$ ONLY)

LABOR+MATS

TYPE

FAIL FAIL

TYPE LOC OF CAUSE OF PUMP

AlL

TOTAl

WELL

# 'WELL

DATE

*EQUIPMNT*DEPTH

FAILURE

*FAILURE *FAILURE ONLY

OTHER

*SERVICE COST

REMARKS

... M -3L..-_--'L ..

ASE::

A

1

PUMP

4-17-91 ROD

PMP

'WORN

*WEAR

972+

0+

1010- 1982

*CHANGE PUMP-RAN

ZXl 1/16X16

RHBS

3- 4-92 ROD PMP

3

PUMP 1-

2-91 ROD

PMP

7- 8-92 ROD

PMP

WO 3' PA PLUNGER

TD*STUCK SAND

942+

0+

3864-

4806*HAD

TO STRIP OUT RODS

AND

TBG-

WM-3

LEASE::

*lEAK

'BAlLSEAT'WEAR

TD*STUCK 'BAlLSEAT'SAND

...J l M : : . . i - 3 ' - - - - ' L ~ E A S E : :

A

502+ 0+ 1605- 2107

CLEANE 6788 TOTAl

FAILURE

COST

259+ 0+

7400-

7659*HAD TO CLEAN OUT SAND

9766

TOTAl

FAILURE

COST

B

1 PUMP-

11- 1-89 R0

1- 7- 91

12 - 3-91

PMP 669 3'STUCK

*PLUNGER

'SAND'

1205 0+ 1891- 3096*lOAD TBG

OK

ROD PMP *WORN

*PLUNGER

*CORRODED 934+ 0+ 1 52 8- 24 62 9 9

OTHER

6690 STUCK 'BODY*OTHERELE 456+ 1000+

25739-

27195*HADTOCUTOFFTBG-MiLLOUTTAC-

 7 28-92

RODPMP TD*STUCK*NONE *SAND

FISH TBG

777+ 3341 + 4470- 8888*HAD

TO REPLACE 165

3/4

RODS

(PUMP

ST 41641

TOTAl

FAILURE

COST

* 'A ot ,a ,••

•• ,., .

. . . . . . A

...........................

A

•

1 PUMP*12-14-90*NONE

*NONE

4- 16-91

ROD PMP

4- 6-

91

ROD

1000

6- 16-92

ROD

PMP

TO

Fig.

3-Four-year problem well history.

3. Two rod failures (pin, coupling, body)

in the last

2

months.

4. A combination

of

any three failures in

the last 2 months-e.g., a pump failure, a

polished-rod failure, and a rod break.

5. An ESP life

of

less than 24 months.

6. A hydraulic reciprocating pump life of

less than 4 months.

7. A jet pump life

of

less than 24 months.

8. Gas-lift equipment (valves, mandrels)

life

of

less than 24 months.

Use

of

Monitoring

Data

for

Making

Decisions

Production and equipment performance data

are required for decision making. Specifics

of the production, knowledge of the well op

eration, and failure data are required to

make sensible (economical) corrective de

cisions. Investigative engineering takes all

the monitoring data and determines the prob

able cause

of

failure (or

of

unsatisfactory

performance) and the best solution. For ex

ample, a particular beam-pump well

is

reportedly having rod breaks at the upset.

What is the problem? Is it manufacturing

defects or well operation? More information

is

required. The same problem

of

rod breaks

occurred with pumps from two different

manufacturers. The well was recently acid

ized, which increased the production and

necessitated a larger pump. Dynamometer

analysis on the well indicated that the rods

were operating at 110

%

to

5 %

above the

range

of

stress specified by the Goodman

diagram. The unit was a 228 with a 74-in.

stroke operating at 12.6 strokes/niin. Based

on that information, the best failure-control

solution would be to change to a larger unit,

redesign the rod string, increase the stroke

JPf • April 1994

: t i ~ ~

I

EASE::

*NONE

*NONE

STUCK

*PLUNGER

SAND

t;

0+ 0+

505+ 0+

0

947-

O*COMMINGLE CHESTER

AND

MORROW ZONES

INSTAlL TEST ART LIFT EQUIP

3-14-91

'WORN *COUPLlNG'WEAR

0+

7+

1373-

1452*CHAINGE PUMP-RAN

ZX1

1/16X16

RHBCW/

3' PA PLUNGER

1380*CHAINGE

OUT

1 7 8

SLIM

HOLE

COUPLING

2188*COUPLING

PULLED OFF PIN WHILE UNSEAT

5020

TOTAL FAILURE

COST

'WORN

'BARREL

*CORRODED 832+

25+

1331-

length, and slow down the well. However,

if all factors are considered, the most eco

nomical solution may be to reduce speed

(with its attendant loss in productivity)

or

live with the failures, rather than installing

a larger unit and/or redesigning the rod

string if a full-cycle economic analysis can

not justify the changes.

A successful failure-control program re

quires regular meetings at each field office

perhaps every 6 to

2 months-to

review the

performance

of

the problem wells. Each

problem well is reviewed, and the specifics

of

the installation, production, and failures

are discussed. The outcome is specific de

cisions to solve the problems economically.

Post-mortems of actions recommended in

the previous meeting are conducted, and

needed changes are identified, discussed,

and agreed upon. Examples

of

data

to

be re

viewed at such meetings are displayed in

Figs. 2 and 3.

In 1992, all projects involving engineer

ing staff were reviewed to assess need and

profitability. The value of the failure-control

project as a

tool to

optimize profitability

was

affirmed. A field production superintendent

described his view of the failure-control

program.

I know

of

nowhere else in the indus

try to obtain these services, either

through contractor

or

vendor. These

people serve

as

an excellent clearing

house for information on reliability

of

new products, etc. These people

have an excellent understanding of

the operational and mechanical side

of business. They communicate very

well with field personnel. These guys

are working on the kind of stuff we

all need to pay more attention to. This

is

where we make our

bread

and

butter money.

Training

and

Technology Transfer

Improvement is difficult without training.

Training on recognizing and solving prob

lems should be directed to company person

nel and well servicing crews. Data

monitoring serves as an indicator

of

when

training

is

required. For example,

if

the rod

end failures for a given property

or

produc

ing area exceed 30%

of

total rod failures,

a training session on equipment pulling and

handling (a care and handling seminar) is

scheduled.

6

API's recommended practices

provide excellent information and training

aids. Internal recommended practices

7

on

a variety

of

topics that target production op

erations can be developed. These documents

contain failure-control experience gained

over many years and provide practical

guidance to field engineering and production

personnel.

Like training, technology transfer is a re

quirement for improvement. New and better

materials and operating procedures are being

developed that can increase run time. New

and improved equipment is targeting such

problem areas as tubing and rod wear. Each

new method should be evaluated on its per

formance, including cost and run-time im

provement. Technology transfer is

also

information sharing. It

is

just as important

to share what has not worked as what has

worked.

Examples of new technology under trial

include the application and testing

of

vacuum

339

8/17/2019 SPE-26212-PA

6/6

TABLE 3 FAILURE CONTROL

PERFORMANCE

Type of Failure

Rods

Rod pumps

Tubing

ESP

All downhole failures

Equipment Life

(months)

1970 1988

20

20

60

15

12

75

40

100

48

33

deposition of noble-metal films on stuffing

box packing and polished rods (for friction

reduction) and on ESP stages and gas-lift

valves for scale control. Development and

testing

of

high-temperature materials for

composition ring plungers and for progress

ing cavity stator elastomers are also under

way.

Keeping Score

Results of the failure-control program de

scribed here can be summarized by a com

parison of failure-control rates for the years

1970 and 1988. (Since 1990, some proper

ties have been purchased and some let go.

Failure-control efforts have not slackened;

keeping company-wide score has.) Table 3

compares the mean time between failures for

1970 and 1988 and documents the improve

ment in average equiment life.

Conclusions

Managing artificial lift requires the follow

ing tools.

340

1. The information and experience nec

essary to select the optimum (ultimately the

most economical) lift system and the opti

mum components for that lift system.

2. Continuous production performance

monitoring.

3. A data-collection system that allows ef

forts to be focused on problem wells.

4. Periodic meetings to discuss these

problem wells.

5. A central contact who assists with the

meetings and provides continuity, informa

tion, and contacts from inside the company

and the industry.

6. Training for company pesonnel and for

contractors.

7. Continuous and repeated technology

transfer.

Producers have an obligation to achieve

maximum profitability (adequate revenues

from making oil are no longer accept

able). Efforts directed to achieve maximum

profitability benefit not only the producer

managing the program but also other com

panies with investments

in

the properties that

the producer operates.

cknowledgments

We thank Arco management for supporting

and encouraging this work. We also thank

all Arco personnel who contribute to and

participate in the Equipment Performance

and Failure Control System; improvements

to date are a result of their efforts.

References

I.

Neely, A.B. et al.: Selection

of

Artificial

Lift Methods, paper 10337 presented at the

1981

SPE Annual Technical Conference and

Exhibition, San Antonio, Oct. 4-7.

2. Clegg, J.D., Bucaram, S.M., and Hein, N.W.:

Recommmendations and Comparisons for

Artificial-Lift Methods Selection, JPT (Dec.

1993) 1128.

3. RP4 Metallurgical Selection for Corrosion and

Erosion Control Arco E&P Technology,

Plano, TX.

4. Bucaram, S.M. and Sullivan, J.H .: A Data

Gathering

and

Processing System To Optimize

Producing Operations, JPT (Feb.

1972 185.

5. Bucaram, S.M. and Yeary, B.J.:

A

Data

Gathering System To Optimize Producing Op

erations: A 14-Year Overview, JPT April

1987) 457.

6. Bucaram, S.M. , Byars, H.G. , and Kaplan, M.:

Selection, Handling and Protection of Down

hole Materials: A Practical Approach, Ma-

terials Protection and Performance (Sept.

1977) 12,

No.9,

20.

7.

RP I, Selection and Use

of

Internally Plastic

Coated Tubing Arco E&P Technology, Plano,

TX.

SI

Metric

Conversion

Factors

ft

x

3.048*

in. x 2.54*

'Conversion factor

is

exact.

E Ol

m

E+OO =

em

This paper is SPE 26212.

Distinguished

Author Series ar·

ticles are general, descriptive representations that summar-

ize the state of the art in an area of technology by describing

recent developments for readers who are not specialists in

the topics discussed. Written by individuals recognized as

experts in the area, these articles provide key references

to more definitive work and present specific detail s only to

illustrate the technology.

Purpose:

To inform the general

readership of recent advances in various areas of petrole-

um engineering. A softbound anthology, SPE Distinguished

Autho r Series: Dec. 1 981 Dec.

1983 is

available from SPE's

Book Order Dept.

April 1994 •

JPT