GUIDANCE DOCOMENT ON
MECHANICAL INTBSRITY TESTING
OF DDECTICN WELI£
epa amino ho.
68-01-5971
Submitted to:
Dr. Jentai Yang
Office o£ Drinking Water
Nr. David Zelnick
Contract Operations
Prepared for:
0. S. Environmental Protection Agency
Prepared by:
Geraghty & Miller, Inc.
April 30, 1982
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GUIDANCE DOCOMEKT CW
MECHANICAL IWTBSRnY TESTING
of mmmm mis
Em annuo no.
68-01-5971
Qthmifr+yri tO:
Dr. ."Umi-ai Vffry»
Off ice of Drinking Watec
Mr, Cavid Zelnick
Centxact Operations
Prepared feci
0. S. Environmental Protection agency
Prepared byt
Geraghty 6 Miller, inc.
April 30, 1382
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Ifryhrw p|r¥yyn*!!|tfis
Hiis report was prepared under Work Assignment No. 1 of EPA Contract No,
68-01-5971. Tbe Geraghty & Miller, Inc., task manager was Vincent P.
Pay, The principal authors were Paul G. Jakob and Vincent P. Any.
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TABLE OF CONTENTS
Page
I. INTRODUCTION 1
1. Purpose of This Document 1
2. The Weaning of Mechanical Integrity 1
3. Classification of Injection Wells 2
a) Class 1 2
b) Class II 2
c) Class III 2
i. Sulfur Mining Wells 3
ii. Salt Solution Wells 3
iii. In-Situ Leaching of Uranium 3
iv. In-Situ Leaching of Copper 4
v, In-Situ Combustion of Coal,
Oil Shale, and Tar Sands 4
vi. Geothermal Energy 4
d) Class IV 5
e) Class V 5
4. The. Distinction Among Tests Required in
Section 146.08 to Detect the Presence
and the Location of Leaks and Fluid
Movement 5
II. PRESSURE TESTS AND MONITORING OF ANNULUS PRESSURE 5
1. Applicability Related to Well Construction 5
2. Procedures and Interpretation 6
3. Costs for Pressure Tests and Monitoring 9
4. Typical Requirements of Selected States 10
III. GEOPHYSICAL LOGS REQUIRED IN THE UIC REGULATIONS 12
1. Noise Logs 13
a) Basic Principles and Presentation 13
b) Application 13
c) Interpretation 14
2. Temperature Logs 15
a) Basic Principles and Presentation 15
b) Application 16
c) interpretation 17
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-2-
Table of Contents
Page
IV. ADDITIONAL GEOPHYSICAL LOGS THAT MAY BE USED
FOR DETERMINING MECHANICAL INTEGRITY 18
1. Radioactive Tracer Logs 18
a) Basic Principles and Presentation 18
b) Application 19
c) Interpretation 20
2. Cement Bond Logs 20
a) Basic Principles and Presentation 20
b) Application 22
c) Interpretation 22
3. Caliper Logs 22
a) Basic Principles and Presentation 23
b) Application 23
c) Interpretation 23
4» Casing Condition Logs - The Thickness Log 24
a) Basic Principles and Presentation 24
b) Application 24
c) Interpretation 25
5. Casing Condition Logs - Pipe Analysis Log 25
a) Basic Principles and Presentation 25
b) Application 26
c) Interpretation 26
V. WELL RECORD EVIDENCE OF MECHANICAL INTEGRITY
FOR CLASS II INJECTION WELLS 28
VI. GENERAL CONSIDERATIONS 28
REFERENCES CITED 30
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TABLES AND FIGURES
Follows
Page
TABLE 1;
Applicability of Tests That May
Be Used for Mechanical Integrity
Verification
TABLE 2:
Procedure for Testing the Mechanical
Integrity of an Injection Well Having
Tubing and Packer
FIGURE Is
FIGURE 2;
FIGURE 3j
FIGURE 4;
FIGURE 5s
FIGURE 6:
FIGURE 7;
FIGURE 8j
Injection Well with a Leak Through
the Casing and Fluid Movement Through
a Vertical Channel 1
Class I Injection Wells 2
A Frasch Sulfur Well in Louisiana 3
A Salt Solution-Mining Well Showing
Multiple Casings and Cement , 3
Three Well Configurations Illustrating
the Three Modes of Pressure Testing#
and the Monitoring of the Annulus
Pressure 6
Exemplary Noise Log Display 14
Examples of Temperature Logs Showing
the Natural Geothermal Gradient and
Anomalies Caused By Flow Through a
Channel Behind the Well Casing 17
Radioactive Tracer Log Showing the
Detection of a Leak in the Casing
and Subsequent Fluid Movement in a
Channel Behind the Casing. 20
FIGURE 9:
Typical Cement Bond Log and VDL
Displays
21
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-2-
Tables and Figures
FollOWS
Page
FIGURE 10 s Typical Thickness Log Display 25
FIGURE 11; Comparison of Signals Produced
by Known Pipe Defects 26
FIGURE 12: Typical Display of the Pipe
Analysis Log 26
FIGURE 13s Typical Display of the Vertilog 27
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GOIDftNCE nTTWFJTT GN
MECHANICAL rWTSSRITY TESTING
of injection mm
I* ISDDRCDOCSnCM
1. Purpose of Hiis Document
The purpose of this document is to iiqpart to managers who are not
acquainted with the technical aspects of construction and operation of
injection wells, the knowledge to enable them to inplement the rules and
regulations in that section of the Underground Injection Control
Regulations regarding the mechanical integrity of injection wells.
Beginning with the definition of mechanical integrity as expressed in the
regulations, this document explains the theory and practice of the
various tests used in determining the mechanical integrity of an
injection well.
2. Ehe Meaning of Mechanical Integrity
Injection wells can convey fluids that any be regarded as
potentially detrimental to drinking-water quality. It is inportant to
assure that injected fluids do not contaminate ground water used for
drinking or having the potential for such use. Ibis assurance is gained
during the construction of an injection well by; (1) using well casings,
tubings, and packers that do not leak and, (2) by properly cementing the
araulus between the casing and formation, thus precluding the movement of
flnjffcr trftfwgh the «»n annulus. figure 1 illustrates pn^gnt-iai
threats. If a well does not have these defects, it is said to have
mechanical integrity.
Section 146.08 of the State Underground Injection Control Program
(40 CFR Part 146, Federal Register, Volume 45, No. 123, Jlsie 24 1980)
states that a well has mechanical integrity if: (1) there is no
significant leak in the casing, tubing, or padceri and (2) there is no
significant fluid movement into an underground source of drinking water
through vertical channels adjacent to the injection well bore. According
to Section 146.08, the absence of leaks mist be demonstrated by either
performing a pressure test with liquid or gas or by monitoring the
anmlus pressure. &saks or fluid movement that pertain to the second
criterion oust be demonstrated absent by a temperature or noise log. The
mechanical integrity of injection wells associated with oil and gas
production (Class III} may be danonstrated by well records indicating the
presence of adequate cement to prevent fluid movement in the well
aniulus. Exception to rules governing both types of leaks may be
authorized by the Adninistrator of the EPA.
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Geraghty & Miller, Inc.
•INJECTED FLUID
u
CONFINING ZONE
INJECTION ZONE
CEMENT
FORMATION
LEAK THROUGH
HOLE IN
CASING
CASING
CEMENT
FORMATION
FLUID
MOVEMENT
THROUGH
VERTICAL
CHANNEL
IN ANNULUS
Figure 1
INJECTION WELL WITH A LEAK THROUGH THE CASING
AND FLUID MOVEMENT THROUGH A VERTICAL CHANNEL
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2
3. Classification of Injection Wells
Section 146.05 defines five classes of injection wells on the basis
of use and the relationship of the injection tone to underground sources
of drinking mates. A definition of each class of well, and a description
of wells in Classes I, II, and HI with ezan^les of typical construction
are presented below.
a. Class Is Class I wells include: (1) wells used by generators of
hazardous wastes or owners or operators of hazardous waste
management to inject waste* other class IV
wells, and (2) other industrial and municipal disposal wells which
inject fluids beneath the lowermost formation containing drinking
water within one-quarter mile of the well.
Class 1 injection wells include basically two types, as illustrated
on Figure 2. fiat referred to as Type A is most common type
consisting of one or mare strings of grouted casing, tubing, and
packer. Type B, cannon to municipal injection well systems,
consists siiply of several strings of grouted casing and no taking
and packer.
b* u* class XI includes wells which inject fluids? (1) which
surface in connection with conventional oil or
natural gas production, (2) for enhanced recovery of oil or natural
gas, and (3) for storage of hydrocarbons which are liquids at
standard tmperature and pressure.
Wells in Class XI have no typical design; however, those recently
constructed are generally fitted with tubing and packer.
Construction characteristics vary according to function, depth,
location, age, and other factors.
c. Class HI: Class XXX wells are those that inject fluids in order to
extract minerals or energy, including but not limltpd to those for:
(1) mining of sulfur by the Frasch process, (2) solution mining of
minerals, (3) in-situ ccnbustion of fossil fuels, and (4) recovery
of geothezmal energy to produce electric power.
In 1980 there were approximately 7,830 Class XXX injection wells
that would be subject to DIE regulations. Of these, about 500 exist
for the purpose of sulfur recovery by solution mining, and 6,300 for
in-situ leaching for uranium recovery. Ttm remainder are used in
recovery of copper aid other metals as well as for geothermal
energy. Typical construction details of each type of well in Class
XXX are described below.
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Geraghty & Miller, Inc.
INJECTED FLUID
CASING
CEMENT
¦7- TUBING
r-4 INERT
FLUID
CONFINING ZONE
ROCKER
INJECTION ZONE
TYPE A
TYPE
MOST COMMON CLASS I
INJECTION WELL
MUNICIPAL WELL, INJECTING
NON-CORROSIVE WASTES
Figure 2
CLASS 1 INJECTION WELLS
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3
i. Sulfur Mining Wells
SUlfur contained in the lcwer part of the limestone cap rock
overlying salt domes or in bedded salt strata is mined by the Frasch
process in the Gulf Coast area of Texas and Louisiana and in west
Texas. In the Frasch process, injection of fluids and recovery of
rail fur take place in the same well. Figure 3 shows the design of a
sulfur well with canented casing that is used in parts of Louisiana.
High pressure frcm steam injection causes the sulfur to dissolve and
then rise in a snail-diameter inner casing, frcm which it is ptmped
to the surface by air lift.
In typical Frasch sulfur wells in Texas, an outer casing (8- or
10-incb-dianieter) is set into the top of the cap rock, and the
overlying formations are pezmitted to collapse around the uncemented
casing. The depth of the injection zone ranges frcm about 400 to
2100 feet. Six-inch casing, with two perforated zones near the
bottom, is set inside the outer casing to the base of the
sulfur-bearing cap rock. Hie upper perforations, for steam
injection, are separated frcm the lower perforations and frcm a
three-inch production casing by means of a packer.
ii. Salt Solution Wells
Solution mining of salt is accomplished by the injection of water
and recovery of brine through wells. Solution mining is practiced
to depths ranging frcm several hundred feet to about 10,000 feet.
Well designs are adapted to the particular salt body to be mined and
differ widely. In thick salt beds or in salt domes, injection and
withdrawal are commonly through single, multiple-cased wells (Figure
4), with injection into an inner casing and return flow through the
aniulus. The inner casing or tubing may be movable to permit
variable-point injection. Thin-bedded salt deposits in the
mid-continental and northeastern part of the country are canmonly
mined by the use of one or more separate injection and recovery
wells.
iii. In-Situ Leaching of Uranium
Uranium deposits suitable for mining by in-situ leaching are found
in sand and sandstone in Texas and to a lesser extent in wycming.
These deposits mist be belcw the water-table and in well-confined
strata. nran^mn is leached by the injection of dilute alkaline or
acid solutions (lixiviants), in combination with a chemical oxidant,
at depths from 300 to 2000 feet. Separate wells are used foe
extraction.
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Geraghty & Miller, Inc.
AIR IN
"~SULFUR SOLUTION OUT
WATER IN
* /
13-3/8" SURFACE CASINO
5301
8-5/8" CASINO
fr-
ill
Ul
u.
3-1/2" SULPHUR TUBINO
O
<
U.
IE
3
CO
3/4" AIR LINE (LIFT)
5 Z
O o
«j z.
Ul
A
OVERBURDEN /
X
K
SL
Ul
o
LEAD SEAL COLLAR
m
6-5/8" WATER LINER
11*1/2" HOLE
SULFUR ZONE
SEAT RING OR ROCKER
TOP OF
ANHYDRITE
2000",
Figure 3
A FRASCH SULFUR WELL IN LOUISIANA
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Geraghty & Miller, Inc.
uu
If
Ui
£ 1
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LU S#
7777777
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WATER IN
SWINE OUT
GAS IN AND OUT i
/ OVERBURDEN
/
^ 13-3/8" CASINO
V
7/
:\ SALT FORMATION
9-8/8" CASING
•-S/8" CASING
TOP OF CAVERN
T" CASING (Hanging String)
4-1/2" CASING (Hanging String)
Figur* 4
A SALT SOLUTION-MINING WELL
SHOWING MULTIPLE CASINGS AND CEMENT
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4
A typical «ell consists of a single-wall cemented casing and well
screen, slotted casing, or perforated pipe. He casing material nay
be FVCr steel, or fiberglass. Various patterns are used In the
spacing of injection and production wells, the function of which may
be reversed.
iv. In-Situ Leaching of Copper
to-sitn leaching of copper is practiced in igneous ore bodies, or in
worked-out mines where the ore is not of sufficient grade to be
extracted by conventional methods. A dilute sulfuric acid solution
or water is injected into the ore deposit through wells and the
leachate is recovered through other wells, nine workings, or other
openings. Much of the work to date is experimental and solution
mining of copper is not widely used.
No single construction method is used for boreholes that inject
coj^jer-leaching solutions. Where leaching solutions are introduced
into previously mined, caved, or blasted ore bodies, injection wells
ccranonly are shallow, cased or uncased boreholes into which the
fluids enter by gravity flow.
v. In-Situ Ccnbustion of Coal, Oil Shale, and Tar Sands
In-situ combustion of fossil fuels is presently being evaluated as
an environnentally preferable node of mineral extraction, but is not
developed beyond the experimental stage. Wells that mar? be used for
air injection, ignition, and/or recovery, are experimental In both
design and scale. It is not possible at this time to consider
topical injection well designs in this category.
vi. Geothennal Energy
The principal uses of injection wells associated with geothermal
facilities are to dispose of brines brought to the surface from
underground zones of high temperature and to dispose of brine and
condensates from generating plants. Hie only facility in the United
States presently producing electricity and utilizing injection wells
continuously is in northern California, where nine injection wells
return ana 11 amounts of condensate back to the producing formation
by gravity flow. The wells have multiple casing and cement seals.
Because of the early stage of development of geothennal resources
for electrical generation, there are no injection well designs in
this category that may be considered typical. Injection wells used
in the development of geothermal energy and not for electrical
generation, belong to Class V and are not considered here.
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5
d. Class 17: Class 17 wells are used by generators of hazardous waste
or of radioactive wastes, by owners or operators of twMTt^io waste
management facilities? or by oncers or operators of radioactive
waste disposal sites to dispose of hazardous wastes or radioactive
wastes into or above a formation which within one-quarter mile of
the well contains an underground source of drinking water. Nells of
tMs class are not addressed in this docunent.
e. Class ¥s Class V injection wells are those not specifically
included in Classes I, II, m, or IV. Some types of wells that
belong to this category are air-conditioning return-flow wells,
cesspools, drainage wells, recharge wells, salt-water intrusion
barrier weUs, sand back-fill wells, septic system wells, subsidence
control wells, wells used for hydrocarbon storage, geothermal wells
used in and aquaculture, and nuclear rHagrami weUs. "ftom
wells, like tdiose of Class 17, are not addressed in this document.
*• Tte Distinction among Tests Required in Section 146.08 to D
Thre*€ba&%t*£k smpvI #*)tA r/v^af"lAvi tsf* T^stlrcs anrt 91 hi 4 AfirKfflMkrii*
GJtKJ iwtjKS %¦ * Ja. jJWgSwHMfip J? XU*LWI I^KJVCPIIB#i*ii»
Pressure tests or the monitoring of amulus pressure can detect the
presence of i#ahis in ***> casing, tubing, or packer, but generally yield
no information on the location of such leaks unless specific zones are
isolated. ISie temperature log and noise log not only can detect the
presence of leaks, but *»">*»* fiiiiri movement ftfrpntigft vertical
adjacent to the well bore. Obey also can be used to locate sueii
failures. Iteae logs, however, cannot be used to distinguMi between a
leak and fluid movement behind the casing without a pressure test or
monitoring of anzulus pressure.
It is apparent from the foregoing that there are significant and
basic differences amount the types of tests and their results. In
addition to the required geophysical logs, there are many others that may
provide indications of various types of well failures. These include the
radioactive tracer, csnent bond, caliper, and casing condition logs.
These may be considered supplementary (to be employed when ambiguity
results from the required logs) or as alternatives to the required logs
if approved in writing by the EPA Administrator. A stannary of the
eqppiUcability of the required and other useful tests is presented as
T&ble 1. The characteristics of each test, its applicability,
interpretation, and limitations, are discussed belcw.
II. ERESSDRE TESTS AND M0NITORIN3 OF ANNDLOS PRESSURE
!• Applicability Related to Well Construction
Either a pressure test or monitoring of the amulus pressure may be
used to detect the presence of leaks in the casing, tubing, or packer of
an injection well. These tests are applicable to all types of casing,
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TABLE 1
APPLICABILITY OF TESTS THAT HAY BE USED FOR MECHANICAL
INTEGRITY VERIFICATION
CAUSE OF INJECTION WELL FAILURE
APPLICABILITY TO
TYPES OF CASING
TEST
LEAKS IN CASING,
TUBING OR PACKER
FLUID MOVEMENT
BEHIND CASING
PVC AND
METAL SIMILAR SYNTHETICS
Presence Location Presence Location
Pressure Test
yes
no (1)
no
no
yes
yes
Monitor Annulus Pressure
yes
no
no
no
yes
yes
Temperature Log
yes
yes
yes
yes
yes
yes
Noise Log
yes
yes
yes
yes
yes
yes
(2)
Radioactive Tracer Log (4)
yes
yes
yes
(5)
yes (5)
yes
yes
Cement Bond Log (4)
no (3)
no (3)
yes
(3)
yes (3)
yes
yes
(2)
Caliper Log (4)
no (3)
no (3)
no
(3)
no (3)
yes
yes
Casing Condition Log (4)
yes (3)
yes (3)
yes
(3)
yes C3>
yes
no
(1} can be "yes", if teat is staged
(2J log response may be somewhat dampened
(3) may indicate potential failure site
(4) may be used with approval of EPA Administrator
(5) only if access by tracer can be gained through the
casing or beneath casing shoe
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6
although consideration of casing strength may be necessary where FVC is
used, especially at higher tacperatures. The pressure test can be
conducted in three ways, depending on the well's construction details.
Monitoring of the amulus for change in pressure, however, is only
applicable to the well configuration having tubing and packer. The three
pressure test configurations and one monitoring configuration are
illustrated in Figure S - A, Bf aid C.
Configuration A, a cased and grouted well sealed at the bottom (by a
retrievable plug or packer) and teg, shows a test of the casing only.
Hie lack of a tubing or permanent packer precludes other pressure
testing. Likewise, the lack of an amxilus precludes pressure monitoring
as an alternative determinant of well integrity.
Configuration B, a cased and grouted well fitted with tiding and
pecker sod sealed at the top, dhows a test of the casing, tubing, and
packer. itrfs test cannot of the three components of
the well is leaking. Pressure monitoring of the annulus between the
tubing and casing could also be conducted as an alternative to pressure
testing.
Configuration C is a cased and grouted well fitted with tubing,
packer, and seating nipple, the presence of the seating nipple at the
base of the tubing allows pressure testing of the tubing exclusively, in
addition to the pressure test and pressure monitoring as possible in
Ccxifigration B.
2Pfn/*Ai*liirafi wpwi Trrb QiT>fii4»a4'4 aw
• ana UKCtyltCwatAOll
Both industry and regulatory agencies use and/or require pressure
tajg*Hnr» of the various iniection well ccoconents as a means of
determining the presence of leaks. Pressure tests are relatively-
inexpensive and easy to perform in both old and new injection wells? they
also produce results that are siaple and easy to interpret. For these
reasons, pressure testing of the casing, tubing, and packer is considered
the principal and most reliable means of determining mechanical
integrity.
Topically, pressure tests have been performed at pressures
equivalent to 125 percent of the design operating pressure for periods
that range from 5 to 30 minutes. Minings pressure-test criteria for well
integrity should be the maintenance of 125 percent of the peak operating
pressure for a period of 30 minutes. The well is determined to be sound
if the pressure stabilizes at a point equal to or greater than the peak
operating pressure and does not fall below that value. If the pressure
fai la below the peak value, the well is determined to be unsound? a
significant leak is considered to exist, and remedial, measures are taken.
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Geraghty & Miller, Inc.
We* With Casing,
Fitted With
Retrievable Plug
For Pressure Test
Well With Casing,
Tubing And Packer
Weft With Casing.
Tubing. Packer And
Seating Nipple
CASING
nf—CASING
DRILL PIPE
1
CEMENT
n
k CEMENT / ^
TEMP0RARY//
PACKER
INJECTION
ZONE
SEATING
NIPPLE
TEST CASING ONLY
TEST CASING. PACKER
AND TUBING
OR MONITOR THE ANNULUS
TEST TUBING ONLY
Figure 5
THREE WELL CONFIGURATIONS ILLUSTRATING
THE THREE MODES OF PRESSURE TESTING.
AND THE MONITORING OF THE ANNULUS PRESSURE
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7
Pressure-teat procedures are significantly different between
injection wells that are new or under construction and those that exist,
lest procedures are designed to take best advantage of the unique
features of each type of well.
In a new well, the inner casing is usually pressure tested after it
has been fwmtwfoH awl before f-awtng shoe is drilled out. At that
time, cement is present at bottom of the rag-ing so <-h*fc ~$>«» rawing i«
sealed. A seal at the top can be effected by using a blow-out preventer
or other easily adapted wellhead seal. Usually the pipe is filled with
fiiHH and pressure is *ppi using the rig FT (*i>9 p«ip*
usually can be utilized to supply pressures up to 1000 psi; for greater
pressures, cement puiping equipment is generally used) •
If the casing does not hold pressure in accordance with accepted
criteria, an atteapt to locate the leak using a noise log or temperature
log nay be used. Based on these findings, repairs to the casing may be
siaiie. If the casing hol& pressure, then the next tests for mechanical
integrity can be undertaken.
m an old well without tubing or packer, the botton of the inner
casing can be sealed with a retrievable plug (bridge plugs or packers are
used) prior to testing, such plugs are available to fit casings having
•yngjA* diameters trim 1.87 to 13.37 inches. for
pressure noted above can be utilized. Plugs should not be set in old or
corroded steel casings that may be prone to rupture. Casing condition
logs described below are useful in determining the competency of a casing
to withstand packer pressures. In the case of WC casings or those of
similar synthetics, a ccnparison between the rupture pressure of the
casing and the packer pressure should be made prior to testing to insure
that casing strength is not exceeded. lie tanperature should be
considered in this ccopudLsoiu
In old wells with tubing but no packer, the outside casing is tested
after the tubing b&B, pulled and a retrievable plug set. If
successful, the tubing is reinstalled and tested in the well. Usually,
the tubing is fitted with a seating nipple at the bottom. The tubing is
then sealed at the top and a pressure test is performed. Following a
successful test, the ball is "reversed out" and the well is ready for
service.
Both new and old wells with tubing and packer are tested by
pressurization. The most efficient step-wise procedure for testing such
a well is graphically described in Table 2. It is assuned in this
procedure that work by a geophysical logging service company is less
expensive than that of a service ccnpany capable of setting a retrievable
packer at the bottom of the casing. This would generally be true,
especially considering that geophysical logging services are required at
the well site in testing for fluid movement in vertical channels in the
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TABLE 2
PROCEDURE FOR TESTING THE MECHANICAL INTEGRITY
OF AN INJECTION WELL HAVING TUBING AND PACKER
STEP
NUMBER PROCEDURAL STEP
1 CHECK FOR LEAK IN CASING, TUBING, OR PACKER
2 Pressurize Annulus
3 Annulus Pressure Adequate? Yes, go to 20
4 CHECK FOR LEAK IN TUBING
5 Pressurize Tubing with Seating Nipple and Ball
6 Tubing Pressure Adequate? Yes, go to 10
7 LOCATE LEAK IN TUBING
8 Run Noise or Temperature Log in Tubing with
Pressurized Annulus
9 Fix Tubing Leak
10 CHECK FOR LEAK IN CASING OR PACKER
11 Pressurize Annulus
12 Annulus Pressure Adequate? Yes, go to 20
13 CHECK FOR LEAK IN CASING
14 Remove Tubing, Install Bridge Plug, Pressurize Casing
15 Casing Pressure Adequate? Yes, go to 19
16 LOCATE CASING LEAK
17 Run Noise.or Temperature Log with Pressure in Casing
13 Fix Casing Leak
19 Fix Packer
20 CHECK FOR FLUID MOVEMENT IN BOREHOLE ANNULUS
21 Run Noise and Temperature Log
22 Leak Detected? No, go to 24
23 Repair Fluid Movement Failure
24
MECHANICAL INTEGRITY CONFIRMED
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8
well bore, the second and mandatory test for mechanical integrity of
injection wells.
Pressure tests are generally conducted on the entire length of
casing or tubing, but nay be sta^d at vaious well depths if warranted.
Suspicion of two or more independent leaks at different depths nay
justify staged testing. Such testing has the potential to locate, in
addition to detect, a leak, in this procedure, a bridge plug and packer
are set on opposite sides of the suspected leak. This procedure is
ccoplicated and time consuming, but nay be considered in the event a leak
cannot be located because of constraints on geophysical logging.
In some instances, a reverse type of test is used to determine
casing integrity of a new or used well. In this test, fluid is removed
from the casing. This oust be done cautiously in order to prevent casing
collapse. For deep wells, the evacuation is staged using a bridge plug
and packer. The space between the plug and packer is evacuated and then
observed to determine whether or not fluid enters. This test is called a
dry test and will work only in those portions of the casing opposite
formations that are saturated with fluids and are somewhat permeable.
The alternative to the pressure test in the determining leaks is the
monitoring of anmlus pressure in the injection well. Hiis can be used
only on those wells constructed with tubing and packer. In this
arrangement, the pressure in the »»w«Ti ^ a)vniirj be held 10 psi above
atmospheric pressure and retained there. This pressure would then be
monitored by periodic checks or by continuous recording, along with the
injection pressure. A leak in the casing, tubing, or packer is indicated
by a change in the annulus pressure, either higher or lower. A leak in
the tubing or packer would probably result in a higher pressure due to
the transfer of the injection pressure. A leak in the casing, cxi the
other hand, would probably result in a lower pressure.
It is possible that monitoring of annulus pressure would not detect
the presence of a leak or leaks that nay be in equilibrium with the
pressure iqoosed on the annulus. To eliminate this possibility, it is
desirable to periodically vary the pressure applied to the annulus. In
effect, this procedure constitutes a long-term pressure test. By varying
the annulus pressure, the presence of leaks at equilibrium at any one
pressure will becane apparent. Pressure variations need not be more than
a few psi.
If the injected fluid varies significantly in temperature, either
seasonally or with another factor, fluctuations in the annulus presaire
may occur in response to thermal expansion or contraction of the fluid in
the anmlus. If this influence on the annulus pressure is excessive, it
may be necessary to monitor the tenperature of the injected fluid in
order to be sure that presaire changes are solely due to changes in the
tacperatnre and not due to leaks.
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9
3, Costa for Pressure Tests and Monitoring
Costs for pressure testing a well are directly related to its
construction, for a new well or an existing one equipped with tubing and
packer, the test is single and the cost is not high. In a new well, a
pressure test is performed cm the inner casing after it has been cemented
in place, ***3 before cement at bottom of th» ns»a^r*j
(fr-iiiori out. For pressure testing the <*-*«g rig, the
estimated cost is $400. If a cement punp is required, the cost is
estimated to be $800 to $1,200, depending on the time the equipment is on
A similar cost would be incurred in performing a pressure test on an
existing well equipped with a tubing and packer. Usually this can be
done by operating personnel, using their own or rental equipment.
Greater costs will be incurred performing a pressure test on a well
with no tubing or packer, or only tubing. In the case of a well with
tubing, a rig will hare to be used to pull the tubing and reset it. For
a well with no tubing or packer, a rig will be used to set and pull a
retrievable plug. In most cases, a workover rig rather than a standard
rig is employed, as it is designed gpeKri-firsii iy for tjygf* operations.
Determination of the cost of performing pressure tests with greater
accuracy than the estimates above is asplieated by the fact that a
"typical* well does not exist. Casing depths aid diameters vary, as do
the depths of the tubing settings. The condition of the well is often a
controlling factor in how long it takes to do a particular task.
Companies doing such work charge according to caoplicated schedules that
incorporate factors of time, distance to the well, standby charges,
working depths, and the size o£ the tools to be used. In the event the
eqolpoent most be used in a "hostile environment" (abnormal pressure,
high temperatures, or a corrosive fluid), additional charges are billed.
rffiaarni«ant-iv. Horsmoo of th* numerous variables would be considered,
it is impossible to arrive at a precise cost for pressure testing.
Sane idea of the range in costs for a pressure test is obtained by
setting up arbitrary examples assuming a range of well depths, distances
to the well, time required to pull tubing, set and remove a retrievable
plug, and reset the tubing. The following exanples assume a 300-mile
round trip to the well, well depths from 2,000 to 6,000 feet (80 percent
of injections wells are included in this depth range), rig time at $125
per hour, and mileage charges of $1.50 per mile. It also is assumed that
there are delays no greater than 8 hours (accounted as rig time) due to
unanicipated conditions such as site work to make the well more
accessible, problems in removing well-head equipment prior to entry, etc.
Costs due to lost production time, use of alterative waste disposal
facilities, in-house administration and engineering associated with any
testing are not included. The same assumptions are used to develop costs
for performing a test on a well with no tubing, but for which a rig is
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10
required. In this case, no rig time is needed foe pulling and resetting
tubing.
Costs for performing tests under the above assumptions are listed
belc*r (estimates are in teens of 1980 dollars and rounded to the nearest
$100).
Working Depth. r™a+a
ffaefcl
With Tubing &
Without Tubing
& Packer
2,000
$ 6,400
$ 5,600
3,000
$ 7,400
$ 6,000
4,000
$ 8,300
$ 6,400
5,000
$ 9,200
$ 6,900
6,000
$10,200
$ 7,400
The cost of continuous monitoring of the annulus pressure is for
instnamtation and personnel. A recording pressure gauge or water-level
recorder can vary in cost feom one to several thousands of dollars,
appending on the features. Personnel costs would depend upon the needed
frequency of naiirtenance and repair of the instrument. Because of the
high degree of yih ri 17i ^ y in the codLs associated with continuous
monitoring, no estimates are made.
The a>st of non-continous monitoring pressure in the anmlus between
the tubing and casing is almost exclusively for personnel. The oily
equipment cost is that of an accurate pressure gauge or aancmeter, which
should amount to less than $100. If, for example, it is assisted that a
weekly reading of the annulus pressure is made by an injection well
•operator,* and that it takes approximately 15 minutes to read and record
the pressure, the annual cost of monitoring will vary with employment
costs. If the total employment cost is $25/hair or $50/hour, the amxial
cost will be $325 or $650, respectively.
In practice, the measurement frequency of the annulus pressure will
depend on the operating schedule, the stability of the measured pressure,
tbe influence of temperature changes on pressure, and perhaps other
factors.
4. Typical Requirements of Selected States
The rules and regulations of the states with regard to minimal
standards in the performance of pressure tests and annulus monitoring are
highly variable. While most states recognize the need to test an
injection well for its mechanical integrity, they do not specif details
of the test. A common approach used by many states is to require the
well operator (permit applicant) to design and perform a pressure test
and to submit the pressure tests data to the regulatory agency, who then
reviews the data and renders a judgment on the integrity of the well.
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11
Other states make a judgment of well integrity based on the casing and
cementing program, as well as geologic and environnental criteria.
In contrast to pressure tests or annul n» monitoring as required and
specified for all claBBpfl of injection wells in Section 146.08, several
states require tests that apply to specific types of injection wells.
Oklahoma, for example, requires a pressure test on the casing of brine
disposal wells at 300 psi or the authorized operating pressure, whichever
is higher. Cta industrial disposal wells, where tubing and packer
construction is required, the annulus pressure must be at least 20 psi,
and monitored continuously. Tbe tubing in these wells oust be
independently tested to withstand the higher of 150 percent of operating
pressure or 300 pei. The state of Michigan also disHnguiBheB the type
of tests required for injection wells of different classes. Distinction
in pressure test requirements is made in California between "onshore" and
"offshore" injection wells, the offshore wells being more stringently
controlled.
Because pressure tests can be performed on the casing, tubing, or on
the well anmlus, and at various pressures for various durations, and
repeated with various frequencies, it is not surprising to find
considerably different standards among the states. Hie states of
Michigan and Oklahoma require pressure tests at pressures of 133 percent
and 150 percent (or 300 psi, whichever is higher) of the operating
pressure, respectively. The state of Florida requires pressure tests
conducted at 150 psi with no pressure loss on certain Class 1 wells. Cti
offshore wells, the state of California requires pressure tests at
specific minimim pressures for each casing string emplaned. Hrese
pressures depend upon the bottom depth of the casing. Host states that
require pressure tests do not specify the testing procedure.
The duration of pressure tests and minimim performance criteria also
are rarely specified by state regulatory agencies. The pressure during
tests as required on offshore wells in California for example, is not
allowed to decrease by more than 10 percent in 30 minutes. The duration
of a pressure test is one factor that regulators tend to leave to the
discretion of the injection well operator.
Pressure tests are required once and only once by the majority of the
states. Of those states that require more than one pressure test in the
useable life of a well, California requires a test of onshore wells every
six months, and Michigan requests tests biennially on brine production
(injection) wells. Again, there is no consensus of regulatory opinion.
Requirements for monitoring the annulus pressure do not vary as
widely as pressure test requirements. Monitoring of the annulus by
manual measurement in Class I wells is required with a weekly frequency
in Louisiana, while in Oklahoma and Texas continuous monitoring of the
annulus pressure is required. Continuous monitoring is optional to
pressure tests in several states. Such continuous monitoring involves
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12
the use of a recording pressure-measuring device, similar in concept to a
recording barometer.
flie pressure to be Jsposed on the well annilus during monitoring is
generally not specified in state regulations. Okie exception is Oklahoma,
which requires that a mlnitnim of 10 psi be constantly maintained on the
well annilus.
In summary, no consensus of philosophy or minimim requirements with
regard to pressure testing exists among the states. lypes of injection
wells and/or problems with injection wells that are peculiar to a
particular state have largely determined the rules and regulations a
State ***** iwplgwiafrt-ofl,
in. mmmm* hogs required hi we mc reeclaticns
Fran among many of geophysical logs available from the major service
companies, two are especially valuable in the detection and location of
leaks and behindH±e-casing fluid movement in injection wells. Hype are
the ravine log and Mm temperature log. Ror^ncua of frfwfr iTOrpo
abilities, one or the other of these logs is required in the test for
mechanical integrity as specified in Section 146,08. the cost of these
logs depends an the distance travelled by the service company, the type
of log, time on site due to delays, and the pricing schedule of a
particular ccnpany? thus, considerable variation in cost per logging
survey will result.
ftae geophysical logs described in this section and in section W are
applicable to the majority of injection wells. However, wells will
inevitably be «»mn»nfr«>pa«i* wwifain obstacles, snags, or other
potential hazards to the logging sonde. In order to protect the survey
sondes, it is general practice to check the well clearance with a
non-active and inexpensive "dummy." Also referred to as a sinker bar,
this is a sinple, smooth-surfaced, weighted bar having the approximate
dimensions of the survey sonde that is to follow. Successful lowering
and retrieval of the ddmy in the well adds assurance that the desired
survey(s) can be successfully performed.
Another pre-survey inspection of the well condition is the
televiewer, which yields a visual record of the well bore. Hie use of
the televiewer is usually reserved for a problems that cannot be
identified by other than visual means. Application of the televiewer is
limited to casing sizes 4 inches and greater.
In wells that cannot be logged because of configuration or size
constraints, there remains no option to testing the well by
pressurization. Testing for behind-the-casing fluid movement is thus
precluded.
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13
1. Noise Logs
was developed to detect and locate noise due to moving
gases and f1'H% and is therefore well milted for mariharnf-ai integrity
testing*
a. Basic Principles and Presentation
A noise logging tool detects sound energy created by the turbulent
flow of fluids moving through channels, leaks, or any fluid
constriction. Sound energy from a noise source is detected through
cement, casing, gas, aid borehole fluids, Sound is detected between
the frequencies of 200 and 6,000 Bz and converted to an electrical
signal. *flai logging tool or sonde is basically a sophisticated
microphone. lis resultant electrical signal is transmitted via
rmMo, to ssirfmem ^l#qtrpnic equipment where it is recorded.
Hie noise signal has a wave fas caifaosed of a rmnfcer of
-Frarpi
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14
scnewhat attenuated, as long as it is clearly discernible from the
background. Signal attenuation will occur in a well where tbe log
is taken inside tbe tubing or in a large-diameter well when
attempting detection of a befaind-the-casing leak.
Hie noise log is applicable in both steel and F9C casings, in steel
casing, sound energy is transmitted along the n«jngth more
readily than in PVC. PVC casing, on tbe other band, absorbs tbe
sound more than steel. Given a noise o£ equal intensity behind a
steel or &JC casing, tbe noise would be more intense, and present
oyer a longer casing length with steel casing. Tbe less intense
noise arriving through the fVC casing, however, would nevertheless
be detectable.
Significant nft,aB ran be detected in a ««Hiv» at a distance of
up to 200 feet above or below the source. Xn practice, it is
customary to make station stops at depth intervals of 25 to 50 feet
until a noise source is detected. In order to pinpoint the location
of a noise source, a station-stop interval of 1 or 2 feet is
appropriate. Unless a noise source is detected, noise logging can
be nearly as rapid as continuous types o£ logging. Because each
station stop requires about 3 minutes, however, stops that are 1 to
2 feet apart will obviously oonwmp considerable time.
c. Interpretation
For mechanical integrity testing, it is sufficient to consider the
noise log in its sinplest form—a trace of noise intensity vs depth
in tbe well. Interpretation in a steel or FTC casing is basically
the same except for tbe signal attentuation in tbe FWC well. Ike
amplitude of the noise log signal without further analysis of the
noise spectrum cannot distinguish the direction of fluid flow, the
rate of flow, nor cm it indicate Aether liquid or gas creates the
noise.
A typical noise log is illustrated in Figure 6. In this exanple,
fluid otters a channel behind tbe casing at a point opposite a
permeable bed, moves upward, and departs the channel as it enters
another permeable bed. Several important facts ace revealed in this
example. First, noise levels are greater than the background level
over the entire length of the channeled section where fluid is
moving. Second, the top and bottom peaks indicate the points of
fluid entry and departure. Hie flow direction could have been shotm
downward on the diagram and the log would have looked essentially
the same, third, the middle noise peak on the log, the result of a
constriction in the cement channel, could have been shown as another
point of entry or departure and the noise log would have ranained
tbe same.
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Geraghty & Miller, Inc.
CASING
CEMENT
LESS
PERMEABLE
FORMATION
CHANNEL
CONSTRICTION
CHANNEL
PHYSICAL CONDITION OF WELL
v NOISE
\ DETECTION
J
STATION
111
>
u
J
PEAK
u
»
(
0
z
peak
2
D
O
(
X.
o
4
^b-PCAK
'
NOISE LEVEL
(Millivolts)
NOISE LOG DISPLAY
Figure 6
EXEMPLARY NOISE LOG DISPLAY
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15
In canbination with other logs, the capability of the noise log is
enhanced. For exanple, the tenperature log may indicate the
direction of flow through the well bore after fluid movement is
first detected by the noise log. The direction of fluid movement,
however, may not be indicated by either log independently, The use
a£ more than one geophysical log is a very common technique that
should be used whenever eoonrarical ly possible to confirm a
diagnosis.
2. Tenperature Logs
Temperature logs are among the oldest of all geophysical surveys and
are in widespread use. Along with the noise log, the tenperature log is
one of the optional tests used to confirm the absence of fluid movement
in vertical in the well bore. It fllso has high utility in
locating leaks through casing or tubing.
a. Basic Principles and Presentation
The tenperature log is basically a record of the tenperature and its
variation with depth in a well. A temperature sensor is lowered
into a fluid-filled well on a wire line. Hie device that measures
temperature is a thermistor, which emits an electrical signal that
is proportional to its temperature, this signal is relayed to the
surface where it is represented cm a strip chart that moves in the
direct on of increasing depth below the surface, the taiperature log
has an accuracy of at least 0.5 degrees Fr and nay be as great as
0.01 degrees F. The operating range is generally from 0 F to 350 F.
It has become < mum mi to run a differential tenperature log
simultaneously with the temperature log. This log is a record of
the difference in tenperature between two thermistors separated at a
measured distance on the sensor probe. In essence, it serves to
highlight those zones in the well where the tenperature is changing
rapidly as indicated by the tenperature gradient. Both the
tenperature and the differential tenperature are recorded and
presented in the same fashion, and most commonly side by side on the
aamft chart.
Tenperature variations detected in wells are both natural and
artificial. The manner in which the tenperature departs from
natural background tenperature yields a diagnosis of well conditions
including fluid movanent behind the casing. The temperature of the
earth increases with depth below the surface at a rate of
approximately 1 degree F per 100 feet (the geotfaenaal gradient) •
There are many exceptions to this generality, especially in the
upper hundred feet or so where ground water circulates and
tenperatures may be influenced by seasonal variations. lfce
temperature at a depth of about 100 feet is generally about 3
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16
degrees F greater than the men annual air temperature at any
location. Below this, the temperature rises in atpccaimately linear
fashion with depth. Variations in temperature due to natural
are usually quite gentle and follow smooth trends. In contrast to
natural trends, teaperature changes due to well characteristics are
likely to be abrupt, and therefore Ai f ngn< ahahi » T
b. Application
Tenperature logs may be run on fluid-filled casings as small as
two-inches in diameter, and are feasible in any class of injection
well. Wella of a particular design in any class, however, may
present similar problems to the application of tbe temperature log.
A well fitted with tubing and packer, for example, requires the
removal of the tubing in carder to properly detect or locate fluid
movement behind the casing. ttis is because tenperature anomalies
may not be transmitted through tbe Mrn.1j.ta and tubing, itemperature
irrj« are applicable in antf "pjc casings. w*^a>iiaw> of frfre
laser heat conductivity of F9C, however, thermal anomalies
transmitted tuning would be somewhat diminished.
For tbe purpose of detecting and locating fluid movement behind tbe
casing, tanperature logs should be taken aider conditions of thermal
stability. A tenperature log of a flowing well will reflect the
temperature of title flowing fluid in the entire cased interval,
making detection of a relatively minor tenperature difference
impossible. In such a well the probe and wireline would have to be
placed in the well and log ran through a device known as a
stripper head or lubricator in order to step any flow and prevent
spina.
Another well condition that must be avoided is that of a recently
cemented well, where tenperatures will reflect the heat of hydration
of the caient. This heat is sufficient to mask the minor
differences sought in the temperature log test. Many days may be
necessary for the heat of hydration to dissipate in the vicinity of
a well. The time required will, of course, vary with well
dimensions. If the temperature of a well is measured before
cementing, it then becomes a siaple matter to wait for the well
tenperature to return to near this point after cementing, in carder
to run an acceptable temperature log.
Hie diameter of tbe well is yet another factor that can control the
efficacy of the temperature log. The degree of correlation between
tbe temperature log and the taperature at or behind the casing is
reduced in a large-diameter well (greater than 12-inch-diameter) due
to the thermal, attenuation that occurs between the source of the
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17
ancnaXy and the logging probe. Tbe temperature log of a
large-diameter bole also may reflect an inverted temperature
relationship wberein the warmer fluid near the bottom of the well
baa migrated tcxiards the top due to its relatively greater bouyancy.
c. Interpretation
fluid leaks and mcvauent in channels behind the casing will display
characteristic signatures on temperature logs. Typical temperature
logs are shown in Figure 7-A, B, and C. Exanple k shows an
idealized geotbermal gradient that typifies a tanperature log in a
stable well without behind-the-casing fluid movement. Example B
shows, superimposed on gradient, an anomaly in
temperature to the downward movement of flirt fiT fh* rUvmrmi
coiyfrictB relatively cooler to lower level ~•Him &
low-teBperature bulge in tN? nnrmai gradient. RganpT** c ********
ttfforf tilwVW IlfURffi IWWHIIOn^ ftf nancofl a
y|^A/B4i>e cUkJucswv vnMs&,\2 iiitr u^rku.u juuwvoubuw vj» !» aijam msulumsd a
higb-tenperature bulge in the nonnal gradient.
Departure of a terperature log from the geothezmal gradient may be
due to ray reasons other thm leaks or fluid movement behind the
casing. As allndprt to above, the geotbermal gradient is a general
concept; in reality, the gradient may deviate as a function of
various subtle factors. Several of these factors that are most
likely to be encountered include the heat associated with volcanic
rocks (intrusives), variations in heat conductivity of geologic
formations, and the flow of ground water, m order to understand
how these influences to the anrerage gradient may be manifest in a
well, mhstTfflflal information on the geology of the subject area is
essential. For example, is the area known to be influenced by
geologically-recent volcanic activity? Are there significant
differences between the beat conductivity of adjacent geologic
strata? Do significant aquifers exist in the borehole interval?
What is the ground-water flow path, and does ground water gain or
lose heat to identifiable geologic features? Do ground-water
convection cells exist in the aquifer? Xhe answers to these
questions may provide the key to tenperature log interpretation.
Within the context of the above, interpretation of a temperature log
as a mechanical integrity test must address the relative size and
vertical height of a thermal ananaly. If the accuracy of the log is
0.1 degrees F, the average geotheraal gradient would have to be
disturbed in an interval of at least 10 feet in the vertical
direction in order for a thermal anomaly to appear. A mininumally
detectable ananaly would thus indicate behind-the-*casing flew
through m interval of 10 feet or greater. Anomalies caused by
fluid movement from one to mother are likely to be considerably
greater to vertical height, dose to the land surface (<100 ft),
seasonal effects and rapid groundwater circulation may
significantly alter the geotbermal gradient making it unsuitable as
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Geraghty & Miller, Inc.
INCREASING
TEMPERATURE
FLUID
ENTRY
TO THE
CHANNEL
FLUID
EXIT
EXAMPLE A
FLUID
EXIT
FROM THE
CHANNEL
EXAMPLE 9
FLUID
'ENTRY
EXAMPLE C
NATURAL GEOTHERMAL
GRADIENT AS
IN A STABLE WELL
TEMPERATURE ANOMALY
SUPERIMPOSED ON CEO-
THERMAL GRADIENT
INDICATIVE OF DOWNWARD
FLOW THROUGH A CHANNEL
BEHIND THE WELL CASINO
TEMPERATURE ANOMALY
SUPERIMPOSED ON GEO-
THERMAL GRADIENT
INDICATIVE OF UPWARO
FLOW THROUGH A CHANNEL
BEHINDTHE WELL CASING
Figure 7
EXAMPLES OF TEMPERATURE LOGS SHOWING THE NATURAL
GEOTHERMAL GRADIENT AND ANOMALIES CAUSED SY
FLOW THROUGH A CHANNEL BEHIND THE WELL CASING
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18
a standard background for the detection of a anomaly. For
this reason and others r the average geothermal gradient «hr»vid not
be considered the only acceptable standard background for the
detecton of a thermal anomaly. in reality, any deviation in
tenperature from an otherwise smooth trend in tenperature should be
suspect as indicative of undesirable fluid movement or a leak, if
available, temperature logs run before well completion can be used
to establish a background reference* As in the case of the noise
log, temperature logs should be interpreted with the aid of other
geophysical logs to eliminate ambiguities.
17. ADDITIONAL GEOPHYSICAL LOGS THAT MAY BE OSED FOR DETERMINING
MECHANICAL INTEGRITY
Aside from the noise log and temperature log, many other geophysical
logs have the ability to indirectly indicate problems with the casing and
cement grout of an injection well. These logs may be used as
supplementary to the required log or as alternatives. For use as
alternatives, they require the written approval of the EPA Adninistrator
(such approval will be published in the Federal Register and may be used
in all states unless restricted by the Adninistrator). Several or all of
these logs may be run while the logging service ooopany is on-site for
the required log.
1* Radioactive Tracer Logs
Radioactive tracer logs can be used to determine the travel path of
fluids wherever a anall quantity of radioactive material can be injected
into the flow stream, lie potential of the radioactive tracer log for
confirming the mechanical integrity of an injection well lies in its
ability to trace the movement of fluid behind the casing.
a. Basic Principles and Presentation
The radioactive tracer survey consists of making a comparison of two
gamma ray logs, one run before and one after the injection of a
small quantity of radioactive tracer material. Following the first
gamma ray log that establishes the background reference, the
injection is made in the well in the vicinity of where a leak or
fluid movenent is suspected to exist, so that the tracer material is
taken into the flow stream at the leak. The second gamma ray log is
then taken and the path followed by the tracer through the leak is
described by higher than background gamma radiation on the log. Die
superposition of the before and after gamma ray logs is the
radioactive tracer log.
The probe or sonde used in making the radioactive tracer log
consists of a tracer ejector and one or more gamma ray detectors.
There is usually substantial flexibility in the physical arrangement
of components in the probe assembly. A radioactive tracer
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19
material haying a very short half life is injected into the well,
tubing, or casing, in small quantities of about 0.1 ml each. Even
with this small amount of tracer fluid, there is usually a
FaihBt-antiftl contrast in gam* radiation intensity between the
natural background source and the injected tracer source. The
tracer most commonly used is Iodine 131 which has a half life of
8.04 days.
The method of tracer log presentation is the straight-forward
superposition of gamma ray logs with the radiation intensity
expressed in cycles per second or API units. The two log traces are
usually distinguished on the chart by the type of line used (solid,
dashed, or dotted).
b. Application
Tbe radioactive tracer log has application in all injection-well
classes, in rwinig mafpHaia and designs, in pgr? having
diameters of 2 inches and greater. Hie method of application,
however, differs according to the nature of the suspected leak and
the well design.
In the case of injection wells with no tubing, the radioactive
tracer log can be used to trace the movement of fluid through a leak
at any point in the casing, or beneath the bottom of the casing and
into channels in the cement of the well bore. Following the first,
or background gamma ray log, a dose of tracer material is ejected
near the suspected leak. After an appropriate period for the tracer
to enter the leak, the casing should be flushed and another gamma
ray log run to detect the remnant tracer material behind the casing.
Additional gamma ray logs can be run periodically to observe the
movement of the tracer with time.
A similar procedure can be used to detect leaks in the tubing of an
injection well. In the case where fluid movement exists in a
channel behind a leakless casing, however, there is no way to eject
the tracer material into the stream of fluid to trace its movement.
In this case, the radioactive tracer log is not applicable except
for testing the adequacy of the cement at and imoediately above the
casing shoe.
Tire operating limits of the radioactive tracer log are defined by
the detectability of the tracer material. Hie detect ability is a
function of the radioactive strength and the amount of tracer, the
flow rate through a leak and the contrast between the injected
radiation and the natural background radiation. Except for the
tracer dosage, these factors cannot be controlled.
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20
c. Interpretation
The interpretation of the radioactive tracer log involves the
comparison of gamna ray logs taken before and after the introduction
of tracer material (Figure 8). if the well is flushed after the
injection of the tracer, thai an increased gamna radiation shown in
the second log would indicate the point of a leak. Well flushing
would not be necessary if enough time were allowed after the
injection of the tracer and before the second gamma log, so that all
the tracer could have migrated through the leak. An ancmaly that
persists in an unflusbed well and the absence of an ancmaly in a
flushed well indicate the absence of a leak.
An anomaly may exist at a single point (depth) and indicate
horizontal migration of the tracer away from the well, or an ananaly
may spread over a range in depth and indicate vertical movement of
the tracer and the presence of a channel behind the casing. The
interpretation of a radioactive tracer log, like other logs, should
be tendered with clues frcm all possible sources, especially other
geophysical logs.
2. Cement Bond Logs
The cement bond log was developed specifically to determine the
condition of cement behind the casings. It is applicable in wells having
diameters of 2 inches and greater. By itself, it does not indicate
whether fluid movement occurs, but it does indicate if the potential for
fluid movement exists (i.e. the absence of cement or the presence of
channeled cement). Another survey that also determines the condition of
the cement behind the casing is coranonly run simultaneously to the canent
bond log. This complementary survey is nailed the 3D Velocity Log by the
Birdwell Division, the Acoustic Signature Log by Dresser Atlas, the
Variable Density Log (VEL) by Schlumberger Well Services, and the
Microseianogran by Welex. The following describes both the cement bond
log and the VEL (choice of this name inplies no preference).
a. Basic Principles and Presentation
The principles of the cement bond log and VEL logs offered by the
various companies are essentially the same. The logging sonde is
equipped with a trananitter and two receivers. The receivers are
set at different spacings; one is utilized for the cement bond log,
and the other for the VDL. The transmitter emits a signal with a
ringing frequency of 20 to 25 kHz (kilohertz) that is radiated in
all directions. tool is centralized within the bore hole and
run on a wire line; a continuous record is made.
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Geraghty & Miller, Incs
INCREASING
GAMMA RADIATION
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GAMMA RAY LOG
TAKEN BEFORE
INFECTION
GAMMA RAY LOG
TAKEN AFTER
INJECTION
• CEMENT
-CASING
.CASING
LEAK
— FLUID
MOVEMENT
IN CHANNEL
RADIOACTIVE TRACER UOG
WELL DIAGRAM
Flgur« 8
RADIOACTIVE TRACER LOG
THE DETECTION OF A LEAK IN
AND SUBSEQUENT FLUID MOVEMENT
IN A CHANNEL BEHIND THE CASING
SHOWING
THE CASING
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21
The cement bond log receiver, which is usually set three feet from
the transmitter, detects and measures the amplitude of the first
arrival of the sound energy. In effect, this logging method depends
on ti» difference between the energy loos of a sound pulse traveling
through casing that is standing free (no bond) in the hole, and the
energy loss of a pulse travelling through casing that is firmly
bonded to a hard material of a low sonic velocity, such as cement.
The sound pulse will travel through free casing with very little
attentuation, whereas the sonic pulse loses energy continuously to
the client sheath and a large signal attentuation results when the
cement is firmly bonded to the casing.
By recording the amplitude of the first arrival, it is possible to
locate points in the cemented section where the bond may not be
adequate and a potential for fluid movement exists. Laboratory
experiments have shown that the signal attentuation in cenented pipe
is proportional to the percentage of the casing circumference that
is bonded with cement, and that a decrease in attentuation to less
than 70 to 80 percent of the maximim value may indicate cementing
problems.
The VOL log, when used in conjunction with the cement bond log, can
provide additional information on the quality of the canent. The
VEL receiver on the sonde is usually set 5 feet from the
trananitter. Basically, the VOL log is a photographic display of
the arrival of the sonic signal as produced on a special
oscilloscope. The photographic record of a VOL log appears as a
series of alternating light and dark bands representing variations
in positive and negative signals. A continuous record of the wave
train is made as the logging tool is raised or lowered in the bore
hole.
A typical presentation of a cement bond log and a VEL is shewn on
Figure 9. These logs were taken in a bore hole in which known
portions were cemented and uncemented (the uncemented portion was
gravel packed). The uncemented part is shown by a high amplitude
signal on the cement bond log display (no signal loss to the
formation), whereas the cemented portion of the casing is indicated
by the low amplitude of the signal.
The VOL display indicates both the condition of the casing-cement
bond and the formation acoustical coupling. The earliest arrivals
shown on the VOL display indicate the condition of the casing-cement
bond and lend verification to the cement bond log. later arrivals
indicate the condition of the acoustical coupling of the cement and
the formation. If the cement is well-coupled to both the casing and
the formation, the later arrivals on the VEL are indicative of the
formation characteristics as the sound energy penetrates deeply.
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Geraghty & Miller, Inc.
Increasing Increasing
Signal Transit
Amplitude
CBL LOG VOL LOG
Figure 9
TYPICAL CEMENT BOND LOG AND VDL DISPLAYS
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22
The VOL display (Figure 9) shews a characteristic, strong, "free
pipe" signal which gives the appearance of the undistorted
alternating light and dark bands. In this zone, no signal strength
is lost to the formation, accounting for the rather sharply
VOL display.
In suunaxy, the cemented portion of the casing is characterized by
the lew amplitude signal on the cement bond log, the weak almost
inriistinqnifihahle pipe signal on the VDL, and the wavy, and
irregular formation signal on the VDL.
b. Application
The cement bond log yd VOL have application in determining
mechanical integrity in any injection well that has a cemented
casing. Wtells with tubing, however, can only be surveyed after the
removal of the tubing. In FTC casings, results of the cement bond
log are somewhat compromised because of signal attenuation. This
can be at least partially overcome by comparing the log response of
a canented interval with an interval known to be free of cement.
Anomalous signals that appear in the cemented interval and show
similar characteristics as the uncemented interval, indicate
suspected locations of poor bonding. This testing technique, to the
extent possible, should be implemented on all casing types. The
condition and extent of cement bonding behind the casing are strong
indicators of the mechanical integrity of a well. However, these
logs only indicate the presence or absence of an adequate bond, and
do not detect fluid movement.
c. Interpretation
Hie interpretation of the cement bond log and VDL is described
above. This description is sufficient in the majority of cases
where well integrity is being tested. There are, however, several
aditional interpretive problems (such as distinguishing a
micorannulus frcm channeling), that require a more detailed
knowledge of these logs aid probably further tests. These problems
are unusual and not considered essential to understanding the basic
use of these logs.
3. Caliper Logs
The Caliper Log is a straight-forward record of the borehole or
casing as it varies with depth. The application of the caliper
log as a tool to determine the mechanical integrity of a well is made
only for the detection of the most exaggerated distortion in the diameter
of a casing. Although the caliper log cannot detect leaks or fluid
movement behind the casing, these problems may occur sometimes in
association with a distorted casing.
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23
a. Basic Principles and Presentation
The production of a caliper log entails the lowering of the caliper
probe to the bottom of the borehole, releasing the detector arms,
and raising the probe in the borehole to produce a record of the
variation of borehole diameter with depth. The probe consists of a
central shaft fitted with three or more hinged aims that fold
against springs into the side of the shaft when fully retracted. As
the probe is pulled upward in the borehole the detector arms extend
where the borehole has a large diameter and retract at locations
having a snail diameter. The movements of the arms are converted to
an electrical signal that is transmitted to the surface and recorded
on a plot showing the average borehole diameter versus the depth.
The borehole or casing diameter is usually calibrated and recorded
in units of inches.
Oil iper probes having four or six detector arms are available that
enable the determination of the shape of the borehole cross-section.
This is useful in mechanical integrity testing# as the shape of a
distorted casing cross-section has a significant bearing on the
determination of the degree and possible cause of casing damage.
b. Application
He caliper log, like other logs, is not Umit-pd or less applicable
to any one injection well class. It is equally applicable in steel
and FVC casings. Well construction, however, does make a
difference. Tttoing wells must have the tubing removed before the
casing can be logged.
The operating range of a caliper tool is commonly from 4 to 24
inches, with an accuracy over this range of 1/4 inch. Wells being
tested for mechanical integrity would seldom have dimensions outside
these limits. Tools capable of measuring diameters up to 60 inches
are available.
c. Interpretation
The caliper log is interpreted in a straight-forward manner. The
average well diameter measured at any depth is the diameter
displayed on the strip chart. A six-arm caliper log will be
represented by four traces on the log. One trace represents the
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24
average diameter of the casing borehole. The remaining three traces
indicate the diameter of eada of three pairs of am. Thus,
fH f-fortanrwt in CrOSS-SeCtiOnal ly>rrihr>1[» chap* be
determined.
4. Casing rraH-jjHrm Logs — t*h rimcaB Log
Recxjgnizing that corrosion and its effect on the mechanical
integrity of a well is an ijiportant factor in the economic production of
hydrocarbons, geophysical logging companies have developed logs to
determine the condition of well casings. Tm distinct principles of
detection are aqployed in those logs. For convenience sake they will be
referred to as the thickness log and the pipe analysis log, although the
names vary with each logging ccnpany. These logs are applicable to wells
having steel casings and tubings and are indirectly indicative of the
mechanical integrity.
a. Basic Principles and Presentation
The thickness log, also referred to as a magnelog, employes a sonde
on a niilti—conductor wireline and surface electronic circuitry to
detect and amplify the signal and reproduce it in conventional log
form. The casing thickness is evaluated by measuring the phase
shift of a low-frequency alternating current signal emitted by a
transmitter coil and detected by a receiver coil spaced at a fixed
distance from the transmitter in the sonde.
The transmitter coil sets up a magnetic field inside of the casing,
in the casing itself, and outside of the casing. The receiver coil
is spaced so that it intercepts only the lines of magnetic flux that
pass outside of the casing. Because the lines of flux must pass
through the casing at two places, the phase of the induced current
in the receiver coil leads that of the transmitter. The flux lines
pass through the casing more or less perpendicular to the casing
wall. Consequently, pipe thickness affects the phase shift, with
the TOnrimmi phase shift (for a given section of pipe) being where
the wall thickness is the greatest. The log, therefore, takes
advantage of this relationship to give an indication of the
condition of the casing by using changes in the phase shift to
measure thickness variations.
b. Application
The thickness log will function in fluid-filled steel casings from
4-1/2 to 8-5/8 inches in diameter. It is applicable only in
metallic casings. Because a relatively large area is investigated,
the tool has a limited resolution and the smallest casing defect
(hole) it can detect is about one inch in diameter. The thickness
log cannot distinguish between inner-wall and outer-wall defects?
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25
however, when used in conjunction with the pipe analysis log, it can
be used to distinguish which of two concentric casings is defective,
c. Interpretation
Casing is manufactured in a variety of dimensions, weights, and
alleys* Each will respond to the thickness log in a different
manner because of variations in the magnetic and electrical
characteristics of the casings. Because of these differences,
proper interpretation of the log requires a knowledge of the
diameter, weight, and type of steel casing being logged. Similarly,
the locations of couplings, wall scratchers, perforations,
centralizers, etc., should be known because they too, will influence
the log. An example of this is shown on Figure 10, which is a
"thickness" log for different weights (wall thickness) of
5-1/2-inch-diameter casing. The sharp peaks to the right at regular
intervals are due to the couplings. An area interpreted as
corrosion is shown at 1024 feet, where there is a reduction in
HiiHrrMMtB from "normal * for the pipe.
5, Casing Condition Logs - Pipe Analysis Log
This logging survey, based on measurements of flux density variation
and eddy currents, is used to provide a more quantitative assessment of
casing condition than the thickness log. This tool also can discriminate
between defects on the inner and outer casing walls.
a. Basic Principles and Presentation
The log is a form of magnetic flux-leakage test, relying on
disturbances in an artificial ly-created magnetic field to detect
casing defects. The probe houses from six to twelve coils
(depending on the size of casing being surveyed), through which a
DC current is passed, setting up a magnetic field. The field
consists of magnetic flux lines that travel through casing easier
than through gas or fluids.
The logging probe enploys a magnetic field strong enough to saturate
the casing walls with magnetic flux lines. As long as the wall of
the casing is uniform and consistent, the magnetic flux lines will
travel through it. When irregularities such as pits, holes,
partings, cracks, etc., are present, the flux lines will be
disturbed and flux leakage will occur. In an area where flux
leakage occurs, a small voltage is generated and detected fcy
transducers which relay a signal that is proportional to the
percentage of metal loss in the casing. This signal is recorded in
chart form.
Descrixnination between internal and external corrosion of the casing
is accomplished by monitoring the variations in eddy currents
-------
Geraghty & Miller, Inc.
PHASE SHIFT INCREASES
PIPE THICKNESS DECREASES
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26
generated in the magnetic field by pipe defects. The coils used to
detect eddy currents are co-located with the flux-leakage
transducers (coils). The signal frequency of the eddy currents
detected is high, such that the depth of investiation is shallow,
usually about 0.040 inch. Thus, the eddy current detector
investigates only the inside of the casing. Comparison of the flux
leakage with the eddy current signals makes it possible to
distinguish between inner and outer casing wall defects. An inner
casing wall defect will influence both flux leakage and eddy current
signals, whereas an outer wall defect will influence only the flux
leakage signal.
The logging probe is run in a centralized position in the casing.
Coils are staggered on the probe so they overlap each other to
provide circumferential coverage of the casing. The coil mountings
are spring loaded that adjust to the size of casing to be inspected.
The flux leakage and eddy current signals are detected, amplified,
and presented as a series of curves or tracers on standard log
forms. As noted, the amplitude of the flux leakage signal on the
log is proportional to the percentage of the metal loss in the
casing. Thus, the greater the aq>litude of the signal, the greater
the casing defect. An exanqple of this is shewn on Figure U and its
acconpartying table, which is the record of the signals produced by
known anomalies in a test piece of casing. Examination of the
signal produced by internal defects A and B, which are
3/8-inch-diameter holes with wall penetrations of 25 and 50 percent,
respectively, shows that the magnitude of the signal is proportional
to the loss of casing (depth of penetration of the defect). Hie
external defects producing signals K and L, which are 3/4 of an inch
in diameter, appear on the total wall trace but not on the eddy
current test, demonstrating the means by which internal and external
wall defects are discriminated.
Application
The pipe analysis log is designed for use in steel or other metallic
casings ranging from 4-1/2 to 8-5/8 inches in diamter. The tool can
be run in a fluid- or gas-filled casing. The pipe analysis log
responds to all changes in casing "thickness" and will be affected
by couplings, DV collars, perforations, wall scratchers,
centralizers, nrin defects, and different pipe weights and grades of
steel. Thus, the i« of the normal casing condition should be
known so that their presence can be recognized during
interpretation.
Interpretation
A typical log display is shown on Figure 12, which is an example of
the Pipe Analysis Log provided by Schlumberger Well Services. The
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Geraghty & Miller, Inc.
MAG-FLUX
TEST
(TOTAL WALL)
EDDY-CURRENT
test
(INNER SURFACE)
DEFECT
LOCATION
01 AM.
(in.)
PERCENT
WALL
PENETRATION
A
INTERNAL
3/8
21
B
INTERNAL
3/8
SO
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INTERNAL
1/2
21
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1/2
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25
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so
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L
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Figure 11
COMPARISON OF SIGNALS PRODUCED BY KNOWN PIPE DEFECTS
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Geraghty St Miller, Inc.
PIPE ANALYSIS LOG
ENHANCED CURVES LOWER ARRAY
UPPER ARRAY
INNER
SURFACE,
\ ~
TOTAL
WALL
DEPTH
CC
cc
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SURFACIv WALL
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Figure 12
TYPICAL DISPLAY OF THE PIPE ANALYSIS LOG
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27
The flux leakage signal is referred to as Total Wall" and the eddy
current signal is called the "Inner Surface." The enhanced curves
on the left-hand track ace derived from the iraximim signal from any
of the transducer coils and are used to emphasize major defects.
The term "CC" refers to casing coupling. Gbvious defects can be
seen on tbe casing above a depth of 70 feet. Because they appear on
both the inner surface and total vail curves, they are interpreted
to be defects on the inner wall of the casing.
The Dresser Atlas log that measures the same parameters is known as
the Vertilog. Its manner of presentation is slightly different
(Figure 13) • TWo tracks known as FL1 and FL2 are presented; these
measure flux leakage. One track is shown as the discriminator; it
measures eddy currents and is used to determine inner wall defects.
The fourth track is a display of the average signal and is used to
determine if the defect is circumferential in nature and to confirm
that the tool is working properly. Any time a signal is recorded on
a flux leakage trackf a corresponding signal should be recorded on
the average track. A typical Vertilog should be recorded on the
average track. Examination of the log on the right side of Figure
13 shows the log response for couplings and for various degrees of
corrosion and distinguishes between internal and external corrosion.
The left-hand log presents the results of the survey of a casing in
reasonably good condition with a few defects. The teems Class 1, 2,
etc., refer to a classification of the condition of the casing,
based on the percentage of the deterioration; it is used by Dresser
Atlas in its reports of rasing condition surveys (Class 1 represents
defects equal to 0 to 20 percent of the wall thickness, Class 2 from
20 to 40 percent, Class 3 from 40 to 6 percent, and Class 4 from 6
to 80 percent).
Survey data are compared to standard charts derived from
laboratocy-made defects on test casings to determine the percentage
of deterioration. Typically, an oil-well operator is not concerned
about casing condition until a Class 4 defect appears, whereas the
operator of a gas storage well would be concerned when a defect
reached 20 percent of the wall thickness.
Of the two casing condition logs, the pipe analysis tool is the most
sensitive and is capable of detecting relatively small defects.
Both, however, are valuable tools. One suggested method of using
them is to run one at the time a well is constructed, to serve as a
reference for future comparison. If the well is operated on a
long-term basis, subsequent logs can be used to obtain some idea of
the degree of deterioration and an approximation of its rate.
-------
DISCRIMINATOR TRACK (INNER WALL DEFECTS)
3§5§ki
im
i«
CASINO
COUPLINQ8
SEVERE
EXTERNAL
CORROSION
MODERATE
EXTERNAL
CORROSION
FLUX LEAKAGE TRACKS
INTERNAL
DEFECTS
Figure 13
TYPICAL DISPLAY OF THE VERTILOG
<3
to
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28
v. toll mam evidence op mechanical integrity for class ii ntJEcncN
WKT.T.S
The absence of fluid migration behind the casing of injection wells
associated with the production of oil and gas (Class IZ) may he
demonstrated by well records showing adequate cement to prevent audi
migration. b exception for CI wis XT wells ^ ^ imA> so as not to inpede
the production of «*> ra'Hpqr log* logs may be to measure
the full diameter of the borehole in an unusually ragged or cavernous
zone; therefore a greater volume say exist between the casing and the
well bore than that calculated. In this case, especially in the light of
corroborative geologic evidence, an adequate cement is considered likely.
A cement bond log showing a ti#t casing-to-fonnation bond over the
cemented interval is also considered adequate assurance of mechanical
integrity.
VI. GENERAL CCKSnSKAIICNS
The testing for mechanical integrity entails the execution of a
number of steps, each one a specific test, that together provide
assurance that the tested well is environmentally sound. At least two
tests are required though more may be necessary if the results of these
are not conclusive.
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29
flie two required tests are a pressure test (or monitoring) and a
geophysical log (either noise log or temperature log) • Other tests may
be substituted for these two, if approved by the EPA AMnistrator. If
either o£ the tests indicate well failure, then other tests are
necessaiy, first to veryify, and then to locate and understand the
failure for effective remedial action*
Pressure tests and axuulus monitoring are conducted at tbe well bead
arxji yield the most valuable
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30
REFERENCES CITED
AMERICAN PETROLEUM INSTITUTE, 1973. Bulletin on
Performance Properties of Casing, Tubing, and Drill Pipe,
API BUI. 5C2, 16th Edition, Dallas, Texas.
CUTHBERT, J. P., and JOBNSON, tf • M., JR., 1975. New
Casing Inspection Log; 1975 AGA Operating Section
Transmission Conference, Bal Harbour, Florida, May 19-21,
1975? Schlumberger Well Services.
DRESSER ATLAS DIVISION, DRESSER INDUSTRIES, INC., 1976.
Systems Catalog. Caliper (pg. 23}, Acoustic Cement Bond Log
(pg. 33), Tracer Log (pg. 39), Temperature Log (pg. 41).
GROSMANGIN, M., KOKESB, F. P., and MAJANI, P., 1960.
Cement Bond Log, Annual California Regional Meeting of the
AIME, Pasadena, Ca., Paper 1512-G.
HAIRE, JOHN N., and HEFLIN, JEARALD D., 1977. Vertilog
(trade name)- A Down-Hole Casing Inspection Service, Paper
Number SPE6513 Society of Petroleum Engineers, Dallas,
Texas.
GUYOD, HURBERT, (no date). Temperature Well Logging,
Well Instrument Developing Company, Parts 6 ft 7.
LYNCH, EDWARD J., 1962. Formation Evaluation, Harper &
Row, (Cement Bond Log, pg. 282-283)~
MYUNG and STURDEVANT, 1970. Introduction to the Three
Dimensional Velocity Log (Cement Bond Evaluation), Birdwell
Division, Seismograph Service Corporation.
PICKETT, JAMES, 1981. Personal Communication,
Manager—Casing Inspection Services, Dresser Atlas, Houston,
Texas.
SCHLUMBERGER, WELL SERVICES, 1975. Cased Hole
Applications, Cement Bond Log (pg. 44-59, 87, 99), Pipe
Inspection Logging (pg. 100), High Resolution Thermometer
(pg. 119), Thru-Tubbing Caliper (pg. 119), Radioactive
Tracer (pg. 120).
SCHLUMBERGER, WELL SERVICES, 1973. Production Log
Interpretation, Temperaure Log and Radioactive Tracer Log,
Chapters 2 & 3.
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31
SMOLEN, JAMES J., 1976, PAT Provisory Interpretation
Guidelines, Schlumberger Well services Interpretation
Department.
WELEX, (no date)• Open Hole Services Catalog,
(Caliper, pg. 26).
WYLLIE, R. J«, 1963. Fundamentals of Well Log
Interpretation, Academic Press, (Cement Bond Log, Pg.
162-164).
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