UNDERGROUND INJECTION CONTROL
INSPECTION MANUAL
Respectfully Submitted To
US Environmental Protection Agency
by
Engineering Enterprises, Inc.
Norman, Oklahoma
February, 1988
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ENGINEERING
ENTERPRISER INC.
Revision of the Underground Injection Control
Inspection Manual was done for the United States
Environmental Protection Agency (USEPA)'under contract
No. 68-03-3416, Work Assignment No. 0-0-7-1. The USEPA
Work Assignment Manager was Mr. Donald M. Olson, Chief,
Compliance and Enforcement Section, UICB, Washington,
D.C.
The revisions were effected by the technical staff
of Engineering Enterprises, Inc., 1225 West Main,
Norman, Oklahoma 73069.
__ il
EEI Work Assignment Manager.
W. J. (BIN) Whitsel I
EEI UIC Program Director!
Tal Ib Syed
February 12, 1988
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PREFACE v I I
INTRODUCTION
The Safe Drinking Water Act .- i 1 - 1
Underground Injection Control 1 - 1
Purpose of the Inspection Guide 1 - 1
Injection Wei I Classification Scheme 1 -2
SubclasslfIcatlons 1 - 2
REVIEW OF INSPECTION REQUIREMENTS
Overview of SDWA and Amendments 2 - 1
The SDWA, Its Regulations and Authority for Inspections 2 - 1
Enforcement Program. 2 - 1
Penalties for Noncompl lance . 2-2
Underground Sources of Drinking Water 2-3
Exempted Aquifer 2-3
Area of Review 2-4
Corrective Action 2-15
Quality Assurance 2-16
Barlow's Guidance, an Overview of Other Federal Regulations 2-16
Kinds of Inspections 2-17
Emergency, Compliance, and Citizen Complaint Inspections 2-17
Preoperational Inspections 2-18
Mechanical Integrity Test Inspections........... 2-18
Plugging and Abandonment Inspections 2-19
Closure of Class IV Wells 2-19
General Maintenance Inspections 2-19
TECHNIQUES FOR EFFICIENT INSPECTIONS
Inspection Goal 3.- 1
Legal Responsibilities for EPA UIC Program ' 3 - 1
Investigative Techniques and Procedures 3 - 1
Pre-Inspect ion Planning 3 - 1
Inspection Plan Development 3-7
Inspection Scheduie 3 - 8
Notification of Interested Parties 3 - 8
Unannounced Inspections 3-8
II
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Fac 11 Ity Entrance 3 - 8
Open Ing Conference 3 - 11
Facility Inspection and Documentation 3-13
Closing Conference 3-16
Sample Collection and Handling 3-16
Chain of Custody.... 3-17
The Right of Warrantless Entry 3-17
Withdrawal of Consent to Inspection 3-18
Denial of Entry 3-18
The Warrant 3 - 20
I nspect Ion w Ith Warrant 3 - 20'
Return I ng the Warrant 3 -.21
Seeking a Warrant before Inspection. -. 3-21
Professional Business Ethics ...... 3 - 2f
I nspect Ion Report 3 - 22
INSPECTIONS
General Inspection Procedures " 4 - 1
General Inspections 4 - 1
Check List for General Site Inspection 4-2
Preoperat lona I I nspect Ions 4 - 11
Logging 4-11
LIthologIc Logging 4-12
Electric Logging 4-12
Radioactivity Logging 4-16
Acoustic Logs 4-16
Witnessing Wire-line Logging Procedural Checklist 4-17
Cementing 4-18
Witnessing Primary Cementing Procedural Checklist 4-19
I n Ject I v Ity and Aqu I fer Test Ing 4 - 20
Witnessing Injectlvlty Tests Procedural Checklist 4-20
Other Preoperat lona I Inspections 4-21
Comp 11ance Ver I f Icat Ion 4 - 21
Mechanical Integrity (Ml) Test Inspections 4-23
Ml Testing Procedures 4-23
Internal Mechanical Integrity 4-27
Internal Ml (Static Pressure Test) 4-27
Internal Ml (Dynamic Test) Procedural Checklist.... 4-29
External Mechanical Integrity 4-36
Geophys Tea I Logs 4 - 36
Application and Interpretation of the Radioactive
Tracer Survey (RATS) 4 - 45
Water-In-annulus Test 7 4-49
Manifold Monitoring for Mechanical Integrity Testing 4-51
Plugging and Abandonment (P&A) 4-57
The P&A Program and Wei I Classification 4 - 57
The Objective of P&A 4-58
Major Phases In P&A 4-58
Well Abandonment and Plugging 4-58
Location of Cement Plugs 4-59
Corrosion and Mechanical Integrity - 4-59
Stress-Induced Damage and Mechanical Integrity 4-59
P&A for Class III Wells 4-59
HI
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Cement Se I ect I on for P&A 4 - 71
Well Preparation and Plug Installation Procedures 4-71
The Balance Method of Plug Instal I at Ion 4-72
The Cement Reta Iner Method 4 - 73
The Two-Plug Method 4-73
Dump Ba I ler Method 4 - 77
Check List for Witnessing P&A 4-81
Class IV Closure 4-81
Plugging Considerations for Class IV Wei Is 4 - 81
Emergency Inspections 4 - 89
Citizen Complaint Investigations 4-89
FIELD SAFETY
Personal Protective Equipment 5 - 1
Suggested Personal Protective Equipment Specifications 5-2
Other General Considerations for Personal Safety 5-4
Hazards Related to Injection Well Operations 5-5
Safety during Well Treating Operations 5-5
Drilling and Well Workover Safety 5-6
Safety during Routine Inspections 5-7
Class I Injection Well Hazards 5-7
Disposable Clothing and Equipment 5-7
Decontam I nat Ion . 5 - 7
Safe Handling of Hazardous Chemicals 5-8
Iv
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LIST OF ILLUSTRATIONS
FIgure Title
1.1 Underground Injection Control Program
Classification of Wei Is 1 -3
2.1 Idealized Example of Cone of Impression 2-5
2.2 How the Position of the Cone of Impression Defines
the Radius, R, of the Area of Review 2-7
2.3 Plan View of Area of Review. i... 2-7.
2.4 Example of Fluid Migrating from the Injection Zone
Into a Fresh Water Aquifer 2-11
2.5 Example of Fluid Migrating out of the Injection Zone
through a Fault ' '. 2-13
3.1 Notice of Inspection 3-9
4.1 Annual Injection Monitoring Report 4-3
4.2 Monthly Monitoring Report 4-5
4.3 Dally Monitoring Report 4-7
4.4 Head Loss Chart 4-31
4.5 Noise Log 4-37
4.6 Temperature Log Showing Cement Top 4-41
4.7 Temperature Log Showing Fluid Loss 4-43
4.8 Radioactive Tracer Log Showing Fluid Movement 4-47
4.9 Mechanical Integrity Test Results -
Water-In-annulus Test 4-53
4.10 Mechanical Integrity Test Results -
Water-In-annulus Test 4 - 55
4.11 Wei I-PIuggIng-Cased and Cemented Well with
Removab I e Packer 4 - 61
4.12 Well PIuggIng-Part IalIy Cased, Partial Iy Cemented '
We I I w Ith Non-removab I e Packer 4-63
4.13 Kinds of Open-hole Construction 4-65
4.14 Kinds of Open-hole Construction 4-67
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4.15 Plugging - Wei I with Insufficient Casing 4-69
4.16 Plug-catcher Method of Well Cement 4-75
4.17 Dump Bailer Method of Well Cementing 4-79
LIST OF TABLES
labie Title fags
3.1 Inspector's Responslbl I Itles 3 - .3
4.1 Logging Methods and Uses .' < 4-13'
4.2 Logging Equivalents 4-15
4.3 Possible Appropriate Responses to Violations 4 - 25
4.4 Checklist for Plugging and Abandonment 4-83
4.5 Capacity of Hole 4-87
vl
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PREFACE
Much of the Information and material In this edition of the Underground
I njectloji Control Ins pact Jon ManuaJ was originally assembled by Ken E. Davis
Associates of Houston, Texas (July 1984), under the title ULC Inspection
Guide. The guide was prepared In support of the U.S. Environmental Protection
Agency's Underground Injection Control (UIC) Program, required to satisfy the
mandate of the 1974 Safe Drinking Water Act.. .
The original guide was developed to meet two goals: (1) train prospective
field Inspectors and their UIC program supervisors In the many Intricacies of
Injection well Inspection and reporting; and (2) provide a useful reference
for actual field Inspections of underground Injection facilities.
A revised edition of the Guide was prepared by the engineering staff of
Engineering Enterprises, Inc. (EEI) In February 1985. This resulted In
reorganization of the material, some rewriting, correction of errors, and
reduction In volume. The work was accomplished under terms of a general
contract between EEI and EPA. It was recognized by both EEI and EPA that, as
experience was gained by the UIC programs across the country, the need for
further revisions would likely develop.
In order to bring the scope and material of the Guide more In line with
current needs as revealed by experience and Improved technology, the EPA
Underground Injection Control Branch (UICB) In May of 1986 Initiated Work
Assignment 0-7 Task 1 under EPA Contract No. 68-01-7011 with Engineering
Enterprises. This Underground Injection^ Control InspectIon ManuaJ Is the
result of that action.
This manual has been notably strengthened by the Inclusion of new material on
quality assurance and control, classification of Injection wells, definitions
for exempted aquifers, Improved guidance on legal matters related to
Inspections, possible appropriate responses to violations, and chain of
custody for samples, among others. Readers will appreciate the Inclusion of
an Index of more than 300 entries.
Engineering Enterprises, Inc. Is grateful for the opportunity to participate
In the preparation of this essential document. We especially appreciate the
support and understanding of Mr. A. Roger AnzzolIn, EPA Project Manager; and
the professional dedication and attitude demonstrated by Ms. Nancy Zeller and
by Mr. Donald M. Olson, Chief of the Compliance and Enforcement Section of
UICB, In our mutual efforts to make this undertaking a success.
vll
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1 Introduction
THE SAFE DRINKING WATER ACT
The 1974 Safe Drinking Water Act (SDWA), with amendments, establIshed a
joint Federal-State system for protecting the nation's underground sources of.
drinking water (USDW). It specifically Instructed 'the United States
Environmental Protection Agency (USEPA) to establish a program that would
protect the nation's potentially usable fresh water aquifers from
contamination by_ujTdenground Injectjon well operations. At the present time
^sucfT an aquifer-or Its part Is defined by EPA as that "which supplies any
public water system or which contains a sufficient quantity to supply a public
water system; and which currently supplies drinking water for human
consumption, or contains fewer than 10,000 mg/l total dissolved sol Ids (TDS),
and which Is not an exempted aquifer" (40 CFR § 146.3). These are referred to
as USDW's.
UNDERGROUND INJECTION CONTROL
EPA has required all States to have an Underground Injection Control (UIC)
program. Each State has the option of Implementing Its own program. If a
State does not assume primary enforcement responsibility, EPA must administer
an UIC program In that State. Currently, EPA administers full or partial
programs In 24 States and territories and on Indian Lands.
An essential part of the UIC program Is the field Inspection of underground
Injection operations to monitor compliance with provisions of the SDWA, the
UIC regulations, and with conditions set forth In UIC permits.
1:1 Purpose of the Inspection Guide
This UIC Inspection Guide was developed specifically for Inspection
personnel.
Every effort was made to Include Information useful to the inspector in
carrying out his duties In the field. A conscious effort was also made
to exclude material that does not enhance his ability to perform as
required.
This Guide Is Intended to help the Inspector complete Inspections
efficiently and prepare comprehensive, well organized reports. New
personnel may wish to reinforce their knowledge by reading certain other
publications. The Inexperienced Inspector should read and keep at hand
the following references:
1 - 1
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1:1 - 1:3
40 CFR Parts 124, 144, 146 and 147
An Introduction to the Technology of Subsurface Wastmater
Injection. (EPA-600/2-770240), December 1977
Injection Wel I Construction Practices and Technology. Prepared for
the USEPA Office of Drinking Water under Contract No. 68-01-5971,
October 1982
Major Policy Statements and Guidance Documents from the Office of
Water and the UIC Branch
Other references are cited at the end of each chapter
INJECTION WELL CLASSIFICATION SCHEME
The Inspector should be familiar with the UIC well classification scheme and
the basis for categorizing each well Into Its appropriate class. He should
understand the basic structural and functional differences between Injection
well types. Figure 1.1 Illustrates the five major well classes, with one or
two possible configurations for each class.
Regulations developed under the Safe Drinking Water Act classify Injection
welIs Into the following five major groups:
Class I: Industrial and municipal wells that Inject below USDW's
(Includes hazardous waste welIs)
Class II: ON and gas wells
Class III: Solution mining welIs
Class IV: Wells that are used to Inject hazardous or radioactive
wastes Into or above USDW's (these wells are banned)
Class V: Wells not Included In any of the above classifications
1:2 Sub-classifications (1)
1:3 Class I
1. Wells used by generators of hazardous waste or owners/operators of
hazardous waste management facilities to Inject hazardous waste
beneath the lowermost formation containing, within one quarter mile
of the well bore, an underground source of drinking water
(1) From 40 CFR § 146.5 - Classification of Injection wells
1 - 2
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I
CO
CLASS I
INDUSTRIAL MUNICIPAL
CLASS II
OIL & GAS
CLASS III
MINING
CLASS IV
CLASS V
OTHERS, AS:
(BANNED) COOLING DRAINAGE
LAND SURFACE, --,
/UNCONSOLIDATED
f SANDS, GRAVELS
.WATER TABIF., , t. J
- - -AQJfl CTUDE" CLAY- - - - -:
AQUIFER SANDS
IFRESH WATER - UNDER-
GROUND SOURCE OF
DRINKING WATER..
-_-_-^OjJ I CLUDE^:------------!-----:
: "AQUIFER:::::::::::
: :: FRESH UNDERGROUND
: iiSOURCE OF DRINKING
: "WATER::::::::::::::
:: ::6RAC.Ki.SH. .WATE.R:
|
-
-
II "
» * j~u~^rLrLJ7_ru~u~
;
, -2-I-^-I-~-~-~-2
P_
V
i mm m i Ji, ~
r
T
4
t
: : .'AQUIFER: ::::::::::::: i^j :::::::::::: !1
..SALINE WATER. iNJECtiON ZONE- ''-'-
XT
*
r
p
*
r.
T
f
r
»*
_ ^ ^ . |_ _ ^ T~_J~__~* *
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^
-I-I-I-I-I-I-I-I- -
j
1 1 1 I 1 "TT'TT (III*
*jfj J «. ;-»__« ^ « «. _'
**" »-**"»%** **=* I- WELLS USED TO INJECT HAZARDOUS^ ;
**»-«*»-** 'o*WASTES OR DISPOSE OF INDUSTRIAL AND° =
J-i*V**V*VW** MUNICIPAL FLUIDS BENEATH THE LOWER- VJ
= *,* =Vl *«-**=* B*.MOST FORMATION CONTAINING WITHIN % #»
V-l**"* » ******** MILE AN UNDERGROUND SOURCE OF -t = " * */
#«»«J-\»»i* -*-*;DRINKING WATER// *V»^*"*C-**'**V*
rl f^ » n n II.
.
' *
r
,
-
I
p_ ...... .. ..-I . __r-.-, r-r~9 - ,,...,.., ~ 1 V~ ~
^ . . ; \ IZl^rr^T" __ __ ^^ _.
_: L_ *
III- WELLS WHICH
! INJECT FOR EXTRACTION;
OF MINERALS OR ENERGY; \J
JV- DISPOSAL OF ' _V- WELLS NOT
^ :.:: HAZARDOUS OR RAnin-:";;;-;INr| linrn IN 1THER':^:::
:---------l---r-"---i ACTIVE WASTES INTO :-:CLASSES. GENERALLY"--
OR ABOVE A FORMATION INJECT NONHAZARDOUS
WITHIN h MILE OF AN FLUID INTO OR ABOVE
UNDERGROUND SOURCE. A USDW
.OF.. DRINK I. NG.. WATER.
i r___
' r~_~iJ~ ~ ~^~ir~_~_ _~_~^~_~i.^^
* II- WELLS USED TO INJECT BRINES PRODUCED BY''*'**'/*'**
,;OIL AND NATURAL GAS ACTIVITIES, OR FLUIDS FOR-V**** **
^ENHANCED RECOVERY INTO A FORMATION (WITH CONFINING1/**'
O^ZONES AND NO FAULTS OR FRACTURES WITHIN THE AREA'/***"*
V* OF REVIEW J. -V«%* »v.- %'-" *V*V*1,* I «".*>",-, t» " V4*.
*_v.v*v» % * . * *"* " A- * - »*»*> =**»*.*;*;***/
^»^^ M11**^* **&»* «t ^ cs _ *_»« ^n
Figure 1.1 Underground Injection Control Program Classification of Wells
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THIS PAGE INTENTIONALLY LEFT BLANK
1 - 4
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1:3-1:6
2. Other Industrial and municipal disposal wells which Inject fluids
beneath the lowermost formation containing, within one quarter mile
of the well bore, an underground source of drinking water
1 :4 Class I I
Wells which Inject fluids:
1. Which are brought to the surface In connection with conventional oil
or natural gas production and may be commingled with waste waters
from gas plants which are an Integral part of production operations,.
unless those waters are classified as a hazardous waste at the time
of Injection
2. For enhanced recovery of oil or natural gas
3. For storage of hydrocarbons which are liquid at standard temperature
and pressure
1:5 Class I I I
Wells which Inject for extraction of minerals, Including:
1. Mining of sulfur by the Frasch process
2. In-sltu production of uranium or other metals
This category Includes only In-sltu production from ore bodies which have
not been conventionally mined. Solution mining of conventional mines
such as stopes leaching Is Included In Class V.
3. Solution mining of salts or potash
1:6 Class JV
1. Wells used by generators of hazardous or of radioactive waste, by
owners or operators of hazardous waste management facilities, or by
owners or operators of radioactive waste disposal sites to dispose
of hazardous or radioactive waste Into a formation which within one
quarter mile of the well contains an underground source of drl.nklng
water
2. Wei Is used by generators of hazardous or of radioactive waste, by
owners or operators of hazardous waste management facilities, or by
owners or operators of radioactive waste disposal sites to dispose
of hazardous or radioactive waste above a formation which within one
quarter mile of the well contains an underground source of drinking
water
1 - 5
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1:6-1:7
Wells used by generators of hazardous waste or owners or operators
of hazardous waste management facilities, to dispose of hazardous
wastes which cannot be classified under Section 146.05(a)(1) or
Section 146.05(d)(1) and (2), e.g., wells used to dispose of
hazardous wastes Into or above a formation which contains an aquifer
which has been exempted pursuant to UIC Regulations (Section 146.04)
1:7 Class V
Injection wells not Included In Class I, II, III, or IV. Class V wel.ls
Include:
1. Air conditioning return flow wells used to return to the supply
aquifer the water used for heating or cooling In a heat pump
2. Cesspools, Including multiple dwelling, community or regional
cesspools, or other devices that receive wastes, which have an open
bottom and sometimes have perforated sides (the UIC requirements do
not apply to single family residential cesspools which receive
solely sanitary wastes and have the capacity to serve fewer than 20
persons a day)
3. Cooling water return flow wells used to Inject water previously used
for cool Ing
4. Drainage wells used to drain surface fluid, primarily storm runoff,
Into a subsurface formation
5. Dry wells used for the Injection of wastes Into a subsurface
formation
6. Recharge wells used to replenish the water In an aquifer
7. Salt water Intrusion barrier wells used to Inject water Into a fresh
water aquifer to prevent the Intrusion of salt water Into the fresh
water
8. Sand backfill and other backfill wells used to Inject a mixture of
water and sand, mill tailings or other solids Into mined out
portions of subsurface mines whether what Is Injected Is a radioac-
tive waste or not
9. Septic system wells used to Inject the waste or effluent from a
multiple dwelling, business establishment, community or regional
business establishment septic tank (the UIC requirements do not
apply to single family residential septic system wells, nor to non-
residential septic system wells which are used solely for the
disposal of sanitary waste and have the capacity to serve fewer than
20 persons a day)
1 - 6
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1:7
10. Subsidence control wells (not used for the purpose of oil or natural
gas production) used to Inject fluids Into a non-oil or gas
producing zone to reduce or eliminate subsidence associated with the
overdraft of fresh water
11. Radioactive waste disposal wells other than Class IV
12. Injection welIs associated, with the recovery of geothermal energy
for heating, aquaculture and production of electric power
13. Wells used for solution mining of conventional mines such as stopes
leaching .
14. Wells used to Inject spent brine Into the same formation from which
It was withdrawn after extraction of halogens or their salts
15. Injection welIs used In experimental technologies
16. Injection wells used for In situ recovery of lignite, coal, tar
sands, and olI shale
1 - 7
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2 Review of Inspection Requirements
OVERVIEW OF SDWA AND AMENDMENTS
Section 1445 (B) (1) of the Safe Drinking Water Act gives the
Administrator or his designated representative the authority to enter upon and
to Inspect any facility subject to Underground Injection Control (UIO) Program
requirements. Additionally, 40 CFR § 144.51 (I) states that the permittee
shall allow the Director, or an authorized representative, upon th'e-
presentation of credentials and other documents as required by law, to:
'1. Enter upon the permittee's premises where a regulated facility or
activity Is located or conducted, or where records must be kept under the
conditions of the permit
2. Have access to and copy, at reasonable times, any records that must be
kept under the conditions of this permit
3. Inspect at reasonable times any facilities, equipment (Including
monitoring and control equipment), practices, or operations regulated or
required under this permit
4. Sample or monitor at reasonable times, for the purpose of assuring permit
compliance or as otherwise authorized by the SDWA, any substances or
parameters at any location
These provisions apply to operators of. wells authorized by either permit or
rule.
2:1 The Safe Drinking Water Act, Its Regulations and Authority for
Inspections
2:2 Enforcement Program
The Safe Drinking Water Act requires that Injection well owner/operators
who violate the provisions of the UIC regulations be subject to either
civil or criminal penalties In the case of willful violation of the UIC
regulations. The Agency also has the authority to require the facility
to take any actions necessary to achieve compliance. This section
presents a brief review of the enforcement programs established to deal
with violations and the penalties that may be assessed under various
circumstances.
2 - 1
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2:3 - 2:6
2:3 Enforcement Procedures
EPA has the authority to Issue an Administrative Order for compliance or
penalties or both or Initiate a civil or criminal action for
owners/operators of Injection wells falling to meet statutory or
regulatory requirements. Enforcement actions may be taken In several
types of situations:
1. Failure to apply for permit (where required)
2. Failure to comply with permit or rule-authorized requirements (UIG-
Regulatlons)
3. Failure to take all reasonable steps to protect underground sources
of drinking water from any adverse Impact resulting from
noncomp11ance
See the UIC regulations for more detailed Information on criteria and
. standards applicable to Class I, II and III wells (40 CFR Part 146,
Subparts B, C, and D).
EPA has a variety of mechanisms for Identifying noncompI lance. First, to
Identify wells requiring permits, EPA can utilize well Inventories and
related well records. Second, Inspections of sites by EPA officials
during construction and after operation begins can provide Information on
such noncomp I Iance. Third, material provided to EPA In permit
applications, monitoring reports, and operating records can reveal cases
of noncompI lance. Finally, EPA may rely on Information provided by
Interested citizens or by a non-compliance report Itself.
2:4 Penalties for NoncompI lance
2:5 Civil Penalties for Noncompllance (Safe Drinking Water Act § 1423(b))
"Any person who violates any requirement of an applicable underground
Injection control program (UIC regulation) or an order requiring
compliance under subsection (c) shall be subject to a civil penalty of
not more than $25,000 for each day of such violation, and If such
violation Is willful, such person may, In addition to or In lieu of the
civil penalty (authorized above), be Imprisoned for not more than 3 years
or fined In accordance with Title 18 of the United States Code, or both."
2:6 Administrative Penalties for NoncompJlance (Safe Drinking Water Act
§ 1423(c))
"In any case In which the Administrator Is authorized to bring a civil
action under this section with respect to any regulation or other
requirement of this part other than those relating to the underground
Injection of brine or other fluids which are brought to the surface In
connection with oil or natural gas production, or any underground
2-2
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2:6 - 2:8
Injection for the secondary or tertiary recovery of oil or natural gas,
the Administrator may also Issue an order under this subsection either
assessing a civil penalty of not more than $10,000 for each day of
violation for any past or current violation, up to a maximum
administrative penalty of $125,000, or requiring compliance with such
regulation or other requirement, or both."
For cases Involving underground Injection of brine or other fluids
brought to the surface In connection with oil or gas production, or
Injection for secondary or tertiary recovery of oil or natural gas, the
civil penalty shall be "not more than $5,000 for each day of violation-
for any past or current violation, up to a maximum administrative penalty
of $125,000, or requiring compliance with such regulation or other
requirement, or both."
2:7 Underground Sources of Drinking Water
Federal underground Injection control regulations promulgated under the
authority of .the Safe Drinking Water Act are directed toward protecting
underground sources of drinking water (USDW). Underground source of
drinking water (USDW) means an aquifer or Its portion:
1. Which supplies any public water system
2. Which contains a quantity of groundwater sufficient to supply a
pubIIc water system
a. currently supplles drinking water for human consumption
b. contains fewer than 10,000 mg/l total dissolved solids
c. which Is not an exempted aquifer
Under the UIC program, It Is not necessary to Identify specific aquifers
as USDW's. The Agency has ruled that any aquifer or portion thereof that
fits the definition Is, In fact, a USDW (40 CFR Part 144).
2:8 Exempted Aquifer
An aquifer or portion of an aquifer which meets the criteria for an USDW
In § 146.3 may be designated an exempted aquifer If It meets the
following criteria:
1. It does not currently serve as a source of drinking water for human
consumption
2. It cannot now and will not In the future serve as a source of
drinking water because:
2-3
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2:8 - 2:9 .
a. It Is mineral, hydrocarbon or geothermal energy bearing with
production capability, or can be demonstrated by a permit applicant
as part of a permit application for a Class II or III operation to
contain minerals or hydrocarbons that considering their quantity and
location are expected to be commercially producible
b. It Is situated at a depth or location which makes recovery of water
for drinking water purposes economically or technologically
Impractical
c. It Is so contaminated that It would be economically or
technologically Impractical to render that water fit for human
consumption, or
d. It Is located above a Class III well mining area subject to
subsidence or catastrophic collapse
The total dissolved solids content of the groundwater Is more than 3,000
and less than 10,000 mg/l and It Is not reasonably expected to supply a
public water system (40 CFR §146.4).
2:9 Area of Review
Fluids Injected under pressure Into a geologic formation could, under
certain conditions, force formation fluids and possibly contaminants to
move upward Into underground sources of drinking water via features such
as Improperly abandoned wells and undetected fault/fracture systems that
penetrate the Injection zone.
The area of review Is the area surrounding an Injection well or a group
of Injection wells to be studied by permit applicants for the possible
presence of pathways through confining strata and along which formation
or Injected fluids, under pressure from the Injection operation, might be
forced Into a USDW (40 CFR § 146.6). An area of review for Injection
wells should be determined on a case-by-case basis, using appropriate
formulas and available geological Information. The area of review should
have a radius of no less than 1/4 mile unless the use of a mathematical
model for the facility. In question results In a radius of less than 1/4
mile. Many states have more stringent requirements. That Is, the minimum
allowable radius Is greater than 1/4 mile. See figures 2.1, 2.2, 2.3,
2.4 and 2.5.
2-4
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INITIAL PIEZOMETRICI-I-I-I-
SURFACE (INJECTION ZONE)
CONFINING LAYER
I
a
CONE OF IMPRESSION
(PRESSURE PROFILE
OF INJECTION ZONE)
FRESH WATER
INJECTION ZONE
E7;
Figure 2.1 Idealized Example of Cone of Impression
2-5
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INITIAL PIEZOMETRiC^-I-I1
SURFACE (INJECTION ZONE)
CONFINING LAYER
CONE OF IMPRESSION
(PRESSURE PROFILE
OF INJECTION ZONE)
INJECTION ZONE
Rgure 2.2' How the Position of the Cone of Impression
defines the radius, R, of the Area of Review
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INJECTION WELL
DELINEATED
AREA OF REVIEW
Figure 2.3 Plan view of Area of Review
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8>-I>: CONFINING LAYER -±2^.
INJECTION ZONE
1
1
t
Figure 2.4 Example of fluid migrating from the injection zone
into a fresh water aquifer through an unplugged well. Migration
is made possible because of the pressure differential, shown as H.
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Figure 2.5 Example of fluid migrating out of the injection zone
through a fault that penetrates to the injection zone within the AOR.
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2:10
2.10 Corrective Action
EPA may require that corrective action be taken as necessary to prevent
movement of fluid Into an USDW when any well, that penetrates the
Injection zone, within the area of review of an Injection operation Is
Inadequately constructed, plugged, or abandoned. The EPA may require
under the authority granted In 40 CFR §144.12, that an Improperly
completed well In the area of review be plugged or repaired even If the
associated Injection well Is authorized by rule. In general, the
regulatory staff will review data submitted by the applicant, evaluate
the proposed corrective action plan, and If -the p.lan Is approvable,
Incorporate It as a permit provision.
Requirements under 40 CFR §146.7 state that the Director consider the
following technical Information In the permit application to determine
the adequacy of the cqrrectlve action plan and to determine what
additional steps are needed to prevent fluid movement Into a USDW.
1. Nature and volume of Injected fluid
2. Nature of native fluids or byproducts of Injection
3. Potentially affected population
4. Geology
5. Hydrology
6. History of the Injection operation
7. Completion, and plugging records. Abandonment procedures In effect at
the time the welI was abandoned
9. Hydraulic connections with underground sources of drinking water
The applicant submits a corrective action plan for any wells within the
area of review which may potentially endanger an USDW because of the
proposed Injection.
Corrective action plans may require:
1. Physical alteration and correction of any Inadequate well system
within the area of review prior to beginning Injection operations,
or
2. The operation of the Injection facility at reduced pressure levels
until such time as EPA determines that physical alteration and
correction of an Inadequate welI system Is accomplIshed, or
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3. Reduced pressure operation of the facility for the life of the
project
2:11 Quality Assurance
The General Grants Regulations require under 40 CFR §130.503(e) that all
data used In any programs receiving assistance from EPA to have adequate
quality assurance (QA). Internal EPA directives require the same of all
EPA-Implemented programs.
Data gathered during Inspections and received In.the form of self--
monitoring report therefore need to meet QA requirements. These QA
requirements have been put In place to guarantee that data are adequate
for the purpose Intended and of known quality. The Office of Drinking
Water will Issue guidances on how to apply QA principles to all
"environmental measurements" used In the DIG program. These guidances
will be Issued In phases: (1) ChemlcaJ tests; (2) Physical tests; and
(3) Geophysical tests. The chemical test guidance on Qual Ity Assurance
has been Issued and the remaining guidances are forthcoming.
2:12 Barlow's Guidance, an Overview of Other Federal Regulations
The Supreme Court decision In Marshal vs. Barlow's Inc., U.S., 98 S. Ct.
1816 (1978) was an Important case affecting the conduct of EPA
Inspections. The decision bears upon the need under certain
circumstances to obtain warrants or other processes for Inspections
pursuant to EPA-admlnlstered Acts.
In Barlow's, the Supreme Court.held that an OSHA Inspector was not
entitled to enter the non-publIc portions of a work site without either
(1) the owner's consent, or (2) a warrant.
In summary, Barlow's has two (2) major effects on EPA enforcement
Inspections:
1. Where an Inspector Is refused entry, EPA will seek an Inspection
warrant through the local U.S. Attorney's Office
2. Sanctions will not be Imposed upon the owners of establishments who
Insist on a warrant before allowing Inspections of the non-public
portions of an establIshment
Barlow's decision Is discussed In Chapter 3.0. For additional
Information obtain a copy of the EPA procedural guidelines concerning
this decision from the USEPA Office of Enforcement and Compliance
Monitoring.
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2:13 - 2:15
2:13 Kinds of Inspections
As part of the EPA's compliance monitoring program, the UIC staff may be
called upon to verify that certain Injection well facility construction,
completion, operation, maintenance, and closure procedures are performed
according to approved plans and schedules and meet all permit or rule
requirements. On-slte Inspections will be a major part of this
verification effort.
2:14 Purposes of Inspections
Inspections may serve one or more of the following purposes:
1. Emergency Inspections
2. Preoperatlonal Inspections (verification -of compliance with
construction requirements)
3. Mechanical Integrity Tests
4. Comp I lance Verification
5. Plugging and Abandonment Verification
6. Class IV Closure Verification
7. General Maintenance Inspection
8. Citizen Complaint Investigation
2.15 Emergency, Compliance, and Citizen Complaint Inspections
One of the above Inspection types may be conducted, when appropriate to:
1. Investigate complaints from the public
2. Determine whether there Is a violation
3. Provide basis for enforcement action
4. Define nature and extent of violation
5. Provide data to assist In determining cause of violation
Complaints alleging Improper construction, complet-lon, operatlon'or
maintenance at an Injection well facility received by UIC staff will be
thoroughly Investigated. Response to complaints may consist of:
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1. Establishing the nature of the complaint
2. Reviewing appropriate EPA files
3. Establishing contact with the operator to verify the complaint and
discuss corrective action
4. Coordinating with other EPA, State or local regulatory authorities
5. Performing a site Inspection to determine If a problem exists
6. Referring the complaint to Regional Counsel for appropriate
enforcement action
2:16 PreoperatTonal Inspections
Site inspections to verify or witness drilling and completion procedures
will be conducted by UIC staff according to need and to availability of
resources. Owner/Operators are required to notify EPA of the Initiation
of construction operations. Construction operations and testing that may
be witnessed or supervised by the staff Include:
1. Wei I logging
2. Setting and cementing surface casing
3. Setting and cementing protection casing
4. Setting of tubing and packer
5. Formation pressure and Injectivlty testing
6. Formation fluid testing
7. Mechanical Integrity testing
2:17 Mechanical Integrity Test Inspections
Inspections to verify or witness mechanical Integrity tests may be
conducted on a scheduled basis during Routine Maintenance Inspections,
prior to authorizing Injection Into a new well as part of a
PreoperatIonaI Inspection, or at the conclusion of a well workover. The
scope of the Inspection Is dependent on well construction. Inspection
activities could Include:
1. Reviewing historical pressure monitoring data
2. Witnessing pressure test of annulus to evaluate internal mechanical
Integrity
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3. Witnessing logging or reviewing cementing records to evaluate
external mechanical Integrity
Satisfactory mechanical Integrity tests are required to be performed and
witnessed once every five years for Class I, II and some Class III wells.
All new Class I, II and III wells must have a demonstration of mechanical
Integrity prior to authorization to Inject.
2:18 Plugging and Abandonment Inspections
Abandonment of all classes of Injection wel-ls Is witnessed by Ul'C-
Inspectors to Insure that closure Is performed according to approved
plans and schedules. (Plugging and abandonment and notification
requirements are found In 40 CFR §144.28 (c), (j), and (k).) Inspections
will generally follow an operator's notification of Intent to plug and
abandon a well but could result from an enforcement action taken by the
Agency. Plugging and abandonment field activities will generally Include
both well preparation and plugging.
2:19 Closure of Class IV Wells
Injection Into Class IV welIs has been banned (Resource Conservation and
Recovery Act of 1976 as amended by the Hazardous and Solid Waste
Amendments of 1984, Sec. 7010). Proper closure of Class IV wells could
be more complex than for other classes of wells, because of the nature of
these operations and their potential for threatening public health.
Inspections are performed In order to:
1. Evaluate previously plugged Class IV facilities
2. Determine If reentry Into a previously plugged well Is required
3. Evaluate degree of hazard to public health
4. Install monitoring facilities If required
5. Witness plugging procedures
In addition to witnessing the closure of a Class IV well, Class IV
Inspections Involving sampling and reviewing company records may be
conducted to determine If, In fact, a welI Is a Class IV welI.
2:20 General Maintenance Inspections
The DIG staff may conduct regularly scheduled Inspections of permitted
Injection facilities In order to:
1. Verify that operations being carried out conform to conditions set
forth In the corresponding permit
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2:20
2. Detect developing conditions that might lead to future violations of
permit conditions or of regulations
3. Update EPA records on the facilities and their operations
4. Verify that operations are being conducted using adequate quality
assurance/qua IIty control procedures
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3 Techniques for Efficient Inspections
INSPECTION GOAL
A primary goal of the Inspector Is to assemble Information that can be
used for determining compliance with permit conditions, applicable
regulations and other requirements of the EPA UIC program. Th.Is
Information may ultimately result In enforcement case development and
support. In performing these duties, inspectors should observe standard
procedures for conducting legal and effective Investigations and In
meeting accepted safety practices and quality assurance requirements.
3:1 Legal Responsibilities for EPA UIC Program
The Environmental Protection Agency Is given authority under the Safe
Drinking Water Act to establish a program to regulate underground
Injection, to define control technologies, to obtain Information through
compliance Inspections and specific requests for Information, and to take
administrative, civil and/or criminal enforcement actions when violations
of the Act or Implemented regulations are discovered. Inspectors should
be familiar with the terms and conditions set forth by the SDWA and
should conduct all Investigations with Its legal framework In mind. This
Includes the following:
1. Presentation of proper credentials (SDWA §1445 [bTl])
2. Presentation of required notices and receipts (Notice of Inspection
Form, figure 3.1)
3. Proper handling of necessary warrants when facility entry Is denied
4. Handling of confidential Information
5. Proper handling of samples (Chaln-of-Custody) and photographs
3:2 Investigative Techniques and Procedures
This section describes the step by step procedures that should be
followed In making a thorough and efficient Inspection. Inspectors
should be familiar with these general Investigative procedures to ensure
accurate, concise and legally defensible Inspections. An outline of
procedural responsibilities In the Inspection process Is shown In table
3.1.
3:3 Pre-InspectIon Planning
Pre-Inspect Ion preparation Is essential to the effective planning and
overall success of an Inspection.' Pre-planning an Inspection will ensure
that It Is properly focused and efficiently conducted.
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TABLE 3.1
INSPECTOR RESPONSIBILITIES
1. Pre-Inspect Ion Preparation;
o Establish purpose and scope of Inspection
o Review background Information and Agency records
o Develop plan for Inspection
o Prepare documents and equipment
o Coordinate schedule with laboratory If samples are to be
collected
2. Entryj
o Present official credentials. (As per SDWA §1445 [bXHD
o Manage denial of entry If necessary
3. Opening Conference;
o Discuss Inspection objectives and scope
o Establish working relationship with facility officials
4. Facility Inspection;
o Review facility records
o Inspect monitoring equipment and operations
o Collect samples
o Prepare documentation of Inspection activities
5. Clos I ng Conferences
o Collect missing or additional Information
o Clarify questions with facility officials
o Prepare necessary receipts
6. FoLJow-upj
o Prepare a follow-up letter to confirm Inspection and summarize
results
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3:3
The first step Is to establish the purpose and scope of the Inspection.
This should give an Indication of the extent and degree of preparation
required for the Inspection.
Next, Inspectors should become familiar with all facility operations to
be Inspected and collect and review all background Information necessary
to conduct an efficient and thorough Inspection. The types of
Information available to the Inspector for gaining Insight Into facility
operations are:
»
General FaclI Ity Informatlon
1. Maps showing facility location, well locations, and geographic
features
2. Well names, numbers, and current operating status
3. Names, titles, and phone numbers of responsible fad I It/ officials
4. Nature of pretreatment and Injection
5. Production levels - past, present and future
6. Hydro-logical data
7. Geology/hydrogeology of the area
8. Changes In facility conditions since previous Inspection/permit
appl Icatlon
Requirements,. Regulations,, and Limitations
1. Copies of existing permits, regulations, and requirementsFederal,
State, and localand restrictions placed on discharges, compliance
schedules, monitoring and reporting requirements, monitoring
locatlon(s), available monitoring equipment and analytical methods
used by faclIIty
2. Any exemptions and waivers
3. Previous facility applications for water, air, and solid waste
permits (these files may contain useful data not shown elsewhere)
Injection Well and Pre-Treatment Systems
1. Description and design data for Injection well system and process
operation
2. Sources and characteristics of Injected fluids
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3:3
3. Type and quantity of fluids Injected
4. Spill prevention control and containment (SPCC) plan
5. Available by-passes or diversions and spill containment facilities
6. Pollution control, treatment methods, and monitoring systems
7. Well completion Information
8. Inspection history of flow and pressure meters
Facility Compliance and Enforcement History
1. EPA and State compllance files
2. Correspondence among facility, local, State and Federal agencies
3. Complaints and reports, follow-up studies, findings, and remedial
action
4. Previous Inspection reports, records, correspondence on past
Incidents of violations, status of requested regulatory corrective
action, If any, and compliance by facility
5. Status of current and pending administrative and/or judicial action
against faclIIty
6. Self-monitoring data and report
7. Previous EPA, State, and consultant studies and reports
8. Previous deficiency notices Issued to facility
The above Information can be obtained from compliance files of Federal,
State and local agencies.
Other sources of Information are:
1. Laws and Regulations - The Safe Drinking Water Act and amendments,
the Resource Conservation and Recovery Act (RCRA) and amendments,
and the Underground Injection Control Regulations establish
procedures, controls, and other requirements applicable to a
facility. In addition, State laws and regulations, and sometimes
even local ordinances, are applicable to the same facility.
2. Permits and Permit Applications - Permits provide site specific
Information on the limitations, requirements, and restrictions
applicable to underground Inject I on/compllance schedules as well as
monitoring, analytical, and reporting requirements. Permit
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3:3 - 3:4
applications provide technical Information on facility size, layout,
and location of waste sources; treatment and control practices;
contingency plans and emergency procedures; waste characteristics,
types, and volumes; and locations of wells.
3. Regional and State Files and Contracts - Files and contracts often
can provide facility self-monitoring data, Inspection reports, and
permits and permit applications related to Individual facilities.
They can provide compliance, enforcement, and I Itlgatlon history;
exemptions and waivers applied for and granted or denied; citizen
complaints and actions taken; process and operational
problems/solutions; pollution problems/solutions; laboratory
capabilities or Inadequacies; and other proposed or historical
remedial actions. Consultant reports can provide design,
construction and operation data and recommendations for remedial
measures and safe operating parameters.
4. Technical Reports, Documents, and References - These sources provide
Information on enhanced recovery operations, as wel I as data on
available pretreatment techniques
5. Other Statutory Requirements - Facility files maintained pursuant to
other statutory/regulatory requirements
3:4 Inspection Plan Development
Once the purpose of the Inspection has been establI shed and al I necessary
background Information has been reviewed, a plan for Inspection should be
developed. This should Include a comprehensive list of tasks to be
performed and the resources needed to complete them. Procedural steps
and scheduling should also be detailed In the Inspection plan. The
following Items generally should be Included In an Inspection plan:
Objectives:
1. What Is the purpose of the Inspection?
2. What Is to be accompl I shed?
Tasks;
1. What tasks are to be completed?
2. What Information must be collected?
Procedures:
1. What procedures are to be used?
2. Will the Inspection require special procedures?
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Resource sj
1. What personnel will be required?
2. What equipment or Instruments will be required?
3. What safety precautions should be taken? What safety precautions
are required by the facility owner/operator? (This Is especially
Important when the facility Is Injecting hazardous wastes.)
3:5 Inspection Schedule
1. What will be the time requirements for Inspection activities?
2. What will be the key tasks to be accomplished during the Inspection?
3. Has there been schedule coordination with the "lab where samples are
taken?
3:6 Notification of Interested Parties
The final step In pre-Inspect Ion preparation concerns notification of
personnel and agencies to be Involved In the Inspection process.
Notifications may be made by telephone, particularly In an emergency
situation, and followed promptly by a letter. This procedure Is used In
several states. A notice of Inspection usually requests Information
regarding specific facility safety regulations and may Include the date
of Inspection and a schedule of procedures for coordinating Inspection
activities with the facility.
3:7 Unannounced Inspections
Situations Involving suspected Illegal discharges or emissions may
warrant'an unannounced Inspection If there Is concern some crucial
evidence may be altered or destroyed. See also 3:14, "Emergency"
S ItuatIons.
3:8 Fac11Ity Entrance
Consensual entry will be the norm for most Inspections and the following
procedures should be applied when entering a facility. The Inspector
should arrive during normal working hours and Immediately locate the
facility owner or appropriate agent. The Inspector should clearly
Identify himself as an EPA UIC Inspector, present the proper credentials
and a notice of Inspection (figure 3.1). Credentials must be presented
before performing any Inspection duties.
Inspectors should not sign any "waiver" or "release" that relieves the
facility of responsibility for Injury or restricts the use of Information
obtained during the course of the Inspection.. This approach does not,
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U.S. ENVIRONMENTAL PROTECTION AGENCY
Notice of Inspection
Address (EPA Regional Office)
Date
Hour
Firm Name
Firm Address
Inspector Name 4 Title
Inspector Signature
Notice of Inspection is hereby given according to Section 1445 (b) of the Safe
Drinking Water Act (42 U.S.C. §300 f et seq.).
Reason for Inspection
For the purpose of inspecting records, files, papers, processes, controls
and facilities, and obtaining samples to determine whether the person subject
to an applicable underground Injection control program has acted or is acting
In compliance with the Safe Drinking Water Act and any applicable permit or
rule.
Section 1445 (b) (c) of the SDWA (42 U.S.C. §300 j-4 (b) (c) is quoted on the
reverse of this form.
EPA FORM
Receipt of this Notice of Inspection Is hereby acknowledged.
Name:
Title:
Date: _
Figure 3.1 Notice of Inspection
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Section 1445.
# # * * *
(b)(1) Except as provided In paragraph (2), the Administrator, or
representatives of the Administrator duly designated by him, upon presenting
appropriate credentials and a written notice to any suppl ler of water or other
person subject to (A) a national primary drinking water regulation prescribed
under section 1412, (B) any applIcable underground Injection control program,
or (C) any requirement to monitor an unregulated contaminant pursuant to
subsection (a), or person In charge of any of the property of such suppller or
other person In charge of any of the property of such supplier or other person
referred to In clause (A), (B), or (C), Is authorized to enter any-
establishment, facility, or other property of such supplier or'other person In
order to determine whether such suppller or other person has acted or Is
acting In compliance with this title, Including for this purpose, Inspection
at reasonable times, of records, files, papers, processes, controls, and
facilities, or In order to test any feature of a public water system,
Including Its raw water source. The Administrator or the Comptroller General
(or any representative designated by either) shal I have access for the purpose
of audit and examination to any records, reports, or Information of a grantee
which are required to be maintained under subsection (a) or which are
pertinent to any financial assistance under this title.
(2) No entry may be made under the first sentence of paragraph (1) In an
establishment, facility, or other property of a supplier of water or other
person subject to a national primary drinking water regulation If the
establishment, facility, or other property Is located In a State which has
primary enforcement responsibility for public water systems unless, before
written notice of such entry Is made, the Administrator (or his
representative) notifies the State agency charged with responsibility for safe
drinking water of the reasons for such entry. The Administrator shalI, upon a
showing by the State agency that such an entry will be detrimental to the
administration of the State's program of primary enforcement responsibility,
take such showing Into consideration In determining whether to make such
entry. No State agency which receives notice under this paragraph of an entry
proposed to be made under paragraph (1) may use the Information contained In,
the notice to Inform the person whose property Is proposed to be entered of
the proposed entry; and If a State agency so uses such Information, notice to
the agency under this paragraph Is not required until such time as the
Administrator determines the agency has provided him satisfactory assurances
that It will no longer so use Information contained In a notice under this
paragraph.
(c) Whoever falls or refuses to comply with any requirement of subsection (1)
or to allow the Administrator, the Comptroller General, or representatives of
either, to enter and conduct any audit or Inspection authorized by subsectfon
(b) shall be subject to a civil penalty of not to exceed $25,000.
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3:8 - 3:9
however, apply to contractors. Denial of entry will be discussed In
Section 3:16.
3:9 Opening Conference
The Initial meeting with the permittee should detail the scope of the
.Inspection and the schedule to be followed during the Inspection. The
authority under which this Investigation Is being conducted should be
specified and the names of all personnel (EPA and Contractor) Involved
with this Inspection should be provided to the permittee. This opening
conference should promote cooperation and a professional workln.g
atmosphere which will ultimately contribute to the success of the
Inspection.
Jjispect IQJI Objectives.;
An outline of the Inspection objectives Informs facl'llty officials of the
purpose and scope of the Inspection and may held avoid misunderstandings.
Inspection Schedule;
A discussion of the order In which operations will be Inspected helps
eliminate wasted time by allowing officials time to make records
available and start up Intermittent operations.
SplIt Samples:
Facility officials should be Informed during the opening conference of
their right to receive a split of any sample collected for laboratory
analysis.
Meetings;
A schedule of meetings with key personnel a I lows them to a I locate clear
times to spend with the Inspector.
Recordsj
A list of records to be Inspected allows officials to gather and make
them available to the Inspector.
Accompaniment;
It is Important that a facility official accompany the Inspector during
the Inspection not only to describe the site and Its principal operating
characteristics, but also for safety and liability considerations.
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3:9
Permit Verification;
The Inspector should verify the following Information with facility
officials:
1. Name and address of facility
2. Composition and source of Injection fluids
3. Injection rates and pressures
4. Number and location of Injection welIs .
5. Operating status of Injection wel Is
6. Adequate quality assurance/quality control
7. Calibration and maintenance of monitoring devices
Safety Requirements;
The Inspector should determine which EPA, OSHA and facility safety
regulations are applicable to the Inspection, and should be prepared to
meet these requirements (See chapter 5.0).
New Requlj~emsntsj
The Inspector should discuss any new rules and regulations that apply to
the facility and answer any questions pertaining to them.
Photographs;
Photographs are used to clarify and supplement written Information In the
Inspection report, and to provide' evidence for enforcement proceedings.
The facility, however, may object to the taking of photographs. If a
mutually acceptable solution cannot be reached and photographs are
considered essential to the Inspection, Agency supervisory and legal
staff should be contacted for advice.
Facility personnel may also request that any photographs taken during the
Inspection be considered confidential. The Agency Is obliged to comply
with this request pending further legal determination. Self-developing
film, although lower quality, Is useful In certain situations. The
facility's official representative may refuse permission to take
photographs unless they can see the finished print. Dupllca-te
photographs (one for the Inspector and the other for the Company) should
satisfy this need.
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3:10
3:10 Facility Inspection and Documentation
The inspector Is responsible for providing documentation of any suspected
permit violations or other discrepancies uncovered during an Inspection.
A detailed record of Inspection procedures, field observations and
physical evidence collected should be maintained for later use In any
enforcement proceedings, as a basis for written reports, or for
examination by compliance personnel. Inspectors should use a hardbound
field notebook with numbered pages. All documentation should be done In
Ink (mistakes and corrections Initialed). The following types of
Information should be recorded during an Inspection:
Observations;
All conditions, practices, and other observations that will be useful In
preparing the Inspection report or that will contrlb-ute to val Id evidence
should be recorded.
Procedures;
Inspectors should describe all procedures followed Involving entry,
sampling, records examination and document preparation.
Documents;
All documents taken or prepared by the Inspector should be noted and
related to specific Inspection activities.
Samples^
"Chaln-of-custody" procedures must be followed to control the fate and
condition of samples from collection to final analytical results
reported. The system must ensure that no alterations or loss of samples
occurred from the time they were taken to the time they were analyzed.
All quality assurance/quality control procedures should be strictly
adhered to.
Statements;
Formal statements obtained from facility personnel can be useful In
documenting an alleged violation. The person making the statement should
have personal, firsthand knowledge of the Information. The following
procedures and considerations should be used when documenting a formal
statement:
1. Determine the need for a statement. WIN It provide useful
Information? Is the person making the statement qualified to do so
by personal knowledge?
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3:10
2. Ascertain all the facts and record those whfch are relevant and
which the person can verify In court, making sure all Information Is
factual and firsthand, and avoiding taking statements that cannot be
personally verified.
Statement Preparation!
1. Use a simple narrative style, avoiding stilted language
2. Narrate the facts In the words of the person making the statement
3. Use the first-person singular ("I am manager of...")
4. Present the facts In chronological order (If possible)
5. Positively Identify the person (name, address, -position)
6. Show why the person Is qualified to make the statement
7. Present the pertinent facts
8. Have the person read the statement and make any necessary
corrections before signing. If necessary, read the statement to the
person In the presence of a witness
9. All mistakes that are corrected must be Initialed by the person
making the statement
10. Ask the person making the statement to write a brief concluding
paragraph Indicating that he or she read and understood the
statement (this safeguard will counter a later claim that the person
did not know what he or she was signing)
11. Have the person making the statement sign It
12. If he or she refuses to sign the statement, elicit an acknowledgment
that It Is true and correct. Ask for a statement In his or her own
hand ("I have read this statement and It Is true but I am not
signing It because..."). Falling that, declare at the bottcm of the
statement that the facts were recorded as revealed and that the
person read the statement and avowed It to be true. Attempt to have
any witness to the statement sign the statement Including witness'
name and address
13. Provide the person with a copy of the statement
Photographs,:
Photographs provide an objective view of facility conditions during the
Inspection. The permittee's approval should be obtained before
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3:10
photographing any facility operations; however, photographs may always be
taken from public areas. The following details should be recorded when
taking photographs during an Inspection:
1. Name and title of the photographer and witness (If any)
2. Type of film used (I.e., brand, size, expiration date, ASA number,
etc.)
3. Focal length of the lens being used
4. F-stop and shutter speed at which the camera Is set
5. Lighting conditions encountered
6. Time of day, weather conditions
7. Date
8. Location, and direction camera Is facing
9. A brief description (scale) of the subject being photographed
Record a brief description of the photograph (location, subject, date,
etc...) on the back of the photograph to simplify later Identification.
Drawings and Mapsi
Maps, drawings and charts are valuable tools In producing an accurate
schematic representation of the facility under Inspection. Oilfield maps
can be used to locate production and Injection welIs.
Records'and File Copies;
This Information can provide Important Insight Into a facility's
condition and operations. Records and files can be In several forms
written or printed materials, computer or electronic records, or
photographic records. Follow these suggestions when examining and
copy Ing records.
1. Group related records together
2. Handle confidential business records according to EPA procedures.
Not all records may be claimed as business confidential (see 40 CFR
Part 2). .If In doubt, treat the records as confidential until" a
decision on the claim can be obtained from the appropriate EPA
official
3. Note physical location of the original record (I.e., address of the
.facility, building number, room number)
3-15
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3:10 - 3:12
4. Obtain and record Information about a facility's recordkeeplng
procedures which may be useful In later Inspections
5. Return originals, after copying, to the proper personnel or to their
correct location
Unusual Conditions and ProbJemsj
Describe unusual conditions and problems In detail.
General Information^
List In the Inspection report the names and titles of facility personnel
and the activities they perform, along with any pertinent statements they
made.
3:11 Closing Conference
Following the Inspection the results may be discussed with the facilities
management team or operating personnel In a closing conference. This
discussion may cover all specific findings of the Investigation and where
appropriate, the findings should be compared with the facility's DIG
permit requirements.
The Inspector must refrain from discussing any legal or enforcement
consequences with the permittee. He should not recommend any service
company or consultant for correcting existing or potential well problems.
3:12 Sample Collection and Handling
Size and Approximate Mumber of Samples to be Taken
The number of samples depends on the Inspection objective, type of site
Inspected and Information desired. The sample, representative of the
main body of waste, must be adequate In size for all needs Including
laboratory analyses or splitting with other organizations. Appendix D
presents data on recommended containers, preservatives and holding times
for various analyses. All sample containers, Including those used In
sampling hazardous waste, should be filled to overflowing before capping
to reduce the loss" of any volatile components and to reduce possible
oxidation. All sampling should follow the approved Quality Assurance
Project Plan for the State.
Sample Containers
Sample containers must be chemically clean and of the design and size
specified by the analytical laboratory for the particular type of waste,
the required preservation, and the required analytical procedure. The
EPA Handbook for Analytlcal Quailty Control In Water and Wastewater
Iaboratorles (EPA 600/4-79/019) gives special Instructions for the
3-16
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3:12 - 3:14
cleaning of bottles to be used for organic analysis. For some samples It
Is possible to use a new plastic container and dispose of It after
completing the. analysis.
Types of Samples Grab or Composite
A grab sample Is one taken from only one point at one particular time.
Most Class II well facilities will require grab samples. If sampling
points are provided, the wellhead Is an Ideal place to take a grab sample
of the Injected fluids. It should be noted that all samples of the waste
stream should be taken at a point which Is down I I-ne from all treatment
units, such as a filter. WIdemouth sampling containers are preferred to
facilitate rapid collection; the sample volume Is set by the analytical
laboratory. Individual grab samples are required If analyses for
dissolved gases, residual chlorine, sulfldes, or pH are to be made.
These require Immediate preservation and sealing (see appendix D).
A composite sample Is a mixture of Individual samples collected "over
time." A composite Is more representative of the average wajste
composition than a grab sample. Care must be taken not to mix
Incompatible wastes.
A Class I Injection stream should be sampled proportional to the flow
rate. A typical ratio Is one mllllllter sample for each gallon per
minute of flow. Automatic liquid samplers composite samples on the basis
of flow or time.
3:13 Chain of Custody
Follow Chaln-of-Custody Procedures. The Agency must be In a position to
demonstrate the reliability of analytical test results by proving the
chain of possession from the time of col lection through transportation to
the laboratory, storage, handling and analysis. Procedures have been
established by the EPA to create an accurate written record that can be
used to trace the possession of the sample from the moment of Its
collection through Its Introduction Into evidence. Details of sample
control are Included In the NEIC Policies and Procedures Manual (EPA-
330/9-78-001) and In the Regional or State UIC Quality Assurance Project
Plan. Instructions for completing the Chaln-of-Custody record are
Included In appendix A. Further sources of Information on sampling and
sample handling are Included In the reference section at the end of this
chapter.
3:14 The Right of Warrantless Entry
"Emergency" Situations
In an emergency, where there Is not time to get a warrant, a warrantless
Inspection Is permissible. The Regions will always have to exercise
considerable judgment concerning whether to secure a warrant when .deal Ing
3-17
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3:14 - 3:16
with an emergency situation. However, If entry Is refused during an
emergency, the Agency would need the assistance of the U.S. Marshal to
gain entry, and a warrant could probably be obtained during the time
necessary to secure the Marshal's assistance.
An emergency situation would Include potential Imminent hazard
situations, as well as situations where there Is potential for
destruction of evidence or where evidence of a suspected violation may
disappear during the time that a warrant Is being obtained.
"Open Fields" and "In Plain View" Situations
Observation by Inspectors of things that are In plain view, that Is,
things that a member of the public could be In a position to observe,
does not require a warrant. Thus, an Inspector's observations from the
public area of a plant or even from certain private property not closed
to the public are admissible. Observations made eve'n before presentation
of credentials while on private property which Is not normally closed to
the public are admissible.
3:15 Withdrawal of Consent to Inspection
The owner may withdraw his consent to the Inspection at any time. The
Inspection Is valid to the extent to which It has progressed before
consent was withdrawn. Thus, observations by the Inspector, Including
samples and photographs obtained before consent was withdrawn, would be
admissible In any subsequent enforcement action. Withdrawal of consent
Is tantamount to a refusal to allow entry and should be treated as
discussed above, unless the Inspection had progressed far enough to
accomplish Its purposes.
3:16 Dental of Entry
Denial of entry Into a facility requires certain procedural steps that
should be undertaken by the Inspector to ensure that proper legal
guidelines are followed. The steps outlined below are In accordance with
the Safe Drinking Water Act and the 1978 U.S. Supreme Court decision In
Marshal vs. Barlow's. lnc.r U.S., 98 S. Ct. 1816, and should be followed
In the event entry to a facility Is denied for Inspection purposes. A
professional attitude should prevail at all times.
Inspector 1dent IfIcatlon
Upon arrival at the facility the Inspector should clearly Identify
himself as an EPA UIC Inspector and present the proper credentials and
notlce(s) of Inspection to the facility owner or agent In charge.
The establishment owner may complain about allowing an Inspector to enter
or otherwise express his displeasure with EPA or the Federal government.
However, as along as he allows the Inspector to enter, the entry Is
3-18
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3:16
voluntary and consensual. On the other hand, If the Inspector gains
entry In a coercive manner (either In a verbal or physical sense), the
entry would be not be consensual.
Barlow's clearly establishes that the owner does have the right to ask
for a warrant under normal circumstances. Therefore, refusal to a I low
entry for Inspectlonal purposes will not lead to civil or criminal
penalties If the refusal Is based on the Inspector's lack of a warrant
and the situation Is such that the right of warrantless entry doesn't
exist (to be discussed later). If the owner were to allow the Inspector
to enter his establishment only In response to a threat of enforcement
liability, It Is quite possible that any evidence obtained In such an
Inspection would be Inadmissible. An Inspector may, however, Inform the
owner who refuses entry that he Intends to seek a warrant to compel the
Inspection.
Reason for Denial
If entry Is not granted, ask why. Tactfully probe the reason for the
denial to see If obstacles (such as misunderstandings) can be resolved.
If resolution Is beyond the authority of the Inspector, he or she may
suggest that the facility officials seek advice from their attorneys on
clarification of the scope of EPA's Inspection authority under the Safe
Drinking Water Act.
Denial ConfIrmed
If entry Is still denied, the Inspector should leave the premises
Immediately and telephone the designated Regional Enforcement Attorney as
soon as possible for further Instructions. The Regional Enforcement
Attorney should contact the U.S. Attorney's Office for the district In
which the establishment desired to be Inspected Is located and explain to
the appropriate Assistant United States Attorney the need for a warrant
to conduct the particular Inspection. The Regional Attorney should
arrange for the United States Attorney to meet with the Inspector as soon
as possible. The Inspector should bring a copy of the appropriate draft
warrant and affidavits.
Record Details of Denial
All observations pertaining to the denial are to be carefully noted In
the field notebook. Include facility name and exact address, name and
title of person(s) approached, authority of person(s) who refused entry,
time of denial, reason for denial, facility appearance, any reasonable
suspicions that refusal was based on a desire to cover up regulatory
violations, etc. All such Information will be Important should a warrant
be sought.
3-19
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3:17 - 3:18
3:17 The Warrant
In the event that a warrant becomes necessary the Inspector should be
aware of what Information Is required to obtain a warrant. There are
several general rules for securing warrants. Three documents have to be
drafted:
1. An application for a warrant
2. An accompanying affidavit
3. The warrant
Each document should be captloned with the District Court of
jurisdiction, the title of the action, and the title of the particular
document.
The application for a warrant should generally Identify the statutes and
regulations under which the Agency Is seeking the warrant, and should
clearly Identify the site or establishment desired to be Inspected
(Including, If possible, the owner and/or operator of the site). The
application can be a one or two page document If all of the factual
background for seeking the warrant Is stated In the affidavit, and the
application so states. The application should be signed by the U.S.
Attorney or by his Assistant U.S. Attorney.
The affidavits In support of the warrant application are crucial
documents. Each affidavit should consist of consecutively numbered
paragraphs, which describe all of the facts that support warrant
Issuance. If the warrant Is sought In the absence of probable cause. It
should recite or Incorporate the neutral administrative scheme which Is
the basis for Inspecting the particular establishment. Each affidavit
should be signed by someone with personal knowledge of all the facts
stated. In cases where entry has been denied, this person would most
likely be the Inspector who was denied entry. Note that an affidavit Is
a sworn statement that must either be notarized or personally sworn to
before the magistrate or judge. See appendix F for examples of the
documents described above.
3:18 Inspection with Warrant
Once the warrant has been Issued by the magistrate or judge, the
Inspector may proceed to the establishment to commence or continue the
Inspection. Where there Is a high probability that entry will be refused
even with a warrant or where there are threats of violence, the Inspector
should be accompanied by a U.S. Marshal when he goes to serve the warrant
on the recalcitrant owner. The Inspector should never himself attempt to
make any forceful entry of the establishment. If the owner refuses entry
to an Inspector holding a warrant but not accompanied by a U.S. Marshal,
the Inspector should leave the establishment and Inform the Assistant
3-20
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3:18 - 3:21
U.S. Attorney and the designated Regional Attorney. They will take
appropriate action such as seeking a citation for contempt. Where the
Inspector Is accompanied by a U.S. Marshal, the Marshal Is principally
charged with executing the warrant. Thus, If a refusal or threat to
refuse occurs, the Inspector should abide by the U.S. Marshal's decision
whether It Is to leave, to seek forcible entry, or otherwise.
The inspector should conduct the Inspection strictly In accordance with
the warrant. If sampling Is authorized, the Inspector must be sure to
carefully follow all procedures, Including the presentation of receipts
for all samples taken. If records or other property are authorized to be
taken, the Inspector must provide a receipt for the-property taken and
maintain an Inventory of anything taken from the premises. This
Inventory will be examined by the magistrate to assure that the warrant's
authority has not been exceeded.
3:19 Returning the Warrant
After the Inspection has been completed, the warrant must be returned to
the magistrate or judge. Whoever executes the warrant, I.e., whoever
performs the Inspection, must sign the return of service form Indicating
to whom the warrant was served and the date of service. He should then
return the executed warrant to the U.S. Attorney who will formally return
It to the Issuing magistrate or judge. If anything has been physically
taken from the premises, such as records or samples, an inventory of such
items must be submitted to the court, and the inspector must be present
to certify that the Inventory Is accurate and complete.
3:20 Seeking a Warrant before Inspection
The Barlow's decision recognized that, on occasion, the Agency may wish
to obtain a warrant to conduct an Inspection even before there has been
any refusal to allow entry. Such a warrant may be necessary when
surprise Is particularly crucial to the Inspection, or when a company's
prior bad conduct and prior refusals make It likely that warrantless
entry will be refused. Pre-Inspect ion warrants may also be obtained
where the distance to a U.S. Attorney or a magistrate Is considerable so
that excessive travel time would be consumed If entry were denied. At
present, the seeking of such a warrant prior to an Initial Inspection
should be an exceptional circumstance, and should be coordinated through
Headquarters. If refusals to allow entry without a warrant increase,
such warrants may be sought more frequently (see appendix F).
3:21 Professional Business Ethics
Inspectors should conduct their Inspections with a high degree of
professionalism and workmanship. Since the inspector Is usually the
Initial or only contact between the operator and the regulatory agency It
is Imperative that he be dignified, tactful, courteous and diplomatic.
To promote good working relations and establish a cooperative atmosphere
3-21
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3:21 - 3:22
the Inspector should be firm but responsive. The following rules should
be applied when Inspecting a facility:
1. The Inspection should be developed and reported with complete
objectivity
2. Information acquired during an Inspection Is for official use only
3. No favors or benefits should be accepted under circumstances that
might be construed as Influencing the Inspector's performance of
duties
3:22 Inspection Report-
Inspection reports are essential and valuable tools In preparing evidence
reports and In providing clear, concise methods for correcting problems
and deficiencies noted during the Inspection.' A well organized
Inspection report should follow the general guidelines discussed In this
section.
Organization and ^Arrangement
The organization and arrangement of a report should be:
1. Accurate: All Information must be factual and based on sound
Inspection practices. Observations should be the verifiable result
of firsthand knowledge. Compliance personnel must be able to depend
on the accuracy of alI Information.
2. Relevant: Information In an Inspection report should be pertinent
to the subject. Irrelevant facts and data will clutter a report,
reducing Its clarity and usefulness.
3. Comprehensive: Suspected vlolatlon(s) should be substantiated by as
much factual, relevant Information as feasible to gather. The more
comprehensive the evidence Is, the better and easier the enforcement
task will be.
4. Coordinated: AM pertinent Information should be organized Into a
complete package. Documentary support (for example, photographs,
statements, samples and documentation) should be clearly referenced.
5. Objective: Information should be objective and factual; the report
should not speculate on the ultimate result of any factual findings.
6. Clear: The Information In the report should be presented In a
clear, well organized manner.
7. Neat and Legible: Allow time to prepare a neat, legible report,
type written If possible.
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3:22
Preparing and Writing the Inspection Report
Basic steps In preparing and writing the Inspection report are:
1. Reviewing the Information: The first step In preparing the
narrative Is to collect all Information gathered during the
Inspection. The Inspector's field notebook should be reviewed In
detail. All evidence should be reviewed for relevance and
completeness. Gaps may need to be filled by a phone call or, In
unusual circumstances, by a follow-up visit.
2. Organizing the Material: The Information may be organized In many
forms, depending on the Individual need, but should be presented In
a logical manner. An example of an Inspection report form has been
Included In appendix N.
3. Referencing Accompanying Material: Documentary support for a
narrative report should be clearly referenced so that the documents
can be readily located. Documents should be checked for clarity.
4. Writing the Narrative Report: The purpose of the narrative Is to
record factually the procedures used In, and findings resulting
from, the evidence-gathering process. The Inspector should refer to
routine procedures and practices used during the Inspection, but
should describe facts relating to potential violations and
discrepancies In detail. The field notebook Is a guide for
preparing the narrative report.
MaJji Body of the Report
The main body of the report should contain all pertinent facts and
Information acquired during the Inspection. It generally will contain
three basic Items listed below:
1. Permittee Compliance History
2. Documentary Support
3. Supplementary Narrative Information
Useful Guidelines In Writing
Useful guidelines In writing a narrative report Include:
1. General Information
o State location of facility and name, title and phone number of
person In charge
o Give general description of facility
3-23
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3:22
o State the purpose of the Inspection and how the facility came
to be Inspected (for example, operator notification, complaint
response, etc...)
2. Findings and Conclusions
o State what the findings of the Inspection were. Include any
problem areas that currently do, or potentially may, affect
com pi lance
o Compare compliance with permit requirements, Including effluent
limitations where appropriate
o Describe any problems, such as denied or withdrawn consent of
entry to the facility; reluctance; or If a warrant was needed.
3. Facility Information
o Give the size of the facility based on observations and
previous data for both production and Injection flows; give
number of we I Is
o Describe the Injection system and the operations
o Compare permit or permit application with actual facility
conditions (Include sampling points and.monitor Ing locations)
4. Documentation
o List the records reviewed, noting the reasons for their review,
and referencing documents that were borrowed or copied
o Describe any Inadequacies In recordkeeplng procedures, or If
any required Information was unavailable, Incomplete or
Inaccurate; special consideration should be given to pressure
and flow measurement records, and construction schedules (If
relevant)
o Note and reference any statements taken during the Inspection
o Reference any photographs taken during the Inspection that
relate to possible violations
o Reference any drawings, maps, charts, or other documents made
or taken during the Inspection
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3:22
5. Monitoring Information
o Describe sampling points and techniques used
o Note If split samples were taken
o Describe methods of annulus and Injection pressure monitoring
o Describe chaln-of-custody procedures used In handling samples
6. Attachments
o Prepare a list of all supporting documents (a general Index
will help compliance personnel to locate specific documents)
3-25
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REFERENCES
United States Environmental Protection Agency. J^PDES CompLJance Jnspectlon
Manual. Draft Report, EPA Office of Water Enforcement and Permits,
Washington, D. C., March, 1984.
United States Environmental Protection Agency. Sampling Documenttor U.S. EPA
Direct Implementation Program. Engineering Enterprises, Inc., Norman,
OK, March, 1986.
United States Environmental Protection Agency. J-iandbook for Samp I Ing and
Sample Preservation of Water and Wa^te Water. .EPA-600/4-82-029,
Washington, D.C.
United States Environmental Protection Agency. Revised Pratt Protocol for
Ground Water Jjis^iectlojis at Hazardous Waste Treatment and Disposal
Fact 11 ties, prepared for EPA by Versar, Inc., October, 1985.
3-26
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4 Inspections
INTRODUCTION
The general techniques for Inspections were discussed In detail In Chapter
Three. The purpose of Chapter Four Is to examine the different types of
Inspections that an Inspector may be asked to perform. These Include
preoperatlonal Inspections, mechanical Integrity test Inspections, plugging-
and abandonment, Class IV closure verification, emergency Inspections,
compliance verification, and citizen complaint Investigations. Each of the
following sections provides pertinent background Information and describes the
procedures required to perform each type of Inspection.
4:1 General Inspection Procedures
General Inspections by UIC Staff to verify or witness facility operations
may be conducted routinely according to a general plan, or In response
to a complaint or other Indications that a violation may exist. The
procedures outlined below are to be followed during all types of
Inspections. They are general guldel Ines for the Inspector, and any
observations made with regard to any of the Items In the following lists
should be duly recorded.
4:2 General Inspections
General Inspection of the Injection facilities and monitoring wells
should be routinely conducted by the Inspector while he Is on site and
should Include at least the following Items:
1. Check for changes to the Injection system, Including supply lines,
treatment, storage, and monitoring devices
2. Verify that there has been no change In facility process which could
affect the waste stream
3. Check for signs of surface spills related to Injection facility
4. Check for signs of well workover since last Inspection
5. Check for signs of corrosion, rust, wear and damage to surface
facllItles
6. Check Instruments (gages, manometers, recorders, meters, etc.) for
sensitivity and accuracy
7. Verify that number and Identity of Injection and monitoring wells
agree with those listed In the permitting documents
4 - 1
-------
4:2 - 4:3
Review records to verify compliance with permit and/or regulatory
conditions: The Inspector should verify that all required Information
has been accurately recorded and Is up-to-date. Facility operations
should be compared with permit conditions to verify compliance. The
records review should Include an examination of operator records on QA/QC
for all monitoring devices and for the samp I Ing analyses of Injected
fluid. (Include review of sampling method.)
If any activities differ from those stated In the permit the inspector
should note whether EPA was notified. An examination of records showing
Injection rates and pressures and physical and chemical properties of the
injected fluids can reveal the operating history of the facility.
Figures 4.1, 4.2, and 4.3 are EPA forms used by Injection well
owners/operators to report required Information.
Rev Iew th e seIf-mgn I tor In g system and reporting procedures: The EPA DIG
Program requires that permittees maintain records and report periodically
the amount and nature of waste Injected. Routine Inspections should be
conducted at all permitted facilities to verify compliance with permit
and/or regulatory requirements. A review of facility records should
encompass the following:
1. Is the monitoring performed according to permit or rule
requirements?
2. Is all required Information available?
3. Is the Information correct?
4. Is the information being maintained for the required period of time?
5. Are the monitoring gauges properly maintained and frequently
calIbrated?
Evaluate the operation and maintenance of the facility. After careful
observation of a facility and review of Its performance records, the
Inspector should determine If anything requires further Investigation.
He should decide whether the owner/operator has complied with applicable
requirements or If he needs assistance.
4:3 Check List for General Site Inspection
Examination of Injection Facility. Verify:
1. Information contained In the permit
2. Adequacy of equipment calibration and maintenance
3. Adequacy of backup facilities (if any)
4-2
-------
3 EPA
UNCTIO STATES (MVMOMMCNTAb MOT1CT1ON ACIMCT
WASMWSTO*. OC 10MO
ANNUAL DISPOSAL/INJECTION WELL MONITORING REPORT
HAMf AMOAOOM>VO> OOSTMC nUMITTU
MAMSAMOAOOMCSSOtSUWACSOWMCft
LOCATI WCLk AND OUTUM UMT ON
UCTIOM I>T - MO
I I I
I I
i I I
I ! i
i 1 l
STATI COUNTY
4 0*
-40*
LOCATI WHO. M TWO OMSCnOM MOM NtAMST UMS Of OUAMTVH StC^ON AMD OHIUJNG UNfT
WCU.ACTTVTTV
PB
C i H«> portion Sier«g« Numoar o* Watt* .
TOTAL VOUIMC MJSCTCO
ruu
WOMTVI
AVtlUr and all attachments and that, bestd on my inquiry of tr.jsa individuals immediately resoonsitlojor
obtaining the information. I believe that tha informotion is trua. accurate, and complete. I am aware that there are
significant penalties for submitting false information, including the possibility of tine and imprisonment. (Ret. 4O
CFR 144.32).
rrru (/*.« n*» *> ***i
OATE StCMtO
6PA form 78JO-11 (2-M)
Rgure 4.1 Annual Injection Monitoring Report
4-3
-------
THIS PAGE INTENTIONALLY LEFT BLANK
4-4
-------
UNITEb STATES ENVIRONMENTAL PROTECTION AGENCY
A _. -^ - WASHINGTON, DC 20460
VC PA INJECTION WELL MONITORING REPORT
YEAR
Injection Pressure (PSI)
1. Minimum
2. Average
3. Maximum
Injection Rate (Gal/Min)
1 . Minimum
2. Average
3. Maximum
Annular Pressure (PSI)
i
1. Minimum
2. Average
3. Maximum
Injection Volume (Gal)
1 . Monthly Total
2. Yearly Cumulative
Temperature (F°)
1 . Minimum
2. Average
3. Maximum
pH
1. Minimum
2. Average
3. Maximum
Other
MONTH
MONTH
-
Name and Address of Permittee
Name and Official Title /Please type or print)
Signature
Form Approved
OMB No. 20OO-OO42
Approval expires 9-30-86
MONTH
Permit Number
Date Signed
EPA Form 7620-8 (2-84)
Rgure 4.2 Monthly Monitoring Report
4-5
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4-6
-------
For Sample Use Only - Comparable Format Acceptable
U.S. ENVTSOWENTAL PROTECTION AGENCY MONTHLY MONITORING REPORT
FOR CLASS INJECTION WELLS
Insert Operator Name 6 Address
Sheet
of
Please complete and subnit this report at the end
of each month. This report must be postmarked no
later than Che 10th day of the following month.
PERMIT NUMBER
MO. YEAR
check one >
ECR
SWD
DATE
1
2
3
4
5
INJECTION PRES. (psxq)
6 I
7 I
3
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
2<3 I
27
28 1
29
30
31
AVtSA/Gi.
HIGHEST
VALUE
LOWEST
VALUE
ANNULUS PRES. (psig)
FLOW RATE (BPO)
CUM. VOL. (BPD)
Specific Gravity of Injected Fluids:
Rgure 4.3 Daily Monitoring Report
4-7
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4-8
-------
4:3
4. Performance of pre-lnjectlon facilities
5. Suitability and operation of monitoring equipment
6. Efficiency of manifold monitoring
7. Evidence of surface contamination
8. Evidence of noncompllance with regulatory requirements
Permit Verification and Compliance Review. Verify:
1. Name and mailing address of permittee
2. Facility description In permit
3. Proper notification of any operational changes to EPA/State
4. Maintenance of accurate records of Injection volumes and pressures
5. Number and location of wells as described In the permit
6. Description and source of Injection fluids
7. Permits for all wells In use
Self-Monitoring and Reporting Review. VerIfy:
1. All data, measurements, and analyses required by permit
2. Monitoring wel I locations
3. Calibration of monitoring equipment
4. Sampling and analysis data adequacy
o Dates, times, location of samp I Ing
o Name(s) of Individual(s) performing sampling
o Sample volumes, kinds of containers, preservation, and storage
o Analytical methods and techniques
o Results of analyses
o Names of laboratories and personnel performing analyses
o Instantaneous flow at grab sample stations
4-9
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4:3
Operation and Maintenance Evaluation. VerIfy;
1. All required Information available and current
2. Information maintained for required period
3. Plant records adequacy
o 0 & M Manual
o "As-built" engineering drawings
Injection Fluid Samples.
1. Obtain either grab (using procedures from Chapter 3) or composite
samples, as required
2. Measure pH, temperature and conductivity of Injection fluid, where
possible,
3. Observe qua IIty assurance/qua IIty control procedures
4. Follow chaln-of-custody procedures
5. Obtain spl It samples, If owner/operator so requests
6. Document samples In field notebook
The remaining sections In this chapter will address the correct protocol
to be followed, In addition to those outlined In 4:2 and 4:3, when
performing each type of Inspection. The Inspection types to be discussed
are:
Preoperational
Compllance verification
Mechanical Integrity test
Plugging and abandonment
Class IV closure
Emergency
Citizen complaint Investigation
4-10
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4:4 - 4:5
4:4 Preoperatfonal Inspections
After a new UIC permit Is granted and prior to start-up, the Inspector
may perform several preoperatlonal Inspections. The purpose of these
Inspections Is to (1) assure that the well Is constructed so as to
protect the USDW; (2) assure that any. deviations from the construction
design were approved by the EPA; (3) determine If the geology and
hydrogeology encountered during drilling are as described In the permit
application; and (4) assure that the well has mechanical Integrity and
Injection potential prior to being approved for use.
There are certain critical construction activities the Inspector should
witness. Seme of the more Important are:
Open hole and cased hole logging
Primary cementing
Formation pressure and Inject Ivlty testing
Mechanical Integrity testing
It Is strongly recommended that the owner/operator be required to notify
the EPA when drllling begins, and not less than 72 hours before any other
critical construction activity (as defined by EPA) Is scheduled to take
place. This permits the Inspector to plan In advance his visit to the
site.
4:5 Logging
Several comprehensive references on well log analysis are listed at the
end of this chapter. A brief description of conmonly used logs Is
presented below. A general checklist for witnessing well logging In the
field Is also Included.
Logging provides subsurface Information on:
Geologic strata kinds and thicknesses penetrated by the well
Condition (regularity) of the drilled (open) bore hole
Kinds of fluids present In the strata
Integrity of cemented Intervals
Integrity of steel casing In the welI
Presence and significance of leaks through the annul us outside the casing
and through the formations close to the welI.
4-11
-------
4:5 - 4:7
Some logging tools yield useful Information only In open (uncased) holes;
others only In cased holes; a few In both open and cased holes.
Electric logs, borehole callper logs, and density logs are limited to
open-hole conditions, because any casing present In the hole would shield
the tools from required contact with, or effect of, the rocks. Cement
bond, casing, and radioactive tracer logs are used only In cased holes.
Radioactive (gamma and neutron) and temperature logs can be used In
either open or cased holes.
Many logging techniques require circulation of drilling or workover
fluids prior to logging; some can be run In dry holes.
Some logging tools are not suitable for use In conductive fluids
(drilling mud, brine, etc.), while others are adversely affected by
nonconductIve fluids. With the proper selection and use of logging
equipment temperature, pressure, resistivity, flow, depth, hole size, and
llthology can all be measured or described. Some parameters must be
calculated or Inferred from logs. For example, no logging method can now
directly measure permeability, extent of rock fracturing, or mechanical
properties of formation rocks.
Well logging can be divided Into five general categories: llthologlc,
electrical, radioactive, acoustical, and specialized. The methods, with
their applications, are shown In table 4.1. Well servicing companies
have different trade names for equivalent types of geophysical logs (see
table 4.2).
4:6 Llthologlc Logging
Many formations can be Identified by examination of samples retrieved
during drll I Ing.
Rotary drilling provides continuous formation samples obtained as
cuttings. A sample or mud log Is a continuous description of the
geologic character of each stratum and the depth at which each change
occurs. It may also Include drilling times and gas content of the mud.
Ideally, representative samples should be collected at measured depths
and at such Intervals as will show the Iithologlc character of the
formations penetrated.
4:7 Electric Logging
Electric logging Is a process by which electrical measurements provide
data on the formations penetrated by the borehole, The principal
downhole measurements made are voltage and resistance. These electrical
properties are measured by lowering a tool Into the borehole and
recording spontaneous potential (voltage), resistivity, and the Inverse
of resistivity: conductivity.
4-12
-------
TABLE 4.1 - WELL LOGGING METHODS AND USES
Method
Type
Lithologic
Coring
Mud Log
Cuttings Samples
Electrical
Resistivity
Spontaneous Potential
Radioactivity
Natural Gamma Ray
Gamma -Gamma (Density)
Neutron
Radioactive Tracer
Acoustic
Cement Bond
Sonic Logs
Visual
Downhole Televiewer
Specialized
Temperature
Directional Survey
Caliper
Flow Meter
Casing-Collar Locator
Casing-Inspection Log
Formation
Identification
Physical
Formation*
Characteristics
^.-m.-^-mm.m.'m'mi
t^Kmi^'m'^'m'm'v
^m.-m'm.'^'m'm^f
Fluid
Flow
Well Construction
Influence
Evaluate
.
*.m.^<
^m.
-------
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4-14
-------
TABLE 4.2 SOME GEOPHYSICAL WELL LOGGING SERVICES AVAILABLE FROM THREE
COMPANIES PROVIDING WELL LOGGING SERVICES. EQUIVALENT TYPE
LOGS ARE LISTED ON THE SAME LINE ACROSS THE TABLE.
COMPANY
WELEX
SCHLUMBERGER
DRESSER - ATLAS
o
o
Electric Log
Induction Electric Log
Dual Induction Guard Log
Guard Log
Contact Log
FoRxo Log
Acoustic Velocity Log
Compensated Acoustic Velocity Log
Fracture Finder Log
Micro-Seismogram Log
Density Log
Compensated Density Log
Simultaneous Gamma Ray-Neutron Log
Side Wall Neutron Log
Electrical Log
Induction Electrical Log
Dual Induction Laterolog
Laterolog-3, Laterolog-7
Microlog
Microlaterolog
Proximity Log
Sonic Log
BHC Sonic Log
Amplitude Log
Variable Density Log
Formation Density Log
Compensated Formation .Density
Log
Gamma Ray-Neut ron Log
SNP Neutron Log
Electrolog
Induction Electrolog
Dual Induction Focused Log
Laterolog
Minilog
Micro-Laterolog
Proximity Log
Acoustilog
BHC Acoustilog
Fraclog
Variable Amplitude Density
Log
Densilog
Compensated Densilog
Gamma Ray-Neutron Log
Epithermal Sidewall Neutron
Log
-------
4:7 - 4:10
The resulting resistivity helps to Identify rock types (clay, sand,
limestone, etc.) and detect the presence of water and hydrocarbons.
Self-potential (SP) can reveal large changes In Total Dissolved Solids
(TDS), for example, from fresh water to salt water or brine. It can,
under certain conditions, help to confirm conclusions drawn from the
resistivity curve. Both curves are useful In locating the depths at
which changes In formations occur, and can be used to verify depth
measurements and other Information reported by the driller.
A more detailed description of electric logging Is found In appendix C.
4:8 Radioactivity Logging
Common to all radiation logging devices Is some means of measuring
radioactivity In the borehole. The radioactivity may be either natural
or Induced, or It can result from Injection of an Isotope used as a
tracer. Because certain types of radioactivity are very penetrating,
these radioactivity logs can be used In cased holes.
A natural radiation log measures gamma radiation produced by decay of
uranium, thorium, or potassium contained In the formation. This log may
also be used to detect a radioactive tracer; however, the chief use of
natural gamma logs Is to Identify the llthology.
There are many other types of radioactivity logs; however, those most
commonly used are natural gamma, gamma-gamma, and standard neutron.
4:9 Acoustic Logs
An acoustic-velocity log Is a record of the transit time of an acoustic
pulse through a fixed length of rock or casing parallel to the borehole
between transmitters and receivers In a logging sonde. The chief uses
are for determining porosity, Identifying fractures, and evaluating the
cement bond between the casing and the formations. See Cement Bond Log,
appendix C. Some of the more common acoustic logging tools which have
received wide use and acceptance In downhole acquisition of data are (1)
cement bond, (2) borehole compensated sonic velocity, and (3) the sonic
televiewer.
4:10 Temperature Log
Gives a continuous record of temperature Immediately surrounding a sensor
In the borehole. This log can also be used to detect movement of fluids
behind casing and to detect the top of a recently placed cement column."
4-16
-------
4:11 - 4:16
4:11 Directional Survey
Provides Information on borehole slope and direction and establishes
bottom-hole location In relation to the surface entry point.
4:12 CalI per Log
Provides a continuous measurement of borehole or casing diameters.
4:13 Fluid-movement Logging
Measures naturally or artificially Induced flow within the borehole.
4:14 Casing Collar Locator
Accurately locates well casing collars and perforations In a well.
4:15 Casing Inspection Log
Used to detect pipe corrosion.
Well logs can be Interpreted to determine llthology, porosity,
resistivity, density, and moisture content of fluid-bearing rocks. Well
logs can also permit a valid quantitative Interpretation of reservoir
characteristics. Logging programs allow the evaluation of well
construction and fluid-flow conditions within the well. Originally
developed for the detection of hydrocarbons, today's logging methods are
applied to all classes of Injection wells.
4:16 Witnessing Wire-line Logging Procedural Checklist
Obtain construction details of the we^LJ^ These will Include the
following:
1. Well name and number
2. Well location
3. Elevation of drill floor, or reference point
4. Hole diameters and depths
5. Casing Information
6. Mud characteristics, Including type, lost circulation, viscosity,
fluid weight, fluid loss, filter cake, and pH
7. Hole conditions, Including oversized hole, doglegs, tight spots, and
deviation records
4-17
-------
4:16 - 4:17
Verify that the detalIs on the log head Ings are correct and that any log
faults that would affect log Interpretation and that are not rectified at
the well site are Included In the "Remarks" section.
Check the depth and register of logs. The casing shoe may be used as a
reference point. Any disagreement between driller's depth and maximum
logging depth should be reconciled Immediately.
Verify, that the correct speed and time constant are be Ing used. A gap
appears In the line at the margin of track one, or once per minute, so
logging speed can be checked for consistency and correctness.
Verify that the time constant Is_j:ecQrded In the log heading.
Obtain detal Is^ of the horizontal and vertical scales to be used. Most
logs are run on 1:200 and 1:500 scales.
Tell the operator how many field prints are required.
Check the general character ot the logs;
1. Logs should be run on one scale; or a backup should appear
2. Cyclic variations, zero values, and constant readings should arouse
suspicion
3. "Be suspicious of logs that constantly peak or level out at less than
full-scale deflection
4. Look especially for events that demonstrate the range of response of
the tool, e.g. hlgh-and low-porosity beds, shales, salts, anhydrite,
and washouts
Request details from the logging company on the quality assurance/quality
control checks run on the tool prior to beginning the log run.
4:17 Cementing
Primary cementing of Injection wells Involves pumping a cement slurry
down through well casing. Pump pressure forces cement out from the
bottom of the casing, and then upward Into the annular space outside the
casing wall. This Is the preferred method of primary cementing. (The
practice of dumping cement down this annul us on top of a packer Is
unacceptable.)
The number of cementing operations and the total length of each cement
column varies somewhat by well class (see figure 1.1 for typical
exampIes).
4-18
-------
4:17 - 4:18
After cement Is displaced through the casing, pumps are shut down and
cement outside the casing string Is allowed to set. Primary cementing
restricts fluid movement between downhole formations, and protects and
supports the casing. Secondary cementing refers either to remedial
attempts to complete an Inadequate primary job, or to seal off a
particular Injection zone without abandoning the entire well. "Squeeze
cementing" Is a common term for secondary cement jobs that Isolate
particular zones.
Despite precautions, loss of circulation may end any cement job
prematurely. This Is usually caused by weak formations ("thief zones")
Into which a large portion of the cement flows. When cement falls to
return to the surface, a temperature log and cement bond log should be
run to locate the top of the cement. If the bond log Indicates that the
Injection zone was not safely Isolated by the primary cement job, then It
will be necessary to perforate the casing and squeeze cement through the
perforations to complete the job. Another way Is to cement directly Into
the unfilled annulus through a small work string (sometimes referred to
as a tremle pipe); however, this method may be effective to depths of
only a few hundred feet.
For more Information on the technical aspects of cementing, refer to
appendix D.
4:18 Witnessing Primary Cementing - Procedural Checklist
1. Check cement volumes against Integrated callper log If calIper log
has been run. Otherwise, be sure the volume to be used Is based on
gauged hole size, plus a safety factor for hole enlargement.
Request several samples of cement for later analysis
2. Check preflush and spacer volumes
3. Check actual number and placement of central Izers against
requirements
4. Note If casing Is rotated or reciprocated during cementing
5. Observe mud returns during cement displacement to detect return of
preflush and cement at the surface (very Important). Items to .watch
for are color change, odor, pH change, Increased funnel viscosity,
and density (using a pressurized mud balance). Record time and
cement volume pumped when cement returns are observed
6. Witness bumping of top plug (moment top plug lands on bottom plug,
shutting off flow). Record time, displacement volume and pressure
7. Note If casing Is open or closed during "waltlng-on-cement" (WOO
time. Holding pressure on the Inside of the casing during the WOC
period can produce a mlcroannulus at the casing-cement Interface.
4-19
-------
4:18 - 4:20
8. At end of Job, run material balance on water and cement used to
confirm that cement was mixed as designed
9. Get copy of cement service company's field report from
owner/operator at end of Job
4:19 Injectlvlty and Aquifer Testing
Permeability, thickness, and porosity are Important aquifer properties
upon which groundwater reservoir calculations are based. These hydraulic
properties may be determined by means of Injectlvlty. and pumping tests'.-
The effects on a reservoir from pumping or Injecting at a known rate Is
measured In the subject well or In other (observation) wells penetrating
the reservoir. Graphs of pressure buildup (or drawdown) versus time
during pumping or Injection operations are used to determine hydraulic
properties of a reservoir.
Bottom hole pressure tests are conducted Immediately after well
completion to establish the Initial reservoir pressure before Injection
operations commence. This may be done with one of various types of
downhole pressure Instruments which are run on an electric line or
wire I Ine. A less accurate method Is to measure the depth to the top of
the fluid In the well and calculate the hydrostatic pressure at the
bottom. If a bottom hole pressure determination Is made by the latter
method, the wellbore fluid must be of known, uniform density.
Injection or production tests conducted prior to putting a well Into
operation can provide a fair estimate of formation properties. Because
of the transient state of a reservoir during the early part of an
Injection test, Interpretation of test results from short tests may be
misleading. Injectlvlty tests conducted later In the Injection operation
when steady-state conditions have been achieved are more reliable.
Average -reservoir pressure, permeability and reservoir volume can be
determined from pressure decay or falloff data measured In the shut-in
well following steady-state Injection.
Inlectlvltv tests should continue for sufficient time to Insure that
steady-state conditions are approached In the reservoir. The wel I Is
then "closed In" for a pressure decay test. Bottom-hole and surface
pressure are recorded during the flow and shut-in periods.
4:20 Witnessing Injectlvlty Tests - Procedural Checklist
Verify that Injection (pumping) rate Is kept as nearly constant as
possible throughout the test. Character of the Injected fluid should not
change.
Note variations In pressure and flow rates.
4-20
-------
4:20 - 4:22
Note If there are other pumping or injection operations tapping the same
Injection zone and close enough to affect test results.
Note time Injection starts and when It ends; also note time when test
ends.
4:21 Other Preoperatlonal Inspections
Insist on baseline well data In new Injection areas. Various reporting
forms have been developed and used by EPA for wel I .Inventory and database
development. .
Obtain formation water samples and analyze for common anfons, cations,
and IDS. For a field of wells completed to similar depths only
representative samples should be required.
Obtain a copy of the analysis report If cores are taken from the
Injection and/or confining, zones. For a field of wells completed to
similar depths, only representative coring should be required.
Request corrosion data from a representative wastewater sample for Class
I weII projects.
4:22 Compliance Verification
A se-t of unique permit conditions Is established during the permit
application process for each Injection well to maintain the Integrity of
that well and to protect underground sources of drinking water. The
owner/operator Is required to operate the facility In strict accordance
with these permit specifications. Failure to do so constitutes a permit
violation and the facility Is considered to be In a state of
noncompllance. For example, the operator Is required to limit the
Injection pressures strictly to that specified In the permit. Injection
of any fluid at a pressure In excess of that authorized by the Agency
constitutes a permit violation and the facility Is no longer In
com pi lance.
The permit outlines certain monitoring and reporting requirements. Among
these Is a description of the required monitoring program what Is to
be monitored; how; how often; and with what precision. It may be
necessary to detail the Installation and maintenance of monitoring
equipment. The permit must clearly state the reporting requirements.
Reporting and monitoring requirements may vary with well classification.
When monitoring forms or reports show permit violations, the regulator
should examine facility monitoring records for trends,' and should study
future reports for further violations and trends. Obvious violations or
unfavorable trends call, for an Investigation by the Inspector. The
investigation, if It confirms a violation, may require enforcement
action.
4-21
-------
4:22
Compliance Inspections resulting from reported violations or the
discovery of unfavorable trends will Include visual Inspection of the
facility and review of well records. Sampling of the Injected fluid may
be Included to determine compliance with the permit or well
classification.
In the conduct of Inspections to verify compllance with DIG permit and/or
regulatory requirements, the Inspector must ensure that the Information
Is col lected In such a manner that It Is admissible as evidence In any
Judicial enforcement action. To ensure this admlsslbl I Ity the Inspector
must: -
Select the Inspection target using a neutral administrative scheme.
Neutral selection of Inspection targets Is only required for facilities
where the Agency does not have reason to believe that a violation has
occurred or Is occurring.
Gain admittance to the facility legally. That Is, Inspect the facility
at a reasonable time (generally during normal operating hours) and
present the required written Inspection notice Section 1445(b)(1) SDWA
and appropriate credentials to the person authorized to consent to the
Inspection.
Examine surface Installations for apparent violations of permit
conditions. In general, he should look for signs that:
1. The present Installation design differs from that shown In the
appl Icatlon for permit
2. The facility Is not being operated as permitted, for example,
Injection pressure exceeds that authorized, or rate of Injection Is
greater than that authorized
3. Records of wastes Injected show unauthorized fluids are being, or
have been, Injected
4. There have been leaks or discharges to the surface (to ground
surface, pits, ponds, water courses, drainage ditches, etc.)
5. There Is rust or corrosion, or lack of general maintenance
(lubrication, cleaning, painting)
6. The facilities are not adequately protected from vandalism, fire,
accidents, or sabotage
Ensure that samples are representative. All samples must be collected
using EPA-approved sampling procedures and containers and preserved
according to laboratory reccmmendatlons. Quality assurance procedures
should be followed In all cases.
4-22
-------
4:22 - 4:24
Ensure that samples are transported to the laboratory using chaln-of-
custody procedures (see appendix A). The Agency must be able to document
that the samples reached the laboratory within recommended holding times,
and without tampering. .
Ensure that visual observa^tJgnsf phonographs and notes are properly
documented. All observations should be recorded In a bound notebook In a
clear and concise manner. If Information Is obtained from employees of
the facility, the name and title of the employee should be recorded.
Ensure that aJ 1 vloI atIons are clearly and specifically documented.
If asked to 1 eav eP do so. Then telephone the appropriate Regional
enforcement attorney for Instruction, In accordance with procedures
outlIned In chapter 3.
The Inspector should be aware that field Inspection Is generally not
appropriate as a sole or 'final Agency response to a violation. Other
actions which may be appropriate are Included In table 4.3. A number of
these responses must be Initiated at either the State, Regional or
Federal offices and require approval of the appropriate offlclal(s).
Examples of situations and their proper responses have been Included In
appendix E.
4:23 MECHANICAL INTEGRITY (Ml) TEST INSPECTIONS
Mechanical Integrity (Ml) Inspections are expected to be a major activity
of Inspection teams. Several test methods are approved under the UIC
regulations to determine Injection well Integrity. The particular method
employed Is related to well construction and the detection sensitivity
required. Special techniques have been proposed for determining the
Integrity of certain Class II wells that do not have protection casing.
The Ml tests described In this chapter are either specified by the EPA
(section 146.08) or are available for use as alternative methods upon
approval by the Director.
Mechanical Integrity test Inspections of Class II wells are to be run on
a 5-year cycle with priority levels assigned to wells according to
Regional guIdelInes.
4:24 Ml Testing Procedures
By current legal definition there are two aspects to mechanical Integrity
as explained In 40 CFR 146.8. First, an Injection well has mechanical
Integrity If there Is no significant leak In the casing, tubing "or
packer(s) and there Is no significant fluid movement Into an underground
source of drinking water through vertical channels adjacent to the well
bore (|146.8(a)(1) and (2)). The first requirement Is referred to as
"Internal" Ml and the second Is referred to as "external" Ml.
4-23
-------
THIS PAGE INTENTIONALLY LEFT BLANK
4-24
-------
TABLE 4.3
POSSIBLE APPROPRIATE RESPONSES TO VIOLATIONS
A. Telephone calI (must have appropriate documentation).
B. Warning letter tailored to Individual operator notifying him/her of the
nature of the violation and required responses (must Include possible
criminal/civil liabilities).
C. Field Inspection (generally not appropriate as a final response to a
violation).
D. Opportunity for consultation ("show cause" meeting) which provides the
violator a chance to ask questions of the agency and get Information.
E. Formal request for Information (may Include new Information, mechanical
Integrity test, monitoring, etc. - see §144.27). Note: Owner/operator's
failure to respond to this request results In autcmal-Jc termination of
authorization by rule, (§144.27[c]).
F. Request for permit application (§144.27; 144.12[c] or [d]). Note: When
§144.27 Information request authority Is not appropriate, the §144.25
authority can be used to terminate authorization by rule If the permit
application Is not submitted In a timely fashion, or If the permit Is
denied.
G. Initiate permit modification, alteration or termination or Impose or
modify a compliance schedule.
H. Issue Administrative Order to owner or operator of a Class V well
requiring such actions as may be necessary to prevent primary drinking
water standard violations or to prevent contamination which may otherwise
adversely affect the health of persons. (§144.12[c]C2l).
I. Commence bond forfeiture or utilize other financial mechanisms to plug
the welI.
J. §1431 SDWA Administrative Order or, where well Is Injecting solid or
hazardous waste, RCRA, §3008 or §7003 Administrative Order (or where
appropriate, a CERCLA §106 Administrative Order).
K. Issue Administrative Order.
L. Referral to State AG/Depar-hnent of Justice (DOJ) (Civil or Criminal).
4-25
-------
THIS PAGE INTENTIONALLY LEFT BLANK
4-26
-------
4:25 - 4:26
4:25 Internal Mechanical Integrity
Internal Ml Is to be demonstrated, In most wells, by either monitoring
pressure In the space between the casing and tubing (the annulus) or by
conducting a pressure test with liquid or gas In the annulus and
monitoring for pressure losses or gains. This Is possible only In wells
whose annul I are sealed at the top and at the bottom. Some we I Is operate
with fluid seals Instead of a packer. These wells cannot be pressure
tested, thus requiring careful monitoring of the annulus pressure at all
times. In some areas of the country, alternative procedures for
demonstrating Internal Ml In certain .Class II. wells may be necessary
because of well construction features. Some of these wells have "open
hole" completions, that Is, are uncased below the surface casing depths.
There Is, therefore, no closed annular space between the protection
casing and the Injection tubing which may be pressurized. Methods for
testing these Class II wells are discussed In section 4:32. The
procedures that follow apply to cased we I Is with packers and we I I head
seals.
4:26 Internal Ml (Static Pressure Test)
Determine the weight^ In pounds per ^aUoji^o_t the annulus fluid.
Determine the Me-lght^Ln pounds per gaL lonp Qf.jtbe Jjiject ton f I aid (In
the tubing).
Ensure that the hydrostatic pressure In the annulus (test procedures) Is
(1) greater than the formation pressiire at all depths and (2) greater
than the hydrostatic pressure Ln the tubing. That Is:
PA/$ + 0.052 (WAp)(D) > 0.433 (S.6.) (D)
PA/S + 0.052 (WAp)(D) > (0.052) (WIF) (D) +
where:
F*A/S -annulus pressure at the surface, psl
PTSI/S "tubing pressure, shut-In, at the surface, psl
WAp -weight of annulus fluid, pounds per gallon
WIF -weight of. Injection fluid, pounds per gallon
4-27
-------
4:26
D - depth to packer, feet
S.G.* -specific gravity of formation fluid (unltless)
The constant, 0.052, converts pounds per gal Ion to psl, and 0.433 Is the
approximate pressure gradient for fresh water that converts feet of fresh
water to psl.
tt '
Specific gravity can be approximated using the total dissolved solids"
(IDS) content of the fluid. For example, a formation fluid having a
100,000 IDS content has 100,000 mg/l IDS.
This reduces to:
100,000 mg/1,000g = 100g/1,000g
The total weight of the fluid, Including the weight of solids, would be:
1 00 g + 1 000 g = 1100 g
Specific gravity Is the weight of a volume of fluid divided by the weight
of an equal volume of water:
S.G. = 1,100g/1,000g =1.1
For example, If the well has a packer at 3000 feet with a 10 ppg annulus
fluid and 8.5 ppg tubing fluid with no surface shut-in pressure and the
formation fluid has 100,000 TDS, then the necessary casing pressure must
satisfy:
PA/S + 0.052(WAF)(D) > 0.433(5.6.)(D)
PA/S + °'052(10 Ppg)(3000 ft) > 0.433 psl/ft (1.1)(3000 ft)
PA/S + 156° Psl > °*476 Psl/ft (300° ft)
PA/S + 156° Psl > 1428 Psl
and
PA/S + 0.052(WAF)(D) > 0.052(W|F)(D) + PTS|/S '
PA/S + °'052(10 ppg)(3000 ft) > 0.052(8.5 ppg)(3000 ft) + 0
PA/S + 156° Psl > 1326 Psl
4-28
-------
4:26 - 4:27
In this example, both conditions are satisfied, as long as PA/$ > 0, and
the test may proceed.
Determine Type of Packer
If the packer In the well Is a compression set packer (that Is, tubing
weight Is placed on the packer to effect a seal), then additional annulus
pressure will tend to effect a better seal. However, a tension-set
packer (tubing tension needed to effect a seal) will tend to unseat
itself with Increased annulus pressure.
The original tubing tension at the time the well was completed will
determine the possibility of unseating. The owner/operator may decide
the proposed test pressure Is unsafe. If he so decides, then an
alternate test procedure Is given In the next Section.
Check to be sure the annulus Is absolutely full of liquid. Air bubbles
will sometimes dissolve In the annulus during testing, causing a change
In the shut-in pressure.
Apply the pressure test for 30 minutes. The well can be said to have
Internal Ml If the total change In pressure falls within the acceptable
range for that facility as established by the State or Region. Slight
pressure decreases may be the result of an air bubble; or perhaps
temperatures In the well bore have not stabilized. If the pressure
change exceeds the acceptable level, repressure the annulus and monitor
again. If-, during this second test, the pressure again decreases by an
unacceptable amount, a leak Is probable.
Initial pressure Increases are also possible, but they should not
continue. For Instance, the heating of the pressure gauge Itself by
sunlIght might cause small errors In readings.
4:27 Internal Ml (Dynamic Test) Procedural Checklist
Conduct a dynamic test (one conducted while Injecting) If the Injection
welI can not be tested statically following the above procedures. The
most dependable method for a dynamic test calls for the use of continuous
monitoring charts taken over a period of time (usually seven days), and
will Include a continuous record of tubing Injection pressure and casing
annul us pressure.
Be aware that continuous monitoring charts will, unfortunately, reflect
annulus pressure changes caused by Injection pressure changes and
Injection temperature changes In addition to leaks. These ancmalles must
be Identified and adjusted for to avoid missing possible leaks.
4-29
-------
4:27
Maintain the annul us pressure so that the hydrostatic pressure In the
annul us at any depth Is greater than both formation pressure and tubing
hydrostatic pressure. (The case where annul us hydrostatic pressure Is
not greater than tubing hydrostatic pressure will be addressed under Item
D, below. The formation pressure at any depth Is given by:
PFm = 0.433(5.6.
where: Ppm = formation pressure,, psl
S.G. = specific gravity of formation fluid
D = depth, feet
The tubing hydrostatic pressure at depth Is given by:
where: Wjp = weight of Injection fluid, ppg
D = depth to packer, feet
Ppr = frlctlonal pressure loss per 100 feet (see figure 4.3),
psl
P| /5 = surface Injection pressure, psl
The annul us hydrostatic pressure at depth Is given by:
PAD - o.052(wAF) (D) + PA/S
where: W^p = weight of annul us fluid
= sur"face annul us pressure, psl
For example, If a well has a tubing Injection pressure of 1100 psl, a 2
bbls per minute flow rate In a 2-7/8" tubing, a packer at 4000 feet, 10
ppg water annul us fluid and a minimum surface pressure of 600 psl (as
recorded on a continuous recording device), then the following conditions
exist:
4-30
-------
HANDBOOK OF APPLIED RHEOLOGY
FRICTION PRESSURE vs FLOW RATE
FOR VARIOUS PIPE DIAMETERS
FLUID VISCOSITY - I cp
A- I 1/4- 1.380"
B - I 1/2"- 1.610"
C -2 3/8'- 1.995."
0-2 7/8-2.441
E-3 1/2-2.992
DRILL PIPE
F -3 1/2" - 13.3* -2.764"|.D.
CASINO
G -4 1/2 -I 1.6** -4.0OO 1.0.
H -3 1/2" -I7.0«* -4.892" 1.0.
I -7" -23.0* -6.366" I.D.
4 5678 10
FLOW RATE BPM
20 30 40 60 80 100
Figure 4.4 Head Loss Chart
4-31
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4-32
-------
4:27
Formation Pressure (for a formation fluid with a 100,000 IDS content):
PFM = (0.433HS.G.MD)
= (0.433 psl/ft) (1.1) (4000 ft)
= 1905 psl
Frlctlonal pressure drop, Ppp (from figure 4.4), Is 2.5 psl/100 ft. for 2
bbls/mln. so the total over 4000 feet of depth I-s:
Tubing hydrostatic pressure:
"TD ' °-052 - PFR * pi/s
= 0.052(9 ppg)(4000 ft) - 100 psl + 1100 psl
= 2872 psl
Annul us Pressure:
PAD= 0.052(WAF)(D) + PA/S
= 0.052(10 ppg) (40.00 ft) + 600 psl
= 2080 psl + 600 psl
= 2680 psl
The above example concludes that the surface annul us pressure Is too low
to prove Ml since the relationship
PAD > PTD
must be maintained. Approximately 200 psl additional annulus pressure
would result In hydrostatic pressures being equal at the packer.
Consequently, an additional 200+ psl annulus pressure would be
reconmended. That Is, annulus pressure In excess of 800 psl should be
used In the above example to prove Ml from continuous monitoring records.
If this annulus pressure Is unacceptable for any reason, the following
alternative test procedures should be considered.
4-33
-------
4:27
Where annul us hydrostatic pressure does not exceed tubing hydrostatic
pressure, the annul us hydrostatic pressure must at least be greater than
the formation pressure to be sure there are no casing leaks. That Is,
PA/S + 0.052(WAF)(D) > (0.433MS.G.HD)
where: P/\/$ = surface annul us pressure, psl
W^p = annul us fluid weight, ppg
D = depth to packer, feet
S.G. = specific gravity of formation fluid
Once this criterion Is met, the tubing can be tested for leaks.
If the tubing hydrostatic pressure Is greater than the annu'lus
hydrostatic pressure both at the surface and at the packer, then It Is
normally greater at every depth.
This would prove the Integrity of the tubing since, If a leak did exist,
annul us pressure during Injection would rise. Therefore:
PI/S > PA/S
and
PI/S + 0.052(WIF)(D)-PFR(D)/100 > PA/S + 0.052 (WAfr)(D)
where: pj/$ = surface Injection pressure, psl
= sur~face annul us pressure, psl
= Injection fluid weight, ppg
= annul us fluid weight, ppg
= depth to packer, feet
= frlctlonal pressure loss per 100 feet (see
figure 4.4)
4-34
-------
4:27
In the previous example of the well Injecting 2 bbls per minute, we see
that
PA/S + 0.052 (WAF) (D) > 0.433 (S.G.) (D)-
PA/S + 0.052 (10 ppg)(4000 ft) > 0.433 psi/ft (1.1) (4000 ft)
or
600 psl + 2080 psl > 1905 psl
That Is, the annul us hydrostatic pressure exceeds formation pressure at
any depth. Also, looking at the tubing hydrostatic pressure, we have
PI/S > PA/S
1100 psl > 600 psl
and
PI/S + 0.052 (WIF)D - PpR(D)/1000 > PA/S + 0.052
1100 psl + 0.052 (9 ppg) (4000 ft) - 2.5 psi/ft (40 ft)
> 600 psl + 0.052 (10ppg)(4000 ft)
1100 psl + 1872 psl - 100 psl > 600 psl + 2080 psl
2872 psl > 2680 psl
This shows that tubing hydrostatic pressure exceeds casing hydrostatic
pressure by approximately 192 psl. A pressure differential of this
magnitude Is a good Indication that no tubing leaks exist.
In case none of the above techniques proves mechanical Integrity, another
test can be run. Either raising or lowering Injection or annulus
pressure will set up a new set of conditions. If changing either does
not affect the other, Ml has been proven.
It should be apparent from the above that Ml testing procedures may have
to be adjusted to fit particular situations.
4-35
-------
4:28 - 4:29
4:28 External Mechanical Integrity
4:29 Geophysical Logs
Two geophysical logs have been designated as acceptable under 40 CFR
146.08 to determine the absence of fluid movement behind the casing
(.external Ml). These are the Noise Log and the Temperature Log. Their
Interpretations, applications and limitations are discussed below. An
additional method for proving external Ml that may be used In conjunction
with the above methods but Is not required under 40 CFR 146.08 Is the
radioactive tracer survey. This method Is discussed'further In section D'.
The Jtolsa Log
The Noise Log Is used to determine mechanical Integrity of Injection
wells by measuring and analyzing noise generated . downho I e by flowing
IIqulds (or gases).
This tool records sound amplitude and frequency levels versus depth to
produce a log capable of tracing a channel flow pattern. In addition,
the tool Is normally capable of discriminating between single phase (all
liquids or all gases) and two-phase (liquid and gas) flow. In Injection
wells the flow will almost always be single phase (liquid).
The amplitude profile Is a measure of the amount of noise generated by a
flow which In turn Is proportional to the volume of the flow and the
pressure differential acting on the flow. The greatest pressure
differential occurs at the point of escape of the flow (I.e., the
difference In pressure between the channel and the formation accepting
the flow). The Noise Log shows these differences In pressure as peaks.
The frequency range of the Noise Log Is about 200 to 6000 Hertz (Hz). It
Is registered on the log as amplitude at various frequency levels. The
frequency levels reflect the pressure differentials described above. The
greater the pressure difference, the higher the frequency level.
Figure 4.5 Illustrates high-rate channeling In an Injection well. High
Injection pressures are forcing fluid through a cement channel Into
receptive upper sands (B-1, A-3, A-2). Note also that the 200 Hz
amplitude curve varies from a minimum of 4 mv below 6100 feet (the no-
leak level) to a maximum of 1000 mv at -5870 feet where there Is an
apparent obstruction In the channel behind the pipe.
The four traces represent sound Intensities (In millivolts) for the four
frequencies used - 200 Hz, 600 Hz, 1000 Hz, and 2000- Hz. The 200 "Hz
curve represents all frequencies 200 Hz and higher, the 600 Hz all
frequencies 600 Hz and higher, and so on.
Where the I Ines come close together (as at 5870 feet and 6800 feet),
there Is a single phase flow (all gas or al I liquid); where the
4-36
-------
SP CURVE
(FROM OPEN HOLE)
A-2
SAND
A-3
SAND
B-1
SAND
MILLIVOLTS
0.2 1jO 10.O 10OO 10004
5400
55QQ
5600
5700
5800
5900
6000
6100
0.2
DEPTH
CFEET)
4.5 Noise Log
4-37
1jO 10.0 100.0 1000X3
MILLIVOLTS
NOISE LOG
(FROM CASED HOLED
-------
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4-38
-------
4:29
separation is substantial (as at 5800 feet), there would be two-phase
(gas and liquid) flow. In most Injection wells the single phase flow
would, of course, be liquid.
The Temperature Log
Temperature log surveys are used to locate cement tops, tubing or casing
leaks, and channeling behind casing. This log measures well temperature
variations that are dependent on volumes of materials, rate of fluid
movement, temperature differences between the media, and length of time
that heat transfer has taken place.
In locating cement column tops, temperature surveys are run approximately
6 to 12 hours after a string of casing has been cemented. During the
setting process the cement gives off heat. The temperature log records
this heat wherever there Is cement column outside the casing (see figure
4.6).
Tubing or casing leaks can be confirmed and pinpointed by temperature
logging. Fluid entering or exiting a point in the well should result In
a detectable temperature change. The resulting temperature profile Is
then compared with an assumed or normal temperature gradient for the
well. Examples of these types of situations are Illustrated In figure
4.7.
To detect channeling behind the casing, static conditions In the well are
needed. A flowing well cannot be studied with a temperature log because
the log would record only the temperature of the flowing fluid.
LImItatIons ot Noise and^Temperature Logs
The Noise and Temperature Logs are potentially useful In all classes of
Injection wells. However, certain construction details may affect their
usefulness:
1. The well must have casing
2. The amplitude of the Noise Log may be affected by different
construction materials
3. In many cases, before running either log, the Injection tubing must
be removed from the we I I
4. The larger the diameter of the well the less reliable the
Temperature Log
5. Temperature Logs may not be very reliable at shallow depths (less
than 1000 ft)
4-39
-------
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4-40
-------
COLLAR LOG TEMPERATURE °F
107° 137°
CO
01
o
o
CO
O)
o
o
CO
-^
o
o
CO
00
o
o
CO
-------
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4-42
-------
EXAMPLE A
EXAMPLE B
EXAMPLE C
FLUID ENTRY
TO THE
CHANNEL
LU
LL
O
Q.
LJJ
Q
O
c/5
<
UJ
cc
O
z
FLUID EXIT
FROM THE
CHANNEL
FLUID EXIT
JO THE
CHANNEL.
FLUID ENTRY
FROM THE
CHANNEL
TEMPERATURE
INCREASING
EXAMPLE A - NATURAL GEOTHERMAL GRADIENT AS MEASURED IN A STABLE WELL
EXAMPLE B - TEMPERATURE ANOMALY SUPERIMPOSED ON GEOTHERMAL GRADIENT
INDICATIVE OF DOWNWARD FLOW THROUGH A CHANNEL BEHIND THE WELL CASING
EXAMPLE C - TEMPERATURE ANOMALY SUPERIMPOSED ON GEOTHERMAL GRADIENT -
INDICATIVE OF UPWARD FLOW THROUGH A CHANNEL BEHIND THE WELL CASING
Figure 4.7 Temperature Log Showing Fluid Loss
4-43
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4-44
-------
4:30 - 4:31
4:30 Application and Interpretation of the Radioactive Tracer Survey (RATS)
In cased Injection wells with tubing and packer Installed, It Is possible
to conduct a Radioactive Tracer Survey (RATS) In addition to running a
Temperature or Noise Log. The RATS has been approved as an alternative
Ml test; however, there are limitations on Its use described In the
Federal Register approval notice (see FR 52, 237, pp 46837-38, December
10, 1987).
The RATS Is run using an Iodine Isotope solution. Radioactive Iodine has
an 8-day half-life and decays "totally" within 30'days. The survey I-s
carried out as follows: (1) The Gamma Ray tool Is run through the
tubing, from total depth up past the zone of Interest, to get a
"background" log; (2) The radioactive solution Is Introduced Into the
Injection fluid either at the surface or directly from the logging tool,
as Injection proceeds; (3) the Gamma Ray tool moves through the zone of
Interest several times In order to "track" the radioactive solution (a)
In the tubing; (b) In the we I I bore below the packer; (c) Into the
Injection Interval; and (d) (If external Ml has failed) In the channel
outside the casing.
While conducting the Radioactive Tracer Survey, fluid Is pumped Into the
well at a rate slightly above that for normal operating conditions. One
repeat run of the Gamma Ray log Is obtained over the Injection Interval
and Immediately above this section. If no change In Gamma Ray count
above the top of the disposal Interval Is detected, then no external
migration of Injected fluid Is occurring. Specific guidance for running
RATS Is Included In appendix C.
The Radioactive Tracer Log In figure 4.8 Indicates a leak In the casing
and fluid movement In a channel behind the casing. Note that the log run
after Injecting radioactive material Is superimposed on the base log.
To avoid misinterpretation and possible oversight of conditions
Indicating a lack of mechanical Integrity, all noise, temperature, and
radioactive tracer surveys should be analyzed by a qualified Individual
who has had training and experience In welI log Interpretation.
4:31 Well Record Evidence of Mechanical Integrity
The external Ml of Class II and certain Class III Injection wells (see 40
CFR 146.08) may be demonstrated by well records showing the presence of
adequate cement to prevent fluid migration. (Note: This method may not
be used to prove mechanical Integrity In Class I wells. New Class II
wel Is must have either a cement bond log, a temperature log, or -an
unfocused density log which defines the condition of cement behind the
pipe. This Is In addition to the Information provided by cementing
records.)
4-45
-------
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4-46
-------
INCREASING
GAMMA RADIATION
HI
I
Q_
111
Q
O
u.
DC
O
GAMMA RAY LOG
TAKEN BEFORE
INJECTION
GAMMA RAY LOG
TAKEN AFTER
INJECTION
-CEMENT
-CASING
-CASING
LEAK
i
FLUID
MOVEMENT
IN CHANNEL
RADIOACTIVE TRACER LOG
WELL DIAGRAM
Rgure 4.8 Radioactive Tracer Log Showing Fluid Movement
4-47
-------
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4-48
-------
4:31 - 4:32
Procedure
1. Determine whether adequate cement exists In the well by comparing
the emplaced cement volume with the volume of the space (annulus)
between the outer casing and well bore. The annulus volume Is
calculated from the outside casing diameter and a callper log
reading of the well bore. An adequate cement seal Is likely to
exist when the Injected cement volume exceeds the calculated annular
volume by at least 20%.
2. Evaluate cement bond logs and temperature logs as an Indication of
adequate cement In the well. Owners/operators shou-ld keep records
of these logs for evidence of mechanical Integrity.
3. The cement top In a relatively new shal low wel I can be located by
dropping a weighted line down the annulus space until It contacts a
sol Id barrier.
The Internal Ml of certain Class II enhanced recovery wells can be
demonstrated by the examination of monitoring records. Records of
Injection well monitoring showing the absence of significant changes In
the relationship between Injection pressure and Injection flow rate can
be used to demonstrate Internal mechanical Integrity for those Class II
wells that are completed without either a packer or long string casing
between the surface casing and the Injection zone casing.
4:32 Water-In-annulus Test
Limitations on the use oi Water-In-annulus MechanlcalJntegr Lty Test
Use of the water-In-annulus test Is limited to existing Class II enhanced
recovery Injection wells (existing wells are those wells In operation
prior to June 25, 1984):
1. Located In Al legany, Cattaraugus, and Steuben Counties, N.Y. and
Elk, Forest, McKean, Potter, Venango, Warren, and Washington
Counties, PA
2. Injecting through a tubing string the size of which severely
restricts the placement of temporary plugs for pressure testing or
logging
3. Constructed without long string casing due to the competent nature
of the rock In the uncased Interval
4, Constructed with surface casing set through the lowermost
underground source of drinking water
5, Constructed and tested with no obstruction In the surface casing to
Interfere with the test
4-49
-------
4:32
6. Constructed with tubing and packer cemented Into the hole
Immediately above the Injection zone
Procedures for Conducting the Water-Ln-annuJjis MechanIcaL_Jjitegr Ity Test
The water-In-annul us test as approved under the one year Interim
extension consists of the following procedures:
1. Determine with a verifiable procedure that there are no obstructions
In the annulus to at least the depth of the surface casing seaf
which could Interfere with the test
2. Shut the well In at least 24 hours before running the test and bleed
off pressure on the Injection tubing
3. Measure the Injection tubing pressure and the existing water level
In the annulus and record the values
4. Fill the annulus between the Injection tubing and surface casing to
the top of the casing and measure and record the water levels for
one-half hour
5. Record the final water level
6. Begin Injection Into the well and wait for the pressure to stabilize
before beginning the second half of the test. Record the stabilized
pressure
7. Repeat steps 4 and 5
8. Compare the rate of water level change between shut-In and operating
conditions
Test JjiterpT-etat Ion
1. The well has mechanical Integrity If there Is no change In the water
level In either shut-in or. operating conditions or the rate ojf
change Is less than 2 1/2 feet: per one-half tiour
2. The well does not have mechanical Integrity If the water level rises
with the well operating, but does not change with the well shut-in
3. The well does not have mechanical Integrity If the rate of change Is
less than 2 1/2 feet per one-half hour and If that rate of change Is
not equal between shut-in and operating conditions (e.g.. If the
water level declines 2 1/2 feet during shut-in conditions and 1 1/2
feet during operating conditions, the well falls mechanical
Integrity). The well must be shut-in until a successful mechanical
Integrity test demonstration Is made
4-50
-------
4:32 - 4:33
4. The welI does not have mechanical Integrity If the water level drops
at a rate greater than 25 feet In one-half hour or If the annul us
could not be fII led to the top with water to perform the test. Each
of these cases requires that the well be shut-In until a successful
mechanical Integrity test demonstration Is made
5. The test Is Inconclusive regarding Integrity of the surface casing
If the water level drops at the same rate under both conditions and
the rate of change Is between 2 1/2 feet and 25 feet per one-half
hour. This result requires one of the following options to .be
exercised.
Option 1 - Repeat the water-In-annulus test on a quarterly basis to show
Integrity of the tubing and packer
Option 2 - Show that the water loss Is not due to a leak In the surface
casing'by either plotting the water level rate of fall as It drops
through and below the surface casing, thereby Indicating the location of
the leak, or by pumping the water level down to the base of the surface
casing and comparing the rate of fall with the rate of fall with the
annul us f II led
Option 3 - Repair the welI by Inserting a liner pipe Inside the Injection
tubing on a packer or by filling the annul us full with cement
Option 4 - Demonstrate mechanical Integrity by one of the other methods
outlIned In Part 146.8
Figures 4.9 and 4.10 are forms that may be used to record results of the
water-In-annulus test.
4:33 Manifold Monitoring for Mechanical Integrity Testing
The agency currently contends that Injection wells are to be tested for
mechanical Integrity Individually. Available evidence Indicates a
manifold system Is not suited to Ml testing, but may be used for routine
monitoring In seme Class II and III wells.
This method of Ml testing Involves continuous monitoring of the
fnjectlvlty of a cluster of wells. Permanent flow rate and pressure
recording Instruments are set up at a designated number of manifold sites
where each manifold supplles a cluster of wel Is In Its area.
Manifold monitoring would at best Indicate that one of the methods of
mechanical Integrity testing described In the preceding sections have-to
be performed on each wel I to locate a leak.
4-51
-------
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4-52
-------
Mechanical Integrity Test Results
Haterln-Annulus Test
Company Name
Lease Name
Wei I Number/Name
Wei I Shut-In
Date
.Casing
Sizing
Tubing
Size
Shut-In
Pressure
Water Level
Start
End
Time
Start End
Comments
Measured at ten minute Intervals
Flgure'4.9
4-53
-------
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4-54
-------
Mechanical Integrity Test Results
Hater-In-Annulus Test
Company Name
Lease Name _
Wei I Number/Name
Date
Injection
Pressure
Water Level
Start End
Time
Start End
Test Results
(P/F)
Comments/
Reasons for Failure
Test Witnessed By
Figure 4.10
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4-56
-------
4:34 - 4:35
4:34 HTOGING AMD ABANDONMENT (PSA)
Proper plugging and abandorment of injection wells is essential to the
protection of underground sources of drinking water. An inadequately
plugged well could serve as a conduit for contaminants. Inspections are
conducted both during and after a plugging operation to assure a thorough
and careful completion of the task. The inspector should be familiar
with the regulations that govern the plugging and abandonment of a well
and the technologies that are involved in well plugging. The remainder
of this section will discuss the legal and technical aspects of plugging
and abandonnent.
The Underground Injection Control program includes regulations (40 CFR
146.10) that are implemented to ensure that abandoned injection wells do
not allow the movement of fluid either into or between underground
sources of drinking water. Specific requirements for the PSA plan,
notice of abandonnent, and the P&A report are found" in 40 CFR 144.28 (c),
(j) and (k). The owner/operator is required to notify the Regional
Administrator of impending plugging and abandorment at least 45 days
prior to such activities in EPA-adninistered programs.
4:35 The P&A Program and Well Classification
The operational status of an injection well should be characterized as
one of the following:
1. under construction
2. active
3. temporarily inactive (shut-in)
4. plugged and abandoned
5. abandoned and not properly plugged
The Abandonment Schedule
Current regulations specify that the time between cessation of operations
and the actual date of abandonment for Class I, II, and III wells not
exceed two years (Sec. 144.28). It may be necessary to abandon an
injection well within a determined length of time (less than two years)
to avoid the risk of environmental damage. Under certain circumstances
EPA will decide whether to abandon a well immediately upon cessation of
operations.
4-57
-------
4:36 - 4:38
4:36 The Objective of P & A
The objective of all plugging and abandonment Is to restore, Insofar as
feasible, the controlling hydrogeologlcal conditions that existed before
the well was drilled. USDW's will be protected when Internal and
external Ml have been assured.
4:37 Major Phases In P&A
An abandonment procedure Involves two phases: (1) well preparation; and
(2) well plugging. In many cases, the well can be. entered and Inspected
to ascertain Its condition. Tubing, packer, salvageable casing, and'
other materials should be removed. Remedial activities such as well
cleanout, fishing, milling, or squeeze cementing may be necessary to
ensure well Integrity and the effective placement of the cement plug(s).
Plugging Involves placing cement In a well either over Its entire depth
or at a series of discrete locations. If a series of plugs Is set, a
piugglng fluid (generally drlI I Ing fluld) Is left In the we I I between the
plugs. In addition to cement plugs, Class III wells can be plugged with
other plugs at the discretion of the Director. Bridge plugs alone are
not allowed. A variety of placement techniques Is available; they
generally Involve pumping the cement through drill pipe or tubing. P&A
designs are developed by the operator/owner and submitted to the Director
for approval.
4:38 Well Abandonment and Plugging
The Influence of Well Construction
Procedures used for proper abandonment of an Injection wel I depend on
well construction especially the casing and cementing program and the
completion method. However, seme deficiencies can be overcome In the
final preparation for abandonment. In some cases well preparation
Involves Installing a plug Inside the tubing near the packer and then
cutting the tubing above the cement plug. The four most conmon well
constructions are:
1. Open hole with surface pipe not cemented and no protective casing
2. Open hole with surface pipe partially cemented and no protective
casing
3. Open hole with surface pipe cemented to surface and no protective
casing
4. Both surface pipe and protective casing cemented
4-58
-------
4:38 - 4:42
Agricultural and Mineral Reserve Areas
Procedures for agricultural areas may require cutting the conductor
casing below plow depth (about 3 feet). Plugs may also be required
across potentially commercial mineral reserves (Including oil or gas).
4:39 Location of Cement Plugs
In most cases ft Is not necessary to Install continuous plugs. A series
of plugs set across or above underground sources of drinking water,
across or above potential oil and gas producing zones, at the base of the
surface casing, at the surface, and above the packer will be sufficient
provided the plugs are separated by an adequate plugging fluid (see
figures 4.11 and 4.12).
WeJ1 Preparation
Review the well construction (figures 4.13, 4.14 and 4.15) and determine
what changes are required before actually placing plugs. For example,
consider a well with Insufficient surface casing, I.e., the casing does
not extend below the base of the USDW fresh water. A suitable plugging
design Is that shown In figure 4.14. Study the well diagrams Included In
appendix G, Illustrating some plugging strategies used In Texas. Prior
to plugging, decide where sections of casing should be perforated so that
the open annulus can be squeezed.
4:40 Corrosion and Mechanical Integrity
Injection welI casing and cements are subject to corrosion and
degradation by Injection fluids and formation fluids. Corrosion of the
well casing or degradation of primary cement can make successful P&A
difficult. Plugs Inside the well casing will serve little purpose If
Injection fluids or formation fluids are able to migrate through a poorly
cemented annular space between the casing and the formation.
4:41 Stress-Induced Damage and Mechanical Integrity
Injection wells are also subject to mechanical stresses during
Installation and operation that may result In casing damage and
leakage. Deformation of the casing may also occur, Interfering with the
normal function of tools required In plugging operations.
4:42 P & A for Class III Wells
Unlike Class I and Class II wells, Class III mineral extraction wells may
be shallow, and completed In unconsolIdated sand and gravel formations;
however, If the well Is a deep one, the plugging procedure would be the
same as that for Class II welIs.
4-59
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4-60
-------
CONDUCTOR
PIPE:
SURFACE
CASING
BASE OF
USDW
5 1/2' - 8 5/8"
PROTECTION
CASING
TUBING
CEMENT
I
MONITORED
ANNULUS
FLUID
INJECTION
PACKER
PERFORATIONS
CEMENT
PLUG 3
ABANDONMENT
FLUID!
CEMENT
PLUG 2
ABANDONMENT
FLUID
/-MECHANICAL
/ BRIDGE PLUG
INJECTING
PLUGGED
Figure 4.11 Well Plugging - Cased and "Cemented Well with Removable Packer
4-61
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4-62
-------
INJECTION STRING
2 3/8'4.6 LB
CASING §
6 5/81 OD
WELDED
SURFACE
USDW
PRODUCING HORIZON
BOTTOM OF HOLE
CEMENT
SUPPORT
PLUG
SHOT/CUT
OFF PIPE
INJECTING
PLUGGED
Figure 4.12 Well Plugging - Partially Cased, Partially Cemented Well with Non-removable Packer
4-63
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4-64
-------
BOREHOLE
CEMENT
-CASING
-OPEN HOLE
i
BOREHOLE
CEMENT
SURFACE CASING
BOREHOLE
-PROTECTION CASING
-CEMENT
OPEN HOLE
Figure 4.13 Kinds of Open-hole Construction
4-65
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4-66
-------
?:
I&
i.*/
I
ft
I
8
I
*S » ,«
SURFACE CASING
CEMENT
-FIRST INTERMEDIATE
INTERMEDIATE CASING
-OPEN HOLE
HOLE
STUB OF CUT
CEMENT
PERFORATED INTERVAL
Rgure 4.14 Kinds of open-hole construction
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4-68
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CEMENT
CASING
HOLE
BASE OF
USDW
Rgure 4.15 Plugging - Well with Insufficient Casing
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4-70
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4:42 - 4:44
The relative shal lowness and smalI diameter of Class I I I welIs have
resulted fn abandonment practices which typically differ In several
respects from those of Class I and II wells. Generally, Class III wells
are easier and less expensive to cement from bottom to top using no
mechanical plug or an Inexpensive rubber plug.
4:43 Cement Selection for P 4 A
Selection of the best cement for a plug will depend on well depth,
temperature, character of ambient fluids, and mud properties.
Recommended thickening time Is "job running time" p-l us one (1) hour at
the temperature and pressure conditions for the plug- depth. The cement"
used should develop a high compresslve strength and tolerate mud
contamination likely to occur during placement.
For example, Class A cement Is often used for Class II wells. This
cement Is Intended for use frcm the surface to a depth of 6000 feet. The
recommended water-cement ratio, according to the American Petroleum
Institute (API), Is 0.46 by weight (5.2 gallons/sack). A wide variety of
additives Is available to alter the properties (weight, strength,
permeability) of the cement and to accelerate or retard Its setting time.
4:44 Well Preparation and Plug Installation Procedures
The following Is an example of the general procedure used In performing a
P&A program:
Move In workover rig and remove tubing
Move In a workover rig of a size and power suited to the welI depth and
diameter. Next, remove any Injection tubing In the well. Where there
are tubing and packer, It may be possible to remove both. If not, set a
plug Inside the tubing, at packer depth; then cut off the tubing just
above the packer and remove the tubing from the welI.
Clean the hole. If necessary
Subsequent steps depend upon the condition of the casing. If the well
casing above the cut-off tubing and packer Is In good condition, It Is
possible to complete abandonment by placing cement plugs at the required
locations.
In seme cases. It may be necessary to clean out the hole. This operation
may be quick and easy, or It may be long and arduous. Proper hole
preparation Is Important to effective seal Ing.
Achieve static eoul 11 br I urn
After cleaning the hole, design a mud system and, by circulating It,
achieve static equilibrium. Indicators of static equilibrium are the
4-71
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4:44 - 4:45
absence of mud movement and the exclusion of fluids that might cause
movement. Achieving static equilibrium Is Important to prevent any
contamination, breakup or dilution of the cement that would produce a
weak plug. In wells under pressure, the mud can be weighted with
additives such as salt, barlte, Iron oxide or galena; or a blowout
preventer can be used to overcome the pressure. With a blowout preventer
In place, mud can be circulated to static equilibrium.
Clean the casing or open JioJe surfaces with rotating scratchers:
The final step In well preparation Is to prepare the casing wall or wal.l
of the open hole for cementing. The lower portion of the.tubing or drill
pipe that Is lowered In the hole to set the plug and cement should be
equipped with central Izers and rotating wall scratchers. The rotation of
the scratchers cleans the bore to Improve bonding, allows bypassed mud to
mix uniformly with the cement, minimizes the formation of channels In the
cement, and reduces mud contamination. This tool" may be used with a
scouring chemical wash which will flush the sides of the well.
Install. Plugs
The circumstances under which static equilibrium of the mud system was
achieved will control how the plug Is placed. If the mud has been
brought to static equilibrium without the use of a blowout preventer, a
mechanical bridge plug Is lowered very carefully to the desired depth. A
small cement plug Is then spotted on top of the bridge plug. Additional
cement plugs may then be placed at selected Intervals, using either the
balanced or two plug method.
With a blowout preventer In place, cement plugs can be set through the
preventer. After the bottom plug has set up, the pressure In the well
can be bled off. If the pressure falls to zero and remains there, the
bottom plug Is good. The preventer can then be removed and additional
plugs set as required.
Common Methods of Plug InstaJ latlon
Several methods of plug Installation are acceptable under the UIC
program. Of these, the Balance Method is the most common. The Cement
Retainer and Two-plug methods can also be used.
4:45 The Balance Method of Plug Installation
This technique Involves setting a cement plug In the bottom of the casing
or at some other predetermined point that may be above the bottom of the
casing or In the open hole below the casing. The cement slurry Is pumped
down the drill pipe or tubing and back up to a calculated height that
4-72
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4:45 - 4:47
will balance the cement Inside and outside the pipe. The pipe Is then
pulled slowly out of the cement. When the pipe Is a considerable
distance above the top of the cement, It Is cleaned by reverse
circulation.
A smaI I-diameter pipe or tubing string Is used In order to leave as large
an annulus area as possible outside of the cementing pipe. This will
allow the cementing pipe to be pulled from the well without causing an
excessive drop In the cement or a surge of the cement plug, thereby
decreasing the chance of mud contamination.
The mud system must be In static equilibrium, as any fluid movement can
cause a poor plug. For a balanced plug job, calculations must be made to
determine cement volumes and heights of fluid. An example of the
calculations Involved Is presented In appendix F.
4:46 The Cement Retainer Method
This technique Involves the Installation of a cement retainer (packer)
.plug within a cased hole. The cement can be displaced through the cement
retainer so that the formations below the retainer can be squeezed with
cement. After the cementing of those formations, the cement retainer can
be closed at the bottom and the cement pipe disconnected from the top of
the retainer. Cement then can be placed on top of the retainer by slowly
withdrawing the cement pipe above It.
1. Cement Is placed below the retainer, assuring an effective plug upon
closing the retainer valve
2. Cement Is forced Into the formation without subjecting the old
casings to high pressure
3. Good control of the cement Is maintained
4. Gas percolations from the formations up past the retainer are
prevented, allowing the cement to set above the retainer without any
gas diffusion
5. The pressure test can be carried out Immediately after the retainer
Is set
This method Is one that Is highly regarded for placing cement under
pressure Into a producing formation or Injection zone through an open
borehole, through casing perforations, or through screens.
4:47 The Two-plug Method
This method Is used principally In open holes, employing a plug catcher
(figure 4.16) mounted on the bottom of a cementing string or drill pipe.
A bridge plug Is usually first set In the hole at the desired depth
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4-74
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PLUG CATCHER
CEMENT
ENTERS
ANNULUS
BOTTOM PLUG
PUMPED OUT '
EXCESS
SLURRY
TOP PLUG
CAUGHT
REVERSE
CIRCULATION
CUTS OFF
TOP CEMENT
PLUG
BOTTOM PLUG
Figure 4.16 Plug-catcher Method of Well Cementing
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4-76
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4:47 - 4:48
(bottom of the cement plug). The plug catcher is designed to permit the
first of two travelling plugs to pass through, and to catch the second
plug the one following the cement slurry. When the second plug lands,
a sudden rise In cement pressure announces Its arrival. A latching
device locks the second plug In place and helps to prevent cement from
moving back Into the string, but st.1 1 1 permits reverse circulation of
cement and fluids out through the cementing string.
After the cement has been placed, the cementing string Is raised so that
the top of the plug can be removed ("dressed off") at the desired height
by reverse circulation. .
Central Izers and scratchers can be Instal led at the bottom of the
cementing string to minimize contamination of the cement and to Improve
bonding.
Advantages of the Two-Plug Melbod
1. It minimizes the likelihood of overd Isplaclng the cement
2. It forms a tight, hard cement
3. It establishes a definite top for the plug
The two-plug method of plugging Is preferred to the balance method.
4:48 Dump Bailer Method
This method (figure 4.17) Is available for setting plugs In shallow
wells. A wireline truck lowers a bailer Into the well. Generally, a
bridge plug or cement basket Is first placed In the hole at the specified
depth. The bailer opens upon contact with the bridge plug and releases
the cement slurry at this location, as It Is raised.
Advantages Q! the Dump Ba I Jej^ Method
1. The depth of the cement plug Is easily measured
2. The cost Is low compared with others that require pumping equipment
D I sadvantages, of the Jumft BaJ Ler Jtethod
1. It Is less suited to setting deep plugs
2. Mud can contaminate the cement unless the hole Is circulated before
dumping (this Is also true of the balance method)
3. There Is a limit to the quantity of slurry that can be placed per
run, and an Initial set may be required before the next run can be
made
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4-78
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DUMP BAILER
CASING OR
BOREHOLE
CEMENT PLUG
BRIDGE PLUG
PLUGGING FLUID
Rgure 4.17 Dump Bailer Method of Well Cementing
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4:49 - 4:51
4:49 Check List for Witnessing P & A
Table 4.4 presents a checklist that should be helpful Fn witnessing a
P4A. If an Inspector Is available to witness the field procedures, he
may visit the site when events 7 through 11 are being completed.
4:50 CLASS IV CLOSURE
Construction or operation of an Injection well to dispose of hazardous or
radioactive water Into or above an underground formation which contains
drinking water Is prohibited under the Safe Drinking Water Act and under
the Hazardous and Solid Waste Amendments (1984) to the Resource
Conservation and Recovery Act (1976, Section 7010(a)). The proper
closure of Class IV wells Is of high priority.
Most Class IV wells differ dramatically In construction from Class I or
Class II wells. Some are better described as cesspools or sumps. Some
are uncased excavations varying In surface dimensions and ranging In
depth from 4 to 20 feet. Others are cased, or partially cased, with
large diameter pipe (up to 16") to depths of hundreds of feet.
4:51 Plugging Considerations for Class IV Wells
Because of the varied construction found In Class IV wells, closure
procedures must be determined on a case by case basis. Plugging and
abandonment of these ..weI Is should be witnessed by an EPA Inspector.
The Objective
The plugging operation should eliminate vertical movement of water within
any annular space that exists, and within the well bore. If artesian
conditions prevail, the plugging must confine the water to the aquifer In
such a way as to prevent loss of artesian pressure and prevent
circulation between ii»o or more aquifers.
When abandoning a Class IV well every effort should be made to restore
the geologic and hydrologlc conditions that existed before the well was
drilled and constructed.
Wei I Preparation
All materials which may Interfere with the sealing operation must be
removed. If possible, the casing should be removed. If the casing
cannot be removed, It should be torn or perforated to allow the grout to
completely fill any annular space, as well as the Interior of the casing
or bore holes.
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4-82
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TABLE 4.4
CHECK LIST FOR PLUGGING AM) ABANDONMENT
EVENT < ACTIVITY
1 Review drilling records and welI construction records
2 Review operations history
3 Review regional hydrogeologlc data
4 Determine plugging Intervals
5 Determine plug height and volume requirements for each
plug (refer to Appendix F)
6 Develop preliminary plugging and abandonment plan
7 Provide notice to EPA of Intent to plug and abandon
8 Remove tubing, packers, and salvageable casing, as
applIcable
9 Inspect well casings and primary cement for corrosion
breaks and voids
10 Repair and clean out well as necessary
11 Finalize abandonment plan, that Is, make any necessary
modifications based on results of Events 8 and 9
12 Establish static equilibrium of plugging fluid, If
necessary
13 Install bottom plug
14 Allow cement adequate time to set, If necessary
15 Pressure test plug for basic Integrity
16 Install Intermediate plugs, as needed
17 Repeat events 13 and 14 for each Intermediate plug
18 Install top plug, cut off casing 3' below grade,
Install monument If desired
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4-84
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4:51
Plugging Materials
Acceptable plugging materials Include cement and. In certain cases, non-
permeable clays. If a non-permeable clay Is used. It Is Important that
the predominant grain size be very small (diameter less than 1/256 mm),
with a very small percentage of particles In the silt- and sand- size
ranges. A quick and practical way to test a clayey material for
significant amounts of silt or sand, Is to rub the material vigorously In
the palm of the hand. A gritty feeling Indicates the presence of larger
particles.
Cement Is an excellent plugging material for Class IV' wells. The cement
should be used alone, without any sand or gravel. The use of concrete mix
for well plugging Is discouraged because, when the mix Is placed In
water, the coarser sand and gravel materials separate from the mix and
settle to the bottom, forming a permeable zone In the plug.
Plug Placement
Regardless of the type of material that Is used to plug a we I I, care must
be taken to completely fill the well bore. The easiest way to accomplish
this Is to mix the material with water to the consistency of a heavy
slurry. The material should be Introduced Into the well at the bottom,
or at the bottom of the Interval to be sealed (or filled), and placed
progressively upward.
In preparing a plugging slurry the mixture should be brought to a weight
of about 15 pounds per gallon. Table 4.5 can be used as a guide In
determining the amount of material required to fill most round boreholes
of nominal size. Let us suppose that a well 6 Inches In diameter and 250
feet deep Is to be plugged. On the 6 Inch diameter line of table 4.5 we
find that the volume of each linear foot Is 0.196 cubic foot and that
each linear foot has a capacity of 1.47 gallons. Thus, for the 250 foot
well, the volume Is 49.0 cubic feet (0.196 x 250), or a total capacity of
367.5 gallons (1.47 x 250). If this well were to be filled with cement,
we find that each liner foot would require 0.18 sack of cement, or a
total of 45 sacks (0.18 x 250) of cement to completely fill the well.
All sealing materials should be placed by grout pipe, tremle pipe, cement
bucket or dump bailer In such a way as to avoid segregation or dilution
of the sealing materials.
If the well Is very shallow and surface dimensions are large, backfilling
with clay using earth moving equipment may be acceptable. This type of
plugging and abandonment would be similar to closure of. an unl Ined pond-.
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4-86
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Diameter of
Hole (Inches)
Volume per Lin.
Ft. (cu.ft.)
TABLE 4.5
CAPACITY OF HOLE
Capacity per
Lin.Ft. (aals.)
Sacks Cement,
jjer LJn. Ft.
Lin. Ft. Per
Sacks Cement
2
2.5
3
3.5
4
4.5
5
5.5
6
6.5
7
7.5
8
8.5
9
9.5
10
10.5
11
11.5
12
12.5
13
13.5
14
15
16
17
18
19
20
22
24
26
28
30
36
0.022
0.034
0.049
0.067
0.087
0.117
0.136
0.165
0.196
0.230
0.267
0.307
0.349
0.394
0.442
0.492
0.545
0.601
0.650
0.721
0.785
0.852
0.922
0.994
1.069
1.227
1.396
1.576
1.766
1.969
2.182
2.640
3.142
3.687
4.276
4.909
7.069
0.16
0.25
0.37
0.50
0.65
0.88
1.02
1.23
1.47
1.72
2.00
2.30
2.61
2.95
3.31
3.68
4.08
4.50
4.94
5.39
5.87
6.37
6.90
7.44
8.00
9.18
10.44
11.80
13.21
14.73
15.95
19.75
23.50
27.58
31.99
36.72
52.88
0.02
0.03
0.04
0.06
0.08
0.1-1
0.12
0.15
0.18
0.21
0.24
0.28
0.32
0.36
0.40
0.45
0.50
0.55
0.60
0.66
0.71
0.77
0.84
0.90
0.97
1.12
1.27
1.43
1.61
1.79
1.98
2.40
2.86
3.36 '
3.89
4.46
6.43
50.25
32.15
22.52
16.47
12.64
9.94
8.06
6.67
5.60
4.77
4.12
3.59
3.15
2.79
2.49
2.23
2.02
1.83
1.67
1.53
1.40
1.29
1.19
1.11
1.03
0.90
0.79
0.70
0.62
0.56
0.50
0.42
0.35.
0.30
0.26
0.22
0.16
Cement calculations based on the volume of an average cement mixture being
1.1 cubic feet per sack of cement.
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4-88
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4:51 - 4:53
If a clay slurry Is used for plugging, at least the upper few feet of the
well should be filled with cement. This will help to prevent thinning of
the mud slurry by surface water and provide a sol Id upper surface.
Upper Wei I Terminus
Cut the casing off below grade If the well Is located In an area where
cultivation or construction Is probable. This could be done before
plugging begins. With the recommended cement plug In place, fill
material can then be placed over the well.
4:52 EJCRGENCY INSPECTIONS
An Inspector must be prepared to conduct a facility Inspection when an
emergency situation arises. An emergency situation Includes any situation
that poses an Imminent and substantial threat to the health of persons or
danger to the environment. The operator may wish to perform a workover,
convert the welI(s), revIse permit conditions, drill a new well or
conduct an environmental cleanup. These actions require the Issuance of
a temporary emergency permit. Inspectors have no authority to Issue
permits written or verbal. Permits can only be Issued, modified,
suspended or canceled by the Director of the DIG Program or his delegate.
Before a temporary permit Is Issued, It Is Important for the Inspector to
ascertain whether an emergency condition actually exists and that the
situation Is not the result of Improper planning and/or nonconpllance.
In addition, the proposed actlon(s) must be carefully examined to assure
that they will not result In movement of fluid Into underground sources
of drinking water. It should be emphasized that any permit Issued to
correct an emergency situation Is temporary In nature and that the- term
of the permit shal I not exceed the time necessary to prevent or correct
the hazard.
After a temporary permit has been Issued, the owner/operator must adhere
to the permit conditions while the proposed action Is being performed.
When evaluating the facility to verify the validity of the emergency or
when conducting an Inspection while the proposed action Is being carried
out, the Inspector should keep a detailed Inspection record and should
follow all applicable protocols as they are outlined elsewhere In this
guidance.
4:53 CITIZEN ONFLAINT INVESTIGATION
A complaint of either noncompllance or groundwater contamination which
has been registered by a citizen, or citizens group, against an Injection
well facility requires a response from the Agency. One possible response
Is a site Investigation of the facility. In some cases, the Inspector
may have to Inspect other wel Is In the area. Sampl Ing of Injected
fluld(s), water wells, and/or surface seeps may be required.
4-89
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4:53
The Inspector should follow the procedures outlined for compliance and
general Inspections (chapter 2 and sections 2:15 and 2:20) with
appropriate modifications Included to allow verification of the citizen's
specific complalnt(s).
4-90
-------
REFERENCES CHAPTER 4
API Recommended Onshore Production 0 per at Jug Practices for Protect Jon __of ..the
Environment. Issued by Production Department. API, API RP51, May 1982,
Dal las, Texas 75201.
Dewan, J.T. Mechanlca I J ntegr Ity Tests - Class IJ Wei Is R^v le*L and
Recommendation. Consultants Preliminary Report for EPA Regions III and II,
September, 1983.
Donaldson E.G., et al, Subsurface Waste I njectlon^ In the United States -
Fifteen Case Histories. United States Department of the Interior Bureau of
Mines, Information Circular 8636, 1974. .
Florida Department of Environmental Regulation, Bureau of Drinking Water and
Special Programs, State of Florida, Underground Injection Control Program.
January 1982.
Hubbert, M.K. and Willis, D.G. , Mechanics, of Jtydrau I l.c Fracturing, Trans AIME,
Vol. 210, 1957, 1530-168.
Matthews, C.S., and Russell, D.G., Pressure Buildup and Flow Tests In WeU^.
Soc. Petroleum Engineering, Doherty Series Mon. V.I, 1967.
McPhater, D. and MacTIerman, B., Wei I -Site Geologist's Hand^ook^ Pennwel I
Pub 1 1 sh Ing Company, Tulsa, Oklahoma, 1983.
Ohio River Valley Water Sanitation Commission, Undergr ou nd In Ject-ioii of
Wastewaters In the Oh I o Valley Regloj. ORANSCO, CIncInanntI, Ohio, 1973.
PIrson, Sylvaln J. Handbook, of JVell Log Anal ysls. Prentice-Hall Inc.,
Eng I ewood Cliffs, N.J., 1963.
Schlumberger, Scblumberger Log I nterpretatJojif Principles. Volume 1, New
York, Schlumberger Limited, 1972.
Smith, O.K. Cementing. (Monograph Vol. 44 of the Henry L. Doberty Series)
Society of Petroleum Engineers of AIME, Dal las, 1976.
Texas Department of Water Resources. Underground I njectlc-fi Control Technical
Assistance Manual f Report 274, 61 p.
U.S. Environmental Protection Agency, Technical Manual Injection Wei I
AbandonmentP EPA Office of Drinking Water Contract 68-01-5971, 1980.
U.S. Environmental Protection Agency. GuMance Document on Mechanical
Integrity Testing of Injection Wells. EPA Contract 68-01-5971, April, 1982.
4-91
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REFERENCES CHAPTER 4 (CONT.)
U.S. Environmental Protection Agency, Development of Procedures and Costs for
Proper Abandonment and Plugging of Injection Weilsr EPA Office of Drinking
Water Contract 68-01-5971, April 1980.
NIelson, David M., and Aller, Linda, Methods for Determining the Mechanical
Integrity of Class II Injection Wells,. U.S. Environmental Protection Agency
(EPA 600/2-84-121). Washington, D.C., 1984.
4-92
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5 Field Safety
The UIC Inspector Is required to visit many different types of Injection sites
operating under constantly changing conditions. Heavy machinery and tools are
used to perform most Injection well construction and servicing, and many times
adverse weather and hostile environmental conditions exist. Fortunately
direct exposure to hazardous situations Is minimal for an Inspector. Safety
In the highly competitive well drilling fl.eld Is, however, often sacrificed
for speed; It then becomes the Individual's responsibility to protect
himself. One cannot always rely on the well operator or his contractors to
specify what equipment and precautions are required.
5:1 Personal Protective Equipment
In general, certain personal protective equipment Is always required In
the field. This Includes head, eye, and foot protection. Where special
circumstances warrant, hand and hearing protection may also be needed.
Breathing equipment will be needed by the UIC field Inspector when
respiratory hazards are present. Respiratory hazards are characterized
by either contaminated atmospheres or oxygen-deficient atmospheres.
Head Protection
1. An approved helmet (safety hard hat) Is required to be worn by all
Inspectors while within a control area, with the exception of self-
contained areas such as truck cabs and field offices
2. A helmet to protect the head from limited electric shock and burn
should comply with requirements and specifications set forth In
American National Standards Safety Requirements for Industrial Head
Protection. Z89.1 - 1969. (Class A helmets are recommended)
3. Employees should Inspect and maintain liners In helmets to comply
with standards and they should be worn properly
4. Helmets should not be modified In any manner
Eye and Face Protection
Safety glasses must be worn at all times during field Inspections, and
must meet the ANSI Eye Protection Standard Z87.1 - 1979.
Protect I on
1. Safety shoes or safety boots are required for all field Inspections
2. Safety-toe footwear must meet the requirements and specifications In
Amer lean MatlonaJ Standard for Safe ty-Toewearf Z41.T - 1967, and
must be properly maintained. ' ' ''
5 - 1
-------
5:1 - 5:2
General Protective Equipment
1. Unreasonably loose, poorly fitted or torn clothing should not be
worn
2. Hazardous Jewelry, such as finger rings, chain bracelets, etc.,
should not be worn. This Is not Intended to Include wrist watches
equipped with bands which will easily break
3. When conditions warrant, typically during drilling and workovers-,
gloves and hearing protectors should be worn .
4. Long hair that may become entangled In moving or rotating machinery
should be contained In a suitable manner. Beards and sideburns
should be kept In such condition and of such length so as not to
Interfere with the proper and efficient use of .gas masks, air masks,
or other safety apparel or equipment. Any facial hair lying between
the sealing surface of a respirator faceplece and the wearer's skin
that will prevent a good seal shall not be allowed
5:2 Suggested Personal Protective Equipment Specifications
The following provides Information on features needed In all types of
personal protective equipment used In drilling and well servicing
operations (API, 1981). This equipment Is not needed or necessary In all
circumstances, but, If In your own judgment such equipment Is necessary,
the following description may prove helpful.
Head Protection
1. Field personnel should use high density polyethylene hats. The
shell should have three major features:
o A rain trough to prevent water from running down the back of the
neck
o Structured ribs molded Into the crown to assure maximum strength and
rigidity
o A flat facade to accomodate hot stamping of EPA Identification* The
Hard Hat should weigh 13 ounces and have adjustable. headband and
four-point suspension
2. Winter liners, which are universally sized and deslgned; to fit under
most brands of safety caps or hats, should cover the back of the
neck and be flame retardant
The liner should fold up, out of the way, on the outside of the cap
or hat when not In use
5-2
-------
5:2
Eye Protection Equipment
1. Eye protection must meet the requirements of American National
Standard Z87.1-1979, each lens having been subjected to a rigorous
drop-ball test before leaving the factory
Lenses that should be accepted are as follows:
o True Coloineutral grey lenses primarily used as anti-glare lenses
outdoors
o Clearto be used Indoors and outdoors
o Calobargreen lenses designed to be worn as a safeguard against
glare, ultraviolet and Infrared radiators
2. All eye protection should use side shields made of 24 or 40 wire
mesh with plastic binding and reinforcing brace bar, to provide
maximum lateral protection
3. Cover goggles should have four slotted air vents (or air directing
baffles) to control air flow and prevent Inner fogging, meeting the
requirements of ANSI X871-1979 for eye protection devices and having
lenses of a molded polycarbonate material, ophthalmlcally correct
and free of distortion and aberrations
Hearing Protection
1. Muff-type hearing protectors shouId be lightweight, rotational units
that can be worn over the head, behind the head, or under the chin
and should have been tested In accordance with ANSI Z24.22-1957
2. Self-adjusting hearing protectors should be lightweight, easy-to-
wear, properly fitted, disposable and Individually wrapped, with
attenuation tested In accordance with ANSI Z24.22-1957
3. Self-fitting In-the-ear hearing protectors, attached to a vinyl-
covered stainless steel headband that Is designed to be worn over
the head, under the chin or behind the head, should be non-toxic,
non-allergenlc high tear strength slllcone rubber, with attenuation
tested In accordance with ANSI S-3.19, 1975
Hand Protection
1. General Purpose:
o Determine the physical conditions to which the glove will be
subjected (cutting, puncturing, abrasion, etc.)
5-3
-------
5:2 - 5:3
o Consider the glove features required to perform the work (dexterity,
protection, grip, etc.)
o Choose the style which provides the best combination of features and
resistance to physical conditions
2. Specific Use Requirements:
o Choose glove types with highest ratings for the chemical and
physical conditions Involved, using two sets of gloves with the
outer set appropriate to the types of fluids Involved .
o Select unsupported gloves for extra dexterity and sense of touch,
picking a fabric-lined style If cut, snag, puncture or abrasion
resistance are Important
o Select an appropriate palm finish to provide the grip needed for the
job smooth, sprayed, dipped or embossed (sprayed and dipped
finishes grip best when wet)
o Choose glove length according to depth to which arm will be
Immersed, and to protect against chemical splash
o Select thin-gauge gloves for Jobs demanding sensitivity and high
flexibility, choosing a heavy duty style, particularly In dealing
with organic solvents, If greater protection or durability Is
wanted
o Choose the glove size or sizes that will assure optimum wear,
dexterity, working ease, comfort and employee satisfaction
3. Comprehensive Protection:
Determine the degree of glove toughness, sheerness, fit, sensitivity
and dlsposabtIIty required and then select the glove which provides
those benefits In order of their Importance
5:3 Other General Considerations for Personal Safety
Protective Clothing and Injury
Wearing special protective clothing can reduce an Individual's hearing,
vision and agility and greatly Increase the chance of Injury by drilling
tools, equipment and vehicles.
Eatlngp Drinking. Smoking
Personnel must not eat, drink, chew gum or tobacco, smoke, take medicines
or perform any other practice that might Increase hand to mouth transfer
of toxic materials, from gloves, unwashed hands or equipment.
5-4
-------
5:3 - 5:5
Mustaches^ Beards
If respirators are required, personnel should not have excessive facial
hair (heavy mustaches, beards) which can prevent the proper fit of
respirators.
Inspector's VehIcle
The Inspector's vehicle should be parked well clear of the control area
with keys left Inside so that It may be moved In the event of an
emergency situation.
5:4 Hazards Related to Injection Well Operations
The UIC Inspector will encounter different types of hazards depending on
the type of Inspection being conducted. These fall Into three main
categories:
1. Hazards during Well Treating Operations
2. Hazards during Drilling and Well Workove.r
3. Hazards during Routine Inspections
5:5 Safety during Well Treating Operations
Well treating usually consists of hydraulic fracturing, acidizing, or
both. The principal hazards are high pressures and corrosive materials.
Treating pressures of up to 5,000 psl are not uncommon. When lines give
way under this type of pressure flying objects can become deadly
projectiles. For this reason all pressurized hoses should be
hydrostatlcally tested, secured by chains and sometimes covered with hose
covers to deflect fluid leaks. Normally as an added precaution well
treating Is scheduled during daylight hours. A face shield Is required
whenever acids are to be handled.
The principal acids used In well stimulation work Include hydrochloric,
acetic, formic and hydrofluoric acids. Some special acids such as
sulfamlc, citric, lactic and others are used on occasion for special
applications. A short discussion of chemical hazards Is presented In
section 5:11.
During well treatment the Inspector should stay clear of the controlled
area, which should be plainly designated. The most advantageous location
to witness treatment Is on the treatment truck where Injection pressures
can be monitored. The Industry requires that treatment trucks and tanks
be located at least 100 feet from the well and out of falI line of the
derrick.
5-5
-------
5:6
5:6 Drilling and Well Workover Safety
The Inspector's greatest exposure to accidents Is probably during well
drilling and workover operations. To protect himself from a serious
accident he must be able to recognize unsafe conditions and unsafe
practices.
General Safety Rules
The following general safety rules should apply anytime the Inspector Is
Involved In monitoring construction, workovers, plugging and abandonment,-
or other activities requiring a drilling or workover rig.
1. Park outside of guyllnes
2. Wear hard hat, safety shoes and safety glasses at all times within
the guy I Ines
3. Note location of fire extinguishers. They could be stored at
different locations on each Job but are normally at an obvious and
easily accessible place
4. Never smoke near flammable materials
5. Insure that pipe stored on pipe rack Is adequately chocked with a
chock pin
6. Stay clear of shear relief valves and lines when under pressure
Safety In the Working Area
Normally an Inspector's duties will not require him to go on the rig
floor; however, should this become necessary, he must be accompanied by
the operator or his representative. While In the Immediate working area
the following safety rules should be followed:
1. Wear gloves for greasy and slippery handrails and to protect against
potential hand Injuries
2. Keep hands off of and feet clear of all lines that are moving
3. Watch for greasy or slippery floor
4. Stand clear of rig crew members when they are breaking apart tools
or tubular goods
5. Watch for wickers on wire rope
6. Note that guard rails on ladders and platforms must be In place
5-6
-------
5:6 - 5:10
7. Stay alert. Consider the hazards related to the work being
performed
5:7 Safety during Routine Inspections
Protective Equipment
Hard hat, safety glasses, outer protective coveralls and safety shoes are
minimal safety equipment required for entering any operating area.
Services Provided by Operator's Personnel .
Insist that any gauge calibration or sampling be performed by the
operator's personnel. This Is especially Important when performing an
Inspection at a Class I hazardous waste facility. High pressures and
faulty equipment can also be dangerous. The wel I-operator should know
the best way to take a sample, what safety measures his personnel should
take, and what Isolation points are necessary to "swap out" (replace)
gauges, If this Is required.
5:8 Class I Injection WelI Hazards
Class I Injection operations are especially hazardous since corrosive or
toxic chemicals may be Involved. The Inspector may come Into contact
with high concentrations of hazardous materials. Sampling equipment
will. In many cases, become unavoidably contaminated. These Items must
be thoroughly cleaned before the next use or discarded. The
decontamination procedure will vary greatly depending on the type and
strength of the hazardous material, and the nature of site activities. In
general, the more hazardous the contaminant, the more thorough the
decontamination should be. Contaminated equipment must not be placed
where It may expose others to hazardous substances. If splashed during
testing operations, personnel should shower themselves Immediately.
5:9 Disposable Clothing and Equipment
Use disposable clothing and sampling devices to minimize the amount of
equipment to be cleaned and volumes of decontamlnants and rinse solutions
to be disposed of.
5:10 Decontamination
Steam cleaning or high pressure spraying, utilizing water with a general
purpose low sudsing soap or detergent, Is the decontamination method of
choice (Maslansky, 1983). Physical scrubbing by disposable or easily
decontaminated brushes may be necessary to loosen caked-on materials. In
most Instances hot water (120-180°F) Is more effective than cold.
Flushing should be done under high pressure, taking care not to damage
such Items as dials, gauges and loosely hanging wires or hoses.
5-7
-------
5:11
5:11 Safe Handling of Hazardous Chemicals
Information on potentially hazardous materials and chemicals Is available
frcm manufacturers' catalogs and specific handling guides, such as Baskln
(1975). The documents tell how to safely handle chemical materials
encountered at Injection well sites. In addition, fire hazard, chemical
reactivity and first aid measures are presented so that steps necessary
for accident prevention may be taken.
When a Class I hazardous waste facility Is to be Inspected the Inspector
should determine which hazardous substances may. be present at that site".
This Information should be Included In the permit. The Inspector should,
at a minimum, determine the hazardous properties of these substances and
take all necessary precautions to ensure his or her safety. A little
advance preparation will make performing the Inspection that much safer.
5-8
-------
REFERENCES CHAPTER 5
American Petroleum Institute. Recommended Practices for Occupational Safety
and Health for Oil and Gas Well Drilling and Servfee Operations. API RP54,
Dal las, Texas, 1981.
Association of OMwel I Servicing Contractors, Recommended Safe Procedures and
Guidelines for Oil and Gas Well Servicing. AOSC, Dallas, Texas 1980.
Baskln, David A. Handling Guide for Potentially Hazardous Materials.
Materials Management and Safety, Incorporated, Nlles, Illinois, 1975.
Maslansky, S. P. Well Drilling and Hazardous Material Sites. Waste Water
Journal, April 1983, pp 46-50.
Environmental Protection Agency Order 1440.3, Respiratory Protection. July 24,
1981.
5-9
-------
INDEX OF SUBJECTS
AOR, 2:09
AOR, corrective action within, 2:10
Accident prevention, 5:1 - 5:8
Acids, safe handling of, 5:5, 5:11
Acoustic logging, 4:9
Additives for cement, App. D
Administrative orders, 2:6, App. E
Affidavit for warrant, 3:17
Air conditioning wells, 1:7
Analytical parameters, App. B
Aquifer, 2:7
Aquifer testing, 4:19, 4:20
Area of Review (AOR), 2:9
Authority for Inspections, 2:0, 2:1
Authority to enter, 2:0, 3:8, 4:22
Authority to establIsh UIC regulatory program, 1:0, 1:1,.3:1
BOP equipment, App. L
BackfII I welIs, 1:7
Backup faclIItles, 4:3
Balance method of plugging, 4:45, App. G
Banned Class IV wells, 1:1, 1:2, 1:6, 4:50, 4:51
Barlow's Guidance, 2:12, 3:16
Barrier wells, salt water Intrusion, 1:7
Blowout prevention and control, App. L
Bottom hole pressure test, 4:19
Calibration and maintenance of equipment, 4:2, 4:3
Casing collar locator, 4:14
Casing, steel, Integrity of, 4:5
Cement additives, App. D
Cement bond log, 4:5, App. C
Cement plugs, locating of, 4:39, App. D, H
Cement retainer method of plugging, 4:46
Cement, selection for plugging, 4:43, App. D
Cementing casing, 2:16, 4:17, App. D
Cementing devices, App. D
Cementing, primary, 4:17, 4:18
CentralIzers for cementing, App. D
Cesspools, 1:7
Chain of custody, 3:13, 4:3, 4:22, App. A
ChecklIsts for Inspections, App. M
Chemicals, safe handling of, 5:5, 5:11
"Christmas tree" at wellhead, App. I
Citizen complaint Investigation, 4:53
Citizen complaint, 2:15
Class III wells, plugging of, 4:42
Class IV welIs closure, 2:19, 4:50, 4:51
Class V welIs, 1:1, 1:7
Classification of Injection welIs, 1:1, 1:2
-------
Closing conference, 3:11
Closure of Class IV wells, 2:19, 4:50, 4:51
Clothing, protective, 5:3, 5:7, 5:9
Coal, In-sltu recovery wells for, 1:7
Complaint Investigation, 4:53
CompI lance history, facilities, 3:3
Compliance, verification of, 4:22
Composite samples, 3:12
Conduct, Inspector, 3:16, 3:18, 3:21, 4:22
Conference, closing, 3:11
Conference, opening, 3:9
Consent to enter and Inspect, 3:8, 3:16, 4:22
Containers for samples, 3:12, App. B
Contaminated articles, cleaning of, 5:10
Contaminated clothing and equipment, disposal of, 5:9
Cooling water return wells, 1:7
Copies of files, 3:10
Corrective action, 2:10
Corrective action, permit for, 2:10
Credentials, Inspector's, 3:8, 3:16, 4:22
Custody, chain of, 3:13, 4:3, 4:22, App. A
DV (differential valve) cementing tools, App. D
Decontamination, 5:8, 5:9, 5:10
Dental of entry, 3:16, 4:22
Directional survey, 4:11
Documentation of findings, 3:10, 4:22
Documents, warrant, 3:17, App. F
Drainage welIs, 1:7
Dry welIs, 1:7
Dump bailer method of plugging, 4:48
Dynamic test for Internal Ml, 4:27
Emergency Inspections, 2:15, 4:52
Energy wells, geothermal, 1:7
Enforcement history, facility, 3:3
Enforcement procedures, 2:3
Enforcement program, 2:1
Entry, consensual, 3:8, 3:16, 4:22
Entry, denial of, 3:16, 4:22
Epoxy cement, App. D
Exempted aquifer, 2:7, 2:8
Experimental technology wells, 1:7
External mechanical Integrity, 4:28-4:33, 4:37, 4:38
Eye, face protection, 5:1, 5:2, 5:5, 5:6, 5:7
Facility Information, 3:3, 3:22, 3:10, 4:2, 4:3, 4:22
File reviews, 3:3
Flles, copies of, 3:10
Float collar, App. D
Flow meters, recorders, App. I
Foot protection, 5:1, 5:6, 5:7
-------
Formal statements, 3:10
Formation fluid, 2:16, 4:21
Formation fluid samples, 2:16, 4:21, 5:7
Formation pressure, 2:16
Formation testing, 4:19, 4:20
Forms, Inspection, App. M, N
Frasch sulfur mining welIs, 1:5
Friction (head) loss, 4:27
Gas wel Is, 1:1, 1:2
Gauges and meters, App. I
General Inspections, 4:2
General maintenance Inspections, 2:20
Geophysical logs and external Ml, 4:29
Geothermal energy wells, 1:7
Glasses, eye, 5:2, 5:6, 5:7
Gloves, protective, 5:2, 5:6
Goggles, protective, 5:2, 5:6, 5:7
Grab samples, 3:12
Guide (cementing) shoe, App. D
Hand protection, 5:2, 5:6
Hard hats, 5:1, 5:2
Hazardous chemicals, safe handling of, 5:11
Hazardous waste Injection welIs, 1:1, 1:2, 1:6
Hazards at welI sites, 5:1-5:11
Head protection, 5:1, 5:2, 5:3, 5:5, 5:6
Hearing protection, 5:2
Helmet, protective, 5:1, 5:2
Hydrocarbon storage wells, 1:4
Identification, Inspector, 3:8, 3:16, 4:22
"In plain view" right to Inspect, 3:14
In-sltu mining wells, 1:5, 1:7
Industrial Injection welIs, 1:1, 1:3
Injection fluid samples, 3:12, 4:3, 5:7, App. I
Inject Ivlty testing, 2:16, 4:19, 4:20
Inspect, authority to, 2:1
Inspection plan development, 3:4
Inspection procedures, 4:1-4:5, 4:16, 4:18, 4:20, 4:23 - 4:33
Inspection report, 3:22
Inspection forms, App. M, N
Inspection, general, 4:2
Inspection, notification of, 3:6
Inspection, unannounced, 3:7
Inspections for mechanical Integrity, 4:23-4:33
Inspections, emergency, 4:52
Inspections, preoperattonal, 2:16, 4:4, 4:21
Inspections, schedulIng, 3:5
Inspections, site 4:3
Inspector's responsibilities, 3:1, 3:2'
Instrumentation, welIhead, app. I
-------
Internal mechanical Integrity, 4:25-4:27
Investigation, citizen complaint, 4:53
"Kicks", App. L
"KIII Ing" a welI, App. L
Latex cements, App. D
Leaks through annulus outside casing, 4:5, 4:8, 4:13, 4:24, 4:28, 4:29, 4:30, 4:32
Leaks through casing, 4:5, 4:15, 4:29, 4:30
Legal responsibility to regulate, 3:1
Log, cal I per, App. D
Logging of wells, 2:16, 2:17, 4:5 - 4:16, 4:29, 4:30, App. C
Logging, llthologlc, 4:6
Logging, neutron, 4:8, App. C
Logging, radioactivity, 4:8, 4:30, App. C
Logging, resistivity, 4:5, 4:7, App. C, 4:16
Logging, self-potential (SP), 4:7, App. C
Logging, wire-line, 4:16
Logs, acoustic, 4:9, 4:29
Logs, callper, 4:5, 4:9, 4:12
Logs, casing Inspection, 4:5, 4:15
Logs, cement bond, 4:5, App. C
Logs, density, 4:5, 4:6, 4:8, 4:9
Logs, electric, 4:5, 4:7, App. C, 4:16
Logs, fluid movement, 4:13, 4:5, 4:8, 4:24, 4:28, 4:29, 4:30, 4:32
Logs, noise, 4:9, 4:29
Logs, temperature, 4:10, 4:29
Manifold monitoring and Ml, 4:33, App. I
Mechanical Integrity and corrosion, 4:40
Mechanical Integrity and well class, 2:17
Mechanical Integrity and well records, 4:31
Mechanical Integrity by water-In-annulus test, 4:32
Mechanical Integrity, 2:17, 4:3, 4:23-4:33
Mechanical Integrity, external, 4:28-4:33, 4:37, 4:38
Mechanical Integrity, Internal, 4:25-4:27
Meters and gauges, App. I
Mineral extraction, Injection wells for, 1:5, 4:42
Monitoring at wellhead, App. I
Monitoring equipment, 4:2, 4:3, 4:22, App. I
Monitoring Information, 3:10, 3:22, 4:22
Monitoring, pressure data, 2:17, 3:22, 4:2, 4:3, 4:22, App. I
Multiple stage (cementing) tools, App. D
Municipal Injection welIs, 1:1, 1:3
Neutron logging, 4:8, App. C
Noise log, 4:29
Noncompllance Inspections, 2:15
Noncompllance, responses to, App. E
Noncompllance - civil and administrative penalties, 2:3, 2:4-2:6, 2:15
Notification of Inspection, 3:6
-------
011 and gas welIs, 1:1, 1:4
Oil shale, In-sltu recovery wells for, 1:7
One-quarter mile radius, 2:09
"Open field" right to Inspect, 3:14
Opening conference, 3:9
Operation and maintenance, facility, 4:2
Operational services, 5:7
Order, administrative, 2:6, App. E
Packers, 2:16, 4:25, 4:26 - 4:27
Penalties for noncompllance, 2:4, App. E
Penalties, administrative, 2:6, App. E
Penalties, civil, 2:5
Permit application, 3:3
Permit verification and compliance, 4:3, 4:22
Permit for corrective action, 2:10
Permits, 3:3
Photographs, 3:9, 3:10, 4:22
Planning, pre-Inspect Ion, 3:3
Plugged formations, App. K
Plugging and abandonment, 2:18, 4:34-4:51
Plugging and abandonment, notification of Intent for, 2:18
Plugging and abandonment, witnessing, 4:49
Plugging of wells, 2:10, 2:18, 4:34-4:39, 4:42-4:51, App. G, H
Plugging, balance method of, 4:45, App. G
Plugging, cement retainer method of, 4:46
Plugging, dump bailer method of, 4:48
Plugging, two-plug method of, 4:47
Plugs, cement, 4:38, 4:39, App. D, H
Potash solution mining, 1:5
Pozzolan-l Ime cements, App. D
Pre-treatment facilities, 3:3, 4:2, 4:3, 4:22
Preoperatfonal Inspections, 2:16, 4:4, 4:21
Preparation of well for plugging, 4:44, App. H
Preservation of samples, App. B
Pressure test, annul us, 2:17, 4:25 - 4:27, 4:32, App. I
Pressure test, static, 4:26
Primary cementing, 4:17, 4:18
Protective equipment, personal, 5:1 - 5:8
Pump discharge, volume data, App. J
Quality assurance (QA), 2:11
Quality assurance, control, 2:11, 4:3, 4:22, App. A, B
Radiation, Induced, 4:8, App. C
Radiation, natural, 4:8, App. C
Radioactive Iodine, 4:30
Radioactive tracer survey (RATS), 4:30, App. C
Radioactive tracer, 4:8, App. C
Radioactive waste Injection welIs, 1:1, 1:2, 1:6, 1:7
Radioactivity logging, 4:8, 4:30, App. C
RATS, 4:30, App. C
-------
Recharge welIs, 1:7
Regulations, General Grants, 2:11
Release, Injury, 3:8
Release, restricted Information, 3:10
Remedial cementing, 4:17, App. D
Repair of wells, 2:10, 5:6, App. K
Report forms for Inspections, App. L
Report, Inspection, 3:22
Reporting requirements, 4:22
Reservoir pressure test, 4:19, 4:20
Reservoir testing, 4:19, 4:20
Responses to violations, 4:22, App. E
Responsibilities of Inspector, 3:1, 3:2
SP logging, 4:7, App. C
Safe Drinking Water Act, 1:0, 2:0, 2:1
Safety, 3:9, 5:1-5:11
Salt solution mining, 1:5, 1:7
Saltwater barrier wells, 1:7
Sample containers, 3:12, App. B
Sample preservation, App. B
Sample size, 3:12
Samples of Injection fluid, 3:12, 4:3, 5:7, App. I
Samples, 3:9, 3:10, 3:12-3:13, 3:22, 4:21, 4:22, App. A, B, I
Samples, composite, 3:12
Samples, grab, 3:12
Samples, splIt, 3:9, 3:22
Secondary cementing, 4:17
Septic tank system welIs, 1:7
Shoe, guide, App. D
Shoes, safety, 5:1, 5:6, 5:7
Site Inspection, checklist for, 4:3
Snubbing, App. L
Solution mining welIs, 1:1, 1:2, 1:7
Spent brine Injection wells, 1:7
Squeeze cementing 4:17, App. D
Stand pipe pressure control, App. L
Statements, formal, 3:10
Static pressure test, 4:26
Stopes leaching welIs, 1:7
Storage of hydrocarbons by wells, 1:4
Stress-Induced damage and Ml, 4:41
Stripping, App. L
Subsidence control wells, 1:7
SuI fate-resistant cement, App. D
Sulfur mining Injection welIs, 1:5
Surface facilities, 4:2, 4:3, 4:22
IDS IImlt for USDW, 2:7
IDS, logging of, 4:7, App. C
Tar sands, In-sltu recovery wells for, 1:7
-------
Temperature logs, 4:10, 4:29
Test, pressure, annul us, 2:17, 4:25 - 4:27, 4:32, App. I
Total dissolved solids (TDS) limit for USDW, 2:7
Tracer, radioactive, 4:8, 4:30, App. C
Treatment, well, safety during, 5:4, 5:5
Troubleshooting welIs, App. K
Tubing and packer, 2:16, 4:26 - 4:27
Two-plug method of plugging, 4:47
USDWs and well classes, 1:1, 1:2
USDW, 1:1, 1:2, 2:7
USDW, definition of, 2:7
Underground sources of drinking water (USDW), 2:7
Upper terminus of plugged wells, 4:38, 4:51
Uranium mining wells, 1:5
Verifying mechanical Integrity, 2:17, 4:23-4:38
Violation documentation, 3:10, 4:22
Violation, alleged, 2:15
Violations, response to, 4:22, App. E
Waiver, Injury, 3:8
Waiver, restricted Information, 3:8
Warrant documents, 3:17, App. F
Warrantless entry, 3:14
Warrant prior to Inspection, 3:20
Warrant, 3:18 - 3:20
Warrant, Inspection by, 3:18 - 3:20
Water-In-annulus test for Ml, 4:32
Well construction Influence on plugging and abandonment, 4:38, App. H
Well preparation for plugging, 4:38, 4:.39, 4:44, 4:51, App. H
Well records as evidence of Ml, 4:31
Wellhead configuration, App. I
WelIhead Instrumentation, App. I
WIre-lIne logging checklist for witnessing, 4:16
Withdrawal of consent to Inspect, 3:15, 4:22
Witnessing logging, 2:17
Witnessing mechanical Integrity, 2:17, 4:23-4:33
Witnessing plugging and abandonment, 4:49
Witnessing primary cementing, 4:18
Witnessing wlre-lIne logging, 4:16
Workover of Injection well, 2:17, 4:2, 5:6, App. K
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APPENDIX A
CHAIN OF CUSTODY
-------
APPENDIX A
CHAIN OF CUSTODY
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APPENDIX A
CHAIN-OF-CUSTODY
A:1 ChaIn-of-Custody Procedures
In any activity that may be used to support litigation, the sampler must
be able to provide the cha I n-of-possession and custody of any samples
which either are offered as evidence or for. wh'Ich test results are.
Introduced as evidence. Written procedures must be available and
followed whenever evidence samples are collected, transferred, stored,
analyzed or destroyed. The primary objective of these procedures is to
create an accurate written record which can be used to trace the
possession and handling of a sample fron the mome.nt of its collection
through analysis and Its Introduction as evidence.
A sample is defined as being In someone's "custody" if:
o 'It Is In one's actual possession; or
o It Is In one's view, after being In one's physical possession; or
o It is In one's physical possession and then locked up so that no one
can tamper with It; or
o It Is kept in a secured area, restricted to authorized personnel
only.
The number of persons Involved In collecting and handling samples should
be kept to a minimum. Field records should be completed at the time the
sample Is collected and should be signed or Initialed, Including the date
and time, by the sample col lector(s). Field records should contain the
following information:
o Unique sampling or log number
o Date and time
o Source of sample (Including name, location and sample type)
o Preservative used
o Analyses required
o Name of collector(s)
o Pertinent field data (pH, DO, chlorine residual, specific
conductance, temperature, redox potential, etc.)
o Serial number on seals and transportation cases.
A - 1
-------
A:1 - A:2
Each sample must be labeled using waterproof Ink and sealed Immediately
after It Is collected. Labels should be filled out before collection to
minimize handling of sample container.
The sample container should then be placed In a transportation case along
with the cha I n-of-custody record form, pertinent field record, and
analysis request form as needed. The transportation case should be
sealed or locked. A locked or sealed chest eliminates the need for close
control of Individual samples. However, on those occasions when the use-
of a chest Is Inconvenient, the collector should seal the cap of the
Individual sample container with tape In a way that any tampering would
be easy to detect.
When transferring the samples, the transferee must sign and record the
date and time on the cha I n-of-custody record, which should have been
prepared according to enforcement requirements. Custody transfers made
to a sample custodian In the field should account for each sample,
although samples may be transferred as a group. Every person who takes
custody must fill In the appropriate section of the chaIn-of-custody
record. To minimize custody records, the number of custodians In the
chaln-of-possesslon should be minimized. Figure A.I Is an example of a
chaIn-of-custody record.
A:2 Instructions For Filling Out Chaln-of-Custody Record (Tag)
Note: All signatures must be legible
1. Sample No: Record In field log as wel I as on tag
2. Source of Sample: Be specific
3. Preservative: Be specific
4. Sample collector/witness: Signatures only (new procedures)
5. Remarks: Specify lab to receive samples and analyses to be
performed; specify whether sample Is grab or composite; for composite
samples specify the type of composite, for example, 24 hour composite,
1/2 depth-bottom composite, etc.; specify unusual characteristics that
may require special laboratory handling, for example, nauseous odor,
flammablIIty, etc.
Situation A: Sampler or witness personally delivers sample to lab.
Receipt of Sample: To be filled out by lab personnel receiving sample,
1. Received from: Name must be sampler or witness as shown on reverse
side of tag.
2. Disposition of Sample: Record lab log number In this space.-
A - 2
-------
CHAIN OF CUSTODY RECORD
ENVIRONMENTAL PROTECTION AGENCY
Environmental Services Division
Edison, New Jersey 08837
Name of Unit and Address
Samp e
Number
Number of
Containers
Description of Samples
Person Assuming Responsibility for Samples Time Date
Sample
Number
Samp le
Number
Sample
Number
Sample
Number
Rel Inquished by
Rel tnqulshed by
Rel Inquished by
Rel Inquished by
Received by
Received by
Received by
Received by
Time
Time
Time
Time
Date
Date
Date
Date
Reason for Change
of Custody
Reason for Change
of Custody
Reason for Change
of Custody
Reason for Change
of Custody
Figure A.I
A- 3
-------
A:2
Situation B; Sampler of witness sends sample to lab by certified mall or
common carrier.
Dispatch of Sample: To be filled out by sampler or witness.
1. Date/time Obtained: Same as reverse side of tag.
2. Source: Enter company or water body name and sample number.
3. Date/time Dispatched: Enter date and time custody of sample w.as
transferred to postal or carrier agent.
4. Method of Shipment:
(a) Common Carrier: Prepare GBL, listing and Identifying all samples
being sent. Sign GBL. Enter name of carrier and GBL number on tag.
(b) Postal Service: Enter Certified Mall In this space. Prepare a list
of sample numbers sent, Include name of lab receiving samples and record
certified mall number on this list. Sign and date this list. Affix
certified mall receipt to listing of sample numbers.
5. Sent to: Specify name of lab and person receiving samples.
Situation C: Sampler or witness sends sample to lab by courier. Courier
completes dispatch of sample:
1. Date/time obtained: Specify when custody of sample transferred from
sampler or witness to courier.
2. Source: Must be sampler or witness by name.
3. Method of Shipment: Specify type of vehicle used.
4. Date/time dispatched and sent to: Same as B.3 and B.5 above.
If two couriers are required: First courier fills out Receipt of
Sample Section as follows:
5. Received from: Must be sampler or witness
6. Disposition of sample: Record name of second courier. Second
courier fills out Dispatch of Sample as In C.1 to C.4 above.
Situation D; Sampler or witness transfers samples to courier who sends
samples by certified mall or common carrier to lab.
Carrier fills out Dispatch of Sample as follows:
1. Date/time obtained and source:
Same as C.1 and C.2 above.
A - 4
-------
A:2
2. Date/time Dispatched, Method of Shipment, Sent To Sections: Same as
B.3, B.4, and B.5.
Situation E: Sampler or witness personally performs analyses (no change
of custody). Fill out Remarks Section on front tag as follows. "I
personally performed the required analyses." Give date, time, and
laboratory name and sign. If any unusual situations arise, contact
Regional Enforcement personnel for advice.
A - 5
-------
APPENDIX
SAMPLING CONTAINERS, PRESERVATIVES
AND ANALYTICAL PARAMETERS
-------
APPENDIX B
SAMPLING CONTAINERS, PRESERVATIVES
AND ANALYTICAL PARAMETERS
-------
Table B.I Required Containers, Preservation Techniques, and Holding Times
Measurement
Table/Parameter
1A Bacterial Tests
Col I form, fecal
and total
Fe ca 1 s tre ptococ c I
|B Inorganic Tests
Acidity
Alkalinity
Ammonia
Biochemical oxygen
demand
Biochemical oxygen
demand carbonaceous
Bromide
Chemical oxygen
demand
Ch 1 or I de
Chloride Residual
Color
Cyanide, total and
Container Preservative
P,
P,
P,
P,
P,
P,
P,
P,
P,
P,
P,
P,
P,
G
G
G
G
G
G
G
G
G
G
G
G
Cool, 4°C
0.008* Na2S2025
Cool 4°C .
0.008$ Na2S2025
Cool, 4°C
Cool, 4°C
Cool, 4°C
H2S04 to pH<2
Cool, 4°C
Cool, 4°C
None required
Cool, 4°C
H2S04 to pH<2
None required
None required
Cool 4°C
Cool 4°C
Maximum
Holding Time
6 hours
6 hours
14 days
14 days
28 days
48 hours
48 hours
28 days
28 days
28 days
Analyze
Immediately
48 hours
14 days6
amenable to chI or I nation
NaOH to pH> 12
0.6g ascorbic acid
B - 1
-------
Table B.I Required Containers, Preservation Techniques, and Holding Times
Measurement
Tab 1 e/Parameter
JB. IjiorganJc Tests (cont.;
Fluoride
Hardness
Hydrogen Ion (ph)
KJeldahl and organic
Nitrogen
Chromium VI
Mercury
Metals,
except above
Nitrate
Nitrate- nitrite
Nitrite
Oil and grease
Conta I ner
P
P, G
P, G
P, G
P, G
P, G
P, G
P, G
P, G
P, G
P, G
Preservative
None required
HN03 to pH<2
None required
Cool, 4°C
H2S04 to pH<2
Cool, 4°C
HN03 to pH<2
HN03 to pH<2
Cool 4°C
Cool 4°C
H2S04 to pH<2
Cool, 4°C
Cool 4°C
Maximum
Holding Time
28 days
6 months
Analyze
'Immediately
28 days
24 hours
28 days
6 months
48 hours
28 days
48 hours
28 days
Organic carbon
Orthophosphate
Oxygen, Dissolved
Probe
WInkler
Phenols
P, G
P, G
G Bottle
and Top
G Bottle
and Top
G only
H2S04 to pH<2
Cool, 4°C
HCI or h
to pH<2
HCI or H2S04
28 days
Filter Immediately 48 hours
Cool, 4°C
None required
Fix on site and
store In dark
Cool, 4°C
H2S04 to pH<2
Analyze
Immediately
8 hours
28 days
B - 2
-------
Table B.I Required Containers, Preservation Techniques, and Holding Times
Measurement
Table/Parameter Container
IB (Cont.)
Phosphorus
(elemental )
Phosphorus, total
Residue, total
Residue, Filterable
Residue, Non-filterable
(TSS)
Residue, settleable
Residue, volatile
SI 1 lea
Specific conductance
Sulfate
Sulflde
Sulf Ite
Surfactants
Temperature
G
P.
P.
P,
P,
P,
P,
P
P,
P,
P,
P,
P,
P,
G
G
G
G
G
G
G
G
G
G
G
G
Preservative
Cool, 4°C
Cool, 4°C
H2S04 to pH<2
Cool, 4°C
Cool, 4°C
Cool, 4°C
Cool, 4°C
Cool, 4°C
Cool, 4°C
Cool, 4°C
Cool, 4°C
Cool, 4°C add
zinc acetate plus
sodium hydroxide
to pH>9
None required
Cool, 4°C
None required
Maximum
Holding Time
48 hours
20 days
7 days
7 days
7 days
48 hours
7 days
28 days
28 days
28 days
7 days
Analyze
I mmed I ate 1 y
48 hours
Anal yze
Immediately
Turbidity
P, G
Cool, 4°C
48 hours
B - 3
-------
SampJe Preservation and Maximum Holding Tljies Specific to CJas_s
II WeJJ SampJ es
The sampling preservation and maximum holding times are defined to maintain
the Integrity of the samples so that accurate and reliable data will be
generated by the laboratories analyzing such samples. It Is Incumbent on the
sampling teams to understand these requirements and plan the sampling projects
so that the requirements are met. It Is also necessary that the laboratory
personnel understand the requirements and notify the proper authorities when
there are problems so that corrective action can be taken.
Sampling containers should be made from polyethylene with polyethylene-lIned
lids. Glass Is required only when dissolved oxygen samples are stabilized fn-
the field and titrated later. Glass sample bottles may be used for all other
sample types but polyethylene-lIned lids are necessary.
When filtration Is required, It should be performed on-slte. If conditions
preclude field filtration, the samples must be delivered to facilities and
filtered within four (4) hours. Samples should be chilled to 4°C during
transit.
Table B.2 summarizes preservation and holding times for some tests.
B - 4
-------
Parameter
TABLE B.2
Preservation
Technique
Major Cations
(Na+, K+, Ca+2, Mg"1"2)
Major An Ions
(CI", S04, F~, Br")
Trace Metals
(Fe, Mn, Zn, Pb, Hg)
AlkalInlty
SulfIde
pH
Dissolved Oxygen
Specific Conductance
Total Dissolved Solids
CompatabllIty
HN03 to pH <2.0
Cool to 4°C
HNOj to pH < 2.0
Cool to 4°C
Cool to 4°C
Add Zn Acetate Reagent
plus NaOH to
pH >9.0
None
Meter methodnone
WInkier methodadd
MnS04 and Azlde-NaOH
reagents
Cool to 4°C
Cool to 4°C
Cool to 4°C
Maximum
Holding Time
6 months
1 month
6 months
14 days
7 days
1 hour maximum
determine on-slte
8 hours
28 days
7 days
48 hours
Note: Holding time and preservation requirements for other parameters
may be obtained from the RQAOs.
B - 5
-------
APPENDIX C
ELECTRICAL LOGGING
RADIOACTIVITY LOGGING
-------
APPENDIX C
ELECTRICAL LOGGING
RADIOACTIVITY LOGGING
-------
:1 - C:2
APPENDIX C
ELECTRICAL LOGGING
Electrical logging is a process by which electrical measurements provide data
on formations penetrated by the borehole.
C:1 Self Potential (SP) Logging
The principal downhole measurements made are voltage and resistance. The
voltage measured is the spontaneous potential (SP-) of the drilling mud
column in the borehole with respect to the ground ' potential near the
drilI ing rig.
The SP Is generated through the operation of several mechanisms Involving
borehole fluids and the boundaries between subsurface strata.
Measurement of this voltage is accomplished by lowering a sonde that
carries one electrode down the hole, and by recording the difference in
voltage between the sonde-borne electrode and an electrode driven Into
the ground at the surface. The SP log Is useful In detecting large
changes in the chemical character of formation fluids. Total Dissolved
Sol Ids (TDS) content of the formation water can be calculated from a
properly cal ibrated SP log.
C:2 Electrical Resistance
Resistance of subsurface strata is measured in two general way-s. One
method involves impressing a voltage across 2 electrodes suspended one
above the other on a cable lowered into the liquid-filled bore hole.
The flow of current from one electrode to the other Induces a voltage
difference between two other electrodes located between the first two.
The voltage induced across the second pair of electrodes is recorded
continuously on a graph at the surface. A variation of this method is to
monitor the amount of current that Is actually forced into the formation
from the electrodes. The first method requires that the drilling mud be
conductive. The second method .involves induction, and so nonconducting
muds can be used.
An induction log uses a transmitter In one end of a sonde to generate a
magnetic field that induces eddy currents into the formation surrounding
the borehole. These eddy currents in turn generate their own magnetic
fields which are sensed by a receiver in the other end of the sonde. The
magnitude of the Induced eddy currents and their associated magnetic
fields Is a function of formation resistivity; the sonde receiver records
the apparent formation resistivity.
In practice, the electric log usually consists of a lateral curve, two
normal curves, and an SP curve all simultaneously recorded on a strip
log. The induction log is commonly a combination of four logs made
simultaneously: SP, short normal, conductivity, and its reciprocal,
resistivity. The gamma ray and single-point resistance curves are.
substituted in many Instances for the SP and resistivity. The gamma ray.
C - 1
-------
C:2 - C:5
and single-point resistance logging systems are very versatile In terms
of measurements which can be made, and when combined with radioactive or
acoustic systems are very effective in determining formation
characteristics.
RADIOACTIVITY LOGGING
Common to all radiation logging devices is some means of measuring
radioactivity in the borehole. The radioactivity may be either natural
or Induced, or It can result from injection of an isotope used as. a
tracer. Because certain types of radiation are very penetrating, these
radioactivity logs can be used In cased holes. .
C:3 Natural Radiation Log
A natural radiation log measures gamma radiation produced by decay of
uranium, thorium, or potassium contained In the formation. This log may
also be used to detect a radioactive tracer; however, the chief use of
natural gamma logs is to identify the I ithology.
C:4 Gamma Density (Gamma-Gamma) Log
Gamma density (gamma-gamma) and neutron logs are examples of induced
radiation logs. A gamma density tool Includes a source of gamma rays
which penetrate into the formation at the borehole wall. This tool also
contains a detector which Is located a short distance away and measures
the flux of gamma rays scattered by the formation. The detected flux Is
proportional to the electron density of the formation, which In turn is
roughly proportional to formation bulk density.
C:5 Neutron Log
The standard neutron log measures the reduction of neutron energy
resulting from collisions of emitted neutrons with nuclei of formation
materials. The greatest energy losses occur when neutrons collide with
hydrogen nuclei. Thus, the log reflects the total water content of the
rocks. This may Include pore water between mineral grains, bound or
absorbed water In clay, or water of crystallization in gypsum. This log
gives Information concerning the porosity, or degree of water saturation
of the formation.
C - 2
-------
APPENDIX C
LOUISIANA DEPARTMENT OF NATURAL RESOURCES
OFFICE OF CONVERSATION
RADIOACTIVE TRACER SURVEY GUIDELINES AND PROCEDURE
for Injection Wells Completed with Tubing and Packer
that have Tubing, Packer, and Casing Integrity
Guide!Ines:
A. The gamma-ray log may be run up to 60 ft/mln at a time constant of. .1
second (suggested) or up to 30 ft/mln at TC 2-or up to 15 ft/mln at
TC 4. Indicate logging speed and time constant on the log heading.
B. Include a collar locator for depth control.
C. Vertical scale may be 1", 2", or 5" per 100 ft, 2" being preferred.
D. Indicate In API units the horizontal scale. It Is suggested that
two gamma-ray curves be recorded on each log pass at different
sensitivities (such as one at 20 API units per division and one at
100 API units per division). If only one gamma-ray curve Is
recorded, make sure the sensitivity used Is such that the tracer
material will be obvious when detected and will not be confused with
normal "hot spots" In the formations; I.e., choose a low
sensitivity. It should be sensitive enough to show IIthology.
E. Indicate beginning and ending clock tfmes on each log pass.
F. Indicate Injection rate (If any) during each log pass.
G. Indicate volume of water Injected between log passes.
H. Indicate volume and concentration of each slug of tracer material.
If preferred, most of the above may be shown In tabular form rather than on
the log, as long as all Information Is provided (the Injection and Mining
Division will provide forms on request).
Procedure:
1. Run a base log from the Injection zone (starting 100 ft below. If
possible) to at least 100 ft above packer depth.
2. Release tracer material from the tool Into the tubing about 100 ft
above packer depth (or. If tool will not release tracer, tracer may
be Injected at the surface, although It will probably string out
going down). Trace the slug to at least the top of the prev lously
C - 3
-------
recorded slug depth (to show whether any tracer was left behind).
Although It Is difficult to determine the number of passes needed,
the complete pathway fol I owed by al I of the tracer needs to be
demonstrated. Ideally, the following passes should be made:
1. upon release of the tracer about 100 ft above packer
depth;
2. below packer depth (whether In tubing or casing) but
before leaving the casing;
3. while or just after leaving the casing;
4. to ?) continuing to follow the tracer with several passes'
until It virtually disappears; the last pass should
essentially duplIcate the base log.
It Is suggested that pumping not occur during logging; that Is, pump
only to move tracer downnole between log passes. Be cautious of the
volume of water pumped during or between log passes to prevent
premature loss of the tracer! If the tracer has been prematurely
lost, It will be necessary to release another slug and follow It
from the point of the last good log pass.
3. A few passes may be shown on one log segment If desired as long as
each gamma-ray curve along with Its collar locator Is
distinguishable. Otherwise, make each pass on a separate log
segment.
4. An Interpretation of the log must be supplied by the logging company
on the log Itself.
5. Include a schematic diagram of the well on the log Itself. The
diagram should show the casing diameters and depths, tubing diameter
and depth, packer depth, perforated Intervals and total or plugged
back depth. Indicate the pathway the tracer material appears to
have taken using arrows.
6. Write Serial Number of well on log heading, If available.
NOTE: The above "Guidelines" and "Procedure" will apply In most Instances.
In certain situations, It will be necessary to deviate from these
directions. Necessary modifications may be made as long as the
pathway the tracer follows from packer depth on down can be
demonstrated.
AprM/84
C - 4
-------
LOUISIANA DEPARTNENT OF NATURAL RESOURCES
OFFICE OF CONSERVATION
RADIOACTIVE TRACER SURVEY GUIDELINES AND PROCEDURE
for Annular Disposal Wells
The purpose of running a radioactive tracer survey In an annular disposal welI
Is twofol d:
.1. to show whether Injected fluids will leak through a hole or holes In
the casing above the casing shoe; and
2. to show whether Injected fluids will migrate vertically outside the
casing after reaching the casing shoe.
GuldelInes:
A. The gamma-ray log may be run up to 60 ft/mln at a time constant of 1
second (suggested) or up to 30 ft/mln at TC 2 or up to 15 ft/mln at
TC 4. Indicate logging speed and time constant on the log heading.
B. Include a collar locator for depth control.
C. Vertical scale may be 1", 2", or 5" per 100 ft, 2" being preferred.
D. Indicate In API units the horizontal scale. It Is suggested that
two gamma-ray curves be recorded on each log pass at different
sensitivities (such as one at 20 API units per division and one at
100 API units per division). If only one gamma-ray curve Is
recorded, make sure the sensitivity used Is such that the tracer
material will be obvious when detected and will not be confused with
normal "hot spots" In the formations; I.e., choose a low
sensitivity. It need not be sensitive enough to show llthology.
E. Indicate beginning and ending clock times on each log pass.
F. Indicate Injection rate (If any) during each log pass.
G. Indicate volume of water Injected between log passes.
H. Indicate volume and concentration of each slug of tracer material.
If preferred, most of the above may be shown In tabular form rather than on
the log, as long as all Information Is provided (the Injection and Mining
Division will provide forms on request).
Procedure:
1. Run a base log from at least 200 ft below the casing shoe to the
surface.
C - 5
-------
2. Pump tracer material. Iodine , Into the annular space and trace
the slug with the gamma-ray tool. Run short (approximately 500 ft)
overlapping log passes following the tracer downhole. Each pass
should extend from about 100 ft below the slug depth to at least 25
ft above the top of the previously recorded slug depth (to show
whether any tracer was left behind). An Ideal sequence would be
somethIng I Ike:
a. place gamma-ray tool at 475 ft;
b. pump tracer down until detected by tool;
c. log from 600 ft to the surface slug discovered at 475-500 ft);
d. place tool at 975 ft;
e. pump tracer down until detected by tool;
f. log from 1100 ft to 450 ft (25 ft above previous slug)
g. place tool at 1475 ft;
h. pump tracer down until detected by tool;
I. log from 1600 ft to 940 ft (25 ft above previous slug I.
and so on at approximately 500-ft Increments (assuming no tracer was
previously left behind). It Is suggested that pumping not occur
during logging; that Is, pump only to move tracer downhole between
log passes to prevent premature loss of the tracer! If the tracer
has been prematurely lost. It will be necessary to Inject another
slug and follow It from the last point of the last good log pass.
3. As soon as the tracer reaches the casing shoe, stop pumping (or slow
as much as possible) and run a log to the surface.
4. As tracer Is pumped out of the casing Into the welI bore, run a few
short log passes from at least 50 ft below the slug depth to at
least 50 ft above the slug depth showing the pathway the tracer
follows. Continue running passes until the tracer virtually
disappears. The last pass should essentially duplicate the. base
log.
5. Another log may be run to the surface after Step 4. This should be
done particularly If the log run In Step 3 still shows "hot spots"
due to leaks or to pipe scaling entrapping some of the tracer
material.
C - 6
-------
6. A few passes may be shown on one log segment if desired as long as
each gamma-ray curve along with Its collar locator Is
distinguishable. Otherwise, make each pass on a separate log
segment.
7. An Interpretation of the log must be supplied by the logging company
on the log Itsel f.
8. Include a schematic diagram of the well on the log Itself. The
diagram should show the casing diameters and depths, tubing diameter
and depth (If any), perforated Intervals, and total or plugged back
depth. Indicate the pathway the tracer material appears to have
taken using arrows.
9. Write Serial Number of well on log heading. If available.
NOTE: The above "Guidelines" and "Procedure" will apply In most Instances.
In certain situations, It will be necessary to deviate from these
directions. Deep wells will probably need a concentrated slug In
order to show Integrity along the entire length of casing.
Necessary modifications may be made, as long as the two purposes
stated at the top can be demonstrated as evidence of well Integrity.
Apr 11/84
C - 7
-------
LOUISIANA DEPARTMENT OF NATURAL RESOURCES
OFFICE OF CONSERVATION
RADIOACTIVE TRACER SURVEY GUIDELINES AND PROCEDURES
for Casing Disposal Wells (completed without Tubing or Packer)
The purpose of
twofol d:
running a radioactive tracer survey In an Injection well Is
1. to show whether Injected fluids will leak through a hole or holes In
the casing above and, In some cases, below the Intended disposal
Interval ; and
2. to show whether Injected fluids will migrate vertically outside the
casing after reaching the Intended disposal zone;
Guide! Ines:
A. The gamma-ray log may be run up to 60 ft/mln at a time constant of 1
second (suggested) or up to 30 ft/mln at TC 2 "or up to 15 ft/mln at
TC 4. Indicate logging speed and time constant on the log heading.
B. Include a collar locator for depth control.
C. Vertical scale may be 1", 2", or 5" per 100 ft, 2" being preferred.
D.
E.
F.
Indicate In API units the horizontal scale. It Is suggested that
two gamma-ray curves be recorded on each log pass at different
sensitivities (such as one at 20 API units per division and one at
100 API units per division). If only one gamma^ray curve Is
recorded, -make sure the sensitivity used Is such that the tracer
material will be obvious when detected and will not be confused with
normal "hot spots" In the formations; I.e., choose a low
sensitivity. It need not be sensitive enough to show I Ithology.
Indicate beginning and ending clock times on each log pass.
Indicate Injection rate (If any) during each log pass.
G. Indicate volume of water Injected between log passes.
H. Indicate volume and concentration of each slug of tracer material.
If preferred, most of the above may be shown In tabular form rather than on
the log, as long as all Information Is provided (the Injection and Mining
Division will provide forms on request).
Procedure:
BEFORE LOGGING: REMOVE TUBING, IF PRESENT, FROM WELL (REQUIRES WORK
PERMIT FROM THE INJECTION AND MINING DIVISION). IF THE LOGGING TOOL
CANNOT GET DOWN TO AT LEAST THE UPPERMOST PERFS, THE WELLS WILL NEED TO
BE CLEANED OUT BEFORE RUNNING THE SURVEY.
C - 8
-------
1. Run a base log from the Injection zone (starting 200 ft below, If
possible) to the surface.
2A. If the well takes fluid on a vacuum or the static fluid level Is
below the top of the casing:
a. Indicate fluid level on the log;
b. release tracer material from the logging tool In the top 20 ft
of fluid;
c. log from at least 50 ft below to at least 50 ft above the slug
before pumping the tracer downward. .
2B. If the we I I does not take fluid on a vacuumt
a. place logging tool at 50 ft;
b. pump tracer material Into the well from the surface until it is
first detected by the logging tool; stop pumping; ,
c. log from at least 50 ft below the slug to the surface before
resuming pumping.
3. Pump tracer down and run short (approximately 500-ft) overlapping
log passes following the tracer downhole. Each pass should extend
from about 100 ft below the slug to at least 25 ft above the top of
the previously recorded slug depth (to show whether any tracer was
left behind). An Ideal sequence would be something like:
a. place gamma-ray tool at 450 ft;
b. pump tracer down until detected by tool;
c. log from 600 ft to the surface slug discovered at 425-500 ft);
d. place tool at 950 ft;
e. pump tracer down until detected by tool;
f. log from 1100 ft to 400 ft (25 ft above previous slug!).
g. place tool at 1450 ft;
h. pump tracer down until detected by tool;
I. log from 1600 ft to 885 ft (25 ft above previous slug!).
and so on at approximately 500-ft Increments (assuming no tracer was
previously left behind). It Is suggested that pumping not occur
during logging; that is, pump only to move tracer downhole between
C - 9
-------
log passes to prevent premature loss of the tracer! If the tracer
has been prematurely lost, It will be necessary to (nject another
slug and follow It from the last point of the last good log pass.
4. As soon as the tracer reaches the Injection level, stop pumping and
run a log to the surface.
5. Return to the Injection Interval and run several short log passes
frcm at least 50 ft below the slug depth to at least 50 ft above the
slug depth showing the pathway the tracer follows. Continue running
passes until the tracer virtually disappears. The last pass should
end up being similar to base log.
6. Another log may be run to the surface after Step 5. This should be
done particularly If the log run In Step 4 still shows "hot spots"
due to leaks or to pipe scaling entrapping some of the tracer
material.
7. A few passes may be shown on one log segment If desired as long as
each gamma-ray curve along with Its collar locator Is
distinguishable. Otherwise, make each pass on a separate log
segment.
8. An Interpretation of the log must be supplied by the logging company
on the log Itself.
9. Include a schematic diagram of the well on the log Itself. The
diagram should show the casing diameters and depths, tubing diameter
and depth (If any), perforated Intervals, and total or plugged back
depth. Indicate the pathway the tracer material appears to have
taken using arrows.
10. Write Serial Number of well on log heading.
NOTE: The above "Guidelines" and "Procedure" will apply In most Instances.
In'certain situations, It will be necessary to deviate from these
directions. Deep wells will probably need a concentrated slug or
multiple slugs Injected downhole In order to show Integrity along
the entire length of casing. Necessary modifications may be made,
as long as the two purposes stated at the top can be demonstrated as
evidence of well Integrity.
Apr 11/84
C - 10
-------
APPENDIX C
CEMENT BOND LOG
The Bond Index Method
The bond Index method relates the amplitude attenuation In a zone of
Interest to the attenuation In a zone that Is Ideally 100? cemented. The
advantage of this technique Is that Is depends on a ratio of attenuations and
not absolute values, thus minimizing possible errors resulting fron unknown
parameters or conditions. Zone Isolation predictions are dependent upon the
bond Index and the length of bonded Interval, which varies with casing size.
Gearhart Industries, Inc. has developed an Interpretation tab.le
(following page) for cement bond log evaluation. One simply has to find the
appropriate casing size and weight, read to the right to obtain the millivolt
value for 100$ cement (assuming a cement of 3000 psl compresslve strength) and
the good bond cutoff value (bond Index of 0.6). The 100? cement value Is
listed for those cases where the lowest value on the log may not be 100?
cement.
A vertical line Is drawn on the log at the appropriate millivolt value
for good bond cutoff. Any reading to the left of this line (lower millivolt
values) Is considered a good bond; any reading to the right (higher millivolt
values) Is considered a poor bond. The column on the far right of the table
Is the required vertical length of good bonding necessary for Isolation.
C - 11
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Cement Bond Log Interpretation Guide
Gearhart Industries, Inc.
Casing
Size
4 1/2"
5" .
5 1/2"
7"
7 5/8"
9 5/8"
10 3/4"
Wt.
9.5
11.6
13.5
15.0
18.0
21.0
15.5
17.0
20.0
23.0
23.0
26.0
29.0
32.0
35.0
38.0
40.0
26.4
29.7
33.7
39.0
40.0
43.5
47.0
53.5
.5
,5
40.
45.
48.0
51.0
54.0
55.5
Travel
Time
u-sec
254
258
269
Free
Pipe
Signal
81 mv
76 mv
72 mv
289
62 mv
302
59 mv
332
51 mv
352
48 mv
Class H Cement
3000 psl 60% Bond
100* Cement Cutoff
0.2 mv
0.6 mv
1.0 mv
0.9 mv
2.2 mv
3.6 mv
0.7 mv
1 .0 mv
2.1 mv
3.5 mv
1.0 mv
1.7 mv
2.4 mv
3.3 mv
4.0 mv
5.0 mv
6.0 mv
1 .1 mv
1.8 mv
2.6 mv
3.5 mv
1.8 mv
2.2 mv
2.7 mv
4.0 mv
1.2 mv
1.8 mv
2.1 mv
2.5 mv
2.7 mv
2.8 mv
2.3 mv
4.6 mv
7.0 mv
5.5 mv'
10.0 mv
15.0 mv
4.8 mv
6.0 mv
9.0 mv
13.0 mv
5.5 mv
7.5 mv
9.3 mv
13.0 mv
14.0 mv
15.0 mv
17.0 mv
5.5 mv
7.5 mv
10.0 mv
13.0 mv
6.8 mv
8.5 mv
9.0 mv
12.0 mv
5.1 mv
6.5 mv
7.6 mv
8.0 mv
8.4 mv
8.8 mv
I ntervaI
For
Isolation
5 feet
5 feet
6 feet
11 feet
12 feet
15 feet
18 feet
C - 12
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APPENDIX D
CEMENTING OF WELLS
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APPENDIX D
CEMENTING
OF
WELLS
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D:1 - 0:4
APPENDIX D
CEJCNTING OF WELLS
D:1 Cements
The American Petroleum Institute has established eight classes of deep
well cements based upon suitability for use at various depths and
temperatures. A number of special cements, for which American Petroleum
Institute standards have not been established, have certain applications
In disposal wells. Pozzolan-lIme cements combine the advantages of light..
weight and strength at high temperatures. Sulfate-resistant cements may
be used to cement casing directly above the Injection zone when It Is
expected that the Injected wastewater will have elevated levels of
sulfate. Latex cements may be used to Improve bond strength of cement to
casing and to Increase the resistance of the hardened cement to acid.
Epoxy resin cements are especially resistant to corrosive acids and other
chemicals. These resins are mixed with a catalyst and used to cement the
bottom portion of the long-string casing where corrosive wastes may be In
contact with the cement. They are also used for squeeze cementing in
welIs.
0:2 Cement Additives
Cementing companies may select from more than 40 additives to obtain
optimum cement slurry characteristics for any downhole condition. The
general categories of cement additives Include: accelerators, retarders,
light-weight additives, heavy-weight additives, lost-circulation control
additives, water-loss control additives, and friction reducers.
D:3 Cement Volume Requirements
The volume of cement needed for a casing job Includes the calculated
volume of annular space outside the wall, plus an excess volume of
annular space outside the wall, plus an excess volume of cement for lost
circulation or hole washouts and high porosity zones. Volume of the
annular space outside the casing wall Is considered to be equal to the
hole volume determined from a good cal fper log, minus the volume of the
casing string to be cemented. An additional volume of cement, equal to
from 20 to 30 percent of the calculated annular cement volume, should
also be on location and ready for pumping In case It Is needed. If a
good callper log cannot be obtained for the borehole, the required cement
volume can be calculated from an estimate of hole diameter based on drill
bit size. However, the percent of excess cement should then be Increased
to allow for the relative Inaccuracy of this method.
0:4 Cementing Devices
To obtain a good primary cement job, a number of devices can be Installed
In a casing string during assembly. A guide shoe Installed on the bottom
0 - 1
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D:4 - D:5
of each casing string helps guide the casing downhole to the setting
depth. The shoe Is constructed with a beveled edge on the bottom. A
float collar Is Installed on top of the first, or lowest, joint of a
casing string. This tubular device contains a valve which allows mud and
cement to be pumped down through the pipe, but prevents backflow of fluid
up Inside the casing. The float collar holds the cement slurry In place
outside the casing.
Multiple stage tools, or DV (differential valve) tools, may be Installed
In a casing string to allow the casing to be cemented In separate
operations, or stages. Use of such tools may be advisable In certain-
areas to prevent downhole formations from being subjected to high cement
slurry hydrostatic pressures that may fracture formations. The stage
tool also Is used to emplace different types of cement In the same hole,
for example, to separate epoxy from Portland cements. Typically, a
stage tool Is placed at an Intermediate depth, or about one-half the
total cementing depth.
With a stage tool, the bottom stage of the casing Is cemented and allowed
to harden. After the bottom stage slurry has completely passed through
the tool and Is In place outside the casing, ports In the tool are
mechanically opened. Excess cement from the bottom stage can be
circulated out of the hole through these open ports, and mud circulation
can be continued while waiting for the bottom stage cement to harden.
When the top stage slurry Is pumped down the casing, the cement
circulates through the ports In the stage tool and Is displaced upward
outside the casing to the surface. By mechanically closing the stage
tool ports, the top stage slurry Is held In place outside the casing
until the cement hardens.
D:5 CentralIzers
CentralIzers, to hold the casing In the center of the hole, contribute to
a successful cement Job. Also, scratchers may be Installed on the casing
In wells that have been drilled with mud, where the casing Is free to be
rotated or reciprocated In the hole; this enhances the cement bond by
removing mud cake from the borehole. Viscous preflush, or mud flush'used
ahead of the cement slurry, and casing wiper plugs ahead of and behind
the slurry help keep It free of mud contamination. Turbulent flow
conditions In the annul us also Increase the chances for good cement bond.
D - 2
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APPENDIX E
RESPONSE TO NONCOMPLIANGE
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APPENDIX E
RESPONSES TO NONCOMPLIANCE
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TABLE E.I
RESPONSES TO NONCOKFLIANCE
(non-SNC)
CATEGORY 1
24 Hour Reporting and/or Written Follow-
up §§144.28(b). 144.51(1X6)
Well Construction, I/ Part 146,
§144.28(6)
Operating Requirements §§144.28(f),
144.52(e) Part 146, §1144. 51(e)
Failure to Plug and Abandon Properly
If nonendanger Ing
Contamination of USDW, 5S144.12. 1431,
SDWA
Compliance Schedule I/, §5144. 39(a) (4),
144.57(1X5), 144.53
Record Retention, §§144.28(1),
144.5KJX2)
Appropriate Response (See Table E. 2)
A
B
X
X
X
X
X
X
X
c
X
X
X
X
4/
X
X
0
X
X
X
X
4/
X
X
E
X
X
X
X
X
F
X
X
X
X
X
X
G
X
X
X
X
X
H
X
X
X
X
X
1
X
J
X
X
X
X
X
K
X
X
X
X
X
X
X
L
X
X
X
X
X
X
X
PI
I
I/ Suspected/known endangerment; willful violations
21 Strongly recommended In conjunction with referral, as applicable
3/ Suspected/known endangerment
4/ Where an aquifer exemption Is pending, these responses may, In seme cases, be appropriate while
the exemption Is being processed
SNC Significant Non-Compllance
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CATEGORY II
Financial Responsbl 1 Ity (Inadequate
and/or failure to submit) lf!44.28(d),
144.60-70. 144.52(a)(7)
Failure to Make Required Notification
(P&A, MIT, transfer of ownership, etc.)
5§144.28(g), (J) (1) 144.23(b)(3),
144.51(1)(n), 144.13
Failure to Monitor, §5144. 28(g), Part
146
Wei 1 Construction (below ground
construction, no suspected endangerment)
S144.28 (e)
Operating requirements (no suspected
endangerment but violation substantial),
144.28(f), Part 146, $5144. 51(a), (e)
Failure to P&A properly (no suspected
endangerment), 11144. 52(a) (6),
144.28(c) 146.10, 144. 51 (o), 144. 23b
Failure to run M. I.T., $5144. 28(g)
144.51(p)
Compliance Schedule (non-endangering)
§5144.25 (Result In unauthorized
Injection)
Failure to comply with permit condition,
§144. 51 (a) (not Included elsewhere)
Failure to apply for a permit, 5§144.25
(Results In unauthorized Injection)
Mechanical Integrity Failure which Is not
endangering and Is not Included under SNC
milestones
Appropriate Response (See Table E.2)
A
X
X
X
X
B
X
X
X
X
X
X
X
X
X
X
X
c
X
X
X
X
X
X
X
X
X
X
0
X
X
X
X
X
X
X
X
X
X
X
E
X
X
X
X
X
X
X
X
X
F
X
X
X
X
X
X
X
X
X
G
X
X
X
X
X
X
X
X
X
H
1
X
X
X
J
X
X
X
K
X
X
X
X
X
X
X
X
X
X
X
L
5/
X
X
X
X
X
X
X
X
X
X
5/ Repeated or unusual (willful or bad faith)
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CATEGORY I 1 I
Report
- Incomplete
, - No Report .
- Late
- 1 ncorrect
§§144.28(h), (k), 144.51(0), Part 146,
Wei 1 Construction (above ground,
nonsubstantlal ), §§144.28(e) I/
Operating requirements (non endangering.
repetitive or substantial), §144.52(a).
Part 146
No P&A Plan 8/, §§144.23(b) (2), 148.28(c)
Unauthorized P&A (non-endangering)
§5144.23, 144.28(c)
Inventory Requirements 7/ (1 Year
Inventory Requirements) S144.26
Appropriate Response (See Table E.2)
A
X
X
X
X
X
B
X
X
X
X
X
c
X
X
X
X
6/
X
D
X
X
6/
X
X
E
X
X
X
X
X
X
F
,
X
6/
6/
X
G
X
X
X
7/
H
1
X
J
K
X
X
X
X
L
5/
5/
5/
5/
5/ Repeated or unusual (willful or bad faith)
6/ Area Permits Only
7/ Failure' to submit Inventory results In automatic termination of authorization by rule - see
unauthorized Injection In Categories 1 and 1
8/ Request operator to submit P&A plan under §§144.27. Failure to submit plan after request
results In termination of authorization by rule - see unauthorized Injection In Categories
1 and 1 1
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TABLE E.2
POSSIBLE APPROPRIATE RESPONSES TO VIOLATIONS
A. Telephone call (must have appropriate documentation).
B. Warning letter tailored to Individual operator notifying him/her of the
nature of the violation and required responses (must Include possible
criminal/civil liabilities).
C. Field inspection (generally not appropriate as a final response to a
violation).
D. Opportunity for consultation ("show cause" meeting) which provides the
violator a chance to ask questions of the agency and get Information.
E. Formal request for Information (may Include new information, mechanical
Integrity test, monitoring, etc. - see §144.27). Note: Owner/operator's
failure to respond to this request results In automatic termination of
authorization by rule, (§144.27[c]).
F. Request for permit application (§144.27; 144.12[c] or [d]). Note: When
§144.27 Information request authority Is not appropriate, the §144.25
authority can be used to terminate authorization by rule If the permit
application is not submitted In a timely fashion, or If the permit Is
denied.
G. Initiate permit modification, alteration or termination or impose or
modify a compliance schedule.
H. Issue Administrative Order to owner or operator of a Class V well
requiring such actions as may be necessary to prevent primary drinking
water standard violations or to prevent contamination which may otherwise
adversely affect the health of persons. (§144.12f_cX23).
I. Commence bond forfeiture or utilize other financial mechanisms to plug
the wel I.
J. §1431 SDWA Administrative Order or, where well Is Injecting solid or
hazardous waste, RCRA, §3008 or §7003 Administrative Order (or where
appropriate, a CERCLA §106 Administrative Order).
K. Issue Administrative Order.
L. Referral to State AG/Department of Justice (DOJ) (Civil or Criminal).
E - 4
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APPENDIX F
WARRANT DOCUMENTS
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APPENDIX F
WARRANT DOCUFCNTS
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7
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25
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28
Form CBO-183
12-8-76 DOJ
Michael R. Spaan
United States Attorney
District of Alaska
Federal Building, Room 252
701 C Street
Anchorage. Alaska 9951 3
U.S. DISTRICT COURT
DISTRICT OF ALASKA
IN THE HATTER OF: ' ) C1v1l No.
)
UNOCAL CORPORATION ) APPLICATION FOR WARRANT
Kenai Gas Field ) FOR ENTRY AND INVESTIGATION
Anchorage. Alaska ) PURSUANT TO SECTION 1445
) OF THE SAFE DRINKING HATER
) ACT, 42 U.S.C. 5300J-4 et seq.
The United States of America, at the request of the Administrator
of the United States Environmental Protection Agency' (EPA), applies to this
Court for a warrant authorizing EPA officials and their assistants to enter
upon land hereinafter referred to as the Unocal Facilities, and then and
there conduct such Initial monitoring, testing or analysis, or any
combination thereof, together with such attendant sampling, surveying.
Information gathering, and photographing as may be reasonable and necessary
to ascertain whether Unocal Corporation has acted or is acting in compliance
with its EPA emergency permit and Part C of the Safe Drinking Water Act
(SDWA), 42 U.S.C. §300h, at the Unocal Facilities in Alaska.
The EPA submits this application pursuant to the SDWA, 42 U.S.C.
S300f. and alleges for this application as follows:
APPLICATION FOR WARRANT - Page 1
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Form OBD-183
12-8-76 001
(3) The examination of records, files papers, processes and controls
required by permit to be found either on-site or at Unocal's
offices;
(4) The taking of photographs; and
(5) Any additional activities, including interviews and conferences,
as necessary to ascertain compliance or noncompliance with permit
conditions.
E. Although EPA was, and is, entitled to a warrantless entry
upon the Unocal Facilities under the SDWA (and EPA does not waive this legal
position by this application), in order to assure peaceful acquiescence by
the owners and operators of the Unocal Facility to the EPA action, EPA
applies for this warrant.
F. The United States Supreme Court decisions in Camara v.
Municipal Court. 387 U.S. 523 18 L.Ed. 2d 930, 87 S.Ct. 1727 (1967) and
Marshall v. Barlow's Inc.. 436 U.S. 307 56 L.Ed. 2d 305, 98 S.Ct. 1816
(1978), provide ample authority for this Court to issue a warrant where a
statute, such as the SDWA confers a right of entry. See also Bunker Hill v.
EPA. 658 F.2d 1280 (9th Cir. 1981) and Accord Public Service Co. of Indiana
v. United States Environmental Protection Agency, 509 F. Supp. 720 (S.D.
Ind. 1981). The standard for probable cause justifying the Issuance of an
administrative search warrant, less rigorous than for a search and seizure
warrant in a criminal investigation, requires only a showing of either
"specific evidence of an existing violation" or "reasonable legislative or
administrative standards' for conducting a particular inspection, Marshall
v. Barlow's Inc.. 436 U.S. 307, 320 56 L.Ed. 2d 305, 98 S.Ct. 1816 (1978)'.
For purposes of an administrative search such as this,
probable cause justifying the Issuance of a warrant
may be based not only on specific evidence of an
existing violation but also on a showing that
reasonable legislative or administrative standards for
APPLICATION FOR WARRANT - Page 3
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IS
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arm 080-183
2-8-76 DOJ
conducting an inspection are satisfied with respect to
a particular establishment." Caraara v. Municipal
Court. 387 U.S. 523, 538 18 L.Ed. Zd 930, 87 S.Ct.
T7zT~(1967).
G. The EPA has reviewed available information and has determined
that Unocal has not acted and is not acting in compliance with its permit or
Part C of the SOWA, 42 U.S.C. 300h et seq. Steinborn Affidavit at
paragraphs 10 and 11. In addition, past practice of providing prior notice
of an inspection may have resulted in the concealment of violations.
Steinborn Affidavit at paragraph 16. Further, if EPA was denied warrantless
access, the geographic remoteness of the Unocal Facility would preclude
subsequent inspection by EPA this year. Steinborn Affidavit at
paragraph 10. Finally, EPA seeks a warrant to assure peaceful acquiessence
to EPA actions by the owners and operators of the Unocal Facilities.
H. EPA has established requisite probable cause, and has shown
reasonable legislative and administrative standards, satisfying the
requirements set forth in the Barlow and Camara decisions, supra, to allow
for a warrant to issue.
I. In this case, EPA has demonstrated that (1) EPA has reason to
believe that a violation has occurred or is occurring (Steinborn Affidavit
at paragraphs 10 and 11); (2) investigations, sampling, and other response
actions are necessary and/or appropriate to ascertain the nature and extent
to the violations which have occurred at the Unocal Facilities (Steinborn
Affidavit at paragraph 13); and (3) consent for EPA and its officers,
employees, representatives to enter upon the Unocal Facilities to carry out
any response activities described herein has not been requested because of
the need for surprise to assure noncompllance is not concealed, and given
APPLICATION FOR WARRANT - Page 4
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^arm CBO-183
2-8-76 001
the remote geographic area subsequent Inspections by EPA this year would not
be economically possible if access Is denied (Steinborn Affidavit at
paragraph 16).
J. It is estimated that the activities for which this warrant is
sought will take two (2) working days to complete beginning OR Thursday,
August 6, 1987. Should two (2) days prove to be an Insufficient period of
time for the EPA to conduct such activities due to circumstances unforeseen
at this time, the United States will apply to this Court for an extension of
any warrant granted by this Court.
A form of warrant 1s attached to this application.
DATED this
day of August, 1987.
By:
By:
Respectfully submitted,
MICHAEL SPAAN
United States Attorney
MARK ROSENBAUM
Assistant United States Attorney
ONICA KIRK
Assistant Regional Counsel
U.S. Environmental Protection Agency
APPLICATION FOR WARRANT - Page 5
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Form 080-183
12-8-76 DOJ
Michael R. Spann
United States Attorney
District of Alaska
Federal Building, Room 252
701 C Street
Anchorage, Alaska 99513
U.S. DISTRICT COURT
DISTRICT OF ALASKA
IN THE MATTER OF:
UNOCAL CORPORATION
Kenai Gas Field
Anchorage, Alaska
Civil No.
WARRANT FOR ENTRY AND
INVESTIGATION PURSUANT
TO [SECTION 1445 OF THE
SAFE DRINKING WATER
ACt, 42 U.S.C. 5300J-4
TO: THE UNITED STATES MARSHAL FOR THE DISTRICT OF ALASKA AND ANY OFFICER.
EMPLOYEE, OR DESIGNATED REPRESENTATIVE OF THE UNITES STATES ENVIRONMENTAL
PROTECTION AGENCY. i
I
An affidavit by Daniel Stelnborn of the United States
Environmental Protection Agency (EPA), having established that the need to
determine whether Unocal Corporation acted or Is acting In compliance with
Its EPA emergency permit and Part C of the Safe Drinking water Act,
42 U.S.C. §300h, 1n its operation of the Alaska Unocal Facilities, namely,
(a) KU HD-1 located at T.5N, R.11U. Section 31. 1/4 Section 5E. 606 feet
from the south line and 2297 feet from the east line 1n the Alaska Kenai Gas
Field and (b) Poppy Lane Gravel Pit located at W 1/2, SW 1/4 Section 27 T5N,
R.11W Seward Meridian, Alaska, and Unocal's Alaska offices on behalf of the
WARRANT FOR ENTRY AND INVESTIGATION - Page 1
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Form 080-183
12-8-76 DOJ
EPA, having established that the Issuance of this warrant Is constitutional,
and that the right of the EPA to enter and Investigate the Unocal Facilities
is authorized by the Safe Drinking Water Act, (SDWA), 42 U.S.C. §300f; and
this Court having found that reasonable grounds exist for Issuance of a
warrant for entry and investigation of the Unocal Facilities:
IT IS HEREBY ORDERED that upon service of this Warrant upon a duly
designated representative of the Unocal Corporation, officers, employees and
designated representatives of the EPA, including employees of the State of
Alaska Department of Environmental Conservation (ADEC) and the Alaska Oil
and Gas Conservation Commission (AOGCC), and the United States Marshal.
shall be permitted to enter upon the property described as:
a. KU WD-1 located at T.5N, R.11U, Section 31. 1/4
Section 5E, 606 feet from the south line and 2297 feet
from the east line in the Alaska Kenai Gas Field.
b. Poppy Lane Gravel Pit located at W 1/2, SU 1/4 Section
27 T5N, R.11W Seward Meridian, Alaska.
c. The Unocal Corporate offices located in Anchorage,
Alaska.
IT IS FURTHER ORDERED that officers, employees and designated
representatives of the EPA, including any employees of the State of Alaska
Department of Environmental Conservation (ADEC) and the Alaska Oil and Gas
Conservation Commission (AOGCC), and the United States Marshal, shall be
authorized and permitted to enter and, as necessary, to re-enter the
above-described premises during the hours of 8:00 a.m. to 6:00 p.m., on
August 6 and 7, 1987 to conduct thereon the following activities:
1. A detailed walking inspection of the entire inspection site and
gravel pit;
2. The taking of samples, collected at sample ports and/or drums and
tanks via sample containers and/or thiefs, from injection waste
streams and reservoirs/containers that may contain waste intended
for injection Into well KU WD-1;
WARRANT FOR ENTRY AND INVESTIGATION - Page 2
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-orm OBO-183
24-76 DOJ
3. The examination of records files, papers, processes and controls
required by permit to be found at the Unocal Facilities;
4. The taking of photographs; and
5. Any additional activities, Including Interviews and conferences,
as necessary to ascertain compliance or noncompllance with permit
conditions.
IT IS FURTHER ORDERED that a copy of this Warrant shall be left at
the premises at the time of Investigation.
IT IS FURTHER ORDERED that a brief Inventory Identifying any
materials removed form the premises shall be furnished by EPA the the owner,
operator, or representative of the Unocal Corporation.
IT IS FURTHER ORDERED that the duration of the entry.
Investigation, and activity authorized by this Warrant shall be of such
reasonable length to enable the EPA to satisfactorily complete the
above-described activities, but In no Instance shall entry be permitted for
longer than ten (10) working days from the date hereof.
IT IS FURTHER ORDERED that the United States Marshal Is hereby
authorized and directed to assist officers, employees, and representatives
of the EPA In such manner as may be reasonable and necessary to properly
execute this Warrant and all the provisions contained herein.
IT IS FURTHER ORDERED that a prompt return of this Warrant shall
be made to this Court within twenty (20) days from the date hereof, showing
that this Warrant has been executed, and that the entry and activities
authorized herein has been completed within the time specified above.
Dated this *V^ day of August 1987.
\States Magistrate
WARRANT FOR ENTRY AND INVESTIGATION - Page 3
F - 8
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INVENTORY OF PROPERTY RECEIVED
PURSUANT TO WARRANT
While conducting the entry and Inspection of the Unocal Facilities
on the 6th and 7th days of August, 1987, I, Glen Brack seized certain
property.
The following Is an Inventory of the property seized:
I hereby swear and affirm that a receipt for the property was signed by me
and left with £.*& C.. :>/», />> A^nac 6m -liv.hi C'.-*.»i.ir7 .
F - 9
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RETURN OF SERVICE
I hereby certify that a copy of the within Warrant was served by
presenting a copy of the same to Bob C. SWv'tVi , an agent
of Unocal Corporation on August 6, 1987, at the Unocal facilities 1n Alaska.
Glenn Bruck
OfficialTitl
RETURN
Inspection of the establishment described 1n this Warrant
completed on August 7, 1987.
Glenn BruclT
F - 10
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Form CBO-183
DO!
Michael R. Spaan
United States Attorney
District of Alaska
Federal Building, Room 252
701 C Street
Anchorage, Alaska 99513
U.S. DISTRICT COURT
DISTRICT OF ALASKA
IN THE MATTER OF:
UNOCAL CORPORATION
Kenai Gas Field
Anchorage, Alaska
Civil No.
AFFIDAVIT IN SUPPORT OF
APPLICATION FOR WARRANT
FOR ENTRY AND INVESTIGATION
PURSUANT TO SECTION 1445
OF THE SAFE DRINKING WATER
ACT, 42 U.S.C. S300J-4
I, Daniel I. Steinborn, being duly sworn, state as follows:
1. I make this affidavit in support of the attached warrant
which is sought pursuant to the authority of the Safe Drinking Water Act,
42 U.S.C. §300f et £eq. I base this Affidavit on personal knowledge,
discussions with representatives of Unocal Corporation and my review of
government and other records.
'2. I am a Supervisory Environmental Protection Specialist in the
Water Division of the United States Environmental Protection Agency (EPA),
Region 10, Seattle, Washington. I have been employed in the Water Division
of the U.S. EPA, Region 10, since 1976.
3. Since February 1987, I have been the Chief of the Underground
Injection Control (UK) and Program Support Section, Drinking Water Branch
AFFIDAVIT IN SUPPORT OF APPLICATION FOR WARRANT - Page 1
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Form OBD-183
12-8-78 DOT
Water Division, Region 10 of the EPA. I an responsible for supervising
EPA's implementation of the UIC program in Region 10.
4. I received a Bachelor of Arts degree in Political Science at
Western Washington State College, Bellinghara, Washington in June 1969. I
received a Master of Public Policy degree at the University of Michigan,
Ann Arbor, Michigan in 1980.
5. In my capacity as Chief of the UIC Section, I am responsible
for directing and coordinating the regulation and investigation of injection
well KU WD-1 which is located in the Kenai Gas Field, Alaska and the Poppy
Lane Gravel Pit site which is located near Meridian, Alaska. Both sites are
owned and operated by Unocal Corporation (Union 011 Company of California)
and are subject to the underground Injection control (UIC) program of Part C
of the Safe Drinking Water Act, 42 U.S.C. S300h et seq.
6. KU WD-1 is located at T.5N. R.11W, Section 31, 1/4 Section
SE, 606 feet from the south line and 2297 feet from the east line in the
Alaska Kenai Gas Field. The Poppy Lane Gravel Pit site is located in the
W 1/2, SW 1/4 of Section 27 T5N, R11W Seward Meridian, Alaska.
7. KU WD-1 is operated subject to permits issued by EPA,
pursuant to 42 U.S.C. 300h-3, and Alaska 011 and Gas Conservation Commission
(AOGCC) which has received delegated authority from EPA to regulate Class II
injection wells in Alaska.
The EPA emergency permit 1s issued for operating a Class II
produced water well. The AOGCC permit authorizes the disposal of
non-hazardous oil field wastes by injection. Both permits prohibit the
injection of hazardous wastes.
AFFIDAVIT IN SUPPORT OF APPLICATION FOR WARRANT - Page 2
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farm CBO-183
12-8-76 DOJ
8. In addition to injecting wastes generated by producing wells
in the Kenai Gas Field. KU UO-1 is allowed to inject wastes obtained from
the Poppy Lane Gravel Pit. Portions of the gravel pit were used for
uncontrolled refuse disposal prior to and after Unocal's purchase in 1965.
The site has also been used for disposal of construction and demolition
debris, plus peat and soils not suitable for construction. Some of this
waste may have been contaminated with gas well condensate.
9. Contamination investigations of the Poppy Lane-Gravel Pit
site have been conducted by the Alaska Department of Environmental
Conservation (AOEC) since 1985. An extraction well located in the north
west corner of the gravel pit has been used for removal of contaminated
ground water. These waste fluids were transported and injected into KU
UO-1. This action is allowable under the EPA emergency permit so long as
Unocal demonstrates that the injected fluids are equivalent in composition
to produced waters.
10. On or about November 14, 1986, EPA requested that Unocal
demonstrate that the injected fluids are equivalent in composition to
produced waters from the Kenai Gas Field. The analyses were incomplete and
a chemical analysis of the actual injectate was not provided. EPA notified
Unocal on May 27, 1987, that the demonstration was insufficient. Unocal has
failed to provide further information and has, thereby, not demonstrated
produced water equivalence.
11. Unocal's EPA permit establishes a maximum injection pressure
of 1100 psi. Unocal's exceedence of the maximum injection pressure in
October 1985, November 1985, February 1986, March 1986, April 1986 and
August 1986 was confirmed.
AFFIDAVIT IN SUPPORT OF APPLICATION FOR WARRANT - Page 3
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form CBO-183
U-8-76 DOJ
12. On April 10, 1987, EPA informed Unocal by letter that it was
in violation of the permit and that corrective actions were necessary.
13. In order to evaluate compliance with all permit conditions
and to determine the operating status of the facility, EPA must enter and
investigate the Unocal KU HO-1 Injection well site, the Poppy Lane Gravel
Pit and the Unocal office in Anchorage, Alaska (Unocal Facilities).
14. The following investigative activities must be performed at
the Unocal Facilities:
(1) A detailed walking Inspection of the entire Inspection site and
gravel pit;
(2) The taking of samples, collected at sample ports and/or drums and
tanks via sample containers and/or thiefs, from injection waste
streams and reservoirs/containers that may contain waste Intended
for injection into wull KU WO-1;
(3) The examination of records, files papers, processes and controls
required by permit to be found either on-site or at Unocal's
offices;
(4) The taking of photographs; and
(5) Any additional activities', including interviews and conferences.
as necessary to ascertain compliance or noncompllance with permit
conditions.
15. The above described activities should take approximately two
days and can be completed on August 6 and 7, 1987.
16. Because (1) injection activities are subject to easy and
immediate alteration thereby concealing violations, (2) prior notice of the
inspection in previous years has resulted in the appearance of concealment.
AFFIDAVIT IN SUPPORT OF APPLICATION FOR WARRANT - Page 4
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080-183
76 DOJ
and (3) the remoteness of the site from Seattle precludes, for economic
resource reasons, further EPA Inspections in the event access is denied
without prior notice, a warrant is necessary to ensure surprise and
guarantee entry.
Daniel I. Steinborn
Subscribed and s torn to before me this
day of July, 1987.
NOTARY PUBLIC;
AFFIDAVIT IN SUPPORT OF APPLICATION FOR WARRANT - Page 5
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APPENDI)
BASIC BALANCE PLUG JOB
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APPENDIX G
BASIC BALANCE PLUG JOB
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APPENDIX 6
BASIC BALANCE PLUG JOB
A cement plug may be set anywhere fn a hole that Is static. To set a balanced
plug, the height of each fluid Inside and outside the work string must be
equal. In order to do a balanced plug Job, certain volumes and heights of
fluids must be calculated. These Include volume of cement In cubic feet and
sacks, mixing water for the cement, displacement fluid required to spot the
cement, and (If water Is run ahead of the cement) the volume of water required
behind the cement to balance the water ahead.
A plug Job could be as follows: set a 200 ft plug of C|ass A cement, 15.'6
Ib/gal, In an 8 3/4 In. open hole with 15 bbl of water run ahead of the
cement. The plug Is to be spotted through a work string of 4 1/2 In. ED 16.6
Ib/ft drill pipe. The drill pipe Is run to a depth of 6,000 ft (which will be
the bottom of the cement plug). There Is mud In the hole.
The first calculation would be the cubic feet of cement required for the Job.
Since a 200 ft plua Is to be left In the open hole, go to the Cementing
Tables, Section 210 , for capacity of the open hole In cu ft/I In ft and find
₯₯
0.4176 cu ft/I In ft x 200 ft = 84 cu ft
Class A cement mixed at 15.6 Ib/gal Is to be used for the job. Slurry
properties for Class A cement are In Section 230 of the Cementing Tables. For
15.6 Ib/gal, the water requirement Is 5.2 gal/sk and the yield Is 1.18 cu
ft/sk. With this Information, the sacks of cement can be determined by
dividing the cubic feet required by the yield of a sack of cement.
84 "cu ft
= 71 sk
1.18 cu ft/sk
Once the number of sacks has been determined, the volume of mixing water can
be calculated from the slurry properties obtained for the Class A cement In
Section 230. Each sack of cement requires 5.2 gal/sk; therefore,
71 sk x 5.2 gal/sk = 369 gal of water
369 gal of water
= 8.8 bbl of water - -
42 gal/bbl
Since 15 bbl of water are to be pumped ahead of the cement, we need to
determine the height of this water In the annulus. The height of 15 bbl of
Section numbers are those found In Ha I 11 burton Cement I ng TaMes. Halliburton
Services, Duncan, Oklahoma 1981 or later.
4t-)t
Results rounded to practical significant figures
G - 1
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water In the annul us must be balanced by the same height of water Inside the
drill pipe. The 15 bbl of water ahead of the cement will end up In the
annulus between the drill pipe and the hole; therefore, go to Section 122
(volume and height between drill pipe and hole) In the column headed I In
ft/bbl and find 18.2804 I In ft/bbl. Calculate
15 bbl x 18.2804 I In ft/bbl = 274 ft of water In the annulus
There must be 274 ft of water Inside the drill pipe to have equal balance.
The volume required In the drill pipe Is determined by going to Section 210 In
the column bbl/lln ft to find .0142 bbl/lln ft for 4 1/2 In. EU 16.0 Ib/ft
drill pipe. Since each foot of this drill pipe will hold .0142 bbls, then
.0142 bbl/lln ft x 274 ft = 3.9 bbl of water
will be required In the drill pipe behind the cement or above the cement.
The displacement necessary to spot the cement plug must now be calculated. In
order to calculate the displacement to spot the plug, the height of the cement
must be determined. Cement height must be the same In the annulus and In the
drill pipe when the plug Is set. Therefore, for each foot of cement height In
the annulus, there should be one foot of cement height In the drill pipe. The
volume required to fill one linear foot of annulus can be found In Section
122. For the 4 1/2 In. to 8 3/4 In. annulus, under the column headed cu
ft/I In ft, this value Is 0.3071 cu ft/I In ft. To balance the one foot In the
annulus, one foot In the drill pipe will require .0798 cu ft/I In ft. This Is
found In Section 210 In the column headed cu ft/I In ft for 4 1/2 In. EU 16.6
Ib/ft drill pipe. Therefore, one linear foot of hole with the drill pipe In
the hole has a volume of
.3071 cu ft/I In ft (annular volume)
+ .0798 cu ft/I In ft (drill pipe capacity)
.3869 cu ft/I In ft of hole with drill pipe In the hole.
Since the volume of cement for the job was calculated as 84 cu ft, the height
of cement can be calculated by dividing:
84 cu ft
= 217 ft
.3869 cu ft/ft
With the bottom of the drill pipe at 6,000 ft, then
6,000 ft - 217 ft (cement height) - 274 ft (water height) =
5509 ft (mud displacement depth)
G - 2
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The volume of mud required for displacement Is calculated by going to Section
210 for capacity of 4 1/2 In. EU 16.6 Ib/ft drill pipe. In the column marked
bbl/lln ft. find .0142 bbl/lIn ft. With this figure, the calculation Is
.0142 bbl/lln ft x 5509 ft = 72.2 bbl
of mud displacement to spot the plug
G - 3
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BASIC BALANCE PLUG JOB Is calculated as follows:
PLUG JOB
4-1/2' IN.,
16.6 LB/FT
f.
1
u
1
K4i ir\
RILL PIPE
8-3/4* HOLE
MUD
WATER
CEMENT
6,000 FT.
Set 200 ft plug In 8 3/4
In. hole.
4 1/2 In. EU 16.6 I b/ft
drllI pipe to 6,000 ft
Class A cement mixed at
15.6 Ib/gal
15 bbl of water ahead
CALCULATE;
1. Volume of cement In
cu ft
84 cu ft
2. Number of cement
sacks
71 sk
3. Mixing water In bbl
8.8 bbl
4. Water behind cement
In bbl
3.9 bbl
5. Mud displacement In
bbl
78.2 bbl
Capacity of 83/4 In hole
.4176 cu ft/ft x 200 ft = 84 cu ft
2. Sacks of cement
84 cu ft
1.18 cu ft/sk
71 sk
G - 4
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3. Mixing water
71 sk x 5.2 gal/sk = 369 gal
then
369 gal
= 8.8 bbl
42 gal/bbl
4. Water behind
V and H 18.2804 ft/bbl x 15 bbl = 274' ft
Capacity 4 1/2 In. drill pipe .0142 bbl/ft x 274 ft = 3.9 bbl
5. Mud displacement
Height of cement - V and H
4 1/2 In. x 8 3/4 In. .3071 cu ft/I In ft
Capacity 4 1/2 In., 16.6 Ib/ft + .0798 cu ft/I In ft
drill pipe .3869 cu ft/I In ft
84 cu ft
= 217 ft of cement
.3869 cu ft/I In ft
6,000 ft - 217 ft of cement - 274 ft of water = 5509 ft of
drill pipe to be displaced with mud
Capacity 4 1/2 In. EU 16.6 Ib/ft drill pipe
.0142 bbl/ft x 5509 ft = 78.2 bbl
6-5
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USEFUL BALANCE PLUG FORMULA
1. BARRELS OF FRESH WATER AHEAD WHEN BARRELS OF FRESH WATER
BEHIND IS GIVEN
The total volume of fresh water ahead of the cement plug Is
the product of the annul us capacity times the volume of
fresh water behind the plug divided by the volume of the
drill pipe. To calculate this volume In barrels use the
following formula:
(VA) (VFWB)
VFWA =
(VDP)
where:
VFWA = Volume of fresh water ahead of the cement plug In
barrels
VDP = Volume (capacity) of the drill pipe In barrel/foot
VA = Volume of annular space between the drill pipe and
open hole or casing In barrels per foot
VFWB = Volume of fresh water behind the cement plug In
barrels
or;
Barrels of fresh water ahead of cement = (feet/barrel of drill pipe) x
(barrel/feet of annul us) x (barrels of fresh water behind).
2. BARRELS OF FRESH WATER BEHIND WHEN BARRELS OF FRESH WATER
AHEAD IS GIVEN
The total volume of fresh water behind the cement plug Is the volume of
the fresh water ahead divided by the product of the drill pipe capacity
times the annulus capacity. To calculate this volume In barrels use the
following formula:
(VDP)(VFWA)
VFWB =
VA
the symbols and units are the same as In 1. above.
G - 6
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or:
(feet/barrel In annul us) x (barrels of fresh water ahead) = Height of
fresh water In annulus (HFWA) In feet; and (HFWA) x (barrel/foot In drill
pipe) = Barrels of fresh water behind the cement.
3. HEIGHT OF CEMENT WITH DRILL PIPE IN
The vertical distance covered by a cement plug before the drill pipe Is
withdrawn from It Is the total cement slurry volume divided by the sum of
the capacities of the drill pipe plus the annular space between the open
hole or casing. To calculate this distance In feet use the following
formula:
TSV
HOC =
(VDP) + (VA)
where:
HOC = Height of cement column In feet
TSD = Total cement slurry volume In barrels
VDP = Volume (capacity) of drill pipe In barrels/foot
VA = Volume of annular space between the drill pipe and
casing or open hole In barrels/foot
or:
(barrel/foot of drill pipe) + (barrel/foot of annulus) = total
barrels per foot (TBPF), and the (total slurry of volume In barrels) -
(TBPF) = height of cement (HOC).
4. MUD TO BALANCE
The volume of mud required to displace and balance the cement plug Is the
sum of the total depth of the drill pipe minus the height of cement minus
the height of water times the volume (capacity) of the drill pipe. To
calculate the volume of mud required to balance the system In barrels use
the following formula:
MTB = (TOP - HOC - HOW) x (VDP)
where:
MTB = Volume of mud to balance In barrels
TOP = Total depth of drill pipe In feet
HOC = Height of cement plug In feet
HOW = Height of water In feet
or:
(total footage of drill pipe) - (height of cement column In feet) -
(height of water column In feet) = height of mud column (HOM), and (HOM)
x (barrel/feet of drill pipe) = mud to balance.
G - 7
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APPENDIX H
SCHEMATIC WELL DIAGRAMS
SHOWING PLUG LOCATIONS"
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APPENDIX H
SCHEMATIC WELL DIAGRAMS
SHOWING PLUG LOCATIONS
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10'
« SURFACE CASING
HOLE
PRODUCTION CASING
BASE OF LOWERMOST USDW
PERFORATIONS
Fig. R.I Wells with production casing and cemented
through all USDW's and production horizons.
H - 1
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HOLE
CEMENT
SURFACE CASING
BASE_QE_LOWERMOST USDW
Fig. H .2 Well with sufficient casing set to
protect all USDW's.
H - 2
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t
10'
HOLE
SURF
-INTERMEDIATE
HOLE
50'
BASE OF LOWERMOST USDW
50'
Fig. H.3 Well with intermediate casing and cemented
through all USDW's and production horizons.
H - 3
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HOLE
CEMENT
CASING
QFLQWERMOST USDW
Fig. H.4 Well with surface casing set deeper
than 200 feet below base of the USDW".
H - 4
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HOLE
SURFACE CASING
BASE OF LOWERMOST USDW
Underground Source of
Drinking Water)
PRESSURE SALT WATER ZONE
CONFINING LAYERS
PRODUCING ZONE
Fig. H.5 Well without production casing.
II - 5
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HOLE
SURFACE CASING
PRODUCTION
BASE OF LOWERMOST USDW
MULTI-STAGE TOOL
PERFORATIONS
Fig. H.6 Multi-cased, cemented well with
production casing.
H - 6
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THIS PLUG MUST BE
TAGGED
HOLE
CEMENT
CASING
BASE OF LOWERMOST USDW
Fig. H.7 Well with insufficient casing set to
protect all of the USDW.
H - 7
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10'
HOLE
-SURFACE CASING
INTERMEDIATE CASING
50'
\ BASE OF LOWERMOST USDW
50'
Fig. H.8 Well with intermediate casing not cemented
through all USDW and production horizons.
H - 8
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10'
SURFACE CASING
HOLE
PERFORATIONS
PRODUCTION CASING
50> BASE OF LOWERMOST USDW
PERFORATIONS
100'
-PERFORATIONS
Fig. H.9 Well with production casing not cemented
through all USDW's and production horizons.
H -- 9
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APPENDI/J
WELLHEAD CONFIGURATION
AND MONITORING
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APPENDIX I
WELLHEAD CONFIGURATION
AND MONITORING
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1:1 - 1:5
APPHOIX I
WHIflEAD GCNFIGURATICN AH) MCNT1CRING
1:1 Equipment and Instrunentaticn
Surveillance of an injection operation is prirtarily one of monitoring
certain critical operating parameters at the wellhead. The greatest risk
of escape of injected fluids is normally through or around the outside of
the injection well itself, rather than through semi-impermeable confini-ng
beds, fractures, or unplugged wells. . This section describes wellhead..
equipment and instrumentation used to monitor the integrity of an
operating well.
Pressure- and flow- measuring instrumentation are of primary importance
in monitoring an injection well. Miscellaneous parameters such as pH,
temperature, wastewater chemistry, etc. may also be measured.
1:2 Process Flow Diagram
Ask the operator for a process flow diagram; with this you will be able
to locate and identify instrumentation of special interest to you.
Figure I.I is a piping and instrumentation diagram (P & ID) around a
Class I wellhead. Class II wellhead equipment is usually simpler (see
Figure 1.2).
1:3 Instrument Specifications
Ask for specification sheets for the monitoring instruments. A
manufacturer's catalog will furnish detailed information on instrument
calibration procedures, sensitivity, materials of construction and parts
identification.
1:4 Meters and Gauges
As you inspect a well facility you will see pressure gauges located on
the wellhead and/or wellhead piping. A flow meter will generally be
located on the injection pipeline, whereas all recorders and totalizers
are normally found in a control roan or operations shelter.
Wellhead Configuration
1:5 Functions of Wellhead Equipment
The wellhead is used to maintain surface control of . the well. It-is
usually made of cast or forged steel, machined to a close fit to form a
seal and prevent well fluids from blowing out or leaking at the surface.
Heavy fittings with parts designed to hold pressures up to 20,000 Ibs per
sq in (psi) may be found on sane. Other wellheads may be just simple
assemblies to support the weight of the tubing in the well, not -made to
hold pressure (Figure 1.2).
I - 1
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WING
VALVE
INJECTION NATCft
TO ANNUUU3 4M
MONITORING
Legend:
F! - Flow Rate Indicator
FR - Flow Recorder
FT - Flow Transmitter
Pll - pH Meter
.PI - Pressure Indicator
PR - Pressure Recorder
PT - Pressure Transmitter
PAH - Pressure Alarm, High
PSH - Pressure Switch, High
/ S - Sample Valve
CASING
ANNULUS VALVC
PCUO VAU/E
KKN K. J»AVIM
FIGURE I.I
TYPICAL WELL HEAD
INSTRUMENTATION
CLASS I WELL
ENGINEERING ENTERPRISES
-------
METER
STRAINER
UNION
CHECK VRLVE
TEE
I
OJ
PRESSURE OAOE
TEE
VALVE
REDUCER
KKN K. I»AVM
FIGURE 1.2
TYPICAL WELLHEAD
CLASS H WELL
ENGINEERING ENTERPRISES, INC
-------
1:6
1:6 Well Ctxrpcnents
The wellhead consists of casing head, tubing head, valves and pressure
gauges.
1. Casing Head
During the drilling of the well, as each string of casing is run into the
hole, it is necessary to install heavy fittings at the surface to which
the casing is attached. Each string of casing is supported by a casing
head already installed at the top of the next, larger string of casing-
when it wa£ run.
Each part of the casing head usually provides for the use of "slips"
(gripping devices) to hold the weight of the casing. The casing head is
used during drilling and workover operations as. an anchor base for
pressure-control equipment.
2. Tubing Head
The tubing head is similar in design; it sits on top of the uppermost
casing head. Its most important functions are to:
o Support the tubing string
o Seal off pressures between the casing and outside of tubing at the
surface
o Provide connections at the surface with which the flowing liquid can
be controlled
In sane wells that have only one string of casing, the casing head may
not be used and the tubing head is supported on the top of the casing at
or near ground level. Tubing heads vary in construction depending on the
need to withstand pressure.
The tubing head must be easily taken apart and put together to facilitate
well-servicing operations. Jfeny different types have been developed for
use under high pressures, with different designs and pressure ratings to
fit expected well conditions.
3. Valving and Piping above the Wellhead
Injection wells that are expected to handle corrosive fluid (or high
pressure) are usually equipped with special, heavy-valves above Che
casing head (or tubing head). This group of valves (called a Christmas
tree because of its shape and the large number of fittings), controls the
flow of fluid into the well.
Pressure gauges are used to measure the annular and tubing pressures.
The pressures are monitored for injection control and to comply with UIC
regulations. .
1-4
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1:7 - 1:11
1:7 Injection Pressure Measurement
Injection pressure is monitored to provide a record of reservoir
performance and to document compliance with regulations. Injection
pressures are limited, to prevent hydraulic fracturing of the injection
reservoir and confining beds and to prevent damage to well equipment. As
with flow data, injection pressure should be continuously recorded.
A continuous recording will tell whether injection operations have been
without incident. Increases in wellhead pressures can indicate formation
plugging, tubing or packer restriction, or. increase in reservoir.
pressure. Decreases in pressure can mean fracture 'of reservoir rocks,
fracture of confining layer(s), or loss of external mechanical integrity.
1:8 Equipment Maintenance
Pressure indicators and recorders require periodic service. Lack of
maintenance can yield poor data. A test gauge can be used to check the
accuracy of the operator's gauge.
1:9 Pressure Gauges
The Bourdon Tube pressure gauge is the type generally used for measuring
wellhead pressures. Gauges are available to cover pressure ranges of 0
to 5000 psi or higher. They are offered in a variety of materials to
resist corrosive fluids.
1:10 Pressure Recorders
Circular chart recorders are frequently used to record pressures. They
are driven by clocks available in a variety of time cycles: one to
several hours, half-day, full day, week, etc. (Figures 1.3 and 1.4).
Strip chart recorders are generally used in a control room. Most
commercially available strip chart recorders transform a voltage or
current signal into displacement of a pen. They provide easily read
graphic displays while compiling permanent historical records.
1:11 Injection Flow Volume and Rate Measurements
Purpose of volume measurement:
The purpose of monitoring the injected volume is to permit estimating the
radial distance of injection fluid dispersion, to allow for
interpretation of pressure data, and to provide a permanent record. This
record provides evidence of compliance, aids in interpretation of well
behavior, and may signal the need for well maintenance.
Flow meters also require regular maintenance. Corrent flew rate readings
are necessary for the proper interpretation of pressure changes. The
accuracy of a flow meter can be checked by: (a) comparing its
performance with another known to be accurate; (b) comparing its readings.
1-5
-------
INJECTION PRESSURE
iANNULUS PRESSURE
RATE OF FLOW
CONTINUOUS MONITORING
INJECTION PRESSURE/RATE OF FLOW/ANNULUS PRESSURE
SEVEN DAY RECORD
FIGURE.1.3
1-6
-------
INJECTION
TEMPERATURE
ANNULUS
PRESSURE
NOON
CONTINUOUS MONITORING
INJECTION TEMPERATURE/ANNULUS PRESSURE
TWENTY-FOUR HOUR.RECORD
FIGURE 1.4
1-7
-------
1:11 - 1:14
with rates calculated by observed changes in volume in a tank over a
measured time period; or (c) comparing its readings with rates calculated
while filling a container of known volume over a measured period of time.
If positive displacement pumps are used, flow measurements can be checked
against the volumetric discharge of the pump. Pump strokes are counted
for a specified period of time, say one minute, and the number of strokes
multiplied by the discharge volume of the pump in gallons per stroke..
Tables containing volumetric discharge data for various models of duplex
and triplex pumps using different liner sizes are found in Appendix I.
1:12 Flow Regulation
Where positive displacement pumps are not used, flow may be controlled by
special valves or by flow-control chokes. The automatic valve is used at
the wellhead to adjust automatically to pressure changes. It consists of
a valve body, an actuator (closing mechanism), and a pilot (sensing
assembly). Its function is to protect both the well and the reservoir.
When a pressure change occurs (indicating a leak) the automatic valve can
stop the flow. Some valves are designed to close gradually to avoid
destructive surge phenomena.
1:13 Gammon Types of Flow Meters and Recorders
Propeller (or turbine) meters and magnetic flow meters are conmonly used
to measure flow through pipe lines. Other types are venturi tube meters,
ultrasonic meters and rotameters. The flow recorders will be identical
to those used for pressure recording. Often flow and pressure will be
traced on a single chart; in this case, a different color ink is used for
each record.
1:14 Miscellaneous Measurement
Check the permit to determine if measurements other than flow rate and
pressure are required;
o If the injected fluid is corrosive, pH may be (continuously)
measured. Corrosion measurements may also be made.
o If fluid temperature is important, it may be measured.
o In some wastewater streams suspended solids measurement is important
as a measure of the tendency to plug the receiving formation.
o Chemical analysis of injection water may be periodically conducted
on grab samples to check compatibility or to identify constituents.
1-8
-------
1:15 - 1:17
Annulus and Manifold Monitoring Systems
1:15 Annulus Pressure Monitoring
An annulus pressure monitoring system can reveal the loss of mechanical
integrity before environmental damage is done. This is very important in
Class I injection wells.
Pressure in the casing-tubing annulus of Class I wells should be
monitored to detect changes that might indicate leakage through the
injection tubing or the tubing-casing packer. Any' unexplained change in..
annulus pressure should call for investigation of the'cause.
1:16 Annulus Fluid Level Monitoring
The fluid level in the annulus of a well having casing and injection tube
(but no packer) can be monitored by an electrode suspended in the
annulus.
In the same kind of construction, i.e., no packer, a corrosive liquid can
be pumped down the injection tubing while a non-corrosive liquid is
pumped simultaneously down the annulus at a slightly greater pressure.
In another variation, a non-corrosive hydrocarbon such as kerosene
floats in the annulus on top of the water. The interface between the
hydrocarbon and the water or injection fluid is maintained
constantly at a predetermined level.
1:17 Manifold Monitoring for a Cluster of Wells
Monitoring requirements are less stringent for Class II wells. Annulus
monitoring is not specifically required. Where well density is high,
manifold monitoring may be practiced. Flow and pressure measuring
instruments are installed at locations where each manifold feeds a number
of wells. Injectivity of each cluster of wells is monitored
continuously.
1-9
-------
REFERENCES - APPENDIX I
Barlow, A.C. Waste Disposal Well Design in Underground Waste Management
Environmental Implications. American Association of Petroleum
Geologists, Manoir 18, Tulsa, Oklahoma, 1972.
Donaldson, E.G. Subsurface Disposal of Oilfield Brines and Petro- Chemical
Wastes, Volume I. U.S. DOE, Environmental Control Symposium, 1978.
I - 10
-------
APPENDI)
PUMP DISCHARGE PRESSURE
AND VOLUME DATA
-------
APPENDIX J
PUMP DISCHARGE PRESSURE
AND VOLUME DATA
-------
Pump Discharge Pressure (psi)
Pump Discharge Volume (gal./stroke)
Securitu
Mwutoctur
M«M
223
325
450
600
B-1640
0-38
G-»5
G-6S
G48
M-25
H-1SO
f : BETHLEHEM - Durtci
Mai Mn Jtro*« Red
I.M.f S.f.M LOT** Sin
225 60 14 2
325 80 18 21/4
450 60 16 21/2
600 55 18 2-1/2
1999 90 16 3-1/2
4«8 100 14 2-1/8
608 100 16 2-1/2
874 100 16 2-1/7
1212 100 18 23/4
338 100 12 2
177 65 12 2
4-3/4 5 S-1/4
1249 1121
4.4 4.9
1610 1450
4.9 5.5
2300 2055
4.8 5.3
2965 2650
5.3 6.0
_ _ _
1485
4.3
1691
4.8
2460
48
3066
5.2
1383 - 1132
3.4 - 4.2
1180 - 948
3.4 - 4.2
5-1/2 £3/4 (
1016 924 845
5.4 5.9 6.5
1310 1190 1085
6.0 6.6 7.2
1855 1680 1530
5.9 6.5 7.1
2395 2293 1972
6.6 7.3 aO
4570
6.5
1227 - 1031
5.3 - 64
1397 - 1174
59 - 7.1
2033 - 1708
5.9 - 7.1
2534 . 2129
6.5 . 79
944
5.1
855 779 711
4.6 11 5.5
LiiwrSm(M)
6-1/4 6-1/2 6-3/4
775 714 - 659
7.1 7.7 8.3
995 910 845
7.9 8.6 9.3
1400 1287 1186
7.8 8.5 9.2
1808 1660 1530
8.8 9.5 104
3900
7.9
878
7.6
1001
8.5
1456
8.5
1814
94
799-685
6.1 - 7.1
653 600 555
6.1 6.6 7.1
7 7-1/4 7.1/2
610 568 S28
8.9 9.6 10.3
780 725 675
10.0 10.8 11.6
1098 1018 945
10.0 10.8 11.6
1415 1312 1220
11.2 12.1 13.0
3360 - 2920
9.3 - 10.9
757 - 660
8.9 - 103
863 - 751
10.0 - 11.6
1255 - 1093
10.0 - 11.6
1564 - 1363
11.1 - 12.8
593
8.2
515 478
7.7 12
7-3/4 . t
495 463
11.0 11. 8'"
650 590
12.4 13.2
884 826
12.3 13.1
1141 1068
13.9 '14.8
2570
12.6
580
11.8
660
111
961
13.1
1198
14.7
_ _
-
MOTutKtunr: CONTINf NTAL-EMSCO - OwlMm
MMM
0-125
0-175
0-22S
0-300
0-375
OA-SOO
08-550
0550
08-700
OA-700
08-850
OA-890
DC 1000
0-1000
DC 1350
0-1 350
OC16SO
0 USD
Mai MM S0WM Bo*
I.H.P. S.PJN. UnfOt Sin
125 85 10 1-3/4
175 75 12 17/8
225 70 12 1-7/8
300 70 14 2
375 70 14 2
500 65 16 2-1/2
550 65 16 2-1/2
700 65 16 2-3/4
850 80 18 3
1000 60 18 3
1350 60 18 3-1/2
1650 60 18 3-1/2
Lifw So* ( in )
4.1/2 4-3/4 5
840 748 670
2.5 2.9 12
1130 1000 898
3.0 34 18
1551 1379 1234
10 3.4 18
1600 1430
19 4.4
1991 1777
19 44
2720 23SO
4.2 4.8
2915 2590
4.2 4.8
_
- -
« _
_
5-1/4 5-1/2 5-3/4 6 6-1/4 6-1/2 ! 6-3/4 7 7-1/4 I 7-1/2
604 548 499
IS 3.9 4.3
807 731 666
4.2 4.6 5.1
1111 1007 916
4.2 4.6 5.1
1280 1162 1060
49 5.4 5.9
1600 1451 1318
4.9 54 5.9
2100 1902 1710
43 5.9 6.5
2317 2090 1894
5.3 5.9 6.5
2727 2463
5.8 6.4
- - 2954
7.0
3480
70
_
_
456 419 386
4.7 5.1 5.5
608 558 514
5.6 6.1 6.6
838 769 708
5.6 6.1 6.6
965 886 815
6.5 7.1 7.7
1156 1104 1018
6.5 7.1 7.7
1566 143S 1317
7.1 7.8 15
1727 1577 1449
71 7.8 8.5
2236 2044 1875
7.0 7.7 84
2680 2440 2240
7.7 8.4 9.2
3153 2871 2635
7.7 8.4 9.2
4474 4058 3706
73 8.1 88
5469 4960 4530
7.3 11 &8
357 326 308
6.0 6.4 6.9
475
7.1
654 607 S65
7.1 7.7 8.3
754 698 650
13 19 96
939 871 810
8.3 19 9.6
1225 1122 1035
9.2 10.0 10.8
1336 1235 1146
9.2 10.0 10 8
1726 1593 1478
9.1 9.8 106
2055 1895 1758
10.0 10.9 11.7
2418 2229 2068
10.0 10.9 11.7
3392 3123 2880
9.6 10.5 11.4
4146 3817 3520
9.6 10.5 11.4
-
:
602
10.3
744
10.3
970
11.6
1067
11.6
1374
11.4
4629
12.7
1917
12.7
2669
12.3
3262
12.3
NOTE:
Toe V»lm: Oiltft»m Prraar*
Bottom Vi!u«: DiKtWft Vohimt
J -
-------
Pump Discharge Pressure (psi)
Pump Discharge Volume (gal./stroke)
Manufacturer CONTINENTAL EMSCO TnplM
Mod«
F-350
P-500
P-650
P-800
P- 1000
F-1300
P-1600
FA- 1300
PA- 1600
««I»O Rated Strek*
l.H.P S.P M. Ltwjtn
350 175 7
500 <65 7'7
650 160 3
300 150 9
1000 140 10
<300 120 12
1600 120 12
1300 120 12
1600 120 12
3S 3* «
3525 3080 2705
09 10 I'
4851 - 3818
'0 - 12
- - 5585
- - 15
_ _
_
_ _ _
_ _ _
Lm«f Sis* (in)
4'4 4H 4*
2390 2135 -
13 14
3282 3025 2632
14 15 17
4237 3788 3401
15 16 13
- 4415 3970
19 21
- 5340 4790
21 23
_ _
_
3 5% SW
1730 1570 1428
18 20 22
2440 2154 2024
19 21 23
3070 2770 2525
20 23 25
3590 3260 2965
23 25 28
4330 3920 3575
25 28 31
- - 4516
- - 37
5558
- - 37
5464 4516
30 - 37
5 SCO 5500
30 - 37
5*1 a «'.
1309 1200 H06
24 JS 23
794 1699 !565
25 2 7 30
2336 2128 -
27 30 -
2715 2490 2295
30 33 36
3270 3010 2770
34 3 r 40
4126 3791 3494
40 44 48
5078 4665 4?99
40 44 48
4126 3892 34
14
IS
. 16
Rod
Sin
2-1/4 :
2-V8 ,
2-3/4
Un«r Sit* (In)
s
1774
4.4
2801
45
3083
46
SV4
1444
5.4
2258
5.5
35U83
« '
1200
85
1883
8.7 '
2SC2 .
70 ;
H
,0,3
1SM
8.0
2142
8.4
7
888
8.5
1334
9.4
,822
9.8 '
ManutKturar ELUS WK.LIAM3 CO.
MM*
W-330
WM40
WH no
W400
WH400
VM50
VV-1000
W.,400
W-1700
W-2000
MM.
300
440
323
800
800
830
1000
,400
,700
2000
Mai.
430
420
300
13S
130
,13
,33
110
110
,10
SHOteS.
' 1
i
7 1
8-1/2 i
,0 i
9.1/2 1
9-1/2 I
14 i
" !
,3 '
Trtptoi
I 2V, 3 1 3Vi
3601 2303 1600 , 1176
3 4 6 > 9
~ i 21g"
I
_ _ _ ; _
- i -
_ _ ! _
- : -
_ _ _ ' i _
_ j _
- ; -
3V,
,024
1 0
,87,
-
-
-
-
-
-
-
-
Un«v Sa» (in)
4 I 4V. 4%
900 I _
,.1 !
,650 , 1462 ,304
1.0 1.1 1.2
2368 ' _ 1866
11. ,4
_ : _
_ i _ 2988
~ ' 2.1
- ! -
- : -
_
_
_
3
- :
- ,
1312
1 8
3229
2419
28
4716
2.4
4716
2.4
5000
3.6
5000
3.8
5000
3.8
5'4
-
-
'1?
26,5
2.8
2000
3.1
^
3896
- 2.9
4546
43
5000
48
5000
46
6
-
-
fS°
*3.?
,660
3.7
3269
3.5
3273
3.5
3619
3.1
*£?
5000
5.5
6%
-
-
890
30
1670
17
7 "
-
-
-
,812
43
,432 1234
4.3 ' 5.0
2786
4.1
2791
4.1
2401
48
2406
48
3234 2603
6.0 I 7.0
^ : Vf
t? : 377451
NOTE
Tap v»m«
P'»sv»e
Bottom vaiu* C
-------
Pump Discharge Pressure (psi)
Pump Discharge Volume (gal./stroke)
Securiti
M*nulKU*«' OAPONEB- DENVER OuQMi
MM*
f+Lf*\.
fn-fnn
FO«0
FO-fXO
FXN
FZ-FX2
GH-GXP
Gfl-GXPA
GB-GXH
GXH
GXN
GXP
GXO
GXR
KXf
KXG
KXJ
U*i Uai Siren* Mod
IMP SPM itftgtn Silt
625 55 20 2-1-2
255 70 u 2
U9 70 10 1-3 4
320 65 16 2
400 75 u 2
220 70 12 2
625 70 16 2-1.2
550 65 16 2-1. '2
825 60 16 2-3'*
1250 60 16 3-1-4
500 70 14 2-l<4
700 70 16 2-1/2
130 70 16 2-1.4
1000 60 18 2-3.4
700 70 16 2-12
1000 60 18 2-3-4
1500 60 18 3-14
2559 2280 2 115
59 67 74
1163 - 961
44 _ 54
"3 - 638
32 - 39
1319 1259 1132
50 56 61
1692 - 1398
44 _ 54
988 - 817
3? 46
2725 - 2205
48 59
2400 2140 1990
48 53 59
- - 2636
- - 65
2435 - 1974
43 - 53
3060 - 2470
48 - 59
1470 - 1195
49 - 60
- _ «.
- - 2470
- - 59
_ _ _
Lif
1929 1777 1631
82 . 89 98
- 807 -
65
- 536 -
47 -
1031 951 876
68 74 81
- 1175 -
- 65 -
- 686 -
- 55 -
- 1825 -
71
1820 1670 1550
65 71 78
2510 2215 2025
72 79 86
- 3942 -
77
- 1633 -
64
- 2040 -
71
- 1000 -
73
- 3113 2815
- 78 86
- 2040 -
71
- 3113 2815
78 86
- 4845 -
- 75 -
wr Su« (in)
1514 . 1404 1306
106 115 125
688 638 593
77 83 89
457 423 393
55 60 54
810 751 699
88 95 10 T
f 1001 - 863
77 . - 90
585 542 504
66 7i rr
1530 1410 1305
85 92 100
1425 1320 1225
85 92 100
1887 1750 1627
94 102 111
3281 3035 2793
92 101 109
1377 1271 1177
76 82 88
1712 1578 1460
85 92 100
843 778 720
86 93 101
2578 2373 2194
94 102 111
1712 1578 1460
85 92 100
2578 2373 2194
94 102 11 i
4025 3640 3350
90 100 '09
1217 1132 1065
135 144 155
543 - -
96 - -
367 - -
69 - -
651 605 570
iiO 118 '26
805 752 -
96 .103 -
470 . - -
82 - -
1205 - 1055
108 - 123
1145 1070
108 116
1517 1418
ii9 128 -
2580 2400 2232
H8 127 136
1094 - -
95 - -
1357 1171
108 116
668 - -
109 - -
2035 1903 1172
H9 128 137
1357 H7i -
10 8 116 -
2035 1903 1172
119 128 '37
3095 - -
118 - -
1000 .
' 'Si
_
»
_
_
_
_
Mannaciww GAflONER-OENVER Tnpwi
MOM4
P>«
PT-7
pz-r
PZ-8
pr-9
PZ-10
PZ-ll
Rat*4 R«t*« Strot*
I.M P SPM l*xgin
275 175 8
500 160 7
550 165 7
750 165 8
1000 ISO 9
1350 130 10
1600 130 11
l««r Sue (m)
3 3V 3S
3118 2657 2290
7 9 10
MB ^ ^
, '^
. .
~
~
~
4 4H 5
1753 1386 1122
13 16 20
3150 2550
- 14 18
- 3556 2880
- 14 18
5381 4238 3433
13 16 20
5530 4485
- 19 23
_
5S 6 6'.
_ _
2110 1770 -
22 26
2380 2000 -
22 26
2843 2385 2200
25 29 32
3710 3110 2875
28 33 36
5200 4400 -
31 37 -
5595 4702 -
34 40 -
SS 7
^_
1510 1300
30 35
1705 1470
30 25
2650 - 2285
39 45
3700 3200
43 50
4006 3454
47 55
NOTE
4- ana 4V/ SUM
Top vtx Ducnacqt P»«
Bononi VMM Oncnarge vownt
- 3
-------
Se
Pump Discharge Pressure (psi)
Pump Discharge Volume (gal./stroke)
Manuiactirn HALLIBURTON
Model
NT-4COO
R«l«d
I.HP
275
Tnolea
R«l»d
S.PM.
75
Slroli*
Login
3
Lm«f SK* (in)
S
4500
20
SS
3000
25
9
3000
29
M*nulactjrf IOECO OuOKl
Model
MM. 200
MM. 300
MM-300GS
MM-45G
MM- 550
MM-55CF
MM-600
MM- 700
MU-700F
MM- 900
MM-tOOO
MM-IOOOG3
MM- 1250
MM-1450F
MM- 1625
MM-I7SOP
Mai MII Stroke Rod
I H P SPM Leftgin Sit*
200 30 10 1-7.3
300 30 12 2
450 X 12 2-1. '4
550 35 15 2-K2
600 65 16 2-1/2
700 65 16 2-3/4
900 65 16 3
1000 65 16 3
1250 65 18 3-1/6
1450 65 18 3-1/8
1625 65 18 3-3/8
1750 65 18 3-3/8
Liner S'I«
2000 1325 1460
17 20 25
2500 2380 1830
20 23 30
- 2830
28
_ _ «
^ ^ ^
- 1163 -
- 31
- 1458 -
- 37 _
2510 2225 -
32 37
3120 2775 24«0
40 45 50
- 2830 2540
- 48 53
- 3038
- - 52
»
<_ ^ ^
970 364 790
33 42 46
H85 - 985
46 - 55
(in)
667 617
- 55 59
- 832 -
- 66 -
1810 - 15001 - 1265 1165
45 - 551 - 65 70
2235 2020 18451 '690 1550 1425
55 61 67 1 73 80 37
2280 2060 1880
59 65 71
- 1582 1348
- 85 92
2730 2470 22461 - 1878 -
58 83 70 | 84
3810 32SO 2950
52 60 68
4020 - 3280
52 - 88
3680
- - 76
- - 4270
- - 78
- - 4920
74
- - 5000
74
2459
- 82 -
- 2735 2510
- 82 89
3350 3065 2820
84 92 100
3880 3560 3270
84 91 100
- 4060 3790
- 89 97
4800 4380 4020
82 90 98
712 S62 -
77 82 -
1082 1000
76 82 -
1320 1220
94 101
1250 1165 -
10.0 10 8
1595 1487 1375
99 106 114
2085 1933 1796
97 104 "2
2325 2155 :u»
97 10 4 112
2800 2400 2230
108 117 126
3010 2790 2590
108 M7 125
3400 3170 2940
106 115 124
3700 3410 3175
106 115 123
_ _ .
_
1285 -
122 -
1670 1562
121 129
I860 1740
121 129
2079 i»40
135 145
_ _
ManuiKtuer IOECO TrioMm
........ Rii»d Rated Stroke
IMP S.PM. Ltogtn
T-500 500 165 8
T-300 800 150 9
T-lOOO-o 1000 140 10
T-I300MP 1300 120 12
T-1600HP 1600 120 12
LUMT Silt (in)
4 4H $
3586 2826 2289
13 16 20
- 4424 3588
- 19 23
- 5339 4322
- 21 25
- - 5462
- - 30
- - 5556
- - 3.1
5S 6 8H
1895 1591 1356
25 29 34
2960 2488 2121
23 33 39
3580 3002 2559
31 38 43
4514 3793 3232
37 44 52
5556 4669 3978
37 44 52
I 7 7H
1169 -
4
1828 -
45
2204 -
5 -
2787 2428
60 69
3430 2988 .
60 39
NOTE
*oo vaki«
Bonom vaiu* C*cna>g« voun*
J - 4
-------
Pump Discharge Pressure (psi)
Pump Discharge Volume (gal./stroke)
Seen
M«tu««enjrar: MATIOMAL SU^LV - Ou*ni
«
C-1SO-B
C-250
C-3M
E-800
700
0-700
G-1000-C
M-8BO-A
M-1280
K.IK
K-2BO
K-380
It 500
K-SOO-A
K-700
K-700-A
KSH.IBO
KSH.2SO
N.1000
N-1XO
N-1600
MM Mo t»»U **
I.M.P. S.m UMC* SiB
IBS 70 12 1-7/8
330 65 15 2-1/4
498 « 11 2-3/1
MO 70 14 3-S/t
835 65 16 3-1/1
700 70 14 2-5/8
1000 68 16 3-1/1
SSO 70 15 2-7/1
12SO 66 16 3-1/1
180 80 10 2
280 75 12 2
380 70 14 2-3/1
513 70 15 28/8
700 66 16 2-7/8
180 80 . 10 2
280 75 12 2
1000 65 16 27/8
1300 65 16 3-1/8
1600 68 16 3-3/t
lu«r S>n
2950 2705 2485
7 6 8.3 9.0
3915 3580 3290
74 8.1 8.8
4940 4505 4135
73 7.9 8.7
7 7-1/4 7-1/2 |7-l/4- .1
595 SSO
7.7 8.3
875 810
9.5 10.2
1290 1195 1115
11.3 12.2 13.1
1415 1310 1215
8.7 94 10.1
1260 -
9.6
1680 1560 1450
8.7 94 10.1
2335 2160 2010
96 104 11.2
1935 1790 1665
9.1 9.8 10.6
2915 2700 2505
9.6 10.4 11.2
SIS 475
6.4 6.9
710 660
7.7 8.2
900 835
8.8 9.5
1150 1065 990
9.3 10.0 10.8
1605 1490 1385
9.8 10.5 11.4
-
2295 2130 -
9.8 10.5
3030 2810 -
9.6 10.4 -
3810 3515
9.4 10.2
-
-
1040
14.0
113S 1060
10.8 11.5
-
1350 1265
10.8 11.5
1865 -
12.1
1550 1450
11.4 112
2335 -
12.0
-
-
-
1290 1305
12.2 13.0
_ _
_ _
-
-
NOTE:
Toe V»tm:
Bottom VaM: Oii0Mrfi Vokim
J - 5
-------
Seoi
Pump Discharge Pressure (psi)
Pump Discharge Volume (gai./stroke)
M«j<«ctu»tr NATIONAL SUPPLY - Trip*.
MoM
7-P-50
8.C-80
9-P-IOO
10.P-130
I2-IM60
Rrad M*ad SnM
I.HJ. J^M. LOT**
500 165 7%
800 ISO 8%
tOOO ISO 9X
1300 140 10
1600 120 12
UMT Sin (ml
IH 4 4* 1 4* 4* 5 1 5* S'A 5*. 1 66% 6*
4830 3695 -
1.0 1.3
- 4925
1.6
- '_
_
-
2920 - 2365
1.6 - 2.0
439S 1945 3560
1.8 2.0 Z2
S38S 4830 4360
1.9 2.1 14
-
- - -
1955 -
14
3230 2940 2690
2.4 2.6 2.9
3955 3605 3300.
2.6 29 3.1
S09S 4645 4250
2.8 11 14
5555 5085
3.7 4.0
1645.1515 -
18 11 -
2470 2280 -
3.1 14 -
3030 2790 2580
14 3.7 4.0
3900 3S9S 31JS
17 4.0 4.3
4670 4305 3980
4.4 4.8 5.2
« 7 7"*
- - - .
_
2395 -
4.3
3085
4.S
3690 3430 3200
5.6 8.0 6.4
MinufKlurtr: OIL WELL - Ougtn
MOM
21J-P
2144«
218^
220*
81W
81 8-P
1400*
170OP
7000*
A. TOO*
A-8SO*
A- 1000*
Ma Ma SMM Rod
I.M.f S.P.M. Luiftli Sin
220 70 12 1-7/8
350 70 14 2-1/4
500 65 18 2-1/4
600 60 20 2-1/2
LtfMr Sin Im.l
5 S-1/2 6
1200 - 820
18 - 5.6
1375 1140
5.3 6.4
2040 - 1370
is - a2
2650 - 1785
19 - 19
700 65 16 2-1/4 ; - 2725 2235
1 - 5.8 7.0
925 65 18 1-1/4
1400 65 18 3-1/2
1700 65 18 3-1/2
65 18 3-1/4
700 65 16 2-3/4
850 65 16 3-1/4
1000 65 18 3-1/4
2990
75
4310
7.3
6-1/J 6-1/4 7
690 640 600
6.6 7.1 7.7
960 890 820
7.6 8.2 8.8
1155 1065 989
9.7 10.5 11.3
1485 1370 1270
10.6 11.S 115
1875 1725 1598
a 4 9.1 9.8
2480 2275 2100
9.0 9.9 10.7
3560 - 3000
8.8 - 10.5
5000 4320 - 3640
73 8.8 - 10.S
3660 2990
6.1 7.5
2725 2735
5.8 70
3500 2850
5.4 17
3860 2990
6.1 7.5
2480 2275 2100
90 9.9 10.7
1875 172S 1593
8.4 9.1 9.8
2370 2175 2005
8.0 as 9.5
2480 2775 2100
9.0 9.9 -10.7
7-1/4 7-1/4 8
550
13
765
9.5
915
12.2
1175 1020 955
13.4 15.4 16.6
1478 1280 1197
10.6 112 111
1940 1675 1560
116 114 14.4
. -
- -
1940 167S - -
11.6 13.4
1478 1280
10.8 112
1870 1600
10.2 11.9
1940 1675
11.6 114
NOTE:
Too VUu«:
Bonom Value: OitclW9i Voiunw
J - 6
-------
Pump Discharge Pressure (psi)
Pump Discharge Volume (gal./stroke)
Sectirttu1
Mmtmrar: OIL WELL - Tri*a
fttatfri
3»*T
8so-*r
noftrr
AECO^T
Ai40o-*T
AITO»*T
Mai Ma SMW
I.H f. S.P.M. LM««I
350 ITS 1
850 160 9
1100 ISO 10
MO ITS 8
1400 ISO 10
1700 ISO 12
LMT Sin (ml
4 4-1/2 S I 5-1/2 5-3/4 6
2400 1900 1500
1.3 1.6 2.0
SOOO 4400 3560
1.S 1.9 2.3
SOOO 4500
2.1 2.6
3780 2990 2470
1.3 1.6 2.0
SOOO
2.5
SOOO
3.1
1250 1144 1050
2.5 2.7 2.9
2940 - 2470
2.8 - 3.3
3700 - 3110
3.1 - 3.7
2000 1830 1680
2.S 17 2.9
4723 4321 3968
?.1 34 37
4723 4321 3968
3.7 4.0 4.4
6-1/2 6-3/4 7
900 - 770
3.4 - - . 4.0
2110
3.9
2650
43
14X - 1240
3.4 - 4.0
3381 * 3135 2915
4.3 4.6 5.0
3381 3135 2915
S.2 5.6 6.0
7-1/4 7-1/2 7-374
- ' ' - .
_
-
v « «
2718 2540 2378
5.4 5.7 6.1
2718 2540 2378
6.4 6.9 7.3
Mwuteaurar OMEGA GEOSOURCE - Tnptti
: Mai. M*i. Stro*«
: I.M.*. S.P.M. L*ngO>
LHMT Sin (In)
D-750
750
120
3000
1.6
3000
2.0
3000
2.5
3000
2.9
2S62
34
2209
4.0
MwtKturar: O*t INC. (GIST! - Tri*n
ftMri
on leoo
0*1200
0*13500
0*17000
O*t 700MOL
O*t7000L
0*1 100001
Km* ftra* SMh*
\<*f. tfM. LMf*
160 230 6
200 400 6
350 120 8
700 150 8
1000 133 10
Umr Sin (ml
1H 2 2H
-
5650 3183 2031
0.1 0.2 0.4
_
_
-
3 3H 4
1096
- i.o
1415 1039 796
0.5 0.7 1.0
- - -
-
_
4» 5 SX
866
1.2
-
2610 2114 1747
1.6 2.0 ZS
4089 3312 2737
1.6 2.0 2,5
4585 3790
2.6 3.0
6 IX 7 7H
: : : :
- - - -
1469 - '
3.0
2300 1960 1690 -
3.0 3.4 4.0 -
3184 2713 2340 2038
17 4.3 S.O S.7
NOTE:
Too VMm:
Benom VMwt: Oncnarfi voium*
J - 7
-------
Secu
Pump Discharge Pressure (psi)
Pump Discharge Volume (gal./stroke)
Mtnuficnxtr
MwM
UMF
waf
81000F
Manufacturer
Mod*
BIOOOT
81300T
81 SOOT
SKVTOf-SMCWSTEM - Ouptoi
Rat** Raw* Strok*
I.M.P. S.P.M. Ltn^tM
550 70 14
750 85 '8
1000 80 18
4» S 5*
2997 2678 2404
3.8 43 47
3642 3255
46 5.2
-
Lira* Sin {ml
SH 5*
2171 1969 1796
5.3 5.8 6.4
2920 2645 2400
5.8 6.4 7.00
3885 3510 3167
6.2 6.9 7.7
n 6» M
1648 1515 1393
6.9 7.6 3.2
2185 2010 1850
7.7 14 9.1
2884 2948 2428
8.4 9.2 10.0
1 -1
1293
8.8 " 1
1710 -t
9.9
2241
10.8
SKYTOP B«EW$T£R - Triplu
Ratttf Rattd Stroka
IMP. S.P.M. L«n«ih
1000 130 10
1300 170 12
1600 120 12
4 4* S
5000 5000 4660
1.6 2.1 26
SOOO 5000 5000
20 2.5 3 1
SOOO 5000 5000
2.0 2s 3.1
Lin*r SIM lint
5* 6 6*
3»4» 3233 2754
3.1 3.7 43
4558 3790 3234
3.7 44 5.2
SOOO 4664 3980
3.7 44 12
7
2377
5.0
2785
6.0
3427
6.0
Manufacture
Mod*
HP 8000
HP. 14000
H* 16000
HP- 18000
HP8000A
HP.14000A
r: WNELANO - OupM
MM Mu Strata Rod
I.H.P. S.P.M. LMfOI Sin
343 70 12 2
574 65 14 2-1/4
600 65 16 21/2
750 60 18 23/4
200 60 12 2
353 SO 14 21/4
5 5.1/2 5-3/4
1220 995
3.7 46
1558
5.3
2337
5.9
2700
6.5
995 -
4.6
1627 1476
5.3 5.8
{.imr Sin In
6 6-1/4 6-1/2
326-698
55 - 66
1290 - 1035
6.4 - 76
1921 1751 1608
7.1 7.8 15
2314 2113 1937
79 86 94
828 - 698
5.5 - 66
1346 1233 1135
6.4 70 76
il
6-3/4 7 7-1/4
644 597 555
71 77 8.2
1000 927 862
82 88 95
1480 1367 1268
9.2 10.0 10.8
1782 1648 1526
102 M.I 119
644 597 555
71 77 8.1
1047 970 900
8.2 88 95
7-1/2 7-3/4
-
302
102
1178 1098
11.6 12.4
1419 1327
12.8 13.8
338
10.2
Manulaerurtf : WILSON - OugMx
Ntot*
600
600H
900
1250
Ctjnt
Tiim
Ma Mu Siren. R<*
I.H.P. S.P.M. ltn*
-------
APPENOIV K
TROUBLESHOOTING
-------
APPENDIX K
TROUBLESHOOTING HELLS
-------
K:1 - K:3
APPENDIX K
TROUBLESHOOTING WELLS
Loss of mechanical Integrity In a well may be evident from changes In the
annul us pressure or Injection pressure and flow. Locating the cause may be
more .difficult. Diagnostic tests static or dynamic performed on the
well may point to the general assembly at fault: the Injection tubing, the
casing, or the packer. But Identifying the single pipe, piece of tubing, or
Joint that has the leak requires opening the well and (where possible)
removing the tubing and packer.
Lengths of Injection tubing can be Individually Inspected and tested at the
surface, as can the packer. If monitoring data Indicate a possible leak In
the casing, there are casing evaluation tools and procedures that pinpoint
probable locations and give an Idea of their seriousness. These tools and
procedures were described In Chapter 4.
Some common problems are described below. Following that, case histories of
some problem wells are presented.
K:1 Types of Problems
K:2 Untreatable Problems
If the well Is untreatable, It will eventually be abandoned. Some
examples of untreatable problems are:
o Local formation unsuitable for Injection, that Is, transmlsslv Ity
(kh) too low
o Because of several Injectors In the given area or other natural
reasons reservoir pressure too high
o "Confining" strata protecting underground water not really confining
o Well repairs no longer cost effective
Considerable time, effort and costs may be required to conclude that the
well problem Is untreatable.
K:3 Treatable Problems
If the well problem Is treatable, the operator will develop a program to
correct the problem, submit It to the Director for approval, and th'en
contract with qualified service companies to get the work done. The
Inspector may have to be present during the workover or during
critical phases of It to verify that the work Is performed as
specif led.
K - 1
-------
K:4 - K:5
K:4 Formation and Borehole Problems
Formation and borehole problems develop gradually from a variety of
causes. Among the more common are:
o Plugging of the borehole face, formation and/or filter by suspended
solids In the Injected fluid
o Plugging of borehole face and/or filter by the growth of organisms
o Swelling of clays by "Incompatible" Injection 'fluid
o Plugging from oils, emulsions, etc.
o Damage from workover and stimulation activities
o Poor filter design or Installation
K:5 Common Examples of Troubleshooting
Example 1! Tubing Leak
An operator Injecting wastewater In a Class I well In Deer Park, Texas
reported communication between the tubing and annulus. An engineering
company performed a mechanical Integrity test which Indicated a leak In
the Injection tubing. The problem was solved as described below:
The tubing leak followed a similar failure of this well two months
before. The previous leak was tracd to the Injection tubing at a depth
of 3025 feet, which was subsequently repaired (Workover No. 3) with a
wireline-set tubing patch. The current workover, unlike Workover No. 3,
Involved pulling the Injection string. A service rig was moved on
location and set up on September 13, 1983. The following day the
Injection tubing was removed from the well.
Selected joints of tubing were placed on the pipe rack and visually
Inspected. The remainder was stood back In the derrick to expedite
relnstallatlon. All of the visually Inspected tubing appeared to be In
good condition.
The two joints containing the Pengo tubing patch from Workover No. 3 were
set aside. A smalI 1/8" hole was noted In the body of one of the joints.
This hole was not detected In the calIper log conducted during Workover
No. 3 on July 12, 1983 (the hole was thought to be at a threaded
connection).
The presence of a hole In the body of a joint Indicated that a downhole
corrosion problem existed. An Otis CalIper survey was run to a depth of
3600 feet. In-line corrosion coupon testing had previously Indicated a
"moderate" corrosion rate of 10 mils per year (mpy).
K - 2
-------
K:5
After pulling all of the tubing out of the well and redressing the seal
assembly, the tubing was run back Into the well while hydrotestlng each
60 foot stand Internally to 4000 psl.
A total of six joints were replaced with new 3 1/2", 9.3#, J-55 tubing.
Counting from the top of the well the following joints were replaced:
Joint No. Descr IjrrJon of Fa 11 ure7Defect
95 1/8" hole In body - patched during previous workover
96 patched during previous workover
124 1/8" hole In body
129 corroded threads
130 hydrostatic test failure at 3000 psl
183 hydrostatic test failure at 2500 psl
Mechanical Integrity was restored to the well after the four-day
workover. The annulus was pressured to 1010 psl on September 16, 1983.
There was no measurable loss In 30 minutes on the 2000 psl field gauge.
The welI was then turned over to operations. A recommendation was made
to Inject water compatible with carbon steel tubing or replace the
existing tubing with corrosion-resistant fiberglass tubing.
Example 2; Casing Leak
This example describes the detection and repair of a casing leak of a
Class I Injection well In South Louisiana. Continuous monitoring of the
annulus and Injection pressures had previously Indicated a leak of the
packer, tubing or casing.
A series of nine pressure tests were run on the 7" protection casing to
determine the location of leaks In the casing. This was accomplished by
setting a test packer at different depths and pressuring up on the
casing. The leak was determined to be In the Interval between 4071' and
4081'.
The following day 12 barrels of cement were spotted and squeezed. The
cement was allowed to set, under pressure, overnight, and was then
drilled out and the hole was circulated clean. After pressure testing
the casing, another 4 1/2 barrels of cement were spotted and squeezed,
and a I lowed to set up.
K - 3
-------
K:5
Four days later the cement was drilled out and the hole was circulated
clean; however, subsequent pressure tests still Indicated a small leak In
the casing. It was decided that the best approach to that problem would
be to set the packer about 20 feet above the leak. Verbal concurrence
was received from the Louisiana UIC office, with the understanding that a
letter confirming the conversation would be sent to the UIC office as
soon as practicable.
Thereafter, the cast Iron bridge plug at 4196 feet was fished out and the
well was washed and circulated clean.
The Otis RB-1 packer was then redressed, run back In the hole on 100
joints of 4 1/2" tubing, set at 4035 feet (bottom of packer) and pressure
tested satisfactorily at 515 psl for 4 1/2 hours.
The 4 1/2" x 7" annulus was filled with brine containing TretolIte
corrosion Inhibitor and sodium sulflte (oxygen scavenger).
After pressure testing the tubing, the test plug and collar stop were
retrieved, the welIhead Installed, the annulus pressurized, and the
workover rig released.
Example 3i Packer seal leakp acldlzatlon
This workover was performed to repair an annular leak, restore
Injectlvlty and demonstrate mechanical Integrity of a well In South
Texas.
After pulling the 5 1/2" Injection tubing It appeared that the Otis Seal
Assembly (which was Inserted Into the packer) had been leaking. Bad
threads were also found on 6 joints of the tubing by surface visual
Inspection.
The Injection packer was subsequently retrieved and an open-ended mule
shoe was run to reverse circulate shale and sand from 4347' to 45401.
After cleaning the welI bore, previous difficulty In seating a test packer
was corrected by scraping the 7" protection casing.
A radioactive tracer survey established the point of exit from the casing
to be 4460' - 4464'. This survey was conducted to fulfill part of the
mechanical Integrity test requirements set forth by the Texas Department
of Water Resources. The log showed all of the fluid was moving Into the
disposal Interval and there were no Indications of vertical migration.
The well was acidized next by washing the perforations'with 1260 gallons
of 28$ HCI and 840 gallons of 15$ HCI. This was followed by 1000 gallons
of 15$ HCI, 7500 gallons of 22$ HCI plus 6% HF acid, and 1000 gallons of
15$ HCI. The acid was displaced with 32,000 gallons of 9 ppg low-calcium
brine. The Initial flush rate of 840 gpm @ 1200 psl was reduced to 420
gpm @ 690 psl after 10,000 gallons had been pumped.
K - 4
-------
K:5
The well was reassembled using a new Brown Oil Tool Type "D" Liner Hanger
Packer. External hydrostatic testing of the tubing connections was
performed while running It Into the well. Prior to setting the new
packer, the annulus was filled with 9 ppg brine Inhibited with NL Barold
Coat B-1400. Wellhead modifications were required to achieve annular
pressure Integrity.
ExampJe 4; Wei I Cleanout and Reperforation
This example describes the methods used to restore Injectlvlty to a Class
I disposal welI In Louisiana.
After rigging up the service rig, the well was killed with 100 BBL of
brine water. The tree was removed, followed by Installation of the
blowout preventer.
The 4 1/2" Injection tubing was cleaned and washed from 2375' to the
surface with a 3 7/8" bit, scraper, and hydrojet. The Injection tubing
and 4 1/2" x 7" Texas Iron Works (TIW) "LH" packer were pulled out of the
well. The 7" protection casing was cleaned down to 3525' (PBTD) using a
stripper and power swivel. The perforations at 2760'-2766' were
selectively washed, and surged to recover sol Ids from the formation.
This was repeated until the formation appeared to be clean.
To restore the Injectlvlty of the receiving zone, the well was acidized
with a mixture of ^5% HCI, and 12$ HCI/3* HF, followed by an Injection
test. When the Injection test proved unsatisfactory, the well was surged
and washed again. This sequence of surging, washing, acidizing and
Injection testing was repeated several times without success. Therefore,
It was recommended the welI be perforated at the 2400-foot sand above the
existing Injection Interval. This procedure was approved by the
Louisiana Department of Natural Resources.
A block squeeze was made between 2469'-2470' with 100 sacks of Class "H"
cement to prevent upward migration of fluid. The squeeze was tested to
1800 psl. A cement bond log was run from 2620' to the bottom of the
surface casing. A casing callper log was also run from 2620' to the
surface. The casing was perforated between 2605' and 2635' with four (4)
shots per foot. The well was washed and cleaned and an Injection test
was conducted satisfactorily.
The 7" x 4'l/2" TIW "LH" packer was set at 2664' after 4 1/2" Injection
tubing was run In the hole while hydrostatJcal ly testing each Joint to
3000 psl for three (3) minutes. The annulus was filled with brine and
tested for two (2) hours at 1010 psl. A Radioactive Tracer Log was run
to determine, the direction of flow. The bottom hole pressure was also
determined. The equipment was rigged down.
The welI was returned to service.
K - 5
-------
APPENDIX L
BLOWOUT PREVENTION AND CONTROL
-------
APPENDIX L
BLOWOUT PREVENTION AND CONTROL
-------
1:2
APPENDIX L
BLOWOUT PREVENTION AND CONTROL
A blowout fs by definition the uncontrolled flow of formation fluids to the
surface or another underground zone. They can occur during drilling or
workover If excessive formation pressures are encountered.
The UIC Inspector may never see a blowout. However, since a single blowout or
spill, depending on Its magnitude, time or place,, can do Irreparable
environmental harm, a basic discussion on blowout prevention needs to be-
addressed. This section of the Inspection Guide is obviously not Intended as
a course to train the Inspector In how to prevent or control a blowout.
Blowout control can be quite complex, requires detailed planning, practice and
precise execution. It Is a primary responsibility of the drilling or workover
crew working under potentially high pressure conditions.
Every phase of wel I control follows logical concepts. These concepts can be
placed Into one of three levels of well-control:
o Primary Control
o Secondary Control
o Tertiary Control
L:1 Primary Control
Primary Control is the prevention of Jd_cks. A kick Is the entry of
formation fluids Into the wellbore In large enough quantity to require
shutting In the well under pressure. This level of control is the most
critical - If kicks are prevented, blowouts cannot occur.
Formation fluids cannot enter the hole at a given point as long as the
hydrostatic pressure of the mud In the annulus Is greater than the
formation pressure. Hydrostatic.pressure depends on only two variables -
density and height of the fluid column. The density Is expressed in Ibs
per gal or psl/ft. The height is simply the depth to the pressure zone.
in directional wells, the fluid column height Is the true vertical depth.
1:2 Causes of Kicks
Any event or chain of events that results In Insufficient hydrostatic
pressure can cause a kick. The most ccmmon causes are:
o Failure to keep the hole full on trips
o Excessive swab pressures
o Insufficient mud density
L - 1
-------
1:2 - L:4
o Loss of circulation
o Abnormally-pressured formations
Several drilling studies have shown that the most frequent cause of kicks
Is Insufficient mud weight.
Another frequent cause of blowouts Is kicks encountered while drilling
shallow gas accumulations. Reaction time Is short; minimum blowout
prevention equipment Is present; total containment.of formation pressure
Is difficult, If not Impossible; and the hole unloads In a very short-
time.
In some Class I disposal wells kicks and even blowouts have occurred
during workovers. This has been due to gas accumulations resulting from
Interactions between the wastewater and formation,- for example, acidic
wastewater reacting with carbonate rocks to form carbon dioxide.
Kicks can be minimized If the rig crews:
o Understand the causes of kicks
o Use proper equipment and techniques to detect an unexpected
reduction In hydrostatic pressure
L:3 Secondary Control
Loss of Primary Control does not mean that the well Is "out of control".
As long as the kick Is properly handled, control can be maintained until
the Invading fluids are circulated out and Primary Control restored.
This Is called Secondary Control. A kick that Is not contained can
rapidly deteriorate Into a blowout.
Closlng-In the welI - that Is, shutting In the well quickly Is the first
and most Important step In Secondary Control. This requires continual
practice by drilling and workover crews. Blowout preventer (BOP) drills
should be conducted routinely for crews working In high pressure areas.
Not all wells should be shut-In. If casing Is set shallow or fracture
gradients are especially low, shuttlng-In the well may cause Immediate
blowing ("broaching") to the surface or to an underground- formation.
Diverting flow away from the rig may be the best alternative. The well
eventually may be killed by pumping heavy mud at a fast rate, setting a
cement or barlte plug, or natural bridging of the formation.
L:4 BOP Equipment
Control cannot be maintained without equipment. The blowout preventers,
closing unit, manifolding, choke and auxiliary equipment are all
Important. To Insure that each segment will operate In an emergency, the
equipment must periodically be maintained and tested. All preventers and
related equipment should be tested with "water to full rated pressure,.
L - 2
-------
L:4 - L:7
with the exception of the annular preventer. Testing of the annular
preventer to more than 10% of the working pressure could damage the
seal Ing element.
In addition to pressure testing, ram-type preventers should be actuated
on the drill pipe once each trip, but not less than once each day. The
annular preventer should be actuated on the drill pipe once each week.
An Inside BOP and work/drill string safety valves should be kept In an
accessible location on the rig floor at all times.
L:5 Stripping or Snubbing
It Is difficult to klI I a welI If the drlI I string Is not on bottom. If
the kick was detected while tripping, the drill string may have to be
stripped or snubbed Into the hole. Excessive pressures should be bled
off to prevent breaking down the formation or exceeding surface equipment
pressure ratings.
1:6 Circulating Out the Kick
Full Primary Control Is not restored until the kick Is circulated out and
mud balances the pressure In the kicking formation. The two Important
concerns while accomplIshlng these two tasks are:
o Keep the bottonhole pressure Imposed on the formation higher than
the formation pressure. If It Is not,, more formation fluids can
enter the hole.
o Do not let surface pressures get too high while trying to
overbalance the formation pressure. Excessive surface pressure can
fracture the formation, or rupture casing and blowout prevention
equipment.
L:7 We11-ControI Methods
The only proper way to circulate out a kick Is to maintain a constant
bottcmhole pressure. Conventional Industry methods are special cases of
a more general Constant Bottcmhole Pressure Method. They differ, In a
practical sense, by the mud weight selected for the first circulation:
o DRILLER'S METHOD
New Mud Weight = Original Mud Weight
o WAIT AND WEIGHT (ENGINEER'S) METHOD
New Mud Weight = KIM Mud Weight
o CONCURRENT (COMPOSITE) METHOD
New Mud Weight Increasing from Original Mud Weight to
KM I Mud Weight
L - 3
-------
L:7 - L:9
Each version has advantages and disadvantages. The proper value to use
for the new mud weight depends on well conditions, crew capability,
barlte supplies, mixing facilities and company policy.
L:8 Standplpe Pressure Control
Changes In the bottcmhole pressure Imposed on the formation are monitored
by the standpipe or drill pipe pressure gauge. In order to maintain the
proper bottomhole pressure, the required standpipe pressure must be
determined at the beginning of circulation. The tlnaJ standpipe pressure
should be maintained from the time the new mud reaches the bit until It'
Is detected at the surface.
The Initial standpipe pressure Is the reduced pumft pressure plus the
shut-in drill pipe pressure. This Is valid regardless of the "method"
chosen. The final standptpe pressure depends on the new mud weight. If
the mud Is not weighted up (Driller's Method), the Initial and final
pressures are the same. If the mud Is weighted to kill mud weight (Walt
and Weight Method), the final standpipe pressure Is equal to the new
reduced pump pressure (old value modified by a mud weight ratio).
The reduced pump pressure values should be taken and recorded hourly to
Insure they are available In an emergency. For wells using subsea
stacks, It Is also Important to measure the choke-line pressure losses at
the kill pump rate. The kill pump rate Is reduced from the normal rate,
usually to about a half or a third. The selected kill pump rate should
be maintained constant throughout the kick-circulation process.'
A schedule can be prepared to show the required standpipe pressures as
new mud Is circulated. (The Driller's Method dees not require a
schedule.) Essentially, we need to know how much new mud Is In the drill
string, when the new mud reaches the bit, and the associated standpipe
pressures. One method of developing the standpIpe pressure scbeduJe Is
to use graph paper. Another way Is to calculate a pressure reduction per
100 strokes.
L:9 Potential Difficulties
Even with the best planning and training, difficulties can be encountered
while killing the well. The crew should look for problem signs and take
appropriate action. Among these difficulties are:
o Starting up the pump
o Barlte contamination
o Loss of circulation
o Hole In the pipe
o Plugged pipe or bit nozzle
L - 4
-------
L:9 - L:11
o Pump failure
o Choke plug or washout
o Stuck pipe
o Sour gas (h^S), and
o Drill string off bottom
L:10 Effect of Influx
Formation fluids entering the wellbore can be gas, oil, saltwater, or a
combination of all three. The type of Influx can affect the well
behavlor.
The constant bottcmhole pressure method Is not affected by the type of
Influx. Essentially each kick Is treated as gas, the worst case. The
differences that do exist Include pit volume changes, required casing
pressures and disposal at the surface.
Gas Is compressible; oil and saltwater are not. Gas must be allowed to
expand as It Is circulated out of the hole. Otherwise, pressures In the
hole Increase and endanger fracturing the formation. Most of the gas
expansion occurs In the top 1000-2000 ft. The gas expansion reduces the
hydrostatic pressure In the annul us. Thus, casing pressures on a gas
kick will be higher throughout the kill operation.
If the Invading fluid cannot be Incorporated Into the mud easily (such as
small amounts of saltwater or oil), the kick fluid physically must be
removed from the mud system. Gas Is processed through a mud-gas
separator and degasser, and flared. Large volumes of oil and water can
be routed away from the active circulating system and disposed of
carefully.
L:11 Tertiary Control
Tertiary Control Is the proper use of equipment and techniques to regain
control after a blowout has occurred. The blowout can be a surface or
underground blowout. In either case, control of the well has been lost.
If the casing and at least part of the wellhead equipment are still
Intact, a blowout at the surface Is generally capped. Otherwise, a
rellef wel I must be drilled. A relief well Is directionally drilled. In
an attempt to establish communications with the blowout. This can be
quite difficult If multlshot surveys are not available. Once the relief
well Is close to the flowing wellbore, thousands of barrels of water
usually are pumped to establish communications and "load" the hole. The
water Is followed by heavy mud and later by cement, If necessary.
L - 5
-------
Underground blowouts are also usually controlled by relief wells. In
some situations, however, the well can be killed by pumping heavy mud
down the drill pipe at a relatively high rate. Once well control has
been attained, a liner can be set and cemented across the loss zone.
L - 6
-------
REFERENCES APPENDIX L
IADC, "Blowout Prevention," Lessons In Rotary Drilling. Unit III, Lesson 3.
Petroleum Extension Service, University of Texas, Austin.
Zamora, Mario and KImball, Mike, "New CBHP Method Solves Kick-Control
Problems." Oil and Gas Journal. March 6, 1978.
Hamby, T.W. and Smith, J.R. "Contingency Planning for Drilling and Producing
High Pressure, Sour Gas Wells," SPE 2512, 1971.
Nelson, R.F., "The Bay Marchand Fire." Journal of Petroleum Technology, March,
1972. .
L - 7
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APPENDIX
INSPECTIONS CHECK LIST
-------
APPENDIX M
ADDITIONAL INSPECTION CHECKLISTS
-------
INSPECTIONS CHECK LIST
Date of Inspection
/ / Date of last Inspection
DESCRIPTION OF CORROSION PREVENTION/MONITORING SYSTEM:
Corrosion loop
Weight Loss Coupons
Electrical Resistance Probes
Polarization Resistance Probes
Logs-Type
Cathodlc Protection
Soil Potential Survey
Other (please describe)
DATE OF LAST CORROSION EVALUATION BY OPERATOR:
Type
Visual
Other
(describe briefly)
RESULTS
OK
Corrosion of:
Casing; depth
Tubing; depth
Packer
M -
-------
INSPECTIONS CHECK LIST (continued)
Other (Indicate component)
Injection fluid released YES
Contaminated USDW YES
CASING MATERIAL
Steel
Stainless Steel
Monel
Titanium
Other; specify
NO
NO
TUB I
NG MATERIAL
Steel
Stainless Steel
Fibercast
Fiberglass
Other
PACKER TYPE AND MATERIAL
Tension
Compression
Material: Steel
Other
, specify
Special protection (please Indicate). Note that some packers, especially
tension packers, have rubber pads or special coatings to prevent contact
with Injection fluIds .
M - 2
-------
WASTE CHARACTERISTICS
PH =
Dissolved oxygen (concentration) mg/l
Hydrogen SulfIde, H2S (concentration) mg/l
Carbon Dioxide, CC>2 (concentration) mg/l
Amenable to biological degradation
Acidic
Basic
Most recent sample analysis (attached) Indicates no significant changes
EVALUATION OF THE CASING/TUBING/PACKER MATERIALS TO RESIST CORROSION
(By consulting the tables In page of the manual a preliminary
evaluation can be made. The Inspector may also use different criteria for
evaluation; however, he/she should Indicate the reason for the decision.)
Adequate
Inadequate
Criteria used:
M - 3
-------
PRESSURE GAUGE INSPECTION CHECKLIST
Pressure Gauges
Yes No N/A
1. Is Bourdon tube gauge protected from corrosion
and freezing?
2. Is pressure reading relatively constant?
(absence of rapid pointer movement due to
pulsating pressure or pipeline vibration)
3. Are gauge materials suitable for the media
monitored?
4. Is a pressure transducer properly Installed?
5. Date gauge last calibrated:
6. Method of calIbratlon:
Pressure Recorders
1. Are pressure recorders properly Installed?
(e.g., chart protected from weather, etc.)
2. Are pressure recorders operational?
(e.g., Ink, charts moving, etc.)
3. Is back-up gauge provided?
4. Do back-up pressure and recorded
pressure agree?
M - 4
-------
ROW >ASUREMENT INSPECTION CHECKLIST
A. flow Measurement Inspection Checklist - General
Yes No N/A (a) Primary flow measuring device Is properly
Installed and maintained.
Yes No N/A (b) Is there a straight length of pipe before and
after the flowmeter of at least.5 to 20
diameters? This depends on the type of
flowmeter and the raflo'of pipe diameter to.
throat diameter. Also, the Introduction of
straightening vanes may reduce this requirement.
Yes No N/A (c) If a magnetic flowmeter Is used, check for
electric noise In Its proximity and that the
unit Is properly grounded.
Yes No N/A (d) Is the full pipe requirement met.
Yes No N/A 2. Flow records are properly kept.
(a) Records of flow measurement are recorded In a
bound numbered log book.
Yes No N/A (b) All charts are maintained In a file.
Yes No N/A (c) All calibration data Is entered In the log book.
Yes No N/A 3. Sharp drops or Increases In flow values are accounted
for.
Yes No N/A 4. Actual flow Is measured.
Yes No N/A 5. Secondary Instruments (totalizers, records, etc.) are
properly operated and maintained.
Yes No N/A 6. Appropriate spare parts are stocked.
Electrical noise can sometimes be detected by erratic operation of the
flowmeter's output. Another Indication Is the flowmeter location In the
proximity of large motors, power lines, welding machines, and other high
electrical field generating devices.
B. Flow Measurement Inspection Checklist.
1. Type of flowmeter used:
2. Note on diagram flowmeter placement In the system.
Observe the direction of -flow, the vertical- height
relationship of the source, outfall, and measuring
meter. Give a I I dimensions In pipe diameters.
M - 5
-------
3. Is meter Installed correctly?
(a) If magnetic flowmeter, It should be Installed In
an ascending column, to reduce air bubbles and assure
fulI pipe flow.
(b) If differential pressure meter such as venturl,
It should 'be Installed In a horizontal plane so that
high pressure tap Is on the inlet of flow and taps
are horizontal sloping slightly downward with
facilities for cleaning taps.
4. Flow range to be measured:.
Yes No N/A 5. Flow measurement equipment adequate to handle
expected ranges of flow values.
6. What are the most common problems that the operator
has had with the flowmeter?
7. Flowmeter flow rate: mgd; Totalizer flow
rate: mgd; Error %
8. Permit project flow:
Yes No N/A 9. Flow totalIzer Is properly calibrated.
10. Frequency of routine Inspection by trained Operator
/month.
11. Frequency of maintenance Inspections by facility
personnel: /year.
12. Frequency of flowmeter calibration:
M - 6
-------
13. Indicator of correct operation:
redundant flowmeters auxiliary flowmeters_
pressure readings other
power usage of pumps
14. Indicators of proper Qua IIty Assurance:
redundant flowmeters frequent calibrations.
oth er
M - 7
-------
APPENDIX N
INSPECTION REPORT FORMS
-------
APPENDIX N
INSPECTION REPORT FORMS
-------
APPQDIX N
INSPECTION KJfitOKT FQFMS
Engineering Enterprises, Inc. recommends the form on the following page
for recording mechanical integrity test (MIT) data when running the standard
annulus pressure test. As alternative MIT are approved by the Director of the
Office of Drinking Water, forms will need to be developed to ensure
documentation appropriate for the particular MIT.
Two additional forms follow: a Class I inspection form that has been
well received; and a form for field verification of well files. EEI does riot
recommend conducting file reviews for the UIC Federal Reporting System-
commitments in the field; however, field review of files can be a valuable
addition to site inspections by providing confirmation of information contained
in the EPA Regional files.
N - 1
-------
UIC MECHANICAL INTEGRITY TEST
WELL IDENTIFICATION
Owner/ Operator :
Address:
City: State: Zip:
Primary Contact:
Phone: ( )
Facility No. :
State: T ;R
County: Qtr Sec:
Well/Unit: No.
Field:
Type: EOR. SWD. Other.
State Permit No. :
Federal Permit No. :
Inspection/Test Date:
HELL LOCATION
;Sec . 'from . line.
& 'from line.
HELL/TEST DATA
Type of Test: Shut-in. Injected Fluid:_
Injecting. Annulus Fluid:
SG:
SG:~
Injection Formations:
Perforated Intervals:
Tub ing: '
Injection Rate(BPD):
Injection Pressure(PSI):
Packer Type:_
Set at:"
@
Casing:
RESULTS:
TIME
PRESSURE (PSIG)
ANNDLUS TUBING
TEST PRESSURE:
PSI
Max. Allowable Pressure Change:
Test Pressure z .03
Half Hour Pressure Change_
PSI
PSI
TEST PASSED TEST FAILED . (CHECK ONE)
IF FAILED. NO INJECTION MAY OCCUR UNTIL CORRECTIONS HAVE BEEN MADE AND WELL PASSES.
.SIGNATURE OF COMPANY REPRESENTATIVE
SIGNATURE 0? EPA REPRESENTATIVE
DATE
DATE
1 of 1
-------
4-ia-as
UIC FILE REVIEW
ADDRESS
LEASE MAJ£E -
FILE IDENTIFICATION-
f-l SINGLE TELL,
LJ 03 t BELOW
DAREA REvnrw
LOT ATTACHED
KYS
STATE PERMIT NO.
POOL
FNL . FEL.
m. ~ f WL
TTATT WAU*/cnnr
1 COUNTY
rr./a
TN.A7 (circU oo«)
COUNTY
rnnr
WELL COMPLETION
DEPTH
TO TOP
Or CEUENT
CASING
STWNC
Sort»c«
Iat*rta«dl«l*
ProducUoo
Tubing
.(ft
CASING
DUUCTTR
(Inch**)
CEMENT
SHOE
DEPTH
CTUENT
VDLUWE
PEBTORATZD
orrravALS
CONriKlNG
TOP ELEVATION
THICKNESS
(usy
-(ft)
LOWERUOST
USDW
DfJECnON
roRUAnoM
FORMATION
TOP ELEVATION
PEHMEASIUTT.
L«
-(Prt)
.(£«)
FILE EVALUATION
i EACH WELL a COUPLCTED WTO A coNnNm
.NON-USD* FORMATION ?
2 EACH WELL CS DESIGNED FDR UVECim USE ?
q EACH WEU. S CASED AND CrUENTTD TO PREVENT
0 UOVEUENT op fT-UTD INTO OR 3ETTECN USOW« t
4 EACH 'ftlL IS OPERATED AT AN APPROPRUTZ
4 PR£b-3UR£. ANO WTTH AOEQUATE CONTROLS.
TO PREVEJiT nUCTURING Of THE CONTTNING ZONE 7
A PLUGGING AND ABANDONUENT PLAN HAS SEEN
SUbiOTTEO FOR EACH WELL ?
OPERATOR UACTACO APPROPRUTZ nNANCLU.
i_>SSU1UNCE ?
HOT Df COUPTUNTT
(Ust of will «a4 rpiuaaCtaa
WELLS NOT 01 COMPLUNCZ
(Uit of mi
' WELLS NOT 01 COMPLIANCE
(Ust of v«Ua *o4 xpUaatloa «lUci*d)
WZLL3 NOT W COtmiANCZ
(list of w*llM mad «zpUa>tioa
_ . WELLS NOT a COMPUANCE
(U»t at ««Us «nd «rpUn«tWm
(Uat of v«
WELLS NOT B»
EACH
AS
a yOVTrORED AND REPORTED
(2
WELLS NOT Ot COUPUANCE
of «*Ui «a«
-------
4-0-43 3bMl
UIC - FILE REVIEW/MIT
WELL IDENTIFICATION-
OPERA70B _^. ncnjTT NO.
LZLL3I M1UZ-NO. . POOU
EXTERNAL MIT - CEMENT CALCULATIONS
7OB 3UBT1CX C13ING 1 j fOB DrTCUODUTI AND PRODUCTION CJLSHC
CA3WC DLL _ (la.) BOUt DLL. _ (la.) CJ3WC DU. - : - (la.) HOLX DU. _ (la.)
AWMULAB vouna - (c».n./n.) CILCUUIXD AWHUUJI vouna _ (c
YUXD PTB liCX - (ca.ft.) CnflOfT TOLD PES SJtfX _ (ea.ft.)
uaxa _ CIMBIT vouna _ (ca.n.) siacs USZD __ cnmrr vouna _ (cw.n.)
orpra-rop or cnaxrtvzox IOM) _ (it) Dtpra-Top or cnaNT(w/2ox iou) _ __ (n)
COMMENTS
-------
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
REGION V
CLASS I INSPECTION REPORT
STREET: STATE PERMIT No:
COUNTY: WELL NAME & No:
CITY/ST/ZIP: TYPE OF WELL: HAZARDOUS / NONHAZARDOUS
INSPECTION DATE: TIME OF INSPECTION:
TYPE OF INSPECTION: ROUTINE / MIT / COMPLAINT / COMPLIANCE / PERMIT
NAME(S) OF PERSON(S) UIC INSPECTOR MET WITH DURING INSPECTION:
NAME TITLE PHONE No.
A. INJECTION WELL INFORMATION
INJECTION PRESSURE: (psig) ANNULUS PRESSURE:_____(psig) RATE:_
AVERAGE DAILY VOLUME: INJECTION FLUID TEMPERATURE: ; (°F)
1. IS THERE DOCUMENTATION OF GAUGE CALIBRATION: . . *Q YES |~| NO
*DATE OF CALIBRATION:
2. IS INJECTION RATE AND VOLUME: { MEASURED OR ESTIMATED ) ?
3. DOES THE TYPE OF INJECTION FLUID FLUCTUATE.: |~| YES |~| NO .
4. WHAT TYPE 4 SPECIFIC GRAVITY FLUID IS IN THE ANNULUS:
5. WHAT IS THE SPECIFIC GRAVITY OF THE INJECTION FLUID:
-------
WELL INFORMATION CONTINUED
6. LOCATION OF PERFORATIONS AND/OR OPEN HOLE:
7. TYPE AND MODEL OF PACKER:(TENSION/COMPRESSION/NEUTRAL/OTHER [PLEASE SPECIFY BELOW]):
PACKER TYPE: MODEL: v.
(ft) . ___(ft)
/ AUTOMATIC / COMPUTER
8. WHAT IS THE SETTING DEPTH OF THE PACKER:_ii_i
9. HOW IS INJECTION PRESSURE RECORDED: MANUAL
10. HOW IS ANNULUS PRESSURE RECORDED: MANUAL
11. IS FLUID TEMPERATURE RECORDED:
12. IS ANNULUS FLUID VOLUME RECORDED: |~| YES
WELL INFORMATION COMMENT SECTION
AUTOMATIC
/ AUTOMATIC / COMPUTER
O YES ' HI N0
PI NO
B. ANNULUS PRESSURE MAINTENANCE SYSTEM
1. IS ANN. PRES. CONTINUOUSLY MAINTAINED IN ACCORDANCE WITH PERMIT: |~| YES |~| NO
2. IS ANNULUS PRESSURE REQUIRED TO''3E GREATER THAN INJECTION PRESS.: |~| YES |~| NO
3. IS ANNULUS PRESSURE CONTINUOUSLY -GREATER THAN INJECTION PRESSURE: |j YES Q NO
4. HOW IS ANNULUS PRESSURIZED: POSITIVE -DISPLACEMENT PUMP / NITROGEN / OTHER
5. IS ANNULUS FLUID VOLUME-CONTINUOUSLY MONITORED/RECORDED BY OPERATOR: |~| YES |~| NO
6. HAS OPERATOR RECEIVED TRAINING ON WELL OPERATION |~| YES |~| NO
MAINTENANCE-SYStrH COMMENT SECTION
-------
C.-ALARM SYSTEM
, f
1. IS INJECTION WELL ALARM SYSTEM'OPERABLE: " |~| YES Q NO
2. WHAT TYPE OF ALARM "SYSTEM-IS UTILIZED:' ' MANUAL SYSTEM / AUTOMATIC SYSTEM
3. HAS ALARM SYSTEM BEEN TESTED BY A UTC INSPECTOR Q YES ~| NO
4. ON WHAT FREQUENCY IS ALARM SYSTEM TESTED:
5. IS ALARM TRIGGERED BY HIGH PRESSURE |~| YES |~| NO , LOW PRESSURE Q YES |~| NO
LOW PRESSURE DIFFERENTIAL |~| YES |~| NO , OTHER' |~| YES |~| NO
6. IS THERE A TIME DELAY BEFORE ALARM SOUNDS TO ACCOUNT FOR START - UPS |~| YES Q NO
7. IS OPERATOR ON SITE 24 HOURS PER DAY TO RESPOND TO FAILURES: |~| YES |~| NO
-AtARM SYSTEM" COMMENT SECTION -
. . . . -, .D. TESTING ,.
. . " I"', "^^^"~ ' . . ,1
1. WAS A MECHANICAL INTEGRITY TEST CONDUCTED AT-THIS INSPECTION: |~] YES |~| NO
2. WAS A START-UP TEST CONDUCTED AT THIS INSPECTION:. ,, , Q YES Q NO
TESTING COMMENT SECTION
* IF TESTING IS CONDUCTED AT THIS INSPECTION PLEASE ATTACH A COPY OF THE TEST REPORT.
-------
E. OVERALL INSPECTION COMMENTS
INSPECTORS NAME "~~~~ INSPECTOftS SlfiNATuftE
* INSPECTOR IS: ( CONTRACTOR / EPA EMPLOYEE ).
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