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1 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
°1 REGION 8
PRO'_° 999 18TH STREET - SUITE 300_
DENVER, CO 80202-2466
Phone 800-227-8917
http://www.epa.govIregion08
JAN 2 2 2003
Ref: 8P-W-GW
CERTIFIED MAIL
RETURN RECEIPT REQUESTED
Mr. Kevin P. Kauffman
President
Kauffman Well Services, Inc.
1675 Broadway, Suite 2800
Denver, Colorado 80202-4628 -
RE: UNDERGROUND INJECTION CONTROL (UIC)
Final Permit, Wattenberg Disposal, LLC., Suckla
Farms #1: CO10938-02115; Sec. 10 - T1N - R67W,
6`h PM Weld County, Colorado.
Dear Mr. Kauffman:
Enclosed is a Final Underground Injection Control (UIC) Permit for the renewal of
authorization for the Class I non-hazardous injection well Suckla Farms #1, Weld County,
Colorado. The Final Statement of Basis, which discusses development of the Permit, is also
enclosed.
The Public notice appeared in the Sunday Denver Post on October 20, 2002, and in the
Fort Morgan Times on October 19, 2002. A notice of our intent to issue a Permit was also sent
to interested parties, and to the surface landowners who may be affected by the proposed action.
The public comment period ended on November 21, 2002 and no comments were received.
A decision has been made to issue the Permit for the Suckla Farms No. 1 (CO10938-
02115). There have been some minor changes in the language to provide EPA and Wattenberg
Disposal some flexibility in running the required pressure falloff test. One of these changes was
to shift the date of the test into the spring time to reduce the possibility of cold weather affecting
test results. The test is now required to take place prior to May 151. The initial pressure falloff
test required under this new Permit will be prior to May I, 2004.
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Page 1 of 3
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As there were no comments regarding the draft Permit and only minor changes from the
draft to the Final Permit, there is no thirty day waiting period required. The enclosed document
is a signed original of the Final Permit and a copy of the Final Statement of Basis. The Permit is
effective as of the date of the signature on the Permit.
Your previous Class I non-hazardous injection well Permit for the Suckla Farms #1 is no
longer in force and the Suckla Farms No. 1 is now under the conditions of the new Final Permit.
As of this approval, responsibility for Permit compliance and enforcement is transferred to the
Region VIII UIC Technical Enforcement Program office. Therefore, please direct all future
notification, reporting, monitoring and compliance correspondence to the following address,
referencing your well and the new UIC Permit number on all correspondence regarding this well.
Technical Enforcement Program -UIC
U.S. EPA Region VIII, Mail Code 8ENF-T
999 18th Street, Suite 300
Denver, Colorado 80202-2466
You may contact Paul S. Osborne at (303) 312-6125, if there are any questions regarding
this Permit action. For questions regarding notification, testing, monitoring, reporting or other
Permit requirements for the Suckla Farms No. 1, the UIC Technical Enforcement Program may
be reached by calling (800) 227-8917. You may also call Nathan Wiser at 303-312-6211, or Ken
Phillips at 303-312-6125. Thank you for your continued cooperation.
'ncerely,L. :(A/
Ste en S. Tubber
Acting Assistant Regional Administrator
Office of Partnerships and
Regulatory Assistance
Enclosures: Final Permit
Final Statement of Basis
cc: Mr. Robert EU Smith, OGWDW
Weld County Commissioners
Mr. Ed DiMatteo, COGCC
Colorado State Engineer's Office
Attn: Mr. George Van Slyke
Page 2 of 3
Mr. Douglas M. Ikenberry, P.E.
__Colorado Department of
Public Health and Environment
HMWMD-B2
4300 Cherry Creek Drive South
Denver, CO 80246
Ms. Cindi Etcheverry,
Weld County Health Dept.
1515 N. 17th
Greeley, Colorado 80631
Page 3 of 3
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AS kt , UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
REGION 8
Pao 999 18Th STREET - SUITE 300 -
DENVER, CO 80202-2466
Phone 800-227-8917
http:llwww.epa.govl region08
Ref: 8P-W-GW
FINAL STATEMENT OF BASIS
SUCKLA FARMS #1, CLASS I DISPOSAL WELL
WATTENBERG DISPOSAL, LLC
COMMERCIAL NON-HAZARDOUS
CLASS I DISPOSAL FACILITY
WELD COUNTY, COLORADO
EPA PERMIT NUMBER: CO10938-02115
CONTACT: Mr. Paul S. Osborne (8P-W-GW)
U.S. Environmental Protection Agency
999 18th Street, Suite 300
Denver, Colorado 80202-2466
Telephone: (303) 312-6125
COMPANY: Mr. Kent Gilbert
Senior Vice President, E&P
Wattenberg Disposal LLC
K.P. Kauffman Company, Inc.
1675 Broadway, Suite 2800
Denver, Colorado 80202-4628
DESCRIPTION OF FACILITY AND BACKGROUND INFORMATION:
On March 7, 2002, EPA received an application from Wattenberg Disposal LLC. for a
new underground injection control (UIC) Class I non-hazardous Permit for the existing Suckla
Farms #1 Class I injection well located on private property in Weld County, Colorado. This well
was initially permitted as a Class I well on June 16, 1992, for a period of 10 years. The submittal
of a complete application prior to expiration of the Permit extends the existing Permit until
Statement of Basis for EPA Permit No. CO10938-02115
45 Printed on Recycled Paper
completion of the re-permitting process and the issuance of a final decision regarding a new Permit
(40 CFR 144.37). The applicant proposes to continue to inject a mixture of fluids produced from
oil and gas operations and non-hazardous industrial waste into the Lyons Formation between the
depths of 9,276 feet and 9,418 feet. The initial total dissolved solids (TDS) content of the Lyons
Formation was approximately 33,000 mg/liter and an aquifer exemption was not required.
This Permit application is for continued operation a Class I non-hazardous well for the
disposal of both produced water from oil and gas operations, including gas plants and methane
storage operations, and non-hazardous industrial fluids. The industrial fluids will consist of
reclaimed water associated with the removal of underground fuel storage tanks, pit water from oil
field wash pits, contaminated surface water from construction sites, and other non-hazardous
fluids. Fluids are anticipated to be from the Front Range area as far south as Pueblo, Colorado.
The average injection pressure is anticipated to be 900 pounds per square inch gauge (psig) with
average injection rate of around 1,700 barrels of water per day.(BWPD). The maximum injection
pressure will be limited to 3700 psig.
The top of the injection zone, the Lyons Formation, is located at a depth of about 9,139 feet
KB and extends to 9,424 feet KB. The perforated interval extends from 9,276 to 9,418 feet. The
Lyons is a massive crossbedded sandstone with fine to coarse grains. The Lyons Formation is
overlain by the Lykins Formation. The Harriman Shale comprises the bottom portion of the
Lykins and is composed of interbedded anhydrite, dolomite and red silty shale. The Lyons is
underlain by the Fountain Formation. The top of the Lyons is composed of fine grained quartz
sandstones, siltstones and maroon shales which act as a major confining unit.
The Suckla Farms injection well is located in a portion of the Spindle Field adjacent to
Weld County Road 19. The legal location is:
Class I Disposal Well Suckla Farms #1
SE 1/4 of the NW 1/4
500 feet from south line and 2020 feet from the west line
Section 10, Township 1 North - Range 67 West, 6ih PM.
Weld County, Colorado
The applicant has notified all surface landowners within one-quarter (1/4) mile of the
disposal well of their intent to re-apply for a new Class I Permit for this well.
Regional Geology and Stratigraphy:
The Suckla Farms #1 Class I disposal well is located about 25 miles North of Denver,
Colorado in the Denver-Julesburg Basin. The Denver-Julesberg Basin is a north-south trending
"trough" or asymmetrical Syncline. Strata which are exposed along the Front Range dip steeply
eastward. On the east flank of the Basin, the strata dip gently westward. The well is located
approximately 5 to 10 miles east of the axis of the Basin where the thickness of the sedimentary
section is near its maximum.
•
Statement of Basis for EPA Permit No. CO10938-02115 Page 2 of 17
The following tabulation summarizes the geologic formations encountered when the
Suckla Farms #1 was drilled. The depth to the top of the Formation is provided when known.
Geologic Formation Depth to Top USDW
Arapahoe Formation Yes
Laramie Formation Yes
Fox Hills Formation Yes
Pierre Shale 700 ft. Major confining unit
Niobrara Shale 7,362 ft. No
Codell 7,694 ft. No
J Sand 8,133 ft. No
Dakota Sandstone 8,281 ft. No
Lakota Sandstone 8,368 ft. No
Morrison Formation 8,404 ft. No-confining zone
Entrada 8,562 ft. No
Harriman Shale 9,069 ft. No-confining zone
Lyons Formation 9,139 ft. No
Lyons Sandstone Injection Interval 9,288 ft. No
Hydrogeology:
Underground sources of drinking water (USDWs) are defined in 40 CFR § 144.3 as:
(1) an aquifer or its portion;
(i) which supplies any public water system; or
(ii) which contains a sufficient quantity of
groundwater to supply a public water system; and
(A) currently supplies drinking water for human consumption; or
(B) contains fewer than 10,000 mg/1 total dissolved solids; and
(2) ' which is not an exempt aquifer.
In this area, the principal aquifers used for public and domestic and other uses are the
Arapahoe Formation and the Laramie-Foxhills aquifer system. These major USDWs overlie the
Pierre Shale, which is a major confining unit in the basin, and is approximately 6,600 feet thick.
The Pierre is principally a dark gray marine shale, but sand lenses, such as the Hygiene sand and
the Wellington sand do occur in places.
The Hygiene and the Wellington sands often contain water with a quality and quantity
sufficient to be defined as a USDW. All the formations underlying the Pierre are not USDWs
because they contain water with a TDS of greater than 10,000 mg/liter. The injected interval, prior
to injection, contained water with a TDS of about 33,000 mg/liter.
The upper confining zone is the Harriman Shale which comprises the bottom portion of
the Lykins Formation. The Harriman Shale is composed of interbedded anhydrite, dolomite and
Statement of Basis for EPA Permit No. CO10938-02115 Page 3 of 17
red silty shale. Additionally, the top of the Lyons Formation at 9,139 feet is composed of fine
grained quartz sandstones, siltstones and maroon shales which also act as a confining unit.
Injection Zone: The injection zone is the sandstone unit encountered at about 9,276 feet.
The Lyons Sandstone is a massive crossbedded sandstone with fine to coarse grains with some
cementing. The perforated interval of the Lyons is from 9,276 feet to 9,418 feet.
As indicated above, the disposal of oil field related fluids and non-hazardous fluids will be
into the Lyons Sandstone. The Suckla Farms #1 was sampled and analyzed prior to conversion to
a Class I injection well and the reservoir fluid contained about 33,000 mg/liter total dissolved
solids (TDS).
Wattenberg Disposal, LLC has submitted all required information and data necessary for
permit issuance in accordance with 40 CFR Parts 124, 144, 146, and 147, and a draft permit has
been prepared. The permit will be issued for a period of ten (10)years; no reapplication will be
necessary during this period, unless the permit is terminated for reasonable cause (40 CFR 144.39,
144.40 and 144.41). However, the permit will be reviewed after five years of operation, and the
results of the review will be used to determine if changes in the permit are needed.
This Statement of Basis (SOB) gives the derivation of the site-specific permit conditions
and reasons for them. The referenced sections and conditions correspond to the sections and
conditions in EPA Permit CO10938-02115. The general permit conditions for which the content
is mandatory and not subject to site specific differences (based on 40 CFR Parts 124, 144, 146 and
147), are not included in the discussion.
Part II, Section A WELL CONSTRUCTION REQUIREMENTS
Casing and Cementing (Condition 1)
All casing and cementing details were submitted with the Permit Application and are
incorporated into this Permit as part of Appendix A which graphically displays the details of the
injection well under consideration:
(a) SURFACE CASING (8-5/8 inch) is set in a 12-1/4 inch diameter hole to a depth
of 759 feet Kelly Bushing (KB) into the Pierre Shale confining zone. The casing is
secured with cement which has been circulated to the surface isolating the casing
from the wellbore.
(b) LONG STRING CASING (5-1/2 inch) has been set in a 7-7/8 inch diameter hole
to a depth of approximately 9,557 feet KB and cemented from TD to approximately
8,398 feet KB. An EPA review of the original cement bond log indicates that there
is good cement bonding over that zone. There is approximately 875 feet of very
good cementing above the perforations through the adjacent confining zone. The
well bonded cement extends through the Morrison Formation which is also an
Statement of Basis for EPA Permit No. CO10938-02115 Page 4 of 17
excellent confining unit (composed of black, red and green shales, with a few beds
of limestone, sandstone and anhydrite).
(c) Tubing and packer: Approximately 9,240 feet of 2-7/8 inch tubing is presently set
in the well with the packer being located about 36 feet from the uppermost
perforation at 9,276 feet KB.
Tubing and Packer Specifications (Condition 2)
All Class I injection wells, except those municipal wells injecting non-corrosive wastes,
shall inject fluids through tubing with a packer set immediately above the injection zone, or tubing
with an approved fluid seal as an alternative (40 CFR § 146.12 (c)). The Permit for the Suckla
Farms #1 does not specify the size or type of tubing, but requires that the tubing/packer be set no
higher than 300 feet above the top of the perforations. The packer is presently set at 9,014, 262
feet above the perforations. This height was required because of''slick" casing from 9014 to TD
making it impossible to set the packer. This tubing and packer must be of sufficient quality and
strength to be compatible with the injection fluid and pressure.
Monitoring Devices (Condition 3)
The Permit establishes that the primary method of monitoring is continuous pressure
monitoring of the injection and casing tubing annulus pressure and continuous monitoring
of the injection rate and volume; these devices shall be operated and maintained as long as the
Permit is in effect. The instrumentation must have a sampling capability sufficient to create a
continuous record. In addition, it is necessary to have a mechanism to access the wellhead and
injection line to obtain manual measurements of injection and annulus pressure and samples of the
injection fluid. The fluid sampling point must be in the line that takes the fluid from the holding
tanks, but the location should be prior to entering the injection pump system. The injection
pressure monitoring point must be down gradient of the injection pump in an unobstructed portion
of the injection line immediately adjacent to the wellhead. Both the injection pressure and annulus
pressure points must be installed so that valid manual measurements can be taken as a means of
verifying the continuous monitoring.
Prior to beginning Class I non-hazardous injection operation, the operator shall install and
maintain in good operating condition the following equipment:
(a) Injection pressure: a continuous pressure monitoring device in the 2-7/8
high temperature-coated tubing at the wellhead connected to an instrument
such as a continuous chart recorder with a resolution of at least 5 psi or a
digital recorder with a sampling frequency of at least every 30 seconds and a
one-half(V2) inch Female Iron Pipe (1,1P) fitting, isolated by plug or globe
valves and located on the tubing to allow attachment of one-half(1/2) inch
Male Iron Pipe (MIP)pressure gauges or the attachments for equivalent
"quick-disconnect" pressure gauges certified for ninety-five (95) percent
Statement of Basis for EPA Permit No. CO10938-02115 Page 5 of 17
accuracy, or better, throughout the range of permitted operation in order to
verify values for injection pressure being recorded from the continuous
monitoring device.
(b) Wellhead pressure of the tubing/casing annular space: a continuous
pressure monitoring device in the wellhead casing/tubing annulus that is
connected to a device such as a continuous chart recorder with a resolution
of at least 5 psi or a digital recording system with a sampling frequency of at
least every 30 seconds and a one-half(1/2) inch Female Iron Pipe (FP)
fittings, isolated by plug or globe valves, and located on the tubing/casing
annulus; and the above fittings will be positioned to allow attachment of
one-half(1/2) inch Male Iron Pipe (MIP) pressure gauges or the attachments
for equivalent "quick-disconnect" pressure gauges certified for ninety-five
(95) percent accuracy, or better, throughout the range of permitted operation
in order to monitor the annulus fluid pressures and provide verification of
the accuracy of the continuous monitoring device.
The tubing/casing annulus must be maintained full of either fresh water
treated with a non-toxic corrosion inhibitor or other packer fluid as
approved, in writing, by the Director. This fluid must be maintained under
a positive pressure. A diesel freeze blanket or other fluid as approved, in
writing, by the Director may be circulated from surface to below frost level
at completion to prevent freezing and possible equipment failure during
winter months.
(c) Because the well will be operating under reasonably high pressures, the
continuous monitoring system must have an automatic well shut down
switch (such as a Murphy switch) installed based on the following
parameters:
(i) The surface injection (tubing) pressure shall be maintained at
pressures below 3700 psi. Any operation that exceeds this pressure
should trigger an immediate shut down of the injection pumps. EPA
recommends this trigger be set slightly less than the MAIP in order
to lessen the potential for a violation of the Permit pressure
limitations; and
(ii) Because the annulus fluid pressure will vary as a result of fluctuation
in the injectate temperature, the tubing/casing annulus pressure may
not stay at a fixed value. The Permit establishes and operating range
to allow for natural fluctuation. The tubing/casing annulus pressure
should be maintained between 100 and 200 psi. A Murphy switch or
other automatic shut down device is required on the annulus to
assure that any operation outside of this range will result in an
Statement of Basis for EPA Permit No. CO10938-02115 Page 6 of 17
immediate shut down of the injection pumps. When adjusting this
annulus fluid pressure, the operator should use the target value of
150 psi.
(d) Magnetic or turbine flow meters, and continuous recording devices, such
as a continuous chart recorder with an accuracy of 5 barrels per day or a
digital recording system with a sampling frequency of at least every 30
seconds must be installed in the injection line immediately upstream of the
wellhead to track and document disposal fluid flow rates, and total fluid
volumes.
For a given injection rate, the injection pressure should remain relatively
constant. Input flow volumes will be cross checked against injection
pressure records to identify any possible divergence in the injection pressure
for a given flow rate. A drop in injection pressure without a corresponding
reduction in input flow rate may indicate a possible casing, packer, or other
failure.
(e) Fluid analysis: the injection line must be equipped with sampling ports and
appropriate connections to facilitate periodic collection of fluid samples
representative of the injection fluids for chemical analysis. The sampling
point must be in an unobstructed portion of the injection line down stream
from the tanks but prior to the injection pumps.
Proposed Changes and Workovers (Condition 4)
The permittee is required to give notice as soon as possible to the Director in advance of
any planned physical alterations or additions to the permitted well. Major alterations or workovers
of the permitted well must meet all conditions as set forth in this permit. A major
alteration/workover is considered to be any work performed, which affects casing, packer(s), or
tubing.
The permittee must provide all records of well workovers, logging, or other test data to
EPA as part of the quarterly report for the period in which the activity was completed. Appendix
B contains samples of the appropriate reporting forms. After any workover that involves remedial
cementing of the casing, the operator shall run a new cement bond log (with a gamma ray, travel
time curve, casing collar locator, amplitude curve, and variable density log) that covers the area of
the cementing to verify the adequacy of the cement placement. This log will be run following the
guidelines in Appendix D.
Demonstration of mechanical integrity(tubing/casing annulus pressure test) must be
performed within thirty (30) days of completion of workovers/alterations and prior to resuming
injection activities, in accordance with Part II, Section C, Condition 2.
Statement of Basis for EPA Permit No. CO10938-02115 Page 7 of 17
Logging and Well Testing Specifications. - (Condition 5)
Based on the construction and cementing details of the disposal well, all known and
possible USDWs are adequately protected behind the cemented surface and long string casings.
The existing cement bond log on the well indicates good bonding from TD to 8,398 feet on the
long string and the surface casing was cemented by circulating cement to the surface. If there is a
major workover of the well that involves remedial cementing, the operator must run a new
cement bond log (with a gamma ray, travel time curve, casing collar locator, amplitude curve, and
variable density log) that covers the area of the cementing to verify the adequacy of the cement
placement. This log will be run following the guidelines in Appendix D. The Permit requires the
operator to provide EPA, at least two days, advance notice of any planned well tests or logs. This
notice should include a written plan for the proposed activity.
Although the construction and cementing details of the disposal well indicate that all
known and possible USDWs are adequately protected behind the cemented portion of the surface
and long string casings, either a temperature log or a radioactive tracer log will be required at
least every five years to verify that there continues to be no flow adjacent to the casing. This will
ensure confinement of fluids in the injection zone. If necessary to demonstrate no flow adjacent to
the casing, the Permit provides that the Director may request that additional logs be conducted. In
addition, the operator must run a pressure tubing annulus test at least once every five years to
demonstrate mechanical integrity of the casing, tubing and packer.
In addition to the mechanical integrity test requirements, the operator must run a pressure
fall-off test. The pressure fall-off test is required for Class I operations [40 CFR § 146.13 (d) (1)]
and must be performed at least once every twelve months for the purpose of monitoring
pressure buildup in the injection zone in order to detect any significant loss of fluids due to
fracturing in the injection and/or confining zone, and to aid in determining the lateral extent of the
injection plume. The initial yearly test must be run in April 2004.
The Permit requires that the operator prepare a plan for running the yearly falloff test.
Appendix I contains a guideline for conducting pressure falloff tests that was developed by EPA
Region VI for use in developing a site specific plan. This Guideline provides a great deal of detail
as to the specifics of running and analyzing a pressure falloff test. The Guideline should be used
by the operator for development of their site specific test plan. This plan must be submitted to
EPA at least 30 days prior to the running of the test.
The pressure fall-off test involves injecting fluid at a constant rate for at least
twenty-four (24) hours, or a sufficient period of time (which-ever is greater) until
the reservoir pressure reaches stability (radial flow conditions, as determined by a
field evaluation of the raw data), followed by a shut-in period of sufficient duration
to establish a valid observation of a pressure fall-off curve. This test shall be
considered complete when the pressure curve becomes asymptoic to a horizontal
line as the reservoir reaches ambient pressure. The initial pressure buildup must be
performed with both a downhole quartz pressure gauge with an accuracy of 0.01 psi
Statement of Basis for EPA Permit No. CO10938-02115 Page 8 of 17
and a surface monitoring system using gages of the same type and accuracy. Any
subsequent falloff tests must utilize surface monitoring with quartz gages at, at a
minimum. The Director may require that subsequent tests be conducted with a
downhole quartz gage if deemed necessary. It is important that the initial and
subsequent tests follow the same test procedure, so that valid comparisons of
reservoir pressure, permeability, and porosity can be made. The permittee shall
analyze test results and provide an annual report which compares the results with
previous test data. Any pertinent logs must be accompanied with an
appropriate narrative interpretation by a knowledgeable log analyst.
PART II, Section B CORRECTIVE ACTION
There are no wells in the area of review that penetrate the injection zone. Although there
are no known penetrations of the injection zone within the area of review, pressure fall-off tests are
to be conducted in the injection well on an annual basis in order to monitor the pressure buildup in
the injection zone and help determine the lateral extent of the injection plume. In view of the
above, no corrective action by the permittee is considered necessary prior to the issuance of a
Class I Non-hazardous Permit.
PART II, Section C WELL OPERATION
Prior To Commencing Injection Condition 1)
Injection of any Class I nonhazardous fluids or Class II fluids into the Suckla Farms # 1 is
presently covered under the authority of the existing Permit. Upon approval of this new Permit,
continued injection into the Suckla Farnis # 1 is authorized subject to the conditions herein.
Mechanical Integrity (Condition 2)
To ensure the existing and continued mechanical integrity of the well, the operator must
run an initial mechanical integrity test of the injection well that demonstrates: 1) there are no
leaks in the tubing, casing and packer; and 2) there is no flow into or between USDWs
adjacent to the wellbore. The permittee must also demonstrate part I and part II of mechanical
integrity on a continuing basis by arranging and conducting a test, at least once every five years.
A tubing/casing annulus pressure test must be conducted to demonstrate Part I (no leaks in the
tubing, casing or packer) at the maximum injection pressure and either a temperature log or a
radioactive tracer survey(RATS) must be conducted to demonstrate Part II (no flow into or
between USDWs adjacent to the casing). Also an MIT is to be successfully conducted after
workovers (see Part II. A. 5.). Results of the test shall be submitted (on EPA form found in
Appendix B), with documentation, to the Director as soon as possible but no later than thirty (30)
days after the test is complete.
Test methods and criteria are to follow current UIC Guidance (Appendix G) for
Conducting a Pressure Test to Determine if a Well has leaks in the Tubing, Casing or
Statement of Basis for EPA Permit No. CO10938-02115 Page 9 of 17
Packer. The absence of any flow behind casing must also be demonstrated; this shall be
accomplished by performing either a temperature log, using the Guidance in Appendix E, or a
RATS, using the Guidance in Appendix F. -
The Permittee is required to notify the UIC Director at least two (2) weeks prior to any
required integrity test. The Director may allow a shorter notification period if it would be
sufficient to enable the EPA to witness the mechanical integrity test (MIT). Notification may be in
the form of a yearly or quarterly schedule of planned mechanical integrity tests or it may be on an
individual basis.
If the well fails to demonstrate mechanical integrity during a test, or a loss of mechanical
integrity as defined by 40 CFR § 146.8 becomes evident during operation, the permittee shall
notify the Director in accordance with Part III, Section E. 10. (c) of this permit. Furthermore,
injection activities shall be terminated immediately; and operations shall not be resumed until the
permittee has taken necessary actions to restore integrity to the well and the Director gives written
approval (see 40 CFR 122.51(g)(2)) to recommence injection.
Injection Interval (Condition 3)
The proposed injection zone is limited to the Lyons Sandstone. The actual top of the
Lyons is at 9,139 feet. The perforated interval of the Lyons is from 9,276 feet to 9,418 feet.
The injection zone is confined by a 70 foot interval of the Harriman Shale which underlies the
Entrada Formation at 9,069 feet, and is composed of interbedded anhydrite, dolomite and red silty
shale. Additionally, the top of the Lyons Formation is composed of highly cemented, fine grained
quartz sandstones, siltstones and maroon shales which also act as a confining unit.
Injection Pressure Limitation (Condition 4)
A valid step rate test was conducted on the Suckla Farms # 1 after the initial Class I Permit
was issued. Based on the instantaneous shut-in pressure from this test, a maximum surface
injection pressure of 3,700 pounds per square inch gauge (psig) has been established. If a
higher pressure is requested, it must be accompanied by a step-rate test (SRT) of the injection
zone, using fluid normally injected, to determine both the instantaneous shut-in pressure (ISIP) and
the formation breakdown pressure. A tracer survey or temperature survey may also be required to
demonstrate Part II of mechanical integrity at the higher pressures. The Director will determine
the allowable pressure modification based upon the test results and other parameters reflecting
actual injection operations.
The permittee shall give thirty (30) days advance notice to the Director if an increase in
injection pressure will be sought. Details of the proposed test shall be submitted at least seven (7)
days in advance of the proposed test date so that the Director has adequate time to review and
approve the test procedures. Results of all tests shall be submitted to the Director within ten (10)
days of the test. Any changes in the maximum injection pressure established under this section,
as dictated by the test results, may be made as a minor modification to the Permit.
Statement of Basis for EPA Permit No. CO10938-02115 Page 10 of 17
Injection Volume Limitation.
(Condition 5)
Although the injection reservoir contains fluids in excess of 10,000 mg/liter, Public
concerns (raised when the well was initially permitted) about long term inject led EPA to establish
a volume limitation. Cumulative injection volume of oil field produced water and non-hazardous
fluids will be limited to 8,300,000 barrels. This volume was calculated using the formula shown
below, which indicates the amount of fluid required to fill up the portion of the reservoir within a
1/4-mile radius around the injection well. This volume limitation may be modified during the five
year Permit review based on the results of future pressure falloff tests. These tests will be
analyzed to provide more reliable estimates of reservoir parameters.
V = ( rhn)/5.615
where,
V = maximum cumulative volume (bbl)
r= radial distance of 1/4-mile (ft)
h = height of injection zone available for fill up (ft)
n = porosity of injection zone (decimal percent)
5.615 = conversion factor
Calculation of the total, cumulative zone available for fillup by displacement (V) is
accomplished by substituting 1320 for"r", 142 feet for"h". and 0.20 for"n".
V = ( (1320) (142) (0.20))/5.615 = 8,301,706 barrels
The injection rate will not be limited,but in no instance may the injection pressure exceed
that listed in Part II, Section C, (Condition 4), above, or a pressure determined by subsequent step-
rate tests. When the maximum volume is reached, EPA will make a decision whether to extend
the limits of the injection zone, or to terminate the Permit.
Injection Fluid Limitation. (Condition 6)
Fluids injected into the Suckla Farms#1 shall be limited to produced oil field waste that
is produced at the surface, gas plant waste that is non-hazardous,waste water from methane
gas storage operations, or non-hazardous industrial waste water, as authorized under the
• provisions of the Class I Permit. A compendium of the sources that were approved over the last
ten years was submitted as part of the application for renewal of this Permit. This compendium
consists of 212 pages of source names and locations with a maximum of 44 sources per page. This
list of existing sources is incorporated into the Administrative Record of the Suckla Farms #1
Permit. Fluids from these sources may be accepted for disposal without prior notification to the
Director as long as the waste water meets the conditions of the Permit. The Permit establishes
conditions for approval of any new Class II fluid sources and any industrial sources. Injection of
any hazardous waste as identified by EPA under 40 CFR 261.3 is prohibited. The only
industrial fluids approved for injection are as follows:
Statement of Basis for EPA Permit No. CO10938-02115 Page 11 of 17
(a) reclaimed water associated with the removal of underground automotive, conventional
engine, or heating fuel storage tanks;
(b) pit water from field wash pits, if analyzed as non-hazardous;
(c) non-hazardous contaminated surface water from construction sites;
(d) stored fuels, if analyzed as non-hazardous; and
(e) non-hazardous industrial fluids that have been approved for disposal by the Director.
Annular Fluid (Condition 7)
Unless an alternative to a packer has been approved under 40 CFR § 146.12 (c), the
annulus between the tubing and the long string (5-1/2 inch) casing shall be filled with fresh
water treated with a corrosion inhibitor, or other packer fluid as approved, in writing, by the
UIC Director and maintained under a minimum positive pressure of 200 to 300 pounds per square
inch gauge (psig). A diesel freeze blanket of approximately one barrel may be placed on the
backside to prevent freezing and possible equipment failure.
PART II, Section D MONITORING, RECORDKEEPING AND
REPORTING OF RESULTS
Disposal Well Monitoring Program. (Condition 1)
EPA regulations (40 CFR Part 146.13) require continuous monitoring and recording of
injection pressure, flow rate, volume, and tubing/casing annulus pressure. The permittee is
also required to analyze water quality of the injected fluids.
All Class I industrial waste fluids delivered to the facility will be sampled for fluid
analysis prior to being delivery, or prior to being transferred to on-site storage tanks. These'
fluid samples shall be analyzed for chemical, physical, radiological, biological constituents,
including pH, total dissolved solids (TDS), and conductivity, If the analyses of several loads from
the same source indicate little or no change, the Director may elect to waive the requirement that
each load be sampled. However, one load of industrial waste coming from the same source (where
the process is not likely to change) must be tested once every five loads prior to being transferred
to on-site tanks.
The Permit requires that the operator maintain a record of each source of fluid received
for disposal. This record must include the name of the source, the well name and API number if
applicable, the volume of each load (in barrels), and the owner of the facility supplying the fluid..
A flow meter will measure in barrels the quantity of Class I fluids pumped from the
storage tanks to the Class II injection system. These comingled fluids will be sampled for
Statement of Basis for EPA Permit No. CO10938-02115 Page 12 of 17
analysis, prior to injection, at random, but not less than once every three months. This final
analysis shall include a determination of TDS, pH, specific conductivity, specific gravity, major
cations and anions, oil and grease, and total organic carbon.
For measuring fluid volume and rate, if the continuous monitoring is carried out with
digital equipment, the instrumentation must be capable of recording, at least one value for each of
the parameters at least every thirty (30) seconds. Initially, recordings must be made once every
ten (10) minutes. If the monitoring is recorded with a continuous chart recorder, the chart
should have a scale that will allow a change in rate of 5 barrels per day to be detected.
Monitoring should occur whether or not fluids are being injected. This information should be
analyzed in the first annual report under this Permit to determine if this frequency is representative
of the injection activity. A minor modification to the Permit will be made to increase the
frequency of recording if the variability of the injection volume and rate (as warranted by the data
results) affects the representative nature of the data. A minor modification to the Permit may be
made to decrease the frequency of recording if the Director determines that the fluctuation of the
parameters is such that less frequent data collection would not significantly affect the
representative nature of the reported data.
For continuous monitoring of the injection and tubing/casing annulus pressure, if the
continuous monitoring is carried out with a continuous chart recorder, the chart shall be of
a scale that allows changes in pressure of 5 psi to be detected. If the continuous monitoring is
carried out with digital equipment, the instrumentation shall be capable of recording at least one
value for each of the parameters at least every minute. Initially, recordings should be made
once every ten (10) minutes. Monitoring must occur whether or not fluids are being injected.
The information on pressure should be analyzed and the analysis submitted with the first
annual report, to determine if the continuous monitoring equipment is providing information
representative of the injection activity. This analysis should include a comparison between the
results obtained from the continuous recording equipment and the manual readings taken at least
daily from the well head gages. If digital recording equipment is utilized, the analysis should
include an analysis of the representative nature of the recording frequency. A minor modification
to the Permit will be made to increase the frequency of recording if the variability of the injection
pressure and annulus (as warranted by the data results) affects the representative nature of the data.
A minor modification to the Permit may be made to decrease the frequency of recording if the
Director determines that the fluctuation of the parameters is such that less frequent data collection
would not significantly affect the representative nature of the reported data.
Monitoring Information.
(Condition 2)
Records of any monitoring activity required under this permit shall include:
(a) The dates, exact place, and the time interval of sampling, monitoring, or
field measurements;
Statement of Basis for EPA Permit No. CO10938-02115 Page 13 of 17
(b) The name of the individual(s) who performed the sampling or
measurements;
(c) The exact sampling method(s) used to take samples;
(d) The date(s) laboratory analyses were performed;
(e) The name of the individual(s)who performed the analyses;
(f) The analytical techniques or methods used by laboratory personnel; and
(g) The results of such analyses.
Recordkeeping, (Condition 3)
The permittee is being required to keep records concerning:
(1) the nature and composition of all injected fluids until three (3) years after
the completion of plugging and abandonment, which has been carried out in
accordance with the Plugging and Abandonment Plan shown in Appendix C
of the permit, and is consistent with 40 CFR § 146.10.
(2) all monitoring information, including all calibration and maintenance
records and all original strip chart recordings for continuous monitoring
instrumentation and copies of all reports required by this permit for a period
of at least five (5) years from the date of the sample, measurement, or
report, throughout the operating life of the well.
The permittee shall maintain copies (or originals) of all the records listed above at the
office of:
Watienberg Disposal, LLC
Suckla Farms #1
10137 Weld County Road 19
Ft. Lupton, Colorado 80621
Reporting of Results (Condition 4)
The Permit requires that the average, maximum and minimum monthly values of injection
pressure, flow rate and volume, and annular pressure be reported quarterly, along with the data
from the fluid analyses. The operator shall also provide summary graphs covering the reporting
period of the injection pressure, the annulus pressure, and the injection rate. Copies of the
analytical results for the samples of injected fluids, and records of any major changes in
characteristics or sources of injected fluid shall be included in the Quarterly Report.
Statement of Basis for EPA Permit No. CO10938-02115 Page 14 of 17
The Quarterly Reports shall include the results and associated documentation of any
mechanical integrity testing, pressure falloff testing, well workover, or well logging completed
during the period covered by the report.
The first Quarterly Report covers the period from the effective date of the permit through
the end of that quarter. Subsequent Quarterly Reports for a year cover the periods of: January 1
through March 31; April 1 through June 30; July 1 through September 30; and, October 1 through
December 31. Each Quarterly Report must be submitted to the Denver Office by the 15th of the
following month. The Permit requires submittal of the information on Form 7520-8 with
attachments as needed.
PART II, Section E PLUGGING AND ABANDONMENT
Notice of Plugging and Abandonment
(Condition I)
To provide sufficient time for the Director to witness the well plugging, if deemed
necessary, the Permit requires that the Director be notified forty-five (45) days before
abandonment of the well.
Plugging and Abandonment Plan.
(Condition 2)
The plugging and abandonment plan (Appendix C of the Permit) submitted by the
permittee is based on the ability of the operator to cut the 5-1/2 inch longstring casing at
approximately 7,200 feet. If the casing is pulled the plugging consists of four(4) plugs (this
counts the placement of cement in the surface casing. This plan has been reviewed and approved
by the EPA with a provision. If it is not feasible to pull the 5-1/2 inch longstring casing, it will be
necessary to perforate the casing at approximately 7,200 feet and squeeze cement into the annular
space between the borehole and the 5-1/2 inch casing. The resulting composite plugging Plan
required by the Permit is as follows:
(a) Immediately prior to plugging and abandoning the Suckla Farms #1 disposal well,
the retrievable tension-type packer will be released and the tubing and packer will
be removed from the wellbore.
(b) Run back into the wellbore with a tubing string to the bottom of the 5-1/2 inch
casing and condition the wellbore. Place a 250 foot cement plug from about 9,225
feet to 9, 476 feet, using either Class B type II neat cement or an equivalent Class G
cement. Wait sufficient time for plug to set and tag plug with tubing string.
(c) Cut the 5-12 inch long string casing at approximately 7,200 feet and pull the casing.
Run into well with a tubing string and condition the well with 9.6 ppg bentonite
or plugging gel. Set a 200 foot plug, using Class "G", or equivalent type cement,
from 7,100 feet to 7,300 feet (a minimum of 75 feet below the top of the casing
Statement of Basis for EPA Permit No. CO10938-02115 Page 15 of 17
stub. If the casing is not pulled, the 5-1/2 inch casing must be perforated-at 7,200
feet and cement squeezed into the annular space.
(d) Within the 8-5/8 inch surface casing and the 7-7/8 inch wellbore, set a 100 foot
plug, using Class "G" or equivalent cement, from 709 feet (50 feet above the
surface casing shoe) to 809 feet. If the casing is not pulled, the 5-1/2 inch casing
must be perforated at just below the casing shoe and cement squeezed into the
annular space.
(e) Within the 8-5/8 inch surface casing, set a sufficient Class "G" cement to fill the
casing from the surface to a minimum depth of 50 feet. If the casing is not pulled,
the 5-1/2 inch casing must also be filled with Class "G" cement to a depth of at
least 50 feet.
(1) After the wellbore is plugged the Permit requires cutting off the 8-5/8 inch casing 1
to 3 feet below ground surface. A steel cap dry hole marker is required to be
welded on the 8-5/8 inch casing. The surface must then be restored to landowner
and/or County requirements.
(Condition 3)
Inactive Wells.
The Permit requires that after a two (2) year period of injection inactivity, the permittee
must plug and abandon the well in accordance with the Plugging and Abandonment Plan, unless
the permittee:
(a) has provided notice to the Director; and
(b) has demonstrated that the well will be used in the future; and
(c) has described actions or procedures, satisfactory to the Director, that will be taken
to ensure that the well will not endanger underground sources of drinking water
during the period of temporary abandonment.
ni a anti Abandonment Report.
(Condition 4)
Within sixty (60) days after plugging the well, the permittee shall submit a report on
Form 7520-13 to the Director. The report shall be certified as accurate by the person who
performed the plugging operation and the report shall consist
actual either: (1) a statement:(I)adiffered fromthat t the
plan,
well was plugged in accordance with the plan; or(2) where plugging g
a statement that specifies the different procedures followed.
Statement of Basis for EPA Permit No. CO10938-02115
Page 16 of 17
PART II, Section F FINANCIAL RESPONSIBILITY
Demonstration of Financial Responsibility.
(Condition 1)
The permittee is required to maintain continuous financial responsibility and resources to
close, plug and abandon the injection well as provided in the plugging and abandonment plan.
(a) Wattenberg Disposal LLC. has chosen to demonstrate financial responsibility
through a Standby Trust Agreement and a SAFECO Insurance Company of
America Surety Performance Bond(, L.L.P., the well operator), in the amount
sufficient to plug and abandon the well. As deemed appropriate, the Director may
require the operator to provide information updating the plugging plan and
associated costs. At a minimum, such a review will be made during the five year
review of the Permit. The performance Bond which names EPA as beneficiary in
the event of permittee default on the plugging and abandonment requirements and
is hereby incorporated as part of this permit. The Standby Trust Agreement
established by the permittee shall remain in effect for the duration of this permit,
unless part (b), below, has been complied with.
(b) The permittee may, upon written request to EPA, change the type of financial
mechanism or instrument utilized. A change in demonstration of financial
responsibility must be approved by the Director. A minor permit modification will
be made to reflect any change in financial mechanisms, without further opportunity
for public comment.
•
Insolvency of Financial Institution.
(Condition 2)
In the event that an alternate demonstration of financial responsibility has been approved
under (b) above, the permittee must submit an alternate demonstration of financial responsibility
acceptable to the Director within sixty(60) days after either of the following events occur:
(a) The institution issuing the trust or financial instrument files for bankruptcy; or
(b) The authority of the trustee institution to act as trustee, or the authority of the
institution issuing the financial instrument, is suspended or revoked.
Cancellation of Demonstration by Financial Institution. (Condition 3)
The permittee must submit an alternative demonstration of financial responsibility
acceptable to the Director, within sixty(60) days after the institution issuing the trust or financial
instrument serves 120-day notice to the EPA of their intent to cancel the trust or financial
instrument.
Statement of Basis for EPA Permit No. CO10938-02115 Page 17 of 17
eis,sr%
. a •
g UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
�,d REGION 8
"°no E 999 18'"STREET - SUITE 300
DENVER, CO 80202-2466
Phone 800-227-8917
http://www.epa.goe/region08
Ref: 8P-W-GW
UNDERGROUND INJECTION CONTROL PROGRAM
FINAL PERMIT
Class I Non-Hazardous Waste Disposal Well
Permit No. CO10938-02115
Well Name: Suckla Farms #1
County & State: Weld, Colorado
issued to:
Wattenberg Disposal, LLC
1675 Broadway, Suite 2800
Denver, Colorado 80202
Date Prepared:
January 10, 2003
as
tor Printed on Recycled Paper
s A.ew$TA,•
• n •
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
4 e/ REGION 8
�' 'A° 999 l8�"STREET - SUITE 300
DENVER, CO 80202-2466
Phone 800-227-8917
http://www.ePa.govireglon08
Ref: 8P-W-GW
•
UNDERGROUND INJECTION CONTROL PROGRAM
FINAL PERMIT
Class I Non-Hazardous Waste Disposal Well
Permit No. CO10938-02115
Well Name: Suckla Farms #1
County & State: Weld, Colorado
issued to:
Wattenberg Disposal, LLC
1675 Broadway, Suite 2800
Denver, Colorado 80202
Date Prepared:
i' Printed on Recycled Paper
TABLE OF CONTENTS
1
TITLE SHEET
2
TABLE OF CONTENTS
PART I. AUTHORIZATION TO CONSTRUCT AND OPERATE 5
PART II. SPECIFIC PERMIT CONDITIONS
7
A. WELL CONSTRUCTION REQUIREMENTS 7
7
1. Casing and Cementing 7
2. Tubing and Packer Specifications 7
3. Monitoring Devices 9
4. Proposed Changes and Workovers 9
5. Logging and Well Testing Specifications
B. CORRECTIVE ACTION
9
10
C. WELL OPERATION
10
1. Prior to Commencing Injection 10
2. Mechanical Integrity 12
3. Injection Interval 12
4. Injection Pressure Limitation 12
5. Injection Volume Limitation 12
6. Injection Fluid Limitation 12
7. Annular Fluid
D. MONITORING, RECORDKEEPING, AND REPORTING OF RESULTS 14
14
1. Injection Well Monitoring Program 14
2. Monitoring Information 16
3. Recordkeeping 17
4. Reporting of Results
E. PLUGGING AND ABANDONMENT
17
17
1. Notice of Plugging and Abandonment 17
2. Plugging and Abandonment Plan 18
3. Inactive Wells. 18
4. Plugging and Abandonment Report
EPA Final Permit No. CO 10938-02115
Page 2 of 105
TABLE OF CONTENTS CONTINUED
F. FINANCIAL RESPONSIBILITY 18
1. Demonstration of Financial Responsibility 18
2. Insolvency of Financial Institution 18
3. Cancellation of Demonstration by Financial Institution 19
PART III. GENERAL PERMIT CONDITIONS 19
A. EFFECT OF PERMIT 19
B. PERMIT ACTIONS 19
1. Modification, Reissuance, or Termination 19
2 Transfers 20
3. Operator Change of Address 20
C. SEVERABILITY - 20
D. CONFIDENTIALITY 20
E. GENERAL DUTIES AND REQUIREMENTS 20
1. Duty to Comply 20
2. Penalties for Violations of Permit Conditions 21
3. Need to Halt or Reduce Activity not a Defense 21
4. Duty to Mitigate 21
5. Proper Operation and Maintenance 21
6. Duty to Provide Information 21
7. Surface Leak Prevention 21
8. Inspection and Entry 21
9. Records of Permit Application 22
10. Signatory Requirements 22
11. Reporting of Noncompliance 22
APPENDIX A (CONSTRUCTION DETAILS) 24
APPENDIX B (REPORTING FORMS) 26
APPENDIX C (PLUGGING & ABANDONMENT PLAN) 33
APPENDIX D (CEMENT BOND LOGGING) 34
EPA Final Permit No. CO 10938-02115 Page 3 of 105
TABLE OF CONTENTS CONTINUED
APPENDIX E (GUIDANCE - TEMPERATURE LOG) 56
APPENDIX F (GUIDANCE - RADIOACTIVE TRACER SURVEY) 58
APPENDIX G (GUIDANCE FOR CONDUCTING A PRESSURE TEST) 61
APPENDIX H (GUIDANCE FOR CONDUCTING STEP RATE TEST) 69
APPENDIX I (GUIDANCE FOR CONDUCTING PRESSURE FALLOFF TEST) 76
EPA Final Permit No. CO 10938-02115 Page 4 of 105
Issued this day of .
This permit shall become effective
L-Ck\--1(/'
Ste hen S. Tuber
*Acting Assistant Regional Administrator
Office of Partnerships and
Regulatory Assistance
* NOTE: The person holding this title is referred to as the "Director" throughout this
permit.
•
EPA Final Permit No. CO 10938-02115 Page 6 of 105
PART II. SPECIFIC PERMIT CONDITIONS
A. WELL CONSTRUCTION/CONVERSION REQUIREMENTS
1. Casing and Cementing. The construction details submitted with the application are
hereby incorporated into this permit as Appendix A which graphically displays the
details of the injection well under consideration. The construction shown in
Appendix A is binding on the permittee.
2. Tubing and Packer Specifications. This well shall. have a tubing and packer suitable
for the proposed injection activity. The packer shall set on tubing and maintained at
a location that is no more than 300 feet above the top most perforation at 9,276 feet.
3. Monitoring Devices. The primary method of monitoring shall be continuous
pressure monitoring of the injection and casing tubing annulus pressure (at the
wellhead) and continuous monitoring of the injection rate and volume. Prior to
beginning Class I non-hazardous injection operation, the operator shall install and
maintain in good operating condition the following equipment:
(a) Injection pressure: a continuous pressure monitoring device in the injection
tubing at the wellhead shall be connected to either a continuous chart
recorder with a resolution of at least 5 psi or a digital recording system
with a sampling frequency of at least every 30 seconds; and a one-half
(%2) inch Female Iron Pipe (FIP) fitting, isolated by plug or globe valves and
. located on the tubing to allow attachment of one-half(%s) inch Male Iron
Pipe (MP) pressure gauges or the attachments for equivalent "quick-
disconnect" pressure gauges certified for ninety-five (95) percent accuracy,
or better, throughout the range of permitted operation in order to verify
values for injection pressure being recorded from the continuous monitoring
device.
(b) Wellhead pressure of the tubing/casing annular space: a continuous
pressure monitoring device in the wellhead casing/tubing annulus shall be
connected to either a continuous chart recorder with a resolution of at
least 5 psi or a digital recording system with a sampling frequency of at
least every 30 seconds; and a one-half(%1) inch Female Iron Pipe (FIP)
fitting, isolated by plug or globe valves, and located on the tubing/casing
annulus; and the above fittings shall be positioned to allow attachment of
one-half(Yz) inch Male Iron Pipe (MIP)pressure gauges or the attachments
for equivalent "quick-disconnect" pressure gauges certified for ninety-five
(95) percent accuracy, or better, throughout the range of permitted operation
in order to verify values for injection pressure being recorded from the
continuous monitoring device.
EPA Final Permit No. CO 10938-02115 Page 7 of 105
The tubing/casing annulus shall be maintained full of either fresh water
treated with a non-toxic corrosion inhibitor or other packer fluid as
approved, in writing, by the Director. This fluid shall be maintained under
a positive pressure of between 100 and 200 psi. A diesel freeze blanket of-
other fluid as approved, in writing, by the Director may be circulated from
surface to below frost level at completion to prevent freezing and possible
equipment failure during winter months.
(c) Well shutdown: the continuous monitoring system shall have automatic
well shut down switches, such as a Murphy switch, installed which shall
shut-in the well if either of the following occur:
(i) The surface injection (tubing) pressure shall be operated at pressures
less than 3,700 psi. Any increase in pressure that exceeds 3,695 psi
shall result in an immediate shut down of the injection pumps; or
(ii) Because the gas pressure will vary as a result of fluctuation in the
injectate temperature, the tubing/casing annulus pressure shall be
maintained between 100 and 200 psi. Any operation outside of this -
range shall result in an immediate shut down of the injection pumps.
When adjusting the annulus fluid pressure, the operator shall use the
target value of 150 psi;
(d) Fluid volume and flow rate: Flow meters (magnetic or turbine) and
continuous recording devices, such as a chart recorder with an accuracy of 1
barrel per minute or a digital recording system with a sampling frequency of
at least every 30 seconds shall be installed in the injection line immediately
upstream of the wellhead to track and document disposal fluid flow rates,
and total fluid volumes.
For a given injection rate, the injection pressure should remain relatively
constant. Input flow volumes shall be cross checked against injection
pressure records to identify any possible divergence in the injection pressure
for a given flow rate. A drop in injection pressure without a corresponding
reduction in input flow rate may indicate a possible casing, packer, or other
failure; and
(e) Fluid analysis: the injection line shall be equipped with sampling ports and
appropriate connections to facilitate periodic collection of fluid samples
representative of the injection fluids for chemical analysis. The sampling
point shall be in an unobstructed portion of the injection line down
stream from the tanks but prior to the injection pumps.
EPA Final Permit No. CO 10938-02115 Page 8 of 105
4. Proposed Changes and Workovers. The permittee shall give advance notice as soon
as possible to the Director of any planned physical alterations or additions to the
permitted well. Major alterations or workovers of the permitted well shall meet all
conditions as set forth in this permit. A major alteration/workover shall be
considered any work performed, which affects casing, packer(s), or tubing.
The permittee shall provide all records of well workovers, logging, or other test data
to EPA as part of the quarterly report for the period in which the activity was
completed. Appendix B contains samples of the appropriate reporting forms.
Demonstration of mechanical integrity(tubing/casing annulus pressure test,
Appendix G) shall be performed within thirty(30) days of completion of
workovers/alterations and prior to resuming injection activities, in accordance with
Part II, Section C. 2. (a) of the Permit.
5. Logging and Well Testing Specifications. The permittee shall give at least two
days, advance notice to the Director of any planned logging or testing. This notice
shall include a plan for conducting the proposed test or log. The test plan shall be
developed using the Guidelines in Appendix I:
(a) After any workover that involves any remedial cementing of the casing, the
operator shall run a new cement bond log (with a gamma ray, travel time
curve, casing collar locator, amplitude curve, and variable density log) that
covers the area of the cementing to verify the adequacy of the cement
placement. This log will be run following the guidelines in Appendix D;
and
•
(b) A pressure fall-off test is required for Class I operations [40 CFR § 146.13
(d) (1)] and must be performed at least once every twelve months for the
purpose of monitoring pressure buildup in the injection zone in order to
detect any significant loss of fluids due to fracturing in the injection and/or
confining zone, and to aid in detennining the lateral extent of the injection
plume.
The initial yearly pressure falloff test shall take place during the month of
April 2004. Any subsequent falloff tests shall be run within a one week
period of the date of the initial falloff test The pressure fall-off tests shall
involve injecting fluids at a constant rate for at least twenty-four(24)hours,
or a sufficient period of time (which ever is greater) until the reservoir
pressure reaches stability(radial flow conditions, as determined by a field
evaluation of the raw data), followed immediately by a shut-in period of
sufficient duration to establish a valid observation of a pressure fall-off
curve.
EPA Final Permit No. CO 10938-02115 Page 9 of 105
The Operator shall develop a test plan for conducting the pressure falloff
test. Appendix I contains a guideline for conducting pressure falloff tests
that was developed by EPA Region VI for use in developing a site specific
plan. The final test plan §hall be submitted to Region VIII for review and
approval, at least, 30 days prior to conducting the annual pressure falloff
test.
The actual falloff test shall conform to the final falloff test plan approved by
EPA. This test shall be considered complete when the pressure curve
becomes asymptotic to a horizontal line as the reservoir reaches ambient
pressure. The initial pressure buildup shall be performed with both a
downhole quartz pressure gauge with an accuracy of 0.01 psi and surface
monitoring equipment utilizing pressure monitoring devices with an
accuracy of 0.01 psi to establish a correlation between surface and downhole
measurements. It is important that the initial and subsequent tests follow the
same test procedure, so that valid comparisons of reservoir pressure,
permeability, and porosity can be made. At a minimum, subsequent tests
shall be conducted with surface pressure monitoring devices with an
accuracy of 0.01 psi. The Director may require the use of downhole quartz
gages on any subsequent test, if deemed necessary. The permittee shall
analyze test results and provide a report with an appropriate narrative
interpretation of the test results, including an estimate of reservoir
parameters, information on any reservoir boundaries, an estimate of the well
skin effect, and reservoir flow conditions. The report shall also compare
the test results with the previous years test data and shall be prepared
by a knowledgeable analyst.
B. CORRECTIVE ACTION
The operator is not required to take any corrective action before the effective date of this
Permit.
C. WELL OPERATION
Prior to Commencing Injection. Injection of Class I non-hazardous materials into
the Suckla Farms# 1 is presently occurring under the authority of the existing
Permit. Upon the effective date of this Permit, continued injection into the Suckla
Farms # 1 is authorized subject to the conditions herein.
2. Mechanical Integrity.
(a) Notification. The Permittee shall give at least two weeks, advance notice of
any required integrity test. The Director may allow a shorter notification
period if it would be sufficient to enable the EPA to witness the mechanical
EPA Final Permit No. CO 10938-02115 Page 10 of 105
•
integrity test (MIT). Notification may be in the form of a yearly or quarterly
schedule of planned mechanical integrity tests or it may be on an individual
basis.
(b) Test Methods and Criteria. For Part I(internal) of mechanical integrity, test
methods and criteria are to follow current UIC Guidance for Conducting
a Pressure Test to Determine if a Well has leaks in the Tubing, Casing -
or Packer (Appendix G). A well passes the mechanical integrity test for
Part I if there is less than a ten (10)percent decrease or increase in pressure
over the thirty(30) minute period. For Part II (external of mechanical
integrity, test methods and criteria are to follow current UIC Guidance for
demonstrating the absence of significant flow into or between USDWs
adjacent to the casing using either temperature surveys or a radioactive
tracer survey (Appendix E and Appendix F).
(c) Routine Demonstrations of Mechanical Integrity. The Permittee must
demonstrate Part I and Part II of mechanical integrity by arranging and
conducting a test at least once every five years. A tubing/casing annulus
pressure test shall be conducted at the maximum injection pressure or at
least 1000 psig whichever is lesser (with a pressure differential of at
least 200 psig between the annulus pressure and the injection tubing
pressure) to demonstrate Part I(no leaks in the tubing, casing or packer).
This test shall be for a minimum of thirty(:30) minutes with the well shut-in,
and pressure values shall be recorded at five-minute intervals. The operator
shall conduct either a temperature log or a radioactive tracer log to
demonstrate Part II(no flow into or between USDWs adjacent to the
casing). If necessary to demonstrate no flow adjacent to the casing, the
Director may request that additional logs be conducted.
Also, Part I of mechanical integrity shall be successfully demonstrated after
workovers (see Part II. A. 5. of the Permit). Results of the test shall be
submitted (on EPA form found in Appendix B), with documentation, to the
Director with the Quarterly Report for the period in which the activity was
completed.
(d) Loss of Mechanical Integrity. If the well fails to demonstrate mechanical
integrity during a test, or a loss of mechanical integrity as defined by 40
CFR § 146.8 becomes evident during operation, the permittee shall notify
the Director in accordance with Part III, Section E. 10. (c) of this permit.
Furthermore, injection activities shall be terminated immediately; and
operations shall not be resumed until the permittee has taken necessary
actions to restore integrity to the well and the Director gives approval to
recommence injection.
•
EPA Final Permit No. CO 10938-02115 Page 11 of 105
3. Injection Interval. Injection zone shall be limited to the Lyons Sandstone in the
interval from the depths of 9,276 feet and 9,418 feet. The injection zone is confined
by a 300 foot interval of shales and interbedded siltstones that overlie the injection
reservoir.
4. Injection Pressure Limitation. Based on the instantaneous shut-in pressure from a
fracture treatment of the well, a maximum surface injection pressure of 3,700
pounds per square inch gauge (psig) has been established.
(a) If a higher pressure is requested, it must be accompanied by a valid step-rate
test (SRT) of the injection zone, using fluid normally injected, to determine
both the instantaneous shut-in pressure (ISIP) and the formation breakdown
pressure. The Director will determine the allowable pressure modification
based upon the test results and other parameters reflecting actual injection
operations.
(b) The permittee shall give thirty (30) days advance notice to the Director
if an increase in injection pressure will be sought. Details of the
proposed test shall be submitted at least seven (7) days in advance of the
proposed test date so that the Director has adequate time to review and
approve the test procedures. Results of all tests shall be submitted to the
Director within ten (10) days of the test. Any changes in the maximum
injection pressure established by this section, as dictated by the test results,
will be made as a minor modification to the Permit.
.5. Injection Volume Limitation. Cumulative injection volume of oil field fluids, plus
Class I non-hazardous waste fluid shall be limited to 8,300,000 barrels over the
total life of the well. The injection rate is not limited, but in no instance shall the
rate result in an injection pressure that exceed the limit established in Part II,
Section C, item 3, above. When the maximum cumulative volume is reached, EPA
will make a decision to extend the limits of the injection zone or to terminate the
Permit.
6. Injection Fluid Limitation. The permittee is authorized to inject Class II oil and gas
related fluids, Class I fluids from underground fuel storage tank (UST) cleanup sites
that has been determined to be non-hazardous, and other non-hazardous industrial
wastes as approved by the Director. Class II fluids are brought to the surface in
connection with natural gas storage operations, or conventional oil and 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. Injection of any hazardous waste as
identified by EPA under 40 CFR 261.3 is prohibited.
The permittee has provided EPA with a current list of Class II sources (production
EPA Final Permit No. CO 10938-02115 Page 12 of 105
wells),consisting of 212 pages (up to 44 wells per page), that have utilized the
facility for disposal in the past. This list is part of the administrative record and the
Permittee may accept fluids from wells presently on this list without further
notification of EPA. New additions to this list in the Administrative record shall
be made a binding part of this Permit following the procedures outlined below:
For new Class II and UST (conventional fuel and heating oil) fluid sources:
(a) The permittee shall submit a request for disposal of fluids from any new
Class II or UST source (associated with the storage of conventional
engine fuel or heating oil), prior to acceptance of the fluid for disposal.
The request shall include the source name, location, operator, and a brief
description of the operation that produced the source. If the source is an
UST site, the discussion must provide information demonstrating that no
metals above the TC toxicity characteristics are present in the fluid.
(b) The request shall be accompanied by a water analysis consisting of at least
total dissolved solids content,pH, specific conductivity, and specific gravity.
(c) Any approval for injection may be granted 'verbally, with subsequent written
approval from the Director.
For new UST (Other than conventional fuel and heating) or industrial non-
hazardous fluid sources:
(a) The permittee shall submit a request for disposal of fluids from any new
source, prior to acceptance of the fluid for disposal. The request shall
include the source name, location, operator and a description of the
operation that produced the waste fluid.
(b) The request shall include a complete analysis of the fluids, including cations,
anions, BTEX, EP Corrosivity, EP Ignitability, EP Reactivity, and EP
Toxicity using the Toxicity Characteristic leaching Procedure for all listed
parameters.
(c) Any approval for'injection may be granted verbally, with subsequent written
approval from the Director.
7. Annular Fluid. The annulus between the tubing and the long string casing shall be
filled with fresh water treated with a corrosion inhibitor or other packer fluid as
approved, in writing, by the Director. The annulus shall be maintained under a
positive pressure ranging from 100 to 200 pounds per square inch gauge (psig) with
a target value of 150 psig.
EPA Final Permit No. CO 10938-02115 Page 13 of 105
D. MONITORING, RECORDKEEPING, AND REPORTING OF RESULTS
1. Injection Well Monitoring Program. Samples and measurements shall be
representative of the monitored activity. The permittee shall utilize the applicable
analytical methods described in Table 1 of 40 CFR § 136.3, or in Appendix III of 40
CFR Part 261, or in certain circumstances, by other methods that have been
approved by the EPA Administrator. Monitoring shall consist of:
(a) Sampling and anatysis of injection fluids. Analysis of the injection fluids
shall be performed as follows:
(i) For fluids which may vary in composition, the analysis of industrial
waste fluids shall be performed prior to delivery, or prior to being
pumped from individual delivery trucks into on-site storage tanks.
Fluid samples shall be analyzed for chemical,physical, biological,
and radiological constituents, including cations and anions, pH,
conductivity and total dissolved solids content. If however, the
analyses of four(4) loads indicates the material is not hazardous and
the quality has little variability, the Director may waive the
requirement for analyzing every load. Subsequent to this waiver, a
minimum of one load in five shall be analyzed.
(ii) For fluids associated with a specific process which do not vary in
chemical composition, the analysis of industrial waste fluids
received at the well site shall be performed once every ten loads or
once per month, which ever is less. Fluid samples shall be analyzed
•
for chemical, physical, biological, and radiological constituents,
including cations and anions, pH, conductivity, and total dissolved
solids content. If, however, the analyses of the monthly samples
shows significant variability(variation of greater than 20%) chemical
composition, the frequency of analyses may be increased to that
specified in item (i) above.
(iii) Analysis of commingled injection fluids prior to injection shall be
performed at random, but not less than once every three months,
for total dissolved solids, pH, specific conductivity, specific gravity,
major cations and anions, oil and grease, and total organic carbon.
(b) Monitoring offluid sources accepted for disposal. The permittee shall
maintain a record of each source of fluid received for disposal. This
record shall include the name of the source, the well name and API number
if applicable, the volume of each load (in barrels), and the owner of the
facility supplying the wastewater.
EPA Final Permit No. CO 10938-02115 Page 14 of 105
(c) Continuous monitoring of flow rate and cumulative volume. If the
continuous monitoring is carried out with digital equipment, the
instrumentation shall be capable of recording at least one value for each of
the parameters at least every thirty(30) seconds. Initially, recordings shall
be made once every ten (10) minutes. If the monitoring is recorded with a
continuous chart recorder, the chart shall have a scale that will allow a
change in rate of 5 barrels per day to be detected. Monitoring must
occur whether or riot fluids are being injected. This information shall be
analyzed in the first annual report under this Permit to determine if this
frequency is representative of the injection activity. A minor modification to
the Permit shall be made to increase the frequency of recording if the
variability of the injection volume and rate (as warranted by the data results)
affects the representative nature of the data. A minor modification to the
Permit may be made to decrease the frequency of recording if the Director
determines that the fluctuation of the parameters is such that less frequent
data collection would not significantly affect the representative nature of the
reported data.
(d) Continuous monitoring of injection and annulus pressure. Continuous
monitoring shall be at the wellhead. If the continuous monitoring is
carried out with a continuous chart recorder, the chart shall be of a scale that
allows changes in pressure of 5 psi to be detected. If the continuous
monitoring is carried out with digital equipment, the instrumentation shall
be capable of recording at least one value fo:r each of the parameters at least
every thirty(30) seconds. Initially, recordings should be made once every
ten (10) minutes. Monitoring must occur whether or not fluids are being
injected. Manual reading from a pressure gage on the injection tubing
and the annulus shall be taken daily for comparison to the continuous
monitoring and recording devices.
The information on pressure shall be analyzed in the first annual report to
determine if the continuous monitoring equipment is providing information
representative of the injection activity. If digital recording equipment is
utilized, the analysis shall include an analysis of the representative nature of
the recording frequency. A minor modification to the Permit shall be made
to increase the frequency of recording if the variability of the injection
pressure and annulus (as warranted by the data results) affects the
representative nature of the data. A.minor modification to the Permit may
be made to decrease the frequency of recording if the Director determines
that the fluctuation of the parameters is such that less frequent data
collection would not significantly affect the representative nature of the
reported data.
EPA Final Permit No. CO 10938-02115 Page 15 of 105
2. Monitoring Information. Records of any monitoring activity required under this
permit shall include:
(a) The dates, exact place, and the time interval of sampling, monitoring;or
field measurements;
(b) The name of the individual(s) who performed the sampling or
measurements;
(c) The exact sampling method(s) used to take samples;
(d) The date(s) laboratory analyses were performed;
(e) The name of the individual(s) who performed the analyses;
(I) The analytical techniques or methods used by laboratory personnel; and
(g) The results of such analyses.
3. Recordkeeping.
(a) The permittee shall retain records concerning:
(i) the nature, volume, source and composition of all injected fluids
until three (3) years after the completion of plugging and
abandonment which has been carried out in accordance with the
Plugging and Abandonment Plan shown in Appendix C.
(ii) all monitoring information, including all calibration and maintenance
records and all original chart recordings or digital files for
continuous monitoring instrumentation and copies of all reports
required by this permit for a period of at least five (5) years from the
date of the sample, measurement or report throughout the operating
life of the well.
(b) The permittee shall continue to retain such records after the retention period
specified in paragraphs (a) (i) and (ii) above unless he delivers the records to
the Director or obtains written approval to discard them.
(c) The permittee shall maintain copies (or originals) of all pertinent records
[Part 11, Section D. 1..(a), (b), (c), and (d)] available for inspection at the
office of:
EPA Final Permit No. CO 10938-02115 Page 16 of 105
Wattenberg Disposal, LLC -
Suckla Farms #1
10137 Weld County Road 19
Ft. Lupton, Colorado 80621
4. Reporting of Results. The permittee shall submit Quarterly Reports to the Director
summarizing the results of the monitoring required by Part II, Section D. 1. (a), (b),
and (c) of this permit.
(a) The report shall include the monthly average, maximum, and minimum
measured values for injection pressure, flow rate and volume, and
annulus pressure. A list of all individual sources of waste fluids
brought to the facility (including facility well name and API number, if
applicable) and the total volume from each source shall be provided.
The operator shall also provide summary graphs covering the reporting
period of the injection pressure, the annulus pressure, and the injection
rate. Copies of the analytical results for the samples of injected fluids, and
records of any major changes in characteristics or sources of injected fluid
shall be included in the Quarterly Report.
(b) The Quarterly Reports shall include the results and associated
documentation of any mechanical integrity testing, pressure falloff
testing, well workover, or well logging completed during the period
covered by the report.
•
(c) The first Quarterly Report shall cover the period from the effective date of
the permit through the end of that quarter. Subsequent Quarterly Reports for
a year shall cover the periods of: January 1 through March 31; April 1
through June 30; July 1 through September 30; and, October 1 through
December 31. Each Quarterly Report shall be submitted to the Denver
Office by the 15th of the following month. Appendix B contains Form
7520-8 which may be copied and used to submit the quarterly summary of
monitoring.
E. PLUGGING AND ABANDONMENT
1. Notice of Plugging and Abandonment. The permittee shall notify the Director
forty-five (45) days before abandonment of the well.
2. Plugging and Abandonment Plan. The permittee shall plug and abandon the well as
provided in the Plugging and Abandonment Plan, Appendix C. The Director
reserves the right to change the manner in which the well will be plugged if the well
is modified during its permitted life or if the well is not made consistent with EPA
EPA Final Permit No. CO 10938-02115 Page 17 of 105
requirements for construction and mechanical integrity. The Director may ask the
permittee to update the estimated plugging cost periodically. Such estimates shall
be based upon costs which a third party would incur to plug the well according to
the plan. _
3. Inactive Wells. After a two (2) year period of injection inactivity, the permittee
shall plug and abandon the well in accordance with the Plugging and Abandonment
Plan, unless the permittee:
(a) has provided notice to the Director; and
(b) has demonstrated that the well will be used in the future; and
(c) has described actions or procedures, satisfactory to the Director, that will be
taken to ensure that the well will not endanger underground sources of
drinking water during the period of temporary abandonment.
4. Plugging and Abandonment Report. Within sixty (60) days after plugging the
well, the permittee shall submit a report on Form 7520-13 to the Director. The
report shall be certified as accurate by the person who performed the plugging
operation and the report shall consist of either: (1) a statement that the
well was plugged in accordance with the plan; or(2) where actual plugging differed
from the plan, a statement that specifies the different procedures followed.
F. FINANCIAL RESPONSIBILITY
1. Demonstration of Financial Responsibility. The permittee is required to maintain
continuous financial responsibility and resources to close, plug and abandon the
injection well as provided in the plugging and abandonment plan.
(a) The permittee has submitted a Surety Performance Bond for$30,000 for this
well, and a Standby Trust Agreement. Each have been reviewed and
approved by the EPA. The Director may on a periodic basis revise the
demonstration of financial responsibility under 40 CFR 144.53 (a) (7).
(b) The permittee may, upon written request to EPA, change the type of
financial mechanism or instrument utilized. A change in demonstration of
financial responsibility must be approved by the Director. A minor permit
modification will be made to reflect any change in financial mechanisms,
without further opportunity for public comment.
2. Insolvency of Financial Institution. In the event that an alternate demonstration of
financial responsibility has been approved under (b) above, the permittee must
submit an alternate demonstration of financial responsibility acceptable to the
EPA Final Permit No. CO 10938-02115 Page 18 of 105
Director within sixty(60) days after either of the following events occur:
(a) The institution issuing the trust or financial instrument files for bankruptcy;
or
(b) The authority of the trustee institution to act as trustee, or the authority of
the institution issuing the financial instrument, is suspended or revoked.
3. Cancellation of Demonstration by Financial Institution. The permittee must submit
an alternative demonstration of financial responsibility acceptable to the Director,
within sixty(60) days after the institution issuing the trust or financial instrument
serves 120-day notice to the EPA of their intent to cancel the trust or financial
instrument.
PART III. GENERAL PERMIT CONDITIONS
A. EFFECT OF PERMIT
The permittee is allowed to engage in underground injection in accordance with the
conditions of this permit. The permittee, as authorized by this permit, shall not construct,
operate, maintain, convert, plug, abandon, or conduct any other injection activity in a
manner that allows the movement of fluid containing any contaminant into underground
sources of drinking water, if the presence of that contaminant may cause a violation of any
primary drinking water regulation under 40 CFR, Part 142 or otherwise adversely affect the
health of persons. Any underground injection activity not authorized in this permit or
otherwise authorized by permit or rule is prohibited. Issuance of this permit does not
convey property rights of any sort or any exclusive privilege; nor does it authorize any
injury to persons or property, any invasion of other private rights, or any infringement of
State or local law or regulations. Compliance with the terms of this permit does not
constitute a defense to any enforcement action brought under the provisions of Section
1431 of the Safe Drinking Water Act (SDWA) or any other law governing protection of
public health or the environment for any imminent and substantial endangerment to human
health, or the environment, nor does it serve as a shield to the permittee's independent
obligation to comply with all UIC regulations.
B. PERMIT ACTIONS
I. Modification, Reissuance, or Termination. The Director may, for cause or upon a
request from the permittee, modify, revoke and reissue, or terminate this permit in
accordance with 40 CFR Sections 124.5, 144.12, 144.39, and 144.40. Also, the
permit is subject to minor modifications for cause as specified in 40 CFR Section
144.41. The filing of a request for a permit modification, revocation and reissuance,
or termination or the notification of planned changes or anticipated noncompliance
on the part of the permittee does not stay the applicability or enforceability of any
EPA Final Permit No. CO 10938-02115 Page 19 of 105
permit condition.
2. Transfers. This permit is not transferrable to any person except after notice is
provided to the Director and the requirements of 40 CFR 144.38 are complied with.
The Director may require modification, or revocation and reissuance, of the permit
to change the name of the permittee and incorporate such other requirements as may
be necessary under the SDWA.
3. Operator Change of Address. Upon the operator's change of address, notice must be
given to the appropriate EPA office at least fifteen (15) days prior to the effective
date.
C. SEVERABILITY
The provisions of this permit are severable, and if any provision of this permit or the
application of any provision of this permit to any circumstance, is held invalid, the
application of such provision to other circumstances, and the remainder of this permit shall
not be affected thereby.
D. CONFIDENTIALITY
In accordance with 40 CFR Part 2 and 40 CFR 144.5, any information submitted to EPA
pursuant to this permit may be claimed as confidential by the submitter. Any such claim
must be asserted at the time of submission by stamping the words "confidential business
information" on each page containing such information. If no claim is made at the time of
submission, EPA may make the information available to the public without further notice.
If a claim is asserted, the validity of the claim will be assessed in accordance with the
procedures in 40 CFR Part 2 (Public Information). Claims of confidentiality for the
following information will be denied:
The name and address of the permittee; and
Information which deals with the existence, absence or level of
contaminants in drinking water.
E. GENERAL DUTIES AND REQUIREMENTS
1. Duty to Comply. The permittee shall comply with all conditions of this permit,
except to the extent and for the duration that such noncompliance is authorized by
an emergency permit. Any permit noncompliance constitutes a violation of the
SDWA and is grounds for enforcement action, permit termination, revocation and
reissuance, or modification. Such noncompliance may also be grounds for
enforcement action under the Resource Conservation and Recovery Act (RCRA).
EPA Final Permit No. CO 10938-02115 Page 20 of 105
(i) Any monitoring or other information which indicates that any
contaminant may cause endangerment to a USDW.
(ii) Any noncompliance with a permit condition or malfunction of the
injection system which may cause fluid migration into or between
underground sources of drinking water.
(d) Oil Spill and Chemical Release Reporting. The operator shall comply with
all other reporting requirements related to oil spills and chemical releases or
other potential impacts to human health or the environment by contacting
the National Response Center(NRC) at 1.800.424.8802 or 202.267.2675, or
through the NRC website at htto://www.nrc.uscg.mil/index.htm.
(e) Written Followup. A written submission shall also be provided within five
(5) days of the time the permittee becomes aware of the circumstances. The
written submission shall contain a description of the noncompliance and its
cause; the period of noncompliance, including exact dates and times, and if
the noncompliance has not been corrected, the anticipated time it is expected
to continue; and steps taken or planned to reduce, eliminate, and prevent
recurrence of the noncompliance.
(f) Other Noncompliance. The permittee shall report all other instances of
noncompliance not otherwise reported at the time monitoring reports are
submitted. The reports shall contain the information listed in Part III,
Section E. 10. (c) (ii) of this permit.
(g) Other Information. Where the permittee becomes aware that any relevant
facts were not submitted in the permit application, or incorrect information
was submitted in a permit application or in any report to the Director, the
permittee shall submit such correct facts or information within two (2)
weeks of the time such information becomes known.
EPA Final Permit No. CO 10938-02115 Page 23 of 105
APPENDIX A -
(CONSTRUCTION DETAILS)
EPA Final Permit No. CO 10938-02115 Page 24 of 105
•
KPK
K.P,Kauf0rnn Co,Inc
Dairy Workover or Completion Report
SUPERVISOR RickOAlerneler
j w s. m F4: j Injection Weil 31 Road Dlr 19 at 10.5,3/10E,N Into DATE: impact
ri L peso sem.;I 0 1n 87w County: Weld,CO Line Locate: Wa
Format Lyons Parts: 9278.8415,194 holes
Casing: 5.5"203 3,50 TD:9571 PBTD: 9478 KB Mars: 10
Tubing Detail,1131/01:
Footaqs oils..
549644 173 Tbg 2-718'00,EUE.Brd,6.53,.1-55,Flberfne
3499.35 110 Tbg 2-718'00,EUE,and,B.5$,N-80,Flberilne
1J 1 2.331"x2-715"sorer
1.1 1 Seating nipple,2418"
7.8 1 2318'25.5^Arrowset I(Rocky Mtt 011 Tools),set in compression
9005.49 TOTAL Set at 9014'KB
f-8518",244 Surface casing
��758 KB
20$N-30 Prod.casing
2-718",6.53.1-65&N-S0 Martine Tubing
5408 Cement top
A
if 0
f, 2318"Seating nipple below cover
l R
Arrowset I,set at 9014 KB
g1 .VwK .yr%9276 Lyons Formation
.n fi I.11.,),P^ kv!^'.9418 194 0.5'dia.holes
'21PBTD 9478 KB
TO 9511 KB
APPENDIX B
(REPORTING FORMS)
1. EPA Form 7520- 7: APPLICATION TO TRANSFER PERMIT
2. EPA Form 7520- 8: INJECTION WELL MONITORING REPORT
3. EPA Form 7520-10: COMPLETION REPORT FOR BRINE DISPOSAL WELL
4. EPA Form 7520-12: WELL REWORK RECORD
5. EPA Form 7520-13: PLUGGING RECORD
6. EPA Form R8: MECHANICAL INTEGRITY PRESSURE TEST
EPA Final Permit No. CO 10938-02115 Page 26 of 105
. • pptn•re he. 7000-00.7.AAcra.er nodes$.30,-9'
unnt6 1{ll ENVIRONMENTAL PFCf�'N AGIN
�j t ,. I III WASNINGION,DC 70'b0
i6E PA .� APPLICATION 101RANEFER PERMIT !
NAME AND ADDRESS OF UcIs1MG Pf RMrrtEE
NAME AND ADDRESS OF SURFACE OWNER
FEFMII NUMEEF
SIAM COUNTY •
LOCATE WELL AND ONLINE UNn ON
SECTION PVT — SAO ACRES
SURFACE LOCATION DESCRIPTION
N 'A OF `A OF k SECTION TOWNSHIP RANGE
•
—4---I---4-•
4-1---4----I- LOCA1L WILL IN TWO DIRLC110N./RUM Nts na:a La,t: 01 OUA 11r BRION"
TTT la'.IIOn— I.hor
n IN/SI--Lint a *orlon
* ion
TTT I I . erg._ h.Born II/WI--Lint ofcurrier Anion o TYPE Or PERMIT
-��---I---�'-I I WELL AC11VIn - WELL_lalUI I I _
I WELL
I ❑Operating ❑Inaivcual
W .t----t- I I D Class II 0 Mocif it*tion/Conversion 0 Amai
ber of Wells_
I DE not Disposal 0 ProposeO
Num_1I1�_III III
I ❑E ohmnced Fecowry
D Nyorocarbon Storage
D Class 111
--111--"Ir"'t_`_'—1{— ' D Other
—1J-.-1'1-I-1 Lassa Name Well Number
I
S
Ns MLISI if NO ADORE551[S)OF NEW DWNE RISI
NAME AND ADDRESS OF NEW OPE MiOF •
AnaCh to this application a written agreement between the visaing and new perminee containing a
specific date for transfer of permit responsibility, coverage, and liability between them.
The new permiTlee must show evidence of financial responsibility by the submission of surety bond,or
other adequate assurance, such as financial statements or other materials acceptable to the director.
•
•
•
CERTIFICATION •
I certify under the penalty of law that I have personally estamined and am familiar with the information
submitted in this document and all attachments and that, based on my inquiry of those individuak
immediately responsible for obtaining the information, I believe that the information is true. accurate.
lete•lam swan that there are significant penalties for submitting false information.including
and comp
the possibility of fine and imprisonment. (Ref. 40 CFR 144.32)
NAME AND OF HURL TITLE IPNeie ope w►rind
SIGNATURE DATF SIGNED
EPA Form 76204(1411
• II.
.
• ••
• UNITED 51411E I NVIRONME MAL PROTECTION 461 NO /arm Appeared
WASHINGTON,DC 2o'eo ()ME Ni.2040.0042
4+ COMFLE1ION REFOR1 FOR BRINE DISPOSAL, App,era.apt.,S•30-8g
�� E PA HYDROCARBON S1 ORAGE, OR ENHANCED RECOVERY WELL
NAME AND ADDRESS Of SURFACE OWNER
DAME ANC ADDRESS Of DUSTING PLRMITTEE
•
WYE COUNTY FE RMIT NUMBER
Levu writ AND OLTIL INE UNIT ON
e
SECTION PVT — iA0 ACRE' SUM ACE LOCATION DESCFIfTION ,
N 'A Of Is Of 'F SEC1ION TOWNSHIP RANGE
I --I---1— LOCATE WELL IN TWO DIFECIION5 FROM NLAFEE1 LINES Of OULFIEF SECTION AND DRILLING UNIT
4-1---4— I I I •
Eunice
II I ��� Location_h.item IN/S)_Line of coiner section
TTTint_t.nom II/WI_ line rd cue net minion
�_�----I— "I I I rr• ��W� ELL FAC1IVm TYPE OF PERMIT •
E 0 0 Erin.Disposal ❑ Indivioual Estimated Fracture Freaaure
I I II Lnhenced Recovery 0 Area of lnjenion Zone
_1�_1 1-l.- G Hyoiaerbon Storage Number of Wells—
—1 1I I I I A not paled Deily Injection Volume lEblsl I Injection Interval
�J_ 1 11 1��_1� <vrrape I M.,imum Feel so Feel
I— I I I ' Ami[ipaletl Deily Injection Frinure IPSO Depth l0 bottom of Lowerml r Fns?waur Formation
S Ifni)
Average . Me,imum
type of Injection f luio'Chad the eppraprian NOUIs(1 Leese Nettle
Well Number
0 Sall Water ❑Euriish Wilts 0 fresh Water
0 Liouid Hyorocerbon 0 Other Name of Injection Zone
e Drilling boonDate Well Competed Permeability of Injection 2one t
•
Family of Injection Zone
I DON%Completed
Ea LNG A ND I UE LNG CEMENT HOLE
----------
OD Site Wk/Ft—Grace— New or Used Depth leeks CAN Depth eh Demeter
INJIClION ZONE STIMULATION _ WIRE TINE LOGE.LIST LRCM TYPE
—.---------
Mammals end Amount Used lop lypes lopped Intervals
uervallrealed
pleat Anichments A— E Hired on the reverse.
CER7IFICAI ION •
!certify under the penalty o!law that Hat personally eirsmined and am lamellar with the information
submitted in this document and all attachments and that, based on my inquiry of those individuals •
immediately responsible lot obtaining the information, I believe that the information is true, accurate,
and complete.l am a ware that the/e are significant penalties for submitting/a/se information,including
the possibility of line and imprisonment. (Ret 40 CfR 144.32A
AND OFFICIAL TITLE ryka,a OP a OHO • DATE SIGNED
• pp.' rll Nc.;000.OOr2.Approver espies 5.304E
UNI1ID:li1lt I NVIFONMENIAL PPO7I
WAS NINGT ON.DC 2000
:, E PA ANNUAL DISPOSAL/INJECT IONNWEND MA ONIIASE o ORING SURFACEWREPORT
NA-pa.AND ADDRESS Of EJtISTING PEFMfiTEE
NER
FLFMII NUMEER
• S1ATE COUNTY
LOCATE WELL iND— 0trAD ANCRESn� SUFIACE LOCATION DESCRIPTION SECTION PLAT — r ri I CTION 1OWNSHN RANGE
LO(11(WILL IN TWO DIRECTIONS I FOM ALA St El LINTS 01 OUA Fl F SIC110N AND ORILUNG urn
I I.. T 1 I I suds» L{rM d owner amnion
I I I Ipu1Nn_ft.tom IN/SI_-
---rT' T_rT_ ,oy� l.firm rl —_ limdc�rnYPE0 n
�. I I I .I' I I WELL hCIIVITY TYPE Of WIWI
D Individual
I I I I I E Devine ced Fe DArea
D I nht nced Fearer/yy__I__L1 1� D Hewoce:Don:Tereus Number of WellS�
1 I Well Number
—tI I--i II I ( Irtee Nemt
t�
_1 I I I I I
a
1 VF ING—Gel ING ANNULUS PRESSURE
101AL VOLUME INJE Cl ED (OPTIONAL mow OPING)
INJECTION PRESSURE MINIMUM P110 MA}IMUM PSIG
Fs* Pal ma
MONTH YEAR 'VI Fi GI PSW MA}IMUM P.W
------------ -----
CERIIFICAlION
ICe/uly under the penalty ol law that Ihive personally°e iinedandamfa 1dYl(IUmilial ththeeals riinformation
or ationsubmitted in
el
onor
this document i for all attachments'believe
and he bated n ti my inquiry
possibility of and in aware
imprisonment t heel.40
obtaining the information,I bEIIEYE that the inlet nation is true, accurate, and complete.lain that there are
obtsigaining
penalties for submining false inlo/melion including the p Y
CfR 144.32A DATE SIGNED
NAM(AND Of I KIAL TITLE(freest ow 9:pilau SIGNATURE
i c.7000ADe5.AAprtrai eloirq SS-3°41®UN0f0. ell5INVIFDNMI„In FFOlECl10N AGE �
WASHINGTON,DC i0e60
. EPA WELL REWORK RECORD
.AME AND ADDRESS DI PIRMIT1EE NAME AND ADDRESS OF CONTRACTOR
STATE I COUNT FE RMII NUMGER
LOCATE WELL AND OUTLINE UND ON
SECTION PLAT- AO ACRES
6
'UREACE LOCATION DESCRIPTION
N 'A Of to OF '4 SECTION TOWNSHIP RANGE
IOCelvvt-^'^'r•' • I ANC KLINGUNn
4--1--Tr- I_ ---4- Sunaw
• I I I I I I Ioutran_h.from IN/S1—_line of moaner section
TITTT I Inc_ I hem If _-line of(stoner senior
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*----4" -- WELL ACTIVITY 7 ota l Depth Ee fore Fe wore TYPE OF FE RMI1
I I I I I I I 0 Stine Disposal C Inoivicual
r I E C'E nnenceo Recovery •
1.--!--14- I -I-1- C'Fyor oca rpon Storage Tafel Depth Alter Rework N�mpel of Wells
I I I I I I Lien Name DEN Frwori Commences
1--1— ".7t-t--t-
1_1_1_1_1__L
Well Number
_1 I Date Rework Campine
c
WELL CASING RE CORD- EEiORE RE WORK
Casino I Crmem _ Fenorouone I Am or Protium
-P fir Depth I Eerie I hoe I From I le lrenmrm Fenn
1I I
I
1
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WE IL I CASING F E CORD- An E R REWORK (mtit'll Additions and Chenpes Only)
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Sin Depth I Saes' I lope I Irons I it _ treatment Fawn 1
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USE ADM,ZONAL SHEETS IF NECESSARY I4r Log Types I loppeo Imervaq
I
CE Al IF 1CM ION
/certify under the penalty of law that I have pets onally eF amined and am familial with the information
submitted in this document and all attachments and that, based on my inquiry of those individuals
immediately responsible lot obtaining the information, /believe that the information is true, accurate,
and complete.lama wale that there ate significant penalties lot submitting false information.including
the possibility of line end imprisonment. (Ref. 40 CM 144.321.
ND OFFICIAL TITLE/Rose type of Aunt/ SIGNATURE DATE SIGNED
C 17:rat INt'.FCrMtNiK ',WIC kGINC1 • ._ -.-. -•_•••_ ' ••-:•
wa tT'INGTCN.CC :cat
r (� A H FLUGGiNG RECORD •
P N.ul.•t el:alts Ll :1LINLN:• :C+•aawT •
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' . CERTIFICATION •
•
I certify under penalty of law that this ccccmeflt and
l l ettnea cnto rntsatsu were
Uutprepared
diedender
rson-
direction or supervision in act:rcance with a system d alt
nil properly cutler and evaluate the infor.•ation Tuoaitteo. Eased on my inquiry of the person
',he aerate the system. or these persons directly restcrsible for gathering the
or Fer_cns
• information, the infcrnatioe sutfnitted is, to the best of my' Inowleooe and belief, true.false
accurate.
and cc,nplete. 1 es aware that there are significant penalties for sutmitt:ng
information, including the possibility of fine.and 'imprinscment for knowing violations.
(REF. AO CFI 122.22)
GATE FIONEY
OFFICIAL TTild Flew nfP v Snag.
I SIGNATUAE
0 i 9 G
Mechanical Integrity Test • -
•
Casing or Annulus Pressure Mechanical Integrity Test
U.S.Environmental Protection Agency
Unoerrround Injection Control Fromm
EES 1E'°Street,Suite 500 Denver,CO b0202•246E
Date: / /
EPA Witness:
Test conducted by:
Others present
7spc: ER SWD Status: AC TA UC •
We11 Name:
Field:„------Sec_ 7 _N/S R_E/W County: State:__
Location�—
Operator: PSIG
Last M17; 1`9aximum Allowable Pressure:
1s this a regularly scheduled ten? ) Yes
`
No
initial ten for permit? I 3 Yes No
•
Test after well rework? [ .3
I I YesNo bpd
Well injecting during test? I I Yes I ] No If Yes, rate:
Pre-test casinE/rubinE annulus pressure:
Psi&
MIT DATA TABLE
Test ] Test #/2 Ten #3
TUBING PRESSURE
Initial Pressure
psis pals psig
_ si Psis
End of test pressure pats p &
CASING/TUBING ANNULUS psig PRESSURE psis — PsiB
0 minutes psig
5 minutes psis psis
]0 minutes
psig psig psig
15 minutes
psig psig psig
20 minutes
Psis psig psig
psig psig psig
25 minutes
30 minutes • psig psig psig
_ minutes
psig psig psig
minutes • psig psig psig
S 1 . l Pass I ]Fail • I ] Pass I .]Fail _I ] Pan - I Wail
RESULT •
Does the annulus MECHANICAL INTEGRITY PRESSURE TEST •
Additional comments for mechanical integrity pressure test, such as volume of.fluid added to annulus
.....i i,md back at end of test, reason for failing test (casing head leak, tubing leak, other), etc.:
APPENDIX C
(PLUGGING & ABANDONMENT PLAN)
EPA Final Permit No. CO 10938-02115 Page 33 of 105
Plugging and Abandonment Plan
Immediately prior to plugging and abandoning the Suckla Farms #1 disposal well,
the retrievable tension-type packer will be released and the tubing and packer will
be removed from the wellbore.
2. Run back into the wellbore with a tubing string to the bottom of the 5-1/2 inch
casing and condition the wellbore. Place a 250 foot cement plug from about 9,225
feet to 9, 476 feet, using either Class B type II neat cement or an equivalent Class G
cement. Wait sufficient time for plug to set and tag plug with tubing string.
3. Cut the 5-12 inch long string casing at approximately 7,200 feet and pull the casing.
Run into well with a tubing string and condition the well with 9.6 ppg bentonite
or plugging gel. Set a 200 foot plug, using Class "G", or equivalent type cement,
from 7,100 feet to 7,300 feet (a minimum of 75 feet below the top of the casing
stub. If the casing is not pulled, the 5-1/2 inch casing must be perforated at 7,200
feet and cement squeezed into the annular space.
4. Within the 8-5/8 inch surface casing and the 7-7/8 inch wellbore, set a 100 foot
plug, using Class "G" or equivalent cement, from 709 feet (50 feet above the
surface casing shoe) to 809 feet. If the casing is not pulled, the 5-1/2 inch casing
must be perforated at just below the casing shoe and cement squeezed into the
annular space.
5. Within the 8-5/8 inch surface casing, set a cement plug, using sufficient Class "G"
cement to fill the surface casing from the surface to a minimum depth of 50 feet.
If the casing is not pulled, the 5-1/2 inch casing must also be filled with Class "G"
cement to a minimum depth of 50 feet.
6. After the wellbore is plugged the Permit requires cutting off the 8-5/8 inch casing 1
to 3 feet below ground surface. A steel cap dry hole marker is required to be
welded on the 8-5/8 inch casing. The surface must then be restored to landowner
and/or County requirements.
EPA Final Permit No. CO 10938-02115 Page 34 of 105
APPENDIX D
(CEMENT BOND LOGGING TECHNIQUES AND
INTERPRETATION)
EPA Final Permit No. CO 10938-02115 Page 35 of 105
APPENDIX D
(CEMENT BOND LOGGING TECHNIQUES AND
INTERPRETATION)
EPA Final Permit No. CO 10938-02115 Page 35 of 105
a UNITED SlAlES ENVIRONMENTAL FRO1ECTION AGENCY
y REGION Vitt
a t.rn 1 :;5 tEth STREET • SUITE 100
ei DENVER. COLORADO 50202.2466
..ee�� ;,,, ... 1994
APR. 1 °
SUBJECT: GROUND WATER SECTION GUIDANCE NO. 3interpretation
Cement bend logging techri es and
FROM: TOM Pike, Chief �
UIC Direct Implementatio Section
All—Section-Staff
-.-.. .._. .....
T0: All_._..�ecti -- -
Montana Operations Office
These procedures are to be followed when running and
interpreting cement bond logs for injection and production (area
of review) wells.
•
FART I - PREPARE THE WELL
Allow eaaent tc cure :or a sufficient time to develop full s forpr hours. Ifth. A safe bet run the bond1logo let beforehe theement cementure
for 72 the log may show
achieves its maximum compressive strength,
poor bending. Check cement handbooks for curing times.
Circulate the bole with a fluid (either voter or mud) of
unifcrs ccatistencp. Travel times are influenced by the
type of fluid in the hole. If the fluid changes between two
pcints, the travel times may "drift, " czu; ing difficulty in
interpretation and quality control. .
Be prepared tc rut the cement bead log under pressure to
reduce the effects of micro-annulus. Micro- annulus may be
caused by several reasons , but the eXitencecement's ability to
micro-
annulus does not necessarily destroys
e form a hydraulic seal. If the log shows poor bonding, rerun
the log with the slightly more pressure on the casing as was
present when the cement cured. This will cause the casing
to expand against the cement and close the micro-annulus.
FART II - PARAMETERS TO LOG
Amplitude (mV) - This curve shows how much acoustic signal
reaches a receiver and is an important indicator of cement
bond. Record the amplitude on the 3 foot spaced receiver.
Travel time (pa) - This curve shows the amount of tine it
takes an acoustic signal
between
nnt weight,
the
source
tand a
receiver. For free pipe of a given redictable , although
travel time between points is very p
variable among different company ' s tools . Service companies
should be able to provide accurate estimates of travel times
rforequired
free d aspe a ufalityvccntrol measurement.n size end ht. Travel
Recordtthe is
required as a quality Y
travel time on the 3 foot spaced receiver.
arau...a fnrd•r new
variable among different company' s tools . Service companies _
should be able to provide accurate estimates of travel times
for free pipe of a given size and weight . Travel time is
required as a quality control measurement. Record the
travel time on the 3 foot spaced receiver.
Variable density (VDL) - Pipe signals, formation signals,
and fluid signals are usually-easy-to recognize on the VDL.
If these signals can be identified, a practical
determination for the presence or absence of cement can be
made . VDL is logged on the 5 foot spaced receiver.
Casing collar locator (CCL) - Used to correlate the bond log
with cased hole logs and to match casing collars with the
collars that show up on the VDL portion of the display.
Gamma ray - Used to correlate the bond log with other logs .
PART III - LOGGING TECHNIQUE
Calibrate the tool in free pipe at the shop, prior to, and
following the log run. Include calibration data with log.
Run receivers spaced 3 feet and 5 feet from transmitter.
Run at least 3 bow-type or rigid aluminum centralizers in
vertical holes, 6 centralizers in directional holes. A CCL
is not an adequate centralizer.
Complete log header with casing/cement data, tool/panel
data, gate settings and tool sketch showing centralizers .
Set the amplitude gate so that skipping does not. occur at
amplitudes greater than 5 mV.
' Record amplitude with fixed gate and note position on log.
Record amplified amplitude on a 5X scale for low amplitudes .
Record .amplitude and travel time on the 3 foot receiver.
Record travel time on a 100 ps scale (150 - 250, 200 -
300) .
Logging speed should be approximately 30 ft/min.
Log repeat sections.
e . Printed on Recycled Paper
• r
PART IV - QUALITY CONTROL
Compare the tool calibration data to see if the tool
"drifts" during logging. Differences in the calibration
data may require you to re-log the well to obtain reliable
data.
compare repeat sections to see if logg .nq results are
repeatable.
Check the logged free pipe travel times with the service
company charts for the specific tool and casing size used.
Since the travel times depend on such factors as casing
weight , type of fluid in the hole, etc. , these charts should
be used only as guidelines . When you are confident of the
free-pipe travel times as seen on the log, use them. When
interpreting the log, a decrease in travel time (faster
times) with simultaneous reduction of amplitude may show a
de-centered tool . A 4 to 5 micro-second (us) decrease in
travel time corresponds to about a 35% loss of amplitude. A
decrease in travel time more than 4 to 5 as is
unacceptable.
PART V - LOG INTERPRETATION
Do not rely on the service company charts for amplitudes
corresponding to a good bond. These amplitudes depend on
many factors : type of cement used, fluid in the hole, etc.
To estimate bond index, choose intervals on the log that
correspond to 0% bond and 100% bond. Read the amplitude
corresponding to 100% bond from the best-bonded interval on
the log (NOTE: the accuracy of this amplitude reading is
very critical to the bond index calculations) . Next, find
the amplitude corresponding to 0% bond. Some bond logs may
not include a section with free pipe . In this instance,
choose the appropriate free-pipe travel time from the
service company charts for your specific tool, or from the
generalized chart (TABLE 2) at the end of this guidance. To
calculate a bond index of 80%, use the following equation:
A - 10[(0.2)Iog(A0)+ (0.8)log(A1100)]
80
where :
A80 = Amplitude at 80% bond (mV)
A0 = Amplitude at 0% bond (mV)
•
-- Printed on Recycled Paper
1
A100 = Amplitude at 100%-bond (mV)
EXAMPLE:
As an example, consider a bond log showing the following
conditions :
Free one (0� bond) amplitude at -81 mV.
- 100 % bond amplitude at 1 mV.
Substituting the above values into the equation results in:
A = 1 o[(0.2)log(81)+ (0.8)Iog(1)l
80
A80= 2.41mV
Another way to calculate the amplitude at 80% bond is by
plotting these same log readings on a semi-log chart .
Plot the values for 0% Bond and 100% Bond vs . their
respective Amplitudes on a semi-log chart - amplitudes on
the log scale (y-axis) , and bond indices on the linear scale
(x-axis) . Then, connect the points with a straight line.
To estimate the amplitude corresponding to an 80% Bond
Index, enter the graph on the x-axis at 80% bond. Draw a
straight line upward until you reach the diagonal line
connecting the 0% and 100% points . Continue by drawing a
horizontal line to the y-axis . This point on the y-axis is
the amplitude corresponding to an 80% Bond Index.
Printed on Recycled Paper
S
Using the values from the example above, your chart will
look like that shown below:
o ieeae�eee��e�ee�ee�ee��
t♦t111111a��
w
40
20 TI 0%BOND
0 81 mV
100%BOND
j 1 mV
W J
a 2.4 mV
0 _
,
80% BOND
0
,Y X F M [0 Oo m \/ b 'a
% BOND
In this example, 801 bond shows an amplitude of 2 .4 mV.
A convenient way to evaluate the log is to draw a line on
the bond log' s amplified amplitude (5X) track corresponding
to the calculated 80% bond amplitude . Whenever the logged
amplified amplitude (5X) curve drops below (to the left of)
the drawn line, this indicates a bond of 80% or more .
PART IV - CONCLUSIONS - REMINDERS
Different pipe weights and cement types will affect the log
readings, so be mindful of these factors in wells with
varying pipe weights and staged cement or squeeze jobs .
Printed on Recycled Paper
•
Collars generally do not show up on the VDL track in well-
bonded sections of casing.
Longer (slower) travel time due to cycle skipping or cycle
stretch usually suggests good bonding.
Shorter (faster) travel times indicate a de-centered tool or
Fast ation nd will provide—err neous—amp tude
readings that make evaluation impossible through that
section of the log. Fast formations do not assure that the
cement contacts the formation all around the borehole.
Although the bond index is important, you should not base
your assessment of the cement quality on that one factor
alone . You should use the VDL to support any indication of
bonding. Also, you must know how each portion of the CBL
(VDL, travel time, amplitude, etc. ) influences another.
Most 3 ' -5 ' CBL ' s cannot identify a 1/2" channel in cement .
Therefore, you also need to consider the thickness of a
cemented section needed to provide zone isolation. For
adequate isolation in injection wells, the log should
indicate a continuous 80% or greater bond through the
following intervals as seen in TABLE 1, below:
TABLE 1 - INTERVALS FOR ADEQUATE BOND
PIPE DIAMETER (in) CONTINUOUS INTERVAL WITH BOND z 80% (ft)
4-1/2 15
5 15
5-1/2 18
7 33
7-5/8 36
9-5/8 45
10-3/4 54
Adequately bonded cement by itself will not prevent fluid
movement. If the bond log shows adequate bond through an
interval where the geology allows fluid to move (permeable
and/or fractured zones) , fluids may move around perfectly •
bonded cement by travelling through the formation. Always,
cross-check your bond log with open hole logs to see that
you have adequate bonding through the proper interval (s) .
- Printed on Recycled Paper
•
TABLE 2 - TRAVEL TIMES AND AMPLITUDES FOR FREE PIPE
(3 FT RECEIVER)
CASING CASING TRAVEL TIME (ps) AMPLITUDE
SIZE WEIGHT (mV)
(in) (lb/ft) 1-11/16" TOOL 3-5/8" TOOL
9.5 252 233 81
4-1/2
11.6 250 232 81 .
13.5 249 230 81
15.0 257 238 76
5
18.0 255 2:36 76
20.3 253 235 76
15.5 266 248 72
5-1/2 17.0 265 247 72
20.0 264 245 72
23.0 262 243 72
23.0 291 271 - 62
26.0 289 270 62
29.0 288 268 62
7
32.0 286 267 62
35.0 284 265 62
38.0 283 264 62
26.4 301 281 59
7-5/8 29.7 299 280 59
33.7 297 278 59
39.0 295 276 59
40.0 333 313 51
9-5/8 43.5 332 311 51
47.0 330 310 51
53.5 328 309 51
40.5 354 333 48
10-3/4 45.5 352 332 48
51.0 . 350 330 48
55.5 349 328 48
FCD:Marth 31,19 4:RCTIRCTAckd.eop
4(lj'il Printed on Recycled Paper
ni n I .
D
to. UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
1/4
n REGION 8
999 18" STREET - SUITE 300
'+rr DENVER, CO 80202-2466
http://www.epa.goviregion08
January 17,2001
CEMENT EVALUATION NOTES
Compiled for the MIT Workgroup
by
Jerry T. Thornhill
USEPA, Robert S. Kerr Research Lab.
Edited
by
Paul S. Osborne
USEPA, Region VIII
Background-Acoustic Cement Bond Logging
The Reasons for cementing wells are: 1) to support the casing; and 2)to isolate zones
(hydraulic seal), such as producing horizons, injection reservoirs, and underground sources of
drinking water(USDW). When a well is completed, a cementing record will be submitted as
part of the well completion record. This information will not address the question regarding the
adequacy of the cement to isolate the various zones. One of the methods utilized to assess the
adequacy of the cementing of a well to isolate the various zones is by using an acoustic cement
bond log (CBL). Although an acoustic cement bond logs does not directly measure hydraulic
seal, the measured bonding qualities do provide inferences of sealing adequacy(zone isolation).
The bonding of cement to the casing can be measured quantitatively using a CBL. The bonding
of cement to the formation, however cannot be measured quantitatively using a CBL, but it does
provide a qualitative estimate of the bonding to the formation. Determination of cement integrity
is accomplished by an analysis of the full acoustic waveform, the amplitude or attenuation rates
of the casing arrivals, and a single receiver travel-time measurement.
The Acoustic CBL tool used to make the cement bond log puts energy into the well and
measures the energy returned. The operating frequency for all conventional instruments is 20
kHz. The time it takes for energy to return and-the amplitude of the returned energy are
determined by the cement bonding. Elastic compressional waves are propagated down the sleeve
of the instrument, vertically through the borehole fluid, and horizontally across the borehole
fluid. Of primary interest to the CBL log is the wavefront moving directly toward the casing. As
the wave front impinges upon the casing, some energy is reflected, while the balance is
transferred into the steel, the cement sheath and the formation. Acoustic energy propagates
through fluid at about 180-220 microseconds per foot, and about 57 microseconds per foot
through steel. At each of these interfaces, some energy will be reflected, and some will be
transferred into the adjoining medium. The reflected waves coming back from the various
1
0Printed on Recycled Paper
interfaces are recorded preferably by two detectors located 3 and 5 feet from the acoustic
transmitter. The log results are recorded on five curves: 1) a gamma ray curve for lithologic
correlation; 2) a casing collar locator for depth correlation; 3) an amplitude curve derived from
the 3 foot receiver as a measure of casing bonding; 4) a travel time curve which is an indicator of
the centralization of the tool; and 5) a variable density log (VDL) and or signature wave forms
from the 5 foot receiver as a measure of the formation bonding.
CBL Requirements
The requirements for obtaining a meaningful cement bond log are:
1. The Tool must be centered in the casing.
2. The transmitter and receiver(s) must be a known distance apart.
The most common transmitter/receiver spacing is 3 feet. This spacing is ideal for
measuring fastest sound travel which is through the casing and is used for
amplitude and travel time measurements. The attenuation of this signal is a
measure of the bonding of the cement to the casing. h is useless for looking at
formation bonding.
The 5 foot receiver is used to record variable density and/or signature waveforms.
This spacing will not show the casing signal but will show the formation signal.
The preferred tool has a transmitter with two receivers spaced 3 foot and 5 foot
from the transmitter. This arrangement gives the casing signal (3 foot receiver)
recorded as the amplitude curve and formation signal, (5 foot receiver)recorded as
the VDL trace.
A 4 foot spacing (single receiver) has been tried as a compromise. It still does not
show formation signals.
3. The "gate" must be set properly. Figure A-2 indicates the wave form being
investigated. T sub o represents when the tool is turned on. Dead time is the time
it takes to receive the first signal (El through El). As shown in Figure A-4, El to
E3 are measured to determine the casing bonding (3 fbot receiver signal). The
signals from this receiver give an evaluation of the amplitude changes the sonic
energy will experience on its path along the casing.
Tool systems are gated to measure a particular part of the wave train. Acoustic
logging instrumentation uses both fixed and floating gates. A fixed gate system is
one in which the transmitter is fired at fixed intervals, followed by a fixed time for
the gate to open and remain open, and fixed time interval for the gate to close.
Fixed gates are currently being used for primary bond amplitude measurements;
however,prior to development of full waveform recordings, older generation
2
CBI's used a floating gate amplitude measurement with a floating gate travel-time
curve to evaluate cement conditions.
The principle of the floating gate is that it remains open across the entire acoustic
spectrum until an amplitude pulse having sufficient amplitude to extend beyond
the threshold bias setting is found. This response is then recorded as the time of
the irct acoustic arrival pulse
The basic waveform consists of four different types of wave arrivals:
a. compressional wave in casing ,
b. compressional wave in the cement sheath,
c. compressional, shear,pseudo-Rayleigh, and Stonefey waves in the
formation, and
d. mud or fluid waves.
4. The fluid wave travels through the fluid straight to the receiver. After the fluid
wave shows up, the V DL is useless. When the fluid wave enters the receiver,
distortion occurs. Therefore, the useful part of the V DL is that prior to the fluid
wave. When shear waves are detected on the Signature or Variable Density, they
are representative of cement integrity in the overwhelming majority of cases.
5. A reliable cement bond log will have the following:
3 foot-5 foot RECEIVER SPACING
GAMMA-RA Y
CASING COLLAR LOCATOR
AMPLITUDE CURVE
TRAVEL TIME CURVE
VARIABLE DENSITY DISPLAY
Amplitude Curve Interpretation
A. A high amplitude indicates that the casing is relatively free to vibrate;
hence, it is poorly bonded or supported.
B. A low amplitude indicates that the casing is more confined or bonded,
causing absorption of the wave energy by surrounding media.
C. Amplitude measurements between maximum and minimum values are
functions of the percentage of casing bond.
3
THIS SINGLE MEASUREMENT (AMPLITUDE), AND THE OVERSIMPLIFIED
INTERPRETATION OF IT, IS FREQUENTLY THE SOURCE OF MUCH OF
THE CONTROVERSY AND ERROR REGARDING CEMENT BOND LOG
ANALYSIS.
To analyze a bond log, ignore the amplitude curve initially, go to the V DL and measure
t gsignal or free pipe Tf fh— _ ?_asi g signal is not present, the signal must have,
been attenuated. Then, go to the amplitude curve. Determine the time of the first arrivals
and their character. VDL formation signals should generally correlate with the gamma
log. The V DL is practically tamper-proof. The operator cannot change the property of
the rock, thus the time required for the signal to be transmitted.
Pitfalls in Bond Interpretation from Amplitude Response
A. Amplitude detection method -fixed gate or floating gate..
B. Instrument centering..
C. Insufficient curing time for cement.
D. Cement sheath less than 314 inch with either well centered or poorly
centered casing .
E. Micro annulus.
F. Gas bubbles in the borehole fluid.
G. Void spaces in the cement sheath.
H. Fast formation.
I. Cement bonded to the pipe. but not to the formation.
J. Changes in acoustic properties of the borehole fluid density and viscosity
die to pressure. temperature, and content.
K. Minimum amplitude signal in well bonded casing varies with respect to
casing size and casing weight.
L. Cements are mixed to particular specifications and may be designed with
different compressive strengths.
M. Cement is sometimes gas cut.
4
CBL Log Quality Checks
Free Pipe
A. Travel time indicating correct expected value for casing size and weight?
B. Travel time,magnetic collar locator, amplitude curve and variable
density/waveform all indicating casing collars on depth with each other?
C. Free pipe amplitude reading correct value for casing size and weight?
D. El arrival on variable density display indicating correct travel time to 5
foot receiver, (i.e. 114 microseconds later than 3 foot receiver travel time)?
E. Collars on amplitude curve are 3 foot in vertical height and 5 foot on
VDL. This ensures amplitude and VDL/WF are measured on proper
receiver.
Cemented Pipe
A. Travel time stretching or cycle skipping occurring in well bonded sections.
B. 100% and 70% bonded intervals consistent with minimum sonic
amplitude picked from CBL interpretation chart?
C. Is travel time less than free pipe value indicating eccentering or fast
formation ?
D. If eccentering is expected, check V DL for chevron pattern at collars and
low CBL amplitudes.
E. If fast formation is suspected, i.e. open hole logs indicate delta T less than
57 microseconds per foot, check 1" formation arrival on VDL/WF. If less
than expected free pipe value on 5 foot receiver, fast formation can be
confirmed. Note: pre-log planning will alert operator to presence of fast
formations.
F. Have log passes been run under sufficient pressure to eliminate Micro
annulus effect?
G. Does main log pass agree with repeat section?
H. Is main log pass properly conflated to open hole log? Note: if perforations
are picked from a pressure pass, make sure field personnel are aware of
5
• •
this and that proper correlation is taken into account prior to perforating.
Instrument Centering
A. If the logging instrument is properly centered in free or poorly bonded
pipe, the travel time should be a reasonably precise value.
B. Travel time measurement is the time it takes the signal to leave the
transmitter and return to the receiver. This is not formation bonding.
There is no way to tell formation bonding quantitatively. Travel time can
be very useful. It can be used to determine whether or not the tool is
centralized. Travel time will occur early if an instrument is poorly
centered.
C. Amplitude can also increase when casing is eccentered because a portion
of the annular cement sheath is either absent or extremely thin. (less than
3/4 inch).
Cycle Skip°mg
Cycle skipping to later amplitude arrivals is caused by the attenuation of pipe
arrivals.
Stretch
A. Travel-time stretch may occur when an attenuated first pipe arrival is
detected in bonded intervals.
B. Stretch is often an indication of adequate zone isolation.
•
Casing Collars
A. Casing collars are identified as a decrease in the amplitude, a slight
increase in TT, and/or clear chevron ("W")patterns on the VDL..
B. The distance between the "W"pattern corners on the V DL represents the
transmitter-receiver spacing.
C. Casing collar anomalies are typically not apparent in well bonded casing.
D. Caliper information defining the size and perhaps the shape and rugosity
of the borehole wall behind pipe is always an important criteria to log
analysis of cement condition.
6
• •
Calibration -
Well Site Calibration Procedure (Wedge Wireline)
A. With Tsol in hole and in fluid,panel output is calibrated for a linear output
relation of 100 my. for 10 chart divisions-I0 my/div. This calibration is
done in order to scale the amplitude values.
B. Secondary amplitude x 4 or x5 is calibrated.
C. Internal calibration cycle of 35 my. amplitude and 50 microseconds wave
length is activated; the Gate is set on the cycle, and amplitude deflection is
adjusted according to previous 0-100 my. settings.
D. Calibration cycle is deactivated. tool signal on 3 foot receiver is present;
the gate is set on the first compressional cycle, and amplitude reading is
verified. It should be noted that our system does not rely on free pipe
sections in order to calibrate or adjust the amplitude curve.
Shot) Calibration(Wedge Wireline)
A. The tool is centered inside a section of 5.5 inch, 15 lb/ft. casing ;
completely covered with water; the tank is pressured to 5000 psi.; the
signal on the 3 foot receiver is adjusted for a maximum output of 80 my.
B. Signal output on the 5 foot receiver is adjusted in order to compensate for
energy loss related to the 3 foot receiver, due to the extended travel time of
114 microseconds, which usually ranges in the order of 30%loss.
C. Panels are calibrated for response and linearity.
D. After the above procedure is completed, a full display of calibration is
recorded for every tool.
Notes:
An internal electrical calibration for the peak amplitude measurement is
utilized to calibrate the instrument. (Atlas Wireline)
The shop calibration fixture utilized is a 5.5 inch OD aluminum pressure
tube. The tube is filled with water and pressured up to 500 psi or greater.
7
• •
(Atlas Wireline).
Shop calibrations are required monthly or more frequently as needed.
A complete calibration sequence requires BEFORE and AFTER records,
including Signature (or V DL) and travel time calibrations.
SECOND-GENERATION RADIAL CEMENT EVALUATION INSTRUMENT
The Segmented Bond Tool (SBT) is a promising second-generation radial cement bond
instrument, which measures the quality of cement effectiveness both vertically and laterally
around the
circumference of the casing. The SBT is designed to quantitatively measure six segments, 60
degrees each, around the pipe periphery. The instrument employs an array of high frequency
steered
transducers, which are mounted on six pads. The instrument is capable of logging in casing sizes
from 4.5 inches to 13 3/8 inches with any type of fluid or gas occupying the borehole. A 5-foot
omnidirectional transmitter-receiver span is provided for Signature or Variable Density display.
The Segmented Bond Tool (SBT) examines not only the longitudinal cement quality, but also the
circumferential effectiveness of the cement sheath radially around the entire periphery of the
casing.
8
• •
CEMENT BOND LOGGING
GENERAL INSTRUCTIONS
Tool Cents alizatiuu
A. Minimum of three centralizers.
B. Preferably bow spring or rigid aluminum centralizers.
C. Position centralizers immediately above and below transmitter-receiver
section and on top of tool assembly.
II. Well Data
A. Well name, location, serial number(if any).
B. Data on cement, including type, volume,time,whether pipe was
reciprocated or rotated or both, etc.
C. Casing scratcher and centralizer depths.
D. Unique downhole conditions.
•
E. Casing data including size, weight, grade,joint type, depths. Well bore
fluid data including type, weight, and salinity.
G. Bottom hole temperature.
H. Well history for maximum previous pressure on casing.
DI. Calibration
Tool should have been calibrated at the company shop and the service company
should perform surface calibration before running tool in hole. Each service
company has their own calibration procedure. An example of one company's shop
and well site calibration procedure is shown below:
Sl r
A. The tool is centered inside a section of 5.5", 151b/ft casing; completely
covered with water; the tank is pressured to 500 psi; the signal on the 3ft
9
• •
receiver is adjusted for a maximum output of 80mv.
f 5ft ceiver is adjusted in order B. Sigal output loses o related to the 3ft., to
due to the extended travel time of 114 microseconds.
C. Panels are calibrated for response and linearity .
D. A full display of calibration is recorded for every tool. Shop calibrations
are required monthly or more frequently as needed. A copy of the shop
calibration should be attached to the log.
Well Site Calibration
A. With tool in hole and in fluid,panel output is calibrated for a linear output
relation of]00mv. for 10 chart divisions.-]0 my/div. This calibration is
done in order to scale the amplitude values.
B. Secondary amplitude X4 or X5 is calibrated.
C. Internal calibration cycle of 35mv amplitude and 50 microseconds
wavelength is activated; The gate is set on the cycle, and amplitude
deflection is adjusted according to previous 0-100mv settings.
D. Calibration cycle is deactivated. Tool signal on 3 foot receiver is present;
the gate is set on the first compressional cycle, and amplitude reading is
verified.
IV. Complete Log Heading.
V. Run V DL,MSG, Signature,X-V plot on 200-1200 microsecond time scale.
VI. Run repeat sections (200' minimum) through intervals of interest or intervals with
questionable bond.
VII. Logging speed should be 1800 feet/hr.
VII, If tool is improperly centralized, do not continue to log. Pullout of bole and adjust or
replace centralizers.
IX. Upon completion of logging run, check surface calibration.
10
• •
ACOUSTIC CEMENT BOND LOGGING
CHECK LISTS
INFORMATION REQUESTED PRIOR TO RUNNING CEMENT EVALUATION LOGS
I. CEMENT DATA.
A. Types, volumes, slurry weights,pumping rate.
B. Estimated compressive strength.
C. Date and time cementing operation was completed.
D. Additives.
E. A copy of Cementing Report would be helpful.
II. ASSOCIATED CEMENTING PROBLEMS.
A. Lost circulation?
B. Unable to reciprocate? Stuck pipe?
C. Abnormal pressures held after plug down? How long? •
III. CASING INFORMATION.
A. All strings --- size, weight, grade, coupling(flush Joint?)
B. Top/bottom depths --- overlaps? Annular thickness?
C. Cementing aids ---scratchers, centralizers, hydrobonders -where?
IV. WELL INFORMATION.
A. Straight hole or deviated? If deviated, at what depth? Degree?
B. Bit size?
C. Wellbore fluid? Accurate density? Same as plug down fluid?
D. Casing problems? Liner not set? Potential for gas cut fluid?
•
11
• •
E. Open perforations? Unable to pressure up?
F. Wellhead connection required? Need pump-in sub?
G. Any previous cement analysis done? Temperature logs?
I. Has coated casing been run in well?
J. Squeeze guns brought w/CBL?
CBL LOG QUALITY CHECKS
FREE PIPE
A. Transit time Indicating correct expected value for casing size and weight?
B. Transit time,magnetic collar locator, amplitude curve and variable
density/waveform all Indicating. Casing collars on depth with each other?
C. Free pipe amplitude reading correct value for casing size and weight?
D. El arrival on variable density display indicating correct transit time to 5 foot
receiver, (i.e. 114 microseconds later than 3 foot transit time)?
E. Collars on amplitude curve are 3foot in vertical height and 5 foot high on VDL.
This ensures amplitude and VDL/WF are measured on proper receiver.
II. CEMENTED INTERVAL
A. Transit time stretching or cycle skipping occurring in Well Bonded Sections?_
B. 100% and 70%bonded Intervals consistent with minimum Sonic amplitude picked
from CBL Interpretation chart?
C. Is transit time less than free pipe value Indicating eccentering or fast
formation?
D. If eccentering is expected, check V DL for Chevron pattern at collars and low CBL
amplitudes.
12
E. If fast formation is suspected, i.e. open hole logs indicate—T less than 57
microseconds per foot, check 1st formation arrival on VDLWF. If less than
expected free pipe value on 5foot receiver, fast formation can be confirmed. Note:
pre-log planning will let .us know whether fast formations are expected.
F. Have log passes been run under sufficient pressure to eliminate Micro annulus
effect?
G. Does main log pass agree with repeat section?
H. Is main log pass properly correlated to open hole log? Note: if perforations are
picked from a pressure pass make sure field personnel are aware of this and that
proper correlation is taken into account prior to perforating.
13
APPENDIX E
(GUIDANCE - TEMPERATURE LOG)• I .
zi 41, 0: 1-:7
• }i ,, }k1i1 ±� # ''`• !: .:
X11 , 1`;> I •
• •! +) r }�7 f�ti' ����'1 � )V t )�� ' •
EPA Final Permit No. CO 10938-02115 Page 56 of 105
psitinn.%. UNITED STATES ENVIRONMENTAL PROTECTION •ENCY
LZral
REGION VIII
PR 999 18th STREET - SUITE 500
DENVER, COLORADO 80202-2466
TEMPERATURE LOGGING FOR MECHANICAL INTEGRITY
January 12, 1999
PURPOSE:
The purpose of this document is to provide a guideline for the acquisition of temperature
surveys, a procedure that may be used to determine the internal mechanical integrity ot tubing aria
casing in an injection well. A temperature survey may be used to verify confinement of injected fluids
within the injection formation.
Test results must be documented with service company or other appropriate (acceptable)
records and/or charts, and the test should be witnessed by an EPA inspector. Arrangements may be
made by contacting the EPA Region 8 Underground Injection Control (UIC) offices using the EPA toll-
free number 1.800-227.8917 (ask for extension 6137 or 6155).
LOGGING PROCEDURE
Run the temperature survey while The tool need not
going into
the hole,
, with
centralized.temperature sensor located as close to
the bottom of the tool as possible.
Record temperatures a 1.5°F per inch, on a 5 inches per 100 feet log scale.
Logging speed should be within 20 • 30 feet per minute.
Run the log from ground level to total depth (or plug-back depth) of the well.
When using digital logging equipment, use the highest digital sampling rate as possible. Filtering
should be kept to a minimum so that small scale results are obtained and preserved.
•
e maximum llowed on prssure.oethe tethe first lg trace while injeting at up to mperatuore survey, the maximum injection hpressu a will abe limited to'the pr Subsequent
used during
the survey.
LOG TRACES
Log the first log trace while the well is actively injecting, and record traces for gamma ray,
temperature, and differential temperature. Shut-in (not injecting) temperature curves should be
recorded at intervals depending on the length of time that the injection well has been active. Preferred
time intervals are shown in the following table:
._ .............::::...:..::,.:�.;::n:.'..,;:��:<::::.::..:...:.:.::»:.::,C::R::D`>d�::!L≥^; !iii%��i53is;�i>iQ:.�a:?Rii�::.
,
� :f• Ca S0. � \(.` -... ,
�� k � Acilve ........... ....................... �.. .,v.�.., . � :Record Curves at These.T�ines {In.<Wbtfr
1 3 6 12
1 month
6 months 1 6 10.122 22.24 .
1 year 1 10.12 22.24 45.48
5 years 1 10.12 22.24 45.48 90.96
•
or 1 22.24 •4
HAUI C\RB UI C•Gui clan c e\I NFOJe m p L og.wp d
FY.
Printed on Recycled Paper
APPENDIX F
(GUIDANCE FOR CONDUCTING A RADIOACTIVE
TRACER SURVEY) -
,'f J ) )) "sir NJI , •D
• il rq 1, . ' .it': .11;1 ,,..,., ..., it In .i ,;10i j 1
. . . If" ' titillii ritiltiltlittlot,...D.
EPA Final Permit No. CO 10938-02115 Page 58 of 105
y"'E°st"fs. UNITED STAT ENVIRONMENTAL PROTECTIOfGENCY
th I REGION VIII
kr 999 18th STREET - SUITE 500
DENVER, COLORADO 80202-2466
RADIOACTIVE TRACER SURVEY
January 22, 1999
PURPOSE:
The purpose of this document is to proviacquisition of a radioactive
tracer survey (RATS), a procedure that may be used to determine whether injected fluidsmay
• migrate vertically outside the casing after injegt Tl,guidance may be used to develop a well-
specific survey plan that accounts for specific wen cortttW/ction and operation considerations.
Prior approval of planned RATS procedures by EPA is strongly recommended.
Radioactive Tracer Survey results must be documented with service company and other
appropriate log records and/or charts, and the test should be witnessed by an EPA inspector.
Arrangements may be made by contacting EPA Region 8 Underground Injection Control (UIC)
offices using the EPA toll-free number 1.800.227-8917 (ask for extension 6155 or 6137).
RECORDING GUIDELINES
The logging must be done while the well is injecting at normal injection pressure and rate. The
pressure and rate should be brought to equilibrium conditions prior to conducting the survey.
The survey tool must include a collar locator for depth control, an injector, and two detectors (one
above and one below the injector).
Vertical log-scale may be one inch, two inches, or five inches per 100 feet.
The Gamma Ray log may be run at up to 60 feet per minute (ft/min) at a time constant (TC) of
one second, or up to 30 ft/min at a TC of 2 seconds, or up to 15 ft/min at a TC of 4 seconds. The
logging speed and time constant used must be indicated on the log heading.
The horizontal log scale must be recorded in standard API Units (or in counts per second).
The gamma ray (GR) sensitivity must be set so that the tracer will be obvious when detected and
will not be confused with normal "hot spots" in the logged formations (e.g., the gamma ray
sensitivity set so that the lithology can be correlated by recording a "base log").
Record the beginning and ending clock times of each log pass.
Record the injection pressure and rate during each log pass.
Record the volume of fluid injected BETWEEN log passes.
Record the type, volume, and concentration of each tracer "slug" used.
Show the percentage of fluid loss across the perforated interval(s).
Printed on Recycled Paper
•
RECOMMENDED PROCEDURE:
With the GR sensitivity set for the lithologic correlation log as outlined above, run one "base log"
from the injection zone to at least 500 feet above the injection zone (or at least 200 feet above the
top of the confining zone).
� ,, ,a operatine +hP weli at normal operating injection pressure and rate, and continue to do
so until the pressure and rate become stabilized.
Set the tool so that the injector is positioned just below the tubing packer and inject a "slug" of
tracer.
tracer iation within the Reduce the Gpershorizontal scale).ivity enough to keep the To do this,entire non•re orrdedepass through the slug may bedth of
run.
the chart pap
Drop tool to an appropriate depth below the slug and record Log Pass #1. Log to above the upper
interface until the radiation level returns to the same level as below the slug. Drop tool to the
appropriate depth below the slug and record Log Pass # 2 in the same manner as #1.
Repeat log passes process until the tracer slug strength dissipates to one tenth (1/10) of original
strength me settings
sedfo on Log Pass a d lotfrols mthe injectionoint, reset lncrease) the zone to at least 500sfeetty to above the einjection zone
used for the base log, 8
(or at least 200 feet above the top of the confining zone).
Drop tool to an appropriate depth below the slug, reset (reduce) the GR sensitivity to that used for
logging (same setting as Log Pass #1), and record a log pass up to the packer. Repeat this
logging process until the tracer slug is gone or has completely stopped. Then reset (increase) the
GR sensitivity back to the base log setting and make a final logging pass from the injection zone to
at least 500 feet above the injection zone (or at least 200 feet above the top of the confining zone).
This final pass should show a close similarity to the pre-test base log response. NOTE: More than
one pass may be shown on a log segment as' long as each. separate GR curve with its
corresponding collar locator are distinguishable, otherwise record each pass on a separate log
segment.
Drop and set the tool at the depth where the bottom detector is just above the uppermost
perforation and inject a slug of tracer (the tool remains stationary for this logging record). As the
slug moves past the bottom detector, the log trace should show an increase in the GR response.
Hold the tool at this depth while pumping at the equilibrium pressure and rate.
SUBMITTING THE RESULTS:
An interpretation of the logging results must be supplied when submitting the data for EPA
approval. The interpretation must include a fluid loss profile across the perforations, in
increments of at least 25%
Include a schematic diagram of the well construction on or with the log. The diagram should show d depth,intervals,
casingtot diameters eph u depths,back total depthing ,ander s the location ofthe tool when the slug wa interval, any open s
inj a to . depth or plugged
injected. Also, indicate with arrows the pathway(s) the tracer slug appears to have gone.
-APPENDIX G
(GUIDANCE FOR CONDUCTING A PRESSURE TEST TO
DETERMINE IF A WELL HAS LEAKS IN THE TUBING,
CASING OR PACKER)
EPA Final Permit No. CO 10938-02115 Page 61 of 1O5
•
� "
$' v UNIlEDPA1ESVIRONMEN1AL FRO1EtON A'CY
REGION VIII
699 iEth STREET - ELIME sots
DENVER, COLORADO 60201.2466
EUEJECT: GROUND WATER SECTION GUIDANCE N0. 39
Pressure testing injection wells for part I (internal)
Mechanical Integrity
FROM: Tom Pike, Chief
UIC Direct ]mplementation Section
TO: All Section Staff •
Montana Operations Office
Intros tL°n
The Underground Injection Control (UIC) regulations require
that an injection well have mechanical integrity
watl all
hlstimes (40
mecand (1) )
hanical integrity (40 CFR 146.8) if:
(1 ) There is no significant leak in the tubing, casing or
packer; and
(2) There is no significant fluid movement
Uininto
1) anrough
an
underground source of drinking water
vertical channels adjacent to the injection wellbore.
Definition: Mechanical Integrity Pressure Test for Part I .
A pressure test used to determine the integrity of all the
downhole components of an injection well, •usually
tubing, casing and packer . It is also used to test tubing
cemented in the hole by using a tubing plug or retrievable
packer . Pressure tests must be run at least
ncel every
tfive
years. If for any reason the tubing/packer eas is
pinjection well is required to pass another mechanical
integrity test of the tubing casing and packer prior to
recommencing injection regardless in enh s o
ss of wh
en tee last
f an wwas
conducted. Tests run by op
PA
inspector must be conducted according to these procedures
and recorded on either the attached form or an equivalent
form containing the necessary information. A pressure
recording chart documenting the actual annulus test
pressures must be attached to the fcrm.
•
This guidance addresses making a determination of Part I of
• packer) - e _Reoicn, (npolicys in is : 1)�etoudeterminelng or
if there are
packer) • k.. in the tubin casing or acker; 2) to assure
significant lea similar th wh '
that the casing can withstand re.,sure
:a..
Printed on Recycled Pepe
• • • • ® •
would be applied if the tubino or packer fails; 3) to make the
Region ' s test procedure consistent with the procedures utilized
by other Region VIII Primacy proorams; and 41 to provide a
procedure which can be easily administered and is applicable is
ail class I and JI wells .• Although there are several methods
cllowed for determining mechanical integrity, the principal
method involves running a pressure test of the tubi,iy/casing
annulus . Region VIII ' s procedure for running a pressure test is
intended to aid UIC field inspectors who witness pressure tests
for the purpose of demonstrating that a well has Part I of
Mechanical Integrity. The guidance is also intended as a means
of informing operators of the procedures required for conducting
the test in the absence of an EPA inspector.
Pressure Test Description
Teso uenc
The mechanical integrity of an injection well must be
maintained at all times . Mechanical integrity pressure tests are
required At_liAgi every five (5) years . If for any reason the
tubing/packer is pulled, however, the injection well is required
to pass another mechanical integrity test prior to recommencing
injection regardless of when the last test was conducted. The
Fecional UIC program must be notified of the workover and the
prcpcsed date of the pressure test._ The well 's test cycle would
then start from the date of the new test if the well passes the
test and documentation is adequate. Tests may be required on a
more frequent basis depending on the nature of the injectate and
the construction of the well (see Section guidance on MITs for
wells with cemented tubing and regulations for Class I wells) .
Region VIII 's criteria for well testing frequency is as
follows:
1 CFRss I hazardous 146. 68 (d) (1) ) andte annuallylon wells; initially (40
thereafter;
2 . Class I non-hazardous waste injection wells; initially
and every two (2) years thereafter, except for old
permits (such as the disposal wells at carbon dioxide
• extraction plants which require a test at least every
five years) ;
3, Class II wells with tubing, casing and packer;
•
initially and at least every five (51 years thereafter;
4 . Class II wells with tubing cemented in the hole;
initially and every one (1) or two (2) years thereafter
.'sl.
fumed on Rreyd d faOe
depending on well specific conditions (See Region VIII
UIC Section Guidance 4136) ;
5. d) II well
s which have been temporarily abandoned shut-in for
(TAd) must be pressure tested after being
two years; and
6. Glass III uranium extraction wells; initially.
«u� .. -_. _....__ ..
Testes detect significant
assure that the test pressure willpressure similar to
sTand�that the casing is subjected to press
leak_ would be applied if the tubing or packer fails, the
that which -t � prEffure a al to t e
wing annulus should ebevseford] 000 n:ia whichever
tubing/casing
},eve a difference
maximum
�e gams infection hc.vever
]ems The a200 r test ersnreaure must
Either rester or Jess tln n the niectJor�
of at least i0e `Ve] Js which in-ect at ressures of Jena than
vre _00 psis -nd the
tO0 7E- • rEEEUre of
must tent at a minimum?00 sJ difference between the annv] vn and the infection tvbJng
ZEcct77E dJ ff 200 E
Mtn be at Jess
7-S—Critejil
The duration of the pressure test is 30 minutes .
1 • «ur s should be
tubino ,re_. cif tes ,
•
2 . moth the annulus an d ver fiv 1��_
mon 't red and r •
ercent or more
3. If there is a pressure change of 10 P
from the initial test pressure during the 30 minute
duration, the well has failed to
dtoudemonil st_aite
rmechanical
r
integrity and should be
plugged.
A : A pressure change of 10 percent or more is considered
significant. If there is no significant pressure
change in 30 minutes from the time that the pressure
source is disconnected from the annulus, the test may
be completed as passed.
RecordkeePin9
and Reporting The test results must be recorded on the attached form.
The
The
annulus pressure should be recorded at five (5) minute intervals .
Tests run by operators in the abseneofaan EPA
oinsp cto must be
r
e
according to these p ce pressure
attachedconductedequivalent form and a p
attached form or an e9
-- Punted on Ascyc d Paper
• S . . •® • •
•
-. chart documenting the actual annulus test pressures must be
attached to the submittal . The tubing pressure at the beginning
and end of each test must be recorded. The volume of the annulus
fluid bled back at the surface after the test should be measured
and recorded on the form. This can bed associated t
onebybding the
nto a
annulus pressure oar �„J dirchcrigingh
e five gallon container. The volume information can be used to
verify the approximate location of the packer.
procedure for pressure Ted
1 . Scheduling the test should be done at least two (2)
weeks in advance.
2 . Information on the well completion (loiationeofnt of he
eork
packer, location of perforations, p
on the casing, size of casing and tubing, etc. ) and the
results of the previous MIT test should be reviewed by
the field inspector in advance of the test. Regional
UIC Guidance W35 should also be reviewed.
wInformation
relating to the previous MIT and any well
should be reviewed and taken into the field for
verification purposes.
3. All Class I wells and Class II • SWD wells should be
shut-in prior to the test . A 12 to 24-hour shut-in is
preferable to assure that the temperature of the fluid
in the wellbore is stable.
q , Class
ith enhanced
test, butrecovery
is recommendedethat the operating well be
during
shut-in if possible.
5. The operator should fill the casing/tubing annulus with
inhibited fluid at least 24 hours in advance, if
possible. Filling the annulus should be undertaken
through one valve with the second valve open to allow
air to escape. After the operator has filled the
annulus, a check should be made to assure that the
annulus will remain full . If the annulus can not
maintain a full column of fluid., the operator should
notify the Director and begin a rework. The operator
should measure and report the volume of fluid added to
the annulus . If not already the case, the
casing/tubing valves should be closed, at least, 24
hours prior to the pressure test.
Following steps are at the well:
6. Read tubing pressure and record on the form. If the
•
hinted on Recycled Pap
•
well is
shut-in, the reported information on the actual
maximum operating pressure should be used to determine
test pressures .
1 . Read pressure on the casing/tubing annulus and record
value on the form. If there is pressure on the
annulus, at should lit hied off mine to the test. If
the pressure will not bleed-off, the guidance on well
failures (Region VIII UIC Section Guidance 835) should
be followed.
b . Ask the operator for the date of the last workovertand
the volume of fluid added to the annulus prior
test and record information on the form.
9. Hook-up well to pressure source and apply pressure
until test value is reached. '
Immediately disconnect pressure source and startetest -
10. time
significant drop have
e
d (If there
of has disconnection, the test may
during The pressure gages used to monitor
to be restarted) .pressure and annulus pressure should
injection tubing
have a pressure range which will allow the test
pressure to bethe near
gagethe
must be mid-range
of sufficient accuracy gage.andisianelty,. of a 10 percent
and scale to allow an accurate reading est pressure of
change •
0p to be debe . For instance, increments .
pi
600 psi should be monitored with a 0 to 1000 psi gage.
The scale should be incremented in 20 psi
11 . Record tubing and annulus pressure values every five
(5) minutes.
12. At the end of the test, record the final tubing
pressure.
13. If the test fails, check the valves, bull plugs and
casing head close up for possible leaks . The well
should be retested.
14 . If the second test indicates a well failure, the Region
should be informed of
well the fshould be thin 24 shut-inours 48
the op
hours per Headquarters guidance 1i6eratorfollow-up
letter should be prepared by the op
outlines the cause of the MIT failure and proposes a
potential course of action. This report should be
submitted to EPA within five days .
;A'.
Printed on Recycled reps
® � • ® •
15. Bleed off well into a bucket, if possible, to obtain a
volume estimate. This should be compared to the
calculated value obtained using the casing/tubing
annulus volume and fluid compressibility values .
•
16 . Return to office and prepare follow-up.
p ternative Test Option
While it is expected that the test procedure outlined above
will be applicable to most wells, the potential does exist that
unique circumstances may exist for a given well that precludes or
makes unsafe the application of this test procedure. In the
event that these exceptioric] or extraordinary conditions are
encountered, the operator has the option to propose an
alternative test or monitoring procedures. The request must be
submitted by the operator in writing and must be approved in
writing by the UIC-implementation Section Chief or equivalent
level of management.
•
Attachment
•
•
•
•
•
•
•
i4:
frinsed on Recycled Apr
® • 0, •
Mechanical Integrity Test Test
Casing or Annulus Pressure Mechanical Integrity
U.S.Environmental Protection Agency lion l°toQram 8P-Vi
Undupound Injection Control Flogra n UIC Direct Implementation
502ntatZ
995 1r Strut,Suitt SOO Denny, .
Date: _____•_L--1—
EPA Witness:
Test cosduprey by
Others present: -----
Type: ER SWI) Status: AC TA UC
Well Name:
Field: State._
Location: Sa:,__
T__N/S R_E/W County:_ �--
Operator:
/ Maximum Allowable Pre«ure:
_____ SIG
LastMTf: / •
Is this a regular])'
scheduled test? [ ] Yes [ ] No
Initial test for permit? [ ] Yes -[ ] No
Test after well rework? I I Yes ' [ ] NC bpd
y�ell injecting during test? [ ] Yes [ ] No uYes,rate:
prig
Pre-test casingitubing annulus pressure:
T9iTDATA TABLE Test #1
Test #12 Test fl3
TUBING PRESSURE Si
Si
Si
Initial PreSNfe
e
c
•
ANNUZ US PRESSURE •
CASING/TUBING .si
.si•
0_minutes El esi:
•
.si:
5 minutes si si:
esi
esi,
1 minutes rsi:
esi
'si_ si.
15 minutesesi•
.s]• esi:
20 minutes . i•
esi. .
25 minutes s esi.
si.
'Si,30 minutes esi.
es .
,.
minutes i si�
Pass Fail . Pass
Fail Pus Fail .
RESULT -
No
Does*annulus pressure build back up after the test? [ [ Yes [ ] •'
. (over)
APPENDIX H
(GUIDANCE FOR CONDUCTING A STEP-RATE TEST)
EPA Final Permit No. CO 10938-02115 Page 69 of 105
.. . . • 'Y
'^y, UNITED LelES ENVIRONMENTAL FROTEG VAG
1 REGION VIII •
ZraS1REET - SUITE 500
III 18th PK DENVER, COLORADO 60202-ia66
Si EP•RAl E "( EST PROCEDURE
January 12, 1999
PUFF
The put pose of this document is to provide a guideline for the acquisition of a Step Rate Teat
(SRI). These procedures are consistent with acceptable oilfield practices. Test results may be
provide for the
used by the EPA to derground ine sources of Maximum rinkinCeg watertion at an injection weCESUre ll )having mechanical
protection the underground and use to record step rate test data.
integrity. Attached is a form that you may copy '
Step rate test results must be documented with service company or other appropriate
(acceptable) records and/or charts, and the test should be witnessed by an EPA inspector.
Arrangements may be made by contacting the EPA Region b Underground Injection Control (UIC)
offices using the EPA toll-lice number 1.800.227.8917 (ask for extension 6137 or 6155).
81EP RATE LEST FROCEDUR '
1) approxishould
o e shut-in
bei shut in n formation pressures enough . or to if the shut shut-in such
l flows to hebottom
surface, e pressures
w injection string should be equipped with a gauge and the static surface pressure
wellhead
read and recorded.
series of successively higher injection rates are determined using guidelines below, and
2) A time and pressure values are read and recorded for each rate and time step.
the at last Exoctl as long as the preceding rate. If stabilized pressure
Each rate step should -� s ested below, the test results may be
values are not obtained within the rate steps .ugg
inconclusive.
Formation Permeabili md)
TotalTotaf tie!rate-step (mini)
60 min
s 5 and 30 min
z lO and
3) Suggested injection rates:
5% 1
10% .
20%,
q0% 1 01 Anticipated Maximum Injection Rate
60%
80%r i •
100%1 .
4) Injection rates should be controlled with a constant flow regulator that has been tested prior
to use. A throttling device is not sufficient.
Printed cm Recycled Paper
•
5) Flow rates should be measured with a calibrated turbine ilowmeter.
6) Record injection rates using a chart recorder or a strip chart.
7) Measure pressures with a down hole pressure Crumb.
Measure and record injection pressures with a gauge or recorder (for immediate test
results). -•-- - __ .. . . . . .. ........
9) A plot of injection rates and the corresponding stabilized pressure values should be
graphically represented as a constant slope straight line to a point at which the formation
fracture, or "breakdown", pressure is Exceeded. The slope of this subsequent straight line
should be less than that of the before-fracture straight line.
ly en xceeded, evidenced by least 30) If the formationra •pressCture pressure ure combinations•$eaterethanEtheEbreo down pressure, hetinjectiono
injection up ruld•p ed the line valve Closed, and the pressure is allowed to bleed-otl into
pump should be stopped,
the injection formation. There will occur a significant instantaneous pressure drop
(Instantaneous Shut-in Pressure or ISIP), atter which the pressure values begin to level out.
This ISIP value must be read and recorded. The ISIP obtained in this manner may be
considered to be the minimum pressure required to hold open a fracture in this formation at
this well.
11-) Once the ISIP is obtained, the SRT is concluded.
ned the maximum test ction
12) Inpr ss reeuti that the lized, the testresults may wn indicate thatre was not therformattion is accepting fluids without
pressure
•
y:1UICNRU/C-Guidance\INfahePkale lest wpd January a2999
Mind en Recycled Pape
• 2
0 5' FAZE TEST DATA •
Date: Open-do► _
We
(bbl/min)
STEP sll Te≤( Fate ( ofmaaimumale)
Time (min)
trieuure (psi):
c of maximum rate) (bbl/min)
51EP �y Te_t Rate (�
Time (min) '�—
Pressure (psi):
t " ( ?0 of maximum tale)
(bbl/min)
Time (min) :
1
Pressure (psi):
c
( 4 of maximum sale)
(bbl/min)
S1EP t;4 Te_t Rate O°
Time (min) :
Pressure (psi):
STEP $t5 Test Rate ( 6 of maximum rate) (bbl/min)
�
Time (m(n) • —
Pressure (psi):
(bbl/min)
STEP st6 Test Fate ( of maximum rate) '
Time (mm) :
Pressure (psi):
c
( of maximum tale) (bbl/min)
51EP �7 Te_1 Rate �
Time (min) :.---
Pressure (psi:.--
ISIP : (psi)
i WUniadEd BYi
•
EXAMPLE STEP RATE TEST
The following is an example of a Step-Rate Test wit a u ar an c
data and graphic results of the test are on the following pages.
The operator of Anywell #I] set up a SRT for the following conditions:
A) Maximum anticipated injection rate was 4 bbl/min.
5) Following the recommended test procedures, the operator planned on using these
rates for the test:
1) 5% of 4 bbl/min = 0.2 bbl/min
2) 30% of 4 bbl/min = 0.4 bbl/mitt
3) 20% of 4 bbl/min = 0.8 bbl/mitt
4) 40% of 4 bbl/min = 1.6 bbl/min
5) 60% of 4 bbl/min = 7.4 bbl/mitt
6) 60% of 4 bbl/min = 3.2 bbl/mip
7) 100% o14 bbl/min = 4.0 bbl/min
C) The formation permeability is estimated as 300 md, therefore each step will last for
30 minutes.
)r this test, the injection formation broke down at approximately 3200 psi, and the ISIP was listed
1000 psi.
:cause the injection formation will part at ]000 psi, the maximum injection pressure will be held
the ISIP. 11 the formation had not broken down at 1200 psi, the maximum allowable injection
essure would be the maximum pressure obtained during the test.
al
/„plE 57£P RATE TEST
Well:
Dafe: f.a S4 Opt;ilor letva Oct'
(all min)
Test Faie ( ot maximum rate) �—
�TEF1 ITime (min) _2c_ 30
�J-
-�— " 700 700 I
cc yE y9 _
Pressure (psi) — (bbl/min)
STEP ifY Test Fate of maximum rate) �_ ---
c � 30 I
0 r
Time (min) .._-t- 7�5 _ 7Gi Es
(pressure (Psi): -- �—
7— /fir
T e51 Fo1e ( of maximum rate) _ --
(bbl/min)
cTEF >y3 30 I
(Time (min) .�- - 400
�yf
Pressure (Psi): —7j
(bbl
/min)
Yt4 e5f Faie ( 40° of maximum rate) _ Y
STEP 30
(Time (min) 79 f0 J.
i 7yo
7c0
(bbl/min)
t5 of maximum rate) —2 4
STEP �5 .Tesi Faie ( 0° 30
—20 _r
rime(man) 7780 7_ .COI I
cyp 10.:0 7_� 71
- 5f
I
750 _1
(pressure (Pai): --� (bbl/min)
6 Tesi Faie ( of maximum rate)
STEP #rime ( 30 I
Time ( ) -- 14A0 min 1�5,G 1�9 I
pressure (v31): 7— 7U0�
1uc0 7_ =/0
Test Pate ( JO of maximum rate)
4. (bbl/min)
STEP 147 &s_ 30
— — -- 20_
rime (min) —S2_—_ c< 7�%0 7600
( 1450 75Gi� 1�'
pressure (v:i):
.52 : 11100 (psi)
A/_ _ ..•sae
I
STEP-RATE TEST E AMPLE 7c342' #,
1.9
1.7
1.6
0) 1.5
CL.
W , a .
1.2
U3 1.1
N a
ul
It AD.,
Q.. -
(i8
•
O D•7
C.6
W Ds •
z
D3
Da
C.1 •
D 4
G
INJECTION RATE ( bbl / min)
APPENDIX I
(GUIDANCE FOR CONDUCTING A PRESSURE
FALLOFF TEST)
EPA Final Permit No. CO 10938-02115
Page 76 of 105
EPA Region 6
UIC PRESSURE FALLOFF
TESTING GUIDELINE
Third Revision
ii.,
•
sgi
is . et
.‘.
PRONG
August 8, 2002
• •
TABLE OF CONTENTS
1
1.0 Background 1
2.0 Purpose of Guideline
3.0 Timing of Falloff Tests and Report Submission 2
4.0 Falloff Test Report Requirements 2
5.0 Planning 5
General Operational Concerns 6
Site Specific Pretest Planning 7
6.0 Conducting the Falloff Test 7
7.0 Evaluation of the Falloff Test 7
1. Cartesian Plot 7
2. Log-log Plot 8
3. Semilog Plot 8
4. Anomalous Results 8
8.0 Comparison of Falloff Test Results to No Migration Petition Data 8
9.0 Technical References
APPENDIX
i
• •
APPENDIX
Initial Formation Reservoir Pressure from Falloff Testing A-1
Pressure Gauge Usage and Selection A-1
Usage A-1
Selection - A-2
Test Design A-2
General Operational Considerations A-2
Wellbore and Reservoir Data Needed to Simulate or Analyze the Falloff Test . . . . A-4
Design Calculations A-4
Considerations for Offset Wells Completed in the Same Interval A-5
Falloff Test Analysis A-6
Cartesian Plot A-6
Log-log Diagnostic Plot A-7
Identification of Test Flow Regimes A-7
Characteristics of Individual Test Flow Regimes A-8
Wellbore Storage A-8
Radial Flow A-8
Spherical Flow A-8
Linear Flow A-9
Hydraulically Fractured Well A-9
Naturally Fractured Rock A-9
Layered Reservoir A-9
Semilog Plot • A-9
Determination of the Appropriate Time Function for the Semilog Plot A-10
Parameter Calculations and Considerations A-11
Skin Factor A-12
Radius of Investigation A-13
Effective Wellbore Radius A-13
Reservoir Injection Pressure Corrected for Skin Effects A-13
Determination of the Appropriate Fluid Viscosity A-14
Reservoir Thickness A-15.
Use of Computer Software A-15
Common Sense Check A-16
ii
• •
EPA Region 6
UIC PRESSURE FALLOFF TESTING GUIDELINE-
Third Revision
August 8, 2002
1.0 Background
The Hazardous and Solid Waste Amendments of 1984 to the Resource Conservation and
Recovery Act mandated prohibitions on the land disposal of hazardous waste. These
prohibitions are known as the land disposal restrictions and EPA promulgated regulations to
implement these requirements for injection wells on July 26, 1988. The land disposal restrictions
for injection wells are codified in 40 CFR Part 148. In addition to specifying the effective dates
of the restrictions on injection of specific hazardous wastes, these regulations outline the
requirements for obtaining an exemption to the restrictions.
Facilities that have received an exemption to the land disposal restrictions under 40 CFR Part
148 have demonstrated that, to a reasonable degree of certainty, there will be no migration of
hazardous constituents from the injection zone for as long as the waste remains hazardous. As
part of this approval,facilities are required by Region 6 to meet approval conditions including
annual monitoring in accordance with 40 CFR 148.20(d)(2).
Region 6 has adopted the 40 CFR 146.68(e)(1) requirements for monitoring Class 1 hazardous
waste disposal wells. Under 40 CFR 146.68(e)(1), operators are required annually to monitor the
pressure buildup in the injection zone, including at a minimum, a shut down of the well for a
time sufficient to conduct a valid observation of the pressure falloff curve.
A falloff test is a pressure transient test that consists of shutting in an injection well and
measuring the pressure falloff. The falloff period is a replay of the injection preceding it;
consequently, it is impacted by the magnitude, length, and rate fluctuations of the injection
period. Falloff testing analysis provides transmissibility, skin factor, and well flowing and static
pressures. All of these parameters are critical for evaluation of technical adequacy of no
migration demonstrations and UIC permits.
2.0 Purpose of Guideline
This guideline has been developed by the Region 6 office of the Evironmental Protection Agency
(EPA)to assist operators in planning and conducting the falloff test and preparing the annual
monitoring report. Typically,this report should consist of a falloff test and a comparison of the
reservoir parameters derived from the test with those of the petition demonstration. Falloff tests
provide reservoir pressure data and characterize both the injection interval reservoir and the
completion condition of the injection well. Both the reservoir parameters and pressure data are
necessary for no migration and UIC permit demonstrations. Additionally, a valid falloff test is a
requirement of a no migration petition condition as well as a monitoring requirement under 40
_ CFR Part 146 for all Class I injection wells. For no migration purposes, the annual report is
viewed not as an enforcement tool,but as an annual confirmation that the petition demonstration
continues to be valid.
The main body of this guideline contains general information that pertains to the majority of the
facilities impacted. Because each site is unique, one guideline cannot be written to encompass all
situations. A more detailed discussion of many topics and equations is included in the attached
Appendix.
The ultimate responsibility of conducting a valid falloff test is the task of the operator. Operators
should QA/QC the pressure data and test results to confirm that the results "make sense"prior to
submission of the report to the EPA for review.
3.0 Timing of Falloff Tests and Report Submission
Falloff tests must be conducted within one year from the date of the original petition approval
and annually thereafter. The time interval for each test should not be less than 9 months or
greater than 15 months from the previous test. This will ensure that the tests will be performed at
relatively even intervals throughout the duration of the petition approval period. Operators can,
at their discretion, plan these tests to coincide with the performance of their annual state MIT
requirements as long as the time requirements are met. The falloff testing report should be
submitted no later than 60 days following the test. Failure to submit a.falloff test report will be
considered a violation of the applicable petition condition and may result in an enforcement
action. Any exceptions should be approved by EPA prior to conducting the test.
4.0 Falloff Test Report Requirements
In general, the report to EPA should provide general information and an overview of the falloff
test, an analysis of the pressure data obtained during the test, a summary of the test results, and a
comparison of the results with the parameters used in the no migration demonstration. Some of
the following operator and well data will not change so once acquired, it can be copied and
submitted with each annual report. The falloff test report should include the following
information:
1. Company name and address
2. Test well name and location
3. The name and phone number of the facility contact person. The contractor contact may
be included if approved by the facility in addition to a facility contact person.
2
4. A photocopy of an openhole log (SP or Gamma Ray) through the injection interval
illustrating the type of formation and thickness of the injection interval. The entire log is
not necessary.
5. Well schematic showing the current wellbore configuration and completion information:
• Wellbore radius
•
Completed interval depths
Type of completion (perforated, screen and gravel packed, openhole)
•
6. Depth of fill depth and date tagged.
7. Offset well information:
Distance between the test well and offset well(s) completed in the same interval or
•
involved in an interference test
Simple illustration of locations of the injection and offset wells
•
8. Chronological listing of daily testing activities.
9. Electronic submission of the raw data(time,pressure, and temperature) from all pressure
gauges utilized on a floppy disk or CD-ROM. A READ-ME file or the disk label should
list all files included and any necessary explanations of the data. A separate file
containing any edited data used in the analysis can be submitted as an additional file.
10. Tabular summary of the injection rate-or rates preceding the falloff test. At a minimum,
rate information for 48 hours prior to the falloff or for a time equal to twice the time of
the falloff test is recommended. If the rates varied and the rate information is greater than
10 entries, the rate data should be submitted electronically as well as a hard copy of the
rates for the report. Including a rate vs time plot is also a good way to illustrate the
magnitude and number of rate changes prior to the falloff test.
11. Rate information from any offset wells completed in the same interval. At a minimum,
the injection rate data for the 48 hours preceding the falloff test should be included in a
tabular and electronic format. Adding a rate vs time plot is also helpful to illustrate the
rate changes.
12. Hard copy of the time and pressure data analyzed in the report.
13. Pressure gauge information: (See Appendix,page A-1 for more information on pressure
gauges)
• List all the gauges utilized to test the well
• Depth of each gauge
• Manufacturer and type of gauge. Include the full range of the gauge.
• Resolution and accuracy of the gauge as a% of full.range.
• Calibration certificate and manufacturer's recommended frequency of calibration
14. General test information:
• Date of the test
• Time synchronization: A specific time and date should be synchronized to an
equivalent time in each pressure file submitted. Time synchronization should also
be provided for the rate(s) of the test well and any offset wells.
• Location of the shut-in valve (e.g., note if at the wellhead or number of feet from
the wellhead)
3
15. Reservoir parameters (determination):
• Formation fluid viscosity, µf cp (direct measurement or correlation)
• Porosity, 4) fraction (well log correlation or core data)
• Total compressibility, c,psi' (correlations, core measurement, or well test)
• Formation volume factor, rvb/stb (correlations, usually assumed 1 for water)
• Initial formation reservoir pressure - See Appendix,page A-1
• Date reservoir pressure was last stabilized (injection history)
• Justified interval thickness, h ft- See Appendix,page A-15
16. Waste plume:
• Cumulative injection volume into the completed interval
• Calculated radial distance to the waste front, r„,,,a ft
• Average historical waste fluid viscosity, if used in the analysis, µwok cp
17. Injection period:
• Time of injection period
• Type of test fluid
• Type of pump used for the test(e.g., plant or pump truck)
• Type of rate meter used
• Final injection pressure and temperature
18. Falloff period:
• Total shut-in time, expressed in real time and At, elapsed time
• Final shut-in pressure and temperature
• Time well went on vacuum, if applicable
19. Pressure gradient:
• Gradient stops - for depth correction
20. Calculated test data: include all equations used and the parameter values assigned for
each variable within the report
• Radius of investigation, r; ft
• Slope or slopes from the semilog plot
• Transmissibility, kh/µ and-ft/cp
• Permeability(range based on values of h)
• Calculation of skin, s
• Calculation of skin pressure drop, OPT„
• Discussion and justification of any reservoir or outer boundary models used to
simulate the test
• Explanation for any pressure or temperature anomaly if observed
21. Graphs:
• Cartesian plot: pressure and temperature vs. time
• Log-log diagnostic plot: pressure and semilog derivative curves. Radial flow
regime should be identified on the plot
• Semilog and expanded semilog plots: radial flow regime indicated and the
semilog straight line drawn
• Injection rate(s)vs time: test well and offset wells (not a circular or strip chart)
22. A comparison of all parameters with those used in the petition demonstration, including
references where the parameters can be found in the petition.
4
23. A copy of the latest radioactive tracer run to fulfill the annual mechanical integrity testing
requirement for the State and a brief discussion of the results.
-- 24. Compliance with any unusual petition approval conditions such as the submission of an
annual flow profile survey. These additional conditions may be addressed either in the
annual falloff testing report or in an accompanying document.
5.0 Planning
The radial flow portion of the test is the basis for all pressure transient calculations. Therefore
the injectivity and falloff portions of the test should be designed not only to reach radial flow,but
to sustain a time frame sufficient for analysis of the radial flow period.
General Operational Concerns
Successful well testing involves the consideration of many factors, most of which are within the
operator's control. Some considerations in the planning of a test include:
- • Adequate storage for the waste should be ensured for the duration of the test
Offset wells completed in the same formation as the test well should be shut-in,or at a
•
minimum,provisions should be made to maintain a constant injection rate prior to and
during the test
• Install a crown valve on the well prior to starting the test so the well does not have to be
shut-in to install a pressure gauge
• The location of the shut-in valve on the well should be at or near the wellhead to
minimize the wellbore storage period
• The condition of the well,junk in the hole, wellbore fill or the degree of wellbore damage
(as measured by skin)may impact the length of time the well must be shut-in for a valid
falloff test. This is especially critical for wells completed in relatively low
transmissibility reservoirs or wells that have large skin factors.
• Cleaning out the well and acidizing may reduce the wellbore storage period and therefore
the shut-in time of the well
• Accurate recordkeeping of injection rates is critical including a mechanism to
synchronize times reported for injection rate and pressure data. The elapsed time format
usually reported for pressure data does not allow an easy synchronization with real time
rate information. Time synchronization of the data is especially critical when the analysis
includes the consideration of injection from more than one well.
• Any unorthodox testing procedure, or any testing of a well with known or anticipated
problems, should be discussed with EPA staff prior to performing the test.
• Other pressure transient tests may be used in conjunction or in place of a falloff test in
some situations. For example, if surface pressure measurements must be used because of
a corrosive wastestream and the well will go on vacuum following shut-in, a multi-rate
test may be used so that a positive surface pressure is maintained at the well.
5
• •
• If more than one well is completed into the same reservoir, operators are encouraged to
send at least two pulses to the test well by way of rate changes in the offset well following
the falloff test. These pulses will demonstrate communication between the wells and,if
maintained for sufficient duration,they can be analyzed as an interference test to obtain
interwell reservoir parameters.
Site Specific Pretest Planning
1. Determine the time needed to reach radial flow during the injectivity and falloff portions
of the test:
• Review previous welltests, if available
• Simulate the test using measured or estimated reservoir and well completion
parameters
• Calculate the time to the beginning of radial flow using the empirically-based
equations provided in the Appendix. The equations are different for the
injectivity and falloff portions of the test with the skin factor influencing the
falloff more than the injection period. (See Appendix,page A-4 for equations)
• Allow adequate time beyond the beginning of radial flow to observe radial flow so
that a well developed semilog straight line occurs. A good rule of thumb is 3 to 5
times the lime to reach radial flow to provide adequate radial flow data for
analysis.
2. Adequate and consistent injection fluid should be available so that the injection rate into
the test well can be held constant prior to the falloff. This rate should be high enough to
produce a measurable falloff at the test well given the resolution of the pressure gauge
selected. The viscosity of the fluid should be consistent. Any mobility issues (k/µ)
should be identified and addressed in the analysis if necessary.
3. Bottomhole pressure measurements are usually superior to surface pressure
measurements because bottomhole measurements tend to be less noisy. Surface pressure
measurements can be used if positive pressure is maintained at the surface throughout the
falloff portion of the test. The surface pressure gauge should be located at the wellhead.
A surface pressure gauge may also serve as a backup to a downhole gauge and provide a
monitoring tool for tracking the test progress. Surface gauge data can be plotted during
the falloff in a log-log plot format with the pressure derivative function to determine if
the test has reached radial flow and can be terminated. Note: Surface pressure
measurements are not adequate if the well goes on a vacuum during the test. (See
Appendix, page A-2 for additional information concerning pressure gauge selection.)
4. Use two pressure gauges during the test with one gauge serving as a backup, or for
verification in cases of questionable data quality. The two gauges do not need to be the
same type. (See Appendix,page A-1 for additional information concerning pressure
gauges.)
6
• •
6.0 Conducting the Falloff Test
1. Tag and record the depth to any fill in the test well
2. Simplify the pressure transients in the reservoir
• Maintain a constant injection rate in the test well prior to shut-in. This injection
rate should be high enough and maintained for a sufficient duration to produce a
measurable pressure transient that will result in a valid falloff test.
• Offset wells should be shut-in prior to and during the test. If shut-in is not
feasible, a constant injection rate should be recorded and maintained during the
test and then accounted for in the analysis.
• Do not shut-in two wells simultaneously or change the rate in an offset well
during the test.
3. The test well should be shut-in at the wellhead in order to minimize wellbore storage and
afterflow. (See Appendix, page A-3 for additional information.)
4. Maintain accurate rate records for the test well and any offset wells completed in the
same injection interval.
5. Measure and record the viscosity of the injectate periodically during the injectivity
portion of the test to confirm the consistency of the test fluid.
7.0 Evaluation of the Falloff Test
1. Prepare a Cartesian plot of the pressure and temperature versus real time or elapsed time.
• Confirm pressure stabilization prior to shut-in of the test well
• Look for anomalous data,pressure drop at the end of the test, determine if
pressure drop is within the gauge resolution
2. Prepare a log-log diagnostic plot of the pressure and semilog derivative. Identify the flow
regimes present in the welltest. (See Appendix,page A-6 for additional information.)
• Use the appropriate time function depending on the length of the injection period
ri 0o
and variation in the injection rate preceding the falloff (See Appendix, page
for details on time functions.)
• Mark the various flow regimes -particularly the radial flow period
• Include the derivative of other plots, if appropriate (e.g., square root of time for
linear flow)
• If there is no radial flow period, attempt to type curve match the data
7
• S
3. Prepare a semilog plot.
• Use the appropriate time function depending on the length of injection period and
injection rate preceding the falloff
• Draw the semilog straight line through the radial flow portion of the plot and
obtain the slope of the line
• Calculate the transmissibility,kh/µ
• Calculate the skin factor, s, and skin pressure drop, OPtkin
• Calculate the radius of investigation, r,
4. Explain any anomalous results.
8.0 Comparison of Falloff Results to No Migration Petition Data
A comparison between the falloff test results and the parameters used in the no migration petition
demonstration should be made. Specifically, the following should be demonstrated:
Both the flowing and static bottom hole pressures measured during the test should be
•
corrected for skin and be at or below those which were predicted to occur by the pressure
buildup model in the approvided no migration petition for the same point in time. (See
Appendix,page A-13)
• It should be shown that the (kh/µ)parameter group calculated from the current falloff data
is the same or greater than that employed in the pressure buildup modeling.
9.0 Technical References
1. SPE Textbook Series No. 1, "Well Testing," 1982, W. John Lee
2. SPE Monograph 5, "Advances in Well Test Analysis," 1977, Robert Earlougher, Jr..
3. SPE Monograph 1, "Pressure Buildup and Flow Tests in Wells," 1967, C.S. Matthews
and D.G. Russell
4. "Well Test Interpretation In Bounded Reservoirs,"Hart's Petroleum Engineer
International, Spivey, and Lee,November 1997
5. "Derivative of Pressure: Application to Bounded Reservoir Interpretation," SPE Paper
15861, Proano, Lilley, 1986
6. "Well Test Analysis," Sabet, 1991
7. "Pressure Transient Analysis," Stanislav and Kabir, 1990
8. "Well Testing: Interpretation Methods,"Bourdarot, 1996
9. "A New Method To Account For Producing Time Effects When Drawdown Type Curves
Are Used To Analyze Pressure Buildup And Other Test Data," SPE Paper 9289,.Agarwal,
1980
8
• •
10. "Modem Well Test Analysis—A Computer-Aided Approach,"Roland N. Home, 1990
11. Exxon Monograph, "Well Testing in Heterogeneous Formations,"Tatiana Streltsova,
1987
12. EPA Region 6 Falloff Guidelines
13. "Practical Pressure Gauge Specification Considerations In Practical Well Testing," SPE
Paper No. 22752, Veneruso, Ehlig-Economides, and Petitjean, 1991
14. "Guidelines Simplify Well Test Interpretation," Oil and Gas Journal, Ehlig-Economides,
Hegeman, and Vik, July 18, 1994
15. Oryx Energy Company, Practical Pressure Transient Testing, G. Lichtenberger and K.
Johnson, April 1990 (Internal document)
16. Pressure-Transient Test Design in Tight Gas Formations, SPE Paper 17088, W.J. Lee,
October 1987
17. "Radius-of-Drainage and Stabilization-Time Equations," Oil and Gas Journal,H.K. Van
Poollen, Sept 14, 1964
18. "Effects of Permeability Anisotropy and Layering On Well Test Interpretation,"Hart's
Petroleum Engineer International, Spivey, Aly, and Lee,February 1998
19. "Three Key Elements Necessary for Successful Testing,"Oil and Gas Journal, Ehlig-
Economides,Hegeman, Clark,July 25, 1994 -
20. "Introduction to Applied Well Test Interpretation,"Hart's Petroleum Engineer
International, Spivey, and Lee, August 1997
21. "Recent Developments In Well Test Analysis,"Hart's Petroleum Engineer International,
Stewart,August 1997
22. "Fundamentals of Type Curve Analysis,"Hart's Petroleum Engineer International,
Spivey, and Lee, September 1997
23. "Identifying Flow Regimes In Pressure Transient Tests,"Hart's Petroleum Engineer
International, Spivey and Lee, October 1997
24. "Selecting a Reservoir Model For Well Test Interpretation,"Hart's Petroleum Engineer
International, Spivey, Ayers, Pursell,and Lee,December 1997
27. "Use of Pressure Derivative in Well-Test Interpretation," SPE Paper 12777, SPE
Formation Evaluation Journal,Bourdet, Ayoub, and Pirard, June 1989
28. "A New Set of Type Curves Simplifies Well Test Analysis,"World Oil, Bourdet,
Whittle,Douglas, and Pirard, May 1983
9
APPENDIX -
Initial Formation Reservoir Pressure from Falloff Testing
For use in the no migration demonstration pressure buildup modeling:
• Some predictive models calculate a pressure buildup while other models calculate a
specific pressure based on an initial reservoir pressure assigned to the model. No
wellbore skin should be assumed in the demonstration. Historical falloff flowing
pressure data used for comparison with model results should be corrected for skin effects
The initial pressure should represent the initial reservoir pressure prior to initiation of
•
injection in the model.
Direct bottomhole static measurements are best. If no measurements are available, or are
•
questionable, attempt to correct static surface pressures to bottomhole conditions. Use
site specific information if available. Alternatively, the facility can reference a technical
paper that may discuss the initial pressure of the injection interval at another location in
the same area or an initial static pressure measurement from an offset injection well.
• Review historical measured static pressures. The initial reservoir pressure should be
lower than the measured static pressures following injection at the well.
For use in Cone of Influence(COD calculations in both no migration demonstrations and UIC
permits:
• P'is the false extrapolated pressure obtained from the semilog straight line at a time of 1
hour and is often used as the average reservoir pressure
• P'is only applicable for a new well in an infinite acting.reservoir
• EPA Region 6 does not recommend using P. for the average reservoir pressure. For long
injection periods,P'will differ significantly from P, the average reservoir pressure
• Use the final shut-in pressure, if the well reaches radial flow, for the cone of influence
calculation
Pressure Gauge Usage and Selection
Usage
• EPA recommends that two gauges be used during the test with one gauge serving as a
backup.
• As a general rule, downhole pressure measurements are less noisy and are preferred.
Surface pressure measurements can be employed if positive pressure is maintained at the
surface throughout the test. Surface gauges are insufficient if the well goes on a vacuum.
• Surface pressure gauges may be impacted by the fluctuations in ambient temperature that
can occur over the course of a normal day. If unchecked, this aspect of these gauges can
result in erroneous pressure readings. Insulating the gauges appears to be an effective
countermeasure for temperature fluctuations in many instances.
A-1
• •
• A surface or bottomhole surface readout gauge (SRO) allows tracking of pressures in real
time. Analysis of this data can be performed in the field to confirm that the well has
reached radial flow prior to endingthe test.
• The derivative function plotted on the log-log plot amplifies noise in the data, so the use
of a good pressure recording device is critical for application of this curve.
• Mechanical gauges should be calibrated before and after each test using a dead weight
tester.
• Electronic gauges should also be calibrated according to the manufacturer's
recommendations. The manufacturer's recommended frequency of calibration, and a
copy of the gauge calibration certificate should be provided with the falloff testing report
demonstrating this practice has been followed.
Selection
• The pressures must remain within the range of the pressure gauge. The larger percent of
the gauge range utilized in the test, the better. Typical pressure gauge limits are 2000,
5000, and 10000 psi. Note that gauge accuracy and resolution are typically a function of
percent of the full gauge range.
• Electronic downhole gauges generally offer much better resolution and sensitivity than a
mechanical gauge but cost more. Additionally, the electronic gauge can generally run for
a longer period of time, be programmed to measure pressure more frequently at various
intervals for improved data density, and store data in digital form.
• Resolution of the pressure gauge must be sufficient to measure small pressure changes at
the end of the test.
• The type of wastestream injected may prevent the use of a downhole gauge unless brine
from offsite is brought in and used for the test. This may be cost prohibitive.
Test Design
General Operational Considerations
• The injection period controls what is seen on the falloff since the falloff is replay of the
injection period. Therefore,the injection period must reach radial flow prior to shut-in of
the well in order for the falloff test to reach radial flow
Ideally to determine the optimal lengths of the injection and falloff periods, the test
•
should be simulated using measured or estimated reservoir parameters. Alternatively,
injection and falloff period lengths can be estimated from empirical equations using
assumed reservoir and well parameters.
• The injection rate dictates the pressure buildup at the injection well. The pressure
buildup from injection must be sufficient so that the pressure change during radial flow,
usually occurring toward the end of the test, is large enough to measure with the pressure
gauge selected.
A-2
• Waste storage and other operational issues require preplanning and need to be addressed
prior to the test date. If brine must be brought in for the injection portion of the test,
operators should insure that the fluid injected has a consistent viscosity and that there is
adequate fluid available to obtain a valid falloff test. The use of the wastestream is the
injection fluid affords several distinct advantages:
1. Brine does not have to be purchased or stored prior to use.
2. Onsite waste storage tanks may be used.
3. Plant wastestreams are generally consistent, i.e., no viscosity variations
• Rate changes cause pressure transients in the reservoir. Constant rate injection in the test
well and any offset wells completed in the same reservoir are critical to simplify the
pressure transients in the reservoir. Any significant injection rate fluctuations at the test
well or offsets must be recorded and accounted for in the analysis using superposition.
• Unless an injectivity test is to be conducted, shutting in the well for an extend period of
time prior to conducting the falloff test reduces the pressure buildup in the reservoir and
is not recommended.
• Prior to conducting a test, a crown valve should be installed on the wellhead to allow the
pressure gauge to be installed and lowered into the well without any interruption of the
injection rate.
• The wellbore schematic should be reviewed for possible obstructions located in the well
that may prevent the use or affect the setting depth of a downhole pressure gauge. The
fill depth in the well should also be reported. The fill depth may not only impact the
depth of the gauge, but usually prolongs the wellbore storage period and depending on the
type of fill, may limit the interval thickness by isolating some of the injection intervals. A
wellbore cleanout or stimulation may be needed prior to conducting the test for the test to
reach radial flow and obtain valid results.
• The location of the shut-in valve can impact the duration of the wellbore storage period.
The shut-in valve should be located near the wellhead. Afterflow into the wellbore
prolongs the wellbore storage period. The injection pipeline leading to the well can act as
an extension to the well if the shut-in valve is not located near the wellhead. Operators
should report the location of the shut-in valve and its distance from the wellhead, in the
test report.
• The area geology should be reviewed prior to conducting the test to determine the
thickness and type of formation being tested along with any geological features such as
natural fractures, a fault, or a pinchout that should be anticipated to impact the test.
A-3.
- Net thickness,h- See Appendix,page A-15
• Porosity, 4) - log or core data
• Viscosity of formation fluid, µ/- direct measurement or correlations
• Viscosity of waste, µwaz„- direct measurement or correlations
Total system compressibility, c, - correlations, core measurement, or well test
• Permeability, k -previous welltests or core data
• Specific gravity of injection fluid, s.g. - direct measurement
• Injection rate, q - direct measurement
Design Calculations
When simulation software is unavailable the test periods can be estimated from empirical
equations. The following are set of steps to calculate the time to reach radial flow from
empirically-derived equations:
1. Estimate the wellbore storage coefficient, C(bbl/psi). There are two equations to
calculate the wellbore storage coefficient depending on if the well remains fluid filled
(positive surface pressure) or if the well goes on a vacuum (falling fluid level in the well):
a. Well remains fluid filled:
C=vw`Cwa t= where, Vw is the total weilbore volume, bbls
_I
c,„,„,, is the compressibility of the injectate, psi
b. Well goes on a vacuum:
V„ where, V„is the wellbore volume per unit length, bbls/ft
C=
P.g
144•g<
p is the injectate density,psi/ft
g and& are gravitational constants
2. Calculate the time to reach radial flow for both the injection and falloff periods. Two
different empirically-derived equations are used to calculate the time to reach radial flow,
t,.ma flow for the injectivity and falloff periods:
a. Injectivity period:
200000+12000s)•C hours
radial flow > k•h
b. Falloff period:
170000•C•e o.14•,
tradial flow k•h hours
The wellbore storage coefficient is assumed to be the same for both the injectivity and
falloff periods. The skin factor, s, influences the falloff more than the injection period.
appropriate time function based on the rate history of the injection penoa preceamg me
falloff. (See Appendix,page A-10 for time function selection) The log-log plot is used
to identify the flow regimes present in the welltest. An example log-log plot is shown
below:
Example Log-log Plot
mono .. -
. Pressure
Data
1000
Wellbore Storage Period
>• `� Semilog Pressure
/ Derivative Function
o too _ 11114!
° Radial
Transition period
III! Flow
10 Unit slope during
�""
wellbore storage Derivative flattens •
1III III II I illi I n[
OAO,
,0
Elapsed Tune(ham)-Tp•21.0
Identification of Test Flow Regimes
• Flow regimes are mathematical relationships between pressure, rate, and time. Flow
regimes provide a visualization of what goes on in the reservoir. Individual flow regimes
have characteristic slopes and a sequencing order on the log-log plot.
• Various flow regimes will be present during the falloff test, however,not all flow regimes
are observed on every falloff test. The late time responses correlate to distances further
from the test well. The critical flow regime is radial flow from which all analysis
calculations are performed. During radial flow, the pressure responses recorded are
representative of the reservoir, not the wellbore.
• The derivative function amplifies reservoir signatures by calculating a running slope of a
designated plot. The derivative plot allows a more accurate determination of the radial
flow portion of the test, in comparison with the old method of simply proceeding 11/2 log
cycles from the end of the unit slope line of the pressure curve.
• The derivative is usually based on the semilog plot,but it can also be calculated based on
other plots such as a Cartesian plot, a square root of time plot, a quarter root of time plot,
and the 1/square root of time plot. Each of these plots are used to identify specific flow
regimes. If the flow regime characterized by a specialized plot is present then when the
derivative calculated from that plot is displayed on the log-;log plot, it will appear as a
"flat spot"during the portion of the falloff corresponding to the flow regime.
• Typical flow regimes observed on the log-log plot and their semilog derivative patterns
are listed below:
Flow Regime Semilog Derivative Pattern
Wellbore Storage Unit slope
Radial Flow Flat plateau
Linear Flow Half slope
Bilinear Flow •
BQuarter slope
Partial Penetration Negative half slope
Layering Derivative trough
Dual Porosity Derivative trough
Boundaries Upswing followed by plateau
Constant Pressure Sharp derivative plunge
Characteristics of Individual Test Flow Regimes
• Wellbore Storage:
1. Occurs during the early portion of the test and is caused by the well being shut-in
at the surface instead of the sandface
2. Measured pressure responses are governed by well conditions and are not
representative of reservoir behavior and are characterized by both the pressure and
semilog derivative curves overlying a unit slope on the log-log plot
3. Wellbore skin or a low permeability reservoir results in a slower transfer of fluid
from the well to the formation, extending the duration of the wellbore storage
•
•
period
4. A wellbore storage dominated test is unanalyzable
• Radial Flow:
1. The pressure responses are from the reservoir,not the wellbore
2. The critical flow regime from which key reservoir parameters and completion
conditions calculations are performed
3. Characterized by a flattening of the semilog plot derivative curve on the log-log
plot and a straight line on the semilog plot
• Spherical Flow:
1. Identifies partial penetration of the injection interval at the wellbore
2. Characterized by the semilog derivative trending along a negative half slope on
the log-log plot and a straight line on the 1/square root of time plot
3. The log-log plot derivative of the pressure vs 1/square root of time plot is flat
A-8
•
• Linear Flow
1. May result from flow in a channel,parallel faults, or a highly conductive fracture
2. Characterized by a half slope on both the log-log plot pressure and semilog
derivative curves with the derivative curve approximately 1/3 of a log cycle lower
than the pressure curve and a straight line on the square root of time plot.
3. The log-log plot derivative of the pressure vs square root of time plot is flat
• Hydraulically Fractured Well
1. Multiple flow regimes present including wellbore storage, fracture linear flow,
bilinear flow,pseudo-linear flow, formation linear flow, and pseudo-radial flow
2. Fracture linear flow is usually hidden by wellbore storage
3. Bilinear flow results from simultaneous linear flows in the fracture and from the
formation into the fracture, occurs in low conductivity fractures, and is
characterized by a quarter slope on both the pressure and semilog derivative
curves on the log-log plot and by a straight line on a pressure versus quarter root
of time plot
4. Formation linear flow is identified by a half slope on both the pressure and
semilog derivative curves on the log-log plot and by a straight line on a pressure
versus square root of time plot
5. Psuedo-radial flow is analogous to radial flow in an unfractured well and is
characterized by flattening of semilog derivative curve on the log-log plot and a
straight line on a semilog pressure plot
• Naturally Fractured Rock
1. The fracture system will be observed first on the falloff test followed by the total
system consisting of the fractures and matrix.
2. The falloff analysis is complex. The characteristics of the semilog derivative
trough on the log-log plot indicate the level of communication between the
fractures and the matrix rock.
• Layered Reservoir
1. Analysis of a layered system is complex because of the different flow regimes,
skin factors or boundaries that may be present in each layer.
2. The falloff test objective is to get a total tranmissibility from the whole reservoir
system.
3. Typically described as commingled (2 intervals with vertical separation) or
crossflow (2 intervals with hydraulic vertical communication)
Semilog Plot
• The semilog plot is a plot of the pressure versus the log of time. There are typically four
different semilog plots used in pressure transient and falloff testing analysis.. After
plotting the appropriate semilog plot, a straight line should be drawn through the points
located within the equivalent radial flow portion of the plot identified from the log-log
plot.
A-9
• •
• Each plot uses a different time function depending on the length and variation of the
injection rate preceding the falloff. These plots can give different results for the same
test, so it is important that the appropriate plot with the correct time function is used for
the analysis. Determination of the appropriate time function is discussed below.
The slope of the semilog straight line is then used to calculate the reservoir
transmissibility-kh/µ, the completion condition of the well via the skin factor- s, and
also the radius of investigation-r;of the test.
Determination of the Appropriate Time Function for the SemilogPlot
The following four different semilog plots are used in pressure transient analysis:
1. Miller Dyes Hutchinson(MDH) Plot
2. Homer Plot
3. Agarwal Equivalent Time Plot
4. Superposition Time Plot
These plots can give different results for the same test. Use of the appropriate plot with the
correct time function is critical for the analysis. _
The MDH plot is a semilog plot of pressure versus At, where At is the elapsed shut-in
•
time of the falloff.
1. The MDH plot only applies to wells that reach psuedo-steady state during
injection. Psuedo-steady state means the pressure response from the well has
encountered all the boundaries around the well.
2. The MDH plot is only applicable to injection wells with a very long injection
period at a constant rate. This plot is not recommended for use by EPA Region 6.
The Homer plot is a semilog plot of pressure versus (tp+At)/At. The Homer plot is only
•
used for a falloff preceded by a single constant rate injection period.
1. The injection time,tp=Vp/q in hours, where Vp=injection volume since the last
pressure equalization and q is the injection rate prior to shut-in for the falloff test.
The injection volume is often taken as the cumulative injection since completion.
2. The Homer plot can result in significant analysis error if the injection rate varies
prior to the falloff.
The Agarwal equivalent time plot is a semilog plot of the pressure versus Agarwal
•
equivalent time, Ate.
1. The Agarwal equivalent time function is similar to the Homer plot,but scales the
falloff to make it look like an injectivity test.
2. It is used when the injection period is a short, constant rate compared to the length
of the falloff period.
3. The Agarwal equivalent time is defined as: Atp log(tp At)/(tp+At), where tp is
calculated the same as with the Homer plot.
A-10
• •
A-11
a
• The superposition time function accounts for variable rate conditions preceding the
falloff.
1. It is the most rigorous of all the time functions and is usually calculated using
welltest software:
2. The use of the superposition time function requires the operator to accurately
track the rate history. As a rule of thumb, at a minimum, the rate history for twice
the length of the falloff test should be included in the analysis.
The determination of which time function is appropriate for the plotting the welltest on semilog
and log-log plots depends on available rate information, injection period length, and software:
1. If there is not a rate history other than a single rate and cumulative injection, use a Homer
time function
2. If the injection period is shorter than the falloff test and only a single rate is available, use
the Agarwal equivalent time function
3. If you have a variable rate history use superposition when possible. As an alternative to
superposition, use Agarwal equivalent time on the log-log plot to identify radial flow.
The semilog plot can be plotted in either Homer or Agarwal time if radial flow is
observed on the log-log plot.
Parameter Calculations and Considerations
• Transmissibility- The slope of the semilog straight line, m, is used to determine the
transmissibility(kh/µ)parameter group from the following equation:
k•h 162.6•q•B
m
where, q=injection rate, bpd (negative for injection)
B = formation volume factor,rvb/stb (Assumed to be 1 for formation
fluid)
m=slope of the semilog straight line through the radial flow portion of
the plot in psi/log cycle
k=permeability,and
h=thickness, ft (See Appendix,page A-15)
µ =viscosity, cp
• The viscosity, p. , is usually that of the formation fluid. However, if the waste plume size
is massive, the radial flow portion of the test may remain within the waste plume. (See
Appendix,page A-.14) e similar,
1 wastese tream has te and formation gnifi fluid
viscosity difference,the sviscosity values usually ize of te waste plume and
distance to the radial flow period should be calculated.
2. The mobility, k/µ, differences between the fluids may be observed on the
derivative curve.
• The permeability, k, can be obtained from the calculated transmissibility(kh/µ)by
A-12
IIF
substituting the appropriate thickness, h, and viscosity, µ, values.
Skin Factor
• In theory, wellbore skin is treated as an infinitesimally thin sheath surrounding the
wellbore, through which a pressure drop occurs due to either damage or stimulation.
Industrial injection wells deal with a variety of waste streams that alter the near wellbore
environment due to precipitation, fines migration, ion exchange, bacteriological
processes, and other mechanisms. It is reasonable to expect that this alteration often
exists as a zone surrounding the wellbore and not a skin. Therefore, at least in the case of
industrial injection wells, the assumption that skin exists as a thin sheath is not always
valid. This does not pose a serious problem to the correct interpretation of falloff testing
except in the case of a large zone of alteration, or in the calculation of the flowing
bottonihole pressure. The Region has seen instances in which large zones of alteration •
were suspected of being present.
• The skin factor is the measurement of the completion condition of the well. The skin
factor is quantified by a positive value indicating a damaged completion and a negative
value indicating a stimulated completion.
1. The magnitude of the positive value indicating a damaged completion is dictated
by the transmissibility of the formation.
2. A negative value of-4 to -6 generally indicates a hydraulically fractured
completion, whereas a negative value of-1 to -3 is typical of an acid stimulation
in a sandstone reservoir.
3. The skin factor can be used to calculate the effective wellbore radius,rV„also
referred to the apparent wellbore radius. (See Appendix,page A-13)
4. The skin factor can also be used to correct the injection pressure for the effects of
wellbore damage to get the actual reservoir pressure from the measured pressure.
• The skin factor is calculated from the following equation:
s=1.1513 Pnr Psi to k r° z +32 3
m g(Q +1)•0.p•c, •r„ )
where, s = skin factor, dimensionless
Pm,=pressure intercept along the semilog straight line at a shut-in time of 1 hour,
psi
Pwt=measured injection pressure prior to shut-in,psi
µ = appropriate viscosity at reservoir conditions, cp (See Appendix, page A-14)
m=slope of the semilog straight line, psi/cycle
k=permeability, and
=porosity, fraction
c,=total compressibility, psi'
rw=wellbore radius, feet
to=injection time, hours
AI33
• • •
Note that the term t,/(tp+At), where At=1 hr, appears in the log term. This term is usually
assumed to result in a negligible contribution and typically is taken as 1 for large t.
However, for relatively short injection periods, as in the case of a drill stem test (DST),
this term can be significant.
Radius of Investigation
• The radius of investigation, r;, is the distance the pressure transient has moved into a
formation following a rate change in a well.
• There are several equations that exist to calculate the radius of investigation. All the
equations are square root equations based on cylindrical geometry, but each has its own
coefficient that results in slightly different results, (See Oil and Gas Journal, Van Poollen,
1964).
• Use of the appropriate tune is necessary to obtain a useful value of r1. For a falloff time
shorter than the injection period, use Agarwal equivalent time function, Ate, at the end of
the falloff as the length of the injection period preceding the shut-in to calculate
• The following two equivalent equations for calculating r1 were taken from SPE
Monograph 1, (Equation 11.2) and Well Testing by Lee (Equation 1.47),respectively:
r k•t k•t
r = .10.001050. c1 %948.0.,u•c,
Effective Wellbore Radius
• The effective wellbore radius relates the wellbore radius and skin factor to show the
effects of skin on wellbore size and consequently, infectivity.
• The effective wellbore radius is calculated from the following:
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rr„ =rwe
• A negative skin will result in a larger effective wellbore radius and therefore a lower
injection pressure.
Reservoir Injection Pressure Corrected for Skin Effects
• The pressure correction for wellbore skin effects, AP,r;•, is calculated by the following:
Apo. = 0.868•m•s
where, m=slope of the semilog straight line,psi/cycle
s=wellbore skin, dimensionless
• The adjusted injection pressure,Pwa is calculated by subtracting the AP,idn from the
measured injection pressure prior to shut-in, PM. This adjusted pressure is the calculated
reservoir pressure prior to shutting in the well, At=0, and is determined by the following:
•
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•
S
Pw fa = Pwf —OPskin
• . From the previous equations, it can be seen that the adjusted bottomhole pressure is
directly dependent on a single point,the last injection pressure recorded prior to shut-in.
Therefore, an accurate recording of this pressure prior to shut-in is important. Anything
that impacts the pressure response, e.g.,rate change, near the shut-in of the well should be
avoided.
Determination of the Appropriate Fluid Viscosity
If the wastestream and formation fluid have similar viscosities, this process is not
necessary.
• This is only needed in cases where the mobility ratios are extreme between the
wastestream, (lc/µ)„, and formation fluid, (k/µ)F Depending on when the test reaches
radial flow, these cases with extreme mobility differences could cause the derivative
curve to change and level to another value. Eliminating alternative geologic causes, such
as a sealing fault, multiple layers, dual porosity, etc., leads to the interpretation that this
change may represent the boundary of the two fluid banks.
• First assume that the pressure transients were propagating through the formation fluid
during the radial flow portion of the test, and then verify if this assumption is correct.
This is generally a good strategy except for a few facilities with exceptionally long
injection histories, and consequently, large waste plumes. The time for the pressure
•
transient to exit the waste front is calculated. This time is then identified on both the log-
log and semilog plots. The radial flow period is then compared to this time.
• The radial distance to the waste front can then be estimated volumetrically using the
following equation:
10.13368•Vwasteinjected
rwaste plume Vf r.h•4 .
where, Vweste injected=cumulative waste injected into the completed interval, gal
--
estimated distance to waste front, ft
rwacteplwne
h =interval thickness, ft
ck =porosity, fraction
• The time necessary for a pressure transient to exit the waste front can be calculated using
the following equation:
126.73•fr„ •ct •Vwarte injected
tw — s•k•h
where, t„=time to exit waste front, hrs
Vw•.injected=cumulative waste injected into the completed interval, gal
h=interval thickness, ft
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• •
k=permeability,and
µ„,=viscosity of the historic waste plume at reservoir conditions, cp
c,=total system compressibility,psi'
• The time should be plotted on both the log-log and semilog plots to see if this time
corresponds to any changes in the derivative curve or semilog pressure plot. If the time
estimated to exit the waste front occurs before the start of radial flow, the assumption that
the pressure transients were propagating through the reservoir fluid during the radial flow
period was correct. Therefore, the viscosity of the reservoir fluid is the appropriate
viscosity to use in analyzing the well test. If not, the viscosity of the historic waste plume
should be used in the calculations. If the mobility ratio is extreme between the
wastestream and formation fluid, adequate information should be included in the report to
verify the appropriate fluid viscosity was utilized in the analysis.
Reservoir Thickness
• The thickness used for determination of the permeability should be justified by the
operator. The net thickness of the defined injection interval is not always appropriate.
• The permeability value is necessary for plume modeling,but the transmissibility value,
kh/µ, can be used to calculate the pressure buildup in the reservoir without specifying
values for each parameter value of k,h, and µ.
• Selecting an interval thickness is dependent on several factors such as whether or not the
injection interval is composed of hydraulically isolated units or a single massive unit and
wellbore conditions such as the depth to wellbore fill. When hydraulically isolated sands
are present, it may be helpful to define the amount of injection entering each interval by
conducting a flow profile survey. Temperature logs can also be reviewed to evaluate the
intervals receiving fluid. Cross-sections may provide a quick look at the continuity of the
injection interval around the injection well.
• A copy of a SP/Gamma Ray well log over the injection interval, the depth to any fill, and
the log and interpretation of available flow profile surveys run should be submitted with
the falloff test to verify the reservoir thickness value assumed for the permeability
calculation.
Use of Computer Software
• To analyze falloff tests, operators are encouraged to use welt testing software. Most
software has type curve matching capabilities. This feature allows the simulation of the
entire falloff test results to the acquired pressure data. This type of analysis is particularly
useful in the recognition of boundaries, or unusual reservoir characteristics, such as dual
porosity. It should be noted that type curve matching is not considered a substitute,but is
a compliment to the analysis.
• All data should be submitted electronically with a label stating the name of the facility,
the well number(s), and the date of the test(s). The label or READ.Me file should include
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the names of all the files contained on the diskette, along with any necessary explanations
of the information. The parameter units format (hh:mm:ss,hours, etc.) should be noted
for the pressure file for synchronization to the submitted injection rate information. The
file containing the gauge data analyzed in the report should be identified and consistent
with the hard copy data included in the report. If the injection rate information for any
well included in the analysis is greater than 10 entries, it should also be included
electronically.
Common Sense Check
• After analyzing any test, always look at the results to see if they"make sense"based on
the type of formation tested, known geology,previous test results, etc. Operators are
ultimately responsible for conducting an analyzable test and the data submitted to the
regulatory agency.
• If boundary conditions are observed on the test, review cross-sections or structure maps to
confirm if the presence of a boundary is feasible. If so, the boundary should be
considered in the AOR pressure buildup evaluation for the well.
• Anomalous data responses may be observed on the falloff test analysis. These data
anomalies should be evaluated and explained. The analyst should investigate physical
causes in addition to potential reservoir responses. These may include those relating to
the well equipment, such as a leaking valve,or a channel, and those relating to the data
acquisition hardware such as a faulty gauge. An anomalous response can often be traced
to a brief,but significant rate change in either the test well or an offset well.
• Anomalous data trends have also been caused by such things as ambient temperature
changes in surface gauges or a faulty pressure gauge. Explanations for data trends may be
facilitated through an examination of the backup pressure gauge data, or the temperature
data. It is often helpful to qualitatively examine the pressure and/or temperature channels
from both gauges. The pressure data should overlay during the falloff after being
corrected for the difference in gauge depths. On occasion, abrupt temperature changes
can be seen to correspond to trends in the pressure data. Although the source of the
temperature changes may remain unexplainable, the apparent correlation of the
temperature anomaly to the pressure anomaly can be sufficient reason to question the
validity of the test and eliminate it from further analysis.
• The data that is obtained from pressure transient testing should not collect dust,but be
compared to petition or permit parameters. Test derived transmissibilities and static
pressures can confirm compliance with no migration and non-endangerment (AOR)
conditions.
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