HomeMy WebLinkAbout1.06 SPCC Complete
Article 4-203.E.21
SPCC Plan
Ursa Operating Company
Speakman A Booster
Compressor
OA Project No. 015-3104
U.S. Operations
792 Buckhorn Drive
Denver, CO 80265
(720) 580‐8350
Field-wide Spill Prevention,
Control, and
Countermeasure Plan
Colorado Operations
Garfield County, Colorado
July 2013
Rev #: 3 (March 2014)
Colorado Operations
950 17th Street, Suite 2200
Denver, CO 80202‐2805
(720) 279‐5500
Field-wide Spill Prevention,
Control, and
Countermeasure Plan
Colorado Operations
July 2013
Rev #: 3 (March 2014)
Prepared by:
HRL Compliance Solutions, Inc.
2385 F ½ Road
Grand Junction, CO 81505
ii
Contents
Regulatory Cross-Reference for an Onshore Production Facility .............................................................. 1
Regulatory Decision Matrix ....................................................................................................................... 8
1.0 SPCC PLAN APPROVALS AND CERTIFICATIONS .............................................................. 9
1.1 Management Approval and Review ......................................................................................... 9
1.2 Professional Engineer Certification ........................................................................................ 10
1.3 Substantial Harm Certification Example Form ............................................................................ 11
1.3.1 Battlement Mesa Substantial Harm Certifications ........................................................... 12
1.3.2 Castle Springs/Wolf Creek Substantial Harm Certifications ........................................... 16
1.3.3 North Gravel Trend/Roan Substantial Harm Certifications ............................................. 27
1.3.4 Gravel Trend Substantial Harm Certifications ................................................................. 28
1.4 Plan Review and Amendments ................................................................................................. 71
2.0 FACILITIES, PROCEDURES, METHODS, OR EQUIPMENT NOT YET FULLY
OPERATIONAL ..................................................................................................................................... 73
3.0 SPCC PLAN POLICIES AND PROCEDURES ......................................................................... 74
3.1 Owner Information ................................................................................................................... 75
3.1.1 Facility Layout ................................................................................................................. 75
3.1.2 Tanks, Piping and Equipment .......................................................................................... 75
3.1.3 Containment Structures .................................................................................................... 76
3.1.3.a Additional Regulatory Requirements: ............................................................................. 76
3.1.4 Potential Discharge Volume and Direction of Flow ........................................................ 80
3.1.5 Proximity to Navigable Waters ........................................................................................ 80
3.1.6 Site Specific Facility Diagrams ........................................................................................ 80
3.1.7 SPCC Plan Development Tables...................................................................................... 81
3.2 General Requirements .............................................................................................................. 82
3.2.1 Discovery, Response and Cleanup of Releases ............................................................... 82
3.2.2 Notification Contacts ....................................................................................................... 82
3.2.3 Notification Forms ........................................................................................................... 82
3.2.4 Response Plan .................................................................................................................. 82
3.3 Routine Facility Operations, Inspections and Maintenance ...................................................... 83
3.3.1 Facility Operations ........................................................................................................... 83
3.3.2 Facility Inspection Program ............................................................................................. 83
ii
3.3.2.a Testing and Record Keeping Guidance ........................................................................... 85
3.3.4 Maintenance Program ...................................................................................................... 86
3.4 Response and Reporting Information ....................................................................................... 87
3.4.1 Spill Response .................................................................................................................. 87
3.4.2 Spill Reporting ................................................................................................................. 87
3.5 Spill Response Training ........................................................................................................... 89
3.5.1 Annual Training ............................................................................................................... 89
3.5.2 Discharge Prevention Briefings ....................................................................................... 89
3.5.3 Training Records .............................................................................................................. 89
APPENDICES
Appendix A Site Specific SPCC Plans
Appendix B Oil Spill Contingency Plan and Emergency Response Plan
Appendix C Discharge Notification Forms
Appendix D SPCC Forms
Appendix E Summary of Operating Procedures and Flowline Maintenance Program
Appendix F Written Commitment of Manpower
ATTACHMENTS
Attachment 1 Onshore Order 3
Ursa Operating Company LLC Oil Production Facility SPCC Plan
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Regulatory Cross-Reference for an Onshore Production Facility
Regulation Description Section
§112.3(b)(2) SPCC Plan prepared within six months after becoming
operational (effective 11/10/2010) 1.4
§112.3(d)(1) Professional Engineer (PE) certification with five, or six
(if applicable for produced water containers) elements 1.4
§112.5(a) Amendment of SPCC Plan 1.4
§112.5(b) Review of Plan at least every 5 years with documentation
(i.e. a log) 1.4
§112.6 Qualified Facilities: meets qualification criteria N/A
§112.7 General requirements for SPCC Plans for all facilities &
all oil types 2.0 – 3.5
§112.7 Management approval of Plan 1.1
§112.7
Discussion of facilities, procedures, methods or
equipment not yet fully operational with details of
installation and operational start-up
2.0
§112.7(a)(1) General requirements; discussion of facility’s
conformance with rule requirements 3.0 – 3.5
§112.7(a)(2) Deviations from Plan requirements N/A
§112.7(a)(3)
Facility description and diagram, type of oil and capacity
of each container, transfer stations and piping, buried
containers on diagram
Site Specific Plan
in Appendix A
§112.7(a)(3)(ii) Discharge prevention measures 3.2 – 3.3
§112.7(a)(3)(iii) Discharge drainage controls 3.2 – 3.3
§112.7(a)(3)(iv) Countermeasures for discharge discovery, response and
cleanup
3.4 and Appendix
B
§112.7(a)(3)(v) Methods of disposal of recovered materials in accordance
with legal requirements 3.4
Ursa Operating Company LLC Oil Production Facility SPCC Plan
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Regulation Description Section
§112.7(a)(3)(vi)
Contact list and phone numbers for facility Incident
Commander, National Response Center, cleanup
contractors, all Federal, State, and local agencies who
must be contacted in case of a discharge
3.4 and 3.5
§112.7(a)(4) Spill reporting information 3.4
§112.7(a)(5) Discharge procedures Appendix A
§112.7(b) Failure prediction (sources, quantities, rates, and
directions)
3.1.4 and
Appendix A
Tables and
Diagrams
§112.7(c)
Secondary containment for all areas from which a
discharge of oil could occur (i.e. mobile refuelers,
loading/unloading areas, transformers, oil filled
operational equipment, etc.) other than bulk containers
3.1.3 and
Appendix A
Tables Diagrams
§112.7(d) Explanation of impracticability of secondary containment N/A
§112.7(a)(3)(ii) Discharge prevention measures 3.2 – 3.3
§112.7(a)(3)(iii) Discharge drainage controls 3.2 – 3.3
§112.7(a)(3)(iv) Countermeasures for discharge discovery, response and
cleanup
3.4 and
Appendix B
§112.7(a)(3)(v) Methods of disposal of recovered materials in accordance
with legal requirements 3.4
§112.7(a)(3)(ii) Discharge prevention measures 3.3 and
Appendix E
§112.7(a)(3)(iii) Discharge drainage controls 3.3, Appendix A
Tables
Ursa Operating Company LLC Oil Production Facility SPCC Plan
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Regulation Description Section
§112.7(a)(3)(iv) Countermeasures for discharge discovery, response and
cleanup
3.4 and
Appendix B
§112.7(a)(3)(v) Methods of disposal of recovered materials in accordance
with legal requirements 3.4
§112.7(a)(3)(vi)
Contact list and phone numbers for facility response
coordinator, National Response Center, cleanup
contractors, all Federal, State, and local agencies who
must be contacted in case of a discharge
3.4 and
Appendix B
§112.7(a)(4) Spill reporting information 3.4 and
Appendix B
§112.7(a)(5) Discharge procedures Appendix A
§112.7(b) Failure prediction (sources, quantities, rates, and
directions)
3.1.4 and
Appendix A
Tables and
Diagrams
§112.7(c)
Secondary containment for all areas from which a
discharge of oil could occur (i.e. mobile refuelers,
loading/unloading areas, transformers, oil filled
operational equipment, etc.) other than bulk containers
3.1.1, Appendix
A Tables and
Diagrams
§112.7(d) Explanation of impracticability of secondary containment N/A
§112.7(d)(1) Oil spill contingency plan per part 109 3.1.4 and
Appendix B
§112.7(d)(2) Commitment of manpower, equipment & materials to
remove a discharge Appendix F
§112.7(e) Written procedures for inspections and tests 3.3
§112.7(e) Records of inspections and tests signed and kept 3 years 3.3.2 and
Appendix D
§112.7(f)(1) Employee training 3.5 and
Appendix D
§112.7(f)(2) Designated individual accountable for discharge
prevention 3.1, 3.2.2, 3.4
§112.7(f)(3) Discharge prevention briefings scheduled and conducted
annually
3.4 and
Appendix D
§112.7(h) Loading/unloading rack (excluding offshore facilities) N/A
§112.7(h)(1) Containment for contents of largest compartment Appendix A
Tables
§112.7(h)(2) Warning light/sign, barrier system, wheel chocks, or break
interlock system to prevent departure with connected lines Appendix E
Ursa Operating Company LLC Oil Production Facility SPCC Plan
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Regulation Description Section
§112.7(h)(3) Inspect drains and outlets of vehicles Appendix E
§112.7(i) Brittle fracture or catastrophic failure evaluation
requirements
NA – no field
constructed
tanks to be
utilized
§112.7(j) Conformance with State requirements 3.0, 3.2.1, and
Appendix A
§112.3(k)(1) Qualified Oil-Filled Operational Equipment: meets
criteria N/A
§112.7(k)(2)(i) Inspection procedures or monitoring program 3.3
§112.7(k)(2)(ii)(A) Oil spill contingency plan per part 109 Appendix B
§112.7(k)(2)(ii)(B) Written commitment of resources Appendix B
and Appendix F
§ 112.8
Spill Prevention, Control, and Countermeasure Plan
requirements for onshore facilities (excluding production
facilities)
N/A
§ 112.9
Spill Prevention, Control, and Countermeasure Plan
Requirements for onshore oil production facilities
(excluding drilling and workover facilities).
All
§ 112.9(a) Meet general and specific requirements All
§ 112.9(b)(1)
Oil production facility drainage: Restrain drainage from
diked areas; remove accumulated oil 3.3
§ 112.9(b)(2)
Oil production facility drainage: Inspect field drainages,
oil traps, sumps or skimmers for accumulations of oil,
remove oil 3.3
§ 112.9(c) Oil production facility bulk storage containers: 2.0
§ 112.9(c)(1)
Containers compatible with material and conditions of
storage 3.1
§ 112.9(c)(2)
Secondary containment for tank battery, separation and
treating units with capacity of largest container &
freeboard for precipitation Appendix A
§ 112.9(c)(2)
Drainage from undiked areas with potential to discharge
oil directed to catchment basin or holding pond N/A
Ursa Operating Company LLC Oil Production Facility SPCC Plan
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Regulation Description Section
§ 112.9(c)(3) Visually inspect containers, foundations and supports 3.3
§ 112.9(c)(4) Engineered to prevent discharges Appendix A
§ 112.9(c)(5)
Flow-through Process Vessel Alternative in lieu of
compliance with 112.9(c)(2) and (3) N/A
§ 112.9(c)(6)
Produced Water Containers comply with §112.9(c)(1)
and (c)(4); and §112.9(c)(2) and (c)(3), 2.0
§ 112.9(d) Facility transfer operations, oil production facilities 3.3
§ 112.9(d)(1)
Inspect aboveground valves, piping, drip pans, supports,
pumping, and etc. 3.3
§ 112.9(d)(2) Inspect salt water disposal facilities N/A
§ 112.9(d)(3)
Flowlines and intra-facility gathering lines are provided
with secondary containment per 112.7(c) Appendix A
§ 112.9(d)(3)(i)
For flowlines and intra-facility gathering lines that are
not provided with secondary containment, a Contingency
Plan following the provisions of Part 109 is included Appendix B
§ 112.9(d)(3)
For flowlines and intra-facility gathering lines that are
not provided with secondary containment, a written
commitment of manpower, equipment, and materials
required to expeditiously control and remove any
quantity of oil discharged that might be harmful is
provided
Appendix B
and
Appendix F
§ 112.9(d)(4)
A written program of flowline/intra-facility gathering
line maintenance has been prepared and implemented Appendix E
§ 112.9(d)(4)(i)
Flowlines and intra-facility gathering lines and
associated valves and equipment are compatible with the
type of production fluids, their potential corrosivity,
volume, and pressure, and other conditions expected in
the operational environment
3.1
Ursa Operating Company LLC Oil Production Facility SPCC Plan
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Regulation Description Section
§ 112.9(d)(4)(ii)
Procedures to visually inspect and/or test flowlines and
intra-facility gathering lines and associated
appurtenances on a periodic and regular schedule for
leaks, oil discharges, corrosion, or other conditions that
could lead to a discharge are included. For flowlines and
intra-facility gathering lines that are not provided with
secondary containment in accordance with §112.7(c), the
frequency and type of testing must allow for the
implementation of a contingency plan as described under
Part 109
3.3 and
Appendix E
§ 112.9(d)(4)(iii)
Take corrective action or make repairs to any flowlines
and intra-facility gathering lines and associated
appurtenances as indicated by regularly scheduled visual
inspections, tests, or evidence of a discharge.
3.3
§ 112.9(d)(4)(iii)
Procedures to promptly remove or initiate actions to
stabilize and remediate any accumulations of oil
discharges associated with flowlines, intra-facility
gathering lines, and associated appurtenances
3.3 and
Appendix B
§ 112.10
Spill Prevention, Control, and Countermeasure Plan
requirements for onshore oil drilling and workover
facilities. N/A
§112.20(e)
Completed and signed certification of substantial harm
form. 1.3
§ 112.11
Spill Prevention, Control, and Countermeasure Plan
requirements for offshore oil drilling, production, or
workover facilities. NA
COGCC 317B.d
Requirements for DCPS Operations at New Oil and Gas
Locations in the Intermediate Buffer Zone:
3.1 and
Appendix A
Ursa Operating Company LLC Oil Production Facility SPCC Plan
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Regulation Description Section
COGCC 604. Oil
and Gas
Facilities
Building specs for crude oil and condensate tanks, tank
location/distance requirements, berm construction
requirements, tank labeling requirements.
3.1 and Appendix
A
COGCC 605.a. Crude Oil and Condensate Tanks. 3.1 and Appendix
A
COGCC 906
Series Rules
Protocol specified for spills and releases in association
with O&G operations. 3.4 and Appendix C
Onshore Order 3
For all oil and gas operations on Federal and Indian
leases (except Osage), Onshore Order 3 specifies
requirements pertaining to site security.
Appendix A
Ursa Operating Company LLC Oil Production Facility SPCC Plan
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Regulatory Decision Matrix
Federal
Regulation
40 CFR §112, SPCC Onshore Order 3
State
Regulation COGCC Series Rules
All Locations
300 Series - 317B Locations - Regulatory
guidance for 317B areas will be updated
due to an invalid reference within the
regulations.
210.b.(2) Tank Battery
Label Requirements
210.d Tank and Container
Label Requirements
210.e General Sign
Requirements
906.e Secondary
Containment Requirements
604 Series - Setback Locations.
COGCC Form 2A COA’s
605.a Crude Oil and
Condensate Tanks
Landowner COA’s
CDPHE 7 C.C.R. 1101-14, (non-E&P)
605.a.(1) Tank Standards
605.a.(2),(3),(5),(6),
(7),(8),(11) Tank Placement
Distances from other
equipment
605.a.(4) Berm Construction
605.a.(9)Tank Gauges
605.a.(10) Vent Lines
40 CFR §112, FRP
Ursa Operating Company LLC Oil Production Facility SPCC Plan
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1.0 SPCC PLAN APPROVALS AND CERTIFICATIONS
1.1 Management Approval and Review
Ursa Operating Company LLC is committed to the implementation of the procedures outlined
in this SPCC Plan and to the prevention of any release of oil to navigable waters of the United
States of America. A copy of this Plan shall be maintained at the Ursa Operating Company LLC
Rifle, Colorado office and will be made available to the EPA Regional Administrator for on-site
review during normal working hours.
Authorized Management Representative:
S i g n a t u r e :
N a m e : R o b e r t B l e i l
Title: Ursa Regulatory & Environmental Manager
Ursa Operating Company LLC Oil Production Facility SPCC Plan
1 .2 Professional Engineer Certification
Date of Most Recent Plan Technical Review/PE Certification :
February 4 , 2014.
By means of this certification, I attest that:
I am familiar with the requirements of the SPCC rule (40 CPR 112);
The facility has been visited and examined by myself or my agent;
This Plan has been prepared in accordance with good engineering practice, including consideration
of applicable industry standards, and with the requirements of the SPCC rule;
Procedures for required inspections and testing have been established; and,
This Plan is adequate for the facility.
Signature f Pr fessional Engineer Date
(Q
State Registration No. State
Note: The PE 's certification do es not relieve the owner/operator of the facility of the duty of fully impleme nting the
SPCC Plan in accordance with all applicable requirements.
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Ursa Operating Company LLC Oil Production Facility SPCC Plan
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Field Name: Battlement Mesa
Facility Name: Speakman A Pad
Facility Location: 39.421017, -108.060560
The mailing address of the facility is: 792 Buckhorn Drive
Rifle, Colorado 81650
1. Does the facility have a maximum storage capacity of oil greater than or equal to
42,000 gallons and do the operations include over water transfers of oil to or from vessels?
Yes _____ No X
2. Does the facility have a maximum storage capacity of oil greater than or equal to one
million (1,000,000) gallons and is the facility without secondary containment for each
aboveground storage area sufficiently large to contain the capacity of the largest aboveground
storage tank within the storage area?
Yes _____ No X
3. Does the facility have a maximum storage capacity of oil greater than or equal to one
million (1,000,000) gallons and is the facility located at a distance such that a discharge from
the facility could cause injury to an environmentally sensitive area?
Yes _____ No X
4. Does the facility have a maximum storage capacity of oil greater than or equal to one
million (1,000,000) gallons and is the facility located at a distance such that a discharge from
the facility would shut down a public drinking water intake?
Yes _____ No X
5. Does the facility have a maximum storage capacity of oil greater than or equal to one
million (1,000,000) gallons and within the past 5 years has the facility experienced a reportable
spill in an amount greater than or equal to 10,000 gallons?
Yes _____ No X
Note: Tanks which store non-petroleum related liquids have not been included in the maximum
storage capacity
I certify under penalty of law that I have personally examined and am familiar with the information
submitted in this document, and that, based on my inquiry of those individuals responsible for
obtaining this information, I believe that the submitted information is true, accurate, and complete.
Authorized Management Representative:
S i g n a t u r e : D a t e :
Name: Robert Bleil Title: Regulatory and Environmental Manager
Ursa Operating Company LLC Oil Production Facility SPCC Plan
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1.4 Plan Review and Amendments
LOG OF PLAN REVIEW AND AMENDMENTS
NON TECHNICAL AMENDMENTS
• Non-technical amendments are not certified by a Professional Engineer.
• Examples of changes include, but are not limited to phone numbers, name changes, or any non-
technical text change(s).
TECHNICAL AMENDMENTS
• Technical amendments are certified by a Professional Engineer.
• Examples of changes include, but are not limited to, commissioning or decommissioning
containers; replacement, reconstruction, or movement of containers; reconstruction, replacement,
or installation of piping systems; construction or demolition that might alter secondary
containment structures; changes of product or service; or addition/deletion of standard operation
or maintenance procedures related to discharge prevention measures. It is the responsibility of the
facility to determine, and confirm with the regulatory authority as necessary, what constitutes a
technical amendment. The preamble of the rule states that an amendment is required only “when
there is a change that materially affects the facility’s potential to discharge oil” (67 FR
47091).
• An amendment made under this section will be prepared within six (6) months of the change and
implemented as soon as possible but not later than six (6) months following preparation of the
amendment.
• Technical Amendments affecting various pages within the plan can be P.E. certified on those
pages, certifying those amendments only, and will be documented on the log form below.
MANAGEMENT REVIEW
1. Management will review and amend this SPCC Plan at least each five (5) years or when there is a
change in the facility design, construction, operation, or maintenance that materially affects its
potential for a discharge. The review will be documented on the form below.
2. Management will review and amend this SPCC whenever there is a discharge of more than 1000
gallons of oil into or upon navigable waters in a single discharge or a discharge of more than 42
gallons of oil in each of two discharges occurring within any twelve month period. The Plan will
be submitted to the Regional Administrator within 60 days.
REVIEW AND AMENDMENT LOG
Review/
Amend Date
Signature *
(Specify)
Amend
Plan
(will/will
not)
Description of
Review Amendment
Affected
Pages or
Section
PE
Certification
(Y/N)
October 2013 Will
Addition of Site Specific
SPCC Plans (Dever C and
Norcross A, both within the
Gravel Trend Field)
Appendix A Yes
December 2013 Will
Addition of Site Specific
SPCC Plan, Castle Springs
Compressor Station
Appendix A Yes
Ursa Operating Company LLC Oil Production Facility SPCC Plan
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REVIEW AND AMENDMENT LOG Continued
Review/
Amend Date
Signature *
(Specify)
Amend
Plan
(will/will
t)
Description of
Review Amendment
Affected
Pages or Sections
PE
Certification
(Y/N)
February 2014 Will
Addition of Site
Specific SPCC Plans,
Speakman A, McLin
B, McLin C, non-
technical amendments
Appendix A,
Certification of
Harm pages,
Updated
notification
numbers, reporting
table, inspection
form, 3.1.3.a.,
Yes
March 2014 Will
Addition of a Site
Specific Plan –
Monument Ridge,
updates to Frei A
storage volume
Appendix A,
Certification of
Harm Pages.
Yes
*Typically signed by Manager, Professional Engineer or plan reviewer.
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2.0 FACILITIES, PROCEDURES, METHODS, OR EQUIPMENT
NOT YET FULLY OPERATIONAL
This SPCC Plan is being drafted in accordance with federal, state and local regulatory
requirements.
Per site inspections completed by a third party consulting group, deficiency items must be
addressed to obtain compliance with federal, state and local SPCC regulations and requirements.
Ursa is aware of the non-compliance items and is making the necessary efforts to address the
compliance items defined in Table 5 of the Site Specific SPCC Plans (Appendix A).
Ursa Operating Company LLC Oil Production Facility SPCC Plan
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3.0 SPCC PLAN POLICIES AND PROCEDURES
This SPCC Plan, hereinafter referred to as ‘the plan’, is a carefully conceived document prepared
to address onshore production facilities in Colorado operated by Ursa Operating Company LLC
(Ursa) which are subject to the federal SPCC regulations. There are several additional State of
Colorado SPCC-related requirements which are supplemental to the EPA oil pollution
prevention regulations (40 CFR 112). The applicability of these regulations will be discussed in
the site specific spcc plans contained in Appendix A. This plan was developed to satisfy the
applicable state and federal requirements. Specifically, this plan was developed to:
• Communicate pollution prevention requirements to Ursa employees.
• Document Ursa’s SPCC procedures and measures.
• Enable Ursa employees to report a spill and provide all the necessary information in the
event of a release.
• Assist Ursa in contacting and reporting pertinent information to the appropriate agencies.
• Provide site-specific information in a simple way.
Based on the type of respective operating facilities, the plan addresses both the general plan
regulatory requirements specified in 40 CFR 112.7 and those specific to onshore production
facilities 40 CFR 112.9. To ensure coverage of applicable regulations, a Regulatory Cross
Reference was provided at the beginning of this plan. It identifies salient sections of the
regulation in accordance with the plan section in which it is addressed. General requirements
applicable to each facility and to the overall management of SPCC-related activities are included
in the main text portion of the plan. Appendix A provides site specific information for each
individual facility covered by the SPCC plan. This information includes a site layout, description
of equipment, volume and type of material stored, surface water flow directions, and spill
prevention controls.
Technical amendments, such as addition of hydrocarbon storage containers, to this plan will be
issued within 6 months as mandated by 40 CFR 112.5. Such amendments will be certified by a
professional engineer if the amendment is considered to be technical. In accordance with
pertinent regulations, non-technical Plan amendments/reviews and revisions will also be issued
on a timely basis by personnel with the appropriate level of authority.
This plan conforms to the SPCC Regulations and was developed in accordance with sound
engineering practices. Any deviations from regulatory requirements that were noted during the
development of this plan are noted on Table 2. A complete copy of the SPCC Plan is maintained
at the Rifle Field Office and at the Denver Corporate Office.
Ursa Operating Company LLC Oil Production Facility SPCC Plan
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3.1 Owner Information
Name: Ursa Operating Company LLC
Address: U.S. Operations
792 Buckhorn Drive
Denver, CO 80265
Regional Address:
792 Buckhorn Drive
Rifle CO, 81650
Company Contacts: Robert Bleil, Ursa Regulatory & Environmental Manager
Tara Mall, HSE
Facility Location: This SPCC Plan is applicable to onshore production facilities
operated by Ursa in Colorado. Site specific information is
located within the Appendix A of this plan.
3.1.1 Facility Layout
Details for each facility covered by this plan are provided in Appendix A of this plan. In
general, the physical layout of an onshore production facility is associated most often with a well
pad. Equipment associated with the well pad includes, but is not limited to, separators,
dehydrators, wellheads, above/below ground piping, produced water tanks, condensate tanks,
methanol tanks, production pits, and miscellaneous storage. The equipment on the well pad is
typically organized in a manner which facilitates safe and efficient automobile navigation.
The valves associated with tanks, holding either oil or other chemicals, are kept in the closed and
locked position to help ensure unintentional flow does not occur when the tank is not being
actively used. The area around the tanks is kept free and clear of debris that could pose a safety
hazard (e.g. fire, traffic).
Storm water which flows across uncontained portions of the site is not anticipated to come into
contact with hydrocarbons. Visual inspections of the entire location are performed by designated
personnel or third party contractors as described in Section 3.3 of this plan with regards to SPCC
requirements and the Storm Water Management Plan with regards to storm water management.
3.1.2 Tanks, Piping and Equipment
The condensate and produced water tanks (tanks) are considered bulk storage tanks/containers
under the SPCC regulation. All tanks were built in accordance with API Specification 12F Shop
Welded Tanks for Storage of Production Liquids design. All enclosed tanks are equipped with
gas vents to relieve any pressure that might build up inside the tank, and are also equipped with
vacuum protection that prevent over or under pressuring of the tanks. All tanks are equipped with
hatchways for venting, gauging and/or access. All tanks should have stairways and hand railings
to facilitate worker safety when the gauging operations are underway. The tanks have been
sized to provide sufficient capacity to prevent overfilling. Tanks are gauged periodically to
Ursa Operating Company LLC Oil Production Facility SPCC Plan
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monitor the oil level to ensure that sufficient tank capacity is available for storage of produced
water or condensate. It should be noted that separator units are also considered to be bulk storage
containers and are subject to sized secondary containment and periodic inspection. As described
in Section 3.3, tanks are visually inspected on a regular basis for leaks, corrosion, and any
other malfunctions or deterioration. The tanks are also integrity tested prior to placement at the
facility. The equipment and associated hose is compatible with the fluids stored and storage
conditions such as pressure and temperature. Any flowlines are to be compatible with the
materials being transferred through them. Flowlines shall be powder coated and/or painted.
3.1.3 Containment Structures
Corrugated steel containment structures or earthen berms are present to provide secondary
containment for bulk storage structures. The storage volume of the respective secondary
containment is large enough to contain the entire capacity of the largest single container in the
secondary containment plus sufficient freeboard to allow for precipitation taking into account for
displacement as applicable. Additional storage volume may be required in the event the facility is
located in a Colorado Oil and Gas Conservation Commission (COGCC) high density area or the
intermediate or internal 317B buffer zone. Locations located within setback areas are also subject
to additional containment requirements. Section 3.1.3.a provides the respective information.
In addition, many of the facilities have a perimeter earthen berm around the well pad which can
provide secondary containment for separators, and condensate and produced water loading and
unloading activities. Should a release occur, the earthen berm will prevent migration of the
spilled material away from the site and allow Ursa to control and mitigate the release in a
timely and efficient manner. If a site perimeter berm is utilized as secondary containment, a
waterbar should be installed at the pad’s entrance, and any storm water diversion features should
drain to a catchment basin. These structures help to ensure releases of produced water (i.e. oil) at
facility on the surface are contained.
In some areas, there may be additional secondary containment requirements. Please see below for
additional requirements which may be applicable to facilities subject to this spcc plan.
3.1.3.a Additional Regulatory Requirements:
COGCC:
For facilities located in a Colorado Oil and Gas Conservation Commission (COGCC) high
density area, and/or a 317B Area, additional stipulations pertaining to SPCC requirements
will apply as provided below:
COGCC 317B.d
Requirements for Drilling Completions Production and Storage Operations at New
Oil and Gas Locations in the Intermediate Buffer Zone: The following shall be
required for all DCPS Operations at New Oil and Gas Locations within a Surface
Water Supply Area and in the Intermediate Buffer Zone as defined in Table 1. (1)
Pitless drilling systems; (2) Flowback and stimulation fluids contained within tanks
that are placed on a well pad or in an area with down gradient perimeter berming;
(3) Berms or other containment devices shall be constructed in compliance with
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Rule 603.e.(12) 605.a.(4)1 and 906.e.(1)1 around crude oil, condensate, and
produced water storage tanks
COGCC 604. Setback and Mitigation Measures for Oil and Gas Facilities, Drilling, and
Well Serviceing Operations
Exception Zone Setback. No Well or Production Facility shall be located five
hundred (500) feet or less from a Building Unit except as provided in Rules
604.a.(1) A and B, and 604.b.
Buffer Zone Setback. No Well or Production Facility shall be located one thousand
(1,000) feet or less from a Building Unit until the Operator certifies it has complied
with Rule 306.e. and the Form 2A or Form 2 contains conditions of approval related
to site specific mitigation measures as necessary to eliminate, minimize or mitigate
potential adverse impacts to public health, safety, welfare, the environment, and
wildlife.
High Occupancy Buildings. No Well or Production Facility shall be located one
thousand (1,000) feet or less from a High Occupancy Building Unit without
Commission approval following Application and Hearing. Exception Zone Setback
mitigation measures pursuant to Rule 604.c. shall be required for Oil and Gas
Locations within one thousand (1,000) feet of a High Occupancy Building, unless
the Commission determines otherwise.
Designated Outside Activity Areas. No Well or Production Facility shall be
located three hundred fifty (350) feet or less from the boundary of a Designated
Outside Activity. The Commission, in its discretion, may establish a setback of
greater than three hundred fifty (350) feet based on the totality of circumstances.
Buffer Zone Setback mitigation measures pursuant to Rule 604.c. shall be required
for Oil and Gas Locations within one thousand (1,000) feet of a Designated Outside
Activity Area, unless the Commission determines otherwise.
Maximum Achievable Setback. If the applicable setback would extend beyond the
area on which the Operator has a legal right to locate the Well or Production
Facilities, the Operator may seek a variance under Rule 502.b. to reduce the setback
to the maximum achievable distance.
Mitigation Measures. The following requirements apply to an Oil and Gas
Location within a Designated Setback Location and such requirements shall be
incorporated into the Form 2A or associated Form 2 as Conditions of Approval.
Leak Detection Plan. The Operator shall develop a plan to monitor Production
Facilities on a regular schedule to identify fluid leaks.
Berm construction. Berms or other secondary containment devices in Designated
Setback Locations shall be constructed around crude oil, condensate, and produced
water storage tanks and shall enclose an area sufficient to contain and provide
secondary containment for one-hundred fifty percent (150%) of the largest single
tank. Berms or other secondary containment devices shall be sufficiently impervious
1 The regulatory references are not currently finalized. Upon finalization, the text will be updated.
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to contain any spilled or released material. All berms and containment devices shall
be inspected at regular intervals and maintained in good condition. No potential
ignition sources shall be installed inside the secondary containment area unless the
containment area encloses a fired vessel. Refer to American Petroleum Institute
Recommended Practices, API RP - D16.
Tank specifications. All newly installed or replaced crude oil and condensate
storage tanks shall be designed, constructed, and maintained in accordance with
National Fire Protection Association (NFPA) Code 30 (2008 version). The operator
shall maintain written records verifying proper design, construction, and
maintenance, and shall make these records available for inspection by the Director.
Only the 2008 version of NFPA Code 30 applies to this rule. This rule does not
include later amendments to, or editions of, the NFPA Code 30. NFPA Code 30 may
be examined at any state publication depository library. Upon request, the Public
Room Administrator at the office of the Commission, 1120 Lincoln Street, Suite
801, Denver, Colorado 80203, will provide information about the publisher and the
citation to the material.
Exception Zone Setback. Within the Exception Zone Setback, the following
mitigation measures will be mandatory: . All mitigation measures required pursuant
to subsection 604.c.(2), above, and Berm Construction: i. Containment berms shall
be constructed of steel rings, designed and installed to prevent leakage and resist
degradation from erosion or routine operation. ii. Secondary containment areas for
tanks shall be constructed with a synthetic or engineered liner that contains all
primary containment vessels and flowlines and is mechanically connected to the
steel ring to prevent leakage. iii. For locations within five hundred (500) feet and
upgradient of a surface water body, tertiary containment, such as an earthen berm, is
required around Production Facilities. iv. In an Urban Mitigation Area Exception
Zone Setback, no more than two (2) crude oil or condensate storage tanks shall be
located within a single berm.
COGCC 605. Oil and Gas Facilities
Atmospheric tanks used for crude oil storage shall be built in accordance with the
standards specified with the respective regulation. (2) Tanks shall be located at least
two (2) diameters or three hundred fifty (350) feet, whichever is smaller, from the
boundary of the property on which it is built. Where the property line is a public
way the tanks shall be two thirds (2/3) of the diameter from the nearest side of the
public way or easement. A. Tanks less than three thousand (3,000) barrels capacity
shall be located at least three (3) feet apart. B. Tanks three thousand (3,000) or more
barrels capacity shall be located at least one-sixth (1/6) the sum of the diameters
apart. When the diameter of one tank is less than one-half (1/2) the diameter of the
adjacent tank, tanks shall be located at least one-half (1/2) the diameter of the
smaller tank apart. (3) At the time of installation, tanks shall be a minimum of two
hundred (200) feet from any building unit.(4) Berms or other secondary containment
devices shall be constructed around crude oil, condensate, and produced water tanks
to provide secondary containment for the largest single tank and sufficient freeboard
to contain precipitation. Berms and secondary containment devices and all
containment areas shall be sufficiently impervious to contain any spilled or released
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material. Berms and secondary containment devices shall be inspected at regular
intervals and maintained in good condition. No potential ignition sources shall be
installed inside the secondary containment area unless the containment area encloses
a fired vessel.(5) Tanks shall be a minimum of seventy-five (75) feet from a fired
vessel or heater treater.(6) Tanks shall be a minimum of fifty (50) feet from a
separator, well test unit, or other non-fired equipment.(7) Tanks shall be a minimum
of seventy-five (75) feet from a compressor with a rating of 200 horsepower, or
more.(8) Tanks shall be a minimum of seventy-five (75) feet from a wellhead.(9)
Gauge hatches on atmospheric tanks used for crude oil storage shall be closed at all
times when not in use.(10) Vent lines from individual tanks shall be joined and
ultimate discharge shall be directed away from the loading racks and fired vessels in
accord with API RP 12R-1, 5th Edition (August 1997, reaffirmed April 2, 2008).
Only the 5th Edition of the API standard applies to this rule; later amendments do
not apply. The API standard is available for public inspection during normal
business hours from the Public Room Administrator at the office of the
Commission, 1120 Lincoln Street, Suite 801, Denver, Colorado 80203. In addition,
these materials may be examined at any state publication depository library. (11)
During hot oil treatments on tanks containing thirty-five (35) degree or higher API
gravity oil, hot oil units shall be located a minimum of one hundred (100) feet from
any tank being serviced.
906.e.(1) Spill/Release Prevention Secondary containment.
Secondary containment that was constructed before May 1, 2009 on federal land, or
before April 1, 2009 on other land, shall comply with the rules in effect at the time
of construction. Secondary containment constructed on or after May 1, 2009 on
federal land, or on or after April 1, 2009 on other land shall be constructed or
installed around all tanks containing oil, condensate, or produced water with greater
than 3,500 milligrams per liter (mg/l) total dissolved solids (TDS) and shall be
sufficient to contain the contents of the largest single tank and sufficient freeboard
to contain precipitation. Secondary containment structures shall be sufficiently
impervious to contain discharged material. Operators are also subject to tank and
containment requirements under Rules 603. and 604. This requirement shall not
apply to water tanks with a capacity of fifty (50) barrels or less.
Federal Leases
Onshore Order 3
For facilities which are subject to Onshore Order 3 (i.e. assets located on Federal
leases, or wells and facilities on State or privately-owned mineral lands committed to
a unit or communitization agreement that affects Federal or Indian interests), valves
and other points which oil could be loaded out of will be subject required to be
marked with a unique identifier called a seal to ensure oil (i.e. condensate) is not
unloaded from the equipment without the volume being documented and provided to
the respective federal agent (i.e. bureau of Land Management official, or Bureau of
Indian Affairs official). For additional information pertaining to the requirements of
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this regulation please see Attachment 1.
3.1.4 Potential Discharge Volume and Direction of Flow
The direction of flow will be specific to the respective location the facility is associated with, and
is noted within the site specific plan(s) included within Appendix A. Please see below for
examples of potential discharge volumes and causes.
One scenario for release of oil is the loss of containment of the largest tank at any particular
facility due to rupture (300 bbl. example tank size). This could result in the release of up to
12,600 gallons of oil within one hour. Oil would spill into the secondary containment. In this
scenario, oil would be contained within the secondary containment.
Another possible scenario would be the release of oil outside the secondary containment during
truck loading/unloading activities; such as a ruptured hose connection on water truck. This could
result in the release of approximately 150 gallons of oil per minute, until the attendant could
access the shutoff valve. The volume of oil released during this scenario is variable.
A third possible scenario would be the rupture of a flowline outside of secondary containment
due to equipment failure. This could result in the release of approximately 150 gallons of oil per
hour, until the failure is noticed during routine inspections. The volume of oil released during
this scenario is variable.
In all instances, the spill response and notification procedures provided in Ursa’s Spill Prevention
and Management Plan would be implemented in an orderly and efficient manner. In addition to
the Spill Prevention and Management Plan, an Oil Spill Contingency Plan is included with this
plan.
3.1.5 Proximity to Navigable Waters
All facilities are located within the Colorado River watershed. The surface water proximity is
illustrated within maps and tables contained in Appendix A. In the event of an uncontrolled
discharge from a facility, oil would follow the natural topography of the landscape. Additionally,
each facility diagram within the site specific plan depicts the anticipated direction of runoff from
the facility and the distance relative to the potentially impacted navigable waterway.
3.1.6 Site Specific Facility Diagrams
Site specific facility maps and diagrams are included in Appendix A with the following detail
and location information as applicable:
• Process equipment,
• Fixed aboveground storage tanks.
• Direction of surface water runoff.
• Completely buried and bunkered tanks (including USTs covered under 40 CFR 280 or
281).
• Drum and portable container storage areas.
• The type of oil and storage capacity.
• Material of construction for all containers.
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• Connecting pipes including intra-facility gathering lines.
3.1.7 SPCC Plan Development Tables
Site specific SPCC detail tables were drafted for each facility included in this plan. Details from
the development tables such as the number of tanks, capacity, contents, and secondary
containment descriptions are provided in Tables 2, 3 and 4 of the respective site specific plans.
The development tables were created to standardize SPCC site inspections and maintain a
database of information including but not limited to:
• General facility information.
• Tank information.
• Processing equipment.
• Containment/loadout information.
• Failure information outside of containment.
• Facility property information.
• Surrounding drainage.
• Comments.
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3.2 General Requirements
3.2.1 Discovery, Response and Cleanup of Releases
The respective facilities are inspected routinely as described in Section 3.3.2. In the event a
release is discovered, the protocol provided in the Spill Prevention and Management Plan will be
implemented. Section 3.5.1 of this plan provides guidance with regards to annual training
requirements. It is recommended that oil handling personnel obtain and maintain the appropriate
Hazwoper training for their position. All recovered materials will be handled in accordance with
all applicable federal, state and local laws and regulations as described in the Spill Prevention
and Management Plan and Section 3.4 of this plan.
3.2.2 Notification Contacts
Robert Bleil or Tara Mall:
- 970-625-9922 – Rifle Office Number
- 720-425-0303 – Robert Mobile
- 970-618-2155 – Tara Mobile
- 720-508-8350 – Denver Office
Please see the flowcharts included in Appendix B if the above personnel cannot be contacted,
should a release occur, additional information is provided in the Spill Prevention and
Management Plan. Prior to any notification to agencies, the Spill Prevention and Management
Plan will be utilized to determine the agency notification requirements.
3.2.3 Notification Forms
The appropriate forms which must be completed prior to reporting a spill are included in this plan
as Appendix D. For additional information, please refer to the Spill Prevention and Response
Plan and Appendix B of this plan.
3.2.4 Response Plan
General information on the response to, and reporting of, oil discharges can be found in the
Spill Prevention and Response Plan. Additional information is located within Section
3.4 of this plan and the attached Oil Spill Contingency Plan, a copy of which is provided in
Appendix B. The Oil Spill Contingency Plan describes procedures that will be implemented
under various emergency scenarios, including when an oil discharge occurs. The plan is also
designed to address releases from areas such as flowlines where secondary containment is not
practical.
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3.3 Routine Facility Operations, Inspections and Maintenance
Ursa’s oil spill prevention program is described in this section of the SPCC plan and includes
routine facility operations, periodic inspections and maintenance activities. It addresses all
routine activities associated with the oil production facilities as required by 40 CFR 112.7 and
112.9.
3.3.1 Facility Operations
All equipment is operated and positioned in a way which is designed to prevent and
contain releases. Load line and drain valves are maintained in a closed position when not in use.
The facility is visited periodically by Ursa personnel. The volume of liquid is gauged and the
fluid level in each tank is assessed prior to loading or offloading oil2 when the inventory
approaches the tank capacity. The designated personnel also performs a visual inspection of all
above ground vessels, tank hatches, valves, and secondary containment features to ensure issues
are promptly identified as described in Section 3.3.2.
Tank truck loading/unloading occurs at all the facilities covered in this plan. However, the
facilities will not have a loading/unloading rack as defined by 40 CFR 112.2. The tanks may be
connected to each other via piping, or each tank may be self-contained within the secondary
containment area. Trucks used to offload oil are positioned adjacent to the secondary containment
structures and are attended by the personnel during all loading and unloading activities. All
loading and unloading activities are conducted by qualified contract personnel who are
trained in proper loading and spill prevention techniques and procedures. Pumper truck
personnel inspect tank truck and transfer lines including drains and outlets on the tank trucks
prior to filling and before departure to ensure that there are no leaks or discharges. If necessary,
truck personnel tighten, adjust, or replace equipment that is leaking. Premature vehicular
departures are prevented with a manual air brake system and oversight. A Summary of Operating
Procedures (SOP) can be found in Appendix E.
3.3.2 Facility Inspection Program
Tanks containing oil are inspected periodically. Designated personnel are trained to identify and
report any leaks or other deficiencies (e.g. compromised secondary containment). Inspections are
conducted on a monthly basis and include review of equipment, tanks, valves, hatches, and
lines; the site drainage system; and the entire tank battery, including the area within the
containment structures and earthen berms. Specifically, each storage vessel, separator, and
miscellaneous equipment is visually inspected for deterioration and maintenance needs, including
the foundation and support of each tank/container located on or above the ground surface. The
inspection also includes visual check of facility transfer equipment including transfer piping and
valves, drip pans, pumping well polish rod stuffing boxes, tanks, separators, heater-treaters, valve
glands and bodies, pipe supports, and bleeder and gauge valves. Inspection of conditions
associated with buried flowlines is accomplished by observing the ground surface above the
lines for evidence of leaks on a routine basis. Please see the inspection form included as
Appendix D. It should be noted that some locations will have additional inspection requirements
2 Oil means oil of any kind or in any form, including, but not limited to: fats, oils, or greases of animal, fish, or marine
mammal origin; vegetable oils, including oils from seeds, nuts, fruits, or kernels; and, other oils and greases, including
petroleum, fuel oil, sludge, synthetic oils, mineral oils, oil refuse, or oil mixed with wastes other than dredged spoil.
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in accordance with the respective location’s COGCC Form 2A conditions of approval. The
approved Form 2A has been included for reference within the respective site specific plans for
locations it was available for. In the event additional Form 2A documents are approved, the
document shall be included within the site specific plans as soon as practical.
During the field inspection, the site drainage systems such as drainage ditches, road ditches, and
intermittent creeks in the vicinity of the facility are inspected for accumulations of oil. Rainwater
and other precipitation that accumulates within the berm is either allowed to evaporate, infiltrate
into underlying soil, or is removed using a vacuum truck. Excess rainwater removed by the
vacuum truck is either returned to storage or transported for offsite disposal at a permitted non-
hazardous disposal facility. No drains are present in the secondary containment structures or
earthen berms. A discharge of rainwater from the secondary containment structures cannot occur
unless the structure fails or is breached.
Observations made by the SPCC inspector are recorded on SPCC/Containment inspection, which
are stored at the Rifle Field Office and the corporate office in Denver. A copy of the
SPCC/Containment inspection form is provided in Appendix D. Mechanical integrity and spill-
related issues are addressed as they are identified.
During the inspection, the site drainage systems such as drainage ditches, road ditches, and
intermittent creeks in the vicinity of the facility are inspected for accumulations of oil. Rainwater
and other precipitation that accumulates within the berm is either allowed to evaporate, infiltrate
into underlying soil, or is removed using a vacuum truck. Excess rainwater removed by the
vacuum truck is either returned to storage for use in storage or transported for offsite disposal at a
permitted non-hazardous disposal facility. No drains are present in the secondary containment
structures or earthen berms. A discharge of rainwater from the secondary containment structures
cannot occur unless the structure fails or is breached.
Oil accumulating within the secondary containment area is removed using absorbent pads or is
removed with excess rainwater using a vacuum truck as described above. Accumulated oil is not
discharged outside of the secondary containment area. Evidence of hydrocarbon spills are noted
and remediated as appropriate as described in Section 2.4.
Please see below for a table which provides guidance with regards to inspection and testing
recommendations:
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3.3.2.a Testing and Record Keeping Guidance
General Requirements Applicable to All Facilities
Bulk storage with no secondary
containment and for which an
impracticability determination has been
made
112.7(d) Test
Integrity testing. Periodically.
However, because there is no
secondary containment, good
engineering practice may
suggest more frequent testing
than would otherwise be
scheduled.
Valves and piping associated with bulk
storage containers with no secondary
containment and for which an
impracticability determination has been
made
112.7(d) Test
Integrity and leak testing of
valves and piping associated
with containers that have no
secondary containment as
described in §112.7(c).
Periodically.
Recordkeeping requirement 112.7(e) Record
Keep written procedures and a
signed record of inspections and
tests for a period of three years.
Records kept under usual and
customary business practices
will suffice, for all actions.
Lowermost drain and all outlets of tank
car or tank truck 112.7(h)(3) Inspect
Visually inspect. Prior to filling
and departure of tank car or tank
truck.
Field-constructed aboveground
container 112.7(i) Evaluate
Evaluate potential for brittle
fracture or other catastrophic
failure. When the container
undergoes a repair, alteration,
reconstruction or a change in
service that might affect the risk
of a discharge or failure due to
brittle fracture or other
catastrophe, or has discharged
oil or failed due to brittle
fracture failure or other
catastrophe. Based on the results
of this evaluation, take
appropriate action.
Requirements for Onshore Production Facilities
Diked area 112.9(b)(1) Inspect
Visually inspect content. Prior
to draining. You must remove
accumulated oil on the rainwater
and return it to storage or
dispose of it in accordance with
legally approved methods.
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Requirements for Onshore Production Facilities Continued
Field drainage systems, oil traps,
sumps, and skimmers 112.9(b)(2) Inspect
Detect accumulation of oil that
may have resulted from any
small discharge. Inspect at
regularly scheduled intervals.
You must promptly remove any
accumulations of oil.
Aboveground containers 112.9(c)(3) Inspect
Visually inspect to assess
deterioration and maintenance
needs. Periodically and on a
regular schedule
Foundations or supports of each
container that is on or above the surface
of the ground
112.9(c)(3) Inspect
Visually inspect to assess
deterioration and maintenance
needs. Periodically and on a
regular schedule
All aboveground valves and piping
associated with transfer operations 112.9(d)(1) Inspect
During the inspection, assess
general condition of flange
joints, valve glands and bodies,
drip pans, pipe supports,
pumping well polish rod
stuffing boxes, bleeder and
gauge valves, and other such
items. Periodically and on a
regular schedule.
Saltwater disposal facilities 112.9(d)(2) Inspect
Inspect to detect possible system
upsets capable of causing a
discharge. Often, particularly
following a sudden change in
atmospheric temperature.
Flowlines 112.9(d)(3) Inspect
Have a program of flowline
maintenance to prevent
discharges from each flowline.
Each program may have its own
specific and individual
inspection, testing, and/or
evaluation requirements and
frequencies as determined by
the PE.
3.3.4 Maintenance Program
Ursa has a robust maintenance program aimed at eliminating releases of oil and minimizing
unplanned downtime. Preventative maintenance on mechanical equipment (e.g. pumps) is
completed in accordance with manufacturer recommendations to ensure proper operation. Any
equipment requiring maintenance that is identified by visual inspections of the facilities are
addressed by either Ursa mechanical staff or third party contractors. Equipment repairs are made
in accordance with the relevant codes and industry standards.
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3.4 Response and Reporting Information
Detailed spill reporting and response procedures are provided in the Spill Prevention and
Response Plan in addition to the information contained within this section. The specific response
protocol utilized will depend on the size and nature of the release.
3.4.1 Spill Response
The Incident Commander (IC) (Rob Bleil) and/or Alternate Incident Commander (AIC) (Tara
Mall) are responsible for implementing response procedures in the event of an oil spill or
discharge emergency. These personnel have the authority to commit the resources necessary to
carry out a response. However, all oil handling personnel of Ursa receive training to familiarize
themselves with all aspects of the SPCC Plan, facility operations, the location and characteristics
of materials handled at the facility, the locations of all records within the facility; and are
responsible for proper implementation of response procedures should the IC or AIC be
unavailable.
1. Assess the basic situation;
2. If the incident poses an immediate threat of fire, explosion, or other impact to safety, health,
or the environment, the local fire department will be contacted at 911 or relay information
to dispatch via radio;
3. Call the company personnel;
4. If it is safe to enter the area and the personnel are properly trained and certified, they can
protect themselves with personal protective equipment (PPE);
5. Eliminate ignition sources;
6. Restrict access;
7. Stop the source of the release if safe to do so;
8. Contain the spill if possible to safely to so with available spill response inventory items;
9. Report the release to the appropriate authorities listed in Section 8.0;
10. If the spill involves a minor amount of oil, it will be cleaned up by Bargath personnel
provided that:
a. They have current and appropriate HAZWOPER and applicable OSHA training;
b. Appropriate Material Safety Data Sheets (MSDS sheets) are available for the
material spilled; and
c. Appropriate PPE is available and used.
In general, recovered fluids are either returned to an uncompromised tank for storage, or
transported offsite for disposal at a permitted commercial disposal facility. Hydrocarbon
impacted soil is segregated onsite and is tested to assess the contamination of concern identified
in the COGCC Table 910-1. Please see the flowcharts in Appendix B for streamlined spill
response protocol.
3.4.2 Spill Reporting
As described in the Spill Prevention and Response Plan, Emergency Response Plan and the Oil
Spill Contingency Plan, the Incident Commander will be notified in the event of a release.
Notification forms are provided in Appendix C. The forms will document the event concisely by
identifying information that needs to be obtained. Depending on the size and environmental
conditions associated with the spill, the Incident Commander may have to report the release to
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various state and federal regulatory agencies. For specific reporting information please see the
Colorado and Federal Verbal Notification & Written Reporting Protocol Table located in
Appendix B in addition to the Spill Prevention and Response Plan.
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3.5 Spill Response Training
3.5.1 Annual Training
Ursa and its contractors provide the following minimum training to oil-handling personnel:
• Operation and maintenance of equipment to prevent oil discharges;
• Oil discharge procedure protocols;
• Applicable oil spill prevention (State & Federal) laws, rules, and regulations;
• General facility operations; and
• The contents of the facility SPCC Plan.
Training is conducted prior to assignment of job responsibilities and then again annually.
Training includes oil spill prevention, SPCC Plan requirements, and federal and state pollution
prevention and spill reporting/response requirements.
3.5.2 Discharge Prevention Briefings
The facility conducts discharge prevention briefings for oil-handling personnel at least once a
year to assure adequate understanding of the SPCC Plan for the facility. At a minimum, this is
conducted via annual SPCC and spill response refresher training describing the contents of the
SPCC regulations and plans, spill response techniques, and a review of federal and state spill
reporting requirements. These briefings also include discussion of potential discharges or
component failures and precautionary measures. If a spill has occurred, Ursa will also
summarize the spill events and the measures implemented to prevent future releases.
3.5.3 Training Records
Copies of training and discharge prevention logs can be found in Appendix D. Training records
and Discharge Prevention Briefing logs are maintained for a minimum period of three (3) years
at the Rifle Field Office. Each contractor organization providing oil-handling personnel maintains
training records for its employees.
Ursa Operating Company LLC Appendix A
APPENDIX A
SITE SPECIFIC SPCC PLANS
Colorado Operations
792 Buckhorn Dr.
Rifle, CO 81650
Site Specific
SPCC/Containment Plan
Speakman A Well Pad
Garfield County, Colorado
February 2014
Revision #: 3 (October 2014)
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Contents
Introduction ................................................................................................................................................... 1
Facility Purpose ............................................................................................................................................ 1
Directions to the Facility: .......................................................................................................................... 1
Tables ............................................................................................................................................................ 2
Table 1. Facility Detail Summary ............................................................................................................. 2
Table 2. Tank Summary Details ............................................................................................................... 4
Table 3. Containment Summary ............................................................................................................... 6
Table 4. Containment Calculations ........................................................................................................... 7
Secondary Containment 1, Corrugated Metal Containment: ................................................................ 7
Secondary Containment 2, Corrugated Metal Containment: To be constructed ................................... 8
Table 5. Site Deficiencies ......................................................................................................................... 9
Table 6. Proximity to Navigable Waters ................................................................................................... 9
Table 7. Site Specific Plan Amendments ................................................................................................ 10
SPCC/Containment Site Detail Maps ......................................................................................................... 11
Secondary Containment 1: Site Detail Map ............................................................................................ 12
Secondary Containment 2 Site Detail Map ............................................................................................. 13
Approved COGCC Form 2A ...................................................................................................................... 14
Ursa Operating Company LLC Site Specific SPCC/Containment Plan
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Introduction
This site specific SPCC/Containment Plan (Plan) provides the pertinent information with regards
to the environmental and equipment information associated with the respective facility, as required
to ensure procedures and protocol implemented by Ursa to meet all applicable federal regulations
included in Spill Prevention Control and Countermeasure (SPCC) as described in CFR 40 §112.
This site specific plan also contains the relevant information required to meet all state and local
containment-related requirements. The protocol and procedures as provided in Ursa’s Field Wide
SPCC/Containment Plan will be applied to the respective facility.
Facility Purpose
The Speakman A Well Pad is an existing facility which facilitates the extraction of natural gas for
use in the surrounding area via pipeline infrastructure. Produced water and condensate are
considered by-products of the natural gas extraction process and are stored at the facility until their
respective final use is determined. Produced water may be recycled or treated at a water treatment
facility, while condensate can be utilized as an additive to fuel refining processes. A facility detail
summary is provided in Table 1. It should be noted that the well pad currently has working
wellheads, flow lines, separators, condensate tanks, and produced water tanks which are subject to
the SPCC and state regulations.
Please see the Tables and Maps included in the following portion of this Plan for additional
information pertaining to the facility.
In the event of a spill please contact the Incident Commander or Alternate Incident Commander.
If there is a serious threat to life please call 911.
Directions to the Facility:
Heading east on I-70, take Exit 75 and turn right onto County Road 215. Continue onto Country
Road 400 and then onto North Battlement Parkway. Travel 1.5 miles and turn right (south) onto
Stone Quarry Road. Travel 2.7 miles and turn left onto a gravel road. Travel 0.5 miles and turn left
(north) onto the Speakman A access road.
Ursa Operating Company LLC Site Specific SPCC/Containment Plan
2
Tables
Table 1. Facility Detail Summary
LOCATION OF AND ACCESS TO FACILITY
Facility Name: Speakman A Well Pad
Legal description: SW, 24, T7S, R96W, 6th PM
County, State: Garfield County, Colorado
Latitude and Longitude: 39.420827, ‐108.060354
Land Ownership (e.g. Federal (BLM, BIA) or
private)
Private Land, wells have federal access
though – Onshore Order 3 is applicable.
Is the facility secured by a gate and lock? No
Type of facility (e.g. onshore oil and gas
production facility, storage facility): Onshore oil and gas production facility
Adjacent land is used for:
Agricultural, grazing, residential, and oil
and gas production – subdivisions to the
northwest ~0.25 miles
Describe the terrain surrounding the facility: Flat bench, pinion, juniper, sagebrush
What is the direction of surface flow of the
facility? Northwest
Are there surface water features, or drainages
visible within 500 feet?
Yes, there are two unnamed
intermittent/ephemeral drainages. One on
the west side ~344 feet and one on the
east side ~310 feet. Both are tributaries to
the Colorado River
Is there H2S Gas known at this facility? No
SECONDARY CONTAINMENT OVERVIEW (see the Tables Section for specifics)
How many containment areas are at this facility? Two (2)
Are there any catch basins being utilized for
secondary containment at this facility? No
Is the facility within a COGCC 317B, or setback
area? No
If the facility is within a 317B internal or
intermediate zone, high density, or setback area
and limit the number of tanks to two condensate
tanks per containment?
No
Is there a stocked spill kit onsite? No
Ursa Operating Company LLC Site Specific SPCC/Containment Plan
3
TANKS, FLOWLINES, AND EQUIPMENT
Total Oil Storage of Facility (bbl.)
Above ground:
Below ground: 0
Are the tanks labeled in accordance with
regulatory requirements pertinent to SPCC
regulations?
Yes
Are the tanks equipped with equalization
lines? Yes
Do load lines extend beyond the containment? No Cont. 1/ Yes Cont. # 2
Are tanks equipped with ladders? Yes
Are there any buried vessels No
What are the flow lines constructed of? Steel
Are flow lines above or below ground? Below ground
How is oil transferred from the facility? By Truck
Separators onsite? Properly labeled? Yes.
Wellheads onsite? Properly labeled? Yes, yes.
55 gallon drum storage? No
Misc. chemical storage Methanol, 1,000 gallons
CONTAINMENT DETAILS
Containment ID, as specified on site detail
map Secondary Containment 1
Shape (e.g. rectangle, oval, or other shape) Ellipse
Length (feet) 93
Width (feet) 45
Height (inches) 2.5
What is the containment constructed of? Corrugated metal
Is the containment lined? Yes
Is there a rock substrate within the
containment? Yes – small gravel
Containment ID, as specified on site detail
map Secondary Containment 2
Shape (e.g. rectangle, oval, or other shape) Ellipse
Length (feet) 74
Width (feet) 45.8
Height (inches) 2.5
What is the containment constructed of? Corrugated metal
Is the containment lined? Yes
Is there a rock substrate within the
containment? Yes – small gravel
Ursa Operating Company LLC Site Specific SPCC/Containment Plan
4
Table 2. Tank Summary Details
Equipment Details
Container Fluid Materials of
Construction
Diameter and
Height (ft.)
Volume
(bbl.) Containment Comments
120096696 Prod. water Coated Steel 12 x 20 400 Secondary
Containment 1
-
120096694 Prod. water Coated Steel 12 x 20 400 Secondary
Containment 1
-
120096695 Prod. water Coated Steel 12 x 20 400 Secondary
Containment 1
-
120096698 Prod. water Coated Steel 12 x 20 400 Secondary
Containment 1
120096699 Prod. water Coated Steel 12 x 20 400 Secondary
Containment 1
-
120096697 Prod. water Coated Steel 12 x 20 400 Secondary
Containment 1
-
120096720 Prod. water Coated Steel 12 x 20 400 Secondary
Containment 1
-
120096722 Prod. water Coated Steel 12 x 20 400 Secondary
Containment 1
Tank is disconnected and
out of service
Catch Trap Tank 1 Produced
water/condensate Coated Steel 2’, 4’ 2.6 Secondary
Containment 1
Propped up on legs – no
displacement volume
Separators (12) Produced
water/condensate Steel NA 12 Integrity testing Each separator holds 1 bbl.
of produced
1 The catch trap tank is utilized to capture liquids from the condensate and produced water tanks within the flare flow line infrastructure prior to the associated gas
traveling to the flare for emissions control.
Ursa Operating Company LLC Site Specific SPCC/Containment Plan
5
Equipment Details continued
Container Fluid Materials of
Construction
Diameter and
Height (ft.)
Volume
(bbl.) Containment Comments
26674 Produced Water Coated Steel 15.6’ x 9’ 300 Secondary
Containment 2
-
25035 Produced Water Coated Steel 15.6’ x 9’ 300 Secondary
Containment 2
-
26673 Produced Water Coated Steel 15.6’ x 9’ 300 Secondary
Containment 2
-
26354 Produced Water Coated Steel 15.6’ x 9’ 300 Secondary
Containment 2
-
27203 Produced Water Coated Steel 15.6’ x 9’ 300 Secondary
Containment 2
-
24972 Produced Water Coated Steel 15.6’ x 9’ 300 Secondary
Containment 2
-
Planned
Separators (16)
Produced
water/condensate Steel N/A 16 Integrity Testing
Each separator holds 1 bbl. of
produced water/condensate.
There are three separator
houses.
Ursa Operating Company LLC Site Specific SPCC/Containment Plan
6
Non-oil storage - Not subject to SPCC regulations.
Methanol tank Methanol Coated Steel NA 1,000
gallons
Secondary
Containment 1
Propped up on legs – no
displacement volume
considerations.
Table 3. Containment Summary
Containment Construction details Comments
Secondary Containment 1 Line, Corrugated Metal Containment Condensate tanks, one catch tank and a methanol tank are
within this structure.
Secondary Containment 2 Lined, Corrugated Metal Containment Produced water tanks are held within this structure
Ursa Operating Company LLC Site Specific SPCC/Containment Plan
7
Table 4. Containment Calculations
Secondary Containment 1, Corrugated Metal Containment:
DISPLACEMENT VOLUME:
Vessel No. Diameter (ft.) Height (ft.) = Berm
Height Cubic. Ft.
120096696 12 2.50 NA
120096694 12 2.50 283
120096695 12 2.50 283
120096698 12 2.50 283
120096699 12 2.50 283
120096697 12 2.50 283
120096720 12 2.50 283
120096722 12 2.50 283
Catch Tank 2 NA NA
Displacement Volume (Total volume taken up by vessels other than the
largest vessel) (cubic feet) 1,978
SECONDARY CONTAINMENT VOLUME:
Length (ft.) Width (ft.) Height
(ft.) Unit
Containment Dimensions
93.0 45.0 2.50
r1 r2 pi
46.5 22.5 3.14
Containment Surface Area (square feet) 3,285
Containment Volume (cubic feet) 8,213
Displacement Volume (cubic feet) 1,978
Containment Volume (cubic feet) - the Displacement Volume (cubic feet) 6,235
Largest Tank in Containment (barrels) 400
Largest Tank in Containment (gallons) 16,800
Largest Tank in Containment (cubic feet) 2,246
Precipitation of 24 hour, 25 year event (inches) 2.10
Precipitation of 24 hour, 25 year event (feet) 0.18
Precipitation of 24 hour, 25 year event (cubic feet) 574.91
Containment Volume Required for Tank contents, and precipitation event
(cubic feet) 2,820.90
Percentage of largest tank in the containment 277.60
Percentage of largest tank in the containment and precipitation 221.02
Is the Containment Sufficient? Yes
Ursa Operating Company LLC Site Specific SPCC/Containment Plan
8
Secondary Containment 2, Corrugated Metal Containment:
DISPLACEMENT VOLUME:
Vessel No. Diameter (ft.) Height (ft.) = Berm Height Cubic. Ft.
26674 15.6 2.67 NA
25035 15.6 2.67 509
26673 15.6 2.67 509
26354 15.6 2.67 509
27203 15.6 2.67 509
24972 15.6 2.67 509
Displacement Volume (Total volume taken up by vessels other than the
largest vessel) (cubic feet) 2,547
SECONDARY CONTAINMENT VOLUME:
Length (ft.) Width (ft.) Height (ft.) Unit
Containment Dimensions
74.0 45.8 2.67
r1 r2 pi
37.0 22.9 3.14
Containment Surface Area (square feet) 2,661
Containment Volume (cubic feet) 7,095
Displacement Volume (cubic feet) 2,547
Containment Volume (cubic feet) - the Displacement Volume (cubic feet) 4,548
Largest Tank in Containment (barrels) 300
Largest Tank in Containment (gallons) 12,600
Largest Tank in Containment (cubic feet) 1,684
Precipitation of 24 hour, 25 year event (inches) 2.10
Precipitation of 24 hour, 25 year event (feet) 0.18
Precipitation of 24 hour, 25 year event (cubic feet) 465.59
Containment Volume Required for Tank contents, and precipitation event (cubic
feet) 2,150.08
Percentage of largest tank in the containment 269.97
Percentage of largest tank in the containment and precipitation 211.51
Is the Containment Sufficient? Yes
Ursa Operating Company LLC Site Specific SPCC/Containment Plan
9
Table 5. Site Deficiencies
Deficiency Requirement Agency /Citation Correction Completion
Date
Table 6. Proximity to Navigable Waters
Water ID Classification
Distance From Facility
(ft.)
Direction from Facility
Comments
East unnamed
intermittent/
ephemeral drainage
Ephemeral,
intermittent
drainage
310 feet East The USGS topographical map
(Parachute) indicates that these
drainages are tributaries to the
Colorado River. West unnamed
intermittent/ephemeral
drainage
Ephemeral,
intermittent
drainage
345 feet West
Ursa Operating Company LLC Site Specific SPCC/Containment Plan
10
Table 7. Site Specific Plan Amendments
Date Technical/Non-
technical Section Affected Reason for Amendment
February 2014 Technical All Tables, Maps Addition of UIC Injection Well Tanks and Containment,
updates to the site maps, inclusion of Form 2A.
August 2014 Non-technical Text Updates to nomenclature
October 2014 Non-technical Maps, tables Integration of specific tank identification numbers.
June 2015 Non-Technical Tables Updated tank disconnection status and tank contents to
prod. water in cont. # 1
Ursa Operating Company LLC Site Specific SPCC/Containment Plan
11
SPCC/Containment Site Detail Map
Ursa Operating Company LLC Site Specific SPCC/Containment Plan
12
Secondary Containment 1: Site Detail Map
Ursa Operating Company LLC Site Specific SPCC/Containment Plan
13
Secondary Containment 2 Site Detail Map
Ursa Operating Company LLC Site Specific SPCC/Containment Plan
14
Approved COGCC Form 2A
Ursa Operating Company LLC Appendix B
APPENDIX B
OIL SPILL CONTINGENCY PLAN
AND EMERGENCY RESPONSE
PLAN
Ursa Operating Company LLC Appendix B
Oil Spill Contingency Plan
This Oil Spill Contingency Plan (Plan) was prepared in accordance with 40 CFR 112.7(a)(5) to
address discharges of oil from the facilities covered by the Spill Prevention Control and
Countermeasure (SPCC) Plan. It also addresses oil discharges from field operations where
secondary containment is impracticable, per 40 CFR 112.7(d). This Plan complements the
prevention and control measures presented in the SPCC Plan by defining procedures and tactics
for reporting and responding to discharges of oil.
The Plan is intended to protect the public and minimize damage to the environment by providing
a timely, efficient, coordinated and effective action plan to respond to oil discharges. The plan is
consistent with the National Oil and Hazardous Materials Pollution Contingency Plan and
follows the guidelines provided in 40 CFR 109.
40 CFR 109.5 (a) Definition of the authorities, responsibilities and duties of all persons.
Ursa Management is responsible for:
Ensuring the necessary resources for control and cleanup are available
Ensuring that personnel are adequately trained to notice, report and respond to oil
discharges
Ursa’s Field Superintendent (or designate), serving as the Incident Commander, is responsible
for:
Overall coordination of the control and cleanup of the oil discharge
Committing the necessary resources (including monetary)
Requesting additional assistance from outside contractors and/or the Federal authorities
if necessary
Ensuring repairs are made prior to putting equipment back in service
Ensuring that proper notifications are made to Federal, State and Local agencies,
including any follow up documentation
Providing site safety plan if necessary
Coordinating disposal of contaminated material
Being familiar with the SPCC and Oil Spill Contingency Plans
Being alert for oil discharges and responding to them as appropriate
Assisting, as required, in the control and cleanup of the oil discharge
40 CFR 109.5(b) Establishment of notification procedures.
Ursa owns and operates a number of oil production facilities located in Garfield County,
Colorado. Personnel are trained to look for and report any oil discharge. The following is a list
of emergency contact numbers. Depending on the size and nature of the oil discharge some or
all of these contacts will be notified. Please refer to the flow charts and tables on the following
pages for spill response and notification protocol.
Ursa Operating Company LLC Appendix B
Colorado Operations
I NCIDENT NOTIFICATION & MANAGEMENT PROTOCOL
(H&S INCIDENTS, SPILLS, ENVIRONMENTAL/PROPERTY DAMAGE , NOVS)
MAJOR INCIDENT VERBAL NOTIFICATIONS If MAJOR INCIDENT AND NO
'H&S Recorda ble In cident (Person Discovering Incident) ..... DIRECT COMMUNICATION, K EEP
CALLING DOWN THE CHAIN-NO
'Repo rtabl e Spill I Incident MESSAGES or E-MAILS
'NOV w/ P ote nt ia l Fines ~ J, 'S pill Off-Pad
'Spi ll to Liv e Wate r f+ OPERATIONS PRODUCTION CONTRACTOR 'Me di a Inq uiry Po ssible
'P ropert y Damage Matt Honeycutt Shane Vaug hn ~ INCIDENT? NOTIFY
'L andowner Compl aint RES PON SIBLE ---IMMEDIATE REPORT I I CO NTRAC TOR
,
TO ENVS Han s W yc hgram Pake Y ounger IMMEDIATELY
w w • • • H&S REG I ENVIRONMENT LAND
T ara Mall Ro b Bleil Jeff Powers
SAFETY/INJURIES
TOP PRIORITY INCIDENT MANAGEMENT ••••
DISPATCH EMERGENCY,
INCIDENT & SPILL RESPONSE
CREWS AP PROPRIAT E IG--
-..,
H&S
I
FIRE I SERIOUS INJURY I
VEHICLE ACCIDENTS
LIFE THREATENTING?
(Implement SSERP)
I
OSHA FIRST AID I
REPORTABLE INJURY -
TREAT & REPORT
I
NEAR MISSES-REPORT
IF FUTURE RISK OF
SERIOUS INJURY I LIFE
THREA TENING
O PERATIONS (Cell Pl'lo ne)
M.Honeycutt (970) 812-2198
S.Vaughn (970) 623-9539
P.Younger (970) 260-2423
H.Wych:g~am (303) 884-9079
H&S
T.Mall (970) 618-2155
I
w
REG I ENVIRONMENT
I
SPILLS I RELEASES
(Implem ent Spill Response
Plan) Notify Spill Coordinator
I
ENVIRONMENT I
NATURAL RESOURCES /
WILDLIFE IMPACTS
(Resolve w/Ops Leads )
I
NON-COMPLIANCE I
FAILED AGENCY
INSPECTIONS & NOVS
(Resolve w /Ops Le ads)
RE G I EN·V I H&S (Cell)
R. Bleil (R/E) (720) 425-0303
S PILL PROGRA M L EA D
K.Rowe (970) 261-2015
LAN DI PROPERTY
DAMAGE
PROP ERTY DAMAGE
AN DOWNER
MPLAINTS I
ATER WELL
ONCERN S
IL
co
w
c
LAND
RES PO
RESOLVES WITH
NSIBLE PARTY &
AN DOWNER L
LAN D (Ce ll)
J. Powers (970) 309-9359
MEDIA/COMMUNITY
D. Sjh1pson (281) 467-3-117
NOTE: MEDIA INQUIRIES SHOUL D BE DIRECTED TO DON SIMPSON
Ursa Operating Company LLC Appendix B
In accordance with ----1 Section VI. D.2
In accordance with
Section VI. G
Colorado Operations
SPILL RESPONSE PROCESS
SPILL DISCOVERY
Notify On-Site Supervisor
Contain and/or contr?I spill if safe
Complete Upper Shaded Section of
Ursa Incident Investigation Form
~lotify Ursa
Ops Lead
!
Contact Spill Program Lead
K. Rowe (HRL)
Regulatory Agency Noti~cations
Responsible Party Detemrination
Contractor Ursa
i i
Remediation Remediation
i i
Waste Manaqement Waste Manaqement
i !
Corrective Action I Corrective Action I
Training Training
i
Documentation Copies Documentation to
to Ursa Regulatory Agencies
Proiect Closure Proiect Closure
Close valves or stop/redirect ftow
to prevent spill from getting larger.
See Appendix B
See Appendix C -Sp ill Notification Protocol
COG CC
LEPC I Fire Chief
CDPHE
In accordance with
Section VI. D.1
In accordance with
Section VI. G
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Ursa Operating Company LLC Appendix B
Spill response shall be completed in accordance with the Ursa Spill Response Plan.
The following pages contain phone numbers for contractors, regulatory agencies and
local emergency contact entities.
Water Haulers and Misc.
T.D. Productions
(970) 230-0704 (Terry Dick)
(970) 230-0702 Dispatch
(970) 984-2218
Wild Well Control Inc. (281) 353-5481
Hogback (970) 309-6322 (24/7)
Redi-Vac trucks (970) 625-0233 office
(970) 7561277 cell Lucas Gallegos
Dalbo (970) 625-0431 office
(970) 625-8659 cell Audie Williams
Cascade Tanks (Mountain Water) (970) 948-7262
Mountain Valley (970) 948-7262 cell Branden
Speedy (970) 985-9248 Office
(970) 309-8154 Cell Tracy
J&A Services (970) 434-9435 Travis Payne
(970) 590-4560 Cell Travis Anderson
Rain for Rent (970) 625-4600 office
Well Watchers (970) 309-7313 Cell Dan Mc queen
R & W BOP (970) 255-6487 Office
Mountain States Pressure Control (307) 362-1903 Office
Cudd Well Control (970) 858-8230 office
(970) 778-5553 cell Allen Bourgeois
Advanced Oil Field Services (970) 625-9704 office
Flint Energy (970) 625-4265 office
Calfrac – Kathleen Neault, HSE Supervisor (970) 243-7812 office
(970) 985-8613 cell
Frontier Drilling – James Lynch, Safety
Manager (435) 503-5767
Ursa Operating Company LLC Appendix B
AGENCY CONTACT NUMBER E-Mail ADDRESS
Local and State Agencies
Parachute Fire Chief David Blair 970-285-9119 (o)
970-250-9851 (c) firechief@gvfpd.org 0124 Stone Quarry Rd.
Parachute, CO 81635
Rifle Fire Chief Chad Harris 970-625-1243 (o)
970-379-9681 (c) Chad.Harris@crfs.us 1850 Railroad Ave.
Rifle, CO 81650 Silt Fire Chief
CDPHE Bob Peterson
John O’Rourke
970-248-7151(Bob)
719-269-5327 (John)
1-877-518-5608 [24-hr]
Robert.Peterson@dphe.state.co.us
or
John.Orourke@state.co.us
4300 Cherry Creek Drive South
Denver, CO 80246
CDNR Assigned at call 1-800-536-5308 Assigned at time of call 1313 Sherman Street, Room 718
Denver, CO 80203
CO Dept. of
Transportation Mike Verkitus 970-216-0577 Mike.Verketis@dot.state.co.us 222 South 6th St. Room 100
Grand Junction, CO 81501
COGCC Carlos Lujan (970)-625-2497 or
(303) 894-2100
Carlos.Lujan@state.co.us
1120 Lincoln Street, Suite 801
Denver, CO 80203
Garfield County
OEM (LEPC) Kirby Wynn (970) 945-0453 kwynn@garfield-county.com
Kirby Wynn
107 8th Street
Rifle, CO 80751
Garfield County
Health Agency Morgan Hill (970) 625-5200 ext 8106
970-379-3826 mhill@garfield-couny.com 195 W. 14th Street
Rifle, CO 81650
Pitkin County OEM
Alex Burchetta
or
Cindy Mohat
970-920-5037 alex.burchetta@pitkinsheriff.com
Cindy Mohat
Emergency Management Cord.
Pitkin County sheriff’s Office
506 E. Main
Aspen, CO 81611
Silt Public Water
Intake
Jack Castle
Or
Gerry Pace
970-876-2353 ext 817
970-876-5444
970-876-0460
jackc@townofsilt.org
231 N. 7th Street
PO Box 70
Silt, CO 81652
Rifle Public Water
Intake Dick Deussen 970-665-6590 ddeussen@rifleco.org 202 W. Railroad Av.
Rifle, CO 81650
Parachute Public
Water Intake Mark King 970-285-7630 (office)
970-986-1821 (cell) mking@parachutecolorado.com
222 Grand Valley Way
PO Box 100
Parachute, CO 81635
Federal Agencies
National Response
Center Assigned @ Call 1-800-424-8802
Available 24 hours
HQS-DG-lst-
NRCINFO@uscg.mil
2703 Martin Luther King Jr Ave.
SE, STOP 7713
Washington, DC 20593-7713
US Dept. of
Transportation Assigned @ Call (202) 366-4000 N/A 1200 New Jersey Avenue, SE
Washington, D.C. 20590
Environmental
Protection Agency Assigned @ Call (202) 272-0167 N/A
Ariel Rios Building
1200 Pennsylvania Ave., NW
Washington, DC 20460
Bureau of Land
Management Jim Byers 970-876-9056 (o)
970-319-2532 (c) jbyers@blm.gov 2850 Youngfield Street
Lakewood, CO 80215
Ursa Operating Company LLC Appendix B
40 CFR 109.5(c) Provisions to assure that full resource capability is known.
All field operation personnel are familiar with the location of spill response equipment and
response strategies, and with the SPCC and Oil Spill Contingency Plans. They receive annual
training in the deployment of response material and handling of hazardous waste
(HAZWOPER).
Sufficient equipment to respond to the majority of oil discharges is kept at the Ursa Field Office
and is accessible 24-hours a day to field operation personnel. This equipment is verified on a
monthly basis by designated personnel and is replenished as needed.
Ursa Operating Company LLC Appendix B
Identification and Inventory of Recommended Applicable Equipment
3-Cases 17” x 19” x 3/8” Oil absorbent Pads
1-Case 7” W x 15” L Oil Absorbent Pillows
1-Case 3” x 4’ Mini Booms
1-Case 3” x 8” Oil Absorbent Booms
1 5” x 10’ Oil Absorbent Boom
2-Boxes 36” x 56” 3 mil Trash Can Liners
1 Large Tyvek Coverall
1 Extra Large Tyvek Coverall
1-Bag Size 10 Green Nitrile Gloves
2 Round Point Blade Shovels
2 Square Point Blade Shovels
15 5-1/2 foot Steel Fence Posts
1 Fence Post Driver
1-Roll 16 ga Tie Wire
1-Bundle Wooden Stakes
1 Crescent 148 Piece Tool Set
6 28” Traffic Cones
2-Rolls Duct Tape
2-Rolls 6 mil 20’ x 100’ Plastic Sheeting
3 20 lb. Fire Extinguishers
1 Metal First Aid Kit
2 55 Gal. Poly Drums (Drums contain absorbent booms, pillows and pads)
1 55 Gal Steel Drum
40 CFR 109.5(d) Provisions for well-defined and specific action to be taken after discovery
and notification of an oil discharge.
Ursa has the primary responsibility to provide the initial response to oil discharge incidents
originating from its operations. To accomplish this, Ursa has designated the Regulatory and
Environmental Manager, Robert Bleil, as the qualified Incident Commander. Tara Mall will
serve as the Alternate Incident Commander. In addition, Ursa maintains an Emergency
Response Team, some or all of which may be mobilized depending on the size and nature of
the oil discharge.
Upon the discovery of an oil discharge the Incident Commander will be notified so that
appropriate action can be taken. The Incident Commander has the authority to direct and
coordinate response operations and may request assistance from Federal authorities as
necessary. Containment and clean-up operations will be managed out of the Ursa Field Office.
Operations personnel are equipped with cellular phones to assist with communications.
In the event of a discharge, the first priority is to stop the product flow and to shut off all
ignition sources, followed by the containment, control, and mitigation of the discharge.
Specifically, the following response procedures will be implemented in accordance with the
respective personnel’s level of training:
Ursa Operating Company LLC Appendix B
Response Procedures
Please refer to the Spill Prevention and Response Plan for a definitive guide for response
procedures.
A. Detection:
1. Notify the Incident Commander that an oil spill has occurred (provide location,
source, amount, nearby areas of concern, etc.).
2. Shut off ignition sources (motors, electrical circuits, open flames).
3. Turn off pumping unit that charges or provides flow to the flowlines.
4. Locate the source of flowline leak.
5. Attempt to stop the source of the leak, if it can be done safely.
6. Initiate containment.
B. Assessment and Notifications:
1. Investigate the discharge to assess the actual or potential threat to human health
or the environment.
2. Mobilize the Emergency Response Team if necessary.
3. Request outside assistance from local emergency responders, as needed.
4. Communicate with property owners regarding the discharge and actions taken to
mitigate the damage.
5. Make appropriate notifications to Federal, State, and Local agencies.
C. Control and Recovery
1. Prevent the spread of oil by deploying absorbents (i.e. booms), by building
diversion structures (i.e. berms), or digging temporary containment pits.
2. Direct clean-up of the oil and oil contaminated material.
3. Arrange to have soil and/or water samples analyzed per COGCC Table 910-1
standards, and/or CDPHE water standards. If contaminants are below the affected
agencies allowable concentrations cleanup is complete.
4. Containerize contaminated material (soil, water, absorbent material, etc.).
D. Disposal of Recovered Product and Contaminated Response Material
1. Recovered product can either be added to another tank or disposed of at an
appropriate disposal site.
2. Properly characterize, label and store all contaminated material.
3. Dispose of contaminated material in accordance with all applicable solid and
hazardous waste regulations using a licensed waste hauler and disposal facility.
Ursa Operating Company LLC Appendix B
E. Termination
1. Arrange for necessary repairs to equipment or flowlines.
2. Review circumstances that led to the discharge and take necessary precautions to
prevent a recurrence.
3. Submit any required follow-up reports to the authorities.
4. Update the SPCC and Oil Spill Contingency Plan as necessary.
40 CFR 109.5(e) Specific and Well Defined Procedures to Facilitate Recovery of Damages
An Environmental Incident Report will be filled out by the Incident Commander and maintained
on file at the Ursa Field Office. Any other documentation regarding the oil discharge will also
be kept on file.
Ursa Operating Company LLC Appendix C
APPENDIX C
DISCHARGE NOTIFICATION FORMS
• COGCC Form 19 Spill/Release Report
• Ursa’s Environmental Incident Report
• Submittal of Information to Regional Administrator for Reportable Discharge(s)
Ursa Operating Company LLC Form 19
Ursa Operating Company LLC Contractor Spill/Release Report
r:;r Ursa , OPERATING •• _-..~"''"'.fir_._ COMPANY I Pad/Location:
• Report Date: ----------
CONTRACTOR SPILURELEASE REPORT CONTRACTOR:
ENVIRONMENTAL SPILL/RELEASE INVEST/GA Tl ON-COLORADO OPERATIONS
O.i::rnrr@d: Tim~: Companv: Phon~: --------
INCIDENT TYPE RELEASE TYPE LANDS AFFECTED MEDIA AFFECTED BIOTA AFFECTED
( ) facility ( ) E&P Waste () Private ( ) Land/Soil ( ) None
( ) Transportation ( ) Non-E&P () Federal ( ) Air ( ) Plar'ltS
() State ( ) Waters (U.SJ ( ) Wildlife -Game
( ) Other: ( ) Other: () On-Lease ( ) Wetland/Riperian ( ) Wildlife -T&E
() Off-Lease ( ) Ground Water ( ) Wfldlife-Non-game
SIGNIFICANT THREAT TO HUMANS OR ENVIRONMENT () No ( ) YES -Implement Emergency Response Plan
INCIDENT DESCRIPTION (How incident occurred, type of effluent, emissions, chemical, etc.):
ESTIMATED VOLUME/QUANTITY OF RELEASE: !VOLUME RECOVERED:
VOLUME REMAINING FOR WASTE MGMT:
RESPONSIBLE PARTY:
COMPANY ENV. REP: PHONE: EMAIL:
ROOT CAUSE
CORRECTIVE ACTION
CORRECTIVE ACTION CONFIRMED: IDATE:
FINAL DISPOSITION OF WASTE (STORAGE, TREATMENT, DISPOSAL)
TEMPORARY STORAGE LOCATION:
FINAL DISPOSAL LOCATION:
PLANS TO IMPLEMENT ADDITIONAL TRAINING (DESCRIBE) DATE:
Signature (Env. Rep): Date:
THIS REPORT MUST BE FILED AND SUBMITTED WITHIN 24 HOURS
OF THE INCIDENT TO THE URSA SPILL COORDINATOR
Ursa Operating Company LLC EPA Reportable Discharge Notification Form
Submittal of Information to Regional Administrator for Reportable
Discharges
In the event of a reportable discharge or discharges, this page can be utilized to provide official
notification to the Regional Administrator. If the Facility has had a discharge or discharges which
meet one of the following two criteria, then this report must be submitted to the Regional Administrator
within 60 days.
This Facility has experienced a reportable spill as referenced in 40 CFR Part 112.1(b) of 1,000
gallons or more.
This Facility has experienced two (2) reportable spills (as referenced in 40 CFR Part
112.1(b) of greater than 42 gallons each within a 12-month period.
Facility Name and Location:
Facility contact (Name, Address, Phone Number):
Facility maximum storage or handling capacity:
Facility normal daily throughput:
Describe the corrective action and countermeasures taken (include description of equipment repairs and
replacements):
Describe the Facility (maps, flow diagrams and topographical maps attached as necessary):
Describe the cause of discharge(as referenced in 40 CFR Part 112.1(b)) including failure analysis of the
system:
Describe the preventative measures taken or contemplated to be taken to minimize the possibility of
recurrence:
Other pertinent information:
Ursa Operating Company LLC Appendix D
APPENDIX D
SPCC FORMS
• SPCC/Containment Field Inspection
• Personnel Training Log
Ursa Operating Company LLC Appendix D
Ursa Operating Company LLC Appendix E
SPCC Training and Briefing Log Form
SPCC Training/Briefing Log
Trainer:
Date:
Subjects Discussed:
Name and Signature:
Please note: briefings are to take place on an annual basis at a minimum. All oil handing personnel shall be
training in accordance with the criteria specified in 40 CFR 112.7(f)(1). At a minimum, training is to include:
a. the operation and maintenance of equipment to prevent discharges;
b. discharge procedure protocols; - (addressed during the Ursa Spill Response portion
of this training)
c. applicable pollution control laws, rules, and regulations; general facility operations;
and,
d. the contents of the facility SPCC Plan.
Ursa Operating Company LLC Appendix E
APPENDIX E
SUMMARY OF OPERATING PROCEDURES
FLOWLINE MAINTENANCE PROGRAM
Ursa Operating Company LLC Appendix E
SUMMARY OF OPERATING PROCEDURES
FLOWLINE MAINTENANCE PROGRAM
Before any pumper is on location, gas meters must be on and properly calibrated.
The following (however not limited to) need to be checked in addition to regular
pumper’s responsibility to ensure a safe and normal operation by the production
operators/pumpers during their routine checks:
1. Water/oil dump valve and water flow meter malfunction:
A. Physically check every separator once every day by isolation/bleed-off
method.
B. If there is any leak through the dump valve and if it is large, replace the
trim or valve immediately, if not, try to fix the problem on site as soon as
possible and plan to replace the trim/valve at the earliest opportunity.
C. Monitoring SCADA for gas & water flow rate can be used in conjunction
with physical check.
2. High/low setting trim troubleshooting:
A. Physically check Kimray valve for leak (by listening noise, feeling
temperature change on both sides of the valve and looking for frost for
high differential minor leaks).
B. If leak is suspected, confirm by physically checking separator by blowing
separator down, then opening up to flowline to see if any gas is flowing
back into separator.
C. If leak is identified, replace high/low trim immediately.
3. Water/oil trim hanging open
A. Physically check every separator when on a pad by listening for gas
blowing through water/oil dump and visually check trim set position, then
rectify problem.
B. Periodically monitor separator pressures throughout day using SCADA to
detect discrepancies, then rectify problem.
C. Physically check by-pass valves for leaks by feeling temperature difference
on both sides of valve, look for, frost or noise.
D. If valves are leaking, take necessary actions and inform Ursa about its
replacement.
4. Water Skid Pressures at different areas in the field
A. Identify skid pressures that are higher than normal operating range on a
daily basis (use best judgment) and report to Ursa.
B. Purge gas from water headers to lower skid pressures.
Ursa Operating Company LLC Appendix E
5. Operation of Water Network during hydraulic fracturing & flowback using
the same system
A. When the field lines are being utilized for hydraulic fracturing (frac) &
flowback operations, the pump will be operated exclusively by the frac &
flowback personnel. If you need to utilize any section of the network for
pumping into injection pads or pumping out from any pad to injection
pads, communicate this first to the frac/flow back personnel. For your
water needs at injection pads, coordinate this with frac/flowback personnel.
B. When there is no special operation, the network should be operated at
regular regime.
C. All operations (operation/cleaning and water pumping etc.) must be carried
out with the designated personnel and appropriate controls in place.
D. Finally, and most importantly, for any safety/environmental issues (e.g.,
spillage or leakages) immediately contact your immediate supervisor who
in turn shall contact Ursa and offer your best assistance to minimize the
impact from the incident to people, environment and assets. If your
immediate supervisor or Ursa personnel cannot be reached, please refer to
the Emergency Contacts list in Section 3.4.1 of this SPCC Plan for
alternate contacts. PLEASE DO NOT LEAVE A VOICEMAIL, talk to
the contact directly.
*Note: All of the above situations can also be identified through manually shutting
water skid off, and seeing if any gas is blowing to the production tanks
Ursa Operating Company LLC Appendix E
STANDARD OPERATING PROCEDURE FOR REMOVING
PRODUCTION WATER FROM TANKS
1. Pull truck onto the location
2. Inspect the location
3. Note unusual situations and report the issue to the dispatcher
4. Wear appropriate personal protective equipment: fire retardant clothing, hardhat,
safety glasses and steel-toed shoes
5. Plan an escape route, park facing the exit
6. When possible park as close to the stairs as possible
7. Observe the area for additional leaks, spills, releases, equipment damage, etc.
8. Gauge the tank.
9. Watch your footing and utilize the handrail
10. Attach the bondstrap as close to the unloading operation as possible
11. Connect the hose to the tank and the truck
12. Break the seal on the tank valve and record the seal number on the field ticket
13. Place the truck pump in the vacuum position
14. Open the valve on the truck first
15. Open the valve on the tank next
16. Ensure that the vacuum on the truck is operating properly
17. Open valve on the truck slowly
18. Remove material from the tank
While using the clear site glass note when oil appears or when the tank
domes and close the valve on the tank
19. Open the bleeder valve (if present) on the load line
20. Pull material from the hose into the truck
21. If the truck is too full, then push some of the material back into the tank so that the
hose can be effectively drained
22. Shut off the pump
23. Gauge the tank again
24. Record the amount of material withdrawn from the tank and document results on field
ticket
25. Install new seal on the tank valve
26. Record the new seal number on the field ticket
27. Disconnect the hose from the tank
28. Disconnect the hose from the truck
29. Collect remaining fluids in 5 gallon bucket
30. Inspect the hose, fittings and piping for damage
31. Properly place the hose in trays and secure all fittings
32. Replace the dust caps on the back of the truck valves
33. Remove the bondstrap
34. Leave copy of the field ticket for the pumper
35. Again, note any unusual occurrences
36. Leave location and drive to disposal site
Ursa Operating Company LLC Appendix E
STANDARD OPERATING PROCEDURE FOR PRODUCED FLUID
TRANSFERS TO TANKS
1. Initial Tank Inspection – Valves and Overflow (Gooseneck) Caps
A. Prior to any fluid transfers, the water handling contractor will perform an
initial inspection of the tanks to confirm that all valves on tanks are closed
and that the overflows (gooseneck) have caps.
B. Initial inspection includes the valve which is located at the back of the
tank in front of the wheel axles.
C. All man hatches will be inspected to confirm that they are tight.
2. Initial Tank Inspection to Confirm Tank Fluid Levels
A. Prior to any fluid transfers, identify the full tanks and the empty tanks.
B. Tanks with closed thief hatches located at the top of the stairs are
considered full. These tanks can’t accept produced fluids. All tanks with
produced water should have a closed thief hatch with a carbon blanket
installed.
C. Fluid Gauges Don’t Work – Check tank status prior to pumping or
transferring fluids.
D. Make sure that your tank has room before you begin unloading!
3. Visu
A.
al Tank Inspection after Fluid Transfer Begins
Visually check each tank for leaks (valves, overflow/gooseneck caps)
immediately after tank filling begins.
B. Continue watching the tank until your truck is completely unloaded.
C. Tank fluid transfers are immediately stopped if a leak is found or tank is
overfilled.
4. Spill Reporting and Cleanup
A. If a spill occurs the contractor/driver will contact their immediate
supervisor.
B. Contractor will stop all fluid transfers during a spill event.
C. Truck driver will reverse his pump and begin vacuuming up the free
liquids that spilled if transfer by truck.
5. Final Inspection after Fluid Transfer is Completed
A. Confirm that tank flex hose is drained of fluids prior to disconnecting the
hose from the tanks – Do Not Drain Liquids on the Ground.
B. For pipeline fluid transfers, flex hoses must be left connected to the
manifold in front of the frac tanks – Flex hoses should not be disconnected.
C. Contractor will close the tank thief hatches on the tanks that are full to
prevent overfilling.
Ursa Operating Company LLC Appendix E
FLOWLINE MAINTENANCE PROGRAM
Flowlines and piping at production facilities can be sources of releases. The quantity and rates
of such events will vary according to failure mode, operating pressures, current production
rates, and duration of the release.
Flowlines and intra-facility gathering lines and associated valves and equipment are
compatible with the type of production fluids, their potential corrosivity, volume and
pressure, and other conditions expected in the operational environment.
The majority of the piping in the field is constructed of steel and was installed in 2009 or
later. Flowlines are powder coated and/or painted. The steel lines all have cathodic protection.
The pressure lines operate between 0 to 600 pounds per square inch (psig), they were
designed for 0 to 1440 psig. Flowline construction materials are corrosion resistant to
condensate, crude oil, and produced water. Flowlines are sized appropriately for the flow
volumes expected at the facility.
Aboveground flowlines and associated appurtenances are visually inspected daily during the
pumper’s regularly scheduled site visits for leaks, oil discharges, corrosion, or other conditions
that could lead to a discharge as described in 40 CFR 112.1(b). Inspection of conditions
associated with buried flowlines is accomplished by observing the ground surface above the
lines for evidence of leaks on a monthly basis. Records of the inspections are stored at the Rifle
Field Office and the corporate office in Denver. Buried flowlines are also inspected whenever
they are exposed.
Metallic lines have a cathodic protection system which is monitored once or twice a year as
deemed necessary. High density polyethylene (HDPE) lines are operated at or below the
recommended pressure and pressure tested on a regular basis to check their integrity. The
aboveground manifolds are inspected on a monthly basis for conditions, repair, painting, etc.
Appropriate corrective actions or repairs are made to any flowline, intra-facility gathering line,
or associated appurtenances if evidence of a discharge is present. Evidence of a discharge
includes product that has surfaced above the flowline. Suspected releases, including significant
loss of pressure in the line or significant reduction in product recovered in the production tanks
will be investigated.
In the event a leak is discovered, the lines will be replaced with pipe constructed of appropriate
materials. All repaired or replaced flowlines are pressure tested prior to being put into
operation.
Actions are initiated promptly to stabilize and remediate any accumulations of oil
discharges associated with flowlines, intra-facility gathering lines, and associated
appurtenances.
Ursa Operating Company LLC Appendix E
Releases are reported to the appropriate supervisor and cleanup personnel upon discovery.
Oil and impacted media are removed or remediated as soon as practicable.
Ursa Operating Company LLC Appendix F
APPENDIX F
WRITTEN COMMITMENT OF MANPOWER
Written Commitment of Manpower, Equipment, and Materials
In addition to implementing the preventive measures described in this Plan, Ursa
will also specifically:
• In the event of a discharge:
1. Make available all trained personnel and contractors to perform response
actions
ii. Collaborate fully with local, state, and federal authorities on response
and cleanup operations
• Maintain on-site oil spill control equipment.
• Maintain all communications equipment in operating condition at all times.
• Ensure that facilities are accessible.
• Review the adequacy of on-site and third-party response capacity with pre-
established response/cleanup contractors on an annual basis and update
response/cleanup contractor list as necessary.
• Maintain formal agreements/contracts with response and cleanup contractors who
will provide assistance in responding to an oil discharge and/or completing
cleanup.
Rob Bleil, Regulatory and Environmental Manager
N a m e a n d T i t l e : S i g n a t u r e :
______________
Date:
Ursa Operating Company LLC Attachment 1
ATTACHMENT 1
ONSHORE ORDER 3
Ursa Operating Company LLC Attachment 1
I
Contents
1.0 Introduction ..................................................................................................................................... 1
Table 1. Well pads which are subject to the requirements of Onshore Order 3 ........................................ 1
Table 2. Specific wells which are subject to the requirements of Onshore Order 3 . Error! Bookmark not
defined.
2.0 Definitions ........................................................................................................................................ 2
3.0 Record Keeping Requirements ...................................................................................................... 6
4.0 Seal Requirements .......................................................................................................................... 6
Figure 1. An effectively sealed valve cannot be turned without breaking the seal. .................................. 6
Figure 2. An ineffectively sealed valve, the wheel nut can be taken off and thus product removed. ....... 7
Figure 3. The yellow tag is a federal seal and is a designator of a violation. ........................................... 7
Table 3. Non-LACT System Seal Requirements ...................................................................................... 8
Table 4. LACT System Seal Requirements .............................................................................................. 9
5.0 Site Diagram Requirements ......................................................................................................... 10
Figure 4. Example diagram and valve documentation ............................................................................ 11
Figure 5. Example diagram of a LACT Unit .......................................................................................... 12
6.0 Site Security Inspection Requirements ....................................................................................... 13
Site Security Inspection Form ................................................................................................................. 14
7.0 Seal Tracking Requirements ........................................................................................................ 17
Seal Tracking Form .............................................................................................................................. 18
8.0 Operator and Federal Contact Information ............................................................................... 19
Table 5. Contact Information .............................................................................................................. 19
9.0 Removal of Oil Requirements ...................................................................................................... 20
Removal of Oil Form ............................................................................................................................ 21
10.0 Theft or Mishandling of Oil Protocol .......................................................................................... 22
10.1 Internal Notification Protocol ..................................................................................................... 22
10.2 Federal Notification Requirements: ............................................................................................ 22
Theft of Mishandling of Oil Form .......................................................................................................... 23
11.0 Site Security Plan ............................................................................................................................ 24
Notification to Authorized Representative Form .................................................................................... 25
Ursa Operating Company LLC Attachment 1
1
1.0 Introduction
Onshore Order 3 establishes minimum standards for site security with regards to
measurement and sales of condensate and/or crude oil for facilities located on all Federal and
Indian (except Osage) oil and gas leases. In addition, this regulation is applicable to all wells
and facilities on State or privately-owned mineral lands committed to a unit or
communitization agreement that affects Federal or Indian interests, notwithstanding any
provision of a unit or communitization agreement to the contrary. The following sections of
this attachment will provide the basic requirements for ensuring Ursa’s operations remain
compliant with the respective regulation.
This Order establishes the minimum standards for site security by providing a system for
production accountability and covers the use of seals, by-passes around meters, self-inspection,
transporters' documentation, reporting of incidents of unauthorized removal or mishandling of oil
and condensate, facility diagrams, recordkeeping, and site security plans.
Please see Table 1 and 2 of this document for a list of well pads and specific wells which are
subject to the regulation. It should be noted that this list will serve as a living document and
should be updated when there is a sale or acquisition as applicable.
Please note that the BLM is responsible for compliance of Onshore Order 3 if a facility is located on
federal land. The BLM and USFS may coordinate efforts when a facility is located on USFS surface
land, but the BLM will retain responsibility per BLM Memorandum of Understanding WO300-2006-
07.
In order to ensure Ursa remains compliant with Onshore Order 3, personnel involved with oil
gauging, loading, and sales should be presented and trained with the required protocol per the
regulation. The two most important aspects to retain compliance are proper documentation
and ensuring valves are sealed effectively.
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Ursa Operating Company LLC Attachment 1
2
2.0 Definitions
Becoming familiar with the below terminology will help ensure that the regulatory
requirements are fulfilled with regards to Onshore Order 3.
Authorized Officer – means any employee of the Bureau of Land Management (BLM)
authorized to perform the duties in Groups 3000 and 3100 of this title [43 CFR 3000.0-5(e)].
Authorized Representative – means any entity or individual authorized by the Secretary to
perform duties by cooperative agreement, delegation, or contract (see 43 CFR 3160.0-5).
Business Day – means any day Monday through Friday, excluding Federal holidays.
By-Pass – means any piping arrangement connected upstream and downstream of a meter which
allows oil or gas to continue on to the sales line without passing through the meter. Equipment
which permits the changing of the orifice place without bleeding the pressure off the gas meter
run shall not be considered a by-pass.
Effectively Sealed – means the placement of a seal in such a manner that the position of the
sealed valve may not be altered, or a component in a measuring system affecting quality or
quantity accessed, without the seal being destroyed.
Major Violation – means noncompliance which causes or threaten immediate, substantial, and
adverse impacts on public health and safety, the environment, production accountability, or
royalty income.
Oil – means all nongaseous hydrocarbon substances, other than those substances leasable as cole,
oil shale or “gilsonite”. Please note that unless the oil is salable, the operator is not required
to maintain records of the loading/unloading and seals. If the oil (i.e. condensate)
accumulated within the produced water tanks becomes salable, all requirements for
documentation and record keeping will apply.
Production Phase – means that period of time or mode of operating during which crude oil is
delivered directly to or through production vessels to the storage facilities and includes all
operations at the facility other than those defined by the sales phase.
Sales Phase – means that period of time or mode of operation during which crude oil is removed
from the storage facility for sale, transportation, or other purposes.
Seal – means a device, uniquely numbered which completely secures either a valve of those
components of a measuring system that affect the quality and/or quantity of the liquid measured.
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Ursa Operating Company LLC Attachment 1
8
The following Tables (3 and 4) provide guidance with regards to the equipment which is subject
to the seal requirements. Any exceptions or additional guidance is included in the right hand
column.
Table 3. Non-LACT System Seal Requirements
EQUIPMENT REQUIRING SEAL EXCEPTIONS, NOTES
NON-LACT SYSTEMS
Sales Valves
The valves shall be effectively sealed during the
production and sales phases or combination of sales
phases.
Circulating Valves
Drain Valves
Fill Valves
Equalizer Valves
Any valve which provides access to oil
prior to measurement for sales.
All lines entering or leaving oil storage
tanks
Exempt: Valves on production vessels (e.g. gun barrel,
wash tanks)
Exempt: Valves on produced water tanks, provided
access does not exist through a circulating drain or
equalization system to production and sales tanks
Exempt: Sample cock valves with piping of 1 inch or
less in diameter
Exempt: When a single tank is used for collecting
small volumes of condensate, all other requirements
apply.
Exempt: Gas line valves of 1 inch or less used as tank
bottom "roll" lines, provided there is no access to the
contents of the storage tank and said lines cannot be
used as equalizer lines.
Exempt: Tank heating systems which use a fluid other
than the contents of the storage tanks.
Exempt: Tank vent fill valves
The above seal requirements will be applicable to most well pads to a certain degree. The seal
requirements for the LACT units are specified in Table 4 on the following page. The LACT
Units are a much less common facility.
Ursa Operating Company LLC Attachment 1
9
Table 4. LACT System Seal Requirements
LACT SYSTEM SEAL REQUIREMENTS
LACT systems
Sales or equalizer lines do not need to be
sealed. However, any valves which allow
access for the removal of oil prior to
measurement through the LACT system shall
be sealed. There shall be no bypass around the
LACT unit.
Sample Probe None
Sampler Volume Control None
All valves entering or leaving the
sample container excluding the safety pop-off valve
Meter Assembly, including the counter
head, meter head and automatic
temperature compensator
None
Temperature recorder None
Back pressure valve downstream of the
meter None
Any drain valve in the system None
Manual sampling valves None
Ursa Operating Company LLC Attachment 1
10
5.0 Site Diagram Requirements
Accurately reflects the relative position of the production equipment, piping and
metering systems - does not need to be to scale.
Commencing with the header, identify the vessels, piping, and metering systems
located on the site and shall include the appropriate valves and any other equipment
used in the handling, conditioning, and disposal of oil. gas, and water produced,
including any water disposal pits or emergency pits. In those instances where pits are
co-located, such pits may be shown in parentheses on the facility diagram.
Indicate which valve(s) shall be sealed and in what position during the production and
sales phases and during the conduct of other production activities, i.e., circulating
tanks, drawing off water, which may be shown by an attachment, if necessary.
Require as an addition. when describing co-located facilities operated by 2 different
operators, a skeleton diagram of the co-located facility, showing only equipment. For
co-located common storage facilities operated by 1 operator, one facility diagram shall
be sufficient.
Be filed within 60 days of completion of construction of a new facility or when existing
facilities are modified or when a non-Federal facility is included in a Federally
supervised unit agreement or communitization agreement.
Clearly identify the lease to which it applies and the location of the facility covered by
quarter section, section, township, and range or by a legal land description, with co-located
facilities being identified by each lease and its facilities.
Clearly identify the site security plan covering the facility.
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Ursa Operating Company LLC Attachment 1
13
6.0 Site Security Inspection Requirements
Ursa shall establish an inspection program for the purpose of spot checking their facilities
with regards to compliance with Onshore Order 3 requirements. One location a month
shall be inspected with the form included in this Section and cross referenced with the seal
tracking form (Section 7.0) to verify the information. Any information which does not
cross reference properly will be flagged and investigated. Pending the results of the
investigation, notification may be provided to an authorized representative and will be
documented and filed for later reference.
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Ursa Operating Company LLC Attachment 1
17
7.0 Seal Tracking Requirements
To ensure compliance with Onshore Order 3, and to provide a document which tracks all
seal installations and removals, a seal tracking form has been provided within this Section.
The form shall be completed at the time of the oil loading operation by the Ursa personnel
providing oversight of the loading operation. A designated form for each field shall be
managed in accordance by the designated Ursa personnel in both hardcopy and electronic
form. The personnel managing the seal tracking form shall conduct the monthly site
inspections and cross reference the seal tracking form with the respective site inspection.
U r s a
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Ursa Operating Company LLC Attachment 1
20
9.0 Removal of Oil Requirements
The removal of oil from a facility for sale or transport must be documented and observed
by specified persons (i.e. gauger, Ursa representative, BLM personnel). A form has been
provided in this Section to fulfill the documentation requirement.
Prior to removal of oil from tanks, a verbal notification to the respective BLM personnel
is required. The authorized officer or representative from the BLM is to be present at the
time of loading. The BLM personnel may collect independent gauging measurements.
Their presence is to provide oversight during the gauging process to verify the volume of
oil being loading and documented is accurate for royalty purposes.
Ursa Operating Company LLC Attachment 1
21
Removal of Oil Form
Removal of Oil From Tanks be Means Other Than Through a LACT Unit
Date:
Name of seller: Ursa Operating Company, LLC
Federal or Indian lease number:
Legal location of the tank:
Tank number and capacity:
Valve Number
Seal number prior to loading*:
Seal number after loading:
Opening gauge and temperature*:
Closing gauge and temperature*:
Observed gravity and sediment and water content*:
Name of Gauger:
Signature of Gauger:
Name of Ursa representative:
Signature of Ursa representative:
Name of Federal representative:
Signature of Federal representative:
* Omission of the designated information constitutes a major violation, complete missing
information and submit within 3 days of notice.
Ursa Operating Company LLC Attachment 1
22
10.0 Theft or Mishandling of Oil Protocol
10.1 Internal Notification Protocol
Personnel identifying the incident will report all applicable information to the
Regulatory and Environmental Manger (REM) in addition to the Health and
Safety Manager (H&S).
In the event of criminal activity, law enforcement may be involved. The REM
and/or H&S will determine the involvement of law enforcement.
The form included in this section shall be completed within 10 days of
discovery of the incident.
o Any additional information not identified within the form is to be
attached.
o All forms shall be retained for a period of seven years in
accordance with the regulatory requirements.
10.2 Federal Notification Requirements:
The theft of mishandling of oil shall be reported no later than the next business
day after discovery of the incident to the authorizing officer.
All oral reports shall be followed up with a written report within 10 business
days.
o Please see the form within this Section for the written report form.
Violations:
o Minor
e.g. failure to file a complete report
corrective action: oral report upon request, and submit report of
incident within 10 business days after notice of failure to file a
complete report is received.
o Major
e.g. failure to report the incident
corrective action: oral report upon request and submit report of
incident within 10 business days after notice of failure to report
incident is received.
Ursa Operating Company LLC Attachment 1
23
Theft of Mishandling of Oil Form
Theft or Mishandling of Oil
Verbal notification required: next business day after incident is discovered
Written notification required: 10 days after incident is discovered
Date:
Name of seller: Ursa Operating Company, LLC
Name of Ursa representative reporting the incident:
Name of the person who discovered the incident
and company:
Date and time the incident was discovered:
Federal or Indian lease number:
Legal location of the tank:
Tank number and capacity:
Estimated volume oil or condensate removed:
The manner which access to the oil was removed:
The way access was obtained:
Whether the incident was reported to local law
enforcement agencies and company security:
Signature of Ursa representative:
Ursa Operating Company LLC Attachment 1
24
11.0 Site Security Plan
The operator shall establish a site security plan for all facilities. The plan need not be submitted
to the authorized officer, but the authorized officer shall be notified of the location where the
plan is maintained and the normal working hours of said location. The plan shall be available to
the authorized officer upon request. The plan shall include, but is not limited to the following:
A self-inspection program that monitors production volumes and ensures
compliance with all seal requirements at each storage and sale facility and each
LACT unit, if applicable
o See form found in Section 6.0
A system to ensure the maintenance of accurate seal records and the completion of
accurate run tickets
o See forms found in Sections 7.0 and 8.0
A system to ensure the reporting of incidents of apparent theft or mishandling of
oil
o See form in Section 9.0
A system to ensure that there are no by-pass of meters
o See form in Section 6.0
A list of the leases, communitization agreements, unit agreements, and specific
facilities that are subject to each plan
o See Tables 1 and 2 of this document.
Documentation that the authorized officer has been notified of the completion of a
plan and site facility diagram(s) and the leases, communication agreements, unit
agreements, and specific facilities that are subject to each plan and diagram(s)
Documentation that the authorized officer was notified within 60 days of
completion of construction of a new facility or of commencement of first
production or of inclusion of the production from a committed nonfederal well
into a federally supervised unit or communitization agreement, whichever occurs
first, whether that facility is covered by a specific existing plan or a new plan has
been prepared.
o See Form in Section 11.0 of this document.
Ursa Operating Company LLC Attachment 1
25
Notification to Authorized Representative Form
Notification to Authorized Representative
Name and Title of Ursa Representative Providing Notification:
Federal Field Office Notification Provided to:
Reason for Notification: X Notes:
Completion of a Plan
Completion of a Site Diagram
Lease addition of change
Communication Agreement
Unit Agreement
Providing list of locations with are
subject to the Order
Fill in the following information as applicable to the Notification:
Date of construction completion:
Date of commencement of first
production:
Date of inclusion of production from a
committed nonfederal well into a
federally supervised communitization
agreement:
Was this notification provided within 60 days of completion of construction, or of
commencement of first production, or of inclusion of the production from a committed
nonfederal well into a federally supervised communitization agreement?
Yes No
If no, why:
___________________________________ __________________________________________
Ursa Representative Signature: Date:
Supplemental information to be attached to this form as an attachment(s).