Drilling and Production Units and Well Spacing

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Petroleum Technology Transfer Council
Eastern Gulf Region
Report on the
Focused Technology Workshop
^'Drilling and Production Units and Well Spacing
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Capital Club, Capital Towers, 19th Floor
125 South Congress Street
Jackson, Mississippi
March 26,1997
Workshop Sponsored By
The U.S. Department of Energy, National Petroleum Technology Office,
Federal Energy Technology Center,
BDM-Oklahoma, Inc.,
and
Prepared By
The Eastern Gulf Producer Advisory Group
and
Eastern Gulf Region Lead Organization
of the
FOCUSED TECHNOLOGY WORKSHOP
^'Drilling and Production Units and Well Spacing**
Introduction
The Fourth Focused Technology Workshop hosted by the Eastern Gulf Region
Producer Advisory Group and Eastern Gulf Region Lead Organization of the Petroleum
Technology Transfer Council was held at the Capital Club, Capital Towers, Jackson,
Mississippi. The title of the workshop was "Drilling and Production Units and Well
Spacing." The workshop was sponsored by the U.S. Department of Energy, National
Petroleum Technology Office, Federal Energy Technology Center, BDM-Oklahoma,
Inc., and Petroleum Technology Transfer Council.
The workshop focused on oil and gas regulatory practices of establishing drilling
and production units and setting well spacing in the Mississippi Interior Salt Basin and
related sub-basins. Presentations were made regarding practices of establishing drilling
and production units and well spacing by the regulatory agencies in the Gulf Coastal
states. A case study at Southwest Excel Field, Monroe County, Alabama was presented
by oil and gas consultants. A panel discussion, which included the state regulators, was
held to review the field case study.
Eastern Gulf Region
The Eastern Gulf Region consists of the states of Mississippi, Alabama and
Florida (MAFLA area). A considerable number of small and medium-sized producers
operate in the region. The MAFLA area has been and will continue to be an important oil
and gas producing area. The discovery of the Amory Field in Mississippi in 1926 initiated
production in the region. Cumulative production from the region is approximately
11 trillion cubic feet of gas and 3 billion barrels of oil. The region is a mature oil and gas
province with over 2,200 established fields. Oil and gas are produced from a host of
DE 19 '97
Paleozoic, Mesozoic and Cenozoic reservoirs in Mississippi, Alabama and Florida. Major
reservoirs include the Jurassic Norphlet, Smackover and Haynesville formations; the
Upper Jurassic-Lower Cretaceous Cotton Valley Group; the Lower Cretaceous Hosston,
Rodessa, and Fredericksburg-Washita units; the Upper Cretaceous Tuscaloosa, Eutaw
and Selma units; and the Tertiary Wilcox and Miocene strata.
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Technical Report
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P^rpose
The purpose of the workshop was to review the regulatory practices of establishing
drilling and production units and well spacing in the Eastem Gulf Region. The workshop
is part of the national program of the Petroleum Technology Transfer Council to
accelerate the dissemination of oil and gas technology to domestic producing companies.
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The workshop was designed to transfer technology and knowledge to producers regarding
certain regulatory practices in the Gulf Coastal states. With this information, it is
anticipated that domestic producers could, with the assistance from regulators, improve
operating efficiency, improve ultimate field recovery, and add to the domestic oil and gas
reserves.
Problem Identification
At the First Problem Identification Workshop held in Jackson, Mississippi, on
August 22, 1995, the producers in the Eastem Gulf Region identified the following areas
as priority for resolution: regulations goveming naturally occurring radioactive materials
(NORM), availability and archiving of basic well data and associated databases,
waterflood and pressure maintenance projects, review of existing regulations and rules,
and operating costs associated with salt water disposal. The NORM issue was addressed
at the First Focused Technology Workshop hosted by the Eastem Gulf Region Producer
Advisory Group and Eastem Gulf Region Lead Organization in Orange Beach, Alabama,
on October 11, 1995. The second workshop, which was held in Tuscaloosa, Alabama, on
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March 26, 1996, focused on the archiving and dissemination of oil and gas information in
the region. The Third Focused Technology Workshop, which was held in Jackson,
Mississippi, on August 13, 1996, concentrated on successful waterflood and pressure
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maintenance projects. This fourth workshop focused on certain oil and gas regulatory
practices.
Technologies Addressed at the Workshop
Overview
The workshop was organized into three major sessions. The major sessions
included the following topics: regulatory practices of establishing drilling and production
units and well spacing in the Gulf Coastal states, a case study of Southwest Excel Field,
Monroe County, Alabama, and a panel discussion about the field case study. In addition,
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an overview of the functions and goals of the Petroleum Technology Transfer Council
were reviewed briefly at the start of the workshop. Also, the ongoing process of problem
identification in the region was discussed at the end of the workshop.
Sessions
Harry Spooner, Chair of the Producer Advisory Group for the Eastern Gulf
Region, welcomed the participants to the workshop. He provided an overview of the
functions and goals of the Petroleum Technology Transfer Council. He also updated the
group on the joint proposal prepared by the Mississippi Office of Geology and the
Mississippi Oil and Gas Board to make available oil and gas exploration and production
data to producers in an electronic format. The proposal was prepared in response to the
producers' needs to have access to this type of information.
The first session was entitled "Drilling and Production Units and Well Spacing."
This session included presentations regarding practices of establishing drilling and
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production units and well spacing from the oil and gas regulatory agencies in the Gulf
Coastal states. Speakers included Walter Boone (Oil and Gas Supervisor for Mississippi),
David Curry (Administrator, Oil & Gas Section, Florida Geological Survey), Michael
Killeen (Director, Geological Oil & Gas Division, Louisiana Office of Conservation),
David Triana (Engineer, Oil & Gas Division, Permitting Services Section, Texas Raikoad
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Commission), and Gary Wilson (Deputy Oil and Gas Supervisor, Alabama State Oil and
Gas Board).
Walter Boone discussed Rule 7 (Spacing of Oil Wells), Rule 8 (Spacing of Gas
Wells) and Rule 9 (Exceptions to Spacing Rules) of the Mississippi State Oil and Gas
Board. He reviewed the size of drilling units for oil wells (40, 80,160 acres) and for gas
wells (160, 320, 640 acres) which are related to subsurface depths. He also discussed the
spacing of oil and gas wells and the distance the well is required to be from other wells
and the exterior boundaries of the drilling unit.
David Curry reviewed Florida statutes on well spacing and drilling units, field
wells, exploratory wells, routine drilling units, horizontal wells and associated drilling
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units, and non-routine units and wells. In Florida, drilling units, production units, and
well spacing are ahnost synonymous. There are no production units different from the
original drilling units except where special field or unitization rules were adopted
subsequent to the discovery well. These units may be based on geographical, geological
or other considerations. Most units are geographical quarter sections.
Michael Killeen discussed Louisiana Statewide Order 29-E which addresses well
spacing for oil, gas and field order spacing. Spacing is set for oil and gas wells from
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property lines and between wells in the same reservoir zone. He reviewed the formation
of geographic, geologic and reservoirwide units and the unitization procedure. He
discussed the special rules being considered for horizontal wells being drilled in the
Austin Chalk.
David Triana reviewed drilling and production units and well spacing in Texas.
All assignments of acreage for drilling or proration in Texas are- voluntai"y in that an
application for Railroad Commission action must originate with an operator or working
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interest owner. A drilling unit is the minimum acreage (well density) required to receive a
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wildcat or field permit to drill. The drilling unit may consist of stand-up acreage, legal
subdivision, pooled unit or density exception. The well location mustmeet well spacing
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requirements from the lease line and between wells on the same lease or field. The well
spacing pattern addresses the number and location of wells over a reservoir and includes
spacing, density and diagonal. A proration unit is the acreage assigned to a well for the
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purpose of allocating production. Unitization and horizontal wells were also discussed.
The hearing process in Texas was reviewed.
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Gary Wilson discussed Alabama's Rule 400-1-2-.02 (Spacing of Wells). He
reviewed drilling units in southwest Alabama, in the Black Warrior Basin, in the coastal
waters area, and for coalbed methane development. A well is spaced on a unit based on
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the maximum area which may be efficiently and economically drained by the well. The
spacing for a well to be drilled to a pool in an established field is governed by special
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field rules for the field. The final spacing for a producing well is determined at the time
the field is established. A wildcat well may be drilled on a unit consisting of a
governmental quarter-quarter section (40 acres) or a governmental quarter section
(160 acres), In southwest Alabama, a wildcat deep gas well may be drilled on a unit
consisting of a governmental section (640 acres). Spacing for offshore wildcat wells can
be on units consisting of 40, 160, 320 or 640 acres. In the Black Warrior Basin, a wildcat
gas well may be drilled on a unit consisting of a governmental half section (320 acres).
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Permits for wells to be drilled on non-governmental units may be approved. A well
drilled adjacent to a field (productive extension) is normally in accordance with the
spacing provisions in the special field rules. The unit size may be increased by an amount
not to exceed 30% of the original unit size.
The second session concentrated on a field case study located in a sub-basin
associated with the Mississippi Interior Salt Basin. The case study was Southwest Excel
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Field, Monroe County, Alabama. Brian Sims, consultant, and Robert Wood, Tom Joiner
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& Associates, made presentations.
Brian Sims reviewed the history of the Frisco City Sandstone play and the regional
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geology of the area. He discussed the petroleum characteristics of the play. He
emphasized the relationship of reservoir distribution to pre-Jurassic paleotopographic
features and the significance of 3-D seismic in defining prospects. He showed examples
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of the importance of selecting a well location through the use of 3-D seismic. He also
illustrated why the establishment of drilling and production units should include
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consideration of 3-D seismic data.
Robert Wood presented the history of development of the Frisco City Sandstone
reservoir at Southwest Excel Field, Monroe County, Alabama, from the original prospect
to the final field configuration. He discussed the events leading up to the drilling of the
wildcat well for the field which was drilled as a seismic prospect over a Paleozoic
basement feature. He reviewed the field development from the drilling of first offset well
to the discovery well to enlargement of the original drilling and production units. The
field presently consists of three drilling and production units. The unit for the Nettles 912 No. 1 well consists of 208 acres. The unit for the Nail 16-3 No. 1 ST well consists of
172 acres, and the unit for the Nail 16-6 No. 1 well consists of 160 acres. The unit
enlargements were approved because the added acreage was in imminent danger of being
drained from the producing wells in Southwest Excel Field.
The third session consisted of a panel discussion on key technical and regulatory
criteria for establishing drilling and production units and well spacing. The panel
included the state oil and gas regulators. The panel was moderated by S. Cragin Knox,
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State Geologist for Mississippi. Each state regulator commented on the Southwest Excel
Field case study. Workshop participants then had the opportunity to comment on the case
study and to ask questions of the regulators. The discussion focused primarily on the
merits of geologic units as opposed to geographical units and the advantages of
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considering 3-D seismicdata in establishing drilling and production units.
Ernest A. Mancini, Eastern Gulf Region Director, reviewed the problem
identification process for the region. He discussed the results of the First Problem
Identification Workshop held on August 22, 1995. He emphasized that problem iden
tification was an ongoing process and that the focused technology workshops were
designed to address the problems identified by the producers. He discussed the process
for selecting the topics for focused technology workshops.
The workshop concluded with a discussion of topics for future focused technology
workshops. Participants agreed the next workshop should focus on computers and their
applications in the oil industry.
Producers' Response to Workshop
General
Overall, the producers' response to the workshop was very favorable. Suggestions
were made for improving the next workshop. These suggestions included: do more oneon-one contacts to increase small operators participation in the workshop and have more
follow-up with operators after the workshop to assist with the implementation of the
technology.
New Insights
The producers continue to point out that the accessibility of data for the Eastern
Gulf Region is the single most important factor that the Petroleum Technology Transfer
Council can assist them with.
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Evaluation of the Workshop
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Present Workshop
Participants were reminded during the workshop to fill out an evaluation form.
Only two participants returned the evaluation form. The comments were favorable. In
addition, a number of participants provided comments about the workshop during the
panel discussion. Many of the comments related to geologic units and the use of
advanced technologies, such as 3-D seismic data, in establishing drilling and production
units.
Fumre Workshops
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For the immediate future, the Focused Technology Workshops will be held in
Jackson, Mississippi. This location appears to be best for the producers in the region.
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Continued emphasis will be placed on having industry experts with first-hand knowledge
as the principal presenters. Participants decided that the next workshop should focus on
computers and their applications in the oil industry.
Administrative Report
Announcement
The announcement for the Focused Technology Workshop was mailed to over 400
individuals involved with the production of oil and gas in the Eastem Gulf Region. Direct
contacts were made to industry requesting the workshop be announced in newsletters and
at meetings. Members of the Producer Advisory Group were personally contacted.
Attendees
There were 41 registered to attend the workshop, including 21 producers and
industry consultants. The remaining participants were from government and professional
and business organizations.
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Materials
Materials related to the workshop are attached and the handouts from the
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workshop are enclosed.
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Financial Report
This report will be mailed atalater date.
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ATTACHMENTS
Eastern Gulf Region
Fourth Focused Technology Workshop
Sponsored by:
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• Petroleum Technology Transfer Council,
Drilling andProduction Units and
Well Spacing
Eastern Gulf Region
Capital Club, Capital Towers, 19th Hoor
• National Petroleum Technology Office
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. Federal Energy Technology Center
Jackson, Mississippi 39201
• BDM - Oklahoma, Inc.
(601) 969-7101
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The Eastern Gulf Producer Advisory Group and the Eastern Gulf
Region of the Petroleum Technology Transfer Council invite oiland gas pro
ducing and related companies operating in Mississippi, Alabama, and Florida
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to participate in a Focused Technology Workshop on drilling and production
units and well spacing in the Mississippi Interior Salt Basin and related subbasins. The workshop is designed to examine the technical and regulatory
criteria for establishing drilling andproduction units and in determining well
spacing. The workshop will include presentations regarding practices of
establishing drilling and production units and well spacing from the regulatory agencies in the Gulf Coastal states. A case study will be presented for
the Mississippi Interior Salt Basin and related sub-basins. Apanel discussion
focusing on the key technical and regulatory criteria for establishing drilling
and production units and well spacing will follow the case study presentation.
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Itis essential that we have anaccurate accounting ofthose who plan to
attend and participate in the workshop. Therefore, please complete and
return the attached registration form (found on other side) to us by March 12,
1997.
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We look forward to your participation.
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PETROLEUM TECHNOLOGY TRANSFER COUNCIL,
EASTERN GULF REGION
announces a
Tuesday, March 26,1996
at
Tom BevillEnergy, Mineral, and Material ScienceBuilding
Room 101
The University of Alabama
Tuscaloosa, Alabama
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The Eastern Gulf Producer Advisory Group and the Petroleum Technology Transfer Council invite oil, natural gas
and coalbed methane companies operating in Mississippi, Alabama, and Florida to participate in a Focused Technology
Workshop entitled Archiving and Dissemination of Oiland GasInformation, The workshop is to introduce operators to
technical solutions to thehigh priority problems ofexploration, production and regulatory compliance in theEastern Gulf
Region. The subject of this workshop is one of the areas identified as priority issues by the industry at the Problem
Identification Workshop of August 22, 1995 inJackson, Mississippi. The Focused Technology Workshop is part of the
national program of the Petroleum Technology Transfer Council, designed to accelerate the dissemination of oil and
natural gas technology to domestic producing companies.
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This Focused Technology Workshop will address the information needs of the oil and gas producers in the Eastern
Gulf Region. The focus of the workshop will be to make producers aware of available information from state agencies,
federal agencies, professional organizations, and the private sector. Producers will also learn how these data are archived
and how the information can be accessed and acquired. The workshop will conclude with a discussion on establishing a
strategy for improved dissemination and accessibility of oil and gas information.
It is essential that we have an accurate accounting of those who plan to attend and participate in the workshop.
Therefore, please complete and return the attached registration form to us by March 22,1996.
We look forward to your participation.
WORKSHOP REGISTRATION FORM
Name:
Last
First
Initial
Preferred Name on Badge:
Affiliation:
Mailing Address:
City:
State:
Telephone:
Fax:
Zip:
_
Please complete form and return by mail, Fax, or E-mail transmittal to:
Ernest A. Mancini
Department of Geology
University of Alabama
Box 870338
Tuscaloosa, AL 35487-0338
Telephone: (205) 348-4319
Fax: (205) 348-0818
E-mail: [email protected]
There is no cost to attend any session of tills conference,
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PLEASE RETURN BY MARCH 22,1996
PETROLEUM TECHNOLOGY TRANSFER COUNCIL, EASTERN GULF REGION
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Archiving and Dissemination of Oiland Gas Information
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Tom BevillEnergy, Mineral, andMaterial Science Research Building,
Room 101,The University of Alabama, Tuscaloosa, Alabama 35487
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(205)348-4319
AGENDA
Tuesday, March 26,1996
• 8:00 - 8:30 a.m.
Information Needs of the Producers as Identified at the Problem Identification Workshop
Presentation:
• 8:30 - 10:15 a.m.
Ernest Mancini, Eastem Gulf Region Director
State Agency Panel on Information Availability andArchiving
Presentations: Alabama
Robert Mink, Geological Survey of Alabama
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David Bolin, Alabama State Oil and Gas Board
Mississippi Cragin Knox, Mississippi Office of Geology
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Richard Lewis, Mississippi State Oil and Gas Board
Florida
Edward Garrett, Florida Geological Survey
• 10:15-10:30 a.m.
Break
• 10:30 - 11:30 p.m.
Department of Energy and Associated Organizations Panel on Information
Availabilityand Accessibility
Presentations:
Betty Felber, DOE
Lance Cole, BDM-Oklahoma
Deborah Rowell, PTTC
John Benton, PTTC
• 11:30 - 12:15 p.m.
Professional Organizations Panel on Information Accessibility
Presentations:
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Robert Graebner, American Geological Institute
DeLayne Perkins, Interstate Oil and Gas Compact Commission
• 12:15 - 1:30 p.m.
Lunch
• 1:30 - 3:00 p.m.
Private Sector Panel on Information Availability
Presentations:
• 3:00 - 3:15 p.m.
• 3:15 - 4:15 p.m.
P
Richard Tucker, PeU-oleum Information Corporation
Mike Morgan, Dwights Energydata
Thomas Smith, Seismic Micro-Technology
Break
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Mike Rosenmayer, Schlumberger
Craig Klein, Neuralog, Inc.
• 4:15 - 5:00 p.m.
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Discussion on Strategyfor Improving Dissemination and Accessibility ofInformation
Discussion Moderators:
Harry Spooner, Producer Advisory Group
Deborah Rowell, PTTC
Ernest Mancini, University of Alabama
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Eastern Gulf Region
Drillingand Production Units and Well Spacing
Jackson, Mississippi
March 26,1997
INDUSTRY
Les Aultman
Brian Sims
111 E. Capitol BIdg., Suite 345
803 Annandale Rd.
Madison, MS 39110
Jackson, MS 39201
Robert Wood
Tom Joiner & Associates
P.O. Box 030710
Larty Baria
Harry Spooner
Jura-Search, Inc.
P.O. Box 997
Spooner Energy, Inc.
Deposit Guaranty Plaza, Suite 954
Jackson, MS 39205
Jackson. MS 39201
Dave Gate
Andrew Sylte
111 E. Capitol St., Suite345
Pruet Oil Company
217 West Capitol St., Suite 201
Jackson, MS 39201
Jackson MS 39201
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Paul A. Ferguson
Taurus Exploration, Inc.
Thomas W. Sylte
Kelton Oil Company
2101 Sixth Ave., North
Box 230
Birmingham, AL 35216
Pensacola, FL 32591-0230
John D. Herlihy
Herlihy Oil & Gas
Lloyd & Thomson
Robert L. Thomson
P.O. Box 13986
P.O. Box 1847
Jackson, MS 39236
Jackson, MS 39215-1847
Todd Mines
Moon-Hines Oil & Gas
125 S. Congress, #1804
Terry Tigrett
Moon-Hines-Tigrett Operating Co.
1806 Capital Towers
Jackson, MS 39201
Jackson, MS 39201
David A. Leach
Ron Tisdale
Nuevo Energy Company
111 E. Capitol St., Suite 240
Taurus Exploration, Inc.
Jackson, MS 39201
Birmingham, AL 35203
Julius Ridgway
Ridgway Energy, Inc.
Roger Townsend
Spooner Petroleum Company
956 Deposit Guaranty Plaza
210 East Capitol St.
P.O. Box 16667
2101 Sixth Ave., North
Jackson, MS 39201
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Michael A. Ryan
Howell Petroleum Corporation
Vaughn Watkins
1820 Capitol Towers
1111 Fannin St., Suite 1500
Houston, TX 77002
Jackson, MS 39201
Robert Schneeflock
William P. White
111 East Capitol St.. Suite 240
111 East Capitol St., Suite 240
Jackson, MS 39201
Jackson, MS 39201
GOVERNMENT
Walter Boone
Mississippi State Oil and Gas Board
500 Greymont Ave., Suite E
Jackson, MS 39202
ACADEMIC
PROFESSIONAL & BUSINESS
ORGANIZATIONS
Clinton A. Graham
Mid-Continent Oil and Gas Assoc.
Department of Geology
Box 870338
Jackson, MS 39201
Ernest A. Mancini
University of Alabama
Steve Champ!in
Mississippi Office of Geology
Chris W. Jones
P.O. Box 23146
P.O. Box 20307
Deposit Guaranty National Bank
David Curty
Florida Geological Survey
John Land McDavid
903 West Tennessee St.
820 Trustmaric BIdg.
248 E. Capitol St.
Tallahassee, FL 32304
McDavid, Noblin & West PLLC
Jackson, MS 39201
Nancy Johnson
Fossil Energy
U.S. Department of Energy
1000 Independence Ave., SW
Washington, D.C. 20585
Michael Killeen
Louisiana Office of Conservation
William A. Philip
Deposit Guaranty National Bank
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P.O. Box 1200
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Jerry Sheldon
Geological Oil & Gas Division
Gerald & Brand
Box 158
P.O. Box 94275
Jackson, MS 39205
Baton Rouge, LA 70804-9275
Cragin Knox
Joe Sims
Mid-Continent Oil & Gas Assoc.
P.O. Box 20307
Robert M. Mink
Watts Ueltschey
Brunini, Grantham, Grower & Hewes
Geological Survey of Alabama
P.O. Box 0
P.O. Drawer 119
Jackson, MS 39205
Jack Moody
P.O. Box 20307
Don Oltz
Geological Survey of Alabama
P.O. Box O
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Viola Rawn-Schatzinger
BDM-Oklahoma
P.O. Box 2565
Bartlesville, OK 74005
David C. Triana
Oil & Gas Division, Permitting Section
Texas Railroad Commission
P.O. Box 12967
Austin, TX 78711-2967
Gary Wilson
State Oil and Gas Board of Alabama
P.O. Box O
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PETROLEUM TECHNOLOGY TRANSFER COUNCIL
EASTERN GULF REGION
EVALUATION FORM
1. Your Company
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Company's Address
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Contact Telephone
—
( ) Management
( ) Engineer
( ) Geologist
( ) Geophysicist
( ) Support
( ) Other
Your Position:
z. What new drilling or production technologies have you employed in your operations within the last two
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3. What emerging technologies are you aware of, and are most interested in, which will help improve the
profitability of your operation?
4. How can we improve the Focused Technology workshop?
5. Do you have and needresponse, on othertechnologies outside of those addressed at this meeting?
.. Suggest other possible additional means the PTTC can use to address technology needs.
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General and additional comments:
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PETROLEUM TECHNOLOGY TRANSFER COUNCIL, EASTERN GULF REGION
fourth FOCUSED TECHNOLOGY WORKSHOP
Sponsored By
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Petroleum Technology Transfer Council, Eastern Gulf Region
U.S. Department of Energy
National Petroleum Technology Office
Federal Energy Technology Center
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BDM-Oklahoma, Inc.
Drilling and Production Units and Well Spacing
Capital Club, Capital Towers, 19th Floor
Jackson, Mississippi 39201
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(601) 969-7101
PROGRAM
Wednesday, March 26,1997
• 8:30 -
9:00 a.m.
Welcome
Harry Spooner, Chair, PTTC, Eastern Gulf Region, I*roducer Advisory Group
Presentations bv Gulf Coastal States
• 9:00 - 9:30 a.m.
Mississippi
Walter Boone, Oil and Gas Supervisor, Mississippi Oil and Gas Board
• 9:30 - 10:00 a.m.
Florida
David Curry, Administrator, Oil and Gas Section, Florida Geological Survey
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*10:00 -10:15 a.m.
•10:15
-11:00 a.m.
Break
Texas
David Triana, Engineer, Oil and Gas Division, Permitting Services Section,
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• 11:00 - 11:30 a.m.
Louisiana
Michael Killeen, Director, Geological Oil and Gas Division,
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• 11:30 - 12:00 p.m.
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* 12:00 - 1:00 p.m.
Alabama
Gary Wilson, Deputy Oil and Gas Supervisor, Alabama Oil and Gas Board
Lunch
Case Smdv: Drilling and Production Units and Well Spacing in the Mississippi Interior Salt Basin
and Related Sub-Basins
• 1:00 - 2:00 p.m.
Presentation: Southwest Excel Field, Monroe County, Alabama
Brian Sims, Consultant
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Robert Wood, Tom Joiner & Associates
• 2:00 - 2:45 p.m.
Discussion
• 2:45 - 3:00 p.m.
Break
Panel Discussion: Key Technical and Regulatory Criteria for Establishing Drilling and Production Units
and Well Spacing
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• 3:00 - 4:00 p.m.
Moderator:
Cragin Knox, State Geologist, Mississippi Office of Geology
• 4:00 - 4:30 p.m.
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Future Focused Technology Workshops
Ernest A. Mancini, University of Alabama
Eastern Gulf Region
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"Drilling and Production Units and Well Spacing"
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Walter Boone,
Oil and Gas Supervisor,
Mississippi Oil and Gas Board
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RULE 7. Spacing of Oil Wells
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1. With respect to each pool occurring in the discovery well, the top of which is encountered below a
measured depth of 12,000 feet below the surface, and in the Pennsylvanian and older formations with
respect to each pool occurring in the discovery well, the top of which is encountered below a measured
depth of 3,500 feet below the surface, every oil well:
(a) Shall be located on a drilling unit consisting of eighty (80) contiguous surface acres, or two (2)
contiouous govemmental quarter-quarter sections containing not less than seventy-two (72) acres or more
than eighty-eight (88) acres, upon which no other drilling or producible well is located. The word
'contiguous' as used herein shall mean borderino each other at more than one point:
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(b) Any drilling unit not composed of two (2) governmental quarter-quarter sections must be completely
encompassed by the perimeter of a rectangle 1600 feet by 2725 feet. Provided, however, no unit shall be
permitted which will create Island acreage;
(c) The well shall be located at least 1,000 feet from every other drilling well or well completed in or
producing from the same pool located in conformity with this rule; and
(d) The well shall be located at least 500 feet from every exterior boundary of the drilling unit.
2.
However, with respect to each pool occurring in the discovery well, the top of which is encountered
below a measured depth of 12,000 feet below the surface, the State Oil and Gas Supervisor may permit 160
acre units for such pools if such unit size will promote and encourage the orderly development of the pool.
Every oil well drilled in such pool:
a)
Shall be located on a drilling unit of four (4) contiguous quarter-quarter sections containing
not less tlian 144 nor more than 176 acres upon which no other well drilling toorproducing from same pool
Is located. The word 'contiouous' as used herein shall mean bordering each other at more than one point.
b)
Any drilling unit not composed of four (4) contiguous quarter-quarter sections shall contain
160 surface acres which must be completely encompassed by perimeter of a rectangle 2640 feet by 3500
feet provided, however, no unit shall be permitted which will create island acreage.
c)
Each well shall be located at least 1500 feet from every drilling or producible well from the
same pool and not less than 750 feet from every exterior boundary of the drilling unit.
3. With respect to all other pools, every oil well:
(a) Shall be located on a drilling unit consisting of forty (40) contiguous surface acres, or a
governmental quarter-quarter section containing not less than thirty-six (36) acres or more than forty-four
(44) acres, upon which no other drilling or producible well is located. The word 'contiguous' as used herein
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shall mean bordering each other at more than one point.
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(b) Any drilling unit not a governmental quarter-quarter section must be completely encompassed by
the perimeter of a rectangle 1810 feet by 1445 feet. Provided, however, no unit shall be permitted which will
create island acreage.
(c) The well shall be located at least 660 feet from every other drilling well or well completed in or
(d) The well shall be located at least 330 feet from every exterior boundary of the unit.
4. No portion of the drilling unit upon which a well is located shall be attributed, in whole or in part, to any
other drilling or producible well in the same pool.
5. if any well drilled In conformity with the provisions of this rule, or as an exception thereto, is completed
as a gas well, It shall not be produced except for a test period of not exceeding forty-five (45) days, or in
compliance with applicable special field rules, or until authorization has been granted by the Board after
notice and hearing.
RULE 8. Spacing of Gas Wells
1. With respect to each pool occurring in the discovery well, the top of which is encountered below a
measured depth of 12,000 feet below the surface, and in the Pennsylvanian and older formations with
respect to each pool occurring in the discovery well, the top of which is encountered below a measured
depth of 3.500 feet below the surface, every gas well:
(a) Shall be located on a drilling unit consisting of (1) 640 contiguous surface acres; or (2) a
governmental section containing not less than 600 acres or more than 680 acres; or (3) sixteen (16)
contiguous governmental quarter-quarter sections whose total acreage is not less than 600 acres or more
than680 acres. In anycase, no other well producing from the same pool shall be located on anysuch unit.
The word 'contiguous' as used herein shall mean bordering each other at more than one point.
(b) Any gas drilling unit formed undersection 1(a) ofthisrule must be completely encompassed bythe
perimeter of a rectangle 5580 feet by 6245 feet. Provided, however, no unit shall be permitted which will
m
create Island acreage.
(c) The well shall be located at least 3,000 feet from every otherdrilling well or well completed in or
(d) The well shall be located not less than 1,500 feet from every exterior boundary of the drilling unit.
2. With respect to each pool occurring in the Oligocene and younger Formations, the top of which Is
encountered In the discovery well above a measured depth of 5,000 feet below the surface, the State Oil
and Gas Supervisor may permit one hundred sixty (160) acre units for such pools if such unit size will
promote and encouragethe orderly development of the pool. Every gas well drilled in such pool:
a) shall be on a drilling unit consisting of (1) one hundred sixty (160) contiguous surfaceacres, or
(2) a governmental quarter section containing notlessthan one hundred forty-four (144) acres or more than
one hundred seventy-six (176) acres. In any case, no other well producing from the same pool shall be
located on any such unit. The word 'contiguous' as used herein shall mean bordering each other at more
than one point.
b) Any gas driiling unit formed under Section 2(a) of this Rule must be completely encompassed
bythe perimeter ofa rectangle 2640 feet &3500 feet. Provided, however, no unit shall be permitted which
will create island acreage;
c) The well shall be located at leastfifteen hundred (1500) feetfrom every otherdrilling well or well
completed In or producing from the same pool located In conformity with this Rule; and
d) The well shall be located not less than seven hundred fifty (750) feet from every exterior
boundary of the drilling unit.
3. With respect to all other pools, every gas well:
(a) Shall be located on a drilling unit consisting of (1) 320 contiguous surface acres; or (2) a
governmental half-section containing not less than 300 acres or more than 340 acres; or (3) eight (8)
contiguous governmental quarter-quarter sections whose total acreage is not less than 300 or more than
340 acres. In any case, no other well producing from the same pool shall be located on any such unit.
The word 'contiguous' as used herein shall mean bordering each other at more than one point.
(b) Any gas drilling unit formed under section 2(a) ofthis rule must be completely encompassed bythe
perimeter of a rectangle 3735 feet by 5380 feet. Provided, however, no unit shall be permitted which will
n
create island acreage.
m
(c) The well shall be located at least 1,980 feet from every other drilling well or well completed in or
(d) The well shall belocated not less than 990 feet from every exterior boundary of the drilling unit.
4. No portion of thedrilling unit upon which a well islocated shall beattributed, In whole orin part, toany
other well drilling in or producing from the same pool.
n
^
5. If any well Is completed as a gaswell in the gas cap of a pool productive of oil, or if any well drilled
as a gaswell isproductive from orcompleted in anoil pool, it shall not beproduced except for a test period
not exceeding forty-five (45) days, orin compliance with applicable special field rules, or until authorization
has been granted by the Board after notice and hearing.
n
RULE 9. Exceptions to Spacing Rules
The Board may grant an exception to any spacing rule whenever
the Board shall determine, after notice and hearing, and the facts
clearly support the determination, that the unit is partly outside the
pool. or. for some other reason, a well so located on the unit
would be non-productive or topographical conditions are such as
to make the drilling at such location unduly burdensome.
Application for an exception on Form 2 shall be accompanied by
^
a plat or sketch drawnto the scale of not smallerthan one (1) inch
^
equaling 1000 feet, accurately showing to scale the property on
which the permit is sought, all other completed, drilling and
permitted wells on this property, and all adjoining sun-ounding
properties and wells. The application shall be verified by some
(*1
person acquainted with the facts.
Whenever an exception is granted, the Board shall take such
action as will offset any advantage which the person securing the
exception may have over any other producers by reason of the
drilling of the well as an exception, and so that drainage from
developed units to the tract with respect to which the exception is
granted will be prevented or minimized and the producer of the
well drilled as an exception will be allowed to produce no more
than his just and equitable share of the oil and gas in the pool. If
the drilling unit Is of less acreage than that prescribed by the
applicable spacing rule as a regular drilling unit, such special unit
shall be allowed to produce only in the proportion that the acreage
content of such special unit bears to the acreage content of the
regular prescribed unit.
n
|«B|
143
n
EASTERN GULF REGION
PETROLEUM TECHNOLOGY TRANSFER COUNCIL
^
JACKSON/ MISSISSIPPI
MARCH 26, 1997
MISSISSIPPI WELL SPACING
MISSISSIPPI OIL AND GAS BOARD
Walter Boone, Oil and Gas Supervisor
im
Declaration of PolicyStatute 53-1-1
Well Spacing and Unit Formation
1^
n
ADMINISTRATIVE REQUIREMENTS
Statewide Rule 7
Statewide Rule 8
- Oil Wells
- Gas Wells
Special Field Rules
- Adopted by Board Order,
after
notice and hearing
BOARD ORDER PERMITS
Exceptions to statewide and special field rules approved,
f-i
after notice and hearing.
Horizonal Wells and Units
^
Unitization of Oil and Gas Fields and Pools
UNITIZATION REQUIREMENTS
fHV
Eastern Gulf Region
David Curry,
Administrator, Oil & Gas Section,
Florida Geological Survey
(-1
m-
PETROLEUM TECHNOLOGY TRANSFER COUNCIL - EASTERN GULF REGION
JACKSON, MISSISSIPPI
MARCH 26,1997
FLORIDA WELL SPACING AND DRILLING UNITS
FLORIDA GEOLOGICAL SURVEY
David Curry, Oil and Gas Section
I.
Legal References
1. Chapter 377, Part 1, Florida Statutes
2, Chapters 620-25 through 30, Florida Administrative Code
fpfi
Ch. 620-25, General Regulations
Oh. 620-26, Permitting
Oh. 620-27, Drilling
Oh. 620-28, Production & Flowlines
Oh. 620-29, Injection Wells, Workovers, & Abandonments
Oh. 620-30, Wetlands & Submerged Lands
PI
IT.
Well Spacing & Drilling Units
"
1. 620-26.004(1): Field Wells
2. 620-26.004(2): Exploratory Wells
3. 620-26.004(3): Drilling Units
"
4. 620-26.004(4): Well Locations Within DrilUng Units
5. 620-26.004(5): Horizontal Wells & Associated Drilling Units
6. 620-26.004(6): Nonroutine Drilling Units & Wells
(*1
pn
in.
Field Wells: Spaced in accordance with general spacing rules unless special field spacing
rules have been adopted.
IV.
Exploratory Wells: Spaced in accordance with depth as follows < 7,000 feet: 40 acre unit; well no closer than 460 ft. to drillingunit boundary.
> 7,000 feet: 160 acre unit;
Gas Wells: 640 acre units;
"
"
920
1320
"
March 26,1997
Page 2 of2
V.
Routine Drilling Units: Based on Township / Range Grid System & using existing
Sections, 1/4 and 1/4 1/4 Sections as drilling units.
VI.
Horizontal Wells & Associated DrillingUnits: Units for horizontal wells include all 10
acre blockswithin 920 feet ofthe productive section ofthe well. Wells penetrating the
central portion of a routine unit include the entire unit. Subsequent field unitization is
required
Vn.
Nonroutine Units & Wells: Individual units created to solve problems unique to particular
wells.
^
1. Adopted when necessary to protect correlative rights or to preventwaste.
2. Supporting data required.
^
2. All substantially affected parties contacted; hearing usually required.
4. Public input accepted, decision taken, notice ofdecision provided to all parties.
5. Decision final after 21 days notice unless a legal appeal is filed.
NOTES:
In Florida, drilling units, production units, and well spacing are almost synonymous.
There are no production units different fi*om the original drilling units except where special field
or unitization rules were adopted subsequent to the discovery well. These units may be based on
geographical, geological, or other considerations. Historically, most units have been geographical
1/4sections but with the advent of horizontal drilling, geologically based units are becoming more
common. The process used to create nonroutine drilling or production units is the same process
used to consider requests for special field rules, field unitizations, rule waivers, etc. The applicant
requests authorization to deviate firom standard procedure and provides whatever supporting
documentation he/she thinks necessary. The Department looks at the request and usually,
although not always, schedules a hearing to allow input fi*om affected parties (in the case of
unitization, the unit agreement must be ratified by at least 75% of the working interest).
Subsequent to the hearing, the Department will review all information provided, take a decision,
issue a Final Order, and provide legal notice to all substantially affected parties. The Final Order
becomeseffective 21 days after issue unless a legal challenge is filed withinthat time.
A copy ofRule 62C-26.004, Well Spacing andDrilling Units, is attached.
/dc
attachments
a;/pttc-tlk.397
^
n
62C-26.004 Well Spacing and Drilling Units.
(1) Field Wells. Wells drilled in
existing fields shall be spaced in
accordance with the special field rules
adopted as orders by the Department.
Where no such orders exist, general
spacing rules 62C-26.004(2) through (5)
shall apply.
shall be located where they cause the
least surface disturbance and do not
result in drainage or other environmental
problems.
(a) Oil Well Bhl. Routine oil test
wells drilled to a depth of less than 7000
feet shall have a bottom hole location no
(2) Exploratory Wells. Exploratory oil
wells drilled to a depth of less than 7000
closer than 460 feet to the nearest drilling
unit boundary; oil test wells drilled to
feet shall be located on 40 acre units;
more than 7000 feet shall have a bottom
hole location no closer than 920 feet to
exploratory oil wells drilled to a depth
greater than 7000 feet shall be located on
160 acre units. All gas test wells,
regardless of depth, shall be located on
640 acre units.
the nearest drilling unit boundary.
(b) Gas Well Bhl. Routine gas test
wells or gas condensatewells shall have
a bottom hole location no closer than
units shall be based on the U.S.
1320 feet to the nearest drilling unit
boundary.
Government Surveyed Township and
Range system. This system will be
utilized to space wells as specified in
62C-26.004(4).
(c) Wandering Bhl. Should the
bottom hole location of any producing
well not meet the spacing requirements in
(3) Drilling Units. Routine drilling
62C-26.004 and where such location was
n
(a) One Well Limit. No drillingunit
shall contain more than one currently
producing well in the same pool or be
attributed in whole or in part to any other
producingwell in the same reservoir
except where provided for by special
field rules or by 62C-26.004(5).
not approved as a condition of the
drilling permit, the well shallbe
(b) Routine Units. All routine
drilling units shall be shaped so that all
diagonals lie wholly within the unit with
the length ofthe longest diagonal not
exceeding 125% ofthe length of a
diagonal of a square containing the
62C-26.004(5).
samenumber of acres as the unit. All
other drilling units shall be created in
accordance with 62C-26.004(5).
(4) Well Locations within Drilling
Units: Surface locations shall be
determined by surface conditions and
considered a nonroutine location as
defined in 62C-26.004(5) and the
operator shall apply for a nonroutine
location as outlined therein. No such well
shall be produced, except for testing,
prior to meetingthe criteria defined in
(5) Horizontal Wells and Associated
Drilling Units (Wells Deeper Than
7,000 Feet).
(a) Nearest Well. No producing
section of any well may be closer than
1840 feet to another productive well.
FW»
62C-26.004(5) Well Spacing (Cont'd)
(b) Unit Construction. All ten acre
blocks, each being one-sixteenth of a
routine 160 acre drillingunit, whose
nearest boundary is within 920 feet of the
productive section of a horizontal well
all substantially affected parties
(offsetting mineral-interest owners,
operators, and lessees).
shall be included in the unit. Horizontal
determine whether the nonroutine well or
wells with productive sections
penetrating the 400 foot square in the
center of a routine drillmg unit shall
unit is necessary to prevent waste as
defined in Section 377.19(10), Florida
Statutes, or to protect correlative rights,
and shall grant, deny or condition the
permit on that basis.
include the entire 160 acre unit.
(b) Necessity. The Department shall
I—I
(c) Unitization. Productive
horizontal wells shall be unitized as soon
as possible after testing is completed.
(d) Well Numbers. Horizontal wells
shall be numbered according to the
quarter section of the entrance to the
producing formation.
(e) Survey. A Directional Survey
shall be run from the surface casing shoe
to total depth and shall be filed with the
Administrator within 30 days after
logging.
(i) Non-Routine Units. The special
requirements for non-routine drilling
units and wells shall apply to horizontal
wells.
(6) Nonroutine Drilling Units and
Wells. The Department may grant
drilling permits within shorter distances
to adjacent drilling unit boundaries or on
different drilling units than those
prescribed in this rule whenever the
Department determines that such steps
are necessary to protect correlative rights
(c) Agency Notices. The
Department shall advise all substantially
affected parties, whose names and
addresses appear on the application or
who have so requested in writing to the
Department, of its proposed final agency
action. Such notice shall be given to the
affected parties no later than 28 days
prior to final agency action by the
Department.
(d) Additional Data. In addition to
the documents required for a routine
application, the applicant shall submit a
letter explicitly stating what action the
applicant wishes the Department to take
and why. Supporting material shall
include any studies, data, cross sections,
maps, plats, or other available documents
which support or explain the request. All
interpreted geologic data shall be signed
by a geologist licensed under Chapter
492, Florida Statutes.
SpecificAuthority377.20,377.22 FS.
Law Implemented 377.25,377.26,377.27 FS. History-New
11-26-81, Formerly 160-26.04, Amended 6-4-89, 5-12-93,
Formerly 16C-26.004, Amended3-24-96.
or to prevent waste.
(a) Applications. Applicants
seeking permits for nonroutine wells or
drilling units must include in the
application the names and addresses of
n
1^
Eastern Gulf Region
Drilling and Production Units and Well Spacing"
tf
f-ft
Michael Killeen,
Director, Geological Oil & Gas Division,
J—I
r-t
Eastern Gulf Region
Workshop on Drilling and Production Units and Well Spacing
March 26,1997
Michael Killeen, Director, Geological Oil and Gas Division
Office of Conservation Organization
Commissioner of Conservation Regulatory Authority
(-1
Title 30 of the Louisiana Revised Statutes of 1950
Well Spacing (Statewide Order 29-E)
OIL - 330 feet from property lines and 900 feet between wells
completed in the same sand/zone
GAS - 330 feet from property lines and 2000 feet between wells in same sand/zone
Field Order Spacing may vary from 29-E spacing
n
Formation of Units
Definition of a UNIT
Unitization Procedure
"
"
Pre-Application Notice
Pre-Application Conference
Unit Application
Legal Notice, Posting and Publication ofNotice
Public Hearing
StaflfReview
Conunissioner's Order
Geographic Units
rn
—
Geologic Units
Reservoirwide Units (Act 441)
Page Two
Austin Chalk Horizontal Wells
Special Rules being Considered
Austin Chalk Spacing
Projects with Central Gulf PTTC
Conservation
Rules
&
Regulations
available
from
Central
Gulf
PTTC on CD or Disk
Louisiana Desktop Well Reference CD
n
I«^
STATE OF LOUISIANA
DEPARTMENT OF CONSERVATION
BATON ROUGP:, LOUISIANA
July 15. 1957.
STATEWIDE ORDER NO. 29-E
m
Order establishing rules for spacing of
wells drilled in search of oil and gas in
areas of Louisiana for which no spacing
^
regulations have been prescribed by Spec
ial Orders.
After considering the desirability of establishing Statewide Rules and
Regulations for the drilling of wells in Louisiana in search of oil or gas in
m
fMi
areas in which no spacing rules are established by Special Orders, and after
public hearing on that subject held In New Orleans, Louisia^, on October 10.
1955, under Docket No. 55-167 pursuant to proper legal notice:
IT IS ORDERED THAT no permits shall be issued for the drilling of
wells in search of oil or gas and no well shall be drilled in search of oil or
gas in areas of Louisiana in which no spacing rules are prescribed by Special
Orders, unless the location of such well shall comply with the following re
quirements:
^
^
(1) No spacing shall be required for wells drilled
in search of oil to depths less than 3, 000 feet
subsea, except as provided for in the last para-
'
graph of this order.
(2) Wells drilled in search of OIL to depths below
3, 000 feet subsea shall not be located closer
than 330 feet from any property line nor closer
than 900 feet from any other well completed in,
drilling to, or for which a permit shall have been
granted to drill to, the same pool.
(3)
Wells drilled in search of GAS shall not be lo
cated closer than 330 feet to any property line
nor closer theui 2, 000 feet to any other well
completed in, drilling to, or for which a permit
shall have been granted to drill to, the same pool.
(4)
^
When an order has been issued creating a pattern
of drilling or developmental units for a pool, if
application is made for a permit to drill a well
outside of the unit pattern which might develop an
extension of the pool, the Commissioner may re»
quire that such well be located and drilled in
^
compliance with the provisions of orders affec
ting that pool.
{5)
«
All applications for permits to drill in search of
oil or gas shall contain with such application a
commercial ownership map containing such in
formation that is in the possession of the applicant
showing (1) the location of existing producing or
drilling wells, (2) the lease and property ownership of tracts offsetting or in the vicinity of the
well for which the permit is sought, and (3) the
location of the proposed well with respect to pro
perty and lease lines, as provided for in State«
wide Order No.
29-B.
s'i-y\ rr: of Louisiana
BATON ROUr.E, LOUISIANA
^
September 5. 1957
AMENDMENT TO STATE VVIDC ORDER NO. Z9-E
Pursuant to power deiegatci vmder the laws of the State of Liouisiana,
and particularly Title 30 oi Louisiana Revised Statutes of 1950. and based upon
a hearing held vmder Docket No. 55-167 in New Orleans. Louisiana, October 10,
1955, it is ordered that Statewide Order No. 29-E be and it is hereby amended
^
as follows:
1. In lieu of the opening paragraph of Order No. 29-E,
the following shall b«; substituted:
IT IS ORDERED THAT no permits shall
be issued for t'-e drilling oi wells in search
of oil or gfis auc no well shall be drilled in
search ot oil or gas nor shall a well be
abandoned in one pool and recompleted in
another pool in a field in Louisiana in which
no spacing rules are prescribed by special
orders. unJess the location of such well
shall comply with the following requirements:
2. .Subparagraph (4) un the second sheet of said order shall
be renumbered (S) and th«'re shall be included among the excep-
'***'
tions on Page Id of said order ihc ii-llowing subparagra^^h (4):
(4) Whore a pernrii ib requested for a wild
cat well to be drilled in an area in which the
surface or mineral ownership is so divided
tliat the well cannot be located in compliance
with the requirements of this Order and a
drilling unit cannot be formed in advance of
drilling because it is not known whether the
well will be completed as an oil well or a
gas well, a permit may nevertlieless be
granted tor the drilling of the well when the
applicant presents evidence satisfactory to
the Commissioner that the applicant has
available for assignment to said well leases
or acreage of area and size to constitute, in
the judgment of the Ctimmissioner, a reasonable producing imit for such well and such
appii- njit aj;r' es to crertte or to apply to the
Cominissiuner for creation of a reasonable
I '
p?|
producing unit within a reasonable time after
completion of the well.
This Amendment shall be effective from cUid after Septeniber 1, 1957,
OF THE STATE OF LOUISIANA
BY:
(Sgd) John B. Hussey
JOHNB. HU55E7
COMMISSIONER OF CONSERVATION
_
^-1
STATEWIDE ORDER NO. 29-E {Continued)
^
"Property Line" as used herein jhall mean the boundary dividing tracts
on \vhich mineral rights, royalty, or leases are separately owned, except that
where conventional units shall have beei; created for the drilling of the well,
the boundairies of the unit shall be considered the "property line".
Exceptions to the above shall be granted when, conforming to the follow
ing requirements:
«
(1)
Where prior to the issucuice of this order,
a pool has already been partially developed
with a greater density of wells than that pres
cribed herein, the Commissioner of Conserva-
tm
tion may. without additional public hearing,
exempt such pools from the provisions of this
order. The exemptions for these pools shall
be granted only after application has been made
to the Commissioner of Conservation in writing
accompanied by a map delineating the location
of all existing wells completed and producing
from the poo^ for which exception is being asked.
(2)
Where prior to the issuance of this order a well
has previously been completed at a location off
setting the property or unit line closer to the
property or unit line thsm the setback prescribed
herein, the Commissioner may, without additional
public hearing permit like exception for this off
setting well, such exception to be limited to the
pool from which the offsetting well is producing.
(3)
The Commissioner may, without additional public
hearing exempt from this order wells drilled in
areas which ho t:onsi<lors to be affected by pierce-
^
ment type salt domes or other complexly faulted
areas to which, in the opinion of the Commissioner.
this order would not be properly applicable. These
requests for exceptions shall also be made in writing to the Commissioner of Conservation accom
***
panied by sufficient evidence to justify the exempt
classification.
(4)
fpii
^
In addition to the exceptions provided for in Para
graphs 1, 2 and 3 hereof, the Commissioner may,
without additional pubJic hearing, grant an excep
tion to the provisions of this order in any case
where the granting of such an exception appears
to be necessary to pruvent waste, to prevent in
equity or loss of property rights. Such an excep
tion shall be considered and granted under this
Paragraph only when the applicant shall have fur
nished the following data and evidence through the
District Manager.
^
(a) A letter setting forth all pertinent
facts and reasons why the granting
of the exception is necessary.
(b)
A formal application for permit
to drill - Form MD - 10 - R.
(c)
An ownership map as required by
the provisions of Paragraph 5
hereof.
m
m.
STATEWIDE ORDER NO. 29-E (Continued)
(d)
Page 3
A written certificate that copies
of the letter request provided for
in subparagraph (a) hereof and of
the ownership map have been sent
to each lease owner of tract off-
^
setting or in the vicinity of the pro
posed well.
If within ten (10) days after the filing of the application
no protest shall have been made in writing by any party and
^
if the Commissioner considers that from the evidence sub
mitted the requested permit should be granted, he may issue
it forthwith and without a public hearing. If a written protest
should be filed within the ten (10) day period, the Commis
sioner may in his discretion either (1) issue or deny the permit
i»i
based on the available evidence or (2) call a public hearing
after legal notice. If the permit application is denied without
a public hearing, the applicant then may apply for and obtain
a public hearing in the manner provided by law.
When the pools covered by this order have had four (4) wells drilled to
and completed therein or after one (l) year has elapsed from the completion of
the first well in the field, whichever occurs first, the operator of wells in the
m
field shall petition the Commissioner of Conservation for a public hearing for
the purposes of establishing field rules and regulations and the creation of
drilling imits for the pools in the field. The right is reserved, however, to any
party in interest to apply for a hearing at an earlier date; and if the Commis
sioner fmds from an examination of tlie information furnished in connection with
any application for a drilling permit that an earlier hearing should be held to
establish rules and drilling units, the Commissioner may impose a condition in
the drilling permit that such an application be filed within a reasonable time, to
be specified by the Commissioner, after the successful completion of the well
in the horizon to which it is projected.
This order is intended only to regulate the spacing of wells prior to the
establishment of special rules and regulations and the creation of drilling units,
and it should not be construed as having the effect of unitizing separate owner
ships or of creating drilling or spacing units.
This order also is not intended to eliminate pools shallower thsin 3, 000
feet trom appropriate rules and regulations, including spacing regulations after
noticepublic hearing. After sufficient geological and engineering evidence
is available with respect to these pools found at depths of 3. 000 feet or less subsea tên the operator or operators owning wells therein are required to petition
the Commissioner of Conservation for a public hearing for the purpose of estab
lishing rules and regulations and the creation of drilling units for each such pool.
This Order shall be effective from and after August 1, 1957.
OF THE STATE OF LOUISIANA
BY:
(Sgd) JohnB. Hussev
JOHNB. HUSSE7
COMMISSIONER OF CONSERVATION
<*1
Eastern Gulf Region
David Triana,
Engineer, Oil and Gas Division,
rn
EGR - PTTC Focused Technology Workshop
Texas
All assignments of acreage for drilling or proration in Texas arevoluntary in thatan application for
Commission action must originate with an operator or working interest owner.
Drilling Unit: minimum acreage (well density) required to receive a Wildcat
or Field "Permit to Drill"
--May consist of:
"Stand-up acreage"
Legal Subdivision (W-1A)
Pooled Unit (Voluntary; P-12)
Density Exception (SWR-38)
•
•
waste prevention
correlative rights (drainage)
-Well location on Drilling Unit must meet well spacing:
Lease-line spacing
Between well spacing (same lease/field)
-Well Spacing Pattem - The regulation ofthe number and location of wells over a
reservoir as a conservation measure.
n
-Two sources: Statewide Rules (SWR 37 & 38)
Field Rules - Application/Hearings Process
Proration Unit: Acreage assigned to a well for the purpose of allocating production. Statement of
Productivity required (P-15).
-Types: "Stand-up"
Substandard:
-Legal Subdivision
-Density Exception
m
Pooled Unit:
-Administrative (P-12)
-MIPA - "Forced" Pooling
f-i
Well Spacing Pattem: (Spacing, Density, Diagonal)
-Statewide Rules (467' x 1200' on 40 ac.)
-Commission Standards (1x2)
Unitization:
n
-not pooling
-operation in commonfor Enhanced Recovery purposes
-in conjunctionwith: Enity for Density
m
Horizontal Wells:
im
-first recognized permit in 1989
^
-drilled to date: 5,587 (1/84 - 1\97)
-completed to date: 4,618 (1/84 - 1/97)
-permitting as directional drill (SL, PP, BHL)
m
-acreage assignments:
-SWR86
^
-Special Field Rules
Hearing Process:
-Governed by TX Admin. Procedures ACT (TAPA)
-Notice and Opportunity for Hearing (NOA)
-21-day notice required
-administrative grant if no protest
n
-Notice and Hearing (NAH)
-10-day minimum notice requiredprior to hearing
-Action within 90 days of hearing if no protest
n
-Protested hearing process requires 90-120 days minimum
-Notice
-Hearing
-Proposal for Decision circulated
m
-Exceptions/Replies
-Presentation of PFD for Decision
-Motion for Rehearing
-Rehearing or
-Order Finaled
n
n
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Discussions of Law,
Practice and Procedure
RAILROAD COMMISSION
OF TEXAS
Published by
Oil and Gas Division
n
f-1
Part I
Railroad Commission Field Rules
A.
Introduction
The Cotnmission adopts or amends field rules to prevent waste
and to protect the correlative rights of owners of interests
within the field.
In the absence of field rules so adopted,
statewide rules apply.
Applications ror rield^ rules or field
rule amendments are made in letter form, referring to the rield
in question and briefly listing the particular rules requested.
The Commission staff schedules a hearing date and issues notice.
The notice of hearing specifically states that the Commission may
enter such rules as it deems justified.
The Commission may enter
rules requested by the applicant or by a party to the hearing
other than the applicant, or may enter Commission-proposed rules
supported by the evidence.
The Railroad Commission notifies interested parties of field
rule hearings.
In a temporary field rule hearing, the Commission
determines the identity of interested parties based on the lease
tract of the discovery well for the new field. The Commission
notifies all operators offsetting the lease tract of the^discov-
ery well, and any owners of mineral interests on lands offsetting
the drillsite lease.
If at the time temporary field rules are
requested, a s.econd operator has completed a well in the field,
that operator is given notice.
When a hearing is held to con
sider the establishment of permanent field rules, all operators
with wells in the field are notified.
A request for field rules is normally made by an operator
n
with a well or wells
in the lield.
On
and Gas Docket No.
7B-77,425 involved an application for field rules by a working
interest owner who was not the operator designated to the Commis
sion for any well in the field. In that case, the interests of
the operating interest owner were determined to be sufficiently
distinct from those of the designated operator to merit standing
for the working interest owner.
Generally the Commission will permit applications i.or field
rules only by operators in the field. Exceptions may be made
where a non-operator requires tield ruies in order to pursue an
application under the Mineral Interest Pooling Act (MIPA), or
m
where the Commission determines that the interests of the appli
cant and the operator are sufficient distinct.
Basic
field
rules
normally
address
spacing
and
density.
Rules providing for net gas-oil ratio, pressure surveys, ^testing
surve'^'s,
and multiple unit associated gas well allowables may
also be considered for adoption.
B.
Documentary Evidence
Documentary evidence submitted in Rai_road Commission fiela
rule hearings normally includes an area map prepared by or under
the supervision of an engineer or geologist. A certified survey
or's map is not usually required.
The area map should specify
the
scale,
show
the
North
wells within the field.
direction,
and
locate
and
label
all
The map should show where existing wells
are located in relation
to
leases
and the
estimated field
limits.
Section and survey boundaries should be accurate.
Weil informa
tion should include name, number, depth, and date of completion.
The exam.iner would expect an area map which includes the entire
field area and surrounding fields within two to five miles of the
subject
field.
Each
field
should
be
identified
on
the
map.
Testimony concerning the area map should relate the field geology
to the area geology.
Submission of a log of a typical well in
the field is generally necessary.
A typical well log would
include
all
zones
of
interest,
would
often
be
taken
from
the
deepest well in the field to show faulting and other geologic
information below the subject zone, and would be a log where
faulting or lenticularity, if any exists in the field, appear.
The log submitted should be of a nype that would best identify
the zones being studied.
The nearest producible horizon is
important because comparisons may be drawn concerning whether the
same or different field rules are applicable.
An induction
electrical log is usually submitted.
For gas fields, a copy of the initial potential test for the
discovery well on Railroad Commission Form G-1 is generally
relevant to show the initial bottom hole pressure in the field.
The four-point test is used to estimate the well's deliverability
(flow rate) at a given draw-down.
For oil fields, a Railroad
Commission
Form
W-2
should
field to show potential,
initial flowing pressure.
be
submitted
gas-oil
ratio,
for
all
water
in
the
production
wells
and
A completed Reservoir Data Sheet (see Appendix "A" to this
section) should be submitted at field rule hearings.
tion curve and a monthly production tabulation for
should
A produc
the field
also be submitted.
\êre limited data are available because
the
field is
in i t s
early stages of development, a list of nearby established fields
in the same formation, along with the Railroad Commission field
rules for those fields,
should be submitted as an exhibit.
In unprotesued hearings, a stenographic transcript is uaken
and kept for record, but is generally not transcribed.
There
fore, it is helpful to the examiner for an applicant to submit as
an exhibit a written statement of the reasons the proposed rules
are appropriate and necessary in this area.
C.
Temporary Field Rules
Statewide Rule 43 (16 TAC § 3.43) permits applications for
temporary field rules after the first well in a field has been
completed.
The
purpose
of
permitting
field
rule
applications
based on limited well data is to encoura.se develoDment to delin-
n
eate more rapidly che limits of the reservoir and to prevent the
wasteful clustering of wells near the discovery well. The tempo
n
rary field rules are effective for a stated time period, generally 18 months. The effective period set by the Commission varies
depending on the time expected to be needed to attain sufficient
well data to support more precise field rules.
^
r»
p
Prior to the expiration of the rules, the Commission sched
ules a hearing to review the temporary rules. If no one appears
and presents evidence to justify continuation of the temporary
rules or adoption of new rules, the temporary rules may be can
celled.
When temporary field rules are cancelled, the field is
governed by statewide rules.
When evidence is submitted at the
review hearing, che Commission may establish temporary rules
again or may adopt pemanent rules for the field.
D. Permanent Rules
Permanent
adequate
rules
information
are
is
established
available
to
for
a
field
determine
only
the
where
drainage
abilities of wells in the field.
When requesting permanent rules, applicants should provide
reservoir voliimecric calculations estimating the recoverable oil
or gas in the reservoir as well as a production decline curve for
representative wells in the field to estimate production expected
^
from such wells.
Evidence
of
pressure
communication between wells
field constitutes evidence of acreage being drained.
in
the
Applicants
requesting large proration units should prove that existing wells
are draining the requested number of acres.
m
^
Applicants should provide a structure map-; an isopach map
and p/z curves for several wells in the field. In a p/z curve p
(which equals pressure over a factor of gas compressibility) , is
plotted against cumulative production.
In gas fields,
Railroad Commission Form G-1 and Form G-10
should be filed for each well in the field.
m,
E.
„
Well Spacing and Density
1.
Generally
The well-spacing rule
^
^
establishes
the
minimum distance
a
well can be located to the nearest lease line, property line, or
subdivision line, and to ocher wells on the same lease completed
in the same reservoir.
The density rule establishes the number
of acres required to be assigned to each well in a given reservoir.
Density and spacing provisions in field rules substitute
for those provisions of Statewide Rules 37 and 38.
tion provisions of Rules 37 and 38 are applicable
field rules exist:.
The excep
even where
The shape of proration units is established
by a diagonal rule, which generally requires that the length of
n
3
the proration unit not exceed two times the width of the unit.
This permits rectangular units on which wells are located along
n
n
"
«
the center lines of the units, resulting in
on cjnuare units
Generally, well spacing is closely related to
density. The following well spacing and diagonal requirements
are usually considered acceptable for the spec'-ried density.
Density
Well Spacing
Diagonal Limit
640
320
160
80
acres
acres
acres
acres
i tcr^s
"
«
piy
1867' - 3735'
933' - 1867
660 - 1320
1320' - 2640;
"3^.:
:
iir.: \ll'
150' - 300-
Deviation from the above parameters is
tain circumstances, including where ^
primarily long, narrow leases, where irregu_a-
8500;
6500
iTcn'
3250
:
iooS'
500'
^
fields)
occur or numerous surface obstructions exisu (townsite fields),
and where reservoir conditions
dictate.
which may require spacing not comparable to uhe density inciuae
lenticularity and faulting-..
Where production will in large part occur
n
completion of existing wells formerly
the field rules may be altered to be consistent with the
rules in the other field in order to encourage development Oi. the
hydrocarbons.
^
p
-
The soacing and density provisions in the field rules are
intended to establish regular development in a rield and to avoid
clustering of wells to the detriment of the reservoir. In the
absence of field rules specifying the density for a particular
field, operators are subject to Statewide Ruie 3^, which requ res
that 40 acres be assigned to each well. I: special fêld
address only spacing, Rule 38(b) controls -or_ density.
drilled to depths of 5000 feet or less in Districts 7B and 9 and
in McCulloch County are governed by special cistrict-wide rules,
known as County Regular rules.
The density provision is intended to e_s5ablish the acreage
chat wells in the specific field can drain errectively. At field
rule hearings where density provisions are
pressure and production performance data are presented to ^^di
?Itr whether ^the wells are capable of
proration unit size. The supporting data ro. a density "q^"t
_
should include pressure interference testing or material balance
calculations based on production history or a PJf
versus production curve. From these dat=. it is possible to
estimate the total volume of hydrocarbons in place under the
requested proration unit size and estimate tne recovery efficien-
n
cy and probable ultimate recovery from a proration unit. For new
or young reservoirs with few existing wells and short producing
history,
it may be necessary to rely on experience in nearby,
similar fields which may be useful in predicting what to expect
from the new field.
The Commission, however,
takes into account
the effect of new completion techniques including fracturing or
^
other
stimulation.
In shallow oil fields,
the yardstick allowable provided by
statewide rules generally equals or exceeds the wells' abilities
to produce. For these fields it is recommended that only spacing
provisions be requested and adopted.
Density would then be
dictated by Statewide Rule 38(b).
An acreage-based allowable
''
would not be applicable and the allowable for every well in the
^
field, regardless of assignment of acreage, would be based on the
yardstick statewide rule requirement for that depth and spacing.
This eliminates the requirement for filings to establish the
productive acreage. Omission of the density provision will have
this effect in any case, but is particularly appropriate in
p,
shallow fields (fields at depths of less than 3,000 feet).
The
Luling-Branyon Field is an example of the type of field in which
only spacing provisions are needed.
^
2. Optional Density Provisions
In the same reservoir,
two
^
or more wells
to
a less productive portion may need
drain a
unit
that
in
other areas
is
ade
quately drained by one well; therefore, an optional unit size is
adopted. An operator .may assign acreage ranging anywhere between
the two options.
Generally one option is one half the other
optional unit size.
Certain fields in the state have greater
variance.
The Sonora (Canyon) Field in Sutton County has field
rules permitting densities ranging between 640 and 160 acres; the
Sawyer (Canyon) Sand in Sutton County has units ranging in size
between 640
pii
^
n
^
rm
and 80 acres.
Optional density provisions are appropriate in reservoirs
with erratic permeability or lenticularity. For example, in the
Boonsville (Bend, Conglomerate, Gas) Field, certain sands do net
appear in more than one or two wells. Two wells on the same 320
acre proration unit may each drain completely different sands.
Where optional rules are in effect, operators may drill on
the prescribed unit size, and later drill a second well on that
unit without exception to Statewide Rule 38.
The first well is
permitted to retain the larger acreage assignment for allowable
purposes until completion of the second well and assignment of
acreage to the second well.
For example, field rules for the
Boonsville (Bend Conglomerate, Gas) Field provide for optional
units of 320 or 160 acres. An operator wich a 320 acre lease may
drill a first well and assign 320 acres for allowable purposes.
Later, that operator may continue to assign 320 acres to the
first well until the second well is completed and acreage assigned to it.
When a G-I or W-2 completion report, and Forri
P-15 , Assignment of Productive Acreage, are filed to obtain ar.
-
"
allowable for the second well, the acreage assigned to the first
well must be reduced accordingly. Double assignment of acreage
to producing wells is prohibited by Statewide Rule 40(d) (16 TAG
n
§ 3 .40) .
pi,
The spacing provisions in fields with optional unit sizes
are based on the smaller of the two optional densities.
3.
^
of
Tolerance Provisions
Tolerance acreage provisions in field rules permit the use
scrap acreage remaining after a lease is drilled to final
density under the field rules.
F*
For example, in West Texas,
sections consist of more than 640 acres.
some
Therefore, after drill
ing one well under 640 acre rules or two wells under 320 acre
rules, scrap acres remain unassigned.
Tolerance acreage pro-
^
visions permit assignment of such scrap acreage to existing wells
or permit an additional well, if the scrap acreage exceeds the
tolerance amount, usually 10 percent of the unit size.
The
tolerance
provision
in
the
field
rules
specifies
a
maximum number of acres or percentage of the density provision
which may be added to the base density provision and assigned to
a well or wells. Generally 10 percent tolerance is permitted for
gas wells and 50 percent for oil leases. Thus, with 640 acre gas
field rules and 10 percent tolerance, in the example above, all
704 acres could be assigned to the well for allowable purposes.
^
P
pi|
m
n
An oil well in- a field with 40 acre rules and 20 acre tolerance
could have 60 acres assigned to the last well on the lease.
The
application of tolerance acreage varies slightly in oil and gas
fields in that tolerance may be used for each well in gas fields,
but in oil fields tolerance may be assigned only when the pro
posed well is the last well to be drilled on the lease or the
last well has been drilled.
Where remaining scrap acreage equals or exceeds the toler
ance acreage amount provided in the field rules, an operator may
drill an additional well if the tract is a legal subdivision.
(See the discussion of Legal Subdivision under Rule 37).
For
example, where a lease consists of 120 acres and the field rules
require 80 acres per well with a 40 acre tolerance, the operator
may either assign 120 acres to the first well or, if the tract is
a legal subdivision, drill a second well.
If the tract were 121
acres, the operator could assign only 120 acres or, if a legal
subdivision, drill a second well.
If the tract in question is a pooled unit, tolerance acreage
provisions may be used only where all leases in the pooled unit
are included in their e n t i r e t y j ..
\ J «->c/ •: ; Vc
' •'
'1 • . • ' O'* . f - PcC *
p,
4 i)
Where no tolerance provision is included in the field rules,
Rule 38(b)(3) provides a tolerance for the lease of one-half the
density provision.
Where optional densities are permitted, the
tolerance provision generally is written to apply only to the
larger of the options.
Rule 38(b)(3) provides the one-half
density tolerance provision for the other optional density.
n
4.
Exceptions to Diagonal
The diagonal provision in the field rules establishes the
maximum distance permitted between the
two furthermost points in
the proration unit. ' Exception to the diagonal requirement may be
requested and granted administratively if a particular proration
unit has a diagonal greater than that permitted in the field
rules.
Requests for exceptions are reviewed by a Commission
—
engineer to assure that all acreage proposed to be included in
the proration unit is reasonably productive and likely to be
drained by production from the field.
Drainage by offsetting
wells, not necessarily the specific well in question, satisfies
the drainage requirement. Because the allowable may be based on
productive acreage only, assignment of non-productive acreage is
not permitted. Denial of an application for exception to the
diagonal requirement will result in cutting the size of the
proration unit for allowable purposes.
The well will not be
required to be shut-in. Applications for exception ^to diagonal
requirements are accepted only after completion of the well.
Such applications are not permitted prior to drilling or com-
pletion because the information available to the Commission for
evaluation is inadequate.
F.
Allowable
An allocation
n
formula
is
designed
to
prevent waste
and
protect correlative rights by fairly distributing the available
market for production from the reservoir.
of
reservoir
and data available,
the
Depending on the type
formula may be
based on
productive acreage, net acre feet, deliverability, pressure,
initial potential, or some combination of these.
Productive
acreage is the most common basis. In single-operator fields,
deliverability is adopted frequently as a basis.
n
When the rules adopted for a field include a density pro
vision and an allocation formula based partially or entirely on
acreage, all operators in the field must file with the proration
department in Austin certified plats showing the size and shape
of the unit assigned co each well, along with a signed statement
on Form P-15 that all acreage claimed is reasonably productive of
hydrocarbons (16 TAC § 3.31). A plac must be filed for each well
in the field designating the productive acreage assigned to each
^
well.
exists.
Separate plats are generally required unless a large unit
The Commission's proration analyst relies on the plat to
establish allowables based on acreage.
^
r*
Operators are expected to
file such plats within a reasonable period of time after the
adoption of field rules.
If no plat Is filed within 1 month
after the adoption of field rules, the proration analyst will
attempt to notify the operator and, if no plat is received,
cancel the allowable for all wells for which plats have not been
filed.
Acreage permitted to be included within the productive
acreage includes portions of leases wiihin the probable fieid
limits as known at the time of filing.
/m,
areas
condemned by
dry holes,
areas
This would not include
across
faults,
and areas
beyond the oil-water contact.
n
7
Part VI
Rule 37 and 38 Exceptions
A.
Definitions and Limitations
Rules 37 and 38 are the Commission's spacing and density
rules for oil and gas wells. Rule 37 (16 TAG § 3.37) prohibits
the drilling of wells less than 467 feet from the nearest lease
line or less than 1200 feet from the nearest well on the same
lease completed in the same reservoir, unless an exception is
obtained.
Rule 38 (16 TAG § 3.38) requires that a minimum of 40
acres be assigned as productive acreage to each well. These are
the spacing and density rules of statewide application. There
are also special field rules and district rules which control for
n
more limited areas and which override Rules 37 and 38 wherever
field or district rules are applicable. The applicable minimum
^
Exceptions to these rules are granted in two situations;
distance is generally referred to as "the Rule 37 distance."
1.
When, because of unusual conditions on the tract,
an
exception is necessary to recover hydrocarbons which will go
^
unrecovered if no exception is granted (waste presention) , and
—
that right of. a mineral owner, which existed at the time the
applicable spacing rules attached, to recover his fair share or
2.
When enforcement of the rules will operate to destroy
the minerals beneath his tract or their equivalent (prevention or
confiscation).
Even though a particular exception sought by an applicant
may be an exception to special field rules, the exception is
referred to as a Rule 37 exception (if the proposed well is too
close to the lease line or nearest well on the lease) or a Rule
38 exception (if insufficient acreage will be assigned to the
(-1
well) .
There is no guarantee that a mineral owner or lessee will be
granted the Rule 37 or 38 exception necessary to drill a well^ on
his or her tract.
The owner of a "voluntary subdivision," a
tract which assumed a shape or size incapable of support a regu
^
lar location subsequent to the attachment of Rule 37 or Rule 38
or special field rules, normally is not entitled to a Rule 37 or
Rule 38 exception to prevent confiscation. (See discussion of
Voluntary Subdivision Rule, below.) Subdivisions made after the
attachment of spacing rules, resulting in mineral tracts of
substandard size' or shape,
are presumed "o have been made in
contemplation of oil and gas development and may not be used as a
means of circumventing the applicable spacing rules. Exceptions
to the spacing rules may be granted to voluntary subdivisions on
the basis of prevention of waste, if proven.
^
The prohibition
against granting exceptions for "illegal" or "voluntary" subdi-
visions
to prevent confiscation, and the "Century Doctrine"
exception will be discussed in greater derail in section F(3).
4 i
B.
Obtaining a Rule 37 Exception
1.
Filing the W-1
The first step in obtaining a Rule 37 exception is the
filing of the Railroad Commission Form W-1 (drilling application)
for the proposed well. The need for a Rule 37 exception should
be noted on the application itself.
A plat must accompany the
X^-1, as well as a list of all offsetting operators or unleased
n
mineral interest owners and their addresses.
site
tract
but
which
proposed location.
^
This "service list"
must include operators and unleased mineral owners for all tracts
which are contiguous to the drill site tract, not just those
within the Rule 37 distance to the proposed location.
The list
should also include tracts which are not contiguous to the drillare
within
the
Rule
37
distance
to
the
If an adjacent tract has been leased by an
undivided mineral interest owner, the list must include the
lessee-operator and the names and addresses of any unleased
cotenants.
If
there
is
more
than
one
lessee
or more
than
one
mineral owner, all lessees or mineral owners should be included.
^
The list should refer to the plat in a manner which makes identi
n
ble. When, after diligent effort, the applicant determines that
it is not possible to locate all of the interest holders entitled
to notice, the applicant should inform the Commission of this
fact.
Notice by publication will be required in such circum-
^
stances.
"
cause notice of the hearing to be published in a newspaper of
general circulation in the county where the well is to be located
(or in an adjoining county if there is no newspaper in the county
where the well is to be located). The notice should be published
fication of each tract and its operator or mineral owner possi
After a hearing date is assigned,
the applicant must
once each week for four consecutive weeks. The first publication
date must be at least 28 days before the hearing date.
n
When the W-1 is received by the Commission's permitting
section, it will be forwarded to the legal section as a Rule 37
application.
If there are errors or omissions in the applica
tion, a member of the staff will contact the applicant by letter
or telephone.
Complete applications will be set for hearing.
Notice of
the hearing will be sent by the Commission to each of the parties
on the list attached to the plat.
The applicant may wish to
include his or her representative or attorney on the list for
notice.
Failure to give notice to all necessary parties may result
in a void or voidable Rule 37 permit.
2.
Exception by Waiver
An applicant may obtain a Rule 37 exception without a hear
ing by including signed waivers from each offsetting operator and
offsetting unleased mineral owner wich the drilling application.
A Rule 37 permit will be issued without hearing upon review of a
28
complece application accompanied by all necessary waivers.
See
16 TAG § 3.37(h)(2)(b).
n
There is no prescribed, form for a Rule 37 waiver.
„
'
applicant may draft waivers for use by the offsets.
the waiver should make it readily apparent that the
that they are waiving their right to notice and to
object to the proposed well and know the location of
well.
The
The text of
signers know
the right to
the proposed
Notarization is not required.
n
Upon request by the applicant, an examiner may deem a Par
ticular offsetting tract as "unaf_fectedy by the proposed well.
PH
Waivers from tracts deemed
"unaffected" are not necessary to
obtain a Rule 37 exception by waiver.
Neither is notice required
to interest holders in such tracts. The designation of a tract
as "unaffected" will be made only upon a showing by the applicant
^
that great distance in relation to the field rules or previously
recognized field conditions make it impossible for a well at the
proposed location to drain the "unaffected tract. If the appli-
cant is relying on the existence of a rault or other special
geological condition in the field to establish the impossibility
of drainage, the existence of that condition must have been
established in a prior protested Railroad Commission hearing.
Although such geological conditions will not be found administra
tively by the examiner, extreme distance between the well and the
tract in question, in relation to the field rules, will oe con-
sidered as a basis for a designation by the examiner of a tract
as "unaffected."
f-i
n
The applicant seeking an exception by waiver has the option
of "walking" his application through the Commission.^ The appli
cant may bring the application to the Austin office in person and
submit the application for review and approval by the permitting
department. The application and all necessary waivers should
then be submitted to the Rule 37 section personnel who may au
thorize a Rule 37 permit immediately.
3.
Administrative Exceptions without Waiver
An applicant for a Rule 37 exception may obtain an exception
without waivers and without formal hearing if at least 10 days
notice of a hearing has been given to all affected parties (see
above) and no protest is made at the hearing. Note that the
Commission must'be allotted at least 14 days to effectuate such
notice. These exceptions are granted administratively after the
docket is called,' pursuant to Rule 37(h)(2)(A). (16 TAG
§ 3.37(h)(2)(A)).
An applicant who is certain that no party will appear to
protest an application need not attend the hearing to keep his or
her application alive. The application will be noted as unprotescea'by the hearings examiner and, in mosc cases, a permit will
be granted.
Protestants and other intervenors are required to give five
29
days notice of their intent to protest or participate in an
application by filing a written statement with the Commission. A
protestant who fails to give notice runs the risk of being
disqualified as a protestant.
A protestant who has not given
notice may appear at the hearing and request that the examiner
waive the five day notice requirement.
However, under such
circumstances, an examiner is likely to grant a surprised appli
cant's request for postponement.
The failure of an applicant to appear at a hearing at which
an unexpected protestant appears is not necessarily fatal to the
application. The examiner may call a postponement. However, the
failure of an applicant to appear at a hearing for which timely
notice of a protest was received may result in dismissal of the
application.
Dismissal is without prejudice.
Applicants may
reapply subject only to the penalties of procedural delays.
C.
Obtaining a Rule 38 Exception
As with the Rule 37 exception, the first step in obtaining a
Rule 38 exception is the filing of the Form W-1, the drilling
application. A plat showing the drill site tract and all offset
ting operators or unleased mineral owners and a Form W-1-A should
accompany the W-1.
Information contained in the W-l-A may establish the ability
n
of the applicant to obta'in an exception (based on prevention of
^
W-l-A is further explained in section D.
n
If the W-l-A does not establish the right of the applicant
to an exception, the matter will be set for hearing.
In contrast
to Rule 37 exceptions, exceptions to Rule 38 are" not granted on
the basis of waiver, nor are they granted administratively when
the application is unprotested.
^
confiscation) without the need for a hearing.
If this is the
case, a drilling permit.will be granted as a regular permit. The
At hearing, the applicant must demonstrate through exhibits
and testimony the need for a Rule 38 exception to prevent waste
if the exception is for the initial well on the tract.
The
definition of waste
for
Commission purposes
is
discussed
in
section ?(2).
Second or subsequent wells on a tract may be
entitled to exceptions to prevent either confiscation or waste.
Procedures for obtaining Rule 38 exceptions for additional
wells on the lease are based on similar principles.
The one
additional consideration is that of tolerance acreage.
Tolerance acreage is a provision created by the Commission
for the purpose of allowing utilization of the "odd scraps" of
productive acreage left over when a tract has been developed to
its final density under applicable density and spacing rules.
Any tolerance provisions included in the field rules control.
In
the absence of such provisions, the 50 percent tolerance factor
permitted by Rule 38 controls.
30
of a
n
Utilization of tolerance acreage is dependent on the filing
valid W-l-A establishing the right of the applicant to
protection against confiscation. If the W-l-A does not establish
a right to protection against confiscation the operator may drill
a well on the remaining acreage only pursuant to a Rule 38 exception on the basis of waste.
Under these circumstances, an excep
tion may be issued only after notice and hearing.
If the W-l-A does establish the right of the applicant to
^
P-i
protection against confiscation, the operator's options are
determined by the amount of productive acreage remaining. If the
remaining acreage is equal to or greater than the tolerance
acreage amount, the operator may use it to drill an additional
well. The permit for the well may be issued without a Rule 38
exception.
"
If the remaining acreage is less than the tolerance acreage
n
amount, it may be assigned to existing wells on the lease, pos
sibly increasing the allovjables of such wells.
The tolerance
acreage amount is the maximum acreage which may be assigned to
existing wells as tolerance acreage.
In other words, no proration unit in the field may be larger than the standard unit
provided for in the field rules, plus the tolerance percentage.
m
For a more detailed discussion of tolerance acreage see Part I,
section E(3).
D.
The Form W-l-A
An applicant seeking an exception to the spacing or density
n
„
rules because a tract is of substandard acreage or of a size and
shape which will not support a regular spacing location should
file a Form W-l-A with the drilling application.
The purpose of
the W-l-A is to establish, if possible, that the tract assumed
its shape and size prior to attachment of the spacing rules to
the tract.
The W-l-A may further establish that the tract has
not been under common ownership and control with an adjoining
tract since the attachment of spacing rules. If so, the form may
serve to establish the owner's right to protection against con
fiscation.
If the date on which the cract assumed its present shape and
size predates the attachment of spacing rules, the tract's en
1*1
titlement to a density excepcion is presumed unless specific
objecuion is received by the Commission.
As can be seen, the
W-l-A is used primarily to establish the right to a Rule 38
exception.
The information contained in the W-l-A is also of
evidentiary significance in Rule 37 cases where the tract is
incapable of supporting a regular location. The form itself may
be subject to u'he hearsay objecuion, but a qualified witness may
testify as to the information contained in the W-l-A.
In pro
tested'Rule 37 cases, however, a W-l-A cannot secure the right to
an exception.
The applicant r.ust still prove by admissible
evidence* that a well 'at the proposed location is necessary to
give "he applicanc's lessor the opportunity zo recover his or her
fair share of the minerals in place beneath the tract.
31
E.
The Voluntary Subdivision Rule
On May 29, 193A, the Commission enacted a rule, now con
tained in Rule 37 (16 TAG § 3.37) commonly referred to as the
Voluntary Subdivision rule or the Rule of May 29th. The practi
cal effect of the rule is that only owners of tracts which
assumed their present shape and size prior to the attachment of
field rules are capable of obtaining exceptions based on confis
cation for the first well on a tract.
A tract of a shape and/or
size that will not support a regular location that was subdivided
from a larger tract after attachment of spacing and density rules
is not entitled to an exception on the basis of prevention of
confiscation.
The purpose of the rule is to prevent circumvention of the
spacing rules through the voluntary subdivision of tracts. The
basic test is:
was the subdivision performed in contemplation of
oil and gas development. Various potential issues serve to make
application of the voluntary subdivision rule a complex matter.
Four of these issues are discussed below.
1.
When did the spacing rules attach?
n
In any case involving voluntary subdivision, the date of
subdivision must be compared to the date of attachment for the
n
attach when an area is proven to be productive of oil or gas.
Therefore, a date must be determined on which such productivity
was established.
The date of attachment is presumptively the
discovery date listed by the Gommission for the oldest reservoir
accessible from the subject tract.
This presumption, however,
can be overcome by evidence supporting an earlier or later date.
applicable
n
^
^
spacing rules.
Generally,
the
spacing rules will
In certain cases, the discovery well and subsequent develop
mental wells for a given field may have been drilled so far from
the subject tract that it is plausible to assert that the subject
tract was not known to be productive of oil or gas at the time of
or even after the discovery.
Under such circumstances, a subdi
vision which was effected after the discovery date for the oldest
accessible reservoir might not have been in contemplation of oil
and gas development.
The burden of proof is on the party
attempting to overcome the discovery-well date presumption.
n
n
Pursuant
to
Railroad Commission of
Texas V. Richards, 336
S.W.2d 4A9 (Tex. Civ. App.--Austin 1960, no writ), the leasing of
the subject tract for oil and gas development may cause attachment of the spacing rules, regardless of whether the area is a
proven one.
„
"
2.
Which spacing rules apply?
The spacing rules in effect at the time of the subdivision
apply for purposes of determining the right of a tract to protection
against confiscation.
Ketail Oil Co., v. Shell Oil Co.,
170 S.VJ.2d 253 (Tex. Civ. App.--Austin 1943, no writ)
Texas
32
Trading Co. V. Stanolind Oil &Gas Co., 161 S.W.2d 1046 (Tex. Civ. App.-Beaumont 1942, writ ref'd w.o.m.).
"
"
3. Which subdivisions are voluntary?
In addition to
those subdivisions
typically regarded as
voluntary, judicial partitions are regarded as voluntary subdi
visions. Humble Oil & Refining Co. V. Lasseter,
App.--Austin 1938, writ dism'd w.o.m.).
120 S.W.2d 541 (Tex. Civ.
n
Subdivisions which occur as a result of adverse possession
are also voluntary.
The subdivision, however, does not occur
until the period of limitations has run. Tidewater Ass'd Oil Co. v.
Hughes Oil Co., 250 S.W.2d 405 (Tex. Civ. App.--Austin 1952, writ
ref *d' n.r .e.) .
"
4. Have legally subdivided tracts been united under common
ownership and control since attachment of the spacing
rules?
Substandard tracts united under common ownership and control
^
n
subsequent to attachment of spacing rules are not entitled to
separate consideration for confiscation purposes. Note, however,
that the pooling of distinct, legally subdivided tracts to^ form a
production unit does not automatically extinguish the right or
the individual tracts to protection from confiscation upon disso-
lution of the pooled unit.
Rule 38(A)(5) may require a hearing
prior to dissolution if the dissolution is being performed pur
suant to separate development.
^
n
If the parties in a pooled unit successfully effect a cross-
conveyance of interests, the right of subsequently subdivided
tracts to protection against confiscation may be extinguished,
(See Veal v. Thomason, 138 Tex. 341, 159 S.W.2d 472 ^1942]).
F.
Issues in Rule 37 and Rule 38 Exceptions
1.
The Hearing
At a hearing an applicant may present evidence to support
his or her claim that an exception is necessary to prevent waste,
n
confiscation or both. Definitions of these two bases for excep
tion and discussions of the types of evidence useful to support
them are included in separate sections, co follow.
r-i
At hearings, offsetting operators and unleased mineral
owners are given the opportunicy 1:0 cross-examine the applicant's
^
witnesses and to present their own witnesses and evidence on
relevant issues. Protesting witnesses may be cross-examined by
the applicant.
The overall burden of proof in a hearing is always on the
paruy seeking an exception to che spacing^ and density rules.
However, the issues which must oe addressee in the applicant s
n
33
^
case vary with the
circumstances
challenges raised by the protestant.
of the
application and
the
^
The burden of proof must be examined in two different cir
cumstances.
When the tract is capable of supporting a regular
^
presumed.
location,
the
need
for
protection
against
confiscation
is
The applicant need only show the necessity for the
proposed location.
However, if the protestant introduces evi
dence overcoming that presumption and indicating that the appli-
"
cant^ is receiving his fair share from wells in the area, the
applicant must then establish that a well on this tract is neces
sary to recover the applicant's fair share.
^
In the second circumstance, an applicant seeking an excep
tion
^
to
drill
a
well
on
tract which
is
either
substandard
in
37 exception is impossible, must establish a prima facie case
that the proposed well is necessary to recover the applicant
lessor's fair share of the oil and/or gas in place beneath the
lessor's tract or their
"
a
acreage or of such a size and shape that drilling without a Rule
of Texas v. Williams,
163
equivalents
Tex.
370,
in
kind.
356
Railroad Commission
S.W.2d
131
(1961).
Frequently this issue of fair share is reduced to one question:
Does the applicant's lessor have an interest in another well or
1-1
wells in the drainage area of the subject tract sufficient to
enable the lessor, without the requested well, to recover the
lessor's fair share of the minerals in place beneath the subject
tract or their equivalen^ts in kind?
If recovery of the appli
cant's fair share is possible without the requested well loca
tion, no exception is recommended.
n
In other words,
the
issue of
fair
share must be
satisfac
torily addressed by the applicant whenever:
n
a.
The subject tract is substandard
undrillable without a Rule 37 exception, or
acreage
b.
The protestant makes a prima facie fair
case, challenging the applicant's right to an exception.
or
share
In the absence of either of these circumstances, the appli-
cant need prove only that the an irregular location is necessary
surface or subsurface conditions and that the proposed
location is a reasonable one.
The applicant must negate the
reasLbi.lLty of all regular locations for recovering the applicant's rair share.
o
t-K
When 2:air share is a proper element of the case, the examintake evidence regarding the opportunity of the mineral
n
er
^
^
eneath the
tract.fromEntitlement
an exception
on
derived
the mineraltoowner's
right tobased
recover
his or^
in place. Because a lessee's right in this
respec-^can De no greater than the lessor's, it is the lessor's
oppor
o recover his or her fair share which is reviewed by
owner or owners to recover their fair share of the minerals in
the Coinni^ssion.
n
34
When Che exception sought is for the second or third well on
the lease, fair share must be proven as an element ot tne
confiscation case whenever insufficient acreage is assigned to
the well. When the applicant has assigned sufficient acreage to
the well but seeks a Rule 37 exception, the applicant need only
prove that the location is necessary due to surface or subsurface
conditions.
Subsurface
conditions
may
include
uncompensated
drainage from another tract, or the need for structural height or
greater net pay or other circumstances.
2.
Waste
To obtain an exception based on the prevention of waste an
applicant must show that due to unusual conditions concerning the
tract
unless
Tex
Co./
the ultimate loss of substantial hydrocarbons will occur
the
51'
exception
^09
134 Tex.
Co.,
178
ref'd.
is
S.W.2d 338
59,
S.W.2d 573
131
(Tex,
granted.
(1948),
S.W.
Civ.
Hawkins v. Texas Company,
146
Golf Land Co, v. Atlantic Refining
2d 73
(1939),
App.--San Antonio
Byrd v. Shell Oil
1944,
writ
w.o.m.).
As the Texas
Shell Oil Co.,
Supreme Court
139 Tex.
66, 161
stated
in
Railroad Commission v.
S.W.2d 1022, 1026 (1942), "There
must be some factual basis for classifying some applicants as
n
subject to the general spacing provisions of the rule and other
applicants as within the exception. This reasonable basis can
only be a showing of unusual conditions peculiar to the area
where the well is sought to be drilled - not testimony that would
be equally applicable to any other part of the field. Therefore,
in order to sustain the validity of the rule, we must give it the
construction that the exception is to be granted only upon a
showing of unusual conditions."
The
test
was
emphasized
in
Wrather v. Humble Oil & Refining
Company, 147 Tex. 144, 214 S.W.2d 112 (1948). "The waste excep
tion clause in Rule 37 has no application where ordinary or usual
conditions prevail. To justify an exception under that clause it
is necessary to show that the conditions affecting the drainage
of wells on a particular tract are so peculiar, unusual and
abnormal that it is removed rrom the same category of the sur
rounding area to which the general rule applies. VThen those
peculiar and unusual conditions are found to exist in a localized
n
area, exceptions may then be granted for the drilling of addi
tional wells to the extent necessary to offset the abnormality
and place it on parity, from the standpoint of efficient drain
age, with other areas where ordinary and usual reservoir condi
tions prevail."
Id at 117.
The Supreme Court in the
Commission,
571 S.W. 2d 497
conditions"
are not
limited
case of
Exxon Corporation v. Railroad
(1978),
seated that
"unusual
zo
subsurface
conditions
and may
include an existing wellbore when a new well drilled în compli
ance wi-h applicable spacing rules will not be drilled due to
economic
n
reasons.
35
As with all Rule 37 exceptions, the applicant must show that
no regular location is available which will satisfy the goal of
f
preventing waste or confiscation.
^
existence
The applicant should focus his or her efforts on proving the
field;
of
unusual
conditions,
not
present
throughout
the
the ultimate loss of substantial amounts of hydrocarbons
in the absence of an exception; and the necessity of the specific
proposed location.
A detailed discussion
of
establish various issues follows
the
types
of
evidence
used
to
the section on confiscation.
m
3.
Confiscation
Confiscation
^
can
result
from
either
a
Railroad
Commission
denial of a permit to recover hydrocarbons below a tract whose
owner is. entitled to a well or from drainage of hydrocarbons from
a tract caused by surrounding producing operators.
PI
„
Frequently the crucial issue in a hearing on confiscation is
whether or not t-he applicant is entitled to protection against
confiscation. Two types of tracts are not entitled to protection
against confiscation:
^
substandard acreage or to a shape incapable of supporting a
regular location after attachment of the applicable spacing
a.
rules)
Voluntary , subdivisions
(tracts
subdivided
to
and
n
b.
Substandard
capable of recoverying
tracts
whose
their fair
interest
__
neighboring tracts in which they hold an interest.-
"
Commission V. Williams,
163
Tex.
ovmers
share by means of wells
370,
356
(See
are
on
Railroad
S.W.2d 131 [1962].)
If
either of these conditions is established, the applicant may base
his application for an exception on waste, but not on confiscation,.
ri
An exception to the general prohibition against confiscation
exceptions for voluntary subdivisions is found in the Century
Doctrine. Railroad Commission of Texas V. Magnolia Petroleum Co., 130 Tex. 484 ,
109
^
(See Voluntary Subdivision Rule, above.)
S.W. 2d
holding
a
967
(1937).
substandard
Under
acreage
this
tract
theory,
or
an applicant
tract
incapable
of support a regular location which is a voluntary subdivision
may "reconstruct" the tract to its shape and size prior to the
attachment of spacing rules.
This reconstruction is merely
figurative.
The entire tract is reviewed to determine what the
owner would have been entitled to. The applicant need not obtain
leases on the additional tracts or bring them under common owner-
^
^
ship. If a well has not been drilled or permitted for the recon
stituted tract the applicant may request that the Railroad Com
mission issue a permit for the reconstituted tract on the basis
of prevention of confiscation.
Under this doctrine, the Commission may locate the well at any point on the reconstituted tract
that
n
36
the
evidence
indicates
will
best
protect
against
"
confiscation.
Not surprisingly, the applicant's evidence tends
to favor the applicant's tract in
of granting such a permit affects
the "êntire reconstituted tract, a
must be noticed as such, with all
this regard. Because the act
the development prospects or
Century Doctrine application
owners of minerals within the
reconstituted tract or their lessees receiving notice.
"
4. Exhibits Commonly Used to Prove Many of the Situations
Set Out Above
a.
Waste
(1) Physical:
The operator must prove that due to unusual con
ditions concerning the tract, a substantial amount of oil or gas
will ultimately be lost and that an irregular location is needed
to recover that oil or gas.
(a) Structure Maps
n
A structure map as used in a Rule 37 and/or
p
Rule 38 case is generally a contour map of the top of the produc-
ing formation.
This map may show faults and enable one to deter
mine structural dip.
This, type of map is most often used to show
that a proposed location is "up dip" or higher in structural
positions than existing wells. Especially in a water drive
n
reservoir, this is important because the highest structural well
will recover more oil and oil that no other well will recover.
(b) Isopachous Maps—
These maps generally show the areal extent or
the net porous interval. In conjunction with structural maps,
isopach maps reveal the structural location of the porous interval. For Rule 37 purposes, the structural location of the porous
interval will readily reveal ir a well is needed in a Rule 37
location to prevent waste.
These maps are constructed by determining the
n
net porosity-thickness of the zone via resistivity or porosity
logs ând constructing iso-thickness (isopach) contours for all
such logs which penetrate the zone.
(c) Structural Cross-Sections—
A structural cross-seccion generally consisns
of electric or porosity logs
chat are all referenced from^ a
common datum (usually sea level).
A structural cross-section
aids in the confirmation of a scruccure map and the nee produc
tive zone shown on isopachous maps.
Structural cross-sections
also show formation continuity from well to well.
(d) Drainage Maps—
These
maps
show
the
present
or
ultimate
drainage radii for wells in an area in a common zone. The drain
age radius calculation is based on reservoir parameters and can
be
(*l
done
for
a well's
cumulative production
to
date
or,
meaningfully, total expected cumulative production per well.
more
When the ultimate drainage radius of each
well is drawn around each well, areas may show up that no well
will drain.
The inference is that since no well will drain this
oil, including possible future wells at regular locations on
offset tracts, the subject well is necessary to avoid that ulti
mate loss. Such a finding will result in a waste exception only
in connection with proof of unusual conditions. It cannot be
assumed that all drainage is radial. In addition, radial drain
age analysis is of little value in fractured reservoirs.
(e) Fracture Trend or Seismic Maps—
A fracture trend map extrapolates ^seismic
data and well history and potential data to indicate a fracture
trend in an area.
This is of major importance to the Austin
Chalk formation which consists of fractured chalk.
A well en
countering the matrix alone will produce little oil because the
chalk has very low permeability.
A well that encounters a natu
ral oil bearing fracture will have very high permeability and
will produce the oil from that fracture.
Seismic cross-sections are processed seismic
data used by geophysicists to interpret faulting in a formation.
Seismic sections give a two dimensional, picture along ^the line
where they are shot. Geophysicists can interpret these fractures
for small distances off the shot line.
(2) Economic Factors in Physical Waste-
Cost data are generally used to show that a new
well is too costly to be economic but that a plug back or reentry
of an existing well bore at an
irregular location will result in
an economic completion.
When requesting use of an existing wellbore to
prevent waste, an applicant should shov? that the existing well
was
not a subterfuge to
get a later Rule 37 location.
Exxon Corporation V. Railroad Commission of Texas, 571 S.W. 2d
497 (Tex.
1978) .
b. Confiscation—
When confiscation refers to drainage, the^ applicant
must show movement of hydrocarbons across lease lines^.
All
fluids move from points of higher pressure to points of lower
pressure.
38
(1) structure Maps—
Structure
maps
show
that
structural
highs
are
located such that a spacing exception is necessary for the appli
cant to obtain his or her fair share of the hydrocarbons in the
reservoir.
(2) Drainage Maps—
As
discussed in
the Waste
Section,
drainage maps
indicate how much of an area has been drained to date or will be
drained eventually.
Typically, circles around the well bore are
used to depict the drainage.
When a drainage area encroaches
on another lease, drainage can be inferred.
age.
Circular drainage patterns refer to radial drain
Many formations do not exhibit radial drainage patterns.
One may not be able to tell just what is being drained in these
formations.
Even in non-radial drainage formations, however, the
absent overwhelming evidence to the contrary.
(3) Log Cross-Sections—
These are used to show the continuity of the
formation.
This is important in a confiscation case as one must
show that the same reservoir extends to the allegedly draining
well or wells.
Geologists and engineers correlate the logs be
tween wells and can postulate whether there is any break in the
continuity between wells.
(4) Pressure Data—
Pressure data can be used to show pressure sinks
and other variations when collected in such a manner as to make
comparisons meaningful. Pressure data may be used to indicate
the' presence of a water drive, and hence the likelihood of con
fiscation in the absence of an exception.
(5) Proration—
One effect of the proration system may be to cause
one part of a field draining another.
This is especially true in
fields where net acre-feet and gas-in-place determinations have
been made.
If one part^/ is getting more than thac person's
determined percentage of production from che field due to the
workings of the proration system, drainage can be inferred. Use
of Rule 3 7 and a confiscation exception to cure this problem is
39
generally inappropriate, as it results in proliferation of wells.
The proper cure is to ask for a new proration formula.
^
^
c. Exhibits-
Attached hereto are typical exhibits showing the fol-
lowing (each letter below corresponds to the letter found on the
exhibit):
(1)
Structure map
(2)
Isopachous map
(3)
Log cross section
(4)
Drainage map
(5)
Seismic cross section
(6)
Isobaric map
(7)
Economic waste calculations
n
p
n
n
40
Part Vn
Forced Pooling
A.
Definition
Chapter 102 of the Texas Natural Resources Code, generally
known as the Mineral Interest Pooling Act (MIPA) , authorizes the
Commission to force the pooling of adjacent tracts, upon request,
and under limited circumstances.
Pooling is performed ^for the
purpose of achieving proration units of the size called for in
the applicable field rules.
^
Considering the act's limited applicability and built-in
constraints,
wm
it
is
definitely not a
cure-all for operators or
mineral o^mers with substandard acreage.
The act does,^ aowever,
provide a useful tool to eligible applicants for avoiding the
drilling of unnecessary wells, protecting correlative rights, or
preventing waste. The act is presently codified in TEX. NAT.
RES. CODE ANN. §§ 102.001 to 102.112 (1978).
n
B.
n
Eligibility
The applicability of the Act to various interest holders is
not
settled.
The
Commission
presently
interprets
the
Act
as
follows.
The following persons may apply for forced pooling:
^
1.
With respect to an existing unit,
including a royalty owner and
any interest owner
n
2.
With respect to a proposed unit, the owner of any
working interest or the owner of an unleased tract, other than a
royalty interest. A person who owns a royalty interest alone can
apply for forced pooling only in an existing unit.
Forced pooling is not available to reservoirs discovered and
produced prior to March 8, 1961. Applicants for forced pooling
should check the discovery date listed by the Commission for a
^
given field before applying to force pool in that field.
„
owned by the State of Texas or land in which the stace has a
The Mineral Interest Pooling Act specifically exetipts land
direct or indirect interest.
Such lands are subject to the act
only with the consent of the Commissioner of the General Land
Office or other board or agency having jurisdiction.
The act may be employed only in fields for which field rules
have been promulgated by the Commission. Forced pooling is not
n
available in wildcat areas or in fields subject only to statewide
spacing rules.
The act cannot be used to force pool an unleased mineral
owner of a tracc by a leased mineral owner of the same -ract or
49
his lessee.
However, a lessee or co-tenant may
unleased owner with an adjacent uract.
See TEX.
ANN.
§ 102.011 requiring that
there be
two
force pool the
NAT. RES. CODE
or more
separately-
owned t r a c t s .
C.
Limitations
Forced pooling cannot be used to achieve a proration unit in
excess of that provided for in the field rules or, in any case,
in excess of 160 acres for oil or 640 acres for gas plus 10
percent tolerance.
The Commission is prohibited from force pooling the owner of
productive acreage thac is equal to or in excess of the standard
proration unit size for the reservoir, unless the forced pooling
is requested by a person who holds productive acreage smaller
than the standard proration unit size and that person has not
been provided a reasonable opportunity to pool voluntarily.
If
these conditions are met, the Commission may pool the smaller
acreage with the adjacent large acreage and may authorize a
larger than standard allowable for the unit if the resulting unit
is greater than the standard proration unit size for the
reservoir.
The Commission may pool only acreage which, at the time of
the Commission order, reasonably appears to be within the produc
tive limits of- the reservoir.
The burden is upon the applicant
requesting the forced pooling to show that all of the acreage to
be included in the proposed unit is productive in the common
reservoir.
If this burden is not met as to some of the requested
acreage, the Railroad Commission may order the pooling of an
amount of acreage less than requested by the applicant, so only
productive acreage is included in the resulting unit.
D.
Applying for Forced Pooling
The Commission cannot, upon its own motion, order forced
pooling.
The Commission may order forced pooling only upon
application.
Application for forced pooling may be made only after the
applicant has made a reasonable offer for voluntary pooling to
the owners of interests in the subject tract(s) and that offer
has been rejected.
Once the offer has been rejected and the applicant has
determined that he or she is eligible for forced pooling, the
applicant should write to the Oil and Gas Division requesting
that a hearing be scheduled on a forced pooling request for the
subject tracts. There is no prescribed form for the application.
The request should recire that a reasonable offer was made and
rejected and should include the terms of the rejected offer.
The
offer will be examined by the Commission. The application should
describe the tracts to be pooled and identify all interest owners
in those
50
tracts.
The application will be reviewed by an examiner and, if
appropriate, will be set for hearing. Forced pooling may be
ordered only after notice and hearing.
The applicable statute requires that at least 30 days notice
of the hearing be given on an application for forced pooling.
Note
that
this
time period is
greater
than the minimum time
period required for all other hearings held by the Oil and Gas
Division.
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^
The applicant must supply to the Commission a list of inter
ested parties entitled to notice. This list must include all
mineral owners, operating or working interest owners and all
royalty owners for the applicant's tract and the tract(s) to be
force pooled.
Notice to these parties will be issued by the
Commission.
m
When
all
interest
holders
cannot
be
located,
the
applicant must utilize notice by publication. Notice by publica
tion is the responsibility of the applicant. If published notice
is not properly given, the hearing will be dismissed. Publica-
^
^
" tion must be made in a newspaper of general circulation in the
county where the subject property is located or, if there is no
^
secutive weeks, the first date of publication to be at least 30
days before the set hearing date.
such newspaper in that county, in a newspaper of an adjoining
county. The notice must be published once each week for 4 con-
An affidavit of publication made by the publisher and a
printed copy of the publication should be directed to the Commis
^
sion office in Austin prior to the hearing date, to be made a
part of the record.
E.
Forced Pooling Orders
The Commission may order forced pooling on-ly to accomplish
one or more of three purposes; avoiding the drilling of unneces
sary wells, protecting correlative rights or preventing waste.
^
Any order issued by the Commission must afford each owner of
an interest in the unit the opportunity to produce or receive his
or her fair share of production from the reservoir. The order
generally must provide that production from the pooled unit shall
be
allocated
to
the
individual
tracts
within
the
unit
in
the
proportion that the number of surface acres of each tract bears
1-^
to the total number of surface acres in the entire unit.
How
ever, if the Commission finds that this surface acreage allo
cation does not allocate a fair share to each tract,
^
the Commis
sion may allocate production on some other basis, provided that
no non-consenting owner shall receive less than that owner would
have received under a surface acreage allocation.
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est
When a working interest owner as opposed to a royalty inter
owner is force pooled inzo a unit, he is liable for his
proportionate share of the drilling and completion costs whether
M
or not
che well has
already been drilled.
A working
interest
51
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owner may elect to pay his share of costs in advance rather than
out of production proceeds.
of the costs may,
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^
The working interest owner's share
in the alternative, be taken out of his share
of the proceeds, so that he will not begin receiving a share of
the proceeds of the well until his share of proceeds has exceeded
his share of the cost plus the risk penalty. If a working inter
est owner elects to pay his share of costs out of his share of
proceeds, the Railroad Commission may assess a risk penalty
against the working interest owner who is force pooled. The risk
penalty may not exceed 100 percent of the drilling and completion
costs.
This means
that the force pooled working interest owner
may be required to pay up to twice his proportionate share of the
drilling and completion costs out of his share of the proceeds
before he can begin to receive the proceeds from the well.
Royalty interests are not subject to a risk penalty or assessment
of
costs.
pa*
The Commission does not always assess the maximum risk
penalty.
The Commission is authorized to determine the proper
costs of drilling and completion if there is a dispute between
the parties.
Production from any portion of the force pooled unit will be
considered production from each separately owned tract within the
pooled unit for purposes of maintaining leases. The terms of the
individual leases on the various
tracts
included within the unit
will determine. whether portions of an individual tract that are
not included in the unit will be held by production on the unit.
In other words, a Pugh Clause in an individual lease will control
as to that lease. (A "Pugh Clause" is a clause in a lease which
provides that upon expiration of the primary term, the lease will
remain in effect only for acreage which has been assigned to
producing wells.)
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F.
n
Forced Pooling Hearings
The Commission in a hearing on forced pooling will require
evidence or testimony on a number of issues in addition to those
of waste, correlative rights or avoiding unnecessary wells.
These issues involve satisfaction of statutory requirements as
earlier discussed and the protection of represented or unrepre
sented
interests.
The following questions included below must be addressed in
each hearing.
1.
Were
all
interested
parties
given
at
least
30
days
notice of the hearing on the application by actual notice or by
newspaper publication?
2.
Was the subject reservoir discovered and first produced
after March 8, 1961?
3.
52
Does all of the acreage to be included in the proposed
^
unit reasonably appear to lie within the productive limits of the
subject reservoir?
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4.
Are two or more separately owned tracts of land em
braced by the proposed unit?
5.
Has an offer been made by the applicant to all ovmers
of all subject tracts to pool their interests voluntarily?
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6.
Was that offer a fair and reasonable one?
(Note:
The
application will be dismissed by the Commission if _the oifer is
not found to be fair and reasonable.
r-i
In the case o£ an existing
proration unit, the Commission will find an offer to be fair and
reasonable if the offer was to share on the same yardstick basis
^
as the other owners within the existing proration unit are then
sharing.)
7.
Will the establishment of the proposed unit afford to
each interest owner within such unit receipt of its fair share of
^
the production?
^
interest?
8.
Are
lands
involved
in
which
the
state
holds
an
If so, has the proper authority consented to forced
pooling?
9.
Does the offer to pool or operating agreement contain
^
any of the following provisions:
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mineral interests in the unit;
^
the unit;
a.
preferential right of the operator to purchase
b.
a call on or option to purchase production from
c.
operating charges that include any part of dis
trict or central office expense other than reasonable overhead
^
charges; or
fm
operation of the unit.
^
agreement will not be found to be fair and reasonable.
d.
prohibition against nonoperanors questioning the
If any such provision is includec, the offer or operating
With the exception of numbers three and seven above, evi
dence to answer these questions is primarily documentary, i.e.
leases and assignments to indicate ownership of interests, affi
davits of publication to establish notice, etc.
^
Evidence on the primary issues of waste, correlative rights
or avoiding unnecessary wells will be similar to that used
P.ule 37 and Rule 38 hearings. Refer to the explanation of useful
evidence
at
the
conclusion
of
that
Section
for
evicentiary
considerations.
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53
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Appeal from a Railroad Coiranission ruling on forced pooling
is
to the District Court for the area where the subject tracts,
or parts thereof, are located and not necessarily to the District
Court in Travis County.
PI
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54
Part Vm
Unitization
A.
Definition
Unitization is consolidation of tracts on a field-wide basis
or, where the field is quite extensive, on a partial field basis.
Unitization is generally used for purposes of effecting secondary
recovery.
The need for unitization in secondary recovery opera
tions is readily apparent.
A waterflood of a field, for example,
^
will cause water and hydrocarbons to cross from one lease to
another.
Without agreement of the majority of the interest
owners in the field, the operator injeccing the water might
become the subject of numerous lawsuits for damages for drainage
of a lease caused by the operator.
"
unitizations are codified in TEX.
to 101.052.
^
The statutes granting the Railroad Commission authority over
B.
p-
RES.
CODE AWN.
§§ 101.001
The Commission's Authority and Criteria for Approval
Unitization can be accomplished only by voluntary action of
the parties involved. The Commission cannot compel any interest
owner to join in unitization.
hearings
to
approve
unitization.
H
NAT.
the
The Railroad Commission does hold
secondary
recovery
project
and
the
The Commission will require that the unitization
agreement provide that'participation of each interest owner will
be based on the same factors or parameters as every other inter
est owner's participation, such as by proportionate share in the
surface
rm
acres,
in
net-acre-feet,
combination of factors,
in
past
production,
or
some
including use of different factors for
different phases of the project.
It is rare for a lease to authorize the lessee to enter into
a unitization agreement without the consent of the mineral inter
est owner. Thus, in seeking to effect unitization, the royalty
owners as well as the operators or working interest owners niust
-ng
before
the
.
Commission
will
call
.
a
hearing
to
approve
the
unitization
If joinder is less than 100 percent of the interest owners,
^
the Railroad Commission will still approve the unitization if it
finds that it will prevent waste and that the cost of the secon
dary recovery project will not be greater than the worth of the
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additional hydrocarbons that will be recovered.
_
To be effective, the unitization agreement must be filed in
the courthouse of the county in which the land is located.
00
The Commission will require chat any production through a
well on a lease with non-joining owners must be measured and
reported separately from unit production.
Payments to those
owners
should
continue
to
be
made
on
a
Commission will not permit unit operators
lease
basis.
The
to convert a non-con
senting landowner's last producing well to an injection well.
Commission approval of
of the primary advantages
Agreeunitizations is immunity from the stace's antitrust laws.
Agree
ments, however, may not provide for cooperative refining or
marketing of the hydrocarbons produced. Commission approval does
not force nonconsenting owners inco the agreement.
Agreements
for unitizations and cooperative facilities do not bind a land
owner, royalty owner, lessor, lessee, overriding royalty owner,
or any other person who does not execute them..
The agreements
bind only the persons who execute them, their heirs, successors,
assigns and legal representatives.
Agreements which attempt to regulate spacing or production
or in other ways attempt to contain or supercede the requirements
of the Commission will not be approved.
C.
Obtaining Approval
An applicant may request approval of a specific unitization
agreement by writing to the Oil and Gas Division and asking that
a hearing be held on the proposed agreement. The percentages of
working and royalty interests participating should be indicated
in the request. The application should also include a list or
all interest owners, surface owners, offset operators, and their
addresses.
In
addition
to
the
considerations
discussed
above,
the
following issues will be examined in a hearing on a unitization:
1.
Does
all
acreage
covered by
the
proposed unit
rea
sonably appear to be productive from the subject reservoir(s)?
2.
Have all the owners of interests in oil and gas in the
area to be affected been given an opportunity to enter into the
unit on the same yardstick basis as the owners of interests :Ln
the oil and gas under tracts included in the unit?
3.
Is
the
unitization
reasonably
necessary
to
prevent
waste or promote conservation of oil or gas or both?
As with hearings on forced pooling, evidence will be either
documentary (when relating to ownership of interests or conten"
of agreements) or geological (testimony or prepared exhibits
addressing issues of structure, drainage, etc.).
For a dis
cussion
of
this
latter
type
of
evidence,
see
the
secnion
on
evidence a- the conclusion of the segment on Rule 37 and Rule 38
exceptions (Part VI, Section F[4]).
Applicants should review TEX. NAT. RES. CODE
. §101.013
(1978) before requesciag a Commission hearing on unicizacion.
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•
Entity-for-Density Purposes
Tn waterflood or enhanced recovery projects, operators may
"
reauer-' thaC che unit be desigtiacad as an encity-ior-densLcy
Dufposes.
Onics designaced as such are assignea special spacing
rules chat permic flexibility in producing and evaiuacing Che
"
injection project for maxiniuiii recovery.
m
'
"^he
densitv
orovision
ror
entit3-es-ror-density
purposes
s-fmplv provides that overall density for the unit may notêxceec
one* well for the number of acres in a prcration unit appi.LcaDie
to the field.
^
3e"ween-well suacing is
generally ' notare
applicable to entit:.es
for density purposes as long
as wells are located bevona ttie
minimum specified distance from tne unit boundary
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d7
§3
RULE 5. APPUCATION TO DRDLX, DEEPEN, REENTER, OR PLUG BACK.
(Amended Effective September 1, 1992)
(a) Permit requirements for spacing, density and units. An application for a permit to
drill, deepen, plug back, or reenter any oil well, gas well, or geothermal resource well, shall
n
^
be made under the provisions of §§ 3.37, 3.38, 3.39 and/or 3.40 of this title (relating to
Statewide Spacing Rule; Weil Densities; Prorarion and Drilling Units: Contiguity of Acreage
and Exception Thereto; and Assignment ofAcreage to Pooled Development and Proration
Units) (Statewide Rules 37, 38, 39 and 40), or as an exception thereto, or under special rules
governing any panicular oil, gas, orgeothermal resource field or as an exception thereto and
filed with the Commission on a form' approved by the Commission. An application must
"
be accompanied by any relevant information, form or cenification required by the Railroad
Commission or a Commission representative necessary to determine compliance with this
rule and state law.
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(b) Definitions. The following words and terms, when used in this section, shall have the
following meanings, unless the context clearly indicates otherwise.
(1) Application - Request by an organization on the appropriate form for a permit to
drill, deepen, plug back, or reenter any oil well, gas well, or geothermal resource well.
(2) Connnission - The Railroad Commission of Texas.
(3) Commission representative - A Commission employee authorized to act for the
Commission. Any authority given to a Commission representative is also retained by the
^
Commission. Any action taken by the Commission representative is subject to review by
the Commission.
(4) Organization - Any person, firm, pannership, joint stock association, corporation,
or other organization, domestic or foreign, operating wholly or panially within this state,
acting as principal or agent for another, for the purpose of performing operations within
t-!
the jurisdiction of the Commission.
^
that the organization has committed a violation and all appeals have been exhausted or an
agreed order entered into by the Commission and an organization relating to an alleged
(5) Outstanding final order- Either a Commission order against an organization finding
violation, where:
(A) the conditions that constituted the violation or alleged violation have not been
corrected;
' W-i I,Application to Drill. Deepe.i. Plug Back, or Re-enter)
n
(B) all administrative, civil and criminal penalties, if any, relating to the violation or
agreed settlement relating to an alleged violation have not been paid; or
(C) all reimbursements of costs and expenses, if any, assessed by the Commission
relating to the violation or to the alleged violation have not been collected.
(6) Positdon of ownership or control -Aperson holds aposition of ownership or control
in an organization if the person is:
n
(A) an officer or director of the organization;
(B) a general partner of the organization;
(C) the owner of an organization which is a sole proprietorship;
n
(D) the owner of more than a 25 percent ownership interest in the organization; or
(E) the designated trustee of the organization.
n
(7) Violation - Non-compliance with Title 3, Texas Natural Resources Code, or a
Commission rule, order, license, permit, or certificate relating to safety or the prevention
or control of pollution.
(c) Organization eligibility to ffle an application. The Commission may not accept an
^
apphcation from an organization, if within the five years preceding the date on which the
apphcation is filed:
(1) the applicant organization has any outstanding final orders against it; or
^
(2) any person holding aposition of ownership or control in the applicant organization
„
also has held a position of ownership or control in any organization, including the appHcant
organization, registered with the Commission that has an outstanding final order against
it relating to a violation during that period of ownership or control.
m
(d) Compliance certification.
pi
(1) The Commission or a Commission representative may require an applicant
organization to file a comphance certification. The cenification shall include a statement
that within the last five years:
n
(A) The apphcant organization has no outstanding final orders against it; and
(B) no person in a position ofownership or control of the apphcant organization has
held a position of ownership or control in any organization, including the named
«
10
organization, that has an outstanding final order against it relating to a violation during
that period of ownership or control.
_
(2) Failure to file a required certification will delay or prevent approval of the
application. Knowingly filing a false certification may be a violation of the Texas Natural
Resources Code § 91.143 and may also subject a permit to denial or revocation. A permit
that is issued on the basis of a certification statement that is later determined to be
incorrect is also subject to revocation.
(3) If the cenificarion is signed by an agent of an applicant organization, the
certification is binding on the agent and the organization as if signed by a person holding
a position of ownership or control in the organization.
(e) Commencement of operations. Operations of drilling, deepening, plugging back, or
reentering shall not be commenced until the permit has been granted by the Conmiission
and the waiting period, if any, has terminated, or authorization has been granted pursuant
to subsection (f) of this section.
(f) Testing of existing wells in other reservoirs inside the casing. For an existing well, an
operator may request authorization to commence operations to deepen inside the casing or
plug back prior to the granting of a permit to deepen or plug back.
(1) This authorization shall be requested by filing with the District Office a letter of
intent to deepen inside the casing or plug back. The letter shall include:
(A) the operator name;
(B) the lease name;
ri
(C) the lease number or gas identification number;
^
(D) well number;
(E) county;
(F) field name:
(G) a list of all reservoir(s) to be tested;
(H) the casing setting depth and the depth of the deepest reservoir to be tested;
(I) a plat showing the weU location; and
11
(J) a statement as to whether or not the well location would require an exception to
§§ 3.37, 3.38, 3.39 and/or 3.40 of this title (relating to Statewide Spacing Rule; Well
Densities; Proration and Drilling Units: Contiguity of Acreage and ^ception Thereto;
and Assignment of Acreage to Pooled Development and Proration Units) (Statewide
Rules 37, 38, 39 and 40) if completed in any of the reservoirs to be tested. If an
exception would be required, the letter of intent shall also include a statement that all
affected offsets have been given written notice of the intent to test with the opponunity
to witness the testing and the offsets shall be identified on the plat.
(2) Operations of deepening inside the casing or plugging back shall not be commenced
until the District Office has reviewed and signed the letter of intent. Testing pursuant to
this authorization shall be completed within 90 days from the date the District Office signs
the letter of intent.
(A) No reservoir tested pursuant to the provisions of this subsection shall be tested
for more than 15 davs.
n
(B) If the operator desires to place the well on production, the operator shall shut-in
the well, with no production being sold, and file a permit application for the tested
reservoirs with the appropriate fees. If the permit application for the tested reservoirs
requires an exception to § 3.37, 3.38, 3.39 and/or 3.40 of this title (relating to Statewide
Spaping Rules; Well Densities; Proration and Drilling Units: Contiguity of Acreage and
Inception Thereto; and Assignment of Acreage to Pooled Development and Proration
n
Units) (Statewide Rules 37, 38, 39 and 40), no consideration will be given by the
Comimission to the cost of recomputing and testing the well in determining whether or
not to grant the exception.
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(C) Within 30 days of completion of testing, the operator must either file an
application for a permit to produce a reservoir tested pursuant to this subsection or file
an amended completion report in accordance with § 3.16of this title (relating to Log and
n
Completion of Plugging Repon) (Statewide Rule 16) with a copy of the intent to test
signed by the District Office and a statement that a permit to produce a tested reservoir
is not being sought, or if the well has been plugged and abandoned, a plugging report
including reservoir and perforation data. If a permit is not obtained for the tested
reservoirs and/or an allowable is not assigned, the producer shall report all test
"
production in the producer's monthly report filed for the last permitted reservoir in
which the weU was completed and may request authorization to sell the test production.
The test production may be sold after such authorization is granted.
n
^
(g) Exploratory and specialty wells. An application for any exploratory well or cathodic
protection well that penetrates any protection depth, fluid injection well, injection water
source weU, disposal well, brine solution mining well, or underground hydrocarbon storage
well shall be made and filed with the Commission on a form approved by the Commission.
Operations for drilling, deepening, plugging back, orreentering shall not be conraienced until
12
the permit has been granted by the Commission. For an exploratory well, an exception to
filing such form prior to commencing operations may be obtained if an application for a core
hole test is filed with the Commission.
(h) Exception permits. If an application for a permit presents a question ofan exception
to the applicable densiry rule as well as an exception to the spacing rule, the operator
seeking a spacing and density exception must obtain such an exception as required under
p
the applicable spacing and density rules.
(i) Drilling permit fee. With each application or materially amended application, the
applicant shall submit to the Commission a nonrefundable fee as determined by § 3.76
(relating to Fees, Bonds, and Alternative Forms of Financial Security Required to be
Filed)(Statewide Rule 78).
r-l
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§ 3.11. RXJUE 11- INCLINATION AND DIRECTIONAL SURVEYS REQUIRED.
(Amended Effective May 23, 1990)
(a) General. All wells shall be drilled as nearly vertical as possible by normal, prudent,
practical drilling operations. Nothing in this section shall be construed to permit the drilling
of any well in such a manner that the wellbore crosses lease and/or property lines (or unit
lines in cases of pooling) without special permission.
(b) Inclination surveys.
(1) Requirements.
(A) An inclination survey made by persons orconcerns approved by the Commission
shall be filed on a form^ prescribed by the Commission for each well drilled or deepened
with rotary tools, except as hereinafter provided, or when, as a result of any operation,
the course of the well is changed. The first shot point of such inclination survey shall be
made at a depth not greater than 500 feet below the surface of the ground, and
succeeding shot points shall be made either at 500-foot intervals or at the nearest drill
bit change thereto, but not to exceed 1,000 feet apart.
(B) Inclination surveys conforming to these requirements may be made either during
the normal course of drilling or after the well has reached total depth. Acceptable
directional surveys may be filed in lieu of inclination surveys.
(Q Copies of all directional orinclination surveys, regardless ofthe reason for which
they are run, shall be filed as a part ofor in addition to the inclination surveys otherwise
required by this section. Ifcomputations are made from dipmeter surveys to determine
the course of the wellbore in' any portion of die surveyed interval, a report of such
computations shall be required.
(D) Inclination surveys shall not be required in any well drilled to a total depth of
2,000 feet or less on a regular location at least 150 feet from the nearest lease line,
provided the well is not intentionally deviated from the vertical in any marmer
whatsoever.
(E) Inclination sui-veys shall not be required on wells deepened with rotary tools ifthe
well is deepened no more than 300 feet or the distance from the surface location to the
nearest lease or boundary line, whichever is the lesser, and provided that the well was
not intentionally deviated from the vertical at any time before or after the beginning of
deepening operations.
W-12 (Inclinaiion Rcpon)
44
M
i-n
«
(F) Inclination surveys will not be required on wells that are drilled and completed
as dry holes and are permanently plugged and abandoned. If such wells are reentered
at a later date and completed as producers or injection or disposal wells, incUnation
reports will be required and must be filed with the appropriate completion form for the
well.
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"
(G) Inclination survey Slings will not be required on wells that are reentries within
casing of previously producing wells if inclination data are already on file with the
Railroad Commission of Texas (Commission). If such data are not on file with the
Commission, the results of an inclination survey must be reponed on the appropriate
form and filed with the completion form, except as provided by subparagraph (D) of this
paragraph.
(2) Reports.
(A) The repon fonn shall be signed and certified by a party having personal
knowledge of the facts therein contained. The repon shall include a tabulation of the
maximum drifts which could occur between the surface and the first shot point, and each
two successive shot points, assuming that all of the unsurveyed hole between any two
shot points has the same inclination as that measured at the lowest shot point, and the
total possible accumulative drift, assuming that all measured angles of inclination are in
the same direction.
(B) In addition, the repon shall be accompanied by a certified statement of the
operator, or of someone acting at his direction on his behalf, either:
rf
(i)
that the well was not intentionally deviated from venical; or
(ii)
that the well was deviated at random, with an explanation of the
circumstances.
(C) The report shall be filed in the District Office by attaching one copy to each
appropriate completion form for the well.
(D) Tne Commission may require the submittal of the original chans, graphs, or discs
n
resulting from the surveys.
(c) Directional surveys.
(1) When required.
(A) When the maximum displacement indicated by an inclination survey is greater
than the actual distance iTora the surface location to the nearest lease line or pooled unit
boundary, it wiU be considered lo be a violating well subieci to plugging and to penalty
45
I
action However, an operator may submit adirectional survey, run at his o^
bv aCommission-approved surveying company, to show the true bottomed hole location
of th?" ê E the presc^'ed Jits. When such directional sumy shows the
weU to be bottomed within the confines of the lease, but nearer to awell or leê toe
or pooled unit boundary than allowed by appUcable nile^ or by the
th^weU has been grated an exception to §3J7 of th,s title (relanng to Statewde
Spacing Me), anew^^nnit will be required if it is established that the bottom hole
location or completion location is not a reasonable location.
(B) Directional suirveys shall be required on each weU drilled under die directional
deviation provisions of this section.
m
(O No on, gas, or geothennal resource aUowable shall be assigned any weU on which
aSectional survey is required under any provision of this section until adirectional
survey has been ffled with and accepted by the Commission.
n
(2) Filing and type of survey.
rA) Directional surveys required under this section must be run by competent
surveying companies, aoproved by the Commission, signed and cenified by a person
h^faLal Lwledge of the fects, in the manner prescribed by the Comîon m
with §3.12 of this title (relating to Direcnonal Survey Company Repon).
(B) All directional surveys, unless otherwise specified by the Commission, shall be
either single shot surveys or multi-shot surveys with the shot pomts not more than 200
n
feet apart, beginning within 200 feet of the surface, and the bottom hole location must
be oriented both to the surfece location and to the lease lines (or umt Imes mcases of
pooling).
rC) If more than 200 feet of surface casing has been run, the operator may bcîhc
directional survev immediately below the surface casing depth. However, if such method
is used, the inclination drifts from the surface of the ground to the
must be added cumulatively and reponed on the appropnate form. Tlus total shaU be
assumed to be in the direction least favorable to the operator, and such pomt shall b
considered the staning point of the directional survey.
(d) Intentional deviation ofwells.
(1) Definitions.
(A) Directional deviation-The intentional deviation of a well from vertical in a
predetermined compass direction.
46
in
(B) Random deviation-The intentional deviation of awell without regard to compass
direction for one of the following reasons:
(i)
to straighten a hole which has become crooked in the normal course of
drilling;
(ii)
to sidetrack a portion of a hole because of mechanical difficulty in drilling.
(2) When pennittecL
(A) Directional deviation. Apermit for directionally deviating a well may be granted
by the Commission:
(i)
for the purpose of seeking to reach and control another well which is out of
control or threatens to evade control;
(ii)
where conditions on the surface of the ground prevent or unduly complicate
the drilling of a well at a regular location;
(iii) where conditions are encountered underground which prevent or unduly
hinder the normal completion of the well;
(iv) where it can be shown to be advantageous from the standpoint of mechanical
operation to drill more than one well from the same surface location to reach the
productive horizon at essentially the same positions as would be reached if the several
wells were normally drilled from regular locations prescribed by the well spacing rules
in effect;
(v)
for the purpose of drilling a horizontal drainhole; or
(vi) for other reasons found by the Commission to be sufficient after notice and
hearing.
(B) Random deviation. Permission for the random deviation of awell may be granted
by the Commission whenever the necessity for such deviation is shown, as prescribed in
paragraph (3)(C) of this subsection.
(3) Applications for deviation.
(A) Applications for wells to be directionally deviated must specify on the application
to drill, and on the plat anached, both the surface location of the weU and the target
area within which the bottom hole location is to be made.
47
(B) If the necessity for directional deviation arises unexpectedly after drilling has
begun, the operator shall give written notice by letter or telegram of such necessity to
the appropriate District Office and to the Commission office in Austin, and upon giving
such notice, the operator may proceed with the directional deviation. If the operator
proceeds with the drilling of a deviated well under such circumstances, he proceeds at
his own risk. Before any allowable shall be assigned to such well, a permit for the
subsurface location ofeach completion interval shall be obtained from the Commission
under the provisions set out in the Commission rules. However, should the operator fail
to show good and sufficient cause for such deviation, no permit will be granted for the
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well-
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(C) If the necessity for random deviation arises unexpectedly after the drilling has
begun, the operator shall give written notice by letter or telegram of such necessity to
the appropriate District Office and to the Commission office in Austin, and, upon giving
^
such notice, the operator may proceed with the random deviation, subject to compliance
with the provisions of this section on inclination surveys.
(e) Surveys on request of other operators. The Commission, at the written request of any
operator in a field, shall determine whether a directional survey, an inclination survey, or any
other type of survey approved by the Commission for the purpose of determining bottom
hole location of wells, shall be made in regard to a well complained of in the same field.
(i) The complaining party must show probable cause to suspect that the well
complained of is not bottomed within its own lease lines.
^
(2) The complaining party must agree to pay all costs and expenses of such survey, shall
assume all liability, and shall be required to post bond in a sufficient sum as determined
by the Commission as security against all costs and risks associated with the survey.
(3) The complaining pany and the Conmiission shall agree upon the selection of the
well surveying company to conduct thesurvey, which shall be a surveying company on the
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Conmiission's approved list.
^
party, or his agent, who has an interest in the field.
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(5) Nothing in these rules shall be construed to prevent or limit the Commission, acting
on its own authority, from conducting spot checks and surveys at any time and place for
the purpose of determining compliance with the Commission rules and regulations.
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(f) Penalties,
(4) The survey shall be witnessed by the Commission, and may be wimessed by any
(1) False reports. The filing of a false or incorrect directional survey shall be grounds
for cancellation of the well permit, for pipeline severance of the lease on which the well
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48
l
j
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\
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is located, for penalty action under the applicable statutes, and/or tor such other and
funher action as may be appropriate.
(2) Other- The same penalties and actions as set fonh in paragraph (1) of this
subsection shall be assessable against any operator who refuses to comply with a
Commission order which issues under subsection (e) of this section.
49
§3.1Z RULE 12. DIRECTIONAL SURVEY COMPANY REPORT.
(a)
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For each well drilled for oil, gas, or geothermal resources for which a directional
survey report is required by rule, regulation, or order, there shall be prepared and filed the
following information. The information shall be certified by the person having personal
knowledge of the facts, by execution and dating of the data compiled:
(1) name of surveying company;
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(2) name of person performing the survey for the company;
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(3) the position the person holds with the company;
(4) the date on which the survey was performed;
(5) type of survey conducted and whether multi-shot;
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(6) a complete identification of the well so as lo include the name of the operator of
the well; the fee owner; the Commission lease number, if assigned; the well number; the
land survey; the field name; and the county and state;
(7) survey conducted from a depth of
(b)
feet to
feet.
Each directional survey, with its accompanying cenification and a certified plat on
which the bottom hole location is oriented both to the surface location and to the lease lines
(or unit lines in case of pooling) shall be mailed by registered or cenified mail direct to the
Commission in Austin by the surveying company making the survey.
50
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§337. RULE 37. STATEWIDE SPACING RULE.
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(a) Distance requirements.
(1) No well for oil, gas, or geothermal resource shall hereafter be drilled nearer than
1,200 feet to any well completed in or drilling to the same horizon on the same tract or
farm, and no well shall be drilled nearer than 467 feet to any property line, lease line, or
subdivision line; provided the Commission, in order to prevent waste or to prevent the
confiscation of property, may grant exceptions to permit drilling within shoner distances
than prescribed in this paragraph when the Commission shall determine that such
exceptions are necessary either to prevent waste orto prevent the confiscation ofproperty.
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(2) When exception to this section is desired, application shall be made by filing the
proper fee as provided in §3.76 of this title (relating to Fees Required To Be Filed) and
the appropriate form' according to the instructions on the form, accompanied by a plat
as described in subsection (c) of this section. For each adjacent tract and each tract nearer
to the well than the prescribed minimum lease-line spacing distance, the applicant shall file
a list of the mailing addresses of all affected persons, who include:
(A) the designated operator;
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(B) all lessees of record for tracts that have no designated operator; and
(C) all owners of record of unleased mineral interests. Such application shall be
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cenified by some person acquainted with the facts, stating that all facts therein are true
and within the knowledge of such person and that the accompanying plat is accurately
drawn to scale and correctly reflects all pertinent and required data.
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(3) .Aji exception may be granted pursuant to subsection (h)(2) ofthis section, or after
a public hearing held after at least 10 days notice to all persons described in subsection
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(aX-) ot
section. At any such hearing, the burden shall be on the applicant to
establish that an exception to this section is necessary either to prevent waste or to prevent
the confiscation of property. For purposes of giving notice of an application for an
^
exception, the Commission will presume that every person described in subsection (a)(2)
of this section will be affected by the application, unless the Oil and Gas Division Director
or the director's delegate determines they are unaffected. Such determination wiU be made
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only upon written request and a showing by the applicant that:
(A) competent, conclusive geological or engineering data indicate that no drainage of
hydrocarbons from the particular tract(s) subject to the request will occur due to
^ W-l Application to Drill. Deepen. Plug Back, or Re-enter)
12'
production from the applicant's proposed well; and
(B) notice to the panicular operator(s), lessee(s) of record, or owner(s) of record of
unleased mineral interest would be unduly burdensome or expensive.
(b) The distances mentioned in subsection (a) of this section are minimum distances to
provide standard development on a pattern of one well to each 40 acres in areas where
proration units have not been established.
(c) In filing the form, as hereinabove provided, applicant shall attach a plat to each copy
of the form. The plat shall be drawn preferably to the scale of one inch equaling 1.000 feet;
however, scales of one inch equaling 500 feet or one inch equaling 2,000 feet will be
accepted. On request and approval bythe Division Director or the director's delegate, other
scales may be accepted based on unusual circumstances. The plat must accurately show to
scale the property on which the exception is sought; all other completed, drilling, or
permitted wells in the same field(s) on said property: and all adjoining surrounding
propenies and completed wells in the same field(s) within the prescribed minimum
between-well spacing distance of the applicant's well. The plat must show the entire lease
or unit, indicating the names and offsetting properties of all adjacent offset operators and
unleased mineral interest owners, and all operators and unleased mineral interest owners
of tracts nearer to the well than the prescribed minimum lease-line distance requirement.
For exceptionally large leases or units, an applicant, on request and approval by the Division
Director or the director's delegate, may file one plat of the entire lease or unit with the
initial application only. In subsequent applications for the same lease or unit, such applicant
shall reference this plat, and file only that ponion of the plat containing the drilling unit and
well site that are the subject of the subsequent application.
(d) In the interest of protecting life and for the purpose of preventing waste and
preventing the confiscation of property, the Commission reserves the right in particular oil,
gas, and geothermal resource fields to enter special orders increasing or decreasing the
minimum distances provided by this section.
(e) No well drilled in violation of this section without special permit obtained, issued, or
granted in the manner prescribed in said section, and no well drilled under such special
permit or on the Commission's own order which does not conform in all respects to the
terms of such permit shall be permitted to produce either oil, gas, or geothermal resources
and any such well so drilled in violation of said section or on the Commission's own order
shall be plugged.
(f) No operator shall commence the drilling of a well, either on a regular location or on
a Rule 37 exception location, until first having been notified by the Commission that the
regular location has been approved, or that the Rule 37 exception location has been
approved. Failure of an operator to comply with this subsection will cause such well to be
closed in and the holding up of the allowable of such well.
128
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(g) Subdivision of property.
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(1) In applying Rule 37 (Statewide Spacing Rule) of statewide application and in
applying every special rule with relation to spacing in every field in this state, no
subdivision of property made subsequent to the adoption of the original spacing rule wiU
be considered in determining whether or not any property is being confiscated within the
terms of such spacing rule, and no subdivision of property wiU be regarded in applying such
^
^
spacing rule or in determining the matter of confiscation if such subdivision took place
subsequent to the promulgation and adoption of the original spacing rule.
(2) Any subdivision of property creating a tract of such size and shape that it is
necessary to obtain an exception to the spacing rule before a well can be drilled thereon
is a voluntary subdivision and not entitled to a permit to prevent confiscation of property
if it were either:
(A) segregated from alarger tract in contemplation of oil, gas, or geothermal resource
development; or
(B) segregated by fee title conveyance from a larger tract after the spacing rule
became effective and the voluntary subdivision rule attached.
„
(3) The date of attachment of the voluntary subdivision rule is the date of discovery of
oil, gas, or geothermal resource production in acertain continuous reservoir, regardless of
the subsequent lateral extensions of such reservoir, provided that such rule does not attach
in the case of a segregation of a small tract by fee title conveyance which is not located in
an oil, gas, or geothermal resource field having a discovery date prior to the date of such
segregation.
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(4) The date of attachment of the voluntary subdivision rule for jnultiple reservoir fields
located in the same structural feature and separated venically biit not laterally (i.e., the
multiple reservoirs overlap geographically at least in pan), shall be the same date as that
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assigned to the earliest discovery well for such multiple reservoir structure.
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(5) If a newly discovered reservoir is located outside the then productive limits of any
previously discovered reservoirs and is classified by the Commission as a newly discovered
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field, then the date of discovery of such newly found reservoir remains the date of
attachment for the voluntary subdivision rule, even though subsequent development may
result in the extension ofsuch newly discovered reservoir until it overlies or underlies older
reservoirs with prior discovery dates.
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^5^
date of attachment of the voluntary subdivision rule for a reservoir that has
been developed through expansion of separately recognized fields into a recognized single
reservoir and is merged by Conmiission order is the earliest discovery date of production
from such merged resen-oir, and that date will be used subsequent to the date of merger
129
^
of the fields into a single field.
(7) The date of attachment of the voluntan' subdivision rule for a reservoir under any
^
special circumstance which the Conmiission deems sufficient to provide for an exception
^
have their rights protected.
may be established other than as prescribed in this section, so that innocent panies may
(h)
Exceptions to Rule 37.
(1) An order granting an exception to Rule 37 wherein protest is had, shall carry as its
last paragraph the following language: It is further ordered by the Commission that this
^
order shall not be final until 20 days after it is actually mailed to the panies by the
Commission; provided that if a motion for rehearing of the application is filed by any party
at interest within such 20-day period, this order shall not become final until such motion
^
is overruled, or if such motion is granted, this order shall be subject to further action by
the Commission. Permits issued pursuant to subsection (h)(2) of this section shall be
issued without the 20-day waiting period.
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(2) The Director of the Oil and Gas Division or a delegate of the Director may issue
an exception permit for drilling, deepening, or additional completion, recompletion, or
^
reentry in an existing well bore if:
(A) a notice of at least 10 days has been given, and no protest has been made to the
m
application; or
(B) written waivers of objection are received from all persons to whom notice would
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^
be given pursuant to subsection (a)(2) of this section.
(3) Applications filed for drilling, deepening, or additional completion, recompletion,
or reentry will be processed and permit issued in accordance with this regulation, subject
to the Commission's discretion to set any application for hearing. If the Director or a
delegate of the Director declines to grant an application, the operator may request a
hearing.
(i)
Rule 37 permits.
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(1) Unless otherwise specified in a permit or in a final order granting an exception to
this section, permits issued by the Commission for completions requiring an exception to
this section shall expire two years from the effective date of the permit unless drilling
operations are commenced in good faith within the two-year permit period. The permit
^
period will not be extended.
PI
commence. On final adjudication and decree from the last court of appeal the two-year
(2) So long as a Rule 37 exception is in litigation, the two-year permit period will not
130
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permit period will commence, beginning on the date of final decree.
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(j) Once an application for a spacing exception has been denied, no new application shall
be entenained except on changed conditions. Changed conditions in the Commission's
administration of its Spacing Rule 37 and amendments thereto applicable to the various
special fields andreservoirs ofTexas and in passing upon applications for permits under said
rule and amendments shall include, among other things, the following.
(1) Any material changes in the physical conditions of the producing reservoir underthe
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tract under consideration or under the area surrounding said tract which would materially
affect the recovery of oil, gas, or geothennal resource from the given tract.
(2) Any material changes in the distribution or allocation of allowable production in the
^
area surrounding the tract under consideration which would materially affect or tend to
affect the recovery of oil, gas, or geothennal resource from the given tract.
^
(3) Any additional permits granted by the Conmiission for wells drilled in the area
surrounding or on offset tracts to the tract under consideration which would materially
affect or tend to affect the recovery of oil, gas, or geothermal resource from the given tract.
(4) Any additional facts or evidence thereof materially affecting or tending to affect the
recovery of oil, gas, or geothermal resource from the applicant's tract, or the property
rights of applicant, which were not known of and considered by the Commission at any
previous hearing or application thereon.
(k) Exceptions to Statewide Rule 37 apply to the total depth for which the permit is
granted or if special field rules are applicable, an exception to the spacing rule shall be
granted only for the reservoir or reservoirs or applicable depth .to which the well is
projected. Subsequent recompletion of the well to reservoirs other than that covered by the
permit issued would be granted only after the filing and processing of a new application.
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(1)
Salt dome oil or gas fields.
(1) The provisions of this section shall not apply to cenain approved salt dome oil or
gas fields. An application for classification as a salt dome oil or gas field shall include the
following:
(A) geological evidence proving that an oil or gas field is a piercement-type salt dome,
that faulting has caused the producing formation to be at a 45° angle or greater, and that
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each well is likely to be completed in a separate reservoir;
(B) establishment, by plat or otherwise, of the probable productive limits of the salt
r*
dome area:
131
(C) cenijScarion that notice of the application for salt dome classification with
evidence included has been given to all operators in the field, or if a new field, in
accordance with subsection (a)(2) of this section and;
(D) a list of persons notified and the date notice was mailed.
(2) The Director of the Oil and Gas Division, or the director's delegate, may
administratively grant an application for salt dome classification ifthe evidence proves that
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^
the oil or gas field is a salt dome.
(3) The operator may request a hearing if the Director of the Oil and Gas Division, or
the director's delegate, declines to approve an application. If an application is protested
within 10 days of notice, it will be set for hearing. After hearing, the examiner shall
^
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iMt
recommend final Commission action.
(4) The amendment providing for administrative approval ofsalt dome oil and gas fields
does not alter the status of those fields previously approved and listed in this section.
(m) Wells that were deviated, whether intentionally orotherwise, prior to April 1,1949, and
are bottomed on the lease where permitted, are legal wells. The Rule 37 Depanment will
develop the record in each reapplication for such deviated wells so that the Commission can
determine the condition of each such well. The following will be adduced from sworn
testimony and authenticated data at each such hearing.
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(1) That such well was deviated before April 1, 1949. Proof of completion of the well
prior to that date and its subsequent producing status is not adequate proof of deviation.
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(2) That such well was completed on the lease where the surface location was
permitted. Such bottom hole location must be proven by the submission of an acceptable
authenticated directional survey.
(3) That such bottom hole location is one that either is not in direct violation of a
condition or limitation placed in the permit to drill, or is not in violation of a specific
Commission order. Example: Denial order for a Rule 37 application for a comparable
^
location.
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inclination or a false directional survey with the Commission.
(4) That the present operator ofsuch well or his predecessor has not filed either a false
(5) A well that is either bottomed off the lease, deviated after April 1, 1949, drilled in
direct violation of a specific condition or limitation placed in the Rule 37 permit, or is in
violation of a specific Commission order, is an illegal well and it shall not be permitted, and
such well where permit is refused shall not be considered a replaceable well under
CoEQmission replacement-well regulation.
132
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(6) The provisions of this section do not preclude an operator from applying for
approval ofthe bottom hole location of a deviated well as a reasonable location under the
rules and regulations now applicable, provided, that such bottom hole location shall notbe
approved unless the applicant proves that a vertical projection of the permitted surface
location for such well is within the productive limits of the reservoir.
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p.
n.
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133
§3.38. RULE 38.
WELL DENSITIES.
(Amended Effective November 1, 1989)
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(a) Defimtions. The following words and terms, when used in this section, shall have the
following meanings, unless the context clearly indicates otherwise.
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(1) Director—Director of the Oil and Gas Division or his staff delegate designated in
writing by the director or the Commission.
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(2) Drilling imit-The acreage assigned to a well and outlined on the plat submitted with
an application to drill.
(3) Proration unit—The acreage assigned to a well for the purpose of assigning
allowables and allocating allowable production to the well.
(4) Substandard acreage—Less acreage than the smallest amount established for
standard or optional drilling units.
^
(5) Surplus acreage-Substandard acreage within a lease, pooled unit, or unitized tract
that remains unassigned after the assignment of acreage to each applied for, permitted, or
completed well in a field, in an amount equaling or exceeding the amount established for
standard or optional drilling units. Surplus acreage is distinguished from the term "tolerance
acreage," in that tolerance acreage is defined in context with proration regulation, while
surplus acreage is defined by this rule only in context with well density regulation.
^
(6) Tolerance acreage-Acreage within a lease, pooled unit, or unitized tract that may
be assigned to a weD for proration purposes pursuant to special field rules in addition to
the amount established for a prescribed or optional proration unit.
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(b) Density requirements.
(1) General prohibition. No well shall be drilled on substandard acreage except as
hereinafter provided.
(2) Standard units.
(A) The standard drilling unit for all oil, gas, and geothermal resource fields wherein
only spacing rules, either special, county regular, or statewide, are applicable is hereby
prescribed to be the following.
134
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spacing Rule
(1)
(2)
(3)
(4)
(5)
(6)
(7)
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150 200330330 467467 660 -
Acreage Requirement
300
400
660
933
933
1200
1320
02
04
10
20
20
40
40
(B) The spacing rules listed in subparagraph (A) of this paragraph are not exclusive.
If any spacing rule not listed in subparagraph (A) of this subsection is brought to the
attention of the Commission, it will be given an appropriate acreage assignment.
(c) Development to final density. An application to drill a well for oil, gas, or geothermal
resource on a drilling unit composed of surplus acreage, commonly referred to as the
"tolerance well," may be granted as regular when the operator seeking such permit^ certifies
to the Commission in a prescribed form- the necessary data to show that such permit is
needed to develop a lease, pooled unit, or unitized tract to final density, and only in the
following circumstances:
(1) when the amount of surplus acreage equals or exceeds the maximum amount
providedfor tolerance acreage by special or county regular rules for the field, provided that
this paragraph does not apply for a lease, pooled unit, or unitized tract that is completely
developed with optional units and the special or county regular rules for the field do not
have a tolerance provisions expressly made applicable to optional proration units;
(2) if the special or county regular rules for the field do not have a tolerance provision
expressly made applicable to optional proration units, when the amount of surplus acreage
equals or exceeds one-half of the smallest amount established for an optional drilling unit;
or
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(3) if the applicable rules for the field do not have a tolerance provision for the
standard drilling or proration unit, when the amount of surplus acreage equals or exceeds
one-half the amount prescribed for the standard unit.
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' W-l (Application to Drill. Deepen, Plug Back, or Re-eater)
->
W-lA (Substandard Acreage Dnlling Unit Certification)
135
(d) Applications invdving the voluntaiy subdivision rule.
(1) Density exception not required. An exception to the minimum density provision is
not required for the first weU in afield on alease, pooled unit, or unitized tract composed
of substandard acreage, when the leases, or the drillsite tract of a pooled unit or unitized
tract:
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(A) took its present size and shape prior to the date of attachment of the voluntary
„
subdivision rule (§ 3.37(g) of this title (relating to Statewide Spacing Rule)); or
_
subdivision rule (§ 3.37(g) of this title (relating to Statewide Spacing Rule)) and was not
(B) took its present size and shape after the date of attachment of the voluntary
composed of substandard acreage in the field according to the density rules in effect at
the time it took its present size and shape.
(2) Density exception required. An exception to the density provision is required, and
may be granted only to prevent waste, for awell on a lease, pooled unit, or unitized tract
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that is composed of substandard acreage and that:
(A) took its present size and shape after the date of attachment of the voluntary
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subdivision rule (§ 3.37 of this title (relating to the Statewide Spacing Rule)); and
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in effect at the time it took its present size and shape.
(B) was composed of substandard acreage in the field according to the density rules
^
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(3) Division after joinder or unitization. If two or more separate tracts are joined or
unitized for oil, gas, or geothermal development and accepted by the Commission, the
joined or unitized tracts may not thereafter be divided into the separate tracts with the
rules of the Commission applicable to each separate tract, if the division results in any tract
composed of substandard acreage at the time of division, unless and until the Commission
approves such division after application, notice to all current lessees and unleased mineral
interest owners of each tract within the joined or unitized tract, and an opportunity for
hearing. If wrinen waivers are filed or if a protest is not filed within the time set forth m
the notice of application, the application wiU be granted administratively.
^
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(e) Application involving unitized areas with entity for density orders. An exception to the
minimum density provision is not required for a well in a unitized area for which the
Commission has granted an entity for density order, if the sum of all apphed for, permitted,
or completed producing wells in the field within the unitized area, multiplied by the
applicable density provision, does not exceed the total number of acres in the unitized area.
The operator must indicate the docket number of the entity for density order on the
136
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application form.*
(f) Exceptions to density provisions authorized. The Commission, in order to prevent
waste or, except as provided in subsection (d)(2) of this section, to prevent the confiscation
of property, may grant exceptions to the density provisions set forth in this section. Such an
exception may be granted only after notice and an opponuniry for hearing.
(g) General filing requirements-
(1) Application. An application for permit to drill shall include the fees required in
§ 3.76 of this title (relating to Fees Required To Be FOed) and shall be certified by some
person acquainted with the facts, stating that all information in the application is true and
complete to the best of that person's knowledge and that the accompanying plat is
accurately drawn to scale and correctly reflects all peninent and required data.
(2) Plat. The required platmust depict the lease, pooled unit, or unitized tract, showing
thereon the acreage assigned to the drilling unit for the proposed well and the acreage
assigned to all current applied for, permiited, or completed wells on the lease, pooled unit,
or unitized tract. A permit to drill a well for oil, gas, or geothermal resource will not be
granted until such plat has been attached to and made a part of such form.
(A) On large leases, pooled units, or unitized tracts, if the established density is not
exceeded as shown on the face of the form, a plat will suffice that depicts the acreage
assigned to the well for which the permit is sought and to the immediately adjacent wells
on the lease, pooled unit, or unitized tract.
(B) On plats of leases, pooled units, or unitized tracts from which production is
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secured from more than one field, the plat shall depict the acreage assigned to the wells
in each field that is the subject of the current application.
(3) Substandard acreage. An application for a permit to drill on a lease, pooled unit,
^
or unitized tract composed of substandard acreage must include a cenification in a
prescribed form indicating the date the lease, or the drillsite tract of a pooled unit or
unitized tract, took its present size and shape.
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fP!)
(4) Surplus acreage. An application for permit to drill on surplus acreage pursuant to
subsection (c) of this section must include a certification in a prescribed form" indicating
the date the lease, pooled unit, or unitized tract took its present size and shape.
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' W-l (Application to Drill. Deepen. Plug Back, or Re-enter)
" W-l A (Substandard Acreage Drilling Unit Cenification)
137
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(h) Procedure for obtaining exceptions to the density provisions.
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(1) Filing requirements. If a permit to drill requires an exception to the applicable
density provision, the operator must file, in addition to the items required by subsection
(g) of this section:
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(A) a list of the names and addresses of all affected persons. For the purpose of
giving notice of application, the Commission presumes that affected persons include the
operators and unleased mineral interest owners of all adjacent offset tracts, and the
operators and unleased mineral interest owners of all tracts nearer to the proposed well
than the prescribed minimum lease-line spacing distance. The Director may determine
that such a person is not affected only upon written request and a showing by the
applicant that:
«
(i) competent, convincing geological or engineering data indicate that drainage of
hydrocarbons from the panicular tracts subject to the request will not occur due to
production from the proposed well; and
(fii
(ii) notice to the particular operators and unleased mineral interest owners would
be unduly burdensome or expensive;
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'
(B) engineering and/or geological data, including awritten explanation of each exhibit,
showing that the driUing of a well on substandard acreage is necessary to prevent waste
^
or to prevent the confiscation of property;
(C) additional data requested by the Director.
(2) Notice of application. Upon receipt of acomplete application, the Commission will
give notice of the application by mail to aU affected persons for whom signed waivers have
^
not been submitted.
^
(3) Approval without hearing. If the Director determines, based on the data submitted,
that a permit requiring an exception to the applicable density provision is justified
^
Commission for consideration and action, provided that:
according to subsection (f) of this section, then the application will be presented to the
(A) signed waivers from all affected persons were submitted with the application,
(B) notice of application was given in accordance with paragraph (2) of this subsection
and no protest was filed within 21 days of the notice; or
PI
(C) no person appeared to protest the application at a hearing scheduled pursuant
to paragraph (4)(A) of this subsection.
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138
(4) Hearing on the application.
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(A) If awritten protest is filed within 21 days after the notice of application is given
in accordance with paragraph (2) of this subsection, the appUcation wiU be set for
hearing.
3n
(B) If the application is not protested and the Director determines that a permit
requiring an exception to the applicable density provision is not justified accordmg to
subsection (f) of this section, the operator may request a hearing to consider the
application.
(i) Duration. Apennit is issued as an exception to the applicable density provision shall
expire two years from the effective date of the permit; unless driUing operations are
commenced in good faith within the two year period.
r]
139
m
§3.39. RULE 39. PRORATION AND DRULXJNG UNITS - CONTIGUITY OF
ACREAGE AND EXCEPTION THERETO.
(a) Proration and drilling units established for individual weUs drilled or to be drilled shall
consist of acreage which is contiguous.
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(b) An exception to the contiguous acreage provision may be granted at the operator's
request if acreage that is to be included in the proration or drilling unit is separated by a
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long, narrow right-of-way tract.
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fm\
fm)
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140
§ 3.40. RULE 40. ASSIGNMENT OF ACREAGE TO POOLED DEVELOPMENT
AND PRORATION UNITS.
(a) Acreage up to the amount specified in applicable field rules may be pooled into a
development or proration unit, provided that an operator must file with the Commission a
certified plat delineating the pooled unit, and a certificate of pooling authority^ wherein it
isstated that the tracts are pooled by authorityof an agreement between the various interest
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holders in the several tracts committed to the unit, with such tracts separately identified and
the gross number of acres in each of said tracts shown separately, with a total gross acreage
allowed not to exceed the unit size authorized by rule.
(b) If a tract to be pooled has an outstanding interest for which pooling authority does not
exist, the tract may be assigned to a unit where authority exists in the remaining undivided
interest, provided, that total gross acreage in the tract is included for allocation purposes,
and the certificate filed with the Commission shows that a certain undivided interest is
outstanding in the tract. The Commission will not allow an operator to assign only his
undivided interest out of a basic tract, where a nonpooled interest exists.
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(c) The nonpooled undivided interest holder retains his development rights in his basic
tract, and should such rights be exercised, authority to develop the basic tract be approved
by the Commission, and a well completed as a producer thereon, then the entire interest in
the basic tract must be allocated to said well, and any interest insofar as it is pooled with
another tract must be assigned to the well on the basic tract for allocation purposes.
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Splitting of undivided interest in a basic tract, between two or more wells on two or more
tracts is not acceptable.
n
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(d) Acreage assigned to a well for drilling and development, or for allocation of allowable,
shall not be assigned to any other well or wells projected to or completed in the same
reservoir; such duplicate assignment of acreage is not acceptable, provided, however, that
this limitation shall not prevent the reformation of development or proration units so long
as no duplicate assignment of acreage occurs, and further, that such reformation does not
violate other conservation regulations.
P-12 (Ceniiicate of Pooling Authorit\')
141
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§3-74. RULE 76. CXDMMISSION APPROVAL OF PLATS FOR MINEELAL
DEVELOPMENT.
^
"
^
^
(a) The following words and terms, when used in this section, shall have the following
meanings, unless the context clearly indicates otherwise.
(1) Minerals-Oil and/or gas.
(2) Operations site-A surface area oftwo ormore acres that an owner ofa possessory
mineral interest may use to explore for and produce minerals, which is located in whole
or in part within a qualified subdivision, and designated on the subdivision plat.
(3) Possessory mineral interest-A mineral interest that includes the right to use the land
surface for exploration and production of minerals.
(4) Qualified subdivision-A tract of land not more than 640 acres:
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(A) that is located in a county having a population in excess of400,000, or in a county
having a population in excess of 140,000 that borders a county having a population in
excess of 400,000 or located on a barrier island;
n
(B) that has been subdivided in a maimer authorized by law by the surface owners for
residential, commercial, or industrial use; and
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(C) that contains an operations site for each separate 80 acres within the 640-acre
tract and provisions for roadand pipeline easements to allow use of the operations sites.
^
(5) Barrier island-An island bordering on the Gulf of Mexico and entirely surrounded
by water.
"
(b) As provided in subsections (e) and (f) of this section, the surface owners of a parcel
of land may restrict use of the surface by the possessory mineral owners if the tract is a
qualified subdivision and if a plat of the subdivision has been approved by the Railroad
"
Commission after notice and hearing and filed with the clerk of the county in which the
qualified subdivision is to be located.
(c) An application for a hearing under this section must be made in writing and mailed
or delivered to the Director of the Oil and Gas Division. The application must include:
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(1) a jurisdictional statement setting out the facts stated in subsection (a)(4)(A) and (B)
of this section;
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PI
207
(2) a statement that the applicant has authority to represent and represents all surface
owners of land contained in the proposed qualified subdivision;
(3) the names and addresses of all owners of possessory mineral interests and all
mineral lessors of land contained in the proposed qualified subdivision;
(4) a plat of the proposed subdivision showing each proposed 80-acre tract with its
operations site, road easements, and pipeline easements and a legible copy thereof no
larger than 8 1/2 inches by 11 inches;
(5) a concise description of mineral development in the area, including the number of
oil and/or gas wells within 2.5 miles of the boundary of the proposed qualified subdivision
and the depths at which each well is completed;
(6) a list of all the Railroad Commission designated oil and/or gas fields, if any, which
underlie the proposed qualified subdivision; including the spacingand density requirements.
n
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If no Railroad Conmiission designated fields underlie the qualified subdivision, the
application should so state.
(d) The Railroad Commission shall, on proper notice to the applicant and owners of
possessory mineral interests and mineral lessors of land contained in the proposed qualified
subdivision, hold a hearing on the application to determine the adequacy of the number and
location of operations sites and road and pipeline easements. At the hearing on the
application, evidence may be presented by the applicant and the owners of possessory
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mineral interests and mineral lessors. The applicant must carry the burden of proof. After
considering the evidence, the Commission may approve, reject, or amend the application to
ensure that the mineral resources of the subdivision may be fully and effectively developed.
^
(e) An owner of a possessor}' mineral interest within a Railroad Commission approved
qualified subdivision may use only the surface contained in designated operations sites for
exploration, development, and production of minerals and only the designated easements
"
as necessary to adequately use the operations sites.
^
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(f) The owner of the possessory mineral interest may drill wells or extend well bores from
an operations site or from a site outside of the qualified subdivision to bottomhole locations
vertically beneath the surface of parts of the qualified subdivision other than the operation
sites. Such drilling is subject to other applicable Commission rules and regulations, and is
permissible only to the extent that the operations do not unreasonably interfere with the use
of the surface of the qualified subdivision outside the operations site.
(g) Subsections (e) and (f) of this section cease to apply to a subdivision if, by the third
anniversary of the date on which the order of the Commission becomes final:
208
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(1) the surface owner has not commenced actual construction ofroads orutilities within
the qualified subdivision; and
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(2) a lot within the qualified subdivision has not been sold to a third party.
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(h) All or any portion ofa qualified subdivision may be amended, replatted, orabandoned
by the surface owner. An amendment or replat, however, may not alter, diminish, or impair
n
the usefulness of an operations site or appurtenant road or pipeline easement unless the
amendment or replat is approved by the Commission. Railroad Commission approval of a
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Division, or his delegate, upon submission of items required in subsection (c) of this section
and after notice and opponunity for hearing has been afforded to all possessory mineral
replat or amendment may be administratively granted by the Director of the Oil and Gas
interest owners and mineral lessors of land contained within the original and/or replatted or
amended qualified subdivision.
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209
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§3-86. RULE 86.
HORIZOOTAL DRAINHOLE WELLS.
(Adopted Effective June 1, 1990)
(a) Definitions. The following words and terms, when used in this section, shaD have the
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following meanings, unless the context clearly indicates otherwise:
(1) Correlative Interval—The depth interval designated by the field rules, by new field
designation, or, where a correlative interval has not been designated by the Commission,
by other evidence submitted by the operator showing the producing interval for the field
in which the horizontal drainhole is completed.
n
(2) Horizontal Drainhole—That portion of the wellbore drilled in the correlative interval,
between the penetration point and the terminus.
n
(3) Horizontal Drainhole Displacement—The calculated horizontal displacement of the
horizontal drainhole from the penetration point to the terminus.
(4) Horizontal Drainhole Well-Any well that is developed with one or more horizontal
drainholes having a horizontal drainhole displacement of at least 100 feet
n
(5) Penetration Point—The point where the drainhole penetrates the top of the
correlative interval.
n
(6) Terminus-The farthest point required to be surveyed along the horizontal drainhole
from the penetration point and within the correlative interval.
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(b) Drainhole Spacing.
n
(1) No point on a horizontal drainhole shall be drilled nearer than 1,200 feet (horizontal
displacement), or other between-well spacing requirement under applicable rules for the
field, to any point along any other horizontal drainhole in another well, or to any other well
completed or drilling in the same field on the same lease, pooled unit or unitized tract.
(2) No point on a horizontal drainhole shall be drilled nearer than 467 feet, or other
lease-line spacing requirement under applicable rules for the field, from any property line,
lease line, or subdivision line.
(3) AH wells developed with horizontal drainholes shall otherwise comply with Statewide
Rule 37 (16 TAC § 3.37) or other applicable spacing rules.
(c) Well Densities. All wells developed with horizontal drainholes shall comply with
Statewide Rule 38 (16 TAC § 3.38) or other applicable density rules.
248
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(d) Proration and Drilling Units.
(1) Acreage may be assigned to each horizontal drainhole well for the purpose of
allocating allowable oil or gas production up to the amount specified by applicable rules
for a proration unit for a vertical well plus the additional acreage assignment as provided
in this paragraphAdditional Acreage Assignment
For Fields With A Density Rule of 40 Acres Or Less
Horizontal Drainhole Displacement, ft
100 to
585
20
586 to
1,171 to
1,756 to
2,341 to
2,926 to
1,170
1,755
2,340
2,925
3,510
40
60
80
100
120
etc. - 585 ft increments
N
Additional Acreage Allowed, acres
etc. - 20 acre increments
Additional Acreage Assignment
For Fields With A Density Rule Greater Than 40 Acres
Horizontal Drainhole Displacement, ft
Additional Acreage Allowed, acres
in
150 to
i
827
40
828 to 1,654
80
in
;
1,655 to 2,481
2,482 to 3,308
120 ..
160
I
H
3,309 to 4,135
4,136 to 4,962
200
240
-I
etc. - 827 ft increments
etc. - 40 acre increments
(2) Assignment of acreage to proration and drilling units for horizontal drainhole wells
must be done in accordance with Statewide Rule 40 (16 TAC § 3.40).
•n
249
"
^
(3) All proration and drilling units shall consist of continuous and contiguous acreage and
proration units shall consist of acreage that can be reasonably considered to be productive
of oil or gas.
(4) All points on the horizontal drainhole must be within the proration and drilling unit.
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H
(5) The maximum daily allowable for a horizontal drainhole well shall be determined by
multiplying the applicable allowable for a venical well in the field with a proration unit
containing the maximum acreage authorized by the applicable rules for the field, exclusive
of tolerance acreage, by a fraction:
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(A) the numerator of which is the acreage assigned to the horizontal drainhole well for
proration purposes; and
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(B) the denominator of which is the maximum acreage authorized by the applicable field
rules for proration purposes, exclusive of tolerance acreage.
^
The daily oil allowable shall be adjusted in accordance with Statewide Rule 49(a) (16 TAC
§ 3.49(a)) when applicable.
"
(6) The maximum diagonal for each proration unit containing a horizontal drainhole well
shall be the horizontal drainhole displacement of the longest horizontal drainhole for the
well plus:
n
(A) 2,100 feet for fields that are regulated under Statewide Rules; or
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(B) the maximum diagonal aDowed for fields where the special field rules specify a
maximum diagonal.
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(e) Multiple Drainholes Allowed.
(1) Asingle well may be developed with more than one horizontal drainhole originating
from a single vertical wellbore.
1^
(2) Ahorizontal drainhole well developed with more than one horizontal drainhole shall
be treated as a single well.
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(3) The horizontal drainhole displacement used for calculating additional acreage
assignment for awell completed with multiple horizontal drainholes shall be the horizontal
drainhole displacement of the longest horizontal drainhole plus the projection of any other
horizontal drainhole on a line that extends in a 180 degree direction from the longest
horizontal drainhole.
pn
250
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(f) Dnflling Applications and Required Reports.
(1) Application. Any intent to develop a new or existing well with horizontal drainholes
must be indicated on the application to drill. An application for a permit to drill a
horizontal drainhole shall include the fees required by Statewide Rule 78 (16 TAG § 3.76)
and shall be certified by a person acquainted with the facts, stating that all information in
the application is true and complete to the best of that person's knowledge and that the
accompanying plat is accurately drawn to scale and correctly reflects all pertinent and
required data.
(2) DiiUing Unit PlaL The required plat must depict the lease, pooled unit or unitized
tract, showing the acreage assigned to the drilling unit for the proposed well and the
acreage assigned to the drilling units for all current applied for, permitted or completed
wells on the lease, pooled unit or unitized tract, the surface location of the proposed
horizontal drainhole well, and the proposed path, penetration point, and terminus of all
drainholes. An amended drilling application permit and plat shall be filed after completion
of the horizontal drainhole well if the Commission determines that the drainhole as drilled
is not reasonable with respect to the drainhole represented on the plat filed with the
drilling permit application.
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(3) Directional Survey. A directional survey from the surface to the farthest point
drilled on the horizontal drainhole shall be required for all horizontal drainholes. The
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directional survey and accompanying reports shall be conducted and filed in accordance
with Statewide Rules 11 and 12 (16 TAG § 3.11 and § 3.12). No allowable shall be
assigned to any horizontal drainhole well until a directional survey and survey plat has been
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filed with and accepted by the Conmaission.
n
unit or unitized tract, showing the acreage assigned to the proration unit for the horizontal
drainhole well, the acreage assigned to the proration units for ail wells on the lease, pooled
unit or unitized tract, and the path, penetration point, and terminus of all drainholes. No
allowable shall be assigned to any horizontal drainhole well until the proration unit plat has
(4) Proration Unit Plat The required proration unit plat must depict the lease, pooled
n
been filed wiih and accepted by the Commission.
(g) Exceptions and Procedure for Obtaining Exceptions.
(1) The Commission may grant exceptions to this rule in order to prevent waste, prevent
confiscation, or to protect correlative rights.
n
(2) If a permit to drill a horizontal drainhole requires an exception to this section, the
notice and opponunity for hearing procedures for obtairJng exceptions to the density
provisions prescribed in Statewide Rule 38 (16 TAG § 3.38} shall be followed as set forth
in
in Statewide Rule 38(h) (16 TAG § 3.38(h)).
251
(3) For notice purposes, the Commission presumes that for each adjacent tract and each
tract nearer to any point along the proposed or existing horizontal drainhole than the
prescribed minimnm lease-iine spacing distance, affected persons include:
(A) The designated operator;
(B) All lessees of record for tracts that have no designated operator; and
(Q All owners of record of unleased mineral interests.
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252
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Eastern Gulf Region
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"Drilling and Production Units and Well Spacing
Gary Wilson,
Deputy Supervisor,
Alabama Oil and Gas Board
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STATE OIL & GAS BOARD OF ALABAMA
SPACING OF WELLS (Outline)
400-1-2-.02. Spacing of Wells.
♦
A well is spaced on a unit based on the maximunn area which may be efficiently and
econonnically drained by the well.
♦
The spacing for a well to be drilled to a pool in an established field Is governed by
special field mles for that particular field.
SPACING OF FIELD WELLS
♦
The final spacing for a well completed as a producer is determined by the Board at the
time of field establishment.
♦
The drilling of additional wells for development of a pool may continue prior to field
establishment, subject to the approval of the Supervisor.
WILDCAT DRILLING UNITS - STATEWIDE
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♦
A well may be drilled on a unit consisting of a govemmental quarter-quarter section
(approx. 40 acres).
♦
A well may be drilled on a unit consisting of a govemmental quarter section (approx. 160
acres).
DRILLING UNITS
SOUTHWEST ALABAMA
(WILDCATS)
(In addition to the 40- & 160-acre option)
♦
A well drilled in search of gas in the Counties of Baldwin, Escambia, Mobile, or
Washington may be drilled on a unit consisting of a governmental section for deep
prospects (approx. 640 acres).
♦
A permit for a well to be drilled on a unit other than a governmental section or division
thereof may be approved by the Supervisor.
UNITS FOR OFFSHORE DEVELOPMENT
♦
Spacing for field wells is govemed by special field mles.
♦
Spacing for offshore wildcat wells is the same as for onshore wells in Baldwin and
Mobile Counties (units can be 40,160, 320, or 640 acres in size).
DRILLING UNITS
WARRIOR BASIN
(WILDCATS)
F,
(In addition to the 40- &160-acre option)
♦
A well to be drilled in search of gas in the Counties of Fayette, Lamar, Pickens, or
Tuscaloosa may be drilled on a unit consisting of a governmental half section (approx.
320 acres).
♦
A permit for a well to be drilled on a unit other than a governmental section or division
thereof may be approved by the Supervisor.
„
UNITS FOR COALBED METHANE DEVELOPMENT
♦
The spacing for field wells is governed by special field rules.
♦
Wildcat wells are drilled on 40-acre units consisting of governmental quarter-quarter
"
sections (approx. 40 acres).
^
•
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Permits for wells to be drilled on non-govemmental units may be approved by the
Supervisor.
NON-GOVERNMENTAL UNITS
A permit application for a well to be drilled on a unit consisting of approximately 40, 160,
320, or 640 contiguous surface acres, other than a govemmental section or division thereof,
may be approved by the Supervisor.
PRODUCTIVE EXTENSIONS
♦
The unit for a well drilled adjacent to a field is normally in accordance with the spacing
provisions in the special field rules.
♦
A well located adjacent to an established field may be drilled as a wildcat with written
justification.
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UNIT ENLARGEMENTS
The Board may Increase unit sizes by an amount not to exceed thirty percent (30%).
(Must be supported by evidence that the acreage to be added
is being drained or Is in imminent danger of being drained.)
p*i
2
FROM OIL AND GAS REPORT 1
Rule
400-1-2-.02. Spacing of Wells. (See OGB-1 for the complete rules and regulations of
the Board and all laws pertaining to oil and gas development).
A well shall be spaced on a unit based upon the maximum area which may be efficiently and
economically drained by one well. A unit shall not include any part of another unit established
for the same pool. The spacing for a well to be drilled to a pool in an established field shall be
governed by special field rules for that particularfield. With respect to a well to be drilled to a
pool that is not governed by special field rules, the following spacing provisions shall be
applicable:
(1) A well may be drilled on a unit consisting of a governmental quarter-quarter section
(approximately 40 acres). Such well shall be located at least three hundred thirty (330) feet
from every exterior boundary of the unit.
(2) A well may be drilled on a unit consisting of a govemmental quarter section
(approximately 160 acres). The Supervisor may require written justification for the unit. Such
well shall be located at least six hundred sixty (660) feet from every exterior boundary of the
unit.
"
"
^
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(3) A well to be drilled in search of gas in the Counties of Fayette, Lamar, Pickens, or
Tuscaloosa may be drilled on a unit consisting of a govemmental half section (approximately
320 acres). Such well shall be located at least six hundred sixty (660) feet from every exterior
boundary of the unit. The operator shall designate on the permit application an altemate forty
(40) acre unit, and the well shall be located at least three hundred thirty (330) feet from every
exterior boundary of the alternate unit. If said well is completed as an oil well, then the
spacing for the well shall automatically revert to the designated alternate forty (40) acre unit
until the proper spacing for said well is determined by the Board after notice and hearing.
(4) A well to be drilled in search of gas in the Counties of Baldwin, Escambia, Mobile, or
Washington may be drilled on a unit consisting of a govemmental section (approximately 640
acres). The Supen/isor may require written justification for the unit. Such well shall be located
at least one thousand three hundred twenty (1,320) feet from every exterior boundary of the
unit. The operator shall designate on the pennit application an altemate one hundred sixty
(160) acre unit, and the well shall be located at least six hundred sixty (660) feet from every
exterior boundary of the altemate unit. If said well is completed as an oil well, then the
spacing for the well shall automatically revert to the designated altemate one hundred sixty
(160) acre unit until the proper spacing for said well is detennined by the Board after notice
and hearing.
(5) The Supen/isor, upon receipt of written justification from an operator, may approve a
permit application under paragraphs (1) through (4) above for a well to be drilled on a unit
consisting of approximately 40, 160, 320, or 640 contiguous surface acres other than a
govemmental section or division thereof as set forth herein.
(6) The Supervisor may require that a well to be drilled on a unit contiguous to an existing
field be drilled and completed as an extension of the field, in accordance with the spacing
provisions in the special field rules thereof. If, however, an operator provides written
justification that such proposed well will likely be completed in a pool or pools not defined in
^
the special field rules for said field, the Supervisor may approve the drilling and completion of
such well in compliance with the spacing provisions as set forth herein.
(7) Pursuant to Section 9-17-12(c) of the Code of Alabama (1975), the Board may grant
^
an exception to the spacing rules as may be reasonably necessary where it is shown, after
notice and hearing, and the Board finds, that the unit is partly outside the pool, or for some
1
other reason, that a well located in accordance with applicable rules would be nonproductive,
would not be at the optimum position in such drilling or production unit for the most efficient
and economic drainage of the unit, or where topographical conditions are such as to make
the drilling at an authorized location on the unit unduly burdensome or where an exception is
necessary to prevent confiscation of property.
^
(8) No well shall be located within 200 feet of any permanent residence, unless othen/vise
approved by the Board.
(9) For a well completed in a pool for which special field rules have not been adopted,
^
the Board shall detemiine, in conjunction with the establishment of special field rules
after notice and hearing, the proper spacing for the production unit for said well.
Subject to the approval of the Supervisor, the drilling of additional wells for
development of a pool may continue prior to the establishment of special field rules for
the pool. No well shall produce, other than on a test basis authorized by the
Supervisor or Board, until special field rules applicable to the well are established. In
order to obtain sufficient technical information to establish the proper spacing, a well
^
may be produced on a test basis pursuant to Rule 400-1-6-.01 et seq. for an oil well,
or Rule 400-1-7-.01 et seq. for a gas well.
OFFSHORE WELLS
400-3-2-.02. Spacing of Wells. Unless the spacing of wells in oil and gas fields is govemed
by special field rules or is othenwise approved by the Board after notice and hearing, an
application for a drilling permit in submerged offshore lands shall comply with the applicable
requirements of Rule 400-1 -2-.02, Spacing of Wells.
"
COALBED METHANE WELLS
Rule 400-4-2-.02. Spacing of Wells. A coalbed methane gas well shall be spaced on a unit
based upon the maximum area which may be efficiently and economically drained by one
well. A unit shall not include any part of another unit established for the same pool. The
spacing for a coalbed methane gas well to be drilled to a pool in an established field shall be
governed by special field rules for that particular field. With respect to a coalbed methane gas
well to be drilled to a pool that is not govemed by special field rules, the following shall be
applicable:
(1) Each coalbed methane gas well shall be drilled on a unit consisting of a governmental
quarter-quarter section (approximately 40 acres). Such well shall be located at least three
hundred thirty (330) feet from every exterior boundary of the unit.
(2) The Supervisor, upon receipt of written justification from an operator, may approve a
n
—
permit application under paragraph (1) for a unit consisting of approximately 40 contiguous
surface acres other than a govemmental quarter-quarter section as set forth herein.
(3) The Supervisor may require that a coalbed methane gas well to be drilled on a unit
contiguous with an existing field be drilled and completed as an extension of the field, in
accordance with field spacing provisions in the special field rules thereof. If, however, an
operator provides written justification that such proposed well will likely be completed in a
pool or pools not defined in the special field rules for said field, the Supervisor may approve
the drilling and completion of such well in compliance with the spacing provisions as set forth
herein.
(4) Pursuant to Section 9-17-12(c) of the Code of Alabama (1975), the Board may grant
an exception to the spacing mles as may be reasonably necessary where it is shown, after
^
notice and hearing, and the Board finds, that the unit is partly outside the pool, or for some
other reason, that a coalbed methane gas well located in accordance with applicable rules
would be nonproductive, would not be at the optimum position in such drilling or production
unit for the most efficient and economic drainage of the unit, or where topographical
conditions are such as to make the drilling at an authorized location on the unit unduly
burdensome or where an exception is necessary to prevent confiscation of property.
(5) No coalbed methane gas well shall be located within 200 feet of any permanent
residence, unless othenvise approved by the Board.
(6) For a coalbed methane gas well completed in a pool for which special field rules have
not been adopted, the Board shall determine, in conjunction with the establishment of special
field rules after notice and hearing, the proper spacing for the production unit for said well.
Subject to the approval of the Supervisor, the drilling of additional wells for development of a
pool may continue prior to the establishment of special field rules for the pool. No well shall
produce, other than on a test basis authorized by the Supervisor or Board, until special field
rules applicable to the well are established. In order to obtain sufficient technical information
to establish the proper spacing, a coalbed methane gas well may be produced on a test basis
pursuant to Rule 400-4-6-.01.
"
(7) Ifany coalbed methane gas well drilled in conformity with the provisions of paragraph
one (1) above, or in conformity with the special field rules for a particular field is
completed as other than a coalbed methane gas well, said well shall not be produced
other than on a test basis until authorization has been granted by the Board after
notice and hearing. This rule shall not apply to vent holes drilled for safety purposes in
conjunction with coal mining operations.
m
FROM OIL & GAS LAWS OF ALABAMA (See OGR 1 for all Laws)
pn
Section 9-17-12. Limitations as to ruies, regulations or orders limiting or prorating
pool production generally; establisliment of drilling or production units for pools;
locations for drilling of wells witliin drilling or production units; determination of
producers shares of production and reservoir energy of pools.
(b) For the prevention of waste, to protect and enforce the conrelative rights of the owners
and producers in a pool and to avoid the augmenting and accumulation of risks arising from
the drilling of an excessive number of wells, the Board shall, after a hearing, establish a
drilling or production unit or units for each pool. A drilling or production unit, as contemplated
in this subsection, means the maximum area which may be efficiently and economically
drained by one well, and such unit shall constitute a developed unit as long as a well is
located thereon which is capable of producing oil or gas in paying quantities, or until the
Board shall determine and order otherwise after notice and hearing. It is provided, however,
that the Board shall have no authority to fix a drilling or production unit in excess of either one
hundred sixty (160) acres or one governmental quarter section plus ten percent (10%)
tolerance for any pool deemed by the Board to be an oil reservoir or in excess of either six
hundred forty (640) acres or one governmental section plus ten percent (10%) tolerance, for
any pool, deemed by the Board to be a gas reservoir, the said ten percent (10%) tolerance
provided for so as to allow for in-egular sections; provided however, that the Board may, at its
discretion, after notice and hearing, establish drilling or production units for oil and gas in
excess of the aforesaid limitations when it is affirmatively demonstrated that one well can
efficiently and economically drain the proposed area and that a larger unit is justified because
of technical, economic, environmental or safety considerations, or other reasons deemed
valid by the Board. To insure protection of coequal and correlative rights, the Board may.
after notice and hearing, establish units for oil and gas pools by a quantum not to exceed
thirty percent (30%) greater than the aforesaid limitation provided such action is justified by
sufficient technical data, indicating that such acreage or land in excess of the aforesaid
maximum limitations Is being drained or Is in Imminent danger of being drained and that the
owners of such said excess acreage or lands that the persons owning any Interest or
combination of interests in such said excess acreage or lands cannot othenA/lse receive their
just and equitable share of production from the pool being so drained; provided, however, in
the event such excess lands or Interests are Integrated or pooled by order of the Board, then
the provisions of Section 9-17-13 of this article shall be applicable to such owners of tracts or
interests In such acreage or land in excess of the aforesaid maximum limitations so that the
(*)
operator of the drilling or production unit in which such tracts or interests are included shall
have the right to charge against the Interest of each other owner in the production from the
wells drilled by such designated operator the actual expenditures required for such purpose,
not in excess of what are reasonable, including a reasonable charge for supervision; and the
operator shall have the right to receive the first production from such wells drilled by him
thereon which othenvise would be delivered or paid to the other parties jointly interested in
the drilling of the well so that the amount due by each of them for his share of the expense of
drilling, equipping and operating the well may be paid to the operator of the well out of
production, with the value of production calculated at the market price In the field at the time
such production is received by the operator or placed to his credit.
Notwithstanding the provisions of this section, ail persons entitled to share in the
production of oil or gas from a tract or interest or tracts or Interests in land may voluntarily
agree to the creation or establishment of a drilling or production unit, or may authorize one or
more of the persons entitled to share in such production to create or establish a drilling or
production unit, containing as much or more acreage or land than drilling units established by
the Board for the same pool, but not In excess of 160 acres or one governmental quarter
section, plus ten percent (10%) tolerance, in the case of oil and 640 acres or one
governmental section, plus ten percent (10%) tolerance, in the case of gas; subject to the
aforementioned qualifications In this section and up to thirty percent (30%) greater, as
provided hereinabove; a drilling unit so created or established shall, subject to the approval of
the Board, be valid and binding for all purposes even though such drilling or production unit
contains more acreage or land than the Board has Included, or is authorized by this section
to Include in a drilling or production unit established by it for the same pool; provided,
however, the spacing limitations set forth herein shall not apply to offshore wells and the size
and configuration of drilling and production units of offshore wells shall be as is determined
proper by the Board.
n
p-l
Eastern Gulf Region
n
"Drilling and Production Units and Well Spacing
n
Southwest Excel Field,
Monroe County, Alabama
Brian Sims
n
Consultant
n
!
n
1
fW|
ff
-9
COTTON
VALLEY
GROUP
HAYNESVILLE
FORMATION
"Megargel sand"
"Frisco City sand"
"Haynesviile sand"
g
CO
CO
g
UPPER
Buckner Anhydrite Mbr.
<
a:
SMACKOVER
FORMATION
o
N
o
CO
NORPHLET
FORMATION
HI
PlneJjîll_Anhy^t^l^r
LOUANN SALT
MIDDLE
WERNER
FORMATION
EAGLE MILLS
FORMATION
BASEMENT
COMPLEX
MISSISSIPPI
ALABAMA
Ae+
Jackson
Dome
Manila
\
^
y
Embayment
i'
>
/
A A A AA
^ ^
^
'estBwd ^
AMississippi
Fault
Interior Salt
Conecuh
/
AA System /f
Basin
^
\ -pollard Fault System ^ / ;
Qraben
Foshee
Baldwin High
^
Faulty ^
FLORIDA
System
LEGEND
(
\
Lower Mobile
-Approximate updip limit
'
Embayment
Fault Syst
of the Smackover Formation
-Salt-related anticline
Pensacola Area
Mobile Area
- Basement arch, ridge, or anticline
Viosca Knoll
Pensacola-De8tlnr^~rTT>^
Fault System
Apaiachicoia
Embayment
%
^
Area
-Salt-related fault-hachures on
downthrown side
Apaiachicoia Basin
-Salt dome
Destin Dome Area
0
•
10 20 30 40 Miles
I—I
I
I
I
DeSoto Canyon
Salt Basin
Apaiachicoia Area
1
J
JURASSIC
OIL AND QAS4X)NDEHSATE
TREND
FLORIDA
EXPLANATION
Approximats updip tbnh
of tiM Smackovmr Formation
Salt-r«l«t«d antlclino
X
Batmnant arch, rMga, or antlcllna
V
Salt*raUitad fault-hachuraa on
downlhrown sida
boundary
V. ^Trand
(daahad whara Infarrad)
0
10 20 30 40MilM
l_J
I—I—I
Seal*
/
X
\
/
/
.
^
/
ALABAMA
FLORIDA
20 Miles
Gulf of Mexico
SCALE
PLAYS AND SUBPLAYS
LEGEND
'\
'
Basement ridge play
A. Choctaw ridge complex subplay
-Approximate updip limit
of potential Jurassic reservoirs
B. Conecuh and Pensacola-Decatur
ridge complexes subplay
Regional peripheral fault trend play
-Satt-related fault-block on
C. Gilbertown and West Bend fault
systems subplay
D. Pollard and Foshee fault systems subplay
downthrown side
••' '•• •[
Mississippi interiorsatt basin play
Mobile graben fault system play
Wiggins arch complex play
J T6N
—
nr
t015'f-U\
EA5T FRISCO 'I
'.L
ff
•4 F JS
T
5
31^
11^
1=!
N
107^1-8
P (iHL
b.R.whAtlcy
GYf-'i 5-3
;o757-B
• No. I
i
6 ^SOUTTÊ^ST
es 6-11 , _
No.t I FRISCO ctry
I
3—
Vr
q.f f4e.(
6-2 Mo-1 0^
'I
ll'l
T5N
i
>
Ciry FIELD
vJulUei
fe-INo.l.
T 6 N
1—
1
t-|6 No.l
to/.J. I B
I Alf.iriHoKM
'
T ' ""
6-ifcNo.i
lObif
TT
)W
ii>
|;i
Curii* ijl
'•I
SL
I0tfc2-B
III
Carpertfer
i:
7-1 No. I
I
Nicholas 8-5
No.2
5402-AB
\
I SL Nicholos
8-5 No.l
F^-k>- 5402-B
^BHL<ACTUAL)
8
I0<)&0
• 9883
Peoc-Edge Petroleum
ATIC 18-12 No.l
Netfles 't-ti fJo.l
'I
N
r' sOUlHWEST ll
I EXCEL FIELD ||
!
il
I
sl9
II
lObO'f-Dt
ll
II
Noll lfe-3 Mo.l ST
Fl
.FilOSOVB
loqoH18
17
16
' I NoU
I
iL '
>1
:l
16
'I
I
ji
15
R.4W.
3
2 R.IW. R.1E.
EXPLANATION
MIOCENE
CRETACEOUS
2
OCX kW
3
R.4E.
HAYNESVILLE
fHj
SMACKOVER
NORPHLET
8 !i
M
R.13E.
O
m
T.IN
T.IS.
n
n
n
INDEX TO OIL AND GAS FIELDS IN SOUTHWESTERN ALABAMA^
6S
91.
23
Ap()l«(on(oil)T3N.ME
bitow Bend (Oil) T6N.RSt
B«ni«tt{0iI)T4N.R7E
Jt.
16
62.
BimirtB(gat.tlMn(ion(«l)T».IUE
B«nytO«m(olI)TI0N.R3W
B«youlen«<9n)T7S.R2W
72.
IS.
Beniflgmheinl(m(gts)T7S,IUW
BigEic*inbi«Crc«k(gncond«nMtc)TlN,
lire
1-1
n
43.
BlKltthc((oiDT3N.R4E
74.
BonSccaurB«y(9n)T8S.R«W
BO.
BrlghtoCttck(g«)T8S.ME
32.
78
B(ic«tunn*Cc(tli(on)TnN.KSW
Burnt Corn Citek<oiQT3N.R9E
69.
9.
40.
lOa
Flom«ton(gM<ondCRUtt)TtN.RtE
reiev(gn)T7S.R4E
96.
FrhC0CKy{0a)TSN,R6E
1.
79.
G<lb«f1own(o(QTI0N.R4W
G<nCr«tk(0U)TiaN.R4W
106.
56.
82.
102.
2S.
S9.
GrctnBrtnch(gat)m,ft2E
Gulf SUM Park (gat) m. R4E
Kali Creek (oil) T2N,RSE
Kanbeny Church(oil)T3N.R9E
Hatter'tPond(gMCondenutc)T2S.RlW
KtaflngSprings(gat cendentate)TBN,
R4W
Catlwt»t|lc<n9i(oa)TIN.R9E
81.
61.
31
Chapp*IIKm(o<l)tltN.K3W
S3.
12.
Chilem{g«tcendenMle)T6N.R4W
S4
a«wenCracli(ell)TlN.ftSE
B.
21.
Choct<wRidge(on>TiiN.MW
Otun<hgli{gMcon<JenMt*)TIS,R2W
3.
68.
92.
FolhM(0iI)T2N,RSE
Heton Bayou (gai)raS.R2W
Hubbard't landing (oO)TIN, R2E
Hu>ford(eiqT3N.fttE
Langidalc(eil)TUN.R5W
66.
M.
33.
44.
Latham (oil) T2N.R2C
littleEtcaRiWaCrcek(oit)TIN.i«9E
little Mm Oeek(oH)TtON.R3W
Uttle River (on. abandoned) T3N.R4E
North Bayou lonat (gat) T7S.R2W
North Central Gulf-Mobile Area (gat) T9S.
17.
99.
76.
86.
88.
97.
94.
101.
S8.
North Choctaw Ridge (0(1)Tt IN. R3W
North Cooper't landing (gat) TBS.R3E
NotthO«lch»mpt{9at)T7S,R2W
North Heron Bayou (gat) r7S. R2W
North Monlouitltland (gat) T7S,R2W
North Swiftt landing (gat) T8S.R3E
Northwett Gulf-Mobile Area (gat) T9S,
South Weekt Bay (gat. abandoned) I8S.
71.
South Womack Hill (Oil) ftON.R2W
93.
Southeait Mobile Bay (gat) T9S.RIE
8$.
Southwett Barrytown (oil. abandoned)
3S.
Souwllpa Creek (gat condenviie)l9N,
R3E
TI0N,R3W
R4W
36.
Stave Creek {oiqT7N. RIE
20.
Sugar Ridge(oil)TIIN.R3W
Pace Creek (eil)TlON.RtW
Perdido(oil)TIN.RSE
84.
Swiftt landing (gat) TBS.R4[
Tentaw lake (oil. abandoned) Tin. R2E
To>ev(oil)TltN.R3W
Turkey Creek (oil) TtON. R2W
4S.
Pleatant View (gat) TBS.R4E
60.
Point Judith (g^TBS. RIW
4.
34.
PolUrd{e<l)T1N.RSE
Putt Cutt Creek (oil, abandoned) T9N.
R4W
SS.
63.
98.
South vocation (oil) T4N. R6E
46.
RIW
Red Creek (gat condentale)T7N,R4w
St. Paul't Church (gat) T7S.R2W
Schoolhoute Branch (gat) T7S.R3E
6.
7.
10
83
13.
18.
104.
70.
Turnervtlle (otq T IS. R1W
Uriah (oil, abandoned) T4N. RSE
vocation (o>qT4N.R6E
Wallace (olQ T3N. RtE
Wallert Creek {oiqt«N.RSE
S.
38.
Citn>n«Ot(oiqT2N.R3W
CeMOeck«l«)Tlf.ll1W
17.
Wett Barrytown (oiqi ION. R3W
89.
little Rock (gat condemate)T2N,R7E
26.
Stlat(0iqT1IN.R4W
37.
W«t Bend (OiQ T ION. R2W
64.
Coopw'lUndingCgariTSS.UE
47.
lovetUCreek(oil)TSN.RSE
S7.
Sitemore Creek (oil; gat condentate) T7H.
73.
Weil Dauphin Itland (gat) I9S. R3W
Wett Foley (gat) T7S.R3E
48.
Skunk Bayou (gat. alMndoned) TBS.R3E
22.
Ceptland (g« (ondcnwte: oil.
abandoa«d)T6N,1UW
41.
lower Mobile BayMaiy Ann (gat) T9S.
52.
7$.
SO.
9S.
Cypreit Point (gn) TBS, R3E
EntBtV0Ul0nat{gat)T7S,lt2W
EaMOrttCfB«y(gM)T9S.iME
Fttiwty(9n)T9S.iim
67.
Magnolia River{gai)T7S,R3E
30.
24.
MeMn(oll)TnN,RSW
Mill Creek (oil) TtON,R4W
87.
MonlouH Wand (gat) T7S,R2W
19.
rannyaiurch(oiqT1N.RSE
49.
MovlcO{oa)T1N.RIE
RIW
R7E
tOS.
2.
39.
South Burnt Coin Creek (oil) T3N,ft9E
South Carlton(oiOT3N,R2E
South CoWCreek (oil, abandoned) TIS.
K1W
SI.
South Foley (gat) TBS.R4E
howmMpandrangenumbert areprovided at • generalited guidetoruteInlocating fieMt en figure I.
Figure 1.-OH and gas fields In southwestern Alabama
n
90.
RIE
42.
103.
WettFoshee(oiqT2N,R8E
28.
Wlinbefly(oiOTllN,R3W
14.
Womack Kill (oil) TION. R2W
29.
ZIon Chapel (oil. abandoned) T9N.R4W
1
J
J
J
3
1
Alabama Oil & Gas Board Field and Unit Map
Portion of Monroe County
COUNTY*
yoMnc
iCiUf.
fCLOSi
NdtTH rmco m
ntsce oTv
iccMioa
soi/nciiST rmcQ ovt
nohtm cxca
MomvuLC.
^WTMST
JOItf & lUtL
R7E
SPOONERByr^/32-/3
31
32
BHL - r^- «2
n
IEast Frisco Field
I
C0BKMVe^r6-l„Q
COBRA Byrd 5-3
COBRA Walker^-8\^
-11,800
Cumulative Production to 1-1-97
Cumulative Production to 1:4-97
37,546 BO, 35,546 MCFG
97,750 BO, 78,390 MCFG ^
Shut-in
pw)
J2
COBRAAlbritton 6-16.
#1
n
STRUCTURE MAP
Top Frisco City Sand
F-i
Horizontal Scale
1000
n
r»
n
"^^00
R7E
PI
INTERNATIONAL PAPER
Lancaster 18-14
SPOONER Beard 18-15
n
I
T
m
I
6
N
n
n
n
SEISMIC STRUCTURE
Frisco City Sand
1000
n
2000
2.360
SPOONER PETROLEUM COMPANY
SPOONER PETROLEUM COMPANY
Carbon 31-9 #1 (STH)
Carlson 31-9 §1
^ +/-150
Anhydrite Marker
vdrite Marker
P
5E±2EE56!£«
Basement
rtRMAiO
FMRoKlingOal
Basement
IU>M RMhtM^ÔLO)
TSUaa ~ ~
nOOM
SI Read
Total Oepi
12300
AIT 10 IncMmmtaaasa MTtO)
nil Slg (PS)
m
(QMIM)
1"
tlL9
looao;
AIT20 Indl InvMtljiUanjATJO;,
HstaOltadtrmm
l«.0!
^WM)
M
MOOiO:
Air MIncii liiv««l»Ua^nsi_
IM&i-
'...jio
Tohmm)
,M
2000.0
1
AIT H IncO lavt^tDon (ATd8>
a!o
(OKMIQ
ii&e
4^
.
0
oiv)'
SobS#
AIT M tach lavtMlataoa (ATtO)
SP(8P>
4ae
az
(OMIM)
Cumulative Production to 1-1-97
455,033 BO, 631,668 MCFG
aoooio
(LBF)
too&a
TORCH OPERATING COMPANY
Paramount-McCall 25-7 U1
11400
aihinii
rysKaii
Uiirii
Wwsil
•lllllll
•llllili
•lllllll
•lllllll
^Haynesville
11500
•lllllll
•llllili
•lllllll
n
lllllll
lllllll
III Ml
111 111 BbE'I
lllllll9>i"
lllllll
11600
iSnriji
lllllll
lllllll
llll!l
lllfli
lllllll
n
n
11700
Hkiic
11800
n
n
ônnn
Frisco City Sand
12100
Basement
12300
n""
iiiiii
•lllllll
'iiiiiiii
n
,vy-
n
Paramount-Lancaster 3(^5 #1
TT
••IIIKiCVBLllllll
•mil
•mil
•mil
•••III
Haynesville
•mil
•mil
•mil
•mil
•mil
•mil
•mil
••••tiiiiii
!EZZ«iiidlllll
•mil
•mil
•mil
•mil
t1600
•mil
IVF-:»IIIII
•IIIIIIHBPr-.:::ilBHHmil
•iE:iiw :iiiiiiiHiH^mii
•iiiiiiftifr'4iiiiiiHH^mii
•iiiiiiHHkk
*-T!9i«amii
•IIIIIIHlHlli;r'^-^Wrfmil
•iiiimHM"!'':^3^mii
•IIIIIIHHLL!!<!'^H^mil
•IIIIIIHH^r JiiLl'imil
•iiiiiHHî
.•{••••mil
•IIIIIIHIE:'
MIIIHHÎIIII
•IIIIIHH^l^ iniHlHÎIIII
•llllimH^V- 'HHÎIIII
•IIIIIIHIHÎZ^.
V*^H^mil
•IIIIIHHVrj
ll
-irsa^lllll
•llilllHIH^k^:*<l«iH^mil
•IIIIIlHHÎCi'f': -"••mil
•iiiniBHBi».'»L^HHiini
•iiiiiMHimiiiT.•^•iiiii
illllllBaHlliikk' ;:3B»IIII
•iiiiiiHiHiibiii
'
•llilllHHIF!>V
•IIIIIIHHllllli;:'
;3HIHIII1I
SCO City Sand
Basement trttffl—
r:
• IIIIIIBHBBIIIIIliS'.:.
•miiiHiHiiiiiiCL:. -;:p!;
•miiiHiHîiiiiiHiai^L
•iiiii]BHai^miiiRr?:7r7:
•iiiiiiaaiP^r^f:: âiiiiimi
•P!!;v«ift:3::iiimBimiii
•ii:ii:ir-:r3c:!i!:T-"!imiii
•m.''::^~^SiilfmillHiHIIIIIII
imiillHL::«'>r/'i|i^Hli|||||||
iiiiiiiHBaiini xîjaBiiiiii
•IIIIIIHIHIIIIblWHHIIilli
Paramount'Boone 30-16 M
•llirimpillllll
n
•iiiiiiic:3!»-:3iiiii
Haynesville
a<--iieoo
•iimni>«iiiii
11700
•IIIIIIBHBr->1111
•IIIIIIHIL—lllll
•IIIIIIHHk. mil
miiiiii
• t -ail
V-zz
iigoo
m
mtv' îHiiiii
•ll>or^«||||||
•iiiiiikr^'
•IIIIIIL'.
•Illlll^^
--"am
*11111
TJ^B
•IIIIIIBBF .illlll
Frisco C
ty Sand
•iiiiiir:-«aiiiiii
••iiiiii
sasement
n
12200
• lllllli
Vlllllll
~::3iiiiii
n
oiiiDtiith
n
TOflB
^
J
J
1
1
1
CLAYTON W. WILLIAMS, JR.
Joe Enzor 25-5 U1
U900
iiEiiir'iiii]ii!iiE3
Sdi clr pnk fti-re
gr unccp-laly ccr
nhy; who sft-(iju
ctlii
12000
Sh:
hm r s t dk
cry l»lky brit-frr
slty ndy mica
IStlllllllil
12100
An}»y: v;M puV cfl
xtln xlliJ Tamii-al
12200
Frisco Qty Sand
:.tl: clr rnK rc.fi \
V rii-rje«l i:r • licot
Irl;/ cnm :;li calc
r-/ anliyciritic
12300
l.f?:
buff* tail 11
»
I'nl;,- xi h»-yt.l!»
>'.rnT>i I«r ?•/ iln
I l(% I >
t ' t <'
12U00
I.II:
f AJ
• « • •
11 -I-
xtlii-J'nly *• 111 p/
CCRE #1
All
<hin iintomtl.lr
l|'fi! pnk f'lr rn«
125)'00
ziicia»sii
ENERGY DEVELOPMENT CORP.
NaU 16-3 m
Haynesville
n
^SS!
12400
Frisco City Sand
1
Buckner
AS • • i * Uj) SPTTl ••
• •
B.<SHigii:zrmicr^wa
n
NaU 16-3 m
Haynesvilie
12000
12100
12200
12300
MBIIII
12400
•••115^^
^:-:-rfirrnTrn:
risco City Sand
12500
—
Buckner
'""mil
CS7J»««il
12600
SSEEa^H!)
•
•KdS?.
••sazE
Smackover
12700
••Ksqa
• •KMI
n-OD^B""
TTttAvr,.
Basement
mt— .
•-viMaiHIIII
12900
Nettles 9-12
Haynesville
I Frisco City Sand
Wl Buckner
n
Nettles 9-12 #1
11900
HaynesviUe
.Aflll
i««BI
12100
12200
12300
•
•-•'^^==EE=
12400
••l—igtoi>i:3^r===
••I—
Frisco City Sand
12500
Buckner
12600
•IBEHh^l
Smackover
wcrrtcdii
12700
Basement
12800
•Ba7.«
•••fi
•
vrsiil
•HliKS
•
•••I
•
•••I
m
Eastern Gulf Region
Southwest Excel Field,
Monroe County, Alabama
Robert Wood
Tom Joiner & Associates
R 7 E
10
PROPOSED
PALEOZOtp
BASEMENT -
ID
ISO •
h-
no •
• 240
• aso
*-o
Energy Development Corp.
PROPOSED EXCEPTIONAL LOCATION
SOUTH EXCEL PROSPECT
MONROE COUNTY. ALABAMA
STRUCTURE MAP
LEGEND
—
LOWER HAYNESVILLE SEISMIC MARKER
PROPOSED 40 tc. DRILUNQ UMIT
SCALE IN FEET
C.I.- 0.010 SECONDS
Ejllilbll No._^Dook«l Ho^ 8-3-848
Oal«aZZlfiZSlPr«pi««d by
RohoH t. wood
PfSMted ay:
Tom Jolnor And Attoelaf» Inc. Con«ulllt>fl OmIooUU And Englneors
R 7 E
t
-'2.300'
I0604-e
^ ^^-12.0S1'TVC
Cmw 0**»logm*»l Cotfi.
Allrta Noll 16-3 No.l •
TO 13061
aoo
• 330
120 •
• 340
Exhibit No._2
Docket No.2-l-0Sll & 2-i-flSi2
Datit 1/18/06 Prttnntttii by
R. T. WOOD
Enorgy Development Corp.
LEG B N V
PROPOSED
SOUTHWEST EXCEL FIELD
EXISTING 40 ACRE DRILLING UNIT
MONROE COUNTY, ALABAMA
PROPOSED 160 ACRE PRODUCTION
UNIT
2000
PROPOSED FIELD LIMIT
SCALE IN FEET
STRUCTURE MAP
TOP OF FRISCO CITY OIL POOL
C.I. = 100'
Proparad By
TuinJouwr AndAssoclales Inc.Contulling O«olooi*t»AndEnainaofs
R 7 E
-»2.aoo
170 •
"'2.200
I0604-a
• BKL~
s3«rssr'
PROPOSED EXCEPTIONAL
LOCATION
*240
Exhibit No.
Dockol Mn
Palo 3/8/05 Proomad by
3-22-9526
R. T. WOOD
LEG EH 1>
O
PROPOSED
MONROE COUNTY, ALABAMA
PROPOSED 160 ACRE DRILLING UNIT
STRUCTURE MAP
PROPOSED SOUTHWEST EXCEL FIELD
SCAl E III FEET
TOP OF FRISCO CITV OIL POOL
C.I. = 100*
Prspated Oy
luiii JuMKi Anil Abtocljlm liic Conmlltno 0«oloo>kU And tnguiawk
R 7 E
170 •
s
0180
«y
%
IK
°
O/W CON"ACT -12,113'
Eneray Devetogment Corp.
•140
TD 1306^
-i2.osn ^
z
I
Alfred Noll 16-2 No.l
•
1-^
!?
1130 •
EnergyDtrtlopmenf Cirp,
Alfred Nalil6-6 rto.l |
y
PROPOSED EXCEPTIONAL
i^QCAflON
120 •
• 240
Energy Devetopment Corp.
UOENd
O
EXISTING 160 ACRE PRODUCTION UNIT
EXISTING SOUTHWEST EXCEL FIELD LIMIT
Exhibit No. 6
Date
poBkiH No-
Prepared by
7-17-957
R.T. WOOD
STRUCTURE MAP
1000
C.I. - SO'
Scale In Feet
Dy:
Tom Jaln«r And At«ocl«Ui Inc. ContulHng OMiogttI* And Enginwd
R 7 E
170 •
$
ei8o
<y
-12,051 TVD
0/W CON
•140
ed Nol
13061
/
O
2
n
-12,113'
Energy DttttoemtM Corp
•
1-12,042 TVD
.^7
7T
LO
10904^'^'"
130 •
£ti«rgyOevttopmtnt Ci
Alfred Noll 16-6 No. I |
1
EXCEPTIONAL (
J
Dolcîon
120 •
•
240
Energy Development Corp
UGEHd
O
—
—
EXISTING SOUTHWEST EXCEL FIELD LIMIT
STRUCTURE MAP
Exhibit Mo._Ôockel No. 12-13-9519
Oete 12/13/95prepered by
n
R.T. WOOD
0.1. « 50
Scale In Feet
PttoMM ev
Tom Jolntf And AttecItU* Inc. CensiiHIng OMteaUlt And Ena>n«w«
-".ISO
SOUTHEAST
FRISCO CITY
-ia.too
-12.098 TVD
-I3.0U Encr<w Oe»eJop«tnni Cwp.
Nclllet 9-12 No.1^
TO 12 8S0'
NN
I
m
ESTIMATED
O/W CONTACT -12.113*
(J60'l-H
Energy Ocvctopmtni Corp
Null Id 2 Nu. I If I
IV
•,0.3 06r
-12.043
/// b
^
/
I\:
SOUTHWEST EXCEL
Ocvtiopmeni
'6 I
1263^
Ealiltill Na._£_Dooh«l Mo.®l2lS22i:22:22:2?
p..-2/21/96i...B...d by ROBERT T. WOOD
Energy Dovolopmont Corp
LEG B N P
EXISTING 160 ACRE UNIT
EXISTING.40 ACRE DRILLING UNIT
STRUCTURE MAP
PROPOSED 160-ACRE PRODUCTION UNIT
EXISTING FIELD LIMIT
PROPOSED FIELD LIMIT
1000'
2000
I
SCALE IN FEET
•••.liu.ll
m
ll>
M
A..KIMM M. Con.ultblO OM<llK|l>li
f—\
-14.16®
80UTHBA8T
{
Fmsco^cmr^
t9
la.^ Efttfffir Devtlêni
Nettles
ORIGINAL ESTIMATED
O/W CONTACT -12.113'
0604
-19.010 TVO
jl0604-8-l
Noll 16-3 Na I ST N
'
Energy Oevclopmefll Corp.
Nan 16-2 No. I
TO 13 06i:
ia.ooo'
iCo ênergy
energy (Oevelopmeni CorSV
• il^Noll
:!-Noll 16-6
16- No. I
y
,40^
TO 12835-
p-n
Eiililbll No._E_Dock«t Mo. 6-16-965.066
n... a/7/Ba Prcparad by
ROBERT T. WOOD
Knergy Dovetopment Corp
n
LEO B N V
STRUCTURE MAP
EXISTING 160 ACRE UNIT
1000'
PROPOSED 208 ACRE PRODUCTION UNIT
EXISTING FIELD LIMITS
PROPOSED UNIT EXTENSION AND
FIELD LIMIT REDEFINITION
2000'
I
SCALE IN FEET
(Jy
Iwm
M
A«»OCl*l«t IM. CentwItlM UêteuliU Att4 kMmt»
-la.iW
SOUTHEAST
FRISCO CITY
0
\:I\C
^HPW (-12.086 TVD)S\ •
-iztoo
-is.osa
•
Entray De«cWn«nl Cor^.
VwefttM 9-12 No.l^
^^TDIZ850* \\N
X-12.001TVD,
ORIGINAL ESTIMATED
O/W CONTACT -12.113*
-12.010TVD ♦bw.
•
-B-l <•—-C
.
\r
Devrtopmwt
Energy D^«1cpm«flt,Cfrp.
Energy Oevtlopmfnt Corp.
''on 13
"»-2
osr,No.
I ST
Noll 16- 3 Na 1ST
-12.000
.4S.q4gTyD
ton
tnergy De*«<opment
•^r^Noil 16-6 No.I V
12835
EHhIbll No.—^•Docket Ma. 7'-17-9613.14
n««- 7/1/96 Pr«n».««i by ROBERT T. WOOD
Mnorgy Dovelopmont Corp.
LEG B N d
STRUCTURE MAP
PROPOSED 12 ACRE UNIT EXTENSION
SCALE IN FEET
MURPHY HEIRS TRACT
linn MMm
A»»ocl»l»l
Contudliv OMtaglil. M
tUfXlf
%u.<
•t
'UVUSUVI
SOUTHBAST
^FRjSCO_C|TV^
F/M4/. 20S ACRE
8
PRODUCTION UNIT
10960
i
E
Encrqy OcMlopmcnl Cor|x
Nettin 9-12 No. I
TO 12 890'
Ij
is.-simFmSmSmSni lS»a*M*T«**»rfIT« T
I;
I:
I:
im}
FINAL 172 ACRE
PRODUCTION UNIT
sto^
\
r 'l0604>B-l
10604-
V
ii
10604-8
"•♦bKt
O
rOevetopmctu
Corp. Eneray
Ngl T6-2Development
No. I
I^We-
B-3 Na I ST
Ij
Corp. j;
TO 13 061*
Ij
il
I:
L-'l09?)l%'
Noll l6-6 No. I
TO 12839'
160 ACRE
PRODUCTION UNIT
/7
r-^
16
SOUTHWEST EXCEL
m Avwm
g
m ^miYVavn nnr^m ffTV*TmTV {
Extilbll No._!_Dochal W" 7-17-0613.14
f-»
n... 7/1/96 Pr«B«r«d by
ROBERT T. WOOD
Energy Developmont Corp.
LB$BH d
EXISTING PRODUCTION UNIT
FIELD DEVELOPMENT
MAP
1000'
2000*
SCALE IN FEET
f»M jQlmf And AVMCUtM IM. COfMUttlAO
All4

Drilling and Production Units and Well Spacing

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