Transcript North Dakota Department of Mineral Resources http://www.oilgas.nd.gov http://www.state.nd.us/ndgs 600 East Boulevard Ave. - Dept 405 Bismarck, ND 58505-0840 (701) 328-8020 (701) 328-8000

North Dakota Department of Mineral Resources
http://www.oilgas.nd.gov
http://www.state.nd.us/ndgs
600 East Boulevard Ave. - Dept 405
Bismarck, ND 58505-0840
(701) 328-8020 (701) 328-8000
North Dakota New Well Permits Issued
2000
1800
1600
1400
1200
1000
800
600
400
200
0
1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010 2015
North Dakota Average Monthly Rig Count
250
200
Rigs
150
100
50
0
1975
1979
1983
1987
Rig Count
1991
1995
ND Sweet Oil Price
1999
2003
2007
2011
2015
144 Rigs
200 Rigs
15,000,000
14,000,000
13,000,000
12,000,000
11,000,000
10,000,000
9,000,000
8,000,000
7,000,000
6,000,000
5,000,000
4,000,000
3,000,000
2,000,000
1,000,000
0
1985
1990
$ perMCF
1995
2000
2005
2010
MCF GAS PRODUCED
$30
$28
$26
$24
$22
$20
$18
$16
$14
$12
$10
$8
$6
$4
$2
$0
2015
$/MCF
MCF
North Dakota Monthly Gas Produced and Price
North Dakota Monthly Gas Flared
35%
30%
25%
20%
15%
10%
5%
0%
1985
1990
1995
2000
2005
2010
2,400 wells=90MW
5,000 wells
=185MW
File No Status Sec Twp Rng
Spot
Operator Name
Well Name
Field
19051
DRL
10
162
78 SESE
SURGE ENERGY USA INC.
EIDSVOLD 1-10H
WILDCAT
18701
A
36
164
78 NESE
SURGE ENERGY USA INC.
SCANDIA 3-36H
SOURIS
18997
IA
27
163
78 NENE
SURGE ENERGY USA INC.
BOUNDARY 4-27H
WILDCAT
19099
IA
20
163
78 SWNW
SURGE ENERGY USA INC.
BOUNDARY 11-20H
ROTH
18699
A
34
164
78 NENE
SURGE ENERGY USA INC.
SCANDIA 1-34H
SOURIS
18898
A
11
163
78 NENE
SURGE ENERGY USA INC.
BOUNDARY 1-11H
WILDCAT
18783
A
28
164
77 LOT 1
CORINTHIAN EXPLORATION (USA) CORP
SKARPHOL 3-28
NORTH SOURIS
18709
A
27
164
77 LOT 2
CORINTHIAN EXPLORATION (USA) CORP
SYLVIA 1-27
NORTH SOURIS
19384
IA
33
164
77 NWSW
CORINTHIAN EXPLORATION (USA) CORP
BERNSTEIN 33C 1
NORTH SOURIS
19385
A
4
163
77 NENW
CORINTHIAN EXPLORATION (USA) CORP
BERNSTEIN 4B 1
NORTH SOURIS
19386
A
5
163
77 NWSE
CORINTHIAN EXPLORATION (USA) CORP
BERNSTEIN 1
WILDCAT
10318
A
28
164
77 SWSW
CORINTHIAN EXPLORATION (USA) CORP
SKARPHOL
7606
A
33
164
77 NWNW
CORINTHIAN EXPLORATION (USA) CORP
SKARPHOL 4-33
NORTH SOURIS
1401
A
34
164
77 NESW
CORINTHIAN EXPLORATION (USA) CORP
1-BACKMAN 34BCD
NORTH SOURIS
11317
A
4
163
77 NENE
CORINTHIAN EXPLORATION (USA) CORP
OLSON 2-104
NORTH SOURIS
4838
IA
28
164
77 SESW
CORINTHIAN EXPLORATION (USA) CORP
SKARPHOL
4816
A
33
164
77 NENW
CORINTHIAN EXPLORATION (USA) CORP
SKARPHOL 33-2
NORTH SOURIS
4817
IA
33
164
77 SENE
CORINTHIAN EXPLORATION (USA) CORP
SKARPHOL 33-3
NORTH SOURIS
4819
A
33
164
77 SESE
CORINTHIAN EXPLORATION (USA) CORP
OLSON 33-1
NORTH SOURIS
884
A
33
164
77 SENW
CORINTHIAN EXPLORATION (USA) CORP
SKARPHOL
968
A
33
164
77 NWSE
CORINTHIAN EXPLORATION (USA) CORP
MOEN
932
A
33
164
77 SWNE
CORINTHIAN EXPLORATION (USA) CORP
CARL
1038
A
33
164
77 NESE
CORINTHIAN EXPLORATION (USA) CORP
CLARA MOEN
19613
DRL
18
163
76 NWSW
LEGACY OIL & GAS ND, INC.
LEGACY ETAL FETT 12-18 1-H
WILDCAT
19612
DRL
1
163
77 NESE
LEGACY OIL & GAS ND, INC.
LEGACY ETAL BERGE 9-1H 1-H
WILDCAT
19588
DRL
12
163
77 NWSW
LEGACY OIL & GAS ND, INC.
LEGACY ETAL BERGE 12-12H 1-H
WILDCAT
19682
LOC
19
163
76 NWSW
LEGACY OIL & GAS ND, INC.
LEGACY ETAL FETT 12-19H 1-H
WILDCAT
20129
LOC
10
162
76 SWNW
LEGACY OIL & GAS ND, INC.
LEGACY ETAL BLISS 5-10H 1-H
WILDCAT
19462
DRL
19
163
76 NWNW
LEGACY OIL & GAS ND, INC.
LEGACY ETAL EMERY NORM 4-19H 1-H
WILDCAT
19567
DRL
10
162
76 SWSW
LEGACY OIL & GAS ND, INC.
LEGACY ETAL BLISS 13-10H 1-H
WILDCAT
21323
LOC
18
163
76 NWNW
LEGACY OIL & GAS ND, INC.
LEGACY ETAL BERNSTEIN 4-18H 1-H
WILDCAT
21389
LOC
12
163
77 NENE
LEGACY OIL & GAS ND, INC.
LEGACY ET AL BERGE 1-12H
WILDCAT
28-2
1-28
1
NORTH SOURIS
NORTH SOURIS
NORTH SOURIS
1
NORTH SOURIS
1
NORTH SOURIS
1-33
NORTH SOURIS
Western North Dakota
• 1,100 to 2,700 wells/year = 2,000 expected
– 100-225 rigs = 12,000 – 27,000 jobs = 20,000 expected
– 225 rigs can drill the 5,000 wells needed to secure leases in 2.5 years
– 225 rigs can drill the 28,000 wells needed to develop spacing units in 14 years
– 33,000 new wells = thousands of long term jobs
North Dakota Oil Production and Price
1,000,000
$1,000
900,000
P10
800,000
Barrels per Day
$900
$800
700,000
$700
P50
P90
600,000
500,000
$600
$500
400,000
$400
300,000
$300
200,000
$200
100,000
$100
2,600
Bakken and Three Forks wells drilled and completed
30,000
more new wells possible in thermal mature area
P90=5 BBO – P50=7 BBO – P10=11 BBO (billion barrels of oil)
History
Bakken - Three Forks P10
Bakken - Three Forks P50
Bakken - Three Forks P90
$/Barrel History & DOE-EIA Projected
$/Barrel P50
$/Barrel P10
2055
2050
2045
2040
2035
2030
2025
2020
2015
2010
2005
2000
1995
1990
1985
1980
1975
$0
1970
0
Typical Bakken Well Production
1200
1000
Barrels of Oil per Day
800
600
400
200
0
0
5
10
15
Year
20
25
30
What Does Every New Bakken Well Mean to North Dakota
A typical 2011 North Dakota Bakken well will produce for 28 years
If economic, enhanced oil recovery efforts can
extend the life of the well
In those 28 years the average Bakken well:
Produces approximately 550,000 barrels of oil
Generates over $20 million net profit
Pays approximately $4,360,000 in taxes
$2,100,000 gross production taxes
$1,900,000 extraction tax
$360,000 sales tax
Pays royalties of $7,600,000 to mineral owners
Pays salaries and wages of $1,600,000
Pays operating expenses of $2,300,000
Costs $7,300,000 to drill and complete
Cap and trade
proposals in
congress could
reduce activity
an estimated
35-40%
EPA regulation of
hydraulic fracturing
could halt drilling activity
for 18-24 months
production decline of
25-30%
Current
administration
budget
contains tax
rule changes
that could
reduce activity
an estimated
35-50%
Oil price below
$50 WTI could
reduce activity
an estimated
25-30%
The future looks promising for
sustained Bakken/Three Forks
development
Federal minor source air
permits require 6 -12
months for approval
MONTHLY OIL PRODUCTION FOR LOCAL COUNTIES
1,800,000
1,600,000
1,400,000
1,200,000
1,000,000
800,000
600,000
400,000
200,000
0
1977
1982
1988
1993
1999
BILLINGS
2004
2010
2015
MONTHLY OIL PRODUCTION FOR LOCAL COUNTIES
300,000
250,000
200,000
150,000
100,000
50,000
0
1977
1982
1988
1993
1999
BOTTINEAU
2004
2010
2015
MONTHLY OIL PRODUCTION FOR LOCAL COUNTIES
1,800,000
1,600,000
1,400,000
1,200,000
1,000,000
800,000
600,000
400,000
200,000
0
1977
1982
1988
1993
1999
BOWMAN
2004
2010
2015
MONTHLY OIL PRODUCTION FOR LOCAL COUNTIES
300,000
250,000
200,000
150,000
100,000
50,000
0
1977
1982
1988
1993
1999
BURKE
2004
2010
2015
MONTHLY OIL PRODUCTION FOR LOCAL COUNTIES
800,000
700,000
600,000
500,000
400,000
300,000
200,000
100,000
0
1977
1982
1988
1993
1999
DIVIDE
2004
2010
2015
MONTHLY OIL PRODUCTION FOR LOCAL COUNTIES
3,000,000
2,500,000
2,000,000
1,500,000
1,000,000
500,000
0
1977
1982
1988
1993
1999
DUNN
2004
2010
2015
MONTHLY OIL PRODUCTION FOR LOCAL COUNTIES
160,000
140,000
120,000
100,000
80,000
60,000
40,000
20,000
0
1977
1982
1988
1993
1999
GOLDEN VALLEY
2004
2010
2015
MONTHLY OIL PRODUCTION FOR LOCAL COUNTIES
4,500
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
1977
1982
1988
1993
1999
McHENRY
2004
2010
2015
MONTHLY OIL PRODUCTION FOR LOCAL COUNTIES
5,000,000
4,500,000
4,000,000
3,500,000
3,000,000
2,500,000
2,000,000
1,500,000
1,000,000
500,000
0
1977
1982
1988
1993
1999
McKENZIE
2004
2010
2015
MONTHLY OIL PRODUCTION FOR LOCAL COUNTIES
100,000
90,000
80,000
70,000
60,000
50,000
40,000
30,000
20,000
10,000
0
1977
1982
1988
1993
1999
McLEAN
2004
2010
2015
MONTHLY OIL PRODUCTION FOR LOCAL COUNTIES
10,000
9,000
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
0
1977
1982
1988
1993
1999
Mercer
2004
2010
2015
MONTHLY OIL PRODUCTION FOR LOCAL COUNTIES
8,000,000
7,000,000
6,000,000
5,000,000
4,000,000
3,000,000
2,000,000
1,000,000
0
1977
1982
1988
1993
1999
MOUNTRAIL
2004
2010
2015
MONTHLY OIL PRODUCTION FOR LOCAL COUNTIES
180,000
160,000
140,000
120,000
100,000
80,000
60,000
40,000
20,000
0
1977
1982
1988
1993
1999
RENVILLE
2004
2010
2015
MONTHLY OIL PRODUCTION FOR LOCAL COUNTIES
70,000
60,000
50,000
40,000
30,000
20,000
10,000
0
1977
1982
1988
1993
1999
SLOPE
2004
2010
2015
MONTHLY OIL PRODUCTION FOR LOCAL COUNTIES
700,000
600,000
500,000
400,000
300,000
200,000
100,000
0
1977
1982
1988
1993
1999
STARK
2004
2010
2015
MONTHLY OIL PRODUCTION FOR LOCAL COUNTIES
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
1977
1982
1988
1993
1999
WARD
2004
2010
2015
MONTHLY OIL PRODUCTION FOR LOCAL COUNTIES
5,000,000
4,500,000
4,000,000
3,500,000
3,000,000
2,500,000
2,000,000
1,500,000
1,000,000
500,000
0
1977
1982
1988
1993
1999
WILLIAMS
2004
2010
2015
Uranium
Sea Level
Estimate 800,000 tons of ND Mineable Reserves
$64 billion
Sea Level
Potash
Prairie Fm.
Estimate 20-50 billion tons of ND Mineable Reserves
$6 trillion -15 trillion
We have received a number of enquires from the mineral industry in the past 18 months as
the price increased for a variety of elements and minerals. Chief among these enquiries has
been uranium and potash. Uranium was mined in North Dakota in the 1960s. It was
heavily explored for in the 1970s, but has been of little interest for the last 30 years until
the price for uranium oxide reached an all time high in June of 2007. Companies have also
expressed interest in associated elements molybdenum and germanium. If a company
submits a permit to do in situ leach uranium mining, we will need a geologist dedicated
full-time to that project. We are aware of three companies that are contemplating mining
uranium in southwestern North Dakota.
Potash or potassium salts are primarily used in the production of fertilizer. Potash
exploration took place in northwest North Dakota in the 1970s. Since the beginning of
2007, the price of potash has risen from $190 to $1,050 per ton based on a low supply and
increasing demand. Due to the increased workload, we will need a geologist to oversee
potash exploration and production if we receive a permit from either of the two companies
that we know are actively pursuing potash exploitation.
Potash core from a depth of 9,000 feet
in Burke County.
Formation Resources drilling for uranium, molybedenum, and
germanium under a subsurface mineral permit in Billings
County during the fall of 2008.
Counties that contain uranium deposits are in yellow and those that contain the
shallowest potash deposits are in blue.
SUMMARY OF PROPOSED 2012 RULES
NDAC
RULES
43-02-03 GENERAL RULES
43-02-03-05
Enforcement of Laws and Rules
43-02-03-15
Bonds
43-02-03-16
Permit to Drill
43-02-03-16.3 Recovery of a Risk Penalty
43-02-03-18
Drilling Units
43-02-03-19
Site Construction
43-02-03-19.1 Fencing, Screening, and Netting of Pits
43-02-03-19.2 Disposal of Waste Material
43-02-03-19.3 Earthen Pits and Open Receptacles
43-02-03-19.4 Drilling Pits
43-02-03-19.5 Reserve Pits
43-02-03-21
Casing, Tubing, and Cementing
43-02-03-25
Deviation Tests and Directional Surveys
43-02-03-27.1 Hydraulic Fracture Stimulation
43-02-03-28
Safety Regulation
43-02-03-30.1 Leak and Spill Cleanup
43-02-03-31
Well Log, Completion and Workover Reports
43-02-03-34.1 Reclamation of Surface
43-02-03-49
Oil Spills, Prod Equip, Dikes, and Seals
43-02-03-51
Treating Plant
43-02-03-53
Saltwater Handling Facilities
43-02-03-54
Investigative Powers
43-02-03-55
Abandonment of Wells-Suspension of Drilling
43-02-03-88.1 Special Procedures Administrative Hearings
43-02-03-90.2 Official Notice
43-02-12 GEOPHYSICAL EXPLORATION REQUIREMENTS
43-02-12-06
Notification of Work Performed
PROPOSED CHANGE
Move language to 43-02-03-28 (Safety Regulation)
Increase $20,000 bond to $50,000
Commercial SWD bond increased from $20,000 bond to $50,000
Eliminates $50,000 10-well blanket bond
Consider csg imbrittlement due to H2S when considering recompletions
Clarify that "approximate" well loc is to be included in the invitation to participate
Requires the drilling or spacing unit be included in the invitation to participate
Allows temporary spacing order effective for up to 3 yrs, not 1-1/2 yrs
Amends rule to address only initial well site construction
Soil stabilization additives and materials require approval from Director
Must reduce size of well site after completion if not used f/well operations
Amended to also address "drilling" pits which were newly created
Requires all waste material from undesirable events to be immediately disposed
Requires flare pits to be at least 150 feet from wells and tanks
Allows lined fresh wtr pit for frack water f/1yr in cut w/only drinking wtr chemicals
Creates new section addressing pits allowing cuttings, but no fluids
Must reclaim pit w/in 30 days after drilling well; Director may grant exceptions
Allows small lined pit f/trench water and rig wash, but reclaim before MORT
Must dike pit to keep surface water from entering
Creates new section allowing reserve pits only for wells < 5000' deep or SWD
Must reclaim pit w/in one yr after completing well
Must slope surface to promote surface drainage away from reclaimed area
Requires remedial work f/inadequate sur csg job to be approved by Director
Requires surface casing pressure test after cementing
Requires directional surveys to be in reference to true north
Creates new section addressing hydraulic fracture stimulation
Must use popoff valves, rupture disk, remote valve
Use frack string: no chem disclosure if > 350psi on annulus after frack
Frack down csg: run csg evaluation f/thickness of csg and cmt w/chem disclosure
Incorporated language removed from 43-02-03-05 on well shut in f/public safety
Requires automatic shut-down equip if well is threat to public health or safety
Prohibits injection equipment from being installed < 500' from occupied dwelling
Creates new section and incorporates language from 43-02-03-49&53
Requires operators to respond w/appropriate resources to contain & clean up spills
Run CBL prior to completion
File two digital copies of logs, instead of one digital and one paper
Creates new section to address final restoration after well is plugged
No additional requirements: Language taken from 43-02-03-19
Amend rule--move spill reference to 43-02-03-30.1
Must remove "unused" equip rather than "unusable"
Increases minimum bond from $20,000 to $50,000 for treating plants
Amend rule--move spill reference to 43-02-03-30.1
Requires oil recovered from saltwater handling facilities to be reported to Director
Must remove "unused" equip rather than "unusable"
Director can timely (instead of "immediately") reply to a complaint
Allows Director to decline to investigate--can appeal to IC
Abandonment will now include water source wells and stratigraphic tests
Allows applications for additional wells on a spacing unit without live testimony
Comments and objections to hearings must be rec'd prior business day by 5pm
Comments and objections to hearings must be rec'd prior business day by 5pm
Director may require progress reports prior to completion of a project
43-02-03-27.1 Hydraulic Fracture Stimulation
Creates new section addressing hydraulic fracture stimulation
Must use popoff valves, rupture disk, remote valve
Use frack string: no chem disclosure if > 350psi on annulus after frack
Frack down csg: run csg evaluation f/thickness of csg and cmt w/chem disclosure
TYPICAL HORIZONTAL OIL WELL
Potable Waters
4.5”
Frack
String
Cement
Packer
Run in hole with:
• 4.5” liner
• 30-40 swell packers
• sliding sleeves
• 4.5” frack string
• 5th layer of protection
Upper Bakken Shale
Middle Bakken
4.5” liner
Lower Bakken Shale
Hydraulic Fracturing
Stimulation is Safe
• IOGCC survey—no contamination
• EPA survey – no contamination
• GWPC study verifies State’s regs
• GWPC National Registry f/chemicals
•FracFocus
43-02-03-19.4 Drilling Pits
43-02-03-19.5 Reserve Pits
Creates new section addressing pits allowing cuttings, but no fluids
Must reclaim pit w/in 30 days after drilling well; Director may grant exceptions
Allows small lined pit f/trench water and rig wash, but reclaim before MORT
Must dike pit to keep surface water from entering
Creates new section allowing reserve pits only for wells < 5000' deep or SWD
Must reclaim pit w/in one yr after completing well
Must slope surface to promote surface drainage away from reclaimed area
43-02-03-28
Safety Regulation
Incorporated language removed from 43-02-03-05 on well shut in f/public safety
Requires automatic shut-down equip if well is threat to public health or safety
Prohibits injection equipment from being installed < 500' from occupied dwelling
43-02-03-15
Bonds
Increase $20,000 bond to $50,000
Commercial SWD bond increased from $20,000 bond to $50,000
Eliminates $50,000 10-well blanket bond
Vern Whitten Photography