Luff Exploration Company - South Dakota School of Mines and

Small-Scale Water Floods Using
Horizontal Wells in the Red River
“ Zone – One
“B”
O Operator’s
O
Story
S
Luff Exploration Company
Horizontal water
Horizontal
water‐flooding
flooding is not, strictly is not, strictly
speaking, unconventional oil recovery.
However, the experience of one small operator ma be of interest
operator may be of interest.
Luff Exploration Company
Cedar Hills Field / Bowman County, ND
/
y,
A large portion of Cedar Hills Field (just across the state line into North A
large portion of Cedar Hills Field (just across the state line into North
Dakota) was developed in the Red River “B” Zone by a large independent using exclusively medium‐radius horizontal wells and water flood operations with an alternating pattern of producers and injection wells
operations with an alternating pattern of producers and injection wells. Localized geology was not a significant factor, and seismic (and the resulting mapping ) was typically not shot
resulting mapping ) was typically not shot.
The resulting Cedar Hills South Unit was a very large scale water flood unit
Luff Exploration Company
p
p y
Luff Exploration Company, on the other hand, is a small independent that Luff
Exploration Company on the other hand is a small independent that
has continuously operated on both sides of the SD / ND state line since the mid 1970’s. In the areas developed by Luff during this time period, localized geology matters greatly and there are numerous existing vertical
localized geology matters greatly and there are numerous existing vertical wells, many of them decades old. Luff, as a private company with a small staff, has developed several small‐
Luff
as a private company with a small staff has developed several small
scale water floods in the Red River “B” Zone, and has pioneered the use of short‐radius horizontal drilling technology (from both existing vertical wells and newly‐drilled
wells and newly
drilled vertical wells). vertical wells)
Areas of Concentration – Water Flood Units
In the creation,
creation development,
development and management of small-scale Red River “B”
B
Zone horizontal water floods, Luff has concentrated its efforts in these
categories:
1.
Reservoir characterization, integrating traditional data and non-traditional
data, and using iterative processes.
2.
Using a mix of horizontal drilling methods, to account for both local geology
and the existence of vertical wellbores.
3.
Well surveillance and reservoir management
4.
Installation of state-of-the-art surface facilities and related automation
Luff Exploration Company
Amor North – Red River Unit
Luff Exploration Company
Amor South – Red River Unit
Luff Exploration Company
Grand River – Red River “B” Unit
Luff Exploration Company
State Line – Red River Unit
Bowman County
North Dakota
Luff Exploration Company
South Dakota - State Line Red River Unit
Harding County
South Dakota
Luff Exploration Company
Pete’s Creek Red River Unit
Luff Exploration Company
East Harding Springs Red River Unit
Luff Exploration Company
North Buffalo Red River Unit
East Harding Springs Red River Unit
East Harding Springs Red River Unit
• This unit was formed in 2003 and expanded in 2010. It p
borders the Pete’s Creek Red River Unit on the East side.
• The Plan of Development (POD) calls for alternating horizontal production and water injection wells.
• Examples of complex mapping are shown.
• Two examples of response to offsetting water injection are also shown.
Sandy White P26H
Sandy White P26H
North Dakota
South Dakota
Dividing line
East Harding Springs di
i
Red River Unit
EHSRRU I‐32H
Responded to offsetting water injection
EHSRRU F‐6H
Responded to offsetting water injection
Red lines are unit borders
Black lines show horizontal laterals for producing wells
Blue lines show horizontal laterals for water injection
j
wells
Dashed lines show possible future horizontal wells
Pete’s Creek Red River Unit
Red River Unit
Augmenting 2D/3D Seismic Data in
M
Mapping for Initial Reservoir Description
i f I iti l R
i D
i ti
Creating sub‐surface maps using 3D seismic reflection time data is certainly not new. Creating residual structure maps (structure minus the regional trend) is also not new, though not commonly used. The use of electric log measurement (from vertical wells) of thickness, porosity, and water saturation is also not new.
l
However, Mark Sippel (with Luff) has also incorporated:
•
True vertical depths (TVD) of the reservoir along horizontal laterals
True vertical depths (TVD) of the reservoir along horizontal laterals, in addition to TVD at vertical wells. This augments seismic reflection data, and covers large areas of the reservoir. • Drilling penetration rate along horizontal laterals (fast drilling = good rock).
k)
• Gas measurements while drilling laterals (measured in drilling fluid and drilling cuttings).
Human observation of hydrocarbons (oil) from drilling cuttings
• Human observation of hydrocarbons (oil) from drilling cuttings.
EHSRRU Expansion
lands
East Harding Springs
Red River Unit
(before expansion)
Luff Exploration Company
East Harding Springs Red River Unit
T22-23N, R6E Harding Co, SD
Subsea Depth of Red River B Porosity
Prepared by Mark Sippel
February 2010
CI = 10 feet
EHSRRU Expansion
lands
East Harding Springs
Red River Unit
(before expansion)
Luff Exploration Company
East Harding Springs Red River Unit
T22-23N, R6E Harding Co, SD
Residual Map of
Subsea Depth of Red River B Porosity
Prepared
P
d by
b Mark
M k Sippel
Si
l
February 2010
CI = 10 feet
EHSRRU Expansion
lands
East Harding Springs
Red River Unit
(before expansion)
Luff Exploration Company
East Harding
g Springs
p g Red River Unit
T22-23N, R6E Harding Co, SD
Prepared by Mark Sippel
February
y 2010
Initial Producing Oil Cut
CI = 0.1
0 1 fraction
f ti
EHSRRU Expansion
lands
East Harding
g Springs
p g
Red River Unit
(before expansion)
Luff Exploration Company
East Harding Springs Red River Unit
T22-23N, R6E Harding Co, SD
Oil Saturation (So) Map
Derived from Reservoir Simulation
Prepared by Mark Sippel
February
y 2010
CI = 0.05 fraction
EHSRRU Expansion
lands
Tr. 19
East Harding Springs
Red River Unit
(before expansion)
Tr. 20
Tr. 1
Prepared by Mark Sippel
February 2010
Luff Exploration Company
East Harding Springs Red River Unit
T22 23N R6E Harding Co
T22-23N,
Co, SD
Mobile Oil Pore Volume Map
(So-Sor) X Porosity X Feet
CI = 0.02 pore-feet
EHSRRU F-6H
Cartesian Plot - Daily Oil Production
5-Day Trailing Average Values
Made changes to pump and pumping motion
Y axis has a Cartesian scale
400
350
Well responded significantly
to offsetting water injection
Daily
y Production (BBLS/Day)
300
250
200
150
100
50
0
Date
Oil
RDG 10/3/2010
EHSRRU I-32H - Horizontal "B" Zone
3-Day Trailing Average
350
Cartesian Scale
300
Well responded significantly
to offsetting water injection
Daily Rates
250
200
150
100
50
0
Oil
RDG 10/4/2010
Ice storm
Set large pumping unit
A large pumping unit on
the EHSRRU I-32H
A cow (protected
f
from
the
th moving
i parts)
t )
People!
EAST HARDING SPRINGS RED RIVER UNIT - EHSRRU
Unit Expa
anded
F-6H Drilled
d
Unit formed
100,000
EHSRRU I-32H on prod.
Convert Joyce Miller 1-P
Conv
vert EHSRRU N
N-5H
1,000
Drill E
EHSRRU N-5H
Convert S
Swanson 1-32
Rate (montthly)
10,000
Green curve is monthly oil
production in BBLS/month
100
1998
1999
2000
2001
2002
2003
2004
2005
Time
2006
2007
2008
2009
2010
2011
2012
Pete’ss Creek Red River Unit
Pete
Creek Red River Unit
• This unit was formed in 2009. It borders the North Dakota state line on the North side and the East Harding Springs Red River Unit on the West side.
• The Plan of Development (POD) calls for alternating horizontal p
production and water injection wells.
j
• Examples of open‐hole log sections and reservoir simulation are shown.
North Dakota
South Dakota
Dividing line
Between units
East Harding Springs Red River Unit
PCRRU F‐9H
(currently producing)
Red lines are unit borders
Black lines show horizontal laterals for producing wells
Blue lines show horizontal laterals for water injection
j
wells
Dashed lines show possible future horizontal wells
PCRRU N‐21H
(currently producing)
(currently producing)
Pete’s Creek Red River Unit
Luff Exploration
p
Company
p y
Miller Ranch F-4H
K.B. 2.901 ft.
There are no economically productive
zones between the top of the Gunton and
the Red River “B” zone. This interval is
included in the unitized interval because of
short-radius horizontal re-entries.
Top of Gunton Member
Stony Mountain Formation
8 763 ft
8,763
ft.
Proposed
Stratigraphic Interval
Proposed
Pete’s Creek Red River Unit
Top of the Gunton member of the Stony Mountain
formation down to the Red River “C” Zone Marker
(top of the “C” Zone)
Top of Red River
Red River “A” Zone
Red River “B”
B Zone
porosity
Red River “C” Marker
8 987 ft
8,987
ft.
Red River “C” Zone
porosity
p
y
Schlumberger
Platform Express
Compensated Neutron – 3 Detector Litho-Density Porosity Log
Top of
Top
of
Red River Top of
Top
of
Red River Red River “B”
Red River “B”
Red River “B”
Exhibit 5-3
Enhancing Reservoir Characterization With Tighter
I t
Integration of Reservoir Simulation and Seismic Mapping
ti
fR
i Si l ti
dS i i M
i
Reservoir simulation with a Black Oil model software application is not new. Nor is the use of seismic mapping for initial mapping in the reservoir model.
However, Mark Sippel (with Luff) has taken the reservoir characterization process further, by in iterative process of reservoir mapping (description) and black oil simulation for history match and future prediction of oil, water and gas flow rates and pressure In this iterative process the
water and gas flow rates, and pressure. In this iterative process, the mapping gets changed for:
o
o
o
Structure (to change water cut)
Permeability (to change flow rate)
Porosity (to change rate decline or response and pressure in the reservoir around a well)
Why Do the Iterative Process?
y
Matching reservoir mapping description to observed data while drilling and during production is useful to making better
economic decisions for development and for deriving better
economic decisions for development, and for deriving better
equity parameters for working interest owners and royalty owners during the statutory unitization process.
131000
129N 101W
130000
129000
21
22
23
128000
24
19
20
21
1-21
1
21
127000
126000
1-21
14-19H
125000
1-28
124000
28
123000
27
26
25
30
29
122000
121000
28
P-26H
41-33H
120000
1-34
119000
1-35
1
35
1-34H
33
118000
34
35
1-36
36
31
117000
32
1-35
16-33
1-33
33
116000
1-19
115000
I-21
114000
24
19
20
P-19H
113000
112000
21
22
23
24
26
25
19
1-25
111000
C-28H
F-29H
110000
25
30
109000
29
1-27
28
27
1-30
23N 6E
108000
30
O-28H
107000
106000
1-34H
1-32P
105000
36
104000
31
32
1-31P
103000 24-36
33
I-32H
34
1-32
35
36
31
2
1
6
M-33H
102000
1-35H
101000
F-6H
100000
F-4H
99000
1
6
5
4
98000
ST3
97000
3
N-4H
N-5H
1-6
1-1H
CRI 1-3H
96000
1-11H
1-7
C-8H
95000
C-9H
94000
12
7
8
93000
9
10
I-9H
11
12
7
92000
91000
1-7
B-16H
90000
89000
13
88000
18
17
16
15
14
87000
13
18
86000
1-14H
22N 6E
85000
84000
24
83000
82000
Green lines show horizontal laterals for producing wells in model
19 horizontal laterals
Blue lines show
20 for water injection
21 wells in model
Dotted lines show actual lateral trajectories
22
23
24
19
81000
80000
1248000
1250000
1252000
1254000
1256000
Luff Exploration Company
June 2009
Prepared by Mark Sippel
0
2000 4000 6000 8000
1258000
1260000
1262000
1264000
1266000
1268000
1270000
1272000
1274000
1276000
1278000
1280000
1282000
Pete's Creek Red River Unit Model Map
Grid Cells 100 x 100 x 2
Grid Cell Size 406 ft x 515 ft x 2 ft
1284000
1286000
1288000
Oil rate with time from reservoir simulations for Pete’s Creek Unit.
PETES CREEK RED RIVER UNIT - PETES CREEK
Unit form
med
100,000
Rate (mo
onthly)
10,000
1 000
1,000
Green curve is monthly oil
production in BBLS/month
100
2002
2003
2004
2005
2006
2007
Time
2008
2009
2010
2011
2012
South Dakota – State Line Red River Unit
• This unit was formed in 2008. It borders the North Dakota state line on the North side.
• The Plan of Development (POD) calls for alternating horizontal production and water injection wells.
• Examples of well surveillance are shown.
• An example of response to offsetting water injection is also shown.
SD-SLRRU F-20H
(WIW)
Ferkingstad 33
33-20
20
Njos 1-19 (P&A)
North Dakota
South Dakota
Njos J-19H
Janvrin A-29H
(WIW)
Janvrin L-28H
S th D
South
Dakota
k t – State
St t Line
Li R
Red
d Ri
River U
Unitit
State Line Field
Harding County, South Dakota
Black lines show horizontal laterals for producing wells
Blue lines show horizontal laterals for water injection wells
Ferkingstad 33-20 (SD-SLRRU)
Cartesian Plot - Daily Production
3-Day Trailing Average Values
Ice storm
Injection reduced at Janvrin A‐29H
350
Injection started at
Janvrin A-29H
300
Well Responded significantly to offsetting water injection
Daiily Production
250
200
150
Adjust SAM POC
100
50
0
Date
Oil
RDG 10/5/2010
Larger plunger run
Different Horizontal Drilling Methods
g
Luff has employed several methods for drilling horizontal wells:
o New medium‐radius wells
o New vertical wells, followed by short‐radius horizontal re‐
entry with a different rig
t
ith diff
t i
o Short‐radius horizontal drilling from existing vertical wells
This approach reflects:
o Localized geology
o Existence of numerous vertical wells
Existence of numerous vertical wells
Janvrin L-28H
NW SW, Sec. 28, T23N, R5E
SD-SLRRU
Harding County, SD
Well spudded in 5/22/07
Diagram Not To Scale
KB @ 3,047 ft.
Gr @ 3,032 ft.
8-5/8" casing set at 2,020 ft.(KB)
cemented w/ 500 sx Lite cmt. &
tailed w/200 sx Class "G" cmt.
TOC 2nd stage - 3,360 ft.
from CBL
2nd stage - cement pumped through DV:
o 170 sx Class "G" cmt (tail)
o 140 sx PLC Lite cmt (lead)
D.V. collar @ 6,816 ft. (CBL)
(Casing detail has DV @ 6,849 ft.)
Tubing detail July 17, 2009:
KB
15
280 jts 2-7/8"
8,799
AC
3
3 jts 2-7/8" tbg
SN w/DT
2-7/8" Perf sub
1 jt w/BP
Landed @
94
1
4
31
8,947 ft.
15
8,814
8,817
8,911
8,912
8,916
8,947
Upper Casing window - 8,936 - 8,942 ft.
West Lateral TD @ 10,940 ft. MD
Sidetrack West Lateral @ 9,690 ft. MD
West Lateral Sidetrack TD @ 10,785 ft. MD
TOC for 1st stage - approx. 6,824 ft.
from CBL
1st stage - cement:
o 300 sx Class "G" cmt
Lower Casing window - 8,924 - 8,930 ft.
North Lateral TD @ 8,976 ft. MD
Sidetrack North Lateral @ 8,950 ft. MD
North Lateral Sidetrack TD @ 11,279 ft. MD
CIBP @ 9,010 ft.
Red River "B" Zone
5-1/2" casing set at 9,150 ft. (KB)
TD 9,150 ft. (driller) (KB)
TD 9,159 ft. (logger) (KB)
Updated 12/15/09 KD
Reviewed by GM
PBTD - 9,091 ft. (drilled out)
Producing Automation and Well Surveillance
g
The use of pump‐off controllers for wells with beam pumping units is not new. Nor is the use of SCADA to provide summary information at a field office
information at a field office.
However, Luff’s engineers in Denver have taken the process further, by directly pulling data from the pump‐off controllers, and converting the data to pump intake pressure values (a proxy for producing bottom hole pressure), which is monitored and used in injection / withdrawal decisions and well performance assessments. Pumping unit loading and sucker rod loading is also assessed from the data pulled from Denver.
Pump Off Controller
Load cell at bridle
of pumping unit
Controller and
antenna for telemetry
Surface dynamometer card
Calculated down-hole
dynamometer
y
card
SD-SLRRU – Ferkingstad 33-20
Pump
p intake p
pressure
before response
Current
Pump intake pressure
Significant gas interference
((and loss of stroke)) before
response to water injection
No gas interference currently
SOUTH DAKOTA-STATE LINE RED RIVER UNIT - STATE LINE
Unit formed
100,000
Rate (mo
onthly)
10,000
1 000
1,000
Green curve is monthly oil
production in BBLS/month
100
1998
1999
2000
2001
2002
2003
2004
2005
Time
2006
2007
2008
2009
2010
2011
2012
State‐of‐the‐Art
State
of the Art Facilities and Automation
Facilities and Automation
Extensive automation
Careful water filtration
Variable Speed Drive Injection
Automated oil sales with LACT
Some Lessons Learned
Some Lessons Learned
•
Placing horizontal water injection wells interior to producers and in the oil column is best
column is best.
•
Alternating horizontal production and water injection wells ideally should be no further apart than approximately one‐quarter to one‐third of a mile.
•
Producing wells designated for water injection service, for a period of time, is helpful for several reasons.
•
Injection water quality matters.
•
Automation, including injection and production facilities, water transfer, production well pump‐off controls and dynamometer data collection, etc. helps significantly in water‐flood performance optimization. Luff’s field employees play a critical role in this technical effort.
•
Surprises never stop….
A Good Neighbor
A Good Neighbor
Ken Luff and Luff Exploration
Company have operated
continuously on both sides of
the SD / ND state line since the
early 1970’s. We continue to
work at being a good neighbor.
Photo: Dan Thompson
Thank you for your time!
Luff Exploration Company