2015 Denbury Presentation

NYSE: DNR
Hydraulic Fracturing and Re-Fracturing
Stimulation in Citronelle
Perry Hawks

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Denbury.com | NYSE: DNR
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● Hometown: Maquoketa, Iowa
● University of Oklahoma
● Entering Senior year
 May 2016 graduation date
 Petroleum Engineer
● Denbury Field Intern
 Summer 2014
● Mentor: Tommy Chatfield
2
About Me

3
● Field Overview
● Project Scope
● Database Creation
● Candidate Selection
● Production Forecasting
● Economic Model – Decision Tree Analysis
● Well Work
● Conclusions/Recommendations
Agenda

4
● Unitization and Waterflood began -1961
● Pilot CO2 program – 1980’s
● Purchased from Merit – 2006
● Complex Geology
 Unfaulted structure
 52 productive sands
 Avg perm = 11.78 mD
 Avg porosity = 13%
● OOIP ≈ 537 MMBBL
● Recovered ≈ 172 MMBBL
 RF ≈ 32%
Citronelle Field Overview

5
● Study the historical frac jobs in
Citronelle
 6 sections
 84 wells
 231 frac jobs
● Document specific details of the
frac jobs
● Pick out candidates for re-
stimulation
● Develop an economic model for
proposal
Project Scope

6
● Well Stimulation
● Propagation of fractures outside of formation
damage
● Skin Damage
 Drilling, perforations, production, previous
stimulation
Why Frac?

NYSE: DNR
Database Candidate Selection Production Forecasting Economics Well Work

8
Database
● Detailed spreadsheet of
historical frac and re-frac jobs
 Intervals fractured
 Stages
 Perf Schemes
 Frac fluid
 Proppant
◦ Type,Volume, Distribution,
Concentration
 Pumping Rates
 Pumping Pressures
◦ Min, Max, Avg, ISIP, Breakdown
 Correlations to IPs and EURs

9
Database
0
10000
20000
30000
40000
50000
60000
70000
0 2000 4000 6000 8000 10000 12000
EUR/NetFeetPerfed(bbl/ft) Mass of Proppant / Net Feet Perfed (lbs/ft)
EUR per ft vs Mass of Proppant per ft
0
20
40
60
80
100
120
140
0-50,000 50,000-100,000 100,000+
AverageUplift(bbl/day)
Amount of Proppant (lbs)
Average Uplift vs Lbs of Proppant

11
● Candidate selection
criteria/ranking
recommendations:
 High BHP
 Sound Wellbore Integrity
 High IP
 Fluid Rate Capacity
 Skin
● Noticed all wells in 1980’s CO2
program weren’t frac’d
● A-35-10 #2
Candidate Selection

12
● SPUD in May 1982 with intention of being a
CO2 injection well
● No previous frac jobs
 ≈ 95% of wells in Citronelle have been frac’d
 Only 1 case of decreased production following frac job
● Located in a high producing area of the field.
● Region of comparatively high BHP*
● Potential in several unproduced sands
(Sands: 15B, 16A &B)
● Adjacent wells with good response to frac
 Average uplift of 53 bopd
A-35-10 #2

13
Potential in Un-produced sands
CORE DATA
Sand Average k, mD Average Ф, % Net ft of Pay
6 N/A N/A 6
9B 0.05 7.8 2
10A 5.1 12.3 8
12 0.3 8 3
14B 22.8 12.5 8
15B 49.4 15.8 7
16A 40 14.5 5
16B 97 13.1 5
18 N/A N/A 6
22A 0.3 11 2
22B 25.3 13.6 3
32A 5.9 12.1 13
36B 14.4 13 10
38A-2 0.15 7.1 8
40 0.5 6.4 6
42A&B 5 15.5 14
Average 19.01 11.62 6.63

14
Current Production: 9 oil and 30 water
Initial Production: 119 oil and 11
water
ARIES projected economic
limit hit in 2033

16
Production Forecasting
Decline rate B/A waterflood response:
 De before = 27%
 De after = 10%
Well Date of Frac Job
Difference between B /A Decline
BOPD %
Citronelle A-25-2 Apr-62 305.5 47
Citronelle A-25-3 Dec-57 43.8 22
Citronelle A-25-4 Dec-61 142.8 37
Citronelle A-25-6 Apr-68 -3.7 N/A
Citronelle A-25-9 Feb-69 446.7 17
Citronelle A-25-10 Sep-59 15 25
Citronelle A-25-12 Sep-59 8 34
Citronelle A-25-14 Nov-59 146.2 40
Citronelle A-25-16 Jul-57 135.2 57
Citronelle A-35-10 Jan-59 91.5 9
Citronelle A-35-11 Jun-57 57.1 17
Citronelle A-36-1 Apr-58 80 16
Citronelle A-36-4 Oct-62 204.6 8
Citronelle A-36-5 Apr-58 89 4
Citronelle A-36-6 Feb-60 60.7 7
Citronelle A-36-7 Feb-69 56 15
Citronelle A-36-8 Apr-58 71.2 38
Citronelle A-36-9 Sep-59 67.1 38
Citronelle A-36-12 Jan-59 59.8 23
Citronelle C-2-7 Dec-57 16.4 57
Citronelle C-2-9 Oct-59 39.2 35
Citronelle C-2-10 Dec-57 91.1 43
Citronelle C-2-16 Jul-58 104.2 37
0.00%
20.00%
40.00%
60.00%
80.00%
100.00%
120.00%
0
2
4
6
8
10
12
-4 71 146 222 297 372 More
Frequency
Bin
Barrels per Day Uplift Histogram
Frequency
Cumulative %
83% of wells with similar frac history
showed an uplift of 72-145 bbl/day

17
Production Forecasting
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
900,000
0 2 4 6 8 10 12 14
CumulativeOilProduction,bbls
Zero Time Scale, yrs
Normalized Cum Plot
q low cum
q high cum
IP = 193 bopd. 10% Decline
(Best Case)
IP = 15 bopd. 30/10% Decline
(Worst Case)

19
● Consulted with vendors from C&J and Baker
Hughes as well as Denbury chief well
engineer Pat Handren on frac design
 Frac down liner
◦ Higher rate & Less risk
 Frac down tubing
◦ Cheaper (Maybe not)
● Designed 24 different cases on ARIES to
model different variables and how they effect
NPV, ROR, and payout
 Used findings from production forecasting to
input into ARIES for the decline curve (30/10,10)
● Used $600,000 for the cost of a frac job
down tubing and $790,000 for a frac job
down a liner
Economics
Case Production Decline Capital Oil Price NPV (M$) - 8 yrs ROR Payout (Yrs)
1 193 10 tbg 50 969 81.07 1.55
2 193 10 csg 50 812. 53.06 2.1
3 193 10 tbg 70 4334 100 0.5
4 193 10 csg 70 4177 100 0.65
5 193 30/10 tbg 50 108 19.17 3.79
6 193 30/10 csg 50 -43 0 5.76
7 193 30/10 tbg 70 1466 100 0.8
8 193 30/10 csg 70 1316 100 1.14
9 72 10 tbg 50 63 14.48 4.69
10 72 10 csg 50 -93 5 6.88
11 72 10 tbg 70 1319 100 1.26
12 72 10 csg 70 1162 73.38 1.67
13 72 30/10 tbg 50 -223 0 8.58
14 72 30/10 csg 50 -373 0 8.58
15 72 30/10 tbg 70 365 52.28 1.94
16 72 30/10 csg 70 215 26.81 3.07
17 15 10 tbg 50 -363 0 9.08
18 15 10 csg 50 -520 0 9.08
19 15 10 tbg 70 -102 0 9.08
20 15 10 csg 70 -258 0 9.08
21 15 30/10 tbg 50 -379 0 8.58
22 15 30/10 csg 50 -529 0 8.58
23 15 30/10 tbg 70 -154 0 8.58
24 15 30/10 csg 70 -304 0 8.58

20
Decision Tree Analysis
$283,000 $359,000
• Less Risk
• Higher Pumping Rates
• Longer Fracture Half Lengths
• Essentially New Casing - Integrity
$359,000
$283,000
$76,000

21
Theoretical Project
Citronelle Base Production
20% Increase in
Production

23
Wellbore Diagram
Current Completion Perry Hawks 7/30/15
KB: 342.7' 1097201950000
DF: 341.7' 2492' FSL & 2490' FEL
GL: 325.2' Sec 35-T2N-R3W
Datum: 17.5' above GL Mobile Co, AL
TOC @ 141.2'
9 5/8 " 36# K-55 csg. Set @ 1449'
TOC @ 7614.5'
341 Jts. 2 7/8 " N-80 EUE 8
rd
tbg.
Baker model "R" S.G. pkr.
Set @ 10,748' w/ 10,000 # wt
Sand 6. 10,802-10,812 ft GRM . 6 SPF. (10 - 92)
Sand 9. 10,844-10,850 ft GRM . 6 SPF. (10 - 92)
Sand 10. 10,869-10,879 ft GRM . 6 SPF. (10 - 92)
Sand 12. 10.905-10,912 ft GRM . 6 SPF. (10 - 92)
Sand 14B. 10,924-10,936 ft GRM . 6 SPF. (10 - 92)
Sand 18. 11,009-11,020 ft GRM . 6 SPF. (10 - 92)
Sand 22A. 11,102-11,108 ft GRM . 6 SPF. (10 - 92)
Sand 22B. 11,113-11,119 ft GRM . 6 SPF. (10 - 92)
Sand 32A&B. 11,342-11,352 ft GRM . 6 SPF. (10 - 92)
Sand 34A. 11,386-11,390 ft GRM . 6 SPF. (10 - 92)
Sand 36B. 11,424-11,435 ft GRM . 6 SPF. (10 - 92)
Sand 38 A-2. 11,446-11,452 ft GRM . 6 SPF. (10 - 92)
5 1/2 " 17# & 20# N-80 csg.
Set @ 11,610' w/ 925 sks.
HTLD & 325 sks. Class "H" Sand 40. 11,476-11,480 ft GRM . 4 SPF. (11-81)
+ 35% Silica Flour + 15% Salt Sand 40. 11,476-11,480 ft GRM . 6 SPF. (10-92)
+ 0.75% CFR-2 + 4% HR-2
Sand 42 A&B. 11,491-11,507 ft GRM . 4 SPF. (11-81)
Sand 42 A&B. 11,491-11,507 ft GRM . 6 SPF. (10-92)
PBTD = 11,536'
TD = 11,614'
A-35-10 #2
3 stage frac job

Click to edit title style41-15H Workover
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Prior to RU, pull pump, circulate oil out,
test casing to 500 psi.
MIRU workover unit. Nipple up/test BOP
Release packer & TOOH w/tubing. Lay
down BHA. TIH w/ bit or mill and scraper.
Keep scraper above perfs. CO to +/-
11,568. Circ clean. POOH.
Run Sector Bond log from bottom to TOC.
Run multifinger and casing caliper from
bottom up to 9500’.

25
Run cement retainer on tubing testing in hole and set at +/-11,300.
RU cementers , get PIR and squeeze of perfs below retainer. RO
and POOH with stinger.
RU eline and set retainer @ +/-10,970’. RU cementers, get PIR
and squeeze off perfs below retainer. RO and POOH with stinger.
Run retainer on tubing and set at +/-10,760’. RU cementers, get
PIR and squeeze off perfs below retainer. RO and POOH with
stinger.
TIH and drill out cement and retainers to +/-11,568’ Test squeezes.

26
PU 4”, 10.46#, L-80, Ultraflush Joint liner (duplex system) with PBR
and run from PBTD +/-11,568 up to +/-10,300’. RU cementers and
cement in place.
$18/ft * 10,000 ft = $180,000

27
Bump a plug to clean off
any remaining cement
on the inner liner walls

28
Run 4-5/8” bit and scraper to top of liner drilling any
cmt. Circ clean and test. TOOH.
Run proper size mill for 4” liner and CO to +/-
11,528’ and test. POOH.
Run polishing mill for PBR. TOOH laying down 2-
7/8” tubing.
Install 4” hanger spool. PU and run PU 4”, 10.46#,
P-110, Ultraflush Joint liner with seals. Sting into
PBR and land in wellhead.
Test liner to max frac pressure plus safety factor.
RU eline. Run cement evaluation bond log inside
4” liner. If ok, perf for 1st frac stage.

29
Move in and fill frac tanks. Have
water tested by frac company to
insure it is acceptable.
RU Frac unit. Install and test
treesave. Install relief valve on 4 x 5-
1/2” annulus. Leave surface casing
valve open during frac to monitor.
Perform 1st stage frac as designed.

30
RU eline. Set composite plug
above 1st stage. Test liner.
Repeat the same steps for the
following 2 stages of fracing.

31
RDMO frac equipment and treesaver.
TIH picking up 2-3/8” workstring and bit or mill for 4”.
Clean out to PBTD removing the composite plugs and
any frac sand. POOH.
Run packer and swab as necessary. POOH.
Run RBP and set/test right below liner PBR. POOH
and LD 2-3/8” workstring.
Remove liner from PBR and above laying down and
send in for inspection. Modify wellhead as necessary.
NU BOPs again.
TIH with prod tubing and nec 2-3/8 and remove RBP.
Run production - will need about 468’ of 2-38” or
smaller 2-step on bottom inside liner. Equip for jet
pump.
RTP
Total estimated cost of
well work = $690,000

Click to edit title styleC&J Energy 1st Stage Fracture Simulation
32

33
● Research shows very high probability of uplift in production
 Sustained or short-lived
● Low oil price environment, re-completions are attractive
 Less costly than drilling new wells
 Old frac jobs weren’t sufficient
◦ Proppant crushing and fines migration
● With success, this could be implemented field wide
 Do more research
 Candidate selection & ranking criteria
Conclusions / Recommendations

34
● Citronelle Team
 Tommy Chatfield
 Thi Dao
 Clay Mack
 Ronnie Brewer
 Tyler Froman
 Darren Bender
 Amanda Manson
 Adam Johnson
 Field Crew
● Hydraulic fracturing specialists
 Brian Chacka
 Pat Handren
Acknowledgements
● Other special thanks to:
 Eric Willoughby
 Adin Burns
 Jennifer Anthes
 Mike Cortines
 Jennifer Dehay
 Sal Gutierrez
 Derrick Anderson
 Kris Roberson
 Steve Walker
 Sandra Johnson
 Fellow interns

9/18/2015
36
Rock Stresses
 Horizontal stresses
 “Squeeze” the hole
 Compression side
 Tension side
 Fracture created
perpendicular to least
principal stress
 Slides from Pat Handren’s Fracture Design for Beginners
σ max
σ min

9/18/2015
37
6 shots/ftσ max
σ max 2 shots/ft
Perforating (Just touching the surface!)
σ max 1 shot/ft
σ max 4 shots/ft
 Slides from Pat Handren’s Fracture Design for Beginners

38
Slickwater vs Crosslinked Gel
http://www.hexionfracline.com/fracturing-fluids-101
Crosslinked – more viscous, can carry
the bigger proppant like 20/40.
Typically used in oil wells.
Slickwater – typically used in gas wells.
Not very viscous. Would use in our
case to try to get proppant deep into
formation at beginnning then tail end
job with crosslinked

39
Ottawa Sand vs Ceremic

40
Why Resin Coated?
http://fairmountsantrol.com/wp-content/uploads/2014/09/Why-Choose-Resin-vs-Raw-
Sand-PAS-914.pdf

2015 Denbury Presentation

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