1

Jonathan Bradley,Senior Reservoir Engineer

Anne Tandy (Burnett Ranch) CO2 Flood

King County (TX)

December 8th, 2016

2

Overview

• Summary

• Company & Field History

• Geologic Setting

• Key Event Dates

• Well Layout/Pattern Size

• Well Design

• Facility Overview

• Flood Performance

• Data Monitoring Toolbox

• Current Challenges

• Conclusions Google satellite image of our Central Facility

3

Company & Field History

• Field leased and drilled with marginal success in 50’s and 60’s

• Actively developed in 70’s with waterflood commencing in 80’s

• 13 different zones are productive from over 50 separate fields

• Hunt purchased field in 90’s

• Cumulative production to date exceeds 105 MMBO.

• Project Area 1 (10,750 acres) is the initial CO2 flood area and is now consolidated into one field with 4 reservoirs.

Brief Field History

• Hunt Oil Company was founded in 1934 and today is one of the largest privately owned independent oil companies in the world

• The Company has been responsible for discovering and developing some of the largest oil and gas fields in the world, including:

o East Texas Oil Field (Texas)

o Alif Field (Yemen)

o Camisea (Peru)

• The Company has operated on every continent, except Antarctica, in virtually every climactic and geographic condition; onshore and offshore

New Corporate Headquarters in Dallas, TX

Anne Tandy (Strawn) Field (PA1)Burnett Ranch

4

Overview

• Simultaneous CO2 flood of 4 Strawn intervals in Project Area 1 (PA1) of Burnett Ranch

• Drilling started February 2013; First CO2 injection March 2014

• Patterns: 23 of 43 on CO2; 5 of 43 on H2O; 21 of 33 offsetting producers responding

• Currently: 2,950 bopd; 26,000 bwpd; 20,800 mcfpd; 73,000 mcfipd; 15,900 bwipd

• Drilling rig released Feb 2015; 23 wells remain to be drilled; 19 of 39 planned workovers completed

• Current Pattern Inventory – 4; Drilling Restart targeted for January 2018

• 3 of 4 CTBs CO2-ready; RCF operational; Add compression and second water facility, as needed; Oil sales pipeline commissioned in 2016

5

PRIMARY PROD. SECONDARY PROD.

Onset of CO2

Drilling Project

BR PA1 – Historical Gross Production

TERTIARY PROD.

6

BR PA1 – Geologic Overview

TYPE LOG

API Gravity: 37.7 deg API

Initial GOR: 241 (SCF/BBL)

Pre-CO2 GOR: 76 (SCF/BBL)

Strawn 5400 Sand Strawn 5400 Lime

Fossiliferous ooid grainstone

F.Gr. sand, shale lamination, ripple X-bed

Avg. Porosity

Avg. PermMax Net

Pay

Twin Peaks 15% 25-50 md 16'

Strawn Lower 16-20% 75 md 33'

5400 Sand 20% 100-150 md 50'

5400 Lime 14% 1-10 md 42'

7

Geologic Map

• Four zones

o Twin Peaks

o Strawn Lower

o Strawn 5400 Sand

o Strawn 5400 Lime

• Strawn 5400 Sand & Strawn Lower have considerably higher kh

• Minor faulting

• Four horizontal wells targeting Strawn 5400 Lime

• 115 Total Wells

o 54 Injectors

o 61 Producers

8

Project Development

• 2009-2010

o Petrel/Eclipse Sector Model - Simulation Study for CO2 Flooding Potential

o Assessed preferred deployment schedule (CO2/Water Injection)

• Injection-centered patterns

• Begin with Continuous CO2 Injection, followed by tapered WAG schedule

• Maximized peak oil rate and incremental oil recoveries

• 2010-2011

o Scale-Up Model

• Scaled model results to the broader area defined for CO2 flood

• Forecasted oil, gas and water production and CO2/water injection

• Performed Detailed Engineering Study

o 3D Seismic Program Completed (65 sq. mi.)

o Front End Engineering Design Study Completed

• 2012-2013

o CO2 Purchase Contract Signed

o Field Consolidation Awarded by Texas Railroad Commission

o Field work

• Early phases of pipelines and facilities installed

• Begin drilling and workover program in 1st Qtr 2013

• Begin water injection; re-pressure reservoir(s)

• 2014

o CO2 Injection begins in Anne Tandy (Strawn) Field

o First Response from initial two patterns

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Pattern Layout

• Pattern Size• Northern Area: 80 acres• Southern Area: 120 acres

• Layout Considerations• Geologic Setting • Existing Well Layout• Topography

A’

Initiated Patterns

Water Curtain/Pattern Inventory

A

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Waterflood vs. CO2 Flood

N-176,450

N-195,500

N-115,740

<1,811FT> <1,358FT>

6 16

CALI

0 180

GR

60 190

SPKR

0.1 1000

ILD

0.1 1000

ILM

0.1 1000

RDKR

0.1 1000

RMKR

0.3 -0.1

DPHI_SS

6 16

CALI

0 180

GR

60 190

SPKR

0.1 1000

ILD

0.1 1000

ILM

0.1 1000

RDKR

0.1 1000

RMKR

0.3 -0.1

DPHI_SS

6 16

CALI

0 180

GR

60 190

SPKR

0.1 1000

ILD

0.1 1000

ILM

0.1 1000

RDKR

0.1 1000

RMKR

0.3 -0.1

DPHI_SS

TOP_5400_SAND

TOP_5400_SAND

BASE_5400_SAND

BASE_5400_SAND

TOP_5400_LIME

TOP_5400_LIME

BASE_5400_LIME

BASE_5400_LIME

S5400'_SAND_O-W_TOP

5350(-3645)

5375(-3670)

5400(-3695)

5425(-3720)

5350(-3655)

5375(-3680)

5400(-3705)

5425(-3730)

5300(-3639)

5325(-3664)

5350(-3689)

5375(-3714)

SubseaDepth(ft)

SubseaDepth(ft)

-3625 -3625

-3650 -3650

-3675 -3675

-3700 -3700

-3725 -3725

N-27R5,990

N-10R5,870

N-11R5,540

<1,393FT> <1,342FT>

0 180

GR

0.1 1000

RLA1

0.1 1000

RLA3

0.1 1000

RLA4

0.1 1000

RLA5

0 20

PE

0.3 -0.1

DPHZ

0 180

GR

0.1 1000

ILD

0.1 1000

ILM

0 20

PE

30 -10

DPHI_SST

0 180

GR

0.1 1000

ILD

0.1 1000

ILM

0 20

PE

30 0

PORZC

TOP_5400_SAND

TOP_5400_SAND

BASE_5400_SAND

BASE_5400_SAND

TOP_5400_LIME

TOP_5400_LIME

BASE_5400_LIME

BASE_5400_LIME

S5400'_SAND_O-W_TOP

5400(-3644)

5425(-3669)

5450(-3694)

5350(-3660)

5375(-3685)

5400(-3710)

5325(-3661)

5350(-3686)

5375(-3711)

SubseaDepth(ft)

SubseaDepth(ft)

-3625 -3625

-3650 -3650

-3675 -3675

-3700 -3700

Original Producer

Peak Primary (1977) – 213 BOPD

Peak WF (1990) – 1,009 BOPD

New Offset Producer

Initial Rate (2013) – 12 BOPD

Peak Response (2014) – 269 BOPD

A A’

Strawn5400’Sand

N-176,450’

N-195,500’

N-115,740’

N-27R5,990’

N-10R5,870’

N-11R5,540’

1976 1976 1975

2013 20132013

INJ INJ

Strawn5400’SandStrawn

5400’Sand

Strawn5400’Sand

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Typical Wellbore Completion

• Drilling

o 10 ¾” surface casing at 350’ to 400’

• GAU depths vary between 150’ to 200’

o 7” mixed string production casing at 5600’

• Historically, 7” has shown best performance against external corrosion

• 7” 23ppf J-55 LT&C

• DV tool placed below the Cisco to help ensure cement coverage

o Place Ryt-Wrap casing across 2 most corrosive zones in case of cement channels (Coleman Junction 2300 & Cisco 3500’),

o 13Cr alloy placed in interval to be exposed to CO2/water mix in wellbore (when high fluid column)

• 7” 23 ppf 13Cr80 JFEBear

o 80 ksi yield strength, burst and collapse ratings same as N-80

o JFEBear connection is gas tight with torque shoulder

• Completion

o Perforated 4 SPF @ 120 degree phasing

o Twin Peaks Formation - Fracture stimulated with 200’ frac length

o Strawn Lower Formation - Fracture stimulated with 50’ fracture length

o 5400 Sand Formation – Most are fracture stimulated with 50’ fracture length

• Operations

o ESP’s in most producers 28 ESP’s & 7 Rod pumps

• Monitoring various variables (motor speed, intake pressure, temperature, etc.)

o Currently operating with casing head (annulus) gas commingled with full production

o Treating wells for asphaltenes/paraffin, scale, and corrosion

Injector Producer

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Facility Schematic

INLET

GAS

OIL OIL

HEATER TREATER

25#

WATER

TEST TRAIN

PRODUCTION HEADER

INJECTINGWELL

WATER TANK

FREE WATER KNOCKOUT

COMP

VAPORRECOVERY

75#

COMP

75#

400#

400#

DEHYDRATION

COMP

COMP

COMP

COMP1900#

1900#

1900#

1900#

PUMP

PUMP

PUMP

~1600#

PURCHASED CO2DELIVERY

PRODUCINGWELL

SWD (as needed)

OIL TANK5,000 bbl

OIL SALES P/L

VENT/FLARE

PUMP

PUMP

PUMP

PUMP

WAG SKID

WATER INJECTION STATION (WIS)

RECYCLE COMPRESSION FACILITY (RCF)

Fourth pump excess capacity

CENTRAL TANK BATTERY

(CTB)x4

INLET

OILOIL

WATER

WATER

INLETGAS

OIL & WATER

OIL & WATER

HP 2-PHASE SEPARATOR

400#

WATER

OIL TANK

LP 2-PHASE SEPARATOR

INLET

GAS

OIL & WATER

OIL & WATER

75#

3 oz

VRU

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Field Operating Pressure

INJECTOR PRODUCER

BO

TTO

MH

OLE

OP

ERA

TIN

G P

RES

SUR

E

100-200 psiPre-Response

600 psiPost-Response

3,300-3,700 psiBoth Water &

CO2

Targeted Avg. Reservoir Pressure2,200 psi

• Wellhead Pressures

o Injectors

• 1,600 – 1,700 psi on CO2

• 1,200 – 1,300 psi on Water

o Producers

• HP System: 450 – 500 psi

• LP System: 150 psi

• Consistently evaluating for optimization

o Improved reservoir pressure management

o Optimized pump efficiency given GLR

o Minimize impacts of asphaltine/paraffin

• Not all producers achieve this bottomhole pressure due to pump sizing and deliverability

Minimum Miscibility Pressure: 1800 psi @ 120 deg F (95% CO2)

14

Current PA1 Production & Injection

• Oil production includes small amount of remaining secondary

• Recent leveling of oil production largely driven by reduced process speed

o Declining injectivity

o Fewer patterns initiated

• Manage production to stay below current facility recycle gas limit of 30 Mmcf/d

15

PA1 Development & Response Update

Producers currently responding & recycling CO2 (21)

Producers offset by CO2

Injection yet to respond (12)

24 Patterns have been initiated with CO2.

4 Patterns remain in inventory and are currently part of southern water curtain.

Currently on CO2

Water Curtain (Pattern Inventory)

Current rate

On average, peak response rate 14x pre-response rate

Initial (Pre-WAG) CO2 Injection Rate, mcfpd

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Producer Profile Example

N-91 Producer

YA-83 Producer

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Dimensionless Curve Performance

• Achieved response at 15% HCPV injected CO2

o N-27R: 6 mos.

o N-11R: 7 mos.

• Incorporates production allocation back to injector (subjective)

o Based on HCPV of Injector-Producer wedge

o Only includes injectors initiated on CO2

PROD

INJ

TWIN PEAKS

STRAWN LOWER

STRAWN 5400 SD

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Performance Monitoring “Toolbox”

• RAW DATA

o Production: Tank Battery Rates & Well Tests (TOW)

o Injection: Well Rates & Pressures (TOW)

• Production/Injection data tracked by well, battery, and pattern (using ARIES/Spotfire/Excel)

• Injection/Withdrawal by Pattern (Allocated Production)

• Dimensionless Curves by Pattern (Allocated Production)

• Bottomhole pressures determined from injection profiles, fluid levels, shut-ins, monitor wells, and RFTs

• Injection profiles used to update injection zone allocations

• Hall plots for injector diagnostics (fracture propagation)

• Step Rate Tests to Optimize Injection Rates

• Excel-based Flood Model to predict field performance

• In process of developing fieldwide simulation model in Eclipse

• Limited Tracer Analysis

• Asset integrity management system (AIMS) to monitor facilities

Screenshot from Spotfire Software

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Ongoing Challenges

• Continue to review producing well operating philosophy

o Impacts of producing bottomhole pressure on asphaltine/paraffin deposition

o Determine potential methods of treatment and impacts on project value

• Loss of CO2 Injectivity Post-WAG

o Currently reviewing potential causes and collecting data

o Determining if caused by precipitant, relative permeability change, or other

• Optimize conformance across all zones

o Implement ported sleeve technology installed in injection wells

o Understand impacts on oil rate and present value

• Manage through low oil price environment

o Ongoing operations and current profitability

o Timing of future required capital spend

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Post-WAG Loss of Injectivity

Current view is –

• Do not believe it is a water quality issue regarding oil carryover, solids, etc.

• Solid samples appear to be oil coated scale (mainly barium sulfate, silicon dioxide, sodium chloride)

• Xylene/Toluene, acid, and fresh water ineffective at remediation

• Ongoing core analysis for fluid compatibility, fines migration, and relative permeability

• Continuing field remediation exercises and testing to narrow possible causes

“Somewhat Expected - Hysteresis” “Unexpected CO2 Injectivity Loss”

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Conclusions & Path Forward

• Initial patterns performed as expected with timely response

• Minimal premature CO2 breakthrough

• No evidence of containment issues (vertical or lateral)

• Optimizing development of southern portion of PA1 (wider spacing)

• Scalable design of facilities proving beneficial - currently reviewing expansion options

• Efforts ongoing to review subsequent nearby project areas

22

Thank You

Questions?

Thank you to Steve, Doug, and the entire Conference Committee.

If we run out of time, any follow-up questions or discussion can be sent to jbradley@huntoil.com