Anne Tandy (Burnett Ranch) CO 2 Flood King County (TX) Jonathan - - PowerPoint PPT Presentation

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Jonathan Bradley,

Senior Reservoir Engineer

Anne Tandy (Burnett Ranch) CO2 Flood King County (TX)

December 8th, 2016

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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

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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
• ne 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:

• East Texas Oil Field (Texas)
• Alif Field (Yemen)
• 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

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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

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PRIMARY PROD. SECONDARY PROD.

Onset of CO2 Drilling Project

BR PA1 – Historical Gross Production

TERTIARY PROD.

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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

• oid grainstone

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

Avg. Porosity

• Avg. Perm

Max 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'

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Geologic Map

• Four zones
• Twin Peaks
• Strawn Lower
• Strawn 5400 Sand
• Strawn 5400 Lime
• Strawn 5400 Sand & Strawn

Lower have considerably higher kh

• Minor faulting
• Four horizontal wells targeting

Strawn 5400 Lime

• 115 Total Wells
• 54 Injectors
• 61 Producers

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Project Development

• 2009-2010
• Petrel/Eclipse Sector Model - Simulation Study for CO2 Flooding Potential
• 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
• 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
• 3D Seismic Program Completed (65 sq. mi.)
• Front End Engineering Design Study Completed
• 2012-2013
• CO2 Purchase Contract Signed
• Field Consolidation Awarded by Texas Railroad Commission
• 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
• CO2 Injection begins in Anne Tandy (Strawn) Field
• 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

6 16 CALI 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 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 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

S5400'_SAND_O-W_TOP

• 3625
• 3625
• 3650
• 3650
• 3675
• 3675
• 3700
• 3700

180 GR 0.1 1000 RLA1 0.1 1000 RLA3 0.1 1000 RLA4 0.1 1000 RLA5 20 PE 0.3

• 0.1

DPHZ 180 GR 0.1 1000 ILD 0.1 1000 ILM 20 PE 30

• 10

DPHI_SST 180 GR 0.1 1000 ILD 0.1 1000 ILM 20 PE 30 PORZC

Subsea Depth(ft) Subsea Depth(ft)

• 3625
• 3625
• 3650
• 3650
• 3675
• 3675
• 3700
• 3700

Or Original Producer Peak Prima mary y (1 (1977) ) – 213 BOP BOPD Peak WF WF (1 (1990) ) – 1,009 BOP BOPD Ne New Offse Offset Producer In Initial Rat Rate (2 (2013) ) – 12 BOP BOPD Peak Res Response se (2 (2014) ) – 269 BOP BOPD

A A’

Strawn 5400’ Sand N-17 6,450’ N-19 5,500’ N-11 5,740’ N-27R 5,990’ N-10R 5,870’ N-11R 5,540’

1976 1976 1975 2013 2013 2013

INJ INJ

Strawn 5400’ Sand Strawn 5400’ Sand Strawn 5400’ Sand

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Typical Wellbore Completion

• Drilling
• 10 ¾” surface casing at 350’ to 400’
• GAU depths vary between 150’ to 200’
• 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
• Place Ryt-Wrap casing across 2 most corrosive zones in case of cement channels (Coleman

Junction 2300 & Cisco 3500’),

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

column)

• 7” 23 ppf 13Cr80 JFEBear
• 80 ksi yield strength, burst and collapse ratings same as N-80
• JFEBear connection is gas tight with torque shoulder
• Completion
• Perforated 4 SPF @ 120 degree phasing
• Twin Peaks Formation - Fracture stimulated with 200’ frac length
• Strawn Lower Formation - Fracture stimulated with 50’ fracture length
• 5400 Sand Formation – Most are fracture stimulated with 50’ fracture length
• Operations
• ESP’s in most producers 28 ESP’s & 7 Rod pumps
• Monitoring various variables (motor speed, intake pressure, temperature, etc.)
• Currently operating with casing head (annulus) gas commingled with full production
• Treating wells for asphaltenes/paraffin, scale, and corrosion

Injector Producer

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Facility Schematic

HEATER TREATER

25#

TEST TRAIN PRODUCTION HEADER

INJECTING WELL

WATER TANK FREE WATER KNOCKOUT

75#

75# 400# 400#

DEHYDRATION COMP COMP COMP COMP 1900# 1900# 1900# 1900#

PUMP PUMP PUMP

~1600# PURCHASED CO2 DELIVERY

PRODUCING WELL

SWD (as needed)

OIL TANK 5,000 bbl

OIL SALES P/L

PUMP PUMP PUMP PUMP

WAG SKID

WATER INJECTION STATION (WIS) RECYCLE COMPRESSION FACILITY (RCF)

Fourth pump excess capacity

CENTRAL TANK BATTERY (CTB) x4

HP 2-PHASE SEPARATOR

400#

LP 2-PHASE SEPARATOR

75# 3 oz

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Field Operating Pressure

INJECTOR PRODUCER BOTTOMHOLE OPERATING PRESSURE

100-200 psi Pre-Response 600 psi Post-Response 3,300-3,700 psi Both Water & CO2 Targeted Avg. Reservoir Pressure 2,200 psi

• Wellhead Pressures
• Injectors
• 1,600 – 1,700 psi on CO2
• 1,200 – 1,300 psi on Water
• Producers
• HP System: 450 – 500 psi
• LP System: 150 psi
• Consistently evaluating for optimization
• Improved reservoir pressure management
• Optimized pump efficiency given GLR
• 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)

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Current PA1 Production & Injection

• Oil production includes small amount of

remaining secondary

• Recent leveling of oil production largely

driven by reduced process speed

• Declining injectivity
• Fewer patterns initiated
• Manage production to stay below current

facility recycle gas limit of 30 Mmcf/d

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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
• N-27R: 6 mos.
• N-11R: 7 mos.
• Incorporates production allocation back to injector (subjective)
• Based on HCPV of Injector-Producer wedge
• Only includes injectors initiated on CO2

PROD INJ

TWIN PEAKS STRAWN LOWER STRAWN 5400 SD

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Performance Monitoring “Toolbox”

• RAW DATA
• Production: Tank Battery Rates & Well Tests (TOW)
• 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
• Impacts of producing bottomhole pressure on asphaltine/paraffin deposition
• Determine potential methods of treatment and impacts on project value
• Loss of CO2 Injectivity Post-WAG
• Currently reviewing potential causes and collecting data
• Determining if caused by precipitant, relative permeability change, or other
• Optimize conformance across all zones
• Implement ported sleeve technology installed in injection wells
• Understand impacts on oil rate and present value
• Manage through low oil price environment
• Ongoing operations and current profitability
• 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

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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