Lockhart Crossing: Economically Efficient Reservoir Operations

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1 Lockhart Crossing: 1 Economically Efficient Reservoir Operations Nik Wood Denbury Resources Inc. Presented at the 16 th Annual CO 2 Flooding Conference December 10, 2010 Midland, Texas

2 2 Corporate Information Corporate Headquarters Denbury Resources Inc Tennyson Pkwy., Ste Plano, Texas Ph: (972) Fax: (972) Web Site: Contact Us Phil Rykhoek Chief Executive Officer (972) Mark Allen Senior VP & CFO (972) Laurie Burkes Investor Relations Manager (972) About Forward-Looking Statements The data contained in this presentation that are not historical facts are forwardlooking statements that involve a number of risks and uncertainties. Such statements may relate to, among other things, capital expenditures, drilling activity, development activities, production efforts and volumes, net asset values, proved reserves, potential reserves and anticipated production growth rates in our CO 2 models, 2009 and 2010 production and expenditure estimates, availability and cost of equipment and services, and other enumerated reserve potential. These forward-looking statements are generally accompanied by words such as estimated, projected, potential, anticipated, forecasted or other words that convey the uncertainty of future events or outcomes. These statements are based on management s current plans and assumptions and are subject to a number of risks and uncertainties as further outlined in our most recent 10-K and 10-Q. Therefore, the actual results may differ materially from the expectations, estimates or assumptions expressed in or implied by any forwardlooking statement made by or on behalf of the Company. Cautionary Note to U.S. Investors The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms and make certain disclosures in this presentation, such as potential and probable reserves, that the SEC s guidelines strictly prohibit us from including in filings with the SEC.

3 Economically Efficient Reservoir Operations Agenda 3 Lockhart Crossing Introduction and Background Asset Development Principles / Business Plan Reservoir Surveillance Metric Creation and Comparison Economically Efficient Process Evolution Asset Observations Optimization Process Design and Management Plan Implementation Results

4 4 Lockhart s Geographic Location Phase 3 Tinsley 44 MMBbls Phase 5 33 MMBbls Delhi Delta Pipeline Jackson Dome T E X A S Phase 4 31 MMBbls Lake St. John Sonat MS Pipeline NEJD CO2 Pipeline Martinville Davis Free State Pipeline Quitman Heidelberg Summerland Sandersville Soso Eucutta Cypress Creek Yellow Creek L O U I S I A N A Cranfield Brookhaven Smithdale Olive McComb Mallalieu Little Creek Phase 2 77 MMBbls Citronelle Phase 1 M I S S I S S I P P I Phase 7 Hastings Area MMBbls (1) Green Pipeline 86 MMBbls LCKT Phase 6 26 MMBbls Donaldsonville 9 MMBbls Hastings Fig Ridge Oyster Bayou Phase 8 Seabreeze Complex MMBbls (1) (1) Proved plus probable tertiary oil reserves as of 12/31/08, including past production, based on a range of recovery factors. Hastings Field was purchased 2/2/09.

5 Lockhart Crossing 1 st Wilcox Structure 5 OOIP: 56.1 MMBBLS Production: 18.2 MMBBLS (32%) Discovery July 1982 Callon Petroleum 3,500 Acres Unitized 1985

6 6 1 st Wilcox Bar Isopach OOIP: 41.8 MMBBLS Phi: 15-24%, avg. 20% K: md, avg. 80 md

7 7 1 st Wilcox Channel Isopach OOIP: 14.3 MMBBLS Phi: 10-27%, avg. 21% K: 0.1 4,400 md, avg. 500 md

8 Lockhart 1 st Wilcox Review (Pre CO2) Lockhart Field Wilcox 1 Field Found 1982 Initial Operator Callon Formation Wilcox Depth ~10,100' OWC -10,159' DRIVE Solution Gas - Moderate Water TTL Field Area (acre) 3,500 Production History Black Oil produced (stb) 18,200,000 Solution Gas Produced (stb) 17,300,000,000 Water Produced (stb) 21,200,000 Water Injected (stb) 38,988,000 Recovery Primary (stb) 6,808,038 Recovery Secondary (stb) 11,391,962 Rf Primary 12% Rf Secondary 20% Reservoir Description Original Pressure (psi) 4,600 Lowest Pressure (psi) 2,500 Original Bubble Point (psi) 3,550 Porosity 20% Permeability (bar / channel) (md) 80 / 500 Sw Original (bar / channel) (%) 43 / 28 Avg H Koil (ft) 42 Bo Original (rb/stb) 1.53 Gravity (API) 42 Temp (f) 212 OOIP (stb) 56,000,000 OGIP (Solution) (scf) 53,000,000,000 Solution GOR (scf/stb) 951 Well Count during Primary and Secondary Primary Total 37 Secondary Total 49 Secondary Producers 27 Secondary Injection 22 8

9 9 DRI Asset Development Philosophies Develop assets without utilizing full array of industry tools. This is in efforts to attain relatively higher value through accelerated cash flows that would otherwise be delayed (and slightly more costly) Associated with fields that have: Similar analogue reservoirs in DRI s asset base Lower relative reservoir complexity Smaller size (economies of scale) Integrate the full array of industry s technical tools as resources for optimal field development Associated with fields that have: Generally unique features relative to DRI s tertiary asset base Higher relative reservoir complexity Larger in size (the bigger the difference a X% change in recovery makes)

10 10 Lockhart s Business Plan / Development Principles Lockhart provides a relatively small tertiary target that requires efficiencies in design, development, and operation to be strong economically Utilize known analogues for technical guidance to reduce cost and accelerate timing Utilize old wellbores to develop asset at low cost Small facilities in design and footprint to minimize CAPEX and LOE Asset Design Capacities 3,500 BOPD 11,000 BWPD 60 MMSCFPD recycle 60 MMSCFPD purchase

11 Lockhart Crossing Field CO 2 Flood - Milestones 11 Well work commenced in January 2007 Drilling commenced April 2007 Denbury commenced construction of CO 2 Recycling Facility in May 2007 After receiving COE permit, pipeline construction commenced September 2007 Construction of six-mile 8 CO 2 supply pipeline completed 3 rd quarter 2007 Injection of CO 2 began in December 2007 First CO 2 production occurred in June 2008 first sales July 2008 Test Site 1 operational June 2008, Test Site 2 operational January 2009 Lockhart produced it s 1,000,000th BBL of CO2 Oil in June 2010!

12 Lockhart Original Pattern Design 12

13 13 Lockhart Crossing Field Life Lockhart Crossing Fluid Rates 8,000 70,000 7,000 60,000 6,000 50,000 5,000 BPD 4,000 3,000 40,000 30,000 2,000 1,000 - Feb-82 Feb-86 Feb-90 Feb-94 Feb-98 Feb-02 Feb-06 Feb-10 MSCFPD 20,000 10,000 - Date Oil (bpd) Water (bpd) Water Inject (bpd) CO2 Injection (mscfpd) CO2 Production (mscfpd)

14 14 Lockhart 1 st Wilcox Review Lockhart Crossing Reservoir Surveillance Life Metrics units Start Date 6/1/2008 Current date 11/30/2010 Life to date 2.50 years Life to date 7.1% Expected Life 35 years Cumulative Metrics Cum CO2 injected 51,042,000 MCF Cum Recycle 19,928,234 MCF Cum Purchase 31,113,766 MCF Cum Water 6,540,421 BBLS Cum Oil 1,411,753 STB LCU phase 3 Current Pattern Total HCPVI 44.00% 42.5% Current Pattern Oil Rec 3.96% 4.3% Oil Rec to HCPVI < 0.10 Field Total HCPVI 28% Field Oil Rec 2.5% Total HCPVI to Oil Rec 0.09 dmsless Gross Utilization 36 mcf/stb Net Utilization 22 mcf/stb Rate Metrics Daily Oil Rate 2,866 STBPD Daily Purchase 28.3 mmscfpd Daily Recycle 48.1 mmscfpd Current Pattern HCPVI/day 0.07% HCPV oil recovered/day 0.008% LCU phase 3 HCPV rec /inj/day 0.12 > 0.086

15 15 Dimensionless Top Performer Dimensionless Dimensionless Comparison Comparison LCU LCU Phase Phase 3 3 vs. vs. LCKT LCKT Oil Recovery (% of HCPV) Oil Recovery (% of HCPV) 20% 20% 18% 18% 16% 16% 14% 14% 12% 12% 10% 10% 8% 8% 6% 6% 4% 4% 2% 2% 0% 0% 0% 50% 100% 150% 200% 250% 300% 350% 400% 0% 50% 100% 150% 200% 250% 300% 350% 400% CO2 Injected (% of HCPV) CO2 Injected (% of HCPV) LCU Phase #3 LCKT Field LCU Phase #3 LCKT Field

16 Challenge Comes with Smaller Scale 16

17 17 Presentation Preface The communication objective and technical content of this presentation are basic reservoir and economic concepts Though the concepts demonstrated are elementary these concepts provide a high magnitude of economic impact The focus of this presentation is to highlight simple methods of evaluation to ensure maximization of asset value Hindsight is 20/20, when looking back operation modifications may seem implicit, but it might not have been so clear during the implementation

Reservoir Pressure Surveillance CO2 injection Fluid Withdraw To maintain MMP To maintain flowing wells Reservoir Gas RB CO2 RB Oil RB Water RB IWR IWR = CO2 (RB) (Gas (RB) + Oil (RB) + Water (RB))

18 Reservoir Pressure Surveillance CO2 injection Fluid Withdraw To maintain MMP To maintain flowing wells Reservoir Gas RB CO2 RB Oil RB Water RB IWR IWR = CO2 (RB) (Gas (RB) + Oil (RB) + Water (RB)) IWR (instantaneous) delivers direction your reservoir pressure is going at a given instant. Net Cum Fluid Net Cum Fluid = Cum CO2 RB Cum (Gas (RB) + Oil (RB) + Water (RB)) Delivers direction the reservoir pressure is going at a given instant by the slope of the curve. IWR (cumulative) delivers the relative reservoir pressure from the point in time the accumulation began. Delivers the relative reservoir pressure from the point in time the accumulation began. Delivers magnitude of fluid thus the magnitude of relative pressure change based on reservoir size. 18

19 19 Fluid to Pattern Allocation Fluid dynamics within a reservoir are difficult to calculate Pattern allocation is a simple method used to account / estimate source of fluid flow Used for Net Cum Fluid calculation Serves as guides to remaining saturations within patterns There are many methods for allocation a b Reservoir Boundary 150 RB c mm/day 50% d 50% 100 RB 5 mm/day e f Geometric allocation >Splits Pattern 1 and 2 production of fluid evenly C allocation to Pattern 1 = # of wells # of patterns sharing the well = 1 2 = 50% a b Reservoir Boundary 150 RB 10 mm/day 75% c d 25% 100 RB mm/day e f HCPV & I allocation >splits Pattern 1 and 2 production based on injection rate and magnitude of HCPV C allocation to pattern 1 = (HCPV1 * Injection rate1 / (HCPV1 * Injection rate1 + HCPV2 * Injection rate2)) = 10 * 150 / (10* *100) = 75%

20 Allocation Accuracy Evidence Net Cumulative Fluid Comparing Allocation Methods 2,000,000 1,800,000 1,600,000 1,600 MRB 1,400,000 1,400 MRB 1,200,000 1,000, ,000 5,847 psi 1,050 MRB 5,506 psi 1,016 MRB 600, , , /7/2008 7/7/2008 8/7/2008 9/7/ /7/ /7/ /7/2008 1/7/2009 2/7/2009 3/7/2009 4/7/2009 5/7/2009 6/7/2009 7/7/2009 8/7/2009 9/7/ /7/ /7/ /7/2009 1/7/2010 2/7/2010 Date Thom 1 I&HCPV Thom 1 Geo Net Cum Fluid (RB)

21 21 Economically Efficient Asset Development Economically Efficient (Theoretical) No additional output can be obtained without additional input Production proceeds at the lowest per unit cost The cost of producing a given output is as low as possible Economically Efficient (Financial) Max IRR Max NPV Abide within cash flow constraints Economically Efficient Ranking of Choice = Max NPV Maximize Revenue Delay of negative cash flows Minimize Capital Operating Expense Delay of positive cash flows Cost of Capital

22 22 Maximize Oil Reservoir NPV Asset Optimization Problem Maximize oil recovery magnitude Minimize recovery time (acceleration) Minimize cost Maximize delay in capital outlays

23 23 Optimize recovery time and cost Source Maximize Pressure Drop and Conductivity Purchase Recycle i Maximize BHIP Maximize Conductivity Reservoir p Minimize BHFP Maximize Conductivity Manifold Compress Bulk lines Facility Minimize cost of attaining pressure drop and conductivity Constrained by: coning, MMP, and sand production

24 1,200,000 1,200,000 1,000,000 1,000, , , , , , , , ,000 0 Reservoir Management Net Cumulative Fluid Thom #1 Pattern Net Cumulative Fluid Thom #1 Pattern 12/7/07 12/7/07 12/21/07 12/21/07 1/4/08 1/18/08 1/18/08 2/1/08 2/1/08 2/15/08 2/15/08 2/29/08 2/29/08 3/14/08 3/14/08 3/28/08 3/28/08 4/11/08 4/11/08 4/25/08 4/25/08 5/9/08 5/9/08 5/23/08 5/23/08 6/6/08 6/6/08 6/20/08 6/20/08 7/4/08 7/4/08 7/18/08 7/18/08 8/1/08 8/1/08 8/15/08 8/15/08 8/29/08 8/29/08 9/12/08 9/12/08 9/26/08 9/26/08 10/10/08 10/10/08 10/24/08 10/24/08 11/7/08 11/7/08 11/21/08 11/21/08 12/5/08 12/5/08 12/19/08 12/19/08 1/2/09 1/2/09 1/16/09 1/16/09 1/30/09 1/30/09 1,050 MRB 1,050 MRB 5,847 psi 5,847 psi Open Wells Open Wells 5,200 psi 5,200 psi MMP Date Date Net Cum Fluid (RB) Net Cum Fluid (RB) 1/4/08 0 Optimum Reservoir Management? Fill Up 24

25 Team Objective Communication Objective 1. Maximize injection through utilization of all equipment 2. Accelerate production through accelerated injection 3. Optimally produce reservoir Solution 1. Open Chokes (increasing production rate) 2. Reduce IWR <1 3. Reduce Reservoir Operating Pressure (also helps utilization CO2 expansion) 4. Increase injection (given 3,000 psi surface injection pressure) 5. Accelerate production through optimal reservoir operating pressure Constraints MMP Surface operation constraints Purchase Recycle Water Handling

26 1,200,000 1,200,000 1,000,000 1,000, , , , , , , , ,000 0 Process Management Net Cumulative Fluid Thom #1 Pattern Net Cumulative Fluid Thom #1 Pattern 26 12/7/07 12/7/07 1/7/08 1/7/08 2/7/08 2/7/08 3/7/08 3/7/08 4/7/08 4/7/08 5/7/08 5/7/08 6/7/08 6/7/08 7/7/08 7/7/08 8/7/08 8/7/08 9/7/08 9/7/08 10/7/08 10/7/08 11/7/08 11/7/08 12/7/08 12/7/08 1/7/09 1/7/09 2/7/09 2/7/09 3/7/09 3/7/09 4/7/09 4/7/09 5/7/09 5/7/09 6/7/09 6/7/09 7/7/09 7/7/09 8/7/09 8/7/09 9/7/09 9/7/09 10/7/09 10/7/09 11/7/09 11/7/09 12/7/09 12/7/09 1/7/10 1/7/10 2/7/10 2/7/10 1,050 MRB 1,050 MRB 5,847 psi 5,847 psi open chokes open chokes Open Wells Open Wells 5,200 psi 5,200 psi Date Date Net Cum Fluid (RB) Net Cum Fluid (RB) 0 Optimum reservoir Management? Fill Up Open chokes

27 27 Lockhart Crossing CO2 EOR Induced Acceleration

28 28 Opening of Chokes Thom #1 Net Cum Fluid Felker #1 Injection Rate

29 Results of 2009 to 2010 choke changes 29 Lockhart Choke Size Increase Lockhart Choke Size Increase 180% 180% 160% 160% 140% 140% 120% 120% % increase % increase 100% 100% 80% 80% 60% 60% 40% 40% bopd 1441 bopd 2284 bopd 2284 bopd 50 mmscfpd 50 mmscfpd 65 mmscfpd 65 mmscfpd 20% 20% 0% 0% Choke Size Choke Size Oil Rate Oil Rate CO2 Injection CO2 Injection Category Category

30 30 Optimize recovery time and cost Pressure Drop and Time Savings 70 Cum Production Time dp1 dp2 dp3 dp4 The larger the pressure drop the faster the oil is retrieved.

31 31 Optimize recovery time and cost Cost and Acceleration Cost slow medium fast fastest Acceleration

32 32 Optimize recovery time and cost NPV and Acceleration NPV slow medium fast fastest Acceleration The second largest pressure drop provides maximum value

33 Booster Pump / Asset Optimization 33 6,500 5,500 Max incremental rate and therefore max value attainable by the Thom #1 Booster Pump Value Max incremental rate and therefore max value attainable by the two 3.5 mm/day Max incremental rate and therefore max value attainable by one 3.5 mm/day injection pattern Booster NPV 10% dsct (M$) 4,500 3,500 2,500 1,500 $3.4MM $2.7MM 500 $217M Booster Pump Incremental Injection Rate (mmscfpd) Thom #1 Pattern Bar Injection Wells

Lockhart s Bar Injection Hurdle 34 Bar Injection wells injecting at ~5 mmscfpd Channel wells maximum injection rate ~17 mmscfpd down 2-7/8 tubing Transitively the bar formation is

34 Lockhart s Bar Injection Hurdle 34 Bar Injection wells injecting at ~5 mmscfpd Channel wells maximum injection rate ~17 mmscfpd down 2-7/8 tubing Transitively the bar formation is the bottle neck (not the 2-7/8 tubing) Remaining Lockhart development is in the Bar Formation NPV is hindered due to a choke at the formation Stimulation is not currently an option

35 Horizontal vs. Vertical Horizontal Vertical Effective Formation Contact Injection Rate 5X 1X Production Rate 5X 1X K*H*dp u*ln (re/rw) Formation Contact 40 Formation Contact 200 Lateral Length = 1000

36 Horizontal Well / Asset Optimization 36 Well Count Oil Rate Rate Revenue Acceleration NPV Cost Fluid Rate Facilities Cost NPV The Optimal Asset Harmony (where NPV is maximum)

37 Horizontal Well Asset Optimization Lockhart Future Development Economic Comparison PV10 (M$) Injection rate per horizontal (mmscfpd) Lockhart Incremental Future Development PV10 with vertical well development Total Future Horizontal Well Count

38 Economically Efficient Reservoir Operations Results 38 Induced Acceleration Incremental Value Associated with Acceleration Base Value

significantly more value to be added to the asset outside (and inside) that circle I look

39 Economically Efficient Reservoir Operations Includes optimization of all of this map plus more 39 Today s presentation covered some of the topics in the circled area There s significantly more value to be added to the asset outside (and inside) that circle I look forward to watching the DRI team further maximize the value of Lockhart Crossing by accomplishing their goals

40 40 Special Recognition Management (names left to right) Donnie Dubois - Field, Bob Sutherland - Reservoir, John McDaniel - Land, Joey Smith - Operations, James Fields - Land, Charlie Gibson - V.P. West, Don Butvin - Facilities, Bob Schellhorn - Geology, Mary Tombs - Production

41 41 Special Recognition Plano Team (names left to right) Dan Emmer, John McDaniel, James Fields, Sarah Dixon, Nik Wood, Misty Marko, Randy Charles, Randy McKenzie, Kyla Coker, Nic Bongiovanni, Jim Johnson

42 42 Special Recognition Field Team (left to right) Jason Shaffer, Todd Bergeron, Jimmy Naquin, Eroll Tisdale, Bobby McDougal, Mike Crawford, Henry Schultz, Chris Odom, Donnie Dubois, Dustin Swallow, Cecil Rushing, Dale Louviere, John Duplantis

43 Questions 43

8 th Annual Wyoming CO 2 Conference

8 th Annual Wyoming CO 2 Conference July 2014 Click About to Forward-Looking edit Master title style Statements The data contained in this presentation that are not historical facts are forward-looking