The Industry Market Change and its Effect on Completion Design in the Eagleford Shale April 2017 Kent Kansala - Manager, Completions Western Operations Area
EnCana-Who Are We Anyway?
Eagle Ford and Austin Chalk Geology SS TVD Austin Legal Austin Eagle Ford Properties Eagle Ford (Gillett) Austin Chalk D (Gillett) Porosity (%) 8.0 4.4 BVHA (%) 6.5 3.75 Pore Type Organic Interparticle/ Intraparticle Perm (nd) 300 nd 1500 nd TOC (%) 4.1 0.33 S w (%) 25.0 30.0 Poisson s 0.28 0.32 Youngs (mmpsi) 4.8 7.3 Pressure (psi) 7500 8500 Lower Eagle Ford Cloice Maness Buda 3
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Rig Count Southern & Western Operations US Eagle Ford and Permian Rig Count 600 500 400??? 300 200 100 0 2014 2015 2016 2017 2018 Eagle Ford (Baker Hughes monthly avg.) Eagle Ford (Pac West Forecast, Quarterly) Permian (Baker Hughes monthly avg.) Permian (Pac West Forecast, Quarterly)
Completions Evolution Proppant Loading, Cluster Spacing and Oil Price
Eagleford Basin (Karnes County 2016) Competitor Completion Metrics 2015 Basin Average 2016 Basin Average Encana EOG Conoco Marathon Murphy Pioneer Statoil Proppant (lb/ft) 1,667 1,709 1,515 2,997 1,936 1,017 1,702 1,197 1,478 vs. Avg Less More More Less Avg Less Less Fluid (gal/ft) 1,351 1,348 1,122 2,447 1,378 726 1,919 979 1,107 vs. Avg Less More Avg Less More Less Less Notable differences Basin average lb/ft increased slightly in 2016, gal/ft stayed the same EOG Pumping 75% more proppant/ft than basin average Only operator pumping slickwater completion all 2016 Marathon Pumping 60% less proppant/ft than basin average Strictly Confidential 6
200 ft 200 ft Evolution Completions Evolution - Model Improving Fracture Complexity Completions Parameter Pre-ECA ECA Design Complex Fracture Cluster Spacing (ft) >60 <25 Proppant (LBS/ft) <1,000 >2,000 Fluid System Viscosity High Low Conceptual Model >60 Clusters, High Viscosity Fluid Low Stress XL 25 Clusters High Stress SW 20 Clusters Stress Stress Infill Opportunity: Pre-ECA completions result in bypassed pay Stress shadowing via excessive width overwhelms interior clusters Pilot Test Gun Barrel View Geomechanical Model Interior Clusters Stress Shadowing leading to ineffective clusters Low Proppant Concentration High Wellbore 1000 ft 1000 ft Thinner fluid reduce stress shadowing SW 15 Clusters Creating complex system with Lin Gel: bi-wing with 40/70 Un-propped secondary fissures 40/70 too large Final Design Propping complex system with 100% SW bi-wing with 100 mesh Propped secondary fissures 100 mesh accesses secondary fissures 1000 ft 1000 ft
Conductivity Comparisons- Are We Cra Cra?? 100 mesh Variability 1 YR 1 YR Conductivity Loss: Mesh size Gain: Cleaner fluid
2016 Tests 2000 lb/ft, xlink 6 clust/stage, 35 CS No AC No UEF Primarily infills Moderate drawdown Completions Slickwater Low Prop / High Prop Cluster Spacing Clusters/stage Pump Rate Horizons Austin Chalk Upper Eagle Ford Drawdown Aggressively opening chokes Spacing 2016 Downspacing in Graben Lateral Length Short laterals 3000 lb/ft, SW 10 clust/stage, 18 CS AC delineation Chevron pattern w/ UEF Greenfield where possible Aggressive drawdown
Perf Design- Limited Entry and Hydraulics 10 guns @ 3-8 spf Cluster 1 Cluster 2 Cluster 3 Cluster 4 Cluster 5 Cluster 6 Cluster 7 Cluster 8 Cluster 9 Cluster 10 8 6 5 5 5 4 4 4 4 3 Flow Area: 10 Cl. 48 shot stage - 16.3 in² ~190 * 2500 #/ft = 475,000 lbs
Pump Schedule Slurry Clean Proppant Chemicals Ste Name Rate Vol Fluid Type Conc C01 C02 C03 C04 C05 C06 C07 C08 C09 C10 C11 C12 C13 C14 C15 p Type [bpm] [gal] [ppg] [gpt] [gpt] [gpt] [gpt] [gpt] [gpt] [ppt] [ppt] [ppt] [ppt] [ppt] [ppt] [ppt] [ppt] [ppt] 1 Establish rate 10 1,000 Slick Water 0.00 0 1 0 0.075 0.15 0.25 2 Acid 10 3,000 HCL Acid 7.5% 0.00 1000 0 0 0 0 0 3 Displace Acid (get rate) 80 14,000 Slick Water 0.00 0 1 0 0.075 0.15 0.25 4 0.25 PPG 90 15,000 Slick Water 0.25 Sand 100 0 1 0 0.075 0.15 0.25 5 0.50 PPG 90 15,000 Slick Water 0.50 Sand 100 0 1 0 0.075 0.15 0.25 6 0.75 PPG 90 45,000 Slick Water 0.75 Sand 100 0 1 0 0.075 0.15 0.25 7 1.00 PPG 90 75,000 Slick Water 1.00 Sand 100 0 1 0 0.075 0.15 0.25 8 1.25 PPG 90 75,000 Slick Water 1.25 Sand 100 0 1 0 0.075 0.15 0.25 9 1.50 PPG 90 60,000 Slick Water 1.50 Sand 100 0 1 0 0.075 0.15 0.25 10 1.75 PPG 90 50,000 Slick Water 1.75 Sand 100 0 1 0 0.075 0.15 0.25 11 2.00 PPG 90 41,875 Slick Water 2.00 Sand 100 0 1 0 0.075 0.15 0.25 12 FLUSH 90 14,000 Slick Water 0.00 0 1 0 0.075 0.15 0.25 CHEMICALS # Purpose Name Qty Unit C01 Acid Hydrochloric Acid 7.5% H75 3000.00 [gal] C02 Friction Reducer Water Friction Reducing Agent J627 401.88 [gal] C03 Surfactant Flowback Surfactant B525 0.00 [gal] C04 Biocide PHMB P20 D 30.14 [gal] C05 Scale Inhibitor SC 428 60.28 [gal] C06 ph Adjusting Agent Sodium Hypochlorite 100.47 [gal] C07 0 0 0.00 0 C08 0 0 0.00 0 C09 0 0 0.00 0 C10 0 0 0.00 0 C11 0 0 0.00 0 C12 0 0 0.00 0 C13 0 0 0.00 0 C14 0 0 0.00 0 C15 0 0 0.00 0
Competitor Comparison Korth A EOG well offsetting Korth A
Total BOE Produced BOE Production Rate / day 1,000 100 0 50 100 150 200 250 300 350 Days on Production 160,000 140,000 120,000 100,000 80,000 60,000 40,000 20,000 - Day 50 Day 100 % Increase XLK 31,105 59,015 GEL 54,513 95,692 38% SW 79,682 140,000* 32% 0 50 100 150 200 250 300 350 Days on Production XLK GEL SW
Learnings Completions Large uplift seen in new completions design in Kenedy area (SW/Tight Clusters/2000+lbs/ft) Graben only other area with full SW design Performance similar to historic well (Jimmerson 10 vs 8) BUT new well at tighter spacing. Hons/Hoff are Linear/SW jobs Drawdown Appear to be outperforming historic area wells (Berdie 1-2) Continue to be aggressive where facility capacity allows Austin Chalk Strong results, continue to delineate Upper Eagle Ford Spacing Continue to develop greenfield in chevron pattern Possibly test brownfield (offset to low producers, in wider gap, complete with SW) Wider well spacing may be needed in Graben Continue to evolve chevron spacing Lateral Length Strong initial production from short laterals, steeper decline When not constrained long laterals are showing strong initial production and shallower declines
Summary Good rocks make good wells Completion design along with drilling targets can make any kinds of rocks perform better Tighter clusters make better wells period Optimize hydraulics as best as possible to ensure equal proppant coverage across entire interval Introduce inter-stage diversion if unable to make system hydraulics work Thin fluids can help turn the corner with fine mesh sands giving better chance to frac secondary fracture networks Thin fluids help create more intense complex fracture networks resulting in greater SRV Several factors into well productivity Well spacing Rock Characteristics Understand reservoir Frac Modeling Geo Mapping Frac Diagnostic work (Fiberoptics/microseismic..)
Oil Goes to $50 and the Service Companies Lose Their Minds!!!! We Got This!
BACKUP
Frac Location Frac Trees Working Tanks Pumpdown pumps Blender Wireline Truck Sand Trucks Offloading Manlift Flowback Tanks Frac Pumps Missle Trailer WL Crane
12 Month Cum BOE PE 12 ($/boe/d) Economics Summary Q1 Q2 Q3 Q4
Jimmerson 10H vs 8H Similar A k t elf,10h < t elf,8h
Korth A 8H Korth A 7H Korth A Results IP30 (bbl/d) 2640 1640 150 day Cum Oil 245 135 Strong wells - paid out in <1 year Korth A 8H is outperforming Korth A7H 7H is a shorter lateral 7H is further from the fault 7H is completely offset by EOG well
Bbls/day EFS Managed Choke Schedules Diagnostic A k plots (SPE-174831) Old Methodology Open chokes to limit tubing pressure drop to 525 PSI in week 1 and 350 PSI in week 2, etc. Empirically derived and applied to all wells New Methodology Use diagnostic RTA plots to monitor choke changes Decreasing slope >A k, Lower y intercept >Fcd Why change? Well specific RTA diagnostics provide real time feedback on well performance Open chokes more aggressively without damage SPE Paper 800 1.6 600 400 1.2 0.8 MMCFD 200 0.4
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4 Normalized Pressure Cum., BOE Completions Evolution - Results Improving Fracture Complexity 30000 Results Rate Transient Analysis for A k 25000 Crews Kenedy Area 20000 15000 Square Root Time 10000 5000 0 0 5 10 15 20 25 30 Days on production A k is a proxy for fracture complexity A = created fracture area k = system permeability Shallower slope on the above chart indicates higher A k Lateral length (ft) Crews Wells 2096 Other Kenedy Wells 4838
5 Propping Thin Complex Systems Stim Lab Study: Variables that control transport into secondary fracture systems: Fluid System Viscosity Low-visc fluid systems promote higher flowrates into secondary fracture systems Some visc (<20cp) eliminates sand size segregation for entry into fissures Mesh size Smaller is better for turning the corner Best transport at higher sand concentrations Velocity CSM Lab Tests: Higher velocities resulted in bypass of secondary fissures (hard to control based on unkown x- sect geometry) Smaller proppants (like 70/140 mesh sand) turned the corner and were easily transported into the secondary slots when pumped above threshold velocities, as compared to bigger proppants (like 30/70 mesh sand).
Eagle Ford Shale Completion Expenditures Q1 Q2 Q3 Q4 Proppant per foot (lbs/ft) 1,233 1,838 2,465 2,790* $MM/Well $6.0 $5.0 $4.0 928 719 $M/1,000 CLL $1,000 $800 $3.0 $2.0 $1.0 $5.17 $3.69 478 $2.55 506 391 350 $1.82 $1.69 $1.67 525 $2.01 588 442 $2.32 $2.34 $600 $400 $- 2014 Average 2015 Average 2016 Budget 2016 Q1 2016 Q2 2016 Q3 2016 Average (4843') (4267') (3829') $MM/Well $M/1,000' CLL Column1 Q4 2016 (XXXX') 2017 Budget (5300') 26 $200 Strictly Confidential
Eagle Ford Shale Completion Performance Successes Cost reductions of 60% compared to Q1/15 Successful execution of reduced cluster spacing utilizing slick water Engineers displacing contractors Opportunities Continue testing reduced cluster spacing in Hons/Hoffman greenfield area Optimize thin fluid design to allow higher sand loading and reduced water volumes Challenges Kotara 14H hole in casing; patching mid-june, if successful will complete in July Karnes City, TX Weddington / Zunker Frac Strictly Confidential 27
Conclusions Old Model New Model Producing from 50m (165ft) Permeability matches core analysis (100nD) Significant undrained resource between wells Producing from at least 100m (330ft) Permeability lower than 100nD Significant undrained resource between fracs or vertically in the reservoir Conclusions Adding wells did not increase recovery factors as much as predicted Wells are producing from further away than was assumed Low permeability natural/hydraulic fracture network is resulting in overlapping SRVs Focus on improving diversion along the well bore to access additional reservoir
Impact of Down Spacing Duvernay Eagle Ford Wide Spacing Tight Spacing Both Duvernay and Eagle Ford show a significant impact of well spacing on production results Well spacing and completion design are strongly interrelated