Development of Non-Shale Reservoirs in the Appalachian Basin using Horizontal Drilling Techniques. James Pancake, Scott McCallum, and Chris Zinn Equitable Production Co.
Outline Overview of non-shale horizontal development. Berea sandstone. Lower Huron siltstone. Basic concepts for exploitation of the petroleum system in the Appalachian Basin. Summary
Map of Non-Shale Horizontal Wells Drilled WEST VIRGINIA KENTUCKY VIRGINIA Total Berea Drilled KY = 9 wells WV = 3 wells = LH Silt Spud Well = Berea Spud Well = 10 Miles Total LH Silt Drilled WV = 10 wells
Cross section of non-shale targets in WV and KY 1. X-section possibly bisects two separate Berea sources 2. KY Berea prodelta, Virginia Carolina delta source 3. WV Berea fluviodeltaic to delta front, Cabin Creek delta source 4. LH Siltstone possible turbidite; pinches out to west, gradational to east A X-Section ~150 miles SUNBURY A BEREA LH SILTSTONE A LOWER HURON A
EPC Berea Fairway 20 net sand cutoff
Berea Paleogeographic Setting 1. Four main deltaic complexes in OH, KY, VA and WV a) Bedford Deltaic Complex (OH and KY) b) Gay Fink Deltaic Complex (WV) c) Cabin Creek Deltaic Complex (WV) d) Likely Virginia-Carolina Deltaic Complex (VA, WV and KY) 2. Berea is likely gradational between different sources. Statements above collected primarily from Pepper, et al., 1954.
Paleogeography Late Bedford Time Modified from Pepper, et al., 1954.
Paleogeography Middle Berea Time Modified from Pepper, et al., 1954.
Berea Depositional Environment 1. Gross thickness and net sand maps indicate thicker intervals near Virginia-Carolina delta of Pepper, et al.1954. 2. Possible commingling of Red Bedford and Virginia-Carolina source material in the thickest mapped area (NW) = 30 miles Isopach: Berea Net 3. Area could be a Sand Isopach: (140 api Berea cut-off) Gross combination of 2-3 Thickness delta sources. 0 25 50 75 100 0 25 50 75 100
BEREA SANDSTONE PIKE CO. KY 70 ft target interval Average Φ 7 %. Berea Mineralogy Pike Co. Kentucky 7% 7% 2% Quartz 9% Mica Clays Plagioclase/ Feldspar Carbonates 75%
GRI Berea Study GRI 94/0258.1, S.A. Holditch and Associates, Inc. Ashland Exploration Inc., Ford Motor Co. 80 (COOP 2) 1993 Key Conclusions 2 independent, non-communicating sand packages. Matrix permeability (0.0001 to 0.0008 md). 2 sets of high angle natural fractures Fracture containment in the Berea Operators and GRI should evaluate the potential for horizontal wells in the Berea
Berea Sandstone Dickenson Co. Virginia PECO Sidewall cores, core analysis by Gearhart Labs Subarkosic sandstone to siltstone. Very fine grained, subangular to angular, well sorted. Porosity: 2 10%, average 5% Permeability: 0.0018 0.1298 md, average.0033 md. Low permeability due to silica cement and intergranular clays. Turbidites that originated from a prodelta environment.
Berea Sandstone Wise Co. Virginia 116 ft target interval Average Φ 5%. 1.5 mm
BEREA SANDSTONE WYOMING CO. WV SUNBURY BEREA TARGET ZONE CHAGRIN 30 ft target interval Average Φ 8.6 %.
TVD
567132 Fracture Treatment Results and Parameters 9 Stage Packers Plus Foam Frac 30 Day IP = 2,158 MCF/D 30 Day Cum = 64,753 MCF TotaFluid(bbls) Avg Treated rate(bpm) Avg Breakdown Pressure Avg treat Pressure Stage Sand(lbs) N2(scf) Foam 1 51,191 699,834 417.17 75 Q 44.0 3773 3082 2 51,269 743,818 397.8 75 Q 44.0 2943 2833 3 51,612 747,226 391.3 75 Q 50.0 2649 2829 4 51,623 709,720 385.4 75 Q 50.0 2754 2614 5 51,396 674,607 374.6 75 Q 50.0 2771 2469 6 56,181 705,806 432.1 75 Q 50.0 1632 2483 7 52,541 683,161 411.3 76 Q 50.0 1393 2543 8 51,019 701,375 378.8 77 Q 50.0 2955 2362 9 54,154 719,880 367.0 78 Q 50.0 2427 2300 Total 470,986 6,385,427 3,555 Average 75 Q 49 2,589 2,613
505116 Fracture Treatment Results and Parameters 6 Stage Packers Plus Foam Frac 30 Day IP = 780 MCF/D 30 Day Cum = 33,302 MCF TotaFluid(b bls) Avg Treated rate(bpm) Avg Breakdown Pressure Avg treat Pressure Stage Sand(lbs) N2(scf) Foam 1 50,243 732,076 421.73 75 Q 50.0 3452 2410 2 50,546 732,545 393.0 75 Q 50.0 2693 2215 3 50,246 746,476 386.6 75 Q 50.0 2393 2277 4 50,980 664,371 388.3 75 Q 50.0 2525 2224 5 50,458 656,448 386.8 75 Q 50.0 2297 2108 6 54,393 681,398 378.4 75 Q 50.0 2265 2030 Total 306,866 4,213,314 2,355 Average 75 Q 50 2,604 2,211
Average Berea Production (KY) 1800 Gas Production (MCFD) 1600 1400 1200 1000 800 600 400 200 N = 5 0 1 31 61 91 121 151 181 Time (Days)
Model Parameters Upper Berea Lower Berea X VERTICAL MODEL 5 10 15 20 25 Thickness (>4% Φ) 40.5 ft 28.5 ft UPPER BEREA Reservoir Pressure 925 psi 970 psi Z Water Saturation 35.30% 36.20% LOWER BEREA 5 10 15 20 25 Porosity 5.80% 6.50% HORIZONTAL MODEL Perm. (Matrix) 0.0008 md 0.0008 md X 5 10 15 20 25 UPPER BEREA Perm. (Fracture) Skin 0.03 md -2 0.06 md -2 Z LOWER BEREA 5 10 15 20 25
60 50 40 30 20 10 0 Vertical Well History Comparison Berea Actual 80 acre Grid 80 ACRE 30 334 638 942 1246 1550 1854 2158 2462 2766 3070 3374 3678 3982 4286 4590 4894 5198 5502 5806 Time (Days) RESERVOIR PRESSURE (PSIA) 228.4656 413.8492 599.2328 784.6164 970.0000 Gas Production (MCFD)
Horizontal Well History Comparison Gas Production (MCFD) 1200 1000 800 600 400 200 Horizontal Actual 100 acre 200 acre 500 acre 100 ACRE 200 ACRE 0 30.4 942.4 1854.4 2766.4 3678.4 Time (Days) 500 ACRE RESERVOIR PRESSURE (PSIA) 228.4656 413.8492 599.2328 784.6164 970.0000
Non-Shale Horizontal Wells Drilled WEST VIRGINIA KENTUCKY Total Berea Spudded KY = 9 wells WV = 3 wells VIRGINIA = LH Silt Spud Well = Berea Spud Well = 10 Miles Total Lower Huron Silt Spudded WV = 10 wells
LH Silt Geographic & Stratigraphic Position MINGO LOGAN = 10 Miles C B A WYOMING 1. Very fine grained sandstone to siltstone deposit at the top of the Lower Huron 2. Avg Thickness = 64 3. Avg Porosity = 3.4% A B C
LH Silt Depositional Environment Potential Turbidite Deposits 1. Bounded by shale above and below. 2. Drill cuttings in thicker areas indicate sand sized particles. 3. Many logs indicate fining upward sequence based on GR signature. 4. Trends NE/SW and possibly on Isopach: LH Silt Net strike with the Devonian Gross Sand (140 Thickness api cut-off) paleoslope. 0 20 13 38 55 25 73 38 90 50 = 10 Miles
Gas Check at TD = 581 MCFD Lower Huron Shale
Natural, 30 Day IP = 1486 MCFD
Basic concepts for the total petroleum system in the Appalachian Basin. Devonian aged organic rich black shales act as the source for the various sandstone, siltstone, and limestone reservoirs found in association with or up section from the shales. Sandstones and siltstones act as storage zones and conduits for enhanced gas deliverability. Naturally occurring fractures and faults act to transmit gas and enhance flow throughout the system.
Devonian/Mississippian Petroleum System Fundamental Concepts Initially charged via migration during burial and hydrocarbon generation. Sands, silts, and limes with enhanced K and Phi Reservoirs are secondarily sourced via natural hydraulic fractures that intersect multiple horizons. Fine grained sandstones and siltstones act as French Drains among extremely low permeability shale horizons. Source Beds Natural fractures and faults allow some communication between horizons.
Stacked Laterals, Natural Fracture Evidence Possible Fracture LH Gas Show LHSilt Gas Show LHSilt Lateral LH Lateral Fracture/Fault could explain gas shows occurring in both laterals at similar vertical sections
Reservoir Optimization
System Development Small increases in permeability can result in significant increase in gas deliverability. Fine grained sandstone and siltstone French Drains are ideal target intervals. Multiple wellbores targeting different reservoirs is the most effective and timely method to exploit the entire system. JUST DRILL IT!!
Benefits of Horizontal Drilling in Tight Sandstones Maximize wellbore contact with the reservoir. Ability to target zones within the reservoir with the best porosity and permeability. Connect existing natural fracture network. Revitalization of developed areas. Greater flexibility when planning surface locations, i.e. sweet spots can be accessed from thousands of feet away.
Additional Targets Targets that were depleted or marginally economic are now viable Potential future targets include: Ravencliff, Big Lime, Big Injun, Weir, Gordon, Benson, Alexander Additional testing and data collection is planned
Summary Horizontal drilling in non-shale targets has proven economic to date. Berea and LHSilt show enhanced production versus horizontal shale targets. Multiple targets are viable thereby revitalizing Appalachian basin acreage. The current model being tested is a low permeability hydrocarbon system with more porous and permeable intervals connected by natural fractures. This system is most effectively exploited through horizontal drilling.
Acknowledgements Co-Authors Scott McCallum and Chris Zinn Mike Canich and Equitable Production Co. EPC Joe Morris Martin Puskar Chris Chase Katie Pankowski Taylor Vactor John Ajak