Development of Non-Shale Reservoirs in the Appalachian Basin using Horizontal Drilling Techniques. Equitable Production Co.

Transcription

1 Development of Non-Shale Reservoirs in the Appalachian Basin using Horizontal Drilling Techniques. James Pancake, Scott McCallum, and Chris Zinn Equitable Production Co.

2 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

3 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

4 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

5 EPC Berea Fairway 20 net sand cutoff

6 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.

7 Paleogeography Late Bedford Time Modified from Pepper, et al., 1954.

8 Paleogeography Middle Berea Time Modified from Pepper, et al., 1954.

9 Berea Depositional Environment 1. Gross thickness and net sand maps indicate thicker intervals near Virginia-Carolina delta of Pepper, et al 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

10 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%

11 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 ( to 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

12 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: md, average.0033 md. Low permeability due to silica cement and intergranular clays. Turbidites that originated from a prodelta environment.

13 Berea Sandstone Wise Co. Virginia 116 ft target interval Average Φ 5%. 1.5 mm

14 BEREA SANDSTONE WYOMING CO. WV SUNBURY BEREA TARGET ZONE CHAGRIN 30 ft target interval Average Φ 8.6 %.

15 TVD

16 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, , Q , , Q , , Q , , Q , , Q , , Q , , Q , , Q , , Q Total 470,986 6,385,427 3,555 Average 75 Q 49 2,589 2,613

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18 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, , Q , , Q , , Q , , Q , , Q , , Q Total 306,866 4,213,314 2,355 Average 75 Q 50 2,604 2,211

19 Average Berea Production (KY) 1800 Gas Production (MCFD) N = Time (Days)

20 Model Parameters Upper Berea Lower Berea X VERTICAL MODEL 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 Porosity 5.80% 6.50% HORIZONTAL MODEL Perm. (Matrix) md md X UPPER BEREA Perm. (Fracture) Skin 0.03 md md -2 Z LOWER BEREA

21 Vertical Well History Comparison Berea Actual 80 acre Grid 80 ACRE Time (Days) RESERVOIR PRESSURE (PSIA) Gas Production (MCFD)

22 Horizontal Well History Comparison Gas Production (MCFD) Horizontal Actual 100 acre 200 acre 500 acre 100 ACRE 200 ACRE Time (Days) 500 ACRE RESERVOIR PRESSURE (PSIA)

23 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

24 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 = Avg Porosity = 3.4% A B C

25 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 = 10 Miles

26 Gas Check at TD = 581 MCFD Lower Huron Shale

27 Natural, 30 Day IP = 1486 MCFD

28 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.

29 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.

30 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

31 Reservoir Optimization

32 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!!

33 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.

34 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

35 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.

36 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