Improved Production from Horizontal Wells in the Bakken

Transcription

1 Improved Production from Horizontal Wells in the Bakken More detail - SPE Russell Rankin, Brigham Exploration Michael Thibodeau, Brigham Exploration Mike Vincent, Consultant Terry Palisch, CARBO Ceramics Some Questions How do I maximize reservoir contact? What are design differences between longitudinal and transverse fractures? How many stages? Which proppant? Flowback strategy? Is it just rate acceleration or EUR? Can you prove it with field results? 1

2 Reservoir Contact Overhead, map view of 5 laterals drilled from one wellhead. Multi-Lateral 15, ft of drilled length in 5 laterals <24, ft 2 of reservoir contact Tiny frac; perhaps 2, lbs of proppant at 1 lb/sq ft 2 wings * 2 faces * 2 ft * 5 ft = 4, ft 2 of contact Propped fractures touch more rock than multi-lateral wells It is more cost-effective to touch rock with a fracture than with a drill bit Simple, single laterals designed for stimulation With 15 fracs, estimate ~6,, ft 2 of contact Design Challenges Longitudinal openhole 5, foot lateral provides 1, linear feet of intersection with fracture Transverse Circumference of 6 hole = 1.6 feet If both fractures deliver the same amount of oil to the wellbore, oil must travel 6,25 times faster in the transverse frac due to converging flow. Pressure losses in propped fracs are related to velocitysquared. 6,25 2 = >39 million times greater pressure loss near wellbore You will always want more conductivity near-wellbore in transverse fracs 2

3 How Many Fracs? This operator designs each well to receive 12 to 15 transverse fractures How? Uncemented liners, 3 to 36 swellable packers Plug and Perf, 4 clusters per stage Why? 4 oil entry points per stage Pressure losses in each fracture are reduced by 42 or 16-fold Same contact, but much more effective Lf = 4x Lf =4x Lf = 1x Lf =1x How Many Fracs? 5, 4,5 1,2 1, 4, Stages 3, Stages 3, 24 Stages 2, Stages 2, 1-12 Stages 1,5 7-9 Stages 1, Single Stage , 5, 75, 1, 125, 6 Smaller dataset >1 Stages <1 Stages 4 Similar lateral length and close proximity 2 25, 5, 75, 1, 125, 3

4 Which Proppant? If you believe you have transverse fracs, you should believe you need better proppant near wellbore. Used mostly 2/4 lightweight ceramic. Some use of IDC when availability required. Field Results Results analyzed in two Study Areas in ND SASKATCHEWAN Study Area A Study Area B Roosevelt Co. Williams Co. Richland Co. Nesson Anticline Mountrail Co. MONTANA NORTH DAKOTA McKenzie County Dunn Co 4

5 C D B Field Results A Single stage well IPs ~15 to 3 Bopd Single stage fracs gave low, but remarkably similar production Corroborates Vertical Well Control Indicating Consistent Reservoir Attributes Across ~19 Miles in Study Area A Well A Well B Well C Well D 1 Normalized to Date of Peak Rate A C E D B Field Results Operator s first 2-stage completion 4x to 9x IP 1,5 Well A Well B Well C Well D Well E 1, 5 Well E: 2-stage completion 4x to 9x IP 25, 5, 75, 1, 125, 5

6 Evolution of This Operator s Designs You don t always save your way to prosperity 95% increase in wellcost for 55% increase in EUR!! Validation Offset Comparisons Well G IP/3-day: 5,133/1,99 Boepd Well H IP/3-day: 2,154/1,346 Boepd Offset Wells I, J & K IP/3-day: 1,924/ 657 Boepd IP/3-day: 93/ 52 Boepd IP/3-day: 1,451/ 764 Boepd Offset Well L IP: 789 Boepd Well F IP: 5,35 Boepd 4,5 First Prod Stages Method Proppant 4, Well F 5/1 36 Plug & Perf Ceramic Well G 4/1 27 Plug & Perf Ceramic 3,5 Well H 8/9 24 Plug & Perf Ceramic Well I 8/9 1 Frac Sleeves White Sand 3, Well J 8/9 1 Frac Sleeves White Sand Red: stages, plug & perf, ceramic Blue: 1-18 stages, sleeves, sand 2,5 2, 1,5 1, 5 Well K 9/9 1 Frac Sleeves White Sand Well L 5/1 18 Frac Sleeves White Sand Well F Well G Well H Well I Well J Well K Well L 25, 5, 75, 1, 125, 15, Pumping Unit Installation 6

7 Validation Offset Comparisons 15, Well F Well G Well H Well I 125, Well J Well K Well L 1, 75, 5, 25, Red wells not yet on pump, yet still outperforming despite higher backpressure Pumping Unit Installation Time, Days 1, 1, Validation Diagnostic Plots No detrimental signature with closely spaced ceramic fracs (8 feet) These results compare both prop type and stage count Rate, BOPD 1 Well F Well G.1 Well H Reference line, negative 1/2 slope Pumping Unit Installation (none) Time, Days Transient flow without boundary effects Superior skin, no evidence of increased stage competition! (more in ) 1/Q, days/bbls.4.2 Well J Well K Well L Pumping Unit Installation Square Root of Time, Days.5 Well F Well G Well H Well I 7

8 Validation Offset Similar Stage Count Well M 1 Stages Wells N-S 6-11 Stages 7, 6, Well M Well N Well O Well P Well Q Well R Well S 5, 4, 3, 2, 1 P&P stages of ceramic appears to outperform 6 to 11 frac port stages of sand 1, Months Validation Three Forks Well T IP/3-day: 2,21/989 Boepd Offset Well U IP/3-day: 1,479/ 632 Boepd 2, 1,8 1,6 1,4 1,2 1, First Prod Stages Method Proppant Well T 7/9 18 Plug & Perf Ceramic Well U 11/9 24 Frac Sleeves White Sand Well T Well U 18 P&P stages of ceramic outperforms 24 frac port stages of sand 25, 5, 75, 1, 125, Pumping Unit Installation Figure 21 8

9 Some Answers How do I maximize reservoir contact? Multiple transverse fracs What are design differences between longitudinal and transverse fractures? Transv: Maximize conductivity and entry points How many stages and perf clusters? Have not identified upper limit * 4? Which proppant? Light weight ceramic (may try 16/2) Is it just rate acceleration or EUR? Clearly adding reserves. 8 spacing?! Can you prove it with field results? Yes Some Conclusions Bakken reservoir quality Varies across 2, square miles Remarkably similar across 2 miles Can learn from well results to improve strategies Drill wells you can (and will) effectively fracture Single lats, plug & perf, multiple transverse fracs Frac with ceramic proppant More durable and conductive Proppant Flowback? No significant prop flowback in these ceramic completions Recoverable reserves 5, to 7, boe with current strategy F&D costs Reduced from $4/boe to ~$15/boe. Not yet optimized! 9