Well Spacing Optimization In Unconventional Reservoirs. Ryan Keys 27. June. 2012

Transcription

1 Well Spacing Optimization In Unconventional Reservoirs Ryan Keys 27. June. 2012

2 First, let s define well spacing Q: How many wells do I drill in this area of interest? A: I have 640 acres, and I want 8 wells, so I want to design my wells on 80 acre spacing. I want to develop one full section, and I want 8 wells, so my well spacing is 8 wells per section. My lateral length is about 5000 ft, and I want to fit 8 wells in this section, so I want 660 ft between each lateral.

3 What are we trying to optimize? EUR/Reserves? Problem: To maximize reserves, we d just drill the maximum number of wells regardless of economics Rate of Return? Problem: This is essentially maximizing EUR/well, which will lead to the most conservative well spacing, which may minimize reserves, cash flow, and NPV NPV? Problem: Lots of risk from most aggressive well spacing, infill wells might not be economic, possibly an inefficient use of capital Let s find a good balance between all 3

4 The Scenario HBP wells already drilled Infill drilling program for a 640 acre area that already has one producing well Technical team is satisfied with the well/completion design and well performance of the first well, a 4800 ft lateral with 16 stages and 80 perf clusters that has been producing for 100 days. Nothing beats empirical data, but where do we start? Optimize the distance between adjacent laterals with respect to reserves, rates of return, and NPV Treat the area of interest as one producing entity.

5 Uncertainty isn t fun What does the completion look like? What s the permeability? What parts of the reservoir are being drained? Let s just start with what we know: Lateral Length # of stages and perf cluster spacing Proppant/fluid pumped Pumping data and diagnostics Fluid composition Water saturation and porosity, but not necessarily permeability Rate and pressure data PDP reserves Microseismic? DFIT? Frac simulation?

6 The Diagnostic Plot Normalized Pressure or inverse wellbore productivity, psi/(bbl/d) (# % ) 1 Transition out of linear flow? An indication of frac complexity? And/or reservoir pressure below bubble point? (# % ) 2 Superposition time or sqrt(t), d 0.5

7 The Net Pressure Plot Tortuosity Complexity Bottomhole Pressure, psi Preferential paths established Dominant bi-wing frac(s) Injection Rate, bbl/minute Time

8 Interpretation: Complex SRV (# % ) 1 = 3 (# % ) 2 One stage, 5 perf clusters % 1 = % 2 SRV s # 1 = 3 # 2 SRV b SRV b = Big Bi-wing frac SRV SRV s = Small Complex frac region near wellbore

9 Now what? What we ve learned (# % ) lumped parameter for each flow regime: complexitydominated and bi-wing-dominated When the transition took place, and therefore the size of the complex frac region The change in linear transient productivity between the two flow regimes The ratio of effective frac area between the two flow regimes (complex region has 2/3rds of the total frac area) What we still don t know Permeability Distribution of the frac area in the SRV s Average half-lengths Size of the big SRV (minimum size known)

10 Complex Frac Region SRV Slope Transition time The slope and transition time give the size of the complex frac region (8 acres, 4800 x 73 ft) Do we care about the distribution of the frac area inside this region? High recovery factor

11 A deterministic solution isn t practical All we know about the big SRV is its minimum size But we do have two important relationships: (# % ) (k/l 2 ) max All we know about the big SRV is its minimum size A probabilistic solution will aggregate all possibilities Perm, nd

12 Not all combinations are possible Perm, nd Frac Area, M.^2 Fracs/stage Half Length, SRV size, acres Perm, nd Frac Area, M.^ Fracs/stage Half Length,. SRV size, acres )*+,-/86 )*+,-//,00 = 7.44 wells = ~750ft between laterals

13 We ve optimized reserves and IRR, but not NPV? NPV # Wells 7

14 IRR vs NPV Additional wells will likely yield lower rates of return, but they might still be economic Treat the acreage as one producing entity. What s the lowest acceptable rate of return for 640 acres? Interference from overlapping SRV s will only involve regions of the reservoir with low recovery factors RF Acres EUR, Mbbl % of EUR Complex SRV 25% % Big SRV 5% % Total 6.9% %

15 Modify the existing forecast Rate Current 400 Mbbl Min IRR 350 Mbbl Time

16 The New Well (# % ) 1 (# % ) 1, / (# % ) )*+,-/71 )*+,-//,00 = = ~590ft between laterals RF Acres EUR, Mbbl % of EUR Complex SRV 25% % Old Big SRV 5% % Total 6.9% % RF Acres EUR, Mbbl % of EUR Complex SRV 25% % New Big SRV 5% % Total 7.3% %

17 Optimized NPV/IRR/Reserves NPV # Wells 7 9

18 Conclusions Well Spacing is most explicit when described as distance between adjacent laterals Use available technology and tools, but avoid a deterministic solution Probabilistic analysis helps with seemingly overwhelming uncertainty Know the flow regimes and what is affecting productivity No two wells are the same, but the first well is a reasonable average well in an area of interest As long as the IRR is acceptable, maximize the NPV and reserves Questions?