and Implications SPE Ian Palmer Higgs Palmer Technologies

Transcription

1 Microseismic Clouds: Modeling and Implications SPE Ian Palmer Higgs Palmer Technologies 13 October 2012 Higgs Palmer Technologies 1

2 Acknowledge Co Authors Zissis Moschovidis, PCM Technology, Tulsa, Oklahoma Aaron Schaefer, Aetman Engineering, Houston, Texas Higgs Palmer Technologies 2

3 The Revolution: Shale Gas and Shale Oil Higgs Palmer Technologies 3

4 Wow!! Higgs Palmer Technologies 4

5 Years of Shale Gas Resource: North America Kevin Smith Unlocking BC s Shale Gas Potential, 6 th Annual Shale Gas Symp. (Canadian Institute), Calgary, January Higgs Palmer Technologies 5

6 Cost Advantage of Natural Gas Kevin Smith Unlocking BC s Shale Gas Potential, 6 th Annual Shale Gas Symp. (Canadian Institute), Calgary, January Higgs Palmer Technologies 6

7 Gas Price 10 Year Low In January 2012* NEW YORK Natural gas prices are rebounding from 10 year lows as producers cut back and colder weather forces homeowners to turn up the heat. The price of natural gas futures rose Tuesday to finish at $2.55 per 1,000 cubic feet. The futures contract dropped as low as $2.32 on Thursday, the lowest since Feb. 25, Natural gas rose this week after one of the largest producers, Chesapeake Energy Corp., announced it would slow down production this year. And weather forecasts showed a chilly mix of rain and snow from the Southwest to the Great Lakes. More than half of homeowners use natural gas for heat, and investors are betting they'll need to crank up furnaces as temperatures drop. The price of natural gas has plunged as drillers expanded their reach in North America, tapping vast underground shale layers that are rich in gas and oil. Supplies in storage have grown well beyond the five year average for this time of year. Prices are about 44 percent lower than at the same time last year, and experts say U.S. supplies will continue to test the country's storage capacity because of weak demand. Higgs Palmer Technologies 7 *CHRIS KAHN, AP, 24 January 2012

8 Frac Equipment Limitations Higgs Palmer Technologies 8 Beckwith, R. Hydraulic fracturing the fuss, the facts, the future, JPT Dec 2010, p 34

9 What is Microseismic? Shear failure on natural fracture or weak plane (next slide) Part of energy release is in form of a tiny sound wave (microearthquake) This burst of energy can be picked ikdup by sensitive geophones if not too far away And several geophones can locate the source of the microseismic burst by triangulation Higgs Palmer Technologies 9

10 Shear stress movement large perm increase Peak-on-peak stops crack from closing completely Microseismic burst to geophones Higgs Palmer Technologies 10

11 Ian Palmer: March

12 Microseismic Qualitative Info About where a fracture stimulation goes And how far it extends What kind of coverage? Higgs Palmer Technologies 12

13 Salehi, I., GTI (RPSEA project) Ian Palmer: March

14 Questions All events in plan view with events scaled as bubble sized by magnitude. Questions: 1. Why are microseismic events large along Well C? 2. Why are there no microseismic events to the northeast? 3. Why does the cloud of microseismic events tend to go towards the southwest? 4. Why is the geometry of the microseismic events different near well A? Maxwell, SPE Higgs Palmer Technologies 14

15 Events located during an 8 well 143 stage hydraulic fracture operation. Events are colored by fracture stage. A total of 144,057 microseismic events were captured using multiple near-vertical and horizontal sensor arrays. ESG performed real-time around-the-clock microseismic monitoring of 143 fracture stages over a period of 43 days. Higgs Palmer Technologies 15

16 Microseismic Quantitative Info NEW! Largely ignored but.. Can give permeability during injection into a fracture network (next slide) Permeability is surprisingly large (100s of md) Can give aperture width of fractures in the network Can decide if proppant can fit into these fractures or not Higgs Palmer Technologies 16

17 Fracture network in roadway Higgs Palmer Technologies 17

18 Fracture network in Barnett Shale Primary frac direction (red) roughly N45 o E. Fracture network spacing 70 ft King et al, SPE , 2008 Higgs Palmer Technologies 18

19 Microseismic Quantitative Info NEW! Largely ignored but.. Can give permeability during injection into a fracturenetwork (last slide) Permeability is large (100s of md) but most of this is lost when we turn the well on (01 (<0.1 md) Can calculate aperture width of fractures in the network Can decide if proppant pp can fit into these fractures or not Higgs Palmer Technologies 19

20 Fracture with Large Aperture Width Large-grain proppants can get in Higgs Palmer Technologies 20

21 Fracture with Small Aperture Width Only small-grain proppants can get in Higgs Palmer Technologies 21

22 Modeling Concepts Microseismic reveals where shear failure has occurred (next slide) Shear failure fil (slippage) (li occurs on natural fractures or on weak planes Where the water goes, shear failure goes (we assume shearing occurs by increasing pore pressure) Higgs Palmer Technologies 22

23 Induced d fracture network Frac water spread to wells 1,2,3,4,5 and killed them. The pressure in the water caused the shear failure and microseismic events. Fisher, M. K., et al, SPE 77441, Higgs Palmer ATCE, Technologies San Antonio, Texas,

24 .More The porosity has to be small to get the water out that t far in a short ttime. How small? Less than 0.1% The permeability has to be high h to get the pore pressure high enough to cause shear failure. How high? Greater than ~50 md. High permeability coupled with low porosity imply fracture controlled controlled flow (not matrixcontrolled flow) in a fracture network (next slide). How large is the fracture network? As large as the microseismic cloud. Higgs Palmer Technologies 24

25 Natural or Induced Fractures are the Dominant Conduit during Injection Virgin reservoir Low perm and diffusivity 01mm 0.1 Main fracture face High perm and diffusivity Implies fracture perm and porosity determine penetration of pressure and liquid, not matrix values Higgs Palmer Technologies 25

26 DomAnal Software: Two Separate Models and Two Different Permeabilities Match microseismic spread using geomechanical model (high) injection perm Match gas rates using RTA analysis (low) production perm RPSEA Project Confirm that injection perm >> production perm Seek implications for proppant, pp etc Higgs Palmer Technologies 26

27 Pattern of microseismic bursts after one-stage stimulation of a horizontal well (left panel). The dotted line outlines the stimulation volume. We assume quasiuniform microseismic distribution Match microseismic pattern injection perm in SRV Geometry of flow model (rate transient analysis) to match gas rate versus time (right panel). Match gas rate production perm in SRV Higgs Palmer Technologies 27

28 What we are Finding: in a Nutshell 0.5 Virgin 5 Fluid flow flowrate 1000 x During injection 1 During production flowrate 8 x Ian Palmer: March

29 Case Study: Barnett Shale Horizontal well in Parker County Depth 5,000 ft Higgs Palmer Technologies 29

30 Multi stage sequential fracs through two wells in Barnett shale. Each color is the microseismic spread from one frac stage in one well. King et al, SPE , 2008 Higgs Palmer Technologies 30

31 Weak planes are random, eff = 81%, Cfr = 0.46, φi = 0.019%, 019% Ki = 229 md. Shear failure extends out 900 ft Image from DomAnal Higgs Palmer Technologies 31

32 Results ϕi= 0.019% (this is fracture porosity). Φihas to be small because microseismic spread (associated with frac fluid) is large after pump time of only 3 hours (ie, cannotbematrix porosity). Ki is 229 md for random orientation of weak planes (this is fracture permeability). Ki has to be large to raise the pore pressure enough to induce failure all the way out to the microseismic envelope. A large Ki and a small Φiimply fracture controlled flow (not matrix controlled flow). Higgs Palmer Technologies 32

33 Fracture Network: Aperture and Spacing NEW! We have been able to calculate aperture widths (and spacing) in the fracture network (next slide). Can we use this info to optimize proppant? Higgs Palmer Technologies 33

34 Fracture spacing =?? and open fracture width =?? μ Fracture spacing Fracture width Fluid injection during frac treatment Fracture spacing and width are uniquely determined by injection porosity and permeability Injection porosity = 0.019% and injection permeability = 229 md Higgs Palmer Technologies 34

35 Image from DomAnal Fracture spacing in Parker County network Higgs Palmer Technologies 35

36 Fracture opening width in Parker County network Image from DomAnal Higgs Palmer Technologies 36

37 Implications for Proppant Where is the proppant? Is it doing any good? Is it right sized? Is it getting into the fractures in the fracture network? Higgs Palmer Technologies 37

38 Is it here?? Is it here?? Higgs Palmer Technologies 38 Cipolla, C. Fracture modeling issues in unconventional gas reservoirs (tight sands and shales), SPE ATW, Barossa Valley, Australia, 14 October 2008.

39 Dominant central fracture Proppant Distribution Evenly distributed: eg, lightweight proppant Is it here?? Is it here?? Pillar distribution due to proppant fallout Cipolla, C. The relationship between fracture complexity, reservoir properties, and fracture treatment design, SPE , ATCE, Denver, CO, Sept Higgs Palmer Technologies 39

40 BUT FIRST: Can the proppant even get into the fractures in the fracture network? ANSWER: It depends d on the size of a proppant grain, and the opening width of the fracture(s) Higgs Palmer Technologies 40

41 If we know the fracture opening width Means should use more 100 mesh and less mesh proppant 100 mesh is first stage, followed by mesh second stage Higgs Palmer Technologies 41

42 Equation to Determine Proppant % NEW! % 100 mesh = x (average fracture width) where % means (lbs 100 mesh) / (lbs total for 100 mesh ) average fracture width (microns) during injection comes from injection permeability and porosity when the geomechanics model is matched to the microseismic pattern. Average aperture = 168 µ % 100 mesh = 72% Higgs Palmer Technologies 42

43 Implications Most shale frac treatments use 100 mesh followed by mesh proppant. Our result suggests should use relatively more 100 mesh and less proppant. Can we take this analysis further and tailor the proppant pp to prop pa greater number of fractures in the created fracture network? Higgs Palmer Technologies 43

44 What we have discussed today Proppant Choice Table: Preliminary ess to Travel Conduct Durability of Suitable at work distance ivity resulting elevated temperature? within fracture network ** Suitability in trunk Cost Suitability for multiphase flow Acceptable to screenout or fully pack frac? Suitability at high h stress Erosivit M M better Y M M Larger diameter likely needed near wellbore unless continuous voids are sustained M L medium N L L Only if continuous voids between pillars are sustained y HH M y ML H MH LL medium N LL L Marginally acceptable even if y M H pillars are sustained H L poor N LLL H Only if uniform PML achieved and sustained No LL L HH LL poor N LLLL H No No LL L L M medium N M L Y if low stress and wide fractures y L H L H better Y HH M Y y H M * There are more than 50 mines supplying frac sand, and more than 70 ceramic plants. Quality varies tremendously and buyer should be aware of enormous quality variation with some samples providing less than 20% the conductivity of similarly named proppants. This table assumes top quality material in each category. ** Note that all proppants will fall into a settled bank unless frac geometry interferes with settling, or if forced closure procedures capture particles prior to setting. Travel distance is relative, and it should NOT be presumed that even 100 mesh ULWP is neutrally buoyant or will be suspended until fracture closure, unless densified frac fluids are used. [ULWP is not neutrally buoyant in typical frac fluid]. Flowback resistance: Most field data indicate larger proppant diameters are more flowback resistant, and some fields require stronger proppants to avoid proppant flowback. Curable resins and other additives can effectively control proppant flowback.

45 Conclusions Matching a cloud of microseismic data with geomechanics model which assumes leakoff of frac fluid causes shear failure Injection permeability during a frac stimulation is 100s of md and injection porosity is < 0.1% (this is fracturedominated flow) Assuming a fracture network average fracture spacing ~6 ft and width ~168µ This width can be used to select % of 100 mesh ahead of proppant Goal is to save more of injection perm: production perm in SRV is < 01md 0.1 in this case, and size of SRV is much less than microseismic dimensions Higgs Palmer Technologies 45

46 Acknowledgements We thank Xiaowei Weng for reviewing this work and making valuable comments. Mike Vincent offered many helpful comments on this work. Funding for this project is provided by RPSEA through the Ultra Deepwater and Unconventional Natural Gas and Other Petroleum Resources program authorized by the U.S. Energy Policy Act of Higgs Palmer Technologies 46

47 Shale gas/oil revolution THE END The singularity: