Flowback: Why only a small fraction of the injected fluid? Terry Engelder Department of Geosciences Penn State University

Transcription

1 Flowback: Why only a small fraction of the injected fluid? Terry Engelder Department of Geosciences Penn State University

2 Acknowledgments: Coauthors

3 What happens to the water after the fracking process? Some flows back to the surface and some of this flowback is treated locally and some is transported for injection into deep disposal wells.

4 What happens to the water after the fracking process? Initial Frack Fluid = Clear (black) Recycled Frack Fluid = Red Flowback = Green

5 Initial Frack Fluid = Clear (black) Recycled Frack Fluid = Red Flowback = Green The relative size of these two ponds suggests that not all initial frack fluid flows back to the surface!

6 150,000 bbl injected Production decline curves for two gas-well fluids: H 2 O & CH 4 Volume (barrels) Production of treatment water declines faster than gas production Some of this might be flared! Volume (mmcf) stimulation Increasing salinity Flowback Water Production Water

7 Muskwa gas shale 12 million cf/d 5000 bbl/day 10% One day One day 35 bcf Adefidipe et al., SPE

8 Natural Fracking Gas shale is so impermeable that economic production depends on fracture-enhanced permeability Natural Joints in the Marcellus

9 Contact Area These are the natural fractures (joints) along which sand and other chemicals are pumped:

10 On average a volume above 80% of fluid injected will remain in the ground as Residual Treatment Fluid (RTW) API Operator County Lateral Length Stages Inject during Stimulation Vol/Stage Flowback & Production Water ft Bbl Bbl Bbl Ratio Flowback/ Injected Total Gas Production bcf Days CHESAPEAKE APPALACHIA LLC BRADFORD CHESAPEAKE APPALACHIA LLC BRADFORD CHESAPEAKE APPALACHIA LLC BRADFORD CHESAPEAKE APPALACHIA LLC BRADFORD CABOT OIL & GAS CORP SUSQUEHANNA WPX ENERGY APPALACHIA LLC SUSQUEHANNA CITRUS ENERGY CORP WYOMING SENECA RESOURCES CORP TIOGA EOG RESOURCES INC CLEARFIELD CHIEF OIL & GAS LLC LYCOMING EQT PRODUCTION CO GREENE WPX ENERGY APPALACHIA LLC WESTMORELAND TALISMAN ENERGY USA INC TIOGA RANGE RESOURCES APPALACHIA LLC WASHINGTON AVE = 11% of Injected Fluid On average 89% of injected fluid is still in the ground!

11 Flowback as a Fraction of Injected Volume 0.6 Injection Vol. vs. % Flowback Injection Volume (bbls) Convenience sample: PA Marcellus (statewide)

12 Type of Well Well Type vs. Avg. Flowback % Vertical Wells Horizontal Wells Fraction of Flowback Convenience sample: PA Marcellus (statewide)

13 Imbibition Imbibition is defined as the displacement of one fluid by another immiscible fluid. This process is controlled and affected by a variety of factors that fall in three catagories: Capillary Osmotic hydration Physical-chemical properties

14 How can a sponge pull water up against the force of gravity? Adhesion between the sponge fibers and the water molecules is high enough that water prefers to be touching the sponge more than other water molecules and so there is a tendency for it to "creep" up into the sponge.

15 How can a sponge pull water up against the force of gravity? Capillary effect: Soaking up water results in a lower energy state. Equilibrium occurs when lower energy equals the potential energy of the water raised against gravity above the water line. We say that glass is water wet or hydrophilic!

16 How do large trees get water from their roots to the leaves? To evolve into tall, self-supporting land plants, trees had to develop the ability to transport water from a supply in the soil to the crown--a vertical distance that is in some cases 100 meters or more (the height of a 30-story building).

17 How do large trees get water from their roots to the leaves? Force #1: Capillary pressure! The xylem is composed of elongated cells which die but remain intact to serve as capillary tubes to transport water from the roots to the leaves.

18 Force #2: Osmosis Root pressure is created by water moving from its reservoir in the soil into the root tissue by osmosis (diffusion along a concentration gradient). This action is sufficient to overcome the hydrostatic force of the water column--and the osmotic gradient in cases where soil water levels are low.

19 A third force is required! Capillary action and root (osmotic) pressure can support a column of water some two to three meters high, but taller trees--all trees, in fact, at maturity-- require more force.

20 Force #3: Negative water vapor pressure Evapotranspiration creates a negative water vapor pressure and water is pulled into the leaf from the vascular tissue, the xylem, to replace the water that has transpired from the leaf. This pulling of water, or tension, that occurs in the xylem of the leaf, will extend all the way down through the rest of the xylem column of the tree with the help of capillary tension in the truck and osmotic pressure in the root system. A fourth force is at work = Molecule-molecule cohesion

21 National Geographic National Geographic s evapotranspiration applied to rocks. Taughannock Truman

22 Reasons why leakage is unlikely: 1.) imbibition of RTW into shale 2.) little interconnectivity of fractures 3.) role of multiphase flow 4.) lack of a pressure drive

23 Imbibition Spontaneous imbibition takes place when a wetting fluid is drawn into the pore space of rock by capillary action. Capillary forces and coupled diffusion osmosis processes are the reasons the brines and the RTW are not free to escape from gas shale.

24 Bound Water f < 1% Note: Bound water can t enter fractures as a free brine Water Saturation = 2-10% of total porosity Marcellus Onondaga Limestone Note: Free water can enter the gas shale along fractures as a free brine but this is not brine native to the gas shale Free Water f = 2%

25 Clay Marcellus has a very low water saturation Bound Water f < 1% Note: Bound water can t enter fractures as a free brine Water Saturation = 2-10% of total porosity Note: Free water can enter the gas shale along fractures as a free brine but this is not brine native to the gas shale Free Water f = 2% Only free water can migrate upward from Marcellus!

26 Air Two immiscible fluids: Water & Air Molecular attractions (i.e., interfacial tension) for similar molecules in each fluid are greater than the attractions between the different molecules of the two fluids. Molecular attraction is greatest on the side of the denser fluid Surface tension in the case of water and methane Surface of contact drawn into a curvature which is convex toward the more dense fluid. H 2 O

27 Capillary tubes H 2 O Hg Mercury does not adhere to glass.

28 Interfacial Tension = interfacial tension, a measure of the immiscibilty of two liquids because of the cohesion of like molecules in each. If hydrocarbons were soluble in water, this term would go to zero. Relative to water, gas > light oil > heavy oil. Interfacial tension between oil and water is approximately 35 dynes/cm Surface tension between methane and water is approximately 72 dynes/cm Surface tension between air and mercury is 480 dynes/cm

29 Concave Surface Tension: H 2 O-air contact convex or concave? Convex

30 Wettability Wettability is the tendency of one fluid to spread on, or adhere to, a solid surface in the presence of other immiscible fluids. Wettability is defined by the contact angle, q, of water with the solid phase: Small q = water wet Large q = oil wet Water Wet /Gas Oil Wet /Gas

31 Haynesville gas shale (Louisiana): Strongly oil wet! Oil on an oil-wet surface

32 Tap water sitting on a Vaseline film covering glass - Oil wet surface 4.3 mm q = 105 Vaseline on glass V o = 33.5 ml q = 105 t = 0 min

33 Tap water sitting on a Vaseline film covering glass - Oil wet surface q = 105 Vaseline on glass V o = 33.5 ml q = 105 t = variable 4.3 mm t = 0 min t = 5 min t = 17 min t = 49 min Evaporation

34 Capillary Pressure (P c ) Concave Wetting phase rises above the original or free water level in the capillary tube until adhesive and gravitational forces balance. Varva et al., 1992

35 When water is the wetting phase: Capillary forces drive water into pore throat to displace non-wetting phase Concave Gas Treatment Water Gas Treatment Water This is the mechanism of imbibition and capillary seals!

36 IMBIBITION Imbibition is a fluid flow process in which the saturation of the wetting phase increases and the nonwetting phase saturation decreases. (e.g., waterflood of an oil reservoir that is water-wet). Mobility of wetting phase increases as wetting phase saturation increases. Capillary forces are responsible for natural imbibition

37 Rock Permeability Reservoir Sandstones Single-Phase Fluid: Large Pore Throats Shale Seal Rocks Two-Phase Fluids: Small Pore Throats Brace, 1980

38 Devonian Catskill Fm. (6,000 ft above Marcellus) Gas-driven Natural Hydraulic Fractures Gas recharge by back flow into joints through large pore throats Lacazette & Engelder, 1992

39 (min:sec) Ithaca Siltstone V o = 156 ml q < 5 t < 3 min Joint surface: Gas driven natural hydraulic fracture

40 Catskill a = 22 t = 0.25 min V o = 154 ml 0:10 1:00 4:00 V o = 77 ml 7:00 11:00 17:00

41 Geneseo a = 37 t = 65 min Gray shale: TOC < 1%

42 t (min) 0 Tap water sitting on a Vaseline film covering glass - Oil wet surface 23 Vaseline on glass V o = 77 ml q = 85 t = variable

43 Busik 1H (Susquehanna Cty, PA) Cuttings of Marcellus recovered mid-november 2012

44 Fresh Marcellus cutting: Counter-current Imbibition

45 0 min 17 min h = 3.0 mm h 26% d = 8.3 mm End of counter-current imbibition d + 4% 1 min 37 min Counter-current imbibition 3 min 61 min 7 min 85 min Fresh Marcellus cutting: Countercurrent Imbibition

46 % (Initial Volume) Evaporation Curves (substrate = tape) Tape q 90 V o = 92 ml Tape q 90 V o = 86 ml Tape q 90 V o = 72 ml Time (min)

47 % (Initial Volume) Tape q 90 V o 82 ml Slickenside q 73 V o 101 ml Catskill q = 35 V o = 154 ml Marcellus black q 72 V o 99 ml Marcellus gray q 70 V o 109 ml Time (min.) Counter-current imbibition ends

48 Salinization Imbibition Four principal forces drive fluid/shale interactions: 1.) a hydraulic differential between the drilling fluid pressure in the hydraulic fracture and the pore pressure in the shale matrix (ΔP) 2.) a combination of surface tension and adhesion of fluids (i.e., capilliary forces like those that make a water flood work 3.) osmotic pressure due to chemical osmosis, usually calculated using the activity ratio of water in the shale to hydraulic fracture fluid 4.) diffusion osmosis from higher to lower concentrations for each species which is opposite to the flow of water in chemical osmosis.

49 Osmotic pressure is the pressure that must be applied to prevent the inward flow of water across a semipermeable membrane. Chemical osmotic pressure by high water activity pushes the hydraulic fracture fluids into the shale matrix, expelling gas and high salinity formation water in the process.

50 Haynesville gas shale Water and brine wettability experiments on samples of Haynesville gas shale. Note that the most wetting fluid in this series of experiments is the highest salinity brine and the least wetting is DI water

51 Haynesville gas shale Chemical Osmosis: The least saline brine was most imbibed by the Haynesville shale sample

52 Salinization of flowback The absolute osmostic fluid pressure required to generate such a solution through osmosis diffusion. Osmotic pressure pushes the hydraulic fracture fluids into the shale matrix, expelling gas and high salinity formation water in the process

53 Conclusions Cartoon: Imbibition & Salinization