# Characterizing Mechanical and Flow Properties using Injection Falloff Tests

Presented by Dave Cramer / March 28, 2011 EPA Hydraulic Fracturing Technical Workshop #3

Fate and Transport2



# Agenda

• Review the basics of fracture injection / fall - off tests. • Describe fracture closure analysis for determining in - situ stress and non - ideal fracture closure mechanisms. • Describe after - closure analysis for determining reservoir flow behavior, reservoir flow capacity (kh/u) and initial reservoir pressure (p i 

## ). • Discuss integration of this information for enhanced 

## control of hydraulic fracturing.3



# Injection Fall - off Diagnostics

The process starts with the creation of a small hydraulic fracture, typically requiring less than 5 barrels for a shale gas interval.4 

# Hydraulic Fractures Open Normal to the Least Principal Stress

This stress regime is typical for deeply buried reservoir rock. S 1



### S 3 

### S 25 

# Drivers of Bottomhole Pressure Behavior

Initially, rock mechanical properties and in -situ stress influence the pressure fall- off response. Later, pressure fall- off behavior is dominated by reservoir flow properties and pore fluid pressure. From Nolte6



# Fracture Closure

initial late time Asperities on opposing fracture faces touch in the initial stages of fracture closure. The adjacent void space imparts residual fracture conductivity. Proportional to normalized fracture width MWX Test Site Project7 

# Flow Regimes in Hydraulically Fractured Wells with Residual Fracture Conductivity

Achieved in the after closure period. Radial flow solutions can be used to derive far - field kh/u. 

### During the pseudo - radial flow period, the area of investigation is well beyond the region of the fracture. From Cinco - Ley8 

# Assumed Case for Modeling Purposes: Fracture Enhanced Wellbore in Cylindrical Reservoir

Hydraulic Diffusivity =k / ø μ c T 

### =fluid mobility / fluid storativity Hydraulic diffusivity determines the speed that pressure changes induced by production or injection are transmitted through the reservoir. Fractured - Well Type Curve t D 

### = 0.000264kt/φμ cT

### x F 2 

### Start of pseudo - radial flow t D 

### >19



# Pressure Memory Gauge

To facilitate doing long - duration tests, memory gauges are used to monitor and record the pressure fall- off downhole or more commonly at the wellhead.10 perforating event wireline and perforating gun removed from the well ready to start DFIT pressure loss: 9 psi in ~33 minutes

increase pressure in the wellbore prior to perforating Pre -job estimate of reservoir pore pressure 

# Overbalanced Perforating

Maintaining the wellbore pressure above reservoir pressure prevents gas influx into the wellbore and enables closed- chamber analysis under certain conditions.11



# Propagating a Hydraulic Fracture
Compressing the wellbore fluid

Injection rate (bbl/d) Calc. Bottomhole Pressure (psi) 1 bbl/min injection rate;

1 bbl of fluid injected following fracture initiation. Fracture initiation event Stop injection. Start shut - in period



### Injection time and volume are kept short to minimize fracture dimensions and satisfy the conditions of an impulse event.12



# Modeled Fracture Geometry

Even with a small injection, reservoir investigation is significant.13



# Pressure Fall - off History

Hydrostatic pressure is added to the observed wellhead pressure value to compute bottomhole pressure. 14+ days of data Hydrostatic pressure is added to the observed wellhead pressure value to compute bottomhole pressure.14 

# Diagnostic Log - Log Plot of Pressure Fall - Off

Derivative plot is used for identification of fracture closure behavior

and after - closure reservoir flow regimes.15 

# Log - Log Graph Characteristic Slopes

From Barree (SPE 107877) Primary derivative (dp/dt or d Ψ /t a ) Semi - log derivative (t dp/dt or t a d Ψ /t a ) Impulse derivative (t 2 dp/dt or t a 2 d Ψ /t a ) 

### Diagnostic slopes depend on the derivative type used.16 

# G Function Plots for Fracture Closure

Identification

The semilog derivative is the primary plot for identifying fracture closure.17 

# G - Time Functions for Analyzing a Closing

Fracture Δt D = (t – t p ) / t p g(Δt D ) = 4/3 ((1+Δt p ) 1.5 - Δ t p 1.5 ) G(Δt D ) = 4/π (g(Δt p ) - g 0 where, t = total test time (pumping and shut - in) t p = pumping time G(Δt D ) = G - Function time in previous slide G(Δt D ) C = G - Function time at fracture closure η = fluid efficiency (i.e., fluid remaining in fracture total fluid injection, at shut - in) η = [G(Δt D ) C ] [2 + G(Δt D ) C ]



### The G - Time Function linearizes the pressure response of a closing fracture under ideal conditions.18 

# Square Root of Time Plots for Fracture Closure Identification

The 1 st 

### derivative plot is a secondary method for confirming fracture closure.19

Where, σ v = overburden stress, psi = 10,752 psi (1.12 psi/ft; bulk density log)

ν = Poisson’s ratio = 0.23 (from dipole sonic log computation) α v = vertical Biot’s parameter = 1.0 α h = horizontal Biot’s parameter = 1.0 P r = reservoir pore pressure, 4693 psi (0.49 psi/ft; DFIT) σ t = external (tectonic) stress, psi = 0 psi (assumed) σ h = minimum horizontal stress, psi = 6503 psi (predicted from above) σ h = minimum horizontal stress, psi = 7269 psi (observed from DFIT) 

# Poroelastic Equation for Estimating In - Situ

Horizontal Stress

The fracture closure method for deriving minimum in -situ stress can be used to evaluate and adjust the values derived from predictive equations.20 

# After- Closure Flow Regime Type Curve

Pseudo - radial flow is indicated by 1.) the - 1 slope trend in both Δ P & semilog derivative plots and 2.) equivalency of Δ P and semilog derivative values . Pseudo - radial flow period21 

# After - Closure Flow Regimes Plot Time Function

linear flow time function = linear flow time function 2 

### =
where, 

### t = total test time (including injection time) t c 

### = time to fracture closure (including injection time) Note: In gas reservoirs, the pseudo - time function (t a 

### ) is used to adjust time.

It’s the linear flow time function squared, which is a function of total test time and fracture closure time.22



# After- Closure Radial Flow Plot

The solution derived with the Radial Flow specialty plot shows good agreement with the Type Curve plot. M R =63,300 psi kh/u = 24x70.6 [1.06 (63,300)] =0.028 md - ft/cp; kh=0.000732 md - ft: k=0.000045 md or 45 nanodarcies

μ =0.0258 cp V i : bbls k: md M R : psi/cycle h: ft μ : cp

t = injection time + shut - in time23 Cycle 5 

# After - Closure Flow Regime Plot: Linear Flow

Ratio plot Δ P d Δ P Pseudo - linear flow indicator: when pressure change and

derivative both lie on the half - slope trend line & pressure change is 2x the value of the derivative. This test meets the criteria for pseudolinear flow. Reservoir pressure can be inferred from this analysis. 

### half slope trend lines Radial flow signature is absent Nolte method 

### 2x Certain types of naturally fractured reservoirs exhibit long - term linear flow.24



# Summary

 Injection Fall - off Testing is an efficient way to derive in - situ information on most rock types. • A modest - size hydraulic fracture is created and pressure fall - off during shut in period is analyzed for fracture closure and after - closure radial flow period. • Injection rate and volume are tailored for interval thickness and leak - off characteristics.
 Identification of fracture closure provides information on rock stress. • A combination of derivative - based diagnostic plots are used. • Non - ideal fracture propagation (e.g., fracture height growth, fissure opening, multiple fracture closures) can be identified and evaluated.
 After - closure analysis is used to derive rock transmissibility (kh/u) and pore fluid pressure. • Radial flow is identified and evaluated by type curves and specialty plots. • Computations are based on well testing theory.
 The resulting information is employed to assist in controlling the hydraulic fracturing process. • The information is used in hydraulic fracture modeling to predict fracture geometry, proppant placement, fracture conductivity, etc. • Treatment design is modified as necessary to achieve treatment objectives.