Evaluating Hydraulic Frac

Evaluating Hydraulic Frac

Propagation in a Shallow Sa

Propagation in a Shallow Sa

Interval, South Texas Interval, South Texas

Presented by 

Dave Cramer / March 10, 201

EPA Hydraulic Fracturing Technical Work

Well Construction and Operations
Background

• This is a case study of a water flooded oil reservoir in Sou

• The productive interval is a tight, multilayer, Cretaceous-a

vertical depth ranging from 1200-1700 ft.

• Over 1000 production and water injection wells have been 

area over past 50 years. 

• Hydraulic fracturing is normally employed to stimulate wel

study area. A standard treatment design features the use guar borate fracturing fluid and 12/20 mesh proppant injec(e.g., 40 bbl/min.)

• Although diagnostic fracture injection testing (DFIT) analys

minimum principle stress is horizontal, tiltmeter mapping, toffset-well corehole project and treating pressure analysis the fracture propagation is horizontal (normal to the overbthe vertical fracture component (normal to the minimum hocontained within the pay interval.

• Because of the limited vertical hydraulic fracture propagat

multi-stage treatment methods are employed to establish each of the productive reservoir sand compartments.
 The formation is composed of sandstone The sandstone units are a series of delta

reworked by marine processes.

 Characteristics of the productive sandsto

• reservoir depth ranges from 1200 – 17

• average porosity: 20%

• average permeability: 4 md

• oil gravity: 39 API

Geologic Overview
Scale : 1 : 240 36-72DB : Chittim (2) DEPTH (1230.FT - 1330.FT) 

Depth

IN:CALI (in)

6. 16.

BS (IN)

6. 16.

DEPTH

(FT)TVD(FT)

Litho

VCL (Dec)

0. 1.

PHIE (Dec)

1. 0.

BVW (Dec)

1. 0.

Resistivity

RXOI (OHM.M)

0.2 20.

AT10 (OHM.M)

0.2 20.

AT20 (OHM.M)

0.2 20.

AT30 (OHM.M)

0.2 20.

AT60 (OHM.M)

0.2 20.

AT90 (OHM.M)

0.2 20.

IN:RT (ohm.m)

0.2 20.

Porosity

RHO8 (G/CM3)

1.65 2.65

NPOR (FT3/FT3)

0.6 0.

PEF8 (0)

0. 10.

SonicScanner

FIN:DTS (uSec/ft)

300. 100.

FIN:DTC (uSec/ft)

150. 50.

DTCO (US/F)

150. 50.

DTSM (US/F)

300. 100.

Poisson Ratio

HR:PR_DYN ()

0.1 0.5

Bulk Modulus

HR:BMK_DYN ()

0. 5

HR:SMG_DYN ()

0. 5

12501300

Zone

Log Suite Log Suite

Flow barriers Flow barriers

Log analysis provides estimates of reservoir p
N.J. Chittim 37-30R DFIT

rate (BPM)

1.0 2.0 3.0 4.0 5.0

Time (min)

0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 90.0 100

ISIP=1429 psi (1.10 psi/ft)

Breakdown at 2900 psi

Diagnostic Fracture Injection Te

Rate and Pressure Dat

Injection Rate 

Bottomhole PressureNote: overburden pressure gradient = 1.02 

Low volume fracture injection tests can be analyzestimates of in-situ stress and reservoir transmiss
Vertical fracture closure is a proxy for minimum horiz

DFIT G-dp/dG Plot

Vertical fracture closure at trend-line break-over = 1094 psi (0.84 psi/ft.)

Probable horizontal fracture closure (1.02 psi/ft)

91 hours of 
( ) P 

r 

1 h vv h 

ν σ σα α 

ν ⎡ ⎤ = − + 

⎢ ⎥ ⎣ ⎦ −

Where,

σv = overburden stress, psi = 1331 psi (1.02 psi/f

ν = Poisson’s ratio = 0.31 (from dipole sonic log αv = vertical Biot’s parameter = 1.0

αh = horizontal Biot’s parameter = 1.0

Pr = reservoir pore pressure, 718 psi (0.55 psi/ft; 

σt = external (tectonic) stress, psi = 0 psi (assum

σh = minimum horizontal stress, psi = 1047 psi (p

σh = minimum horizontal stress, psi = 1094 psi (o

Poroelastic Equation for Estima

Horizontal Stress

There is reasonable agreement with predicted and measu
Bottomhole Treating Pressure 

Variability in initial reservoir pressure is due to injection/ withdrawal imbalances within the field.

Regardless of initifracturing pressuroverburden stress

Initial WHP

0

100200300400500600700800900

Apr-08 Jun-08 Jul-08 Se p-08 Oct-08 Dec-08 Fe b-09 Mar-09 May-09

0.00.20.40.60.81.01.21.41.61.82.0

Apr-08 Jun-08 Jul-08 Sep-

overburden (ver
Post-Treatment Multi Test Ho

Treatment Multi Test Ho

From SPE paper 1571 (1961)

An extensive horizontal fracture was “exca
Surface Tiltmeter Deformation V

horizontal fracture

(domed or conical feature)

vertical fracture(trough feature)
Tilt Vector Diagram & Surface D

Visualization, Example from S

Tiltmeter mapping results show the classic signature of a hhydraulic fracture system. Horizontal fracture component is 

Surface displacement was equal to the thick

0.00

6500 ft
Hydraulic Fractures Open Nor

Least Principal Stress

But it’s a little more complicated than this in shallo

S1

S

3

S

2
T-Shaped Fractures

This routinely happens when the difference between hprincipal stresses is small, as is the case with shallow 
Five Zone Limited Entry Treatm

Five Zone Limited Entry Treatm

Top of Top of Bottom 

Horizontal fracture

Horizontal fractures

Horizontal Fracture?

Horizontal fracture

Top of fractured interval is capped by a horiz
5 

Three Zone Limited Entry Treatm

Three Zone Limited Entry Treatm

Horizontal fracture

Top of sa

No appa

Horizontal fracture

Horizontal fracture

Dominant horizontal fracture signature 
Recompletion Tracer Log: W

New perfs

Horizontal fracture

ToTo

Horizontal fractureHorizontal fracture

Bot

Hydraulically fracturing via the new perf set increased by 10 fold. This response is indicative of the lack of vfrom the previously fractured original perf set. 

Original perf set
Two Zones with Ball Sealer Diver

Two Zones with Ball Sealer Diver

Horizontal fractureHorizontal fracturesHorizontal fracture

Top of saTop of ve

Bottom 

Top of fractured interval is capped by a horizo
Five Zone Limited Entry Treatm

Five Zone Limited Entry Treatm

Horizontal fracture

Top of ver

Horizontal fractures

Top of san

Horizontal fracture

Bottom 

Top of fractured interval is capped by a horizo
Treatment Pressure History Evalu

Modeled pressure

Actual pressure

Injectio

Proppant concentration

Actual results matched computer modeled results indicating go
Limited Entry Treatment Modeling

Propped width after fracture closure

Hydraulic Fracture Modeling Res

Width vs radial position for each horiz

Vertical Fracture Component: assumed to be negligible

Horizontal Radius (ft)

Hydraulic Widthat end of injection frac #1

frac #2

frac #3

frac #4

frac #5
Summary

 Conditions are favorable for propagating horizontal fractu

reservoirs. 

• There is a small difference between the overburden (vertical) and 

principal stresses.

• The net pressure required to extend a vertical fracture is in excess 

vertical stress difference. 

 Fracture geometry can be estimated from the treatment p

• Horizontal fractures propagate radially and require decreasing net • Vertical fractures eventually propagate elliptically (length-to-heigh

than one) and require increasing net pressure to grow.

 Vertical fracture growth is contained within the pay sand. 

• Core hole, tiltmeter, tracer survey and treating pressure analysis i

fracturing is the dominant mode of fracture propagation even thou

stress is not vertical.

 Methods are employed to control the hydraulic fracturing 

• There is a strong financial incentive to contain fracture propagatio

sandstone intervals.

• Treatment designs are modeled and evaluated with computer-bas

• Limited entry or selective multi-stage frac treatments are necessa

propagation in all the sub-intervals in the study area.