well design criteria

7/24/2019 Well Design Criteria

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PCB4323 - Well Stimulation Techniques

2016 INSTITUTE OF TECHNOLOGY PETRONAS SDN BHD

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By

Dr Aliyu Adebayo Sulaimon

([email protected])

(Mobile: 0143485422; Office Ext.: 7051)

(Room No.: 14.02.30)

PCB4323 - Well Stimulation Tec

hniques

Dr liyu debayo Sulaimon
mailto:[email protected]:[email protected]


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Learning Outcomes

At the end of this lecture, students should be able to:

Define hydraulic fracturing, describe its stages and identify

requisite equipment

Apply in-situ stress analysis to determine formation breakdown

pressure

Identify different models for predicting the fracture geometry

Determine the productivity of fractured wells

Describe the procedure for a hydraulic fracturing design

Recommend post-frac evaluation tools



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Hydraulic Fracturing

Hydraulic fracturing is an appropriate well-stimulation

technique for wells in low- and moderate- permeability

formations that do not provide commercial production

rates even when there is no damage or the damaged has

been removed by acidizing treatments.

Typical equipment required for hydraulic fracturing are:

Truck-mounted pumps

Blenders Fluid tanks

Proppant tanks



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SURFACE SYMPHONY

Figure 1: Typical hydraulic Fracturing Site. Source:Kansas Geological Survey


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Fracturing

fluid

Blender

Proppant

Pumper

Inject to create pad/fracture

Pad/Fracture

Figure 2: Equipment layout in hydraulic fracturing treatments


Equipment Layout


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Fracturing Stages

There are two stages:

Pad Stage

Only fracturing fluid is injected to fracture andcreate a pad

Slurry Stage

Mixture of fracturing fluid/proppant is injected tofill the fracture

Note:The proppant should have enough compressive

strength to resist formation stress.Dr liyu debayo Sulaimon


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Fracturing Stages


Figure 3: Fracturing stages


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Fracturing Stages

Figure 4: Fracturing pressure profilesDr liyu debayo Sulaimon


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Figure 5: Typical data from an in-situ stress test.

Instantaneous shut-in Pressure, or ISIP, is defined as:

ISIP = Final injection pressure - Pressure drop due to friction in

the wellbore and perforations or slotted liner

Fracturing Stages


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The selection of the fracture fluid for the treatment

is a critical decision. Economides and Nolte (2000)

developed a flow chart(Figs 6)that can be used to

select the category of fracture fluid on the basis of

factors(Table 1)such as:

Reservoir temperature

Reservoir pressure The expected value of fracture half-length

Water sensitivity


Fracture Fluid Selection Process


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Fracturing Fluids

Dr li u deba o Sulaimon

Table 1

Source:

Economides, M.J.

and Nolte, K.G. 2000.

Reservoir

Stimulation, thirdedition. New York:

John Wiley & Sons.


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Fracture Fluid Selection Process

Figure 6: Fracture fluid selection processSource: Economides, M.J. and Nolte, K.G. 2000. Reservoir Stimulation, third edition. New York: John Wiley & Sons.



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Cross-linkers

Figure 7: Crosslinked polymers

Cross-linkers = used to super-

thicken fracturing fluids (100s -

1000sof centipoise.

Guar Gum = Gelling agents or

viscosifiers used to thicken fracturing

fluid (1s-10sof cp)



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Figure 8presents a flow chart created by Economides and Nolte (2000)

for selecting propping agents.

To use the chart, the maximum effective stress on the propping agent

must be determined.

The effective stress is defined inFig. 9.The maximum effective stress

depends on the minimum value of flowing bottom-hole pressure

expected during the life of the well.

If the maximum effective stress is less than 6,000 psi, then Fig. 8

recommends thatsandbe used as the propping agent.

If the maximum effective stress is between 6,000 and 12,000 psi, then

either Resin-Coated-Sand (RCS) or Intermediate-Strength-Proppant(ISP)should be used, depending on the temperature.

If the maximum effective stress is greater than 12,000 psi, High-

Strength-Bauxite (HSB)should be used as the propping agent.

Propping Agent Selection



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Guide to Proppant Selection

Figure 8: Proppant selection based on closure pressure (Source:Economides.& Nolte, 2000)



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Effective Stress on Proppants

Figure 9: Effective stress on the propping agent. (Source: Economides.& Nolte, 2000)


Ti S


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Tip Screen out


A fracture treatment, common where high

fracture flow conductivity is needed.

Very high pressures and very high proppant

loadings are applied near the end of a fracturetreatment where the tip of the fracture has

stopped growing due to bridging of proppant at

the fracture dip because of dehydration (fracfluid leak-off).

Ti S t


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Tip Screen out



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Modelling Procedures:

The model should be run to determine what needs to be mixed and pumped

into the well to achieve the optimum values of propped fracture length and

fracture conductivity.

The base data set should be used to make a base case run.

The engineer then determines which variables are the most uncertain(The

values of in-situ stress, Youngs modulus, permeability, and fluid-loss

coefficientoften are not known with certainty and must be estimated).

Sensitivity runs are carried out with the fracture-propagation model to

determine the effect of these uncertainties on the design process (i.e. the

design engineer should fracture treat the well many times on his or her

computer).

As databases are developed, the number and magnitude of the uncertainties

will diminish.


Fracture Propagation Models


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Two Dimensional (2D) Fracture Propagation Models:

With a 2D model, the engineer fixes one of the dimensions, normally the

fracture height, then calculates the width and length of the fracture.

By calibratingthe 2D model with field results, the 2D models can be used

to make design changes and improve the success of stimulation treatments.

If the correct fracture height value is used in a 2D model, the model will give

reasonable estimates of created fracture length and width if other

parameters, such as in-situ stress,Youngsmodulus, formation permeability,

and total leak-off coefficient, are also reasonably known and used.


Fracture Propagation Models (Contd)


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Examples of (2D) Fracture Propagation Models:

Howard and Fast model (1957): assumed the fracture width was constanteverywhere, allowing the engineer to compute fracture area on the basis of

fracture fluid leak-off characteristics of the formation and the fracturing fluid.

The Perkins-Kern-Nordgren (PKN) geometry(Fig. 10):used when the fracture

length is much greater than the fracture height.

Kristonovich-Geertsma-de Klerk(KGD) geometry (Fig. 11): used if fracture

height is more than the fracture length.

References:

Howard, C.C. and Fast, C.R. 1957. Optimum fluid characteristics for fracture extension. In API Drilling and

Production Practice, 24, 261

Perkins, T.K. and Kern, L.R. 1961. Widths of Hydraulic Fractures. J Pet Technol 13 (9): 937949. SPE-89-PA. http://dx.doi.org/10.2118/89-PA.

Geertsma, J. and de Klerk, F. 1969. A Rapid Method of Predicting Width and Extent of Hydraulic Induced

Fractures. J Pet Technol 21 (12): 1571-1581. SPE-2458-PA. http://dx.doi.org/10.2118/2458-PA.




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Fig. 10: PKN geometry for a 2D fracture

Fracture Geometry


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Fig. 11: KGD geometry for a 2D fracture

Fracture Geometry (Contd)


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Three Dimensional (3D) Fracture Propagation Models:

Today, with high-powered computers, Pseudo-Three-Dimensional (P3D)models are used by most fracture design engineers.

P3D models are better than 2D models for most situations because the P3D

model computes the fracture height, width, and length distribution with the

data for the pay zone and all the rock layers above and below the perforated

interval.

Figures 12and13illustrate typical results from a P3D model.

P3D models give more realistic estimates of fracture geometry and

dimensions, which can lead to better designs and better wells.

P3D models are used to compute the shape of the hydraulic fracture as well

as the dimensions.



F t P ti M d l (C td)


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Fig. 12: Width and height from a P3D model




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Fig. 13: Length and height distribution from a P3D model




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Three Dimensional (3D) Fracture Propagation Models:

The key to any model, including 3D or P3D models, is to have a complete

and accurate data set that describes the layers of the formation to be

fracture treated, plus the layers of rock above and below the zone of interest.

In most cases, the data set should contain information on 5 to 25 layers of

rock that will or possibly could affect fracture growth.

It is best to enter data on as many layers as feasible and let the modeldetermine the fracture height growth as a function of where the fracture is

started in the model.

If the user only enters data on three to five layers, it is likely that the user is

deciding the fracture shape rather than the model.

Reference:

Gidley, J.L., Holditch, S.A., Nierode, D.E. et al. 1989. Three-Dimensional Fracture-Propagation Models. In

Recent Advances in Hydraulic Fracturing, 12. Chap. 5, 95. Richardson, Texas: Monograph Series, SPE.



Data So rces


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Data Sources


Source: http://petrowiki.org/File%3AVol4prt_Page_327_Image_0001.png

Table 2

Fracture Mechanics


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Fracture Mechanics


In petroleum engineering, fracture mechanics theories have been

used for more than 50 years.

Rock fracture mechanics is about understanding what will happen to

the rocks in the subsurface when subjected to fracture stress.

Poro-elastic theory is often used to estimate the minimum horizontal

stress.

The important parameters to consider in hydraulic fracturing are:

Youngsmodulus.

Poissonsratio, and

Fracture toughness

In situ stress,

Basic rock mechanics


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Basic rock mechanics


Poissonsratio:

Defined as the ratio of lateral expansion to longitudinal contraction for a

rock under a uniaxial stress condition.

It is used to convert the effective vertical stress component into an effective

horizontal stress component.

Young s modulus:

Defined as the ratio of stress to strain for uniaxial stress.

The theory used to compute fracture dimensions is based on linear

elasticity.

The modulus(measure of the stiffness)of a rock / formation is a function of

the lithology, porosity, fluid type, and other variables.

If the modulus is large, the material is stiff; a stiff rock results in more

narrow fractures.

If the modulus is low, the fractures are wider.

Fracture Mechanics (Contd)


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TABLE 1:

Fracture Mechanics (Cont d)

Fracture Mechanics


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Fracture Mechanics


Figure 1: Optimizing the fracture design considering risks.

Fracture Mechanics


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Fracture Mechanics


Effective stress concept suggests that pore pressure (Pp) helps

counteract the mechanical stress carried through grain-to-graincontact.

Effective stress:is defined as the total stress minus the pore pressure.

The efficiency of the Ppeffect is measured by poro-elastic factor (Biots

constant),

. = ( )

where

= effective stress

= total (absolute) stress

=

;

Fracture Mechanics


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Fracture Mechanics


where

= rock matrix compressibility

= Bulk compressibility

=

( )

where

= Poissonsratio

= Youngsmodulus

For non-porous rock, = , then =

With high porosity, , then

NOTE: "may be evaluated in the laboratory or from a given failure

envelope obtained from dry sample.

Fracture Mechanics


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Fracture Mechanics


Fracture Toughness, KIC:

It is a property that reflects the rocks resistance for an existing

fracture to propagate for a given fracture mode.

The following are correlations between fracture toughness and

tensile strength, T, fracture radius and net pressure (R &

P ),

Youngsmodulus,E, and compressive strength,o

Economides & Nolte, 1987:

=

where = half-length of an existing crack

Fracture Mechanics


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Fracture Mechanics


Shlyapobersky etal, 1988:

=

( )

where

= , ( 5)

ISIP = Instantaneous Shut In Pressure

, = Minimum horizontal stress

Fracture Mechanics


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Fracture Mechanics


Whittaker et al, 1992:

= . + . ; ( )

= . + . ; ( )

= . + . ; ( )

(MPain); T(Mpa); P(Psi); R(in); E(Gpa); Co(Mpa)

Fracture toughness is a function of confining pressure,Pconf

. = + . . .= ; ()

where Pconf.

(Mpa)

Example 1


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Example 1


Sand and shale samples were laboratory-tested for tensile strength and

fracture toughness with the following results:

Determine the size of the largest crack in the samples.

Solution: Using eq. (3),

For Sand: =

=

= . .

For Shale: =

=

= . .

Formation Tensile strength (psi) Fracture toughness (psi in)

Sand 845 553

Shale 1155 784

Assignment


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Assignment


Question 1:

Use the data provided in Table 1 to estimate the fracture toughness for each

of the lithologies shown. Calculate the Youngsmodulus that would give the

same fracture toughness as calculated in the example problem.

Question 2:

Table A shows selected values of fracture toughness that were determined

experimentally for chalk, limestone and sandstone samples. Analyze in

detail, the difficulty of matching fracturing pressure on the basis of fracture

toughness measured under unconfined conditions.

Assignment


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Assignment


TABLE A: Selected values of fracture toughness

Rock Type Confining Pressure(MPa)

Experimental (MPa in)

Chalk 0.00 0.73

Chalk 24.13 2.22

Chalk 48.26 2.33

Limestone 0.00 1.44

Limestone 24.13 2.12

Limestone 48.26 4.92

Sandstone 0.00 1.36

Sandstone 24.13 2.62

Sandstone 48.26 4.96

Questions?


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