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Hydraulic Fracturing

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Hydraulic Fracturing

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LEARNING OBJECTIVES

1) List the nomenclature of propped Hydraulic Fracturing (HF)

2) Describe the factors which control the Productivity Increase Factor (PIF) achievable by HF

3) Relate PIF to Net Present Value economics as a function of treatment size so as to optimise HF treatment design

4) Explain the role of Rock Mechanics in supplying basic design data for an HF treatment

5) Identify the key elements of the Rock Mechanics of Fracture Initiation and 5) Identify the key elements of the Rock Mechanics of Fracture Initiation and

Propagation

6) Analyse Fracture Propagation Pressure Record to derive basic design data

7) Discuss the importance of the perforation programme design to the success of an HF treatment

8) Distinguish between the different Fracture Propagation Models

9) Explain how to select fracturing materials (fluids/proppants) for an HF treatment 10)Discuss the factors influencing Hydraulic Fracture geometry (fracture shape and

length)

11)Critically describe the Hydraulic Fracture Treatment Design Procedure 12)Describe the stages of a Hydraulic Fracturing Treatment operation

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INTRODUCTION

Propped Hydraulic Fracturing consists of pumping a viscous fluid at a sufficiently high pressure into the completion interval so that a two winged, hydraulic fracture is formed. This fracture is then filled with a high conductivity, proppant which holds the fracture open (maintains a high conductivity path to the wellbore) after the treatment is finished (Figure 1). The propped fracture can have a width between 5mm and 35mm and a length of 100m or more, depending on the design technique employed and the size of the treatment.

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well production rate (Q) can be increased by:

(i) increasing the formation flow capacity (k.h)

{the fracture may increase the effective formation height (h) or connect with a formation zone with a higher

permeability (k)};

(ii) bypassing damage zone

(iii) increasing the wellbore radius (rw) to an effective wellbore radius (rw’) where rw’ is a function of the conductive fracture length Lf .

Production increase due to 150 ft long hydraulic fracture with a flow conductivity of 8,000 mD ft

The relative increase in production achievable by placement of a

hydraulic fracture is much greater in the case of low permeability formations

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HYDRAULIC FRACTURE TREATMENT SELECTION GUIDELINES

Hydraulic fracture stimulation is required for the economic development of low permeability reservoirs. This is because a highly conductive fracture results in a negative skin. The wellbore flowing pressure (P1) has been increased, at a given flowrate, compared to an unimpaired (P2) or impaired (P3) well

(i) the pressure

observed (P2) for the same flow rate for a well with an ideal (S = 0) completion or = 0) completion or (ii) the even lower pressure (P3)

measured for the equivalent well showing a

positive skin due to formation damage.

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The hydraulically fractured well with the negative skin will have the greatest production rate. Propped hydraulic fracture well stimulation should only be considered when the:

(i) well is connected to adequate produceable reserves;

(ii) reservoir pressure is high enough to maintain flow when producing these reserves (or it is economically justifiable to install artificial lift);

(iii) production system can process the extra production.

These minimum criteria are equivalent to those used for matrix treatments and are summarised in table 1. There is, however, one extra, unique requirement for propped hydraulic fracturing:

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professional, experienced personnel are available for treatment design,

execution and supervision along together with high quality pumping, mixing and blending equipment.

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FRACTURE STIMULATED WELL INFLOW PERFORMANCE

The Inflow Performance of a Fracture Stimulated well is controlled by

the dimensionless Fracture Conductivity (Fcd):

The fracture conductivity is increased by:

1. an increased fracture width

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1. an increased fracture width (w),

2. an increased proppant

permeability (large, more

spherical, proppant grains have a higher permeability) and

3. minimising the permeability damage to the proppant

pack from the fracturing fluid.

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Frequently the increased production achieved by carrying out a hydraulic fracturing treatment is represented by the "Folds of Increase" or FOI:

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The previous correlations and equations can be used to quantify the relationship between the increased production (FOI) as a function of the fracture length (Lf), formation permeability (k) and the fracture conductivity (kf*w). Figure 7 shows that for wells in low permeability (0.1mD) formations:

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(i) high values of the FOI are possible;

(ii) FOI is related to fracture half length, while the fracture conductivity has a limited effect, providing its value is greater than a certain minimum.

The (low) formation permeability is controlling the well inflow and increased fracture conductivity does not improve well performance.

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Acid treatment of a low permeability formation with natural fractures filled with a calcite cementing material

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It is well known that there are three principle earth stresses oriented

at right angles to one another.

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In-situ stresses in the subsurface

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As discussed earlier, the vertical stress (σv) can be measured or assumed

with reasonable accuracy. The important rock property for predicting the other two stresses from the vertical stress is called Poisson's Ratio (v), the ratio between Lateral Strain (εy) and the Longitudinal Strain (εx)

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Fracture Initiation and Perforation Program

The Fracture Initiation Pressure (FIP) i.e. the pressure needed to start the

fracture propagating from the perforation will normally be greater than the

FPP.

This is because fracture initiation requires additional energy to

overcome the tensile stresses present around the borehole plus any extra

overcome the tensile stresses present around the borehole plus any extra

pressure required too overcome the fact that the perforation is not

oriented in the preferred direction for fracture propagation.

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Such a case of inefficient perforating leading to an increase in the FIP is

illustrated in Figure 14.

This illustrates how it is unlikely that inline (00phasing)

perforations will be aligned with this preferred direction of fracture propagation

(In the case illustrated the perforation is oriented at right angles to the preferred

fracture criteria).

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Fracture Size

Greater volumes of fracturing fluid will create larger fractures - with higher

treatment costs but also potentially more productive.

However, often uncontrolled

growth of fractures is not desirable from a production point of view e.g. when the

target oil zone is overlain by gas with water underneath.

Figure 18 shows how the

maximum fracture size is limited for this situation. It assumes that:

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Fracture Containment

The hydraulic fracture should thus be designed so that it does not contact

unwanted fluids within a single formation layer. It must also be consider whether

the hydraulic fracture is contained within the pay zone i.e.

whether upward

and/or downward fracture growth is retarded by changes in the formation

property contrast between the two layers. Important formation properties

include:

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Fracture Growth into Boundaries

Whether a pay zone boundary is capable of containing a fracture will depend

on the magnitude of the fracture containment mechanism e.g. minimum

insitu stress contrast and the thickness of the boundary.

Figure 21

schematically illustrates fracture containment for 3 different values of the

stress contrast. Initially the fracture propagates radially in the pay zone until

the boundary layer is reached; after which is becomes more elongated - with

greater stress contrasts giving rise to the more elongated shapes.

N.B. The consecutive lines growing from the left hand side refer to the fracture

shape at increasing times/volume of hydraulic fracturing fluid pumped.

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Fracture Height Measurement

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(ii) Proppant and Gravel Pack Sand are of similar size and the same material maybe used for both applications. Proppant particles are added at low concentration to the fracturing fluid once:

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References

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