completion and stimulation optimization of montney wells

University of Calgary

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2015-02-11

Completion and Stimulation Optimization of Montney

Wells in the Karr Field

Popp, Melanie

Popp, M. (2015). Completion and Stimulation Optimization of Montney Wells in the Karr Field

(Unpublished master's thesis). University of Calgary, Calgary, AB. doi:10.11575/PRISM/25382

http://hdl.handle.net/11023/2106

master thesis

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UNIVERSITY OF CALGARY

Completion and Stimulation Optimization of Montney Wells in the Karr Field

by

Melanie Popp

A THESIS

SUBMITTED TO THE FACULTY OF GRADUATE STUDIES

IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE

DEGREE OF MASTER OF ENGINEERING

GRADUATE PROGRAM IN CHEMICAL AND PETROLEUM ENGINEERING

CALGARY, ALBERTA

JANUARY, 2015

© Melanie Popp, 2015

i

Abstract

The Montney formation in the Karr field has been identified as a very prolific target in today’s

price environment due to its liquids rich potential. The profitability of the play depends greatly

on reducing the amount of capital spent to exploit the resource. The operator has drilled and

stimulated 4 horizontal wells in the area with a variety of placement issues, resulting in

additional costs. An examination of the data from the problem wells identifies two major

sources of premature screen outs and recommendations are made to mitigate this in the short

term. A paradigm shift led to the creation of a fracture model such that the optimal fracture

treatment design can be obtained. Finally, recommendations to whole well completion tactics

are made resulting in a more prosperous well.

ii

Acknowledgments

I would like to first and foremost acknowledge Dr. Roberto Aguilera and the GFREE team.

Even though I was a “satellite member” for many years, I always felt the support.

I would like to thank the staff of Paramount Resources for supporting this work, specifically

Joerg Wittenberg for his guidance. The greatest work often accompanies the greatest challenges.

Much appreciation for Peter Beaton and the staff at Fusion Laboratory Services who agreed to let

me come in and play around on New Years’ Eve to test some of my crazy theories.

Special thanks to everyone who agreed to read and edit this paper when I got really sick of

looking at it! Actually, there was only one person and that’s the fantastic Mr. Matthew Chen!

You rule.

Thanks to Jordan Wilson for all his help and humour. “This thesis haunted me for so long, but

it's just a book I wrote.”

Special thanks also to PLD Team 14 and my wonderful coach Charity Zapanta. For me, PLD,

and this thesis, really started on Day 91.

This work would not have been possible if it wasn’t for my dear friend Mr. Brad Ashton who

held me accountable twice a week for a year and busted my butt if I didn’t honour my word.

What is the “next 10” that we’ll shoot for together buddy? I love you and appreciate you more

than words can describe.

The journey to the end of my masters has been a long one and is marked by the development of

my wonderful son Owen. I became pregnant with you two months into this trek and endured

nights away from you and even writing finals in a small desk while pregnant with you. Let this

be a lesson: Never stop learning. Never stop growing. Stay curious. I love you.

iii

Table of Contents

Abstract…………………………………………………………………………………....i

Acknowledgments………………………………………………………………………...ii

Table of Contents…………………………………………………………………………iii

List of Tables……………………………………………………………………………..vi

List of Figures…………………………………………………………………………....vii

List of Symbols, Abbreviations, Nomenclatures…………………………………………xi

Geology of the Montney Resource Play in Karr ...........................................2 Chapter One:

1.1 EXPLORATION HISTORY AND DEVELOPMENT OF THE MONTNEY FORMATION .............................................................................................................3

1.2 PETROGRAPHY AND SEDIMENTOLOGY ..............................................................5

1.3 KARR AREA MONTNEY D GEOLOGY ...................................................................6

1.4 KARR AREA PRODUCTION ....................................................................................11

1.5 STUDY PURPOSE ......................................................................................................16 Analysis of Fracture Placement Issues .......................................................17 Chapter Two:

2.1 LITERATURE SURVEY ............................................................................................17

2.2 BACKGROUND .........................................................................................................18

2.3 FAILURE ANALYSIS ................................................................................................18 2.3.1 Mechanical Failure ...............................................................................................18 2.3.2 Fracture Width Restriction ...................................................................................23

2.4 CONCLUSIONS..........................................................................................................32 Hydraulic Fracturing Model Calibration ..................................................33 Chapter Three:

3.1 GOHFER® SIMULATOR ...........................................................................................33

3.2 LOG INPUT AND PROCESSING .............................................................................33

3.3 FRACTURE GEOMETRY AND RESERVOIR PARAMETER DETERMINATION35 3.3.1 Diagnostic Fracture Injection Test .......................................................................35

iv

3.3.2 Tracer Log ............................................................................................................43

3.4 PRODUCTION MODEL CALIBRATION ................................................................50 3.4.1 Flow Test Calibration ...........................................................................................50 3.4.2 Build-up Analysis ..................................................................................................50

3.5 HORIZONTAL WELL E ............................................................................................55 3.5.1 Design and Execution ...........................................................................................55 3.5.2 Well Results ...........................................................................................................58

3.6 HORIZONTAL WELL F ............................................................................................60 3.6.1 Design and Execution ...........................................................................................60 3.6.2 Well Results ...........................................................................................................60

3.7 HORIZONTAL WELL G ............................................................................................64 3.7.1 Design and Execution ...........................................................................................64 3.7.2 Well Results ...........................................................................................................64

3.8 INVESTIGATION INTO WATER SOURCE ............................................................66

3.9 SUMMARY OF MODELLING RESULTS ................................................................72 Fracture and Completion Optimization ......................................................73 Chapter Four:

4.1 OPTIMIZATION OF A SINGLE FRACTURE ASSUMING 0.008 MD PERMEABILITY .....................................................................................................73

4.1.1 Fluid considerations ..............................................................................................73 4.1.2 Proppant Selection ................................................................................................77 4.1.3 Job Size .................................................................................................................80 4.1.4 Pumping rate .........................................................................................................82 4.1.5 Maximum Concentration and Total Fluid Volume ...............................................84 4.1.6 Pad Percentage ......................................................................................................86 4.1.7 Optimum Treatment for Single Fracture: Conclusion .........................................87

4.2 OPTIMIZATION OF A HORIZONTAL WELL ASSUMING 0.008 MD PERMEABILITY .....................................................................................................88

4.3 OPTIMIZATION OF A SINGLE FRACTURE ASSUMING 0.08 MD PERMEABILITY...................................................................................................................................89

4.3.1 Fluid considerations ..............................................................................................89

FIGURE 4-14: COMPARISON OF FLUID PERFORMANCE FOR 55 TONNE TREATMENT, 0.08 MD CASE ...............................................................................89

4.3.2 Proppant Selection ................................................................................................91 4.3.3 Job Size .................................................................................................................92 4.3.4 Pumping rate .........................................................................................................94 4.3.5 Maximum Concentration and Total Fluid Volume ...............................................95

v

4.3.6 Pad Percentage ......................................................................................................97 4.3.7 Optimum Treatment for Single Fracture: Conclusion .........................................98

4.4 OPTIMIZATION OF A HORIZONTAL WELL ASSUMING 0.08 MD CASE .......99

4.5 CONCLUSIONS..........................................................................................................99 Economic Impact of Recommended Completions Changes .....................101 Chapter Five:

5.1 ECONOMICS OF CURRENT FRACTURE PLAN (55 TONNE GELLED OIL) ..101

5.2 ECONOMICS OF PROPOSED FRACTURE PLAN (50 TONNE FOAMED SURFACTANT SYSTEM) ....................................................................................102

5.3 ECONOMICS OF NEW PROPOSED COMPLETION PLAN ................................103 Summary, Conclusions and Recommendations ..........................................106 Chapter Six:

vi

List of Tables

Table 2-1: Summary of Failure Criteria ....................................................................................... 19

Table 2-2: Summary of Failure Criteria cont’d ........................................................................... 20

Table 3-1: Comparison of Reservoir Characteristics from PTA Analysis and GOHFER® ......... 54

Table 3-2: Comparison of Fracture Parameters for Multiple Treatments in Same Zone ............ 70

Table 4-1: Comparing Fracture Flow Parameters for Fluid Optimization Run for 0.008 md Permeability Case ................................................................................................................. 75

Table 4-2: Comparing Fracture Flow Parameters for Proppant Optimization Run for 0.008 md Permeability Case ........................................................................................................... 80

Table 4-3: Comparing Fracture Flow Parameters for Job Size Optimization Run for 0.008 md Permeability Case ........................................................................................................... 81

Table 4-4: Comparing Fracture Flow Parameters for Pump Rate Optimization Run for 0.008 md Permeability Case ........................................................................................................... 83

Table 4-5: Comparing Fracture Flow Parameters for Maximum Concentration Optimization Run for 0.008 md Permeability Case .................................................................................... 85

Table 4-6: Comparing Fracture Flow Parameters for Fluid Optimization Run, 0.08 md case .... 90

Table 4-7: Comparing Fracture Flow Parameters for Proppant Optimization Run, 0.08 md case ........................................................................................................................................ 92

Table 4-8: Comparing Fracture Flow Parameters for Job Size Optimization Run, 0.08 md case ........................................................................................................................................ 93

Table 4-9: Comparing Fracture Flow Parameters for Pump Rate Optimization Run, 0.08 md case ........................................................................................................................................ 95

Table 4-10: Comparing Fracture Flow Parameters for Maximum Concentration Optimization Run, 0.08 md case ........................................................................................... 96

Table 5-1: Summary of Economic Analyses ............................................................................. 105

vii

List of Figures

Figure 1-1: Montney deposition in WCSB (Zonneveld, Golding, Moslow, Orchard, Playter, & Wilson, 2011) ...................................................................................................................... 2

Figure 1-2: Lower-Middle Triassic Sequence Stratigraphic Framework (Mederos, 1995) ........... 3

Figure 1-3: Montney Coquina and Subcrop Production Summary (Zonneveld & Moslow, 2012) ....................................................................................................................................... 4

Figure 1-4: Montney Textural Maturity: Mica vs Clay (Davies, Moslow, & Sherwin, 1997) ..... 6

Figure 1-5: Example of Hummocky Cross-Bedding (Zonneveld, Beatty, MacNaughton, Pemberton, Utting, & Henderson, June 2010) ........................................................................ 7

Figure 1-6: Type Well for Montney (Canadian Discovery, 2012) ................................................ 9

Figure 1-7: Porosity vs. Event Bed Thickness (Zonneveld & Moslow, 2012) ............................ 10

Figure 1-8: Porosity Permeability Correlation for Montney Core Samples (Zonneveld & Moslow, 2012) ...................................................................................................................... 11

Figure 1-9: Karr Area Upper Montney Producers ....................................................................... 13

Figure 1-10: GOR of Upper Montney Producers in Karr Area ................................................... 14

Figure 1-11: Montney Production Rates in Karr ......................................................................... 14

Figure 1-12: Correlation of Peak Rate to EUR for Gas Wells in North America (Morgan, 2013) ..................................................................................................................................... 15

Figure 2-1: Example of Mechanical Issue in Liner ..................................................................... 22

Figure 2-2: Example of Formation Width Restriction Resulting in NWB Screenout ................. 24

Figure 2-3: Brittleness Index vs. Treating Pressure ..................................................................... 25

Figure 2-4: Average PHIE vs Treating Pressure .......................................................................... 26

Figure 2-5: Comparison of gelled oil with different energizers .................................................. 28

Figure 2-6: Comparison of Standard Gelled Oil System with Buffered Mixture ........................ 28

Figure 2-7: Example of Ceramic Induced Screenout ................................................................... 30

Figure 2-8: Proppant Size Distribution of Proppants Used in Treatments .................................. 30

Figure 2-9: Example of Unusual Pressure Response from Addition of Ceramic Sand ............... 31

viii

Figure 3-1: Log Data for Vertical Well ....................................................................................... 34

Figure 3-2: Diagnostic Fracture Injection Test ............................................................................ 36

Figure 3-3: G-function plot .......................................................................................................... 38

Figure 3-4: Permeability Estimate from G at Closure ................................................................. 38

Figure 3-5: Square-Root Time Plot .............................................................................................. 39

Figure 3-6: Log-log analysis plot ................................................................................................. 40

Figure 3-7: After Closure Analysis: Linear Flow ....................................................................... 41

Figure 3-8: PDL Analysis ............................................................................................................ 42

Figure 3-9: Proppant Concentration Grids Showing Anticipated Fracture Height from Upper Middle Montney Perforations with Original Stress Profile .................................................. 46

Figure 3-10: Proppant Concentration Grids Showing Anticipated Fracture Height from Lower Middle Montney Perforations with Original Stress Profile ....................................... 47

Figure 3-11: Radioactive Tracer Showing Fracture Height (Upper Middle Montney) ............... 48

Figure 3-12: Radioactive Tracer Log Showing Fracture Height (Lower Middle Montney) ....... 49

Figure 3-13: Proppant Concentration Grid of UMM Stimulation ............................................... 51

Figure 3-14: Proppant Concentration Grid of LMM Stimulation ................................................ 51

Figure 3-15: Flow Test for Lower Interval .................................................................................. 52

Figure 3-16: Flow Test for Upper Interval .................................................................................. 52

Figure 3-17: Expected Production From GOHFER for LMM zone ............................................ 53

Figure 3-18: Expected Production from GOHFER for UMM zone ............................................ 53

Figure 3-19: Example of Treatment Pressures from Horizontal Well E ..................................... 56

Figure 3-20: Treating Pressures on First Zone from Horizontal Well E ..................................... 57

Figure 3-21: Modelled vs. Actual Production for Well E, assuming 22 stages contributing ...... 59

Figure 3-22: Modelled vs. Actual Production for Well E, assuming 14 stages contributing ...... 60

Figure 3-23: Modelled vs. Actual Production for Well F, assuming 21 stages contributing ...... 62

ix

Figure 3-24: Chemical Tracer Results from Well F .................................................................... 63

Figure 3-25: Modelled vs Actual Production for Well F, assuming 13 stages contributing ....... 63

Figure 3-26: Modelled vs Actual Production for Well G, assuming all stages contributing ....... 65

Figure 3-27: Modelled vs Actual Production for Well G, assuming 13 stages contributing ....... 65

Figure 3-28: Example of Typical Microseismic Response from Montney Stimulations ............ 66

Figure 3-29: Multiple Fractures Propagating in Single Stage ..................................................... 68

Figure 3-30: Typical Karr Montney Well showing Upper and Middle Montney Sections ......... 69

Figure 3-31: Proppant Concentration Grids for 55 Tonne frac in zone once (left), twice (center) and three times (right).............................................................................................. 70

Figure 3-32: Production Impact of Multiple Fractures into Same Zone ...................................... 71

Figure 4-1: Regained Permeability Testing Results .................................................................... 74

Figure 4-2: Comparison of Fluid Performance for 55 tonne Treatment for 0.008 md Permeability Case ................................................................................................................. 74

Figure 4-3: Comparison of Leakoff Properties of Gelled Oil (right), VES Foam (center), Slickwater (right) Fluids ....................................................................................................... 76

Figure 4-4: Comparison of Fracture Geometries of Gelled Oil (left), VES Foam (center), Slickwater (right) Fluids for 0.008 md Permeability Case ................................................... 77

Figure 4-5: Proppant Conductivity of 20/40 Jordan Sand (left) and 20/40 Ceramic (right) with Stress ............................................................................................................................. 78

Figure 4-6: Comparison of Proppant Type for 55 Tonne Treatment for 0.008 md Permeability Case ................................................................................................................. 79

Figure 4-7: Comparison of Job Size for 0.008 md Permeability Case ........................................ 81

Figure 4-8: Comparison of Pumping Rate for 0.008 md Permeability Case ................................ 82

Figure 4-9: Comparison of Proppant Concentration Grids for 3 m3/min (left), 5 m3/min (centre), and 7 m3/min (right) for 0.008 md Permeability Case ........................................... 83

Figure 4-10: Comparison of Maximum Concentration for 0.008 md Permeability Case ........... 84

Figure 4-11: Comparison of Proppant Concentration Grids for 200 (l), 400 (m), 800 (r) kg/m3 Bottomhole Concentration for 0.008 md Permeability Case ..................................... 86

x

Figure 4-12: Comparison of Pad Size for 0.008 md Permeability Case ...................................... 87

Figure 4-13: Fracture Spacing Optimization for 0.008 md Permeability Case ........................... 88

Figure 4-14: Comparison of Fluid Performance for 55 Tonne Treatment, 0.08 md case ............ 89

Figure 4-15: Comparison of Fracture Geometries of Gelled Oil (left), VES Foam (center), Slickwater (right) Fluids for 0.08 md case ............................................................................ 90

Figure 4-16: Comparison of Proppant Type for 55 Tonne Treatment, 0.08 md case .................. 91

Figure 4-17: Comparison of Job Size, 0.08 md case ................................................................... 93

Figure 4-18: Comparison of Pumping Rate, 0.08 md case ........................................................... 94

Figure 4-19: Comparison of Maximum Concentration , 0.08 md case ...................................... 96

Figure 4-20: Comparison of Proppant Concentration Grids for 200 (l), 400 (m), 800 (r) kg/m3 Bottomhole Concentration, 0.08 md Case .................................................................. 97

Figure 4-21: Comparison of Pad Size, 0.08 md Case .................................................................. 98

Figure 4-22: Fracture Spacing Optimization for 0.08 Permeability Case ................................... 99

Figure 5-1: NPV for Current 55 Tonne Gelled Oil Treatment for Different Permeability Estimates ............................................................................................................................. 102

Figure 5-2: NPV for Proposed 50 Tonne VES Foam Treatment for Different Permeability Estimates ............................................................................................................................. 103

Figure 5-3: NPV for Additional Stages and 50 Tonne VES Treatments for Different Permeability Estimates ........................................................................................................ 104

xi

List of Symbols, Abbreviations, Nomenclatures

$ dollars ACA After Closure Analysis Bcf Billion cubic feet (of gas) BH bottom hole CFOP Critical Fissure Opening Pressure cm centimetres

Co constand matrix leakoff coefficient

CO2 carbon dioxide cp centipoise

Cp leakoff coefficient CRC ceramic

ct compressability DFIT Diagnostic Fracture Injection Test dP/dG pressure derivative E Young's modulus

e3m3 or 103m3 thousands of cubic metres

e6m3 millions of cubic metres Econo ceramic proppant EUR Estimated Ultimate Recovery f Porosity GOHFER Grid Oriented Hydraulic Fracture Extension Replicator GOR Gas-Oil Ratio (insert unit) HCS hummocky cross-bedding hr hour ID inside diameter k permeability

Kfwf fracture conductivity (fracture permeability x fracture width) kg/m3 kilograms per cubic metres km kilometres kPa kilopascals LMM Lower Middle Montney m metres m viscosity m/s metres per second

m3 metres cubed md or mD or MD millidarcy

xii

mD-m millidarcy-metres min minutes mm millimetres MMbbls Million barrels MMscf Millions of standard cubic feet MPa megapascal

N2 nitrogen NPV Net Present Value PDL Pressure Dependent Leakoff Pe Photoelectic effect pH power of hydrogen

PHIE Effective Porosity (fe) psi pounds per square inch PTA Pressure Transient Analysis

PZ or PZS Process Zone Stress Q Foam quality, by volume RC resin coated sand

rp leakoff height to gross frac height ratio s.g. specific gravity

sec-1 reciprocal seconds

Slurry rate Rate of liquid phase and proppant combined

sm3 standard cubic metres T tonnes TVD true vertical depth UMM Upper Middle Montney VES Viscoelastic Surfactant WCSB Western Canadian Sedimentary Basin Wellhead Rate Rate of liquid, gaseous, and proppant combined

2

Geology of the Montney Resource Play in Karr Chapter One:

The Montney Formation is one of North America’s leading resource plays. What makes the

Montney a particularly desirable resource play is its depositional origin, predictive geometry,

lateral variability, facies heterogeneity, and reservoir attributes of primary and secondary

porosity and permeability.

The Montney Formation was deposited in the Peace River Basin during the Lower Triassic

(Zonneveld & Moslow, 2012) as shown in Figure 1-1 and Figure 1-2.

Figure 1-1: Montney deposition in WCSB (Zonneveld, Golding, Moslow, Orchard, Playter,

& Wilson, 2011)

3

Figure 1-2: Lower-Middle Triassic Sequence Stratigraphic Framework (Mederos, 1995)

Sedimentation was driven by arid climatic conditions, dominance of northeast trade winds,

minimum fluvial influx, offshore coastal upwelling, and north to south longshore sediment

transport. There are a wide range of depositional environments recorded in Montney facies

ranging from mid to upper shoreface sandstones, to middle and lower shoreface hummocky

cross-stratified sandstones and course siltstones, to finely laminated lower shoreface sand and

offshore siltstones, and to turbidites. There are seven stratigraphic horizons in the Montney

featuring a dolomotized coquina facies. (Zonneveld & Moslow, 2012)

1.1 Exploration History and Development of the Montney Formation

From the 1950s to the 1980s, the overly thick Montney was seen as an obstruction to drilling

deeper Paleozoic targets. Some operators were successfully exploiting the play as a sub-crop

4

play, taking advantage of structural drape and stratigraphic traps in sandstone and coquina. Over

the course of thirty years, 604 producing wells were drilled in the coquina and subcrop play for a

total of 132.3 MMbbls of oil and 518.4 Bcf of gas. (Figure 1-3)

Figure 1-3: Montney Coquina and Subcrop Production Summary (Zonneveld & Moslow,

2012)

During the 1990s, drilling ceased temporarily as the general prevailing thought was that any

potential down-dip would be “shaled out” and that reservoir compaction and a down-dip water

leg would further lend itself to poorer quality reservoirs. At the time, it was also thought that the

WCSB (Western Canadian Sedimentary Basin) never achieved water depths great enough to

5

yield any sort of appreciable turbidite sequence. However, drilling in the Valhalla field proved

that there were several stratigraphic and hydrodynamic traps of silty to very fine grained

sandstone as a result of turbidite deposition, yielding some profitable gas and oil wells.

With the rise of unconventional gas exploration in North America in the new millennium, the

Montney became a chief target, specifically in the higher porosity siltstones. However, the

lateral and stratigraphic variability in the Montney has challenged the players to identify the

discrete intervals and areas where reservoir quality is better for economic exploitation.

1.2 Petrography and Sedimentology

The Montney is primarily dominated by siltstone with subordinate very fine-grained siltstone and

several ‘coquina’ horizons. Labelling the Montney in Karr a “shale gas play” is incorrect as it is

predominately quartz dominated with very low proportions of clay minerals in the matrix (Figure

1-4).

Very little work had been done on arid sedimentology until the late 1990s. Using an analogous

modern day depositional environment off coastal Namibia, it was found that while some

sediments were indeed transported and deposited by wind (Aeolian), the majority of the

deposition occurred by ephemeral rivers and streams. The dolomite present is both detrital and

cementatious and clays are mostly illites.

6

Figure 1-4: Montney Textural Maturity: Mica vs Clay (Davies, Moslow, & Sherwin, 1997)

1.3 Karr Area Montney D Geology

The Karr field is located approximately 75 km south of the city of Grande Prairie, Alberta. This

work will focus on wells drilled in the Montney D3 and D4 members (Figure 1-6). These beds

are characterized by a variety of siltstone to sandstone “event beds” enclosed in or interbedded

with either wavy bedded to ripple-laminated siltstones and sandstones with argillaceous

interseams, or darker, finely laminated argillaceous high TOC (total organic carbon) siltstones.

The term “event bed” is applied to a bedform deposited as a geologically instantaneous product

7

of storm-wave currents, turbidity currents, fluidized flow, or other processes. The most common

bedforms observed in the Montney D3 and D4 are hummocky cross-bedding (HCS). This is a

rather broad facies that can include gradational SCS (swaley cross-stratification), interbedded

wavy-laminated silts and sands, burrowed subfacies, fluidized bedforms, transitional turbidites,

and a wide range of soft-sediment deformation fabrics. HCS event beds are interpreted to record

deposition of silt and sand during the waning phases of storm-wave trains in offshore transition

to shoreface settings. Refer to Figure 1-5 for example.

Figure 1-5: Example of Hummocky Cross-Bedding (Zonneveld, Beatty, MacNaughton,

Pemberton, Utting, & Henderson, June 2010)

8

The event beds are clearly expressed on gamma, neutron-density, Pe and resistivity logs. A

rough correlation was found to exist between event bed thickness and core porosity (Figure 1-7).

It also appears that burial depth may have an influence over the particle size, and therefore the

porosity-permeability ratio (Figure 1-8).

The Montney D3 and D4 members are approximately 150 m thick in the Karr area with

porosities ranging from 3-6%. The subject wells of this paper are targeted in different windows

in the Montney and will be discussed more in detail in the individual chapters.

9

Figure 1-6: Type Well for Montney (Canadian Discovery, 2012)

10

Figure 1-7: Porosity vs. Event Bed Thickness (Zonneveld & Moslow, 2012)

11

Figure 1-8: Porosity Permeability Correlation for Montney Core Samples (Zonneveld &

Moslow, 2012)

1.4 Karr Area Production

As of November 15, 2013, there were a total of 25 wells drilled and completed in the Upper

Montney Formation in the area from township 64-67, range 3-7W6M (Figure 1-9). Twenty one

of those wells have production data available publicly.

The Montney is an attractive option because of the potentially high hydrocarbon and natural gas

yields, especially in the thermal maturity window where the field of interest is situated.

However, the variability in reported gas-oil ratio (GOR) is substantial. (Figure 1-10). This is

12

because there is no infrastructure available for condensate production in the area. Liquids are

usually captured at the well or battery site and trucked to midstream facilities. Therefore, the

reporting of them is extremely variable and cannot be used to make predictions on liquids yield

in a particular area.

For the purposes of production performance, gas rates of the study wells were used to generate

type curves. There were only five wells with sustained production over a year (Figure 1-11).

Three of the wells exhibited restricted flow in their early time period (9-12, 8-29, 3-28) which

may be a result of processing limitations. Therefore, in the calculation of the average

production, the first 6 months of production for these three restricted wells was not factored in.

Figure 1-12 shows a common industry correlation of peak rate to estimated ultimate recover

(EUR). For the average production as shown in the black line on Figure 1-11, the peak rate is

approximately 180 e3m3/day or 6.3 MMscf/day. This would correlate to an EUR of 6.3 Bcf for a

typical Montney well.

13

Figure 1-9: Karr Area Upper Montney Producers

R7 R6 R5 R4 R3

14

Figure 1-10: GOR of Upper Montney Producers in Karr Area

Figure 1-11: Montney Production Rates in Karr

0

200000

400000

600000

800000

1000000

1200000

1400000

1600000

1800000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21

GOR (m3/m

3)

0

50

100

150

200

250

0 5 10 15 20 25 30

Gas Production (e3m3/day)

Months

100/09‐12‐064‐04W6/00 100/08‐29‐064‐04W6/02

100/11‐18‐064‐04W6/00 100/02‐01‐066‐06W6/00

100/03‐28‐064‐04W6/02 Average Rate

15

Figure 1-12: Correlation of Peak Rate to EUR for Gas Wells in North America (Morgan,

2013)

16

1.5 Study Purpose

The Montney in Karr presents a very valuable property for exploitation. However, the history of

development experienced by the operator has been a challenge. The fracture stimulations were

difficult to pump resulting in higher completion costs with less than expected production. There

was a risk of abandoning the field if no solution was found.

This thesis will look at how fracture placement success affects the viability of the Montney play

in Karr. Chapter 2 will discuss four horizontal wells with fracture placement issues and identify

the impairments and recommended remediation. Chapter 3 will outline the development of a

model that proved, in the subsequent three completions, to be an accurate measure of well

production. Chapter 4 utilizes the calibrated model to outline further fracture optimization

strategies. Chapter 5 will discuss the economics associated with the new recommended method

of completion and the increased upside to the producer.

The thesis will conclude with recommendations for future resource play development regarding

critical pieces of information needed to understand both the reservoir and the completion, and the

associated value of each of those pieces.

17

Analysis of Fracture Placement Issues Chapter Two:

2.1 Literature Survey

Premature screenouts can be a confusing and costly endeavour for any stimulation program.

Conventional thinking in the 1980’s lead to believe that insufficient far-field fracture width was

the only cause of prematures screenouts. As a result, larger pad volumes were utilized and the

cost of performing well stimulation increased.

In the 1990’s more research identified the major source of screenouts as complicated near

wellbore effects. Near wellbore effects can be grouped into two categories: insufficient access

to the reservoir as a result of perforation restrictions and tortuosity.

Perforation pressure drop is usually assumed to have a negligible influence on the fracture

treating pressure, provided there is adequate flow area created. Perforations can erode when

sand slurries are pumped by increasing the diameter of the perforation and decreasing the

discharge coefficient (Romero, Mack, & Elbel, 1995). Therefore, the most common solution for

perforation friction is to pump proppant slugs early in the treatment (Cleary, 1993).

Fracture tortuosity is described as the convoluted pathway connecting the wellbore to the main

body of the fracture further away from the wellbore. The issue of fracture tortuosity is

particularly complex in horizontal wells. When a fracture is initiated in a horizontal well, the

state of stress around a wellbore is such that it promotes initiation of a longitudinal or axial

fracture (Daneshy, 2009). If the creation of this longitudinal fracture is such that it extends

perpendicular to the minimum principle stress, then tortuosity is not an issue. Since most wells

are drilled to initiate transverse fractures, this initial axial fracture must reorient itself to comply

with the minimum principle stress direction, thus creating a tortuous path for fracture

propagation (Daneshy, 2011). Tortuosity can be overcome by maintaining adequate fluid

18

viscosity during the pumping of the treatment (Aud, 1994) or pumping proppant slugs

(McDaniel, 2001).

2.2 Background

The operator has drilled 4 horizontal wells in the D3-D4 horizons in the Montney. Three of

these wells were equipped with an openhole packer with ball drop system (Wells A, B, and D).

One of these wells (Well C) was completed with a cemented in place liner and pump-down plug

and perforation type completion. With the exception of stage 6-16 on Well A, all wells were

treated with a 30-50 quality (foam, by volume) carbon dioxide emulsion with gelled

hydrocarbons. Stages 6-16 on Well A were treated with a 30 quality carbon dioxide energized

water based crosslinked gel. In these 4 horizontal wells, there was a total of 76 stages available

for stimulation.

2.3 Failure Analysis

Each of the 76 stages was analyzed in detail to determine the cause of failure in each case. The

results are shown in Table 2-1 and Table 2-2. There were 36 stages (47.3%) that were treated

without issue. As screen outs were frequent, designed job sizes changed along the lateral. The

approach was to pump smaller jobs following a screen out and then gradually increase the job

size and maximum bottomhole proppant concentration as comfort with fracture placement grew.

2.3.1 Mechanical Failure

There were 14 stages that were identified to have some sort of mechanical failure. It is important

to note that no mechanical failure was observed in Well C which was the plug and perforation

completion. One of the mechanical failures was with the surface fracturing equipment (Well B,

Zone 12) in which the proppant delivery unit broke down on surface. Of the remaining 13

incidents, all but one of them occurred after a wellbore screenout.

19

Table 2-1: Summary of Failure Criteria

Well Stage

Designed

Proppant

(T)

Placed

Proppant

(T)

%

Proppant

Placed

Failure Mechanism Comments

A 1 52 4 8% fracture width restriction screened out at 200 kg/m3 BH econoprop

A 2 52 0 0% mechanical could not open port due to insufficient cleanout

A 3 52 0 0% mechanical could not initiate frac due to limited entry



A 6 30 24 80% fracture width restriction pressure increase at 350 kg/m3 BH, called flush


A 8 30 31 103% fracture width restriction screened out at 400 kg/m3 BH CRC


A 10 30 40 133% fracture width restriction screened out at 500 kg/m3 BH CRC


A 12 30 22.3 74% fracture width restriction pressure increase at 400 kg/m3 BH, called flush

A 13 30 16.5 55% fracture width restriction pressure increase at 300 kg/m3 BH, called flush


A 15 30 24.5 82% none all proppant placed

A 16 30 30 100% none all proppant placed

B 1 72 60 83% fracture width restriction screened out with 500 kg/m3 BH econo


B 3 72 42 58% none all proppant placed


B 5 72 0 0% mechanical did not see ball action, abandon zone





B 10 72 33 46% fracture width restriction pressure increase at 400 kg/m3 BH, called flush

B 11 72 40 56% fracture width restriction pressure increase at 400 kg/m3 BH, called flush

B 12 72 32 44% mechanical sand conveyor issues, shut down













20

Table 2-2: Summary of Failure Criteria cont’d

Well Stage

Designed

Proppant

(T)

Placed

Proppant

(T)

%

Proppant

Placed

Failure Mechanism Comments

C 1 77 77.0 100% none all proppant placed

C 2 77 77 100% none all proppant placed



C 5 77 60.4 78% fracture width restriction screened out with 1000 kg/m3 BH econo



C 8 54.5 54.5 100% none all proppant placed




C 12 34 39.5 116% none all proppant placed


C 14 54 34 63% fracture width restriction screened out with 400 kg/m3 BH econo


C 16 54.0 60.8 113% none all proppant placed

D 1 72 40.37 56% fracture width restriction screened out with 350 kg/m3 BH econo

D 2 62 0 0% mechanical could not open port due to insufficient cleanout

D 3 62 0 0% mechanical could not open port due to insufficient cleanout

D 4 62 51 82% fracture width restriction screened out with 500 kg/m3 BH sand

D 5 41 39 95% none all proppant placed

D 6 36 23 64% fracture width restriction pressure increase at 250 kg/m3 BH, called flush


D 8 37.6 37.6 100% none all proppant placed




D 12 52.6 34 65% fracture width restriction screened out with 500 kg/m3 BH sand

D 13 52.6 29.6 56% fracture width restriction pressure increase at 300 kg/m3 BH, called flush


D 15 52.6 41.6 79% fracture width restriction pressure increase at 400 kg/m3 BH, called flush

D 16 62 52.6 85% none all proppant placed



D 19 62 19.6 32% fracture width restriction pressure increase at 250 kg/m3 BH, called flush


21

The procedure to deal with a wellbore screenout is to flow the well back to recover most of the

proppant. If it is possible to inject into the formation after flowing back two hole volumes, then

the next stage ball is dropped and the treatment is resumed. Flow rates at the tanks are on the

order of 30 m3/hr. Assuming a pipe ID of 99.6 mm, this equates to a velocity of 1.069 m/s in the

pipe. Settling velocity for the largest particle of ceramic proppant (0.584 mm, 2.63 s.g.) in gelled

oil (220 cp, 0.8 s.g.) is 3.87 x 10-4 m/s. At these flow rates, most of the sand would be cleaned

up inside the liner.

Two possibilities exist for insufficient clean-up. The first assumes that the fluid quality is not

consistent in the pipe. When the pressure is relieved from the system on flowback, the CO2 may

become immiscible in the oil and create pockets of gas where sand could potentially fall out and

remain in the liner. The second possibility is that sand remains packed off in the annulus

between the external casing packers making re-entry difficult.

Mechanical issues are differentiated from formation issues by the reaction the formation has to

the erosional effects of sand and fluid rate. Refer to Figure 2-1. Rate is steadily ramped up from

1 to 2 m3/min and the pressure is expected to stay constant, or decrease as the fracture width

increases. There are very strange pressure signatures which happen when no rate changes occur.

It is suspected that this is a function of cleaning up residual sand in the wellbore or annulus.

There is no effect as the 70/140 mesh proppant enters the fracture (between points 3 and 4, and

again between points 6 and 12) indicating that there are no erosional effects occurring. At this

point, the decision was made to abandon this stage.

22

Figure 2-1: Example of Mechanical Issue in Liner

23

2.3.2 Fracture Width Restriction

A total of 26 stages exhibited signs of fracture width restriction. Screen-outs occurred in 17 of

these stages and 9 were terminated early due to increasing pressure response. An example of a

near wellbore screenout is illustrated in Figure 2-2.

The treatment starts as anticipated with a pressure drop of 23 MPa from the addition fluid rate

and 70/140 mesh sand. Point 6 marks the transition from 30/50 white sand to 30/50 ceramic

proppant. The increase in pressure seen between points 6 and 7 is due to hydrostatics.

The specific gravity of the ceramic proppant, in this case, is 2.70 as opposed to the white sand

which is 2.65. At an average TVD of 2700 m and 1000 kg/m3 maximum proppant

concentration, the difference in hydrostatic pressure is 1.7 kPa.

The ceramic proppant is bottomhole at point 7 when the pressure appears to flatten out. When

the bottomhole proppant concentration reaches 1000 kg/m3, a rapid screenout occurs. The

rapidity at which this screenout occurs is indicative of a near-wellbore width restriction or

tortuosity.

2.3.2.1 Formation Property Evaluation

One of the treated wells had a horizontal log run over the lateral section to ascertain formation

properties. It was assumed that knowing parameters such as brittleness index and effective

porosity, one would better be able to predict fracture placement issues. This proved to be untrue

as seen in Figure 2-3 and Figure 2-4. There is no apparent relationship between the average

treating pressure (used as a proxy for the relative toughness of fracture placement) and either

brittleness index or effective porosity. Therefore, as the formation properties do not appear to

correlate to the fracture placement issues, it is theorized that they are not what is causing the

premature screen-outs.

24

Figure 2-2: Example of Formation Width Restriction Resulting in NWB Screenout

25

Figure 2-3: Brittleness Index vs. Treating Pressure

26

Figure 2-4: Average PHIE vs Treating Pressure

27

2.3.2.2 Fluid Property Evaluation

The fluid properties were examined to determine if they were the cause of the insufficient

fracture widths leading to premature screen-out. The fluid used in these treatments was a gelled

hydrocarbon of 790-840 kg/m3 density with a 50% CO2 assist. The same base fluid was used

with a 30% N2 assist in another of the operator’s properties just 20 km to the south without the

same issue. The properties of these fluids are shown in Figure 2-5.

The CO2 system has a shorter sand carrying capability time, dropping below 100 cp at 30

minutes. The average pump times for treatments are 60 minutes, therefore, the fluid is only

capable of holding proppant suspended for half the treatment. This reduced viscosity would

result in proppant piling near the wellbore and could lend itself to premature screenout.

The next area to examine was that of possible contamination sources. Experience in the field

lends that a small amount of water can be entrained in the oil when it is brought out to location.

Even a 1.5% (by volume) water contamination of the frac oil and a 1:1 reaction at equilibrium

with the CO2, the resultant mixture becomes acidic with a pH of 4.6.

The resultant mixture was then tested in a laboratory environment. Since the testing of gelled

hydrocarbons with CO2 requires specialized equipment, a simple bench test was run with a

representative sample of gelled hydrocarbon and the addition of 1.5 L/m3 of a buffer with a pH

of 4.6 (Figure 2-6).

It is observed that while the mixtures both start with a very high viscosity, the buffered solution

drops quickly in viscosity to below 100 cp in around 30 minutes. Note that these tests were

conducted at 100 sec-1 as opposed to the data shown in Figure 2-5 which was recorded at a

higher shear rate (170 sec-1). The higher shear rate would amplify any viscosity reductions.

28

Figure 2-5: Comparison of gelled oil with different energizers

Figure 2-6: Comparison of Standard Gelled Oil System with Buffered Mixture

0

50

100

150

200

250

300

350

400

0 50 100 150 200

Apparent Viscosity at 170 sec‐1

Elapsed Time (minutes)

30Q N2 with gelled oil 40Q CO2 with gelled oil

29

2.3.2.3 Proppant Evaluation

One trend that was prevalent during fracture treatments was the correlation between ceramic

sand and screenouts. In Figure 2-7, ceramic sand is started on surface at point 8 and when it

reaches bottomhole (slightly before point 9), a rapid screenout occurs.

Although both the ceramic and white sands are compliant with API specifications to be qualified

as 30/50 size, a variance is seen (Figure 2-8). In general, the ceramic sand is larger with more

particles falling in the #40 sieve. Although there were no rapid changes is proppant

concentration, this larger effective size could have effectively plugged off in the already reduced

nearwellbore width and created a screenout.

A vertical well treated in the field also raised concerns about the quality of the proppant

manufacturing. Figure 2-9 shows the addition of ceramic sand at point 9 accompanied by a 6

MPa rapid pressure increase. This does not match the expected hydrostatic increase (1.7 MPa).

When the ceramic proppant reaches bottom, a screenout occurs.

One theory that was postulated (Conway, 2013) was that the rapid friction pressure increase was

caused by over cross-linking of the fluid. After examining of the chemical pumping charts, no

changes were made to chemical loading at this time. As the crosslinker in this particular fluid

system is aluminum based, an additional influx of aluminum from the addition of proppant is

suspected. This could happen if the ceramic was not fired or coated properly, creating free

aluminum particles.

30

Figure 2-7: Example of Ceramic Induced Screenout

Figure 2-8: Proppant Size Distribution of Proppants Used in Treatments

0

10

20

30

40

50

60

70

80

90

#20 #30 #40 #45 #50 #70 Pan

% M

ass Retained

30/50 White 30/50 Ceramic

31

Figure 2-9: Example of Unusual Pressure Response from Addition of Ceramic Sand

32

2.4 Conclusions

As a result of the lack of fracture placement success on the first four wells in the field, the

following changes were then recommended for subsequent treatments:

Mechanical failure was the result of screenouts on previous zones, therefore screenouts

should be avoided at all costs. The pump schedule should reduce the maximum

bottomhole concentration to 300 kg/m3 on the toe stages of the well, gradually increasing

to 500 kg/m3 on the heel stages. Also, smaller total proppant volumes were

recommended.

Much success was had in another field only two townships to the south with nitrogen as

an energizing system for gelled oil, whereas little placement success was had in Karr

using CO2. The CO2 based system appears to have inadequate fluid viscosity to

overcome near wellbore tortuosity. The recommendation was to switch energizers to

nitrogen.

Little success was had pumping ceramic proppant as well. The decision was made to

pump white sand exclusively on the subsequent treatments.

The evaluation of insufficient fracture placement can require a large data set and thinking beyond

paradigms to come up with root causes. The next chapter will incorporate the data learned on the

first four pilot horizontals (and two vertical wells) to properly calibrate a fracture model and

design the optimal stimulation for maximized production.

33

Hydraulic Fracturing Model Calibration Chapter Three:

3.1 GOHFER® Simulator

The hydraulic fracturing simulator chosen was GOHFER® which stands for Grid Oriented

Hydraulic Fracture Extension Replicator. GOHFER® utilizes a grid structure which allows for

vertical and lateral variations in both rock and fluid properties. It is a fully coupled fluid and

solid transport simulator which accounts for both elastic rock displacement calculations as well

as a planar finite difference grid for the fluid flow solutions. The model is also backed by 15

years of laboratory research in all major areas of transport and mechanics as well as 30 years of

research into proppant conductivity and placement. Unlike other models available in industry,

all formulation is publicly available for peer review and discretion, and the modeller can easily

make modifications given input and diagnostic data. The strength of this model was the reason

why it was chosen to be used in this research.

3.2 Log Input and Processing

A vertical well was drilled in the field in 2011 and completed in Cretaceous target intervals

above the Montney. This well was logged with a complete set of open hole logs prior to

cementing and casing the intervals. These logs were used to input into the simulator.

Two intervals were identified for completion inside the Middle Montney (Figure 3-1). The

lower interval (2586-2601m) is in a slightly more dolomitic interval with an average of 6%

porosity. The upper interval (2553-2564 m) is more quartz rich with lower porosities of 3%.

The logs that are input into the simulator are used to create grids to simulate fracture

propagation.

This chapter will be used to describe the changes made to the model to generate the knowns

about fracture geometry from given diagnostic tests.

34

propagation.

Figure 3-1: Log Data for Vertical Well

35

3.3 Fracture Geometry and Reservoir Parameter Determination

3.3.1 Diagnostic Fracture Injection Test

A diagnostic fracture injection test (DFIT) is a test done pre-treatment involving pumping a

small volume of fluid to simulate a pressure pulse in the reservoir. The fracture behaviour

during shut-in and leak-off is governed by fluid loss characteristics and material balance

relations. Work done in the 1970s (Nolte, 1979) provides solutions to basic decline analysis and

provides critical information pertaining to both fracture and reservoir performance.

With the increase in profile of unconventional gas wells, the method was refined in the 2000s

(R.D. Barree, 2007) and many of those methodologies are worked into the diagnostic package in

the GOHFER® software.

In the case of the subject well, a DFIT was performed on the upper section of the Montney

perforated from 2553 – 2564 mTVD. Approximately 15 m3 of 830 kg/m3 refined oil was

injected at 3 m3/min. The well was then shut-in and pressure was monitored for 2 hours until

closure was seen (Figure 3-2).

36

Figure 3-2: Diagnostic Fracture Injection Test

The only way to ensure a good number for fracture closure pressure is to validate with three

distinct plots: the G-function, square-root time, and log-log.

37

3.3.1.1 G-function Analysis

The G-function was created to incorporate both the material balance relation and the fracture

compliance relation into a mathematical description of the pressure during the fracture closing

period (Nolte, 1979). The G-function is a dimensionless function of shut-in time normalized to

pumping time. Application of the G-function is similar to the Horner analysis used for

conventional well tests. The G-function can be used to estimate pore pressure and permeability,

detect the presence of natural fractures, and determine the leakoff mechanism and magnitude.

Fracture closure is identified as the departure of the semi-log derivative of pressure with respect

to G-function from the straight line through the origin (Figure 3-3). This is an example of

moderate pressure dependent leakoff (PDL). Pressure dependent leakoff occurs when the fluid

loss rate changes with pore pressure or net effective stress in the rock surrounding the fracture.

The fluid loss rate is dominated by some change in transmissibility of the reservoir fissure or

fracture system. It is also an indication of a composite dual-permeability reservoir. An

indication of PDL in a tight gas siltstone such as the Montney is a good indication of secondary

permeability contributing to production.

The total main fracture closure stress is identified as 38.0 MPa at a G-time of 2.603. The fissure

opening pressure is 38.6 MPa at G = 2.346. The fissure opening pressure is clearly indicated by

the sharp break in the pressure derivative curve. This break also corresponds to the end of the

“hump” on the semi-log derivative curve, following which the pressure becomes linear with G.

This early-time hump above the extrapolated straight-line on the superposition curve, along with

the sharply curving pressure derivative, is a clear signature of pressure dependent leakoff. After

fissure closure, the pressure derivative is constant, and the superposition curve (semi-log

derivative) is linear (constant slope), both indicating constant leakoff coefficient.

38

Figure 3-3: G-function plot

Since there is a relationship between G-function and flow rate, it is reasonable to expect a

correlation between permeability and G-function. An equation (

Figure 3-4) has been empirically derived to yield a good estimate for permeability when after-

closure radial flow data is unavailable (Barree, Barree, & Craig, 2007). In this case, the

permeability was found to be 0.008 md.

0.0086 0.01 .

0.038

.

k=effective perm, md ct=total compressibility, 1/psi =viscosity, cp Pz=process zone stress(psi) =porosity, fraction E=Young’s modulus, (106 psi) rp=leakoff height to gross frac height ratio

Figure 3-4: Permeability Estimate from G at Closure

39

3.3.1.2 Square-Root Time Analysis

The square-root time plot, or sqrt(t), has frequently been misinterpreted when determining

fracture closure. Some analysts will improperly pick closure where the primary well pressure vs.

sqrt(t) curve deviates from the straight line trend, similar to the G-function methodology.

However, the proper method is to pick the inflection point on the plot (Figure 3-5), which in this

case corresponds to the G-function pick of 38 MPa.

Figure 3-5: Square-Root Time Plot

3.3.1.3 Log-log Analysis

The log-log analysis is shown in Figure 3-6. The normal matrix leakoff period appears as a

perfect ½ slope of the semilog derivative with a parallel pressure difference curve exactly 2-

times the magnitude of the derivative. This parallel trend ends at the previously identified

closure time and pressure of 38 MPa.

40

In this example, a well-defined -½ slope is shown shortly after closure indicating a reservoir

pseudolinear flow period. The after closure analysis (ACA) plot is shown in Figure 3-7 yielding

a reservoir pore pressure of 27.8 MPa (10.9 kPa/m) which is in line with well test analysis of

offsetting wells in the study area.

Radial flow is not seen in this example and therefore additional ACA analysis cannot be

performed.

Figure 3-6: Log-log analysis plot

41

Figure 3-7: After Closure Analysis: Linear Flow

3.3.1.4 PDL Analysis

By correctly identifying the end of pressure-dependent leakoff behaviour in the G-function

analysis (Figure 3-3), one can determine both critical fissure opening pressure (CFOP) and

coefficient for PDL, both of which are inputs to the GOHFER® model. During the pressure-

dependent leakoff phase of closure, the observed magnitude of the pressure derivative (dP/dG) is

an indication of the relationship between leakoff coefficient and pressure. The CFOP is

determined from the end of pressure-dependent behaviour and is 0.223 in this case. The plot of

effective leakoff coefficient at any pressure (Cp) divided by the stabilized constant leakoff after

fissure closure (Co) can be made as a function of pressure differential above the CFOP. (Figure

3-8) The ratio of Cp/Co vs dP when plotted will yield a slope that is the coefficient of pressure

dependent leakoff, or 1.148E-4 in this case.

42

Figure 3-8: PDL Analysis

43

3.3.2 Tracer Log

The most important factor that drives fracture propagation is the total stress grid. If the fracture

treatment that was pumped in the lower interval of the well shown in Figure 3-1 was simulated

given the default grids, even after the knowledge gained from the DFIT, the resultant fracture

44

would be 90 m high (

Figure 3-9). Similarly, the treatment pumped into the upper interval would result in a 97 m frac

height, as shown in Figure 3-10.

45

Most unconventional gas plays begin with vertical exploration wells but quickly change to

horizontal wells without time and care taken to extract the most information out of the vertical

well. One of these critical pieces of information is fracture height growth. This can be used to

design the ultimate fracture treatment and also to determine the need for infill drilling and well

placement. While this information can be calculated from microseismic, it is the author’s

opinion that radioactive tracer is the best source of determining fracture height close to the

wellbore. One of the limitations of the technology is that the radius of investigation of the tools

is only a maximum of 45 cm around the wellbore.

Radioactive tracer can be run in the proppant stages of the treatment such that when the well is

logged post-fracture, the near wellbore fracture height can be determined. Results from the

subject well (Figure 3-11) and another well fractured in the Lower Middle Montney (Figure

3-12) are shown below. The Lower interval in the subject well was fracced and traced.

However it was not perforated in the optimal site because of a downhole fish preventing the

perforation guns from running in to the desired depth. From these results, one can see that the

fracture treatments stay very restricted in the interval of interest ranging from a frac height of

approximately 25 m in both intervals which is much different from the original model

assumptions.

46

Figure 3-9: Proppant Concentration Grids Showing Anticipated Fracture Height from

Upper Middle Montney Perforations with Original Stress Profile

47

Figure 3-10: Proppant Concentration Grids Showing Anticipated Fracture Height from

Lower Middle Montney Perforations with Original Stress Profile

48

Figure 3-11: Radioactive Tracer Showing Fracture Height (Upper Middle Montney)

49

Figure 3-12: Radioactive Tracer Log Showing Fracture Height (Lower Middle Montney)

50

One theory as to why there is a difference between simulated and actual fracture height is the

presence of bedding and bed boundaries in the Montney. Changes in brittle-ductile bedding may

result in a slip plane that restricts fracture growth upwards. Regardless, the data shows that the

fractures are staying restricted and thus the strain component in the model was adjusted to

account for this.

After all the changes are made, the model is then run with the pumping parameters of the actual

job. The resultant proppant concentration diagrams are shown in Figure 3-13 and Figure 3-14.

3.4 Production Model Calibration

3.4.1 Flow Test Calibration

The intervals were individually tested for a 48 hour period after fracture cleanup (Figure 3-15

and Figure 3-16). These initial rates were compared to the GOHFER anticipated production

after the fracture treatment was simulated. The results of the expected production are shown in

Figure 3-17 and Figure 3-18. The x’s denoted on the graph indicate the results from the 48 hour

flow test and indicate a good match.

It should be noted that initial flow tests are not often a good indicator of ultimate production,

specifically in horizontal wells with uncertain lateral placement (Taylor, 2011). However, there

are very few wells in the area with long-term typable production. Further refinement will have

to be done to the model when this production data becomes available.

3.4.2 Build-up Analysis

Following the fracture treatment, gauges were run isolating the individual zones and a flow and

buildup was performed. There is evidence in the completion that communication was occurring

between the 2 intervals and therefore, the analyst chose to treat them as one interval. The results

51

Figure 3-13: Proppant Concentration Grid of UMM Stimulation

Figure 3-14: Proppant Concentration Grid of LMM Stimulation

52

Figure 3-15: Flow Test for Lower Interval

Figure 3-16: Flow Test for Upper Interval

53

Figure 3-17: Expected Production From GOHFER for LMM zone

Figure 3-18: Expected Production from GOHFER for UMM zone

54

Table 3-1: Comparison of Reservoir Characteristics from PTA Analysis and GOHFER®

Reservoir Characteristics Results from

PTA Analysis

Results from

GOHFER (UMM)

Results from

GOHFER (LMM)

Permeability to Gas (k) 0.006 md 0.008 md n/a

Fracture Conductivity 0.29 mD-m 3.4 mD-m 8.9 mD-m

Flowing Fracture Half

Length (xf)

23.0 m 10.3 m 13.9 m

Net Pay (h) 31.8 m 47.0 m 26.0 m

are presented in Table 3-1 and compared with the results that the fracture model showed from the

individual zones.

It is encouraging to see that the permeability as calculated from the PTA analysis and from

GOHFER are relatively similar, indicating a true match.

The difference between the PTA fracture length and the flowing dynamic length as calculated by

GOHFER is common. The length as calculated from PTA relates to the length of time that the

reservoir remains in pseudo-linear flow. This reservoir transient exists outside the actual created

fracture which is why the fracture length is longer than what is calculated from GOHFER.

The GOHFER model also assumed a condensate yield of 1000 m3/e6m3 whereas the PTA model

assumed only gas was flowing. Therefore, in order to yield the same flow rates, the conductivity

from GOHFER would have to be higher to facilitate the flow of both liquids and gas.

55

Although the process of model refinement is continual as new data becomes available, this

model was chosen to move forward in designing a new approach for the next set of horizontal

wells.

3.5 Horizontal Well E

3.5.1 Design and Execution

Given the placement issues that were outlined in Chapter 2, several changes were made to the

standard design to ensure fracture placement. The CO2 energized gelled oil system was

abandoned in favour of nitrogen given the issues related to viscosity with CO2. With the ceramic

proppant quality in question, only natural sand was planned for, with a reduced grain size of

40/70 as opposed to 30/50. As well, maximum bottomhole sand concentrations were limited to

300 kg/m3 in the toe third of the well, 400 kg/m3 in the middle third of the well and 500 kg/m3 in

the heel third of the well. Job sizes were also staged 40, 45, and 50 tonnes of sand respectively.

The job was pumped successfully placing all designed proppant in the formation with no

apparent width restrictions. Average treating pressures were on the order of 42 MPa.

Another interesting phenomenon that was observed is highlighted in Figure 3-19. The point

annotated “1” illustrates where the 70/140 mesh scour sand would enter the formation. In the

previous 4 wells discussed in Chapter 2, this occurrence would result in a pressure drop on

average of 5 MPa indicating the opening up of some tortuous path. There is no apparent drop

associated at this point on the treatment in Well E. The lack of width restriction in this situation

is further evidence that the previous placement issues were fluid related and not formation

related.

This is duplicated on all stages except the first stage where a pressure increase and subsequent

decrease is observed (Figure 3-20). It is postulated that this may be associated with cleaning the

56

wellbore of some sort of drilling related debris as this is not observed on any other stages. The

author is familiar with anecdotal evidence of operators performing a “junk frac” on the toe stage

of the well to rid the well of drilling related debris.

Figure 3-19: Example of Treatment Pressures from Horizontal Well E

1

57

Figure 3-20: Treating Pressures on First Zone from Horizontal Well E

1

58

3.5.2 Well Results

The initial well production is plotted in Figure 3-21 along with GOHFER expected production.

This is assuming that all 22 stages of the 2500 m lateral are contributing in equal amounts. The

modelled production is shown as being higher than the actual production. That is because the

model operates under the invalid assumption that all stages contribute equally.

There are several reasons why all stimulated stages may not be contributing equally. The first

reason is that there could have been fracture communication behind the packer, resulting in a

missed stimulation opportunity and multiple stimulations into the same transverse fracture

network. This will be discussed further in Section 3.8.

The second reason why not all stages contribute equally has to do with flowback practice. Much

work has been presented in recent years considering the physical similarities between flowback

and waterflooding practices (Crafton, 2008). Much like the issue of water coning, a very

aggressive flowback could create preferential pathways (or fracture systems) which would in

turn choke out other stages from contributing.

The third reason is a mechanical one. Well D was brought on line with less than anticipated

flowing gas rates. The decision was made to mill out the frac ports and clean to bottom with coil

to free any obstructions. The production did not improve after this operation. Both a caliper log

and production log were run. The caliper log showed that some of the ports had closed and the

production log validated that these ports were not contributing. In this situation, 7 stages of 21

were shown to be ineffective.

59

Another reason for the performance differences is the variability in petrophysical parameters

evidenced by horizontal logs run on laterals in the field. It has been observed that permeability

can vary on an order of magnitude. The production model shown here assumes that each

transverse fracture initiated is in the same qualiry of rock.

Regardless of the reason for poor production performance, the assumption was made that

roughly 30% of the transverse fractures were not contributing. The results are shown in Figure

3-22 and show a much better fit between the modelled and actual production.

Figure 3-21: Modelled vs. Actual Production for Well E, assuming 22 stages contributing

60

3.6 Horizontal Well F


With a successful fracture placement executed on Well E, a similar type of job was designed for

the next completion in the field. Once again, concentrations were held to 300-500 kg/m3,

however job sizes were increased to 45, 55, and 56 tonnes of 40/70 sand divided evenly amongst

the 21 stages in the wellbore.

The job was pumped successfully placing all designed proppant in the formation with no

apparent width restrictions. Average treating pressures were on the order of 45 MPa.

3.6.2 Well Results

The expected well production is plotted in Figure 3-23 with the actual well production.

Assuming all stages are contributing, the modeled production is once again higher than the actual

Figure 3-22: Modelled vs. Actual Production for Well E, assuming 14 stages contributing

61

production. There is further evidence in this situation that not all zones are contributing equally

and this is shown in Figure 3-24.

A unique oil-based chemical tracer was injected into several intervals (Stages 1, 3, 5, 11, 17)

during the fracture treatment and then monitored on flowback. Initial flowback appears to come

from stages 11 and 17 which eventually decreases as zones 3 and 5 start contributing. This is

expected as the heel stages would unload quicker than the toe stages. No contribution has been

seen from stage 1 after two weeks of flowback. From this data, it is assumed that not all stages

are contributing equally and that as the well cleans up post-treatment, different stages will

contribute at different times.

Assuming a 60-70% contribution from all stages, the results of 13 transverse fractures

contributing are shown in Figure 3-25. A more suitable match is seen between the modelled and

actual production.

It should also be noted that Well E and F produced unanticipated water. The sources of this

produced water is discussed in Section 3.8.

62

Figure 3-23: Modelled vs. Actual Production for Well F, assuming 21 stages contributing

63

Figure 3-25: Modelled vs Actual Production for Well F, assuming 13 stages contributing

Figure 3-24: Chemical Tracer Results from Well F

64

3.7 Horizontal Well G


Little changes were made to the design for Well G. Stages 1-6 were stimulated with 55 tonnes of

proppant with a maximum of 400 kg/m3 and the remainder of the stages were treated with 65

tonnes and a maximum bottom hole concentration of 600 kg/m3. The job was pumped

successfully placing all designed proppant in the formation with no apparent width restrictions.

Average treating pressures were on the order of 40 MPa.

3.7.2 Well Results

The expected well production is plotted in Figure 3-26 with the actual well production. At the

time of publication of this thesis, less than a week’s worth of production data was available. It

should be noted that production is 25% higher in this example where water is not a nuisance.

Assuming a 60-70% contribution factor, the modelled production then matches the actual test

production as shown in Figure 3-27.

65

Figure 3-26: Modelled vs Actual Production for Well G, assuming all stages contributing

Figure 3-27: Modelled vs Actual Production for Well G, assuming 13 stages contributing

66

3.8 Investigation into Water Source

Wells E and F were both re-entries into the Middle Montney from wells that were previously

drilled in the Lower Montney. These Lower Montney wells produced appreciable gas for the

first several months before water production made the wells uneconomic. The initial thought

was that the fracture treatments performed in Wells E and F were propagating downwards into

the water-producing Lower Montney.

The most recent stimulations performed in the field also were accompanied by microseismic

mapping which brought to light an interesting phenomenon. Figure 3-28 shows a typical

microseismic response from a single zone fracture. The fracture is aligned along the expected

azimuth and contained in the zone of initiation. The microseismic dots are color coordinated to

the port that is being treated at the time.

Figure 3-28: Example of Typical Microseismic Response from Montney Stimulations

67

The following stages show something very different. (Figure 3-29). The uppermost stage

appears to initiate at the entry point in the completion. However, the events appearing in the

Doig are suspicious. The next stage (middle slide) has events centering at the same initiation

point as the previous stage with more events appearing higher in the section. The last stage

appears to be expanding on the fracture created during the first stage with even more events

higher in the section. It is suspected that packer isolation was an issue and that all three of these

treatments went into the same interval. This is further validated knowing that extreme dogleg

severity was experience over this particular area in the wellbore in order to accommodate

entering the Middle Montney from a pre-existing Lower Montney completion.

Another clue that the fracture did indeed propagate into the Upper Montney interval was

knowledge of perforating the Upper Montney (Figure 3-30) resulted in water production

accompanied with sour gas in another well in the field.

Figure 3-31 shows the impact of multiple fracturing treatments pumped into the same interval.

Note that with two simultaneous treatments into the same interval, the fracture propagates up

into the water bearing, sour Upper Montney formation.

The data is also tabulated in Table 3-2 and the production impact is shown in Figure 3-32. The

assumption was made that if the treatment stayed contained in the lower interval, no water would

be produced. If it would extend up into the Upper Montney, water production of 40 m3/e6scm

was assumed.

68

Figure 3-29: Multiple Fractures Propagating in Single Stage

69

Figure 3-30: Typical Karr Montney Well showing Upper and Middle Montney Sections

70

Figure 3-31: Proppant Concentration Grids for 55 Tonne frac in zone once (left), twice

(center) and three times (right)

Single 55T frac Double 55T frac Triple 55T frac

Flowing fracture length (m)

9.8 11.8 12.8

Fracture conductivity, Kfwf (md-m)

1.8 2.7 3.4

Fracture height (m) 27.0 67.0 67.0

Table 3-2: Comparison of Fracture Parameters for Multiple Treatments in Same Zone

Upper Montney

71

Figure 3-32: Production Impact of Multiple Fractures into Same Zone

The increase in production from a single fracture treatment to a double or triple treatment lies in

the extra net height that is exploited with bigger fracture treatments. It should be noted that

although the flowing fracture half-length and conductivity is greater in the triple frac case, it does

not improve production significantly.

Furthermore, the facilities in this area are capable of handling the sour gas and water production.

The only disadvantage of the sour gas production is that it makes it more difficult to recycle any

flowback oil for future treatments. Also, water production may facilitate the need for artificial

lift in the latter life of the well.

Therefore, the increase in production gained from the fracture growing up into the Upper

Montney, and exploiting the full height of the Middle Montney, far outweighs the detrimental

effects of gas and water production.

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

0 50 100 150 200 250 300 350 400

Cum. G

as (e6m3)

Days

single 55T frac double 55T frac triple 55T frac

72

3.9 Summary of Modelling Results

Critical pieces of data were gathered over the course of two vertical completions and three

horizontal completions and incorporated into a competent model. Geomechanical and reservoir

parameters were gathered from the DFIT test. Reservoir parameters were validated with a flow

and build-up test. The question of fracture height was confirmed by two radioactive tracer

studies. The parameters were then entered into the model and the actual jobs were executed and

matched to production data from isolated flow tests.

The model was then tested on three separate horizontal wells where all fracture treatments were

executed without issue. The important learning is that in these open-hole completion systems,

only 60-70% of zones appear to contribute to production. The limiting factors were discussed

and a source of water was identified. Taking this into consideration, the model was proven three

times to be effective in predicting ultimate gas rates.

Lastly, a source of water was identified when multiple fracture treatments were pumped into the

same interval. As production facilities are capable of handling the water produced and it does

not impact gas production significantly, it is not necessary to avoid fracturing into the Upper

Montney.

The next step in the design process is to change fracturing parameters and determine the

optimum completion to yield the highest hydrocarbon rates.

73

Fracture and Completion Optimization Chapter Four:

4.1 Optimization of a Single Fracture Assuming 0.008 md Permeability

4.1.1 Fluid considerations

The fluid of choice for the completions done in the field to date has been gelled oil with either

carbon dioxide or nitrogen as an energizer. As referenced in Chapter 2, the gelled oil with CO2

was proven to be ineffective. Early regained permeability work done illustrates that the Montney

can be fluid sensitive (Taylor, 2010) and that hydrocarbon based fluids were recommended.

Using core from the Karr area, a regained permeability test was carried out using three separate

fluids. The fluids were chosen based on other operators in the area. The first fluid tested was a

50 quality gelled oil system with CO2, similar to what was pumped on Wells A-D. The second

fluid was a 85 quality gelled water system with CO2. The third fluid was a simple slickwater

fluid, or water with friction reducer. The results are shown in Figure 4-1 at varying drawdown

pressures.

The best performing fluid was the gelled oil system with a regained permeability of 91.6% at

maximum drawdown pressure. The foamed water system exhibited a 84.5% regained

permeability while the slickwater yielded 35.6%.

These fluids were all then loaded into the calibrated GOHFER simulator assuming a consistent

55 tonne treatment with 40/70 sand pumped at 5 m3/min and a maximum bottomhole

concentration of 500 kg/m3, similar to what was pumped in Well G. The production results are

shown in Figure 4-2. The foamed water modelled was a 85 quality viscoelastic surfactant (VES)

system.

74

Figure 4-1: Regained Permeability Testing Results

Figure 4-2: Comparison of Fluid Performance for 55 tonne Treatment for 0.008 md

Permeability Case

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

0 50 100 150 200 250 300 350 400

Cum. G

as (e6m3)

Days

Energized Gelled Oil VES Foam Slickwater

75

The foamed water outperforms both the slickwater and gelled oil systems by over four times.

This can be explained by evaluating the fracture geometry and conductivities created by each

treatment, as shown below in Table 4-1.

55 tonne Gelled Oil 55 tonne VES foam 55 tonne Slickwater


9.8 7.4 13.2


1.8 2.1 6.1


Table 4-1: Comparing Fracture Flow Parameters for Fluid Optimization Run for 0.008

md Permeability Case

It should also be noted that because the VES foam created a fracture height capable of contacting

the wet Upper Montney, a water production impairment of 40 m3/e6m3 was implemented. Even

after taking this into account, the VES fluid outperforms the others.

The main difference between the VES foam and the other two fluids is the fracture height

created. To understand the cause of the increased fracture height with VES fluids, one must

examine the leak-off properties of both fluids as shown in Figure 4-3.

The major difference is that the VES fluid simply leaks off at a faster rate than the gelled oil

(which also explains the shorter half-lengths with the less efficient VES fluid). As the fluid is

travelling down the created fracture plane, it leaks off at such a rate that it does not reach the

extent that the gelled oil fluid would, with the lower leak-off. Therefore, because the fluid

cannot travel down the length of the fracture before depleting, it becomes more efficient for the

fluid to travel up and create fracture height.

76

Now while the leak-off for the slickwater fluid is greater than both the gelled oil and VES foam,

the viscosity is not adequate enough to create the pressure necessary to create fracture height

growth. The proppant concentration grids for each of these scenarios is shown in Figure 4-4.

Figure 4-3: Comparison of Leakoff Properties of Gelled Oil (right), VES Foam (center),

Slickwater (right) Fluids

77

Figure 4-4: Comparison of Fracture Geometries of Gelled Oil (left), VES Foam (center),

Slickwater (right) Fluids for 0.008 md Permeability Case

Although the fracture length is effectively shorter for the VES fluid, the increased height does

access more of the Montney pay, thus leading to the increase in expected production. Using the

VES foam as the fluid of choice, further optimizations are outlined in the next sections.

4.1.2 Proppant Selection

As discovered in Section 3.3.1, the bottomhole closure pressure was found to be 38 MPa or 5511

psi. A general rule of thumb in proppant selection is that crushing becomes detrimental for silica

based proppants (sands) at anything over 5000 psi (Figure 4-5). Therefore, both proppant sizes

and different proppant materials were tested at a consistent job size, pump rate, and pump

schedule. The results are presented in Figure 4-6.

78

Figure 4-5: Proppant Conductivity of 20/40 Jordan Sand (left) and 20/40 Ceramic (right)

with Stress

79

Figure 4-6: Comparison of Proppant Type for 55 Tonne Treatment for 0.008 md

Permeability Case

It appears from Figure 4-6 that 20/40 ceramic proppant is the best proppant for this application.

Note that the 30/50 sand, 20/40 sand, and 30/50 resin-coated all share similar production profiles

and the curves overlay each other in Figure 4-6. The reason for the similarities is illustrated in

Table 4-2 as all three of those proppants result in very similar flowing fracture lengths and

fracture conductivities. There is a noticeable improvement on both flowing fracture lengths and

conductivity in the ceramic proppants over the sand or resin-coated. This is due to the difference

in static proppant conductivity between sand (380 md-m for 20/40 size) vs. ceramic proppant

(1300 md-m for 20/40 size) at the found closure pressure of 38 MPa (Figure 4-5). It should be

noted that the static proppant conductivity as is reported here is based on dry proppant tested in a

crush cell. The fracture conductivity as reported in Table 4-2 is much lower as this is a dynamic

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

0 50 100 150 200 250 300 350 400

Cum. G

as (e6m3)

Days

40/70 Sand 30/50 Sand 20/40 Sand

30/50 RC 30/50 Ceramic 20/40 Ceramic

80

number which changes over time as a result of fracture clean-up and pressure drops associated

with non-Darcy and multiphase flow effects.

A brief discussion on the detrimental effects of ceramic proppant to fluid stability was discussed

in Chapter 2 (Section 2.3.2.3). The effect described there was a function of the gelled oil

chemistry and it is not anticipated to interfere with the VES chemistry in the same way.

Therefore, the subsequent optimizations will assume 20/40 ceramic proppant.

40/70

Sand

30/50

Sand

20/40

Sand

30/50

Resin

Coated

30/50

Ceramic

20/40

Ceramic


7.3 9.7 9.7 9.6 14.3 16.0


2.0 4.3 4.3 4.1 11.7 15.9

Table 4-2: Comparing Fracture Flow Parameters for Proppant Optimization Run for

0.008 md Permeability Case

4.1.3 Job Size

The next factor to optimize was job size. For the purposes of this investigation, the maximum

bottomhole concentration was held at 400 kg/m3 and the pump rate was 5 m3/min, which is

similar to the design utilized in Wells E-G. The job size was altered proportionally, meaning that

a 50 tonne job would be exactly twice the volumes at each stage as a 25 tonne job and so on.

The results are shown in Figure 4-7 below.

81

Figure 4-7: Comparison of Job Size for 0.008 md Permeability Case

The important thing to observe from this chart is the rate of improvement as the job size gets

bigger. It appears as though the point of diminishing returns is around the 50 tonne mark.

25 tonnes 50 tonnes 75 tonnes 100 tonnes


13.7 15.9 16.9 17.8


16.4 15.4 17.6 17.4

Fracture height (m) 83.0 96.0 96.0 96.0

Table 4-3: Comparing Fracture Flow Parameters for Job Size Optimization Run for 0.008

md Permeability Case

The increases in gas recovery from the 25 tonnes to 50 tonnes scenario is due to additional

fracture height which accesses the entire Montney pay, as well as additional flowing fracture

0

1

2

3

4

5

6

0 50 100 150 200 250 300 350 400

Cum. Gas (e6m3)

Days

25 tonne 50 tonne 75 tonne 100 tonne

82

length. Although additional flowing fracture length and conductivity are seen in the 75 tonne

and 100 tonne scenarios, the increase in gas volumes are insignificant. The 50 tonne schedule

will be the new base case for further optimizations.

4.1.4 Pumping rate

Using the 50 tonne schedule with the VES foam fluid, several different models were run on

varying pump rate. The base case was 5 m3/min and the results of the model are shown in Figure

4-8 and Table 4-4 below.

Figure 4-8: Comparison of Pumping Rate for 0.008 md Permeability Case

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

0 50 100 150 200 250 300 350 400

Cum. G

as (e6m3)

Days

3 m3/min 5 m3/min 7 m3/min

83


Flowing fracture length (m) 15.5 15.9 15.3

Fracture conductivity, Kfwf (md-m) 8.2 15.4 14.2


Table 4-4: Comparing Fracture Flow Parameters for Pump Rate Optimization Run for

0.008 md Permeability Case

The lower rate of 3 m3/min does not achieve adequate proppant coverage into the upper portion

of the Montney pay zone as illustrated in Figure 4-9. The higher rate of 7 m3/min achieves very

similar results to the rate of 5 m3/min. Since additional rate means additional horsepower

charges, it was decided that 5 m3/min is the optimum rate for further model runs.

Figure 4-9: Comparison of Proppant Concentration Grids for 3 m3/min (left), 5 m3/min

(centre), and 7 m3/min (right) for 0.008 md Permeability Case

84

4.1.5 Maximum Concentration and Total Fluid Volume

The maximum bottomhole concentration of proppant is directly related to the total fluid volume

pumped in that higher concentrations require less fluid to place. For the purposes of this

optimization, each run was staged proportionally. For example, the 400 kg/m3 schedule used

twice as much fluid as the 800 kg/m3 and each stage was proportionally the same. The

production results are shown in Figure 4-10.

It should be noted that placing concentrations higher than 800 kg/m3 presented a screenout risk

and were not considered for this optimization run.

Figure 4-10: Comparison of Maximum Concentration for 0.008 md Permeability Case

From this analysis, there is a point of limiting returns around the 400 kg/m3 maximum

bottomhole concentration mark. This is explained by examining the fracture flow parameters in

Table 4-5 and the proppant concentration grids in Figure 4-11.

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

0 50 100 150 200 250 300 350 400

Cum. Gas (e6m3)

Days

200 kg/m3 400 kg/m3 600 kg/m3 800 kg/m3

85

The larger sand concentrations result in longer flowing fracture lengths and also higher fracture

conductivities. It appears that the conductivities are above what is deemed necessary for the

reservoir permeability, and are therefore not leading to any additional production. It also does

not create as much height to fracture into the wet Upper Montney. Since less fluid is used on the

800 kg/m3 scenario, and therefore less costs, this is the recommended bottomhole concentration

for the subsequent runs.

200 kg/m3 400 kg/m3 600 kg/m3 800 kg/m3

Total Injected Volume (m3) 544.0 272.0 204.0 136.0

Flowing fracture length (m) 12.5 15.0 17.8 17.8


4.2 15.4 24.0 32.2


Table 4-5: Comparing Fracture Flow Parameters for Maximum Concentration

Optimization Run for 0.008 md Permeability Case

86

Figure 4-11: Comparison of Proppant Concentration Grids for 200 (l), 400 (m), 800 (r)

kg/m3 Bottomhole Concentration for 0.008 md Permeability Case

4.1.6 Pad Percentage

The pad stage is defined as the initial fluid pumped into the reservoir to initiate the hydraulic

fracture. The pad must create sufficient volume such that all subsequent sand can be injected

without the fluid leaking off and the fracture closing, leading to premature screenout. Therefore,

it is also a function of fluid efficiency.

The current base case design has a pad of 36 m3 for a total fluid volume (minus wellbore flush)

of 136.0 m3. This is a pad percentage of 27%. Different fluid volumes were tested and the

resultant production profiles are plotted in Figure 4-12.

87

Figure 4-12: Comparison of Pad Size for 0.008 md Permeability Case

It appears that altering the pad size of the treatment does not affect the outcome of the treatment.

Therefore, in order to minimize fluid volumes and save on fluid costs, a 25 m3 pad is

recommended.

4.1.7 Optimum Treatment for Single Fracture: Conclusion

Based on the previous analysis, the optimum fracture treatment is 50 tonnes of 20/40 ceramic

proppant in a foamed surfactant system with a maximum bottomhole concentration of 800 kg/m3,

pad volume of 25 m3, and a pump rate of 5 m3/min.

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

0 50 100 150 200 250 300 350 400

Cum. Gas (e6m3)

Days

25 m3 pad 36 m3 pad 45 m3 pad

88

4.2 Optimization of a Horizontal Well Assuming 0.008 md Permeability

With the optimization of a single fracture complete, it is now possible to optimize on fracture

spacing. Figure 4-13 shows the case of a horizontal well and multiple fracture spacing scenarios.

The point of diminishing returns is less than 40 m, making 40 m the optimum fracture spacing

for a horizontal well.

Figure 4-13: Fracture Spacing Optimization for 0.008 md Permeability Case

0

20

40

60

80

100

120

140

160

10 100 1000

1 Year Cum. P

roduction (e6m3)

Fracture Spacing (m)

89

4.3 Optimization of a Single Fracture Assuming 0.08 md Permeability

Horizontal logging results on recent wells drilled have shown a variance in permeability of up to

10 times that which was observed in the previous wells discussed in Chapter 2. This next

analysis will test if the ultimate fracture design is impacted by a magnitude change in

permeability.

4.3.1 Fluid considerations

The same fluids that were considered in 4.1.1 will be also considered for this analysis. The base

case pump schedule is based on the schedule executed for Well G (55 tonne treatment with 40/70

sand pumped at 5 m3/min and a maximum bottomhole concentration of 500 kg/m3). The


Figure 4-14: Comparison of Fluid Performance for 55 Tonne Treatment, 0.08 md case

0

2

4

6

8

10

12

14

16

0 50 100 150 200 250 300 350 400

Cum. G

as (e6m3)

Days

Energized Gelled Oil VES Foam Slickwater

90

The foamed water outperforms both the slickwater and gelled oil systems. This can be explained

by evaluating the fracture geometry and conductivities created by each treatment, as shown

below in Table 4-1.

55 tonne Gelled Oil 55 tonne VES foam 55 tonne Slickwater


21.0 23.8 30.1


1.9 5.0 6.9


Table 4-6: Comparing Fracture Flow Parameters for Fluid Optimization Run, 0.08 md

case

The main difference between the VES foam and the other two fluids is the fracture height

created. This principle was discussed in 4.1.1 and is illustrated in Figure 4-15.

Figure 4-15: Comparison of Fracture Geometries of Gelled Oil (left), VES Foam (center),

Slickwater (right) Fluids for 0.08 md case

91

It should also be noted that because the VES foam created a fracture height capable of contacting

the wet Upper Montney, a water production impairment of 40 m3/e6m3 was implemented. Even

with this perceived impairment, the VES fluid outperforms the others.

Although the slickwater treatment yields a longer flowing fracture half length and greater

conductivity, the exploited height is not as great as the VES fluid. It is also noted that the

flowing half-lengths and conductivities are also greater in this case than in the lower

permeability case (refer to Table 4-1). This is because the reservoir deliverability in this second

case is much greater.

The VES foam is the fluid of choice and will be used for subsequent optimizations.

4.3.2 Proppant Selection

The same proppants as were tested in 4.1.2 are tested for the higher permeability case following

the same methodology. The results are shown below in Figure 4-16.

Figure 4-16: Comparison of Proppant Type for 55 Tonne Treatment, 0.08 md case

0

2

4

6

8

10

12

14

0 50 100 150 200 250 300 350 400

Cum. G

as (e6m3)

Days

40/70 Sand 30/50 Sand 20/40 Sand

30/50 RC 30/50 Econo 20/40 Econo

92

It may be difficult to tell in this graph, but the resin coated and silica based sands are overlying

each other on the bottom curve. The ceramics are the upper curve. The data is presented below

in Table 4-7.

40/70

Sand

30/50

Sand

20/40

Sand

30/50

Resin

Coated

30/50

Ceramic

20/40

Ceramic


23.8 23.2 23.2 22.9 33.1 36.6


5.0 4.7 4.8 4.5 13.5 18.7

Table 4-7: Comparing Fracture Flow Parameters for Proppant Optimization Run, 0.08

md case

The flowing fracture half-lengths and conductivities are similar for the sand and resin coated

proppant, yet a marked increase is seen in the ceramic proppants. This would indicate that there

is some level of proppant crushing and degradation at this depth and stress.

The fact that there is very little difference in performance as a result of proppant size is a

function of the reservoir deliverability. Therefore, 20/40 ceramic will be used as the choice

proppant in subsequent optimization runs.

4.3.3 Job Size

The next factor to optimize was job size. For the purposes of this investigation, the maximum

bottomhole concentration was held at 400 kg/m3 and the pump rate was 5 m3/min, which is

similar to the design utilized in Wells E-G. The job size was altered proportionally, meaning that

a 50 tonne job would be exactly twice the volumes at each stage as a 25 tonne job and so on.

The results are shown in Figure 4-17 below.

93

Figure 4-17: Comparison of Job Size, 0.08 md case

It is important to note that there is no additional benefit to pumping a job larger than 50 tonnes.

This can be explained by examining the fracture characteristics in Table 4-8.

25 tonnes 50 tonnes 75 tonnes 100 tonnes


28.5 36.6 39.5 42.4


16.6 18.0 19.8 21.4


Table 4-8: Comparing Fracture Flow Parameters for Job Size Optimization Run, 0.08 md

case

0

2

4

6

8

10

12

14

16

0 50 100 150 200 250 300 350 400

Cum. Gas (e6m3)

Days

25 tonne 50 tonne 75 tonne 100 tonne

94

There appears to be no additional production gain from a job size larger than 50 tonnes. It

achieves coverage across the entire pay with a sufficiently long and conductive fracture.

Therefore, it will be used in optimizations from this point forward.

4.3.4 Pumping rate

The next parameter to test was pumping rate. The results are shown in Figure 4-18 below.

Figure 4-18: Comparison of Pumping Rate, 0.08 md case

There is no additional production benefit in pumping at rates higher than 5 m3/min. In fact, as is

witnessed in Table 4-9, the conductivity and flowing length of the 7 m3/min case is less than that

of the 5 m3/min. This is because sand will be dispersed further away from the wellbore in lower

concentrations.

The next optimizations will be carried out with 5 m3/min as the optimum rate.

0

2

4

6

8

10

12

14

16

0 50 100 150 200 250 300 350 400

Cum. Gas (e6m3)

Days


95


Flowing fracture length (m) 35.4 36.6 35.5

Fracture conductivity, Kfwf (md-m) 15.0 18.0 16.4


Table 4-9: Comparing Fracture Flow Parameters for Pump Rate Optimization Run, 0.08

md case

4.3.5 Maximum Concentration and Total Fluid Volume

The maximum bottomhole concentration of proppant is directly related to the total fluid volume

pumped in that higher concentrations require less fluid to place. For the purposes of this

optimization, each run was staged proportionally. For example, the 400 kg/m3 schedule used

twice as much fluid as the 800 kg/m3 and each stage was proportionally the same. The


It should be noted that placing concentrations higher than 800 kg/m3 presented a screenout risk

and were not considered for this optimization run.

From this analysis, there is a point of limiting returns around the 400 kg/m3 maximum

bottomhole concentration mark. This is explained by examining the fracture flow parameters in

Table 4-10 and the proppant concentration grids in Figure 4-20.

The larger sand concentrations result in longer flowing fracture lengths and also higher fracture

conductivities. It appears that the conductivities are above what is deemed necessary for the

reservoir permeability, and are therefore not leading to any additional production. It also does

not create as much height to fracture into the wet Upper Montney. Since less fluid is used on the

96

800 kg/m3 scenario, and therefore less costs, this is the recommended bottomhole concentration

for the subsequent runs.

Figure 4-19: Comparison of Maximum Concentration , 0.08 md case

200 kg/m3 400 kg/m3 600 kg/m3 800 kg/m3

Total Injected Volume (m3) 544.0 272.0 204.0 136.0

Flowing fracture length (m) 31.2 35.7 40.1 36.1


9.0 18.0 26.3 30.7


Table 4-10: Comparing Fracture Flow Parameters for Maximum Concentration

Optimization Run, 0.08 md case

0

2

4

6

8

10

12

14

0 50 100 150 200 250 300 350 400

Cum. G

as (e6m3)

Days

200 kg/m3 400 kg/m3 600 kg/m3 800 kg/m3

97

Figure 4-20: Comparison of Proppant Concentration Grids for 200 (l), 400 (m), 800 (r)

kg/m3 Bottomhole Concentration, 0.08 md Case

4.3.6 Pad Percentage

The current base case design has a pad of 36 m3 for a total fluid volume (minus wellbore flush)

of 136.0 m3. This is a pad percentage of 27%. Different fluid volumes were tested and the

resultant production profiles are plotted in Figure 4-21.

It appears that altering the pad size of the treatment does not affect the outcome of the treatment.

Therefore, in order to minimize fluid volumes and save on fluid costs, a 25 m3 pad is

recommended.

98

Figure 4-21: Comparison of Pad Size, 0.08 md Case

4.3.7 Optimum Treatment for Single Fracture: Conclusion

As was the situation with the 0.008 md case, the optimum fracture treatment is 50 tonnes of

20/40 ceramic proppant in a foamed surfactant system with a maximum bottomhole

concentration of 800 kg/m3, pad volume of 25 m3, and a pump rate of 5 m3/min.

0

2

4

6

8

10

12

14

0 50 100 150 200 250 300 350 400

Cum. Gas (e6m

3)

Days

25 m3 pad 36 m3 pad 45 m3 pad

99

4.4 Optimization of a Horizontal Well Assuming 0.08 md case

With the optimization of a single fracture complete, it is now possible to optimize on fracture

spacing. Figure 4-22 shows the case of a horizontal well and multiple fracture spacing scenarios.

The point of diminishing returns is less than 60 m, making 60 m the optimum fracture spacing

for a horizontal well.

Figure 4-22: Fracture Spacing Optimization for 0.08 Permeability Case

4.5 Conclusions

This chapter explored fracture optimizations for two different permeability cases: 0.08 md and

0.008 md. After optimizing on fluid type, sand type, job size, maximum bottomhole

concentration, pump rate and pad size, both cases required the same type of fracture treatment.

The difference came in the optimization of a horizontal well and the number of fractures required

0

50

100

150

200

250

300

350

10 100 1000

1 Year Cum. P

roduction (e6m

3)

Fracture Spacing (m)

100

per lateral. The lower permeability case (0.008 md) required 40 meter spacing while the higher

permeability case (0.08 md) required 60 meter spacing.

The next chapter will cover the economic implications of changing the existing fracture design to

the proposal as researched above.

101

Economic Impact of Recommended Completions Changes Chapter Five:

As the Montney development in Karr continues to evolve, the focus will continue to be on

driving down costs while delivering consistent well results. This chapter will focus on the

economic impact of the recommendations developed in Chapter 4.

5.1 Economics of Current Fracture Plan (55 tonne Gelled Oil)

After dealing with the placement issues as described in Chapter 2, a generic 55 tonne gelled oil

with nitrogen schedule was developed and successfully executed. GOHFER features a simplistic

production model that was used to calculate the net present value of this generic plan. The

model assumes constant flowing pressure, condensate-gas ratios, water-gas ratios, and

commodity prices. For the purposes of this analysis, it was assumed that the wells would not be

choked back due to processing restrictions and a monthly operating cost was not considered. It

was assumed that the well is a 1700 m horizontal well with 20 stages, of which 14 stages are

contributing.

In order to calculate the NPV, first the time to lower economic limit must be calculated, which in

this case was considered to be 10 e3m3/day. The plots for both permeability cases (0.008 and

0.08 md) are shown in Figure 5-1.

102

Figure 5-1: NPV for Current 55 Tonne Gelled Oil Treatment for Different Permeability

Estimates

5.2 Economics of Proposed Fracture Plan (50 tonne foamed surfactant system)

A similar methodology was followed for the proposed fracture plan as outlined in Chapter 4.

The results are presented in Figure 5-2.

Note that the NPV for this type of treatment is roughly 50% (for the lower permeability case)

and 240% (for the higher permeability case) greater than the gelled oil case. Furthermore, the

upfront investment ($8.6MM for drill and completion costs) for the VES system is less than the

cost of the gelled oil treatment ($9.1MM for drill and completion). Also, by using a foam, the

amount of water needed for the treatment is reduced, minimizing the environmental impact.

$(20,000,000)

$(10,000,000)

$‐

$10,000,000

$20,000,000

$30,000,000

$40,000,000

$50,000,000

$60,000,000

$70,000,000

$80,000,000

0 1 2 3 4 5 6 7

Years

Gelled Oil 0.008 md case Gelled Oil 0.08 md case

103

Figure 5-2: NPV for Proposed 50 Tonne VES Foam Treatment for Different Permeability

Estimates

5.3 Economics of New Proposed Completion Plan

As discussed in 4.2 and 4.4, the current spacing of 80 m is inadequate to drain the reservoir and a

spacing of 40-60 m was recommended. The limitations of the current open hole packer

technology is 36 stages (37 including the toe port). Also, on another project, it was noted that

stage isolation increased from 67% to roughly 80% by selectively placing packers in gauge hole

after running an open hole caliper log.

$(20,000,000)

$‐

$20,000,000

$40,000,000

$60,000,000

$80,000,000

$100,000,000

$120,000,000

$140,000,000

0 1 2 3 4 5 6 7 8 9

Net Present Value ($)

Years

VES 0.008 md case VES 0.08 md case

104

The following economic case was based on a 1900 m horizontal with 37 stages at 50 m spacing.

The additional cost for the liner and fracture treatments brought the drill and completion cost up

to $12MM. The results are displayed in Figure 5-3.

Figure 5-3: NPV for Additional Stages and 50 Tonne VES Treatments for Different

Permeability Estimates

A summary of all the analysis performed in Sections 5.1-5.3 is shown in Table 5-1. The

proposed new completion is nearly a six-fold improvement on current completion practices for

the lower permeability case and double for the higher permeability case. It is highly

recommended that this new practice be implemented to maximize asset value.

$(50,000,000)

$‐

$50,000,000

$100,000,000

$150,000,000

$200,000,000

$250,000,000

0 2 4 6 8 10 12

Years

VES 0.008 md case VES 0.08 md case

105

NPV ($MM) for 0.008

md case

NPV ($MM) for 0.08

md case

Current 55T gelled oil fracs, 14/20 stages contributing

35.1 76.9

Proposed 50T VES foam treatment, 14/20 stages contributing

130.5 108.1

Proposed 50T VES foam treatment, 50 m spacing, 30/37 stages contributing

196.7 164.5

Table 5-1: Summary of Economic Analyses

106

Summary, Conclusions and Recommendations Chapter Six:

The success of unconventional resource plays has been made possible by the optimization of

fracture treatments combined with an effort to reduce costs as well count increases. The play

discussed in this paper was facing extinction if the costs to stimulate the wells continued to

escalate.

As illustrated in Chapter One, the Montney in the Karr area possess desirable qualities in a

resource play. Chapter Two outlined the placement issues and disseminated them into two

categories: mechanical failure and fracture width restriction. Mechanical failure was strongly

associated with lack of placement success in the preceding zone so changes were made to the

pumping schedule to ensure fracture placement success. The width restriction issues were a

function of insufficient fluid viscosity and were eradicated after changing the fluid system to a

nitrogen based system as opposed to a carbon dioxide based system. A theory was also put

forward as to why ceramic proppant caused premature screenouts.

Chapter Three utilized data from vertical and horizontal well completions to create a predictive

hydraulic fracture model. The fine-tuning of this model allowed for prediction of production

performance on subsequent completions. An investigation was performed on water production

on some of these completions and a theory of multiple fractures initiated in the same zone was

put forth. Several theories were also postulated for less than 100% lateral contribution. It is

highly recommended that alternative methods of isolation be examined such as cemented

wellbores with sliding sleeves. This could aid in achieving full lateral contribution by

pinpointing fracture treatments.

Using the calibrated fracture model, optimization of fracture treatments assuming two different

base permeabilities (0.08 md and 0.008 md) could then occur as was described in Chapter 4.

107

Parameters that were optimized include fluid type, sand type, job size, maximum bottomhole

concentration, pump rate and pad size, both cases indicated that the optimum fracture treatment

is 50 tonnes of 20/40 ceramic proppant in a foamed surfactant system with a maximum

bottomhole concentration of 800 kg/m3, pad volume of 25 m3, and a pump rate of 5 m3/min.

After optimizing for a horizontal well, the only difference is that the lower permeability case

(0.008 md) would require 40 meter spacing while the higher permeability case (0.08 md)

required 60 meter spacing to adequately exploit the resource.

As the original driver for the study was to reduce completion cost and increase stimulation

effectiveness, so Chapter Five explored the economic impact of the proposed changes to the

plan. By changing the fracture treatment alone, an increase of 40-270% of NPV can be

achieved. A combination of reducing fracture spacing and altering fracture treatment design

results in an increase in NPV of 114-460% can be achieved.

It is strongly recommended that the current fracture design (55 tonne gelled oil) and the design

put forth here be tried on a well pair with similar geological parameters to test the efficacy of the

proposed design. Once this design is pumped and evaluated on a series of wells when it would

be considered successful, the fracture spacing can then be reduced.

108

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