funmilayo dissertation

WATERJETTING: A NEW DRILLING TECHNIQUE IN COALBED METHANE RESERVOIRS

By

GBENGA M. FUNMILAYO, B.S., M.S.

A DISSERTATION

IN

PETROLEUM ENGINEERING

Submitted to the Graduate Faculty of Texas Tech University in

Partial Fulfillment of the Requirement for the Award of the Degree of

DOCTOR OF PHILOSOPHY

IN

PETROLEUM ENGINEERING

Approved

Marshall Watson Chair of Committee

Lloyd Heinze

Malgorzata Ziaja

Waylon House

Fred Hartmeister Dean of Graduate School

August 2010

Texas Tech University, Gbenga M. Funmilayo, August 2010

ii

ACKNOWLEDGMENTS

I would like to thank Dr. Marshall Watson, Chairman of my committee, for his valuable

advice and suggestions that helped me throughout the entire work. Beyond his advice,

he provided all the finances for the field tests leading to this report. I also want to thank

Dr. Lloyd Heinze for being so patient with me during my candidature in the department

of Petroleum Engineering, and for his meritorious guidance during the last stage of my

research activities leading to this dissertation. I am honored to have Dr. Malgorzata

Ziaja and Dr. Waylon House serve as members of my committee.

The research part of this dissertation would not have been possible, were it not for the

contributions of Doug Wright from StoneAge Inc., Joe Straeter from Barger Engineering,

Mark Lewis and his crew members from Bodine Services of Evansville, and Bill Gunn

from United Minerals Inc. Thanks to you all!

This dissertation is dedicated to my God, my mother Victoria Funmilayo, my wife

Olukemi Funmilayo, and to my children: Similoluwa, Mayowa, Oluranti, and Oluleke; for

their supports and inspirations during the “thick” and the “thin” of my career

developments.


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TABLE OF CONTENTS

ACKNOWLEDGEMENTS…………………………………………………………………….. ii

ABSTRACT…………………………………………………………………………………….. v

LIST OF TABLES………………………………………………………………………………vi

LIST OF FIGURES......................................................................................................... vii

NOMENCLATURE……..……………………………………….……….……….……..…….. ix

CHAPTER

I. INTRODUCTION………………………………………………………………………..1 1.0 Overview of Coalbed Methane Reservoir……………...……………………..1

1.1 Potential of Coal Bed Methane………………………..……………………….1

1.1.1 Global Potential of Coalbed Methane…………………………………2

1.1.2 U.S. Potential of Coalbed Methane…………………….……………..3

1.2 The Geology of Coalbed Methane Reservoir………………..……………….4

1.2.1 Geochemical Transformation of Coal…………..……………………11

1.3 The Reservoir Engineering of Coalbed Methane…………………………..14

1.3.1 Coalbed Methane versus Conventional Reservoirs………………..15

1.3.2 Properties of Coalbed Methane Reservoirs………………..……….17

1.4 Drilling and Completions in Coalbed Methane Reservoirs………………..31

1.5 Production Engineering of Coalbed Methane Reservoir……………….....42

1.5.1 Water Production…………………………………………………..…..44

1.5.2 Gas Production………………………………………………………...44

1.5.3 Enhanced Coalbed Methane Production…………………………...47

1.5.4 Well Stimulation/Hydraulic Fracturing……………………………....48


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1.6 The Illinois Coal Basin………………………………………………………..50

1.7 Current Challenges in Coalbed Methane Production…..………………...54

II. LITERATURE REVIEW………………………………………………….…………..57

2.0 Review of Waterjet Technology……………………………………………..57

2.1 Background……………...…………………………………………………….57

2.2 Design of Waterjet Systems…………………………………………………63

2.3 Mechanism of Rock Failure……………………...…………………….…....72

2.4 Drilling of Horizontal Well by Waterjet Technology………………………74

2.5 Current Research versus Previous Works………..…………………….....92

III. FIELD TESTING.................................................................................................97

3.0 Equipment Rig-Up…………………………………………………………...97

3.1 Equipment and Material Specifications………………………….………107

3.2 First Round of Field Test…………………………….…………………….117

3.3 Second Round of Field Test……………..………………………………..120

IV. RESULTS AND DISCUSSIONS…………………………………….…………...124

4.0 Accomplishments…………………………...………………………….......124

4.1 Results………………………………………………………………………124

4.2 Discussions………………………………………...……………………….148

V. CONCLUSIONS AND RECOMMENDATION…………………………………..163

5.0 Conclusions………………………………………………………………...163

5.1 Recommendations……………………………………….……………......166

REFERENCES………………………………………..…………………………….…......169


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ABSTRACT

Applications of waterjeting to drill horizontal wells for the purpose of degassing coalbeds

prior to mining operations and for creating rock-bolts in coalbeds, have long been

established. The closest application of waterjet technology in oil and gas industry has

been in the development of jet-assisted drill bits. This dissertation investigates the use

of high pressure waterjet technology for drilling horizontal wells in coalbed methane

reservoirs.

Horizontal Well technology has been in existence for many years. It has found

successful applications in both conventional and unconventional reservoirs. The major

difference between the conventional horizontal well technology and the proposed

waterjet horizontal well technology is the use of a waterjet to drill, as opposed to a bit.

Secondly, the components of their drillstrings are different.

This research aims at investigating the use of high pressure waterjet technology as a

new and a more cost effective technique to drill horizontal wells in coalbed methane

reservoirs. The ability of high pressure hose to replace the conventional metallic drill

pipe will be investigated. The use of a nozzle to drill horizontal wells in coalbed methane

reservoirs, as opposed to a bit will also be investigated. Optimization of tool (nozzle) for

best drilling practices will be a major objective of the field trials. The various factors that

control the direction of the nozzle, during drilling operations, will form part of the

investigation. Finally, sensitivity studies will be carried out to determine the significance

of all the variables that contribute to the impact force; that is, the force from jets of water

that cuts the rocks (coalbeds).


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LIST OF TABLES

Table 1.1: Characteristics and CBM production potential of coal basin……………….9

Table 1.2: ASTM Rank of Coal…………………………………………………………… 14

Table 1.3: Coalbed methane vs. conventional gas reservoirs………………………... 16

Table 1.4: Properties of Coalbed Methane & their Sources……………………………18

Table 1.5: Lithostratigraphy of the Pennsylvanian System in the Illinois Basin……..54

Table 2.1: Difference between conventional and waterjet horizontal well technology……………………………………………………………………... ..94

Table 4.1: Test A: Measurements recorded for tool configuration 1………………....138

Table 4.2: Test B: Measurements recorded for tool configuration 2………………....139

Table 4.3: Test C: Measurements recorded for tool configuration 3…………. ... .139

Table 4.4: Test D: Measurements recorded for tool configuration 4……………. ….140

Table 4.5: Test E: Measurements recorded for tool configuration 1……..…………..141

Table 4.6: Test F: Measurements recorded for tool configuration 5……..………….142

Table 4.7: Test G: Measurements recorded for tool configuration 3………………..143

Table 4.8: Test H: Measurements recorded for tool configuration 6 ………………..144

Table 4.9: Test I: Measurements recorded for tool configuration 7 ………...……….144

Table 4.10: Test J: Measurements recorded for tool configuration 4…….…………...145

Table 4.11: Test K: Measurements recorded for tool configuration 3………….……..146

Table 4.12: Effect of orifice size on impact pressure…………………………………...150

Table 4.13: Effect of pressure on impact pressure……………………………………...151


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LIST OF FIGURES

Figure 1.1: U.S. Coalbed Methane Resource Map…………………………….………... 6

Figure 1.2: Schematic of the coalification process………………………………………..8

Figure 1.3: Cleat systems and permeability anisotropy of a typical coal seam……....22

Figure 1.4: A typical Isotherm plot…………………………………………………………27

Figure 1.5: Isotherms for Fruitland and Fort Union coal formations…………………...29

Figure 1.6: Effective reservoir thickness………………………………………………….30

Figure 1.7: Pinnate pattern drilling and completions technique……..…………………34

Figure 1.8: Drilling and Completions method………………………………………….....38

Figure 1.9: Completions and stimulations methods in the US coal basins…………...40

Figure 1.10: Decision chart for selecting the drilling and completion method……....…42

Figure 2.1: A typical configuration of waterjet system…………………………………..58

Figure 2.2: A typical configuration of waterjet system…………………………….…….58

Figure 2.3 Effect of nozzle pressure, stand-off distance, and orifice size on impact pressure………………………………………………………………………...72

Figure 2.4: Drillhead that did not require nozzle swivel………………………………..79

Figure 2.5: Jet-assisted diamond drill bit…………………………………………...…….80

Figure 2.6: Drive mechanism for the Petro Jet Multiple Lateral System……...………85

Figure 2.7: Addition of bent sub in the drillhead……………………………………… 86

Figure 2.8: Drive mechanism of the round the corner drill…………………..………...89

Figure 2.9: Equipment layout for the test to verify RTC drilling ability……………… .90

Figure 2.10: Component of the RTC drillhead instrumentation…………………………90

Figure 2.11: Pictorial view of the proposed waterjet horizontal well technology……...95


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Figure 3.1: Some of the major components of the rig — Waterblaster…………….......97

Figure 3.2: Water truck that supplies the water for the test………………….………...98

Figure 3.3: Diesel engine than pumps water from the truck to the tank…...…………99

Figure 3.4: 1st & 2nd inlet filters, and water tank…………...………………………....102

Figure 3.5: Water pump…………………………………………………………………..103

Figure 3.6: Diesel engine that powers the water pump…………………………….....104

Figure 3.7: Foot valve, a component of the foot dump………………………………..107

Figure 3.8: Outlet high pressure and the dump line connections…..………………..108

Figure 3.9: Diffuser, with a pressure gauge mounted on it, and whip check…….....109

Figure 3.10: Backhoe, bern, pipe, testing hose, and jetting operations………………112

Figure 3.11: Nozzle Configuration………………..………………………………………113

Figure 3.12: Nozzle Configuration………………...……………………………………...114

Figure 3.13: Component of BA-PA nozzle.……………………………………………....115

Figure 4.1: Borehole geometry and changes in the color of returning water…….....129

Figure 4.2: Description of particle sizes………………..……………………………….130

Figure 4.3: Measurement of borehole dimensions……………………...…………….131

Figure 4.4: Feeding of hose into the coal seam during a jetting operation….….......134

Figure 4.5: Borehole # seventeenth drilled to the depth of 62 ft……..……….……...135


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NOMENCLATURE

ASTM = American Society of testing and materials

CBM = Coalbed Methane

DAF = Dry Ash-Free

ECBM = Enhanced Coalbed Methane

EOR = Enhanced Oil Recovery

G = Gas content of the coal in the formation, scf/ton

GR = Residual gas of core, scf/ton

GC = Gas released by the core in the canister, scf/ton

GL = Lost gas from the core during coring process, scf/ton

Gs = Gas storage capacity, scf/ton

P = Pressure, psia

PL = Langmuir pressure, psia

VL = Dry, ash-free Langmuir volume, scf/ton

a = Ash content, weigt fraction

wc = Moisture content, weight fraction

ρ = bulk density, g/cm3

ρa = ash density, g/cm3

ρo = pure coal density, g/cm3

ρw = moisture density, g/cm3

Kanisot = permeability anisotropy (Kmax/Kmin)


x

Hh = thickness of the coal seam containing the horizontal wellbore, ft

Hv = sum of all completed seams in a vertical well, ft

re = drainage radius, ft

rw = wellbore radius, ft

S = negative vertical skin factor due to stimulation

Smh = mechanical skin damage to a horizontal well

Sh = negative skin factor due to the horizontal well

Scah = shape related skin factor (function of drainage shape, well length, Hh, and Kv/Kh)

given by correlation derived from charts

L = horizontal length of wellbore, ft

Wp = Water required to be produced for gas desorption to commence, bbls

Wi = Water initially in place in the drainage area, bbls

cw = water compressibility, psi-1

cf = formation compressibility, psi-1

pi = Initial reservoir pressure, psia

pd = Desorption pressure as determined by the Langmuir isotherm, psia

Gi = Gas in Place at initial reservoir conditions, Mscf

A = Drainage area, ac

h = coal thickness, ft

φf = Interconnected fracture (effective) porosity, fraction

Swfi = Interconnected fracture water saturation, fraction

Bgi = Gas formation volume factor at pi, rcf/Mscf


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Cgi = Initial sorbed gas concentration, scf/ton, dry, ash-free coal

fa = Average weight fraction of ash, fraction

fm = Average weight fraction of moisture, fraction

43560 = Conversion factor, ft2/ac

GIPi = initial gas in place

GIPa = gas in place at abandonment

Rf = Recovery factor, %

Vi = initial volumetric gas content, scf/ton

Va = abandonment gas content, scf/ton

Gp = Methane recoverable reserves, Mscf

MSHA = Mine Safety and Health Administration

WJTA = WaterJet Technology Association

Hp = Horse power

P = pump pressure, psi

Q = flow rate, gpm

∆P = pressure loss in pipe or hose, psi

d = internal diameter of the pipe/hose, in

∆L = pipe/hose stretch due to pressure, %

Lp = pipe or hose length, ft

PN = pressure at nozzle, psi

∆PN = pressure loss through the nozzle, psi

Cv = flow rating, dimensionless


xii

do = internal diameter of orifice, in

Cd = flow efficiency, dimensionless

N = number of jets (orifice) required, constant

FR = jet reaction force, lbs

FP = pulling force, lbs

θ = jet angle, degree

π = 3.142

V = flow velocity, ft/sec

PI = impact pressure, psi

DS = stand-off distance, ft

OD = Outer Diameter

ID = Inner Diameter

CWD = Casing While Drilling

RTC = Round The Corner

BHA = Bottom Hole Assembly

MCP = Minimum Cutting Pressure

OCP = Optimum Cutting Pressure

ROP = Rate of penetration

gr = graphite

ma = meta-anthracite

an =anthracite

sa = semi-anthracite


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lvb = Low Volatile Bituminous

mvb = Medium Volatile Bituminous

hvAb = High Volatile A Bituminous

hvBb = High Volatile B Bituminous

hvCb = High Volatile C Bituminous

subA = Sub-bituminous A

suB = Sub-bituminous B

subC = Sub-bituminous C

ligA = Lignite A

ligB = Lignite B


1

CHAPTER I

INTRODUCTION

1.0 Overview of Coalbed Methane Reservoirs

1.1 Potential of Coal Bed Methane

Coalbed methane, CBM, has progressively been gaining ground since the early

80’s, as an alternative source of energy. While technologies are still emerging in

coalbed methane production, the current technologies from both mining and oil

industries have resulted in some breakthroughs to produce methane gas from

coal seam; even though its contribution to total energy production is still minimal.

Considered to be in the category of tight gas and shale gas which are

unconventional resources; CBM is set to continually attract operators with

nations moving towards environmentally friendly natural gas, as an energy

source. In order to increase the contribution of coalbed methane gas to total

energy need, there must be advances in the understanding of coalbed behavior

and characteristics, such as adsorption, diffusion, mechanical properties, and

stress-dependent permeability. In addition to this, technological advancements in

the area of drilling, completion, and stimulation techniques are keys to increased

coalbed methane production.


2

1.1.1 Global Potential of Coalbed Methane

On a global basis, Nazish1 reported that coalbed methane now contributes more

than 1TCF (trillion cubic feet) of gas per annum.

The Hart Energy Publications2 once quoted Joe Awny, senior petroleum

engineer, EquiTable Production Co.; of making the following statement about the

global potential of coalbed methane gas:

“In some regions, coalbed methane could eventually grow from a supplement to conventional natural gas supply to a main source of gas. The global coalbed methane resource is of some significance in the near-term energy mix, where it is currently being exploited in several countries including the U.S., Canada, Australia and China,” he said. “Long term, the resource is expected to be of great significance for the U.S., India, China, Poland, South Africa, Zimbabwe and elsewhere as a main source of gas supply.”

Coalbed Methane production activities are going on in several countries around

the globe and this is expected to increase as more and more countries are

developing interest in the resource play. One particular country that has

developed interest in coalbed methane production is China, the world’s largest

coal producer. Nazish1 reported that its coalbed methane resources are

estimated to range from between 1,000 and 2,800 TCF, which is many times

larger than its conventional gas potential. According to Nazish1, India’s coalbed

methane resource potential has been estimated at 280 TCF, which is also

surpassing its conventional gas potential. There are ongoing partnerships

between the U.S. and Indian companies to explore the potentials of coalbed

methane production.


3

Bangladesh and Philippines are two other countries with significant interests in

coalbed methane production. Activities in coalbed methane production have also

been reported in several parts of Europe, especially in Russia, United Kingdom,

and Germany.

Estimates of worldwide in-place coalbed methane resources are difficult to make,

either because of lack of adequate technology to make such estimate across the

world or because few areas are as mature as the United States. However, The

United States Geological Survey (USGS)3 reported that the global coalbed

methane recoverable reserves are estimated to be about 1,200 TCF.

1.1.2 U.S. Potential of Coalbed Methane

The U.S. estimates of the total coalbed methane resource vary considerably and

the estimates are contingent upon improved understanding and technologies to

explore the resource. Towards the end of 1990s, the USGS3 estimated in-place

coalbed methane resources in the United States at more than 700 TCF; and that

about 100 TCF of the 700 TCF is economically recoverable. The 100TCF comes

from the contiguous 48 U.S. states. The Hart Energy Publications2 reported that

about half of the estimated 100 TCF of recoverable coalbed methane is in the

Powder River Basin with an estimated 24 TCF of recoverable coalbed methane,

the Northern Appalachian Basin with an estimated 11 TCF of recoverable

coalbed methane, the San Juan Basin with an estimated 10 TCF of recoverable

coalbed methane, and the Black Warrior Basin with an estimated 4 TCF of


4

recoverable coalbed methane. The Oil & Gas Journal4 reported that almost 75

TCF may still be discovered in the contiguous 48 U.S. states, apparently with

improved technology. The Hart Energy Publications2 further reported that another

57 TCF of coalbed methane is estimated to be recoverable in Alaska.

In its reports, the Energy Information Administration5 indicated that the number of

CBM producing wells in the contiguous 48 states passed the 15,000 mark in

2001, which was up from 284 wells in 1984. The number of producing wells has

since increased. The Energy Information Administration5 reported that coalbed

methane currently accounts for about 8 percent of total gas production in the

United States. Figure 1.1 shows the coalbed methane resources and their

locations in the United States.

1.2 The Geology of Coalbed Methane Reservoir

Coal is a product of organic decomposition of plants. It is formed when peats

undergo both physical and chemical changes due to the actions of bacterial,

temperature, and pressure over an extended period of time. This process is

called Coalification. Before Coalification is a process called Peatification. In

Peatification, plants are deposited in swamps, buried rapidly enough by

sediments to limit the rate at which the available oxygen in organic-rich water is

completely used up by the decaying process (oxidation) but to allow microbial

decomposition of the plants. The use of oxygen in the decaying process is called


5

aerobic decomposition. If the rate of burial is slow, the oxygen is rapidly used up

and a much slower decomposition process, called anaerobic, takes place. Peats

are usually formed in waterlogged environment where plant debris are deposited

and accumulated. Burial by sediments leads to compaction of peat. The

compaction allows water to squeeze out of the peat, especially during the early

stage of Peatification. As the Peatification process continues, peats are

progressively covered with sediments, pressure continues to compress the peat,

and bacteria continue to react with peat to alter its chemical composition in the

presence of heat and over and extended period of geologic time. Some of the

products of the alteration are methane, carbon dioxide, and nitrogen gases.

The Kentucky Geological Survey6 reported that these gaseous products are

typically expelled from the deposit, and the deposit becomes more and more

carbon-rich as the other elements disperse. The society further asserted that the

stages of this trend proceed from plant debris through peat, lignite, sub-

bituminous coal, bituminous coal, anthracite coal to graphite (a pure carbon

mineral).

Temperature is the most important parameter in the geochemical reactions that

occur during Coalification process. In their studies, The Kentucky Geological

Survey6 concluded that an estimate of ten vertical feet of original peat materials

produces one vertical foot of bituminous coal in eastern and western Kentucky,


6

due to the amount of squeezing and water loss that accompanies the compaction

of peat after burial varies, depending on the original type of peat the coal came

from and the rank of the coal. The Figure 1.2 shows the Schematic of the

Coalification process.

Larsen7, in his study, concluded that the U.S. coals originated in the Tertiary,

Cretaceous, or Carboniferous periods. However, most of the coals come from the

Carboniferous period. Rogers et al8 also concluded that younger coals in the

Cretaceous, Paleocene, and Eocene periods are of lower rank or maturity unless

a localized heat source occurred to accelerate the normal metamorphism or

burial history was altered by tectonic action.

Figure 1.1: U.S. Coalbed Methane Resource Map


7

There are fourteen major coal Basins in the United States. They are:

1 San Juan Basin

2 Black Warrior Basin

3 Raton Basin

4 Piceance Basin

5 Greater Green River Coal Region

6 Powder River Basin

7 Northern Appalachian Basin

8 Central Appalachian Basin

9 Western Washington

10 Wind River Basin

11 Illinois Basin

12 Arkoma Basin

13 Uinta Basin

14 Cherokee Basin

The Table 1.1 gives the characteristics and production potentials of the major

Basins.


8

Figure 1.2: Schematic of the Coalification process


9

Table 1.1: Characteristics and CBM production potential of various coal Basins (Ref # 8,9,10,11,12,13,14,15,16,17,18,19,20,21,22,23,24,25,26,27,28,29,30). S/N

Major U.S. Coal Basin

Location (States)

Age Sediment

CBM Production Potential

Characteristics

1

San Juan Basin SW Colorado and NW New Mexico

Upper and Lower Cretaceous

Most profitable, most prolific CBM production Basin in the world

Favorable coal seam thickness, permeability, gas content, depth, and coal rank in large area

2

Black Warrior Basin

Alabama

Lower Pennsylvanian

First Basin for CBM activities, less profitable than san Juan

multiple thin seams, more difficult and costly to complete limited production rate

3

Raton Basin

NE New Mexico and SE Colorado

Cretaceous, Paleocene, Late Cretaceous

smallest of major coal Basin

multiple thin seams, discontinuous coal groups

4

Piceance Basin

Western Colorado

Cretaceous, Late Cretaceous

profitable and prolific

High coal seam thickness, High Gas content

5

Greater Green River Coal Region

SW Wyoming and NW Colorado

Paleocene, Eocene, Cretaceous, Upper Cretaceous

has five Basins: Sand Wash of NW CO and SW Wyoming, Great Divide of WY, Hanna of WY, Green River of WY, and Washakie of WY

Unfavorable conditions; such as: mostly unsaturated, high water production with aquifer sands lying between coals, thin coal seams, low to very low permeability, normal to under-pressured coal seam

6

Powder River Basin

NE Wyoming, and SE Montana

Eocene, Paleocene

Shallow formation, profitable but not prolific

Favorable coal seam thickness, low Gas content

7

Northern Appalachian Basin

West Virginia, Ohio, Kentucky Pennsylvania, Maryland, and

Pennsylvanian

not prolific, less profitable than black warrior Basin

similar thin seams to black warrior Basin, but more under-pressured and produce less water due to extensive mining that has taken place in the area, lower gas content than black warrior Basin because it is shallower, more under-pressured, and lower rank

8

Central Appalachian Basin

West Virginia, Virginia, Kentucky, and Tennessee

Pennsylvanian

not prolific, less profitable than black warrior Basin

similar to northern Appalachian and black warrior Basins, mining activities has removed the amount of water to be removed to achieve gas production, gas content and permeability are similar to black warrior Basin, but both properties are higher than northern Appalachian


10

Table 1.1: Continued S/N

Major U.S. Coal Basin

Location (States)

Age Sediment

CBM Production Potential

Characteristics

9

Western Washington

Between Canadian border on the north to Oregon border on the south

Eocene

no commercial CBM production, small Basin, complex geology

little available data to describe the Basin, has good gas content

10

Wind River Basin

West-Central Wyoming

Paleocene, Upper Cretaceous

small Basin, complex geology including coal seam discontinuity, no commercial CBM production, located in remote area

little available data to describe the Basin, relatively thin coal seams

11

Arkoma Basin

Central Arkansas and Oklahoma

Pennsylvanian

commercial CBM production but not prolific

less water due to extensive mining that has taken place in the area, high permeability and good gas content

12

Uinta Basin

NE Utah and NW Colorado

Upper Cretaceous

commercial CBM production but not as prolific as san Juan Basin

good coal seam thickness, good gas content, permeability and production rate

13

Cherokee Basin

Near Oklahoma/Kansas/Missouri border and extends northward along Kansas-Missouri border

commercial CBM production but not as prolific as San Juan Basin, contains small amount of low gravity oil

Similar to Arkoma Basin: low water production rates, high permeability

14

Illinois Basin

Illinois, Western Kentucky, and SW Indiana

Pennsylvanian

largest of the coal Basins, no commercial CBM production

good coal seam thickness, multiple coal seams, low water production, low gas content, poor permeability, high nitrogen content, under-saturated coals


11

1.2.1 Geochemical Transformation of Coal

Peatification, the first stage in the development of coal, is the biochemical and

physical process of converting organic matter to peat with only secondary

assistance from geochemical processes. The biogenic methane generated by

bacteria in the Peatification stage is lost unless burial of the peat is rapid enough

and trapped by interbedded shale lenses. Later, however, biogenic methane from

other locales may migrate to the developing coal and be adsorbed.

There are two types of methane gas generation. Biogenic methane is generated

as a result of bacterial reaction during Peatification process (microbial

decomposition). In his research, Rightmire32 discovered that the methane is

usually lost unless burial of the peat is rapid enough and sealing shale lenses are

interbedded to form a trap. Also, Rogers et al8 concluded that the biogenic

methane from other locales may migrate to the developing coal and be adsorbed.

The second type of methane generation, thermogenic methane, evolves during

the coalification process. Temperature acts to change the molecular structure of

coals over geologic time, which leads to the generation of thermogenic methane,

usually in large quantities. Rogers et al8 described what happens in the coal

when thermogenic methane is formed: micropores develop to absorb

extraordinary amounts of methane per unit of coal, and fractures permeate the

coal to transport the excess methane. The term excess methane means the


12

methane gas that could not be stored in the coal micropores due to the fact that

the micropores are completely filled up with gas because the coal has reached its

gas capacity. Just as the compressive strength of coal, the gas content increases

with rank (coal maturation) and its permeability also increases with rank up until

the upper bituminous level and then regresses beyond this rank, due to

continued alterations in the chemical structure of anthracite.

It is a common knowledge that the largest amounts of coalbed methane gas are

from thermogenic sources. In their own work, Law et al33 however, concluded

that biogenic methane may be retained in commercial quantity, especially in thick

coal seams such as the one of the Fort Union formation of the Paleocene Age

and the overlying Wasatch formation of the Eocene Age of the Powder River

Basin of Montana/ Wyoming. Biogenic methane is usually stored in lignite-to-

subbituminous coal rank. Rogers et al8 explained that the practicality of and

commercial production of biogenic methane from such Basin and coal rank is

due to the combination of thick seams and shallow depths of burial. However, the

Seelyville coalbed in the Linton formation of Illinois Basin is also found to be of

commercial value due to shallow depth, even though the coal seams are not as

thick as those of afore-mentioned formations.

Volatiles are common products of Peatification and Coalification. Carbon dioxide

and water are the first volatiles generated, usually during Peatification process


13

and at a temperature lower than 212oF. Higher temperature favors rapid

generation of methane gas. During Coalification process, volatiles such as: CH4,

CO2, H2O, and N2 are generated and evolved. Larsen7 reported that mainly CO2

is librated in the stage going from peat to lignite while Rogers et al8 asserted that

the thermogenic carbon dioxide, although more strongly adsorbed to the coal

matrix than the other volatiles, is more easily dissipated because of its solubility

in water. They further reports that nitrogen is the smallest molecule among the

volatiles and it more weakly adsorbed than methane or carbon dioxide. Hence, it

is more easily dissipated by diffusion during Coalification process.

ASTM ranks coals as a measure of their maturity. The Table 1.2 shows the

various coal ranks and subdivision, according to ASTM classification. There are

five major classifications and thirteen subdivision of coal. The five major classes

are: lignite, sub-bituminous, bituminous, anthracite, and graphite. The bituminous

rank, specifically hvAb through lvb, is the best for coalbed methane production

because coal properties are well developed at this rank. Even thin coal seam of

hvAb through lvb can yield substantial amount of recoverable methane gas

because of well developed cleat systems, permeability, gas content, and gas

capacity.


14

Table 1.2: ASTM Rank of Coal Class Group Abbreviation

Graphite Graphite gr

Anthracitic Meta-Anthracite

Anthracite

Semi-anthracite

ma

An

sa

Bituminous Low Volatile

Medium Volatile

High Volatile A

High Volatile B

High Volatile C

lvb

mvb

hvAb

hvBb

hvCb

Sub-bituminous Sub-bituminous A

Sub-bituminous B

Sub-bituminous C

subA

subB

subC

Lignitic Lignite A

Lignite B

ligA

ligB

1.3 The Reservoir Engineering Aspects of Coalbed Me thane

The purpose of this section is not to present all aspects of the reservoir

engineering of coalbed methane reservoirs. Those presented here are related to

this research. We would like to state clearly that the descriptions are not


15

exhaustive; and only serves the purpose of assisting readers to understand the

aspects of coalbed methane reservoir that are critical to its exploration and

production.

1.3.1 Coalbed Methane versus Conventional Reservoir s

Coalbed methane reservoirs are unconventional; which means their descriptions

do not follow common knowledge already established in the conventional oil and

gas reservoirs. Operators of coalbed methane reservoirs often rely on the

combination of knowledge gained in mining, and oil and gas industries to

produce methane gas. The unique characteristics of coalbed methane reservoirs

necessitate modified approaches in the methane gas production. Over the years,

operators have gained more in-depth knowledge of this resource plays and have

improved their understanding method of methane gas production. Researches

and field practices have lead to:

a. an improved understanding of the fundamentals of coalbed methane

production

b. advances in measuring reservoir properties

c. advances in coalbed methane reservoir simulation

Levine34 compared the characteristics of Coalbed methane and conventional gas

reservoirs. These are presented in Table 1.3.


16

Table 1.3: Coalbed methane and conventional gas reservoirs Properties Conventional Gas Coalbed Methane Gas

Darcy flow of gas to wellbore Diffusion through micropores by

Fick’s Law

Darcy flow through fractures

Gas storage in macropores; real gas

law

Gas storage by adsorption on

micropore surfaces

Production schedule according to set

decline curves

Initial negative decline

Gas content from logs Gas content from cores. Cannot

get gas content from logs

Gas to water ratio decreases with time Gas to water ratio increases with

time in later stages

Inorganic reservoir rock. Organic reservoir rock

Hydraulic fracturing may be needed to

enhance flow

Hydraulic fracturing required in

most of the Basins except the

eastern part of the Powder River

Basin where the permeability is

very high. Permeability dependent

on fractures

Macropore size: 1µ to 1 mm. Micropore size: <5A° to 50A°

Reservoir and source rock independent Reservoir and source rock same

Permeability not stress dependent Permeability highly stress

dependent

Well interference detrimental to

production

Well interference helps production.

Must drill multiple wells to develop


17

1.3.2 Properties of Coalbed Methane Reservoirs

Aminian35 pointed out that gas content, storage capacity, and deliverability are

the key parameters that influence the decision making in the evaluation of CBM

prospects. Whereas gas content and gas storage capacity influence the

determination of gas-in-place, Aminian35 stated that the natural fracture system

permeability and relative permeability are the most critical properties that

influence the deliverability of coalbed methane reservoirs. Coalbed methane

reservoir is considered a dual-porosity reservoir. The low permeability coal matrix

is considered to have the primary porosity while the secondary porosity is in the

natural fractures, the cleats. The majority of methane gas is stored in coal matrix

through adsorption. The matrix system practically has no permeability. Hence,

the flow of gas from the matrix into the cleat systems is by diffusion. The cleat

systems provide the conduit for dewatering and contain little or no gas at the

beginning of coalbed methane gas production. It is essentially filled with water.

Aminian35 provided a list the major properties of coalbed methane reservoirs and

their methods of determination, as seen in Table 1.4.

1.3.2.1 Proximate Analysis

This is a laboratory analysis aimed at determining the composition of a coal. The

major compositions of coal, usually expressed in percentage, are the:


18

a. ash

b. fixed carbon

c. volatile matter, and

d. moisture

Table 1.4: Properties of Coalbed Methane and their Sources Property Source

Storage Capacity Core Measurements

Gas Content Core Measurements

Diffusivity Core Measurements

Pore Volume Compressibility Core Measurements

Gross Thickness Well Logs

Effective Thickness Well Logs

In-Situ Density Well Logs

Pressure Well Tests

Absolute Permeability Well Tests

Relative Permeability Simulation

Porosity Simulation

Fluid Properties Composition Analysis and Correlations

Gas Composition Produced and Desorbed Gas

Drainage Volume Geologic Studies


19

Ash is the mineral matter left in the coal after thermal combustion during

Coalification process. The higher the ash contents of a coal, the lower the

adsorptive capacity of the coal. That is, the lower the amount of methane that

can be adsorbed into the coal. In addition to this adverse effect, mineral matters

also limit cleat formation and gas content of a coal. Hence, mineral matters affect

both the permeability and adsorptive capacity of methane in the coal. These two

properties of coal are very essential for commercial production of coalbed

methane gas. Constituents of ash in the coal are minerals of clay, carbonate,

sulfide (pyrite) and silica (quartz). The ash reduces with coal maturation.

Volatile matters, as previously mentioned are: CO2, H2O, and N2. The volatile

matters reduce with coal maturation because they continually get expelled from

the coal as maturation progresses under the influence of temperature.

Moisture content reduces the adsorptive capacity of methane gas. Lower rank

coals have higher moisture content than higher rank coal. In other word, moisture

content reduces with coal maturation and gas content increases with decrease in

moisture content.

The fixed carbon content increases with coal maturation until graphite is attained

because the ash content, moisture content, and volatile matters all reduce with

coal maturation. Graphite, as a coal rank, has 100 percent fixed carbon. The


20

fixed carbon content of a coal rank is calculated by subtracting the percentage

composition of ash, moisture content, and volatile matters from the total

composition of the coal.

1.3.2.2 Ultimate Analysis

It is a laboratory analysis that gives the elemental composition, measured in

percentage, of oxygen, carbon, hydrogen, sulfur, and nitrogen in a given coal

seam

1.3.2.3 Permeability

Permeability, which is determined either from history matching production data or

from well test analysis, is considered the most critical parameter used in

evaluating the economic potential of a gas-bearing coal. For a gas-bearing coal

to be considered viable, the natural fracture networks and those created by

hydraulic fracturing must have sufficient permeability for commercial production

of methane. As critical as it is to CBM production, it is also the most difficult

parameter to evaluate accurately. The factors that affect permeability are:

a. frequency of the natural fractures

b. natural fractures connectivity

c. degree of fissure aperture opening

d. direction of butt and face cleats

e. water saturation


21

f. depth of coal burial

g. matrix shrinkage upon desorption, and

h. in-situ stresses

The parameter that is most important to CBM gas flow is the gas relative

permeability. The determination of this parameter is further complicated by its

changing nature with water relative permeability (water saturation in the flow

path). The most common method of determining the CBM relative permeability is

to use Corey correlation.

1.3.2.4 Permeability Anisotropy

This is a common feature in CBM production. There are two major types of cleats

system in the coal: butt and face cleats. Usually, the butt cleats permeability is

less than the face cleats. When this variation exists, geometric averaging

technique is used to estimate average permeability of the coal. The equation is

given as:

KxKyK = 1.1

Where;

K = average permeability of the coal seam, md

Kx = permeability in x-direction (Face cleats), md


22

Ky = permeability in y-direction (Butt cleats), md

The Figure 1.3 shows the arrangement of cleat systems and the presence of

permeability anisotropy in a coal seam.

Figure 1.3: Cleat systems and permeability anisotropy of a typical coal seam


23

1.3.2.5 Gas Content

This term is used to describe the total amount of methane gas that is present in

coal seams. Unlike conventional gas reservoirs where methane occupies void

spaces as free gas between sand grains, the CBM gas is held to the solid

surface of the coal by adsorption in numerous microspores. Even though logging

techniques can determine the presence of coal in a formation, the current logging

technologies cannot determine the presence of methane gas in coal seams.

There are two methods by which gas content of a coal seam can be determined:

a. direct method, which measures the volume of gas released from a coal

sample sealed into a desorption canister, and

b. indirect method, which uses empirical correlations, or laboratory-derived

sorption isotherm constructed from gas storage capacity data

Gas content of coal usually increases with depth as do conventional gas

reservoirs, but in contrast, the increase is due to the positive influence of

pressure on coal adsorptive capacity rather than the compressibility of the gas in

conventional reservoirs. Methane gas are either biogenic or thermogenic.

Biogenic methane is generally not economically viable because of very low gas

content; however, it can become viable in coals that are well connected and have

high permeability. The biogenic gas evolves during the early stage of

Peatification process. The coal depth is usually shallow (less than 2000 ft).

Thermogenic gas evolves when the organic mass becomes deeply buried and


24

Coalification becomes a function of pressure, temperature, and time.

Temperature is the most important property in the geochemical reactions that

result in the evolution of thermogenic methane gas.

There are three components to volumetric calculation of gas content of coals.

These are:

a. Measured gas; from the coal in the canister

b. Lost gas; during core retrieval, and

c. Residual gas; from crushed core sample in the canister.

The equation for volumetric calculation of gas content is given as:

LCR GGGG ++= 1.2

Where;

G = Gas content of the coal in the formation, scf/ton

GR = Residual gas of core, scf/ton

GC = Gas released by the core in the canister, scf/ton

GL = Lost gas from the core during coring process, scf/ton

Gas content can be reported in different ways. These include:


25

a. Raw or As-Received

b. Inert Gas-Air Dry

c. Dry, Ash-Free

d. Dry, Ash-Residual Moisture-Sulfur Free

e. Theoretically Pure-Coal

f. In-situ

The most common method of reporting gas content in CBM production is the Dry,

Ash-Free. The term Dry, Ash-Free means the moisture and organic ash contents

of the coal have been removed from the volumetric calculation, leaving only the

methane gas.

1.3.2.6 Isotherm

This term defines the volume of gas adsorbed on a solid surface as a function of

pressure and at a constant temperature for a specific gas and solid material.

Type 1 isotherm is known for its applicability in microporous solids, a

characteristic of coal. Langmuir equation is generally used in the CBM process to

develop type 1 isotherm for coal. Because of its fitness to the adsorption data of

all coals, the Langmuir equation is universally used in the industry for predicting

CBM production. The model is referred to as Langmuir Isotherm. The equation is

given as:


26

L

L

LS V

PP

VG

P += 1

1.3

Rearranging equation 3 gives:

LcLS PP

PwaVG

+−−= )1(

1.4

Where;

Gs = Gas storage capacity, scf/ton

P = Pressure, psia

PL = Langmuir pressure, psia

VL = Dry, ash-free Langmuir volume, scf/ton

a = Ash content, weight fraction

wc = Moisture content, weight fraction

It should be noted that G and GS are quantitatively different from each other.

Whereas G is the actual volume of gas adsorbed to the coal surface at a specific

temperature and pressure, GS is maximum volume of gas a coal seam can

adsorb to its surface, also at a specific temperature and pressure. This means

that G can be less than or equal to GS. A point to note on the isotherm is that at

lower pressure, large volumes of gas are adsorbed or desorbed with small

changes in pressure. The isotherm helps in predicting the critical desorption


27

pressure (CDP), gas content, and recovery factor. Figure 1.4 is a typical isotherm

plot. Given an initial pressure P2, the initial gas content can be read off on the y

(gas content) axis by tracing P2 up from x (pressure) axis until it touches the

isotherm curve. This is an indirect method of estimating the gas content of a coal

seam.

Figure 1.4: A typical Isotherm plot.

1.3.2.7 The Critical Desorption Pressure:

The Critical Desorption Pressure, CDP, is the pressure at which gas starts to

produce during the dewatering process of coal seam. Dewatering is the process

by which water is being produced from coalbed methane reservoir in order to


28

reduce the reservoir pressure. Depending on the coal Basin, it may take up to a

year of dewatering before the critical desorption pressure is attained. In under-

saturated CBM reservoirs, gas production will not initiate until reservoir pressure

falls the CDP. The critical desorption pressure is the pressure at which the gas

content of the coal is in equilibrium with the isotherm. Below the CDP, gas

begins to desorb then diffuse from the coal matrix to the cleat systems and then

begins to flow in the cleat systems towards the wellbore at a higher rate than

water. The higher flow rate of gas as compared to water is because; below CDP,

the gas relative permeability of coalbed methane reservoirs is higher than that of

water. The gas relative permeability continues to increase and consequently, gas

flow rate increases until the production of water stops. Figure 1.5 shows the

isotherm curves constructed for the Fruitland and Fort Union coal formations.

From the Fruitland isotherm curve, the coal formation is under-saturated and has

initial reservoir pressure of 1620 psia. This corresponds to the initial gas content

of about 355 scf/ton and methane gas storage capacity of about 450scf/ton. The

reservoir pressure was reduced to the CDP of 648 psia by dewatering. This is the

pressure at which the Fruitland coal starts producing methane gas. With the

abandonment pressure set at 100 psia, the unrecoverable (abandonment) gas

content was estimated as 128scf/ton. This gives the recoverable gas content of

Fruitland formation as 227scf/ton. This corresponds to the recovery factor of

about 64 percent.


29

Figure 1.5: Isotherms for Fruitland and Fort Union coal formations

1.3.2.8 Effective and Gross Reservoir Thickness:

Effective reservoir thickness is the term used to describe the thickness of coal

seam that has been evaluated and considered commercial for production. Gross

reservoir thickness refers to the summation of the thickness of coal intervals

having densities less than the pre-determined cut-off values. The cut-off values

are generally taken to be equal to the ash density of the coal. Aminian35 indicated

that determining net (effective) thickness is more complicated because it requires

evaluating how much of the gross coal thickness actually contributes to

production. He suggested the use of resistivity logs, well tests, production logs,

or zonal isolation tests for estimating effective reservoir thickness. Figure 1.6

shows an example of coal thickness obtained from a wireline log.


30

Figure 1.6: Effective reservoir thickness (905’-915’ for Seelyville coal in Indiana)

1.3.2.9 In-Situ Density

The true in-situ density of coal can be estimated from open-hole density log data.

In practice, the operators of coalbed methane reservoirs commonly use value of

1.32 to 1.36 g/cm3 for the average in-situ density. However, Nelson36 pointed out

that such random use can lead to serious errors in the estimation of gas-in-place.

When well log is not available, equation relating the density of the ash, moisture,

and organic (pure coal) fractions can be used to estimate the in-situ coal density.

The equation is given as:

w

c

o

c

a

wwaa

ρρρρ+−−+= )1(1

1.5

where:

ρ = bulk density, g/cm3


31

ρa = ash density, g/cm3

ρo = pure coal density, g/cm3

ρw = moisture density, g/cm3

1.4 Drilling and Completions in Coalbed Methane Res ervoirs

1.4.1 Drilling

The drilling operations in coalbed methane reservoirs require that all aspects of

the formation, especially the geological transformation and reservoir properties,

be considered before a choice is made on the drilling technique. Specifically, one

should answer the following questions before selection is made on the choice of

drilling technique:

a. Is the formation saturated or under-saturated?

b. What is the formation pressure (normally pressured, under-pressured or

over-pressured formation)?

c. What is the effective thickness of the target coal seam?

d. What is the formation permeability?

e. Based on permeability and permeability anisotropy, what is the

recommended well spacing? That is how many wells will be drilled in a

given drainage area and what spacing pattern?

f. Has the top soil been reclaimed due to mining operations?


32

If the coalbed methane reservoir is saturated, then there is high tendency that

gas influx may occur during drilling operation. Hence, overbalanced drilling will

be a preferred technique. The overbalanced drilling is a process in which the

wellbore pressure is greater than the formation pressure. However, because

coalbed methane reservoirs are generally of low permeability, care should be

taken to prevent excessive pressure differential between the wellbore and

formation; to prevent formation damage. If the formation is under-saturated,

underbalanced drilling method will be preferred. Underbalanced drilling is the

opposite of overbalanced drilling. It is a process in which the formation pressure

is greater than the wellbore pressure.

In normally pressured reservoirs, drilling with air versus mud is a viable choice. In

over-pressured formations, the use of a combination of liquid, solid, and air is a

preferred option in order to maintain backpressure and also control fluid influx.

When air is used as drilling fluid, air-hammer bits are the preferred bit types.

When liquid is used as drilling mud, tri-cone rotary bits are commonly used.

Permeability and effective thickness of coal seams are usually considered

together in order to make the choice of drilling technique. In high permeability

and relatively think coal seam, vertical drilling technique is preferred. Low, but

favorable, permeability coal Basin with thin coal seams is a candidate for

horizontal drilling technique. Horizontal drilling method can take different forms:


33

a. drilling multi-lateral wells from a single vertical wells

b. drilling a single long horizontal well from a vertical well

c. drilling multi-lateral wells from four multi-lateral/horizontal wells drilled from

a vertical well (pinnate well pattern)

Schoenfeldt37 reported that the use of multi-lateral wells from two vertical wells in

a coal seam has proves successful for a CBM operator. Vitruvian Exploration,

LLC38 (formerly known as CDX Gas, LLC) developed an underbalanced drilling

method in which air is injected down the adjacent well to the well being drilled.

The method requires drilling lateral wells from the horizontal section of a vertical

well. This invention for coalbed methane horizontal drilling and completion

systems is called the Z-PINNATE technology. The company gives some

advantages of pinnate wells pattern as:

a. wells can drain up to 2000 acres from a single drill pad;

b. gas is produced immediately;

c. peak gas production is reached quickly, unlike a vertical wells in CBM

reservoir;

d. wells can drain a reservoir in 2 to 4 years;

e. gas recovery is high (80 to 90%); and

f. high gas flow rates (1 to 5 MMcfd) can be achieved


34

The company indicates that the pinnate pattern is specifically developed for low

permeability coalbed methane reservoirs, and therefore, not suitable in high

permeability coals, as many cases of lateral collapses have occurred. Figure 1.7

is a pictorial configuration of pinnate well pattern.

Figure 1.7: Pinnate pattern drilling and completions technique (after CDX38)

Horizontal well accelerates dewatering process and increases gas production

rates. For this to be achieved, the well has to be drilled perpendicular to the

direction of face cleats. Also, the horizontal well has to be drilled perpendicular to


35

direction of maximum principal stress, in order to maintain wellbore stability.

Diamond39 listed examples of successes recorded from horizontal wells for gas

drainage in coal mines. The drainage is purely for safety reasons and not for

methane gas production as a natural gas. The examples are summarized below:

a. In Utah, two horizontal wells produced 140 Mscf/day of methane gas over

a period of six months.

b. In Pennsylvania (Pittsburg coal), four horizontal wells of lengths ranging

from 982 ft -2505 ft produced a combined total of 580 Mscf/day of

methane gas at the initial stage, but declined to 234 Mscf/day after about

32 months; with a combined total of cumulative gas production of 255

MMscf.

c. In Marylee coal in Alabama, a 1010 ft horizontal well produced methane

gas at a rate of 200 Mscf/day initially, but declined to 65Mscf/day in one

year; with a total cumulative gas production of 40 MMscf.

When considering production of methane as natural gas energy sources,

horizontal wells have been tried out in San Juan Basin with mixed results.

Watson40 reported the results of two wells that were drilled in the Basin. One was

successful and the other was not. The well that was successful has good

permeability and well developed cleat system, while the well that was not


36

successful has opposite reservoir qualities. The success of these wells was

measured by their productivities.

One major reservoir parameter that lends itself to horizontal drilling is the

permrability anisotropy of the reservoir. The higher the permeability anisotropy,

the more favorable is using the horizontal well technique in coalbed methane

reservoir. Joshi41 derived an equation that compares the productivity of horizontal

well to that of vertical well. The equation is used to determine the type of drilling

technique to adopt between vertical and horizontal wells in a particular formation.

Cameron et al42 modified Joshi’s equation for coalbed methane reservoirs. The

modified equation is given as:

386.175.02

ln

75.02

ln

−+++−

+−

=

cahhmhw

e

w

e

v

hanisot

v

h

SSSr

r

Sr

r

H

HK

Q

Q

1.6

−=

wh r

LS

4ln

1.7

Where;

Kanisot = permeability anisotropy (Kmax/Kmin)

Hh = thickness of the coal seam containing the horizontal wellbore, ft


37

Hv = sum of all completed seams in a vertical well, ft

re = drainage radius, ft

rw = wellbore radius, ft

S = negative vertical skin factor due to stimulation

Smh = mechanical skin damage to a horizontal well

Sh = negative skin factor due to the horizontal well

Scah = shape related skin factor (function of drainage shape, well length, Hh, and

Kv/Kh) given by correlation derived from charts

L = horizontal length of wellbore, ft

Cameron et al42 concluded that production rates from horizontal wells will be

more than the rates from vertical wells if Hh/Hv > 0.2 and if Smh is < 2. 0. The

Figure 1.8 shows all the types of drilling and completions method available for

coalbed methane production.

The well spacing configurations determine the number of wells that are required

to produce a given drainage area of coalbed methane reservoirs. Factors that

influence well spacing in CBM production are:

1. well interference

2. permeability

3. permeability anisotropy, and

4. hydraulic fracturing length


38

Unlike in conventional reservoirs, well interference enhances coalbed methane

production, provided the dewatering of coal seams is facilitated by the

interference. Rogers et al8 writes on a study that shows gas and water production

Figure 1.8: Drilling and Completions method (after Sunil43)

extend further in the face-cleat direction, making permeability anisotropy an

important factor in CBM well spacing. The longer the fracture length, the smaller

the number of wells required to produce a CBM field. They further stated that an


39

optimum well spacing for the most economical development of a CBM field can

only be obtained by simulation; where the combined effects of permeability,

permeability anisotropy, and fracture length on interference are considered.

There are different types of well pattern configuration in CBM, as do exist in

conventional reservoirs. The only major difference between CBM and

conventional reservoir is that CBM usually requires more wells than conventional

reservoir for the same drainage area.

If the target coal seam is in an area that has been reclaimed due to mining

operation, air drilling may be required to drill through the reclaimed top soil. This

is because the reclaimed top soil usually has high permeability. The use of

conventional drilling fluids (liquids) will result in high degree of lost circulation.

The use of air as drilling mud prevents such lost circulation from taking place.

1.4.2 Completions

The Figure 1.9 gives the detail of the completions and stimulation techniques that

have been employed in the various coal Basins in the United States. Sunil43

listed the CBM reservoir parameters that influence the selection of drilling and

completion method; and these parameters are as follows:

a. effective thickness of coal net seam

b. coal seam gas content


40

c. coal rank

d. coal seam depth

e. permeability

f. areal extent of coal

g. compressive strength

h. dip of the coal

i. number of coal seams

j. vertical distribution of coal seams

Of the aforementioned parameters, permeability and gas content are the most

important.

Figure 1.9: Completions and stimulations methods in the US coal Basins (after Sunil43)


41

Different types of completion methods exist. They include:

a. natural vertical open-hole completions

b. vertical open-hole cavity completions

c. vertical cased-hole completions

d. horizontal completions, and

e. vertical with top-set under-ream completions

The vertical cased-hole method can either be single zone or multi zone

completions. Sunil43 developed a chart, shown in Figure 1.10, for drilling and

completion candidate selection based on these reservoir parameters and

completions methods.

1.5 Production Engineering of Coalbed Methane Reser voir

The two principal reasons why methane gas is being produced from coalbeds

are:

1. mine safety, and

2. production as natural gas energy

The Mine Safety and Health Administration (MSHA) sets the threshold for

methane concentration in coal mine for safe mining operations. Any

concentration of methane gas the threshold will constitute safety hazard for


42

miners, especially in underground mining operations. Thus, mines are first

degassed to reduce the methane concentration the level set by the MSHA before

coal mining takes place. The produced gas, from mining operation point of view,

is an unwanted (hazardous) component of the mine. Here, the coal is the target

resources.

The methane gas is also produced as natural gas resources. In this situation, the

gas is the target resources while the coalbeds only serve as the reservoir rocks.

Figure 1.10: Decision chart for selecting the drilling and completion method (after Sunil43)


43

1.5.1 Water Production

Most coalbed methane reservoirs are under-saturated. Hence, water must first

be produced, reducing the reservoir pressure to the critical desorption pressure

(CDP), in order to enhance methane gas production. Equation 8 is used to

calculate the amount of water produced at CDP.

)( diitp PPWcW −= 1.8

fwt ccc += 1.9

wii hSAW φ7758= 1.10

Where;

Wp = Water required to be produced for gas desorption to commence, bbls

Wi = Water initially in place in the drainage area, bbls

cw = water compressibility, psi-1

cf = formation compressibility, psi-1

pi = Initial reservoir pressure, psia

pd = Desorption pressure as determined by the Langmuir isotherm, psia

1.5.2 Gas Production

The methane gas production starts once the CDP is attained from the dewatering

process.


44

1.5.2.1 Initian Gas-in-Place

The initial gas-in-place defines the total volume of methane gas present in a

given coal field, either recoverable or not. Initial gas-in-place is calculated from:

−−+

−= )1(359.1

)1(43560ccgi

gi

wfifi waC

B

SAhG ρ

φ

1.11

Where;

Gi = Gas in Place at initial reservoir conditions, Mscf

A = Drainage area, ac

h = coal thickness, ft.

φf = Interconnected fracture (effective) porosity, fraction

Swfi = Interconnected fracture water saturation, fraction

Bgi = Gas formation volume factor at pi, rcf/Mscf

Cgi = Initial sorbed gas concentration, scf/ton, dry, ash-free coal

ρc = Pure coal density, g/cm3

fa = Average weight fraction of ash, fraction

fm = Average weight fraction of moisture, fraction

43560 = Conversion factor, ft2/ac

As mentioned earlier, the process behind CBM production is to dewater the

reservoir until the critical desorption pressure is attained. The initial water


45

saturation in coal cleat is usually 100%. As mentioned earlier, dewatering can

take up to a year in some coal before reaching CDP. At CDP, gas starts to

produce and the water saturation progressively reduces as more and more gas is

being produced. It is worth mention that the cleat permeability increases at the

later stage of CBM production due to shrinkage of the coal matrix. Water is

usually produced through the tubing while gas is produced through the annulus

between tubing and casing, and sent to gas storage facility through pipelines.

The flow of gas from the micropores to the coal cleats is governed by diffusion

while the flow of gas within the cleat system and to the annulus is governed by

Darcy’s flow.

The gas produced (GP) at abandonment pressure is the difference between the

initial gas-in-place (GIPi) and gas-in-place at an abandonment pressure (GIPa).

That is:

aip GIPGIPG −= 1.12

Where

Gp = gas produced (recoverable gas reserve)

GIPi = initial gas in place

GIPa = gas in place at abandonment

The recovery factor is calculated as:


46

a

ai

V

VVRf

−= 1.13

And in terms of gas in place,

i

p

G

GRf =

1.14

Where;

Rf = Recovery factor, %

Vi = initial volumetric gas content, scf/ton

Va = abandonment gas content, scf/ton

Gp = Methane recoverable reserves, Mscf

Gi = Initial gas in place, Mscf.

1.5.3 Enhanced Coalbed Methane Production

Since there is practical limit for lowering total pressures on coal seams in order to

maximize recovery, it is feasible to achieve high recovery of methane by two

methods:

a. reducing the partial pressure of the methane, for example, by injecting

nitrogen into the reservoir, and

b. injecting CO2 to displace methane from coal seams


47

These processes are called Enhanced Coalbed Methane (ECBM) recovery. This

is tantamount to what is obtained in the conventional reservoir as Enhanced Oil

Recovery (EOR).

1.5.4 Well Stimulation/Hydraulic Fracturing

Generally, coalbed methane reservoir will not give up its methane gas content at

commercial rates unless it is stimulated; commonly by hydraulic fracturing. This

is due to its characteristically low permeability. When properly executed, the

hydraulic fracturing technique increases the near-wellbore formation

permeability; thereby facilitating faster dewatering of coalbed methane reservoir

and creates paths for gas to flow from the formation to the wellbore. Progress

has been made to improve on the application of hydraulic fracturing technique

since it was first applied in coalbed methane reservoirs. Extensive researches

have been carried out by the Gas Research Institute on the application of

hydraulic fracturing technique in the Black Warrior Basin. Their works have led to

improved field practices and cost reduction in other coal Basins.

Whereas hydraulic fracturing is a common practice in conventional low

permeability sandstone gas reservoirs, Rogers et al8 listed the following reasons

for modifications of the stimulation technique before it can be extended to

coalbed methane reservoirs:


48

a. the surface of the coal adsorbs chemicals of the fracturing fluid

b. the coal has an extensive natural network of primary, secondary, and

tertiary fractures that open to accept fluid during hydraulic fracturing but

close upon the fluid afterwards, introducing damage, fluid loss, fines, and

treating pressures higher than expected

c. fracturing fluid can leak deep into natural fractures of coal without forming

a filter cake

d. multiple, complex fractures develop during treatment

e. high pressures are often required to fracture coal

f. Young’s modulus for coal is much lower than that for conventional rock

g. induced fractures in some vertical CBM wells may be observed in

subsequent mine-throughs

h. horizontal fractures occur in very shallow coals, such as the Pratt group in

the Black Warrior Basin

i. fines and rubble result from fracturing brittle coal

j. coal seams to be fractured may be multiple and thin, perhaps only 1 or 2ft

thick, requiring a strict economical approach to the operations

Different methods currently exist in hydraulic fracturing of coalbed methane

reservoirs. They include:


49

a. water without proppant

b. water with proppant

c. CO2 or N2 gas with proppant

d. CO2 or N2 without proppant

e. foam with proppant, and

f. cross-linked gel with proppant

The proppant can either be sands or ceramics. The candidate selection for the

type of hydraulic fracturing method to be employed in a given coalbed methane

reservoirs takes into account the:

a. reservoir pressure gradient

b. reservoir permeability, and

c. formation water saturation

1.6 The Illinois Coal Basin

Watson40 gave the detailed description of Illinois Coal Basins, including the

geologic transformation of the Basin. Therefore, attempt will not be made to

duplicate such effort in this work. This section primarily describes the suitability of

Illinois coal Basin for horizontal well development, especially the Seelyville coal

(coal III) in Indiana; where the waterjet horizontal drilling technology was carried

out. Listed are the average formation properties and formation characteristics of

Illinois coal Basin.


50

a. (Low) Gas Content: 30 to 150 scf/ton, DAF

b. (Low) Gas In Place: 5 to 21 Tcf

c. Net Coal Thickness: 15 to 35 ft

d. Coal Rank: hvCb to hvAb; hvBb is common

e. Moisture Content: 5 to 19 %

f. Ash Content: 1 to 25 %

g. Sulfur (Pyrite): 2 to 11 %

h. Volatile Matter: 28 to 41 %; Nitrogen: 15 to 20 %

i. Permeability: 1to 50 md

j. Permeability anisotropy: between 10 to 40

k. Average depth: 600 to 900 ft

l. Regional Pressure Gradient: 0.455 psi/ft

m. Formation Pressure: 267 to 400 psi

n. Formation Temperature: 72oF

There are seven major coalbeds in Illinois Basin. They include:

a. Danville/Baker

b. Hymera/Jamestown/Paradise

c. Herrin

d. Springfield,

e. Survant

f. Colchester, and


51

g. Seelyville/Davis/Dekoven

The classification is largely based on the formation properties; namely the:

a. Extent

b. Thickness

c. Depth

d. Elevation, and

e. Coal qualities

Each of the seven coalbeds has similar formation properties, even though they

cut across the three states of Illinois, Indiana, and Kentucky. There are about

seventy-five coalbeds that have been discovered in Illinois Basin. Drobniak et al44

developed the lithostratigraphy of the Pennsylvanian system in the Illinois Basin,

as shown in Table 1.5. Those in red color are the major coalbeds mentioned

1.6.1 The Seelyville Coalbed

The Seelyville coalbed, located in both Posey and Gibson Counties in Indiana, is

the candidate selected for this research. It is part of the Linton formation in the

Carbondale coal group. Drobniak et al45 carried out some studies on the

Seelyville coal to determine its methane gas production potentials. The result of

their work is summarized below:


52

a. Gas-in-place: 1.5 to 3 Tcf

b. Gas content (determined by canister desorption technique): 15.4 to 182.2

scf/ton, DAF

c. Gas content (calculated using Kim formula): 24.5 to 333.5 scf/ton, DAF

The calculated gas content using Kim formula is significantly higher than that

measured directly. Two reasons could have caused the disparity. The first is that

the lost gas might not have been well accounted for in the measurement and the

second is that the Kim equation could have over-estimated the gas content.

Drobniak et al45 found out that the distribution of gas content in the Seelyville

coalbed is very complex and cannot be quantified only by coal rank. They

concluded that ash content, lithology of the overlying strata, and other factors

(such as depth of burial) influence the distribution of gas content in the Seelyville

coalbed. An Indiana Geologic Survey study found that the coal cleats were

initially filled with kaolinite, which helps preserve the cleat systems, and later with

calcite. The presence of these ash-forming minerals reduces the gas content, as

well as the cleats’ permeability. Mastalerz and Kvale46 suggested, from their

works, that the variation is gas content distribution might partly be due to

migration of methane gas into surrounding sandstone formations. The depletion

of methane gas, due to the said migration, is responsible for the low gas content

in the Seelyville coalbed; and generally in the Illinois coal Basin.


53

Watson40 carried out two pilot projects on Seelyville coalbed and conducted

Injection fall-off test, in order to determine the coal permeability. The two pilot

projects consisted of five vertical wells. One project was in the Posey County

while the other was in Gibson County. He found out that the Seelyville coalbed in

Posey County has an average permeability of 1md while the same coalbed in

Gibson County has an average permeability of 20md. His work confirmed already

established fact that the Illinois coal Basin has very high permeability anisotropy.

The permeability anisotropy is due to the poorly developed butt cleat system in

the Basin. The modified Joshi’s equation indicates that horizontal well performs

better than vertical well in formation with high permeability anisotropy. Therefore,

the significantly high permeability anisotropy in Seelyville coalbed makes

horizontal well a viable completion method in the coalbed.

1.7 Current Challenges in Coalbed Methane Productio n

Despite the unprecedented breakthroughs in coalbed methane production

technology, some coalbed methane reservoirs are currently not commercially

viable under the current technology, even though they have great potential for

methane gas production. These reservoirs typically have low permeability (about

1md), thin coal seams, contain some minerals in their cleat systems, and are

bounded by active water. The current challenge is to explore means of turning

these reservoirs into assets.


54

Table 1.5: Lithostratigraphy of the Pennsylvanian System in the Illinois Basin


55

One possibility is to explore another fracturing fluid that can dissolve the mineral

matters in the cleat systems and also chip off some of the coal seams along the

cleat systems (to increase permeability). A method to remove the dissolved and

chipped particles should be devised, to prevent them from clogging the fractured

flow path; thereby causing skin damage to the coal seams around the wellbore.

The proposed fluid should be designed in a way that its use should preserve the

integrity of the coalbed methane reservoirs.

Another possibility is to develop an improved horizontal drilling technique that will

increase the Maximum Reservoir Contacts (MRC), so that the rate at which

dewatering of the coal seams takes place is greater than the rate at which the

seams are being charged by the surrounding water. It is believed that waterjet

horizontal drilling technique provides the answer. This is the focus of this

research.


56

CHAPTER II

LITERATURE REVIEW

2.0 Review of Waterjet Technology

This chapter deals with the literature review of the scientific theory behind the

ability of a volume of water leaving the nozzle to cut rocks. This process is called

waterjetting. The equations involved in waterjet operations, from the pump to the

orifice of the nozzle and rock face, will be reviewed. Also, the mechanism and

process involved in the ability of jets to disintegrate solid materials, like a coal

seam, will be discussed. Lastly, previous works on the use of waterjet technology

for drilling will be reviewed.

2.1 Background

Waterjet technology has been in existence for decades. Its applications in

industrial cleaning, mining, mechanical, and civil engineering have been well

established. However, its use in petroleum industry, especially in coalbed

methane, for both drilling and stimulation operations is only just emerging. By

definition, waterjetting is the development, transmission, and application of force;

using water as a medium. The waterjet system requires some basic equipment to

operate; which are: water tank, pump, lance (or hose), nozzle, and orifice.

Figures 2.1 and 2.2 are examples of simple configuration of water jet systems.

Water, from the water tank, flows into the pump. The pump, with the aid of the


57

motor, exerts pressure on the water as it flows through the high pressure hose

(see Figure 2.1). There is usually a coupling that connects the high pressure

hose to the control device. The device houses the control valve, the trigger, and

the trigger guard; as shown in Figure 2.2. The valve controls how much water

flows into and out of the nozzle. There are usually two lines that extend out of the

control valve: the high pressure line and the dump line. The dump line is usually

not under pressure. It is used to direct water into an open air or back into water

tank. The high pressure line connects the nozzle with the hose/control device.

The trigger directs the water, either along the high pressure line to the nozzle or

along the dump line. The combination of the high pressure line and the nozzle is

called the lance, while the combination of the lance, the trigger, the trigger guard,

and the control valve is normally called the waterjet gun.

The jets of water leave the orifice of the nozzle as a stream of water. There are

different types of water streams that leave the orifice of the nozzles. The most

common is usually in cylindrical shape, but it is often referred to as a round jet.

The major disadvantage of this type of water stream is that the area of impact is

very small. In other to increase impact area, the jetting is usually design such that

the stream is made to spread out as it leaves the nozzle orifice. This type of

stream is called a fan jet. Improved technology has resulted into development of

some nozzles that changes the shape of the stream from the cylindrical to fan

shape. These shapes that result from new nozzle designs are mainly triangle and


58

square, but other shapes have also been reported. These types of jets are called

shaped jets.

Figure 2.1: A typical configuration of waterjet system (after Summers47)

Figure 2.2: A typical configuration of waterjet system (after Summers47)


59

The definition of waterjet has been loosely expanded to include other types of

fluid or materials, depending on the usage of the technology. For instance, when

fluid other than water is being used for cutting or cleaning, it is called a fluid jet.

Waterjet cutting or cleaning ability can be enhanced in order to increase its

performance. Where waterjet is to be used to cut very hard materials, such as

glass or metal, it is usually difficult for water to penetrate the materials. In order to

increase the cutting ability of the waterjet, abrasive materials are usually added

to the stream. This is called an abrasive waterjet. In order to reduce the pressure

losses in the lance or hose, polymeric additive materials are added to the stream

of water. Summers47 wrote that the additive materials alter the chemical

properties of the stream to reduce pressure losses due to friction which is

generated as the water flows along the walls of the delivery pipe. He also

indicates that the molecular polymers help “glue” the water together after it has

left the nozzle, keeping the stream together and at its delivery speed, over a

greater distance from the nozzle, and thus increasing its effectiveness. This type

of jetting can be referred to as polymer or additive jet. The polymer can be

added to both the conventional (plain waterjet) and abrasive waterjet to improve

their performances. Pulsating waterjet is another method of enhancing the

performance of waterjet systems. In this method, Summers47 wrote that the

overall power in the jet is altered into pulses, which generate alternative very high

and much lower pressures, on the target surface.


60

The pressure provided by the pump is expended in two ways: to drive the stream

of water from the pump, through the pipe/hose, to the nozzle (thereby causing

pressure losses); and to drive the water through the orifice of the nozzle, at a

given velocity, to the target surface. The most important parameter in the cutting

ability of waterjet, as it hits its target, is the velocity at which the stream leaves

the nozzle orifice. It is a common knowledge that the water stream will no longer

be under pressure once it leaves the nozzle. Then the question is “what is the

relevance of attempting to reduce the pressure losses, due to friction and

turbulence in the pipe/hose; and what is the importance of maintaining sufficiently

high pressure at the nozzle, if the pressure drops to zero as the stream leaves

the nozzle”? The answer is: a given amount of pressure must be exerted by the

pump to push a given volume of water through the orifice within a given time.

When the pressure drop is minimal and sufficiently high pressure is maintained at

the nozzle, the velocity at which the stream of water leaves the nozzle will be

very high and the jets will carry much energy with them. When the jets hit its

target, the energy embedded in them is converted back to pressure, called

impact pressure. This is the pressure that actually does the work of cleaning or

cutting the target. The impact pressure produced at the target largely depends on

the volume of water arriving at the target, and the velocity at which the water

arrives at the target. The arrival velocity depends on both the volumetric rate of

water flowing in the line and the internal diameter of the orifice at the end of the

nozzle. The volume of water flowing in the line is controlled by the pressure at


61

which the pump is operating (or pressure at the nozzle) and the internal diameter

of the pipe/hose. The flow velocity and the internal diameter of the flow line or

orifice (or area of the line/orifice) define the volumetric flow rate of the water.

When the water density is factored in, the three parameters define the mass flow

rate of the water arriving at the surface to be cut.

There is usually a distance which the water leaving the orifice has to travel before

it hits the target surface. This distance is called the stand-off distance. The longer

this distance, the more energy is lost before the jets reach the target surface.

This distance has to be optimized for effective operation of waterjet systems.

When the distance is too far from the cutting face, it will result in lack of sufficient

energy to cut the target and when it is too short, it will make nozzle to stop

spinning (rotating), and will not cut the target.

Waterjetting has been defined as the use of water, with or without the addition of

other liquids or solid particles, for both cleaning and cutting purposes. WJTA48

further classified waterjet systems according to its operating pressure. These are:

a. Pressure Water Cleaning : when water under pressure is being used for

cleaning purpose and when the operating pump pressure is 5,000 psi.

b. Pressure Water Cutting: when water under pressure is being used for

cutting purpose and when the operating pump pressure is 5,000 psi.


62

c. High Pressure Water Cleaning: when water under pressure is being

used for cleaning purpose and when the operating pump pressure is

between 5,000 psi and 30,000 psi.

d. High Pressure Water Cutting: when water under pressure is being used

for cutting purpose and when the operating pump pressure is between

5,000 psi and 30,000 psi.

e. Ultra High Pressure Water Cleaning: when water under pressure is

being used for cleaning purpose and when the operating pump pressure is

30,000 psi.

f. Ultra High Pressure Water Cutting: when water under pressure is being

used for cutting purpose and when the operating pump pressure is 30,000

psi.

This project falls under the High Pressure Water Cutting. The objective of this

work is to extend waterjet technology to drilling horizontal wells in coalbed

methane reservoir, as a cheaper alternative to conventional horizontal drilling

technique.

2.2 Design of Waterjet Systems

This section reviews with the equations involved in designing waterjet systems.

Accurate project design is a key to the success of waterjet operations. Below are

the various calculations that are required for the design of waterjet systems.


63

2.2.1 Power Calculation

A pump, powered by a motor, is required to drive the water into the flow line.

Waterjet project is usually designed for a predetermined flow rate and pressure.

Given these parameters, the capacity of the pump required for the project can be

determined using equation 2.1

2.1

Where:

Hp = Horse power

P = pump pressure, psi

Q = flow rate, gpm

The equation 2.1 can also be re-arranged to determine both the flow rate, Q, and

the pressure, P. It is a common phenomenon that the total estimated power of

the pump is usually not available for the pump’s operation. In other words, the

estimated volume of water designed to be delivered into the flow line by the

pump of an estimated capacity may be less than what was originally intended.

Two factors are responsible for this: (1) the motor transmitting the power to the

pump does not usually operate at 100 percent efficiency, and (2) there could be

some small leaks, either intentional or unintentional, in the flow system. The

intentional leaks are meant to lubricate the system.

1714

*QPHp =


64

2.2.2 Pressure Loss through Pipe or Hose

Pressure loss in pipe or hose occurs due to friction in the pipe or hose and due to

flow turbulence. Equation 2.2 from Wright49 is used to estimate the amount of

pressure loss in a pipe.

2.2

Where;

∆P = pressure loss in pipe or hose, psi

d = internal diameter of the pipe/hose, in

∆L = pipe/hose stretch due to pressure, %

Lp = pipe or hose length, ft

From the equation 2.2, the pressure loss increases as the flow rate increases

due to increase in flow turbulence. It reduces with increase in internal diameter

and stretch of the pipe/hose. Also, the pressure loss increases as the pipe/hose

length increases. The pipe/hose stretch is the percentage of increase in the

length of the pipe/hose when subject to high pressure. This parameter is often

difficult to determine when working with long pipe/hose section and is usually

neglected in pressure loss calculation. In order to optimize pressure loss in the

2

5.0

5.2

100

153

∆+=∆

pL

Ld

QP


65

flow line and maximize pressure at the nozzle, a line with sufficient internal

diameter and optimum flow rate is required for a specified length of pipe/hose. It

is also recommended that the amount of couplings in the flow line be reduced in

order to maximize pressure at the nozzle.

2.2.3 Pressure at Nozzle

The pressure delivered at the nozzle is simply the difference between the

pressure at the pump and the pressure loss. This is the pressure that determines

the effectiveness of the jetting operations because this pressure is converted to

the flow velocity that is reconverted back the pressure, normally called the impact

pressure. When the pressure at the nozzle is not sufficient, the amount of energy

in the volume of water leaving the nozzle is reduced, which consequently

reduces the amount of energy or pressure available to perform the job of cutting

the target. Therefore, it is always recommended that sufficient pressure is

provided at the nozzle. The pressure at the nozzle can be estimated from

determining the amount of pressure required to initiate cutting of a target. This

pressure is called Minimum Cutting Pressure (MCP). This pressure varies from

material to material. As a rule of thumb, the Optimum Cutting Pressure (OCP) is

usually three times the MCP. Therefore, the pressure at the nozzle should be

equal to the OCP, at the minimum. Once both the pressure at the nozzle and the

pressure loss in the pipe/hose are known, the waterjet operation can be designed


66

to have the required pressure at the pump by adjusting the flow in the line. The

pressure at the nozzle is calculated from equation 3.3, given as:

2.3

Where;

PN = pressure at nozzle, psi

2.2.4 Pressure Loss through Nozzle

Wright49 developed an empirical equation, equation 2.4, to calculate the pressure

loss through the nozzle, as the fluid flows across the nozzle and jets out through

the orifice. The equation is given as:

2.4

Where;

∆PN = pressure loss through the nozzle, psi

QN = Nozzle flow rate, gpm

Cv = flow rating, dimensionless

The flow rating is a constant term, which is usually set at 2.5.

2

=∆

v

NN C

QP

PPPN ∆−=


67

2.2.5 Orifice Size

It is always required to determine the internal diameter of the orifice to be

inserted in the nozzle head. This value depends on the volumetric flow rate of the

fluid (water), the pressure at the nozzle, the number of jets (orifice) to be used for

the predetermined flow rate, and the overall efficiency of the nozzle. The

equation 2.5, developed by Wright49 is used for the calculation.

2.5

Where;

do = internal diameter of orifice, in

Cd = flow efficiency, dimensionless

N = number of jets (orifice) required, constant

The equation 2.5 can be re-arranged to give equation 2.6, which can be used to

calculate the total flow that passes through the nozzle.

2.6

The nozzle flow rate increases with increase in internal diameter of orifice,

pressure at the nozzle, number of jets, and flow efficiency. The value of this flow

5.0

5.0 ***92.29

=

NCP

Qd

dN

No

dN CNPdQ ****92.29 5.020=


68

rate must be equal to the pump outlet flow rate, in order for the law of

conservation of mass to hold. The pump outlet flow rate is calculated from

equation 2.7 as:

2.7

Where;

Qp = pump outlet flow rate

2.2.6 Jet Reaction Force

The jet reaction force is the backthrust or force an operator of waterjet equipment

may experience in holding a waterjet gun. The force depends on the pressure at

the nozzle, the nozzle efficiency, number of jets, and orifice size. The WaterJet

Technology Association48 (WJTA) has recommended that no one operator

should be allowed to handle more than one-third of their body weight. The

reaction force is calculated using equation 2.8, developed by WJTA.

2.8

Where;

FR = jet reaction force, lbs

dNR CNdPF ****561824.1 20=

231

)(*)( inchesntDisplacemerpmSpeedQp =


69

2.2.7 Jet Thrust/Pulling Force

This is the force required to pull the pipe/hose as the jets of water leaves the

orifice or the nozzle. The pulling force depends on the water flow rate, pressure

at the nozzle, and the jet angle. The pulling force can be calculated using

equation 2.9, developed by Wright49, and it is given as:

2.9

Where;

FP = pulling force, lbs

θ = jet angle, degree

π = 3.142

The pulling force increases with increase in nozzle pressure, flow rate, and jet

angle.

2.2.8 Flow Velocity

The amount of pressure at the nozzle determines the velocity at which the jet

flows to the target face. The pressure is converted to velocity and carries energy

with it to the target surface. The flow velocity increases with pressure at the

nozzle. It is calculated from equation 2.10, given as:

Π=180

*cos*0522.0 5.0 θNNP QPF


70

2.10

Where;

V = flow velocity, ft/sec

It is recommended that the waterjet system is designed to generate flow velocity

high enough to create impact pressure at the surface of the target, sufficient

enough to cut the target material.

2.2.9 Impact Pressure at the Surface

When the jet of water leaves the nozzle, it is no longer under pressure. The

pressure at the nozzle is converted to energy within the jet, as it leaves the

nozzle head. This energy is reconverted back to pressure, known as impact

pressure, upon reaching the surface of the material to be cut. The impact

pressure is calculated from equation 2.11, developed by Wright49, and it is given

as:

2.11

Where;

−

=100

*00177072.0*022.81

o

SN

I

d

DEXPP

P

5.07.14 NPV =


71

PI = impact pressure, psi

DS = stand-off distance, ft

Figure 2.3 shows a three dimensional view of the effects of nozzle pressure,

stand-off distance, and orifice diameters on the impact pressure. The impact

pressure increases with increase in pressure at the nozzle, internal diameter of

orifice, and with decrease in stand-off distance.

2.3 Mechanism of Rock Failure

In rocks, such as coal, failure or disaggregation under waterjets is in stages.

Summers50 wrote about this sequence.

“First, the water will penetrate into any cracks, crevices, or grain boundaries of the solid. These small ‘fluid wedges’ are then pressurized by the impact of subsequent segments of the waterjet. This has the effect of growing the crack to the point of crack coalescence and particle libration. In many larger particulate solids, the largest cracks are along the existing boundaries of the individual grains. This means that the jet will break the rock down into its individual grain constituents, if the process is correctly applied”.

Iyoho et al51 explained further that the jet which arrives at a surface will, under

normal circumstance, have a rapidly changing pressure level across its diameter.

Once it arrives at the surface, the waterjet will immediately penetrate any flaws

present in the rock. Such penetration will cause the cracks to extend and the

differential pressure across the jet diameter will cause the rock to disaggregate

into particles. In his own work, Brace52 pointed out that such flaws (natural

cracks) typically exist at half the grain size of the target materials.


72

In coal, disaggregation occurs along the existing vertical and horizontal planes of

weakness, called “cleats”. When the jet intersects the cleats under high pressure,

it will flow along the coal natural factures, breaking the coal along the planes of

weakness. Experiments have shown that the hole created by this mechanism is

usually rectangular, rather than circular in nature.

Figure 2.3: The effect of nozzle pressure, stand-off distance, and orifice size on impact pressure


73

2.4 Drilling of Horizontal Well by Waterjet Technol ogy

Most of the research, field trials, and application of waterjet drilling technology

have been carried out in coal, either for degassing the mine prior to actual coal

mining or for creating rock bolt holes. The choice of coal, as a candidate rock for

research and field trials of waterjet drilling technology, is mainly due to its low

compressive strength; as opposed to other type of (harder) rock. However, series

of laboratory and field trials have also been carried out on the application of

waterjet technology to drill oil wells; especially in sandstone formations. The

majority of the holes so far drilled by the technology are horizontal. Application of

waterjet technology for drilling horizontal wellbores is divided into three main

categories:

a. Waterjets conveyed by metallic material as drillstring

b. Waterjets conveyed a combination of metallic rod and hose as drillstring,

and

c. Waterjets conveyed only hose as a drillstring

2.4.1 Waterjet with Metallic Material as Drillstrin g

This type of drillstring is being used mostly in the oil and gas industry to drill

conventional horizontal wells. A combination of coiled tubing and conventional bit

are being used to drill horizontal well. It is not the intention of this chapter to

review the application of conventional coiled tubing in drilling horizontal wells,

since this has been extensively dealt with in the literature. Nevertheless, it is


74

important to define what this section means by conventional coiled tubing. It is a

method of drilling horizontal wells in which the vertical section of the well is

inclined slowly until it reaches the horizontal section with the use of conventional

drill bit as opposed to waterjet technology (nozzle or waterjet-assisted drill bit as

drillheads). The point where the inclination begins is called the kickoff point.

Horizontal wells are usually defined by their radius of curvature. Shelkholeslami

et al53 define horizontal wells as follows: wells with arcs of 3 to 40 foot radius are

defined as short-radius horizontal wells. Medium-radius wells have arcs of 200 to

1,000 foot radius, while long-radius wells have arcs of 1,000 to 2,500 feet. The

required horizontal displacement, length of the horizontal section, position of the

kickoff point (from the vertical), and completion constraints are generally

considered when selecting a radius of curvature of a conventional horizontal well.

Generally, the characteristics of reservoir candidates for horizontal wells are:

a. low permeability reservoir

b. thin formations

c. layered formations

d. naturally fractured formations

e. high reservoir anisotropy


75

Summers54 et al carried out the first experiment on horizontal drilling of coal,

using waterjet technology, in 1978. A nozzle was attached to a drill rod and field

tested in a coal outcrop. The trial was designed to drill up to 49 ft at the rate of

penetration (ROP) of 3.28 ft/min. the first hole drilled interestingly exceeded the

set goal. The goal of the project was to find an improved way to degasify a coal

mine before mining operations. They found out that the dimensions of the drilled

holes were roughly square in nature and that the holes were larger than the size

of the nozzle head used in the drilling. The larger than expected borehole sizes

(or annulus between the drillstring and the coal walls) posed the problem of

reduced velocity at which spent water flows out of the hole. When the velocity is

reduced, the ability of the spent water to carry cuttings is hampered; especially

the larger particles. As experienced by Summers54 et al, the particles from the

drilling, which are being carried out of the hole by the water, tended to settle

along the walls of the drilled holes. The continuation of the particle settling on top

of each other resulted in blockage. The blockage caused a pressured build-up

behind and which farther reduced the cutting ability of the waterjet. To solve this

problem, they frequently pulled back the drill assembly out of the hole before

feeding it back again. The advantage of this method is not only in preventing the

build-up of the particles and improving the flow of spent water, it also helps in

breaking down larger particles into smaller ones; thereby enhancing their

potential to be carried out of the hole.


76

One method for reducing the size of holes during drilling is to increase the rate of

penetration, so that the retention time of the jets per foot is reduced, thereby

making smaller holes. Another method is to reduce the rotational speed of the

drill assembly. A third method is in nozzle selection. A nozzle configuration with

jet angle of 900 degrees will make larger holes than those nozzles without 900

degrees jet angle.

The major challenge in horizontal drilling in coal with metallic materials, like drill

rod, is the bending through the corner from the vertical section to the horizontal

section. One method to solve this problem is to allow only the drill head to rotate

while not rotating the drill pipe. The high pressure waterjet connections in the drill

assembly should be design to be able to turn the corner as well. Researchers

have concluded that the head will need both a drive motor to rotate and the

waterjet connections will need a high pressure water swivel to be able to turn the

corner. Several motors and swivels are now available for this type of drilling

assembly. Baker and Timmerman55 pointed out one particular design, shown in

Figure 2.4, which did not require swivel. This tool was field tested and it was able

to drill holes up to 98 ft in length at an average rate of penetration of 1.97ft/min.

The bending radius with this type of drilling assembly is usually large because of

the space required for the head assembly (nozzle, nozzle swivel, and motor) to

bend into the horizontal section of the holes. This type of drillstring assembly has

found its application in conventional drilling of oil wells. In his work, Maurer56


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carried out researches on twenty-five novel methods suggested by researchers

for improving drilling of oil wells. He found out that waterjet-assisted rotary bit is

the most promising as most of the rest were unlikely to improve the rate of

penetration or costs over conventional drilling technique. According to Maurer et

al57, Esso Production Research carried out studies on high pressure jet cutting.

The first jet bit tested contained two jets each with 3.81 mm in diameter and was

tested at a pressure of about 10,290 psi. A second bit was also tried in the

laboratory at a pressure up to 14,700 psi. The second bit contained five nozzles

and the rate of penetration recorded in the laboratory experiment ranged

between 54 and 90 m/hr. Summers47 reported that the bits used in the field trial

of the laboratory results were designed so that all the cutting were carried out by

the fluid jets, and not the bits themselves. The field trials were operated at

pressures of up to13, 965 psi. The rates of penetration of conventional offset

wells were between 3 to 6 m/hr, as compared to the jets which were able to drill

at rates of 32 to 85 m/hr in three wells and 6.9 m/hr in the fourth well. The fourth

well had some gagging problems.

The improved diamond bit design, incorporating high pressure waterjet, provides

answers to the need for reducing the stand-off distance between the nozzle and

the rock. A reduced stand-off distance helps to maintain rate of penetration with

increased hole depth. The design allows high pressure jets to cut reservoir rocks

and wedge it ahead of the rock’s contact with drill bit. The process results in


78

reduced compressive strength of the rock ahead of its contact with drilling bit and

increased rate of penetration of the bit. Conn and Radtke58 presented and an

example of such drill bit, shown as Figure 2.5, designed by Hydronautics.

Application of waterjets, using nozzle assembly with coiled tubing has been

applied to drilling horizontal wells in oil reservoirs. Pendleton and Ramesh59

reported the development of BecWell Horizontal Drilling System by Bechtel. In

the initial design, the drill head, which contains nozzle assembly, was connected

to coiled tubing, made of steel materials. The non-rotating coiled tubing

measured 1.25in OD and 1.1in ID, and operated at the pressure of 6174-10290

psi. The designed drill assembly was field-tested. After the vertical section of the

hole had been drilled and under-reamed to about 7.9 ft over the vertical interval

and a diameter of about 3.9 ft, the designed system was lowered into the hole

and directed into the horizontal position, using the reamed out interval to

maneuver the drillstring. The tool advanced in the horizontal direction. The drive

mechanism was the thrust generated at the nozzle head with the aid of the

hydraulic power of the engine, which delivered pressure to the nozzle. Since the

first design by Bechtel, there have been series of improvements in the tool

designs and configurations. A notable improvement is the development of conical

nozzle, which improves the penetration of the drill.


79

Figure 2.4: Drillhead that did not require nozzle swivel (after Baker and Timmerman55)


80

Figure 2.5: Jet-assisted diamond drill bit, the numbers mark the nozzle locations (after Conn and Radtke58)


81

Dickinson et al60 reported the efforts of Petrophysics Inc. — a company based in

California — to drill horizontal wells using watejet technology. Their system is

called petro-jet systems. The system is further divided into what they called

Petro-Jet Multiple Lateral System and Petro-Jet Extended Reach System.

The Petro-Jet Multiple Lateral System was developed for placing multiple radial

wells from a single vertical or deviated well. It was designed to penetrate near

wellbore damage and to place multiple lateral boreholes of 50 ft to 100 ft in

length. The system uses non-rotating coiled tubing as a drillstring and either a

conical or a Leach and Walker nozzles as the waterjet drillhead. The tool

combination provides torque-free drilling system. The use of hydraulic propulsion

keeps the coiled tubing drillstring in tension and minimizes coiled tubing buckling.

Petro Jet Multiple Lateral System is capable of turning from vertical to horizontal

in just one foot, using the waterjet technology. The system was reported to have

drilled four radial wells, up to 98 ft each, from a single vertical well, in a heavy oil

unconsolidated formation of the Kern River in California. The radial wells were

used for injecting steam into the formation to stimulate oil production. Dickinson

and Dykstra61 listed the major equipment and materials required for multiple

radial drilling by Petro-Jet Multiple Lateral System. These include:

a. Whipstock

b. Drillstring

c. Jet drilling


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d. Control While Drilling

e. Positional survey

f. Slotted liner

g. Gravel packing, and

h. Gravity drainage

Figure 2.6 shows the drive mechanism for the Petro-Jet Multiple Lateral System.

According to Dickinson and Dykstra61, and as of 1995, the system has been used

to place more than 1000 radial wells in California, Canada, Louisiana, Wyoming,

and other U.S. and foreign locations; both in heavy oil and light oil.

The Petro-Jet Extended Reach System was originally designed for the U.S.

Government to drill 25,00 ft horizontally using waterjet technology, and has since

been declassified. The system uses coiled tubing, just as in Petro-Jet Multiple

Lateral System. However, the system uses drill bits, instead of nozzles, as the

drillheads. The bits are designed to work with high pressure waterjet nozzles as

previously described in Figure 2.5. The system allows changing drill bits without

tripping the drillstring and provides Casing While Drilling (CWD) capability.


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2.4.2 Waterjet with a Combination of Rod and Hose a s Drillstring

Kennerley62 was one of the first investigators to use a combination of drill rod and

high pressure hose to drill holes into coal seam. The objective of his research

was to develop a method of drilling a long hole in coal seams to drain methane

gas (hazardous and unwanted gas, from mining point of view) before mining of

coal begins. He used hose as the connection between the pump and the drilling

rod. The drilling rod was directly connected to the nozzle. In one instance, he

drilled a hole to about 89 ft (about 27m). The adaptor connecting the rod to the

hose got swollen. He then withdrew the 89ft strings of rod and replaced it

with 33ft (10m) rod as the connection between the hose and the nozzle to

provide stiffness to the drill string. He could only manage to increase the length

of hole drilled to about 108 ft in total (33m) where the nozzle hit the floor of the

coal seam and cease to drill. He continued the drilling up to 125 ft (38m), but was

only drilling the formation the coal seam.

Kennerly62 attempted to drill another hole, this time, with 33 ft (10m) rod

connecting the nozzle to 131 ft (about40m) high pressure hose, placing his

nozzle assembly at an angle of 4 degrees, up from horizontal. He abandoned the

hole after drilling about 39ft (12m) because the nozzle had hit the roof of the coal

seam. He attempted one more hole with the same configuration as hole , but with

3 degrees facing upward. He abandoned the hole after drilling about 92 ft (28m)

because the nozzle had hit the floor of the coal seam.


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In the initial report of his work, Kennerley63 experienced two problems with his

drilling design:

a. removal of cuttings, and

b. inability of his tool to drill long distances without hitting the roof or the floor

of coal seams

Tool deviation from a target formation is a common problem, even in

conventional mechanical drilling. However, the geo-steering approach with

conventional drilling method is different from that of the waterjet systems. To

tackle the problem of cutting removal, Kennerly63 changed his nozzle designs to

the use of self-rotating type. However, this nozzle type created the problem of

residual cone in the center of the hole drilled. An improvement in tool design

overcame this problem. The improved tool design, called WOMA FR22, used two

self-rotating nozzles to carry out the drilling operation. The self-rotating nozzles

broke down the larger particles into smaller particles and were transported out of

the hole more easily. However, a test was carried out in another site and it was

discovered that the volume of water supplied to the nozzle was no longer

sufficient to transport the cuttings from the hole as the hole was getting deeper. A

set of retro-jets were then added to the drill assembly directly behind the nozzle,

in order to overcome the cutting transport.


85

Figure 2.6: Drive mechanism for the Petro Jet Multiple Lateral System (after Dickinson and Dykstra61)


86

In order to solve the problem of inability to drill long distance with his tool,

Kennerley et al64 modified the tool design, seen in Figure 2.7, by including a bent

sub (a bent rod) located directly behind the drilling nozzle. The bent sub raised

the location of the drilling nozzle, initially at an upward angle of one degree from

horizontal, to the center of the hole. This design reduced the tendency of the

drilling assembly to drop and hit the floor of the coal seam. When a larger

diameter model of the WOMA nozzle (WOMA FR47) was used, they were able to

drill holes up to 171 ft. After the holes were surveyed, it was discovered that the

holes had followed the direction of the face cleat. As a result, the drillsting was

re-designed to include a non-magnetic austenitic stainless steel drill rod section

behind the bent sub. The new feature allowed the hole to be surveyed while

drilling and the drilling direction could be changed, using the bent sub. They were

able to drill up to 728 ft with the re-designed tool at an average rate of

penetration of 3.28 ft/min, with a pressure of 9555 psi and flow rate of about 42

gpm.

Figure 2.7: Addition of bent sub in the drillhead (after Kennerley et al63)


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2.4.3 Waterjet with Hose as Drillstring

In the use of waterjet technology to drill horizontal wells, the major challenge is

how to turn the corner from the vertical section, going into the horizontal direction

under a predetermined bending radius. Summers et al65 were the first to explore

a method of turning the corner, using high pressure hose and nozzle as the

drillstring. They built an equipment and subsequently field tested several versions

of it. The machine was designed on the principle that only the nozzle head and

drive mechanism of the drillstring should rotate while the other parts of the

drillstring leading to the head will not rotate. The drill head consisted of a nozzle

assembly, small high pressure swivel, and a small drive motor. The head was

connected to the water supply tubing, which has three hoses. The first hose, high

pressure hose, was connected to the nozzles. Both the second and third hoses,

low pressure type, supply hydraulic fluid to and from the drive motor. The set-up

had a drive chain welded along the length of the hoses. During the field trials, the

hoses would be fed down the vertical section of the well as a rigid pipe, they

were disconnected on the lower end of the vertical section, and thus, were able

to rotate around the drive pulley at the bottom of the vertical well. They were

later reconnected when drilling the horizontal section of the well and were also

fed as rigid unit, driven by the drive chain; which was engaged by the toothed

sprockets of the drive gear. The drive gear was, in turn, driven by a motor in the

vertical section of the well. These investigators called their invention “round the

corner” (RTC). Figure 2.8 shows the drive mechanism of the RTC equipment


88

while Figure 2.9 shows the schematic equipment layout during the field test to

verify the RTC drilling ability. The process did not only prove to work in turning

the corner, but also able to drill the horizontal section of a well. The minimum

bend radius for the high pressure hose used in the equipment design is about

8.8in. Hence, in order to turn from the vertical section into the horizontal section,

one could ream out a 3 ft vertical interval to 1 ft. The drill head was able to turn

an 8.8 inches turning radius at an angle of 900 degrees. The additional reamed

out space (rat hole) allows the turning mechanism to be raised into the horizontal

position.

Summers et al65 experienced the problems of hole cleaning and hole deviation in

their field trials. The hole-cleaning problem was solved by putting additional jets

on the nozzle assembly, in order to increase the flow rate of the water carrying

the rock fragments back to the vertical section of the well. Summers66 reported a

greater than 15 m/hr rates were recorded in some of the field trials. The

equipment underwent a series of improvements, notably on the drill head to

guide the drill head and position it within the coal seam. Engler67 reported on the

improved design of the drill head instrumentation of the RTC equipment. The

instrumentation, shown in Figure 2.10, was to survey the orientation and location

of the drill head, helping driller to adjust the drill head in the required direction

and azimuth. A full field test of the improved head was carried out in an

abandoned mine area in New Mexico. Shirey and Enger68 reported that the drill


89

string was lowered down a vertical section to the coal seam located at some 98 ft

the surface, and raised into the horizontal section. They reported a horizontal

distance of 39ft-72ft were drilled within the coal seam.

Figure 2.8: Drive mechanism of the round the corner drill (after Summers et al65)


90

Figure 2.9: Equipment layout for the test to verify RTC drilling ability (after Summers et al65)

Anon69 investigated the use of high pressure hose as a drillstring in oil mining,

but no significant success or breakthrough was achieved.

Figure 2.10: Component of the RTC drillhead instrumentation (after Engler67)


91

2.5 Current Research versus Previous Works

The previous sections of this chapter reviewed the various application of waterjet

technology in industrial cleaning and rock cutting. In particular, applications of

waterjeting to drill horizontal wells for the purpose of degassing coalbeds prior to

mining operations and for creating rock-bolts in coalbeds, were extensively

reviewed. As previously mentioned in this chapter, the closest application of

waterjet technology in oil and gas industry has been in the development of jet-

assisted drill bits. This dissertation investigates the use of high pressure waterjet

technology for drilling horizontal wells in coalbed methane reservoirs.

Horizontal Well technology has been in existence for many years. It has found

successful applications in both conventional and unconventional reservoirs. The

major difference between the conventional horizontal well technology and the

proposed waterjet horizontal well technology is that the proposed technology

uses waterjet to drill, as opposed to a rotary bit. Secondly, the components of

their drillstrings are different. The major components of drillstring for the

conventional horizontal well technology are:

a. rigid pipe

b. bit or jet-assisted bit

c. Bottom Hole Assembly (BHA)


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The proposed waterjet horizontal drilling technology has the major components

of its drillstring as:

a. high pressure hose

b. nozzle, and

c. swivel

In contrast to conventional horizontal well technology, the radius of curvature of

the proposed horizontal well using waterjet is designed to be a couple of feet. In

conventional horizontal well technology, the ability of the drillstring to penetrate

into the formation is enhanced by the weight on bit through the bottom borehole

assembly or by using a surface pull-down apparatus. However, in waterjet

horizontal well technology; penetration is accomplished by the pulling (tracking)

force resulting from the pressure at nozzle, efficiency of nozzle, number and

diameter of orifices, and jet angles. In conventional horizontal well technology,

the bit is always in contact with the rock being cut. This process increases the

rate of wear and tear of the bit. In the case of waterjet horizontal well technology,

the nozzle is usually not in contact with the rock to be cut. Rock cutting is

accomplished by high pressure water jetting out of the orifices of the nozzle. The

stand-off distance between the nozzle and the formation being drilled reduces

the rate of wear and tear of the nozzle. Waterjet horizontal well technology is

significantly less expensive than the conventional horizontal well technology,

because it requires simple rig. Also, the materials needed for the drilling


93

operations are cheaper than those needed by the conventional horizontal drilling

technology. An example is the significantly cheaper cost of high pressure hose

versus the high cost of drilling pipe. The rig time is less with waterjet horizontal

drilling technology than the conventional horizontal well technology. Waterjet

drilling does not require multiple and frequent tripping, for the purpose of joining

more pipes during drilling operation. The high pressure hose is long enough to

complete the drilling process in one down-borehole trip.

The differences in features and operational designs of both the conventional

horizontal well technology and the waterjet horizontal well technology are

presented in Table 2.1. The Figure 2.11 is the pictorial view of the proposed

waterjet horizontal well technology.

Detailed report on the equipment and material specifications and field trials of

waterjet horizontal well technology in coalbed methane reservoirs will be

presented in the next chapter, chapter III


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Table 2.1: The difference between conventional and waterjet horizontal well technology Conventional Horizontal Well Technology

Waterjet Horizontal Well Technology

Drillstring made up of rigid pipe, bit or jet-assisted bit, and bottom borehole assembly (BHA)

Drillstring made up of high pressure hose and nozzle

Penetration into formation is by weight on bit or BHA

Penetration into formation is by tracking force

Rock cutting is by bit or jet-assisted bit Rock cutting is by water jetting out of nozzle

Bit wears more frequently due to contact with rock

Nozzle wears less frequently due to the presence of stand-off depth between it and rock

Drilling fluid is a combination of water, chemicals, and other additives

Drilling fluid is purely water

Longer rig time due to periodic tripping for pipe coupling

Shorter rig time — no need for periodic tripping

Larger bending radius (slower build-up rate)

Smaller bending radius (faster build-up rate)

More expensive to operate Less expensive to operate

It has application in any formations: sandstone, carbonate, hard or soft

It has application mostly in soft formation, like CBM reservoir


95

Figure 2.11: A pictorial view of the proposed waterjet horizontal well technology


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CHAPTER III

FIELD TESTING

3.0 Equipment Rig-Up

A simple rig, called WATERBLASTER and shown in Figure 3.1, was used for the

field test of the waterjet horizontal drilling project, as opposed to complex rig in

conventional horizontal drilling operations. Bodine Services of Evansville was the

contractor employed for the test. The major components of the rig are:

1. Water Truck

2. Small Diesel Engine

3. Water Hose

4. Inlet Filters

5. Water Tank

6. Diesel Engine

7. Pump

8. Foot Dump

9. Whip Check

10. Diffuser

11. Testing Hose, and

12. Nozzle


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Figure 3.1: Major components of the rig — Waterblaster

Water Tank

Inlet Filter

Pump

Diesel Engine

Foot Dump

Testing Hose

Water Hose


98

Figure 3.2: Water truck that supplies the water for the test (capacity is 7,700 gallon).


99

Figure 3.3: Small diesel engine than pumps water from the truck to the tank

Diesel Engine

Water Hose


100

Figure 3.2 shows the water truck, which was stationed to supply the water

needed for the test. Its capacity is 7,700 gallon. The water hose connects the

truck to the blaster, via a small diesel engine. With the aid of the small diesel

engine, the water from the truck is pumped to water tank, mounted on the

waterblaster. The water coming from the truck first goes to an inlet filter, then to

the tank and later comes out through an outlet line. Both the inlet filter and the

tank are mounted on the blaster.

The most important precaution in maintaining the nozzles is keeping debris or

particles from entering the tool, which will prevent it from rotating. The inlet filters

serve this purpose of screening out any debris or particle from the stream of

water. Figure 3.3 shows the small diesel engine that connects the truck to the

tank component of the blaster, while Figure 3.4 shows the tank and the two inlet

filters. Some blasters do not have water tank. In such blasters, the water is

transmitted directly from the truck to the pump. Such blasters do not have the

advantage of inline water filtration, and such practice can quickly damage the

jetting heads and prevent them from rotating or spinning.

The water from the tank flows to the pump through the water hose connecting the

two features. The pump, shown in Figure 3.5, has a pressure rating of 20,000 psi

and has five plungers, each of which is rated 8, 9, and 10. The number 8 rating


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was used for the test. The pump has 300 horsepower. The Figure 3.6 shows the

diesel engine that powers the water pump. The pump, with the aid of the engine,

exerts pressure on the water as it flows through the high pressure hose. The

engine is also a part of the configuration of the waterblaster. It has three principal

components: the gear system, the pressure valve, and the reading panel. The

gear system is used to regulate the water flow rate.

The gear system can change the gear from 2 through 5. According to Waterblast,

the company that manufactures the blaster, each gear corresponds to certain

flow rate at which water leaves the pump, depending on the plunger rating being

used. For the plunger 8 rating used for the test, 2nd gear corresponds to the flow

rate of 12.7 gpm, 3rd gear corresponds to the flow rate of 16.5 gpm, 4th gear

corresponds to the flow rate of 21.4 gpm, and 5th gear corresponds to the flow

rate of 27.2 gpm. A higher level of gear leads to higher the pump’s revolution per

minute (RPM). In this project, the equation 2.7 was used to estimate more

accurately the outlet flow rate of the pump; instead of relying on the

manufacturer’s gear-flow rate relationship.

The pressure valve regulates the pressure at which the pump operates. Both the

flow rate and pressure compensate each other to balance the capacity of the

pump. When the pressure is increased, the flow rate is lowered and vice versa.


102

Figure 3.4: 1st & 2nd inlet filters, and water tank

1st Inlet Filter

2nd Inlet Filter

Water Tank


103

Figure 3.5: Water pump

Water Pump


104

Figure 3.6: Diesel engine that powers the water pump

Gear

Pressure Valve

Reading Panel


105

The reading panel helps the operator to measure the values of the flow rate,

pressure, and rpm of the pump.

Water flows from the pump to a control device called the foot dump. The device

houses the foot valve, the dump line connection, and both the inlet and outlet

hose connections. The foot valve controls how much water flows to the nozzle.

The dump line is usually not under pressure. It is used to direct water to

atmosphere or back into water tank. The inlet line allows water under pressure to

pass through the control device while the outlet line allows the water to flow out

of the control device, through high pressure hose line, to the nozzle. The Figures

3.7 and 3.8 show the foot valve, the dump line and the inlet connections. When

the valve is pressed down, it allows water to flow through the high pressure hose.

When releases, it reduces the flow rate because it diverts some of the volume of

water to tank or atmosphere. This causes a decrease in pressure at the nozzle.

The remaining water in the high pressure line is released through the dump line.

It is not mandatory to have the control device as part of the rig system. It is a

safety device that allows the operator to release the pressure at the nozzle

before the rig is shut down.

The whip check is another safety device that connects all hoses on the rig to

itself, so that when hose couplings are loosened, they are still kept together.


106

Another important component of the rig is the diffuser. It is used to measure the

pressure at the nozzle head. The Figure 3.9 shows the whip check and the

diffuser, with a pressure gauge mounted on it. The high pressure testing hose is

connected to the outlet connection on the foot dump using the 9/16 inches

connection at one end while the nozzle head is connected to the other end of the

hose, using ¼ inches NPT connection.

3.1 Equipment and material Specifications

The equipment described here are in addition to the components of the

waterblaster already described in section 3.0.

3.1.1 The Backhoe

The backhoe, shown in Figure 3.10, was the equipment used to build the berns

that was used for the project. It also helped secure the pipe/hose. Also labeled in

the same Figure is the pipe that was used to direct the testing hose to the face of

the coal used for the test. It was secured at an angle of 1800 on the surface of

the berns, so that the jetting can occur at a complete horizontal direction to the

coal face.


107

Figure 3.7: Foot valve, a component of the foot dump

Foot Valve


108

Figure 3.8: Outlet high pressure and the dump line connections

Dump Line

Intlet Line


109

Figure 3.9: Diffuser, with a pressure gauge mounted on it, and whip check

Diffuser Pressure Gauge

Whip Check


110

3.1.2 The Testing Hose

The testing hose for the project was from Spir Star. It has 3/8” internal diameter

(ID). The hose has a pressure rating of 21,700 psi and a bending radius of 8“. Its

weight per foot is 0.46 lb/ft. It has ¼” NPT connection at one end and 9/16” at the

other end. The total length of the hose acquired for the test is 200 feet. The hose

is labeled in Figures 3.1 and 3.10.

3.1.3 The Nozzle

The nozzles used for the project were procured from StoneAge. Seven nozzle

configurations were used for the test. Six out of the seven configurations were

Berger tool with BA-P4 swivels; having JETTED HEAD and the seventh tool was

a Banshee type. The first nozzle configuration contains the following orifices: two

0.052", three 0.032”, and two 0.020" orifice sizes. The second nozzle

configuration contains the following orifices: two 0.052" and two 0.018" and three

plugs. The third configuration contains the following orifices: two 0.052" and three

0.018" and two plugs. The fourth nozzle configuration contains the following

orifices: two 0.052" and three 0.024” and two 0.020”. The fifth nozzle is called

the Banshee nozzle. Its configuration was unknown. The sixth configuration

contains the following orifices: two 0.052", three 0.024" and two plugs. The

seventh tool contains the following orifices: two 0.052" and three 0.032" and two

plugs. The 0.052" orifice sizes are installed in the rear ports having jet angles of

1350. The 0.032", 0.024”, and 0.018” orifice sizes are installed on the front ports


111

having jet angles 150, 300, and 450. The 0.020” orifice sizes are installed in the

side ports having jet angles 900. Where there are two plugs, they are always

installed at the 900 slots. When the plugs are up to three, the angle 150 on the

front port is usually plugged. The orifice installations were already performed by

StoneAge. Hence, there was no need to install them in the field. The tools

operate on retro-jet principles. Figures 3.11 and 3.12 show the orifices and the

arrangement of the jet angles of the nozzles, and Figure 3.13 shows the

component of the BA-PA nozzle. The HEAD is there to hold the orifices, the

SHAFT supports the head and they rotate together. The BODY supports the

shaft with a film of water between, and the INLET NUT provides the means to get

the water from the hose into the shaft. There is film of water between inlet nut

stem and bore of shaft as well. The RETAINING RING holds the inlet nut into the

body, and the O-RING keeps junk out of the weep holes. The BA-P4 nozzle is

rated up to 25 gpm.


112

Figure 3.10: Backhoe, the bern, the pipe, the testing hose, and the jetting operations

Backhoe

Testing Hose Bern Pipe

Jetting Operation


113

Figure 3.11: 0.020 inches and 0.052 inches size orifices at jet angles of 900 and 1350 respectively

Jet Angle 1350

Jet Angle 900


114

Figure 3.12: 0.032 inches size orifices at jet angles of 150, 300, and 450

Jet Angle 300

Jet Angle 450

Jet Angle 150


115

Figure 3.13: Component of BA-PA nozzle (permission from StoneAge)


116

3.2 First Round of Field Tests

Two rounds of field test were conducted. This section explains the test

preparation and procedure during the first round.

3.2.1 Test preparation

The mine site used for the test was provided by the UNITED MINERALS CO.,

LLC. The mine is located in Somerville, Indiana. An approval was sought from

the Mine Safety and Health Administration (MSHA) department prior to carrying

out the test. The crew members for the test consist of four (4) personnel from

ACT Operating Company (the principal investigator) and four (4) personnel from

Bodine Services of Evansville (the waterjet/rig operator). Hazard training was

provided to all the personnel that entered the mine site for the test and all safety

precautions were strictly enforced before, during, and after the test. Serious

attention was paid to personnel safety. As a result, all personnel involved in the

test were made to wear safety equipment and materials. These include: hard hat,

safety glasses, and steel toe shoes. All personnel were made to familiarize

themselves with the operations of waterjet, as laid out in the manual published by

the WaterJet Technology Association (WJTA47). The latest version of the manual

at the time of this test is titled “Recommended Practices for the Use of Manually

Operated High Pressure Waterjetting Equipment”.


117

3.2.2 Testing Procedure

The following is a step-by-step procedure that the test followed:

I. The rig-up operation was performed by coupling and connecting all the

equipment and materials together. The Figure 3.1 shows the rig-up

configuration. The water truck was connected to the water tank via the

inlet filter, with the aid of the water hose at one end and the water tank

was connected to the pump with the aid of the water hose, at another end.

The same water hose connected the pump to the inlet line of the foot

dump. The testing hose was connected to the outlet line of the foot dump

at one end, with the 9/16 inches connection, and the nozzle head was

connected to the testing hose at the other end, with the ¼ inches NPT

connection. While the smaller engine was used to power the water truck to

flow water into the water tank via the hose, the bigger diesel engine,

mounted on the waterblaster, was used to drive the pump; so that water

from the tank flowed to the nozzle head through the connections

described above.

II. It was required that the pressure at the nozzle be determined at the

surface; prior to drilling the coal seam. The procedure is to connect a

pressure gauge to the diffuser, just behind the nozzle head. Then, operate

the pump and gradually increase the flow rate (on incremental basis) and


118

measure the corresponding pressures at the pump and at the gauge. The

Pressure gauge is rated to hold a maximum of 10,000 psi.

III. There were five nozzle configurations available for the first field trial.

These are:

• Tool #1: two 0.052" rear jets, three 0.032" forward jets, and two

0.020" side jets

• Tool #2: two 0.052" rear jets, two 0.018" forward jets, and three

plugs


plugs


0.020" side jets

• Tool # 5: Banshee nozzle

TEST A. Tool # 1 was first selected and the pump was set at 9000 psi and

21.4 gpm. The waterjet operation was initiated with run # 1 and

borehole # 1 was drilled.

TEST B. Tool # 2 was selected.

Run 1 Pump was set at 7000 psi and 12.7 gpm

Run 2 Pump was set at 10,000 psi and 16.5 gpm


119

TEST C. Tool # 3 was selected



TEST D. Tool # 4 was selected



Run 3 Pump was set at 10,000 psi and 21.4 gpm and borehole # 2

was drilled.

TEST E. Tool # 1 was again selected; the pump was again set at 9000 psi

and 21.4 gpm. Run #s 1, 2, and 3 were czrried out; and borehole #s

3, 4, and 5 were drilled.

TEST F. Tool # 5 (Banshee nozzle) was selected; the pump was set at 9000

psi and 21.4 gpm. Run #s 1 and 2 were carried out; and borehole

#s 6 and 7 were drilled.

3.3 Second Round of Field Test

One major problem was encountered during the first field test. The hose could

not maintain its position within the coal seam during the drilling operations. The


120

second field trial was designed to overcome this problem. Three major

modifications were made to the equipment and materials used during the first

trial.

1. Rigid sections of lengths 1 to 5 feet were connected between the nozzle

head and the hose. The aim was to keep the hose within the coal seam

during drilling operations.

2. A swivel was connected between the foot dump and the high pressure

hose used for the test. The swivel was expected to aid the rotation the

hose during jetting operation.

3. The nozzles were optimized to increase its forward jetting and to improve

its spinning abilities.

3.3.1 Test Preparation

The preparation was similar to the first field trial. The service of the same

company, Bodine Services of Evansvile, was engaged for the second field trial.

The UNITED MINERALS CO., LLC again provided access to their coal mine for

the test. Safety training was also provided for all personnel prior to entering the

coal mine and prior to the field test.

3.3.2 Testing Procedure

The rig-up operation was similar to the procedure as the first test. There were

four nozzle configurations available for second field trial. These are:


121


plugs


plugs


plugs


0.020" side jets

TEST G. Tool # 3 was first selected and the pump was set at 9000 psi and

21.4 gpm. The waterjet operation was initiated with run #s 1, 2, and

3; and borehole #s 8, 9, and 10 were drilled.

TEST H. Tool # 6 was selected and the pump was set at 9000 psi and 21.4

gpm. The waterjet operation was initiated with run #s 1 and 2; and

borehole #s 11 and 12 were drilled.

TEST I. Tool # 7 was selected and the pump was set at 9000 psi and 21.4

gpm. The waterjet operation was initiated with run # 1; and

borehole # 13 was drilled.


122

TEST J. Tool # 4 was selected and the pump was set at 9000 psi and 21.4

gpm. The waterjet operation was initiated with run #s 1 and 2; and

borehole #s 14 and 15 were drilled.

TEST K. Tool # 3 was again selected

Run 1 Pump was set at 10,000 psi and 21.4 gpm; and borehole #

16 was drilled.


17 was drilled.


18 was drilled.


19 was drilled.


123

CHAPTER IV

RESULTS AND DISCUSSIONS

4.0 Accomplishments

This research was designed to investigate the use of high pressure waterjet

technology as a new and a more cost effective technique to drill horizontal wells

in coalbed methane reservoirs. The ability of high pressure hose to replace the

conventional metallic drill pipe or tubing was investigated. The use of a nozzle to

drill horizontal wells in coalbed methane reservoirs, as opposed to a rotary bit

was also investigated. Optimization of tool (nozzle) for best drilling practices was

a major part of the field tests. The various factors that control the direction of

hose and nozzle during drilling operations were part of the investigations. Finally,

sensitivity studies were carried out to determine the significance of all the

variables that contribute to the impact pressure, the pressure from jets of water

that cuts the rocks (coalbeds).

4.1 Results

The goal of testing different nozzle configurations was to be able to optimize the

tool. That is, to be able to determine which of the configurations works best, in

terms of greatest pulling force and longest achievable drilling depth. The field

tests sought to answer the following questions:


124

1. For each nozzle configuration and for each combination of pressures,

pulling forces and flow rates, what is the rate of penetration (ROP), depth

drilled, borehole size, borehole path, borehole geometry (square, circular),

and particles description?

2. Do tools without the 900 jets make a large enough borehole?

3. How much larger, if any, do the 900 jets make the borehole?

4. How much faster is the cutting rate with larger forward jets: (0.032 vs.

0.024 vs. 0.018)?

5. Will the tool with only two 0.018 orifice size forward cut borehole at all, and

if so, is the cutting rate sufficient?

Tables 4.1 through 4.6 shows the results obtained during the first field test; for

different tool configurations and under varying conditions of pressures and flow

rates.

Three major problems were encountered during the first field trial:

1. The nozzles frequently quit spinning after one or two runs

2. The nozzle/hose could not maintain a direction within the coal seams

3. The jets were unable to drill the coal seams for any appreciable depth

In order to solve the first problem, the inner surfaces of the nozzles were

polished; to increase the gap between rotating parts so they have less chance of


125

touching and galling during operations. For the second problem, it was assumed

that the lack of control within the coal seams could be due to the fact that the

hose has memory code in it and that it tends to follow its national bends during

jetting operations. Therefore, stiff section of lengths 1 to 3 feet were connected

between the nozzle and the high pressure hose. It was thought that the stiff

section would assist the hose in maintaining its position in the coal seam. It was

also thought that the third problem would be solved, once the hose is able to

maintain its position within the coal seam. The second first test was then carried

out, after these improvements to the tools and the equipment. The results of the

second field test are presented in Tables 4.7 through 4.11.

On another development, it has been suggested that hose rotation, during jetting

operation, could help it maintain its direction within a coal seam. Therefore, a

swivel was connected between the foot dump and the high pressure hose for the

purpose of aiding the rotation of the hose. The result of the tests suggests that

swivel does not help the hose to maintain its position within a coal seam.

Therefore, addition of a swivel to the drilling assembly would not serve any

purpose.

Figure 4.1 shows the geometry of the borehole and the color of the returning

water after drilling into the shale formation, while Figure 4.2 shows the sizes of

particles that were cut during the jetting operations. The fine to medium-fine


126

particles were about 2% to 5% of the size of the boreholes, while the large

particles range from about 5% to 10% of the size of the boreholes. The geometry

of the nineteen boreholes drilled during the two field trials is roughly square in

nature, whose dimensions range between two inches to four inches in both width

and height. Figure 4.3 shows an example of the measurement of the dimensions

of the boreholes.

In order to examine the performance of these tools, description of the results

obtained for the two field trials will be grouped under the various tool

configurations used for the tests. As mentioned earlier in section 3.1.3, all the

tool configurations have two rear-facing orifices of size 0.052”, placed at a jet

angle of 1350. Whenever orifice size of 0.020” is part of the configuration, it is

always located at the sides and at a jet angle of 900.

Two hundred feet (200 ft) of the length of high pressure hosed was used during

the first field test. The length was reduced to one hundred feet (100 ft) during the

second field trial.

4.1.1 Configuration 1: two 0.052", three 0.032", an d two 0.020"

This configuration was used for tests A (Table 4.1) and E (Table 4.5) during the

first field trial. It has three forward-facing orifice size of 0.032”; located at jet

angles 150, 300, and 450. The only run of test A was set at pump pressure of


127

9000 psi. Drilling was initiated at the ROP of 8ft/min. During the drilling, the tool

(and consequently the hose) bent upward and then to the right. It later made a U-

turn and came out of the borehole at a depth of about 8.5 ft from the entrance.

Only about 6.5 ft was drilled horizontally into the coal seam.

The three runs for test E was also set at the same pump pressure and flow rate

as test A. The drilling operation during the first run was at an ROP of 8.7 ft/min.

From the start of the jetting, the tool started bending downward and then turning

left. It drilled about 14 ft within the coal seam before drilling into the shale

formation below the coal seam. This was noticed by the change in the color of

the spent water returning from the borehole. The color was black when the tool

was jetting into the coal seam and suddenly turned brownish as the tool left the

coal seam into the shale formation. About 6 ft was further drilled into the shale,

making a total length of about 20 ft. The sizes of particles that were cut during

the jetting operations were between medium-sized to fines. The rest two runs of

test E both have an ROP of 5 ft/min and the jets could only drill between 3.4 and

4.3 ft before it stopped to spin. The tool quickly bent upward during runs # 2 and

3 and stopped spinning when it hit the formation above the coal seam.

4.1.2 Configuration 2: two 0.052", two 0.018", and three plugs

This configuration was used for test B (Table 4.2) during the first field trial. The

first run was set at 7000 psi pump pressure. The second run was set at 10000


128

psi pump pressure. The tool would not spin, for the two runs, when a stand-off

depth is maintained between the tool and the coal face. It, also would not spin

when in contact with the coal face, and therefore, could not drill any borehole in

the coal seam.

4.1.3 Configuration 3: two 0.052", three 0.018", an d two plugs

The third configuration was used for both field trials. The test C (Table 4.3) was

conducted during the first field trial while tests G (Table 4.7) and K (Table 4.11)

were conducted during the second field test. The pump pressure for the first run

of test C was set at 6000 psi. The second run was set at 9000 psi. The tool

stopped spinning when it was in contact with the coal face for both runs. During

the second field trial, stiff sections of length 1 to 3 ft were connected between the

nozzle and the high pressure hose for test G. This was meant to guide the hose

in maintaining its position in the coal seam. There were three runs during test G,

and were all set at the pump pressure of 9000 psi. Run 1 consisted of 1 ft of stiff

section and a borehole was drilled to a horizontal depth of 17 ft. Run 2 consisted

of 2 ft of stiff section, which drilled a horizontal depth of 20.5. Run # 3 consisted

of 3 ft of stiff section and a horizontal depth of 18 ft was drilled. The drilling

proceeded at the rate of 3 ft/min, with large particles being transported to the

surface from the borehole by the spent (retuning) water. The hose bent

downward and hit the formation below the coal seam during the three runs; at

which time the jetting operations were stopped. There were four runs in test # K.


129

Figure 4.1: Borehole geometry and changes in the color of returning water


130

Figure 4.2: Description of particle sizes


131

Figure 4.3: Measurement of borehole dimensions


132

During the first run, a stiff section of 1ft was connected between the nozzle and

the hose and pump pressure increased to 10000 psi to drill borehole number

sixteenth. The results were similar to those obtained in test G, except that a total

depth of 30.5 ft was drilled, with about 20.5 of it intentionally drilled into the shale

formation below the coal seam. The other three runs were conducted at a higher

pump pressure of 13000 psi. The characteristics of the rest three runs of test # K

were changed. The stiff section was removed and pump pressure increased to

13000 psi to drill boreholes seventeenth to nineteenth. For runs 2 and 3, a total

depth of about 62 ft was drilled and the hose was able to maintain its position in

the coal seam. The jetting proceeded at a rate of 3 ft/min for run # 2 and at 4

ft/min for run # 3. The jetting rate reduced to 1.5 ft/min during the fourth run and a

total depth of about 30 ft was drilled within the coal seam before the nozzle quit

spinning. The hose got stock in the borehole and backhoe was used to pull it out.

The particle sizes were large for the four runs during test K. Figure 4.4 shows

how the hose was being fed into the coal while Figure 4.5 shows borehole

number seventeenth that was drilled to the depth of 62 ft.

4.1.4 Configuration 4: two 0.052", three 0.024", an d two 0.020"

This configuration was used for both the first and the second field trials. Test # D,

presented on Table 4.4; was conducted during the first field test and test J,

presented on Table 4.10; was conducted during the second field trial. Three runs

were made during test D. The first run was set at pump pressure of 4000 psi. The


133

second run was set at 6000 psi. The tool would spin when a stand-off distance

was maintained between it and the coal face, but stopped spinning on contact

with coal face for both runs. Hence, it could not drill any borehole in the coal

seam. The pressure was increased to 10000 psi for the third run. Drilling

proceeded at the rate of 6 ft/min and a total depth of 13 ft was drilled. The hose

bent upward and then to the right. It later made a U-turn and came out of the

borehole at a depth of about 7.5 ft from the entrance. Only about 5.5 ft was

drilled horizontally into the coal seam. The particles transported to the surface

were mostly fines. Two runs were carried out during test J. Both were set at

pressure of 9000 psi. Run 1 had connection of 1ft stiff section and run # 2 had 2

ft of the stiff section connected between the nozzle and the hose. The tool

maintained its position in the coal seam but got stuck in the hole and the jetting

operation was stopped. Depths of 14 ft and 11 ft were drilled during runs 1 and 2

respectively, at the rate of 2 ft/min; before the operation was halted. The sizes of

the particles transported to the surface were medium to fines.


134

Figure 4.4: Feeding of hose into the coal seam during a jetting operation


135

Figure 4.5: Borehole # seventeenth drilled to the depth of 62 ft


136

4.1.5 Configuration 5: Banshee tool

The dimensions of this tool were unknown at the time of the field test. It was used

for the first field trial. Test F (Table 4.6) was conducted and two runs were

performed during the test. Both were set at pressure of 9000 psi. The hose bent

upward and move towards the left before hitting the formation above the coal

seam during the jetting operations. Depths of about 15 ft and 3 ft were drilled

during runs 1 and 2 respectively before the operation was halted. The sizes of

the particles transported to the surface were medium to fines.


This tool configuration was used during the second field trial. Test H (Table 4.8)

was conducted and two runs were carried out during the test. Both were set at

pressure of 9000 psi. Run 1 had connection of 1ft stiff section and run # 2 had 2

ft of the stiff section connected between the nozzle and the hose. The hose bent

towards right and got stuck in the borehole during the first run. It was able to

maintain its position in the coal seam during the second run, but also got stuck in

the hole. The jetting operations were thereafter stopped. Depths of 5 ft and 3 ft

were drilled during runs 1 and 2, at the rate of 2 ft/min and 1ft/min, respectively;

before the operations were halted. The sizes of the particles transported to the

surface were medium to fines.


137


This last configuration was used during the second field trial. Test I (Table 4.9)

was conducted and only one run was carried out during the test. The pump

pressure and flow rate were set at pressure of 9000 psi. The run had a

connection of 1ft stiff section between the nozzle and the hose. The hose was

able to maintain its position in the coal seam, but the tool quit spinning. The

jetting operation was stopped. Depth of about 5 ft was drilled at the rate of 0.8

ft/min before the operations were stopped. The sizes of the particles transported

to the surface were mostly fines.

The relatively same values obtained for flow rates at both nozzle (equation 2.6)

and pump outlet (equation 2.7) confirms that the law of conservation of mass

holds as the water flows into and out of the nozzle.

Texas T

ech U

niv

ers

ity, G

beng

a M

. Fu

nm

ilayo

, August 2

010

�

��

�

TE

ST

A

Table

4.1

: Me

asure

ments

record

ed fo

r tool #

1: tw

o 0

.052", th

ree 0

.032", a

nd tw

o 0

.020

"�

RU

N

P @

P

um

p/G

ear/

Flo

w R

ate

, p

si/g

pm

Dep

th, ft

RO

P,

ft/min

Ho

le S

ize,

inH

ole

G

eo

metry

Ho

le P

ath

Partic

le

Des

crip

tion

1

(Hole

# 1

) 9000/4

/21.4

15

8

3 w

ide,

2.2

5 h

igh

S

quare

W

ent u

pw

ard

an

d

bent to

the rig

ht.

Ma

de U

-turn

and

cam

e o

ut o

f the

coal s

eam

. D

ista

nce

betw

ee

n

entra

nce a

nd

outle

t hole

was

8.5

ft

Mostly

fines

Texas T

ech U

niv

ers

ity, G

beng

a M

. Fu

nm

ilayo

, August 2

010

�

��

�

TE

ST

B

Table

4.2

: Me

asure

ments

record

ed fo

r tool #

2: tw

o 0

.052", tw

o 0

.018", a

nd th

ree p

lugs�

RU

N

P @

P

um

p/G

ear/

Flo

w R

ate

, p

si/g

pm

Dep

th, ft

RO

P,

ft/min

Ho

le

Siz

e, in

Ho

le

Geo

metry

Ho

le P

ath

Partic

le

Descrip

tion

1

70

00/2

/12.7

0

0

N

/A

N/A

T

ool d

id n

ot s

pin

N

/A

2

10

00

0/3

/16.5

0

0

N

/A

N/A

T

ool d

id n

ot s

pin

N/A

TE

ST

C

Table

4.3

: Me

asure

ments

record

ed fo

r tool #

3: tw

o 0

.052", th

ree 0

.018", a

nd tw

o p

lugs�

RU

N

P @

P

um

p/G

ear/

Flo

w R

ate

, p

si/g

pm

Dep

th, ft

RO

P,

ft/min

Ho

le

Siz

e, in

Ho

le

Geo

metry

Ho

le P

ath

Partic

le

Descrip

tion

1

60

00/2

/12.7

0

0

N

/A

N/A

T

ool s

top

ped

spin

nin

g w

hen in

conta

ct w

ith c

oal

seam

N/A

2

90

00/3

/16.5

0

0

N

/A

N/A

T

ool s

top

ped

spin

nin

g w

hen in

conta

ct w

ith c

oal

seam

N/A

Texas T

ech U

niv

ers

ity, G

beng

a M

. Fu

nm

ilayo

, August 2

010

�

��

�

TE

ST

D

Table

4.4

: Me

asure

ments

record

ed fo

r tool #

4: tw

o 0

.052", th

ree 0

.024", a

nd tw

o 0

.020

"�

RU

N

P @

P

um

p/G

ear/

Flo

w R

ate

, p

si/g

pm

Dep

th, ft

RO

P,

ft/min

Ho

le

Siz

e, in

Ho

le

Geo

metry

Ho

le P

ath

Partic

le

Descrip

tion

1

40

00/2

/12.7

0

0

N

/A

N/A

T

ool s

top

ped

spin

nin

g w

hen in

conta

ct w

ith c

oal

seam

N/A

2

60

00/3

/16.5

0

0

N

/A

N/A

T

ool s

top

ped

spin

nin

g w

hen in

conta

ct w

ith c

oal

seam

N/A

3

(Hole

# 2

) 10

00

0/4

/21.4

13

6

3 w

ide,

2 h

igh

S

quare

W

ent u

pw

ard

an

d b

ent to

the

right. M

ade U

-tu

rn a

nd c

am

e

out o

f the c

oal

seam

. Dis

tance

betw

een

entra

nce a

nd

outle

t hole

was

7.5

ft

Mostly

fines

Texas T

ech U

niv

ers

ity, G

beng

a M

. Fu

nm

ilayo

, August 2

010

�

��

�

TE

ST

E

Table

4.5

: Me

asure

ments

record

ed fo

r tool #

1: tw

o 0

.052", th

ree 0

.032", a

nd tw

o 0

.020

"�

RU

N

P @

P

um

p/G

ear/

Flo

w R

ate

, p

si/g

pm

Dep

th, ft

RO

P,

ft/min

Ho

le S

ize,

inH

ole

G

eo

metry

Ho

le P

ath

Partic

le

Descrip

tion

1

(Hole

# 3

) 90

00/4

/21.4

20

8.7

3 w

ide,

2 h

igh

Squ

are

W

ent d

ow

nw

ard

an

d b

ent to

the

left. S

tarte

d

cuttin

g in

to s

hale

at 1

4 ft

Me

diu

m to

fin

e p

artic

les

2

(Hole

# 4

) 90

00/4

/21.4

3.4

5

3 w

ide,

2 h

igh

Squ

are

C

ut c

oal b

ut

quic

kly

bent

up

ward

and h

it th

e ro

of o

f the

coal s

eam

. To

ol

sto

ppe

d s

pin

nin

g

Mostly

fines

3

(Hole

# 5

) 90

00/4

/21.4

4.3

5

3 w

ide,

2 h

igh

Squ

are

C

ut c

oal b

ut

quic

kly

bent

up

ward

and h

it th

e ro

of o

f the

coal s

eam

. To

ol

sto

ppe

d s

pin

nin

g

Mostly

fines

Texas T

ech U

niv

ers

ity, G

beng

a M

. Fu

nm

ilayo

, August 2

010

�

��

�

TE

ST

F

Table

4.6

: Me

asure

ments

record

ed fo

r tool #

5: B

anshe

e to

ol �

RU

N

P @

P

um

p/G

ear/

Flo

w R

ate

, p

si/g

pm

Dep

th, ft

RO

P,

ft/min

Ho

le S

ize,

inH

ole

G

eo

metry

Ho

le P

ath

Partic

le

Descrip

tion

1

(Hole

# 6

) 90

00/4

/21.4

15

2.5

wid

e,

1.2

5 h

igh

Squ

are

W

ent u

pw

ard

and

be

nt to

the le

ft. H

it the ro

of o

f the

coal s

eam

Me

diu

m to

fin

e p

artic

les

2

(Hole

# 7

) 90

00/4

/21.4

3

S

qu

are

C

ut c

oal b

ut

quic

kly

bent

up

ward

and h

it th

e ro

of o

f the

coal s

eam

.

Mostly

fines

Texas T

ech U

niv

ers

ity, G

beng

a M

. Fu

nm

ilayo

, August 2

010

�

��

�

TE

ST

G

Table

4.7

: Measure

ments

record

ed fo

r tool #

3: tw

o 0

.052

", thre

e 0

.018", a

nd tw

o p

lugs

RU

N

P @

P

um

p/G

ear/

Flo

w R

ate

, p

si/g

pm

Len

gth

o

f Stiff

sectio

n,

ft

Dep

th,

ftR

OP

, ft/m

inH

ole

S

ize, in

Ho

le P

ath

Partic

le

Des

crip

tion

1

(Hole

# 8

) 9000/4

/21.4

1

17

3

4 w

ide &

4 h

igh

H

it the b

otto

m o

f coal s

eam

La

rge

2

(Hole

# 9

) 9000/4

/21.4

2

20.5

3

3 w

ide &

4 h

igh

H

it the b

otto

m o

f coal s

eam

La

rge

3

(Hole

# 1

0)

9000/4

/21.4

3

18

3

Hit th

e b

otto

m o

f coal s

eam

La

rge

Texas T

ech U

niv

ers

ity, G

beng

a M

. Fu

nm

ilayo

, August 2

010

�

��

�

TE

ST

H

Table

4.8

: Measure

ments

record

ed fo

r tool #

6: tw

o 0

.052

", thre

e 0

.024", a

nd tw

o p

lugs

RU

N

P @

P

um

p/G

ear/

Flo

w R

ate

, p

si/g

pm

Len

gth

o

f Stiff

sectio

n,

ft

Dep

th,

ftR

OP

, ft/m

inH

ole

S

ize, in

Ho

le P

ath

Partic

le

Des

crip

tion

1

(Hole

# 1

1)

90

00/4

/21.4

1

5

2

2 w

ide &

2 h

igh

Bent to

ward

s

right. H

ose g

ot

stu

ck in

the h

ole

M

ediu

m to

fin

e p

artic

les

2

(Hole

# 1

2)

9000/4

/21.4

2

6.5

1

2 w

ide &

2 h

igh

Main

tain

ed

positio

n in

coal

seam

. Hose g

ot

sto

ck in

the h

ole

Mediu

m to

fin

e p

artic

les

TE

ST

I T

able

4.9

: Measure

ments

record

ed fo

r tool #

7: tw

o 0

.052

", thre

e 0

.032", a

nd tw

o p

lugs

RU

N

P @

P

um

p/G

ear/

Flo

w R

ate

, p

si/g

pm

Len

gth

o

f Stiff

sectio

n,

ft

Dep

th,

ftR

OP

, ft/m

inH

ole

S

ize, in

Ho

le P

ath

Partic

le

Des

crip

tion

1

(Hole

# 1

3)

9000/4

/21.4

1

5

0.8

2 w

ide &

2 h

igh

Main

tain

ed

positio

n in

coal

seam

, but th

e

hose g

ot s

tuck

an

d th

e to

ol q

uit

spin

nin

g

Fin

es

Texas T

ech U

niv

ers

ity, G

beng

a M

. Fu

nm

ilayo

, August 2

010

�

��

�

TE

ST

J

Table

4.1

0: M

easu

rem

ents

record

ed fo

r tool #

4: tw

o 0

.05

2", th

ree 0

.024", a

nd tw

o 0

.02

0"

RU

N

P @

P

um

p/G

ear/

Flo

w R

ate

, p

si/g

pm

Len

gth

o

f Stiff

sectio

n,

ft

Dep

th,

ftR

OP

, ft/m

inH

ole

S

ize, in

Ho

le P

ath

Partic

le

Des

crip

tion

1

(Hole

# 1

4)

9000/4

/21.4

1

14

2

3 w

ide &

3 h

igh

Main

tain

ed

positio

n in

coal

seam

, but h

ose

got s

tuck in

the

hole

Mediu

m to

fin

e p

artic

les

2

(Hole

# 1

5)

9000/4

/21.4

2

11

2

3 w

ide &

3 h

igh

Main

tain

ed

positio

n in

coal

seam

, but h

ose

got s

tuck in

the

hole

Mediu

m to

fin

e p

artic

les

Texas T

ech U

niv

ers

ity, G

beng

a M

. Fu

nm

ilayo

, August 2

010

�

��

�

TE

ST

K

Table

4.1

1: M

easu

rem

ents

record

ed fo

r tool #

3: tw

o 0

.05

2", th

ree 0

.018", a

nd tw

o p

lug

s

RU

N

P @

P

um

p/G

ear/

Flo

w R

ate

, p

si/g

pm

Len

gth

o

f Stiff

sectio

n,

ft

Dep

th,

ftR

OP

, ft/m

inH

ole

S

ize, in

Ho

le P

ath

Partic

le

Des

crip

tion

1

(Hole

# 1

6)

10

00

0/4

/21.4

1

30.5

3

4 w

ide &

4 h

igh

Hit th

e b

otto

m o

f coal s

eam

afte

r 10 ft. d

rilled 2

0.5

ft in

to s

hale

La

rge

2

(Hole

# 1

7)

13

00

0/4

/21.4

0

62

3

3 w

ide &

4 h

igh

Main

tain

ed

positio

n in

coal

seam

La

rge

3

(Hole

# 1

8)

13

00

0/4

/21.4

0

62

4

4 w

ide &

4 h

igh

Main

tain

ed

positio

n in

coal

seam

La

rge

4

Hole

# 1

9)

13

00

0/4

/21.4

0

30

1.5

4 w

ide &

4 h

igh

Main

tain

ed

positio

n in

coal

seam

. Tool q

uit

spin

nin

g a

nd

hose g

ot s

tock in

th

e h

ole

La

rge


147

4.2 Discussions

This section discusses the results of the field tests and the sciences behind the

results. In all, seven tool configurations were employed to drill nineteen

boreholes. Six of the seven tools were Berger nozzles while the seventh

configuration was the Banshee type of nozzle. Five of these configurations were

used during the first field test and four were used during the second field trial. All

the tools were made by StoneAge Inc. The performances of each configuration

will be discussed. The fifth tool configuration, Banshee nozzle, will not be

discussed because its specifications were not known at the time of the tests.

It is important to discuss a parameter called impact pressure, before discussing

the performances of the various tool configurations. This is a major parameter

that influences the performances of the nozzles, and consequently the efficiency

of waterjet in horizontal drilling of coalbed methane reservoirs. Impact pressure is

the pressure that jets of water generate when in contact with a target; in this

case, the coal seam. The impact pressure is a function of three important

parameters:

a. Orifice sizes

b. Pressure at the nozzle, and

c. Stand-off distance


148

Impact pressure increases with both the size of orifice and pressure at the

nozzle, but reduces with increasing stand-off distance. The higher the impact

pressure, the more likely the jets of water would be able to drill boreholes;

provided there is sufficient pulling force to drive the system and provided an

appropriate volume of water is delivered at the drilling face. As earlier mentioned

in this report, the pressure at the nozzle is converted into flow velocity; which in

turn, is converted to impact pressure when jets of water hit a target. The Table

4.12 shows the significance of orifice sizes on impact pressure with a constant

value of 10802 psi at the nozzle and a constant value of 5 inches stand-off

distance. The orifice sizes used in the computation were those used in the actual

field tests. The effect of variation in pressure at the nozzle, at constant values of

stand-off distance and orifice size is shown on Table 4.13. The stand-off distance

of 5 inches was a rough estimate because it was difficult, if not impossible, to

accurately measure this value during jetting operations. As mentioned earlier,

Table 4.12 indicates that the larger orifice sizes will produce the higher impact

pressure, and part of Table 4.13 indicates that higher pressure at the nozzle

produces higher impact pressure at a target. The rest of the Table 4.13 shows

computed values of the total orifice size, the pulling force, the nozzle flow rate,

the flow velocity, and finally the impact pressure; based on the actual test data of

pump pressures and flow rates. A nozzle efficiency of 90 percent and a stand-off

distance of 5 inches were assumed in the analyses of all the results.


149

Back on the nozzle performances; the first configuration was used for tests A and

E, during the first field trial. With the same pump pressure of 9000, only 4603 psi

was delivered at the nozzle. The tool has a combined orifice size of 0.24 inches.

This produces a total pulling force of -7.9 lb and nozzle flow rate of 16.95 gpm.

The negative sign in the pulling force means there is a pull on the hose. With

these data and relevant assumption, only impact pressure of 3594 psi could be

achieved at the face of the coal seam. Kennerley61 determined that a pressure of

about 8000 psi is required at the nozzle for jets to be able to cut a coal. This

value is not universal, but is based on local characteristics of coal. In the case of

seelyvile coal, a higher pressure value of about 10,800 psi is required at the

nozzle for jets to produce an impact pressure of about 8200 psi that will cut the

coal. Generally speaking, an impact pressure of about 8,200 psi is the optimum

for the Pennsylvanian (Bituminous) coal in Illinois, Black Warrior, and

Appalachian Basins because they have similar petrophysical and mechanical

properties. This will be shown later in the analysis of tool configuration # 3. Four

runs were carried out during the two tests (A and E). The depth of borehole

drilled ranges from 3.4 ft to 20 ft. Such depth of drilling could not have been

possible, considering the amount of impact pressure the configuration produces.

The only reason drilling was possible is because the mine used for the test had

already been blasted, thereby reducing the natural compressive strength of the

coal seam within the first few feet of the formation. This claim is supported by the

Texas T

ech U

niv

ers

ity, G

beng

a M

. Fu

nm

ilayo

, August 2

010

�

��

� Table

4.1

2: E

ffect o

f orific

e s

ize o

n im

pact p

ressure

. C

on

fig-

ura

tion

Le

ng

th o

f

Ho

se, ft

Pre

ss

ure

at P

um

p,

psi

Pu

mp

’s

Flo

w

Ra

te,

gp

m

Pre

ss

ure

at N

ozzle

,

psi

Pre

ss

ure

Dro

p in

Ho

se, p

si

To

tal

Orific

e

Siz

e,

inc

he

s

To

tal

Pu

lling

Fo

rce

,

lb

No

zzle

Flo

w

Ra

te,

gp

m

Flo

w

Ve

loc

ity

, ft/se

c

Imp

act

Pre

ss

ure

, ps

i

1st

100

1

300

0

21.4

1

080

2

43

97

0

.24

0

-18.6

2

5.9

5

13

63

84

35

2n

d

100

1

300

0

21.4

1

080

2

21

98

0

.14

0

-49.0

1

6.9

4

15

28

82

16

3rd

1

00

1

300

0

21.4

1

080

2

21

98

0

.15

8

-45.6

1

7.8

5

15

28

82

75

4th

1

00

1

300

0

21.4

1

080

2

21

98

0

.21

6

-35.8

2

2.2

1

528

84

01

6th

1

00

1

300

0

21.4

1

080

2

21

98

0

.17

6

-35.8

1

9.9

6

15

28

83

23

7th

1

00

1

300

0

21.4

1

080

2

21

98

0

.20

0

-18.6

2

3.7

3

15

28

83

73

Texas T

ech U

niv

ers

ity, G

beng

a M

. Fu

nm

ilayo

, August 2

010

�

��

� Table

4.1

3: E

ffect o

f pre

ssure

on im

pact p

ressure

T

oo

lC

on

fi-

ura

tion

Te

st

Le

ng

th

of

Ho

se,

ft

Pre

ss

ure

at P

um

p,

ps

i

Pu

mp

’s

Flo

w

Ra

te,

gp

m

Pre

ss

ure

at N

ozzle

,

psi

Pre

ss

ure

Dro

p in

Ho

se, p

si

To

tal

Orific

e

Siz

e,

inch

es

To

tal

Pu

lling

Fo

rce,

lb

No

zzle

Flo

w

Ra

te,

gp

m

Flo

w

Ve

locity

,

ft/se

c

Imp

ac

t

Pre

ss

ure

,

ps

i

1st

A

200

9000

21.4

46

03

4397

0.2

40

-7.9

16.9

5

997

35

94

1st

E

200

9000

21.4

46

03

4397

0.2

40

-7.9

16.9

5

997

35

94

2nd

B

200

7000

12.7

54

51

1549

0.1

40

-24.7

12.0

4

1085

41

46

2nd

B

200

10000

16.5

73

86

2614

0.1

40

-33.5

14.0

1

1263

56

18

3rd

C

200

6000

12.7

44

51

1549

0.1

58

-18.8

11.4

6

981

34

10

3rd

C

200

9000

16.5

63

86

2614

0.1

58

-26.9

13.7

2

1175

48

92

3rd

G

100

9000

21.4

68

02

2198

0.1

58

-28.7

14.1

6

1212

52

11

3rd

K

100

10000

21.4

78

02

2198

0.1

58

-32.9

15.1

7

1298

59

77

3rd

K

100

13000

21.4

10802

2198

0.1

58

-45.6

17.8

5

1528

82

75

4th

D

200

4000

12.7

24

51

1549

0.2

16

-8.1

10.5

9

728

19

06

4th

D

200

6000

16.5

33

86

2614

0.2

16

-11.2

12.4

2

855

26

33

4th

D

200

10000

21.4

56

03

4397

0.2

16

-18.6

15.9

9

1100

43

57

4th

J

100

9000

21.4

68

02

2198

0.2

16

-22.6

17.6

3

1212

52

90

Texas T

ech U

niv

ers

ity, G

beng

a M

. Fu

nm

ilayo

, August 2

010

�

��

� Table

4.1

3: C

ontin

ued

T

oo

l

Co

nfig

-

ura

tion

Te

st

Le

ng

th

of

Ho

se,

ft

Pre

ss

ure

at P

um

p,

ps

i

Pu

mp

’s

Flo

w

Ra

te,

gp

m

Pre

ss

ure

at N

ozzle

,

psi

Pre

ss

ure

Dro

p in

Ho

se, p

si

To

tal

Orific

e

Siz

e,

inch

es

To

tal

Pu

lling

Fo

rce,

lb

No

zzle

Flo

w

Ra

te,

gp

m

Flo

w

Ve

locity

,

ft/se

c

Imp

ac

t

Pre

ss

ure

,

ps

i

6th

H

100

9000

21.4

68

02

2198

0.1

76

-22.6

15.8

4

1212

52

41

7th

I

100

9000

21.4

68

02

2198

0.2

00

-11.7

18.8

3

1212

52

72

Hose D

iam

ete

r = 0

.37

5 in

ches

Sta

nd-o

ff Dis

tance =

5 in

ches

1st: tw

o 0

.05

2", th

ree 0

.032

", and tw

o 0

.02

0"

2nd: tw

o 0

.052

", two 0

.018", a

nd th

ree p

lugs

3rd

: two 0

.05

2", th

ree 0

.018", a

nd tw

o p

lugs

4th

: two 0

.052", th

ree 0

.024", a

nd tw

o 0

.02

0"

6th

: two 0

.052", th

ree 0

.024", a

nd tw

o p

lugs

7th

: two 0

.052

", thre

e 0

.032

", and tw

o p

lugs


153

relatively higher rates of penetration experienced during the four runs, as

compared to other tests with different tool configurations. The fine nature of the

particles that were produced also lends support to the claim of reduced

compressive strength due to the blasting. As soon as the tool reached the

section of the seam whose strength had not been altered, it would either bend

downward, upward, left, or right; because the associated impact pressure was

not sufficient to cut this section. Coupled with low pulling force, the bending was

probably because the tool found paths of least resistance and traveled within the

blasted section of the coal seam. The tool stopped spinning when it hit the roof of

the coal seam because the impact pressure was not sufficient to drill through the

harder top formation.

The second tool configuration was used for test B. The first run was at 7000 psi,

while the second run of the test was at 10000 psi. These produce 5451 psi and

7386 psi respectively at the nozzle. With a total orifice size of 0.14 inches, the

first run generated -24.7 lb of pulling force and its associated nozzle flow rate of

12.04 gpm and the second run produced -33.5 lb of pulling force and nozzle flow

rate of 14.01 gpm. The impact pressures are 4146 psi and 5618 psi for runs 1

and 2 respectively. The tool did not spin at all, either with or without contact with

coal face. The problem was most probably due to some defects in the design of

the tool. It was expected to drill through, at least, the blasted section of the coal


154

seam; going by its higher pulling forces and impact pressures than the first

configuration.

The third tool configuration was used for tests C, G, and K. Test C was carried

out during the first field trial, whole G and K were carried out during the second

field trial. A site with less impact of mine blast was selected for the second field

trial. The tool has a total orifice size of 0.158 inches. There were two runs under

test C. The first run has pump pressure of 6000 psi, while the second run has

pressure of 9000 psi. The first run has a pulling force of -18.8 lb and nozzle flow

rate of 11.46 gpm. The second run has a pulling force of -26.9 lb and flow rate of

13.72 gpm. Run 1 has an impact pressure of 3410 psi and run 2 has an impact

pressure of 4892 psi. The tool would spin, but stopped spinning as soon as it was

in contact with the coal face. Hence, it could not jet-drill the coal. The most

probably reason for its inability to jet-drill the coal is that the impact pressures for

both run 1 and 2 are below the threshold required to cut the coal. Insufficient

pulling force may also be another reason the tool was not able to penetrate the

coal seam. The fact that it would spin when not in contact with the coal face

suggest that tool defect might not be an issue in this case. There were three

runs under test G. The three had 9000 psi. It was thought that addition of stiff

section between the nozzle and the high pressure hose could help the system

maintain its direction within the coal seam. Hence, run 1 had a stiff section of 1 ft

to drill a depth of 17 ft, run 2 had 2 ft of the still section to drill 20.5 ft, and run 3


155

had the stiff section of 3 ft to drill 18 ft. The drilling proceeded at an ROP of 3

ft/min for each of the three runs. The nozzle pressure of 6802 psi produced a

pulling force of -28.7 lb, nozzle flow rate of 14.16 gpm, and impact pressure of

5211 psi. The tool moved out of the coal seam and hit the formation below it after

drilling the depths earlier mentioned. The relatively low rate of penetration and

large particle sizes transported to the surface suggest that mine blasting did not

have significant effect on the test site. Otherwise, the penetration rate would

have been higher and the particles being cut would have been finer. The ability of

this configuration to drill the coal was a combination of the pulling force and the

impact pressure obtained under the conditions of pump pressure and flow rate.

Surprisingly, the incorporation of stiff section into the system did not solve the

control problem, as tool continued to drill out of the coal seams. The pump

pressure was increased to 10000 psi during test K, with a still section of 1 ft

connected between the nozzle and the hose to perform run 1. The pulling force

increased to -32.9 lb, nozzle flow rate increased to 15.17 gpm, and the impact

pressure increased to 5977 psi. Although the tool’s control problem persisted, the

tool was able to increase its drilling depth to 30.5 ft at an ROP of 3 ft/min. Only

about 10 ft of depth was drilled within the coal seam, while the remaining 20.5 ft

was drilled into the shale formation below the coal seam. The pump pressure

was further increased to 13000 psi to perform runs 2 through 4, under test K. The

run numbers 2 through 4 were without the connection of any stiff section. The

pulling force increased to -45.6 lb, the nozzle flow rate increased to 17.85 gpm,


156

and the impact pressure increased to 8275 psi. A depth of 62 ft was jet-drilled

into the coal seam during runs 2 and 3, at an ROP of 3ft/min and 4 ft/min

respectively. The tool maintained it position within the coal seam. The jetting

operation was intentionally stopped because the available hose length had been

used up. It was possible to record this success because there was sufficient

amount of pressure available at the pump, and consequently, at the nozzle. The

associated impact pressure was high enough to cut the coal and the pulling force

was high enough to drive the hose into the coal seam as the tool was cutting the

coal. In addition, the volume of water delivered to the coal face during the jetting

operation was just enough to transport the cuttings to the surface. In order to

ascertain that the tool kept straight directions within the coal seam during these

runs, tracking equipment was run to survey the borehole drilled. Sucker rods of

length 100 ft were coupled and driven into the drilled boreholes. The rod did not

deviate within the drilled boreholes and exact 62 ft of drilled depths were

measured. Run #4 was performed. The tool fed into the coal seam at a rate of

1.5 ft/min and was able to maintain its position within the coal seam. It, however,

quit spinning and got stuck in the hole after drilling about 30 ft. The slower rate of

penetration than the previous runs was probably due to the spinning problem the

tool suddenly developed. The reason for the tool getting stuck in the hole could

either be because it suddenly stopped spinning or because the amount of water

available to transport the large cuttings to the surface was no longer sufficient.

Part of the spent (returning) water seeped into the coal seam through the cleat


157

systems, rather than all of them returning through the drilled boreholes. When

there is no sufficient water to transport all the cuttings to the surface, the

remaining cuttings bridge the hole and prevent free movement of the hose within

the hole. To solve this problem, it is recommended that the operator drills 10 ft

into the formation, pulls back the equipment 10 ft, drills another 10 ft, and pulls

back 20 ft. The operator should repeat this technique for the entire drilling

operation. The technique helps the larger particles being cut to be further broken

down into smaller pieces, which eases their transportation to the surface with

spent water. The large particle sizes transported to the surface and the relatively

low rate of penetration suggest that mine blasting did not alter the original

compressive strength of the coal.

The fourth tool configuration was used for test D during the first field trial, and

test J during the second field trial. The total orifice size is 0.216 inches. There

were three runs for test D. Run 1 was performed at pump pressure of 4000 psi.

Run # 2 was performed at pump pressure of 6000 psi. The last run was set at

10000 psi as pump pressure. Their corresponding pressures at the nozzle were

2451 psi for run 1, 3386 psi for run 2, and 5603 psi for run 3. The 2451 psi

translates to the pulling force of -8.1 lb, nozzle flow rate of 10.59 gpm, and

impact pressure of 1906 psi for run 1. The 3386 psi translates to the puling force

of -11.2 lb, nozzle flow rate of 12.42 gpm, and impact pressure of 2633 psi for

run 2. The 5603 psi pressure at the nozzle translates to the pulling force of -18.6


158

lb, nozzle flow rate of 15.99 gpm, and impact pressure of 4357 psi for run 3. The

tool could not cut the coal during runs 1 and 2. It would spin, but stopped

spinning on contact with the coal face. This is probably because the impact

pressure achievable by the tool configuration falls below what could cut the coal.

Just as the case with the test C of the third tool configuration, insufficient pulling

force may also be another reason the tool was not able to penetrate the coal

seam. One possibility the tool stopped spinning on contact with coal face could

be a defect in the tool, as spinning was a big problem encountered in all the tool

configurations use for the field trials. Even those tools that were able to jet-drill

boreholes at the initial stages quit spinning in subsequent runs. The spinning is

expected to provide the much needed retro-jets required to cut the coal seam,

drive the tool into it, and clean up the cuttings as jetting progresses. The third run

of test D proceeded at the rate of 6 ft/min and was able to drill a total distance of

13 ft. Tool moved out of the coal seam, went up and bent towards the right

direction. It then made a U-turn and return to the surface of the coal seam. The

distance between the entrance and the exit was about 7.5 ft, indicating that only

about 5.5 ft was drilled into the coal seam. The relatively high ROP and the fine

cuttings transported to the surface suggests that mine blasting did alter the

original strength of the coal. This could be why such a low impact pressure of

4357 psi was able to cut the coal. The tool, however, returned to the surface

because the pressure was not sufficient to jet-drill the section of the coal whose

compressive strength was still intact. Also, the pulling force of -18.6 lb was not


159

enough to move the tool further into the undisturbed coal seam. Hence, the tool

returned to the surface through the path of least resistance within the section

affected by blasting. Test J was carried out after the tool was improved upon by

polishing the inner surfaces to increase the gap between rotating parts, so they

have less chance of touching and galling during operation. At a pump pressure of

9000 psi, a pressure of 6802 psi was delivered at the nozzle. This translates to

the pulling force of -22.6 lb, nozzle flow rate of 17.63 gpm, and impact pressure

of 5290 psi. Two runs were performed for this test. The first run had a still section

of 1 ft and the second run had a still section of 2 ft, both connected between the

nozzle and the hose. Depths of 14 ft and 11 ft were drilled during the first and the

second runs respectively, both at the rate of 2 ft/min. The tool maintained its

position within the coal seam, for the two runs, but the hose got stuck in the hole.

There are two possible reasons why the hose got stuck in the hole. First, at such

relatively low amount of impact pressure, the energy from the jets coming out of

the tool was no longer sufficient to cut the coal. At this point, the hose will no

longer pull further into the borehole. The second reason may be due to

ineffective borehole cleaning. If the drilled borehole is not properly cleaned, the

hose can get stuck and the tool will no longer be able to cut; even though a

considerable amount of pulling force is still available for the hose and a

considerable amount of energy is still available in the jets to cut through the coal.

To resolve the first possibility, the system would have to be operated at a much

higher pressure. Borehole cleaning can be enhanced by tripping in and out of the


160

borehole to further break the cuttings into smaller particle, so that cutting

transportation can be made easier. Increased pump pressure will also increase

the nozzle flow rate, and consequently makes more volume of spent water

available to transport cuttings to the surface.

The sixth configuration was used during the second field trial, for test H, and has

total orifice size of 0.176 inches. A pump pressure of 9000 psi delivered a

pressure of 6802 psi at the nozzle. This translates to the pulling force of -22.6 lb,

nozzle flow rate of 15.84 gpm, and impact pressure of 5241 psi. Two runs were

performed for this test. The first run has a still section of 1 ft and the second run

has a still section of 2 ft, both connected between the nozzle and the hose.

Depths of 5 ft at the rate of 2 ft/min and 6.5 ft at the rate of 1 ft/min were drilled

during the first and the second runs respectively. The tool bent towards the right

during the first run, but maintained its position within the coal seam during the

second run. The hose got stuck in the hole during both runs. The two reasons

explained under the fourth configurations could also be attributed to why the

hose got stuck under this sixth configuration.

The last configuration was used during the second field trial for test I, and has

total orifice size of 0.200 inches. A pump pressure of 9000 psi delivered a

pressure of 6802 psi at the nozzle. This translates to the pulling force of -11.7 lb,

nozzle flow rate of 18.83 gpm, and impact pressure of 5272 psi. Only one run


161

was performed for this test. With a still section of 1 ft connected between the

nozzle and the hose, a depth of 5 ft was jet-drilled at the rate of 0.8 ft/min. The

tool maintained position in coal seam, but the hose got stuck and the tool quit

spinning. The reason the hose got stuck could be due to the low pulling force

associated with this configuration. Tool defect could be why the tool quit

spinning.


162

CHAPTER V

CONCLUSIONS AND RECOMMENDATIONS

5.0 Conclusions

This research investigated the applicability of waterjet technology for drilling

horizontal wells in coalbed methane reservoirs. The CBM reservoir of interest is

the seelyville coal seam of Indiana, in Illinois Basin. The choice of the reservoir

was informed by its characteristics that favor horizontal well technology for its

methane production. Principal among these characteristics is the poorly

developed butt cleats, which enhances the permeability anisotropy of the coal

seam. The research concludes that waterjet technology has very high potential in

being able to drill horizontal wells in coalbed methane reservoirs.

Pulling force and impact pressure are the two principal factors that influence the

ability of waterjets to drill horizontal wells in CBM reservoirs. The pulling force

helps drive the hose into the coal seam as the impact pressure from the jets of

water cuts the coal. Both factors are a function of the orifice sizes and the

amount of pressure at the nozzle. Larger orifice sizes leads to higher impact

pressure and higher nozzle flow rate, but also leads to lower pulling force. Higher

pressure at the nozzle leads to increase in both the pulling force and impact

pressure. The pressure at the nozzle is determined by the amount of pressure at

the pump and operational design that minimizes pressure drops in the system,


163

especially in the hose. A point is reached when a value of impact pressure is

attained that is sufficient to cut the coal. Any further increase in impact pressure

beyond this threshold becomes inconsequential on the jets’ cutting ability.

Beyond this value, pulling force becomes more important than the impact

pressure. The higher the pulling force, the deeper the hose will drive into the coal

seam as the jets cut the coal. Generally speaking, an impact pressure of about

8,200 psi is the optimum for the Pennsylvanian (Bituminous) coal in Illinois, Black

Warrior, and Appalachian Basins because they have similar petrophysical and

mechanical properties

In an effort to determine the best nozzle configurations for the waterjet drilling,

seven different nozzle configurations were tested during two field trials to drill

nineteen boreholes. The tool configuration (third configuration) with two 0.052",

three 0.018", and two plugs worked best. Based on the field data, the tool

maintained the highest pulling force and impact pressure; and it was able to drill

the deepest distance into the coal seam. Simply put, the tool configuration has

the right combination of pulling force, impact pressure, and volumetric flow rate to

perform the jet-drilling operation. Based on the theoretical data presented in

Table 4.12, the tool configuration (second configuration) with two 0.052", two

0.018", and three plugs has potential to perform, probably better than the third

tool configuration. It gives higher pulling force and impact pressure than the third

configuration, under the same condition of pump and nozzle pressure. However,


164

there was defect with the tool, during field trial, which prevented it from spinning

and cutting the coal. Therefore, it was impossible to practically determine its

jetting ability. Unfortunately, it was not part of the configurations tested during the

second field trial.

The inner surfaces of all the tools used during the second field trials were

polished in order to increase the gap between rotating parts, so they have less

chance of touching and galling during operation. The rework most likely

contributed to why better results were obtained for the third tool configuration

than the first field trial.

It was difficult to determine which tool configuration cuts faster than the other,

because many of the tool configurations could not even cut the sections of the

coal whose compressive strength have not been altered. Therefore, the

measured ROP in Tables 4.1 through 4.11 cannot be relied upon for such

determination.

There were no significant differences in the sizes of the boreholes drilled with the

tools having 900 jet angles and those without it. This is probably because the

ROP recorded for the nineteen boreholes are generally low. Borehole sizes tend

to be smaller when jetting rates become very high.


165

It was difficult for the tools to maintain their positions within the coal seam during

the first field trial. It would either deviate to the right, left, upward, or downward of

the coal seam. It was then thought that incorporation of a still section of certain

length would solve the problem. Surprisingly, the connection of the stiff section

did not help in anyway. The problem was, however, resolved by maintaining

sufficiently high pressure at the nozzle. This is the most probable reason the third

tool configuration could drill up to 62 ft into the coal seam, without deviating out

of it.

Finally, there were occasions the tool got stuck in the coal during jetting

operation, due to borehole plugging by the cuttings. The problem was resolved

by drilling about 10 ft into the coal seam, tripping back 10 ft, drilling another 10 ft

and tripping back 20 ft, and so on. The process helps break down larger cuttings

that plug the borehole, into smaller particles; which consequently aids the

transportation of the cuttings to the surface.

5.1 Recommendations

The inability of many of the tools to spin, or the problem of many of them

stopping to spin on contact with coal face or after jet-drilling for sometimes,

should be looked into. In other word, the tools’ design, especially their retro-jet

systems, should be further improved upon to increase their life span. It is

anticipated that each tool should be able to have up to 20 hours of life span.


166

The purpose of testing different tools configurations is to be able to determine

which tools work best. Based on the result of the field tests, it is recommended

that the third tool configuration (tool with two 0.052", three 0.018", and two plugs)

be employed for the actual horizontal drilling of colabed methane reservoirs. The

tool has the right combination of pulling force, impact pressure, and nozzle flow

rate.

Since maintaining high pressure at the nozzle helped control tool direction within

the coal seam during some tests involving the third configuration, it is

recommended that a pump with very high pressure rating be employed during

subsequent tests and actual project development. Maintaining high pressure at

the nozzle will not only help control tools’ position within a coal seam, it will

increase the pulling force and the impact pressure; both of which will lead to

better tools’ performance in terms of hose driving and tools’ cutting ability.

The second tool configuration (tool with two 0.052", two 0.018", and three plugs)

is recommended for further field tests. It is expected that the tool should perform,

at least, as much as the third tool configuration; if a high pressure is maintained

at the nozzle. This has been demonstrated on Table 4.12.

Drilling perpendicular to the face cleat is very critical to faster dewatering and

methane production. Such drilling pattern maximizes reservoir contact.


167

The seelyville coal in Illinois Basin has high percentage of sulfur, abundant of

calcite, and other ash-forming minerals deposited within the cleat systems. It is

believed that dewatering and methane production will proceed faster once these

minerals are dissolved from the cleat systems. Therefore, acid treatment is

recommended.


168

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